annual rEport 2013
3
1
0
2
t
r
o
p
E
r
l
a
u
n
n
a
k
r
a
P
o
e
G
EXplorEr opErator consolidator
contEnts
2
chairman / cEo letter
12
2013 performance
14
our strengths
16
18
our approach
Form 20-F
232
Board of directors
Oil and Gas Production
Oil and Gas Reserves
BottoM linE
18
16
14
12
10
8
6
4
2
0
)
d
/
e
o
b
M
(
n
o
i
t
c
u
d
o
r
p
y
l
i
a
d
e
g
a
r
e
v
a
80
70
60
50
40
30
20
10
0
e
o
b
M
M
n
i
2009
2010
2011
2012
2013
2013
pro forma
2009
2010
2011
2012
2013
2013
pro forma
oil and condensate
Gas
2p oil
2p Gas
Total Revenues
Adjusted EBITDA1
400
350
300
250
200
150
100
$
s
u
M
M
n
i
50
0
200
150
100
50
0
$
s
u
f
o
M
M
n
i
2009
2010
2011
2012
2013
2013
pro forma
2009
2010
2011
2012
2013
2013
pro forma
oil and condensate
Gas
(1) see definition of adjusted EBitda on page 22 of this annual report
dear shareholders,
We are pleased to report that Geopark had another record year in
despite our on-the-ground progress, our share price performance
2013 – with more oil and gas found and produced, our strongest
was down approximately 4.2% for the year with very little trading
financial results ever, an increase in our underlying value per share, a
activity. to address this situation, we made an important transition in
strengthened organization, and strategic expansion into a new
early 2014 from the london aiM Market to the new York stock
region to continue opening future opportunities. Geopark is now
Exchange (nYsE) to reach a wider audience of investors and raise
uniquely positioned in latin america with a self-funding platform
additional funds (approximately $100 million) for expansion.
consisting of 29 hydrocarbon blocks covering 1.9 million acres in 10
consistent with our move to the nYsE, we also increased investment
proven hydrocarbon basins in 4 countries (chile, colombia, Brazil
in our shareholder reporting and communication capacities,
and argentina) with a rich mix of production, development,
including an ongoing 2014 initiative to implement sap throughout
exploration and unconventional resource projects – and the team
our businesses.
to make it work.
Geopark is a company that started from ‘scratch’ in 2002 and our
in 2013, and for the seventh consecutive year, our key performance
consistent growth to date is a reflection of a systematic approach.
measurements (excluding figures from our new Brazil assets)
it means we have been able to continuously increase our production
recorded important gains: oil and gas production up 20%, reserves
at the same time continuously increasing our reserves. it means
up 8% and adjusted EBitda up 38% (with revenues up 35%).
we have been able to improve our operating and capital cost
additionally, our net income increased by 89%, our netback per boe
efficiencies, increase our cash flows, and use our capital wisely to
produced increased by 9% and we had $121 million in cash at
expand the business. it means we have been able to create a solid
year-end. again, growth came from the drill bit with 39 new oil and
supportive base that allows us to exploit the opportunities around
gas wells drilled, with a success rate of 74% and the discovery of
us. it means we have been able to build a strong and capable
seven new oil and gas fields.
team that is prepared to take Geopark into the future. it means we
are in good shape for 2014 and beyond.
We also expanded our business into our fourth country in latin
america by entering Brazil, one of the world’s highest-potential
hydrocarbon regions. including our new Brazil assets (agreed on in
strategic context
2013 and closed in 2014), our 2013 pro forma figures for total oil and
gas production increased to an average of 17,098 boepd, our proven
For our new shareholders joining us following our move to the
and probable reserves (prMs) grew to 70.2 million boe and our
new York stock Exchange, we feel it may be helpful to review some
revenues rose to $387 million with an adjusted EBitda of $198
of the core principles we have applied in building Geopark.
million. With respect to funding, we accessed the international debt
capital markets in early 2013 and successfully closed a $300 million
our objective in founding Geopark was to create value by building
(7 year) bond, which was substantially over-subscribed.
the leading latin american upstream independent oil and gas
significantly, our underlying economic value per share grew last
caring company with the best ‘shareholder value-adding’ oil and
company. By this, we mean an action-oriented, persistent, aware and
year. one internal measurement (the npV10 of our certified 3p
gas assets.
reserves, adjusted by net debt and minority interests, and divided by
the number of outstanding shares), indicates our oil and gas asset
We believe the energy business – specifically the upstream oil and
value per share increased by approximately 20% from 2012 to 2013.
gas industry – is one of the most exciting, necessary, and
(this is a relative performance measure that does not include
economically-rewarding businesses today. no undertaking or society
values for our exploration resources and our expanded inventory
can advance without the supply of energy, and energy remains the
of drilling opportunities.)
critical element in allowing people to better their lives. Much of the
2 annual report 2013
05 annual report 2013
lEttEr to sHarEHoldErs
annual report 2013 3
world still lacks adequate energy supplies for the most basic needs
independent companies. (the us is home to over 6,000 independent
and demand is continually increasing. although new exciting
oil and gas operators, whereas latin america, an area substantially
technologies and sources are being developed, oil and gas is the
larger and with greater resource potential, has only a few handfuls of
most reliable energy source and will be required to support
independents taking advantage of available opportunities.) in
over half of our planet’s continuous and rising energy needs far into
contrast to many areas of the world, the environment and resources
this century.
for operating and funding a business are welcoming and
increasingly more feasible. Furthermore, numerous good oil and gas
We believe the best places for us to find and develop hydrocarbons
assets in latin america are available, undervalued and at very
are in areas around the world where oil and gas have already been
attractive prices right now (particularly compared to north america).
discovered, but which for economic, technical, funding or other
reasons have been inadequately developed or prematurely
Geopark has been conservatively built for the long term. We did not
abandoned. these projects have proven hydrocarbon systems,
start with a short term ‘exit strategy’ in mind, and do not see this as
valuable technical information, existing infrastructure, and, in many
an effective approach in building a team and business. our approach
cases, unexploited low-risk exploration and re-development
required patience in the beginning in order to create the foundation
opportunities. By applying new technology and investment, creating
to put us solidly ‘in the game’, but has enabled us to now have the
stable markets and better economic conditions, and/or more
chance to grab the bigger prizes.
efficient operations, a neglected or forgotten asset can be converted
into an attractive economic project. Work in these areas also
Gerry and i, and our management team, have a substantial part
frequently opens up exciting new hydrocarbon resources in new
of our net worth invested in Geopark. neither Gerry nor i have ever
geological play-types and formations.
sold a share of Geopark stock. in fact, we have been stock buyers
over time (including in the nYsE ipo). We have no special class
We are focused on latin america because of the abundance of these
of stock or arrangements that benefit us differently from any other
types of opportunities throughout the region. latin america ranks
shareholder other than our salaries and stock performance incentive
as one of the highest potential hydrocarbon resource regions in the
programs. the entire Geopark team (100% of our employees have
world and its economies are thirsty for new energy. Historically,
received Geopark share awards) is solidly aligned with all of
it has been dominated by larger major and national oil companies,
our shareholders to build real and enduring value for every share
with the presence of only a modest number of more-agile
of Geopark.
4 annual report 2013
lEttEr to sHarEHoldErs
opportunity Enhancement and risk diversification
By its very nature, the upstream oil and gas business represents the
characteristics of a local company. our pride and care in how we act
undertaking of risk in search of significant rewards. to succeed, an
and perform in our home regions are key elements of our success.
oil and gas company must effectively identify and manage the
existing risks and uncertainties to ensure capturing the available
these generally decentralized businesses are further enhanced by
rewards. We believe this to be one of Geopark’s key capabilities; and
being tied together by an overall corporate organization, which
our year over year track record is evidence of our success in
improves efficiencies, reduces costs with operational and financial
effectively balancing risk among the subsurface, geological, funding,
synergies, controls quality, and can more effectively raise capital for
organizational, market, price, partner, shareholder, regulatory and
our projects. it also is a source for new technologies and ideas. For
political environments. For example, during the difficult global
example, our team introduced a new geological play-type to the
financial crisis of 2008/9, which caused many to retreat, Geopark was
llanos Basin in colombia (an area that has been explored for more
able to bring all the elements of our business together to achieve
than 75 years) that resulted in multiple new oil field discoveries, and
continuous growth.
new oil technology to the Magallanes Basin in chile that successfully
increased production and reserves.
We believe the best results in the upstream business are achieved
with a larger scale portfolio approach with multiple attractive
importantly, through effective and controlled capital allocation, our
projects in multiple regions managed by talented oil and gas teams.
businesses can also beneficially compete with each other thereby
this diversification reflects both a defensive and offensive approach.
allowing our resources to flow to the highest performing projects.
it is protective of any downside because the collective strength of
our projects limits the negative impact of any underperforming
We believe this business approach makes Geopark a more attractive
asset. it also has an exciting multiplier effect on the potential upside
investment vehicle for all our shareholders; with a strong foundation
because of the increased number of opportunities independently
to minimize any downside, a big upside through multiple
marching ahead.
growth opportunities, and an overall organizational system to more
efficiently run and grow the individual businesses.
our country businesses are managed by experienced local
professionals and teams with high reputations. they know both the
specific subsurface rocks and conditions and the above-ground
operating and business environments in each region and give us the
annual report 2013 5
annual report & 20F Form 04
capabilities
Businesses: review and outlook
our experience in the oil and gas business has repeatedly
Geopark’s approach has resulted in an expanding business in each
demonstrated the need for good people with commitment and real
country, managed by good teams, with supporting production and
oil and gas know-how. We believe in and have experienced the
cash flow, and inventories of attractive new growth projects. We are
amazing capacity of people to excel in an environment of expanding
aggressively investing to grow our businesses and, in 2014, have
opportunity and trust. our efforts to create such a team have far
embarked on a $220-250 million work program – funded by our own
exceeded our expectations and Geopark is blessed to have an
cash flows – targeting a strong 15-20% production growth rate. this
incredible group of men and women who truly work day and night
program (which does not include expected new project acquisitions)
to make us better in every way. our results speak to the daily heroics
consists of drilling of 50-60 new wells, new seismic surveys and
(mostly unseen) by our team that keep us together and have
new facility construction; and is balanced between exploration (40%)
moved us consistently closer towards our goals.
and development (60%) and spread approximately between chile
(62%), colombia (33%) and Brazil (5%). By design, our work program
our record of delivery is based on three fundamental and distinct
is largely discretionary and can be adapted to accommodate any
skill sets – as Explorers, operators and consolidators – which we
new opportunities or needs.
deem critical for enduring success in the oil and gas business. our
team has consistently demonstrated the science and creativity to
chile Business
find hydrocarbons in the subsurface, but also the muscle and
experience to get the oil and gas out of the ground and profitably to
Geopark first proved our business model in chile where we became
market. our attractive asset portfolio is evidence of our ability to
chile’s first private oil and gas producer. From a ‘flat-footed’ start-up
acquire good projects in the right basins in the right countries with
in 2006, we built a solid business currently with production of
the right partners and at the right price.
approximately 7,000 boepd, 2p (prMs) reserves of approximately 45
today, we have over 400 employees – from chile, colombia, Brazil
prospective acres. in 2011, lG (the Korean conglomerate) acquired
and argentina – each of whom joined Geopark with the purpose
a 20% interest in our chile business for $148 million, plus other
of building a unique and special company that is prepared to
benefits, thereby giving a value to our chile business alone of
million boe and 6 blocks with approximately 1.0 million highly-
handle challenges and seize opportunities. as a quickly growing
approximately $740 million.
company, we have repeatedly seen individuals step-up to the new
responsibilities presented – and we have a deep and powerful
in 2013 in the Fell Block, we continued to increase oil production (up
leadership team taking Geopark to the next level.
14%) from our successful drilling program in the tobifera formation,
a volcaniclastic geological formation, formerly considered non-
the international upstream oil and gas business is not for the
prospective. today, over 60% of our chile production is from the
fainthearted or easily discouraged. time-after-time, the Geopark
tobifera formation and we are further developing the methodology
team has been able to push ahead to find solutions where often
to most effectively exploit this exciting opportunity, including the
others have given-up or failed. this is the engine and fire of our
application of electrical submersible pumps. the Fell Block, which
growth and the true long term intangible value of our company.
covers approximately 370,000 acres and currently produces from
We are immensely grateful to all these men and women for
approximately 20 oil and gas fields (all developed by Geopark),
their professionalism, discipline, unity and heart.
continues to hold new opportunities from identified but undrilled
prospects and from the exploration of new geological formations.
in 2014, we expect to drill another 17-19 wells to increase production
and reserves. the Fell Block also contains an attractive thick shale
formation over a large area (180,000 acres) that has tested oil
and contains a large unconventional oil resource opportunity that
is currently being evaluated.
6 annual report 2013
lEttEr to sHarEHoldErs
annual report 2013 7
capabilities
our experience in the oil and gas business has repeatedly
of building a unique and special company that is prepared to
handle challenges and seize opportunities. as a quickly growing
company, we have repeatedly seen individuals step-up to the new
demonstrated the need for good people with commitment and real
responsibilities presented – and we have a deep and powerful
oil and gas know-how. We believe in and have experienced the
leadership team taking Geopark to the next level.
amazing capacity of people to excel in an environment of expanding
opportunity and trust. our efforts to create such a team have far
exceeded our expectations and Geopark is blessed to have an
incredible group of men and women who truly work day and night
to make us better in every way. our results speak to the daily heroics
(mostly unseen) by our team that keep us together and have
moved us consistently closer towards our goals.
our record of delivery is based on three fundamental and distinct
skill sets – as Explorers, operators and consolidators – which we
deem critical for enduring success in the oil and gas business. our
team has consistently demonstrated the science and creativity to
find hydrocarbons in the subsurface, but also the muscle and
experience to get the oil and gas out of the ground and profitably to
market. our attractive asset portfolio is evidence of our ability to
acquire good projects in the right basins in the right countries with
the right partners and at the right price.
today, we have over 400 employees – from chile, colombia, Brazil
and argentina – each of whom joined Geopark with the purpose
the international upstream oil and gas business is not for the
fainthearted or easily discouraged. time-after-time, the Geopark
team has been able to push ahead to find solutions where often
others have given-up or failed. this is the engine and fire of our
growth and the true long term intangible value of our company.
We are immensely grateful to all these men and women for
their professionalism, discipline, unity and heart.
Businesses: review and outlook
Geopark’s approach has resulted in an expanding business in each
country, managed by good teams, with supporting production and
cash flow, and inventories of attractive new growth projects. We are
aggressively investing to grow our businesses and, in 2014, have
embarked on a $220-250 million work program – funded by our own
cash flows – targeting a strong 15-20% production growth rate. this
program (which does not include expected new project acquisitions)
consists of drilling of 50-60 new wells, new seismic surveys and
new facility construction; and is balanced between exploration (40%)
8 annual report 2013
lEttEr to sHarEHoldErs
lEttEr to sHarEHoldErs
and development (60%) and spread approximately between chile
(62%), colombia (33%) and Brazil (5%). By design, our work program
is largely discretionary and can be adapted to accommodate any
in 2014, we expect to drill another 17-19 wells to increase production
new opportunities or needs.
and reserves. the Fell Block also contains an attractive thick shale
chile Business
formation over a large area (180,000 acres) that has tested oil
and contains a large unconventional oil resource opportunity that
is currently being evaluated.
Geopark first proved our business model in chile where we became
chile’s first private oil and gas producer. From a ‘flat-footed’ start-up
Following our acquisition of three new blocks in the island of
in 2006, we built a solid business currently with production of
tierra del Fuego in 2012 across the Magellan straits, our team moved
approximately 7,000 boepd, 2p (prMs) reserves of approximately 45
efficiently and swiftly to complete a 1,500 sq km seismic campaign,
million boe and 6 blocks with approximately 1.0 million highly-
begin drilling on the Flamenco Block, and successfully discovering
prospective acres. in 2011, lG (the Korean conglomerate) acquired
and putting the new chercan field into production in 2013. these
a 20% interest in our chile business for $148 million, plus other
blocks cover an area of approximately 460,000 acres and represent a
benefits, thereby giving a value to our chile business alone of
similar geological play, with targets in the tobifera, springhill and
approximately $740 million.
tertiary formations, as the successful Fell Block. our geological
and geophysical team has identified 25-30 new attractive leads and
in 2013 in the Fell Block, we continued to increase oil production (up
prospects, and a 15-17 exploration and development well drilling
14%) from our successful drilling program in the tobifera formation,
program is now underway for 2014.
a volcaniclastic geological formation, formerly considered non-
prospective. today, over 60% of our chile production is from the
colombia Business
tobifera formation and we are further developing the methodology
to most effectively exploit this exciting opportunity, including the
after patiently waiting for asset prices to settle down from an
application of electrical submersible pumps. the Fell Block, which
over-inflated oil and gas asset market in 2010 and 2011, we found a
covers approximately 370,000 acres and currently produces from
window of opportunity in early 2012 to enter colombia. Following
approximately 20 oil and gas fields (all developed by Geopark),
continues to hold new opportunities from identified but undrilled
prospects and from the exploration of new geological formations.
annual report 2013 9
We are also making efforts to establish a new platform in peru; which
interest partner. We also target relationships with the national
has major hydrocarbon resources and is making a concentrated
oil companies where we operate, such as with Enap in chile and
effort to become more accessible to and benefit from oil and gas
petrobras in Brazil.
investment activities similar to its neighbors (such as colombia).
We are also beginning to evaluate opportunities in Mexico;
critical to the success of any new project is to conduct a thorough
which has always represented a big prize, but where it has been
technical and economic analysis prior to acquiring any new asset.
difficult for companies to acquire direct holdings. current rapidly
We make sure we understand the project, its risks and its value –
advancing regulatory reforms may finally open the door for
and we buy right. no team can turn a faulty or overpriced project
private companies to access some of Mexico’s highly attractive
into a good business. Following an intensive geological, geophysical,
hydrocarbon assets – many of which would be an excellent fit for
engineering, operational, legal and financial analyses and due
Geopark’s approach and skillset.
diligence, we perform a detailed discounted cash flow (dcF)
valuation. We also consider the option value or strategic benefits of
With our overall growth targets and portfolio approach, new project
a project when entering a new region. We do not buy assets on
acquisitions are an important part of our business. our acquisition
simplified ‘$ per barrel’ metrics which we believe do not properly
efforts begin with a technical approach to define the hydrocarbon
account for multiple factors (including technical, cost, tax, and time)
basins where our geological and engineering teams identify
that impact the economics of oil and gas projects. We also avoid
an attractive potential. after screening for political risks, our new
markets or ‘bubbles’ when assets are over-priced.
business teams proactively ‘scratch and dig’ to locate interests or
opportunities within those areas and to establish a position. it is a
long term and continuous effort and we have been building an
culture
attractive inventory of new projects in the region over the last ten
years, aided by our team’s 25+ year experience in latin america.
‘creating Value and Giving Back’ is our motto and represents
Geopark’s market-based approach to align our business objectives
our focus is always to build a larger scale balanced portfolio that
with our core values and responsibilities. our in-house designed
includes lower-risk short term cash flow generating properties, mid
program, titled s.p.E.E.d., targets and integrates the critical elements
term medium-risk development projects, and longer term higher-
– safety, prosperity, Employees, Environment and community
risk big upside projects. this permits steady secure growth with
development – necessary to make our total business plan work.
an opportunity for accelerated high growth ‘home-runs’ from the
Without succeeding equally in each of these interdependent areas,
bigger projects.
our overall success and ambitions cannot be realized. this is
important in every country where we operate, and we make every
Good oil and gas partners are a key element of our new business
effort to achieve the most effective governance, full compliance
efforts and we like to balance our acquisition risk by including
and consistent transparency with all relevant authorities. not only
experienced partners in new projects. We have developed a long
does this allow us to be a more successful business enterprise over
term strategic alliance with lG to build a portfolio of upstream assets
the long term, it reflects our pride in carrying out an important
across latin america and with tecpetrol (the affiliate of techint) to
mission in the right way. the men and women of Geopark care
acquire new projects in Brazil. the international Finance corporation
passionately about how our company acts – both internally
(iFc) of the World Bank is a long term principal shareholder of (and
and externally – and we all consider our culture to be our core asset
sometimes lender to) Geopark, and has also joined us as a working
and the prime source of our past success and future opportunity.
10 annual report 2013
lEttEr to sHarEHoldErs
lEttEr to sHarEHoldErs
the world is continuously moving in a more regulated direction
and, our thanks and appreciation to our shareholders – long term
with higher expectations, and to be able to operate in this new
and new – who have joined us, believed in our project and
environment is a fundamental part of business today. We believe
supported our efforts. as always, your comments and
that Geopark’s ability to meet these challenges and perform to
recommendations are welcome and appreciated. We invite you to
or beyond these ever increasing standards represents a competitive
always visit us in the field or at any of our offices to better know
advantage for the future. For example, the manner of, results from,
us and learn first-hand how we work.
and impact on the communities of our overall work in chile provided
the rationale and support for the government and regional
Following this letter, please find the Form 20-F annual report which
community to allow us to successfully expand our project into new
provides a more comprehensive review of our activities during 2013,
areas. it can also be meaningful and fun, such as with our full
with further details and explanations and more exact clarifications
scholarships targeting young women, in the local communities near
of some of the subjects and figures generally presented in this letter.
our field operations, to enter into and study the sciences.
(please also refer to the 20-F for definitions of “adjusted EBitda”
the iFc of the World Bank, our long time shareholder, has been a
constructive force in helping us operate and manage our business in
We look forward to delivering and reporting to you on our
used herein.)
consideration of the environment and communities around us.
results in 2014.
the iFc further assists us by carrying out annual audits and physical
site visits of both our regulatory compliance and best-practices
sincerely,
approach.
thank You
again, our thanks to all the men and women in Geopark for the
Gerald E. O’Shaughnessy
company you have created, for your trust of each other and for the
chairman
unique spirit which propels us forward. our gratitude especially
extends to our relentlessly supportive families who have
all contributed mightily to who we have become and what we
will do next.
our thanks to our Board of directors for your guidance through the
year and your continuous efforts in helping Geopark improve and
grow. in addition to significant corporate governance
responsibilities, Geopark’s Board members have spent substantial
time working directly with our teams, sharing their experience, and
traveling to our different operations.
James F. Park
chief Executive officer
annual report 2013 11
2013 pErForMancE
Key Operational Results
Key Financial Results
Key Strategic Results
Oil and Gas Production
Revenues Up 35%:
Brazil Production Acquisition:
Up 20%: average oil and gas
total revenues increased
acquisition of 10% interest in
production increased to 13,517
to $338.4 million. pro forma,
Manati Field, largest producing
boepd. pro forma, annual
revenues increased to
gas field in Brazil, in May 2013
2013 production increased to
$386.9 million
(closed in March 2014)
17,098 boepd
Adjusted EBITDA up 38%:
Brazil Exploration Blocks:
74% Drilling Success:
adjusted EBitda increased to
nine new hydrocarbon blocks
39 new wells drilled (balance
$167.3 million. pro forma,
awarded in rounds 11 and
of exploration, appraisal
adjusted EBitda increased
12 in Brazil in the sergipe
and development) with 7 new
to $197.0 million
alagoas, parnaiba, potiguar and
oil and gas field discoveries
reconcavo Basins (one block
Adjusted EBITDA per
from round 12 subject to
2P Reserves Up 8%:
boe up 9%: adjusted EBitda
anp approval)
deGoyler and Mcnaughton
per boe increased to $33.9
certified 2p prMs reserves grew
Funding:
to 61.6 mmboe, with reserve
Cash Resources:
2020 Bond issued for $300
replacement of 199%.
$121.1 million at year end
million in February 2013 to
including the Manati Field
replace existing debt
(Brazil) acquisition, 2p prMs
Capital Expenditures:
and finance organic and
reserves increased by 23%
capital expenditures amounted
inorganic growth
to 70.2 mmboe
to $228.0 million including
Seismic Operations:
and $82.3 million invested
strategic alliance with
$145.7 million invested in chile
New Partnership:
approximately 1,350 sqkm
in colombia
of 3d seismic acquired in chile
and colombia
Net Income up 89%:
Tierra del Fuego Start-Up:
seismic, drilling and production
profit for the year increased
to $34.9 million
tecpetrol for new upstream
oil and gas projects in Brazil
start-up
* pro forma
12 annual report 2013
2009200820072006
Oil
Gas
17
16
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
)
d
/
e
o
b
M
(
n
o
i
t
c
u
d
o
r
p
y
l
i
a
d
e
g
a
r
e
v
a
annual report 2013 13
2010201120122013*
our strEnGtHs
KNOw-HOw
ASSETS
TRACK RECORD
strong team,
capabilities,
approach and
culture.
diversified
risk-Balanced
asset Base with
proven Value,
scale and upside.
consistent
operational and
Financial Growth /
ability to unlock
Value from assets.
CAPITAl
GROwTH PlATFORm
supporting
cash Flow,
access to Funding
and strategic
partners.
High-impact
portfolio
of organic and
new project
opportunities.
14 annual report 2013
C OlOmB I A
P E R U
p a c iFi c
o cEa n
C H IlE
B R A Z Il
A R G E N T I N A
a t l a n t i c
o cEa n
Asset Types
production
development
Exploration
unconventional
new acquisition targets
annual report 2013 15
our approacH
Geopark has been built around five fundamental
and distinct capabilities:
Explorer:
risk Management:
the ability, experience, methodology and creativity to find and
the comprehensive management approach to consistently and
develop oil and gas reserves in the subsurface – based on the best
significantly grow and build economic value per share by effective
science, solid economics and ability to take the necessary
planning, balanced work programs, cost efficiency focus, secure
managed risks.
operator:
access to capital sources, reliable communication with shareholders,
and by accommodating risk among the subsurface, funding,
organizational, market, partner/shareholder, and regulatory/political
the ability to execute in a timely manner and the know-how
to profitably drill for, produce, treat, transport and sell
our oil and gas – with the drive and persistence to find solutions,
environments.
culture:
overcome obstacles, seize opportunities and achieve results.
the commitment to build a unique performance-driven trust-based
consolidator:
culture which values and protects our shareholders, employees,
environment and communities to underpin and enhance our
long term plan for success. our s.p.E.E.d. program reflects this value
the ability and initiative to assemble the right balance and portfolio
system and represents an integrated approach to align our
of upstream assets in the right hydrocarbon basins in the right
business objectives with our core principles and responsibilities
regions with the right partners and at the right price – coupled with
and provides our competitive advantage.
the vision and skills to transform and improve value above ground.
EXPlORER
OPERATOR
CONSOlIDATOR
RISK mANAGEmENT
CUlTURE
16 annual report 2013
annual report 2013 17
ForM 20-F
18 annual report 2013
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
Form 20-F
REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2013
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
to
For the transition period from
OR
SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report
Commission file number: 001-36298
Geopark Limited
(Exact name of Registrant as specified in its charter)
Bermuda
(Jurisdiction of incorporation)
Nuestra Señora de los Ángeles 179 - Las Condes, Santiago, Chile
(Address of principal executive offices)
Pedro Aylwin
Director of Legal and Governance
GeoPark Limited
Nuestra Señora de los Ángeles 179 - Las Condes, Santiago, Chile
Phone: +56 (2) 2242 9600 - Fax: +56 (2) 2242 9600 ext. 201
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Copies to:
Maurice Blanco, Esq.
Davis Polk & Wardwell LLP
450 Lexington Avenue - New York, NY 10017
Phone: (212) 450 4000 - Fax: (212) 701 5800
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class
Common shares, par value US$0.001 per share
Name of each exchange on which registered
New York Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
(Title of Class)
Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of business covered by the annual report.
Common shares: 57,863,615
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934. x Yes No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements
for the past 90 days.*
* The registrant became subject to such requirements on February 6, 2014, and it has filed all reports so required since that date. x Yes No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to
submit and post such files). Yes No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and
large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Non-accelerated filer x
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
Large accelerated filer o
Accelerated filer o
US GAAP o
International Financial Reporting Standards as issued by
the International Accounting Standards Board x
If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow.
o
Item 17 o Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes x No
Other o
GeoPark Limited
Table of contents
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
FORWARD-LOOKING STATEMENTS
ENFORCEMENT OF JUDGMENTS
21
24
25
D. Selling shareholders
E. Dilution
F. Expenses of the issue
26
PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS 26
26
A. Directors and senior management
ITEM 10. ADDITIONAL INFORMATION
A. Share capital
B. Memorandum of association and bye-laws
161
161
161
161
161
161
165
165
165
168
168
168
168
C. Material contracts
D. Exchange controls
E. Taxation
F. Dividends and paying agents
G. Statement by experts
H. Documents on display
I. Subsidiary information
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES
168
ABOUT MARKET RISK
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 168
168
A. Debt securities
B. Warrants and rights
C. Other securities
D. American Depositary Shares
168
168
168
169
PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES 169
169
A. Defaults
B. Arrears and delinquencies
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF
SECURITY HOLDERS AND USE OF PROCEEDS
ITEM 15. CONTROLS AND PROCEDURES
A. Disclosure Controls and Procedures
B. Management’s Annual Report on Internal Control over
Financial Reporting
C. Attestation Report of the Registered Public Accounting Firm
D. Changes in Internal Control over Financial Reporting
ITEM 16. [RESERVED]
ITEM 16A. Audit committee financial expert
ITEM 16B. Code of Conduct
ITEM 16C. Principal Accountant Fees and Services
ITEM 16D. Exemptions from the listing standards for audit committees
ITEM 16E. Purchases of equity securities by the issuer and
affiliated purchasers
ITEM 16F. Change in registrant’s certifying accountant
ITEM 16G. Corporate governance
ITEM 16H. Mine safety disclosure
PART III
ITEM 17. Financial statements
ITEM 18. Financial statements
ITEM 19. Exhibits
Glossary of oil and natural gas terms
169
169
169
169
169
169
169
169
169
169
169
170
171
171
171
172
173
173
173
173
176
B. Advisers
C. Auditors
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
A. Offer statistics
B. Method and expected timetable
ITEM 3. KEY INFORMATION
A. Selected financial data
B. Capitalization and indebtedness
C. Reasons for the offer and use of proceeds
D. Risk factors
ITEM 4. INFORMATION ON THE COMPANY
A. History and development of the company
B. Business overview
C. Organizational structure
D. Property, plant and equipment
ITEM 4A. UNRESOLVED STAFF COMMENTS
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
A. Operating results
B. Liquidity and capital resources
C. Research and development, patents and licenses, etc.
D. Trend information
E. Off-balance sheet arrangements
F. Tabular disclosure of contractual obligations
G. Safe harbor
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A. Directors and senior management
B. Compensation
C. Board practices
D. Employees
26
26
26
26
26
26
26
34
35
35
61
61
64
125
125
125
126
126
142
147
147
147
147
147
148
148
153
155
156
E. Share ownership
157
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 157
157
A. Major shareholders
B. Related party transactions
C. Interests of Experts and Counsel
ITEM 8. FINANCIAL INFORMATION
A. Consolidated statements and other financial information
B. Significant changes
ITEM 9. THE OFFER AND LISTING
A. Offering and listing details
B. Plan of distribution
C. Markets
20
GeoPark 20F
158
160
160
160
161
161
161
161
161
Presentation of Financial and Other Information
Certain definitions
Unless otherwise indicated or the context otherwise requires, all references
in this annual report to:
“Chile” are to the Republic of Chile;
“Colombia” are to the Republic of Colombia;
“Brazil” are to the Federative Republic of Brazil;
“GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words
“Argentina” are to the Argentine Republic;
of a similar effect, are to GeoPark Limited (formerly GeoPark Holdings
“Peru” are to the Republic of Peru;
Limited), an exempted company incorporated under the laws of Bermuda,
“US$” and “U.S. dollars” are to the official currency of the United States
together with its consolidated subsidiaries;
of America;
“Agencia” are to GeoPark Latin America Limited Agencia en Chile, an
“Ch$” and “Chilean pesos” are to the official currency of Chile;
established branch, under the laws of Chile, of GeoPark Latin America Limited,
“Col$” and “Colombian pesos” are to the official currency of Colombia;
an exempted company incorporated under the laws of Bermuda;
“GBP” are to the official currency of the United Kingdom;
“GeoPark Latin America” are to our subsidiary GeoPark Latin America Limited,
“AR$” and “Argentine pesos” are to the official currency of Argentina;
an exempted company incorporated under the laws of Bermuda;
“real,” “reais” and “R$” are to the official currency of Brazil;
“GeoPark Fell” are to our subsidiary GeoPark Fell SpA., a sociedad por acciones
“IFRS” are to International Financial Reporting Standards as adopted by
incorporated under the laws of Chile;
the International Accounting Standards Board, or IASB;
“GeoPark Chile” are to our subsidiary GeoPark Chile S.A., a sociedad anónima
“ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels
cerrada incorporated under the laws of Chile;
Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis );
“GeoPark Colombia” are prior to our internal corporate reorganization of our
“CNPE” are to the Brazilian National Council on Energy Policy (Conselho
Colombian operations, to our subsidiary GeoPark Colombia S.A., a sociedad
Nacional de Política Energética);
anónima cerrada incorporated under the laws of Chile and subsequent to
“ANH” are to the Colombian National Hydrocarbons Agency (Agencia
such reorganization, to GeoPark Colombia Coöperatie U.A., a cooperative duly
Nacional de Hidrocarburos);
incorporated under the laws of the Netherlands;
“ENAP” are to the Chilean National Petroleum Company (Empresa Nacional
“GeoPark Colombia S.A.S.” are to our subsidiary GeoPark Colombia S.A.S., a
de Petróleo)
sociedad anónima simplificada incorporated under the laws of Colombia,
“economic interest” means an indirect participation interest in the net
which absorbed Winchester, Luna and Cuerva and their Colombian branches
revenues from a given block based on bilateral agreements with the
by merger and assumed all rights and obligations of each;
concessionaires; and
“Winchester” are to our subsidiary Winchester Oil and Gas S.A., now GeoPark
“working interest” means the right granted to the lessee of a property to
Colombia PN S.A. Sucursal Colombia, a Colombian branch of a sociedad
explore for and to produce and own oil, gas, or other minerals. The working
anónima incorporated under the laws of Panama, which merged into GeoPark
interest owners bear the exploration, development and operating costs on
Colombia S.A.S.;
either a cash, penalty or carried basis.
“Luna” are to our subsidiary La Luna Oil Company Limited S.A., a sociedad
anónima incorporated under the laws of Panama, which merged into GeoPark
Colombia S.A.S.;
“Cuerva” are to our subsidiary GeoPark Cuerva LLC, formerly known as
Hupecol Caracara LLC, a limited liability company incorporated under the
laws of the state of Delaware, which merged into GeoPark Colombia S.A.S.;
“LGI” are to LG International Corp., a company incorporated under the
laws of Korea;
“Panoro” are to Panoro Energy do Brasil Ltda., a limited liability company
incorporated under the laws of Brazil and a subsidiary of Panoro Energy
ASA, a company incorporated under the laws of Norway, with assets in Brazil
and Africa;
“Rio das Contas” are to Rio das Contas Produtora de Petróleo Ltda., a limited
liability company incorporated under the laws of Brazil;
our “Brazil Acquisitions” are to our Rio das Contas acquisition, which we
completed on March 31, 2014, our award of two new concessions by the ANP,
which are subject to confirmation of qualification requirements, and our
award of seven new concessions by the ANP, in Brazil;
GeoPark 20F
21
Financial statements
Financial statements
Our consolidated financial statements
This annual report includes our audited consolidated financial statements
• The combined statement of financial position for GeoPark as of December
31, 2013 to give pro forma effect to the acquisition of Rio das Contas as if
such acquisition had occurred as of December 31, 2013.
as of December 31, 2013 and 2012 and for each of the years ended December
We refer to these pro forma financial statements as our Unaudited Condensed
31, 2013, 2012 and 2011, or our Annual Consolidated Financial Statements.
Combined Pro Forma Financial Data. For purposes of preparing our
Our Consolidated Financial Statements are presented in U.S. dollars and have
certain adjustments to the historical and pre-acquisition financial information
been prepared in accordance with IFRS, as issued by the International
of Rio das Contas. See “Item 3. Key Information—A. Selected financial data—
Accounting Standards Board (“IASB”).
Unaudited Condensed Combined Pro Forma Financial Data.” Our Unaudited
Unaudited Condensed Combined Pro Forma Financial Data, we have made
Our Annual Consolidated Financial Statements have been audited by Price
informational purposes only and does not purport to represent our results of
Waterhouse & Co. S.R.L., Argentina, a member firm of PricewaterhouseCoopers
operations or financial condition had our acquisition of Rio das Contas
Network, or PwC, an independent registered public accounting firm, as stated
occurred at the respective dates indicated above.
Condensed Combined Pro Forma Financial Data is presented for
in their report included elsewhere in this annual report.
Our fiscal year ends December 31. References in this annual report to a fiscal
read in conjunction with “Item 5. Operating and Financial Review and
year, such as “fiscal year 2013,” relate to our fiscal year ended on December
Prospects,” our Consolidated Financial Statements and the Rio das Contas
Our historical financial information and pro forma financial data should be
31 of that calendar year.
Consolidated Financial Statements, including, in each case, the
accompanying notes thereto, included elsewhere in this annual report.
Acquisition of Rio das Contas
On May 14, 2013, we agreed to acquire all of the issued and outstanding
shares of Rio das Contas from Panoro, for a total cash consideration of
US$140 million subject to certain purchase price and easement adjustments.
Non IFRS financial measures
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-IFRS financial measure that is used
The closing of the acquisition was subject to certain conditions, including
by management and external users of our financial statements, such as
approval by the ANP, among others. We closed the acquisition on March
industry analysts, investors, lenders and rating agencies.
31, 2014.
References to Rio das Contas Consolidated Financial Statements are to the Rio
income tax, depreciation, amortization and certain non-cash items such as
das Contas Audited Consolidated Financial Statements. Our results as
impairments and write-offs of unsuccessful exploration and evaluation assets,
reflected in our Consolidated Financial Statements included in this annual
accrual of stock options and stock awards and bargain purchase gain on
report are not comparable to our results for any period following the future
date on which we consolidate the results of Rio das Contas.
acquisition of subsidiaries. Adjusted EBITDA is not a measure of profit or cash
flows as determined by IFRS.
We define Adjusted EBITDA as profit for the period before net finance cost,
Pro forma financial data
In light of our Rio das Contas acquisition that closed on March 31, 2014,
We believe Adjusted EBITDA is useful because it allows us to more effectively
evaluate our operating performance and compare the results of our
we include in this annual report Unaudited Condensed Combined Pro Forma
operations from period to period without regard to our financing methods
Financial Data to illustrate:
or capital structure. We exclude the items listed above from profit for the
period in arriving at Adjusted EBITDA because these amounts can vary
• The combined results of operations for GeoPark for the year ended
substantially from company to company within our industry depending upon
December 31, 2013 to give pro forma effect to the acquisition of Rio das
accounting methods and book values of assets, capital structures and the
Contas as if such transaction had occurred as of January 1, 2013; and
method by which the assets were acquired. Adjusted EBITDA should not be
22
GeoPark 20F
considered as an alternative to, or more meaningful than, profit for the period
or cash flows from operating activities as determined in accordance with IFRS
Market share and other information
Market data, other statistical information, information regarding recent
or as an indicator of our operating performance or liquidity. Certain items
developments in Chile, Colombia, Brazil and Argentina and certain industry
excluded from Adjusted EBITDA are significant components in understanding
forecast data used in this annual report were obtained from internal reports
and assessing a company’s financial performance, such as a company’s cost
and studies, where appropriate, as well as estimates, market research,
of capital and tax structure and significant and/or recurring write-offs, as
publicly available information (including information available from the SEC
well as the historic costs of depreciable assets, none of which are components
website) and industry publications. Industry publications generally state that
of Adjusted EBITDA. Our computation of Adjusted EBITDA may not be
the information they include has been obtained from sources believed to
comparable to other similarly titled measures of other companies.
be reliable, but that the accuracy and completeness of such information is
not guaranteed. Similarly, internal reports and studies, estimates and market
For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit
research, which we believe to be reliable and accurately extracted by us
for the year, see Note 6 to our Annual Consolidated Financial Statements
for use in this annual report, have not been independently verified. However,
as of and for the years ended 2012 and 2013, included in this annual report.
we believe such data is accurate and agree that we are responsible for the
accurate extraction of such information from such sources and its correct
We have also included Pro Forma Adjusted EBITDA in this annual report to
reproduction in this annual report.
show our Adjusted EBITDA after giving pro forma effect to our Rio das Contas
acquisition that closed on March 31, 2014. For a reconciliation of Pro Forma
In addition, we have provided definitions for certain industry terms used
Adjusted EBITDA to the IFRS financial measure of pro forma profit for the year,
in this annual report in the “Glossary of oil and natural gas terms” included as
see “Item 3. Key Information—A. Selected financial data—Unaudited
Appendix A to this annual report.
Condensed Combined Pro Forma Financial Data—Note 2—Reconciliations.”
Rounding
We have made rounding adjustments to some of the figures included in this
annual report. Accordingly, numerical figures shown as totals in some tables
may not be an arithmetic aggregation of the figures that precede them.
Oil and gas reserves and production information
D&M Reserves Report
The information included in this annual report regarding estimated quantities
of proved reserves in Brazil, Chile, Colombia and Argentina is derived, in
part, from estimates of the proved reserves as of December 31, 2013.
The reserves estimates are derived from the report prepared by DeGolyer and
MacNaughton, or D&M, independent reserves engineers, or the D&M Reserves
Report, included as an exhibit to this annual report, prepared by D&M. The
D&M Reserves Report was prepared by D&M for us and presents estimates as
of December 31, 2013 of oil and gas reserves located in the Fell Block in Chile,
the Del Mosquito, Cerro Doña Juana and Loma Cortaderal Blocks in Argentina
and the La Cuerva, Llanos 32, Llanos 34, Llanos 17 and Yamú Blocks in
Colombia and the interests held through Rio das Contas, which we acquired
on March 31, 2014, in Brazil in BCAM-40 Concession (Manatí).
Information about our reserves only presents reserves estimates for our
working interests in the blocks covered by such report as of the date of such
report. These estimates are included in this annual report in reliance upon
the authority of D&M as an expert in these matters.
GeoPark 20F
23
Forward-looking Statements
This annual report contains statements that constitute forward-looking
• market or business conditions and fluctuations in global and local demand
statements. Many of the forward-looking statements contained in this annual
for energy;
report can be identified by the use of forward-looking words such as
• the direct or indirect impact on our business resulting from terrorist
“anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,”
incidents or responses to such incidents, including the effect on the
“estimate” and “potential,” among others.
availability of and premiums on insurance; and
• other factors discussed under “Item 3. Key Information—D. Risk factors” in
Forward-looking statements appear in a number of places in this annual
this annual report.
report and include, but are not limited to, statements regarding our intent,
belief or current expectations. Forward-looking statements are based on
Forward-looking statements speak only as of the date they are made, and
our management’s beliefs and assumptions and on information currently
we do not undertake any obligation to update them in light of new
available to our management. Such statements are subject to risks and
information or future developments or to release publicly any revisions to
uncertainties, and actual results may differ materially from those expressed
these statements in order to reflect later events or circumstances or to
or implied in the forward-looking statements due to various factors,
reflect the occurrence of unanticipated events.
including, but not limited to, those identified under the section “Item 3.
Key Information—D. Risk factors” in this annual report. These risks and
uncertainties include factors relating to:
• operating risks, including equipment failures and the amounts and timing
of revenues and expenses;
• termination of, or intervention in, concessions, rights or authorizations
granted by the Chilean, Colombian, Brazilian and Argentine governments
to us;
• uncertainties inherent in making estimates of our oil and natural gas data;
• the volatility of oil and natural gas prices;
• environmental constraints on operations and environmental liabilities
arising out of past or present operations;
• discovery and development of oil and natural gas reserves;
• project delays or cancellations;
• financial market conditions and the results of financing efforts;
• political, legal, regulatory, governmental, administrative and economic
conditions and developments in the countries in which we operate;
• fluctuations in inflation and exchange rates in Chile, Colombia, Brazil,
Argentina and in other countries in which we may operate in the future;
• availability and cost of drilling rigs, production equipment, supplies,
personnel and oil field services;
• contract counterparty risk;
• projected and targeted capital expenditures and other cost commitments
and revenues;
• weather and other natural phenomena;
• the impact of recent and future regulatory proceedings and changes,
changes in environmental, health and safety and other laws and regulations
to which our company or operations are subject, as well as changes in the
application of existing laws and regulations;
• current and future litigation;
• our ability to successfully identify, integrate and complete acquisitions
• our ability to retain key members of our senior management and key
technical employees;
• competition from other similar oil and natural gas companies;
24
GeoPark 20F
Enforcement of Judgments
We are incorporated as an exempted company with limited liability under
such director, officer or auditor may be guilty in relation to the company.
the laws of Bermuda, and substantially all of our assets are located in Chile,
Section 98 further provides that a Bermuda company may indemnify its
Colombia, Brazil and Argentina. In addition, most of our directors and
directors, officers and auditors against any liability incurred by them in
executive officers reside outside the United States, and all or a substantial
defending any proceedings, whether civil or criminal, in which judgment
portion of the assets of such persons are located outside the United States.
is awarded in their favor or in which they are acquitted or granted relief by
As a result, it may be difficult for investors to effect service of process on
the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda
those persons in the United States or to enforce in the United States
Companies Act.
judgments obtained in U.S. courts against us or those persons based on the
civil liability provisions of the U.S. securities laws.
Our bye-laws contain provisions whereby we and our shareholders waive any
claim or right of action that we have, both individually and on our behalf,
There is no treaty in force between the United States and Bermuda providing
against any director or officer in relation to any action or failure to take action
for the reciprocal recognition and enforcement of judgments in civil and
by such director or officer, except in respect of any fraud or dishonesty of
commercial matters. As a result, whether a U.S. judgment would be
such director or officer. We may also indemnify our directors and officers in
enforceable in Bermuda against us or our directors and officers depends on
their capacity as directors and officers for any loss arising or liability attaching
whether the U.S. court that entered the judgment is recognized by the
to them by virtue of any rule of law in respect of any negligence, default,
Bermuda court as having jurisdiction over us or our directors and officers,
breach of trust of which a director or officer may be guilty in relation to the
as determined by reference to Bermuda conflict of law rules and the
company other than in respect of his own fraud or dishonesty. We have
judgment is not contrary to public policy in Bermuda, has not been obtained
entered into customary indemnification agreements with our directors.
by fraud in proceedings contrary to natural justice and is not based on an
error in Bermuda law. A judgment debt from a U.S. court that is final and for
No treaty exists between the United States and Chile for the reciprocal
a sum certain based on U.S. federal securities laws will not be enforceable
recognition and enforcement of foreign judgments. Chilean courts, however,
in Bermuda unless the judgment debtor had submitted to the jurisdiction of
have enforced valid and conclusive judgments for the payment of money
the U.S. court, and the issue of submission and jurisdiction is a matter of
rendered by competent U.S. courts by virtue of the legal principles of
Bermuda (not U.S.) law.
reciprocity and comity, subject to review in Chile of the U.S. judgment in
order to ascertain whether certain basic principles of due process and public
An action brought pursuant to a public or penal law, the purpose of which
policy have been respected, without retrial or review of the merits of the
is the enforcement of a sanction, power or right at the instance of the state in
subject matter. If a U.S. court grants a final judgment, enforceability of this
its sovereign capacity, may not be entertained by a Bermuda court. Certain
judgment in Chile will be subject to obtaining the relevant exequatur (i.e.,
remedies available under the laws of U.S. jurisdictions, including certain
recognition and enforcement of the foreign judgment) according to Chilean
remedies under U.S. federal securities laws, may not be available under
civil procedure law in effect at that time, and depending on certain factors
Bermuda law or enforceable in a Bermuda court, as they may be contrary to
(the satisfaction or non-satisfaction of which would be determined by the
Bermuda public policy. Further, no claim may be brought in Bermuda against
us or our directors and officers in the first instance for violations of U.S.
Supreme Court of Chile). Currently, the most important of such factors are:
the existence of reciprocity (if it can be proved that there is no reciprocity in
federal securities laws because these laws have no extraterritorial jurisdiction
the recognition and enforcement of the foreign judgment between the
under Bermuda law and do not have force of law in Bermuda. A Bermuda
United States and Chile, that judgment would not be enforced in Chile); the
court may, however, impose civil liability on us or our directors and officers
absence of any conflict between the foreign judgment and Chilean laws
if the facts alleged in a complaint constitute or give rise to a cause of action
(excluding for this purpose the laws of civil procedure) and Chilean public
under Bermuda law. However, section 281 of the Bermuda Companies
policy; the absence of a conflicting judgment by a Chilean court relating to
Act allows a Bermuda court, in certain circumstances, to relieve officers and
the same parties and arising from the same facts and circumstances; the
directors of Bermuda companies of liability for acts of negligence, breach
Chilean court’s determination that the U.S. courts had jurisdiction, that
of duty or trust or other defaults.
process was appropriately served on the defendant and that the defendant
was afforded a real opportunity to appear before the court and defend its
Section 98 of the Bermuda Companies Act provides generally that a Bermuda
case; and the judgment being final under the laws of the country in which it
company may indemnify its directors, officers and auditors against any
was rendered. Nonetheless, we have been advised by our Chilean counsel
liability which by virtue of any rule of law would otherwise be imposed on
that there is doubt as to the enforceability in original actions in Chilean courts
them in respect of any negligence, default, breach of duty or breach of trust,
of liabilities predicated solely upon U.S. federal or state securities laws.
except in cases where such liability arises from fraud or dishonesty of which
GeoPark 20F
25
Part I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
We have not included selected consolidated financial data as of and for the
years ended December 31, 2009 and 2010 in the tables below. We have not
presented financial data prior to this period as we qualify as an emerging
growth company under the Jumpstart Our Business Startups Act of 2012 or
the JOBS Act and we make use of an existing accommodation for specified
reduced reporting, requiring only two years of audited financial statements at
the time of our initial public offering. As a result we have not prepared
financial information in IFRS prior to December 31, 2011.
A. Directors and senior management
Not applicable.
B. Advisers
Not applicable.
C. Auditors
Not applicable.
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
A. Offer statistics
Not applicable.
B. Method and expected timetable
Not applicable.
ITEM 3. KEY INFORMATION
A. Selected financial data
We have derived our selected historical statement of income, balance sheet
and cash flow data as of December 31, 2013 and 2012 and for the years
ended December 31, 2013, 2012 and 2011 from our Annual Consolidated
Financial Statements included elsewhere in this annual report, which have
been audited by PwC. We have derived our selected balance sheet data
as of December 31, 2011 from our Annual Consolidated Financial Statements
not included in this annual report.
We maintain our books and records in U.S. dollars and prepare our
consolidated financial statements in accordance with IFRS.
This financial information should be read in conjunction with “Presentation
of Financial and Other Information,” “Item 5. Operating and Financial Review
and Prospects” and our Consolidated Financial Statements and the related
notes thereto, included elsewhere in this annual report.
The selected historical financial data set forth in this section does not include
any results or other financial information of our Colombian acquisitions prior
to their incorporation into our financial statements, or our Brazil Acquisitions.
26
GeoPark 20F
Statement of Income Data
For the year ended December 31,
2013
2012
2011
(in thousands of US$, except per share numbers)
Revenue
Net oil sales
Net gas sales
Net revenue
Production costs
Gross profit(1)
Exploration costs
Administrative costs
Selling expenses
Other operating income/(expense)
Operating profit
Financial income
Financial expenses
315,435
22,918
338,353
(179,643)
158,710
(16,254)
46,584)
(17,252)
5,344
83,964
4,893
(38,769)
Bargain purchase gain on acquisition of subsidiaries
—
Profit before tax
Income tax
Profit for the year
Non-controlling interest
Profit attributable to owners of the Company
Earnings per share for profit attributable
to owners of the Company - Basic
Earnings per share for profit attributable
to owners of the Company - Diluted(2)
Weighted average common shares
50,088
(15,154)
34,934
12,922
22,012
0.50
0.47
221,564
28,914
250,478
(129,235)
121,243
(27,890)
(28,798)
(24,631)
823
40,747
892
(17,200)
8,401
32,840
(14,394)
18,446
6,567
11,879
0.28
0.27
73,508
38,072
111,580
(54,513)
57,067
(10,066)
(18,232)
(2,546)
(439)
25,784
162
(13,678)
—
12,268
(7,206)
5,062
5,008
54
0.00
0.00
outstanding - Basic
43,603,846
42,673,981
41,912,685
Weighted average common shares
outstanding - Diluted(2)
46,532,049
44,109,305
43,917,167
(1) Gross profit is defined as net revenue minus production costs.
(2) See Note 18 to our Annual Consolidated Financial Statements.
GeoPark 20F
27
Balance Sheet Data
As of December 31,
(in thousands of US$)
Assets
Non-current assets
Property, plant and equipment
Prepaid taxes
Other financial assets
Deferred income tax
Prepayments and other receivables
Total non-current assets
Current assets
Other financial assets
Inventories
Trade receivables
Prepayments and other receivables
Prepaid taxes
Cash at bank and in hand
Total current assets
Total assets
Share capital
Share premium
Other
Equity attributable to owners of the Company
Equity attributable to non-controlling interest
Total equity
Liabilities
Non-current liabilities
Borrowings
Provisions for other long-term liabilities
Trade and other payables
Deferred income tax
Total non-current liabilities
Current liabilities
Borrowings
Current income tax
Trade and other payables
Total current liabilities
Total liabilities
2013
2012
2011
595,446
11,454
5,168
13,358
6,361
631,787
—
8,122
42,628
35,764
6,979
121,135
214,628
846,415
44
120,426
150,371
270,841
95,116
365,957
290,457
33,076
8,344
23,087
354,964
26,630
7,231
91,633
125,494
480,458
457,837
10,707
7,791
13,591
510
490,436
—
3,955
32,271
49,620
3,443
48,292
137,581
628,017
43
116,817
122,561
239,421
72,665
312,086
165,046
25,991
—
17,502
208,539
27,986
7,315
72,091
107,392
315,931
224,635
2,957
5,226
450
707
233,975
3,000
584
15,929
24,984
147
193,650
238,294
472,269
43
112,231
96,615
208,889
41,763
250,652
134,643
9,412
—
13,109
157,164
30,613
187
33,653
64,453
221,617
Total equity and liabilities
846,415
628,017
472,269
28
GeoPark 20F
Cash Flow Data
For the year ended December 31,
2013
2012
2011
(in thousands of US$)
Cash provided by (used in)
Operating activities
Investing activities
Financing activities
Net increase (decrease) in cash
Other Financial Data
140,094
(221,299)
164,018
82,813
131,802
(303,507)
26,375
(145,330)
For the year ended December 31,
2013
2012
Adjusted EBITDA(1) (US$ thousands)
Adjusted EBITDA margin(2)
Adjusted EBITDA per boe(3)
167,253
49.4%
33.9
121,404
48.5%
31.1
68,763
(101,276)
131,739
99,226
2011
63,391
56.8%
22.9
(1) Adjusted EBITDA is a non-IFRS financial measure. For a definition of Adjusted EBITDA and other information relating
to this measure, see “Presentation of Financial and Other Information—Financial statements—Non-IFRS financial
measures.” For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year, see Note 6 to our
Annual Consolidated Financial Statements as of and for the years ended 2012 and 2013, included in this annual report.
(2) Adjusted EBITDA margin is defined as Adjusted EBITDA divided by net revenue.
(3) Adjusted EBITDA per boe is defined as Adjusted EBITDA divided by total production expressed in boe.
GeoPark 20F
29
Unaudited Condensed Combined
Pro Forma Financial Data
The following Unaudited condensed combined pro forma income statement
Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by
data below is presented as if the acquisitions of Rio das Contas had occurred
management and external users of our financial statements, such as industry
as of January 1, 2013. The Unaudited condensed combined pro forma
analysts, investors, lenders and rating agencies. We define Adjusted EBITDA
statement of financial position is presented below as if our Rio das Contas
as profit for the period before net finance cost, income tax, depreciation,
acquisition had occurred on December 31, 2013.
amortization and certain non-cash items such as impairments and write-off
The Unaudited Condensed Combined Pro Forma Financial Data is based on
awards and bargain purchase gain on acquisition of subsidiaries.
the following financial statements included elsewhere in this annual report
and should be read in conjunction with them and the notes thereto:
Adjusted EBITDA is not a measure of profit or cash flows as determined
• our Annual Audited Consolidated Financial Statements; and
by IFRS and may not be comparable to other similarly-titled measures of
• the Rio das Contas Audited Consolidated Financial Statements;
other companies.
of exploration and evaluation assets, accrual of stock options and stock
Rio das Contas was acquired on March 31, 2014. The Rio das Contas pre-
acquisition income statement data for the year ended December 31, 2013
and the pre-acquisition statement of financial position data as of December
31, 2013 have been extracted from the Rio das Contas Audited Consolidated
Financial Statements.
The preparation of the Unaudited Condensed Combined Pro Forma Financial
Data includes the impact of certain purchase accounting adjustments, such
as estimated changes in depreciation expense on acquired proved and
unproved properties that are expected to have a continuing impact on us.
Accordingly, the amounts shown in our Unaudited Condensed Combined
Pro Forma Financial data are not necessarily indicative of the results that
would have resulted if the acquisitions had occurred on January 1, 2013 or
that may result in the future.
The Unaudited Condensed Combined Pro Forma Financial Data is for
informational purposes only. Because of its nature, it addresses a hypothetical
situation and it is not intended to represent or to be indicative of the
consolidated financial position or results of operations that we would have
reported had the acquisitions been completed on the dates indicated. It
should not be relied upon as representative of the historical consolidated
financial position or results of operations that would have been achieved,
or the future consolidated financial position or operating results that can be
expected. The unaudited pro forma adjustments, described in the
accompanying notes, are based on available information and certain
assumptions that management believes are reasonable for purposes of this
annual report.
30
GeoPark 20F
Unaudited Condensed Combined
Pro Forma Income Statement
(in thousands of US$)
GeoPark
Rio das Contas
adjustments
Pro Forma
For the year ended December 31, 2013
IFRS
IFRS
historical
historical
Net revenue
Production costs
Gross profit
Exploration costs
Administrative costs
Selling expenses
Other operating income
Operating profit/(loss)
Net financial result
Profit/(loss) before income tax
Income tax
Profit/(loss) for the year
Attributable to:
Owners of the Company
Non-controlling interest
Earnings per share (in US$) for profit
attributable to owners of the Company:
Basic
Diluted
Weighted average number of shares:
Basic
Diluted
Rio das Contas
acquisition(1)
Pro Forma
combined
—
(a)(12,403)
(12,403)
386,923
(214,907)
172,016
338,353
(179,643)
158,710
(16,254)
(46,584)
(17,252)
5,344
83,964
(33,876)
50,088
(15,154)
34,934
48,570
(22,861)
25,709
—
(2,021)
—
—
—
—
—
—
23,688
(12,403)
353
24,041
(4,659)
19,382
(b)(2,934)
(15,337)
(c)5,214
(10,122)
(16,254)
(48,605)
(17,252)
5,344
95,249
(36,457)
58,792
(14,599)
44,194
22,012
12,922
19,382
—
(10,122)
—
31,272
12,922
0.50
0.47
43,603,846
46,532,049
0.72
0.67
43,603,846
46,532,049
(1) See Notes to the Unaudited Condensed Combined Pro Forma Financial Data below.
GeoPark 20F
31
Unaudited Condensed Combined Pro Forma
Statement of Financial Position
(in thousands of US$)
For the year ended December 31, 2013
historical IFRS
historical IFRS
GeoPark
Rio das Contas
Pro Forma
adjustments
Rio das Contas
acquisition(1)
Pro Forma
combined
Assets
Property, plant and equipment
Other
Total non-current assets
Trade receivables
Prepayments and other receivables
Cash at bank and in hand
Other
Total current assets
Total assets
Equity
Share premium
Reserves
Other
Attributable to owners of the Company
Non-controlling interest
Total equity
Liabilities
Borrowings
Provisions for other long-term liabilities
Deferred income tax
Trade and other payables
Contingent payment
Total non-current liabilities
Trade and other payables
Borrowings
Other
Total current liabilities
Total liabilities
Total equity and liabilities
595,446
36,341
631,787
42,628
35,764
121,135
15,101
214,628
846,415
120,426
126,465
23,950
270,841
95,116
365,957
290,457
33,076
23,087
8,344
—
354,964
91,633
26,630
7,231
125,494
480,458
846,415
64,754
394
65,148
9,546
142
17,015
117
26,820
91,968
64,865
5,783
6,784
77,432
—
(d)71,512
—
71,512
—
—
(e)(77,894)
—
(77,894)
(6,382)
(f)(64,865)
(f)(5,783)
(f)(6,784)
(77,432)
—
77,432
(77,432)
731,712
36,735
768,447
52,174
35,906
60,256
15,218
163,554
932,001
120,426
126,465
23,950
270,841
95,116
365,957
—
6,671
3,247
—
—
9,918
634
—
3,984
4,618
14,536
91,968
(g)70,450
360,907
—
—
—
(h)600
39,747
26,334
8,344
600
71,050
435,932
—
—
—
—
71,050
(6,382)
92,267
26,630
11,215
130,112
566,044
932,001
(1) See Notes to the Unaudited Condensed Combined Pro Forma Financial Data below.
32
GeoPark 20F
Notes to the Unaudited Condensed Combined
Pro Forma Financial Data
Note 1
will bear a variable interest rate equal six-month LIBOR + 3.9%. The effect
Purchase price adjustments on Rio das Contas acquisition
of a 1⁄8 percent variance in the interest rate on profit for the year would be
US$0.3 million for the year ended December 31, 2013.
The purchase price allocation of our Rio das Contas acquisition is preliminary
(c) Decrease in income taxes related to foregoing adjustments. The rate
and may be subject to change. The final purchase price may result in
applied for adjustments (a) and (c) is the statutory rate in Brazil of 34%.
an adjustment to the purchase price or its allocation. Any such adjustment
will be reflected as an increase or decrease by means of working capital
The following pro forma adjustments were made to the unaudited condensed
adjustment to be determined when certain information is available.
combined pro forma statement of financial position to reflect the acquisition
(in thousands of US$)
Cost of the acquisition
Cash payment(i)
Total cost of the acquisition
Less: Book value of assets acquired
and liabilities assumed
Total book value of assets acquired
and liabilities assumed
Fair value adjustments:
Proved and unproved properties(ii)
Fair value of assets acquired and liabilities assumed
of Rio das Contas as if it had occurred on December 31, 2013:
(d) Fair value adjustment of US$71.5 million allocated to the recognition of
mineral interest.
140,100
(e) Adjustment to reflect: (i) increase in cash of US$70.5 million due to bank
140,100
indebtedness issued in connection with the acquisition; and (ii) cash payment
77,432
62,668
of US$140.1 million relating to the acquisition.
(f) Elimination of Rio das Contas equity items for consolidation purposes.
(g) Bank indebtedness of US$70.5 million incurred in connection with
the acquisition.
(h) Contingent payment of US$0.6 million relating to the acquisition. The
purchase price is adjusted for an earn-out amount equal to 45% of the net
140,100
cash flows of the BCAM-40 Concession in excess of US$25 million. The earn-
out amount is calculated over a five-year period starting January 1, 2013.
(i) Comprised of a fixed purchase price of US$140 million, increased by a
working capital adjustment of US$0.1 million calculated based on the Rio
das Contas Consolidated Financial Statements. The working capital
Note 2
adjustment is preliminary and is subject to final agreement with the seller.
Reconciliations
(ii) Reflects fair value adjustments of property, plant and equipment and
the recognition of mineral interest.
Reconciliation of pro forma Adjusted EBITDA to the IFRS financial measure of
pro forma profit for the year
The following pro forma adjustments were made to the unaudited condensed
combined pro forma income statement for the year ended December 31,
2013 to reflect the acquisition of Rio das Contas as if it had occurred on
(in thousands of US$)
January 1, 2013:
(a) Additional depreciation expense resulting from the increased basis of
property, plant and equipment acquired of US$9.5 million for the year ended
Pro Forma profit for the year
attributable to owners of the Company
Pro Forma non-controlling interest
December 31, 2013. Also, the accounting policy for depreciation of oil
Pro Forma profit for the year
and gas properties was adjusted to conform to our policy (which is based
Pro Forma income tax
on commercial proved and probable reserves) resulting in additional
depreciation expense of US$2.9 million for the year ended December 31,
2013.
Pro Forma net finance results
Pro Forma others(i)
Pro Forma impairment and write off of unsuccessful efforts
(b) Interest expense on US$70.5 million credit facility incurred in connection
Pro Forma accrual of stock options and stock awards
with the acquisition is calculated using an effective interest rate of 4.2% for
Pro Forma depreciation
the year ended December 31, 2013. The loan, which is secured by the benefits
Pro Forma Adjusted EBITDA
GeoPark receives under the Purchase and Sale Agreement for Natural
Gas with Petrobras, will mature five years from the date of disbursement and
(i) Includes capitalized costs for the year ended December 31, 2013.
For the year ended
December 31, 2013
31,272
12,922
44,194
14,599
36,457
(7,040)
10,962
9,167
89,724
198,062
GeoPark 20F
33
Reconciliation of Rio das Contas historical Adjusted EBITDA to the IFRS
exchange rate for the purchase of U.S. dollars as reported by the Central Bank
measure of Rio das Contas historical profit for the year
of Brazil was R$2.2257 per U.S. dollar.
(in thousands of US$)
December 31, 2013
rate during the months indicated.
For the year ended
The following table presents the monthly high and low representative market
Recent exchange rates of real per U.S. dollar
Low
High
Rio das Contas historical profit for the year
Income tax
Net financial result
Depreciation
19,382
4,659
(353)
7,121
Month:
October 2013
Rio das Contas historical Adjusted EBITDA
30,809
November 2013
Exchange rates
In Chile, Colombia and Argentina, our functional currency is the U.S. dollar.
In Brazil, our functional currency is the real .
December 2013
January 2014
February 2014
March 2014
April 2014 (through April 25, 2014)
The Brazilian foreign exchange system allows the purchase and sale of foreign
currency and the international transfer of real by any person or legal entity,
Source: Central Bank of Brazil.
regardless of the amount, subject to certain regulatory procedures.
2.1611
2.2426
2.3102
2.3335
2.3334
2.2603
2.1974
2.2123
2.3362
2.3817
2.4397
2.4238
2.3649
2.2811
Since 1999, the Brazilian Central Bank has allowed the U.S. dollar-real
market rate for each of the five most recent years, calculated by using
exchange rate to float freely, and, since then, the U.S. dollar- real exchange
the average of the exchange rates on the last day of each month during the
rate has fluctuated considerably.
period, and the representative year-end market rate for each of the five
The following table presents the average R$ per U.S. dollar representative
Our operations in Brazil account for 12% of our consolidated assets and 21%
most recent years.
of our production each on a pro forma basis, after giving effect to our Rio
Real per U.S. dollar
Average Period-end
das Contas acquisition, which closed on March 31, 2014. This portion of our
Period:
business is exposed to losses that may arise from currency fluctuation.
In the past, the Brazilian Central Bank has occasionally intervened to control
unstable movements in foreign exchange rates. We cannot predict whether
the Brazilian Central Bank or the Brazilian government will continue to permit
2009
2010
2011
2012
the real to float freely or will intervene in the exchange rate market through
First quarter 2013
the return of a currency band system or otherwise. The real may depreciate
or appreciate substantially against the U.S. dollar. Furthermore, Brazilian law
Second quarter 2013
Third quarter 2013
provides that, whenever there is a serious imbalance in Brazil’s balance of
Fourth quarter 2013
payments or there are serious reasons to foresee a serious imbalance,
First quarter 2014
temporary restrictions may be imposed on remittances of foreign capital
Second quarter 2014 (through April 25, 2014)
abroad. We cannot assure you that such measures will not be taken by
the Brazilian government in the future. See “—D. Risk factors—Risks relating
Source: Central Bank of Brazil.
to our business—Our results of operations could be materially adversely
1.9936
1.7593
1.6746
1.9550
1.9964
2.0700
2.2889
2.2735
2.3409
2.2331
1.7412
1.6662
1.8758
2.0435
2.0138
2.2156
2.2300
2.3426
2.2630
2.2325
affected by fluctuations in foreign currency exchange rates.”
Exchange rate fluctuation may affect the U.S. dollar value of any distributions
The following tables show the selling rate for U.S. dollars for the periods
Risks relating to our business—Our results of operations could be materially
and dates indicated. The information in the “Average” column represents the
adversely affected by fluctuations in foreign currency exchange rates.”
we make with respect to our common shares. See “—D. Risk factors—
average of the daily exchange rates during the periods presented. The
numbers in the “Period-end” column are the quotes for the exchange rate as
of the last business day of the period in question. As of April 15, 2014, the
B. Capitalization and indebtedness
Not applicable.
34
GeoPark 20F
C. Reasons for the offer and use of proceeds
Not applicable.
• proximity and capacity of oil and natural gas pipelines and other
transportation facilities;
• the price and availability of competitors’ supplies of oil and natural gas in
D. Risk factors
Our business, financial condition and results of operations could be materially
captive market areas;
• quality discounts for oil production based, among other things, on API
and adversely affected if any of the risks described below occur. As a result,
and mercury content;
the market price of our common shares could decline, and you could lose all
• taxes and royalties under relevant laws and the terms of our contracts;
or part of your investment. This annual report also contains forward-looking
• our ability to enter into oil and natural gas sales contracts at fixed prices;
statements that involve risks and uncertainties. See “Forward-Looking
• the level of global methanol demand and inventories and changes in
Statements.” The risks below are not the only ones facing our Company.
the uses of methanol;
Additional risks not currently known to us or that we currently deem
• the price and availability of alternative fuels; and
immaterial may also adversely affect us.
• future changes to our hedging policies.
Risks relating to our business
These factors and the volatility of the energy markets make it extremely
difficult to predict future natural gas and oil price movements. For example,
A substantial or extended decline in oil, natural gas and methanol prices
from January 1, 2010 to December 31, 2013, NYMEX West Texas International,
may materially adversely affect our business, financial condition or results
or WTI, crude oil contracts prices ranged from a low of US$64.78 per bbl
of operations.
to a high of US$113.39 per bbl, Henry Hub natural gas average monthly spot
prices ranged from a low of US$1.82 per mmbtu to a high of US$7.51 per
The prices that we receive for our oil and natural gas production heavily
mmbtu, US Gulf methanol spot barge prices ranged from a low of US$324.61
influence our revenues, profitability, access to capital and growth rate.
per metric ton to a high of US$530.71 per metric ton and Brent spot prices
Historically, the markets for oil, natural gas and methanol (which historically
ranged from a low of US$67.18 per barrel to a high of US$128.14 per barrel.
have influenced prices for almost all of our Chilean gas sales) have been
Further, oil, natural gas and methanol prices do not necessarily fluctuate
volatile and will likely continue to be volatile in the future. International oil,
in direct relationship to each other.
natural gas and methanol prices have fluctuated widely in recent years and
may continue to do so in the future.
As of December 31, 2013, natural gas comprised 26% of our net proved
reserves. On a pro forma basis, after giving effect to our Rio das Contas
The prices that we will receive for our production and the levels of our
acquisition, which closed on March 31, 2014 natural gas comprised 47% of
production depend on numerous factors beyond our control. These factors
our net proved reserves. A decline in natural gas prices could negatively
include, but are not limited, to the following:
affect our future growth, particularly for future gas sales where we may not
• global economic conditions;
be able to secure or extend our current long-term contracts.
• changes in global supply and demand for oil, natural gas and methanol;
• the actions of the Organization of the Petroleum Exporting Countries,
or OPEC;
For the year ended December 31, 2013, 93% of our revenues, were derived
from oil. Giving effect on a pro forma basis to our Rio das Contas acquisition,
• political and economic conditions, including embargoes, in oil-producing
which closed on March 31, 2014, 81.5% of our revenues would have
countries or affecting other countries;
been derived from oil in the same period. See “Item 3. Key Information—A.
• the level of oil- and natural gas-producing activities, particularly in the
Selected financial data—Unaudited Condensed Combined Pro Forma
Middle East, Africa, Russia, South America and the United States;
Financial Data.” Because we expect that our production mix will continue
• the level of global oil and natural gas exploration and production activity;
to be weighted toward oil, our financial results are more sensitive to
• the level of global oil and natural gas inventories;
movements in oil prices.
• the price of methanol;
• availability of markets for natural gas;
Lower oil and natural gas prices may not only decrease our revenues on a
• weather conditions and other natural disasters;
per unit basis, but also may reduce the amount of oil and natural gas that we
• technological advances affecting energy production or consumption;
can produce economically. In addition, changes in oil and gas prices can
• domestic and foreign governmental laws and regulations, including
impact our valuation of reserves and, in periods of sharply lower commodity
environmental, health and safety laws and regulations;
prices, we may curtail production and capital spending projects or may defer
GeoPark 20F
35
or delay drilling wells because of lower cash flows. A substantial or extended
gas to enable us to continue to operate profitably. If we are unable to replace
decline in oil or natural gas prices would materially adversely affect our
our current and future production, the value of our reserves will decrease, and
business, financial condition and results of operations. We have historically
our business, financial condition and results of operations will be materially
not hedged our production to protect against fluctuations in the international
adversely affected.
oil prices. We may in the future consider adopting a hedging policy against
commodity price risk, when deemed appropriate and taking into account the
We derive a significant portion of our revenues from sales to a few key
size of our business and market volatility.
customers.
Unless we replace our oil and natural gas reserves, our reserves and
In Chile, 100% of our crude oil and condensate sales are made to ENAP.
production will decline over time. Our business is dependent on our
For the year ended December 31, 2013, sales to ENAP represented 42.6% of
continued successful identification of productive fields and prospects and
our revenues from oil and 39.8% of our total revenues. ENAP imports the
the identified locations in which we drill in the future may not yield oil or
majority of the oil it refines and partially supplements those imports with
natural gas in commercial quantities.
volumes supplied locally by its own operated fields and those operated by us.
The sales contract with ENAP is commonly revised every two years to reflect
Production from oil and gas properties declines as reserves are depleted,
changes in the global oil market and to adjust for ENAP’s logistics costs
with the rate of decline depending on reservoir characteristics. Accordingly,
in the Gregorio oil terminal. The current agreement was recently executed
our current proved reserves will decline as these reserves are produced.
and signed, with an initial term of 1 year, until March 2015, and it will be
For instance, based on our internal projections, we estimate that the daily
automatically extended for periods of 1 year until the expiration of the Fell
production in our Colombian blocks will peak in 2015 and decline thereafter,
Block CEOP, which is the earlier of August 24, 2032 or the date on which we
and that the daily production in the Fell Block and the Tierra del Fuego
cease exploitation of hydrocarbons in the Fell Block. However, if ENAP were to
Blocks will peak in 2016 and decline thereafter. As of December 31, 2013,
decrease or cease purchasing oil from us, or if we were unable to renew our
our reserves-to-production (or reserve life) ratio for net proved reserves
contract with ENAP at a lower sales price or at all, this could have a material
in Chile and Colombia was 3.5 years. According to estimates, if on January 1,
adverse effect on our business, financial condition and results of operations.
2014, we ceased all drilling and development and workovers, including
recompletions, refracs and workovers, our proved developed producing
In Colombia, for the year ended December 31, 2013, we made 52.5% of our
reserves base in Chile, Colombia and Argentina would decline at an annual
oil sales to Gunvor, 20.9% to Hocol S.A., or Hocol, a subsidiary of Ecopetrol,
effective rate of 50% over the first three years, including 50% during the
and 9.8% to Perenco, with Gunvor accounting for 27.8%, Hocol 11.1% and
first year. In Brazil, we estimate that daily production in the Manatí Field, in
Perenco 5.2% of our overall revenues for the same period. Our current sales
which we acquired an interest as a result of the Rio das Contas acquisition
contracts with Hocol, Perenco and Gunvor are short-term agreements. If
on March 31, 2014, will peak in 2017 and decline thereafter. We estimate
any of Hocol, Perenco or Gunvor were to decrease or cease purchasing oil
that, if on January 1, 2014, all drilling and development and workovers had
from us, or if any of them were to decide not to renew their contracts with us
ceased, including recompletions, refracs and workovers, then the proved
developed producing reserves base attributable to the Manatí Field in Brazil
or to renew them at a lower sales price, this could have a material adverse
effect on our business, financial condition and results of operations.
would have no decline in the first year, but would decline at an annual
effective rate of approximately 30% per year over the next three years.
In Brazil, following our Rio das Contas acquisition, which closed on March 31,
Our future oil and natural gas reserves and production, and therefore our
Field in Brazil will be generated from sales to Petrobras, the operator of
cash flows and income, are highly dependent on our success in efficiently
the Manatí Field, pursuant to a long-term gas off-take contract. See “Item 4.
developing our current reserves and using cost-effective methods to find or
Information on the Company—B. Business overview—Significant
acquire additional recoverable reserves. While we have had success in
agreements—Brazil—Petrobras Natural Gas Purchase Agreement.”
identifying and developing commercially exploitable deposits and drilling
locations in the past, we may be unable to replicate that success in the
There are inherent risks and uncertainties relating to the exploration and
2014, we expect that all of our revenues from the sale of gas in the Manatí
future. We may not identify any more commercially exploitable deposits or
production of oil and natural gas.
successfully drill, complete or produce more oil or gas reserves, and the
wells which we have drilled and currently plan to drill within our blocks or
Our performance depends on the success of our exploration and production
concession areas may not discover or produce any further oil or gas or may
activities and on the existence of the infrastructure that will allow us to take
not discover or produce additional commercially viable quantities of oil or
advantage of our oil and gas reserves. Oil and natural gas exploration and
36
GeoPark 20F
production activities are subject to numerous risks beyond our control,
awarded to us by the ANP to allow us to identify any potential drilling
including the risk that exploration activities will not identify commercially
locations.
viable quantities of oil or natural gas. Our decisions to purchase, explore,
develop or otherwise exploit prospects or properties will depend in part on
Our ability to drill and develop these identified potential drilling locations
the evaluation of seismic and other data obtained through geophysical,
depends on a number of factors, including oil and natural gas prices, the
geochemical and geological analysis, production data and engineering
availability and cost of capital, drilling and production costs, the availability
studies, the results of which are often inconclusive or subject to varying
of drilling services and equipment, drilling results, lease expirations, the
interpretations.
availability of gathering systems, marketing and transportation constraints,
refining capacity, regulatory approvals and other factors. Because of the
Furthermore, the marketability of any oil and natural gas production from
uncertainty inherent in these factors, there can be no assurance that
our projects may be affected by numerous factors beyond our control. These
the numerous potential drilling locations we have identified will ever be
factors include, but are not limited to, proximity and capacity of pipelines and
drilled or, if they are, that we will be able to produce oil or natural gas from
other means of transportation, the availability of upgrading and processing
these or any other potential drilling locations.
facilities, equipment availability and government laws and regulations
(including, without limitation, laws and regulations relating to prices, sale
Our business requires significant capital investment and maintenance
restrictions, taxes, governmental stake, allowable production, importing and
expenses, which we may be unable to finance on satisfactory terms or at all.
exporting of oil and natural gas, environmental protection and health and
safety). The effect of these factors, individually or jointly, cannot be accurately
The oil and natural gas industry is capital intensive and we expect to
predicted, but may have a material adverse effect on our business, financial
make substantial capital expenditures in our business and operations for the
condition and results of operations.
exploration and production of oil and natural gas reserves. We made
US$303.5 million (including US$105.3 million relating to the purchase price
There can be no assurance that our drilling programs will produce oil and
for our Colombian acquisitions) and US$228.0 million of capital expenditures
natural gas in the quantities or at the costs anticipated, or that our currently
for the years ended December 31, 2012 and 2013, respectively.
producing projects will not cease production, in part or entirely. Drilling
programs may become uneconomic as a result of an increase in our operating
In March 2014, we invested US$140 million in Brazil, subject to certain
costs or as a result of a decrease in market prices for oil and natural gas.
adjustments, to acquire Rio das Contas, which we financed through the
Our actual operating costs or the actual prices we may receive for our oil and
incurrence of a loan of US$70.5 million and cash on hand.
natural gas production may differ materially from current estimates. In
addition, even if we are able to continue to produce oil and gas, there
In 2014, we expect our total capital expenditures, excluding the purchase
can be no assurance that we will have the ability to market our oil and gas
price of our Rio das Contas acquisition, to be between US$220 million to
production. See “—Our inability to access needed equipment and
US$250 million, of which approximately 62%, 32% and 5% will be in Chile,
infrastructure in a timely manner may hinder our access to oil and natural gas
markets and generate significant incremental costs or delays in our oil and
Colombia and Brazil, respectively. We expect these capital expenditures
to include the drilling of 50 to 60 new wells (approximately 40% of which
natural gas production” below.
we expect to be exploratory wells), as well as workovers, seismic surveys
and new facility construction. In Brazil, we expect our capital expenditures
Our identified potential drilling location inventories are scheduled over
will consist of between US$5 million to US$7.5 million to finance in part
many years, making them susceptible to uncertainties that could materially
the construction of a gas compression plant in the Manatí Field (following
alter the occurrence or timing of their drilling.
our Rio das Contas acquisition, which closed on March 31, 2014) and
approximately US$0.45 million in license fee payments to the ANP relating
Our management team has specifically identified and scheduled certain
to our Round 12 concessions, with the remainder for seismic surveys in
potential drilling locations as an estimation of our future multi-year drilling
exploration blocks in the Potiguar and Recôncavo Basins.
activities on our existing acreage. As of December 31, 2013, approximately 60
of our specifically identified potential future drilling locations were attributed
The actual amount and timing of our future capital expenditures may differ
to proved undeveloped reserves in Chile and Colombia. These identified
materially from our estimates as a result of, among other things, commodity
potential drilling locations, including those without proved undeveloped
prices, actual drilling results, the availability of drilling rigs and other
reserves, represent a significant part of our growth strategy. In Brazil, we have
equipment and services, and regulatory, technological and competitive
not yet conducted seismic surveys in the seven new concession areas
developments. In response to improvements in commodity prices, we may
GeoPark 20F
37
increase our actual capital expenditures. We intend to finance our future
regulations could change in ways that could substantially increase our costs.
capital expenditures through cash generated by our operations and potential
Any such liabilities, obligations, penalties, suspensions, terminations or
future financing arrangements. However, our financing needs may require us
regulatory changes could have a material adverse effect on our business,
to alter or increase our capitalization substantially through the issuance of
financial condition or results of operations.
debt or equity securities or the sale of assets.
In addition, the terms and conditions of the agreements under which our
If our capital requirements vary materially from our current plans, we may
oil and gas interests are held generally reflect negotiations with
require further financing. In addition, we may incur significant financial
governmental authorities and can vary significantly. These agreements take
indebtedness in the future, which may involve restrictions on other financing
the form of special contracts, concessions, licenses, associations or other
and operating activities. These changes could cause our cost of doing
types of agreements. Any suspensions, terminations or regulatory changes in
business to increase, limit our ability to pursue acquisition opportunities,
respect of these special contracts, concessions, licenses, associations or other
reduce cash flow used for drilling and place us at a competitive disadvantage.
types of agreements could have a material adverse effect on our business,
A significant reduction in cash flows from operations or the availability of
financial condition or results of operations.
credit could materially adversely affect our ability to achieve our planned
growth and operating results.
Oil and gas operations contain a high degree of risk and we may not be
fully insured against all risks we face in our business.
We are subject to complex laws common to the oil and natural gas industry,
which can have a material adverse effect on our business, financial
Oil and gas exploration and production is speculative and involves a high
condition and results of operations.
degree of risk and hazards. In particular, our operations may be disrupted
by risks and hazards that are beyond our control and that are common
The oil and natural gas industry is subject to extensive regulation and
among oil and gas companies, including environmental hazards, blowouts,
intervention by governments throughout the world, including extensive
industrial accidents, occupational safety and health hazards, technical failures,
local, state and federal regulations, in such matters as the award of
labor disputes, community protests or blockades, unusual or unexpected
exploration and production interests, the imposition of specific exploration
geological formations, flooding, earthquakes and extended interruptions
and drilling obligations, allocation of and restrictions on production, price
due to weather conditions, explosions and other accidents. For example,
controls, required divestments of assets and foreign currency controls, and
in the first half of 2013 we experienced a well control incident at our
the development and nationalization, expropriation or cancellation of
Chercán 1 well in the Flamenco Block in Chile with no harm to employees or
contract rights.
property. While we were able to bring that incident under control without
injuries or environmental damage, there can be no assurance that we will
We have been required in the past, and may be required in the future,
not experience similar or more serious incidents in the future, which could
to make significant expenditures to comply with governmental laws and
result in damage to, or destruction of, wells or production facilities, personal
regulations, including with respect to the following matters:
• licenses, permits and other authorizations for drilling operations;
injury, environmental damage, business interruption, financial losses and
legal liability.
• reports concerning operations;
• compliance with environmental, health and safety laws and regulations;
While we believe that we maintain customary insurance coverage for
• drafting and implementing emergency planning;
companies engaged in similar operations, we are not fully insured against all
• plugging and abandonment costs; and
risks in our business. In addition, insurance that we do and may carry may
• taxation.
contain significant exclusions from and limitations on coverage. We may elect
not to obtain certain non-mandatory types of insurance if we believe that
Under these laws and regulations, we could be liable for, among other
the cost of available insurance is excessive relative to the risks presented.
things, personal injury, property damage, environmental damage and other
The occurrence of a significant event or a series of events against which we
types of damage. Failure to comply with these laws and regulations may
are not fully insured and any losses or liabilities arising from uninsured or
also result in the suspension or termination of our operations and subject us
underinsured events could have a material adverse effect on our business,
to administrative, civil and criminal penalties. Moreover, these laws and
financial condition or results of operations.
38
GeoPark 20F
The development schedule of oil and natural gas projects is subject to cost
be expensive to develop, purchase and implement and may not function
overruns and delays.
as expected. Such uncertainties and operating risks associated with
development projects could have a material adverse effect on our business,
Oil and natural gas projects may experience capital cost increases and
results of operations or financial condition.
overruns due to, among other factors, the unavailability or high cost of
drilling rigs and other essential equipment, supplies, personnel and oil field
Competition in the oil and natural gas industry is intense, which makes it
services. The cost to execute projects may not be properly established
difficult for us to acquire properties and prospects, market oil and natural
and remains dependent upon a number of factors, including the completion
gas and secure trained personnel.
of detailed cost estimates and final engineering, contracting and
procurement costs. Development of projects may be materially adversely
We compete with the major oil and gas companies engaged in the
affected by one or more of the following factors:
• shortages of equipment, materials and labor;
exploration and production sector, including state-owned exploration and
production companies that possess substantially greater financial and other
• fluctuations in the prices of construction materials;
resources than we do for researching and developing exploration and
• delays in delivery of equipment and materials;
production technologies and access to markets, equipment, labor and capital
• labor disputes;
• political events;
• title problems;
• obtaining easements and rights of way;
• blockades or embargoes;
• litigation;
required to acquire, develop and operate our properties. We also compete
for the acquisition of licenses and properties in the countries in which
we operate.
Our competitors may be able to pay more for productive oil and natural gas
properties and exploratory prospects and to evaluate, bid for and purchase
• compliance with governmental laws and regulations, including
a greater number of properties and prospects than our financial or
environmental, health and safety laws and regulations;
personnel resources permit. Our competitors may also be able to offer better
• adverse weather conditions;
• unanticipated increases in costs;
• natural disasters;
• accidents;
• transportation;
compensation packages to attract and retain qualified personnel than we
are able to offer. In addition, there is substantial competition for capital
available for investment in the oil and natural gas industry. As a result of each
of the aforementioned, we may not be able to compete successfully in the
future in acquiring prospective reserves, developing reserves, marketing
• unforeseen engineering and drilling complications;
hydrocarbons, attracting and retaining quality personnel or raising additional
• environmental or geological uncertainties; and
capital, which could have a material adverse effect on our business, financial
• other unforeseen circumstances.
Any of these events or other unanticipated events could give rise to delays in
development and completion of our projects and cost overruns.
condition or results of operations. See “Item 4. Information on the
Company—B. Business overview—Our competition.”
In Chile, we partner with and sell to, and may from time to time compete
with, ENAP and, to a lesser extent, some companies with operations in
For example, in 2013, the drilling and completion cost for the exploratory well
Argentina mentioned below. In Colombia, we partner with and sell to, and
Chilco x-1 in our Flamenco Block in Chile was originally estimated at US$2.6
may from time to time compete with, Ecopetrol, as well as with privately-
million, but the actual cost was approximately US$4.0 million, mainly due to
owned companies such as Pacific Rubiales, Gran Tierra, Petrominerales,
mechanical issues during the drilling as it was the first well drilled with a new
Parex Resources Colombia Ltd. Sucursal, or Parex, and Canacol, among others.
drilling rig that needed calibration at the time, leading to longer operations.
In Brazil, we partner with and sell to, and may from time to time compete
Delays in the construction and commissioning of projects or other technical
some of the Colombian companies mentioned above, which have entered
difficulties may result in future projected target dates for production
into Brazil, among others. In Argentina, we compete for resources with YPF,
being delayed or further capital expenditures being required. These projects
as well as with privately-owned companies such as Pan American Energy,
may often require the use of new and advanced technologies, which can
Pluspetrol, Tecpetrol, Chevron, Wintershall, Total, Sinopec and others.
with, Petrobras, privately-owned companies such as HRT, QGEP, Brasoil and
GeoPark 20F
39
Our estimated oil and gas reserves are based on assumptions that may
financial condition and results of operations. In addition, the shutting in of
prove inaccurate.
wells can lead to mechanical problems upon bringing the production back
on line, potentially resulting in decreased production and increased
Our oil and gas reserves estimates in Brazil (including our acquisition of Rio das
remediation costs. The exploitation and sale of oil and natural gas and liquids
Contas, which closed on March 31, 2014), Chile, Colombia and Argentina as of
will also be subject to timely commercial processing and marketing of these
December 31, 2013 are based on the D&M Reserves Report. Although classified
products, which depends on the contracting, financing, building and
as “proved reserves,” the reserves estimates set forth in the D&M Reserves Report
operating of infrastructure by third parties.
are based on certain assumptions that may prove inaccurate. D&M’s primary
economic assumptions in estimates included oil and gas sales prices determined
In Chile, we transport the crude oil we produce in the Fell Block by truck to
according to SEC guidelines, future expenditures and other economic
ENAP’s processing, storage and selling facilities at the Gregorio Refinery.
assumptions (including interests, royalties and taxes) as provided by us.
ENAP currently purchases all of the crude oil we produce in Chile. We rely
upon the continued good condition, maintenance and accessibility of
In Brazil, D&M’s estimates are also based in part on the assumption that the
the roads we use to deliver the crude oil we produce. If the condition of these
gas compression facility for the Manatí Field will be completed by 2015.
roads were to deteriorate or if they were to become inaccessible for any
Oil and gas reserves engineering is a subjective process of estimating
harm our business. For example, in January 2011, social and labor unrest
accumulations of oil and gas that cannot be measured in an exact way, and
resulted in the roads to the Gregorio Refinery being closed for two days, and
estimates of other engineers may differ materially from those set out herein.
we were unable to deliver crude oil to ENAP.
period of time, this could delay delivery of crude oil in Chile and materially
Numerous assumptions and uncertainties are inherent in estimating
quantities of proved oil and gas reserves, including projecting future rates
In the Tierra del Fuego Blocks, we will temporarily depend on the existence of
of production, timing and amounts of development expenditures and prices
continuous ferry service to be able to transport crude oil from the island of
of oil and gas, many of which are beyond our control. Results of drilling,
Tierra del Fuego to the mainland. Ferry service may be adversely affected by
testing and production after the date of the estimate may require revisions to
weather conditions, in particular by certain combinations of strong winds and
be made. For example, if we are unable to sell our oil and gas to customers,
tidal currents that may occur, which may adversely affect our ability to deliver
this may impact the estimate of our oil and gas reserves. Accordingly, reserves
the crude oil we produce in Tierra del Fuego. In the Fell Block, we depend
estimates are often materially different from the quantities of oil and gas that
on ENAP-owned gas pipelines to deliver the gas we produce to Methanex, the
are ultimately recovered, and if such recovered quantities are substantially
sole purchaser of the gas we produce. If ENAP’s pipelines were unavailable,
lower that the initial reserves estimates, this could have a material adverse
this could have a materially adverse effect on our ability to deliver and sell our
impact on our business, financial condition and results of operations.
product to Methanex, which could have a material adverse effect on our gas
sales. In addition, gas production in some areas in the Tierra del Fuego Blocks
Our inability to access needed equipment and infrastructure in a timely
and the Otway and Tranquilo Blocks could require us to build a new network
manner may hinder our access to oil and natural gas markets and
generate significant incremental costs or delays in our oil and natural
of gas pipelines in order for us to be able to deliver our product to market,
which could require us to make significant capital investments.
gas production.
Our ability to market our oil and natural gas production depends
logistics issues and limited storage capacity, which cause delays in delivery
substantially on the availability and capacity of processing facilities, oil
and transfer of title of crude oil. Such capacity issues in Colombia may require
tankers, transportation facilities (such as pipelines, crude oil unloading
us to transport crude from our Colombian operations via truck, which may
stations and trucks) and other necessary infrastructure, which may be owned
increase the costs of those operations. Road infrastructure is limited in
and operated by third parties. Our failure to obtain such facilities on
certain areas in which we operate, and certain communities have used and
acceptable terms or on a timely basis could materially harm our business.
may continue to use road blockages, which can sometimes interfere with
In Colombia, producers of crude oil have suffered from tanker transportation
We may be required to shut in oil and gas wells because access to
our operations in these areas.
transportation or processing facilities may be limited or unavailable when
needed. If that were to occur, then we would be unable to realize revenue
While Brazil has a well-developed network of hydrocarbon pipelines,
from those wells until arrangements were made to deliver the production
storage and loading facilities, we may not be able to access these facilities
to market, which could cause a material adverse effect on our business,
when needed. Pipeline facilities in Brazil are often full and seasonal capacity
40
GeoPark 20F
restrictions may occur, particularly in natural gas pipelines. Our failure
participation interest of 10%. See “Item 4. Information on the Company—B.
to secure transportation or access to pipelines or other facilities once we
Business overview—Health, safety and environmental matters—Other
commence operations in the seven concessions we were awarded in Brazil
regulation of the oil and gas industry—Brazil.”
on acceptable terms or on a timely basis could materially harm our business.
Additionally, offshore drilling generally requires more time and more
Our use of seismic data is subject to interpretation and may not accurately
advanced drilling technologies, involving a higher-risk of technological failure
identify the presence of oil and natural gas.
and usually higher drilling costs. Offshore projects often lack proximity to
existing oilfield service infrastructure, necessitating significant capital
Even when properly used and interpreted, seismic data and visualization
investment in flow line infrastructure before we can market the associated oil
techniques are tools only used to assist geoscientists in identifying subsurface
or gas of a commercial discovery, increasing both the financial and
structures as well as eventual hydrocarbon indicators, and do not enable
operational risk involved with these operations. Because of the lack and high
the interpreter to know whether hydrocarbons are, in fact, present in those
cost of infrastructure, some offshore reserve discoveries may never be
structures. In addition, the use of seismic and other advanced technologies
produced economically.
requires greater pre-drilling expenditures than traditional drilling strategies,
and we could incur losses as a result of these expenditures. Because of these
Further, because we are not the operator of our offshore fields, all of these
uncertainties associated with our use of seismic data, some of our drilling
risks may be heightened since they are outside of our control. Following
activities may not be successful or economically viable, and our overall
our Rio das Contas acquisition, which closed on March 31, 2014, we obtained
drilling success rate or our drilling success rate for activities in a particular
a 10% interest in the Manatí Field which limits our operating flexibility in
area could decline, which could have a material adverse effect on us.
such offshore fields. See “—We are not, and may not be in the future, the sole
Through our Rio das Contas acquisition, which closed on March 31, 2014,
the future, hold all of the working interests in certain of our licensed areas.
we will begin to face operational risks relating to offshore drilling that
we have not faced in the past.
Therefore, we may not be able to control the timing of exploration or
development efforts, associated costs, or the rate of production of any non-
owner or operator of all of our licensed areas and do not, and may not in
operated and, to an extent, any non-wholly-owned, assets.”
To date, we have operated solely as an onshore oil and gas exploration and
production company. However, our operations in the Manatí Field in Brazil
We may suffer delays or incremental costs due to difficulties in negotiations
may include shallow-offshore drilling activity in two concession areas in
with landowners and local communities where our reserves are located.
the Camamu-Almada Basin, which we expect will continue to be operated
by Petrobras.
Access to the sites where we operate requires agreements (including, for
example, assessments, rights of way and access authorizations) with
Offshore operations are subject to a variety of operating risks and laws and
landowners and local communities. If we are unable to negotiate agreements
regulations, including among other things, with respect to environmental,
health and safety matters, specific to the marine environment, such as
with landowners, we may have to go to court to obtain access to the sites
of our operations, which may delay the progress of our operations at such
capsizing, collisions and damage or loss from hurricanes or other adverse
sites. In Chile, for example, we have negotiated the necessary agreements for
weather conditions. These conditions can cause substantial damage to
many of our current operations in the Magallanes Basin. In the Tierra del
facilities and interrupt production. As a result, we could incur substantial
Fuego Blocks, although we have successfully negotiated access to our sites,
liabilities, compliance costs, fines or penalties that could reduce or eliminate
any future disputes with landowners or court proceedings may delay our
the funds available for exploration, development or leasehold acquisitions,
operations in Tierra del Fuego Blocks. In Brazil, in the event that social unrest
or result in loss of equipment and properties. For example, the Manatí Field
that occurred in 2013 continues or intensifies, this may lead to delays or
has been subject to administrative infraction notices, which have resulted
damage relating to our ability to operate the assets we have acquired or may
in fines against Petrobras in an aggregate amount of US$12.5 million,
acquire in our Brazil Acquisitions.
all of which are pending a final decision of the Brazilian Institute for the
Environment and Natural Renewable Resources ( Instituto Brasileiro do Meio-
In Colombia, although we have agreements with many landowners and are
Ambiente e dos Recursos Naturais Renováveis ), or IBAMA. Although the
in negotiations with others, we expect our costs to increase following current
administrative fines were filed against Petrobras, as a party to the concession
and future negotiations regarding access to our blocks, as the economic
agreement governing the Manatí Field, Rio das Contas may be liable up to its
expectations of landowners have generally increased, which may delay access
GeoPark 20F
41
to existing or future sites. In addition, the expectations and demands of
subsequently relinquished all areas of the Tranquilo Block, except for an area
local communities on oil and gas companies operating in Colombia have
of 92,417 gross acres, where we declared four hydrocarbons discoveries.
increased in the wake of recent changes to the royalty regime in Colombia.
Additionally, on April 10, 2013, we voluntarily and formally announced to the
As a result, local communities have demanded that oil and gas companies
Chilean Ministry of Energy our decision not to proceed with the second
invest in remediating and improving public access roads, compensate them
exploratory period and to terminate the exploration phase under the Otway
for any damages related to use of such roads and, more generally, invest
Block CEOP, and subsequently relinquished all areas of the Otway Block,
in infrastructure that was previously paid for with public funds. Due to these
except for two areas totaling 49,421 gross acres in which we have declared
circumstances, oil and gas companies in Colombia, including us, are now
hydrocarbons discoveries. See “Item 4. Information on the Company—B.
dealing with increasing difficulties resulting from instances of social unrest,
Business overview—Our operations—Operations in Argentina—Del Mosquito
temporary road blockages and conflicts with landowners. For example, in
Block” and “Item 4. Information on the Company—B. Business overview—Our
August 2013, our access to Llanos 34 Block was blocked by the local
operations—Operations in Chile—Otway and Tranquilo Blocks.”
community due to national social unrest in Colombia, resulting in our
suspension of production for a period of five days.
For additional details regarding the status of our operations with respect to
our various special contracts and concession agreements, see “Item 4.
There can be no assurance that disputes with landowners and local
Information on the Company—B. Business overview—Our operations.”
communities will not delay our operations or that any agreements we reach
with such landowners and local communities in the future will not require
A significant amount of our reserves and production have been derived
us to incur additional costs, thereby materially adversely affecting our
from our operations in one block, the Fell Block.
business, financial condition and results of operations. Local communities
may also protest or take actions that restrict or cause their elected
For the year ended December 31, 2013, the Fell Block contained 53% of
government to restrict our access to the sites of our operations, which may
our net proved reserves and generated 51.5% of our total production.
have a material adverse effect on our operations at such sites.
On a pro forma basis (including the Rio das Contas Acquisition), for the year
Under the terms of some of our various CEOPs, E&P Contracts and
proved reserves and generated 41% of our total production. While the
concession agreements, we are obligated to drill wells, declare any
acquisitions of Winchester, Luna and Cuerva in Colombia and our expansion
discoveries and file periodic reports in order to retain our rights
into Brazil mean that the Fell Block is a less significant component of our
and establish development areas. Failure to meet these obligations
overall business than it has been in the past, we nonetheless expect
may result in the loss of our interests in the undeveloped parts of
that the Fell Block will continue to be responsible for a significant portion
ended December 31, 2013, the Fell Block contained 38% of our net
our blocks or concession areas.
of our reserves and production. Any government intervention, impairment
or disruption of our production due to factors outside of our control or
In order to protect our exploration and production rights in our license areas,
any other material adverse event in our operations in the Fell Block would
we must meet various drilling and declaration requirements. In general,
unless we make and declare discoveries within certain time periods specified
have a material adverse effect on our business, financial condition and
results of operations.
in our various CEOPs, E&P Contracts and concession agreements, our interests
in the undeveloped parts of our license areas may lapse. Should the prospects
Our contracts in obtaining rights to explore and develop oil and natural
we have identified under these contracts and agreements yield discoveries,
gas reserves are subject to contractual expiration dates and operating
we may face delays in drilling these prospects or be required to relinquish
conditions, and our CEOPs, E&P Contracts and concession agreements are
these prospects. The costs to maintain or operate the CEOPs, E&P Contracts
subject to early termination in certain circumstances.
and concession agreements over such areas may fluctuate and may increase
significantly, and we may not be able to meet our commitments under such
Under certain of the CEOPs, E&P Contracts and concession agreements to
contracts and agreements on commercially reasonable terms or at all, which
which we are or may in the future become parties, we are or may become
may force us to forfeit our interests in such areas. For example, on January 17,
subject to guarantees to perform our commitments and/or to make payment
2013, we voluntarily and formally announced to the Chilean Ministry of
for other obligations, and we may not be able to obtain financing for all such
Energy our decision not to proceed with the second exploration period and
obligations as they arise. If such obligations are not complied with when
to terminate the exploration phase under the Tranquilo Block CEOP, and
due, in addition to any other remedies that may be available to other parties,
42
GeoPark 20F
this could result in cancelation of our CEOPs, E&P Contracts and concession
In addition, according to the Chilean Constitution, Chile is entitled to
agreements or dilution or forfeiture of interests held by us. As of December
expropriate our rights in our CEOPs for reasons of public interest. Although
31, 2013, the aggregate outstanding amount of this potential liability for
Chile would be required to indemnify us for such expropriation, there can
guarantees was approximately US$87.5 million, mainly relating to guarantees
be no assurance that any such indemnification will be paid in a timely manner
of our minimum work program for the Tierra del Fuego Blocks and, to a
or in an amount sufficient to cover the harm to our business caused by such
significantly lesser extent, our minimum work programs for our Colombian
expropriation.
operations and the ten Brazilian concession areas.
In Colombia, our E&P Contracts may be subject to early termination for a
Additionally, certain of the CEOPs, E&P Contracts and concession agreements
breach by the parties, a default declaration, application of any of the
to which we are or may in the future become a party are subject to set
contracts’ unilateral termination clauses or pursuant to termination clauses
expiration dates. Although we may want to extend some of these contracts
mandated by Colombian law. Anticipated termination declared by the ANH
beyond their original expiration dates, there is no assurance that we can do
results in the immediate enforcement of monetary guaranties against us
so on terms that are acceptable to us or at all.
and may result in an action for damages by the ANH and/or a restriction on
our ability to engage in contracts with the Colombian government during a
In particular, in Chile, our CEOPs provide for early termination by Chile in
certain period of time. See “Item 4. Information on the Company—B. Business
certain circumstances, depending upon the phase of the CEOP. For example,
overview—Significant agreements—Colombia—E&P Contracts.”
pursuant to the Fell Block CEOP, under which we are in the exploitation
phase, Chile may terminate the CEOP if (i) we stop performing any of the
In Brazil, concession agreements generally may be renewed, at the ANP’s
substantial obligations assumed under the Fell Block CEOP without cause and
discretion, for an additional period equivalent to the original concession
do not cure such nonperformance pursuant to the terms of the concession,
period, provided that a renewal request is made at least 12 months prior
following notice of breach or (ii) our oil activities are interrupted for more
to the termination of the concession agreement and there has not been a
than three years due to force majeure circumstances (as defined in the
breach of the terms of the concession agreement. We expect that all our
Fell Block CEOP). If the Fell Block CEOP is terminated in the exploitation phase,
concession agreements will provide for early termination in the event of:
we will have to transfer to Chile, free of charge, any productive wells and
(i) government expropriation for reasons of public interest; (ii) revocation of
related facilities, provided that such transfer does not interfere with our
the concession pursuant to the terms of the concession agreement; or (iii)
abandonment obligations and excluding certain pipelines and other assets.
failure by us or our partners to fulfill all of our respective obligations under
See “Item 4. Information on the Company—B. Business overview—
the concession agreement (subject to a cure period). Administrative or
Significant agreements—Chile—CEOPs—Fell Block CEOP.” If the CEOP is
monetary sanctions may also be applicable, as determined by the ANP, which
terminated early due to a breach of our obligations, we may not be entitled
shall be imposed based on applicable law and regulations. In the event of
to compensation. Additionally, our CEOPs for the Tierra del Fuego Blocks,
early termination of a concession agreement, the compensation to which
which are in the exploration phase, may be subject to early termination
we are entitled may not be sufficient to compensate us for the full value of
during this phase under circumstances including (i) a failure by us to comply
with minimum work commitments at the termination of any exploration
our assets. Moreover, in the event of early termination of any concession
agreement due to failure to fulfill obligations thereunder, we may be subject
period, (ii) a failure to communicate our intention to proceed with the next
to fines and/or other penalties.
exploration period 30 days prior to its termination, (iii) a failure to provide the
Chilean Ministry of Energy requisite performance bonds, (iv) a voluntary
Early termination or nonrenewal of any CEOP, E&P Contract or concession
relinquishment by us of all areas under the CEOP, (v) a failure by us to meet
agreement could have a material adverse effect on our business, financial
the requirements to enter into the exploitation phase upon the termination
situation or results of operations.
of the exploration phase, and (vi) a permanent suspension by us of all
operations in the CEOP area or our declaration of bankruptcy. If the Tierra
We sell almost all of our natural gas in Chile to a single customer, who has
del Fuego Block CEOPs are terminated within the exploration phase, we are
in the past temporarily idled its principal facility.
released from all obligations under the CEOPs, except for obligations
regarding the abandonment of fields, if any. See “Item 4. Information on the
For the year ended December 31, 2013, almost all of our natural gas sales
Company—B. Business overview—Significant agreements—Chile—CEOPs.”
in Chile were made to Methanex under a long-term contract, or the Methanex
There can be no assurance that the early termination of any of our CEOPs
Gas Supply Agreement, which expires on April 30, 2017. Sales to Methanex
would not have a material adverse effect on us.
GeoPark 20F
43
represented 6.7% of our total revenues for the year ended December 31,
from us, there can be no assurance that we would be able to sell our gas
2013. Methanex also buys gas from ENAP and a consortium that Methanex
production to other parties or on similar terms, which could have a material
has formed with ENAP. While our contract with Methanex requires it to
adverse effect on our business, financial condition and results of operations.
purchase the entirety of our production of natural gas from the Fell Block,
and requires us to sell to Methanex all of our natural gas production from Fell
We may not be able to meet delivery requirements under the agreement
Block, subject to minor exceptions, if Methanex were to decrease or cease
for the sale of our natural gas in Chile.
its purchase of gas from us, this would have a material adverse effect on our
revenues derived from the sale of gas. In addition, there can be no assurance
Under the Methanex Gas Supply Agreement, Methanex has committed to
that we will be able to extend or renew our contract with Methanex past
purchasing, and we have committed to selling, all of the gas that we produce
April 30, 2017, which could have a material adverse effect on our business,
in the Fell Block (subject to certain exceptions, including reasonable
financial condition and results of operations.
quantities required to maintain our operations and quantities that we might
be required to pay in kind to Chile), with a minimum volume commitment
Methanex has two methanol producing facilities at its Cabo Negro production
which is defined by us on an annual basis. The agreement contains monthly
facility, near the city of Punta Arenas in southern Chile. However, after
DOP obligations, which require us to deliver in a given month the minimum
Argentine natural gas producers cut off exports to Chile in 2007, Methanex
gas committed for that month or pay a deficiency penalty to Methanex, with
had to stop production at all but one of these facilities, and began to rely
a threshold of 90% of the committed quantities of gas. The agreement also
completely on local suppliers of natural gas, including ENAP, for its
contains monthly TOP obligations, which apply when our committed volume
operations. Since 2009, however, the amount of natural gas that ENAP has
for a given month exceeds 35.3 mcfpd, and require Methanex to take in such
been able to provide to Methanex has been decreasing, as ENAP has given
month the minimum gas volume committed for such period or face higher
priority to providing natural gas to the city of Punta Arenas. Although we
TOP obligations in later months, with a threshold of 90% of the committed
sell all the natural gas we produce in the Fell Block to Methanex, and supplied
quantities. These DOP and TOP obligations are subject to make-up provisions
approximately 50% of all the natural gas consumed by Methanex before
without penalty, for any delivery or off-take deficiencies accrued, in the three
the idling of its plant in April 2013, we alone cannot supply Methanex with all
months following the month where delivery or off-take requirements were
the natural gas it requires for its operations.
not met.
The plant was idled due to an anticipated insufficient supply of natural gas.
On August 30, 2013, we signed an amendment to the Methanex Gas Supply
The supply of natural gas decreased during the winter months of 2013 due to
Agreement, pursuant to which Methanex committed, for a period of six
the increase in seasonal gas demand from the city of Punta Arenas in the
months commencing September 15, 2013, to purchase an increased volume,
Magallanes region, to which gas producers, including GeoPark, gave priority,
in a total amount of 400,000 SCM/d per month (subject to reduction for
delivering gas to the city through ENAP. Methanex continued to purchase
deliveries above 200,000 SCM/d to Methanex or ENAP made between April
from us the volume of gas it requires for the plant’s operation during the
29 and September 15, 2013), incorporating an additional premium to the
idling, and we signed an amendment to the agreement, pursuant to
which Methanex pay us a premium over the current gas price for deliveries
gas price depending on the volumes delivered. The amendment also provides
for temporary DOP and TOP thresholds of 100% and 50%, respectively.
exceeding certain volumes of gas, in the period immediately following
The amendment has been extended until April 30 2014. Therefore, we are
the Methanex plant’s startup, which occurred on September 23, 2013. See
currently committed to providing to Methanex a monthly volume of gas of
“Item 4. Information on the Company—B. Business overview—Marketing
0.4 bcf until April 30, 2014.
and Delivery Commitments—Chile.” Methanex has been making investments
aimed at lowering its plant’s minimum gas requirements during the idling,
For example, in 2012, we failed to meet this adjusted volume for each of the
so that the plant is currently able to function with 21.2 mcfpd of gas.
months of April through December of 2012, such that we accrued US$1.7
million in DOP payments owed to Methanex under the Methanex Gas Supply
However, there can be no assurance that Methanex will continue to purchase
Agreement, all of which had been paid as of September 30, 2013.
the committed volume of gas from us or that its efforts to reduce the risk
of future shutdowns will be successful, which could have a material adverse
There can be no assurance that we or Methanex will be able to meet
effect on our gas revenues. Additionally, there can be no assurance that
our respective DOP and TOP obligations under the Methanex Gas Supply
Methanex will have sufficient supplies of gas to operate its plant and continue
Agreement or that we will not incur additional deficiency penalties,
to purchase our gas production. If Methanex were to cease purchasing
in the future.
44
GeoPark 20F
We are not, and may not be in the future, the sole owner or operator of
This limited ability to exercise control over the operations on some of our
all of our licensed areas and do not, and may not in the future, hold all
license areas may cause a material adverse effect on our financial condition
of the working interests in certain of our licensed areas. Therefore,
and results of operations.
we may not be able to control the timing of exploration or development
efforts, associated costs, or the rate of production of any non-operated
LGI, our strategic partner in Chile and Colombia, may sell its interest in
and, to an extent, any non-wholly-owned, assets.
our Chilean and Colombian operations to a third party or may not consent
to our taking certain actions.
As of the date of this annual report, we are not the sole owner or operator
of the Llanos 17, Llanos 32 and Jagüeyes 3432 A Blocks in Colombia, which
We have a strategic partnership with LGI, which has a 20% equity interest in
represented 3% of our total production as of December 31, 2013 (on a pro
GeoPark Chile, a 14% direct equity interest in GeoPark TdF (31.2% taking into
forma basis, accounting for our Rio das Contas acquisition). In Brazil, the terms
account direct and indirect participation through GeoPark Chile) and a 20%
of our Rio das Contas acquisition are such that we are not the sole owner or
equity interest in GeoPark Colombia, through its equity interest in GeoPark
operator of the BCAM-40 Concession, which represented approximately
Colombia Cooperatie. Our shareholders’ agreements with LGI in each of
21% of our total production for the year ended December 31, 2013 (on a pro
Chile and Colombia provides that we have a right of first offer if LGI decides
forma basis, accounting for our Rio das Contas acquisition).
to sell any of its interest in GeoPark Chile or GeoPark Colombia. There can
be no assurance, however, that we will have the funds to purchase LGI’s
In addition, the terms of the joint venture agreements or association
interest in Chile and/or Colombia and that LGI will not decide to sell its shares
agreements governing our other partners’ interests in almost all of the blocks
to a third party whose interests may not be aligned with ours.
that are not wholly-owned or operated by us require that certain actions be
approved by supermajority vote. The terms of our other current or future
In addition, our shareholders’ agreements with LGI in Chile and Colombia
license or venture agreements may require at least the majority of working
contain provisions that require GeoPark Chile and GeoPark Colombia to
interests to approve certain actions. As a result, we may have limited ability
obtain LGI’s consent before undertaking certain actions. For example, under
to exercise influence over operations or prospects in the blocks operated
the terms of the shareholders’ agreement with LGI in Colombia, LGI must
by our partners, or in blocks that are not wholly-owned or operated by us. A
approve GeoPark Colombia’s annual budget and work programs and
breach of contractual obligations by our partners who are the operators of
mechanisms for funding any such budget or program, the entering into any
such blocks could eventually affect our rights in exploration and production
borrowings other than those provided in an approved budget or incurred
contracts in our blocks in Colombia. Our dependence on our partners could
in the ordinary course of business to finance working capital needs, the
prevent us from realizing our target returns for those discoveries or prospects.
granting of any guarantee or indemnity to secure liabilities of parties other
than those of our Colombian subsidiaries and disposing of any material assets
Moreover, as we are not the sole owner or operator of all of our properties,
other than those provided for in an approved budget and work program.
we may not be able to control the timing of exploration or development
Similarly, in Chile, pursuant to the terms of our shareholders’ agreements with
activities or the amount of capital expenditures and may therefore not
be able to carry out our key business strategies of minimizing the cycle time
LGI, LGI’s consent is required in order for GeoPark Chile or GeoPark TdF, as
applicable, to be able to take certain actions, including: making any decision
between discovery and initial production at such properties. The success
to terminate or permanently or indefinitely suspend operations in or
and timing of exploration and development activities operated by our
surrender our blocks in Chile (other than as required under the terms of the
partners will depend on a number of factors that will be largely outside of
relevant CEOP for such blocks); selling our blocks in Chile to our affiliates;
our control, including:
• the timing and amount of capital expenditures;
• the operator’s expertise and financial resources;
• approval of other block partners in drilling wells;
making any change to the dividend, voting or other rights that would give
preference to or discriminate against the shareholders of these companies;
entering into certain related party transactions; and creating a security
interest over our blocks in Chile (other than in connection with a financing
• the scheduling, pre-design, planning, design and approvals of activities
that benefits our Chilean subsidiaries).
and processes;
• selection of technology; and
Additionally, pursuant to our agreements with LGI in Chile, we and LGI have
• the rate of production of reserves, if any.
agreed to vote our common shares or otherwise cause GeoPark Chile or
GeoPark TdF, as the case may be, to declare dividends only after allowing
for retentions of cash to meet anticipated future investments, costs and
GeoPark 20F
45
obligations, and pursuant to our agreement with LGI in Colombia, we and
related to the assets or management of the companies and operations
LGI have agreed to vote our common shares or otherwise cause GeoPark
we have acquired, such as in Colombia or Brazil, or other companies
Colombia to declare dividends only after allowing for retentions of cash
or operations we may acquire in future, will not arise in future, and these
for approved work programs and budgets and capital adequacy requirements
problems could have a material adverse effect on our business, financial
of GeoPark Colombia, working capital requirements, banking covenants
condition and results of operations.
associated with any loan entered into by GeoPark Colombia or our other
Colombian subsidiaries and operational requirements. Our inability to obtain
Significant acquisitions and other strategic transactions may involve other
LGI’s consent or a delay by LGI in granting its consent may restrict or delay
risks, including:
the ability of GeoPark Chile, GeoPark TdF or GeoPark Colombia to take certain
• diversion of our management’s attention to evaluating, negotiating and
actions, which may have an adverse effect on our operations in such
integrating significant acquisitions and strategic transactions;
countries and on our business, financial condition and results of operations.
• challenge and cost of integrating acquired operations, information
management and other technology systems and business cultures with
Acquisitions that we have completed and any future acquisitions, strategic
those of ours while carrying on our ongoing business;
investments, partnerships or alliances could be difficult to integrate and/or
• contingencies and liabilities that could not be or were not identified during
identify, could divert the attention of key management personnel, disrupt
the due diligence process, including with respect to possible deficiencies
our business, dilute stockholder value and adversely affect our financial
in the internal controls of the acquired operations; and
results, including impairment of goodwill and other intangible assets.
• challenge of attracting and retaining personnel associated with acquired
One of our principal business strategies includes acquisitions of properties,
operations.
prospects, reserves and leaseholds and other strategic transactions, including
If we fail to realize the benefits we anticipate from an acquisition, our results
in jurisdictions in which we do not currently operate. The successful
of operations may be adversely affected.
acquisition and integration of producing properties, including our
acquisitions of Winchester, Luna and Cuerva in Colombia and our Brazil
It is also possible that we may not identify suitable acquisition targets
Acquisitions, requires an assessment of several factors, including:
or strategic investment, partnership or alliance candidates. Our inability to
• recoverable reserves;
• future oil and natural gas prices;
• development and operating costs; and
identify suitable acquisition targets, strategic investments, partners or
alliances, or our inability to complete such transactions, may negatively affect
our competitiveness and growth opportunities. Moreover, if we fail to
• potential environmental and other liabilities.
properly evaluate acquisitions, alliances or investments, we may not achieve
the anticipated benefits of any such transaction and we may incur costs in
The accuracy of these assessments is inherently uncertain. In connection
excess of what we anticipate.
with these assessments, we perform a review of the subject properties that
we believe to be generally consistent with industry practices. Our review
and the review of advisors and independent reserves engineers will not reveal
Future acquisitions financed with our own cash could deplete the cash and
working capital available to adequately fund our operations. We may also
all existing or potential problems nor will it permit us or them to become
finance future transactions through debt financing, the issuance of our equity
sufficiently familiar with the properties to fully assess their deficiencies and
securities, existing cash, cash equivalents or investments, or a combination
potential recoverable reserves. Inspections may not always be performed
of the foregoing. Acquisitions financed with the issuance of our equity
on every well, and environmental conditions are not necessarily observable
securities could be dilutive, which could affect the market price of our stock.
even when an inspection is undertaken. We, advisors or independent reserves
Acquisitions financed with debt could require us to dedicate a substantial
engineers may apply different assumptions when assessing the same field.
portion of our cash flow to principal and interest payments and could subject
Even when problems are identified, the seller may be unwilling or unable
us to restrictive covenants.
to provide effective contractual protection against all or part of the problems.
We often are not entitled to contractual indemnification for environmental
The PN-T-597 concession is subject to an injunction and may not close.
liabilities and acquire properties on an “as is” basis. Even in those
circumstances in which we have contractual indemnification rights for
In Brazil, GeoPark Brazil is currently a party to a legal proceeding related to
pre-closing liabilities, it remains possible that the seller will not be able
the concession agreement of Block PN-T-597 that the ANP initially awarded
to fulfill its contractual obligations. There can be no assurance that problems
to GeoPark Brazil in the 12th oil and gas bidding round. As a result of a
46
GeoPark 20F
class action filed by the Federal Prosecutor’s Office, an injunction was issued
The development of our proved undeveloped reserves may take longer
by a Brazilian Federal Court against the ANP, the Federal Government and
and may require higher levels of capital expenditures than we currently
GeoPark Brazil on December 13, 2013. Due to the injunction GeoPark
anticipate. Therefore, our proved undeveloped reserves ultimately
Brazil could not proceed to execute the concession agreement, and cannot
may not be developed or produced.
do so until the injunction is lifted. According to the terms of the Court’s
injunction, the ANP will first need to take certain actions, such as conducting
As of December 31, 2013, only approximately 42% of our net proved reserves
studies that prove that drilling unconventional resources will not contaminate
have been developed. Development of our undeveloped reserves may
the dams and aquifers in the region. On February 21, 2014, GeoPark Brazil
take longer and require higher levels of capital expenditures than we currently
requested that the board of the ANP suspend the execution of the concession
anticipate. Additionally, delays in the development of our reserves or increases
agreement (which entails delivery of the financial guarantee and performance
in costs to drill and develop such reserves will reduce the standardized measure
guarantee and payment of the signing bonus) for six months with a possible
value of our estimated proved undeveloped reserves and future net revenues
extension of an additional six months, or until a firm court decision is reached
estimated for such reserves, and may result in some projects becoming
that does not prevent GeoPark Brazil from entering into the concession
uneconomic, causing the quantities associated with these uneconomic projects
agreement. On April 16, 2014, the ANP’s Board enacted a resolution stating
to no longer be classified as reserves. For example, in Argentina, although we
that all proceedings related to the award of the concession of Block PN-T-597
had production in the blocks in which we have a working interest, D&M
to GeoPark Brazil were suspended.
determined that there were no reserves in these blocks as of December 31, 2013.
This was due to the uneconomic status of the reserves, given the proximity to
There can be no assurance that we will be able to extend the deadlines
the end of the concessions for these blocks, which does not allow for future
associated with the entry into the Concession Contract or enter into the
capital investment in the blocks. There can be no assurance that we will not
concession agreement. See “Item 8—Financial Information—A. Consolidated
experience similar delays or increases in costs to drill and develop our reserves in
statements and other financial information—Legal proceedings.”
the future, which could result in further reclassifications of our reserves.
The present value of future net revenues from our proved reserves will
We are exposed to the credit risks of our customers and any material
not necessarily be the same as the current market value of our estimated
nonpayment or nonperformance by our key customers could adversely
oil and natural gas reserves.
affect our cash flow and results of operations.
You should not assume that the present value of future net revenues from
Our customers may experience financial problems that could have
our proved reserves is the current market value of our estimated oil and
a significant negative effect on their creditworthiness. Severe financial
natural gas reserves. For the year ended December 31, 2013, we have based
problems encountered by our customers could limit our ability to collect
the estimated discounted future net revenues from our proved reserves
amounts owed to us, or to enforce the performance of obligations
on the 12 month unweighted arithmetic average of the first-day-of-the-
owed to us under contractual arrangements.
month price for the preceding 12 months. Actual future net revenues from
our oil and natural gas properties will be affected by factors such as:
The combination of declining cash flows as a result of declines in commodity
• actual prices we receive for oil and natural gas;
prices, a reduction in borrowing basis under reserves-based credit
• actual cost of development and production expenditures;
facilities and the lack of availability of debt or equity financing may result
• the amount and timing of actual production; and
in a significant reduction of our customers’ liquidity and limit their ability to
• changes in governmental regulations, taxation or the taxation invariability
make payments or perform on their obligations to us.
provisions in our CEOPs.
Furthermore, some of our customers may be highly leveraged, and, in any
The timing of both our production and our incurrence of expenses in
event, are subject to their own operating expenses. Therefore, the risk we
connection with the development and production of oil and natural gas
face in doing business with these customers may increase. Other customers
properties will affect the timing and amount of actual future net revenues
may also be subject to regulatory changes, which could increase the risk of
from proved reserves, and thus their actual value. In addition, the 10%
defaulting on their obligations to us. Financial problems experienced by
discount factor we use when calculating discounted future net revenues
our customers could result in the impairment of our assets, a decrease in our
may not be the most appropriate discount factor based on interest rates in
operating cash flows and may also reduce or curtail our customers’ future
effect from time to time and risks associated with us or the oil and natural
use of our products and services, which may have an adverse effect on our
gas industry in general.
revenues and may lead to a reduction in reserves.
GeoPark 20F
47
We may not have the capital to develop our unconventional oil and
where we conduct our activities, thereby increasing our turnover rate.
gas resources.
There is strong ongoing competition in our industry to hire employees in
operational, technical and other areas, and the supply of qualified employees
We have identified opportunities for analyzing the potential of
is limited in the regions where we operate and throughout Latin America
unconventional oil and gas resources in some of our blocks and concessions
generally. The loss of any of our executive officers or other key employees of
in Chile, Colombia, Brazil and Argentina. Our ability to develop this potential
our technical team or our inability to hire and retain new qualified personnel
depends on a number of factors, including the availability of capital,
could have a material adverse effect on us.
seasonal conditions, regulatory approvals, negotiation of agreements with
third parties, commodity prices, costs, access to and availability of equipment,
Unfavorable credit and market conditions, such as the global financial
services and personnel and drilling results. In addition, as we have no
crisis that began in 2008, have affected and could continue to affect
previous experience in drilling and exploiting unconventional oil and gas
negatively the economies of the countries in which we operate and may
resources, the drilling and exploitation of such unconventional oil and
negatively affect our liquidity, business, and results of operations.
gas resources depends on our ability to acquire the necessary technology,
to hire personnel and other support needed for extraction or to obtain
Global financial crises and related turmoil in the global financial system
financing and venture partners to develop such activities. Because of these
have had, and may continue to have, a negative impact on our business,
uncertainties, we cannot give any assurance as to the timing of these
financial condition and results of operations. The lingering effects of the
activities, or that they will ultimately result in the realization of proved
global credit crisis that began in 2008 and of financial crises generally
reserves or meet our expectations for success.
on our customers and on us cannot be predicted. Persistent uncertainty in
Our operations are subject to operating hazards, including extreme
Europe and the United States, may affect our ability to access the credit or
weather events, which could expose us to potentially significant losses.
capital markets at a time when we would need financing, which could have
an impact on our flexibility to react to changing economic and business
Our operations are subject to potential operating hazards, extreme weather
conditions. Any of the foregoing factors or a combination of these factors
conditions and risks inherent to drilling activities, seismic registration,
could have an adverse effect on our liquidity, results of operations and
international credit markets, exacerbated by the sovereign debt crises in
exploration, production, development and transportation and storage of
financial condition.
crude oil, such as explosions, fires, car and truck accidents, floods, labor
disputes, social unrest, community protests or blockades, guerilla attacks,
We and our operations are subject to numerous environmental, health
security breaches, pipeline ruptures and spills and mechanical failure of
and safety laws and regulations which may result in material liabilities
equipment at our or third-party facilities. Any of these events could have
and costs.
a material adverse effect on our exploration and production operations,
or disrupt transportation or other process-related services provided by our
We and our operations are subject to various international, foreign, federal,
third-party contractors.
state and local environmental, health and safety laws and regulations
governing, among other things, the emission and discharge of pollutants
We are highly dependent on certain members of our management and
into the ground, air or water; the generation, storage, handling, use,
technical team, including our geologists and geophysicists, and on our
transportation and disposal of regulated materials; and human health and
ability to hire and retain new qualified personnel.
safety. Our operations are also subject to certain environmental risks that
are inherent in the oil and gas industry and which may arise unexpectedly
The ability, expertise, judgment and discretion of our management and our
and result in material adverse effects on our business, financial condition
technical and engineering teams are key in discovering and developing oil
and results of operations. Breach of environmental laws, as well as impacts
and natural gas resources. Our performance and success are dependent to a
on natural resources and unauthorized use of such resources, could
large extent upon key members of our management and exploration team,
result in environmental administrative investigations and/or lead to the
and their loss or departure would be detrimental to our future success. In
termination of our concessions and contracts. Other potential consequences
addition, our ability to manage our anticipated growth depends on our ability
include fines and/or criminal or civil environmental actions. For instance,
to recruit and retain qualified personnel. Our ability to retain our employees
non-governmental organizations seeking to preserve the environment may
is influenced by the economic environment and the remote locations of
bring actions against us or other oil and gas companies in order to, among
our exploration blocks, which may enhance competition for human resources
other things, halt our activities in any of the countries in which we operate
48
GeoPark 20F
or require us to pay fines. Additionally, in Colombia, recent rulings have
might require us to remediate contamination, or retrofit facilities, at
provided that environmental licenses are administrative acts subject to class
substantial cost. We also could be held liable for any and all consequences
actions that could eventually result in their cancellation, with potential
arising out of human exposure to such substances or for other damage
adverse impacts on our E&P Contracts.
resulting from the release of hazardous substances to the environment,
property or to natural resources, or affecting endangered species or sensitive
We are required to obtain environmental permits from governmental
environmental areas. Environmental laws and regulations also require that
authorities for our operations, including drilling permits for our wells.
wells be plugged and sites be abandoned and reclaimed to the satisfaction
We have not been and may not be at all times in complete compliance with
of the relevant regulatory authorities. We are currently required to, and in
these permits and the environmental and health and safety laws and
the future may need to, plug and abandon sites in certain blocks in each of
regulations to which we are subject. If we violate or fail to comply with such
the countries in which we operate, which could result in substantial costs.
requirements, we could be fined or otherwise sanctioned by regulators,
including through the revocation of our permits or the suspension or
In addition, we expect continued and increasing attention to climate
termination of our operations. If we fail to obtain, maintain or renew permits
change issues. Various countries and regions have agreed to regulate
in a timely manner or at all (such as due to opposition from partners,
emissions of greenhouse gases including methane (a primary component
community or environmental interest groups, governmental delays or any
of natural gas) and carbon dioxide (a byproduct of oil and natural gas
other reasons) or if we face additional requirements due to changes in
combustion). The regulation of greenhouse gases and the physical impacts
applicable laws and regulations, our operations could be adversely affected,
of climate change in the areas in which we, our customers and the end-
impeded, or terminated, which could have a material adverse effect on our
users of our products operate could adversely impact our operations and
business, financial condition or results of operations. Some environmental
the demand for our products.
licenses related to operation of the Manatí Field production system and natural
gas pipeline have expired. However, the operator submitted timely a request
Environmental, health and safety laws and regulations are complex and
for renewal of those licenses and as such this operation is not in default as
change frequently, and have tended to become increasingly stringent
long as the regulator does not state its final position on the renewal.
over time. Our costs of complying with current and future climate change,
environmental, health and safety laws, the actions or omissions of our
We, as the owner, shareholder or the operator of certain of our past, current
partners and third-party contractors and our liabilities arising from releases
and future discoveries and prospects, could be held liable for some or all
of, or exposure to, regulated substances may adversely affect our results
environmental, health and safety costs and liabilities arising out of our actions
of operations and financial condition. See “Item 4. Information on the
and omissions as well as those of our block partners, third-party contractors,
Company—B. Business overview—Health, safety and environmental matters”
predecessors or other operators. To the extent we do not address these
and “Item 4. Information on the Company—B. Business overview—Industry
costs and liabilities or if we do not otherwise satisfy our obligations, our
and regulatory framework.”
operations could be suspended, terminated or otherwise adversely affected.
We have also contracted with and intend to continue to hire third parties
to perform services related to our operations. There is a risk that we may
Legislation and regulatory initiatives relating to hydraulic fracturing and
other drilling activities for unconventional oil and gas resources could
contract with third parties with unsatisfactory environmental, health
increase the future costs of doing business, cause delays or impede our
and safety records or that our contractors may be unwilling or unable to
plans, and materially adversely affect our operations.
cover any losses associated with their acts and omissions. Accordingly, we
could be held liable for all costs and liabilities arising out of the acts or
Hydraulic fracturing of unconventional oil and gas resources is a process
omissions of our contractors, which could have a material adverse effect on
that involves injecting water, sand, and small volumes of chemicals into the
our results of operations and financial condition.
wellbore to fracture the hydrocarbon-bearing rock thousands of feet below
the surface to facilitate a higher flow of hydrocarbons into the wellbore.
Releases of regulated substances may occur and can be significant. Under
We are contemplating such use of hydraulic fracturing in the production of
certain environmental laws and regulations applicable to us in the countries
oil and natural gas from certain reservoirs, especially shale formations.
in which we operate, we could be held responsible for all of the costs
We currently are not aware of any proposals in Chile, Colombia, Brazil or
relating to any contamination at our past and current facilities and at any
Argentina to regulate hydraulic fracturing beyond the regulations already
third-party waste disposal sites used by us or on our behalf. Pollution
in place. However, various initiatives in other countries with substantial shale
resulting from waste disposal, emissions and other operational practices
gas resources have been or may be proposed or implemented to, among
GeoPark 20F
49
other things, regulate hydraulic fracturing practices, limit water withdrawals
Furthermore, on March 28, 2014, our Brazilian subsidiary that acquired Rio das
and water use, require disclosure of fracturing fluid constituents, restrict
Contas entered into a US$70.5 million loan to finance part of the acquisition.
which additives may be used, or implement temporary or permanent bans
This loan includes covenants restricting dividend payments to us. For a
on hydraulic fracturing. If any of the countries in which we operate adopts
description, see “Item 5. Operating and Financial Review and Prospects—B.
similar laws or regulations, which is something we cannot predict right now,
Liquidity and Capital Resources—Indebtedness—Rio das Contas Credit
such adoption could significantly increase the cost of, impede or cause
Facility.
delays in the implementation of any plans to use hydraulic fracturing for
unconventional oil and gas resources.
As a result of these covenants, we are limited in the manner in which we
conduct our business, and we may be unable to engage in favorable business
Our substantial indebtedness could adversely affect our financial health
activities or finance future operations or capital needs.
and our ability to raise additional capital, and prevent us from fulfilling
our obligations under our existing agreements.
Similar restrictions could apply to us and our subsidiaries when we refinance
or enter into new debt agreements which could intensify the risks described
As of December 31, 2013, we had US$317.1 million of total indebtedness
above.
outstanding on a consolidated basis, of which US$300.1 million, or 94.7%, was
secured. As of December 31, 2013, our annual debt service obligation was
Our results of operations could be materially adversely affected by
approximately US$25.2 million, which includes interest payments under the
fluctuations in foreign currency exchange rates.
Notes due 2020. See “Item 5. Operating and Financial Review and Prospects—
B. Liquidity and Capital Resources—Indebtedness.”
Although a majority of our net revenues is denominated in U.S. dollars,
Our substantial indebtedness could:
unfavorable fluctuations in foreign currency exchange rates for certain of
our expenses in Chile, Colombia, Brazil and Argentina could have a material
• make it more difficult for us to satisfy our obligations with respect to
adverse effect on our results of operations. Furthermore, we have not
our indebtedness, and any failure to comply with the obligations of any of our
entered, and do not anticipate entering, into derivative transactions to
debt instruments, including restrictive covenants and borrowing conditions,
hedge the effect of changes in the exchange rate of local currencies to the
could result in an event of default under the agreements governing our
U.S. dollar. Because our consolidated financial statements are presented
indebtedness;
in U.S. dollars, we must translate revenues, expenses and income, as well as
• require us to dedicate a substantial portion of our cash flow from operations
assets and liabilities, into U.S. dollars at exchange rates in effect during or
to the payments on our indebtedness, thereby reducing the availability of
at the end of each reporting period.
our cash flow to fund acquisitions, working capital, capital expenditures and
other general corporate purposes;
In addition, our Rio das Contas acquisition, which closed on March 31, 2014,
• place us at a competitive disadvantage compared to certain of our
significantly increased our exposure to fluctuations in the real against the
competitors that have less debt;
• limit our ability to borrow additional funds;
U.S. dollar, as Rio das Contas’s revenues and expenses are denominated in
reais . The real has experienced frequent and substantial variations in relation
• in the case of our secured indebtedness, lose assets securing such
to the U.S. dollar and other foreign currencies. For example, the real was
indebtedness upon the exercise of security interests in connection with a
R$1.56 per US$1.00 in August 2008. Following the onset of the crisis in the
default;
global financial markets, the real depreciated 31.9% against the U.S.
• make us more vulnerable to downturns in our business or the economy;
dollar and reached R$2.34 per US$1.00 at the end of 2008. In 2011, the real
and
appreciated against the U.S. dollar, reaching R$1.876 per US$1.00 at the end
• limit our flexibility in planning for, or reacting to, changes in our operations
of 2011. In 2012, however, the real depreciated, and on December 31, 2012,
or business and the industry in which we operate.
the exchange rate was R$2.044 per US$1.00. As of December 31, 2013, the
Our Notes due 2020 include a covenant restricting dividend payments. For
either depreciation or appreciation of the real could materially and adversely
a description, see “Item 5. Operating and Financial Review and Prospects—B.
affect the growth of the Brazilian economy and our business, financial
Liquidity and Capital Resources—Indebtedness—Notes due 2020.”
condition and results of operations. See “—A. Selected financial data—
exchange rate was R$2.3426 per US$1.00. Depending on the circumstances,
Exchange rates.”
50
GeoPark 20F
Risks relating to the countries in which we operate
• tax policies; and
Our operations may be adversely affected by political and economic
of earnings from the countries in which we operate in the future.
• the possibility that we may become subject to restrictions on repatriation
circumstances in the countries in which we operate and in which we may
operate in the future.
In addition, our operations in these areas increase our exposure to risks of
guerilla activities, social unrest, local economic conditions, political disruption,
All of our current operations are located in South America. For the year
civil disturbance, community protests or blockades, expropriation, piracy,
ended December 31, 2013, our operations in Chile and Colombia represented
tribal conflicts and governmental policies that may: disrupt our operations;
51.5% and 48%, respectively, of our total production, with our Argentine
require us to incur greater costs for security; restrict the movement of
operations representing less than 0.5% of our total production. As of
funds or limit repatriation of profits; lead to U.S. government or international
December 31, 2013, on a pro forma basis, and accounting for our Rio das
sanctions; limit access to markets for periods of time; or influence the
Contas acquisition, Chile, Colombia and Brazil represented 41%, 38% and
market’s perception of the risk associated with investments in these
21%, respectively, of our average production during the same period.
countries. Some countries in the geographic areas where we operate have
If local, regional or worldwide economic trends adversely affect the economy
experienced, and may experience in the future, political instability, and
of any of the countries in which we have investments or operations, our
losses caused by these disruptions may not be covered by insurance.
financial condition and results from operations could be adversely affected.
Consequently, our exploration, development and production activities may
be substantially affected by factors which could have a material adverse
Oil and natural gas exploration, development and production activities are
effect on our results of operations and financial condition.
subject to political and economic uncertainties (including but not
limited to changes in energy policies or the personnel administering them),
Our operations may also be adversely affected by laws and policies of the
changes in laws and policies governing operations of foreign-based
jurisdictions, including Bermuda, Chile, Colombia, Brazil, Argentina, the
companies, expropriation of property, cancellation or modification of contract
Netherlands and other jurisdictions in which we do business, that affect
rights, revocation of consents or approvals, the obtaining of various
foreign trade and taxation, and by uncertainties in the application of, possible
approvals from regulators, foreign exchange restrictions, price controls,
changes to (or to the application of) tax laws in these jurisdictions. Changes
currency fluctuations, royalty increases and other risks arising out of foreign
in any of these laws or policies or the implementation thereof, and uncertainty
governmental sovereignty, as well as to risks of loss due to civil strife,
over potential changes in policy or regulations affecting any of the factors
acts of war and community-based actions, such as protests or blockades,
mentioned above or other factors in the future may increase the volatility of
guerilla activities, terrorism, acts of sabotage, territorial disputes
domestic securities markets and securities issued abroad by companies
and insurrection. In addition, we are subject both to uncertainties in the
operating in these countries, which could materially and adversely affect our
application of the tax laws in the countries in which we operate and to
financial position, results of operations and cash flows. Furthermore, we may be
possible changes in such tax laws (or the application thereof), each of which
subject to the exclusive jurisdiction of courts outside the United States or may
could result in an increase in our tax liabilities. These risks are higher in
developing countries, such as those in which we conduct our activities.
not be successful in subjecting non-U.S. persons to the jurisdiction of courts in
the United States, which could adversely affect the outcome of such dispute.
The main economic risks we face and may face in the future because of
We depend on maintaining good relations with the respective host
our operations in the countries in which we operate include the following:
governments and national oil companies in each of our countries of
• difficulties incorporating movements in international prices of crude
operation.
oil and exchange rates into domestic prices;
• the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s
The success of our business and the effective operation of the fields in each
or Brazil’s relations with multilateral credit institutions, such as the IMF, will
of our countries of operation depend upon continued good relations and
impact negatively on capital controls, and result in a deterioration of the
cooperation with applicable governmental authorities and agencies,
business climate;
including national oil companies such as ENAP and Petrobras. For instance,
• inflation, exchange rate movements (including devaluations), exchange
for the year ended December 31, 2013, 100% of our crude oil and condensate
control policies (including restrictions on remittance of dividends), price
sales in Chile were made to ENAP, the Chilean state-owned oil company,
instability and fluctuations in interest rates;
and 20.9% of our crude oil and condensate sales in Colombia were made
• liquidity of domestic capital and lending markets;
to Hocol, a subsidiary of Ecopetrol, the Colombian state-owned oil and gas
GeoPark 20F
51
company. In addition, our recent Rio das Contas acquisition in Brazil provides
legislation or health and safety, this could have a material adverse effect
us with a long-term off-take contract with Petrobras, the Brazilian state-
on our business, financial condition and results of operations.
owned company, that covers approximately 74% of net proved gas reserves
in the Manatí Field. If we, the respective host governments and the national
Additionally, we are dependent on receipt of Colombian government
oil companies are not able to cooperate with one another, it could have
approvals or permits to develop the concessions we hold in Colombia. There
an adverse impact on our business, operations and prospects.
can be no assurance that future political conditions in Colombia will not
result in the Colombian government adopting different policies with respect
Oil and natural gas companies in Chile, Colombia, Brazil and Argentina
to foreign development and ownership of oil, environmental protection,
do not own any of the oil and natural gas reserves in such countries.
health and safety or labor relations. This may affect our ability to undertake
exploration and development activities in respect of present and future
Under Chilean, Colombian, Brazilian and Argentine law, all onshore and
properties, as well as our ability to raise funds to further such activities. Any
offshore hydrocarbon resources in these countries are owned by the
delays in receiving Colombian government approvals, permits or no
respective sovereign. Although we are the operator of the majority of
objection certificates may delay our operations or may affect the status of
the blocks and concessions in which we have a working and/or economic
our contractual arrangements or our ability to meet contractual obligations.
interest and generally have the power to make decisions as how to
market the hydrocarbons we produce, the Chilean, Colombian, Brazilian
Pursuant to Article 20 of the Brazilian Constitution and Article 3 of Law No.
and Argentine governments have full authority to determine the rights,
9,478, dated as of August 6, 1997, as amended, or the Brazilian Petroleum
royalties or compensation to be paid by or to private investors for
Law, oil, natural gas and hydrocarbon reserves located within the Brazilian
the exploration or production of any hydrocarbon reserves located in
territory, which encompasses onshore and offshore reserves, as well as
their respective countries.
deposits in the Brazilian continental shelf, territorial waters and exclusive
economic zone, are considered assets of the Brazilian government. Therefore,
Under the Chilean Constitution, the state is the exclusive owner of all mineral
the concessionaire owns only the oil and natural gas that it produces under
and fossil substances, including hydrocarbons, regardless of who owns the
the concession agreements. Oil and natural gas companies in Brazil acquire
land on which the reserves are located. The exploration and exploitation
the exclusive right to explore, develop and produce reserves discovered
of hydrocarbons may be carried out by the state, companies owned by state
within certain concession areas pursuant to concession agreements awarded
or private persons through administrative concessions granted by the
by the Brazilian government. However, if the Brazilian government were to
President of Chile by Supreme Decree or by CEOPs executed by the Minister
restrict or prevent concessionaires, including us, from exploiting these oil and
of Energy. Hydrocarbon exploration and exploitation activities are regulated
natural gas reserves, or interfere in the sale or transfer of the production,
by the Chilean Ministry of Energy. In Chile, a participant is granted rights to
our ability to generate income would be materially adversely affected, which
explore and exploit certain assets under a CEOP. Although the government
would have a material adverse effect on our business, financial condition
cannot unilaterally modify or terminate the rights granted in the CEOP once
and results of operations.
it is signed, if a participant fails to complete certain obligations under a
CEOP, such participant may lose the right to exploit certain areas or may be
Companies in the Brazilian oil and natural gas industry also rely primarily
required to return all or a portion of the awarded areas back to Chile.
on the public auction process regulated by the ANP to acquire rights to
In Colombia, oil and natural gas companies have acquired the exclusive
certain basins in future bidding rounds, there is a risk that future bidding
right to explore, develop and produce reserves discovered within certain
rounds may not take place or that they do not include desirable locations,
concession areas, pursuant to concession agreements awarded by the
since they are conducted by and under the Brazilian government’s discretion,
Colombian government through the ANH or, prior to 2004, entered into with
which could have a material adverse effect on our business, expected results
explore oil and natural gas reserves. While the ANP may offer concessions in
Ecopetrol. However, a concessionaire owns only the oil and natural gas that
of operations and financial condition.
it extracts under the concession agreements to which it is a party. If the
Colombian government were to restrict or prevent concessionaires, including
In Argentina, jurisdiction over oil and gas activities is now largely vested
us, from exploiting these oil and natural gas reserves, or otherwise interfere
in the same provincial states who own the relevant underground oil and gas
with our exploration through regulations with respect to restrictions on
resources. The Federal Executive Branch is still empowered to design
future exploration and production, price controls, export controls, foreign
and rule federal energy policy and to rule on domestic inter-jurisdictional
exchange controls, income taxes, expropriation of property, environmental
and international oil and gas transportation concessions and has, for example,
52
GeoPark 20F
imposed measures controlling oil and gas investments in the provincial
expenditures and required divestments. Existing Colombian regulation
states. Private companies must obtain exploration permits or exploitation
applies to virtually all aspects of our concessions or E&P Contracts in Colombia.
concessions from the provincial states or otherwise enter into certain types
The terms and conditions of the agreements with the ANH generally reflect
of joint venture or association agreements with provincial state-owned
negotiations with the ANH and other Colombian governmental authorities,
oil and gas companies in order to undertake exploration and production
and may vary by fields, basins and hydrocarbons discovered.
activities onshore, and must enter into certain types of joint venture or
association agreements with the federally-owned oil and gas company,
We are required, as are all oil companies undertaking exploratory and
ENARSA, to undertake these activities offshore. Additionally, whereas until
production activities in Colombia, to pay a percentage of our expected
2012, exploration permit and exploitation concession holders had the
production to the Colombian government as royalties. The Colombian
right to freely dispose of and market up to 70% of the production they
government has modified the royalty program for oil and natural gas
generated, on July 28th, 2012, the publication of Presidential Decree
production several times in the last 20 years, as it has modified the regime
1277/2012 abrogated this right. As of December 31, 2013, our production
regulating new contracts entered into with the Colombian government.
in Argentina represented less than 0.5% of our total production, though
The royalty regime for contracts being entered into today for conventional
recent regulations affecting the oil and gas industry in Argentina may have
oil is tied to a scale ring-fenced by field starting at 8% for production
an adverse impact on our business, operations and prospects in Argentina.
of up to 5,000 mbopd and increases up to 25% for production above
Oil and gas operators are subject to extensive regulation in the countries
our assets are located, range between 8% and 25%. Furthermore, production
600,000 mbopd. Royalties for natural gas production of onshore blocks where
in which we operate.
of unconventional resources discovered as of May 19, 2012 is subject to
royalties equivalent to 60% of the royalties applicable to conventional oil.
In Chile, rights to exploration and exploitation of a particular area are
established in a CEOP. According to article 19, No 24 of the Chilean
In Brazil, the oil and natural gas industry is subject to extensive regulation
Constitution, the President of Chile has the power to determine the terms
and intervention by the Brazilian government in such matters as the
and conditions for the granting of a particular CEOP. In addition, the CEOP
award of exploration and production interests, taxation and foreign currency
is subject to extensive supervision by the government through the Chilean
controls. Ultimately, those regulations may also address restrictions on
Ministry of Energy. The President of Chile may also decide to terminate
production, price controls, mandatory divestments of assets and
a CEOP early, though with compensation to the counterparty, and only
nationalization, expropriation or cancellation of contractual rights.
if the relevant area is located within an area declared relevant for national
security reasons.
Under these laws and regulations, there is potential liability for personal
injury, property damage and other types of damages. Failure to comply
Although the government of Chile cannot unilaterally modify the rights
with these laws and regulations also may result in the suspension or
granted in the CEOP once it is signed, exploration and exploitation are
termination of operations or our being subjected to administrative, civil
nonetheless subject to significant government regulations, such as
regulations concerning the environment, tort liability, health and safety and
and criminal penalties, which could have a material adverse effect on
our financial condition and expected results of operations. We expect to
labor, all of which have an impact on our business and operations. Changes
also operate in a consortium in some of our concessions, which, under
in laws and regulations could have an adverse effect on the costs and timing
the Brazilian Petroleum Law, establishes joint and strict liability among
of our operations. For example, in November 2012, the government
consortium members. If the operator does not maintain the appropriate
approved new regulations governing the abandonment of oilfield operations
licenses, the consortium may suffer administrative penalties, including
that would require us to obtain prior approval for new oil wells and could
fines of R$10 to R$500 million.
also require us to post a bond in connection with the abandonment or
closure of an oil well.
In addition, the local content policy, which is a contractual requirement
in a Brazilian concession agreements, has become a significant issue for oil
The Colombian hydrocarbons industry is subject to extensive regulation
and natural gas companies operating in Brazil given the penalties related
and supervision by the government in matters such as the environment,
with breaches thereof. The local content requirement will also apply to the
tort liability, health and safety, labor, the award of exploration and production
production sharing contract regime. See “Item 4. Information on the
contracts by the ANH, the imposition of specific drilling and exploration
Company—B. Business overview—Brazil.”
obligations, taxation, foreign currency controls, price controls, capital
GeoPark 20F
53
The Argentine hydrocarbons industry is also extensively regulated both by
In Argentina, since 2001, the Argentine government has imposed and
federal and provincial state regulations in matters including the award
expanded upon exchange controls and restrictions on the transfer
of exploration permits and exploitation concessions, investment, royalty,
of U.S. dollars outside of Argentina, which substantially limit the ability
canon, price controls, export restrictions and domestic market supply
of companies to retain foreign currency or make payments abroad.
obligations. The terms of our exploitation concessions are embodied in
These and other measures have led the implied AR$/US$ exchange rate as
Decrees and Administrative Decisions issued by the Federal Executive
reflected in the quotations for certain Argentine securities that trade in
Power and incorporate statutory rights and obligations provided under the
foreign markets to differ substantially from the official foreign exchange rate
Hydrocarbons Law. The federal government is further empowered to
in Argentina. If the Argentine government decides once again to tighten
design and implement federal energy policy and to rule on domestic inter-
the restrictions on the transfer of funds, we may be unable to make payments
jurisdictional and international oil and gas transportation concessions,
related to the import of products and services, which could have a material
and has used these powers to establish export restrictions and duties,
adverse effect on us.
induce private companies to enter into price stability agreements with the
government or otherwise impose price control regulations or create incentive
Additionally, in May 2012, the Argentine government expropriated 51%
programs to promote increased production. Jurisdictional controversies
of YPF’s capital stock owned by Repsol YPF of Spain, and 51% of the capital
among the federal government and the provincial states are not uncommon.
stock of Repsol YPF Gas owned by Repsol Butano.
Significant expenditures may be required to ensure our compliance with
There can be no assurance that future economic, social and political
governmental regulations related to, among other things, licenses for
developments in the countries in which we operate currently or in the future,
drilling operations, environmental matters, drilling bonds, reports concerning
which are out of our control, may impair our business, financial condition
operations, the spacing of wells, unitization of oil and natural gas
and results of operations.
accumulations, local content policy and taxation.
Governmental actions in the countries in which we operate and in which
we operate and in which we may operate in the future.
Our operations may be affected by tax reforms in the countries in which
we may operate in the future may adversely affect our business, financial
condition and results of operations.
Our operations may be affected by changes in tax laws in the countries in
which we operate and in which we may operate in the future. For example,
Our business, financial condition and results of operations may be adversely
in early April 2014, the Chilean government put forth a proposal for an
affected by actions taken by the Chilean, Colombian, Brazilian or Argentine
income tax-reform which is designed to increase government revenues. The
governments concerning the economy, including actions aimed at targeting
proposed tax reform eliminates certain tax structures that were previously
inflation, interest rates, oil and gas price controls, foreign exchange controls
beneficial to large companies, including deferral of taxes paid on reinvested
and taxes.
Brazil has in the past periodically experienced extremely high rates of
company profits. Although, as of the date of this annual report, we cannot
estimate the full impact of these proposed tax reforms on our Chilean
operations, there can be no assurance that these tax reforms will not be
inflation. As measured by the National Consumer Price Index ( Índice Nacional
implemented and have an adverse impact on our cash flow and profitability
de Preços ao Consumidor Amplo ), Brazil had annual rates of inflation of 5.9%
due to the loss of certain advantageous tax structures.
in 2010, 6.5% in 2011, 5.8% in 2012 and 5.9% in 2013. Brazil may experience
high levels of inflation in the future. Periods of higher inflation may slow
In Brazil, the Brazilian government frequently implements changes to tax and
the rate of growth of the Brazilian economy. Although the long-term off-take
social security regimes that may affect us and our customers. These changes
contract covering gas production in the Manatí Field is indexed to inflation,
include changes in prevailing tax and contribution rates and, occasionally,
inflation is likely to increase some of our costs and expenses, and, as a result,
enactment of temporary taxes, the proceeds of which are earmarked for
may reduce our profit margins and net income. Inflationary pressures could
designated governmental purposes. Some of these changes in tax laws may
also lead to counter-inflationary prices that may harm our business. Any
result in increases in our tax payments, which could materially adversely
decline in our expected net sales or net income could lead to a deterioration
affect our profitability and increase the prices of our products and services,
in our financial condition.
restrict our ability to do business in our existing and target markets and cause
our results of operations to suffer. There can be no assurance that we will be
54
GeoPark 20F
able to maintain our projected cash flow and profitability following any
adversely affected. In particular, we face risks in Argentina related to
increase in taxes applicable to us and to our operations.
the following: restrictions on Argentina’s energy supplies and an inadequate
governmental response to such restrictions, which could negatively affect
Colombia has experienced and continues to experience internal security
Argentina’s economic activity; social and political tensions and the
issues that have had or could have a negative effect on the Colombian
governmental response to such tensions; requirements of the Federal
economy.
General Environmental Law, which requires persons who carry out activities
that are potentially hazardous to the environment to obtain insurance;
Colombia has experienced internal security issues, primarily due to the
and tax implications under Argentine law with respect to our incorporation
activities of guerrillas, including the Revolutionary Armed Forces of
in Bermuda, which may subject our Argentine subsidiaries to higher tax rates.
Colombia ( Fuerzas Armadas Revolucionarias de Colombia ), or the FARC,
paramilitary groups and drug cartels. In the past, guerrillas have targeted
Risks related to our common shares
the crude oil pipelines, including the Oleoducto Transandino, Caño
Limón-Coveñas and Ocensa pipelines, and other related infrastructure
An active, liquid and orderly trading market for our common shares may
disrupting the activities of certain oil and natural gas companies. On several
not develop and the price of our stock may be volatile, which could limit
occasions guerilla attacks have resulted in unscheduled shut-downs of
your ability to sell our common shares.
the transportation systems in order to repair damaged sections and
undertake clean-up activities. These activities, their possible escalation and
Our common shares began to trade on the New York Stock Exchange
the effects associated with them have had and may have in the future a
on February 7, 2014, and as a result have a limited trading history. We cannot
negative impact on the Colombian economy or on our business, which may
predict the extent to which investor interest in our company will maintain
affect our employees or assets. In the context of the political instability,
an active trading market on the NYSE, or how liquid that market will be
allegations have been made against members of the Colombian Congress
in the future.
and against government officials for possible ties with guerilla groups.
This situation may have a negative impact on the credibility of the
The market price of our common shares may be volatile and may be
Colombian government, which could in turn have a negative impact on
influenced by many factors, some of which are beyond our control, including:
the Colombian economy or on our business in the future.
• our operating and financial performance and identified potential drilling
locations, including reserve estimates;
The Colombian government commenced peace talks with the FARC in
• quarterly variations in the rate of growth of our financial indicators, such as
August 2012. Our business, financial condition and results of operations
net income per common share, net income and revenues;
could be adversely affected by rapidly changing economic or social
• changes in revenue or earnings estimates or publication of reports by
conditions, including the Colombian government’s response to current
equity research analysts;
peace negotiations which may result in legislation that increases our tax
• speculation in the press or investment community;
burden or that of other Colombian companies. Tensions with neighboring
countries may affect the Colombian economy and, consequently, our
• sales of our common shares by us or our shareholders, or the perception
that such sales may occur;
results of operations and financial condition.
• involvement in litigation;
• changes in personnel;
In addition, from time to time, community protests and blockades may arise
• announcements by the company;
near our operations in Colombia, which could adversely affect our business,
• domestic and international economic, legal and regulatory factors unrelated
financial condition or results of operations.
to our performance.
Our operations may be adversely affected by political and economic
• volatility in our industry, the industries of our customers and the global
circumstances in Argentina.
securities markets;
• changes in our dividend policy;
Some of our current operations and management offices are located in
• risks relating to our business and industry, including those discussed above;
Argentina. If local political or economic trends adversely affect the Argentine
• strategic actions by us or our competitors;
economy, our financial condition and results from operations could be
• variations in our quarterly operating results;
GeoPark 20F
55
• actual or expected changes in our growth rates or our competitors’
in the form of loans, dividends, distributions or otherwise. The ability of our
growth rates;
subsidiaries to distribute cash to us is also subject to, among other things,
• investor perception of us, the industry in which we operate, the investment
restrictions that are contained in our and our subsidiaries’ financing
opportunity associated with our common shares and our future performance;
(including our Notes due 2020 and GeoPark Brazil’s loan to finance Rio das
• adverse media reports about us or our directors and officers;
Contas) and joint venture agreements (principally our agreements with LGI),
• addition or departure of our executive officers;
availability of sufficient funds in such subsidiaries and applicable state laws
• change in coverage of our company by securities analysts;
and regulatory restrictions. Claims of creditors of our subsidiaries generally
• trading volume of our common shares;
will have priority as to the assets of such subsidiaries over our claims and
• future issuances of our common shares or other securities;
claims of our creditors and stockholders. To the extent the ability of our
• terrorist acts;
subsidiaries to distribute dividends or other payments to us could be limited
• the release or expiration of lock-up or other transfer restrictions on our
in any way, our business, financial condition and results of operations, as well
outstanding common shares.
as our ability to pay dividends on the common shares, could be materially
adversely affected.
We have never declared or paid, and do not intend to pay in the foreseeable
future, cash dividends on our common shares, and, consequently, your
Additionally, we may not be able to fully control the operations and the
only opportunity to achieve a return on your investment is if the price of our
assets of our joint ventures and we may not be able to make major
stock appreciates.
decisions or take timely actions with respect to our joint ventures unless
our joint venture partners agree. For example, we have entered into
We have never paid, and do not intend to pay in the foreseeable future, cash
shareholder agreements with LGI in Chile and Colombia that limit the amount
dividends on our common shares. Any decision to pay dividends in the
of dividends that can be declared or returned to us, certain aspects related
future, and the amount of any distributions, is at the discretion of our board
to the management of our Chilean and Colombian businesses, the incurrence
of directors and our shareholders, and will depend on many factors, such
of indebtedness, liens and our ability to sell certain assets. See “—Risks
as our results of operations, financial condition, cash requirements, prospects
relating to our business—LGI, our strategic partner in Chile and Colombia,
and other factors.
may sell its interest in our Chilean and Colombian operations to a third party
or may not consent to our taking certain actions.” We may, in the future,
We are also subject to Bermuda legal constraints that may affect our ability
enter into other joint venture agreements imposing additional restrictions
to pay dividends on our common shares and make other payments. Under
on our ability to pay dividends.
the Bermuda Companies Act, we may not declare or pay a dividend if there
are reasonable grounds for believing that we are, or would after the payment
Sales of substantial amounts of our common shares in the public market,
be, unable to pay our liabilities as they become due or that the realizable
or the perception that these sales may occur, could cause the market
value of our assets would thereafter be less than our liabilities. We are also
price of our common shares to decline.
subject to contractual restrictions under certain of our indebtedness.
We are a holding company dependent upon dividends from our
future, for example, to finance potential acquisitions of assets, which we
subsidiaries, which may be limited by law and by contract from making
intend to continue to pursue. Sales of substantial amounts of our common
distributions to us, which would affect our ability to pay dividends
shares in the public market, or the perception that these sales may occur,
We may issue additional common shares or convertible securities in the
on the common shares.
could cause the market price of our common shares to decline. This could
also impair our ability to raise additional capital through the sale of our
As a holding company, our only material assets are our cash on hand, the
equity securities. Under our memorandum of association, we are authorized
equity interests in our subsidiaries and other investments. Our principal
to issue up to 5,171,949,000 common shares, of which 57,863,615 common
source of revenues and cash flow is distributions from our subsidiaries. Thus,
shares were outstanding as of the date of this annual report. We cannot
our ability to pay dividends on the common shares will be contingent upon
predict the size of future issuances of our common shares or the effect,
the financial condition of our subsidiaries. Our subsidiaries are and will be
if any, that future sales and issuances of shares would have on the market
separate legal entities, and although they may be wholly-owned or controlled
price of our common shares.
by us, they have no obligation to make any funds available to us, whether
56
GeoPark 20F
Provisions of the Notes due 2020 could discourage an acquisition of us
Securities Exchange Act of 1934, as amended, or the Exchange Act. Although
by a third party.
we intend to report quarterly financial results and report certain material
events, we are not required to file quarterly reports on Form 10-Q or provide
Certain provisions of the Notes due 2020 could make it more difficult
current reports on Form 8 K disclosing significant events within four days
or more expensive for a third party to acquire us, or may even prevent a
of their occurrence and our quarterly or current reports may contain less
third party from acquiring us. For example, upon the occurrence of a
information than required under U.S. filings. In addition, we are exempt from
fundamental change, holders of the Notes due 2020 will have the right,
the Section 14 proxy rules, and proxy statements that we distribute will
at their option, to require us to repurchase all of their notes at a purchase
not be subject to review by the SEC. Our exemption from Section 16 rules
price equal to 101% of the principal amount thereof plus any accrued
regarding sales of common shares by insiders means that you will have less
and unpaid interest (including any additional amounts, if any) to the date
data in this regard than shareholders of U.S. companies that are subject
of purchase. By discouraging an acquisition of us by a third party, these
to the Exchange Act. As a result, you may not have all the data that you are
provisions could have the effect of depriving the holders of our common
accustomed to having when making investment decisions. For example, our
shares of an opportunity to sell their common shares at a premium over
officers, directors and principal shareholders are exempt from the reporting
prevailing market prices.
and “short-swing” profit recovery provisions of Section 16 of the Exchange
Act and the rules thereunder with respect to their purchases and sales
Certain shareholders have substantial control over us and could limit
of our common shares. The periodic disclosure required of foreign private
your ability to influence the outcome of key transactions, including
issuers is more limited than that required of domestic U.S. issuers and there
a change of control.
may therefore be less publicly available information about us than is regularly
published by or about U.S. public companies. See “Item 10. Additional
Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief
Information—H. Documents on display.”
Executive Officer, Mr. Juan Cristóbal Pavez, a director and Mr. Steven J.
Quamme, a director, control approximately 48% of our outstanding common
As a foreign private issuer, we will be exempt from complying with certain
shares as of the date of this annual report, holding the shares either directly
corporate governance requirements of the NYSE applicable to a U.S. issuer,
or through privately held funds which they control. As a result, these
including the requirement that a majority of our board of directors consist of
shareholders, if acting together, would be able to influence or control matters
independent directors. As the corporate governance standards applicable
requiring approval by our shareholders, including the election of directors
to us are different than those applicable to domestic U.S. issuers, you may not
and the approval of amalgamations, mergers or other extraordinary
have the same protections afforded under U.S. law and the NYSE rules as
transactions. They may also have interests that differ from yours and may
shareholders of companies that do not have such exemptions.
vote in a way with which you disagree and which may be adverse to
your interests. The concentration of ownership may have the effect of
We are an “emerging growth company,” and we cannot be certain if the
delaying, preventing or deterring a change of control of our company, could
reduced disclosure requirements applicable to emerging growth companies
deprive our stockholders of an opportunity to receive a premium for their
common shares as part of a sale of our company and might ultimately affect
will make our common shares less attractive to investors.
the market price of our common shares. See “Item 7. Major Shareholders
We are an “emerging growth company,” as defined in the JOBS Act, and for
and Related Party Transactions—A. Major shareholders” for a more detailed
as long as we continue to be an “emerging growth company” we may choose
description of our share ownership
to take advantage of certain exemptions from various reporting requirements
that are applicable to other public companies that are not “emerging growth
As a foreign private issuer, we are subject to different U.S. securities laws
companies,” including, but not limited to, not being required to comply
and NYSE governance standards than domestic U.S. issuers. This may
with the auditor attestation requirements of Section 404(b) of the Sarbanes
afford less protection to holders of our common shares, and you may not
Oxley Act. We cannot predict if investors will find our common shares less
receive corporate and company information and disclosure that you
attractive because we will rely on these exemptions. If some investors find our
are accustomed to receiving or in a manner in which you are accustomed
common shares less attractive as a result, there may be a less active trading
to receiving it.
market for our common shares and our share price may be more volatile.
As a foreign private issuer, the rules governing the information that we
Under the JOBS Act, emerging growth companies can delay adopting new
disclose differ from those governing U.S. corporations pursuant to the
or revised accounting standards until such time as those standards apply
GeoPark 20F
57
to private companies. We have irrevocably elected not to avail ourselves of
We will continue to incur significantly increased costs and devote
this exemption from new or revised accounting standards, and, therefore,
substantial management time as a result of operating as a public company.
we will be subject to the same new or revised accounting standards as other
public companies that are not emerging growth companies.
Our recent initial public offering will have a significant transformative effect
Our internal controls over financial reporting may not be effective which
expenses as a result of having publicly traded common shares listed on
could have a significant and adverse effect on our business and reputation.
the NYSE. We will also incur costs which we have not incurred previously,
We intend to evaluate our internal controls over financial reporting in
directors and officers insurance, investor relations, and various other costs
including, but not limited to, costs and expenses for directors’ fees, increased
on us. We expect to incur significant legal, accounting, reporting and other
order to allow management to report on, our internal controls over financial
of a public company.
reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002,
as amended, and rules and regulations of the United States Securities and
We also anticipate that we will incur costs associated with corporate
Exchange Commission (the “SEC”) thereunder, which we refer to as “Section
governance requirements, including requirements under the Sarbanes Oxley
404.” The process of documenting and testing our internal control
Act of 2002, as well as rules implemented by the SEC and NYSE. We expect
procedures in order to satisfy the requirements of Section 404 requires
these rules and regulations to increase our legal and financial compliance
annual management assessments of the effectiveness of our internal controls
costs and make some management and corporate governance activities more
over financial reporting. During the course of our internal testing, we may
time-consuming and costly, particularly after we are no longer an “emerging
identify deficiencies of which we are not currently aware.
growth company.” These rules and regulations may make it more difficult
and more expensive for us to obtain director and officer liability insurance,
In addition, if we fail to achieve and maintain the adequacy of our internal
and we may be required to accept reduced policy limits and coverage or incur
controls, as such standards are modified, supplemented or amended from
substantially higher costs to obtain the same or similar coverage. This could
time to time, we may not be able to ensure that we can conclude on an
have an adverse impact on our ability to recruit and bring on a qualified
ongoing basis that we have effective internal controls over financial reporting
independent board.
in accordance with Section 404. We are not currently required to furnish a
report on our internal control over financial reporting and we expect that this
The additional demands associated with being a public company listed
rule will apply to us when we file our annual report on Form 20-F for our
on the NYSE may disrupt regular operations of our business by diverting the
fiscal year ending December 31, 2014, which we will be required to file by
attention of some of our senior management team away from revenue-
April 30, 2015. In addition, we are not currently required to include an
producing activities to management and administrative oversight, adversely
attestation report of our auditors on our assessment of internal controls over
affecting our ability to attract and complete business opportunities and
financial reporting pursuant to the SEC’s rules under Section 404, for as
increasing the difficulty in both retaining professionals and managing and
long as we continue to be an “emerging growth company”. We cannot be
growing our businesses. Any of these effects could harm our business,
certain as to the timing of completion of our evaluation, testing and any
remediation actions or the impact of the same on our operations. If we are
financial condition and results of operations.
not able to implement the requirements of Section 404 in a timely manner
There are regulatory limitations on the ownership and transfer of our
or with adequate compliance, we may not be able to certify as to the
common shares which could result in the delay or denial of any transfers
effectiveness of our internal controls over financial reporting and we may
you might seek to make.
be subject to sanctions, stock exchange delisting or investigation by
regulatory authorities, such as the SEC.
The Bermuda Monetary Authority, or the BMA, must specifically approve all
issuances and transfers of securities of a Bermuda exempted company like
As a result, there could be a negative reaction in the financial markets due
us unless it has granted a general permission. We are able to rely on a general
to a loss of confidence in the reliability of our financial statements. This
permission from the BMA to issue our common shares, and to freely transfer
could harm our reputation and may otherwise negatively affect our financial
of our common shares as long as the common shares are listed on the NYSE
condition, results of operations and cash flows. In addition, we may be
and/or other appointed stock exchange, to and among persons who are
required to incur costs in improving our internal control system and the hiring
non-residents of Bermuda for exchange control purposes. Any other transfers
of additional personnel.
remain subject to approval by the BMA and such approval may be denied
or delayed.
58
GeoPark 20F
We are a Bermuda company, and it may be difficult for you to enforce
United States. As a Bermuda company, we are governed by our memorandum
judgments against us or against our directors and executive officers.
of association and bye-laws and Bermuda company law. The provisions
of the Bermuda Companies Act, which applies to us, differs in some material
We are incorporated as an exempted company under the laws of Bermuda
respects from laws generally applicable to U.S. corporations and shareholders,
and substantially all of our assets are located in Chile, Colombia, Argentina
including the provisions relating to interested directors, mergers and
and Brazil. In addition, most of our directors and executive officers reside
acquisitions, takeovers, shareholder lawsuits and indemnification of directors.
outside the United States and all or a substantial portion of the assets of such
Set forth below is a summary of these provisions, as well as modifications
persons are located outside the United States. As a result, it may be difficult
adopted pursuant to our bye-laws, which differ in certain respects
or impossible to effect service of process within the United States upon us, or
from provisions of Delaware corporate law. Our shareholders approved the
to recover against us on judgments of U.S. courts, including judgments
adoption of new bye-laws which came into effect on February 19, 2014, being
predicated upon the civil liability provisions of the U.S. federal securities laws.
the date on which the company cancelled admission of its common shares
Further, no claim may be brought in Bermuda against us or our directors
on AIM. Because the following statements are summaries, they do not discuss
and officers in the first instance for violation of U.S. federal securities laws
all aspects of Bermuda law that may be relevant to us and our shareholders.
because these laws have no extraterritorial application under Bermuda law
and do not have force of law in Bermuda. However, a Bermuda court may
Interested Directors. Under our bye-laws and The Companies Act, 1981(as
impose civil liability, including the possibility of monetary damages, on us or
amended) of Bermuda, or the Bermuda Companies Act, a director shall
our directors and officers if the facts alleged in a complaint constitute or
declare the nature of his interest in any contract or arrangement with the
give rise to a cause of action under Bermuda law.
company. Our bye-laws further provide that a director so interested shall not,
except in particular circumstances, be entitled to vote or be counted in the
There is no treaty in force between the United States and Bermuda providing
quorum at a meeting in relation to any resolution in which he has an interest,
for the reciprocal recognition and enforcement of judgments in civil and
which is to his knowledge, a material interest (otherwise than by virtue
commercial matters. As a result, whether a United States judgment would be
of his interest in shares or debentures or other securities of or otherwise in
enforceable in Bermuda against us or our directors and officers depends
or through the company). In addition, the director will not be liable to us
on whether the U.S. court that entered the judgment is recognized by the
for any profit realized from the transaction. In contrast, under Delaware law,
Bermuda court as having jurisdiction over us or our directors and officers,
such a contract or arrangement is voidable unless it is approved by a majority
as determined by reference to Bermuda conflict of law rules. A judgment
of disinterested directors or by a vote of shareholders, in each case if the
debt from a U.S. court that is final and for a sum certain based on U.S. federal
material facts as to the interested director’s relationship or interests are
securities laws will not be enforceable in Bermuda unless the judgment
disclosed or are known to the disinterested directors or shareholders, or such
debtor had submitted to the jurisdiction of the U.S. court, and the issue of
contract or arrangement is fair to the corporation as of the time it is approved
submission and jurisdiction is a matter of Bermuda (not U.S.) law.
or ratified. Additionally, such interested director could be held liable for a
transaction in which such director derived an improper personal benefit.
In addition, and irrespective of jurisdictional issues, the Bermuda courts will
not enforce a U.S. federal securities law that is either penal or contrary to
Amalgamations, Mergers and Similar Arrangements. Pursuant to the Bermuda
Bermuda public policy. An action brought pursuant to a public or penal law,
Companies Act, the amalgamation or merger of a Bermuda company with
the purpose of which is the enforcement of a sanction, power or right at
another company or corporation requires the amalgamation or merger
the instance of the state in its sovereign capacity, will not be entertained by a
agreement to be approved by the company’s board of directors and by
Bermuda court. Certain remedies available under the laws of U.S. jurisdictions,
its shareholders. Shareholder approval is not required where (i) the holding
including certain remedies under U.S. federal securities laws, would not be
company and one or more of its wholly-owned subsidiary companies
available under Bermuda law or enforceable in a Bermuda court, as they
amalgamate or merge or (ii) two or more wholly-owned subsidiary companies
would be contrary to Bermuda public policy.
of the same holding company amalgamate or merge. Save for such “short-
Bermuda law differs from the laws in effect in the United States and might
otherwise, the approval of 75% of the shareholders voting at such meeting
form” amalgamations or mergers, unless the company’s bye-laws provide
afford less protection to shareholders.
is required to approve the amalgamation or merger agreement, and the
quorum for such meeting must be two persons holding or representing more
Our shareholders could have more difficulty protecting their interests than
than one-third of the issued shares of the company. Under our bye-laws,
would shareholders of a corporation incorporated in a jurisdiction of the
an amalgamation or merger will require the approval of our board of directors
GeoPark 20F
59
and of our shareholders by Special Resolution, meaning a resolution adopted
applicable law. In such actions, the court has discretion to permit the winning
by 65% of more of the votes cast by shareholders who (being entitled to do
party to recover attorneys’ fees incurred in connection with such action.
so) vote in person or by proxy at any general meeting of the shareholders
iin accordance with the provisions of the bye-laws. Under Bermuda law, in the
Indemnification of Directors. We may indemnify our directors and officers in
event of an amalgamation or merger of a Bermuda company with another
their capacity as directors or officers for any loss arising or liability attaching
company or corporation, a shareholder of the Bermuda company who is
to them by virtue of any rule of law in respect of any negligence, default,
not satisfied that fair value has been offered for such shareholder’s shares
breach of duty or breach of trust of which a director or officer may be guilty
may, within one month of notice of the shareholders meeting, apply to
in relation to the company other than in respect of his own fraud or
the Supreme Court of Bermuda to appraise the fair value of those shares.
dishonesty. Our bye-laws provide that we shall indemnify our officers and
Under Delaware law, with certain exceptions, a merger, consolidation or sale
directors in respect of their acts and omissions, except in respect of their
of all or substantially all the assets of a corporation must be approved by
fraud or dishonesty, or to recover any gain, personal profit or advantage to
the board of directors and a majority of the issued and outstanding shares
which such Director is not legally entitled, and (by incorporation of the
entitled to vote thereon. Under Delaware law, a shareholder of a corporation
provisions of the Bermuda Companies Act) that we may advance moneys to
participating in certain major corporate transactions may, under certain
our officers and directors for the costs, charges and expenses incurred by our
circumstances, be entitled to appraisal rights pursuant to which such
officers and directors in defending any civil or criminal proceedings against
shareholder may receive cash in the amount of the fair value of the shares
them on condition that the directors and officers repay the moneys if any
held by such shareholder (as determined by a court) in lieu of the
allegations of fraud or dishonesty is proved against them provided, however,
consideration such shareholder would otherwise receive in the transaction.
that, if the Bermuda Companies Act requires, and advancement of expenses
shall be made only upon delivery to the Company of an undertaking, by
Shareholders’ Suit. Class actions and derivative actions are generally not
or on behalf of such indemnitee, to repay all amounts if it shall ultimately be
available to shareholders under Bermuda law. The Bermuda courts, however,
determined by final decision that such indemnitee is not entitled to be
would ordinarily be expected to permit a shareholder to commence an
indemnified for such expenses under our Bye-law. Under Delaware law, a
action in the name of a company to remedy a wrong to the company where
corporation may indemnify a director or officer of the corporation against
the act complained of is alleged to be beyond the corporate power of
expenses (including attorneys’ fees), judgments, fines and amounts paid
the company or illegal, or would result in the violation of the company’s
in settlement actually and reasonably incurred in defense of an action, suit or
memorandum of association or bye-laws. Furthermore, consideration would
proceeding by reason of such position if such director or officer acted in good
be given by a Bermuda court to acts that are alleged to constitute a fraud
faith and in a manner he or she reasonably believed to be in or not opposed
against the minority shareholders or where an act requires the approval
to the best interests of the corporation and, with respect to any criminal
of a greater percentage of the company’s shareholders than that which
action or proceeding, such director or officer had no reasonable cause to
actually approved it.
believe his or her conduct was unlawful. In addition, we have entered into
customary indemnification agreements with our directors.
When the affairs of a company are being conducted in a manner which is
oppressive or prejudicial to the interests of some part of the shareholders,
As a result of these differences, investors could have more difficulty
one or more shareholders may apply under the Bermuda Companies Act
protecting their interests than would shareholders of a corporation
for an order of the Supreme Court of Bermuda, which may make such order
incorporated in the United States.
as it sees fit, including an order regulating the conduct of the company’s
affairs in the future or ordering the purchase of the shares of any shareholders
We may become subject to taxes in Bermuda after March 31, 2035,
by other shareholders or by the company.
which may have a material adverse effect on our results of operations.
Our bye-laws contain a provision by virtue of which we and our shareholders
Under current Bermuda law, we are not subject to tax on income or capital
waive any claim or right of action that they have, both individually and on our
gains. We have received from the Minister of Finance under The Exempted
behalf, against any director or officer in relation to any action or failure to take
Undertaking Tax Protection Act 1966, as amended, an assurance that, in
action by such director or officer, except in respect of any fraud or dishonesty
the event that Bermuda enacts legislation imposing tax computed on profits,
of such director or officer. Class actions and derivative actions generally are
income, any capital asset, gain or appreciation, or any tax in the nature of
available to shareholders under Delaware law for, among other things, breach
estate duty or inheritance, then the imposition of any such tax shall not
of fiduciary duty, corporate waste and actions not taken in accordance with
be applicable to us or to any of our operations or shares, debentures or other
60
GeoPark 20F
obligations, until March 31, 2035. We could be subject to taxes in Bermuda
ITEM 4. INFORMATION ON THE COMPANY
after that date. This assurance is subject to the provision that it is not to
be construed to prevent the application of any tax or duty to such persons
A. History and development of the company
as are ordinarily resident in Bermuda or to prevent the application of
any tax payable in accordance with the provisions of the Land Tax Act 1967
or otherwise payable in relation to any property leased to us. We are
General
We were incorporated as an exempted company pursuant to the laws of
incorporated in Bermuda as an exempted company and pay annual Bermuda
Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, our
government fees. In addition, all entities employing individuals in Bermuda
shareholders approved a change in our name to GeoPark Limited, effective
are required to pay a payroll tax and there are other sundry taxes payable,
from July 31, 2013. We maintain a registered office in Bermuda at Cumberland
directly or indirectly, to the Bermuda government. Neither we nor our
House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda. Our principal
Bermuda subsidiaries employ individuals in Bermuda as at the date of this
executive offices are located at Nuestra Señora de los Ángeles 179, Las
annual report.
Condes, Santiago, Chile, telephone number +562 2242 9600, and Florida 981,
1st floor, Buenos Aires, Argentina, telephone number +5411 4312 9400. Our
The transfer of our common shares may be subject to capital gains taxes
website is www.geo-park.com. The information on our website does not
pursuant to indirect transfer rules in Chile.
constitute part of this annual report.
In September 2012, Chile established “indirect transfer rules,” which impose
taxes, under certain circumstances, on capital gains resulting from indirect
Our company
We are an independent oil and natural gas exploration and production, or
transfers of shares, equity rights, interests or other rights in the equity,
E&P, company with operations in Latin America and a proven track record of
control or profits of a Chilean entity, as well as on transfers of other assets
growth in production, reserves and cash flows since 2006. We operate in
and property of permanent establishments or other businesses in Chile, or
Chile, Colombia, Brazil and, to a lesser extent, in Argentina, and also in 2014
the Chilean Assets. As we indirectly own Chilean Assets, the indirect transfer
further expanded our footprint in Brazil as a result of our Rio das Contas
rules would apply to transfers of our common shares provided certain
acquisition, which closed on March 31, 2014. See “B. Business Overview—
conditions outside of our control are met. If such conditions were present
Our operations—Operations in Brazil.”
and as a result the indirect transfer rules were to apply to sales of our
common shares, such sales would be subject to indirect transfer tax on the
We have a well-balanced portfolio of assets that includes working and/or
capital gain that may be determined in each transaction. For a description of
economic interests in 27 hydrocarbons blocks, 26 of which are onshore
the indirect transfer rules and the conditions of their application see “Item 10.
blocks, including eleven currently in production, as well as in an additional
Additional Information—E. Taxation—Chilean tax on transfers of shares.”
shallow- offshore concession in Brazil that includes the Manatí Field. In
addition, we have two new concessions in Brazil that are subject to
Our common shares will for a time trade on two separate stock markets,
confirmation of qualification requirements by the ANP. We produced a net
and investors seeking to take advantage of price differences between such
markets may create unexpected volatility in our share price; in addition,
average of 13,517 boepd during the year ended December 31, 2013, 51.5%
of which was produced in Chile, 48% of which was produced in Colombia
investors may not be able to easily move common shares for trading
and 0.5% of which was produced in Argentina, and of which 82% was oil.
between such markets.
As of December 31, 2013, we had net proved reserves of 20.1 mmboe
(composed of 74% oil and 26% natural gas), of which 10.7 mmboe, or 53%,
Our common shares are currently registered on the NYSE and the Santiago
and 9.4 mmboe, or 47%, were in Chile and Colombia, respectively. After
Offshore Stock Exchange. Although we intend to de-register from the
giving effect to the Rio das Contas acquisition on a pro forma basis, we
Santiago Offshore Stock Exchange as soon as practicable, our common
would have produced an average of 17,098 boepd during the year ended
shares will be traded on two markets for a period of time. During such time,
December 31, 2013, with Chile, Colombia and Brazil representing 41%, 38%
price levels for our common shares could fluctuate between markets,
and 21% of our production, respectively, and with oil representing 65%
independent of our share price on the other market. Investors could seek to
of our total production. Additionally, according to the D&M Reserves Report,
sell or buy our common shares to take advantage of any price differences
as of December 31, 2013, Rio das Contas had net proved reserves of
between the markets through a practice referred to as arbitrage. Any
8.3 mmboe (composed of approximately 98% natural gas).
arbitrage activity could create unexpected volatility in the price of our
common shares on the NYSE.
GeoPark 20F
61
We have built our company around three principal capabilities:
Brazil, which produced approximately 7.6% of the gas produced in Brazil
• as an Explorer, which is our ability, experience, methodology and
in the year ended December 31, 2013. Rio das Contas’s 10% working interest
creativity to find and develop oil and gas reserves in the subsurface, based
in the Manatí Field represented 3,580 boepd of production during 2013.
on the best science, solid economics and ability to take the necessary
We closed our Rio das Contas acquisition on March 31, 2014.
managed risks.
• as an Operator, which is our ability to execute in a timely manner and to
Separately, in September 2013, we entered into concession agreements with
have the know-how to profitably drill for, produce, treat, transport and sell
the ANP relating to seven new concessions in the onshore Recôncavo Basin
our oil and gas – with the drive and persistence to find solutions, overcome
in the State of Bahia and in the onshore Potiguar Basin in the State of Rio
obstacles, seize opportunities and achieve results.
Grande do Norte, or, our Round 11 concessions, and in November 2013,
• as a Consolidator, which is our ability and initiative to assemble the right
the ANP awarded us two additional concessions in the Parnaíba Basin in the
balance and portfolio of upstream assets in the right hydrocarbon basins
State of Maranh(cid:0) o and the Sergipe Alagoas Basin in the State of Alagoas,
in the right regions with the right partners and at the right price – coupled
subject to confirmation of qualification requirements, or, our Round 12
with the visions and skills to transform and improve value above ground.
concessions. See “—Our operations—Operations in Brazil.”
We believe that our risk and capital management policies have enabled
us to compile a geographically diverse portfolio of properties that balances
History
We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park,
exploration, development and production of oil and gas. These attributes
who have over 25 and 35 years of international oil and natural gas experience,
have also allowed us to raise capital and to partner with premier international
respectively, and who collectively hold approximately 26% of our common
companies. Finally, we believe we have developed a distinctive culture within
shares as of the date of this annual report, and are involved in our operations
our organization that promotes and rewards partnership, entrepreneurship
and strategy. Mr. O’Shaughnessy currently serves as our Chairman and Mr.
and merit. Consistent with this approach, all of our employees are eligible
Park currently serves as our Chief Executive Officer and Deputy Chairman, and
to participate in our long-term incentive program, or our Performance-Based
both actively contribute to our ongoing operations and business decisions.
Employee Long-Term Incentive Program. See “Item 6. Directors, Senior
Management and Employees—B. Compensation—Performance-Based
Our history commenced with the purchase of AES Corporation’s upstream
Employee Long-Term Incentive Program.”
oil and natural gas assets in Chile and Argentina. Those assets included a
In Chile, we are the first and the largest non-state controlled oil and gas
was operated by the Empresa Nacional de Petróleo, or ENAP, the Chilean
producer. We began operations in 2006 in the Fell Block and have evolved
state-owned hydrocarbon company, and operating working interests in the
from having a non-operated, non-producing interest to having a fully-
Del Mosquito, Cerro Doña Juana and Loma Cortaderal blocks in Argentina,
operated and producing asset with 10.7 mmboe of net proved reserves as of
which we collectively refer to as the Argentina Blocks. Since 2002, our
December 31, 2013 and average production of 6,962 boepd in 2013. In
business has grown significantly.
non-operating working interest in the Fell Block in Chile, which at that time
addition, we operate five other hydrocarbon blocks in Chile with significant
prospective resources.
In 2006, after demonstrating our technical expertise and committing to
an exploration and development plan, we obtained a 100% operating
In Colombia, following our successful acquisitions of Winchester, Luna and
working interest in the Fell Block by the Republic of Chile. Also in 2006, the
Cuerva in early 2012, we have an asset base of 10 hydrocarbon blocks where
International Finance Corporation, or the IFC, a member of the World Bank
we were able to perform an active exploration and development drilling
Group, became one of our principal shareholders, and we listed our
campaign, which resulted in multiple new oilfield discoveries and to increase
common shares on AIM, a market operated by the London Stock Exchange
average production from 2,965 boepd for the month of April 30, 2012 (the
plc, in an initial public offering of common shares outside the United States.
first full month following our Colombian acquisitions) to 7,725 boepd in the
Subsequently, in 2008 and 2009, we issued and sold additional common
fourth quarter of 2013. Total net production in Colombia averaged 6,491
shares outside the United States.
boepd in 2013. As of December 31, 2013, we had net proved reserves of 9.4
mmboe in Colombia.
In 2008 and 2009, we continued our growth in Chile by acquiring operating
working interests in each of the Otway and Tranquilo Blocks, and by forming
Recently, we expanded our footprint to Brazil. In May 2013, we agreed to
partnerships with Pluspetrol, Wintershall, Methanex and IFC.
acquire Rio das Contas from Panoro, which holds a 10% working interest
in the shallow offshore Manatí Field, the largest non-associated gas field in
62
GeoPark 20F
In 2010, we formed a strategic partnership with LGI, a Korean conglomerate,
On September 30, 2013, we entered into a strategic alliance with Tecpetrol
to jointly acquire and develop upstream oil and gas projects in Latin
S.A. (the oil and gas subsidiary of the Techint Group) or Tecpetrol, to jointly
America. LGI’s business includes a portfolio of energy and raw material
identify, study and potentially acquire upstream oil and gas opportunities
projects, including oil and gas projects in the Middle East and in Southeast
in Brazil, with a specific focus on the Parnaíba, Sao Francisco, Recôncavo,
and Central Asia.
Potiguar and Sergipe Alagoas basins. Tecpetrol has an extensive track record
as an oil and gas explorer and operator throughout the Americas, with a
In 2011, ENAP awarded us the opportunity to obtain operating working
portfolio of assets in Argentina, Peru, Colombia, Ecuador, Mexico, Bolivia,
interests in each of the Isla Norte, Flamenco and Campanario blocks in
Venezuela and the United States and current net production of over 85,000
Tierra del Fuego, Chile, which we refer to collectively as the Tierra del Fuego
barrels of oil equivalent per day. As part of our strategic alliance with
Blocks, and in 2012, jointly with ENAP we entered into special operation
Tecpetrol, we expect to enter into an agreement to jointly develop, by
contracts (Contratos Especiales de Operación para la Exploración y
assigning to Tecpetrol 50% of our working interest in, the PN T 597
Explotación de Yacimientos de Hidrocarburo, or CEOPs) with Chile for the
concession in the Parnaíba Basin in the State of Maranh(cid:0) o, which we were
exploration and exploitation of hydrocarbons within these blocks.
awarded by the ANP, subject to confirmation of qualification requirements.
Also in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14%
equity interest in GeoPark TdF S.A., or GeoPark TdF, for US$148.0 million.
LGI also provided to GeoPark TdF US$84.0 million in standby letters of credit
Recent developments
NYSE Listing
In February 2014, we commenced trading on NYSE raising US$98 million
to partially secure the US$101.4 million performance bond required by
(before underwriting commissions and expenses) through the issuance
the Chilean government to guarantee GeoPark TdF’s obligations with respect
of 13,999,700 common shares that also included shares issued pursuant to
to the minimum work program under the Tierra del Fuego CEOPs. Our
the underwriters’ over-allotment option.
agreement with LGI in the Tierra del Fuego Blocks allows us to earn back up
to 12% equity participation in GeoPark TdF, depending on the success of
our operations in Tierra del Fuego. See “Item 10. Additional Information—C.
Material contracts.”
Acquisition of Rio das Contas
On March 31, 2014, we acquired Rio das Contas, which holds a 10% working
interest in the BCAM-40 Concession in the shallow-depth offshore Manatí
Field in the Camamu-Almada Basin, from Panoro. The total cash consideration
In the first quarter of 2012, we moved into Colombia by acquiring three
for the acquisition is US$140 million, subject to certain purchase price and
privately held E&P companies, Winchester, Luna and Cuerva. These acquisitions
easement adjustments.
provided us with an attractive platform in Colombia that includes working
interests and/or economic interests in 10 blocks located in the Llanos,
The Manatí Field, which is in the production phase, is operated by Petróleo
Magdalena and Catatumbo Basins and covering an area of 575,700 gross acres.
Brasileiro S.A.—Petrobras, or Petrobras (with a 35% working interest), the
Brazilian national company and the largest oil and gas operator in Brazil, in
In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia
for US$20.1 million, including the assumption of existing debt and the
partnership with Queiroz Galv(cid:0) o Exploração e Produção, or QGEP (with a 45%
working interest), and Brasoil Manatí Exploração Petrolífera S.A., or Brasoil
commitment to provide additional funding to cover LGI’s share of required
(with a 10% working interest).
future investments in Colombia. In addition, our agreement with LGI in
Colombia allows us to earn back up to 12% of equity participation in GeoPark
We believe the Manatí Field provides us with a strategically important
Colombia, depending on the success of our operations in Colombia.
upstream asset in Brazil. The shallow offshore Manatí Field is the largest
See “Item 10. Additional Information—C. Material contracts.” We and LGI
non-associated gas field in Brazil, which produced approximately 7.6%
also agreed that we would extend our strategic partnership to build a
of the gas produced in Brazil in the year ended December 31, 2013. During
portfolio of upstream oil and gas assets throughout Latin America through
the years ended December 31, 2012 and 2013, net production attributable
2015. We believe our partnership with LGI represents a positive independent
to Rio das Contas in the Manatí Field was approximately 3,677 boepd
assessment and validation of the quality of our Chilean and Colombian asset
and 3,580 boepd, respectively.
inventory, the extent of our technical and operational expertise and the
ability of our management to structure and effect significant transactions.
Our Rio das Contas acquisition in Brazil provides us with a long-term off-take
In May 2013, we entered into agreements to expand our operations to Brazil.
reserves in the Manatí Field, a valuable relationship with Petrobras and
See “—B. Business overview—Our operations—Operations in Brazil.”
an established local platform and presence, with seasoned and experienced
contract with Petrobras that covers approximately 74% of net proved gas
GeoPark 20F
63
geoscience and administrative team to manage our Brazilian assets and to
We have been able to successfully develop our assets through drilling, with
seek new growth opportunities.
106 of the 152 wells that we drilled from 2006 through 2013 having become
productive wells, a 70% success ratio. We have grown our business through
In the year ended December 31, 2013, Rio das Contas generated net income
winning new licenses and acquiring strategic assets and businesses, with
of approximately US$19.4 million, revenues of approximately US$48.6 million,
15 new blocks incorporated into our portfolio since January 1, 2006, eight
and Adjusted EBITDA of approximately US$30.8 million. See "“Item 3. Selected
new concessions in Brazil awarded to us following our entry into concession
financial data—Unaudited Condensed Combined Pro Forma Financial Data—
agreements with the ANP and the closing of our Rio das Contas acquisition.
Note 2—Reconciliations.”
Since our inception, we have supported our growth through our prospect
development efforts and our drilling program, as well as by developing long-
In addition to the closing purchase price, the purchase agreement also
term strategic partnerships and alliances with key industry participants,
provides that for each year from 2013 to and including 2017, we will make
accessing debt and equity capital markets and developing and retaining a
annual earn-out payments to Panoro in an amount equal to 45% of net
technical team with vast experience and a successful track record of finding
cash flow, calculated as EBITDA less the aggregate of capital expenditures
and producing oil and gas in Latin America. A key factor behind our success
and corporate income taxes, with respect to the BCAM-40 Concession of
ratio is our experienced team of geologists, geophysicists and engineers,
any amounts in excess of US$25.0 million, up to a maximum cumulative
including professionals with specialized expertise in the geology of Chile,
earn-out amount of US$20.0 million.
Colombia, Brazil and Argentina.
See “Item 3. Key Information—D. Risk factors—Risks relating to our business”
For the year ended December 31, 2013, we drilled 39 new wells, 17 in Chile
and “Item 4. Information on the CompanyB. Business overview—Significant
and 22 in Colombia) in blocks in which we have working interests and/or
agreements—Brazil—Rio das Contas Quota Purchase Agreement”
economic interests. Our capital expenditures of US$228.0 million (US$145.7
B. Business overview
We are an independent oil and natural gas exploration and production, or
respectively) for the year ended December 31, 2013 consisted of US$133.3
million related to exploration, including approximately 1,350 sq. km in 3D
E&P, company with operations in Latin America and a proven track record
seismic surveys (more than 1,100 sq. km in Chile, mainly related to the blocks
of growth in production, reserves and cash flows since 2006. We operate
located in Tierra del Fuego and over 250 sq. km in Colombia)
million, US$82.1 million and US$0.2 million in Chile, Colombia and Argentina,
in Chile, Colombia, Brazil and, to a lesser extent, in Argentina.
In March 2014, we invested US$140 million in Brazil, subject to certain
We have a well-balanced portfolio of assets that includes working and/or
adjustments, to acquire Rio das Contas, which we financed through the
economic interests in 27 hydrocarbons blocks, 26 of which are onshore
incurrence of a loan of US$70.5 million and cash on hand.
blocks, including eleven currently in production, as well as an additional
shallow- offshore concession in Brazil that includes the Manatí Field.
In 2014, we expect our total capital expenditures, excluding the purchase
In addition, we have two new concessions in Brazil that are subject to
confirmation of qualification requirements by the ANP. We produced a net
price for our Rio das Contas acquisition, to be between US$220 million to
US$250 million, of which approximately 62%, 32% and 5% will be in Chile,
average of 13,517 boepd during the year ended December 31, 2013, 51.5%
Colombia and Brazil, respectively. These capital expenditures will include the
of which was produced in Chile, 48% of which was produced in Colombia
drilling of 50 to 60 new wells (approximately 40% of which we expect will
and 0.5% of which was produced in Argentina, and of which 82% was oil.
be exploratory wells), as well as workovers, seismic surveys and new facility
Accounting for our Rio das Contas acquisition, on a pro forma basis, we
construction. In Brazil, we expect our capital expenditures will consist of
would have produced an average of 17,098 boepd during the year ended
between US$5 million to US$7.5 million to finance in part the construction
December 31, 2013, with Chile, Colombia and Brazil representing 41%, 38%
of a gas compression plant in the Manatí Field, and approximately US$0.45
and 21% of our production, respectively, and with oil representing 65%
million in license fee payments to the ANP relating to our Round 12
of our total production. As of December 31, 2013, we had net proved
concessions, with the remainder for seismic surveys in exploration blocks
reserves of 20.1 mmboe (composed of 74% oil and 26% natural gas), of which
in the Potiguar and Recôncavo Basins.
10.7 mmboe, or 53%, and 9.4 mmboe, or 47%, were in Chile and Colombia,
respectively. Additionally, according to the D&M Reserves Report, as of
For the year ended December 31, 2013, our average oil and gas production
December 31, 2013, Rio das Contas had net proved reserves of 8.3 mmboe
totaled 13,517 boepd, a 20% increase as compared to our average oil and gas
(composed of approximately 98% natural gas).
production for the year ended December 31, 2012 of 11,292 boepd. Oil and
liquids represented 82% and 66% of our total oil and gas production for the
64
GeoPark 20F
years ended December 31, 2013 and 2012, respectively. Oil production
2014, our average oil and gas production for the year ended December 31,
increased by 48% to 11,113 bopd (consisting of 4,581 bopd, 6,482 bopd and
2013 reached 17,098 boepd (consisting of 11,173 bopd of oil and 35,539
50 bopd in Chile, Colombia and Argentina, respectively) for the year ended
mcfpd of gas), with oil and liquids representing 65% of total production.
December 31, 2013, as compared to 7,491 bopd for the year ended December
31, 2012. Gas production increased to 14,419 mcfpd (consisting of 14,283
The following map shows the countries in which we have blocks with working
mcfpd, 52 mcfpd and 84 mcfpd in Chile, Colombia and Argentina,
and/or economic interests as of December 31, 2013 and also includes our
respectively) for the year ended December 31, 2013. On a pro forma basis,
Brazil Acquisitions. For information on our working interests in each of these
accounting for our Rio das Contas acquisition, which closed on March 31,
blocks, see “—Our assets” below.
Colombia Blocks
C O L O M B I A
La Cuerva
Llanos 34
Llanos 62
Yamu
Llanos 17
Llanos 32
Arrendajo
Abanico
Cerrito
Jagüeyes
Chile Blocks
Fell
Tranquilo
Otway
Isla Norte
Campanario
Flamenco
B R A Z I L
P A C I F I C
O C E A N
A R G E N T I N A
C H I L E
Asset Type / Work Program
Production
Development
Exploration
Unconventional resource
New projects inventory
Brazil Blocks(1)
POT - T 619
POT - T 620
POT - T 663
POT - T 664
POT - T 665
REC - T 85
REC - T 94
BCAM - 40 (Manatí)
SEAL - T 268
PN - T 597
A T L A N T I C
O C E A N
Argentina Blocks
Del Mosquito
Cerro Doña Juana
Loma Cortaderal
(1) We closed the acquisition of Rio das Contas on March 31, 2014. We have
concessions, subject to confirmation of qualification requirements and
also entered into seven new concession agreements with the ANP in
absence of legal impediments, by the ANP in the Parnaíba Basin and the
the Recôncavo and Potiguar Basins in Brazil and were awarded, two new
Sergipe Alagoas Basin. See “—Our operations—Operations in Brazil.”
GeoPark 20F
65
The following table sets forth our net proved reserves and other data as of
and for the year ended December 31, 2013, and also includes on a pro forma
basis information on our recent Rio das Contas acquisition, which closed on
March 31, 2014.
Country
Chile
Colombia
Argentina
Total
Brazil(1)
Pro forma
total
Oil
(mmbbl)
5.4
9.4
0.0
14.8
0.2
15.0
Gas
(bcf)
32.2
0.0
0.0
32.2
48.8
80.9
equivalent
(mmboe)
10.7
9.4
0.0
20.1
8.3
28.4
For the year ended December 31, 2013
Revenues
(in thousands
of US$)
157,491
179,324
1,538
338,353
48,570
386,923
% Oil
50%
100%
—
74%
2%
53%
% of total
revenues
47%
53%
—
100%
—
—
(1) Reflects our Rio das Contas acquisition.
As of December 31, 2013, according to the D&M Reserves Report, the net
proved reserves attributable to our Rio das Contas acquisition in Brazil were
8.3 mmboe (composed of approximately 98% natural gas), which generated
revenues of US$48.6 million for the year ended December 31, 2013.
Our commitment to growth has translated into a strong compounded annual
growth rate, or CAGR, of 45.9% for production in the period from 2007 to
2013, as measured by boepd in the table below.
Average net production (mboepd)
% oil
2013
13.5
82.2%
2012
11.3
66.3%
2011
7.6
33.0%
2010
6.9
28.4%
2009
6.3
19.5%
2008
3.4
9.8%
2007
1.4
12.0%
For the year ended December 31,
During the year ended December 31, 2013, Rio das Contas, whose production
is not accounted for in the table above, produced 3.6 mboepd.
66
GeoPark 20F
The following table sets forth our production of oil and natural gas in the
The following table sets forth the pro forma evolution of our net proved
blocks in which we have a working and/or economic interest as of December
reserves of natural gas as of and for the year ended December 31, 2013, as
31, 2013.
adjusted for the acquisition of Rio das Contas on December 31, 2013.
Oil production
Total crude oil production (bopd)
Average sales price of crude oil
(US$/bbl)
Natural gas production
Total natural gas production
(mcf/day)
Average sales price of natural gas
Average daily production
For the year ended
December 31, 2013
Chile
Colombia
Argentina
4,581
6,482
50
84.3
80.3
70.3
Reserves as of December 31, 2012
Increase (decrease) attributable to:
Revisions
14,283
52
84
Extensions and discoveries
Purchases
(US$/mcf)
5.0
4.18
1.1
Production
Oil and natural gas production cost
Weighted average
Pro Forma Reserves as of
December 31, 2013
production cost (US$/boe)
26.6
47.2
14.8
Net proved reserves
(developed and undeveloped)
of natural gas
Rio das
GeoPark
Contas
Pro Forma
historical
historical
combined
(mmcf)
29,581.0
51,762.9
81,343.9
4,691.0
2,219.0
—
4,712.9
—
—
9,403.9
2,219.0
—
(4,332.0)
(7,708.8)
(12,040.8)
32,159.0
48,767.0
80,926.0
During the year ended December 31, 2013, average daily production of
Our assets
According to the D&M Reserves Report, as of December 31, 2013, the blocks
Rio das Contas was 21,120 mcf/day with an average sales price of natural gas
in Chile, Colombia and Argentina in which we have a working interest had
of 6.4 US$/mcf. In addition, weighted average production cost was 27.0
20.1 mmboe of net proved reserves, with 10.7 mmboe, or 53%, and 9.4
(US$/boe).
Pro Forma net proved reserves
mmboe, or 47%, of such net proved reserves located in Chile and Colombia,
respectively. Giving effect to our Rio das Contas acquisition on a pro forma
basis, we would have net proved reserves of 28.4 mmboe as of December 31,
2013, with Chile, Colombia and Brazil representing 38%, 33% and 29% of net
Pro Forma net proved reserves of oil, condensate and natural gas
The following table sets forth the pro forma evolution of our net proved
proved reserves, respectively.
reserves of oil and condensate as of and for the year ended December 31,
For the year ended December 31, 2013, we produced an average of 13,517
2013, as adjusted for the acquisition of Rio das Contas at December 31, 2013.
boepd, of which 6,962 boepd, or 52%, was produced in the Fell Block, 6,491
boepd, or 48%, was produced in the Colombian blocks and 64 boepd,
Net proved reserves
or 0.5%, was produced in the Argentine blocks. Giving effect to our Rio das
(developed and undeveloped)
Contas acquisition on a pro forma basis, we would have produced an
of oil and condensate
average of 17,098 boepd during the year ended December 31, 2013, with
Rio das
Chile, Colombia and Brazil representing 41%, 38% and 21% of our production,
GeoPark
Contas
Pro Forma
respectively, and with oil representing 65% of our total production.
historical
historical
combined
11,885.1
134.3
12,019.4
interest. The following table summarizes certain information about our
(mbbl)
We are the operator of a majority of the blocks in which we have a working
(5.9)
6,641.0
—
37.8
—
—
Chilean, Colombian and Argentine blocks as of December 31, 2013, and also
31.9
includes on a pro forma basis information on our recent Rio das Contas
6,641.0
acquisition.
—
(3,718.6)
(22.1)
(3,740.7)
14,801.6
150.0
14,951.6
Reserves as of December 31, 2012
Increase (decrease) attributable to:
- Revisions
- Extensions and discoveries
- Purchases of minerals in place
- Production
Pro Forma Reserves as
of December 31, 2013
GeoPark 20F
67
Country
Concession
Operator
Block/
Working
interest
(1)(2)(12)
Basin
Gross area Net proved
(thousand
acres)(3)
367.8
reserves
(mmboe)(4)
10.7
Net
production
(boepd)(5)
6,962
% Oil
50%
Fell
Tranquilo(19)
Otway
GeoPark
GeoPark
GeoPark
100% Magallanes
29% Magallanes
100% Magallanes
92.4
49.4(6)
Isla Norte
GeoPark
60%(7) Magallanes
130.2
Campanario
GeoPark
50%(7) Magallanes
192.2
Flamenco(20)
GeoPark
50%(7) Magallanes
141.3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Concession
% Oil
expiration year
66% Exploitation: 2032
— Exploitation: 2043
— Exploitation: 2044
Exploration: 2019
— Exploitation: 2044
Exploration: 2020
— Exploitation: 2045
Exploration: 2019
— Exploitation: 2044
Chile
Chile
Chile
Chile
Chile
Chile
Subtotal
Chile
973.3
10.7
50%
6,962
66%
Colombia
La Cuerva
GeoPark
100%
Llanos
Colombia
Llanos 34
GeoPark
45%
Llanos
Colombia
Llanos 62
GeoPark
100%
Llanos
Colombia
Yamú
GeoPark
54.5/75%(8)
Llanos
47.8
82.2
44.0
11.2
Exploration: 2014
2.6
100%
1,962
100% Exploitation: 2038
Exploration: 2015
6.4
—
0.3
100%
3,469
100% Exploitation: 2039
—
—
— Exploitation: 2041
Exploration: 2017
Exploration: 2013
100%
550
100% Exploitation: 2036
Exploration: 2015
Colombia
Llanos 17
RIL-Parex
36.8%(9)
Llanos
108.8
0.03
100%
49
— Exploitation: 2039
0%(10)
Llanos
100.3
0.06
100%
180
100% Exploitation: 2039
Exploration: 2015
Colombia
Llanos 32
Jagüeyes
Verano
Energy
Colombia
3432A
Columbus
5%
Llanos
Arrendajo
Abanico
Cerrito
Pacific
Pacific
Pacific
0%(11)
Llanos
0%(11) Magdalena
0%(11) Catatumbo
Colombia
Colombia
Colombia
Subtotal
Colombia
Argentina
Del Mosquito
GeoPark
100%
Austral
Cerro Doña
Juana(18)
Loma
Cortaderal(18)
GeoPark
100%
Neuquén
GeoPark
100%
Neuquén
Argentina
Argentina
Subtotal
Argentina
68
GeoPark 20F
61.0
78.1
32.1
10.2
—
—
—
—
—
—
—
—
—
177
95
9
Exploration: 2014
— Exploitation: 2038
Exploration: 2017
100%
Production: 2041
100% Production: 2022
0% Production: 2028
575.7
9.4
100%
6,491
100%
17.3
19.6
28.3
65.2
—
—
—
—
—
—
—
—
64
—
—
64
78% Exploitation: 2016
— Exploitation: 2017
— Exploitation: 2017
78%
Country
Concession
Operator
Block/
Working
interest
(1)(2)(12)
Gross area Net proved
(thousand
acres)(3)
reserves
(mmboe)(4)
Basin
Net
production
(boepd)(5)
% Oil
Concession
% Oil
expiration year
Brazil
Brazil
Brazil
Brazil
Brazil
Brazil
Brazil
Brazil
Brazil
Subtotal Brazil
Total GeoPark
Brazil
Total GeoPark
Pro forma
REC T 94
GeoPark
100% Recôncavo
REC T 85
GeoPark
100% Recôncavo
POT T 664
GeoPark
100%
Potiguar
POT T 665
GeoPark
100%
Potiguar
POT T 619
GeoPark
100%
Potiguar
POT T 620
GeoPark
100%
Potiguar
POT T 663
GeoPark
PN T 597(15) GeoPark(16)
100%
100%(16)
SEAL T
268(15)
GeoPark
Potiguar
Parnaíba
Sergipe
Alagoas
Camamu-
7.7
7.7
7.9
7.9
7.9
7.9
7.9
188.7
7.8
251.4
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Exploration: 2018
— Exploitation: 2045
Exploration: 2018
— Exploitation: 2045
Exploration: 2018
— Exploitation: 2045
Exploration: 2018
— Exploitation: 2045
Exploration: 2018
— Exploitation: 2045
Exploration: 2018
— Exploitation: 2045
Exploration: 2018
— Exploitation: 2045
—(15)
—
—
—
—(15)
1,865.6
20.1
74%
13,517
82%
Exploitation:
2029(13) 2034(14)
BCAM 40 Petrobras(17)
10%
Almada
22.8
8.3
2%
3,580
2%
1,888.4
28.4
53%
17,098
65%
(1) Working interest corresponds to the working interests held by our
Ministry of Energy granted this permit, such that, upon execution of a deed
respective subsidiaries in such block, net of any working interests and/or
of assignment of rights containing the as-approved terms, we will be the sole
economic interests held by other parties in such block.
(2) As of the date of this annual report, LGI has a 20% equity interest in our
participant, and have a 100% working interest, in our two remaining areas
under the Otway Block CEOP. See “—Our operations—Operations in Chile—
Chilean operations through GeoPark Chile and a 20% equity interest in
Otway and Tranquilo Blocks.”
our Colombian operations through GeoPark Colombia.
(7) LGI has a 14% direct equity interest in our Tierra del Fuego operations
(3) Gross area refers to the total acreage of each block.
through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, for a
(4) Reflects net proved reserves as of December 31, 2013.
total 31.2% effective equity interest in our Tierra del Fuego operations. See
(5) Reflects net average production for 2013. Net production refers to average
“—Our operations—Operations in Chile—Tierra del Fuego Blocks (Isla Norte,
production for each block, net of any working interests or economic interests
Campanario and Flamenco Blocks).”
held by others in such block but gross of any royalties due to others.
(8) Although we are the sole title holder of the working interest in the Yamú
(6) In April 2013, we voluntarily relinquished to the Chilean government all
Block, other parties have been granted economic interests in fields in this
of our acreage in the Otway Block, except for 49,421 acres. In May 2013, our
block. Taking those other parties’ interests into account, we have a 54.5%
partners under the joint operating agreement governing the Otway Block
interest in the Carupana Field and a 75% interest in the Yamú and Potrillo
decided to withdraw from such joint operating agreement, and applied for an
Fields, both located in the Yamú Block.
assignment of rights permit on August 5, 2013. On August 26, 2013, the
(9) We currently have a 40% working interest in the Llanos 17 Block, although
GeoPark 20F
69
we have assigned a 3.2% economic interest to a third party. We expect to
apply to formalize this assignment with the ANH so that it will be recognized
Our strengths
We believe that we benefit from the following competitive strengths:
as a working interest.
(10) We currently have a 10% economic interest in the Llanos 32 Block,
High quality and diversified asset base built through a successful track
although we have applied to the ANH to recognize this as a working interest
in the block, and expect to receive the ANH’s authorization in the first half
record of organic growth and acquisitions
Our assets include a diverse portfolio of oil- and natural gas-producing
of 2014.
reserves, operating infrastructure, operating licenses and valuable geological
(11) We do not have a working interest in those blocks, though we have a
surveys. According to the D&M Reserves Report, as of December 31, 2013,
10% economic interest in the net revenues of each of these blocks pursuant
we had 20.1 mmboe of net proved reserves in Chile and Colombia, of which
to various partnership interests’ agreements. See “—Our operations—
74%, or 14.8 mmboe, was oil, and 26%, or 5.3 mmboe, was gas and of which
Operations in Colombia.”
50%, or 7.1 mmboe, was net proved developed reserves. In addition, on
(12) Working interest corresponds to the working interests we expect to
a pro forma basis, after giving effect to our Rio das Contas acquisition, as
hold in such concession, net of any working interests held by other parties
of December 31, 2013, we had 28.4 mmboe of net proved reserves in Brazil,
in such concession, as a result of our Rio das Contas acquisition and Round
Chile and Colombia, of which 53%, or 15.0 mmboe, was oil, and 47%, or
12 concessions
(13) Corresponds to the Manatí Field.
(14) Corresponds to the Camarão Norte Field.
13.4 mmboe, was gas and of which 42%, or 12.1 mmboe, was net proved
developed reserves. Throughout our history, we have delivered continuous
growth in our production, and our management team has been able to
(15) Round 12 concessions are subject to confirmation of qualification
identify under-exploited assets and turn them into valuable, productive
requirements by the ANP and absence of any legal impediments to signing.
assets. For example, in 2002, we acquired a non-operating working interest
See “Item 3. Key information—D. Risk factors—Risks relating to our business—
in the Fell Block in Chile, which at the time had no material oil and gas
The PN-T-597 concession is subject to an injunction and may not close.”
production or reserves despite having been actively explored and drilled over
(16) We expect to jointly develop this concession with Tecpetrol and assign
the course of more than 50 years. Since 2006, when we became the operator
50% of our working interest in this concession to Tecpetrol.
of the Fell Block, through 2013, we have invested more than US$410 million
(17) We closed the Rio das Contas acquisition on March 31, 2014. Partners:
and drilled approximately 95 wells in the block, with 73% of such wells
Petrobras; QGEP and Brasoil.
becoming productive during that period. Currently, we are the operator and
(18) In April 2014, we informed the Secretary of Infrastructure and Energy of
sole concessionaire of the Fell Block, which, during the year ended December
the province of Mendoza of our decision to relinquish 100% of the Cerro
31, 2013, produced approximately 6,962 boepd. As of December 31, 2013, we
Doña Juana and Loma Cortaderal Concessions to the Mendoza Province.
generated 66% of Chile’s total oil production and 16% of its gas production,
(19) On December 31, 2013, the Consortium members and interest were:
according to information provided by the Chilean Ministry of Energy.
GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. Methanex
and Wintershall have recently announced its decision to exit the Consortium.
The acquisitions of Winchester, Luna and Cuerva in Colombia in the first
The new ownership is being negotiated among us and Pluspetrol.
(20) In 2013, there were new discoveries in the Flamenco block. However,
quarter of 2012 gave us access to an additional 574,979 gross exploratory
and productive acres across 10 blocks in what we believe to be one of South
there are no proved reserves estimated for this block due to incomplete
America’s most attractive oil and gas geographies. According to the D&M
testing of these wells as of the date of this annual report.
Reserves Report, as of December 31, 2013, the blocks in Colombia in which
we have a working interest had 9.4 mmboe of net proved reserves, all of
which were in oil. Since we acquired Winchester, Luna and Cuerva, we were
able to perform an active exploration and development drilling campaign,
which resulted in multiple new discoveries and to increase average
production to 6,962 boepd in Colombia in 2013. Also, we have been able to
leverage our technical expertise achieving significant positive results in terms
of reduced drilling costs in our multiple new oilfield discoveries, one of which
was located in the hanging wall of a normal fault, a play type that had not
been successfully tested before in the Llanos basin.
70
GeoPark 20F
In addition, in line with our growth strategy, on March 31, 2014 we closed
additional wells in the formation and we plan to continue to explore this
the acquisition of Rio Das Contas, which gave us a 10% working interest
formation, which has been the focus of our drilling plan. See “—Our
in the BCAM-40 Concession, including the shallow-depth offshore Manatí and
operations” We have also initiated a technical assessment of the oil and gas
Camarão Norte Fields, in the Camamu-Almada Basin in the State of Bahia.
shale potential in the Estratos con Favrella shale formation in some of our
The Manatí Field, which is in the production phase, is operated by Petrobras
blocks in Chile.
(with a 35% working interest), the Brazilian national company and the largest
oil and gas operator in Brazil, in partnership with QGEP (with a 45% working
• In Colombia, in 2013, following our identification of several leads and
interest), and Brasoil (with a 10% working interest). See “—Significant
prospects in our Llanos 34 Block, our most prospective Colombian block,
agreements—Brazil—Rio das Contas Quota Purchase Agreement.”Our Rio
we completed a 3D seismic survey on most of the remaining 50% of the
das Contas acquisition in Brazil provides us with a long-term off-take contract
acreage that had not been previously surveyed. Furthermore, in the second
with Petrobras that covers approximately 74% of net proved gas reserves in
quarter of 2013, we successfully put into production our third discovery,
the Manatí Field, a valuable relationship with Petrobras and an established
the Potrillo 1 well in the Yamú Block, and our fourth discovery, the Tarotaro 1
local platform and presence, with seasoned and experienced geoscience and
well in the Llanos 34 Block. In addition, in the fourth quarter of 2013, we
administrative team to manage our Brazilian assets and to seek new growth
drilled and tested the Tigana 1 exploration well in the Mirador and
opportunities. According to the D&M Reserves Report, as of December 31,
Guadalupe formations, our fifth new oil field discovery, and the Tigana Sur 1
2013, BCAM-40 Concession had 8.3 mmboe of net proved reserves,
exploration well in the Guadalupe formation, our sixth new oil field discovery
(composed of approximately 98% natural gas). See “—Our operations—
in Colombia, both in the Llanos 34 Block. See “—Our operations.
Operations in Brazil.”
Significant drilling inventory and resource potential from existing
that were entered into with the ANP, and we expect to begin seismic surveys
• In Brazil, in 2013 we were awarded seven new exploratory concessions
asset base
Our portfolio includes large land holdings in high-potential hydrocarbon
in these blocks in 2014.
basins and blocks with multiple drilling leads and prospects in different
Our geoscience team continues to identify new potential accumulations and
geological formations, which provide a number of attractive opportunities
expand our inventory of prospects and drilling opportunities.
with varying levels of risk. Our drilling inventory consists of over 200
identified drilling locations, and our development plans target locations
that we believe are low-cost, provide attractive economics and support a
Strong liquidity and financial flexibility to fund expansion
We benefit from both historically consistent cash flows and access to debt
predictable production profile. Currently, we are executing our most
and equity capital markets, as well as other funding sources, which have
significant exploration and drilling plan to date:
provided us with strong liquidity and the financial flexibility to finance our
• In Chile, in 2013, we completed a 3D seismic survey covering approximately
US$140.1 million and US$131.8 million in cash from operations in the years
315,000 gross acres, or 68% of the gross acres in our Tierra Del Fuego Blocks.
Part of the survey took place in the Flamenco Block, where we drilled our first
ended December 31, 2013 and 2012, respectively, and had US$121.1 million
and US$38.3 million in cash and cash equivalents as of December 31, 3013
organic growth and the pursuit of potential new opportunities. We generated
successful exploratory well (Chercán 1), which resulted in our first oil and
and 2012, respectively.
gas discovery in Tierra del Fuego. We have completed the construction of a
flowline to connect this well to existing infrastructure, and the well is
In March 2014, we borrowed US$70.5 million pursuant to a five-year term
currently producing approximately 2,650 mcfpd. We subsequently drilled
variable interest secured loan, secured by the benefits GeoPark receives under
two additional exploratory wells in the Flamenco Block (Omeling 1 and
the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to
Yakamush 1), which are on standby for workover activities. Our Tierra del
six-month LIBOR + 3.9% to finance part of the purchase price of our Rio das
Fuego Blocks have similar geological characteristics to the Fell Block, and we
Contas acquisition, and funded the remaining amount with cash on hand.
intend to replicate the exploration and development strategy we successfully
executed in the Fell Block in these blocks. In 2011, we expanded into a
In February 2014, we commenced trading on the NYSE and raised US$98
new play concept following our first oil discovery in the Konawentru well in
million (before underwriting commissions and expenses), including the over
the Tobífera formation, a volcaniclastic reservoir that lies below the Springhill
allotment option granted to and exercised by the underwriters, through
formation, the traditional sandstone of the Magallanes Basin. Since then,
the issuance of 13,999,700 common shares.
we have significantly increased our oil production from the drilling of
GeoPark 20F
71
In 2010, we issued US$133.0 million aggregate principal amount of 7.75%
Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the
senior secured notes in the international markets, or the Notes due 2015,
oil and gas business internationally and in North America since 1976.
which were redeemed following our issuance in 2013 of US$300.0 million
As of the date of this annual report, Mr. O’Shaughnessy held 13.2% of our
aggregate principal amount of 7.50% senior secured notes due 2020, or
outstanding common shares.
the Notes due 2020.
In 2007, we obtained financing from Methanex Chile S.A., or Methanex,
industry of approximately 25 years in companies such as Chevron, San Jorge,
the Chilean subsidiary of the Methanex Corporation, a leading global
Petrobras, Total, Pluspetrol, ENAP and YPF, among others. Throughout our
methanol producer, in an amount of US$40 million, structured as a gas
history, our management and operating team has had success in unlocking
pre-sale agreement with a six-year term at an interest rate equal to
unexploited value from previously underdeveloped assets.
Our management and operating team has an average experience in the energy
the six-month LIBOR.
In 2006, we completed an initial public offering of our common shares
management and employees (excluding our founding shareholders,
outside the United States on AIM and, in 2008 and 2009, we issued and sold
Mr. Gerald E. O’Shaughnessy and Mr. James F. Park) owned 6.6% of our
additional common shares outside the United States.
outstanding common shares, aligning their interests with those of our
In addition, as of the date of this annual report, our executive directors,
shareholders and helping retain the talent we need to continue to support
In February 2006, the IFC became a significant shareholder by contributing
our business strategy. See “Item 6. Directors, Senior Management and
US$10 million. Later that year, we entered into a loan agreement for
Employees—B. Compensation.” Our founding shareholders are also
US$20 million with the IFC, which we have since fully repaid, to partially
involved in our daily operations and strategy.
finance our investment program.
Long-term strategic partnerships and strong strategic relationships,
Highly committed founding shareholders and technical and management
such as with LGI, provide us with additional funding flexibility to pursue
teams with proven industry expertise and technically-driven culture
Our founding shareholders, management and operating teams have
further acquisitions
We benefit from a number of strong partnerships and relationships. In March
significant experience in the oil and gas industry and a proven technical and
2010, we entered into a framework agreement with LGI to establish a
commercial performance record in onshore fields, as well as complex projects
strategic growth partnership to jointly acquire and invest in oil and natural
in Latin America and around the world, including expertise in identifying
gas projects throughout Latin America. In May 2011, our partnership with
acquisition and expansion opportunities. Moreover, we differentiate
LGI was strengthened by LGI’s acquisition of a 10% equity interest in our
ourselves from other E&P companies through our technically-driven culture,
existing Chilean operations. In October 2011, LGI acquired an additional
which fosters innovation, creativity and timely execution. Our geoscientists,
10% equity interest in GeoPark Chile and a 14% equity interest in GeoPark
geophysicists and engineers are pivotal to the success of our business
TdF, and agreed to provide additional financial support for the further
strategy, and we have created an environment and supplied the resources
that enable our technical team to focus its knowledge, skills and experience
development of the Tierra del Fuego Blocks. In December 2012, LGI acquired
a 20% equity interest in our Colombian business. We also agreed with LGI
on finding and developing oil and gas fields.
to extend our strategic partnership in order to build a portfolio of upstream
oil and gas assets throughout Latin America through 2015. We are currently
In addition, we strive to provide a safe and motivating workplace for
the only independent E&P company in which LGI has equity investments
employees in order to attract, protect, retain and train a quality team in the
in Latin America. See “Item 4. Information on the Company—B. Business
competitive marketplace for capable energy professionals.
overview—Significant agreements—Agreements with LGI” for additional
Our CEO, Mr. James Park, has been involved in E&P projects in Latin America
since 1978. He has been closely involved in grass-roots exploration activities,
In addition, the IFC has been one of our shareholders since 2006, holding
drilling and production operations, surface and pipeline construction,
an 8% equity interest in us. In Chile, we have strong long-term commercial
legal and regulatory issues, crude oil marketing and transportation and
relationships with Methanex and ENAP, and in Colombia, through our
capital raising for the industry. As of the date of this annual report, Mr. Park
acquisitions of Winchester, Luna and Cuerva, we have inherited a strong
held 12.9% of our outstanding common shares.
relationship with Ecopetrol, the Colombian state-owned oil and
information relating to these agreements.
gas company.
72
GeoPark 20F
In Brazil, the closing of our Rio das Contas acquisition on March 31, 2014
of lower-risk cash flow-generating properties and assets that have upside
leads us to believe we will derive substantial benefits from Rio das Contas’s
potential, keeping a balanced mix of oil- and gas-producing assets (though
long-term relationship with Petrobras. Additionally, we have entered into
we expect to remain weighted toward oil) and focusing on both assets and
a strategic alliance with Tecpetrol, to jointly identify, study and potentially
corporate targets.
acquire upstream oil and gas opportunities in Brazil. As part of our strategic
alliance with Tecpetrol, we expect to enter into an agreement to jointly
Continue to foster a technically-driven culture and to capitalize on local
develop, by assigning to Tecpetrol 50% of our working interest in, the
PN T 597 concession in the Parnaíba Basin in the State of Maranhão, which
knowledge
We intend to continue to build and strengthen an environment that will
we were awarded by the ANP, subject to confirmation of qualification
allow us to fully consider and understand risk and reward and to deliberately
requirements. See “—Our operations—Operations in Brazil.”
and collectively pursue strategies that maximize value. For this purpose,
Our strategy
we intend to continue expanding our technical teams and to foster a culture
that rewards talent according to results. For example, we have been
able to maintain the technical teams we inherited through our Colombian
Continue to grow a risk-balanced asset portfolio
We intend to continue to focus on maintaining a risk-balanced portfolio of
acquisitions and intend to retain our technical teams in Brazil after
acquiring Rio das Contas on March 31, 2014. We believe local technical
assets, combining cash flow-generating assets with upside potential
and professional knowledge is key to operational and long-term success
opportunities, and on increasing production and reserves through finding,
and intend to continue to secure local talent as we grow our business
developing and producing oil and gas reserves in the countries in which we
in different locations.
operate. For example, through our recent expansion into Brazil, we have
secured steady cash flows through our acquisition of Rio das Contas, as well
as exploratory potential through our success in two ANP oil and gas bidding
Maintain a high degree of operatorship
We currently are, and intend to continue to be, the operator of a majority
rounds in which we were awarded a total of nine concessions in Brazil.
of the blocks and concessions in which we have working interests. Operating
We believe this approach will allow us to sustain continuous and profitable
the majority of our blocks and concessions gives us the flexibility to allocate
growth and also participate in higher risk growth opportunities with upside
our capital and resources opportunistically and efficiently. We believe
potential. See “—Our operations.”
Maintain conservative financial policies
We seek to maintain a prudent and sustainable capital structure and a
that this strategy has allowed, and will continue to allow, us to leverage our
unique culture and our talented technical, operating and management
teams. As of December 31, 2013, 99.6% of our net proved reserves and 96%
of our production came from blocks in which we are the operator. On a
strong financial position to allow us to maximize the development of our
pro forma basis, accounting for our Rio das Contas acquisition, approximately
assets and capitalize on business opportunities as they arise. We intend
71% of our production as of December 31, 2013 would have come from
to remain financially disciplined by limiting substantially all our debt
blocks that we operate.
incurrence to identified projects with repayment sources. We expect to
continue benefiting from diverse funding sources such as our partners
and customers in addition to the international capital markets.
Maintain our commitment to environmental and social responsibility
A major component of our business strategy is our focus on our
environmental and social responsibility. We are committed to minimizing
Pursue strategic acquisitions in Latin America
We have historically benefited from, and intend to continue to grow through,
the impact of our projects on the environment. We also aim to create
mutually beneficial relationships with the local communities in which
strategic acquisitions. Our Colombian acquisitions highlight our ability to
we operate in order to enhance our ability to create sustainable value in
identify and execute opportunities at what we believe to be attractive prices.
our projects. In line with the IFC’s standards, our commitment to our
These acquisitions have provided us with, and we expect that our Brazil
environmental and social responsibilities is a major component of our
Acquisitions will provide us with, attractive platforms in those countries.
business strategy. These commitments are embodied in our in-house
Our enhanced regional portfolio, primarily in investment-grade countries,
designed Environmental, Health, Safety and Security management program,
and strong partnerships position us as a regional consolidator. We intend to
which we refer to as “S.P.E.E.D.” (Safety, Prosperity, Employees, Environment
continue to grow through strategic acquisitions and potentially in other
and Community Development). Our S.P.E.E.D. program was developed in
countries in Latin America, including Peru which has an investmentgrade
accordance with several international quality standards, including ISO 14001
rating. Our acquisition strategy is aimed at maintaining a balanced portfolio
for environmental management issues, OHSAS 18001 for occupational health
GeoPark 20F
73
and safety management issues, SA 8000 for social accountability and workers’
rights issues, and applicable World Bank standards. See “—Health, safety
and environmental matters.”
Our operations
We have a well-balanced portfolio of assets that includes working and/or
economic interests in 27 hydrocarbons blocks, 26 of which are onshore
blocks, including eleven currently in production, as well as in an additional
shallow-offshore concession in Brazil that includes the Manatí Field.
In addition, we have two new concessions in Brazil that are subject to
confirmation of qualification requirements by the ANP.
Operations in Chile
We became the first privately-owned oil and gas producer in Chile when
we began production in the Fell Block in May 2006, and, for the year ended
December 31, 2013, we produced 66% of Chile’s total oil production
and 16% of its total gas production, according to information provided by
the Chilean Ministry of Energy. We believe our acreage position in Chile
represents an important platform for continued growth and expansion
in that country.
The map below shows the location of the blocks in Chile in which we have
working interests.
C H I L E
A R G E N T I N A
A R G E N T I N A
Tranquilo
Otway
Fell
Isla Norte
Campanario
Flamenco
74
GeoPark 20F
The table below summarizes information about the blocks in Chile in which
we have working interests as of and for the year ended December 31, 2013.
Block
Fell
Tranquilo
Otway
Isla Norte
Campanario
Flamenco(7)
Gross acres
Working
(thousand
acres)
367.8
interest
(1)(6)
100%
Net proved
reserves Production
(boepd)
Basin
6,962 Magallanes
Exploitation: 2032
Concession
expiration year
Partners(2)
—
Pluspetrol;
Operator
GeoPark
(mmboe)(3)
10.7
92.4
(4)49.4
Wintershall;
(6)29% Methanex
(5)100%
—
GeoPark
GeoPark
130.2
(5)60%
ENAP
GeoPark
192.2
(5)50%
ENAP
GeoPark
141.3
(5)50%
ENAP
GeoPark
—
—
—
—
—
— Magallanes
— Magallanes
Exploitation: 2043
Exploitation: 2044
Exploration: 2019
— Magallanes
Exploitation: 2044
Exploration: 2020
— Magallanes
Exploitation: 2045
— Magallanes
Exploitation: 2044
Exploration: 2019
1) Working interest corresponds to the working interests held by our
and Wintershall have recently announced its decision to exit the Consortium.
respective subsidiaries in such block, net of any working interests held by
The new ownership is being negotiated among us and Pluspetrol.
other parties in such block. LGI has a 20% direct equity interest in our
(7) In 2013, there were new discoveries in the Flamenco block. However,
Chilean operations through GeoPark Chile. See “—Significant agreements—
there are no proved reserves estimated for this block due to incomplete
Agreements with LGI—LGI Chile Shareholders’ Agreements.”
testing of these wells as of the date of this annual report.
(2) Partners with working interests.
(3) As of December 31, 2013.
Our Chilean blocks are located in the provinces of Ultima Esperanza,
(4) In April 2013, we voluntarily relinquished to the Chilean government all
Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil- and
of our acreage in the Otway Block, except for 49,421 acres. In May 2013,
gas-producing area. As of December 31, 2013, the Magallanes Basin
our partners under the joint operating agreement governing the Otway Block
accounted for all of Chile’s oil and gas production. Although this basin has
decided to withdraw from such joint operating agreement, and applied
been in production for over 60 years, we believe that it remains relatively
for an assignment of rights permit on August 5, 2013. On August 26, 2013,
underdeveloped.
the Ministry of Energy granted this permit, such that, upon the execution
of a deed of assignment of rights containing the asapproved terms, we will be
Substantial technical data (seismic, geological, drilling and production
the sole participant, and have a 100% working interest, in our two remaining
information), developed by us and by ENAP, provides an informed base for
areas under the Otway Block CEOP. See “—Otway and Tranquilo Blocks.”
new hydrocarbon exploration and development. Shut-in and abandoned fields
(5) LGI has a 14% direct equity interest in our Tierra del Fuego operations
may also have the potential to be put back in production by constructing
through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, for a
new pipelines and plants. Our geophysical analyses suggest additional
total effective equity interest of 31.2% in our Tierra del Fuego operations.
development potential in known fields and exploration potential in undrilled
See “—Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)”
prospects and plays, including opportunities in the Springhill, Tertiary, Tobífera
and “—Significant agreements—Agreements with LGI—LGI Chile
and Estratos con Favrella formations. The Springhill formation has historically
Shareholders’ Agreements.”
been the source of production in the Fell Block, though the Estratos con
(6) At 31 December 2013, the Consortium members and interest were:
Favrella shale formation is the principal source rock of the Magallanes Basin,
GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. Methanex
and we believe it contains unconventional resource potential.
GeoPark 20F
75
Fell Block
In 2006, we became the operator and 100% interest owner of the Fell Block.
During the last three months of 2012 and throughout 2013, we continued our
exploration and development from the Tobífera formation by drilling wells
When we first acquired an interest in the Fell Block in 2002, it had no material
in Konawentru, Yagán and Yagán Norte fields, as well as deepening existing
oil and gas production. Since then, we have completed more than 1,100 sq.
wells in Ovejero and Molino fields with stable production from the formation,
km of 3D seismic surveys and drilled 95 exploration and development wells.
and successful workovers in the Tetera and Kiuaku fields. We are also
In the year ended December 31, 2013, we produced an average of
evaluating the Estratos con Favrella shale reservoir, which we believe
approximately 14,283 mcfpd of gas and 4,581 bopd of oil, or 6,692 boepd,
represents a high-potential, unconventional resource play for shale oil and
in the Fell Block.
gas, as a broad area of the Fell Block (1,000 sq. km) appears to be in the
oil window for this play. We have begun work to reinterpret core data logs
The Fell Block has an area of approximately 368,000 gross acres (1,488 sq. km)
and well test information, evaluate cores and fluids and determine
and its center is located approximately 140 km northeast of the city of Punta
reservoir brittleness (for fracturing) through special field tests.
Arenas. It is bordered on the north by the international border between
Argentina and Chile and on the south by the Strait of Magellan.
Additionally, we have installed ESPs in some key wells in the Fell Block,
The first exploration efforts began on the Fell Block in the 1950s. Through
generating positive results and increasing our oil production in those
2005, ENAP carried out seismic surveys and drilled numerous wells in
wells. Our team is working on identifying other Tobifera wells where to
which we believe were the first-ever ESPs to be used in Chile and which are
the block. From 2006 through August 2011, we invested approximately
replicate these results.
US$210 million in exploring and developing the Fell Block, which allowed
us to transition approximately 84% of the Fell Block’s area from an
exploration phase into an exploitation phase, which we expect will last
Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)
In the first and second quarters of 2012, we entered into three CEOPs with
through 2032. During the exploration phase, we exceeded the minimum
ENAP and Chile granting us working interests in the Isla Norte, Campanario
work and investment commitment required under the Fell Block CEOP
and Flamenco Blocks, located in the center-north of the Tierra del Fuego
by more than 75 times, and as of December 31, 2013, had invested more
province of Chile. We are the operator of all three of these blocks, with
than US$410 million in the Fell Block. There are no minimum work and
working interests of 60%, 50% and 50%, respectively. We believe that these
investment commitments under the Fell Block CEOP associated with the
three blocks, which collectively cover 463,700 gross acres (1,877 sq. km)
exploitation phase.
and are similar and geologically contiguous to the Fell Block, represent
strategic acreage with high resource potential. Following the successful
Geologically, the Fell Block is located in the north-eastern part of the
methodology we employed on the Fell Block, we expect to evaluate early
Magallanes Basin. The principal producing reservoir is composed by
production opportunities from existing nonproducing wells in Tierra del
sandstones in the Springhill formation, at depths of 2,200 to 3,500 meters.
Fuego. We have committed to paying 100% of the required minimum
Additional reservoirs have been discovered and put into production in
investment under the CEOPs covering these blocks, in an aggregate amount
the Fell Block—namely, Tobífera formation volcaniclastic rocks at depths of
2,900 to 3,600 meters, and Upper Tertiary and Upper Cretaceous sandstones,
of US$101.4 million through the end of the first exploratory periods for these
blocks, which we expect will occur by November 2015 for the Flamenco
at depths of 700 to 2,000 meters.
and Isla Norte Blocks and by January 2016 for the Campanario Block, which
includes our covering of ENAP’s investment commitment which corresponds
Our geosciences team continues to identify and develop an attractive
to its working interest in the blocks. In the first quarter of 2012, we began
inventory of prospects and drilling opportunities for both exploration and
3D seismic operations in the Flamenco Block. As of March 2014, 8 wells have
development in the Fell Block, and we expect to continue our comprehensive
been drilled and 1,500 sq. km of 3D seismic have been carried out over the
drilling program in the Fell Block in the coming years. The recent oil
three blocks; which represent the total 3D seismic program commitment.
discoveries in the Konawentru, Yagan, Yagán Norte , Copihue and Guanaco
fields have opened up new oil and gas potential in the Fell Block. An
Exploration in the Tierra del Fuego province in the Magallanes Basin dates
important discovery during 2011 was the Konawentru 1 well, which we
back to the 1940s, when the first surface exploration focused on obtaining
initially tested to have in excess of 2,000 bopd from the Tobífera formation,
stratigraphic and structural information. Structural traps with transgressive
and which has opened up additional potentially attractive opportunities
sandstone reservoirs (Springhill formation) were outlined with refraction
(workovers, welldeepenings and new exploration and development wells)
seismic lines and, in 1945, oil was discovered.
in the Tobífera formation throughout the Fell Block.
76
GeoPark 20F
In the specific area of our Tierra del Fuego Blocks, the first wells were drilled in
the Flamenco Block. Omeling 1 was completed as an oil productive well
1951, resulting in the discovery of the Sombrero oil and gas field. At the end
while Yakamush 1 and Chilco 1 are still waiting for completion. As of April
of the 1950s and in the early 1960s, new fields were discovered to the east
2014, we drilled four additional wells in the Flamenco Block, all of them
(the Catalina and Cuarto Chorrillo fields) and, following the gathering of
were completed as of the date of this annual report, and an
seismic reflection data acquisition, additional new fields were discovered and
additional well is currently being drilled.
existing fields were further developed. During the past decade, geological
studies in the Magallanes Basin have focused on stratigraphic analysis, based
As of December 31, 2013, we had completed 100% of the committed 570 sq.
on 3D and 2D seismic information, the definition and distribution of facies
km of 3D seismic surveys. We have also committed to drilling 10 wells during
of the deltaic and/or turbidite depositional systems of the Late Cretaceous-
the first exploration period under the CEOP governing the Flamenco Block.
Tertiary period and the evolution of the oil system in terms of
generation/timing/expulsion and trapping.
Otway and Tranquilo Blocks
We are the operator of the Otway and Tranquilo Blocks.
Geologically, our Tierra del Fuego Blocks are located in the south-eastern
margin of the Magallanes Basin. The principal producing reservoir is
In the Otway Block, as of December 31, 2013, we had a 25% working
composed by sandstones in the Springhill formation at depths of 1,800 to
interest and our partners were Pluspetrol (25%), Wintershall (25%), IFC (12.5%)
2,300 meters. Additional reservoirs have been discovered and put into
and Methanex (12.5%). Our partners withdrew from the joint operating
production in the Tierra del fuego Blocks namely Tobífera formation
agreement governing the Otway Block in May 2013, and applied to the
volcaniclastic rocks at depths of 2,000 to 2,500 meters, and Upper Terciary
Chilean Ministry of Energy to assign their rights to us in the Otway Block CEOP
and Upper Cretaceous sandstones, at depths of 500 to 1,400 meters.
in August 2013. The Ministry of Energy approved the assignment on
August 26, 2013, subject to the execution of a deed of assignment of rights
Isla Norte Block. We are the operator of, and have a 60% working interest in,
containing the as-approved terms. Following the execution of this
the Isla Norte Block, which covers approximately 130,200 gross acres (527 sq.
assignment deed, we will be the sole participant in the Otway Block CEOP.
km). As of March 2014 we had completed 100% of the committed 350 sq. km
of 3D seismic surveys. We have also committed to drilling three wells during
In 2012, we drilled two wells in the Otway Block, both of which were
the first exploration period under the CEOP governing the Isla Norte Block.
subsequently plugged and abandoned.
Campanario Block. We are the operator of, and have a 50% working interest
in, the Campanario Block, which covers approximately 192,200 gross
On April 10, 2013, we voluntarily and formally announced to the Chilean
Ministry of Energy our decision not to proceed with the second exploratory
acres (778 sq. km). As of December 31, 2013, we had completed 100% of
period and to terminate the exploratory phase under the Otway Block
the committed 578 sq. km of 3D seismic surveys. We have also committed
CEOP, such that we relinquished all areas of the Otway Block, except for two
to drilling eight wells during the first exploration period under the CEOP
areas totaling 49,421 gross acres in which we declared the discovery of
governing the Campanario Block. We are currently drilling the Primavera
Sur 1 well, being the first exploration well of the commitment.
hydrocarbons, in the Cabo Negro and Tatiana prospect areas.
In the Tranquilo Block, as of December 31, 2013, we had a 29% working
Flamenco Block. We are the operator of, and have a 50% working interest in,
the Flamenco Block, which covers approximately 143,800 gross acres
interest, where our partners were Pluspetrol (29%), Wintershall (25%) and
Methanex (17%). Methanex and Wintershall have recently announced its
(582 sq. km). In June 2013, we discovered a new oil and gas field in the block
decision to exit the Tranquilo Block Consortium. The new ownership in the
following the successful testing of the Chercán 1 well, the first well drilled
Tranquilo Block is being negotiated among us and Pluspetrol.
by us in Tierra del Fuego. We conducted a production test in the Tobífera
formation, in which gas flowed at a rate of approximately 4.0 mmcfpd
In the Tranquilo Block we completed a seismic program consisting of 163 sq.
and oil flowed at rates of approximately 35 bopd. We have completed the
km of 3D seismic and 371 sq. km of 2D seismic survey work, and drilled four
construction of a flowline to connect this well to existing infrastructure,
wells, including the Palos Quemados and Marcou Sur well. The Marcou Sur
and the well is currently producing approximately 2,900 mcfpd and 21 bopd
well is under evaluation and we discovered gas in the El Salto formation of
under a long-term production test. Together with ENAP, we decided to pass
the Palos Quemado well. At the Palos Quemados well, we recently completed
on to the commercialization phase. We have also completed drilling three
a 22-week commercial feasibility test aimed at defining its productive
additional wells in 2013, the Omeling 1, Yakamush 1 and Chilco 1 wells in
potential. As the test was not conclusive, we were granted permission by
GeoPark 20F
77
the Chilean Ministry of Energy to extend the testing period for an additional
overriding royalty equal to an estimated 4% of our net revenues for any new
six months. In order to continue producing in this well, we will have to
discoveries of oil. During 2013, we paid US$7.8 million and accrued US$11.5
declare its commercial viability.
million to the previous owners of Winchester pursuant to the Winchester
Stock Purchase Agreement.
On January 17, 2013, we formally announced to the Chilean Ministry of
Energy our decision not to proceed with the second exploratory period and
Our interests in Colombia include working interests and economic interests.
to terminate the exploratory phase of the Tranquilo Block CEOP.
“Working interests” are direct participation interests granted to us pursuant
Subsequently, we relinquished all areas of the Tranquilo Block, except for a
to an E&P Contract with the ANH, whereas “economic interests” are indirect
remaining area of 92,417 gross acres, for the exploitation of the Renoval,
participation interests in the net revenues from a given block based on
Marcou Sur, Estancia Maria Antonieta and Palos Quemados Fields, which we
bilateral agreements with the concessionaires.
have identified as the areas with the most potential for prospects
in the block.
The map below shows the location of the blocks in Colombia in which we
have working and/or economic interests.
As of December 31, 2013, we had completed our minimum work
commitments for the Otway and Tranquilo Blocks, with a total investment of
approximately US$24.0 million for the first exploratory period. The Otway
Block’s seismic commitment program was completed in 2011 and included
C A R I B B E A N S E A
270 sq. km of 3D seismic and 127 km of 2D seismic survey work.
P A N A M A
Cerrito
Llanos 17 +
Yamú
Arrendajo
P A C I F I C
O C E A N
Abanico
V E N E Z U E L A
Jagüeyes
La Cuerva
Llanos 62
Llanos 32
Llanos 34
C O L O M B I A
B R A Z I L
E C U A D O R
P E R U
(1) The PN-T-597 block is subject to an injunction and our bid for the
concession has been suspended.
Operations in Colombia
In the first quarter of 2012, we acquired Winchester, Luna and Cuerva,
three privately-held E&P companies operating in Colombia. We closed the
acquisitions of Winchester and Luna in February 2012 and the acquisition
of Cuerva in March 2012. We acquired Winchester, Luna and Cuerva for a total
consideration of US$105.0 million, adjusted for working capital. Additionally,
in December 2012, LGI agreed to acquire a 20% equity interest in GeoPark
Colombia for a total consideration of US$20.1 million, composed of a US$14.9
million capital contribution, a US$4.9 million loan to GeoPark Colombia and
certain miscellaneous reimbursements. See “—Significant agreements—
Agreements with LGI—LGI Colombia Agreements.”
Our Colombian acquisitions gave us access to 574,979 of gross exploratory
and productive acres across 10 blocks in what we believe to be one of
South America’s most attractive oil and gas geographies. Since we acquired
Winchester, Luna and Cuerva, we were able to perform an active exploration
and development drilling campaign, which resulted in multiple new
discoveries and to increase average production to 6,962 boepd in Colombia
in 2013.
According to the D&M Reserves Report, as of December 31, 2013, the blocks
in Colombia in which we have a working interest had 9.4 mmboe of net
proved reserves, all of which were in oil.
Under the terms of the agreement to acquire Winchester, or the Winchester
Stock Purchase Agreement, we are obligated to make certain payments to the
previous hydrocarbons discovered by exploration wells drilled after October
25, 2011. These payments involve both an earnings-based measure and an
78
GeoPark 20F
Gross acres
(thousand
acres)
Working
interest(1)
Net proved
reserves Production
Partners(2)
Operator
(mmboe)(3)
(boepd)
Basin
Concession
expiration year
Exploration: 2014
The table summarizes information about the blocks in Colombia in which
we have working interests as of and for the year ended December 31, 2013.
Block
La Cuerva
Llanos 34
Llanos 62
Yamú
Llanos 17
Llanos 32
47.8
100.0%
—
GeoPark
RIL-Parex;
82.2
45.0%
Verano Energy
GeoPark
44.0
11.2
100.0%
54.5/
(4)75.0%
108.8
(5)36.8%
100.3
(6)0%
—
—
GeoPark
GeoPark
RIL- Parex
RIL-Parex
APCO;
Verano Energy
Verano
Energy
Jagu(cid:0) eyes 3432A
61.0
5.0%
Columbus
Columbus
(1) Working interest corresponds to the working interests held by our
respective subsidiaries in such block, net of any working interests held
by other parties in such block. LGI has a 20% direct equity interest in our
Colombian operations through GeoPark Colombia. See “—Significant
agreements—Agreements with LGI—LGI Colombia Agreements.”
(2) Partners with working interests.
(3) As of December 31, 2013.
(4) Although we are the sole title holder of the working interest in the
Yamú Block, other parties have been granted economic interests in fields
in this block. Taking those other parties’ interests into account, we have
a 54.5% interest in the Carupana Field and a 75% interest in the Yamú and
Potrillo Fields, both located in the Yamú Block.
(5) We currently have a 40% working interest in the Llanos 17 Block,
although we assigned a 3.2% economic interest to a third party. We expect
to formalize this assignment with the ANH so that it will be recognized
as a working interest.
(6) We currently have a 10% economic interest in the Llanos 32 Block,
although we have applied to the ANH to recognize this as a working interest
in the block, and expect to receive the ANH’s authorization in the first half
of 2014.
(7) The Yamú Block E&P Contract is in both the exploration and exploitation
phases. The phases overlap because the exploitation phase (lasting 24 years)
for the Yamú and Carupana Fields began on the date these fields were
declared commercially viable, while the exploration phase continued to run
for the rest of the block.
2.6
6.4
—
0.3
0.03
0.06
—
1,962
Llanos
Exploitation: 2038
Exploration: 2015
3,469
Llanos
Exploitation: 2039
—
Llanos
550
Llanos
Exploration: 2017
Exploitation: 2041
(7)Exploration: 2013
Production: 2036
Exploration: 2015
49
Llanos
Exploitation: 2039
Exploration: 2015
180
Llanos
Exploitation: 2039
—
Llanos
Exploitation: 2038
Exploration: 2014
GeoPark 20F
79
The table summarizes information about the blocks in Colombia in which we
and Tigana Sur 1 wells represent our fourth and fifth new oil field discoveries,
have economic interests as of and for the year ended December 31, 2013.
respectively, in the Llanos 34 Block since 2012. For the year ended December
Gross acres
(thousand
acres)
78.1
32.1
10.2
Economic
interest(1)
10%
10%
10%
Arrendajo
Abanico
Cerrito
31, 2013, our average net daily production in the block was 3,469 bopd.
During 2013 we completed 250 sq. km of 3D seismic covering the north-west
Production
part of the block, where our team expects to map new exploration prospects
Operator
(boepd)
Basin
to be drilled in 2015. Our partners in the block are Ramshorn International
Pacific
Pacific
Pacific
177
Llanos
Limited, or RILParex and Verano Energy Corp., or Verano Energy, who have
95 Magdalena
a 45% and 10% interest, respectively. See “—Our operations.” We operate in
9 Catatumbo
the block pursuant to an E&P Contract with the ANH. See “—Significant
agreements—Colombia—E&P Contracts—Llanos 34 Block E&P Contract.”
(1) Economic interest corresponds to indirect participation interests in the
net revenues from the block, granted to us pursuant to a joint operating
agreement.
La Cuerva Block. We are the operator of, and have a 100% working interest
in, the La Cuerva Block, which covers approximately 47,000 gross acres
(190 sq. km). Since we acquired an interest in the La Cuerva Block, we have
Eastern Llanos Basin: (La Cuerva, Yamú, Llanos 34, Llanos 32, Llanos 62,
drilled a total of 15 wells in the block, 10 of which were productive. For the
Llanos 17, Jagu(cid:0) eyes 3432A, Arrendajo, Abanico and Cerrito Blocks)
The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region
year ended December 31, 2013, our average net production at the La Cuerva
Block was 1,962 bopd. We operate in the block pursuant to an E&P Contract
of Colombia. Two giant fields (Caño Limón and Castilla), three major fields
with the ANH. See “—Significant agreements— Colombia—E&P Contracts—
(Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had
La Cuerva Block E&P Contract.”
been discovered. The source rock for the basin is located beneath the east
flank of the Eastern Cordillera, as a mixed marine-continental shaly basinal
facies of the Gachetá formation. The main reservoirs of the basin are
Llanos 62 Block. We are the operator of, and have a 100% working interest
in, the Llanos 62 Block, which covers approximately 44,000 gross acres
represented by the Paleogene Carbonera and Mirador sandstones. Within the
(178 sq. km). As of December 31, 2013, we had undertaken 72.2 sq. km of
Cretaceous sequence, several sandstones are also considered to have good
3D seismic surveys within the block. We operate the block pursuant to
reservoirs.
an E&P Contract with the ANH.
Llanos 34 Block. We are the operator of, and have a 45% working interest in,
the Llanos 34 Block, which covers approximately 82,200 gross acres (333 sq.
Yamú Block. We are the operator of, and have a 100% working interest in, the
Yamú Block, which covers approximately 11,200 gross acres (45.5 sq. km).
km). We acquired an interest in and took operatorship of the block in the
Economic rights to certain fields in the Yamú Block have been granted to
first quarter of 2012, which at the time had no production, reserves or wells
other parties. In May 2013, we successfully drilled and completed the Potrillo
drilled on it, and with 210 sq. km of existing 3D seismic on which our
1 well in the block—our third oil field discovery in Colombia—to a total depth
team had mapped multiple exploration prospects. We have drilled some of
these prospects with positive results. Through 2013, we have drilled 14
of 3,560 meters. The well is producing at a rate of approximately 230 bopd.
Surface facilities are already in place, and the crude oil produced from the
wells which resulted in five new oil discoveries and 13 new productive wells.
well is now being marketed and sold. For the year ended December 31, 2013,
These include the Tarotaro 1 exploration well in the Tarotaro Field, which
our average net production at the Yamú Block was 550bopd. We operate in
we successfully drilled, tested and put into production in June 2013.
the block pursuant to an E&P Contract with the ANH.
A test conducted on the Tarotaro 1 well resulted in a production rate of
approximately 2,239 bopd. Surface facilities are already in place and
the crude oil produced from the wells is now being marketed and sold. The
Llanos 17 Block. We have a 40% working interest in the Llanos 17 Block,
which covers approximately 108,800 gross acres (440 sq. km). Ramshorn
Tarotaro Field is the second oil field that we have discovered since our
International Limited (“RIL”) -Parex is the operator of, and has a 60% working
expansion into Colombia in the first half of 2012. We drilled and tested the
interest in, the Llanos 17 Block. Since we acquired a working interest in the
Tigana 1 exploration well in the Mirador formation, with production at a rate
block, two wells have been drilled in the block, one of which was productive.
of approximately 2,126 bopd. In addition, we tested the Guadalupe
We maintain our 40% working interest in the Llanos 17 Block pursuant
formation, with production at a rate of approximately 1,465 bopd. We also
to an E&P Contract with the ANH. However, we expect to apply to the ANH
drilled and tested the Tigana Sur 1 well in the Guadalupe formation, which
to approve an assignment of 3.2% of our working interest in this block to
is currently producing at a rate of approximately 1,598 bopd. The Tigana 1
another party.
80
GeoPark 20F
Llanos 32 Block. Verano Energy is the operator of, and has a 50% working
interest in, the Llanos 32 Block, which covers approximately 100,300 gross
initially entered into with Kappa Resources Colombia Limited (now Pacific),
Maral Finance Corporation, Geoproduction Oil & Gas Company of Colombia
acres (406 sq. km).Verano Energy’s partners in the block are RIL-Parex and
Limitada and Texican Oil PLC.
APCO Properties Ltd., or APCO, who have a 30% and a 20% working interest
in the block, respectively. Currently, we have a 10% economic interest in the
Llanos 32 Block pursuant to a joint operating agreement with Verano Energy.
Operations in Brazil
On May 14, 2013, we announced the future extension of our footprint into
We do not maintain a direct working interest in this block pursuant to an
Brazil when the ANP awarded us seven new exploratory licenses in the REC-T
E&P Contract with the ANH, but we have applied to the ANH to recognize our
94 and RECT 85 Concessions in the Recôncavo Basin in the State of Bahia and
interest in the Llanos 32 Block as a working interest, and expect to receive the
the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 Concessions
ANH’s authorization in the first half of 2014. Since we acquired an interest in
in the Potiguar Basin in the State of Rio Grande do Norte, or our Round 11
the Llanos 32 Block, and as of December 31, 2013, five wells have been drilled
concessions, collectively covering an area of approximately 54,900 gross
in the block, three of which were productive. For the year ended December
acres. On September 17, 2013, we entered into seven concession agreements
31, 2013, our average net production in the Llanos 32 Block was 180 bopd.
with the ANP for the right to exploit the oil and natural gas in these seven
Jagu(cid:0) eyes 3432A Block. We have a 5% working interest in the Jagu(cid:0) eyes 3432A
Block, which covers approximately 61,000 acres (247 sq. km). Our partner in
new concessions. For our winning bids on these seven concessions, we
committed to invest a minimum of US$15.3 million (including bonuses and
estimated work program commitment) during the first three years of
the block is Columbus Energy, who maintains a 95% working interest in and is
the exploratory period for the concessions, and expect to begin seismic
the operator of the Jagu(cid:0) eyes 3432A Block. We maintain a working interest in
work in the first half of 2014. These seven new concessions cover an area
the Jagu(cid:0) eyes 3432A Block pursuant to an E&P Contract with the ANH.
of approximately 54,850 gross acres. Pursuant to ANP requirements, actual
exploitation of these new concessions will also depend on obtaining an
Arrendajo Block. In December 2005, Great North Energy Colombia Inc. (now
Pacific Stratus Energy Corp., or Pacific) and the ANH entered into the Arrendajo
environmental license from the respective state environmental agencies.
The ANP has also qualified us as a class B operator, meaning that we are
Block E&P Contract. Pacific is the operator of, and has a 100% working interest
recognized as having met all technical and managerial conditions required
in, the Arrendajo Block, which covers approximately 78.1 gross acres.
to operate safely in Brazil, both onshore and offshore at water depths of
We do not maintain a direct working interest in this block pursuant to an E&P
less than 400 meters. As of the date of this annual report, seismic licensing
Contract with the ANH, but rather have a 10% economic interest in the net
contracts were signed for the Reconcavo basin blocks and for the Potiguar
revenues of the Arrendajo Block pursuant to a participating interest agreement
basin blocks, which are planned to start during 2014.
between us and Great North Energy Colombia Inc. (now Pacific).
Additionally, we acquired Rio das Contas from Panoro for a total cash
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco
Inc. entered into the Abanico Block association contract. Pacific is the
consideration of US$140 million (subject to working capital adjustments and
further earn-out payments, if any), which closed on March 31, 2014 and gives
operator of, and has a 100% working interest in, the Abanico Block, which
covers an area of approximately 32.1 gross acres. We do not maintain a direct
us a 10% working interest in the BCAM-40 Concession, including the shallow-
depth offshore Manatí and Camarão Norte Fields, in the Camamu-Almada
working interest in the Abanico Block, but rather have a 10% economic
Basin in the State of Bahia. The Manatí Field, which is in the production phase,
interest in the net revenues from the block pursuant to a joint operating
is operated by Petrobras (with a 35% working interest), the Brazilian national
agreement initially entered into with Kappa Resources Colombia Limited
company and the largest oil and gas operator in Brazil, in partnership with
(now Pacific, who subsequently assigned its participation interest to Cespa de
QGEP (with a 45% working interest), and Brasoil (with a 10% working interest).
Colombia S.A., who then assigned the interest to Explotaciones CMS Oil &
See “—Significant agreements—Brazil—Rio das Contas Quota Purchase
Gas), Maral Finance Corporation and Getionar S.A.
Agreement.” Some environmental licenses related to operation of the Manatí
Cerrito Block. In February of 2002, Ecopetrol and Kappa Resources Colombia
Limited (now Pacific) entered into the Cerrito Block association contract.
Field production system and natural gas pipeline are expired. However, the
operator submitted, timely, the request for renewal of those licenses and
as such this operation is not in default as long as the regulator does not state
The Cerrito Block covers an area of approximately 10.2 gross acres. Pacific is
its final position on the renewal. See “—Health, safety and environmental
the operator of, and has a 100% working interest in, the Cerrito Block. We
matters—Other regulation of the oil and gas industry—Brazil.” The Camarão
do not maintain a direct working interest in the Cerrito Block, but rather have
Norte Field is in the development phase and is not yet subject to the
a 10% economic interest in the block pursuant to a joint operating agreement
environmental licensing requirement.
GeoPark 20F
81
Our acquisition of Rio das Contas in Brazil, which closed on March 31, 2014,
The map below shows the location of the concessions in Brazil in which
provides us with a long-term off-take contract with Petrobras that covers
we expect to have working interests as a result of our Brazil Acquisitions.
approximately 74% of net proved gas reserves in the Manatí Field, a valuable
relationship with Petrobras and an established local platform and presence,
with seasoned and experienced geoscience and administrative team to
manage the assets and to seek new growth opportunities.
Also in Brazil, on November 28, 2013, the ANP awarded us two new
concessions, the PN-T-597 Concession in the Parnaíba Basin in the State of
Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin in
the State of Alagoas, in the 12th oil and gas bidding round. Our winning bids
B R A Z I L
are subject to confirmation of qualification requirements. For our winning
bids on these two concessions, we have committed to invest a minimum of
US$4.0 million (including bonus and estimated work program commitments)
during the first exploratory period. These two new concessions cover an
area of approximately 196,500 acres. For more information, see “Item 3.
Key information—D. Risk factors—Risks relating to our business—The PN-T-
597 concession is subject to an injunction and may not close.”
POT-T-620
POT-T-619
POT-T-663
POT-T-664
PN-T-597
POT-T-665
REC -T- 85
REC -T- 94
BCAM-40
SEAL-T-268
On September 30, 2013, we entered into a strategic alliance with Tecpetrol
to jointly identify, study and potentially acquire upstream oil and gas
opportunities in Brazil, with a specific focus on the Parnaíba, Sao Francisco,
Recôncavo, Potiguar and Sergipe Alagoas basins. As part of our strategic
alliance with Tecpetrol, we expect to enter into an agreement to jointly
P A R A G U A Y
A R G E N T I N A
develop, by assigning to Tecpetrol 50% of our working interest in, the PN T
(1) The PN-T-597 block is subject to an injunction and our bid for the
597 concession in the Parnaíba Basin in the State of Maranhão, which we
concession has been suspended. See “Item 3. Key Information—D. Risk
were awarded by the ANP, subject to confirmation of qualification
factors—Risks relating to our business— The PN-T-597 concession is
requirements.
subject to an injunction and may not close.”
82
GeoPark 20F
The following table sets forth information as of December 31, 2013 on our
concessions in Brazil in which we have a current or future working interest,
including the Round 11 concessions and the Round 12 concessions, and
also includes on a pro forma basis information on our recent Rio das Contas
acquisition, which closed on March 31, 2014.
Gross acres
(thousand
acres)
Working
interest(1)
Net proved
reserves Production
Partners
Operator
(mmboe)
(boepd)
Basin
Concession
expiration year
Exploration: 2018
7.7
7.7
100%
100%
7.9
100%
7.9
7.9
100%
100%
7.9
100%
—
—
—
—
—
—
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
7.9
188.7
7.8
251.4
22.8
274.2
100%
100%(5)
—
—(5)
GeoPark
GeoPark
100%
—
GeoPark
Petrobras;
QGEP;
10%
Brasoil
Petrobras
—
—
—
—
—
—
—
—
—
—
—
8.3
— Recôncavo
Exploitation: 2045
Exploration: 2018
— Recôncavo
Exploitation: 2045
Exploration: 2018
Potiguar
Exploitation: 2045
Exploration: 2018
Potiguar
Exploitation: 2045
Exploration: 2018
Potiguar
Exploitation: 2045
Exploration: 2018
Potiguar
Exploitation: 2045
—
—
—
—
—
Potiguar
— Parnaíba
Sergipe
Alagoas
—
—
Exploration: 2018
Exploitation: 2045
—(4)
—(4)
Camamu-
—
Almada
Exploitation:
2029(2) - 2034(3)
3,580
REC-T 94
REC-T 85
POT-T 664
POT-T 665
POT-T 619
POT-T 620
POT-T 663
PN-T-597(4)
SEAL-T-268(4)
Total Brazil
BCAM-40
Total Brazil Pro forma
(1) Working interest corresponds to the working interests we expect to
requirements by the ANP and absence of any legal impediments to signing.
hold in such concession, net of any working interests held by other parties
See “Item 3. Key Information—Risk factors—Risks relating to our business—
in such concession, as a result of our Rio das Contas acquisition and the
The PN-T-597 concession is subject to an injunction and may not close.”
separate award to us by the ANP of the Round 12 concessions.
(5) We expect to jointly develop this concession with Tecpetrol and assign
(2) Corresponds to Manatí Field.
(3) Corresponds to Camarão Norte Field.
50% of our working interest in this concession to Tecpetrol. See Item 3 -
Risk Factors “The PNT- 597 concession is subject to an injunction and may
(4) Round 12 concessions are subject to confirmation of qualification
not close”.
GeoPark 20F
83
BCAM-40 Concession
As a result of the Rio das Contas acquisition, we have a 10% working interest
km of 3D seismic surveys in the REC-T 94 Concession and 30 km of 2D seismic
surveys in the REC-T 85 Concession. We have also committed, following
in the BCAM-40 Concession, which includes interests in the Manatí Field
the signing of the concession agreement in respect of the concessions, to a
and the Camarão Norte Field, and which is located in the Camamu-Almada
work program to the ANP of R$19.3 million (approximately US$8.5 million,
Basin. Petrobras is the operator of, and has a 35% working interest in, the
at the March 31, 2014 exchange rate of R$2.263 to US$1.00) during the first
BCAM-40 Concession, which covers approximately 22,784 gross acres
exploratory period under the concession agreement governing the
(92.2 sq. km). In addition to us, Petrobras’ partners in the block are Brasoil
concessions, consisting of a R$7.2 million (approximately US$3.2 million, at
and QGEP, with 10% and 45% working interests, respectively. Petrobras
the March 31, 2014 exchange rate of R$2.263 to US$1.00) bonus payable
operates the BCAM-40 Concession pursuant to a concession agreement with
to the ANP in the first year of exploration and R$12.1 million (approximately
the ANP, executed on August 6, 1998. See “—Significant agreements—
US$5.3 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00)
Brazil—Overview of concession agreements—BCAM-40 Concession
as a work program guarantee payable over the course of the three years.
Agreement.” In September 2009, Petrobras announced the relinquishment
The work program consists on drilling two exploratory wells and 31 sq. km
of BCAM- 40’s exploration area within the concession to the ANP, except for
of 3D seismic surveys in the REC-T94 Concession and 30 sq. km of 2D seismic
the Manatí Field and the Camarão Norte Field.
surveys in REC-T 85 Concession. The exploratory phase for these concessions
is divided into two exploratory periods, the first of which lasts for three years
The Manatí Field is located 65 km south of Salvador, at a 35-meter water
and the second of which is non-obligatory and can last for up to two years.
depth. The field was discovered in October 2000, and, in 2002, Petrobras
declared the field commercially viable. Production began in January 2007. As
of September 30, 2013, 11 wells had been drilled in the Manatí Field, six of
POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 Concessions
The POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 Concessions
which are productive and connected to a fixed production platform installed
are onshore and located in the Potiguar Basin. As of December 31, 2013,
at a depth of 35 meters, located 9 km from the coast of the State of Bahia.
according to the ANP, the Potiguar basin was the third largest producer of oil
From the platform, the gas flows by sea and land through a 125 km pipeline
in Brazil, with 91 fields in production and 11 fields in development stage
to the Estação Vandemir Ferreira or EVF gas treatment plant. The gas is sold to
including onshore and offshore. Total production of the above mentioned
Petrobras up to a maximum volume as determined in the existing Petrobras
fields were 60,402 bopd and 1.460 mmm3 per day of gas.
Gas Sales Agreement (as defined below). Rio das Contas is negotiating an
amendment to the existing Petrobras Gas Sales Agreement with Petrobras for
The POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620
the sale of additional volumes from the Manatí Field to Petrobras.
Concessions cover a total area of 39,507 gross acres (160 sq. km). The
REC-T 94 and REC-T 85 Concessions
The REC-T 94 and REC-T 85 Concessions are onshore and located in the
concession agreements require us make total investments of R$11.3 million
(approximately US$5.0 million at the March 31, 2014 exchange rate of
R$2.263 to US$1.00) during the first exploratory period under the concession
Recôncavo Basin, which covers an area of approximately 2.7 million gross
agreement, with a R$3.0 million (approximately US$1.3 million at the March
acres (11,000 sq. km). The basin’s main source rocks belong to the Candeias
formation, with reservoirs on the fluvio-deltaic sandstones of the Marfim
31, 2014 exchange rate of R$2.263 to US$1.00) bonus payable to the ANP
in the first year of exploration and R$8.3 million (approximately US$3.7 million
and Pojuca formations, Fluvial sandstones of the Candeias and Marancagalha
at the March 31, 2014 exchange rate of R$2.263 to US$1.00) as a work
formations, and the Fluvio-Eolic sandstones of the Agua Grande and Sergi
program guarantee payable over the course of the three years. We have also
formations. Reconcavo basin is considered a mature basin. According to the
committed to undertaking 222 km of 2D seismic work in the first exploration
ANP, as of December 31, 2013, 92 fields are in production or development
period for the concession areas, with no well drilling commitment during
stage, and production was 43,905 bopd and 2.519 mmm3 per day.
this period. The exploratory phase for these concessions is divided into two
exploratory periods, the first of which lasts for three years and the second
The REC-T 94 and REC-T 85 Concessions cover an area of 7,660 gross acres
of which is non-obligatory and can last for up to two years.
(31 sq. km) and 7,660 gross acres (31 sq. km), respectively. In connection with
our bid to obtain the licenses for these concessions, we have committed to
drilling two exploratory wells in the concessions, and to undertaking 31 sq.
84
GeoPark 20F
Round 12 Concessions
Additionally, on November 28, 2013, the ANP awarded us two new
See “Item 3. Key Information—D. Risk factors—Risks relating to our
business—The PN-T-597 concession is subject to an injunction and may not
concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of
close” and “—D. Risk factors—Risks relating to the countries in which we
Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin
operate—Our operations may be adversely affected by political and
in the State of Alagoas) in the 12th oil and gas bidding round. Our winning
economic circumstances in the countries in which we operate and in which
bids are subject to confirmation of qualification requirements. We have
we may operate in the future” for more information.
committed to invest a minimum of US$4 million (including bonus and work
program commitments). For more information, see “Item 3. Key
information—D. Risk factors—Risks relating to our business—The PN-T-597
SEAL-T-268 Concession
The SEAL-T-268 Concession is located onshore in the Sergipe-Alagoas Basin.
concession is subject to an injunction and may not close.”
This basin encompasses an area of approximately 10.9 million gross acres
PN-T-597 Concession
The PN-T-597 Concession is located onshore in the Parnaiba Basin, which
(44,400 sq. km), of which 3.1 million gross acres (12600 sq. km) are situated
onshore. It has gone through 3 main tectonic stages: pre-rift, rift, and drift.
Source rock intervals were identified on the Rift (Barra de Ituba and Coqueiro
covers an area of approximately 148 million gross acres (600,000 sq. km).
Seco Fms) and Prerift sequences (Aracare Fm). Reservoirs are the fluvio-deltaic
The basin’s main petroleum system consists of the Devonian Pimenteras Fm
and lacustrine sandstones present in the pre-rift and rift intervals (Aracare,
source rock with reservoirs of continental to shallow marine sandstones
Serraria, Penedo and Maceio Fms). Over the drift sequence, turbiditic
of the Poti and Cabeças formations. Intrusive and extrusive magmatic rocks
sandstones were deposited, mainly in the offshore part of the basin and
are interbedded within the sedimentary column, influencing source rock
the cretaceous shale acts as seal. The onshore part of the basin is considered
maturation and sometimes acting as seals.
mature in terms of hydrocarbon exploration.
Parnaiba is a basin with large underexplored areas. As December 31,
Sergipe-Alagoas accounts for a production of 44,417 bopd and 4.6 mmm3
2013, the basin had one producing field accounting for the production
per day of gas as of December 31th, 2013, according to the ANP. At this
of 5.651 mmm3 per day of gas and 144 bopd. Three more fields are in
date, there were 55 fields either in production or development stages on
development stage.
the basin.
The PN-T-597 Concession covers an area of 188,667 gross acres (763.5 sq.
The SEAL-T-268 Concession covers an area of 7,799 gross acres (31.6 sq. km).
km). The offer requires a commitment to the ANP of R$7.7 million
GeoPark’s winning offer requires a commitment to the ANP of R$1.6 million
(approximately US$3.4 million, at the March 31, 2014 exchange rate of
(approximately US$0.7 million, at the March 31, 2014 exchange rate of
R$2.263 to US$1.00) for the first exploratory period. This amount is comprised
R$2.263 to US$1.00) for the first exploratory period. This amount is comprised
of R$0.9 million (approximately US$0.4 million, at the March 31, 2014
of R$0.14 million (approximately US$0.07 million, at the March 31, 2014
exchange rate of R$2.263 to US$1.00) bonus payable to the ANP in the first
exchange rate of R$2.263 to US$1.00) bonus payable to the ANP in the first
year of exploration and R$6.7 million (approximately US$3.0 million, at
the March 31, 2014 exchange rate of R$2.263 to US$1.00) as a work program
year of exploration and R$1.5 million (approximately US$0.7 million, at
the March 31, 2014 exchange rate of R$2.263 to US$1.00) as a work program
guarantee payable over the course of the four years. Work program is
guarantee payable over the course of three years. Work program is equivalent
equivalent to 180 km of 2D seismic, with no well drilling committed during
to 40 km of 2D seismic, with no well drilling committed during the first
the first exploratory period.
exploratory period.
The exploratory phase for these concessions is divided into two exploratory
The exploratory phase for this concession is divided into two exploratory
periods. Given that Parnaiba basin is considered as a “new frontier”
periods, the first lasting three years, and the second, which is optional,
area by the ANP, the first exploratory period lasts four years, and the second
can last for up to two years.
exploratory period, which is optional, can last for up to two years.
GeoPark 20F
85
Operations in Argentina
The map below shows the location of the blocks in Argentina in which we
have working interests as of December 31, 2013.
B O L I V I A
P A R A G U A Y
B R A Z I L
U R U G U A Y
Loma Cortaderal
Cerro Doña Juana
A R G E N T I N A
C H I L E
Del Mosquito
The table below summarizes information about the blocks in Argentina in
which we have working interests as of December 31, 2013.
Block
Del Mosquito
Cerro Doña Juana(3)
Loma Cortaderal(3)
Gross acres
(thousand
acres)
Net proved
Working
interest(1)
Operator
reserves Production
(boepd)
(mmboe)(2)
Basin
Magallanes
Expiration
concession year
17.3
19.6
28.3
100%
100%
100%
GeoPark
GeoPark
GeoPark
—
—
—
64
Austral
— Neuquén
Exploitation: 2016
Exploitation: 2017
—
Neuquén
Exploitation: 2017
(1) Working interest corresponds to the working interests held by our
(3) In April 2014, we informed theSecretary of Infrastructure and Energy
respective subsidiaries in such block, net of any working interests held by
of the Province of Mendoza of our decision to relinquish 100% of the Cerro
other parties in each block.
(2) As of December 31, 2013.
Doña Juana and Loma Cortaderal Concessions to the Mendoza Province.
86
GeoPark 20F
As of December 31, 2013, although we had production in our blocks in
Oil and natural gas reserves and production
Argentina, D&M determined that there were no reserves in these blocks.
This was due to the uneconomic status of the reserves, given the proximity
to the end of the concessions for these blocks, which does not allow for
Overview
We have achieved consistent growth in oil and gas reserves from our
future capital investment in the blocks. However, if we are able to extend
investment activities since 2007, when we began production in the Fell Block.
our concessions in Argentina, the assumptions used to make this
As of December 31, 2013, D&M reported that on a pro forma basis, our total
determination may change in the future.
net proved reserves in Brazil (including our Rio das Contas acquisition that
closed on March 31, 2014), Chile, Colombia and Argentina were 28.4 mmboe.
Del Mosquito Block
We are the operator of, and have 100% working interest in, the Del Mosquito
Of this total, 8.3mmboe or 29%, 10.7 mmboe, or 38%, 9.4 mmboe, or 33%,
were in Brazil, Chile and Colombia, respectively, and we had no net proved
Block. We established oil production in the block in 2002 by rehabilitating
reserves in Argentina.
the abandoned Del Mosquito Field and subsequently discovered the
Del Mosquito Norte field. We are evaluating potential drilling opportunities
The following table summarizes our net proved reserves in Chile, Colombia
on the Del Mosquito Block and the option of bringing a partner into the
and Argentina as of December 31, 2013 and also includes on a pro forma
project to increase investment activity. For the year ended December 31,
basis information related to our Rio das Contas acquisition, which closed on
2013, our average daily production at the Del Mosquito Block was 64 boepd.
March 31, 2014.
The Del Mosquito Block covers an area of approximately 17,313 gross acres
(70 sq. km), and is located in the Magallanes Austral Basin in southern
Argentina.
According to the Secretariat of Energy (Secretaría de Energía) in Argentina,
Chile
or the Argentine Secretary of Energy, for the year ended December 31, 2013,
Colombia
the Magallanes Austral Basin produced approximately 4.6% of Argentina’s
Argentina
total oil production and approximately 25.2% of its total gas production.
Cerro Doña Juana and Loma Cortaderal Blocks
The Cerro Doña Juana and Loma Cortaderal Blocks cover areas of
Total
Brazil(2)
Pro forma total
Total net
proved
reserves
(mmboe)(1)
10.7
9.4
—
20.1
8.3
28.4
Gas
(bcf)
32.2
0.0
—
32.2
48.8
80.9
% Oil
50%
100%
—
74%
2%
53%
Oil
(mmbbl)
5.4
9.4
—
14.8
0.2
15.0
approximately 28,300 (115 sq. km) and 19,600 (79 sq. km) gross acres,
(1) We calculate one barrel of oil equivalent as six mcf of natural gas.
respectively.
(2) Reflects our Rio das Contas acquisition.
As of December 31, 2013 we were the operator of, and have a 100% working
interest in, each of the Cerro Doña Juana and Loma Cortaderal Blocks.
Neither the Cerro Doña Juana nor the Loma Cortaderal Block is currently in
production.
In April 2014, we informed the Secretary of Infrastructure and Energy of
the Province of Mendoza of our decision to relinquish 100% of the Cerro
Doña Juana and Loma Cortaderal Concessions to the Mendoza Province.
Neither the Cerro Doña Juana nor the Loma Cortaderal are currently in
production or have any associated reserves.
GeoPark 20F
87
Our reserves
The following table sets forth our oil and natural gas net proved reserves
and management and acquisition and divestiture opportunities evaluation.
See “Item 6. Directors, Senior Management and Employees—A. Directors
as of December 31, 2013, which is based on the D&M Reserves Report.
and senior management.”
In addition, it includes on a pro forma basis information on our Rio das
Contas acquisition, which closed on March 31, 2014.
In order to ensure the quality and consistency of our reserves estimates and
Oil Natural gas
(mmbbl)
(bcf)
Net proved developed
- Chile
- Colombia
- Argentina
Total net proved developed
- Brazil(2)
Total net proved
developed Pro forma
Net proved undeveloped
- Chile
- Colombia
- Argentina
Total net proved
undeveloped
- Brazil(2)
Total net proved
2.2
3.3
—
5.5
0.1
5.6
3.1
6.2
—
9.3
0.1
undeveloped Pro forma
Total net proved
Total net proved Pro forma
9.4
14.8
15.0
10.0
—
—
10.0
28.8
38.8
22.1
—
—
22.1
20.0
42.1
32.1
80.9
reserves disclosures, we maintain and comply with a reserves process that
Net proved reserves
satisfies the following key control objectives:
As of December 31, 2013
• estimates are prepared using generally accepted practices and
Total net
proved
reserves
(mmboe)(1)
3.9
3.3
—
7.2
4.9
methodologies;
• estimates are prepared objectively and free of bias;
• estimates and changes therein are prepared on a timely basis;
% Oil
• estimates and changes therein are properly supported and approved; and
• estimates and related disclosures are prepared in accordance with
57%
regulatory requirements.
100%
—
Throughout each fiscal year, our technical team meets with Independent
89%
2%
Qualified Reserves Engineers, who are provided with full access to complete
and accurate information pertaining to the properties to be evaluated
and all applicable personnel. This independent assessment of the internally-
12.1
46%
generated reserves estimates is beneficial in ensuring that interpretations
and judgments are reasonable and that the estimates are free of preparer
6.8
6.2
—
13.0
3.4
16.3
20.1
28.4
46%
and management bias.
100%
—
Recognizing that reserves estimates are based on interpretations and
72%
2%
57%
74%
53%
judgments, differences between the proved reserves estimates prepared by
us and those prepared by an Independent Qualified Reserves Engineer of
10% or less, in aggregate, are considered to be within the range of reasonable
differences. Differences greater than 10% must be resolved in the technical
meetings. Once differences are resolved, the independent Qualified Reserves
Engineer sends a preliminary copy of the reserves report to members of our
senior management, who act as a Reserves Review Committee. Our Chief
Executive Officer, Chief Financial Officer, Director of Development Geology
and Director of Exploration, form this committee.
Independent reserves engineers
Pro forma reserves estimates as of December 31, 2013 for Brazil, Chile,
Colombia and Argentina included in this annual report are based on the
(1) We calculate one barrel of oil equivalent as six mcf of natural gas.
(2) Reflects our Rio das Contas acquisition.
Internal controls over reserves estimation process
We maintain an internal staff of petroleum engineers and geosciences
professionals who work closely with our independent reserves engineers
D&M Reserves Report, completed on March 19, 2014 and effective as
to ensure the integrity, accuracy and timeliness of data furnished to
of December 31, 2013. The D&M Reserves Report, a copy of which has
our independent reserves engineers in their estimation process and who
been filed as an exhibit to this annual report, was prepared in accordance
have knowledge of the specific properties under evaluation.
with SEC rules, regulations, definitions and guidelines at our request in
order to estimate reserves and for the areas and period indicated therein.
Our Director of Development Geology, Carlos Alberto Murut, is primarily
responsible for overseeing the preparation of our reserves estimates and for
D&M, a Delaware corporation with offices in Dallas, Houston, Calgary,
the internal control over our reserves estimation. He has more than 30
Moscow and Algiers, has been providing consulting services to the
years of industry experience as an E&P geologist, with broad experience in
oil and gas industry for more than 75 years. The firm has more than 150
reserves assessment, field development, exploration portfolio generation
professionals, including engineers, geologists, geophysicists, petrophysicists
88
GeoPark 20F
and economists that are engaged in the appraisal of oil and gas properties,
royalties, development and environmental permitting and concession terms,
the evaluation of hydrocarbon and other mineral prospects, basin
may require revision of such estimates. Our operations may also be affected
evaluations, comprehensive field studies and equity studies related to the
by unanticipated changes in regulations concerning the oil and gas industry
domestic and international energy industry. D&M restricts its activities
in the countries in which we operate, which may impact our ability to
exclusively to consultation and does not accept contingency fees, nor does
recover the estimated reserves. Accordingly, oil and natural gas quantities
it own operating interests in any oil, gas or mineral properties, or securities
ultimately recovered will vary from reserves estimates.
or notes of its clients. The firm subscribes to a code of professional conduct,
and its employees actively support their related technical and professional
societies. The firm is a Texas Registered Engineering Firm.
Technology used in reserves estimation
According to SEC guidelines, proved reserves are those quantities of oil and
gas which, by analysis of geoscience and engineering data, can be estimated
The D&M Reserves Report covered 100% of our total reserves. In connection
with “reasonable certainty” to be economically producible—from a given
with the preparation of the D&M Reserves Report, D&M prepared its own
date forward, from known reservoirs, and under existing economic
estimates of our proved reserves. In the process of the reserves evaluation,
conditions, operating methods and government regulations—prior to the
D&M did not independently verify the accuracy and completeness of
time at which contracts providing the right to operate expire, unless
information and data furnished by us with respect to ownership interests,
evidence indicates that renewal is reasonably certain, regardless of whether
oil and gas production, well test data, historical costs of operation and
deterministic or probabilistic methods are used for the estimation.
development, product prices, or any agreements relating to current
and future operations of the fields and sales of production. However, if in
The project to extract the hydrocarbons must have commenced or the
the course of the examination something came to the attention of D&M that
operator must be reasonably certain that it will commence the project within
brought into question the validity or sufficiency of any such information
a reasonable time. The term “reasonable certainty” implies a high degree
or data, D&M did not rely on such information or data until it had satisfactorily
of confidence that the quantities of oil and/or natural gas actually recovered
resolved its questions relating thereto or had independently verified such
will equal or exceed the estimate. Reasonable certainty can be established
information or data. D&M independently prepared reserves estimates to
using techniques that have been proved effective by actual production
conform to the guidelines of the SEC, including the criteria of “reasonable
from projects in the same reservoir or an analogous reservoir or by other
certainty,” as it pertains to expectations about the recoverability of reserves
evidence using reliable technology that establishes reasonable certainty.
in future years, under existing economic and operating conditions, consistent
Reliable technology is a grouping of one or more technologies (including
with the definition in Rule 4-10(a)(2) of Regulation S-X. D&M issued the
computational methods) that have been field tested and have been
D&M Reserves Report based upon its evaluation. D&M’s primary economic
demonstrated to provide reasonably certain results with consistency and
assumptions in estimates included oil and gas sales prices determined
repeatability in the formation being evaluated or in an analogous formation.
according to SEC guidelines, future expenditures and other economic
assumptions (including interests, royalties and taxes) as provided by us. The
There are various generally accepted methodologies for estimating reserves
assumptions, data, methods and procedures used, including the percentage
of our total reserves reviewed in connection with the preparation of the
including volumetrics, decline analysis, material balance, simulation models
and analogies. Estimates may be prepared using either deterministic
D&M Reserves Report were appropriate for the purpose served by such
(single estimate) or probabilistic (range of possible outcomes and probability
report, and D&M used all methods and procedures as it considered necessary
of occurrence) methods. The particular method chosen should be based
under the circumstances to prepare such reports.
on the evaluator’s professional judgment as being the most appropriate,
given the geological nature of the property, the extent of its operating history
However, uncertainties are inherent in estimating quantities of reserves,
and the quality of available information. It may be appropriate to employ
including many factors beyond our and our independent reserves engineers’
several methods in reaching an estimate for the property.
control. Reserves engineering is a subjective process of estimating subsurface
accumulations of oil and natural gas that cannot be measured in an exact
Estimates must be prepared using all available information (open and
manner, and the accuracy of any reserves estimate is a function of the quality
cased hole logs, core analyses, geologic maps, seismic interpretation,
of available data and its interpretation. As a result, estimates by different
production/injection data and pressure test analysis). Supporting data, such
engineers often vary, sometimes significantly. In addition, physical factors
as working interest, royalties and operating costs, must be maintained and
such as the results of drilling, testing and production subsequent to the
updated when such information changes materially.
date of an estimate, economic factors such as changes in product prices or
development and production expenses, and regulatory factors, such as
GeoPark 20F
89
Proved undeveloped reserves
As of December 31, 2013, excluding reserves from Rio das Contas, we had
million in capital expenditures to convert such proved undeveloped reserves
to proved developed reserves, of which approximately US$56.3 million and
13.0 mmboe in proved undeveloped reserves, an increase of 2.4 mmboe,
US$33.8 million were made in Chile and Colombia, respectively. Giving effect
or 23%, over our December 31, 2012 proved undeveloped reserves of 10.6
to our recent Rio das Contas acquisition, as of December 31, 2013 we
mmboe. The increase in proved undeveloped oil reserves consisted of 4.8
had 16.4 mmboe in proved undeveloped reserves, of which 3.4 mmboe
mmboe, partially offset by 2.4 mmboe of revisions principally resulting from
corresponds to Rio das Contas.
2.3 mmboe of proved undeveloped reserves converted to proved developed.
Of our 13.0 mmboe of net proved undeveloped reserves, 6.8 mmboe, 6.2
Production, revenues and price history
The following table sets forth certain information on our production of
mmboe and 0 mmboe, or 52%, 48% and 0%, were located in Chile, Colombia
oil and natural gas in Chile, Colombia and Argentina for each of the years
and Argentina, respectively. During 2013, we incurred approximately US$90.1
ended December 31, 2013, 2012 and 2011:
Total
Chile Colombia Argentina GeoPark(4)
2013
Colom-
2012
Total
Average daily production(1)
As of December 31,
2011
Total
Chile
bia(2) Argentina
GeoPark
Chile Colombia Argentina
GeoPark
Oil production
Average crude oil
production (bopd)
4,581
6,482
50
11,113
4,013
3,431
48
7,491
2,441
Average sales price of
crude oil (US$/bbl)(4)
Natural gas production
Average natural gas
84.3
80.3
70.3
82.0
85.42
97.15
67.8
90.5
83.8
production (mcfpd)
14,283
52
84
14,419
22,663
56
84
22,804
30,419
5.0
4.18
1.1
5.0
4.04
4.18
1.1
4.0
3.9
4.0
8.3
12.2
26.5
19.0
10.7
34.0
(6.7)
16.8
Other (US$/boe)
2.9
4.1
3.5
2.5
4.0
2.9
Average production
cost (US$/boe)(3)
Average depreciation
15.1
30.6
12.3
22.5
13.2
38.1
(US$/boe)
11.5
16.6
2.5
13.9
9.9
20.4
142.1
13.4
9.1
Average production
cost (US$/boe)
26.6
47.2
14.8
36.4
23.1
58.4
143.0
33.1
19.4
8.6
1.7
7.6
0.9
19.7
10.3
Average sales
price of natural gas
(US$/mcf)(4)
Oil and gas
production cost
Average operating
cost (US$/boe)
Average royalties and
—
—
—
—
—
—
—
—
—
68
2,508
59.4
83.8
87
30,506
1.1
3.9
6.8
7.0
8.6
1.7
13.7
10.3
29.6
9.3
43.3
19.7
(1) We present production figures net of interests due to others, but
Winchester, Luna and Cuerva prior to their acquisition by us.
before deduction of royalties, as we believe that net production before
(3) Calculated pursuant to FASB ASC 932.
royalties is more appropriate in light of our foreign operations and the
(4) Averaged realized sales price for oil does not include our Argentine
attendant royalty regimes.
blocks because our Argentine operations were not material during such
(2) We acquired Winchester and Luna in February 2012 and Cuerva
periods. Averaged realized sales price for gas does not include our Argentine
in March12. Production figures do not include, for 2012, production for
and Colombian blocks because our gas operations in those countries were
not material during such period.
90
GeoPark 20F
For the year ended December 31, 2013, information on our Rio das Contas
acquisition, which we closed in March 31, 2014, was as follows:
As of Dec 31, 2013
Oil production
Average crude oil production (bopd)
Average sales price of crude oil (US$/bbl)
Natural gas production
Average natural gas production (mcfpd)
Average sales price of natural gas (US$/mcf)(4)
Oil and gas production cost
Average operating cost (US$/boe)
Average royalties and Other (US$/boe)
Average production cost (US$/boe)(3)
Average depreciation (US$/boe)
Average production cost (US$/boe)
Brazil
60
108.3
21,120
6.4
8.3
3.8
12.1
14.9
27.0
Drilling activities
The following table sets forth the exploratory wells we drilled as operators
in Chile, Colombia and Argentina during the years ended December 31, 2013,
2012 and 2011.
Productive
Gross
Net
Dry
Gross
Net
Total
Gross
Net
2013
2012
Exploratory wells(1)
As of December 31,
2011
Chile
Colombia
Argentina
Chile Colombia(2)
Argentina
Chile
Colombia
Argentina
7.0
4.8
3.0
1.5
10.0
6.3
9.0
6.0
1.0
1.0
10.0
7.0
—
—
—
—
—
—
8.0
8.0
6.0
4.5
14.0
12.5
4.0
2.4
3.0
2.5
7.0
4.9
—
—
—
—
—
—
7.0
7.0
7.0
7.0
14.0
14.0
—
—
—
—
—
—
1.0
1.0
—
—
1.0
1.0
(1) Includes appraisal wells.
(2) We acquired Winchester and Luna in February 2012 and Cuerva in March12.
Figures do not include, for 2012, exploration activities for Winchester, Luna
and Cuerva prior to their acquisition by us.
GeoPark 20F
91
The following table sets forth the development wells we drilled in Chile,
Colombia and Argentina during the years ended December 31, 2013, 2012
and 2011.
Productive
Gross
Net
Dry
Gross
Net
Total
Gross
Net
2013
2012
Development wells
As of December 31,
2011
Chile
Colombia
Argentina
Chile Colombia(1)
Argentina
Chile
Colombia Argentina
6.0
6.0
1.0
1.0
7.0
7.0
5.0
2.8
—
—
5.0
2.8
—
—
—
—
—
—
4.0
4.0
2.0
2.0
6.0
6.0
6.0
5.5
2.0
2.0
8.0
7.5
—
—
—
—
—
—
8.0
8.0
—
—
8.0
8.0
—
—
—
—
—
—
—
—
—
—
—
—
(1) We acquired Winchester and Luna in February 2012 and Cuerva in March
For the year ended December 31, 2013, total developed acreage in Brazil was
2012. Figures do not include, for 2012, exploration activities for Winchester,
18.7 thousand acres (gross) and 1.9 thousand acres (net). Total undeveloped
Luna and Cuerva prior to their acquisition by us.
acreage was 4.1 thousand acres (gross) and 0.4 thousand acres (net). Total
developed and undeveloped acreage was 22.8 thousand acres (gross) and 2.3
For the year ended December 31, 2013 there were no exploratory wells drilled
thousand acres (net).
in our Rio das Contas acquisition, which we closed on March 31, 2014.
Developed and undeveloped acreage
The following table sets forth certain information regarding our total gross
Productive wells
The following table sets forth our total gross and net productive wells as of
March 31, 2014. Productive wells consist of producing wells and wells capable
and net developed and undeveloped acreage in Chile, Colombia and
of producing, including natural gas wells awaiting pipeline connections
Argentina as of December 31, 2013.
Total developed acreage
Gross
Net
Total undeveloped acreage
Gross
Net
Total developed and
undeveloped acreage
Gross
Net
Acreage(1)
Argentina
Colombia
(in thousands of acres)
3.3
2.6
2.4
1.3
5.7
3.9
2.0
2.0
-
-
2.0
2.0
Chile
14.5
14.5
7.4
7.4
21.9
21.9
to commence deliveries and oil wells awaiting connection to production
facilities. Gross wells are the total number of producing wells in which we
have an interest, and net wells are the sum of our fractional working
interests owned in gross wells.
Oil wells
Gross
Net
Gas wells
Gross
Net
Chile Colombia(2)
Productive wells(1)
Argentina
46.0
45.0
27.0
25.8
72.0
36.5
—
—
5.0
5.0
—
—
(1) Includes wells drilled by other operators, prior to our commencing
operations, and wells drilled in blocks in which we are not the operator.
(1) Defined as acreage assignable to productive wells. Net acreage based on
(2) We acquired Winchester and Luna in February 2012 and Cuerva in
our working interest.
March2012. Figures include wells drilled by Winchester, Luna and Cuerva
prior to their acquisition by us.
92
GeoPark 20F
For the year ended December 31, 2013, there were 6.0 gross and 0.6 net
productive gas wells in our Rio das Contas acquisition, which we closed on
March 31, 2014.
Present activities
The following table shows the number of wells in Chile, Colombia and
Argentina that are in the process of being drilled or are in active completion
stages, and the number of wells suspended or waiting on completion as
of March 31, 2014.
Wells in process of being drilled
or in active completion(1)
Argentina
Colombia
Chile
Wells suspended or waiting
on completion(2)
Argentina
Colombia
Chile
Oil wells
Gross
Net
Gas wells
Gross
Net
—
—
—
—
1.0
0.5
—
—
—
—
—
—
—
—
1.0
0.3
2.0
0.9
—
—
—
—
—
—
(1) We consider wells to be in active completion when we have begun
until the expiration of the Fell Block CEOP, which is the earlier of August
procedures used in finishing and equipping them for production.
24, 2032 or the date on which we cease exploitation of hydrocarbons in the
(2) We consider wells to be waiting on completion when we have completed
Fell Block. Commercial conditions of the amended contract are similar to
drilling in such wells but have not yet begun to perform testing procedures.
the previous one in effect, however the price will now be related to Ice Brent
For the year ended December 31, 2013, there were no wells in process of
some terms of the contract have improved for us, including changes in the
being drilled or in active completion stages, nor were there any wells
calculation of certain discounts, such as discounts for mercury content.
Crude Futures on the London Intercontinental Exchange. In addition,
suspended or waiting on completion in our Rio das Contas acquisition,
which we closed on March 31, 2014.
Marketing and delivery commitments
Chile
Our customer base in Chile is limited in number and primarily consists of
We deliver the oil we produce in the Fell Block to ENAP at the Gregorio
Terminal, where ENAP assumes responsibility for the oil. ENAP owns
two refineries in Chile in the north central part of the country and must
ship any oil from the Gregorio Terminal to these refineries unless it is
consumed locally.
ENAP and Methanex. For the year ended December 31, 2013, we sold 100%
Under the Methanex Gas Supply Agreement, Methanex has committed to
of our oil production in Chile to ENAP and 99% of our gas production to
purchasing, and we have committed to selling, all of the gas that we
Methanex, with sales to ENAP and Methanex accounting for 39.8% and 6.7%,
produce in the Fell Block (subject to certain exceptions, including reasonable
respectively, of our revenues in the same period.
quantities required to maintain our operations and quantities that we might
be required to pay in kind to Chile), with a minimum volume commitment
Under our oil sales agreement with ENAP, or the ENAP Oil Sales Agreement,
which is defined by us on an annual basis. The agreement contains monthly
ENAP has committed to purchase our oil production in the Fell Block, but
DOP obligations, which require us to deliver in a given month the minimum
only in the amounts that we produce, and with the only limitation being
gas committed for that month or pay a deficiency penalty to Methanex,
storage capacity at the Gregorio Terminal. The sales contract with ENAP is
with a threshold of 90% of the committed quantities of gas. The agreement
commonly revised every two years to reflect changes in the global oil market
also contains monthly TOP obligations, which apply when our committed
and to adjust to logistics costs of ENAP in the Gregorio oil terminal. The
volume for a given month exceeds 35.3 mcfpd, and require Methanex to take
current agreement has been recently executed, with an initial term of 1 year,
in such month the minimum gas volume committed for such period or face
until March 2015, and it will be automatically extended for periods of 1 year
higher TOP obligations in later months, with a threshold of 90% of the
GeoPark 20F
93
committed quantities. These DOP and TOP obligations are subject to make-
up provisions without penalty, for any delivery or off-take deficiencies
Colombia
Our production in Colombia consists almost exclusively of oil. Our oil sales
accrued, in the three months following the month where delivery or off-take
agreements are generally for a fixed term, with a maximum length of one
requirements were not met. We failed to meet this adjusted volume for each
year. They do not commit the parties to a minimum volume, and are subject
of the months of April through December of 2012, such that we accrued
to the ability of either party to receive or deliver production. The contracts
US$1.7 million in DOP payments owed to Methanex under the Methanex Gas
generally provide that they can be renewed by mutual written agreement,
Supply Agreement, all of which had been paid as of September 30, 2013.
and all allow for early termination by either party with advanced notice and
In April 2013, Methanex idled its plant, but committed to purchasing
without penalty.
from us the minimum committed gas volumes under the Methanex Gas
The delivery points for our production range from the well-head to the port
Supply Agreement during the time the plant was idle. The plant resumed
of export (Coveñas), depending on the client. If sales are made via pipeline,
operations on September 23, 2013. The same condition is expected in
the delivery point is usually the pipeline injection point, whereas for direct
2014, as ENAP will require additional gas beyond its own production to
export sales, the most frequent delivery point is the well-head. In Colombia,
supply residential consumption. We also expect that Methanex will require
the restrictions to access pipeline networks, especially for mid to heavy
additional deliveries to restart its plant after the winter months, beginning
crudes, have forced the market to access different ways of transport and
in September 2014.
commercialization, reducing our dependency on pipeline infrastructure
significantly. For the year ended December 31, 2013, we sold approximately
On August 30, 2013, we signed an amendment to the Methanex Gas
66% of our production directly at the well-head and approximately 30%
Supply Agreement, pursuant to which Methanex has committed, for a period
to the major oil companies that own capacity in the pipelines. In the first
of six months beginning September 15, 2013, to purchase an increased
quarter of 2014, access to the pipeline network has improved upon the
volume, a total amount of 400,000 SCM/d per month (subject to reduction
commencement of the Bicentenario pipeline, which added transportation
for deliveries above 200,000 SCM/d to Methanex or ENAP made between
capacity of 100,000 bopd and also open up additional supply opportunities
April 29 and September 15, 2013), at an additional price per month of
involving reduced trucking costs. Since we do not own capacity in, or
US$1.50 per mmbtu for volumes in excess of 180,000 SCM/d, or an additional
have access to, the oil transportation pipelines in Colombia or have any
price per month of US$2.00 per mmbtu in any month in which we commit
other assets for the transportation of our commodities, we use third parties
to deliver at least 500,000 SCM/d (subject to certain exceptions based
to transport our production by pipeline or truck.
on methanol prices). The amendment also provides for temporary DOP and
TOP thresholds of 100% and 50%, respectively. The amendment has been
The price of the oil that we sell under these agreements is based on a
extended until April 30 2014. Therefore, we are currently committed to
market reference price (Brent, WTI or Vasconia), adjusted for certain
providing Methanex with a monthly volume of gas of 0.424 bcf until April
marketing and quality discounts based on, among other things, API, viscosity,
30, 2014. As of the date of this annual report, we have fulfilled the delivery
sulphur and water content, as well as for certain transportation costs
volume commitment.
(including pipeline costs and trucking costs).
We gather the gas we produce in several wells through our own flow lines
For the year ended December 31, 2013, we made 52.5% of our oil sales to
and inject it into several gas pipelines owned by ENAP. The transportation
Gunvor, 20.9% to Hocol and 9.8% to Perenco, with Gunvor accounting
of the gas we sell to Methanex through these pipelines is pursuant to a
for 27.8%, Hocol 11.1% and Perenco 5.2% of our overall revenues for the
private contract between Methanex and ENAP. We do not own any principal
same period. If we were to lose any one of our key customers, the loss could
natural gas pipelines for the transportation of natural gas.
temporarily delay production and sale of our oil in the corresponding block.
However, we believe we could identify a substitute customer to purchase
If we were to lose any one of our key customers in Chile, the loss could
the impacted production volumes.
temporarily delay production and sale of our oil and gas in Chile. For a
discussion of the risks associated with the loss of key customers, see “Item 3.
Key Information—D. Risk factors—Risks relating to our business—
Brazil
Our production in Brazil consists of natural gas and condensate oil. Natural
We sell all of our natural gas in Chile to a single customer, who has in the
gas production is sold through a long-term, extendable agreement with
past temporarily idled its principal facility” and “—We derive a significant
Petrobras, which provides for the delivery and transportation of the gas
portion of our revenues from sales to a few key customers.”
produced in the Manatí Field to the EVF gas treatment plant in the State of
94
GeoPark 20F
Bahia. The contract is in effect until delivery of the maximum committed
Significant agreements
volume or June 2030, whichever occurs first. The contract allows for sales
above the maximum committed volume if mutually agreed by both seller and
buyer. We are currently negotiating an amendment to the contract in order
to provide for the purchase and sale of additional volumes, pending the
Chile
CEOPs
We have entered into six CEOPs with Chile, one for each of the blocks in
closing of the gas compression facility. The price for the gas is fixed in reais
which we operate, which grant us the right to explore and exploit
and is adjusted annually in accordance with the Brazilian inflation index.
hydrocarbons in these blocks, determine our working interests in the blocks
and appoint the operator of the blocks. These CEOPs are divided into
The Manatí Field is developed via a PMNT-1 production platform, which is
two phases: (1) an exploration phase, which is divided into two or more
connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant
exploration periods, and which begins on the effectiveness date of
through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd
the relevant CEOP, and (2) an exploitation phase, which is determined on a
(9.5 mm3 per day). The existing pipeline connects the field’s platform to
perfield basis, commencing on the date we declare a field to be commercially
the EVF gas treatment plant, which is owned by the field’s current concession
viable and ending with the term of the relevant CEOP. In order to transition
holders. The BCAM-40 Concession, which includes the Manatí Field,
from the exploration phase to an exploitation phase, we must declare a
also benefits from the advantages of Petrobras’s size. As the largest onshore
discovery of hydrocarbons to the Ministry of Energy. This is a unilateral
and offshore operator in Brazil, Petrobras has the ability to mobilize the
declaration, which grants us the right to test a field for a limited period of
resources necessary to support its activities in the concession.
time for commercial viability. If the field proves commercially viable, we must
make a further unilateral declaration to the Ministry of Energy. In the
The condensate produced in the Manatí Field is subject to a condensate
exploration phase, we are obligated to fulfill a minimum work commitment,
purchase agreement with Petrobras, pursuant to which Petrobras has
which generally includes the drilling of wells, the performance of 2D or
committed to purchase all of our condensate production in the Manatí
3D seismic surveys, minimum capital commitments and guaranties or letters
Field, but only in the amounts that we produce, without any minimum or
of credit, as set forth in the relevant CEOP. We also have relinquishment
maximum deliverable commitment from us. The agreement is valid
obligations at the end of each period in the exploration phase in respect
through December 31, 2015, but can be renewed upon an amendment
of those areas in which we have not made a declaration of discovery.
signed by Petrobras and the seller.
We can also voluntarily relinquish areas in which we have not declared
discoveries of hydrocarbons at any time, at no cost to us. In the exploitation
If the agreements with Petrobras were terminated, this could temporarily
phase, we generally do not face formal work commitments, other than
delay production and sale of our natural gas and condensate oil in Brazil,
the development plans we file with the Chilean Ministry of Energy for each
and could have a detrimental effect on our ability to find substitute
field declared to be commercially viable.
customers to purchase our production volumes.
Argentina
In Argentina, we sell substantially all of our oil production to Oil
Our CEOPs provide us with the right to receive a monthly remuneration
from Chile, payable in petroleum and gas, based either on the amount
of petroleum and gas production per field or according to Recovery Factor,
Combustibles, but because the volume we produce in Argentina is small
which considers the ratio of hydrocarbon sales to total cost of production
and the sale price is fixed at the moment when all other producers have
(capital expenditures plus operating expenses). Pursuant to Chilean
delivered their product to the Punta Loyola terminal, from which we sell our
law, the rights contained in a CEOP cannot be modified without consent
crude, we do not sell our oil to Oil Combustibles at a predetermined formula
of the parties.
or price, but rather on the basis of on-call contracts based on demand.
We have the ability to store and process the oil we produce in Argentina
which vary depending upon the phase of the CEOP. During the exploration
ourselves, and do not have material contracts with third parties for
phase, Chile may terminate a CEOP in circumstances including a failure
such services. We enter into ad hoc contracts with local companies for the
by us to comply with minimum work commitments at the termination of
transportation of crude from fields in the Del Mosquito Block to the Punta
any exploration period, or a failure to communicate our intention to proceed
Our CEOPs are subject to early termination in certain circumstances,
Loyola terminal.
with the next exploration period 30 days prior to its termination, a failure
to provide the Chilean Ministry of Energy the performance bonds required
under the CEOP, a voluntary relinquishment by us of all areas under the CEOP
GeoPark 20F
95
or a failure by us to meet the requirements to enter into the exploitation
into various exploration phases and (2) the exploitation period, determined
phase upon the termination of the exploration phase. In the exploitation
on a per-area basis and beginning on the date we declare an area to be
phase, Chile may terminate a CEOP if we stop performing any of the
commercially viable. Commercial viability is determined upon the completion
substantial obligations assumed under the CEOP without cause and do
of a specified evaluation program or as otherwise agreed by the parties
not cure such nonperformance pursuant to the terms of the concession,
to the relevant E&P Contract. The exploitation period for an area may be
following notice of breach from the Chilean Ministry of Energy. Additionally,
extended until such time as such area is no longer commercially viable and
Chile may terminate the CEOP due to force majeure circumstances (as
certain other conditions are met.
defined in the relevant CEOP). If Chile terminates a CEOP in the exploitation
phase, we must transfer to Chile, free of charge, any productive wells and
Pursuant to our E&P Contracts, we are required, as are all oil and gas
related facilities, provided that such transfer does not interfere with our
companies undertaking exploratory and production activities in Colombia,
abandonment obligations and excluding certain pipelines and other assets.
to pay a royalty to the Colombian government based on our production
Other than as provided in the relevant CEOP, Chile cannot unilaterally
of hydrocarbons, as of the time a field begins to produce. Under Law 756
terminate a CEOP without due compensation. See “Item 3. Key Information—
of 2002, as modified by Law 1530 of 2012, the royalties we must pay in
D. Risk factors—Risks relating to our business—Our contracts in obtaining
connection with our production of light and medium oil are calculated on
rights to explore and develop oil and natural gas reserves are subject to
a field-by-field basis, using the following sliding scale:
contractual expiration dates and operating conditions, and our CEOPs, E&P
Contracts and concession agreements are subject to early termination in
certain circumstances.”
Production (mbop)
Up to 5,000
Fell Block CEOP. On November 5, 2002, we acquired a percentage of rights
and interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP,
5,000 to 125,000
125,000 to 400,000
and on May 10, 2006, we became the sole owners, with 100% of the rights
400,000 to 600,000
and interest in the Fell Block CEOP. Chile had originally entered into a CEOP
Greater than 600,000
for the Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April
Production
Royalty rate
8%
8-20%
20%
20-25%
25%
29, 1997, which had an effective date of August 25, 1997. The Fell Block
In the case of natural gas, the royalties are 80% of the rates presented
CEOP grants us the exclusive right to explore and exploit hydrocarbons in
above for the exploitation of onshore and offshore fields at depths less than
the Fell Block and has a term of 35 years, beginning on the effective date.
or equal to 304.8 meters, and 60% for the exploitation of offshore fields at
The Fell Block CEOP provided for a 14-year exploration period, composed of
depths exceeding 304.8 meters. For new discoveries of heavy oil, classified
numerous phases that ended in 2011, and an up-to-35-year exploitation
as oil with an API equal to or less than 15°, the royalties are 75% of the rates
phase for each field.
presented above. Additionally, in the event that an exploitation area has
produced amounts in excess of an aggregate amount established in the E&P
The Fell Block CEOP provides us with a right to receive a monthly retribution
from Chile payable in petroleum and gas, based on the following per-field
Contract governing such area, the ANH is entitled to receive a “windfall
profit,” to be paid periodically, calculated pursuant to such E&P Contract.
formula: 95% of the oil produced in the field, for production of up to
5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for
In each of the exploration and exploitation periods, we are also obligated
production of up to 882.9 mmcfpd. In the event that we exceed these levels
to pay the ANH a subsoil use fee. During the exploration period, this fee is
of production, our monthly retribution from Chile will decrease based
scaled depending on the contracted acreage. During the exploitation period,
on a sliding scale set forth under the Fell Block CEOP to a maximum of 50%
the fee is assessed on the amount of hydrocarbons produced, multiplied
of the oil and 60% of the gas that we produce per field.
by a specified dollar amount per barrel of oil produced or thousand cubic
Colombia
E&P Contracts
We have entered into E&P Contracts granting us the right to explore and
feet of gas produced. Further, the ANH has the right to receive an additional
fee when prices for oil or gas, as the case may be, exceed the prices set
forth in the relevant E&P Contract.
operate, as well as working interests in, six blocks in Colombia. Additionally,
Our E&P Contracts are generally subject to early termination for a breach by
we have applied to the ANH to recognize our economic interest in a seventh
the parties, a default declaration, application of any of the contract’s
Colombian block as a working interest. These E&P Contracts are generally
unilateral termination clauses or termination clauses mandated by Colombian
divided into two periods: (1) the exploration period, which may be subdivided
law. Anticipated termination declared by the ANH results in the immediate
96
GeoPark 20F
enforcement of monetary guaranties against us and may result in an action
interest, giving Ramshorn a 55% working interest and us a 45% working
for damages by the ANH. Pursuant to Colombian law, if certain conditions are
interest in the Llanos 34 Block.
met, the anticipated termination declared by the ANH may also result in a
restriction on the ability to engage contracts with the Colombian government
We are currently in the exploration period of the Llanos 34 Block E&P
during a certain period of time. See “Item 3. Key Information—D. Risk factors—
Contract. The contract provides for a six-year exploration period, consisting
Risks relating to our business—Our contracts in obtaining rights to explore
of two three-year phases, which can be extended for up to six additional
and develop oil and natural gas reserves are subject to contractual expiration
months to allow for the completion of exploration activities. The Llanos 34
dates and operating conditions, and our CEOPs, E&P Contracts and concession
Block E&P Contract provides for a 24- year exploitation period for each
agreements are subject to early termination in certain circumstances.”
commercial area, beginning on the date on which such area is declared
La Cuerva Block E&P Contract. Pursuant to an E&P Contract between us and
the ANH that became effective as of April 16, 2008, or the La Cuerva Block
commercially viable. The exploitation period may be extended for periods of
up to 10 years at a time, until such time as the area is no longer commercially
viable and certain conditions are met. We have presented evaluation
E&P Contract, we were granted the right to explore and operate, and a 100%
programs to the ANH for the Max, Túa and Tarotaro Fields, which expire on
working interest in, the La Cuerva Block.
September 15, 2014, December 1, 2014, and November 17, 2015, respectively.
We are currently in the sixth phase of exploration under the La Cuerva Block
Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are
E&P Contract. The exploration period has six phases and terminates on July
required to pay to the ANH a royalty based on hydrocarbons produced in the
16, 2014. Each exploration period requires a guaranty of 10% of the total
Llanos 34 Block. In the Max Field, we pay the ANH a royalty of at least 6.0%,
budget for the corresponding exploration period or post-exploration period
and in the Túa and Tarotaro Fields, we pay a royalty of at least 8.0%.
(such amount must be at least US$100,000 and may not exceed US$3 million).
Additionally, we are required to pay a subsoil use fee to the ANH, which, during
Production began in the west, southwest and southern areas of the block
the exploration period, is scaled depending on the contracted acreage, and
on December 13, 2011, February 15, 2012 and April 23, 2012, respectively.
which, during the exploitation period, is equivalent to the amount of oil
The La Cuerva Block E&P Contract provides for a 24-year exploitation period
we produce multiplied by US$0.1162 per bbl or the amount of natural gas we
for each area in the La Cuerva Block, beginning from the date such area is
produce multiplied by US$0.01162 per mcf. The ANH also has the right to
declared commercially viable.
receive an additional fee when prices for oil or gas, as the case may be, exceed
the prices set forth in the Llanos 34 Block E&P Contract. The ANH also has an
Pursuant to the La Cuerva Block E&P Contract and applicable law, we are
additional economic right equivalent to 1% of production, net of royalties.
required to pay to the ANH a royalty of at least 8.0% based on hydrocarbons
produced, in accordance with the table presented above. Additionally,
we are required to pay a subsoil use fee to the ANH, which, during the
Winchester and Luna Stock Purchase Agreement
Pursuant to the stock purchase agreement entered into on February 10, 2012
exploration period, is scaled depending upon the contracted acreage, and
with Darlan S.A., Bonanza Ventures, Inc., Winamac Holdings Inc. and Realstep
which, during the exploitation period, is equivalent to the amount of oil
we produce multiplied by US$0.1119 per bbl or the amount of natural
Overseas Inc., as the Sellers, or the Winchester Stock Purchase Agreement,
we agreed to pay the Sellers a total consideration of US$30.0 million, adjusted
gas we produce multiplied by US$0.0119 per mcf. The ANH also has the right
for working capital. Additionally, under the terms of the Winchester Stock
to receive an additional fee when prices for oil or gas, as the case may be,
Purchase Agreement, we are obligated to make certain payments to
exceed the prices set forth in the La Cuerva Block E&P Contract.
the Sellers based on the production and sale of hydrocarbons discovered by
Llanos 34 Block E&P Contract. Pursuant to an E&P Contract between Unión
Temporal Llanos 34 (a consortium between Ramshorn and Winchester) and
exploration wells drilled after October 25, 2011. The agreement provides
that we make a quarterly payment to the Sellers in an amount equal to 14%
of adjusted revenue (as defined under the agreement) from any new
the ANH that became effective as of March 13, 2009, or the Llanos 34 Block
discoveries of oil, up to the maximum earn-out amount of US$35.0 million
E&P Contract, Unión Temporal Llanos 34 was granted the right to explore
(net of Colombian taxes). Once the maximum earn-out amount is reached,
and operate the Llanos 34 Block, and we and Ramshorn were granted a 40%
we will pay the Sellers quarterly overriding royalties in an amount equal
and a 60% working interest, respectively, in the Llanos 34 Block. We were
to 4% of our net revenues from any new discoveries of oil. For the year ended
also granted the right to operate the Llanos 34 Block. On December 16, 2009,
December 31, 2013, we paid US$7.8 million and accrued US$11.5 million
we entered into a joint operating agreement with Ramshorn and P1 Energy
with regards to this agreement.
in respect of our operations in the block. On August 31, 2012, the ANH
approved the assignment by Ramshorn to us of an additional 5% working
GeoPark 20F
97
Cuerva purchase and sale agreement
Pursuant to the purchase and sale agreement dated March 26, 2012 between
concession area or the declaration of commercial viability with respect to a
given area), while the development and production phase, which begins for
Hupecol Cuerva Holdings LLC, as the Seller, and us, we agreed to pay to
each field on the date a declaration of commercial viability is submitted
the Seller a total consideration of US$75 million, adjusted for working capital.
to the ANP, can last up to 27 years. Upon each declaration of commercial
Brazil
Rio das Contas Quota Purchase Agreement
Pursuant to the Rio das Contas Quota Purchase Agreement we entered into
field within 180 days. The concessions may be renewed for an additional
period equal to their original term if renewal is requested with at least 12
months’ notice, and provided that a default under the concession agreement
on May 14, 2013, we agreed to acquire from Panoro all of the quotas issued
has not occurred and is then continuing. Even if obligations have been
by Rio das Contas for a purchase price of US$140 million (subject to working
fulfilled under the concession agreement and the renewal request was
capital adjustments at closing and further earn-out payments, if any) upon
appropriately filed, renewal of the concession is subject to the discretion of
viability, a concessionaire must submit to the ANP a development plan for the
satisfaction of certain conditions. With respect to the earn-out payments, the
the ANP.
Rio das Contas Quota Purchase Agreement provides that during the calendar
periods beginning on January 1, 2013 and ending as late as December 31,
The main terms and conditions of a concession agreement are set forth
2017, we will make annual earn-out payments to Panoro in an amount equal
in Article 43 of the Brazilian Petroleum Law, and include: (1) definition
to 45% of “net cash flow,” calculated as EBITDA less the aggregate of
of the concession area; (2) validity and terms for exploration and production
capital expenditures and corporate income taxes, with respect to the BCAM-
activities; (3) conditions for the return of concession areas; (4) guarantees
40 Concession of any amounts in excess of US$25.0 million, up to a maximum
to be provided by the concessionaire to ensure compliance with the
cumulative earn-out amount of US$20.0 million in a five-year period. Once
concession agreement, including required investments during each phase;
the maximum earn-out amount is reached or the five-year period has elapsed,
(5) penalties in the event of noncompliance with the terms of the concession
no further earnout amounts will be payable.
agreement; (6) procedures related to the assignment of the agreement; and
(7) rules for the return and vacancy of areas, including removal of equipment
We financed our Rio das Contas acquisition in part through our Brazilian
and facilities and the return of assets. Assignments of participation interests
subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas
in a concession are subject to the approval of the ANP, and the replacement
Credit Facility”) with Itau BBA International plc, which is secured by the
of a performance guarantee is treated as an assignment.
benefits GeoPark receives under the Purchase and Sale Agreement for Natural
Gas with Petrobras. The facility matures five years from March 28, 2014,
The main rights of the concessionaires (including us in our concession
which was the date of disbursement and bears interest at a variable interest
agreements) are: (1) the exclusive right of drilling and production in
rate equal to the six-month LIBOR + 3.9%. The facility agreement includes
the concession area; (2) the ownership of the hydrocarbons produced;
customary events of default, and subject our Brazilian subsidiary to customary
(3) the right to sell the hydrocarbons produced; and (4) the right to export
covenants, including the requirement that it maintain a ratio of net debt to
the hydrocarbons produced. However, a concession agreement set
EBITDA of up to 3.5x the first two years and up to 3.0x thereafter. The credit
facility also limits the borrower’s ability to pay dividends if the ratio of net
forth that, in the event of a risk of a fuel supply shortage in Brazil, the
concessionaire must fulfill the needs of the domestic market. In order to
debt to EBITDA is greater than 2.5x. We have the option to prepay the facility
ensure the domestic supply, the Brazilian Petroleum Law granted the
in whole or in part, at any time, subject to a pre-payment fee to be
ANP the power to control the export of oil, natural gas and oil products.
determined under the contract.
Overview of concession agreements
The Brazilian oil and gas industry is governed mainly by the Brazilian
Among the main obligations of the concessionaire are: (1) the assumption
of costs and risks related to the exploration and production of hydrocarbons,
including responsibility for environmental damages; (2) compliance with
Petroleum Law, which provides for the granting of concessions to operate
the requirements relating to acquisition of assets and services from domestic
petroleum and gas fields in Brazil, subject to oversight by the ANP.
suppliers; (3) compliance with the requirements relating to execution of
A concession agreement is divided into two phases: (1) exploration and (2)
the minimum exploration program proposed in the winning bid; (4) activities
development and production. The exploration phase, which is further
for the conservation of reservoirs; (5) periodic reporting to the ANP;
divided into two subsequent exploratory periods, the first of which begins on
(6) payments for government participation; and (7) responsibility for the
the date of execution of the concession agreement, can last from three to
costs associated with the deactivation and abandonment of the facilities
eight years (subject to earlier termination upon the total return of the
in accordance with Brazilian law and best practices in the oil industry.
98
GeoPark 20F
A concessionaire is required to pay to the Brazilian government the following:
Under the BCAM-40 Concession Agreement, the ANP is entitled to a
• a license fee;
monthly royalty payment equal to 7.5% of the production of oil and natural
• rent for the occupation or retention of areas;
gas in the concession area. In addition, in case the special participation
• a special participation fee;
• royalties; and
• taxes.
fee of 10% shall be applicable for a field in any quarter of the calendar year,
the concessionaire is obliged to make qualified research and development
investments equivalent to one percent of the field’s gross revenue. Area
retention payments are also applicable under the concession agreement.
Rental fees for the occupation and maintenance of the concession areas
are payable annually. For purposes of calculating these fees, the ANP takes
Pursuant to the Rio das Contas Quota Purchase Agreement, we have agreed
into consideration factors such as the location and size of the relevant
to acquire Rio das Contas’s 10% participation interest in the BCAM-40
concession, the sedimentary basin and the geological characteristics of the
Concession. We closed the acquisition on March 31, 2014.
relevant concession.
A special participation fee is an extraordinary charge that concessionaires
Round 11 concession agreements. Additionally, on May 14, 2013, following
the 11th oil and gas bidding round pursuant to the Brazilian Petroleum Law,
must pay in the event of obtaining high production volumes and/or
we were awarded seven new exploratory licenses in Brazil in the REC-T 94
profitability from oil fields, according to criteria established by applicable
and REC-T 85 Concessions in the Recôncavo Basin in the State of Bahia and
regulations, and is payable on a quarterly basis for each field from the
the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 Concessions
date on which extraordinary production occurs. This participation fee,
in the Potiguar Basin in the State of Rio Grande do Norte. We have entered
whenever due, varies between 0% and 40% of net revenues depending
into seven concession agreements, which we collectively refer to as the
on (1) the volume of production and (2) whether the concession is
Round 11 Concession Agreements, with the ANP on September 17, 2013,
onshore or in shallow water or deep water. Under the Brazilian Petroleum
for the right to exploit the oil and natural gas in these seven new license
Law and applicable regulations issued by the ANP, the special participation
areas. We have paid to the ANP a license fee in the amount of R$10.2 million
fee is calculated based on the quarterly net revenues of each field, which
(approximately US$4.2 million, at the January 31, 2014 exchange rate of
consist of gross revenues calculated using reference prices established by
R$2.4263 to US$1.00), consisting of R$7.2 million (approximately US$3.0
the ANP (reflecting international prices and the exchange rate for the
million, at the January 31, 2014 exchange rate of R$2.4263 to US$1.00) for
period) less:
• royalties paid;
• investment in exploration;
• operational costs; and
the REC-T 94 and REC-T 85 Concessions and R$3.0 million (approximately
US$1.2 million, at the January 31, 2014 exchange rate of R$2.4263 to
US$1.00) for the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663
Concessions, and provide to the ANP financial guarantees in the amount
• depreciation adjustments and applicable taxes.
of R$20.4 million (approximately US$8.4 million, at the January 31, 2014
exchange rate of R$2.4263 to US$1.00), consisting of R$12.1 million
The Brazilian Petroleum Law also requires that the concessionaire of
onshore fields pay to the landowners a special participation fee that varies
(approximately US$5.0 million, at the January 31, 2014 exchange rate of
R$2.4263 to US$1.00) for the REC-T 94 and REC-T 85 Concessions and R$8.3
between 0.5% to 1.0% of the net operational income originated by the
million (approximately US$3.4 million, at the January 31, 2014 exchange
field production.
BCAM-40 Concession Agreement. On August 6, 1998, the ANP and Petrobras
executed the concession agreement governing the BCAM-40 Concession,
or the BCAM- 40 Concession Agreement, following the first round of
rate of R$2.4263 to US$1.00) for the POT-T 664, POT-T 665, POT-T 619, POT-T
620 and POT-T 663 Concessions, to secure our obligations under the
Minimum Exploratory Programs, or PEMs, for the first exploratory period of
the concessions.
bidding, referred to as Bid Round Zero, under the regime established by
Under the Round 11 Concession Agreements, the ANP is entitled to a
the Brazilian Petroleum Law. The exploration phase will end in November
monthly royalty corresponding to 10% of the production of oil and natural
2029. On September 11, 2009, Petrobras announced the termination of
gas in the concession area, in addition to the special participation fee
BCAM-40 Concession’s exploration phase and the return of the exploratory
described above, the payment for the occupation of the concession area of
area of the concession to the ANP, except for the Manatí Field and the
approximately R$7,600 (approximately US$3,358, at the March 31, 2014
Camarão Norte Field.
exchange rate of R$2.263 to US$1.00) per year and the payment to the
owners of the land of the concession equivalent to one percent of the oil
and natural gas produced in the concession area.
GeoPark 20F
99
Round 12 concession agreements
On November 28, 2013, following the 12th oil and gas bidding round
An important characteristic of the consortia for exploration and production
of oil and natural gas that differs from other consortia (Article 278, paragraph
pursuant to the Brazilian Petroleum Law, we were awarded two new
1, of the Brazilian Corporate Law) is the joint liability among consortium
exploratory licenses in Brazil, the PN-T-597 Concession on the Parnaiba Basin
members as established in the Brazilian Petroleum Law (Article 38, item II).
in the State of Maranhão and the SEAL-T-268 Concession in the Sergipe-
Alagoas Basin in the State of Alagoas.
BCAM-40 Consortium Agreement. On January 14, 2000, the consortium
formed by Petrobras, QG Perfurações and Petroserv entered into a
Our offer requires a commitment to the ANP of R$9.3 million (approximately
consortium agreement, or the BCAM-40 Consortium Agreement, for the
US$4.0 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00)
performance of the BCAM-40 Concession Agreement. Petrobras is the
composed of R$1.6 million (approximately US$0.7 million, at the March 31,
operator of the BCAM-40 concession, with a 35% participation interest.
2014 exchange rate of R$2.263 to US$1.00) for the first exploratory period on
QGEP, Brasoil and Rio das Contas have a 45%, 10% and 10% participation
the Concession SEAL-T- 268 and R$7.7 million (approximately US$3.4 million,
interest, respectively. The BCAM-40 Consortium Agreement has a specified
at the March 31, 2014 exchange rate of R$2.263 to US$1.00) for the first
term of 40 years, terminating on January 14, 2040 and, at the time the
exploratory period on the PN-T-597.
obligations undertaken in the agreement are fully completed, the parties
will have the right to terminate it. The BCAM-40 Concession consortium has
Part of our bid for the Round 12 concessions was comprised of work
also entered into a joint operating agreement, which sets out the rights
program guarantees, or commitments to invest certain sums in the blocks as
and obligations of the parties in respect of the operations in the concession.
part our exploration activities. Our SEAL-T-268 commitment is composed
of R$0.14 million (approximately US$0.07 million, at the March 31, 2014
exchange rate of R$2.263 to US$1.00) bonus payable to the ANP and R$1.5
Petrobras Natural Gas Purchase Agreement
QGEP, Rio das Contas, Brasoil and Petrobras are party to a natural gas
million (approximately US$0.7 million, at the March 31, 2014 exchange rate
purchase agreement providing for the sale of natural gas by QGEP, Rio das
of R$2.263 to US$1.00) as part of the work program guarantee payable over
Contas and Brasoil to Petrobras, in an amount of 812 bcf over the term of
the course of the three years. Work program is equivalent to 40 km of 2D
agreement. The Petrobras Natural Gas Purchase Agreement is valid until the
seismic, with no well drilling committed during the first exploratory period.
earlier of Petrobras’s receipt of this total contractual quantity or June 30,
2030. The agreement may not be fully or partially assigned except upon
Our PN-T-597 commitment is composed of R$0.9 million (approximately US$0.4
execution of an assignment agreement with the written consent of the other
million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) bonus
parties, which consent may not be unreasonably withheld provided that
payable to the ANP in the first year of exploration and R$6.7 million
certain prerequisites have been met.
(approximately US$3.0 million, at the March 31, 2014 exchange rate of R$2.263
to US$1.00) as a work program guarantee. See “Item 3. Key information—D. Risk
The agreement provides for the provision of “daily contractual quantities”
factors—Risks relating to our business—The PN-T-597 concession is subject to
to Petrobras, in the following amounts: from the first year through the
an injunction and may not close.” for more information.
end of the fourth year under the contract, 211.9 mmcfpd; from the beginning
of the fifth year through the end of the ninth year, 141.3 mmcfpd; and
Overview of consortium agreements
A consortium agreement is a standard document describing consortium
from the beginning of the tenth year through the end of the contract,
141.3 mmcfpd or such smaller quantity as stipulated by the parties, to take
members’ respective percentages of participation and appointment of
into account the Manatí Field’s depletion. Pursuant to the agreement,
the operator. It generally provides for joint execution of oil and natural gas
the base price is denominated in reais and is adjusted annually for inflation
exploration, development and production activities in each of the
pursuant to the general index of market prices (IGPM). Additionally, the
concession areas. These agreements set forth the allocation of expenses
gas price applicable on a given day is subject to reduction as a result of the
for each of the parties with respect to their respective participation interests
gas quantity acquired by Petrobras above the volume of the annual TOP
in the concession. The agreements are supplemented by joint operating
commitment (85% of the daily contracted quantity) in effect on such day.
agreements, which are private instruments that typically regulate the
aggregation of funds, the sharing of costs, mitigation of operational risks,
The Petrobras Natural Gas Purchase Agreement provides that if the Manatí
preemptive rights and the operator’s activities.
Field’s daily production capacity is less than the amount of the applicable
daily contractual quantity, gas sales shall be made exclusively to Petrobras,
with any sales to third parties subject to a penalty. If the field’s production is
100 GeoPark 20F
above the applicable daily contractual quantity, the agreement provides
for 35 years. The term of each of these concessions is 25 years, with an
that Petrobras must first be offered to purchase the excess amount of gas.
optional extension of up to 10 years. There is no minimum work or investment
commitment under any of the concessions other than the general
Petrobras Natural Gas Condensate Purchase Agreement
On January 1, 2014, Rio das Contas and Petrobras entered into an agreement,
requirement to make needed investments to develop the entire acreage
of the concession, though the Argentine Secretary of Energy takes into
the Petrobras Natural Gas Condensate Purchase Agreement, valid until
account all work and investment undertaken when determining whether
December 31, 2015 for the sale to Petrobras of Rio das Contas’s share of the
to grant an extension of the concession term. Work and investment
total volume of natural gas condensate to be produced in the Manatí Field.
programs for the concessions are required to be presented annually to the
The agreement can be renewed and takes into consideration market factors
incumbent Provincial State enforcement authority, the Argentine Secretary
that affect the production and sale of gas.
of Energy and the Strategic Planning and Coordination Committee for
the National Hydrocarbon Investment Plan.
Pursuant to the agreement, for each liquid barrel of condensed natural gas
sold by Rio das Contas, Petrobras will pay the monthly arithmetic average
Under the terms of our concession agreements, we are entitled to 100% of
of the averages of the daily prices for the “BRENT DTD” barrel, as published
production, with no governmental participation. We are also required, under
by Platt’s Crude Oil Marketwire, subject to a discount of $2.87 per barrel.
Argentine law, to pay royalties to certain Argentine provinces, at a rate
of 12% on both oil and gas sales. In addition to this 12% royalty, we are also
Any assignment of a party’s interest under the agreement requires the other
required to pay additional royalties ranging from 2.5% to 8%, pursuant to
party’s prior written consent.
Argentina
Overview of exploitation concessions
As the concession holder of three concessions in Argentina—the Del
private royalty agreements we have entered into. We also pay annual surface
rental fees established under hydrocarbons law 17.319 and Resolution
588/98 of the Argentine Secretary of Energy and Decree 1454/2007, and
certain landowner fees.
Mosquito Concession, the Cerro Doña Juana Concession and the Loma
Our Argentine concession agreements have no change of control provisions,
Cortaderal Concession— we are subject to numerous restrictions and fees
though any assignment of these concessions is subject to the prior
related to hydrocarbon production and foreign markets. For example,
authorization by the executive branch of the incumbent Provincial State.
the domestic oil and gas market in Argentina has supply privileges favoring
For the four years prior to the expiration of each of these concessions,
the domestic market, to the detriment of the export market, including
the concession holder must provide technical and commercial justifications
hydrocarbon export restrictions, domestic price controls, export duties and
for leaving any inactive and non-producing wells unplugged. Each of these
domestic market supply obligations. We are also subject to certain foreign
concessions can be terminated for default in payment obligations and/or
currency retention restrictions. We must comply with central bank
breach of material statutory or regulatory obligations. We may also voluntarily
registration requirements, maintain a minimum one-year residency in
relinquish acreage to the Argentine authorities. For example, in November
Argentina and comply with central bank registration requirements, including
the requirement that 30% of all funds remitted to Argentina remain
2012, we voluntarily relinquished approximately 102,500 non-producing
gross acres in the Del Mosquito Block to the Argentine authorities, which
deposited in a domestic financial institution for one year without yielding
relinquishment is currently subject to approval by the authorities of the
interest unless such funds are proven invested in exploration and production
province of Santa Cruz and the completion of certain environmental audits.
or meet other limited requirements, as established under Presidential Decree
In addition, in April 2014, we informed the Secretary of Infrastructure and
616/2005. We are also subject to certain export duties under each of the
Energy of the Province of Mendoza of our decision to relinquish 100%
concessions (in particular, to a 20% duty on gas exports, as established under
of the Cerro Doña Juana and Loma Cortaderal Concessions to the Mendoza
Presidential Decree 645/2004) and an up-to-45% duty on oil exports,
Province. The area covered by the Cerro Doña Juana and Loma Cortaderal
depending on oil prices, as established under Resolution 394/2007 of the
blocks is 47.9 acres and neither the Cerro Doña Juana nor the Loma Cortaderal
Argentine Secretary of Energy.
are currently in production or have any associated reserves. Relinquishment
is subject to approval by the authorities of the province of Mendoza.
In general, our Argentina concession agreements for the Del Mosquito,
Cerro Doña Juana and Loma Cortaderal Blocks grant us the exclusive right
Our Argentine concessions are governed by the laws of Argentina and the
to produce, explore and develop hydrocarbons in these blocks, as well
resolution of any disputes must be sought in the Federal Courts, although
as the right to receive a transportation concession to build unused pipelines
provincial courts may have jurisdiction over certain matters.
or other transportation facilities beyond the boundaries of the concessions
GeoPark 20F 101
Agreements with LGI
LGI Chile Shareholders’ Agreements
In 2010, we formed a strategic partnership with LGI to jointly acquire and
Shareholders’ Agreements, we and LGI have also agreed to vote our common
shares or otherwise cause GeoPark Chile or GeoPark TdF, as the case may be,
to declare dividends only after allowing for retentions to meet anticipated
develop upstream oil and gas projects in Latin America. In 2011, LGI acquired
future investments, costs and obligations. See “Item 3. Key Information—D.
a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark
Risk factors—Risks relating to our business—LGI, our strategic partner in
TdF, for a total consideration of US$148.0 million, plus additional equity
Chile and Colombia, may sell its interest in our Chilean and Colombian
funding of US$18.0 million over the following three years. On May 20, 2011,
operations to a third party or may not consent to our taking certain actions.”
in connection with LGI’s investment in GeoPark Chile, we and LGI entered
into a shareholders’ agreement (as amended on July 4, 2011, the GeoPark
Chile Shareholders’ Agreement) and a subscription agreement (as amended
LGI Colombia Agreements
In December 2012, we and LGI agreed that we would extend our strategic
on July 4, 2011 and October 4, 2011, in connection with LGI’s investment
partnership to build a portfolio of upstream oil and gas assets throughout
in GeoPark TdF, the GeoPark TdF Subscription Agreement, and, together with
Latin America through 2015. On December 18, 2012, LGI agreed to acquire a
the GeoPark Chile Shareholders’ Agreement, the LGI Chile Shareholders’
20% equity interest in GeoPark Colombia for a total consideration of
Agreements), setting forth our and LGI’s respective rights and obligations in
US$20.1 million composed of a US$14.9 million capital contribution, a US$4.9
connection with LGI’s investment in our Chilean oil and gas business.
million loan to GeoPark Colombia and miscellaneous reimbursements.
Concurrently, we and LGI entered into a shareholders’ agreement, the LGI
The respective boards of each of GeoPark Chile and GeoPark TdF supervise
Colombia Shareholders’ Agreement, setting forth our and LGI’s respective
their day-to-day operations. Each of these boards has four directors. As long
obligations in connection with LGI’s investment in our Colombian oil
as LGI holds at least 5% of the voting shares of GeoPark Chile, LGI has the
and gas business, and LGI and Winchester (now GeoPark S.A.S.) entered into
right to elect one director and such director’s alternate, and the remaining
a loan agreement, whereby, upon the closing of LGI’s subscription of shares
directors, and alternates, are elected by us. As long as LGI holds at least
in GeoPark Colombia, LGI granted a credit line (of which US$4.9 million
5% of the voting shares of GeoPark TdF, LGI has the right to elect one director
was drawn at closing) to Winchester (now GeoPark S.A.S.) of up to US$12.0
and such director’s alternate, and the remaining directors, and alternates,
million, to be used for the acquisition, development and operation of oil and
are elected by GeoPark Chile.
gas assets in Colombia. Further, on January 8, 2014, following an internal
corporate reorganization of our Colombian operations, GeoPark Colombia
The LGI Chile Shareholders’ Agreements require the consent of LGI or
Coöperatie U.A. and GeoPark Latin America entered into a new members’
the LGI appointed director in order for GeoPark Chile and GeoPark TdF, as
agreement with LGI, or the LGI Colombia Members’ Agreement, that sets out
the case may be, to take certain actions, including, among others:
substantially similar rights and obligations to the LGI Colombia Shareholders’
• making any decision to terminate or permanently or indefinitely suspend
Agreement in respect of our oil and gas business in Colombia. We refer to
operations in or surrender our blocks in Chile (other than as required under
the LGI Colombia Shareholders’ Agreement and the LGI Colombia Members’
the terms of the relevant CEOP for such blocks);
Agreement collectively as the LGI Colombia Agreements.
• selling our blocks in Chile to our affiliates;
• any change to the dividend, voting or other rights that would give
GeoPark Colombia’s board supervises its day-to-day operations. GeoPark
preference to or discriminate against the shareholders of GeoPark Chile
Colombia has four directors. As long as LGI holds at least 14% of the voting
and GeoPark TdF;
shares of GeoPark Colombia, LGI has the right to elect one director and
• entering into certain related party transactions; and
such director’s alternate, and the remaining directors and alternates are
• creating a security interest over our blocks in Chile (other than in
elected by us.
connection with a financing that benefits our Chilean subsidiaries).
The LGI Chile Shareholders’ Agreements provide that if LGI or either Agencia
existing debt of GeoPark Colombia and to provide additional funding to
or GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark
cover LGI’s share of required future investments in Colombia. In addition, we
TdF, as the case may be, the transferring shareholder must make an offer to
can earn back up to 12% additional equity interests in GeoPark Colombia
sell those shares to the other shareholder before selling those shares to a
depending on the success of our Colombian operations.
Under the LGI Colombia Agreements, LGI agreed to assume its share of the
third party. In addition, any sale to a third party is subject to tag-along
and drag-along rights, and the non-transferring shareholder has the right to
The LGI Colombia Agreements require the consent of LGI or the LGI-
object to a sale to the third-party if it considers such thirdparty to be not
appointed director for GeoPark Colombia to take certain actions, including,
of a good reputation or one of our direct competitors. Under the LGI Chile
among others:
102 GeoPark 20F
• making any decision to terminate or permanently or indefinitely suspend
the Republic of Colombia grants such rights through E&P Contracts or
operations in or surrender our blocks in Colombia (other than as required
contracts of association. In Argentina, the Argentine Republic grants such
under the terms of the relevant concessions for such blocks);
rights through exploitation concessions. In Brazil, the Federative Republic of
• creating of a security interest over our blocks in Colombia;
Brazil grants such rights pursuant to concession agreements. See “Item 3.
• approving of GeoPark Colombia’s annual budget and work programs and
Key Information—D. Risk factors—Risks relating to the countries in which
the mechanisms for funding any such budget or program;
we operate—Oil and natural gas companies in Chile, Colombia, Brazil
• entering into of any borrowings other than those provided in an approved
and Argentina do not own any of the oil and natural gas reserves in such
budget or incurred in the ordinary course of business to finance working
countries.” Other than as specified in this annual report, we believe that we
capital needs;
have satisfactory rights to exploit or benefit economically from the oil and
• granting any guarantee or indemnity to secure liabilities of parties other
gas reserves in the blocks in which we have an interest in accordance
than those of our Colombian subsidiaries;
with standards generally accepted in the international oil and gas industry.
• changing the dividend, voting or other rights that would give preference to
Our CEOPs, E&P Contracts, contracts of association, exploitation concessions
or discriminate against the shareholders of GeoPark Colombia;
and concession agreements are subject to customary royalty and other
• entering into certain related party transactions; and
interests, liens under operating agreements and other burdens, restrictions
• disposing of any material assets other than those provided for in an
and encumbrances customary in the oil and gas industry that we believe
approved budget and work program.
do not materially interfere with the use of or affect the carrying value of our
interests. See “Item 3. Key Information—D. Risk factors—Risks relating
We have also agreed to ensure that the board of directors and rules and
to our business—We are not, and may not be in the future, the sole owner
management of our other subsidiaries engaged in our Colombian oil and gas
or operator of all of our licensed areas and do not, and may not in the future,
business are subject to the same principles and restrictions outlined above.
hold all of the working interests in certain of our licensed areas. Therefore,
we may not be able to control the timing of exploration or development
The LGI Colombia Agreements provide that if either we or LGI decide to sell
efforts, associated costs, or the rate of production of any non-operated and,
our respective shares in GeoPark Colombia, the transferring shareholder must
to an extent, any non-wholly-owned, assets.”
make an offer to sell those shares to the other shareholder before selling
those shares to a third party. In addition, any sale to a third party is subject to
tag-along and drag-along rights, and the non-transferring shareholder has
Our customers
In Chile, our primary customers are ENAP and Methanex. As of December
the right to object to a sale to the third-party if it considers such third-party
31, 2013, ENAP purchased all of our oil and condensate production
to be not of a good reputation or one of our direct competitors.
and Methanex purchased 99% of our natural gas production in Chile, and
represented 39.8% and 6.7%, respectively, of our total revenues for the
Under the LGI Colombia Agreements, we and LGI have agreed to vote our
year ended December 31, 2013. Our contract with ENAP is automatically
common shares or otherwise cause GeoPark Colombia to declare dividends
renewed for six-month terms, with oil pricing based on international
only after allowing for retentions for approved work programs and budgets
and capital adequacy requirements of GeoPark Colombia, working capital
market prices. Our contract with Methanex is a long-term contract subject
to take-or-pay and deliver-or-pay provisions, with the price of natural
requirements, banking covenants associated with any loan entered into
gas based on the international market prices for methanol. In Colombia,
by GeoPark Colombia or our other Colombian subsidiaries and operational
our primary customers are Gunvor, Hocol, Perenco and Trenaco, who
requirements. See “Item 3. Key Information— D. Risk factors—Risks relating
purchase our production through short-term contracts, and who represented
to our business—LGI, our strategic partner in Chile and Colombia, may
27.8%, 11.1%, 5.2% and 3.9%, respectively, of our total revenues for the
sell its interest in our Chilean and Colombian operations to a third party or
year ended December 31, 2013. In Argentina, our primary customer is
may not consent to our taking certain actions.”
Oil Combustibles, representing 0.5% of our total revenues for the year ended
Title to properties
In each of the countries in which we operate, the state is the exclusive owner
December 31, 2013. Having closed our Brazil acquisitions on March 31, 2014,
we expect our primary customer in Brazil to be Petrobras.
of all hydrocarbon resources located in such country and has full authority
to determine the rights, royalties or compensation to be paid by private
Seasonality
Although there is some historical seasonality to the prices that we receive
investors for the exploration or production of any hydrocarbon reserves.
for our production, the impact of such seasonality has not been material.
In Chile, the Republic of Chile grants such rights through a CEOP. In Colombia,
Additionally, seasonality does not play a significant role in our ability to
GeoPark 20F 103
conduct our operations, including drilling and completion activities. Although
Health, safety and environmental matters
in winter months, it is more difficult or even impossible to conduct certain
of our operations, such as seismic work, we take such seasonality into account
in planning for and conducting our operations, such that the impact on our
General
We and our operations are subject to various stringent and complex
overall business is not material.
Our competition
The oil and gas industry is competitive, and we may encounter strong
international, federal, state and local environmental, health and safety laws
and regulations in the countries in which we operate governing matters
including the emission and discharge of pollutants into the ground, air or
water; the generation, storage, handling, use and transportation of regulated
competition from other independent operators and from major oil companies
materials; and human health and safety. These laws and regulations may,
in acquiring and developing licenses. In Chile, we partner with and sell
among other things:
to, and may from time to time compete with, ENAP and, to a lesser extent,
• require the acquisition of various permits or other authorizations or the
some companies with operations in Argentina mentioned below. In
preparation of environmental assessments, studies or plans (such as well
Colombia, we partner with and sell to, and may from time to time compete
closure plans) before seismic or drilling activity commences;
with, Ecopetrol, as well as with privately-owned companies such as Pacific
• enjoin some or all of the operations of facilities deemed not in compliance
Rubiales, Gran Tierra, Petrominerales, Parex and Canacol, among others.
with permits;
In Brazil, we partner with and sell to, and may from time to time compete
• restrict the types, quantities and concentration of various substances that
with, Petrobras, privately-owned companies such as HRT, QGEP, Brasoil and
can be released into the environment in connection with oil and natural gas
some of the Colombian companies mentioned above, which have entered
drilling, production and transportation activities;
into Brazil, among others. In Argentina, we compete for resources with YPF,
• require establishing and maintaining bonds, reserves or other commitments
as well as with privately-owned companies such as Pan American Energy,
to plug and abandon wells;
Pluspetrol, Tecpetrol, Chevron, Wintershall, Total, Sinopec and others.
• limit or prohibit seismic and drilling activities in certain locations lying
within or near protected or otherwise sensitive areas; and
Many of these competitors have financial and technical resources and
• require remedial measures to mitigate or remediate pollution from our
personnel substantially larger than ours. As a result, our competitors may
operations, which, if not undertaken, could subject us to substantial penalties.
be able to pay more for desirable oil and natural gas assets, or to evaluate,
bid for and purchase a greater number of licenses than our financial or
These laws and regulations may also restrict the rate of oil and natural gas
personnel resources will permit. Furthermore, these companies may also be
production below the rate that would otherwise be possible. Compliance
better able to withstand the financial pressures of unsuccessful wells,
with these laws can be costly. The regulatory burden on the oil and gas
sustained periods of volatility in financial and commodities markets and
industry increases the cost of doing business in the industry and
generally adverse global and industry-wide economic conditions, and may
consequently affects profitability.
be better able to absorb the burdens resulting from changes in relevant
laws and regulations, which may adversely affect our competitive position.
See “Item 3. Key Information—D. Risk factors—Risks relating to our
Moreover, public interest in the protection of the environment continues
to increase. Drilling in some areas has been opposed by certain community
business—Competition in the oil and natural gas industry is intense, which
and environmental groups and, in other areas, has been restricted. Our
makes it difficult for us to acquire properties and prospects, market oil
operations could be adversely affected to the extent laws are enacted
and natural gas and secure trained personnel.”
or other governmental action is taken that prohibits or restricts seismic or
drilling activities or imposes environmental requirements that result in
We are also affected by competition for drilling rigs and the availability of
increased costs to the oil and gas industry in general, such as more stringent
related equipment. Higher commodity prices generally increase the demand
or costly waste handling, disposal or cleanup requirements.
for drilling rigs, supplies, services, equipment and crews, and can lead to
shortages of, and increasing costs for, drilling equipment, services and
personnel. Over the past several years, oil and natural gas companies have
Climate change
Our operations and the combustion of oil and natural gas-based products
experienced higher drilling and operating costs. Shortages of, or increasing
results in the emission of greenhouse gases, which may contribute to global
costs for, experienced drilling crews and equipment and services could
climate change. Climate change regulation has gained momentum in recent
restrict our ability to drill wells and conduct our operations.
years internationally and at the federal, regional, state and local levels.
On the international level, various nations have committed to reducing their
greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto
104 GeoPark 20F
Protocol was set to expire in 2012. In late 2011, an international climate
life, wildlife protected areas, water quality standards, air emissions and
change conference in Durban, South Africa resulted in, among other things,
soil pollution. In addition, violations of these environmental regulations
an agreement to negotiate a new climate change regime by 2015 that
may lead to fines, the closure of facilities and the revocation of environmental
would aim to cover all major greenhouse gas emitters worldwide, including
approvals. The General Environmental Law and its regulations entitle the
the U.S., and take effect by 2020. In November and December 2012, at an
Chilean government, through the Superintendency of the Environment,
international meeting held in Doha, Qatar, the Kyoto Protocol was extended
to: (1) bring administrative and judicial proceedings against companies that
by amendment until 2020. In addition, the Durban agreement to develop the
violate environmental laws; (2) close non-complying facilities; (3) revoke
protocol’s successor by 2015 and implement it by 2020 was reinforced.
required operating licenses; and (iv) impose sanctions and fines when
companies act negligently, recklessly or deliberately in connection with
Other regulation of the oil and gas industry
environmental matters.
Chile
Companies in the oil and gas sector, like all Chilean companies, must comply
with the general principles concerning employee health and safety laws that
The sanction procedures and environmental liability claims derived from
environmental damage will be handled by the Chilean environmental court.
are contained in the Chilean Labor Code and other labor statutes. The Chilean
For additional information on environmental, health and safety regulations
Ministry of Labor is responsible for the enforcement of those standards, with
applicable to the Chilean oil and gas sector, see “—Industry and regulatory
the authority to impose fines. In addition, the Health Department of the
framework—Chile—Regulatory entities.”
Ministry of Health has the responsibility to monitor compliance and also the
authority to impose fines and stop operations of health and safety violators.
Colombia
Health, safety and environmental regulation of the oil and gas industry in
Regarding environmental matters, the Chilean Constitution grants all
Colombia is dispersed throughout a number of different laws and
citizens the right to live in a pollution-free environment. It further provides
regulations. Environmental regulation is primarily governed by Law 99 of
that other constitutional rights may be limited in order to protect the
1993, which established the Ministry of Environment and provided for
environment. Chile has numerous laws, regulations, decrees and municipal
the issuance of a number of associated laws and regulations. The Ministry
ordinances relating to environmental protection, pursuant to which specific
of Environment through the ANLA monitors compliance with environmental
approvals, consents and permits may be required in order to perform
obligations. Furthermore, licenses for exploration and exploitation of
activities that may affect the environment.
hydrocarbons are granted by the ANLA and this is the entity in charge of
monitoring the permits. Regional corporations who are responsible for
The General Environmental Law (Law No. 19,300), enacted in March 1994
monitoring environmental compliance within their regions have
and modified in 2010 by Law No. 20,417, establishes a framework for
additional obligations.
environmental regulation in Chile, which has become increasingly stringent
in recent years. Recent amendments include, among others, the creation
of a new institutional framework composed of: (1) the Ministry of
Law 99 introduced the requirement of environmental permits for activities,
including oil and gas exploration and production, which can cause serious
Environment (Ministerio del Medio Ambiente); (2) the Council of Ministers
deterioration of renewable natural resources or damage to the environment,
for Sustainability (Consejo de Ministros para la Sustentabilidad); (3) the
or that introduce substantial changes to the landscape. Decree 2820 of
Environmental Assessment Service (Servicio de Evaluación Ambiental); and
2010 requires an environmental license for all hydrocarbon projects, including
(4) the Superintendency of the Environment (Superintendencia del Medio
for each of the following activities: conducting seismic exploration activities
Ambiente), all of which are in charge of regulating, assessing and enforcing
that require the construction of roads for vehicular traffic, exploratory drilling
activities that could have an environmental impact. Recent modifications
projects, exploitation of hydrocarbons and development of related facilities
introduced to existing regulations also gives right for public participation
(including internal pipelines and storage, roads and related infrastructure),
for interested people and non-governmental organizations in the assessment
transportation and handling of liquid and gaseous hydrocarbons, developing
of projects, which could result in additional delays for the final approval of
liquid hydrocarbon delivery terminals or transfer stations, and construction
new projects.
and operation of refineries. Other hydrocarbon activities may require
environmental permits as well. Compliance with environmental regulations
The new institutions and regulatory framework are likely to result in
is handled under a strict sanctioning regime, established by Law 1333 of
additional restrictions or costs on us relating to environmental litigation and
2009, whereby liability is presumed and fines are significant.
protection of the environment, particularly those related to plant and animal
GeoPark 20F 105
Legislation governing Health and Safety is varied, but mainly focuses on
CONAMA Resolution No. 237 sets forth the general rules that must
the Law 1562 of 2012, issued by the Colombian Congress through the System
be complied with regarding environmental licensing. It prescribes that the
of Occupational Hazards.
competent environmental authority, with the entrepreneur’s participation,
shall define the plans, projects and environmental assessments necessary
Law 1010 of 2006 established actions to prevent, correct and punish
to start the environmental licensing proceeding. In addition, IBAMA
labor bullying; Resolution 2646 of 2008 of the Ministry of Health and Social
Normative Ordinance No. 184, from July 17, 2008, defines the general rules
Protection establishes responsibilities for the identification, assessment,
of environmental licensing on the federal level. However, for oil and
prevention, intervention and ongoing monitoring of exposure to psychosocial
gas activities, these general rules do not apply and have been adjusted and
risk factors at work and for determining the origin of defined diseases caused
regulated by specific regulation, as mentioned below.
by occupational stress; among others.
For additional information on environmental, health and safety regulations
seismic activities. Ordinance No. 422, from October 26, 2011, issued by the
applicable to the Colombian oil and gas sector, see “—Industry and
Brazilian Ministry for the Environment, sets forth rules for the environmental
regulatory framework—Colombia—Regulatory entities.”
licensing of: (1) seismic activities (i.e., clarifying and creating some new
CONAMA Resolution No. 350/2004 governs environmental licensing for
steps between those mentioned above); (2) drilling; and (3) oil and gas
Brazil
In accordance with Brazilian environmental legislation, activities or ventures
production and evacuation, as well as Extended Well Tests, or EWTs. For the
environmental licensing of oil and gas production and evacuation, as well
that use natural resources or that are deemed to be actually or potentially
as EWTs, the proceeding is more complex. The steps differ depending on the
polluting are subject to environmental licensing requirements, under which
status of the enterprise and the environmental license sought: (1) planning
the relevant environmental body analyzes location, facilities, expansion and
for the installation of the enterprise, which needs a Preliminary License
operation of projects, as well as establishes conditions for project development.
(Licença Prévia), or LP; (2) implementation and installation of the project
licensed with the LP, which needs an Installation License (Licença de
Environmental licensing of E&P activities in the offshore basin (territorial sea,
Instalação) or LI; and (3) operation of the enterprise installed according with
the continental platform and exclusive economic zones) is granted on a
the LI, which needs an Operation License (Licença de Operação).
federal level. The environmental licensing in Brazil may be subject to federal,
state or municipal (local) licensing as a general rule, and in many industries
The environmental licensing of oil and natural gas exploration, development
it is usual to have projects in which more than one of those entities claim
and production activities is subject to, among several other requirements,
jurisdiction. That may be the case for onshore E&P activities (and it is in the
the preparation of environmental assessments, the complexity and rules
ports sector, for instance), but such controversy does not apply to offshore
of which vary according to the activities sought, the depth and distance from
E&P environmental licensing.
the coast and the environmental sensitivity of the area in which the
development of activities is sought. Among such studies, the Environmental
The IBAMA, by means of its General Supervision for Oil and Gas Licensing
(Coordenação Geral de Licenciamento de Petróleo e Gás), is the entity in
Impact Assessment (Estudo Prévio de Impacto Ambiental) and the respective
Environmental Impact Report (Relatório de Impacto de Ambiental) may be
charge of the environmental licensing for E&P projects.
deemed the most complex and time-demanding environmental assessment,
E&P activities are divided in two subgroups, according to the Brazilian
an Environmental Drilling Study (Estudio Ambiental de Perfuração) may also
Ministry for the Environment: (i) seismic activities; and (ii) drilling and
be required for purposes of respective environmental licensing. This is a very
production of hydrocarbons. In addition to the Complementary Law, the
comprehensive, tailor-made analysis of the environmental impacts, to be
though an Environmental Seismic Study (Estudio Ambiental de Sísmica) or
main rules governing the environmental licensing of such activities
produced by the enterprise.
are: (1) Resolution No. 237, from December 19, 1997, issued by the Brazilian
National Committee for the Environment (Conselho Nacional do Meio-
As a compensatory measure, we are also obligated to allocate funds for the
Ambiente), or CONAMA; (2) Resolution No. 350, from July 6, 2004, also issued
implementation and maintenance of conservation areas, based on Federal
by CONAMA; and (3) Ordinance No. 422, from October 26, 2011, issued by
Law No. 9,985/2000, which are evaluated by the competent environmental
the Brazilian Ministry for the Environment.
agency on the basis of Federal Decree Nos. 4,340/2002 and 6,848/2009
and which must not exceed the value of 0.5% of the total cost involved for
the construction of the facility.
106 GeoPark 20F
Failure to maintain a valid environmental license is classified as an
In the administrative sphere, Federal Decree No. 6,514/2008 provides that
administrative infraction and environmental crime. Any delays or denials
environmental authorities may also impose administrative sanctions for
by the environmental licensing authority in issuing or renewing licenses,
those who do not comply with environmental laws and regulations,
as well as the inability to meet the requirements established by the
including, among others: simple fines from R$50 to R$50 million, depending
environmental authorities during the environmental licensing process, may
on the infraction, e.g., absence of environmental licenses or failure to
harm or even prevent the construction and regular development of the
comply with its terms may subject the entrepreneur to a fine ranging from
activity. Some environmental licenses related to operation of the Manatí
R$500 to R$10 million, daily fines, partial or total suspension of activities,
Field production system and natural gas pipeline are expired. However,
demolition of the enterprise and rights restriction sanctions, such as forfeiture
the operator submitted, timely, the request for renewal of those licenses and
or restriction of tax incentives or benefits, closing of the establishments
as such this operation is not in default as long as the regulator does not
or ventures and forfeiture or suspension of participation in credit lines
state its final position on the renewal.
with official credit establishments.
Environmental nonconformities and damages may result in civil,
Due to environmental damages and noncompliance with environmental
administrative and criminal liabilities.
laws and regulations, the environmental authorities may also propose
Conduct Adjustment Agreements (Termos de Ajustamento de Conduta)
The National Environmental Policy (Federal Law No. 6,938/81) regulates civil
through which the enterprise may be obliged to fund recovery works and
liability for damages caused to the environment, such liability being of an
environmental projects.
objective nature (strict liability), i.e., irrespective of fault. Demonstration of
the cause-effect relationship between damage caused and action or inaction
For additional information on environmental, health and safety regulations
suffices to trigger the obligation to redress environmental damage. The
applicable to the Brazilian oil and gas sector, see “—Industry and regulatory
fact that the relevant entity’s operations are covered by environmental
framework—Brazil—Regulatory entities.”
licenses does not preclude such liability. The National Environmental Policy
established joint liability among polluting agents. In case of environmental
damage to an industrial area, it may be difficult to identify the source of
Argentina
Historically, environmental legislation and enforcement powers in respect
environmental damages and intensity thereof. The victim of such damages
of oil and gas operations have been vested with the federal government.
or whomever the law so authorizes, as indicated below, is not compelled
However, after the 1994 constitutional reform and after the enactment of the
to sue all polluting agents within the same proceeding. Because liability is of
YPF Privatization Law in 1992, provincial states have passed and enforced
a joint nature, the aggrieved party may choose one out of all polluting
concurrent new environmental legislation. The federal government is
agents (for example, the agent with the best economic standing) to redress
empowered to establish minimum environmental protection standards and
all damages. A polluting agent so sued will have a right of recourse against
provincial governments are empowered to complement them, though
the other polluting agents.
provincial environmental legislation is not always fully consistent with federal
environmental legislation.
Furthermore, under Brazilian law, due to environmental damages and
noncompliance with environmental laws and regulations, individuals or
The oil and natural gas industry in Argentina is subject to environmental
entities are also subject to criminal and administrative sanctions.
regulations pursuant to concurrent provincial state and federal legislation.
Such legislation provides for restrictions and prohibitions on the release
In the criminal sphere, the Environmental Crimes Act (Federal Law No.
or emission of various substances produced in association with certain oil
9,605/98) applies to every individual or legal entity that carries out any
and gas industry operations. In addition, such legislation requires that wells,
activity deemed damaging to the environment. Because criminal
facilities and sites be abandoned, reclaimed and/or remediated according
liability is of a subjective nature, the Environmental Crimes Act attributed
to specific standards and/or to the satisfaction of governmental authorities
liability to representatives of legal entities. As a result, upon occurrence
and/or surface owners. Compliance with such legislation can require
of an environmental violation, a legal entity’s officer, administrator, director,
significant expenditures and a breach of such requirements may result in
manager, agent or attorney-in-fact may also be subject to criminal penalties,
suspension or revocation of necessary licenses and authorizations, civil
which comprise fines and imprisonment. With respect to judicial actions,
and criminal liability for pollution damage and the imposition of material
a civil or administrative settlement does not prevent prosecution in a criminal
fines and penalties.
sphere should an environmental crime have occurred.
GeoPark 20F 107
Environmental regulations in Argentina also require that wells be plugged
in and that facility sites be abandoned and returned to Argentina in a
Certain Bermuda law considerations
As a Bermuda exempted company, we and our Bermuda subsidiaries are
state deemed satisfactory to the applicable regulatory authorities. Four
subject to regulation in Bermuda. We have been designated by the Bermuda
years prior to the expiration of any hydrocarbon concession granted by
Monetary Authority as a non-resident for Bermuda exchange control
the Argentine government, an operator is required to present any technical
purposes. This designation allows us to engage in transactions in currencies
or commercial reasons for seeking to leave an inactive and non-producing
other than the Bermuda dollar, and there are no restrictions on our ability
well unplugged to the applicable regulatory authorities. In addition,
to transfer funds (other than funds denominated in Bermuda dollars) in and
the province of Santa Cruz, in which the Del Mosquito block is located,
out of Bermuda.
has created a Registry of Environmental Liabilities and requires operators to
submit a five-year remediation program for all environmental liabilities
Under Bermuda law, “exempted” companies are companies formed for the
that have been registered.
purpose of conducting business outside Bermuda from a principal place of
business in Bermuda. As exempted companies, we and our Bermuda
For additional information on environmental, health and safety regulations
subsidiaries may not, without a license or consent granted by the Minister
applicable to the Argentine oil and gas sector, see “—Industry and regulatory
of Finance of Bermuda, participate in certain business transactions, including
framework—Argentina—Regulatory entities.”
transactions involving Bermuda landholding rights and the carrying on of
business of any kind for which we or our Bermuda subsidiaries are not
Our environmental policy
Our health, safety and environmental management plan is focused on
licensed in Bermuda.
undertaking realistic and practical programs based on recognized world
practices. Our emphasis is on building key principles and company-wide
Insurance
We maintain insurance coverage of types and amounts that we believe
ownership and then expanding programs from within as we continue
to be customary and reasonable for companies of our size and with similar
to grow. Our S.P.E.E.D. program has been developed in accordance with: ISO
operations in the oil and gas industry. However, as is customary in the
14001 for environmental management issues, OHSAS 18001 for occupational
industry, we do not insure fully against all risks associated with our business,
health and safety management issues, SA 8000 for social accountability
either because such insurance is not available or because premium costs
and workers’ rights issues and applicable World Bank standards.
are considered prohibitive.
Our policy is to strive to meet or exceed environmental regulations in the
Currently, our insurance program includes, among other things, construction,
countries in which we operate. We believe that oil and gas can be produced in
fire, vehicle, technical, umbrella liability, director’s and officer’s liability
an environmentally-responsible manner with proper care, understanding and
and employer’s liability coverage. Our insurance includes various limits and
management. We have within our S.P.E.E.D. program a team that is exclusively
deductibles or retentions, which must be met prior to or in conjunction
focused on securing the environmental authorizations and permits for the
with recovery. A loss not fully covered by insurance could have a materially
projects we undertake. This team is also responsible for the achievement of the
environmental standards set by our board of directors and for training and
adverse effect on our business, financial condition and results of operations.
See “Item 3. Key Information—D. Risk factors—Risks relating to our
supporting our personnel. In these activities, we are supported by experienced
business—Oil and gas operations contain a high degree of risk and we may
oil and gas environmental consulting firms. Our senior executives have also
not be fully insured against all risks we face in our business.”
received training in proper environmental management.
Our health and safety policy
We believe that the implementation of additional safety tools in our
operations in 2012 have significantly contributed to control and minimizing
risks in our operation. Actions taken by us included training, permits to
work, internal audits, drills, tailgate safety meetings, job safety analysis and
risk evaluations. As of December 31, 2013, on a rolling 12-month basis,
our Lost Time Incident Rate was 0.62, and our Total Recordable Incident Rate
was 0.95 (based on a rate of 200,000 labor hours) compared to 0.83 and
0.99, respectively, in December 2012. We had no fatalities due to workforce
incidents related to our operations in 2012 and 2013.
108 GeoPark 20F
Industry and regulatory framework
Global oil and gas industry
During 2012, the growth rate of energy consumption globally dropped
According to the BP Statistical Review, global proved natural gas reserves
at the end of 2012 remained stable at 187.3 trillion cubic meters, enough to
meet 55.7 years of 2012’s global production. South and Central America
currently hold 4.1% of global proved natural gas reserves. During 2012, global
following (1) the global economic slowdown and (2) a more efficient use of
natural gas production averaged 3363.9 billion cubic meters, an increase of
energy as a response to the high price environment of recent years.
1.9% over 2011.
Global oil consumption in 2012 grew by 895,000 bopd, or 0.9%, compared to
2011, to reach 89,774,000 bopd. On the other hand, global oil production in
Distribution of proved natural gas reserves in 1992, 2002 and 2012
Percentage
2012 increased by 1.9 mmbopd, or 2.2%, to reach 86.2 mmbopd. Global
natural gas consumption in 2012 grew by 7.1 bcfpd, or 2.3%, to reach 319.8
bcfpd, while global natural gas production in 2012 grew by 6.2 bcfpd, or 1.9%,
to reach 324.6 bcfpd, with the United States recording the largest volumetric
increases in natural gas consumption and production. In 2012, the United
States posted the largest oil and natural gas production gains worldwide, and
saw the largest increase in oil production in its history. Elsewhere, for a second
year, disruptions to oil supply in Africa and parts of the Middle East were
offset by growth among OPEC producers according to the BP Statistical
Review of World Energy June 2013, or the BP Statistical Review.
Middle East
Europe & Eurasia
S. & Cent. America
Africa
North America
Asia Pacific
3.6
5.9
63.7
8.3
17.3
7.5
11.7
7.6
7.8
2.5
48.4
3.1
7.7
56.1
8.4
13.2
7.6
19.7
1992 - Total 1039.3
thousand million barrels
2002 - Total 1321.5
thousand million barrels
2012 - Total 1668.5
thousand million barrels
World proved oil reserves at the end of 2012 reached 1,668.9 billion barrels
(up 0.9% in relation to 2011), enough to meet 52.9 years of 2012’s global
Source: BP Statistical Review
production, according to the BP Statistical Review. In 2012, South and Central
America contributed 19.7% of global proved oil reserves, with Venezuelan
The industry’s outlook is gradually shifting, driven mainly by supply patterns.
reserves as reported by BP Statistical Review being the main source of
According to BP’s Energy Outlook 2030, global energy demand is
production (totaling 297.6 bbopd). Global oil production averaged 86.2
expected to grow by 36% between 2011 and 2030 as a result of increasing
mmbopd (an increase of 2.2% over 2011). Throughout the last twenty years,
consumption by emerging economies (with China and India becoming
the overall contribution of South and Central America to global proved oil
increasingly more import-dependent). On the supply side, unconventional
reserves has increased dramatically as a result of the emergence of markets
oil and gas resources are expected to play a major role in balancing
like Brazil and Ecuador coupled with the dramatic increase of reserves in
global demand, with the United States leading this process. BP projects that
Venezuela (by 370% during the same period).
between 2011 and 2030, the United States will become self-sufficient in
Distribution of proved oil reserves in 1992, 2002 and 2012
Percentage
Middle East
Europe & Eurasia
S. & Cent. America
Africa
North America
Asia Pacific
3.6
5.9
63.7
8.3
17.3
7.5
11.7
7.6
7.8
2.5
48.4
3.1
7.7
56.1
8.4
13.2
7.6
19.7
1992 - Total 1039.3
thousand million barrels
2002 - Total 1321.5
thousand million barrels
2012 - Total 1668.5
thousand million barrels
Source: BP Statistical Review
energy, while key emerging markets, namely China and India, will become
increasingly importdependent.
Chile
Chile is recognized as the most developed and stable economy in South
America. The country’s economy has grown consistently during the last
two decades, a trend which is expected to continue in the near future. With
over 50 free trade agreements, Chile is an open-market economy, and in
2010, became the first South American country to join the Organisation for
Economic Co-operation and Development, or the OECD. The country’s fiscal
policy follows a countercyclical spending rule and the Chilean Central Bank
aims to ensure price stability by targeting yearly inflation of around 3%.
Chile has been successful in attracting foreign direct investment, and in 2011,
achieved the second-highest foreign investment inflows in South America.
Chile holds investment-grade sovereign debt ratings from all major ratings
agencies, S&P, Fitch and Moody’s (AA-, A+, and Aa3, respectively).
GeoPark 20F 109
Oil and gas industry
Demand and consumption
According to ENAP, national consumption of refined oil products reached
18.4 mmcf in Chile during 2012, a 0.4% increase compared to 2011 and
equivalent to 316,200 barrels per day. This increase was mainly due to strong
In 2012, the bulk of gas demand (41%) came from the power generation
sector. Industry and the petrochemical sector accounted for 24% each, and
the residential/commercial sector for the remaining 11%.
Supply and production
Chile is a large net importer of both crude oil and oil products.
and stable economic growth, offset by an increase in prices of the main
Its hydrocarbon reserves, which comprise limited crude oil reserves and
products. As is the case in many OECD countries, oil is predominantly used as
1,447.9 bcf of natural gas reserves according to the OPEC Annual Statistical
a transport fuel, but a notable difference in Chile is that diesel is used as a
Bulletin 2013, or the OPEC Bulletin, are concentrated in the Magallanes
substitute for natural gas in power generation.
Basin at the southern tip of the country.
Diesel is the main product in terms of consumption in Chile (157,300
Due to its limited oil and natural gas reserves, Chile has in the past imported
barrels per day), followed by gasoline (66,300 barrels per day) and liquid
almost all of its crude oil requirements principally from Brazil, Argentina
petroleum gas, or LPG (36,200 barrels per day). Among the different
and Colombia, and most of its natural gas requirements principally
types of refined oil products, gasoline experienced the greatest increase in
from Trinidad and Tobago, Argentina, Guinea and Yemen. In the northern
terms of consumption, with consumption increasing 5.2% compared to 2011.
part of the country, natural gas is imported through the Mejillones
liquid natural gas, or LNG, terminal and is used predominantly for electricity
% change
generation by the mining industry. In the central part of the country
from prior
(including the capital, Santiago), gas is primarily supplied by the Quintero
Consumption in Chile
by type of oil product
(thousands of cubic meters)
Diesel
Gasoline
LPG
Fuel Oil
Kerosene
Others
Total
2012
9,153
3,856
2,109
1,498
1,243
542
2011
8,936
3,667
2,090
1,864
1,192
586
18,401
18,335
year
2.4%
5.2%
0.9%
(19.6%)
4.3%
(7.5%)
0.4%
Source: ENAP 2012 Annual Report
Natural gas consumption grew significantly from the late 1990s to 2004, as
direct pipeline connections were built to Argentina, providing a cheap and
easily accessible supply. In 2002, however, the Argentine government
capped the price of gas in its domestic market, resulting in increased demand
for natural gas in Argentina. This led the Argentine government in 2004 to
restrict natural gas exports to Chile in order to reserve them for domestic use.
See “Item 3. Key Information—D. Risk factors—Risks relating to the countries
in which we operate—Governmental actions in the countries in which we
operate and in which we may operate in the future may adversely affect
our business, financial condition and results of operations.” The restriction
of Argentine natural gas exports has caused gas consumption in Chile to
decrease significantly since 2004, when natural gas accounted for some 24%
of the Total Primary Energy Supply, or TPES, according to the International
Energy Agency. By 2009, natural gas only accounted for 8% of TPES.
LNG terminal.
Oil and Gas Infrastructure in Chile
OIL
Oil Products pipeline
Crude Oil pipeline
Refinery
GAS
Existing pipelines
Gas Fields
Existing LNG
import terminal
Regasification plants
PERU
Arica
BOLIVIA
BOLIVIA
PERU
Arica
Tocopilla
Mejillones
Antofagasta
Taltal
Quintero
Con Con
Santiago
Quintero
Santiago
Bio Bio
Concepción
AR GENTINA
Concepción
AR GENTINA
CHILE
Gregorio
Punta Arenas
Pemuco
CHILE
Punta Arenas
LPG has been consumed in place of natural gas. As such, the LPG and gas
but imported 174.8 mbopd of crude oil and 134.8 bcf of natural gas,
In 2012, Chile produced 6.1 mbopd of crude oil and 40.2 bcf of natural gas
markets overlap in Chile. LPG is predominantly used as a residential fuel in
according to the OPEC Bulletin.
Chile (notably for cooking), particularly in relatively remote regions.
110 GeoPark 20F
The exploration and development of oil fields in Chile has historically been
by law, its Minister is the chairman of the board of directors of ENAP.
controlled mainly by ENAP, with few private companies working in this
The Ministry of Energy is also responsible for the protection, conservation
sector. We were the first private producer of oil and gas in Chile.
and development of renewable and non-renewable energy resources.
Regulation of the oil and gas industry
Under the Chilean Constitution, the state is the exclusive owner of all mineral
SDEC
The SDEC is responsible for monitoring compliance with all regulations
and fossil substances, including hydrocarbons, regardless of who owns the
related to the generation, production, storage, transportation and distribution
land on which the reserves are located. The exploration and exploitation
of all fuels, gas and electricity for the consumer market.
of hydrocarbons may be carried out by the state, companies owned by the
To enforce such regulations, the SDEC has the power to impose fines and,
state or private persons through administrative concessions granted by
if necessary, to take over the administration of deficient services when
the President of Chile by Supreme Decree or CEOPs executed by the Minister
applicable. Our operations are not under the supervision of the SDEC.
of Energy. Exploitation rights granted to private companies are subject
to special taxes and/or royalty payments. The hydrocarbon exploration and
Ministry of Environment, Environmental Assessment Service and Superintendency
exploitation industry is supervised by the Chilean Ministry of Energy.
of Environment
The Ministry of Environment, the Environmental Assessment Service and
In Chile, a participant is granted rights to explore and exploit certain assets
the Superintendency of Environment are primarily responsible for
under a CEOP. If a participant breaches certain obligations under a CEOP, the
environmental issues in Chile, including those affecting the oil and gas
participant may lose the right to exploit certain areas or may be required
industry. The Ministry of Environment is responsible for the formulation
to return all or a portion of the awarded areas to Chile with no right of
and implementation of environmental policies, plans and programs, as well
compensation. Although the government of Chile cannot unilaterally modify
as for the protection and conservation of biological diversity and renewable
the rights granted in the CEOP once it is signed, exploration and exploitation
natural resources and water resources and for promoting sustainable
are nonetheless subject to significant government regulations, such as
development and the integrity of environmental policy and regulations.
regulations concerning the environment, tort liability, health and safety and
The Environmental Assessment Service is responsible for assessing whether
labor. In the past year, for example, the Chilean government has proposed
projects that might have an adverse effect on the environment comply with
new regulations regarding the closure plans applicable to hydrocarbon
Chilean environmental laws and regulations. The Environmental Assessment
operations that could have an impact on the timeframes and costs required
Service directs and coordinates the environmental impact assessment
to set up exploration or exploitation activities.
process, whose final qualification is granted by the competent regional
environmental assessment commission. The Superintendency of
Regulatory entities
The Chilean Ministry of Energy and the National Commission of Energy
Environment’s primary responsibilities are monitoring compliance with the
terms of an environmental impact assessment, as well as monitoring
(Comisión Nacional de Energía), or the CNE, are the principal government
compliance with government plans to prevent environmental damage or to
agencies responsible for the issuance of policies and regulations for the
oil and gas sector. The Chilean Ministry of Energy is responsible for
clean or restore contaminated geographical areas. The Superintendency
of Environment has the power to suspend or terminate, or impose fines
monitoring a participant’s compliance with its obligations under a CEOP. The
from US$1,000 up to US$10.0 million for, activities that it deems to have an
Superintendency of Electricity and Fuels (Superintendencia de Electricidad
adverse environmental impact, even if such activities comply with a
y Combustibles), or the SDEC, supervises compliance with regulations
previously approved environmental impact assessment.
regarding gas pipeline transportation and the Ministry of Environment, the
Environmental Assessment Service and the Superintendency of Environment
are responsible for environmental matters. The new Environmental
The Environmental Courts
The Environmental Courts are principally responsible for hearing appeals
Courts are responsible for adjudicating claims against the Superintendency
of determinations made by the Superintendency of Environment and
of Environment and claims concerning environmental damage.
for adjudicating claims for environmental damage. There is currently one
Ministry of Energy
The Chilean Ministry of Energy is responsible for developing and
Environmental Court in Chile, which began to hear claims on December 28,
2012. Another two Environmental Courts are expected to begin hearing
claims during 2013. The Environmental Court that will have jurisdiction over
coordinating all plans, policies and regulations for the energy sector in Chile
the area in which we operate elected its members on September 12, 2013
and supervising and advising the government in all matters related to
and is expected to begin hearing claims shortly.
energy. It coordinates the different entities in the energy sector in Chile and,
GeoPark 20F 111
Regulatory framework
Regulation of exploration and production activities
Oil and gas exploration and development is governed by the Political
Additionally, Chile is a signatory state to the Substitute Protocol of the
Eighth Additional Protocol to the Economic Complementation Agreement
No. 16 between Chile Republic and Argentina Republic (ACE 16) Regulation
for Marketing, Operations and Transportation of Hydrocarbons Liquids—
Constitution of the Republic of Chile and Decree with Law Force No 2 of 1986
Crude Oil, Liquefied Gas and Liquid Products of Petroleum and Natural Gas
of the Ministry of Mines, which set forth the revised text of the Decree Law 1089
and the following international conventions: the International Convention
of 1975, on CEOPS. However, the right to explore and develop fields is granted
for the prevention of Pollution of the Sea by Oil of 1954, the Convention on
for each area under a CEOP between Chile and the relevant contractors.
the Prevention of Marine Pollution by Dumping of Wastes and Other Matters
The CEOP establishes the legal framework for hydrocarbon activities, including,
of 1972 and the International Convention on Civil Liability for Oil Pollution
among other things, minimum investment commitments, exploration and
Damage of 1969.
exploitation phase durations, compensation for the private company (either
in cash or in kind) and the applicable tax regime. Accordingly, all the provisions
Taxation
governing the exploitation and development of our Chilean operations are
With regard to direct taxes on hydrocarbon exploitation, the general rule is
contained in our CEOPs and the CEOPs constitute all the licenses that we need
that hydrocarbons are transferred to the contractor (its retribution under the
in order to own, operate, import and export any of the equipment used in our
CEOP), and those re-acquisitions from the contractor performed by Chile or
business and to conduct our gas and petroleum operations in Chile.
its enterprises, as well as their corresponding acts, contracts and documents,
are tax exempt. In addition, hydrocarbon exports by the contractor are also
Under Chilean law, the surface landowners have no property rights over
tax exempt. With regard to income taxes, as provided by article 5 of Decree
the minerals found under the surface of their land. Subsurface rights do not
Law No. 1,089, the contractor is subject either to a single tax calculated
generate any surface rights, except the right to impose legal easements
on its retribution, equal to 50% of such retribution, or to the general income
or rights of way. Easements or rights of way can be individually negotiated
tax regime established in the Income Tax Law (Decree Law No. 824 of
with individual surface land owners or can be granted without the consent
1974), in force at the time of the execution of the public deed which contains
of the landowner through judicial process. Pursuant to the Chilean Code
CEOPs, terms of which will be applicable and invariable throughout the
of Mines, a judge can permit a party to use an easement pending final
duration of the contract. Income in Chile is subject to corporate tax on an
adjudication and settlement of compensation for the affected landowner.
accrual basis and has a current rate of 20%. The applicable and invariable
Regulation of transportation activities
Liquid hydrocarbon transportation, storage, importation and marketing are
corporate income tax rates of our CEOPs range between 15% and 18.5%,
as follows: the Fell Block is subject to a rate of 15%, the Otway and Tranquilo
Blocks are subject to a rate of 17% and the Flamenco, Isla Norte and
subject to a number of technical regulations regarding safety, quality and
Campanario Blocks are subject to a rate of 18.5% for the income accrued
other matters. The rules for the transportation of liquid fuels through
or received during 2012 and 17% for the income accrued or received
trucks and pipelines are primarily found in Supreme Decree No. 160 of 2009
during 2013 and onward. Dividends or profits distributed to the foreign
(the Safety Code for Facilities and Production and Refining Operations,
Transportation, Storage, Distribution and Supply of Liquid Fuels) of the
shareholders of the contractors are subject to 35% Additional Withholding
Tax with a tax credit for the corporate income tax paid by the contractor
Ministry of Economy. The Ministry of Energy is responsible for the regulation
being deductible from the corporate income tax already paid as credit.
of transportation by pipeline and the Ministry of Transport is responsible
With regard to the value added tax, contractors may obtain as a refund the
for the regulation of transportation by truck.
value added tax (which is 19% according to the Sales and Services Tax
Gas transportation in Chile is subject to open access rules, in which the
import or purchase of goods or services used in connection with the
gas transportation company must make its excess transportation capacity
exploration and exploitation activities. The applicable tax regime for each
available to third parties under equal economic, commercial and technical
CEOP remains unchanged throughout the duration of the CEOP.
Law contained in Decree Law No. 825 of 1974) supported or paid on the
conditions. Laws prohibit the abuse of a dominant position by a gas
transportation company in order to discriminate among potential customers
Colombia
for use of its pipelines. Pursuant to Ministry of Economy Supreme Decree
No. 280 of 2009, gas pipelines must also comply with the Regulation
of Security for Transportation and Distribution of Gas, which regulates the
Oil and gas industry
Today, Colombia is one of the largest and most stable economies in South
design, construction, operation, maintenance, inspection and termination
America. The country has a stable political and judicial environment, with a
of operations of a natural gas pipeline.
strong track record of growth. Furthermore, Colombia holds investment-
112 GeoPark 20F
grade sovereign debt ratings from all major rating agencies (BBB, BBB- and
Colombia—production profile
Baa3 from S&P, Fitch and Moody’s, respectively).
.
1
3
2
2
.
9
8
1
2
.
3
5
1
2
.
9
8
0
2
.
9
5
2
2
.
5
4
0
2
.
5
6
3
2
.
1
3
0
2
.
4
4
0
2
.
1
7
4
22
5
0
2
.
.
7
0
7
3
.
4
3
0
3
.
2
1
2
3
.
9
8
5
2
.
8
4
6
2
.
8
7
2
2
.
6
3
2
4
.
3
8
8
3
.
5
5
6
3
.
9
8
9
43
3
5
3
.
In 2012, the country’s GDP grew by 4%, with CPI inflation at 2.44%. In order
to stimulate growth and private investments, Colombia has throughout
the last years entered into several free trade agreements, which include the
agreement with the United States in May 2012 and the creation of the
Pacific Alliance with Mexico, Peru and Chile in June 2013.
Oil is currently Colombia’s leading export and source of foreign investment.
Historically, all oil production in the country was from concessions granted
to foreign operators or undertaken by Ecopetrol, in contracts of association
with foreign companies. During 1999 and 2000, the country was considered
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Oil (mmboe)
Natural Gas (bcf )
to be at risk of becoming a net oil importer unless significant additional
Source: BP Statistical Review
reserves were discovered. As a result, Ecopetrol was restructured, and in 2003,
a regulatory agency for the sector, the ANH, was created. Following these
Colombia is divided in 23 sedimentary basins. Colombian sedimentary basins
initial steps, consistent acreage sales to private investors coupled with better
have extensively developed petroleum systems that make them well suited
seismic work led to an improvement in the country’s exploratory success
for exploration and exploitation of hydrocarbons. Colombian supply growth
rate and, consequently, to a change in the country’s production landscape.
is driven mainly by conventional resources located in reservoirs with large
Discoveries in Colombia in general have not been relevant in terms of
regional distribution systems and heavy oil development along the eastern
scale; however, the number of discoveries has favored a significant increase
part of the Tertiary Foreland basins. The Eastern Llanos and Magdalena Valley
in production and the creation of several medium-sized companies.
Basins show the most potential for exploration activities. The Eastern Llanos
Opportunities offered by the Colombian energy sector have changed the
Basin accounts for over 79% of the country’s current oil and liquids reserves,
competitive landscape by attracting foreign investment in the country from
followed by Caguan-Putumayo Basin, which accounts for 9%. The Eastern
leading multinational energy companies that operate in Colombia either
Llanos Basin also contains large gas reserves, comprising 90% of the country’s
independently or through joint ventures. Foreign investment in the oil and
reserves. From 2002 to 2012, Colombian production increased at a CAGR of
gas industry in Colombia has grown from US$1.125 million in 2005 to
5.1% for oil and 6.8% for natural gas.
US$5.377 million in 2012.
Colombia—signed contracts
64
59
59
54
44
76
54
32
28
32
21
7
8
We believe Colombia offers significant potential for value creation through
the application of modern technology and exploration strategies on
undercapitalized producing fields.
Colombia—seismic profile (thousand km 2D equivalent)
26.5
26.0
24.0
20.1
16.3
18.2
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
E&P
TEA
Asociación (ECP)
Source: ANH
11.9
10.0
6.8
3.5
1.4
2.4
2.1
According to the BP Statistical Review, Colombia is the third-largest producer of
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
crude oil and the seventh-largest producer of natural gas in Central and South
Source: ANH
America. According to the BP Statistical Review, in 2012, the country’s oil
production reached 365.5 mmboe, with natural gas production of 423.6 bcf.
GeoPark 20F 113
Regulation of the oil and gas industry
Under Colombian law, the state owns all hydrocarbon reserves discovered
ANLA
The ANLA was created pursuant to Decree 3573 of 2011 issued by
in the Colombian territory and exercises control of the exploitation of such
the Colombian government with the participation of the Administrative
reserves primarily through the ANH.
Department of Public Functions (Departamento Adminstrativo de la Función
Pública), and is responsible for hydrocarbon environmental licensing in
The ANH is responsible for managing all exploration lands not subject
Colombia. Any project in the hydrocarbons sector requiring an environmental
to previously existing association contracts with Ecopetrol. The ANH began
license must submit to environmental licensing procedures, which require
offering all undeveloped and unlicensed exploration areas in the country
the presentation of an environmental impact assessment, an environmental
under E&P Contracts and Technical Evaluation Agreements, or TEAs,
management plan and a contingency plan. Environmental licenses are
which resulted in a significant increase in Colombian exploration activity
granted for exploration and production phases separately.
and competition, according to the ANH. According to the ANH, since January
2004, 450 E&P Contracts and 97 TEAs have been signed, of which 46 E&P
Contracts and eight TEAs have been signed during 2012. The ANH is also
CREG
Laws 142 and 143 of 1994 created the CREG, a special administrative unit of
in charge of negotiating and executing contracts through “direct negotiation”
the Ministry of Mines and Energy, responsible for establishing the standards
mechanisms with attention to special conditions in the areas to be explored.
for the exploitation and use of energy, regulating the domestic utilities of
Regulatory entities
The principal authorities that regulate our activities in Colombia are the
electricity and fuel gas (liquefied petroleum gas and natural gas), establishing
price rules for energy and gas and regulating self-generation and cogeneration
of energy. The CREG is also responsible for fostering the development of the
Ministry of Mines and Energy, the ANH, the National Environmental Licensing
energy services industry, promoting competition and responding to consumer
Authority, or the ANLA, and the Regulatory Commission of Energy and Gas,
and industry needs. Decree 4130 of 2011 assigned the CREG new functions
or the CREG.
that were previously fulfilled by the Ministry of Mines and Energy, including
the regulation of tariffs for oil transportation in poliducts and the regulation of
Ministry of Mines and Energy
The Ministry of Mines and Energy is responsible for managing and regulating
petroleum-derived liquid fluids.
Colombia’s nonrenewable natural resources, assuring their optimal
utilization by defining and adopting national policies regarding exploration,
Superintendency of Domiciliary Public Services
Under Colombian regulations, the distribution and marketing of natural
production, transportation, refining, distribution and export of minerals
gas is considered a public service. As such, this activity, as well as electricity,
and hydrocarbons.
are regulated by Law 142 of 1994 and supervised by the Superintendency
of Domiciliary Public Services (Superintendencia de Servicios Públicos
ANH
The ANH was created in 2003 and is responsible for the administration
Domiciliarios).
of Colombia’s hydrocarbon reserves. The ANH’s objective is to manage the
hydrocarbon reserves owned by the state through the design, promotion
and negotiation of the exploration and production agreements in areas
where hydrocarbons may be found. The ANH is also responsible for creating
Regulatory framework
Regulation of exploration and production activities
Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon
and maintaining attractive conditions for private investments in the
resources located in Colombia and has full authority to determine the rights,
hydrocarbon sector and for designing bidding rounds for exploration blocks.
royalties or compensation to be paid by private investors for the exploration or
Any oil company selected by the ANH to explore a specific block must
the authority responsible for regulating all activities related to the exploration
execute either a TEA or an E&P Contract to develop and exploit the block
and production of hydrocarbons in Colombia.
production of any hydrocarbon reserves. The Ministry of Mines and Energy is
with the ANH. All royalty payments in connection with the production
of hydrocarbons are made to the ANH in kind unless the ANH grants a specific
Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code,
waiver to make royalty payments in cash or the specific contract provides
establishes the general procedures and requirements that must be completed
for payment in cash. Any oil company working in Colombia must present to
by a private investor prior to commencing hydrocarbon exploration or
the ANH periodic reports on the evolution of their exploration and
production activities. The Petroleum Code sets forth general guidelines,
exploitation activities.
obligations and disclosure procedures that need to be followed during the
performance of these activities.
114 GeoPark 20F
Exploration and production activities were governed by Decree 1895 of
system has ranged from 8% for fields producing up to 5,000 bopd to 25%
1973 until September 2009. Decree Law 2310 of 1974 (as complemented by
for fields producing in excess of 600,000 bopd. Changes in royalty programs
Decree 743 of 1975) governed the contracts and contracting processes
only apply to new discoveries and do not alter fields already in their
carried out by Ecopetrol and the rules applicable to such contracts, and also
production stage. Producing fields pay royalties in accordance with the
provided that Ecopetrol was responsible for administering the hydrocarbons
applicable royalty program at the time of the discovery. The purchase price
resources in the Country. Decree 2310 of 1974 was replaced by Decree
is calculated based on a reference price for crude oil at the wellhead and
Law 1760 of 2003, but all agreements entered into by us prior to 2003 with
varies depending on prevailing international prices. Decree 2100 of 2011
other oil companies are still regulated by Decree 2310 of 1974.
modified the commercialization scheme of natural gas royalties. From 2012
and until May 2013, producers had to directly commercialize the royalties
Decree Law 1760 of 2003 provided the faculties, structure and functions
of their own production on behalf of the ANH. In return, the ANH paid a
of the ANH, and granted the ANH full and exclusive authority to regulate and
commercialization fee to producers. As of May 2013, contractors must pay in
oversee the exploration and production of hydrocarbon reserves. Decree
kind royalties to third parties called “Royalty Trading Companies” or “Royalty
Law 1760 of 2003 was complemented by Decree 2288 of 2004, which
Marketing Companies,” which are in charge of commercializing the royalties.
regulates all aspects related to the reversion of reserves and infrastructure
under the joint venture agreements executed by us before 2004.
Regulation of refining and petrochemical activities
Refining and petrochemical activities are considered to be public utility
The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 and
activities and are subject to governmental regulation. Article 58 of the
Agreement 004 of 2012. Accord 008 of 2004, as repealed and replaced by
Petroleum Code establishes that oil refining activities can be developed
Accord 004 of 2012, issued by the Directive Council of the ANH, sets forth the
throughout Colombia. Oil refineries must comply with the technical
necessary steps for entering into E&P Contracts with the ANH. This
characteristics and requirements established by the existing regulations.
Agreement only regulates the contracts entered into as of May 4, 2012. Prior
contracts are still ruled by Agreement 008 of 2004.
The Ministry of Mines and Energy is responsible for regulating, supervising
and overseeing all activities related to the refining of crude oil, import of
Resolution 18-1495 of 2009 establishes a series of regulations regarding
refined products, storage, transport and distribution.
hydrocarbon exploration and exploitation. In the E&P Contracts, operators
are afforded access to non-contracted blocks by committing to an exploration
Decree 2657 of 1964 regulated the oil refining activities and created the Oil
work program. These E&P Contracts provide companies with 100% of new
Refining Planning Committee, which is responsible for studying industry
production, less the participation of the ANH, which participation may differ
problems and implementing short- and long-term refining planning policies.
for each E&P Contract and depends on the percentage that each company
The Committee is also responsible for evaluating and reviewing new refining
has offered to the ANH in order to be granted with a block, subject to
projects or expansion of existing infrastructure. In evaluating a new project,
an initial royalty payment of 8% and the payment of income taxes of 33%.
the Committee must take into account the significance of the project and the
In addition, the Colombian government also introduced TEAs, in which
companies that enter into TEAs are the only ones to have the right to explore,
economic impact, the sources of financing, profitability, social contribution,
the effects on Colombia’s balance of payments and the price structure of the
evaluate and select desirable exploration areas and to propose work
refined products.
commitments on those areas, and have a preemptive right to enter into an
E&P Contract, thereby providing companies with low-cost access to larger
Pursuant to Resolution 18-0966 of 2006 issued by the Ministry of Mines and
areas for preliminary evaluation prior to committing to broader exploration
Energy and Article 58 of the Petroleum Code, any refining company operating
programs. A preemptive right is granted to convert the TEA into an E&P
in Colombia must provide a portion or, if needed, the total of its production
Contract. Exploration activities can only be carried out by the TEA contractor.
to supply local demand prior to exporting any production. If the regulated
Pursuant to Colombian law, companies are obligated to pay a percentage
lower than the export parity price, the price paid for the refined products
of their production to the ANH as royalties and an economic right as ANH’s
will be equivalent to the price for those products in the U.S. Gulf Coast
participating interest in the production. In 1999, a modification to the royalty
market. If there is local demand for imported crudes, the refining company
system established a sliding scale for royalty payments, linking them to
may charge additional transportation costs in proportion to the crudes
production income, the principal item in the price formula, becomes
the production level of crude oil and natural gas fields discovered after July
delivered to the refinery.
29, 1999 and to the quality of the crude oil produced. Since 2002 the royalties
GeoPark 20F 115
In 2008, Law 1205 was issued, with the main purpose of contributing to
According to Law 681 of 2001, multipurpose pipelines must be open to
a healthier environment, and established the minimum quality that fuels
third-party use and owners must offer their capacity on the basis of equal
should have in the country and the time frame for such a purpose.
access to all. Hydrocarbon transport activity may be developed by third
parties and must meet all requirements established by law.
The Ministry of Mines and Energy establishes the safety standards for LPG,
storage equipment, maintenance and distribution. Regulations issued in
The Ministry of Mines and Energy is responsible for studying and approving
1992 established that every local, commercial and industrial facility with a
the design and blueprints of all pipelines, mediation of rates between parties
storage capacity of LPG greater than 420 pounds must receive authorization
or, in case of disagreement, establishing the hydrocarbon transport rates
for operations from the Ministry of Mines and Energy.
based on information furnished by the service provider, issuing hydrocarbon
As of May 2012, under the powers granted by Decree 4130 of 2011 for
of transport-related taxes and managing the information system for the oil
currency and tax matters as well as for royalties, the ANH will determine
product distribution chain.
transport regulations, liquidation, distribution and verification of payment
the crude oil price reference.
Regulation of transportation activities
Hydrocarbon transportation activity is considered a public utility activity in
Colombia and therefore is under governmental supervision and control.
The construction of transportation systems requires government licenses
and local permits awarded by the Ministry of Environment, in addition to
other requirements from the regional environmental authorities.
It is also a public service, and pipelines are considered to be public transport
Recently, further regulations on pipeline access and tariff systems have been
companies. Transportation and distribution of crude oil, natural gas and
defined by the Ministry of Mines and Energy. Over the past months, the
refined products must comply with the Petroleum Code, the Commerce Code
Ministry of Mines and Energy has been working on a project to modify the
(Código de Comercio) and with all governmental decrees and resolutions.
2010 regulation of pipeline access and tariff systems.
Notwithstanding the general rules for hydrocarbon transportation in
Colombia, natural gas transportation has specific regulations, due to the
Taxation
The Tax Statute and Law 9 of 1991 provide the primary features of the oil
categorization of natural gas distribution as a public utility activity under
and gas industry’s tax and exchange system in Colombia. Generally, national
Colombian laws. Therefore, natural gas distribution transportation is
taxes under the general tax statute apply to all taxpayers, regardless of
governed by specific regulation, issued by the CREG that seeks primarily
industry. The main taxes currently in effect—after the December 2012 tax
to satisfy the needs of the population.
reform discussed below—are the income tax (25%), the special income
tax for the development of social investments (9% for 2013 to 2015 and 8%
The exportation of natural gas is not considered a public utility activity
for 2016 and beyond) the equity or net assets tax, sales or value added
under Colombian law and therefore is not subject to Law 142 of 1994.
tax (16%), and the tax on financial transaction (0.4%). Additional regional
Nevertheless, the internal supply of natural gas is a priority for the Colombian
government. This policy is included in Decree 2100 of 2011, providing that
taxes also apply. Colombia has entered into a number of international
tax treaties to avoid double taxation and prevent tax evasion in matters of
in the event the supply of natural gas is reduced or halted as a result of
income tax and net asset tax.
a shortage of this hydrocarbon, the Colombian government has the right to
suspend the supply of natural gas to foreign customers. Notwithstanding
Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the
the foregoing, the Decree 2100 of 2011, establishes freedom to export natural
international investment regime, regulates foreign capital investment in
gas, under normal conditions for gas reserves.
Colombia. Resolution 8 of the board of the Colombian Central Bank, or the
Exchange Statute, and its amendments contain provisions governing
Transport systems, classified as crude oil pipelines and multipurpose
exchange operations. Articles 48 to 52 of Resolution 8 provide for a special
pipelines, can be owned by private parties. The building, operation and
exchange regime for the oil industry that removes the obligation of
maintenance of pipelines must comply with environmental, social, technical
repayment to the foreign exchange market currency from foreign currency
and economic requirements under national and international standards.
sales made by foreign oil companies. Such companies may not acquire
Transportation networks must follow specific conditions regarding design
foreign currency in the exchange market under any circumstances and
and specifications, while complying with the quality standards demanded
must reinstate in the foreign exchange market the capital required in order
by the oil and gas industry.
to meet expenses in Colombian legal currency. Companies can avoid
participating in this special oil and gas exchange regime, however, by
116 GeoPark 20F
informing the Colombian Central Bank, in which case they will be subject
proven domestic oil and natural gas reserves from offshore sites contributed
to the general exchange regime of Resolution 8 and may not be able to
to 94% of total proven reserves (with the remainder located onshore).
access the special exchange regime for a period of 10 years.
Recent pre-salt discoveries are expected to be transformational for Brazil.
On December 26, 2012, the Colombian Congress approved a number of
The hydrocarbon fields Sapinhoá (former Guará), Lula (former Tupi),
tax reforms. These changes include, among other things, VAT rate
Iara, and Cernambi (former Iracema) have the vast majority of the recoverable
consolidation, a reduction in corporate income tax (from 33% to 25%),
volumes of 15.7 bboe announced by Petrobras in its Management and
changes to transfer pricing rules, the creation of a new corporate income
Business Plan for 2013-2017. On October 21, 2013 the ANP hosted an auction
tax to pay for health, education and family care issues (9% for fiscal years
of the Libra prospect in the Santos basin, which was discovered in 2010.
2013 to 2015 and 8% from 2016 and beyond), modifications in
It was the first bidding of the production sharing regime. A consortium
individual income tax, new “thin capitalization” rules and a reduction of
formed by Petrobras, Shell, Total, China National Petroleum Corporation and
social contributions paid by certain employees. The implementation
China National Offshore Oil Corporation was awarded the concession,
of such tax reforms requires further administrative regulation. As of the
offering a 41.65% share of profit oil to the federal government (the minimum
date of this annual report, some administrative regulations had been
share of profit oil set forth under the bidding protocol). ANP studies estimate
published, although we do not expect the final impact of these reforms to
a potential of 26 to 42 billion barrels of oil in situ, of which 8 to 12 billion
be material to our business.
are recoverable barrels.
Brazil
Growth of oil and natural gas production (CAGR from 2002 to 2012)
Oil and gas industry
Recent discoveries in the E&P space have transformed Brazil’s oil and gas
industry landscape and turned the country into one of the fastest-growing
oil and gas markets in the world. According to the BP Statistical Review,
13.39%
the country’s proved oil reserves in 2012 jumping to 15.3 bboe, an increase
5.81%
of 1.8% as compared to the previous year. The reserves’ CAGR throughout
4.42%
3.96% 3.75%
the last 10 years has reached 4.56%, significantly above the world’s
average CAGR of 2.36%. Furthermore, production has also grown above
the global rate during this 10-year period—3.7% as compared to 1.4%—
in great part favored by recent discoveries in the pre-salt and offshore
Atlantic concessions. In 2012, oil production reached 822.4 mmbbl.
2.99% 2.84% 2.78% 2.74% 2.69% 2.00% 2.00%
1.62%
0.70%
-0.53%
r
a
t
a
Q
n
a
t
s
h
k
a
z
a
K
t
i
a
w
u
K
l
i
z
a
r
B
k
a
r
I
i
a
b
a
r
A
i
d
u
a
S
s
e
t
a
r
i
m
E
b
a
r
A
d
e
t
i
n
U
a
i
r
e
g
N
i
n
a
t
s
i
n
e
m
k
r
u
T
n
a
r
I
n
a
i
s
s
u
R
n
o
i
t
a
r
e
d
e
F
S
U
a
y
b
L
i
a
d
a
n
a
C
l
a
e
u
z
e
n
e
V
Similar dynamics took place for the natural gas market, with reserves in
2012 jumping to 0.45 trillion cubic meters, or tm3, with an implied 10-year
Source: BP Statistical Review
CAGR of 6.50%, significantly above the global CAGR of 1.91%. Production
Historically, Brazil’s oil and natural gas industry was controlled by Petrobras.
has also grown above the global rate during this period—6.53% as compared
In 1995, the Brazilian Federal Constitution was amended to allow
to 2.90%—also favored by both non-associated gas finds and gas associated
privately- or publiclyowned companies to engage in the exploration and
with the pre-salt areas. In 2012, natural gas production reached 614.2 bcf.
exploitation of oil and natural gas, subject to conditions set forth in specific
Production levels will be further boosted with the next bidding round,
legislation governing the sector. In 1997, the Brazilian Petroleum Law
which has been pre-announced by the ANP for the fourth quarter of 2013,
created the ANP to promote a transparent regulatory framework and bidding
and which will be dedicated to areas with gas potential according to studies
rounds for new concession areas and to regulate and oversee the Brazilian
led by the ANP.
oil and natural gas sector.
Today, offshore fields are the main contributor to reserves and production;
The opening of the Brazilian oil and natural gas industry attracted the
however, the first phase of the production history in the sector, with
attention of private companies. According to the ANP’s Brazilian Annual
upstream activities dating back to the 1940s, was in the onshore space,
Statistic Report of Petroleum, Natural Gas and Biofuelds, until the end
with the Recôncavo Basin in northeast Brazil playing a pivotal role. In 2011,
of year 2012 Brazil had 701 areas under concession, being 279 blocks under
exploration phase, 75 fields under development and 347 fields under
GeoPark 20F 117
production, with 133 concessionaries conducting exploratory, development
account the increased local production and imports from Bolivia, natural gas
and production activities in Brazilian sedimentary basis. Out of the 347 fields
currently accounts for about 7.5% of total Brazilian energy demand, according
currently in production, 278 were exclusive concessions to Petrobras and
to the 2012 National Energy Balance published by the Energy Research
22 fields were designed as partnership agreements between Petrobras and
Company, or EPE. Furthermore, according to EPE’s 2021 Ten Year Energy
other concessionaries. Petrobras did not take part in the remaining 47.
Expansion Plan, the share of natural gas in overall energy consumption
As of December 2013, the ANP has held 12 oil and gas bidding rounds and
further boosted with the next bid round, which has been pre-announced by
one pre-salt auction. Round zero was the first round, and was held by
the ANP for the fourth quarter of 2013, and which will be dedicated to areas
the ANP to define Petrobras’s participation in its existing concessions after
with gas potential according to studies led by the ANP.
in Brazil should reach 7.8% in 2016 and 8.1% in 2021. Production will be
the end of its monopoly. The graph below indicates the number of
exploration concessions auctioned at each round.
Brazil has the capacity for both sustained and rapid growth in natural gas
The ANP’s exploratory concession grants
251
over the next decade, which may potentially change the balance between
natural gas supply and demand in the country. The increased supply could
open up new opportunities in the country. Natural gas may not only help
sustain the continued growth of the local market, but Brazil may also choose
to reduce the amount of gas imported and, in the long-term, become a
seasonal exporter.
154
89
210
101
20
81
65
41
117
65
52
54
142
87
55
The increase of the gas supply associated with a growing reserve profile
is expected to enable the continued development of the domestic market
at rates above the historical ones. Market growth has been largely directed
72
by increased demand from the industrial and power generation sectors,
which increased their demand for gas by 89.1% between 2002 and 2011,
according to the EPE.
1
12
21
9
12
34
27
7
21
11
10
First
(1999)
Second
(2000)
Third
(2001)
Fourth
(2002)
Fifth
(2003)
Sixth
(2004)
Seventh
(2005)
Ninth
(2007)
Tenth
(2008)
Eleventh
(2012)
Libra
Auction
Twelfth
(2013)
The chart below compares the reserves with the reserves-to-production,
Offshore
Onshore
or R/P, ratio, in Brazil in the periods indicated.
Source: ANP
Reserves versus R/P(1) (Brazil)
On May 14, 2013, the ANP hosted the 11th oil and gas bidding round
offering 289 concessions, located in 11 basins. These concessions cover
approximately 155.8 sq. km. The auction was characterized by a high level
of participation and raised R$2.8 billion in proceeds through license fees.
Of the 289 concessions offered, 142 were successfully bid upon by
industry players.
26
24
315.9
313.5
31
32
29
28
31
29
26
27
491.7
26
476.5
Additionally, on November 28, 2013, the ANP hosted the 12th oil and gas
bidding round offering 240 concessions, located in seven onshore basins.
The auction raised R$165.2 million in proceeds through signing bonuses.
The round was focused on conventional and unconventional resources with
natural gas potential. Of the 240 concessions offered, 72 were successfully
241
242
321
302
343
360
359
362
417
453
452
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Reserves (million cubic metres)
R/P (years)
bid upon by industry players.
Source: BP Statistical Review
Natural gas market in Brazil
The natural gas industry in Brazil has undergone significant changes
(1) R/P is a valuation formula, calculated as total proved reserves, or R, divided
by annualized current net daily production, or P.
over the past decade. During this period, natural gas was the fastest-growing
The chart below illustrates the Brazilian domestic natural gas supply in the
component of the non-renewable energy mix in the country. Taking into
periods indicated.
118 GeoPark 20F
Natural gas production/imports
LNG
Brazil began importing LNG in early 2009 through two import terminals,
one located in northeast Brazil, in the State of Ceará, and another near the
major gas markets in southeast Brazil, in the State of Rio de Janeiro. Both
5,369
5,055
8,086
8,998
9,789
10,334
11,348
8,366
12,647
10,481
terminals offer re-gasification vessels with an anchor point, which may
be connected directly to the national gas network. The terminals are designed
to provide flexibility in gas supply and meet the region’s thermoelectric
15,525
15,792
16,971
17,699
17,706
18,152
21,593
21,137
22,938
24,064
demand.
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Production (mcm)
Import (mcm)
Source: ANP
Brazil’s sedimentary basins
The offshore area covers approximately 383.0 million gross acres and the
onshore area covers approximately 1,112.0 million gross acres.
Infrastructure and workforce
Refineries
There are currently 16 refineries operating in Brazil, of which 12 are Petrobras-
operated. The current refining capacity is approximately 2.1 mmboepd,
up from the 1.9 mmboepd during the 2000s. This increase has been achieved
through capacity expansion of the existing refineries. Petrobras has plans to
continue the expansion of the country’s refining capacity, and several major
projects are either underway or planned that will add a further 1.5 mmboepd
of capacity.
Regulation of the oil and gas industry
Article 177 of the Brazilian Federal Constitution of 1988 provides for the
Federal Government’s monopoly over the prospecting and exploration of oil,
Overview. Extensive infrastructure is already in place in the mature coastal
basins. The Brazilian midstream infrastructure has grown significantly during
natural gas resources and other fluid hydrocarbon deposits, as well as over
the refining, importation, exportation and sea or pipeline transportation
recent years. However, it is still small in comparison to other countries,
of crude oil and natural gas. Initially, paragraph one of article 177 barred the
such as the U.S., China and France. In total, there are 32 oil pipes extending
assignment or concession of any kind of involvement in the exploration of
across 2,000 km. Local oil pipeline systems connect the fields in the Sergipe-
oil or natural gas deposits to private industry. On November 9, 1995, however,
Alagoas, Potiguar and Recôncavo Basins to the coastal export terminals
Constitutional Amendment Number 9 altered paragraph one of article 177
where oil is sent by ship to the refineries in Fortaleza, Bahia and other States.
so as to allow private or state-owned companies to engage in the exploration
The Brazilian government is expected to announce a ten-year plan for
and production of oil and natural gas, subject to the conditions to be set
pipeline development, or Pemat, similar to what is done today in the power
forth by legislation.
and utilities sector, through EPE’s 2021 Ten Year Energy Expansion Plan.
With a well-established onshore oil and gas industry, the country has an
experienced and skilled workforce.
Oil infrastructure. The oil infrastructure in Brazil is relatively limited, and the
majority of oil production is offshore. Oil is loaded onto tankers and shipped
The Brazilian Petroleum Law, which enacted this constitutional provision:
• confirmed the Federal Government’s monopoly over oil and natural gas
deposits and further provided that the exploration and production of such
hydrocarbons would be regulated and overseen by the federal government;
• created the CNPE (as defined below) and the ANP;
• revoked Law Number 2,004/53, which appointed Petrobras as the exclusive
directly to coastal terminals and refineries or exported.
agent to execute the Federal Government’s monopoly; and
• established a transitional rule that entitled Petrobras to: (1) produce in fields
Gas infrastructure. The gas pipeline network in Brazil is still relatively
underdeveloped despite the significant expansion currently underway.
where Petrobras had already started production under a concession
agreement made with the ANP for 27 years, on an exclusive basis, starting
There are many gas transmission pipelines, including international pipelines
on the date the field was declared commercially profitable; and (2) explore
and a large distribution system. However, the existing infrastructure covers
areas where Petrobras was able to show evidence of “established reserves”
only a small portion of Brazil, primarily serving the main population centers
prior to the enactment of the Brazilian Petroleum Law, for up to three years,
of São Paulo and Rio de Janeiro, some states in the south and coastal
subsequently extended to five years.
states in the northeast.
GeoPark 20F 119
Regulatory entities
(the PN-T-597 Concession in the Parnaíba Basin in the State of Maranhão
and the SEAL-T-268 Concession in the Sergipe Alagoas Basin in the State of
National petroleum, natural gas and biofuel agency (ANP)
The Brazilian Petroleum Law created the ANP. The ANP is a regulatory
Alagoas). Our winning bids are subject to confirmation of qualification
requirements. See “—Our operations— Operations in Brazil” and “Item 3.
body of the federal government associated with the Ministry of Mines and
Key information—D. Risk factors—Risks relating to our business—
Energy. The ANP’s function is to regulate the oil, natural gas and biofuels
The PN-T-597 concession is subject to an injunction and may not close” for
industry in Brazil. One of the ANP’s primary objectives is to create a
more information.
competitive environment for oil and natural gas activities in Brazil that will
lead to the lowest prices and best services for consumers. Its principal
In order to participate in the auction process a company must have proven
responsibilities include enforcing regulations as well as awarding concessions
experience in oil and gas exploration and production activities, be legally
related to oil, natural gas and biofuels, in accordance with the Brazilian
constituted under the laws of their home country and undertake that, in the
Petroleum Law, as set forth in Decree No. 2,455, dated January 14, 1998,
event that they are successful in bidding, the company will constitute a
and regulations enacted by the National Council on Energy Policy and
company with its headquarters and management in Brazil, organized under
National Interest.
National council on energy policy (CNPE)
The CNPE, also created by the Brazilian Petroleum Law, is a council of the
President of Brazil presided over by the Minister of Mines and Energy.
Brazilian law, and have the determined (specific for each bidding round)
minimum net equity. If all requirements are met, the company will be
considered qualified to bid and make offers for the bidding areas within its
category.
The CNPE is charged with submitting national energy policies, designing oil
and natural gas production policies and establishing the procedural guidelines
Environmental issues
The identification and definition of the concessions to be offered is based
for competitive bids regarding the exploration concessions and areas with
on the availability of geological and geophysical data indicating the presence
established viability in accordance with the Brazilian Petroleum Law.
of hydrocarbons. Also, in order to protect the environment, the ANP, the
Regulatory framework
IBAMA and the state environmental agencies analyze all the areas prior
to deciding which concessions to offer in licensing rounds. The requirement
levels for environmental licensing for the various concessions to be
Pricing policy
Until the enactment of the Brazilian Petroleum Law, the Brazilian government
auctioned are then published, allowing the future concessionaire to include
environmental considerations in determining what projects to pursue.
regulated all aspects of the pricing of oil and oil products in Brazil, from
These environmental guidelines are revised and updated with every ANP
the cost of oil imported for use in refineries to the price of refined oil products
bidding round.
charged to the consumer. Under the rules adopted following the Brazilian
Petroleum Law, the Brazilian government changed its price regulation
policies. Under these regulations, the Brazilian government: (1) introduced
a new methodology for determining the price of oil products designed to
Consortium
The oil and natural gas industry is characterized in Brazil by the presence of
several companies acting through consortium agreements, or unincorporated
track prevailing international prices denominated in U.S. dollars, and (2)
joint ventures, in order to share the risks of exploration, development and
gradually eliminated controls on wholesale prices.
production activities. Terms of those agreements are set out by the ANP and
the actual risk sharing agreement is reflected in joint operating agreements.
Concessions
In addition to opening the Brazilian oil and natural gas industry to private
investment, the Brazilian Petroleum Law created new institutions, including
the ANP, to regulate and control activities in the sector. As part of this
Taxation
Introduction. The Brazilian Petroleum Law introduced significant
modifications and benefits to the taxation of oil and natural gas activities.
mandate, the ANP is responsible for licensing concession rights for the
The main component of petroleum taxation is the government take,
exploration, development and production of oil and natural gas in Brazil’s
comprised of license fees, fees payable in connection with the occupation
sedimentary basins through a transparent and competitive bidding process.
or title of areas, royalties and a special participation fee. The introduction of
The ANP has conducted 12 bidding rounds for exploration concessions
the Brazilian Petroleum Law presents certain tax benefits primarily with
since 1999. Most recently, in November 2013, the twelfth round was
respect to indirect taxes. Such indirect taxes are very complex and can add
conducted; 240 blocks in 13 sectors of seven basins were offered, of which
significantly to project costs. Direct taxes are mainly corporate income
72 were awarded. Of these 72 blocks, we were awarded two new concessions
tax and social contribution on net profit.
120 GeoPark 20F
Government take. With the effectiveness of the Brazilian Petroleum Law
and the regulations promulgated by the ANP, concessionaires are required
with applicable legal requirements. The period in which the goods are
allowed to remain in Brazil under the REPETRO regime may vary depending
to pay the Brazilian federal government the following:
on the importer, but usually corresponds to the duration of the contract
• license fees;
executed between the Brazilian company and the foreign entity, or the period
• rent for the occupation or retention of areas;
for which the company was authorized to exploit or produce oil and gas.
• special participation fee; and
• royalties on production.
In 2007, the legislation regarding the State Value Added Tax—ICMS
imposed taxation on the import of equipment into Brazil under the REPETRO
The minimum value of the license fees is established in the bidding rules for
regime was significantly changed by ICMS Convention No. 130/2007. This
the concessions, and the amount is based on the assessment of the potential,
regulation allows each State to grant the ICMS tax calculation basis reduction
as conducted by the ANP. The license fees must be paid upon the execution
(generating a tax burden of 7.5% with the recoverability of credits or 3%,
of the concession contract. Additionally, concessionaires are required to pay a
without the recoverability of credits) for goods purchased under the REPETRO
rental fee to landowners varying from 0.5% to 1.0% of the respective
regime for the production phase and the total exemption or ICMS tax
hydrocarbon production.
calculation basis reduction (generating a tax burden of 1.5%, without the
recoverability of credits) for the exploration phase. In order to be in force,
The special participation fee is an extraordinary charge that concessionaires
the ICMS Convention No. 130/07 must be included in each state’s legislation.
must pay in the event of obtaining high production volumes and/or
profitability from oil fields, according to criteria established by applicable
For example, currently, based on Convention No. 130/2007 , the state of
regulation, and is payable on a quarterly basis for each field from the date
Rio de Janeiro grants tax calculation basis reduction for the exploitation
on which extraordinary production occurs. This participation rate, whenever
(generating a tax burden of 7.5%, with the recoverability of credits or 3%,
due, may reach up to 40% of net revenues depending on (i) volume of
without the recoverability of credits) and production of oil and gas
production and (ii) whether the block is onshore, shallow water or deep
(generating a tax burden of 1.5%, without the recoverability of credits).
water. Under the Brazilian Petroleum Law and applicable regulations issued
For production activities, the legislation used to grant an exemption of ICMS,
by the ANP, the special participation fee is calculated based upon quarterly
which was recently changed to a tax calculation basis reduction, according
net revenues of each field, which consist of gross revenues calculated using
to Resolution Sefaz No. 631, dated May 14th, 2013.
reference prices published by the ANP (reflecting international prices and
the exchange rate for the period) less:
• royalties paid;
• investment in exploration;
• operational costs; and
It is important to mention that before the enactment of the Convention
No. 130/2007, the State of Rio de Janeiro has attempted to impose ICMS on
production activities, based on State Law No. 4,117, dated June, 27, 2003,
which was regulated by Decree No. 34,761, dated February 3, 2004, and
• depreciation adjustments and applicable taxes.
was subsequently suspended by Decree No. 34,783 of February 4, 2004 for
The ANP is responsible for determining monthly minimum prices for
an undetermined period of time. Nevertheless, the State of Rio de Janeiro
may choose to enforce the law at any time. Also, the constitutionality of
petroleum produced in concessions for purposes of royalties payable with
this law is currently being challenged by the Public Ministry in the Supreme
respect to production. Royalties generally correspond to a percentage
Court (ADI 3,019-RJ).
ranging between 5% and 10% applied to reference prices for oil or natural
gas, as established in the relevant bidding guidelines (edital de licitação) and
Pursuant to the Brazilian Petroleum Law and subsequent legislation, the
concession agreement. In determining the percentage of royalties applicable
federal government enacted Law No. 10,336/01, to impose the Contribution
to a particular concession, the ANP takes into consideration, among other
for Intervention in the Economic Sector, or CIDE, an excise tax payable by
factors, the geological risks involved and the production levels expected.
producers, blenders and importers on transactions with some of oil and fuel
Relevant Tax Aspects on Upstream Activities. The special customs regime for
goods to be used in the oil and gas activities in Brazil, REPETRO, aims
primarily at reducing the tax burden on companies involved in exploring
and extracting oil and natural gas, through the total suspension of federal
taxes due on the importation of equipment (platforms, subsea equipment,
among others), under leasing agreements, subject to the compliance
products, which is imposed at a flat amount based on the specific quantities
of each product. Currently, the CIDE rates are zero, based on Decree No.
7,764/2012.
GeoPark 20F 121
Argentina
Oil and gas industry
Argentina is the second-largest producer of natural gas and the fourth-
largest producer of crude oil in Central and South America, according to the
BP Statistical Review. The country is a leading producer and consumer of
natural gas in South America, and has a globally significant unconventional
oil and gas resource base. Production of both oil and natural gas throughout
the last years has been dropping as a result of the maturing of the production
fields and lack of investment. In 2012, the country’s natural gas production
reached 1331 bcf, with oil production at 242.4 mmbbl.
3.9
3.7
4.0
3.3
2.9
4.2
4.3
4.2
4.2
4.6
4.4
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Billion cubic feet per day
In response to the economic crisis of 2001 and 2002, the Argentine
government, pursuant to the Public Emergency Law (Law No. 25,561),
Source: BP Statistical Review
established export taxes on certain hydrocarbon products. In subsequent
years, in order to satisfy growing domestic demand and abate inflationary
Driven by economic expansion and stable domestic prices, energy
pressures, this law was supplemented by constraints on domestic prices,
consumption has increased significantly from 2002 to 2012, with demand for
export restrictions and subsidies on imports of natural gas and diesel, among
oil and gas increasing from 331.7 mboe in 2002 to 518.9 mboe in 2012.
other measures. As a result, local prices for oil and natural gas products
Argentine natural oil and gas consumption grew at a CAGR of approximately
had remained significantly below those prevalent in neighboring countries
4.6% during this period, according to the BP Statistical Review. In recent years,
and international commodity exchanges.
demand has outpaced energy supply (in 2012, the deficit reached 42.5 mboe).
After declining during the economic crisis of 2001 and 2002, Argentina’s
the country’s production surplus has shifted toward a deficit. Still, according
real gross domestic product, or GDP, grew at a compounded average
to the BP Statistical Review, Argentina’s R/P ratio is at 10.2x.
growth rate, or CAGR, of 8.4% from 2003 to 2008. Although the growth rate
decelerated to 0.9% in 2009 as a result of the global financial crisis, it
Argentina’s production of oil and natural gas (mmboe)
As a result of this increasing demand and the maturing of local reserves
recovered in 2010 and 2011, growing at an annual rate of 9.2% and 8.9%,
respectively, according to the International Monetary Fund. In 2012, the GDP
554.2
584.2
596.2
589.8
591.0
574.2
558.5
528.8
513.8
491.7
476.5
growth rate dropped to 1.9% as a reflex of the Brazilian slowdown spillover
effect over to its regional trading partners, especially Argentina, Paraguay,
and Uruguay. In Argentina, widespread import and exchange controls also
affected business confidence and investment.
315.9
313.5
300.1
288.8
286.8
278.4
267.8
255.8
249.3
235.8
227.6
Argentina’s consumption of oil and natural gas
238.2
270.7
296.1
301.0
304.1
295.7
290.7
273.0
264.5
255.9
248.9
523
534
522
557
598
612
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
394
405
425
449
471
Oil
Natural Gas
Source: BP Statistical Review
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Thousand barrels daily
Regulation of the oil and gas industry
Under Argentine law, the federal executive branch establishes the federal
policy applicable to the exploration, exploitation, refining, transportation and
marketing of liquid hydrocarbons, but the licensing and enforcement of
exploration and production activities has been transferred from the federal
government to provincial governments.
122 GeoPark 20F
Regulatory entities
The principal authorities that regulate the activities in Argentina are the
Decrees passed during 1989 relating to free marketability of hydrocarbons
at negotiated prices, the deregulation of the oil and gas industry,
Secretariat of Energy and the Strategic Planning and Coordination Committee
freedom to import and export hydrocarbons and the ability to keep
for the National Hydrocarbon Investment Plan, at the federal level, and a
proceeds from export sales in foreign bank accounts. The repeal of these
local enforcement authority at each province (typically a secretariat of energy
articles appears to formalize certain rules such as price controls and
or hydrocarbons board).
the repatriation of export sales proceeds, which has been in fact required
by the government over the last several years.
Regulatory framework
From the 1920s to 1989, the Argentine public sector dominated the upstream
In addition, the decree created the Strategic Planning and Coordination
segment of the Argentine oil and gas industry and the midstream and
Committee for the National Hydrocarbon Investment Plan, charged with
downstream segment of the business.
developing investment plans for the country to increase production
and reserves and to make Argentina more energy self-sufficient. The decree
In 1989, Argentina enacted certain laws aimed at privatizing the majority of
also requires oil and gas companies, refiners and transporters of hydrocarbon
its state-owned companies and issued a series of presidential decrees
products to submit annual investment plans for approval by the commission.
(namely, Decrees No. 1055/89, 1212/89 and 1589/89, or the Oil Deregulation
The decree empowers the commission to issue fines and sanctions,
Decrees, relating specifically to deregulation of energy activities). The Oil
including concession termination, for companies that do not comply with
Deregulation Decrees eliminated restrictions on imports and exports
its requirements. Finally, the Strategic Planning and Coordination Committee
of crude oil, deregulated the domestic oil industry, and effective January 1,
for the National Hydrocarbon Investment Plan is also charged with the
1991, the prices of oil and petroleum products were also deregulated.
responsibility of assuring the reasonableness of hydrocarbon prices in the
In 1992, Law No. 24,145, referred to as the Privatization Law, privatized YPF
domestic market and that such prices allow companies to generate a
and provided for transfer of hydrocarbon reservoirs from the Argentine
reasonable profit margin.
government to the provinces, subject to the existing rights of the holders
of exploration permits and production concessions.
Domain and Jurisdiction of hydrocarbons resources
After a constitutional reform enacted in 1994, eminent domain over
In October 2004, the Argentine Congress enacted Law No. 25,943, creating
hydrocarbon resources lying in the territory of a provincial state is now
a new state-owned energy company, Energía Argentina S.A., or ENARSA.
vested in such provincial state, while eminent domain over hydrocarbon
The corporate purpose of ENARSA is the exploration and exploitation of
resources lying offshore on the continental platform beyond the
solid, liquid and gaseous hydrocarbons; the transport, storage, distribution,
jurisdiction of the coastal provincial states is vested in the federal state.
commercialization and industrialization of these products; as well as
the transportation and distribution of natural gas, and the generation,
Thus, oil and gas exploration permits and exploitation concessions are now
transportation, distribution and sale of electricity. Moreover, Law No. 25,943
granted by each provincial government. A majority of the existing
granted ENARSA all offshore areas located beyond 12 nautical miles from
the coastline up to the outer boundary of the continental shelf that were
concessions were granted by the federal government prior to the enactment
of Law No. 26,197 and were thereafter transferred to the provincial states.
vacant at the time of the effectiveness of this law (i.e., November 3, 2004).
On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty
Regulation of exploration and production activities
The Argentine oil and gas industry is regulated by Law No. 17,319, referred
Act. This law declared achieving self-sufficiency in the supply of hydrocarbons,
to as the Hydrocarbons Law, which was adopted in 1967 and amended
as well as in the exploitation, industrialization, transportation and sale of
by Law No. 26,197 in 2007, which established the general legal framework
hydrocarbons, a national public interest and a priority for Argentina. In addition,
for the exploration and production of oil and gas. In turn, Law No. 24,076,
the law expropriated 51% of the share capital of YPF, the largest Argentine oil
referred to as the Natural Gas Law, enacted in 1992, established the
company, from Repsol, the largest Spanish oil company.
regulatory framework for natural gas transportation and distribution utilities
and the trading of natural gas. In addition, certain concurrent hydrocarbons
On July 28, 2012, Presidential Decree 1277/2012, which regulated the
laws were enacted by some provincial states. In Argentina, eminent domain
Hydrocarbon Sovereignty Law, was released, establishing that the Strategic
over hydrocarbon resources lying in the territory of a provincial state is
Planning and Coordination Committee for the National Hydrocarbon
now vested in such provincial state, while eminent domain over hydrocarbon
Investment Plan must be in charge of the sector’s reference prices. The
resources lying offshore on the continental platform beyond the jurisdiction
decree introduced important changes to the rules governing Argentina’s
of the coastal provincial states is vested in the federal state.
oil and gas industry. The decree repeals certain articles of Deregulation
GeoPark 20F 123
The Hydrocarbons Law authorizes the granting of hydrocarbon exploration
byproducts were capped or regulated. A series of other measures was also
permits made up of up to 3 exploration sub-periods for an aggregate term
adopted, affecting the downstream segment of the industry.
not exceeding 9 years (for onshore blocks) and 12 years (for offshore
blocks) plus certain extensions. The relinquishment of 50% of the exploration
acreage at the end of each exploration sub-period is mandatory. Upon a
Regulation of transportation activities
Exploitation concessionaires have the exclusive right to obtain a
commercial discovery, the holder of such exploration permits is entitled
transportation concession for the transport of oil and gas from the provincial
to apply for and obtain an exploitation concession to exploit such discovery
states or the federal government, depending on the applicable jurisdiction.
for a term of 25 years. Such exploitation concession can be extended for
Such transportation concessions include storage, ports, pipelines and
an additional term of 10 years as part of a concession renegotiation process
other fixed facilities necessary for the transportation of oil, gas and by-
with the incumbent provincial states. Article 59 of the Hydrocarbons Law
products. Transportation facilities with surplus capacity must transport third
provides that the concessionaire shall pay to the state a monthly royalty
parties’ hydrocarbons on an open-access basis, for a fee which is the same
of 12% of the net production of liquid and gaseous hydrocarbons at the well
for all users on similar terms. As a result of the privatizations of YPF and Gas
head, which may be reduced to as low as 5% depending on the productivity,
del Estado, a few common carriers of crude oil and natural gas were
conditions and locations of the wells. Royalties are generally paid in
chartered and continue to operate to date.
cash at the same price received by the producer at the well head, unless
the government gives proper notice of its intention to receive payment in
kind. Also, past the initial 25-year term of a concession, an incremental
Taxation
Exploitation concessionaires are subject to the general federal and provincial
royalty is generally required by the incumbent provincial state as part of
tax regime. The most relevant federal taxes are the income tax (35%), the
the renegotiation to grant the 10-year extension to a concession.
value added tax (21%) and a tax on assets. The most relevant provincial taxes
Because individual provinces are in charge of licensing and overseeing the
are the turnover tax (1% to 3%) and stamp tax. In 2002, in response to the
exploration and exploitation process, there is some variance between
economic crisis, the federal government adopted new taxes on oil and gas
individual provinces in terms of the regulations and royalty requirements
products, including export taxes ranging from 5% for by-products to 45% for
for concessionaires. Holders of exploration permits and exploitation
crude oil. Despite that, under certain incentives programs established in
concessions must also pay an annual surface fee that is based on acreage
2008 (namely, the Oil Plus Program and the Refining Plus Program created by
of land held and which varies depending on the phase (exploration or
Presidential Decree 2014/2008), oil and gas companies increasing their oil
production) of the operation.
reserves and production and refining companies increasing their production
would be granted tax rebate certificates to be credited against the payment
Regulation of refining and petrochemical activities
Refining and petrochemical activities in Argentina have historically been
of the export taxes. However, the Oil Plus Program and the Refining Plus
Program were suspended for certain companies in February 2012 and
governed by free enterprise and private refineries have coexisted with state-
subsequently amended and reinstated in June 2012.
owned refineries.
Until 1989, crude oil production, whether extracted by YPF or by private
Certain tax benefits apply to exploration programs in association with
ENARSA. Also, certain foreign exchange and regulatory benefits apply to
companies operating under service contracts, was delivered to YPF, and the
E&P programs in association with YPF qualifying for such benefits. Argentina
Secretariat of Energy distributed the same among the refining companies
has also implemented certain tax incentives to promote infrastructure
according to quotas. Natural gas production was until then also delivered to
and capital goods investments, including oil and gas production and
YPF and to the then existing stateowned Gas del Estado SE utility company.
transportation, including advanced reimbursement of value added tax and
accelerated income tax depreciation.
The Oil Deregulation Decrees issued in 1989 deregulated the hydrocarbons
industry and granted to the holders of hydrocarbon permits and concessions
the right to freely dispose of the hydrocarbons lifted by them at free market
conditions, and abrogated the previous quota allocation system.
After the economic crisis of 2001 and 2002, hydrocarbons refiners and
producers were prompted by the Argentine Government to enter into a series
of tripartite agreements whereby the prices of crude oil and certain
124 GeoPark 20F
C. Organizational structure
We are an exempted company incorporated pursuant to the laws of Bermuda.
We operate and own our assets directly and indirectly through a number of
subsidiaries.
The following chart shows our main corporate structure as of the date of this
annual report.
99.9%
99.9%
100%
100%
99.9%
GeoPark Limited
(Bermuda)
GeoPark Colombia
Coöperatie U.A.
(Netherlands)
1%
GeoPark Latin
America
Limited – Bermuda
(Bermuda)
100%
GeoPark Latin
America Limited
Agencia en Chile
(Chile)
GeoPark Argentina
Limited – Bermuda
(Bermuda)
100%
GeoPark Argentina
Limited -
Argentinean
Branch (Argentina)
GeoPark Latin
America Coöperatie
U.A.
(Netherlands)
80%
GeoPark Colombia
Coöperatie U.A.
(Netherlands)
20%
LG
International
GeoPark Brazil
Coöperatie U.A.
(Netherlands)
99.9%
GeoPark Brazil
Exploração e
Produção de Petróleo
e Gás Ltda. (Brazil)
99.9%
Rio Das Contas
Produtora de
Petróleo Ltda.
(Brazil)
80%
99.9%
100%
80%
100%
LG
International
20%
GeoPark Chile S.A.
(Chile)
GeoPark S.A.
(Chile)
GeoPark Brazil
SpA. (Chile)
GeoPark Colombia
S.A. (Chile)
GeoPark Colombia
SAS (Colombia)
14%
86%
100%
99%
GeoPark TdF S.A.
(Chile)
GeoPark Fell SpA.
(Chile)
GeoPark
Magallanes
Limitada (Chile)
99.9%
Servicios Southern
Cross Limitada
(Chile)
D. Property, plant and equipment
See “—B. Business Overview—Title to properties”.
Bermuda Companies
Chilean Companies
Argentinean Companies
Colombian Companies
Brazilean Companies
Netherlands Companies
GeoPark 20F 125
ITEM 4A. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
A. Operating results
The following discussion of our financial condition and results of operations
should be read in conjunction with our Consolidated Financial Statements
and Argentina, respectively) for the year 2013, consisting of US$133.3 million
related to exploration, including approximately 1,350 sq. km. in 3D seismic
surveys (more than 1,100 in Chile, mainly related to the blocks located
in Tierra del Fuego and over 250 in Colombia).
In March 2014 we invested US$140 million in Brazil, subject to certain
adjustments, to acquire Rio das Contas, which we financed through the
incurrence of a loan of US$70.5 million and cash on hand.
and the notes thereto, the Rio das Contas Financial Statements included
In 2014, we expect our total capital expenditures, excluding the purchase
elsewhere in this annual report, as well as the information presented under
price for our Rio das Contas acquisition, to be between US$220 million to
“Item 3. Key Information—A. Selected financial data” and “Item 3. Key
US$250 million, of which approximately 62%, 32% and 5% will be in Chile,
Information—A. Selected financial data—Unaudited Condensed Combined
Colombia and Brazil, respectively. These capital expenditures will include the
Pro Forma Financial Data.”
drilling of 50 to 60 new wells (approximately 40% of which we expect will
be exploratory wells), as well as workovers, seismic surveys and new facility
The following discussion contains forward-looking statements that involve
construction. In Brazil, we expect our capital expenditures will consist
risks and uncertainties. Our actual results may differ materially from those
of between US$5 million to US$7.5 million to finance in part the construction
discussed in the forward-looking statements as a result of various factors,
of a gas compression plant in the Manatí Field we acquired as part of the
including those set forth in “Item 3. Key Information—D. Risk factors” and
Rio das Contas acquisition and approximately US$0.45 million in license
“Forward-looking statements.”
fee payments to the ANP relating to our Round 12 concessions, with
the remainder for seismic surveys in exploration blocks in the Potiguar
Factors affecting our results of operations
We describe below the year-to-year comparisons of our historical results
and Recôncavo Basins.
and the analysis of our financial condition. Our future results could
Our results of operations will be adversely affected in the event that our
differ materially from our historical results due to a variety of factors,
estimated oil and natural gas asset base does not result in additional reserves
including the following:
that may eventually be commercially developed. In addition, there can be
no assurance that we will acquire new exploration blocks or gain access
Discovery and exploitation of reserves
Our results of operations depend on our level of success in finding, acquiring
to exploration blocks that contain reserves. Unless we succeed in exploration
and development activities, or acquire properties that contain new reserves,
(including through bidding rounds) or gaining access to oil and natural
our anticipated reserves will continually decrease, which would have a material
gas reserves. While we have geological reports evaluating certain proved,
adverse effect on our business, results of operations and financial condition.
contingent and prospective resources in our blocks, there is no assurance that
we will continue to be successful in the exploration, appraisal, development
and commercial production of oil and natural gas. The calculation of our
Oil and gas revenue and international prices
Our revenues are derived from the sale of our oil and natural gas production,
geological and petrophysical estimates is complex and imprecise, and it is
as well as of condensate derived from the production of natural gas.
possible that our future exploration will not result in additional discoveries,
Our oil and natural gas prices are driven by the international prices of oil
and, even if we are able to successfully make such discoveries, there is no
and methanol (for our Chilean gas production), respectively, which are
certainty that the discoveries will be commercially viable to produce. We have
denominated in U.S. dollars. The price realized for the oil we produce is
been able to successfully develop our assets through drilling, with 70%, or
linked to WTI and Brent, U.S. dollar denominated international benchmarks.
106, of the 152 exploratory, appraisal and development wells that we drilled
The price realized for the natural gas we produce in Chile is linked to the
from January 1, 2006 through December 31, 2013 becoming productive wells.
international price of methanol, which is settled in the international markets
in U.S. dollars. The market price of these commodities is subject to significant
For the year ended December 31, 2013, we drilled 39 new wells 17 in Chile
fluctuation and has historically fluctuated widely in response to relatively
and 22 in Colombia) in blocks in which we have working interests and/or
minor changes in the global supply and demand for oil and natural gas,
economic interests. We made total capital expenditures of US$228.0 million
market uncertainty, economic conditions and a variety of additional factors.
(US$145.7 million, US$82.1 million and US$0.2 million in Chile, Colombia
126 GeoPark 20F
For example, from January 1, 2010 to December 31, 2013, NYMEX WTI
constant, after-tax profit for the year ended December 31, 2013 would have
crude oil contracts prices ranged from a low of US$64.78 per bbl to a high of
been lower by US$21.2 million (US$18.8 million in 2012).
US$113.39 per bbl, Henry Hub natural gas average monthly spot prices
ranged from a low of US$1.82 per mmbtu to a high of US$7.51 per mmbtu,
In Brazil, prices for gas produced in the Manatí Field are based on a long-term
US Gulf methanol spot barge prices ranged from a low of US$324.61 per
off-take contract with Petrobras. For the year ended December 31, 2013, Rio
metric ton to a high of US$530.71 per metric ton and Brent spot prices ranged
das Contas’s average sale price was US$38.2/boe. The price of gas sold under
from a low of US$67.18 per barrel to a high of US$128.14 per barrel. We have
this contract is denominated in reais and is adjusted annually for inflation
historically not hedged our production to protect against fluctuations in the
pursuant to the Brazilian General Market Price Index (Índice Geral de Preços—
international oil prices.
Mercado), or IGPM.
Additionally, the oil and gas we sell may be subject to certain discounts. For
instance, in Chile, the price of oil we sell to ENAP is based on WTI minus
Production costs
Our production costs consist primarily of expenses associated with the
certain marketing and quality discounts based on, among other things, API
production of oil and gas, the most significant of which are gas plant leasing,
and mercury content. Mercury content can vary depending on the geology
facilities and wells maintenance (including pulling works), labor costs,
and features in each field. For the years ended December 31, 2013 and 2012,
contractor and consultant fees, chemical analysis, royalties and products,
these discounts resulted in average price deductions of US$13.11 per bbl
among others. As commodity prices increase, our production costs may
and US$9.35 per bbl, respectively, and realized prices of US$84.3 per bbl and
increase. We have historically not hedged our costs to protect against
US$85.4 per bbl, respectively. Furthermore, the price formula also considers
fluctuations.
adjustments for differences between the WTI and Brent at certain price levels.
We have a long-term gas supply contract with Methanex. The price of the gas
Availability and reliability of infrastructure
Our business depends on the availability and reliability of operating and
sold under this contract is determined based on a formula that takes into
transportation infrastructure in the areas in which we operate. Prices and
account various international prices of methanol, including US Gulf methanol
availability for equipment and infrastructure, and the maintenance thereof,
spot barge prices, methanol spot Rotterdam prices and spot prices in Asia.
affect our ability to make the investments necessary to operate our business,
See “Item 3. Key Information—D. Risk factors—Risks relating to our
and thus our results of operations and financial condition. See “Item 3. Key
business—A substantial or extended decline in oil, natural gas and methanol
Information—D. Risk factors—Risks relating to our business—Our inability
prices may materially adversely affect our business, financial condition or
to access needed equipment and infrastructure in a timely manner may
results of operations.” As of the date of this annual report, we had not entered
hinder our access to oil and natural gas markets and generate significant
into any derivative arrangements or contracts to mitigate the impact on our
incremental costs or delays in our oil and natural gas production.”
results of operations of fluctuations in commodity prices.
In order to mitigate the risk of unavailability of operating and transportation
In Colombia, the price of oil we sell is based on Brent, adjusted for certain
marketing and quality discounts based on, among other things, API, viscosity,
infrastructure, we have invested in the construction of plant and pipeline
infrastructure to produce, process and store hydrocarbon reserves and to
sulfur, delivery point and water content, as well as on certain transportation
transport them to market. In the Fell Block, for example, we have constructed
costs (including pipeline costs and trucking costs). The delivery points for our
over 120 km of pipeline and a gas plant with a processing and compression
production range from the well head to the port of export (Coveñas), depend
capacity of 35.3 mmcfpd. We also constructed an oil treatment plant with a
on the client: if sales are made via pipeline, the delivery point is usually
processing capacity of 9,500 bopd to service oil produced in the Fell Block,
the pipeline injection point, whereas for direct export sales, the most frequent
which became operative in November 2013 and which, following a test period,
delivery point is the well head . As a result, our average realized price for the
we expect will be operated at full capacity by the end of November 2014.
year ended December 31, 2013 was US$80.3 per bbl. Our oil sales contracts in
Colombia are short-term agreements and do not commit the parties to a
minimum volume, and are subject to the ability of either party to receive or
deliver the production, as applicable.
Production levels
Our oil and gas production levels are heavily influenced by our drilling results,
our acquisitions and, to a lesser extent, oil and natural gas prices. Since being
awarded 100% of the working interest in the Fell Block in 2006, and through
If the market prices of WTI, Brent and methanol had fallen by 10% as
December 31, 2013, we have drilled 95 exploratory, appraisal and development
compared to actual prices during the year, with all other variables held
wells in the Fell Block, with 73%, or 69, of such wells becoming productive.
GeoPark 20F 127
Production at the Fell Block has increased from 3,292 boepd in 2008 to 6,962
administrative costs to increase as a result of our Brazil Acquisitions, and
boepd as of December 31, 2013. Since acquiring our Colombian operations and
as a result of becoming a publicly traded company in the United States. Public
through December 31, 2013, 46 exploratory, appraisal and development wells
company costs include expenses associated with our annual and quarterly
have been drilled in blocks in which we have working interests and/or
reporting, investor relations, registrar and transfer agent fees, incremental
economic interests, with 70% of such wells becoming productive. Production
insurance costs and accounting and legal services.
in our Colombian operations has increased from 2,965 boepd for the month
of April 30, 2012 (the first full month following our Colombian acquisitions) to
6,491 boepd for the year ended December 31, 2013.
Acquisitions
Our results of operations are significantly affected by our past acquisitions.
We generally incorporate our acquired business into our results of operations
We expect that fluctuations in our financial condition and results of
at or around the date of closing, such as our Colombian acquisitions in 2012
operations will be driven by the rate at which production volumes from
and our recently acquired Rio das Contas (which we closed on March 31,
our wells decline. As initial reservoir pressures are depleted, oil and gas
2014), which limits the comparability of the period including such
production from a given well will decline over time. See “Item 3. Key
acquisitions with prior periods. See “Item 3. Key Information—A. Selected
Information—D. Risk factors—Risks relating to our business—Unless we
financial data—Unaudited Condensed Combined Pro Forma Financial Data”
replace our oil and natural gas reserves, our reserves and production
for a pro forma analysis of our financial condition and results of operations.
will decline over time. Our business is dependent on our continued
successful identification of productive fields and prospects and the identified
As described above, part of our strategy is to acquire and consolidate assets
locations in which we drill in the future may not yield oil or natural gas in
in Latin America. We intend to continue to selectively acquire companies,
commercial quantities.”
producing properties and concessions. As with our historical acquisitions,
any future acquisitions could make year-to-year comparisons of our results
Contractual obligations
In order to protect our exploration and production rights in our license areas,
of operations difficult. We may also incur substantial debt, issue additional
equity securities or use other funding sources to fund future acquisitions.
we must make and declare discoveries within certain time periods specified
in our various special contracts, E&P Contracts and concession agreements.
The costs to maintain or operate our license areas may fluctuate or increase
Functional and presentational currency
Our Consolidated Financial Statements are presented in U.S. dollars, which
significantly, and we may not be able to meet our commitments under
is our functional and presentational currency. Items included in the financial
these agreements on commercially reasonable terms or at all, which may
information of each of our entities are measured using the currency of the
force us to forfeit our interests in such areas. If we do not succeed in renewing
primary economic environment in which the entity operates, or the functional
these agreements, or in securing new ones, our ability to grow our business
currency, which is the U.S. dollar in each case, except for our Brazil operations,
may be materially impaired. See “Item 3. Key Information—D. Risk factors—
including our recent Rio das Contas acquisition, where the functional
Risks relating to our business—Under the terms of some of our various
currency is the real.
CEOPs, E&P Contracts and concession agreements, we are obligated to drill
wells, declare any discoveries and file periodic reports in order to retain our
rights and establish development areas. Failure to meet these obligations
Geographical segment reporting
We divide our business into four geographical segments—Chile, Colombia,
may result in the loss of our interests in the undeveloped parts of our blocks
Brazil and Argentina—that correspond to our principal jurisdictions of
or concession areas.”
operation. Activities not falling into these four geographical segments are
reported under a separate corporate segment that primarily includes
Administrative costs
Our administrative costs increased by US$10.6 million, or 59%, from 2011 to
certain corporate administrative costs not attributable to another segment.
As of December 31, 2013, our Chilean segment contributed US$157.5 million,
2012, a significant portion of which was attributable to our acquisitions of
or 46.5%, of our revenues, our Colombian segment contributed US$179.3
Winchester, Luna and Cuerva in the first quarter of 2012. Our administrative
million, or 53.0%, of our revenues and our Argentine segment contributed
costs for the year ended December 31, 2013 increased by US$17.8 million,
US$1.5 million, or 0.5%, of our revenues. On a pro forma basis, our
or 61.8%, compared to the year ended December 31, 2012. This increase was
Brazil Acquisitions represented 12.5% of our revenues for the year ended
primarily due to (i) higher corporate expenses related to our growth strategy
December 31, 2013.
and new business efforts, (2) increased staff costs in Colombia, and (iii) the
start-up of our operations in Tierra del Fuego, Chile. Furthermore, we expect
128 GeoPark 20F
In the description of our results of operations that follow, our “Other”
operations reflect our non-Chilean and non-Colombian operations, primarily
Administrative costs
Administrative costs consist of corporate costs such as director fees and
consisting of our Argentine, Brazilian (mainly related to the start-up of our
travel expenses, new project evaluations and back-office expenses principally
operations in such country) and corporate head office operations.
comprised of wages and salaries, share-based compensation, consultant fees
and other administrative costs, including certain costs relating to acquisitions.
Description of principal line items
The following is a brief description of the principal line items of our statement
of income.
Selling expenses
Selling expenses consist primarily of transportation and storage costs.
Net revenue
Net revenue includes the sale of crude oil, condensate and natural gas net
Financial results, net
Financial results, net consists of financial income offset by financial expenses.
of value-added tax, or VAT, and discounts related to the sale (such as API and
Financial income includes interest received from bank time deposits and
mercury adjustments) and overriding royalties due to the ex-owners of oil
the effect of exchange rate differences. Financial expenses principally include
and gas properties where the royalty arrangements represent a retained
interest expense not subject to capitalization, bank charges, the effect
working interest in the property. Revenue is recognized when the significant
of exchange rate differences and the unwinding of long-term liabilities.
risks and rewards of ownership have been transferred to the buyer, the
associated costs and amount of revenue can be estimated reliably, recovery
of the consideration is probable, and there is no continuing management
Profit for the period attributable to owners of the Company
Profit for the period attributable to owners of the Company consists of profit
involvement with the goods.
for the year less non-controlling interest.
Production costs
For a description of our production costs, see “—Factors affecting our results
2014 Drilling and Work Program
In March 2014, we invested US$140 million in Brazil, subject to certain
of operations.”
adjustments, to acquire Rio das Contas, which we financed through
the incurrence of a loan of US$70.5 million and cash on hand.
Capitalized costs of proved oil and natural gas properties are depreciated on
a licensed-area-by-licensed-area basis, using the unit of production method,
In 2014, we expect our total capital expenditures, excluding the purchase
based on commercial proved and probable reserves as calculated under
price for our Rio das Contas acquisition, to be between US$220 million to
the Petroleum Resources Management System methodology promulgated
US$250 million. These capital expenditures will include the drilling of a total
by the Society of Petroleum Engineers and the World Petroleum Council,
50 to 60 new wells (approximately 40% of which we expect will be
or the PRMS, which differs from SEC reporting guidelines pursuant to which
exploratory wells), as well as workovers, seismic surveys and new facility
certain information in the forepart of this annual report is presented.
construction. We expect that approximately 62% of our total capital
The calculation of the “unit of production” depreciation takes into account
estimated future discovery and development costs. Changes in reserves
expenditures for 2014 will be incurred in Chile, which will include the drilling
of approximately 32 to 37 wells, as well as workovers, seismic surveys and
and cost estimates are recognized prospectively. Reserves are converted to
new facility construction, including oil pipelines. We expect that
equivalent units on the basis of approximate relative energy content.
approximately 32% of our total capital expenditures for 2014 will be incurred
Exploration costs
Exploration costs consist of geosciences costs, including wages and salaries
in Colombia, which will include the drilling of approximately 18 to 23 wells,
as well as workovers and new facility construction, mainly related to civic
works, production facilities in the Tua and Tigana fields and improvements
and share-based compensation not subject to capitalization, impairment
to the Taro Taro and Max field facilities. Finally, we expect that approximately
losses, write-offs of unsuccessful exploration efforts, geological consultancy
5% of our total capital expenditures for 2014 will be incurred in Brazil,
costs and costs relating to independent reservoir engineer studies. In
which will consist of between US$5 million to US$7.5 million to finance in
particular, upon completion of the evaluation phase, a prospect is either
part the construction of a gas compression plant in the Manatí Field
transferred to oil and gas properties if it contains reserves, or is charged as
after the Rio das Contas acquisition and approximately US$0.45 million in
exploration costs in the period in which the determination is made. See “—
license fee payments to the ANP relating to our Round 12 concessions,
Critical accounting policies and estimates—Oil and gas accounting.”
with the remainder for seismic surveys in exploration blocks in the Potiguar
and Recôncavo Basins.
GeoPark 20F 129
Critical accounting policies and estimates
We prepare our Consolidated Financial Statements in accordance with IFRS
and the interpretations of the IFRS Interpretations Committee, or the IFRIC,
Cash flow estimates for impairment assessments
Cash flow estimates for impairment assessments require assumptions about
as adopted by the IASB. The preparation of the financial statements requires
two primary elements: future prices and reserves. Estimates of future prices
us to make judgments, estimates and assumptions that affect the reported
require significant judgments about highly uncertain future events.
amounts of assets, liabilities, revenue and expenses, and related disclosure
Historically, oil and natural gas prices have exhibited significant volatility.
of contingent assets and liabilities. We continually evaluate these estimates
Our forecasts for oil and natural gas revenues are based on prices derived
and assumptions based on the most recently available information, our own
from future price forecasts among industry analysts, as well as our own
historical experience and various other assumptions that we believe to be
assessments. Estimates of future cash flows are generally based on
reasonable under the circumstances. Since the use of estimates is an integral
assumptions of long-term prices and operating and development costs.
component of the financial reporting process, actual results could differ
from those estimates.
The process of estimating reserves requires significant judgments
and decisions based on available geological, geophysical, engineering and
An accounting policy is considered critical if it requires an accounting
economic data. The estimation of economically recoverable oil and natural
estimate to be made based on assumptions about matters that are highly
gas reserves and related future net cash flows was performed based
uncertain at the time such estimate is made, and if different accounting
on the D&M Reserves Report. Such estimates incorporate many factors and
estimates that reasonably could have been used, or changes in the
assumptions including:
accounting estimates that are reasonably likely to occur periodically, could
materially impact the financial statements. We believe that the following
• expected reservoir characteristics based on geological, geophysical and
accounting policies represent critical accounting policies as they involve a
engineering assessments;
higher degree of judgment and complexity in their application and require
• future production rates based on historical performance and expected
us to make significant accounting estimates. The following descriptions
future operating and investment activities;
of critical accounting policies and estimates should be read in conjunction
• future oil and natural gas prices and quality differentials;
with our Consolidated Financial Statements and the accompanying notes
• anticipated effects of regulation by governmental agencies; and
and other disclosures included elsewhere in this annual report.
• future development and operating costs.
Business combinations
Business combinations are accounted for using the acquisition method.
Our management believes these factors and assumptions are reasonable
based on the information available at the time we prepare our estimates.
The cost of an acquisition is measured as the fair market value of the assets
However, these estimates may change substantially as additional data
acquired, equity instruments issued and liabilities incurred or assumed on
from ongoing development activities and production performance becomes
the date of completion of the acquisition. Acquisition costs incurred are
available and as economic conditions impacting oil and natural gas prices
expensed and included in administrative expenses. Identifiable assets acquired
and liabilities and contingent liabilities assumed in a business combination
and costs change.
are measured initially at their fair market values at the acquisition date. The
excess of the cost of acquisitions over fair market value of a company’s share
Oil and gas accounting
Oil and gas exploration and production activities are accounted for in
of the identifiable net assets acquired is recorded as goodwill. If the cost
accordance with the successful efforts method on a field by field basis. We
of the acquisition is less than a company’s share of the net assets required,
account for exploration and evaluation activities in accordance with IFRS 6,
the difference is recognized directly in the statement of income.
Exploration for and Evaluation of Mineral Resources, capitalizing exploration
The determination of fair value of identifiable acquired assets and assumed
the underlying resources is determined. Costs incurred prior to obtaining
liabilities means that we are to make estimates and use valuation techniques,
legal rights to explore are expensed immediately to the income statement.
and evaluation costs until such time as the economic viability of producing
including independent appraisers. The valuation assumptions underlying
each of these valuation methods are based on available updated information,
Exploration and evaluation costs may include: license acquisition, geological
including discount rates, estimated cash flows, market risk rates and other
and geophysical studies (i.e., seismic), direct labor costs and drilling
data. As a result, the process of identification and the related determination
costs of exploratory wells. No depreciation and/or amortization are charged
of fair values require complex judgments and significant estimates.
during the exploration and evaluation phase. Upon completion of the
130 GeoPark 20F
evaluation phase, the prospects are either transferred to oil and gas
assumptions and judgments because most of the obligations will be settled
properties or charged to expense (exploration costs) in the period in which
after many years. Technologies and costs are constantly changing, as are
the determination is made, depending whether they have found reserves.
political, environmental, health, safety and public relations considerations.
If not developed, exploration and evaluation assets are written off after
Consequently, the timing and future cost of dismantling and abandonment
three years, unless it can be clearly demonstrated that the carrying value of
are subject to significant modification. Any change in the variables underlying
the investment is recoverable. All field development costs are considered
our assumptions and estimates can have a significant effect on the liability
construction in progress until they are finished and capitalized within oil and
and the related capitalized asset and future charges related to the retirement
gas properties, and are subject to depreciation once complete. Such costs
obligations. The present value of future costs necessary for well plugging and
may include the acquisition and installation of production facilities,
abandonment is calculated for each area on the basis of cash flows
development drilling costs (including dry holes, service wells and seismic
discounted at an average interest rate applicable to our company’s
surveys for development purposes), project-related engineering and the
indebtedness. The liability recognized is based upon estimated future
acquisition costs of rights and concessions related to proved properties.
abandonment costs, wells subject to abandonment, time to abandonment,
Workovers of wells made to develop reserves and/or increase production
are capitalized as development costs. Maintenance costs are charged
to income when incurred.
and future inflation rates.
Share-based payments
We provide several equity-settled, share-based compensation plans to certain
employees and third-party contractors, composed of payments in the form
Capitalized costs of proved oil and gas properties and production facilities
of share awards and stock options plans.
and machinery are depreciated on a licensed area by licensed area basis,
using the unit of production method, based on commercial proved and
Fair value of the stock option plans for employee or contractor services
probable reserves. The calculation of the “unit of production” depreciation
received in exchange for the grant of the options is recognized as an expense.
takes into account estimated future finding and development costs, and
The total amount to be expensed over the vesting period, which is the
is based on current year-end unescalated price levels. Changes in reserves
period over which all specified vesting conditions are to be satisfied, is
and cost estimates are recognized prospectively. Reserves are converted
determined by reference to the fair value of the options granted calculated
to equivalent units on the basis of approximate relative energy content.
using the Black-Scholes model. Determining the total value of our share-
based payments requires the use of highly subjective assumptions, including
Oil and gas reserves for purposes of our Audited Consolidated Financial
the expected life of the stock options, estimated forfeitures and the price
Statements are determined in accordance with PRMS, and were estimated
volatility of the underlying shares. The assumptions used in calculating the
by D&M, independent reserves engineers.
fair value of share-based payment represent management’s best estimates,
but these estimates involve inherent uncertainties and the application of
Depreciation of the remaining property, plant and equipment assets
management’s judgment.
(i.e., furniture and vehicles) not directly associated with oil and gas activities
has been calculated by means of the straight line method by applying such
Non-market vesting conditions are included in assumptions in respect of
annual rates as required to write-off their value at the end of their estimated
the number of options that are expected to vest. At each balance sheet date,
useful lives. The useful lives range between three and 10 years.
we revise our estimates of the number of options that are expected to vest.
Asset retirement obligations
Obligations related to the plugging and abandonment of wells once
We recognize the impact of the revision to original estimates, if any, in the
statement of income, with a corresponding adjustment to equity.
operations are terminated may result in the recognition of significant
The fair value of the share awards payments is determined at the grant date
liabilities. We record the fair value of the liability for asset retirement
by reference of the market value of the shares and recognized as an expense
obligations in the period in which the wells are drilled. When the liability
over the vesting period.
is initially recognized, the cost is also capitalized by increasing the carrying
amount of the related asset. Over time, the liability is accreted to its
When options are exercised, we issue new common shares. The proceeds
present value at each reporting date, and the capitalized cost is depreciated
received net of any directly attributable transaction costs are credited
over the estimated useful life of the related asset. Estimating the future
to share capital (nominal value) and share premium when the options are
abandonment costs is difficult and requires management to make
exercised.
GeoPark 20F 131
Taxation
The computation of our income tax expense involves the interpretation
of applicable tax laws and regulations in many jurisdictions. The resolution
of tax positions taken by us, through negotiations with relevant tax
authorities or through litigation, can take several years to complete and in
some cases it is difficult to predict the ultimate outcome.
Revenue
Net oil sales
Net gas sales
In addition, we have tax-loss carry-forwards in certain taxing jurisdictions that
Net revenue
are available to offset against future taxable profit. However, deferred tax
Production costs
assets are recognized only to the extent that it is probable that taxable profit
will be available against which the unused tax losses can be utilized.
Management judgment is exercised in assessing whether this is the case.
Gross profit
Gross margin (%)(1)
Exploration costs
Administrative costs
To the extent that actual outcomes differ from management’s estimates,
Selling expenses
taxation charges or credits may arise in future periods.
Other operating income/(expense)
Recent accounting pronouncements
See note 2.1.1 to our Consolidated Financial Statements beginning on page
178 to this annual report.
Results of operations
The following discussion is of certain financial and operating data for the
periods indicated. You should read this discussion in conjunction with
our Consolidated Financial Statements and the accompanying notes included
Operating profit
Financial income
Financial expenses
Bargain purchase gain on
acquisition of subsidiaries
Profit before income tax
Income tax
Profit for the year
Non-controlling interest
elsewhere in this annual report.
Profit for the year attributable to
We acquired Winchester and Luna on February 14, 2012 and Cuerva on
March 27, 2012. Accordingly, our results for the year ended December 31,
owners of the Company
Net production volumes
Oil (mbbl)
2013 and 2012 are not fully comparable with prior periods. For accounting
Gas (mcf)
purposes, the results of operations of Winchester, Luna and Cuerva were
Total net production (mboe)
For the year ended % Change
December 31,
from prior
2013
2012
year
(in thousands of US$, except for percentages)
315,435
22,918
338,353
(179,643)
221,564
28,914
250,478
(129,235)
158,710
121,243
47%
(16,254)
(46,584)
(17,252)
5,344
83,964
4,893
48%
(27,890)
(28,798)
(24,631)
823
40,747
892
(38,769)
(17,200)
-
50,088
(15,154)
34,934
12,922
8,401
32,840
(14,394)
18,446
6,567
42%
(21)%
35%
39%
31%
(1)%
(42)%
62%
(30)%
549%
106%
449%
125%
—
53%
5%
89%
97%
22,012
11,879
85%
4,056
5,263
4,933
2,513
8,346
3,904
consolidated into our financial statements beginning on January 31, 2012,
Average net production (boepd)
13,517
11,292
January 31, 2012 and March 31, 2012, respectively. See Note 34 to our
Annual Consolidated Financial Statements.
In addition, our Consolidated Financial Statements will not be fully
comparable with our consolidated financial statements prepared for any
period following the date upon which we fully consolidate Rio das Contas
into our operations for accounting purposes, which will occur in the second
quarter of 2014. See “Presentation of Financial and Other Information.”
Average realized sales price
Oil (US$ per bbl)
Gas (US$ per mmcf)
Average unit costs per boe (US$)
Operating cost
Royalties and other
Production costs(2)
Depreciation
Total production cost
Year ended December 31, 2013 compared to year ended December 31, 2012
Exploration costs
Administrative costs
The following table summarizes certain of our financial and operating data for
Selling expenses
the years ended December 31, 2013 and 2012.
81.9
5.0
19.0
3.5
22.5
13.9
36.4
3.3
9.4
3.5
90.5
4.0
16.8
2.9
19.7
13.4
33.1
7.1
7.4
6.3
(1) Gross margin is defined as total revenue minus production costs, divided
by total revenue.
(2) Calculated pursuant to FASB ASC 932.
132 GeoPark 20F
61%
(37)%
26%
20%
(10)%
25%
13%
21%
14%
4%
10%
(54)%
27%
(44)%
The following table summarizes certain financial and operating data.
Net revenue
Gross profit/(loss)
Depreciation
Impairment and write-off
Chile
Colombia
Other
157,491
89,906
(30,471)
(7,704)
179,324
67,612
(39,406)
(3,258)
1,538
1,192
(323)
—
2013
Total
338,353
158,710
(70,200)
(10,962)
For the year ended December 31,
Chile
Colombia
Other
2012
Total
149,927
84,133
(28,734)
(18,490)
99,501
39,304
(21,050)
(5,147)
(in thousands of US$)
1,050
(2,194)
(3,533)
(1,915)
250,478
121,243
(53,317)
(25,552)
Net revenue
For the year ended December 31, 2013, crude oil sales were our principal
source of revenue, with 93% and 7% of our total revenue from crude oil and
gas sales, respectively. The following chart shows the change in oil and
natural gas sales from the year ended December 31, 2012 to the year ended
December 31, 2013.
For the year ended December 31,
2013
2012
(in thousands of US$)
315,435
22,918
221,564
28,914
338,353
250,478
Year ended
December 31,
Change from prior year
2013
2012
%
(in thousands of US$, except for percentages)
157,491
179,324
1,538
149,927
99,501
1,050
7,564
79,823
488
338,353
250,478
87,875
5%
80%
46%
35%
Consolidated
Sale of crude oil
Sale of gas
Total
By country
Chile
Colombia
Other
Total
GeoPark 20F 133
Net revenue increased 35%, from US$250.5 million for the year ended
compared to the same period in 2012, and (ii) the development of the
December 31, 2012 to US$338.4 million for the year ended December 31,
Max and Tua fields and our discoveries of the Tarotaro field in the Llanos 34
2013, primarily as a result of an increase in volumes of crude sales by 55%.
Block and the Potrillo field in the Yamú Block. This was partially offset by
Sales of crude oil in operated blocks increased to 3,800 mbbl in the year
a decrease in the average realized prices per barrel of crude oil from US$97.1
ended December 31, 2013 compared to 2,448 mbbl in the year ended
per barrel to US$80.3 per barrel, primarily due to the fact that in 2013 we
December 31, 2012, and resulted in net revenue of US$315.4 million for the
started selling part of our oil production at well-head with higher commercial
year ended December 31, 2013 compared to US$221.6 million for the year
discounts, as opposed to transporting it to different delivery points, which
ended December 31, 2012, partially offset by decreases in sales of gas from
led to lower selling expenses that offset the lower selling prices.
US$28.9 million for the year ended December 31, 2012 to US$22.9 million
for the year ended December 31, 2013.
Production costs
The following table summarizes our production costs for the years ended
The increase in 2013 net revenue of US$87.8 is mainly explained by:
December 31, 2013 and 2012.
• an increase of US$79.8 million in oil sales in Colombia
• an increase of US$13.6 million in oil sales in Chile, partially offset by a
decrease of US$6.0 million in gas deliveries in Chile.
Net revenue attributable to our operations in Chile for the year ended
December 31, 2013 was US$157.5 million, a 5% increase from US$149.9
million for the year ended December 31, 2012, principally due to (1) increased
For the year ended % Change
from prior
December 31,
2013
2012
year
(in thousands of US$, except for percentages)
Consolidated
(including Chile, Colombia and Argentina)
sales of crude oil of 1,592 mbbl for the year ended December 31, 2013
Depreciation
compared to 1,415 mbbl for the year ended December 31, 2012 (an increase
Royalties
of 12.5%) due to the continuing development in the Tobifera formation, and
Staff costs
(2) decreased average realized prices per barrel of crude oil from US$85.4 per
Transportation costs
barrel for the year December 31, 2012 to US$84.3 per barrel for the year
Well and facilities maintenance
ended December 31, 2013 (a decrease of US$1.1 per barrel or a total of 1.3%).
Consumables
The decrease in the average realized price per barrel was partly attributable
Equipment rental
to quality discounts in the year ended December 31, 2013 as compared to the
Other costs
(68,579)
(17,239)
(14,202)
(11,392)
(20,662)
(14,855)
(7,139)
(25,575)
(52,307)
(11,424)
(14,171)
(7,211)
(9,385)
(9,884)
(5,936)
(18,917)
same period in 2012. The net increased sales of crude oil were partially offset
Total
(179,643)
(129,235)
31%
51%
0%
58%
120%
50%
20%
35%
39%
by a US$6.0 million reduction in gas sales mainly driven by a decrease of 37%
in production in the year ended December 31, 2013, partially compensated
by higher average gas prices. The contribution to our net revenue during
such years from our operations in Chile was 47% and 60%, respectively.
Net revenue attributable to our operations in Colombia for the year ended
December 31, 2013 was US$179.3 million, compared to US$99.5 million for
the year ended December 31, 2012, representing 53% and 40% of our total
By country
Depreciation
consolidated sales. Such amounts were primarily due to increased sales
Royalties
of crude oil in operated blocks, from 1,087 mbbl for the year ended December
Staff costs
31, 2012 to 2,185 mbbl for the year ended December 31, 2013, an increase
Transportation costs
of 101%. This increase resulted from (i) the incorporation of an additional
Well and facilities
three months of Cuerva’s results in the year ended December 31, 2013 and
maintenance
the incorporation of an additional month of Winchester and Luna’s
Consumables
operations (the revenues for the corresponding period that were not included
Equipment rental
in the year ended December 31, 2012 amounted to US$23.8 million) as
Other costs
2013
Colombia
Chile
Year ended December 31,
2012
Colombia
Chile
(in thousands of US$)
(29,287)
(39,233)
(28,120)
(20,964)
(7,384)
(6,508)
(6,456)
(8,163)
(1,891)
—
(7,896)
(9,661)
(8,988)
(4,733)
(12,105)
(12,886)
(7,139)
(16,967)
(7,088)
(8,560)
(5,986)
(6,290)
(2,717)
—
(4,164)
(7,432)
(1,045)
(2,850)
(7,090)
(5,936)
(7,033)
(10,716)
Total
(67,585)
(111,712)
(65,794)
(60,197)
134 GeoPark 20F
Production costs increased 39%, from US$129.2 million for the year ended
Chilean operations. As a result, gross margin for the year ended December 31,
December 31, 2012 to US$179.6 million for the year ended December 31,
2013 was 47%, which represented a slight decrease of 3% as compared to
2013, primarily due to the addition of US$51.5 million in such costs from our
the gross margin for the year ended December 31, 2012. Gross profit per boe
Colombian operations.
increased 4%, to US$32.2 per barrel for the year ended December 31, 2013.
In our Chilean operations, production costs increased by 2.7%, due to
Gross profit attributable to our operations in Chile for the year ended
the change in revenue mix from gas to oil, which has higher production costs
December 31, 2012 was US$89.9 million, a 7% increase from US$84.1 million
than gas, and due to an increase in our oil production. In the year ended
for the year ended December 31, 2012. The contribution to our gross profit
December 31, 2013, in Chile, operating costs per boe increased to US$12.2
during such years from our operations in Chile was 57% and 69%,
per boe from US$10.7 per boe in 2012. In the year ended December 31, 2013,
respectively.
the revenue mix for Chile was 85.5% oil and 14.5% gas, whereas for the same
period in 2012 it was 80.7% oil and 19.3% gas.
Gross profit attributable to our operations in Colombia for the year ended
December 31, 2012 was US$67.6 million a 72% increase from US$39.3 million
Operating costs in Colombia increased 79.1%, to US$62.8 million for the year
for the year ended December 31, 2012. The contribution to our gross profit
ended December 31, 2013 as compared to the year ended December 31,
during such years from our operations in Colombia was 43% and 32%,
2012, primarily due to an increase in production and deliveries the region and
respectively.
also to the incorporation of an additional three months of Cuerva’s results
in the year ended December 31, 2013 and the incorporation of an additional
Exploration costs
month of Winchester and Luna’s operations in Colombia (operating costs
for the corresponding period that were not included in the year ended
December 31, 2012 amounted to US$14.2 million). However, operating costs
per boe in Colombia decreased to US$26.5 per boe for the year ended
December 31, 2013 from US$34.0 per boe for the year ended December 31,
2012, due to the fact that increased production generated improved fixed
Chile
cost absorption, which positively impacted the production costs per boe.
Colombia
Other
Total
Year ended
December 31,
Change from prior year
2013
2012
%
(in thousands of US$, except for percentages)
(9,758)
(3,341)
(3,155)
(20,452)
(5,528)
(1,910)
10,694
2,187
1,245
(16,254)
(27,890)
11,636
(52)%
(40%)
65%
(42)%
Gross profit
Chile
Colombia
Other
Total
Year ended
December 31,
Change from prior year
Exploration costs decreased 42%, from US$27.9 million for the year ended
2013
2012
%
December 31, 2012 to US$16.3 million for the year ended December 31, 2013,
(in thousands of US$, except for percentages)
7%
84,133
5,773
89,906
primarily as the result of the decrease in recognition of write-offs of
unsuccessful efforts in an amount of US$14.6 million.
67,612
1,192
39,304
(2,194)
158,710
121,243
28,308
3,386
37,467
72%
154%
The 2013 charge in write-off of unsuccessful efforts corresponds to the cost
31%
of five unsuccessful exploratory wells: two in Chile (one in Fell Block and
one in Tranquilo Block) and three in Colombia (one well in Cuerva Block and
Gross profit increased 31%, from US$121.2 million for the year ended
one well in each of the non-operated blocks, Arrendajo and Llanos 32). The
December 31, 2012 to US$158.7 million for the year ended December 31,
2012 charge in write-off of unsuccessful efforts corresponds to the costs
2013, as a result of (i) increased sales and production in Colombia, (ii) the
of eight unsuccessful exploratory wells: five in Chile (two in Fell Block, two in
incorporation of an additional three months of Cuerva’s results in the year
Otway Block and the remaining in Tranquilo Block) and three in Colombia
ended December 31, 2013 and the incorporation of an additional month
(one well in Cuerva Block, one well in Arrendajo Block and the remaining in
of Winchester and Luna’s operations in Colombia (gross profit for the
Llanos 17 Block). The 2012 charge also includes the loss generated by the
corresponding period that was not included in the year ended December 31,
relinquishment of an area in the Del Mosquito Block in Argentina.
2012 amounted to US$9.4 million) and (iii) increased net revenues in our
GeoPark 20F 135
Administrative costs
Operating profit (loss)
Year ended
December 31,
Change from prior year
2013
2012
%
(in thousands of US$, except for percentages)
Chile
Colombia
Other
Total
(16,420)
(16,409)
(13,755)
(10,879)
(7,393)
(10,526)
(46,584)
(28,798)
(5,541)
(9,016)
(3,229)
17,786
51%
Chile
121%
Colombia
31%
62%
Other
Total
Year ended
December 31,
Change from prior year
2013
2012
%
(in thousands of US$, except for percentages)
63,110
38,811
(17,957)
83,964
47,915
8,499
(15,667)
40,747
15,195
30,312
(2,290)
43,217
32%
357%
15%
106%
Administrative costs increased 62%, from US$28.8 million for the year ended
We recorded an operating profit of US$84.0 million for the year ended
December 31, 2012 to US$46.6 million for the year ended December 31, 2013,
December 31, 2013, a 106% increase from US$40.8 million for the year ended
primarily as a result of an increase in costs in: (1) our Chilean operations,
December 31, 2012, primarily due to the incorporation of an additional three
from US$10.9 million in the year ended December 31,2012 to US$16.4 million
months of Cuerva’s results and an increase in production and deliveries
in the year ended December 31, 2013, mainly due to the startup of our
in Colombia in the year ended December 31, 2013 and the incorporation of
operations in Tierra del Fuego; (2) increased staff and other costs in Colombia,
an additional month of Winchester and Luna’s operations in Colombia. In
and (3) higher corporate expenses related to our growth strategy and new
addition, during the year ended December 31, 2013, in Chile, we recognized a
business efforts.
Selling expenses
Chile
Colombia
Other
Total
gain amounting to US$3.2 million in other operating income related to the
reversal of certain provisions previously recorded that, based on the view of
our management and legal advisors, were extinguished as the statute of
limitations was reached.
Year ended
December 31,
Change from prior year
2013
2012
%
Financial results, net
Financial loss increased 108% to US$33.9 million, due to the accelerated
(in thousands of US$, except for percentages)
amortization of debt issuance costs incurred in connection with the
(4,062)
(12,677)
(513)
(5,327)
(18,953)
(351)
(17,252)
(24,631)
1,265
6,276
162
7,379
(24)%
(33)%
(46)%
redemption of the Notes due 2015 in an amount of US$8.6 million following
the issuance of the Notes due 2020 in February 2013, the incorporation of
an additional three months of Cuerva’s results in the year ended December
(30)%
31, 2013 and the incorporation of an additional month of Winchester and
Luna’s operations in Colombia into our results and higher interest expenses
Selling expenses decreased 30%, from US$24.6 million for year ended
December 31, 2012 to US$17.3 million for the year ended December 31, 2013,
generated by the issuance of the Notes due 2020 in an amount of US$12.1
million, partially offset by interest income due to increased cash and cash
primarily due to the change in the delivery point for certain of our production
equivalents.
in our Colombian operations. In our Chilean operations, selling expenses
were 24% lower compared to prior year, primarily as a result of the impact of
the DOP penalty we paid to Methanex in 2012, described in “— Business—
Marketing and Delivery Commitments,” partially offset by the increase in oil
deliveries in Chile.
136 GeoPark 20F
Profit before income tax
Profit for the year
Year ended
December 31,
Change from prior year
2013
2012
%
(in thousands of US$, except for percentages)
Chile
Colombia
Other
Total
49,965
31,049
(30,926)
50,088
42,272
11,223
(20,655)
32,840
7,693
19,826
(10,271)
17,248
18%
Chile
177%
Colombia
50%
53%
Other
Total
Year ended
December 31,
Change from prior year
2013
2012
%
(in thousands of US$, except for percentages)
45,844
13,179
(24,089)
34,934
30,923
6,247
(18,724)
18,446
14,921
6,932
(5,365)
16,488
48%
111%
29%
89%
For the year ended December 31, 2013, we recorded a profit before income
For the year ended December 31, 2013, we recorded a profit of US$34.9
tax of US$50.1 million, an increase of 53% from US$32.8 million for the year
million, a 89% increase from US$18.5 million for the year ended December 31,
ended December 31, 2012, primarily due to the incorporation of an additional
2012, as a result of the reasons described above.
three months of Cuerva’s results in the year ended December 31, 2013
and the incorporation of an additional month of Winchester and Luna’s
operations in Colombia into our results and to increases in production and
Profit for the year attributable to owners of the Company
Profit for the year attributable to owners of the Company increased by
deliveries in Colombia, and, to a lesser extent, higher profits from our Chilean
85% to US$22.0 million, for the reasons described above. Profit attributable
operations, partially offset by the occurrence of two non-recurring events:
to non-controlling interest increased by 97% to US$12.9 million for the
(1) accelerated amortization of debt issuance costs described above;
year ended December 31, 2013 as compared to the prior year due to
and (2) the comparative effect of a bargain purchase gain on acquisition of
the incorporation of an additional three months of Cuerva’s results in the
subsidiaries of US$8.4 million as a result of the acquisitions of Winchester
year ended December 31, 2013 and the incorporation of an additional month
and Luna recorded in the year ended December 31, 2012.
of Winchester and Luna’s operations in Colombia and an increase in
non-controlling interest resulting from LGI’s acquisition of a 20% equity
interest in our Colombian operations.
Income tax
Chile
Colombia
Other
Total
Year ended
December 31,
Change from prior year
2013
2012
%
(in thousands of US$, except for percentages)
(4,121)
(17,870)
6,837
(11,349)
(4,976)
1,931
(15,154)
(14,394)
7,228
(12,894)
4,906
(760)
(64)%
259%
254%
5%
Income tax increased 5%, from US$14.4 million for the year ended December
31, 2012 to US$15.2 million for the year ended December 31, 2013, as a result
of our increased results of operations in Chile and Colombia. Our effective
tax rate for the year ended December 31, 2013 was 30% as compared to 44%
in the year ended December 31, 2012 due to lower charges from deferred
income taxes in the year ended December 31, 2013 mainly resulting from the
effect of currency translation on tax base in Colombia and Chile, compensated
by an increase in current taxes resulting from higher profits in Chile and
Colombia and the impact of tax loss carry forwards recorded in Colombia.
GeoPark 20F 137
Year ended December 31, 2012 compared to year ended December 31, 2011
The following table summarizes certain of our financial and operating data for
For the year ended % Change
December 31,
from
2013
2012
prior year
the years ended December 31, 2012 and 2011.
(in thousands of US$, except for percentages)
Revenue
Net oil sales
Net gas sales
Net revenue
Production costs
Gross profit
Gross margin (%)(1)
Exploration costs
Administrative costs
Selling expenses
Other operating income/(expense)
Operating profit
Financial income
Financial expenses
Bargain purchase gain on
acquisition of subsidiaries
Profit before income tax
Income tax
Profit for the year
Non-controlling interest
221,564
28,914
250,478
(129,235)
121,243
48%
(27,890)
(28,798)
(24,631)
823
40,747
892
73,508
38,072
111,580
(54,513)
57,067
51%
(10,066)
(18,169)
(2,546)
(502)
25,784
162
(17,200)
(13,678)
8,401
32,840
(14,394)
18,446
6,567
—
12,268
(7,206)
5,062
5,008
201%
(24)%
124%
137%
112%
(3)%
177%
59%
867%
264%
58%
451%
26%
—
168%
100%
264%
31%
Profit for the year attributable
to owners of the Company
11,879
54
21,898%
Net production volumes
Oil (mbbl)
Gas (mcf)
Total net production (mboe)
Average net production (boepd)
Average realized sales price
Oil (US$ per bbl)
Gas (US$ per mmcf)
Average unit costs per boe (US$)
Operating cost
Royalties and other
Production costs(2)
Depreciation
Total production cost
Exploration costs
Administrative costs
Selling expenses
2,513
8,346
3,904
11,292
916
11,135
2,771
7,593
90.5
4.0
16.8
2.9
19.7
13.4
33.1
7.1
7.4
6.3
83.8
3.9
8.6
1.7
10.3
9.3
19.7
3.6
6.6
0.9
174%
(25)%
41%
49%
8%
2%
95%
71%
91%
44%
68%
97%
12%
600%
(1) Gross margin is defined as total revenue minus production costs, divided
by total revenue.
(2) Calculated pursuant to FASB ASC 932.
138 GeoPark 20F
The following table summarizes certain financial and operating data.
Net revenue
Gross profit/(loss)
Depreciation
Impairment and write-off
Chile
Colombia
Other
149,927
84,133
(28,734)
(18,490)
99,501
39,304
(21,050)
(5,147)
1,050
(2,194)
(3,533)
(1,915)
2012
Total
250,478
121,243
(53,317)
(25,552)
For the year ended December 31,
Chile
Colombia
Other
2011
Total
110,103
56,888
(25,297)
(5,919)
(in thousands of US$)
1,477
179
(1,111)
(1,344)
111,580
57,067
(26,408)
(7,263)
—
—
—
—
Net revenue
For the year ended December 31, 2012, crude oil sales were our principal
resulted in net revenue of US$221.6 million for the year ended December 31,
2012 compared to US$73.5 million for the year ended December 31, 2011,
source of revenue, with 88% and 12% of our total revenue from crude oil and
partially offset by decreases in sales of gas from US$38.1 million for the year
gas sales, respectively. The following chart shows the increase in oil and
ended December 31, 2011 to US$28.9 million for the year ended December
natural gas sales from the year ended December 31, 2011 to the year ended
31, 2012.
December 31, 2012.
Consolidated
Sale of crude oil
Sale of gas
Total
The increase in 2012 net revenue is explained by:
For the year ended December 31,
• an increase of US$142.2 million in oil deliveries (including US$99.5 million
2012
2011
in oil deliveries from Colombia);
(in thousands of US$)
• an increase of US$6.0 million from the realized price for oil sold; and
221,564
28,914
73,508
38,072
• an increase of US$1.1 million from the realized price of gas sold, partially
offset by a decrease of US$10.2 million in gas deliveries.
250,478
111,580
Net revenue attributable to our operations in Chile for the year ended
December 31, 2012 was US$149.9 million, a 36% increase from US$110.1
million for the year ended December 31, 2011, principally due to (1) increased
Year ended
sales of crude oil of 1,415 mbbl for the year ended December 31, 2012
December 31,
Change from prior year
compared to 864 mbbl for the year ended December 31, 2011 (an increase
%
2012
(in thousands of US$, except for percentages)
2011
of 63.8%) following the discovery of the Konawentru x1 well, which was put
into production in June 2012, and also other discoveries made in the Tobifera
By country
Chile
Colombia
Other
Total
149,927
110,103
99,501
1,050
—
1,477
39,824
99,501
(427)
250,478
111,580
138,898
formation, and (2) an increased average realized prices per barrel of crude oil
36%
from US$83.8 per barrel for the year December 31, 2011 to US$85.4 per
—
barrel for the year ended December 31, 2012 (an increase of US$1.6 per barrel
(29)%
124%
or a total of 1.9%). The increase in the average realized price per barrel was
partly attributable to US$1.0 per barrel less in quality discounts in the year
ended December 31, 2012 as compared to the same period in 2011. The
Net revenue increased 124%, from US$111.6 million for the year ended
increased sales of crude oil were partially offset by a US$9.2 million reduction
December 31, 2011 to US$250.5 million for the year ended December 31,
in gas sales. The contribution to our net revenue during such years from our
2012, primarily as a result of the acquisition of Luna and Winchester in
operations in Chile was 60% and 99%, respectively.
February 2012 and Cuerva in March 2012 in Colombia, which increased our
volumes of crude sales by 41.5%, and increases in sales of crude oil in Chile.
Net revenue attributable to our operations in Colombia for the year
Sales of crude oil increased to 2,448 mbbl in the year ended December 31,
ended December 31, 2012 was US$99.5 million. Our Colombian operations
2012 compared to 864 mbbl in the year ended December 31, 2011, and
contributed 39.7% to our net revenue, resulting from sales of crude oil.
GeoPark 20F 139
Production costs
The following table summarizes our production costs for the years ended
In our Chilean operations, production costs increased by 23.6%, due to
the change in revenue mix from gas to oil, which has higher production costs
December 31, 2012 and 2011.
than gas, and due to an increase in our oil production. In the year ended
December 31, 2012, in Chile, operating expenditures per boe increased to
For the year ended % Change
US$10.3 per boe from US$8.3 per boe in 2011. In the year ended December
December 31,
from prior
31, 2012, the revenue mix for Chile was 80.7% oil and 19.3% gas, whereas
2012
2011
year
for the same period in 2011 it was 65.4% oil and 34.6% gas.
(in thousands of US$, except for percentages)
Consolidated
(including Chile, Colombia and Argentina)
Depreciation
Royalties
Staff costs
Transportation costs
Well and facilities maintenance
Consumables
Equipment rental
Other costs
Total
(52,307)
(11,424)
(14,171)
(7,211)
(9,385)
(9,884)
(5,936)
(25,844)
(4,843)
(6,015)
(2,541)
(5,080)
(1,687)
—
(18,917)
(8,503)
(129,235)
(54,513)
85%
Gross profit
486%
—
122%
137%
In our Colombian operations, 34.8% of our production costs were related
to depreciation charges, 6.9% to royalties, 11.7% to consumables and 9.9%
to equipment rental for the year ended December 31, 2012. In the year
ended December 31, 2012, in Colombia, operating expenditures were
US$30.4 per boe.
102%
136%
136%
184%
Year ended
December 31,
Change from prior year
2012
2011
%
(in thousands of US$, except for percentages)
84,133
39,304
(2,194)
56,888
—
179
121,243
57,067
27,245
39,304
(2,373)
64,176
48%
—
(1,325)%
112%
Year ended December 31,
Colombia
Chile
2012
2011
Chile
Colombia
Chile
Colombia
Other
Total
(in thousands of US$)
By country
Depreciation
Royalties
Staff costs
Transportation costs
Well and facilities
maintenance
Consumables
Equipment rental
Other costs
Total
(28,120)
(20,964)
(24,958)
(7,088)
(8,560)
(5,986)
(6,290)
(2,717)
—
(4,164)
(7,432)
(1,045)
(2,850)
(7,090)
(5,936)
(4,634)
(6,802)
(2,427)
(4,817)
(1,626)
—
(7,033)
(10,716)
(7,951)
(65,794)
(60,197)
(53,215)
Gross profit increased 112%, from US$57.1 million for the year ended
December 31, 2011 to US$121.2 million for the year ended December 31,
2012, as a result of our Colombian acquisitions and increased revenues
in our Chilean operations.
As a result, gross margin for the year ended December 31, 2012 was 48%,
which represented a decrease of 3% as compared to the gross margin
for the year ended December 31, 2011.
Gross profit per boe increased 49%, from US$20.6 for the year ended
December 31, 2011 to US$30.7 for the year ended December 31, 2012.
—
—
—
—
—
—
—
—
—
Production costs increased 137%, from US$54.5 million for the year ended
Gross profit attributable to our operations in Chile for the year ended
December 31, 2011 to US$129.2 million for the year ended December 31,
December 31, 2012 was US$84.1 million, a 48% increase from US$56.9 million
2012, primarily due to the addition of US$60.2 million in such costs from our
for the year ended December 31, 2011. The contribution to our gross profit
Colombian operations.
during such years from our operations in Chile was 69% and 100%,
respectively.
Gross profit attributable to our operations in Colombia for the year ended
December 31, 2012 was US$39.3 million. The contribution to our gross profit
during such period was 32%.
140 GeoPark 20F
Exploration costs
Year ended
compared to US$1.9 million during 2011, and (3) the incorporation of our
December 31,
Change from prior year
Colombian operations into our results.
amounting to US$2.9 million during 2012, as compared to US$1.7 million
during 2011, (2) consultant fees amounting to US$5.1 million during 2012, as
2012
2011
%
(in thousands of US$, except for percentages)
Selling expenses
Chile
Colombia
Other
Total
(20,452)
(7,486)
(5,528)
(1,910)
—
(2,580)
(12,966)
(5,528)
670
(27,890)
(10,066)
17,824
173%
—
(26)%
177%
Year ended
December 31,
Change from prior year
2012
2011
%
(in thousands of US$, except for percentages)
Exploration costs increased 177%, from US$10.1 million for the year ended
Chile
December 31, 2011 to US$27.9 million for the year ended December 31,
Colombia
2012, primarily as the result of a 173% increase in exploration costs in Chile,
Other
(5,327)
(18,953)
(351)
(2,231)
—
(315)
(3,096)
(18,953)
(36)
which represented 73% of our exploration costs in 2012. In 2012, we recorded
Total
(24,631)
(2,546)
(22,085)
139%
—
11%
867%
write-offs relating to five of our Chilean wells (two in the Fell Block, two in
the Otway Block and one in the Tranquilo Block) and three of our Colombian
Selling expenses increased 867%, from US$2.6 million for the year ended
wells (one in the Cuerva Block, one in the Arrendajo Block and one in the
December 31, 2012 to US$24.6 million for the year ended December 31, 2011,
Llanos 17 Block) for a total of US$23.6 million, as compared to write-offs in
primarily due to higher transportation costs in 2012 in connection with our
respect of three of our Chilean wells for a total of US$5.9 million in 2011;
Colombian operations, in an amount of US$18.9 million. In our Chilean
and a loss of US$1.9 million generated by our voluntary relinquishment of
operations, selling expenses were US$3.1 million, or 139%, higher compared
exploration acreage in the Del Mosquito Block in Argentina in 2012, recorded
to the prior year, primarily as a result of (1) a DOP penalty payment in the
in our Other operations, compared to a write-off in respect of charges from
amount of US$1.7 million to Methanex as a result of our failure to meet our
assets relating to the Del Mosquito Block in the amount of US$1.3 million
minimum volume delivery requirements under the Methanex Gas Supply
in 2011. See Note 11 to our Annual Consolidated Financial Statements.
Agreement for each of the months of April through September of 2012 and
The incorporation of our Colombian operations into our results resulted in
(2) an increase of US$1.4 million that was primarily due to higher oil sales
a US$5.5 million (including US$5.1 million in write-offs described above)
volumes in Chile.
increase in our exploration costs for 2012.
Operating profit (loss)
Administrative costs
Year ended
December 31,
2012
2011
Change from prior year
%
(in thousands of US$, except for percentages)
Chile
(10,879)
(7,393)
(10,526)
(6,396)
—
(11,773)
(4,483)
(7,393)
1,247
(28,798)
(18,169)
(10,629)
70%
Colombia
Other
Total
—
11%
59%
Chile
Colombia
Other
Total
Year ended
December 31,
2011
2012
Change from prior year
%
(in thousands of US$, except for percentages)
47,915
8,499
(15,667)
40,747
39,425
—
(13,641)
25,784
8,490
8,499
(2,026)
14,963
22%
—
15%
58%
Administrative costs increased 59%, from US$18.2 million for the year ended
Colombian operations into our results and a 22% increase in our Chilean
December 31, 2011 to US$28.8 million for the year ended December 31,
operations in the year ended December 31, 2012 as compared to the prior
2012, as a result of (1) an increase in costs in our Chilean and other operations
year, which was partially offset by the operating loss in Other.
Operating profit increased 58.0%, primarily due to the incorporation of our
due to higher costs relating to analyzing new business developments and
expansion, including our Colombian acquisitions and our Brazil Acquisitions,
GeoPark 20F 141
Financial results, net
Financial loss increased 21% to US$16.3 million, primarily due to the
December 31, 2011 and 2012 was 59% and 44%, respectively, due in part
to a non-recurring tax exempted bargain purchase gain on acquisition
incurrence of a US$37.5 million loan to partly finance our Colombian
of subsidiaries.
acquisitions, and an increase in exchange difference of US$0.5 million in the
year ended December 31, 2011 as compared to US$2.5 million in the year
Profit for the year
ended December 31, 2012, mainly due to the strengthening of the Chilean
peso against the U.S. dollar, from Ch$519.2 as of December 31, 2011 to
Ch$478.6 as of December 31, 2012, which negatively affected our liability
net position in local currency related to tax payables.
Year ended
Chile
December 31,
Change from prior year
Colombia
2012
2011
%
(in thousands of US$, except for percentages)
Other
Total
Year ended
December 31,
Change from prior year
2012
2011
%
(in thousands of US$, except for percentages)
30,923
6,247
(18,724)
18,446
19,455
—
(14,393)
5,062
11,468
6,247
(4,331)
13,384
59%
—
30%
264%
Chile
Colombia
Other
Total
42,272
11,223
(20,655)
32,840
26,649
—
(14,381)
12,268
15,623
11,223
(6,274)
20,572
59%
—
For the year ended December 31, 2012, we recorded a profit of US$18.4
44%
million, a 264% increase from US$5.1 million for the year ended December 31,
168%
2011, as a result of the reasons described above.
For the year ended December 31, 2012, we recorded a profit before income
Profit for the year attributable to owners of the Company
tax of US$32.8 million, an increase of 168% from US$12.3 million for the
year ended December 31, 2011, primarily due to the incorporation of our
Profit for the year attributable to owners of the Company increased for the
Colombian operations into our results and a bargain purchase gain on
reasons described above. Profit attributable to non-controlling interest
acquisition of subsidiaries of US$8.4 million as a result of the acquisitions
increased by 31% to US$6.6 million in the year ended December 31, 2012 as
of Winchester and Luna in the year ended December 31, 2012.
compared to the prior year due to increased profit in our Chilean operations.
Income tax
B. Liquidity and capital resources
Year ended
December 31,
Change from prior year
Overview
Our financial condition and liquidity is and will continue to be influenced by
2012
2011
%
a variety of factors, including:
Chile
Colombia
Other
Total
(in thousands of US$, except for percentages)
58%
(4,155)
(7,194)
(11,349)
• our ability to generate cash flows from our operations;
(4,976)
1,931
—
(12)
(14,394)
(7,206)
(4,976)
1,943
(7,188)
—
• our capital expenditure requirements;
16,192%
• the level of our outstanding indebtedness and the interest we are obligated
100%
to pay on this indebtedness; and
• changes in exchange rates which will impact our generation of cash flows
Income tax increased 100%, from US$7.2 million for the year ended
from operations when measured in U.S. dollars, and, upon the completion
December 31, 2011 to US$14.4 million for the year ended December 31, 2012,
of our Brazil Acquisitions, the real.
as a result of the incorporation of our Colombian operations into our results
and a 58% increase in income tax in our Chilean operations, consistent with
Our principal sources of liquidity have historically been contributed
the improved profitability of our Chilean operations, offset by the recognition
shareholder equity, debt financings and cash generated by our operations in
of a deferred tax asset of US$1.9 million resulting from expenses generated
the Fell Block, and, since our acquisitions of Winchester and Luna in the first
at our Chilean holding company. Our effective tax rate for the years ended
quarter of 2012, cash generated by our operations in our blocks in Colombia.
142 GeoPark 20F
We have a proven ability to raise capital. Since 2005 to 2013, we have raised
Colombia and other investments of US$198.2 million, including the
more than US$109.5 million in equity offerings at the holding company level
drilling of 45 new wells and seismic surveys registered, principally in our
and more than US$557 million through debt arrangements with multilateral
Tierra del Fuego Blocks. In the year ended December 31, 2011, our
agencies such as the IFC, gas prepayment facilities with Methanex,
total capital expenditures amounted to US$98.7 million, all of which was
international bond issuances and bank financings, described further below,
used in exploration, development and production activities, including
which have been used to fund our capital expenditures program and
US$57.9 million for the drilling of development wells and facilities and
acquisitions and to increase our liquidity.
US$39.5 million for the drilling of exploratory wells and seismic studies.
We have also raised US$173.3 million to date through our strategic
In the year ended December 31, 2013, we made total capital expenditures
partnership with LGI following the sale of minority interests in our Colombian
of US$228.0 million (US$145.7 million, US$82.1 million and US$0.2 million
and Chilean operations.
in Chile, Colombia and Argentina, respectively), consisting of US$133.3
million related to exploration. 39 new wells were drilled (17 in Chile and 22 in
We initially funded our 2012 expansion into Colombia through a US$37.5
Colombia) in blocks in which we have working interests and/or economic
million loan, cash on hand and a subsequent sale of a minority interest in
interests. In addition to the above, in 2013 we completed approximately 1,350
our Colombian operations to LGI. We subsequently restructured our
sq. km. in 3D seismic surveys (more than 1,100 sq. km in Chile, mainly related
outstanding debt in February 2013, by issuing US$300.0 million aggregate
to the blocks located in Tierra del Fuego and over 250 sq. km in Colombia).
principal amount of Notes due 2020, a portion of the proceeds of which we
used to prepay the US$37.5 million loan and to redeem all of our outstanding
In March 2014 we invested US$140 million in Brazil, subject to certain
Notes due 2015. See “Item 4. Information on the Company—Business
adjustments, to acquire Rio das Contas, which we financed through the
Overview—Significant Agreements—Argentina—Agreements with LGI.”
incurrence of a loan of US$70.5 million and cash on hand.
In February 2014, we commenced trading on the NYSE and raised US$98
In 2014, we expect our total capital expenditures, excluding the purchase
million (before underwriting commissions and expenses), including the over
price for our Rio das Contas acquisition, to be between US$220 million to
allotment option granted to and exercised by the underwriters, through
US$250 million. These capital expenditures will include the drilling of a total
the issuance of 13,999,700 common shares.
of 50 to 60 new wells (approximately 40% of which we expect will be
exploratory wells), as well as workovers, seismic surveys and new facility
In March 2014, we borrowed US$70.5 million pursuant to a five-year term
construction. We expect that approximately 62% of our total capital
variable interest secured loan, secured by the benefits GeoPark receives under
expenditures for 2014 will be incurred in Chile, which will include the
the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to
drilling of approximately 32 to 37 wells, as well as workovers, seismic surveys
six-month LIBOR + 3.9% to finance part of the purchase price of our Rio das
and new facility construction, including oil pipelines. We expect that
Contas acquisition, and funded the remaining amount with cash on hand.
approximately 32% of our total capital expenditures for 2014 will be incurred
We believe that our cash and cash equivalents on hand, and cash from
operations will be adequate to meet our capital expenditure requirements,
in Colombia, which will include the drilling of approximately 18 to 23 wells,
as well as workovers and new facility construction, mainly related to civil
and liquidity needs for the foreseeable future.
works, production facilities in the Tua and Tigana fields and improvements
to the Taro Taro and Max fields facilities. Finally, we expect that
Capital expenditures
We have funded our capital expenditures with proceeds from equity
approximately 5% of our total capital expenditures for 2014 will be incurred
in Brazil, which will consist of between US$5 million to US$7.5 million to
offerings, credit facilities, debt issuances and pre-sale agreements, as well as
finance in part the construction of a gas compression plant in the Manatí
through cash generated from our operations. We expect to incur substantial
Field we acquired as part of our Rio das Contas acquisition and approximately
expenses and capital expenditures as we develop our oil and natural gas
US$0.45 million in license fee payments to the ANP relating to our Round
prospects and acquire additional assets.
12 concessions, with the remainder for seismic surveys in exploration blocks
in the Potiguar and Recôncavo Basins.
In the year ended December 31, 2012, we made total capital expenditures of
US$303.5 million, which consisted of investments of US$105.3 million relating
to the purchase price for our acquisitions of Winchester, Luna and Cuerva in
GeoPark 20F 143
In budgeting for our future activities, we have relied on a number of
assumptions, including, with regard to our discovery success rate, the number
Cash flows provided by operating activities
For the year ended December 31, 2013, cash provided by operating
of wells we plan to drill, our working interests in our prospects, the costs
activities was US$140.1 million, a 6.3% increase from US$131.8 million for the
involved in developing or participating in the development of a prospect, the
year ended December 31, 2012. This increase is mainly driven by higher
timing of third-party projects and our ability to obtain needed financing in
production and revenues that we obtained during 2013, partially offset by
respect to any further acquisitions and the availability of both suitable
higher associated costs.
equipment and qualified personnel. These assumptions are inherently subject
to significant business, political, economic, regulatory, environmental and
For the year ended December 31, 2012, cash provided by operating activities
competitive uncertainties, conditions in the financial markets, contingencies
was US$131.8 million, a 92% increase from US$68.8 million for the year
and risks, all of which are difficult to predict and many of which are beyond
ended December 31, 2011. This increase was principally due to increased cash
our control. In addition, we opportunistically seek out new assets and
generated in our operations and the incorporation of US$20.8 million in
acquisition targets to complement our existing operations, and have
operating cash flows from our Colombian operations into our results.
financed such acquisitions in the past through the incurrence of additional
indebtedness, including additional bank credit facilities, equity issuances
or the sale of minority stakes in certain operations to our partners. We may
Cash flows used in investing activities
For the year ended December 31, 2013, cash used in investing activities was
need to raise additional funds more quickly if one or more of our assumptions
US$221.3 million, a 27.1% decrease from US$303.5 million for the year ended
prove to be incorrect or if we choose to expand our hydrocarbon asset
December 31, 2012. This decrease was primarily related to our Colombian
acquisition, exploration, appraisal or development efforts more rapidly than
acquisitions, which occurred in the first quarter of 2012. This amount was
we presently anticipate, and we may decide to raise additional funds even
only partially offset by an increase of US$29.8 million in capital expenditures
before we need them if the conditions for raising capital are favorable.
relating to the drilling of 39 new wells (17 in Chile and 22 in Colombia) and
The ultimate amount of capital that we will expend may fluctuate materially
seismic surveys and facilities construction, as compared to the drilling of 35
based on market conditions, our continued production, decisions by the
wells (15 in Chile and 20 in Colombia) for the year ended December 31, 2012.
operators in blocks where we are not the operator, the success of our drilling
results and future acquisitions. Our future financial condition and liquidity
Cash used in investing activities increased by US$202.2 million during the
will be impacted by, among other factors, our level of production of oil and
year ended December 31, 2012, from US$101.3 million in 2011 to
natural gas and the prices we receive from the sale thereof, the success
US$303.5 million in 2012. This increase includes US$105.3 million related to
of our exploration and appraisal drilling program, the number of
the purchase price for our Colombian operations (net of cash acquired);
commercially viable oil and natural gas discoveries made and the quantities
the remaining increase is primarily explained by increased drilling activities
of oil and natural gas discovered, the speed with which we can bring such
in 2012 (20 wells in Chile and 24 in Colombia) as compared to 23 new
discoveries to production and the actual cost of exploration, appraisal and
wells in 2011.
development of our oil and natural gas assets.
Cash flows
The following table sets forth our cash flows for the periods indicated:
Cash flows provided by financing activities
Cash provided by financing activities was US$164.0 million for the year ended
December 31, 2013, compared to cash provided by financing activities of
US$26.4 million for the year ended December 31, 2012. This change was
Cash flows provided by (used in)
Operating activities
Investing activities
Financing activities
Year ended December 31,
principally the result of cash received in the 2013 period from the issuance
2013
2012
2011
of US$300.0 million of our Notes due 2020 and an increase of US$36.6 million
(in thousands of US$)
in cash from LGI pertaining principally to its investment in our Colombian
and Chilean operations. These were partially offset by the early redemption
140,094
131,802
68,763
of our Notes due 2015 and the repayment of the Banco Itaú BBA Credit
(221,299)
(303,507)
(101,276)
Agreement, in an aggregate amount of US$175.0 million.
164,018
26,375
131,739
Net increase (decrease) in cash
Cash provided by financing activities was US$26.4 million and US$131.7
and cash equivalents
82,813
(145,330)
99,226
million during the years ended December 31, 2012 and 2011, respectively.
This decrease was principally the result of a US$129.5 million reduction in
144 GeoPark 20F
proceeds from transactions relating to non-controlling interest, resulting
Notes due 2020
from LGI’s acquisition of a 20% interest for US$148 million, of which US$142
million was collected in 2012, in our Chilean operations in the year ended
December 31, 2011. In the year ended December 31, 2012, LGI contributed
General
On February 11, 2013, we issued US$300.0 million aggregate principal
US$12.5 million in cash provided by financing activities pursuant to its direct
amount of senior secured notes due 2020. The Notes due 2020 mature on
investment in our Chilean operations. The US$129.5 million decrease
February 11, 2020 and bear interest at a fixed rate of 7.50% and a yield of
was only partly offset by cash provided through the incurrence of a US$37.5
7.625% per annum. Interest on the Notes due 2020 is payable semi-annually
million loan to partly finance our Colombian acquisitions.
in arrears on February 11 and August 11 of each year.
Indebtedness
As of December 31, 2013 and 2012, we had total outstanding indebtedness
Ranking
The Notes due 2020 constitute senior obligations of Agencia, secured by a
of US$317.1 million and US$193.0 million, respectively, as set forth in the
first lien on certain collateral (as described below). The Notes due 2020 rank
table below.
Methanex Gas Prepayment Agreement
BCI Loans(1)
Bond GeoPark Fell SpA (Notes due 2015)(2)
Bond GeoPark Latin America Agencia
en Chile (Notes due 2020)
Banco Itaú BBA Credit Agreement
Banco de Chile(4)
Overdrafts(5)
Total(3)
equally in right of payment with all senior existing and future obligations
of Agencia (except those obligations preferred by operation of Bermuda and
As of December 31,
Chilean law, including, without limitation, labor and tax claims); effectively
2013
2012
senior to all unsecured debt of Agencia and GeoPark Latin America, to the
(in thousands of US$)
extent of the value of the collateral; senior in right of payment to all existing
—
2,143
8,036
7,859
and future subordinated indebtedness of Agencia and GeoPark Latin America;
and effectively junior to any future secured obligations of Agencia and its
—
129,452
subsidiaries (other than additional notes issued pursuant to the indenture
governing the Notes due 2020) to the extent secured by assets constituting
299,912
—
with a security interest on assets not constituting collateral, in each case to
—
37,685
the extent of the value of the collateral securing such obligations.
15,002
—
30
10,000
317,087
193,032
Guarantees
The Notes due 2020 are guaranteed unconditionally on an unsecured basis by
us, all of our wholly-owned subsidiaries, and any subsidiary that guarantees
(1) Includes BCI Mortgages and BCI Letters of Credit (each as defined herein).
any of our debt, subject to certain exceptions.
(2) On December 2, 2010, we issued US$133.0 million aggregate principal
amount of Notes due 2015. The notes were fully redeemed with the proceeds
from the issuance of our Notes due 2020.
Collateral
The notes are secured by a first-priority perfected security interest in certain
(3) Does not include US$8.5 million outstanding as of December 31, 2013
under a subordinated line of credit extended by LGI to GeoPark Colombia
collateral, which consists of: 80% of the equity interests of each of GeoPark
Chile and GeoPark Colombia held by Agencia, and loans of the net proceeds
S.A.S. in December 2012. See Note 28 of our Consolidated Financial
of the Notes due 2020 made by Agencia to each of GeoPark Fell and GeoPark
Statements.
Llanos SAS. Except for certain immaterial subsidiaries and other exceptions,
(4) Short-term financing obtained in December 2013 and fully repaid in
GeoPark and Agencia are also required to pledge the equity interests of our
January 2014.
subsidiaries.
(5) We have been granted credit lines for over US$76 million as of December
31, 2013.
The Notes due 2020 are also secured on a first-priority basis by intercompany
loans, disbursed to subsidiaries, in an aggregate amount at any one time that
On March 28, 2014, we incurred US$70.5 million pursuant to the Rio das
does not exceed US$300.0 million.
Contas Credit Facility to finance the Rio das Contas acquisition.
Our material outstanding indebtedness as of December 31, 2013 is described
below.
Optional redemption
At any time prior to February 11, 2017, we may, at our option, redeem any of
the Notes due 2020, in whole or in part, at a redemption price equal to 100%
GeoPark 20F 145
of the principal amount of such Notes due 2020 plus an applicable “make-
grade ratings from at least two of the following rating agencies, Standard
whole” premium, plus accrued and unpaid interest (including, additional
& Poor’s Rating Group, Fitch Inc. and Moody’s Investors Service, Inc., and no
amounts), if any, as such term is defined in the indenture governing the Notes
default has occurred or is continuing under the indenture governing
due 2020, if any, to the redemption date.
the Notes due 2020, certain of these restrictions, including, among others,
the limitations on incurrence of debt and disqualified or preferred stock,
At any time and from time to time on or after February 11, 2017, we may,
restricted payments (including restrictions on our ability to pay dividends),
at our option, redeem all or part of the Notes due 2020, at the redemption
the ability of certain subsidiaries to pay dividends, asset sales and certain
prices, expressed as percentages of principal amount, set forth below, plus
transactions with affiliates will no longer be applicable.
accrued and unpaid interest thereon (including additional amounts), if any,
to the applicable redemption date, if redeemed during the 12-month
period beginning on February 11 of the years indicated below:
Events of default
Events of default under the indenture governing the Notes due 2020 include:
the nonpayment of principal when due; default in the payment of interest,
Year
2017
2018
2019 and after
Percentage
which continues for a period of 30 days; failure to make an offer to purchase
103.750%
and thereafter accept tendered notes following the occurrence of a change
101.875%
of control or as required by certain covenants in the indenture governing
100.000%
the Notes due 2020; default in the performance or breach of the covenants
contained in the indenture, the notes, or the security documents in relation
In addition, at any time prior to February 11, 2016, we may, at our option,
thereto that continues for a period of 60 consecutive days after written notice
redeem up to 35% of the aggregate principal amount of the Notes due
to Agencia; cross payment default relating to debt with a principal amount
2020 (including any additional notes) at a redemption price of 107.50% of
of US$15.0 million or more, and cross-acceleration default following a
the principal amount thereof, plus accrued and unpaid interest (including
judgment for US$15.0 million or more; bankruptcy and insolvency events;
additional amounts) if any to the redemption date, with the net cash
invalidity or denial or disaffirmation of a guarantee of the notes; and failure
proceeds of one or more equity offerings; provided that: (1) Notes due 2020
to maintain a perfected security interest in any collateral having a fair market
in an aggregate principal amount equal to at least 65% of the aggregate
value in excess of US$15.0 million, among others. The occurrence of an
principal amount of Notes due 2020 issued on the first issue date remain
event of default would permit or require the principal of and accrued interest
outstanding immediately after the occurrence of such redemption; and
on the Notes due 2020 to become or to be declared due and payable.
(2) the redemption must occur within 90 days of the date of the closing of
such equity offering.
BCI Mortgage Loan
In October 2007, in connection with our acquisition of a facility to establish
Change of control
Upon the occurrence of certain events constituting a change of control, we
an operational base in the Fell Block, we executed a mortgage loan granted
by the Banco de Crédito e Inversiones, or BCI, a Chilean private bank, which
are required to make an offer to repurchase all outstanding Notes due 2020,
at a purchase price equal to 101% of the principal amount thereof plus
we refer to as the BCI Mortgage Loan. The loan was granted in Chilean pesos
and is repayable over a period of eight years. The interest rate under this
any accrued and unpaid interest (including any additional amounts payable
loan is fixed at 6.6%. As of December 31, 2013, the aggregate outstanding
in respect thereof) thereon to the date of purchase.
amount under the BCI Mortgage Loan was US$0.2 million.
Covenants
The Notes due 2020 contain customary covenants, which include, among
BCI Letter of Credit
During the last quarter of 2011, we obtained five short-term letters of credit
others, limitations on: the incurrence of debt and disqualified or preferred
from BCI, or, collectively, the BCI Letters of Credit, to commence operations
stock, restricted payments (including restrictions on our ability to pay
in our Tierra del Fuego blocks. Each of the BCI Letters of Credit contains a
dividends), incurrence of liens, transfer, prepayment or modification
pledge by us to BCI of the seismic equipment acquired to start the operations
of certain collateral, guarantees of additional indebtedness, the ability of
in these new blocks. The BCI Letters of Credit expired and were fully paid by
certain subsidiaries to pay dividends, asset sales, transactions with affiliates,
us on February 14, 2014, and the applicable interest rate ranges from 4.5%
engaging in certain businesses, and merger or consolidation with or
to 5.45%. As of December 31, 2013, the aggregate outstanding amount under
into another company. In the event the Notes due 2020 receive investment-
the BCI Letters of Credit was US$1.9 million.
146 GeoPark 20F
LGI Line of Credit
In December 2012, in connection with its investment in GeoPark Colombia,
F. Tabular disclosure of contractual obligations
In accordance with the terms of our concessions, we are required to make
LGI granted as a credit line to Winchester (now GeoPark Colombia S.A.S.),
royalty payments (1) in connection with crude oil and gas production in
or the LGI Line of Credit, of up to US$12.0 million, to be used for the
Argentina, to the Provinces of Santa Cruz and Mendoza, equivalent to 12%
acquisition, development and operation of oil and gas assets in Colombia.
on estimated value at well head, (2) in connection with crude oil and gas
In December 2015, the principal amount of any outstanding amounts shall
production in Chile, to the Chilean government, equivalent to approximately
become immediately due and payable. GeoPark Colombia S.A.S. may also,
5% of crude oil production and 3% of gas production, and (3) in connection
in its sole discretion, choose to make repayments of the principal amounts
with crude oil production in Colombia, to the Colombian government,
outstanding on the last business day of March, June, September and
equivalent to 8%.
December of each year until December 2015. The applicable interest rate is
8.00% per annum and any accrued interest is payable on a quarterly basis.
Less than
One to
Three to More than
As of December 31, 2013, the aggregate outstanding amount under the LGI
Total
one year
three years
five years
five years
Line of Credit was US$8.5 million. See “Item 4. Information on the Company—
B. Business Overview—Significant Agreements—Agreements with LGI.”
Rio das Contas Credit Facility
We financed our Rio das Contas acquisition in part through our Brazilian
subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas
Credit Facility”) with Itau BBA International plc, which is secured by the
Debt
obligations(1)
Operating
lease
obligations(2)
Pending
(in thousands of US$)
317,087
26,630
98
—
290,359
157,023
68,817
56,556
31,145
505
benefits GeoPark receives under the Purchase and Sale Agreement for Natural
Gas with Petrobras. The facility matures five years from March 28, 2014,
which was the date of disbursement and bears interest at a variable interest
investment
commitments(3) 87,488
Asset
rate equal to the six-month LIBOR + 3.9%. The facility agreement includes
retirement
44,428
43,060
—
—
customary events of default, and subject our Brazilian subsidiary to customary
obligations
24,166
—
11,644
448
12,074
covenants, including the requirement that it maintain a ratio of net debt to
Total
EBITDA of up to 3.5x the first two years and up to 3.0x thereafter. The credit
contractual
facility also limits the borrower’s ability to pay dividends if the ratio of net
obligations 585,764
139,875
111,358
31,593
302,938
debt to EBITDA is greater than 2.5x. We have the option to prepay the facility
in whole or in part, at any time, subject to a pre-payment fee to be
(1) Includes current borrowings and non-current borrowings.
determined under the contract.
(2) Reflects the future aggregate minimum lease payments under non-
cancellable operating lease agreements.
C. Research and development, patents and licenses, etc.
See “Item 4. Information on the Company—B. Business Overview” and “Item
(3) Includes capital commitments in Isla Norte, Campanario and Flamenco
Blocks in Chile, nine concessions in Brazil and the Llanos 62 and Llanos 17
4. Information on the Company—B. Business Overview—Title to Properties.”
Blocks in Colombia, which are our only remaining material commitments. See
D. Trend information
For a discussion of Trend information, see “—A. Operating Results—Factors
affecting our results of operations.”
“Item 4. Information on the Company—B. Business overview—Our
operations—Operations in Colombia.”
On March 28, 2014, we incurred US$70.5 million pursuant to the Rio das
Contas Credit Facility to finance the Rio das Contas acquisition.
E. Off-balance sheet arrangements
We did not have any off-balance sheet arrangements as of December 31,
2012 or as of December 31, 2013.
G. Safe harbor
See “Forward-Looking Statements.”
GeoPark 20F 147
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A. Directors and senior management
Board of directors
The board of directors of GeoPark is composed of seven members. At every
annual general meeting one third of the Directors shall retire from office.
From the date of the annual general meeting following the effective date of
the listing of our Common Shares on the NYSE, our Directors shall hold office
for such term as the Shareholders may determine or, in the absence of such
determination, until the next annual general meeting or until their successors
are elected or appointed or their office is otherwise vacated. The term for
the current directors expires on the date of our next annual shareholders’
meeting, to be held in 2014.
The current members of the board of directors were appointed at a
shareholders’ meeting held on July 30, 2013. The table below sets forth
certain information concerning our current board of directors.
Name
Gerald E. O’Shaughnessy
James F. Park
Carlos Gulisano
Juan Cristóbal Pavez(1)(2)
Peter Ryalls(1)(2)
Steven J. Quamme(1)
Pedro Aylwin Director
Position
Chairman and Director
Chief Executive Officer, Deputy Chairman and Director
Director
Director
Director
Director
Director of Legal and Governance
Age
At the Company since
65
58
63
44
63
53
54
2002
2002
(3)2010
2008
2006
2011
2003
(1) Member of the Audit committee.
(2) Independent director under SEC Audit Committee rules.
(3) Carlos Gulisano joined the Company in 2002 as an advisor.
Biographical information of the members of our board of directors is set forth
below. Unless otherwise indicated, the current business addresses for our
directors is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile.
148 GeoPark 20F
Gerald E. O’Shaughnessy has been our Chairman and a member of our
board of directors since he co-founded the company in 2002. Following
Carlos Gulisano has been a member of our board of directors since June
2010. Dr. Gulisano holds a bachelor’s degree in geology, a post-graduate
his graduation from the University of Notre Dame with degrees in
degree in petroleum engineering and a PhD in geology from the University
government (1970) and law (1973), Mr. O’Shaughnessy was engaged in the
of Buenos Aires and has authored or co-authored over 40 technical papers.
practice of law in Minnesota. Mr. O’Shaughnessy has been active in the oil
He is a former adjunct professor at the Universidad del Sur, a former thesis
and gas business over his business career, starting in 1976 with Lario Oil and
director at the University of La Plata, and a former scholarship director at
Gas Company, where he served as Senior Vice President and General Counsel.
CONICET, the national technology research council, in Argentina. Dr. Gulisano
He later formed the Globe Resources Group, a private venture firm whose
is a respected leader in the fields of petroleum geology and geophysics in
subsidiaries provided seismic acquisition and processing, well rehabilitation
South America and has over 30 years of successful exploration, development
services, sophisticated logistical operations and submersible pump works
and management experience in the oil and gas industry. In addition to
for Lukoil in Russia during the 1990s. In 2010 Mr. O’Shaughnessy founded
serving as an advisor to GeoPark since 2002 and as Managing Director from
Lario Logistics, a U.S. midstream company which owns and operates the
February 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera
Bakken Oil Express, serving oil producers and service providers in the Bakken
Argentina San Jorge S.A. and Chevron San Jorge S.A. and has led teams
Oil play. In addition to his oil and gas activities Mr. O’Shaughnessy is also
credited with significant oil and gas discoveries, including those in the Trapial
engaged in investments in banking, wealth management, desktop software,
field in Argentina. He has worked in Argentina, Bolivia, Peru, Ecuador,
computer and network security, and green clean technology. Over the
Colombia, Venezuela, Brazil, Chile and the United States. Mr. Gulisano is also
past 25 years, Mr. O’Shaughnessy has also served on a number of non-profit
an independent consultant on oil and gas exploration and production.
boards of directors, including the Board of Economic Advisors to the
Governor of Kansas, the I.A. O’Shaughnessy Family Foundation, the Wichita
Collegiate School, the Institute for Humane Studies, The East West Institute
Juan Cristóbal Pavez has been a member of our board of directors since
August 2008. He holds a degree in commercial engineering from the
and The Bill of Rights Institute. Mr. O’Shaughnessy is a member of the
Pontifical Catholic University of Chile and a MBA from the Massachusetts
Intercontinental Chapter of Young Presidents Organization and World
Institute of Technology. He has worked as a research analyst at Grupo CB
Presidents’ Organization.
and later as a portfolio analyst at Moneda Asset Management. In 1998,
he joined Santana, an investment company, as Chief Executive Officer. At
James F. Park has served as our Chief Executive Officer and as a member
of our board of directors since co-founding the Company in 2002. He has
Santana he focused mainly on investments in capital markets and real estate.
While at Santana, he was appointed Chief Executive Officer of Laboratorios
extensive experience in all phases of the upstream oil and gas business, with
Andrómaco, one of Santana’s main assets. In 1999, Mr. Pavez cofounded
a strong background in the acquisition, implementation and management
Eventures, an internet company. Since 2001, he has served as Chief
of international joint ventures in North America, South America, Asia, Europe
Executive Officer at Centinela, a company with a diversified global portfolio
and the Middle East. He holds a degree in geophysics from the University
of investments, with a special focus in the energy industry, through the
of California at Berkeley and has worked as a research scientist in earthquake
development of wind parks and run-of-the-river hydropower plants.
and tectonic studies. In 1978, Mr. Park joined Basic Resources International
Limited, an oil and gas exploration company, which pioneered the
Mr. Pavez is also a board member of Grupo Security, Vida Security and
Hidroelétrica Totoral. Over the last few years he has been a board member
development of commercial oil and gas production in Central America.
of several companies, including Quintec, Enaex, CTI and Frimetal.
As a senior executive of Basic Resources International Limited, Mr. Park was
closely involved in the development of grass-roots exploration activities,
drilling and production operations, surface and pipeline construction and
crude oil marketing and transportation, and with legal and regulatory issues,
and raising substantial investment funds. He remained a member of the
board of directors of Basic Resources International Limited until the company
was sold in 1997. Mr. Park is also a member of the board of directors of
Energy Holdings. Mr. Park has also been involved in oil and gas projects in
California, Louisiana, Argentina, Yemen and China. Mr. Park has lived in
Argentina and Chile since 2002.
GeoPark 20F 149
Peter Ryalls has been a member of our board of directors since April 2006.
He holds a master’s degree in petroleum engineering from Imperial College
Pedro Aylwin has served as a member of our board of directors since July
2013 and as our Director of Legal and Governance since April 2011. From
in London. Mr. Ryalls has worked for Schlumberger Limited in Angola, Gabon
2003 to 2006, Mr. Aylwin worked for us as an advisor on governance and
and Nigeria, as well as for Mobil North Sea. He has also worked for Unocal
legal matters. Mr. Aylwin holds a degree in law from the Universidad de Chile
Corporation where he held increasingly senior positions, including as
and an LLM from the University of Notre Dame. Mr. Aylwin has extensive
Managing Director in Aberdeen, Scotland, and where he developed extensive
experience in the natural resources sector. Mr. Aylwin is also a partner at the
experience in offshore production and drilling operations. In 1994, Mr. Ryalls
law firm of Aylwin Abogados in Santiago, Chile, where he represented mining,
represented Unocal Corporation in the Azerbaijan International Operating
chemical and oil and gas companies in numerous transactions. From 2006
Company as Vice President of Operations and was responsible for production,
until 2011, he served as Lead Manager and General Counsel at BHP Billiton,
drilling, reservoir engineering and logistics. In 1998, Mr. Ryalls became
Base Metals, where he was in charge of legal and corporate governance
General Manager for Unocal in Argentina. He also served as Vice President
matters on BHP Billiton’s projects, operations and natural resource assets in
of Unocal’s Gulf of Mexico onshore oil and gas business and as Vice President
South America, North America, Asia, Africa and Australia. Mr. Aylwin is
of Global Engineering and Construction, where he was responsible for
also a member of the board of directors of Egeda España.
the implementation of all major capital projects ranging from deep water
developments in Indonesia and the Gulf of Mexico to conventional oil and
gas projects in Thailand. Mr. Ryalls is also an Independent Petroleum
Consultant advising on international oil and gas development projects both
onshore and offshore.
Steven J. Quamme has been a member of our board of directors since
June 2011. He has 25 years of experience as a fund manager, securities and
corporate lawyer, and investment banker. Mr. Quamme holds a B.A. in
economics from Northwestern University and a J.D. from the Northwestern
University School of Law, where he is a member of the Law School Board.
Mr. Quamme is a member of the board of directors of Cartica Management,
LLC, as well as the board of trustees of The Potomac School and of the Sibley
Memorial Hospital Foundation. He has previously served as a member of
the boards of directors of Equivest Finance, Milestone Merchant Partners,
LLC, Kerrco Inc., Atlantic Entertainment Group, Rausch Industries, Rompetrol,
and Einstein Noah Bagel Corp, LP. From 2005 to 2007, Mr. Quamme served as
the Chief Operating Officer of Breeden Partners, a corporate governance fund.
From 2002 to 2007, Mr. Quamme also served as Senior Managing Director
of Richard C. Breeden & Co., a professional services firm, which focuses on
corporate governance and crisis management. In 2000, Mr. Quamme founded
Milestone Merchant Partners, a merchant bank based in Washington D.C.,
where he served as its CEO until 2005. Mr. Quamme is presently a co-founder
and Senior Managing Director of Cartica Management, a registered
investment advisor focused on emerging markets and a GeoPark shareholder.
150 GeoPark 20F
Executive officers
Our executive officers are responsible for the management and
representation of our company. The table below sets forth certain information
concerning our executive officers.
Name
James F. Park
Andrés Ocampo
Augusto Zubillaga
Pedro Aylwin Chiorrini
Gerardo Hinterwimmer
Salvador Harambour
Marcela Vaca
Dimas Coelho
Carlos Murut
Salvador Minniti
Jose Díaz
Horacio Fontana
Ruben Marconi
Agustina Wisky
Guillermo Portnoi
Pablo Ducci
Position
Chief Executive Officer and Director
Chief Financial Officer
Managing Director of Operations
Director of Legal and Governance
Director for Argentina
Director for Chile
Director for Colombia
Director for Brazil
Director of Development Geology
Director of Exploration
Director of Operations
Director of Drilling
Director of Health, Safety & Environment
Director of People
Director of Administration and Finance
Director of Capital Markets
Age
At the Company since
58
36
44
54
57
53
45
57
57
59
59
56
69
37
39
34
2002
2010
2006
2003
2003
2009
2012
2013
2006
2007
2013
2008
2008
2002
2006
2012
Biographical information of the members of our executive officers is set
forth below. Unless otherwise indicated, the current business addresses for
Augusto Zubillaga has served as our Managing Director of Operations since
January 2012. He previously served as our Production Director. He is a
our executive officers is Nuestra Señora de los Ángeles 179, Las Condes,
petroleum engineer with 19 years of experience in production, engineering,
Santiago, Chile.
well completions, corrosion control, reservoir management and field
development. He has a degree in petroleum engineering from the Instituto
Andrés Ocampo has served as our Chief Financial Officer since November
2013. He previously served as our Director of Growth and Capital (from
Tecnológico de Buenos Aires. Prior to joining our company, Mr. Zubillaga
worked for Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A.
January 2011 through October 2013), and has been with our company since
July 2010. Mr. Ocampo graduated with a degree in Economics from the
At Chevron San Jorge S.A., he led multi-disciplinary teams focused on
improving production, costs and safety, and was the leader of the Asset
Universidad Católica Argentina. He has more than 12 years of experience
Development Team, which was responsible for creating the field
in business and finance. Before joining our company, Mr. Ocampo worked at
development plan and estimating and auditing the oil and gas reserves
Citigroup and served as Vice President Oil & Gas and Soft Commodities at
of the Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron
Crédit Agricole Corporate & Investment Bank.
San Jorge S.A. team that was responsible for identifying business
opportunities and working with the head office on the establishment of
best business practices. He has authored several industry papers, including
papers on electrical submersible pump optimization, corrosion control,
water handling and intelligent production systems.
GeoPark 20F 151
Gerardo Hinterwimmer has served as our Director for Argentina since April
2012. He previously served as our Geosciences Director. He holds a degree in
responsible for the planning, management and execution of the exploration
programs in the exploration blocks in Brazil’s Santos Basin, and as Joint
geology from Universidad Nacional de la Plata. He is a development geologist
Venture Project Manager (in 2011), in which role he was responsible for the
in Argentina and an expert in the Magallanes Austral Basin, with over 25 years
coordination of Petrobras’s functional areas to support Petrobras’s work
of experience working for international and major oil companies, including
programs in the Santos Basin. In 2012, he served as Executive Vice President
YPF S.A., Schlumberger Limited, Petrolera Argentina San Jorge S.A. and
of Exploration at Panoro, where he oversaw the functional workflow for
Chevron San Jorge S.A. Mr. Hinterwimmer has experience in studying and
Panoro Energy ASA’s exploration assets in Brazil. Dr. Dimas holds a degree
evaluating unconventional volcanic clastic reservoirs in the Austral Basin and
in geology from the Federal University of Rio de Janeiro, Brazil, an MSc degree
has been credited with commercial oil and gas discoveries in the Austral
in geophysics (seismic processing) from the Federal University of Bahia,
and Neuquen Basins. He is the author of numerous technical papers and is
Brazil, a Ph.D. in geology (Numerical Basin Modelling) from Cornell University
an editor of the reference manual on productive reservoirs in Argentina.
and an MBA in general administration from the Federal University of Rio de
He has also contributed to the development of recent geological-oriented
Janeiro, Brazil.
technology introduced by Schlumberger Limited in South America.
Salvador Harambour has served as our Director for Chile since 2009. He is
an oil and gas manager with more than 27 years of experience in the energy
Carlos Murut has been our Director of Development Geology since January
2012. He previously served as our Development Manager. Mr. Murut holds
a master’s degree in petroleum geology from the University of Buenos Aires
industry. He holds a degree in geology from the Universidad de Chile and
where he also undertook postgraduate studies in reservoir engineering,
an MsC on basin analysis from the University of London. Prior to joining our
specializing in field exploitation. Mr. Murut has over 30 years of experience
company, Mr. Harambour spent 24 years at ENAP, beginning in 1985 as Field
working for international and major oil companies, including YPF S.A.,
Geologist. In 1993, he joined Sipetrol and worked as Exploration Geologist
Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A.
on several Latin American and European ventures. In 2003, he joined ENAP
Sipetrol Argentina, and in 2005, he was appointed General Manager of
ENAP Sipetrol in Argentina, until he joined GeoPark in 2009.
Marcela Vaca has been our Director for Colombia since August 2012.
Ms. Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá,
Salvador Minniti has been our Director of Exploration since January 2012.
He previously served as our Exploration Manager. He holds a bachelor degree
in geology from National University of La Plata and has a graduate degree
from the Argentine Oil and Gas Institute in oil geology. Mr. Minniti has over
30 years of experience in oil exploration and has worked with YPF S.A.,
Colombia, a Master’s Degree in commercial law from the same university and
Petrolera Argentina San Jorge S.A. and Chevron Argentina.
an LLM from Georgetown University. She has served in the legal departments
of a number of companies in Colombia, including Empresa Colombiana
de Carbon Ltda (which later merged with INGEOMINAS), and from 2000 to
José Díaz has been our Director of Operations since January 2013. Mr. Díaz
holds a degree in petroleum engineering from Cuyo National University,
2003, she served as Legal and Administrative Manager at GHK Company
Argentina, has taken executive business classes at IAE Business School,
Colombia. Prior to joining our company in 2012, Ms. Vaca served for nine
years as General Manager of the Hupecol Group where she was responsible
and pursued graduate studies in oil and gas law and project management
at University of Buenos Aires School of Law and Alta Dirección Escuela
for supervising all areas of the company as well as managing relationships
de Negocios, respectively. He has over 30 years of experience in upstream
with Ecopetrol, ANH, the Colombian Ministry of Mines and Energy, the
operations as a petroleum engineer, including more than 15 years in
Colombian Ministry of Environment and other governmental agencies.
managerial positions. This experience includes positions at international
At the Hupecol Group, Ms. Vaca was also involved in the structuring of the
and major oil companies, including OEA S.A., Chevron San Jorge S.A.,
Hupecol Group’s asset development and sales strategy.
ChevronTexaco and Petrolera El Trebol S.A.
Dimas Coelho has served as our Director for Brazil since February 2013.
He is a geologist and geophysicist with over 30 years of experience
Horacio Fontana has been our Director of Drilling since March 2012. He
previously served as our Engineer Manager. He holds a degree in civil
in hydrocarbons exploration. From 1981 to 2011, Dr. Coelho served for
engineering from Rosario National University and is also a graduate from the
Petrobras in numerous capacities, including as Petroleum Exploration
Argentine Oil and Gas Institute, National University of Buenos Aires, with a
Manager (from 2001 to 2004 and from 2006 to 2010), in which role he was
specialty in field exploitation and a concentration in drilling. Mr. Fontana has
152 GeoPark 20F
over 25 years of drilling experience including at major Argentine companies
like YPF S.A. and Petrolera Argentina San Jorge- Chevron.
Executive directors’ contracts
It is our policy that executive directors have contracts of an indefinite term
providing for a maximum of one-year’s notice in writing of termination
Rubén Marconi has been our Director of Health, Safety and Environment
since March 2012. He previously served as our Drilling Director. He holds
at any time.
a degree in mechanical engineering from Rosario University and was
Gerald E. O’Shaughnessy has a service contract with our company that
a YPF scholar at the University of Buenos Aires where he graduated in
provides for him to act as Executive Chairman at an annual salary of
oil engineering with a concentration in exploitation. Mr. Marconi has over
US$250,000. James F. Park has a service contract with our company that
40 years of field logistics and safety experience with ChevronTexaco,
provides for him to act as Chief Executive Officer at an annual salary of
Chevron Mid Continent Business Unit and Chevron Argentina.
US$500,000. The payment of a bonus to Mr. O’Shaughnessy or Mr. Park is at
Agustina Wisky has worked with our Company since it was founded
in November 2002, and has served as our Director of People since 2012.
our discretion. Our agreements with Mr. O’Shaughnessy and Mr. Park
contain covenants that restrict them, for a period of 12 months following
termination of employment, from soliciting senior employees of our company
Mrs. Wisky is a public accountant, and also holds a degree in human
and, for a period of six months following the termination of employments,
resources from the Universidad Austral—IAE. She has 13 years of experience
from being involved in any competing undertaking. Pedro Aylwin, who
in the oil industry. Before joining our company, Mrs. Wisky worked at AES
was appointed as an executive director in July 2013, has a service contract
Gener and PricewaterhouseCoopers.
with our company that provides for him to act as Director of Legal and
Guillermo Portnoi has been our Director of Administration and Finance
since 2011 and has worked for us since June 2006. Mr. Portnoi is a public
The following chart summarizes payments made to our executive directors
accountant and holds an MBA from Universidad Austral—IAE. He has more
for the year ended December 31, 2013.
Governance.
than 10 years of experience in the oil industry. Before joining our company,
Mr. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers,
where he counted several major oil companies as his clients.
Pablo Ducci has served as our Director of Capital Markets since 2012.
Mr. Ducci holds a bachelor’s degree in science and economics from Pontifical
Catholic University of Chile and a master’s degree in business administration
Executive director
Gerald E. O’Shaughnessy
James F. Park
Executive
directors’ fees
US$250,000
US$500,000
Cash payment
Bonus
US$150,000
US$300,000
from Duke University. From 2004 to 2009, Mr. Ducci worked as a Corporate
Finance Analyst and Corporate Finance Associate with Celfin Capital. In 2010,
Non-executive directors’ contracts
Our non-executive directors are paid an annual fee of GBP35,000, which is
he worked as a Summer Associate for Anka Funds, and from 2011 to 2012,
payable quarterly in arrears. At our option, the fee paid to our non-executive
he served as Vice President of Development for Falabella Retail.
B. Compensation
directors can be paid through the issuance of new common shares and/or
cash. In addition, the Chairmen of the Audit Committee, the Remuneration
Committee and the Nomination Committee are paid an additional annual
fee of GBP5,750 each. The termination of the employment relationship does
Executive compensation
For the year ended December 31, 2013, the aggregate compensation
not entitle non-executive directors to any financial compensation. The
following chart summarizes payments made to our non-executive directors
accrued or paid to the members of our board of directors (including our
for the year ended December 31, 2013.
executive directors) for services in all capacities was approximately
US$4.6 million. Gerald E. O’Shaughnessy, James F. Park and Pedro Aylwin
are our executive directors. For the year ended December 31, 2013,
the aggregate compensation accrued or paid to the members of our senior
management (excluding our executive directors) for services in all
capacities was approximately US$6.8 million.
GeoPark 20F 153
Executive
director
Sir Michael R.
Jenkins(1)
Juan Cristóbal
Pavez(2)
Christian Weyer(3)
Peter Ryalls
Carlos Gulisano
Steven J. Quamme
Share payment
Fees paid in
Performance-Based Employee Long-Term Incentive Program
We have established the Performance-Based Employee Long-Term Incentive
Cash payment
common shares
Program in order to align the interests of our management, employees
Non-executive
Committee
(in number of
and key advisors with those of our shareholders. In November 2007,
directors’ fees
Chairman fees
common shares)
our shareholders voted to authorize the board of directors to use up to a
GBP4,375
GBP1,437.5
1,712
Performance-Based Employee Long-Term Incentive Program. The shareholders
maximum of 12% of our issued share capital for the purposes of the
GBP17,500
GBP17,240
GBP17,500
GBP35,000
GBP17,500
GBP5,750
GBP1,437.5
—
GBP2,875
GBP2,875
also authorized the board of directors to implement the Performance-
2,906
Based Employee Long-Term Incentive Program and to determine specific
—
conditions and broadly defined guidelines for the program.
2,906
—
2,906
IPO award program and Executive Stock Option Plan
On admission to AIM, our executive directors, management and key
employees received options to purchase common shares of the Company
(1) Audit Committee Chairman (until his death on March 31, 2013). Steven J.
granted under the Executive Stock Option Plan. The options became fully
Quamme succeeded Sir Michael R. Jenkins as Audit Committee Chairman.
vested in May 2008 and expired in May 2013.
(2) Remuneration Committee Chairman (since September 24, 2012).
(3) Nomination Committee Chairman (until his resignation on April 15, 2013).
The program included 896,834 common shares, all of which have already
Carlos Gulisano succeeded Christian Weyer as Nomination Committee
been issued.
Chairman.
Pension and retirement benefits
We do not maintain any defined benefit pension plans or any other
employees
The following table sets forth the other common share awards to our
retirement programs for our employees or directors.
executive directors, management and key employees since 2008 through
Other common share awards to executive directors, management and key
April 15, 2014.
Number of underlying
common shares awarded
976,211(1)
1,000,000(2)
500,000(3)
500,000(4)
500,000(6)
% of issued common
share capital
approximately 2.2
Grant
Exercise
Vesting
Expiration
date
December 15, 2008
price
US$0.001
date
December 15, 2012
date
December 15, 2018
approximately 2.0
December 15, 2010
US$0.001
December 15, 2014
December 15, 2020
approximately 1.1
approximately 1.1
approximately 1.1
December 15, 2011
December 15, 2012
US$0.001
US$0.001
June 30, 2013
US$0.001
December 15, 2015
(5)December 15, 2016
December 31, 2015
December 15, 2021
December 15, 2022
December 31, 2019
(1) Dr. Carlos Gulisano holds 100,000 of such awards.
(4) As of the date of this annual report, there are 64,000 awards that will not
(2) As of the date of this annual report, there are 164,400 awards that will
vest due to the relevant employees having left the Company before the
not vest due to the relevant employees having left the Company before the
vesting date.
vesting date.
(5) Certain programs contemplate different vesting dates, in each case before
(3) As of the date of this annual report, there are 6,000 awards that will not
December 15, 2016.
vest due to the relevant employees having left the Company before the
(6) The common shares will be awarded under this program provided certain
vesting date.
minimum financial and operational targets are met through 2015.
154 GeoPark 20F
In addition to the awards described above under our Performance-Based
Employee Long-Term Incentive Program and our Executive Stock Option
Employee Long-Term Incentive Program, on August 31, 2011, we granted
Plan authorize the Company to deposit any common shares they have
an aggregate award of 90,000 common shares at an exercise price of
received under these programs in our Employee Benefit Trust, or EBT. The EBT
US$0.001 to certain of our former employees, of which 30,000 vested in 2012
is held to facilitate holdings and dispositions of those common shares by the
and the remaining 60,000 vested in September 2013. In addition, on
participants thereof. Under the terms of the EBT, each participant is entitled
November 23, 2012, we granted awards of common shares at an exercise
to receive any dividends we may pay which correspond to their common
price of US$0.001 to each of James F. Park (450,000 common shares) and
shares held by the trust, according to instructions sent by the Company to the
Gerald E. O’Shaughnessy (270,000 common shares), in each case with a
trust administrator. The trust provides that Mr. James F. Park is entitled to
vesting date of November 23, 2015.
vote all the common shares held in the trust.
Value Creation Plan
In July 2013, our remuneration committee established the “Value Creation
Share Repurchase Program
On October 29, 2013, we put into place an irrevocable, non-discretionary
Plan,” or VCP, to give our executive officers and key management members
share purchase program for the purchase of up to 400,000 of our common
the opportunity to share in a percentage of the value created for
shares, or the Purchase Program, for the account of our Employee Benefit
shareholders in excess of a pre-determined share price target at the end
Trust, or the EBT. The Purchase Program was in effect through December 31,
of a performance period. Under the VCP, if as of December 31, 2015,
2013, and was managed by BTG Pactual Chile International Limited and
our share price (defined as the average trading price of our common shares
Oriel Securities Limited. The common shares purchased under the Purchase
on the NYSE for the month of December 2015) exceeds US$13.66, VCP
Program will be used to satisfy future awards under our employee long-term
participants will receive an aggregate payment equal to 10% of the excess
incentive programs. See “—Executive compensation.”
above the market capitalization threshold generated by this share price
(assuming that the share capital of the Company has remained at the same
In November 2013, we purchased an aggregate of 50,000 common shares
level as applicable at the time of grant of the VCP: 43,495,585 shares).
at a purchase price between 5.40 and 5.45 GBP for the account of the EBT
The award will be paid in common shares under our Performance-Based
pursuant to the Purchase Program.
Employee Long-Term Incentive Program. The award will vest 50%
on December 31, 2015, and the remaining 50% on December 31, 2016.
C. Board practices
Notwithstanding the foregoing, the total number of common shares granted
pursuant to this plan shall not exceed 5% of the issued share capital of
the Company. Additionally, the share price (and number of common shares
Overview
Our board of directors is responsible for establishing our strategic goals,
outstanding) used to calculate if the market capitalization threshold has
ensuring that the necessary resources are in place to achieve these goals
been met is subject to adjustment for any stock splits.
and reviewing our management and financial performance. Our board of
Potential dilution resulting from Performance-Based Employee Long-Term
Incentive Program
The percentage of total share capital that could be awarded to our executive
directors directs and monitors the company in accordance with a framework
of controls, which enable risks to be assessed and managed through
clear procedures, lines of responsibility and delegated authority. Our board
of directors also has responsibility for establishing our core values and
directors, management and key employees under the Performance-Based
standards of business conduct and for ensuring that these, together with our
Employee Long-Term Incentive Program would represent approximately 12%
obligations to our shareholders, are understood throughout the company.
of our issued common shares. However, as of the date of this annual report,
we have awarded approximately 8.5% of our current total issued share capital
(not including shares that may be issued under the VCP program).
Employee Benefit Trust
Our directors, senior management and key employees who have received
Board composition
Our bye-laws and board resolutions provide that the board of directors
consist of a minimum of three and a maximum of nine members. All of our
directors were elected at our annual shareholders’ meeting held on July 30,
2013, and their term expires on the date of our next annual shareholders’
option awards or common share awards under our Performance-Based
meeting, to be held in 2014. The board of directors meets at least on a
quarterly basis.
GeoPark 20F 155
Committees of our board of directors
Our board of directors has established an Audit Committee, a Remuneration
and our shareholders. No member of the Remuneration Committee
participates in any discussion about his or her own remuneration.
Committee and a Nomination Committee. The composition and
responsibilities of each committee are described below. Members serve
on the Audit Committee for a period of three years. For the Remuneration
Nomination committee
The Nomination Committee is composed of three directors. The members
and Nomination Committees, members serve on these committees until
of the Nomination Committee are Mr. Gerald E. O’Shaughnessy, Mr. Carlos
their resignation or until otherwise determined by our board of directors.
Gulisano (who serves as Chairman of the committee) and Mr. Pedro Aylwin.
In the future, our board of directors may establish other committees to assist
with its responsibilities.
Audit committee
The Audit Committee is composed of three directors: Mr. Peter Ryalls,
The Nomination Committee meets as required and its responsibilities include:
(a) reviewing the structure, size and composition of the board of directors
and making recommendations to the board of directors in respect of any
required changes; (b) identifying, nominating and submitting for approval by
Mr. Juan Cristóbal Pavez and Mr. Steven J. Quamme (who serves as Chairman
the board of directors candidates to fill vacancies on the board of directors as
of the committee). We have determined that Mr. Peter Ryalls and Mr. Juan
and when they arise; (c) making recommendations to the board of directors
Cristóbal Pavez are independent, as such term is defined under SEC rules
with respect to the membership of the Audit Committee and Remuneration
applicable to foreign private issuers. In accordance with NYSE rules, we expect
Committee in consultation with the chairman of each committee; (d)
to have a fully independent audit committee within one year of listing.
reviewing outside directorships/commitments of non-executive directors;
and (e) succession planning for directors and senior executives.
The Audit Committee’s responsibilities include: (a) approving our financial
statements; (b) reviewing financial statements and formal announcements
relating to our performance; (c) assessing the independence, objectivity and
Liability insurance
We maintain liability insurance coverage for all of our directors and officers,
effectiveness of our external auditors; (d) making recommendations for
the level of which is reviewed annually.
the appointment, re-appointment and removal of our external auditors and
approving their remuneration and terms of engagement; (e) implementing
and monitoring policy on the engagement of external auditors supplying
D. Employees
As of December 31, 2013, we had approximately 404 employees, of which
non-audit services to us; (f) obtaining, at our expense, outside legal or other
193 were located in Chile, 109 were located in Colombia, 98 were located in
professional advice on any matters within its terms of reference and securing
Argentina and four were located in Brazil. This represented an increase of
the attendance at its meetings of outsiders with relevant experience and
14% from December 31, 2012, which increase was largely attributable to the
expertise if it considers it necessary; and (g) reviewing our arrangements for
growth of our Colombian operations and new operations in our Tierra del
our employees to raise concerns about possible wrongdoing in financial
Fuego Blocks.
reporting or other matters and the procedures for handling such allegations,
and ensuring that these arrangements allow proportionate and independent
investigation of such matters and appropriate follow-up action.
The following table sets forth a breakdown of our employees by geographic
segment for the periods indicated.
Remuneration committee
The Remuneration Committee is composed of three directors. The members
of the remuneration committee are Mr. Juan Cristóbal Pavez (who serves
Chile
as Chairman of the committee), Mr. Peter Ryalls and Mr. Steve J. Quamme.
The Remuneration Committee meets as required during the year, and its
specific responsibilities include: (a) determining, in conjunction with the
board of directors, the remuneration policy for the Chief Executive Officer,
Colombia
Argentina
Brazil
Total
Year ended December 31,
2013
193
109
98
4
404
2012
163
98
92
—
353
2011
104
—
84
—
188
the Chairman, our executive directors and other members of executive
From time to time, we also utilize the services of independent contractors
management; (b) reviewing the performance of our executive directors and
to perform various field and other services as needed. As of December 31,
members of executive management; and (c) reviewing the design of the
2013, 11 of our employees were represented by labor unions or covered by
share incentive plans that are submitted for approval to the board of directors
collective bargaining agreements. We believe that relations with our
employees are satisfactory.
156 GeoPark 20F
E. Share ownership
As of the date of this annual report, members of our board of directors and
Benefit Trust.” Although Mr. Park has voting rights with respect to all the
common shares held in the trust, Mr. Park disclaims beneficial ownership
our senior management held as a group 28,497,744 of our common shares
over those common shares. 498,915 of these common shares have been
and 49.25% of our outstanding share capital.
pledged pursuant to lending arrangements.
The following table shows the share ownership of each member of our board
by Cartica Management, LLC. The common shares reflected as being
of directors and senior management as of the date of this annual report.
held by Mr. Quamme include 8,189 common shares held by him personally.
(3) Held through certain private investment funds managed and controlled
Shareholder
Gerald E. O’Shaughnessy(1)
James F. Park(2)
Steven J. Quamme(3)
Juan Cristóbal Pavez(4)
Carlos Gulisano
Pedro Aylwin
Peter Ryalls
Augusto Zubillaga
Gerardo Hinterwimmer
Salvador Harambour
Marcela Vaca
Dimas Coelho
Carlos Murut
Salvador Minniti
Jose Díaz
Horacio Fontana
Ruben Marconi
Agustina Wisky
Guillermo Portnoi
Andrés Ocampo
Pablo Ducci
Common
shares
7,533,907
7,441,269
9,699,161
2,887,130
117,281
131,431
45,451
*
*
*
*
*
*
*
*
*
*
*
*
*
*
Sub-total senior management
ownership of less than 1%
Total
642,114
28,497,744
Mr. Steven Quamme, one of our principal shareholders and a member of our
Percentage of
board of directors, is the Senior Managing Director of Cartica Management,
outstanding
LLC, and therefore may be deemed to have voting and investment power
common shares
13.02
over the common shares of GeoPark held by Cartica Management, LLC.
(4) Held through Socoservin Overseas Ltd, which is controlled by Juan
Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez
include 9,326 common shares held by him personally.
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
A. Major shareholders
The following table presents the beneficial ownership of our common shares
as of the date of this annual report.
Shareholder
Gerald E. O’Shaughnessy(1)
James F. Park(2)
Steven J. Quamme(3)
IFC Equity Investments(4)
Moneda A.F.I.(5)
Juan Cristóbal Pavez(6)
Other shareholders
Total
1.11
Common
shares
7,533,907
7,441,269
9,699,161
3,456,594
2,598,650
2,887,130
24,246,904
57,863,615
Percentage of
outstanding
common shares
13.02
12.86
16.76
5.97
4.49
4.99
41.90
100.0%
12.86
16.76
4.99
0.20
0.23
0.08
*
*
*
*
*
*
*
*
*
*
*
*
*
*
49.25
(1) Held directly and indirectly through GP Investments LLP, Vidacos
Nominees Limited and Globe Resources Group Inc. 922,482 of these
* Indicates ownership of less than 1% of outstanding common shares.
common shares have been pledged pursuant to lending arrangements.
(1) Held directly and indirectly through GP Investments LLP, Vidacos
(2) Held by Energy Holdings, LLC, which is controlled by James F. Park,
Nominees Limited and Globe Resources Group Inc., all of which are controlled
a member of our Board of Directors. The number of common shares held
by Mr. O’Shaughnessy. 922,482 of these common shares have been pledged
by Mr. Park does not reflect the 822,702 common shares held as of the date
pursuant to lending arrangements.
of this annual report in the employee benefit trust described under “Item 6.
(2) Held by Energy Holdings, LLC, which is controlled by James F. Park, a
Directors, Senior Management and Employees—B. Compensation—
member of our Board of Directors. The number of common shares held by
Employee Benefit Trust.” Although Mr. Park has voting rights with respect
Mr. Park does not reflect the 822,702 common shares held as of the date of
to all the common shares held in the trust, Mr. Park disclaims beneficial
this annual report in the employee benefit trust described under “Item 6.
ownership over those common shares. 498,915 of these common shares
Directors, Senior Management and Employees—B. Compensation—Employee
have been pledged pursuant to lending arrangements.
GeoPark 20F 157
(3) Held through certain private investment funds managed and controlled
the boards of each of GeoPark Chile and GeoPark TdF will consist of four
by Cartica Management, LLC. The common shares reflected as being held
directors; as long as LGI holds at least 5% of the voting shares of GeoPark
by Mr. Quamme include 8,189 common shares held by him personally.
Chile or GeoPark TdF, as applicable, LGI has the right to elect one director and
Mr. Steven Quamme, one of our principal shareholders and a member of our
such director’s alternate, while the remaining directors, and alternates, are
board of directors, is the Senior Managing Director of Cartica Management,
elected by us. Additionally, the agreements require the consent of LGI or its
LLC, and therefore may be deemed to have voting and investment power
appointed director in order for GeoPark Chile or GeoPark TdF, as applicable,
over the common shares of GeoPark held by Cartica Management, LLC.
to be able to take certain actions, including, among others: making any
(4) IFC Equity Investments voting decisions are made through a portfolio
decision to terminate or permanently or indefinitely suspend operations in or
management process which involves consultation from investment officers,
surrender our blocks in Chile (other than as required under the terms of the
credit officers, managers and legal staff.
relevant CEOP for such blocks); selling our blocks in Chile to our affiliates;
(5) Held through various funds managed by Moneda A.F.I. (Administradora
making any change to the dividend, voting or other rights that would give
de Fondos de Inversión), an asset manager.
preference to or discriminate against the shareholders of these companies;
(6) Held through Socoservin Overseas Ltd, which is controlled by Juan
entering into certain related party transactions; and creating a security
Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez
interest over our blocks in Chile (other than in connection with a financing
include 9,326 common shares held by him personally.
that benefits our Chilean subsidiaries). The LGI Chile Shareholders’
Principal shareholders do not have any different or special voting rights in
decides to sell its shares in GeoPark Chile or GeoPark TdF, as applicable,
comparison to any other common shareholder.
the transferring shareholder must make an offer to sell those shares to the
Agreements also provide that: (i) if LGI or either Agencia or GeoPark Chile
Prior to our initial public offering on the NYSE in February of 2014, our
to a third party is subject to tag-along and drag-along rights, and the non-
principal shareholders were Gerald E. O’Shaughnessy (17.18%), James F. Park
transferring shareholder has the right to object to a sale to the third-party
(16.32%), Cartica Management, LLC (11.36%), IFC Equity Investments,
if it considers such third-party to be not of a good reputation or one of
other shareholder before selling them to a third party; and (ii) any sale
(7.88%) and Moneda A.F.I (5.11%).
our direct competitors. We and LGI also agreed to vote our common shares
or otherwise cause GeoPark Chile or GeoPark TdF, as applicable, to
On February 12, 2014, we completed our initial public offering and listed
declare dividends only after allowing for retentions to meet anticipated
our common shares on the New York Stock Exchange. In the initial public
future investments, costs and obligations. See “Item 4. Information on
offering, we issued 13,999,700 common shares (including the overallotment
the Company—B. Business overview—Significant agreements—Agreements
option granted to and exercised by the underwriters). Pursuant to the
with LGI— LGI Chile Shareholders’ Agreements.”
offering, 5,927,571 shares were issued to certain of our principal shareholders,
as follows: James F. Park purchased 285,000 common shares, Cartica
Management, LLC purchased 4,714,000 common shares, and Moneda
LGI Colombia Agreements
On December 18, 2012, we, Agencia, GeoPark Colombia and LGI entered
purchased 928,571 common shares, as reflected in the table above.
B. Related party transactions
We have entered into the following transactions with related parties:
LGI Chile Shareholders’ Agreements
In 2010, we formed a strategic partnership with LGI to acquire and develop
into the LGI Colombia Shareholders’ Agreement and a subscription share
agreement, pursuant to which LGI acquired a 20% interest in GeoPark
Colombia. Further, on January 8, 2014, following an internal corporate
reorganization of our Colombian operations, GeoPark Colombia Coöperatie
U.A. and GeoPark Latin America entered into a new members’ agreement
with LGI, or the LGI Colombia Members’ Agreement, that sets out
substantially similar rights and obligations to the LGI Colombia Shareholders’
jointly upstream oil and gas projects in Latin America. In 2011, LGI acquired a
Agreement in respect of our oil and gas business in Colombia. We refer to
20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark
the LGI Colombia Shareholders’ Agreement and the LGI Colombia Members’
TdF, for a total consideration of US$148.0 million, plus additional equity
Agreement collectively as the LGI Colombia Agreements. The LGI Colombia
funding of US$18.0 million through 2014. On May 20, 2011, in connection
Agreements provide that the board of GeoPark Colombia will consist of four
with LGI’s investment in GeoPark Chile, we and LGI entered into the LGI Chile
directors; as long as LGI holds at least 14% of GeoPark Colombia, LGI has
Shareholders’ Agreements, setting forth our and LGI’s respective rights
the right to elect one director and such director’s alternate, while the
and obligations in connection with LGI’s investment in our Chilean oil and gas
remaining directors, and alternates, are elected by us. Additionally, the LGI
business. Specifically, the LGI Chile Shareholders’ Agreements provide that
Colombia Agreements require the consent of LGI or the LGI appointed
158 GeoPark 20F
director for GeoPark Colombia to be able to take certain actions, including,
amount owed on the performance bond because minimum work obligations
among others: making any decision to terminate or permanently or
imposed by the terms of the bond have been met.
indefinitely suspend operations in or surrender our blocks in Colombia
(other than as required under the terms of the relevant concessions for such
The LGI Stand-by Letters of Credit initially expired on March 31, 2013, and
blocks); creating a security interest over our blocks in Colombia; approving
were renewed until May 18, 2016, and the applicable interest rate is 1.5%. As
of GeoPark Colombia’s annual budget and work programs and the
of December 31, 2013, the aggregate outstanding amount attributable to
mechanisms for funding any such budget or program; entering into any
GeoPark’s share under the LGI Stand-by Letters of Credit was US$52.3 million.
borrowings other than those provided in an approved budget or incurred in
the ordinary course of business to finance working capital needs; granting
any guarantee or indemnity to secure liabilities of parties other than those
IFC Subscription and Shareholders’ Agreement
On February 7, 2006, in order to finance the exploration, development and
of our Colombian subsidiaries; changing the dividend, voting or other rights
exploitation of our blocks in Chile and Argentina and the acquisition of
that would give preference to or discriminate against the shareholders
additional exploration, development and exploitation blocks in Latin America,
of GeoPark Colombia; entering into certain related party transactions; and
we, IFC and Gerald E. O’Shaughnessy and James F. Park, as Lead Investors,
disposing of any material assets other than those provided for in an approved
entered into an agreement, or the IFC Subscription and Shareholders’
budget and work program. The LGI Colombia Agreements also provide that:
Agreement, pursuant to which IFC agreed to subscribe and pay for 2,507,161
(i) if either we or LGI decide to sell our respective shares in GeoPark Colombia,
of our common shares, representing approximately 10.5% of our then-
the transferring shareholder must make an offer to sell those shares to the
outstanding common shares, at an aggregate subscription price of US$10.0
other shareholder before selling those shares to a third party; and (ii) any sale
million (or approximately US$3.99 per common share).
to a third party is subject to tag-along and drag-along rights, and the non-
transferring shareholder has the right to object to a sale to the third-party
We agreed, for so long as IFC is a shareholder in the company, among
if it considers such third-party to be not of a good reputation or one of
other things, to: ensure that our operations are in compliance with certain
our direct competitors. We and LGI also agreed to vote our common shares
environmental and social guidelines; appoint and maintain a technically
or otherwise cause GeoPark Colombia to declare dividends only after
qualified individual to be responsible for the environmental and social
allowing for retentions for approved work programs and budgets, capital
management of our activities; maintain certain forms of insurance coverage,
adequacy and tied surplus requirements of GeoPark Colombia, working
including coverage for public liability and director’s and officer’s liability
capital requirements, banking covenants associated with any loan entered
reasonably acceptable to IFC, and in respect of certain of our operations;
into by GeoPark Colombia or our other Colombian subsidiaries and
not undertake certain prohibited activities; and ensure that no prohibited
operational requirements. See “Item 4. Information on the Company—B.
payments are made by us or on our or the Lead Investors’ behalf, in respect
Business overview—Significant agreements—Agreements with LGI—LGI
of our operations.
Colombia Agreements.”
We also agreed to provide to IFC, within 30 days of the end of the first half
LGI Stand-by Letters of Credit
In 2011, in connection with LGI’s acquisition of a 20% equity interest in
of the year, copies of our unaudited consolidated financial statements
for the period (prepared under IFRS), a report on our capital expenditures
GeoPark Chile and a 14% equity interest in GeoPark TdF for US$148.0 million.
for the period, a comprehensive report on the progress of the exploration,
development and exploitation of our blocks in Latin America and a statement
LGI provided to GeoPark TdF standby letters of credit for an amount of
of all related party transactions during the period, with a certification by a
US$31.6 million (corresponding to its pro rata share in GeoPark TdF) and for
company officer that these were on an arm’s-length basis; within 90 days of
an additional amount of US$52.3 million (or the additional amount),
the end of our fiscal year, copies of our audited consolidated financial
resulting in an aggregate of US$84.0 million in standby letters of credit,
statements for the year (prepared under IFRS), a management letter from our
or the LGI Stand-by Letters of Credit, to partially secure the US$101.4 million
auditors in respect of our financial control procedures, accounting and
performance bond required by the Chilean government to guarantee
management information systems and any litigation, an annual monitoring
GeoPark TdF’s obligations with respect to the first period’s minimum work
report confirming compliance with national or local requirements and the
program under the Tierra del Fuego CEOPs. The remaining US$17.4 million
environmental and social requirements mandated by the agreement, a report
was provided by GeoPark. All costs and liabilities regarding the additional
indicating any payments in the year to any governmental authority in
amount shall be paid by GeoPark. GeoPark has already applied to the Ministry
connection with the documents governing our Chilean and Argentine blocks
of Energy for an aggregate reduction of approximately US$35 million in the
and certificates of insurance, with a certificate of our insurer confirming that
GeoPark 20F 159
effectiveness of our policies and payment of all applicable premiums; within
injunction is lifted. According to the terms of the Court’s injunction, the
45 days before each fiscal year begins, a proposed annual business plan
ANP will first need to take certain actions, such as conducting studies
and budget for the upcoming year; within 3 days after its occurrence,
that prove that drilling unconventional resources will not contaminate the
notification of any incident that had or may reasonably be expected to have
dams and aquifers in the region. On February 21, 2014, GeoPark Brazil
an adverse effect on the environment, health or safety; copies of notices,
requested that the board of the ANP suspend the execution of the concession
reports or other communications between us and our board of directors
agreement (which entails delivery of the financial guarantee and performance
or shareholders; and, within five days of receipt thereof, copies of any
guarantee and payment of the signing bonus) for six months with a possible
reports, correspondence, documentation or notices from any third-party,
extension of an additional six months, or until a firm court decision is reached
governmental authority or state-owned company that could reasonably be
that does not prevent GeoPark Brazil from entering into the concession
expected to materially impact our operations. Mr. O’Shaughnessy and
agreement. On April 16, 2014, the ANP’s Board enacted a resolution stating
Mr. Park have also agreed to procure that shareholders holding 51% of our
that all proceedings related to the award of the concession of Block PN-T-597
common shares cause us to comply with the covenants above.
to GeoPark Brazil were suspended.
Executive Directors’ Service Agreements
We have entered into service contracts with certain of our executive directors.
Dividends and dividend policy
Holders of common shares will be entitled to receive dividends, if any, paid
See “Item 6. Directors, Senior Management and Employees—B.
on the common shares.
Compensation— Executive compensation—Executive directors’ contracts.”
C. Interests of Experts and Counsel
Not applicable.
ITEM 8. FINANCIAL INFORMATION
We have never declared or paid any cash dividends on our common shares.
We intend to retain all of our future earnings, if any, generated by our
operations for the development and growth of our business. Accordingly,
we do not expect to pay cash dividends on our common shares in the
foreseeable future. Because we are a holding company with no direct
operations, we will only be able to pay dividends from our available cash
on hand and any funds we receive from our subsidiaries. The terms
A. Consolidated statements and other financial information
of our indebtedness may restrict us from paying dividends, or restrict our
subsidiaries from paying dividends to us.
Financial statements
See “Item 18. Financial Statements,” which contains our audited financial
Under the Bermuda Companies Act, we may not declare or pay a dividend
statements prepared in accordance with IFRS.
if there are reasonable grounds for believing that we are, or would after the
Legal proceedings
From time to time, we may be subject to various lawsuits, claims and
proceedings that arise in the normal course of business, including
payment be, unable to pay our liabilities as they become due or that the
realizable value of our assets would thereafter be less than our liabilities. We
do not presently have any reasonable grounds for believing that, if we were
to declare or pay a dividend on our common shares outstanding, we would
employment, commercial, environmental, safety and health matters. For
thereafter be unable to pay our liabilities as they became due or that the
example, from time to time, we receive notice of environmental, health
realizable value of our assets would thereafter be less than our liabilities.
and safety violations. It is not presently possible to determine whether any
such matters will have a material adverse effect on our consolidated
Additionally, any decision to pay dividends in the future, and the amount
financial position, results of operations or liquidity.
of any distributions, is at the discretion of our board of directors and
our shareholders, and will depend on many factors, such as our results of
In Brazil, GeoPark Brazil is currently a party to a legal proceeding related to
operations, financial condition, cash requirements, prospects and other
the concession agreement of Block PN-T-597 that the ANP initially awarded to
factors. See “Item 3. Key Information—D. Risk factors—Risks related to our
GeoPark Brazil in the 12th oil and gas bidding round. As a result of a class
common shares—We have never declared or paid, and do not intend to
action filed by the Federal Prosecutor’s Office, an injunction was issued by a
pay in the foreseeable future, cash dividends on our common shares, and,
Brazilian Federal Court against the ANP, the Federal Government and GeoPark
consequently, your only opportunity to achieve a return on your investment
Brazil on December 13, 2013. Due to the injunction GeoPark Brazil could not
is if the price of our stock appreciates” and “—We are a holding company
proceed to execute the concession agreement, and cannot do so until the
dependent upon dividends from our subsidiaries, which may be limited by
160 GeoPark 20F
law and by contract from making distributions to us, which would affect our
The table below presents, for the periods indicated, the annual, quarterly
ability to pay dividends on the common shares,” as well as “Item 10.
and monthly high and low closing prices (in US$) of our common shares on
Additional Information—B. Memorandum of association and bye-laws.”
the NYSE.
B. Significant changes
A discussion of the significant changes in our business can be found under
“Item 4. Information on the Company—A. History and development of the
company— General—Recent Developments.”
ITEM 9. THE OFFER AND LISTING
A. Offering and listing details
Not applicable.
B. Plan of distribution
Not applicable.
C. Markets
On February 6, 2014 we completed our initial public offering and listed our
Annual price history
2014 (from February 7
through April 25, 2014)
Quarterly price history
2014
1st Quarter
(from February 7, 2014)
2nd Quarter
(through April 25, 2014)
Monthly price history
February 2014
common shares on the New York Stock Exchange, or NYSE. For information
(from February 7, 2014)
regarding the price history of our common shares, see “—A. Offering and
listing details.”
March 2014
April 2014
(through April 25, 2014)
Our common shares have been listed on the NYSE under the symbol “GPRK”
since February 7, 2014. They were previously listed on the AIM under the
Source: Bloomberg
symbol “GPK” until February 19, 2014, and, since 2009, have been admitted to
trade on the Santiago Offshore Stock Exchange (Bolsa Off Shore de la Bolsa
de Comercio de Santiago) in Chile. We intend to de-register from the Santiago
D. Selling shareholders
Not applicable.
Offshore Stock Exchange as soon as practicable.
Common shares
Average daily
High
Low
trading
volume
(US$ per share)
(in shares)
8.40
6.45
69,138
8.10
8.40
8.05
8.10
8.40
6.45
78,469
6.76
50,477
6.45
7.07
133,375
39,250
6.76
50,477
E. Dilution
Not applicable.
F. Expenses of the issue
Not applicable.
ITEM 10. ADDITIONAL INFORMATION
A. Share capital
Not applicable.
B. Memorandum of association and bye-laws
The following description of our memorandum of association and bye-laws
does not purport to be complete and is subject to, and qualified by reference
to, all of the provisions of our memorandum of association and bye-laws.
GeoPark 20F 161
General
We are an exempted company with limited liability incorporated under
any, as may be declared from time to time by our board of directors out
of funds legally available for dividend payments. Holders of common shares
the laws of Bermuda with registration number 33273 from the Registrar
have no redemption, sinking fund, conversion, exchange or other
of Companies. The rights of our shareholders will be governed by Bermuda
subscription rights. In the event of our liquidation, the holders of common
law and by our memorandum of association and bye-laws. Bermuda
shares are entitled to share equally and ratably in our assets, if any,
company law differs in some material respects from the laws generally
remaining after the payment of all of our debts and liabilities, subject to
applicable to Delaware corporations. Below is a summary of some of those
any liquidation preference on any outstanding preference shares.
material differences.
Because the following statements are summaries, they do not discuss all
Board composition
Our bye-laws provide that our board of directors will determine the size
aspects of Bermuda law that may be relevant to us and to our shareholders.
of the board, provided that it shall be not be composed of fewer than three
directors. Our board of directors currently consists of seven directors.
Share capital and bye-laws
Our share capital consists of common shares only. Our authorized share
capital consists of 5,171,949,000 common shares of par value US$0.001
Election and removal of directors
Our bye-laws preserve the staggered board provisions in effect prior to
per share. As of the date of this annual report, there are 57,863,615 common
our delisting from AIM until the annual general meeting following the listing
shares outstanding. All of our issued and outstanding common shares are
of the common shares on the NYSE. From and after the date of such
fully paid and nonassessable. We also have an employee incentive program,
annual general meeting, our directors shall hold office for such term as the
pursuant to which we have granted share awards to our senior management
shareholders shall determine or, in the absence of such determination,
and certain key employees. See “Item 6. Directors, Senior Management
until the next annual general meeting or until their successors are elected or
and Employees.”
appointed or their office is otherwise vacated. Directors whose office has
expired may offer themselves for re-election at each election of the directors.
According to our bye-laws, if our share capital is divided into different
classes of shares, the rights attached to any class (unless otherwise provided
Under our bye-laws, a director may be removed by a resolution adopted
by the terms of issue of the shares of that class) may, whether or not the
by 65% or more of the votes cast by shareholders who (being entitled to
Company is being wound-up, be varied with the consent in writing of
do so) vote in person or by proxy at any general meeting of the shareholders
the holders of at least two-thirds of the issued shares of that class or with the
in accordance with the provisions of our bye-laws. Notice convened for
sanction of a resolution passed by a majority of the votes cast at a separate
the purpose of removing the director, containing a statement of the intention
general meeting of the holders of the shares of the class at which meeting
to do so, must be served on such director not less than 14 days before
the necessary quorum shall be two persons at least holding or representing
the meeting.
by proxy one-third of the issued shares of the class. The rights conferred
upon the holders of the shares of any class issued with preferred or other
rights shall not, unless otherwise expressly provided by the terms of issue of
Any vacancy created by the removal of a director at a special general meeting
may be filled at that meeting by the election of another director in his or
the shares of that class, be deemed to be varied by the creation or issue of
her place or, in the absence of any such election, by the board of directors.
further shares ranking pari passu therewith.
Any other vacancy, including a newly created directorship, may be filled by
our board of directors.
Our bye-laws give our board of directors the power to issue any unissued
shares of the company on such terms and conditions as it may determine,
subject to the terms of the bye-laws and any resolution of the shareholders
to the contrary.
Common shares
Holders of our common shares are entitled to one vote per share on all
Proceedings of board of directors
Our bye-laws provide that our business shall be managed by or under
the direction of our board of directors. Our board of directors may act by the
affirmative vote of a majority of the directors present at a meeting at which
a quorum is present. The quorum necessary for the transaction of business at
meetings of the board of directors shall be the presence of a majority of the
matters submitted to a vote of holders of common shares. Subject to
board of directors from time to time.
preferences that may be applicable to any issued and outstanding preference
shares, holders of common shares are entitled to receive such dividends, if
162 GeoPark 20F
Duties of directors
Under Bermuda common law, members of a board of directors owe a
Interested directors
Pursuant to our bye-laws, a director shall declare the nature of his interest
fiduciary duty to the Company to act in good faith in their dealings with or
in any contract or arrangement with the company as required by
on behalf of the company, and to exercise their powers and fulfill the duties
the Bermuda Companies Act. A director so interested shall not, except in
of their office honestly. This duty has the following essential elements:
particular circumstances set out in our bye-laws, be entitled to vote or
(1) a duty to act in good faith in the best interests of the company; (2) a duty
be counted in the quorum at a meeting in relation to any resolution in which
not to make a personal profit from opportunities that arise from the office
he has an interest, which is to his knowledge, a material interest (otherwise
of director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise
than by virtue of his interest in shares or debentures or other securities
powers for the purpose for which such powers were intended. The Bermuda
of or otherwise in or through the company). In addition, the director will not
Companies Act also imposes a duty on directors of a Bermuda company,
be liable to us for any profit realized from the transaction. In contrast,
to act honestly and in good faith, with a view to the best interests of the
under Delaware law, such a contract or arrangement is voidable unless it is
company, and to exercise the care, diligence and skill that a reasonably
approved by a majority of disinterested directors or by a vote of shareholders,
prudent person would exercise in comparable circumstances. In addition,
in each case if the material facts as to the interested director’s relationship
the Bermuda Companies Act imposes various duties on directors with respect
or interests are disclosed or are known to the disinterested directors or
to certain matters of management and administration of the company.
shareholders, or such contract or arrangement is fair to the corporation
as of the time it is approved or ratified. Additionally, such interested director
The Bermuda Companies Act provides that in any proceedings for negligence,
could be held liable for a transaction in which such director derived an
default, breach of duty or breach of trust against any director, if it appears
improper personal benefit.
to a court that such officer is or may be liable in respect of the negligence,
default, breach of duty or breach of trust, but that he has acted honestly
and reasonably, and that, having regard to all the circumstances of the case,
Indemnification of directors and officers
Bermuda law provides generally that a Bermuda company may indemnify
including those connected with his appointment, he ought fairly to be
its directors and officers against any loss arising from or liability which by
excused for the negligence, default, breach of duty or breach of trust, that
virtue of any rule of law would otherwise be imposed on them in respect of
court may relieve him, either wholly or partly, from any liability on such terms
any negligence, default, breach of duty or breach of trust except in cases
as the court may think fit. This provision has been interpreted to apply only
where such liability arises from fraud or dishonesty of which such director
to actions brought by or on behalf of the company against the directors.
or officer may be guilty in relation to the company.
By comparison, under Delaware law, the business and affairs of a corporation
Our bye-laws provide that we shall indemnify our officers and directors in
are managed by or under the direction of its board of directors. In exercising
respect of their actions and omissions, except in respect of their fraud or
their powers, directors are charged with a duty of care and a duty of loyalty.
dishonesty, or to recover any gain, personal profit or advantage to which such
The duty of care requires that directors act in an informed and deliberate
director is not legally entitled, and (by incorporation of the provisions of the
manner and to inform themselves, prior to making a business decision,
of all relevant material information reasonably available to them. The duty
Bermuda Companies Act) that we may advance monies to our officers and
directors for costs, charges and expenses incurred by our officers and directors
of care also requires that directors exercise care in overseeing the conduct
in defending any civil or criminal proceeding against them on the condition
of corporate employees. The duty of loyalty is the duty to act in good faith,
that the officers and directors repay the monies if any allegation of fraud or
not out of self-interest, and in a manner which the director reasonably
dishonesty is proved against them provided, however, that, if the Bermuda
believes to be in the best interests of the shareholders. A party challenging
Companies Act requires, an advancement of expenses shall be made only upon
the propriety of a decision of a board of directors bears the burden of
delivery to the Company of an undertaking ,by or on behalf of such indemnitee,
rebutting the presumptions afforded to directors by the “business judgment
to repay all amounts so advanced if it shall ultimately be determined
rule.” If the presumption is not rebutted, the business judgment rule attaches
by final judicial decision from which there is no further right to appeal that
to protect the directors and their decisions. Where, however, the presumption
such indemnitee is not entitled to be indemnified for such expenses
is rebutted, the directors bear the burden of demonstrating the fairness
under this Bye-law or otherwise. Our bye-laws provide that the company and
of the relevant transaction. Notwithstanding the foregoing, Delaware courts
the shareholders waive all claims or rights of action that they might have,
subject directors’ conduct to enhanced scrutiny in respect of defensive
individually or in right of the company, against any of the company’s directors
actions taken in response to a threat to corporate control and approval of a
or officers for any act or failure to act in the performance of such director’s or
transaction resulting in a sale of control of the corporation.
officer’s duties, except in respect of any fraud or dishonesty.
GeoPark 20F 163
Meetings of shareholders
Under Bermuda law, a company is required to convene the annual general
Business combinations
A Bermuda company may engage in a business combination pursuant to
meeting of shareholders each calendar year, unless the shareholders in a
a tender offer, amalgamation, merger or sale of assets. The amalgamation or
general meeting, elect to dispense with the holding of annual general
merger of a Bermuda company with another company generally requires
meetings. Under Bermuda law and our bye-laws, a special general meeting of
the amalgamation or merger agreement to be approved by the company’s
shareholders may be called by the board of directors or the chairman and
board of directors and by its shareholders. Shareholder approval is not
may be called upon the requisition of shareholders holding not less than 10%
required where (a) a holding company and one or more of its wholly-owned
of the paid-up capital of the company carrying the right to vote at general
subsidiary companies amalgamate or merge or (b) two or more wholly-
meetings of shareholders.
owned subsidiary companies of the same holding company amalgamate
or merge. Under the Bermuda Companies Act (save for such “short-form
Our bye-laws provide that, at any general meeting of the shareholders, the
amalgamations”), unless a company’s bye-laws provide otherwise,
presence in person or by proxy of two or more shareholders representing in
the approval of 75% of the shareholders voting at a meeting is required
excess of 50% of the total issued voting shares of the company shall
to approve the amalgamation or merger agreement, and the quorum for
constitute a quorum for the transaction of business unless the company only
such meeting must be two persons holding or representing more than
has one shareholder, in which case such shareholder shall constitute a
one-third of the issued shares of the company. Our bye-laws provide that an
quorum. Unless otherwise required by law or by our bye-laws, shareholder
amalgamation or merger will require the approval of our board of directors
action requires a resolution adopted by a majority of votes cast by
and of our shareholders by a resolution adopted by 65% or more of the
shareholders at a general meeting at which a quorum is present.
votes cast by shareholders who (being entitled to do so) vote in person or
Shareholder proposals
Under Bermuda law, shareholders holding at least 5% of the total voting
by proxy at any general meeting of the shareholders in accordance with
the provisions of the bye-laws. Under Bermuda law, in the event of an
amalgamation or merger of a Bermuda company with another company or
rights of all the shareholders having at the date of the requisition a right
corporation, a shareholder who is not satisfied that fair value has been
to vote at the meeting to which the requisition relates or any group
offered for such shareholder’s shares may, within month of the notice of the
composed of at least 100 or more shareholders may require a proposal to
shareholders meeting, apply to the Supreme Court of Bermuda to appraise
be submitted to an annual general meeting of shareholders. Under our
the value of those shares.
bye-laws, any shareholders wishing to nominate a person for election as
a director or propose business to be transacted at a meeting of shareholders
Under the Bermuda Companies Act, we are not required to seek the approval
must provide (among other things) advance notice, as set out in our
of our shareholders for the sale of all or substantially all of our assets.
bye-laws. Shareholders may only propose a person for election as a director
However, Bermuda courts will view decisions of the English courts as highly
at an annual general meeting.
persuasive and English authorities suggest that such sales do require
shareholder approval. Our bye-laws provide that the directors shall manage
Shareholder action by written consent
Our bye-laws provide that, except for the removal of auditors and directors,
the business of the Company and may exercise all such powers as are not,
by the Bermuda Companies Act or by these Bye-laws, required to be
any actions which shareholders may take at a general meeting of
exercised by the Company in general meeting and may pay all expenses
shareholders may be taken by the shareholders through the unanimous
incurred in promoting and incorporating the company and may exercise all
written consent of the shareholders who would be entitled to vote on the
the powers of the Company including, but not by way of limitation, the
matter at the general meeting.
power to borrow money and to mortgage or charge all or any part of the
undertaking property and assets (present and future) and uncalled capital
Amendment of memorandum of association and bye-laws
Our memorandum of association and bye-laws may be amended with the
of the Company and to issue debentures and other securities, whether
outright or as collateral security for any debt, liability or obligation of the
approval of a majority of our board of directors and by a resolution by a
Company or any other persons.
majority of the votes cast by shareholders who (being entitled to do so) vote
in person or by proxy at any general meeting of the shareholders in
Under Bermuda law, where an offer is made for shares of a company and,
accordance with the provisions of the bye-laws.
within four months of the offer, the holders of not less than 90% of the shares
not owned by the offeror, its subsidiaries or their nominees accept such offer,
the offeror may by notice require the non-tendering shareholders to transfer
their shares on the terms of the offer. Dissenting shareholders do not have
164 GeoPark 20F
express appraisal rights but are entitled to seek relief (within one month of
association and any amendments thereto. The shareholders have the
the compulsory acquisition notice) from the court, which has power to make
additional right to inspect the bye-laws of the company, minutes of general
such orders as it thinks fit. Additionally, where one or more parties hold
meetings of shareholders and the company’s audited financial statements.
not less than 95% of the shares of a company, such parties may, pursuant to
The company’s audited financial statements must be presented at the annual
a notice given to the remaining shareholders, acquire the shares of such
general meeting of shareholders, unless the board and all the shareholders
remaining shareholders. Dissenting shareholders have a right to apply
agree to the waiving of the audited financials. The company’s share register
to the court for appraisal of the value of their shares within one month of the
is open to inspection by shareholders and by members of the general
compulsory acquisition notice. If a dissenting shareholder is successful in
public without charge. A company is required to maintain its share register in
obtaining a higher valuation, that valuation must be paid to all shareholders
Bermuda but may, subject to the provisions of the Bermuda Companies Act,
being squeezed out.
Dividends and repurchase of shares
Pursuant to our bye-laws, our board of directors has the authority to declare
dividends and authorize the repurchase of shares subject to applicable law.
Under Bermuda law, a company may not declare or pay a dividend if there are
establish a branch register outside of Bermuda. Bermuda law does not,
however, provide a general right for shareholders to inspect or obtain copies
of any other corporate records.
Registrar or transfer agent
A register of holders of the common shares is maintained by Coson Corporate
reasonable grounds for believing that the company is, or would after the
Services Limited in Bermuda, and a branch register is maintained in the
payment be, unable to pay its liabilities as they become due or the realizable
United States by Computershare Trust Company, N.A., who serves as branch
value of its assets would thereby be less than its liabilities. Under Bermuda
registrar and transfer agent.
law, a company cannot purchase its own shares if there are reasonable
grounds for believing that the company is, or after the repurchase would be,
unable to pay its liabilities as they become due.
C. Material contracts
See “Item 4. Information on the Company—B. Business overview—Significant
Shareholder suits
Class actions and derivative actions are generally not available to
shareholders under Bermuda law. The Bermuda courts, however, would
ordinarily be expected to permit a shareholder to commence an action
in the name of a company to remedy a wrong to the company where
the act complained of is alleged to be beyond the corporate power of the
agreements.”
D. Exchange controls
Not applicable.
E. Taxation
The following summary contains a description of certain Colombian and U.S.
company or illegal, or would result in the violation of the company’s
federal income tax consequences of the acquisition, ownership and disposition
memorandum of association or bye-laws. Furthermore, consideration
of preferred shares. The summary is based upon the tax laws of Colombia and
would be given by a Bermuda court to acts that are alleged to constitute a
regulations thereunder and on the tax laws of the United States and regulations
fraud against the minority shareholders or where an act requires the
approval of a greater percentage of the company’s shareholders than that
which actually approved it.
thereunder as of the date hereof, which are subject to change.
Bermuda tax considerations
At the date of this annual report, there is no Bermuda income or profits
When the affairs of a company are being conducted in a manner which is
tax, withholding tax, capital gains tax, capital transfer tax, estate duty or
oppressive or prejudicial to the interests of some part of the shareholders,
inheritance tax payable by us or by our shareholders in respect of our
one or more shareholders may apply under the Bermuda Companies
common shares. We have obtained an assurance from the Minister of Finance
Act for an order of the Supreme Court of Bermuda, which may make such
of Bermuda under the Exempted Undertakings Tax Protection Act 1966
order as it sees fit, including an order regulating the conduct of the
that, in the event that any legislation is enacted in Bermuda imposing any
company’s affairs in the future or ordering the purchase of the shares of
tax computed on profits or income, or computed on any capital asset, gain
any shareholders by other shareholders or by the company.
or appreciation or any tax in the nature of estate duty or inheritance tax,
Access to books and records and dissemination of information
Members of the general public have a right to inspect the public documents
such tax shall not, until March 31, 2035, be applicable to us or to any of our
operations or to our common shares, debentures or other obligations except
insofar as such tax applies to persons ordinarily resident in Bermuda or is
of a company available at the office of the Registrar of Companies in
payable by us in respect of real property owned or leased by us in Bermuda.
Bermuda. These documents include the company’s memorandum of
We pay annual Bermuda government fees.
GeoPark 20F 165
Material U.S. federal income tax considerations
The following is a description of the material U.S. federal income tax
A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal
income tax purposes that is:
consequences to U.S. Holders (as defined below) of owning and disposing
• a citizen or individual resident of the United States;
of our common shares. This discussion is not a comprehensive description
• a corporation, or other entity taxable as a corporation, created or organized
of all tax considerations that may be relevant to a particular person’s decision
in or under the laws of the United States, any state therein or the District of
to acquire our common shares. This discussion applies only to a U.S. Holder
Columbia; or
that holds our common shares as capital assets for tax purposes. In addition,
• an estate or trust the income of which is subject to U.S. federal income
it does not describe all of the tax consequences that may be relevant
taxation regardless of its source.
in light of the U.S. Holder’s particular circumstances, including alternative
minimum tax and Medicare contribution tax consequences and differing tax
This discussion assumes that we are not, and will not become, a passive
consequences applicable to a U.S. Holder subject to special rules, such as:
foreign investment company, as described below.
• certain financial institutions;
• a dealer or trader in securities who uses a mark-to-market method of tax
accounting;
Taxation of distributions
Distributions paid on our common shares will generally be treated as
• a person holding common shares as part of a straddle, wash sale or
dividends to the extent paid out of our current or accumulated earnings
conversion transaction or entering into a constructive sale with respect to
and profits (as determined under U.S. federal income tax principles). Because
the common shares;
we do not maintain calculations of our earnings and profits under U.S.
• a person whose functional currency for U.S. federal income tax purposes is
federal income tax principles, it is expected that distributions will generally
not the U.S. dollar;
be reported to U.S. Holders as dividends. Dividends paid by qualified foreign
• a partnership or other entities classified as partnerships for U.S. federal
corporations to certain non-corporate U.S. Holders may be taxable at
income tax purposes;
favorable rates. A foreign corporation is treated as a qualified foreign
• a tax-exempt entity, including an “individual retirement account” or “Roth
corporation with respect to dividends paid on stock that is readily tradable
IRA;”
on a securities market in the United States, such as the NYSE, which has
• a person that owns or is deemed to own 10% or more of our voting stock;
approved the listing of our common shares for trading. Non-corporate U.S.
• a person who acquired our shares pursuant to the exercise of an employee
Holders should consult their tax advisers to determine whether the favorable
stock option or otherwise as compensation; or
rate will apply to dividends they receive and whether they are subject to
• a person holding common shares in connection with a trade or business
any special rules that limit their ability to be taxed at this favorable rate.
conducted outside of the United States.
If an entity that is classified as a partnership for U.S. federal income
received, will be treated as foreign-source income to U.S. Holders
tax purposes holds common shares, the U.S. federal income tax treatment
and will not be eligible for the dividends-received deduction generally
of a partner will generally depend on the status of the partner and upon
the activities of the partnership. Partnerships holding common shares and
available to U.S. corporations under the Code with respect to dividends
paid by domestic corporations.
A dividend generally will be included in a U.S. Holder’s income when
partners in such partnerships should consult their tax advisers as to the
particular U.S. federal income tax consequences of their investment in our
common shares.
Sale or other taxable disposition of common shares
Subject to the passive foreign investment company rules described below,
gain or loss realized on the sale or other taxable disposition of our common
This discussion is based on the Internal Revenue Code of 1986, as amended,
shares will be capital gain or loss, and will be long-term capital gain or loss
or the Code, administrative pronouncements, judicial decisions, and final,
if the U.S. Holder held our common shares for more than one year. Long-term
temporary and proposed Treasury regulations, all as of the date hereof, any
capital gain of a non-corporate U.S. Holder is generally taxed at preferential
of which is subject to change, possibly with retroactive effect. U.S. Holders
rates. The deductibility of capital losses is subject to limitations. The amount
should consult their tax advisers concerning the U.S. federal, state, local and
of the gain or loss will equal the difference between the U.S. Holder’s
foreign tax consequences of owning and disposing of our common shares in
tax basis in the common shares disposed of and the amount realized on the
their particular circumstances.
disposition. This gain or loss will generally be U.S.-source gain or loss for
foreign tax credit purposes.
166 GeoPark 20F
Passive foreign investment company rules
We believe that we were not a “passive foreign investment company,” or
Chilean tax on transfers of shares
In September 2012, Article 10 of the Chilean Income Tax Law Decree Law
PFIC, for U.S. federal income tax purposes for 2013, and we do not expect to
No. 824 of 1974, or the indirect transfer rules, were enacted, and impose taxes
be a PFIC in the foreseeable future. However, because the composition of
on the indirect transfer of shares, equity rights, interests or other rights in
our income and assets will vary over time, there can be no assurance that we
the equity, control or profits of a Chilean entity as well as transfers of other
will not be a PFIC for any taxable year. The determination of whether we
assets and property of permanent establishments or other businesses in
are a PFIC is made annually and is based upon the composition of our income
Chile, or the Chilean Assets.
and assets (including the income and assets of, among others, entities in
which we hold at least a 25% interest), and the nature of our activities.
The indirect transfer rules apply to sales of shares of an entity:
• If such entity is an offshore holding company located in a black-listed tax
If we were a PFIC for any taxable year during which a U.S. Holder held our
haven jurisdiction as determined by Chilean tax law, or a black-listed
common shares, gain recognized by a U.S. Holder on a sale or other
jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean
disposition (including certain pledges) of our common shares would
resident holds 5% or more of such entity, or such entity’s rights to equity,
generally be allocated ratably over the U.S. Holder’s holding period for the
control or profits, or 50% or more of such entity’s rights to equity or profits
common shares. The amounts allocated to the taxable year of the sale or
are held by residents in black-listed jurisdictions; or
other disposition and to any year before we became a PFIC would be taxed
• the shares or rights transferred represent 10% or more of the offshore
as ordinary income. The amount allocated to each other taxable year
holding company (considering dispositions by related persons and over the
would be subject to tax at the highest rate in effect for individuals or
preceding 12-month period) and the underlying Chilean Assets indirectly
corporations for that year, as appropriate, and an interest charge would be
transferred, in the proportion indirectly owned by the seller, (a) are valued in
imposed. Further, to the extent that any distribution received by a U.S.
an amount equal to or higher than UTA 210,000 (approximately US$200
Holder on its common shares exceeds 125% of the average of the annual
million) (adjusted by the Chilean inflation unit of reference) or (b) represent
distributions on the shares received during the preceding three years or
20% or more of the market value of the interest held by such seller in such
the U.S. Holder’s holding period, whichever is shorter, that distribution would
offshore holding company.
be subject to taxation in the same manner as gain, as described immediately
above. Certain elections may be available that would result in alternative
As a result of these rules, a capital gain tax of 35% will be applied by the
treatments (such as mark-to-market treatment) of our common shares.
Chilean tax authorities to the sale of any of our common shares if either of
U.S. Holders should consult their tax advisers to determine whether any of
the above alternative are met. This rate might be subject to change in the
these elections would be available and, if so, what the consequences of the
short term. See “Item 4. Information on the Company—Business Overview—
alternative treatments would be in their particular circumstances.
Regulation of the oil and gas industry—Chile”.
Information reporting and backup withholding
Payments of dividends and sales proceeds that are made within the United
States or through certain U.S.-related financial intermediaries generally are
As of December 31, 2013, our Chilean Assets represented more than UTA
210,000 and represent more than 20% of our market value.
subject to information reporting and may be subject to backup withholding
The 35% rate is calculated pursuant to one of the following methods, as
unless (1) the U.S. Holder is a corporation or other exempt recipient or
determined by the seller:
(2) in the case of backup withholding, the U.S. Holder provides a correct
taxpayer identification number and certifies that it is not subject to backup
• the sale price of the shares minus the acquisition cost of such shares,
withholding. The amount of any backup withholding from a payment to
multiplied by the percentage or proportion of the part of the underlying
a U.S. Holder will be allowed as a credit against the holder’s U.S. federal
Chilean Assets’ fair market value (which assets are deemed to be “indirectly
income tax liability and may entitle it to a refund, provided that the required
transferred” by virtue of the sale of shares) to the fair market value of the
information is timely furnished to the Internal Revenue Service.
shares of the seller; or
• the portion of the sales price of the shares equal to the proportion of the
fair market value of the underlying Chilean Assets, minus the corresponding
proportion in the tax cost of such Chilean Assets for the corresponding
holding entity.
GeoPark 20F 167
However, the seller may opt to be taxed as if the underlying Chilean Assets
had been sold directly in which case a different set of tax rules may apply.
H. Documents on display
We are subject to the informational requirements of the Exchange Act.
Accordingly, we are required to file reports and other information with the SEC,
The tax is payable by the seller of the shares; however, the buyer shall make
including annual reports on Form 20-F and reports on Form 6-K. You may
a provisional withholding unless the seller declares and pays the tax within
inspect and copy reports and other information filed with the SEC at the Public
the month following the sale, payment, remittance or it is credited into
Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on
its account or is put at its disposal. Also, if the seller fails to declare and pay
the operation of the Public Reference Room may be obtained by calling the
this tax, and the buyer has not complied with its withholding obligations, the
SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website that
Chilean tax authority (Servicio de Impuestos Internos) may charge such tax
contains reports and other information about issuers, like us, that file
directly to any of them. In addition, the Chilean tax authority may require us,
electronically with the SEC. The address of that website is www.sec.gov.
the seller, the buyer, or its representative in Chile, to file an affidavit with
the information necessary to assess this tax.
Based on information available to us, (i) no Chilean resident holds 5% or more of
our rights to equity, control or profits; or (ii) residents in black-listed jurisdictions
I. Subsidiary information
Not applicable.
hold 50% or more of our rights to equity, control or profits. Therefore, we do not
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES
believe the indirect transfer rules will apply to transfers of our common shares,
ABOUT MARKET RISK
unless the shares or rights transferred represent 10% or more of the company and
the other conditions described above are met (considering dispositions by related
We are exposed to a variety of market risks, including commodity price risk,
persons and over the preceding 12-month period).
interest rate risk, currency risk and credit (counterparty and customer) risk.
However, there can be no assurance that, at any time in the future, a Chilean
changes in interest rates, oil and natural gas prices and foreign currency
The term “market risk” refers to the risk of loss arising from adverse
resident will not hold 5% or more of our rights to equity, control or profits or
exchange rates.
that residents in black-listed jurisdictions will not hold 50% or more of our
rights to equity, control or profits. If this were to occur, all sales of our common
For further information on our market risks, please see Note 3 to our audited
shares would be subject to the indirect transfer tax referred to above.
consolidated financial statements.
Our expectations regarding the indirect transfer rules are based on our
understandings, analysis and interpretation of these enacted indirect transfer
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
rules, which are subject to additional interpretation and rule-making by the
Chilean authorities. As such, there is uncertainty relating to the application by
Chilean authorities of the indirect transfer rules on us.
A. Debt securities
Not applicable.
See “Item 3. Key Information—D. Risk Factors—Risks related to our common
shares—The transfer of our common shares may be subject to capital gains
B. Warrants and rights
Not applicable.
taxes pursuant to recently-enacted indirect transfer rules in Chile.”
C. Other securities
Not applicable.
D. American Depositary Shares
Not applicable.
F. Dividends and paying agents
Not applicable.
G. Statement by experts
Not applicable.
168 GeoPark 20F
Part II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
A. Defaults
No matters to report.
B. Arrears and delinquencies
No matters to report.
D. Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting that
occurred during the period covered by this annual report that has materially
affected, or is reasonably likely to materially affect, our internal control over
financial reporting.
ITEM 16. [RESERVED]
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY
ITEM 16A. Audit committee financial expert
HOLDERS AND USE OF PROCEEDS
Not applicable.
ITEM 15. CONTROLS AND PROCEDURES
We have determined that Mr. Peter Ryalls and Mr. Juan Cristóbal Pavez
are independent, as such term is defined under SEC rules applicable
to foreign private issuers. In accordance with NYSE rules, we expect to have
a fully independent audit committee within one year of listing. In addition,
Mr. Steve Quamme and Mr. Juan Cristobal Pavez are regarded as audit
A. Disclosure Controls and Procedures
As of December 31, 2013, under the supervision and with the participation
committee financial experts.
of our management, including our Chief Executive Officer and Chief Financial
ITEM 16B. Code of Conduct
Officer, we performed an evaluation of the effectiveness of the design
and operation of our disclosure controls and procedures (as defined in Rule
We have adopted a code of conduct applicable to the board of directors
13a-15(e) under the Exchange Act). There are inherent limitations to
and all employees. Since its effective date on September 24, 2012, we have
the effectiveness of any disclosure controls and procedures system, including
not waived compliance with or amended the code of conduct.
the possibility of human error and circumventing or overriding them. Even
if effective, disclosure controls and procedures can provide only reasonable
ITEM 16C. Principal Accountant Fees and Services
assurance of achieving their control objectives.
Amounts billed by Price Waterhouse & Co. S.R.L. for audit and other services
Based on such evaluation, our Chief Executive Officer and Chief Financial
were as follows:
Officer concluded that our disclosure controls and procedures are effective
to provide reasonable assurance that the information we are required
to disclose in the reports we file or submit under the Exchange Act is (1)
recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms and (2) accumulated and
Audit fees
Audit-related fees
communicated to our management to allow timely decisions regarding
Tax fees
required disclosures.
Other fees paid
Total
2013
2012
(In US$ millions)
0.81
0.03
0.26
0.33
1.43
0.40
0.59
0.12
0.30
1.41
B. Management’s Annual Report on Internal Control over Financial
Reporting
This annual report does not include a report of management's assessment
Audit Fees
Audit fees are fees billed for professional services rendered by the principal
regarding internal control over financial reporting due to a transition period
accountant for the audit of the registrant’s annual financial statements
established by rules of the Securities and Exchange Commission for newly
or services that are normally provided by the accountant in connection with
public companies, or an attestation report of the company’s registered public
statutory and regulatory filings or engagements for those fiscal years.
accounting firm.
It includes the audit of our annual consolidated financial statements and
other services that generally only the independent accountant reasonably
C. Attestation Report of the Registered Public Accounting Firm
Not applicable.
can provide, such as comfort letters, statutory audits, consents and
assistance with and review of documents filed with the Securities and
Exchange Commission.
GeoPark 20F 169
Audit-Related Fees
Audit-related fees are fees billed for assurance and related services that
ITEM 16D. Exemptions from the listing standards for audit committees
are reasonably related to the performance of the audit or review of our
Under NYSE and SEC rules for listed companies, we must comply with Rule
consolidated financial statements for fiscal years 2013 and 2012 and
10A-3 under the Securities Exchange Act (Listing Standards Relating to
not reported under the previous category. These services would include,
Audit Committees). Rule 10A-3 provides that we should establish an audit
among others: accounting consultations and audits in connection with
committee composed of members of the board of directors, meet the
acquisitions, internal control reviews, attest services that are not required by
requirements specified in the listing standards, or appoint and establish a
statue or regulation and consultation concerning financial accounting and
board of auditors or similar body to perform the role of the audit committee,
in reliance on the general exemption of audit committees of foreign
private issuers set forth in Rule 10A-3(c)(3) of the Securities Exchange Act.
We have determined that Mr. Peter Ryalls and Mr. Juan Cristóbal Pavez are
independent, as such term is defined under SEC rules applicable to foreign
private issuers. In accordance with NYSE rules, we expect to have a fully
independent audit committee within one year of listing.
reporting standards.
Tax Fees
Tax fees are fees billed for professional services for tax compliance, tax
advice and tax planning.
Pre-Approval Policies and Procedures
Following the listing of our common shares on the NYSE, the Audit
Committee proposes the appointment of the independent auditor to the
Board to be put to shareholders for approval at the Annual General meeting.
The committee oversees the auditor selection process for new auditors
and ensures key partners in the appointed firm are rotated in accordance
with best practices. Also, following our NYSE listing, the Audit Committee
is required to pre-approve the audit and non-audit fees and services
performed by the Company’s auditors in order to assure that the provision
of such services does not impair the audit firm’s independence.
All of the audit fees, audit-related fees and tax fees described in this item
16C have been approved by the Audit Committee.
170 GeoPark 20F
ITEM 16E. Purchases of equity securities by the issuer and affiliated
purchasers
The following table reflects purchases of our common shares by or on behalf
of us or by any affiliated purchaser in 2013.
Total number of
common shares
Maximum number
(or approximate
dollar value)
purchased as part
of common shares
Total number
Average price
of publicly
that may yet
of common shares
paid per common
announced plans
be purchased under
purchased
share in GPB
or programs
—
—
—
—
—
—
—
—
—
—
50,000
—
50,000
—
—
—
—
—
—
—
—
—
—
5.41
—
5.41
—
—
—
—
—
—
—
—
—
—
—
—
—
the plans or programs
—
—
—
—
—
—
—
—
—
—
—
—
—
2013
January 1 to January 31
February 1 to February 28
March 1 to March 31
April 1 to April 30
May 1 to May 31
June 1 to June 30
July 1 to July 31
August 1 to August 31
September 1 to September 30
October 1 to October 31
November 1 to November 30(1)
December 1 to December 31
Total
(1) Purchased pursuant to the Purchase Program for the account of
303A.11 of the NYSE Listed Company Manual, a brief, general summary of
the EBT. See “Item 6. Directors, Senior Management and Employees—B.
those differences is provided as follows.
Compensation—Share Repurchase Program” for a description.
ITEM 16F. Change in registrant’s certifying accountant
Not applicable.
ITEM 16G. Corporate governance
Director independence
The NYSE Standards require a majority of the membership of NYSE-listed
company boards to be composed of independent directors. Neither
Bermuda law, the law of our country of incorporation, nor our memorandum
of association or bye-laws require a majority of our board to consist of
independent directors.
Our common shares are listed on the New York Stock Exchange, or NYSE.
We are therefore required to comply with certain of the NYSE’s corporate
governance listing standards, or the NYSE Standards. As a foreign private
Non-management directors’ executive sessions
The NYSE Standards require non-management directors of NYSE-listed
issuer, we may follow our home country’s corporate governance practices in
companies to meet at regularly scheduled executive sessions without
lieu of most of the NYSE Standards. Our corporate governance practices
management. Our memorandum of association and bye-laws do not require
differ in certain significant respects from those that U.S. companies must
our non-management directors to hold such meetings.
adopt in order to maintain NYSE listing and, in accordance with Section
GeoPark 20F 171
Committee member composition
The NYSE Standards require domestic NYSE-listed domestic companies
Foreign private issuers such as us are exempt from these additional
requirements if home country practice is followed. Bermuda law does not
to have a nominating/corporate governance committee and a compensation
impose similar requirements, and consequently, our audit committee
committee that are composed entirely of independent directors. Bermuda
does not perform these additional functions.
law, the law of our country of incorporation, does not impose similar
requirements.
Independence of the compensation committee and its advisers
On January 11, 2013, the SEC approved NYSE listing standards that require
Miscellaneous
In addition to the above differences, we are not required to: make our audit
and compensation committees prepare a written charter that addresses
either purposes and responsibilities or performance evaluations in a manner
that the board of directors of a domestic listed company consider two factors
that would satisfy the NYSE’s requirements; acquire shareholder approval
(in addition to the existing general independence tests) in the evaluation
of equity compensation plans in certain cases; or adopt and make publicly
of the independence of compensation committee members: (i) the source of
available corporate governance guidelines.
compensation of the director, including any consulting, advisory or other
compensatory fees paid by the listed company, and (ii) whether the director
We are incorporated under, and are governed by, the laws of Bermuda.
has an affiliate relationship with the listed company, a subsidiary of the listed
For a summary of some of the differences between provisions of Bermuda
company or an affiliate of a subsidiary of the listed company. In addition,
law applicable to us and the laws applicable to companies incorporated
before selecting or receiving advice from a compensation consultant or other
in Delaware and their shareholders, see “Item 10. Additional Information—B.
adviser, the compensation committee of a listed company will be required to
Memorandum of association and byelaws.”
take into consideration six specific factors, as well as all other factors relevant
to an adviser’s independence. Compliance with the compensation committee
member independence standards will be required by the earlier of a listed
company’s first annual meeting after January 15, 2014 or October 31, 2014.
ITEM 16H. Mine safety disclosure
Not applicable.
Foreign private issuers such as us will be exempt from these requirements
if home country practice is followed. Bermuda law does not impose similar
requirements, so we will not be required to implement the new NYSE
listing standards relating to compensation committees of domestic listed
companies. Most of the members of our remuneration committee are
independent, and the charter of our remuneration committee does not
require the remuneration committee to consider the independence of any
advisers that assist them in fulfilling their duties.
Additional audit committee functions
The NYSE standards require that audit committees of domestic companies
to serve a number of functions in addition to reviewing and approving
the company’s financial statements, engaging auditors and assessing their
independence, and obtaining the legal and other professional advice of
experts when necessary. For instance, the NYSE Standards require that the
audit committee meet independently with management in a separate
session in order to maximize the effectiveness of the committee’s oversight
function. In addition, audit committees must obtain and review a report
by the independent auditors describing the firm’s internal quality-control
procedures and any issues raised by these procedures. Finally, audit
committees are responsible for designing and implementing an internal
audit function that assesses the company’s risk management processes
and systems of internal control on an ongoing basis.
172 GeoPark 20F
Part III
ITEM 17. Financial statements
We have responded to Item 18 in lieu of this item.
ITEM 19. Exhibits
ITEM 18. Financial statements
Financial Statements are filed as part of this annual report, see page 178.
to Exhibit 3.1 to the Company’s Registration Statement
on Form F-1 (File No. 333-191068) filed with the SEC on
Exhibit no. Description
1.1
Certificate of Incorporation (incorporated herein by reference
September 9, 2013).
1.2
Memorandum of Association (incorporated herein by reference
to Exhibit 3.2 to the Company’s Registration Statement
on Form F-1 (File No. 333-191068) filed with the SEC on
September 9, 2013).
1.3
Current bye-laws (incorporated herein by reference to Exhibit
3.3 to the Company’s Registration Statement on Form F-1
(File No. 333-191068) filed with the SEC on September 9, 2013).
1.4
Form of amended and restated bye-laws (incorporated herein
by reference to Exhibit 3.4 to the Company’s Registration
Statement on Form F-1 (File No. 333-191068) filed with the SEC
on September 9, 2013).
2.2
Indenture, dated February 11, 2013, among GeoPark Chile
Limited Agencia en Chile, GeoPark Limited, GeoPark Latin
America Limited and Deutsche Bank Trust Company Americas
(incorporated herein by reference to Exhibit 4.2 to the
Company’s Registration Statement on Form F-1 (File No. 333-
191068) filed with the SEC on September 9, 2013).
2.3
Share Pledge Agreement, dated February 11, 2013, among
GeoPark Chile Limited Agencia en Chile, GeoPark Chile S.A.,
GeoPark Colombia S.A. and Deutsche Bank Trust Company
Americas (incorporated herein by reference to Exhibit 4.3
to the Company’s Registration Statement on Form F-1
(File No. 333-191068) filed with the SEC on September 9, 2013).
2.4
Intercompany Loan Pledge Agreement, dated February 11,
2013, among GeoPark Chile Limited Agencia en Chile, GeoPark
Fell SpA., GeoPark Llanos SAS and Deutsche Bank Trust
Company Americas (incorporated herein by reference to Exhibit
4.4 to the Company’s Registration Statement on Form F-1
(File No. 333-191068) filed with the SEC on September 9, 2013).
2.5
Supplemental Indenture, dated December 20, 2013, among
GeoPark Latin America Limited Agencia en Chile, GeoPark Latin
America Limited, GeoPark Limited, GeoPark Latin America
Coöperatie U.A. and Deutsche Bank Trust Company Americas
(incorporated herein by reference to Exhibit 4.5 to the
Company’s Registration Statement on Form F-1/A (File No. 333
191068) filed with the SEC on January 21, 2014).
GeoPark 20F 173
Exhibit no. Description
4.1
Special Contract for the Exploration and Exploitation of
Exhibit no. Description
4.8
Subscription Agreement, dated December 18, 2012, among
Hydrocarbons, Fell Block, dated April 29, 1997, among the
LG International Corporation, GeoPark Chile Limited Agencia
Republic of Chile, the Chilean Empresa Nacional de Petróleo
enChile, GeoPark Colombia S.A. and GeoPark Holdings
(ENAP) and Cordex Petroleums Inc. (incorporated herein
Limited (incorporated herein by reference to Exhibit 10.8
by reference to Exhibit 10.1 to the Company’s Registration
to the Company’s Registration Statement on Form F-1
Statement on Form F-1 (File No. 333-191068) filed with
(File No. 333-191068) filed with the SEC on September 9, 2013).
the SEC on September 9, 2013).
4.9
Shareholders’ Agreement, dated December 18, 2012, among
4.2
Exploration and Production Contract regarding exploration for
LG International Corporation, GeoPark Chile Limited Agencia
and exploitation of hydrocarbons in the La Cuerva Block, dated
en Chile and GeoPark Colombia S.A. (incorporated herein
April 16, 2008, between the Colombian Agencia Nacional de
by reference to Exhibit 10.9 to the Company’s Registration
Hidrocarburos and Hupecol Caracara LLC (incorporated herein
Statement on Form F-1 (File No. 333-191068) filed with
by reference to Exhibit 10.l2 to the Company’s Registration
the SEC on September 9, 2013).
Statement on Form F-1 (File No. 333-191068) filed with the SEC
4.10
Subordinated Loan Agreement, dated December 18, 2012,
on September 9, 2013).
between LG International Corporation and Winchester
4.3
Exploration and Production Contract regarding exploration for
Oil & Gas S.A. (incorporated herein by reference to Exhibit
and exploitation of hydrocarbons in the Llanos 34 Block, dated
10.10 to the Company’s Registration Statement on Form F-1
March 13, 2009, between the Colombian Agencia Nacional
(File No. 333-191068) filed with the SEC on September 9, 2013).
de Hidrocarburos and Unión Temporal Llanos 34 (incorporated
4.11
Subscription Agreement, dated October 18, 2011, among LG
herein by reference to Exhibit 10.3 to the Company’s
International Corporation and GeoPark TdF S.A. (incorporated
Registration Statement on Form F-1 (File No. 333-191068) filed
herein by reference to Exhibit 10.11 to the Company’s
with the SEC on September 9, 2013).
Registration Statement on Form F-1 (File No. 333-191068)
4.4
Subscription and Shareholders Agreement, dated February 7,
filed with the SEC on September 9, 2013).
2006, among the International Finance Corporation,
4.12
Shareholders’ Agreement, dated October 4, 2011, among LG
GeoPark Holdings Limited, Gerald O’Shaughnessy and
International Corporation, GeoPark TdF S.A. and GeoPark
James F. Park (incorporated herein by reference to Exhibit 10.4
Chile S.A. (incorporated herein by reference to Exhibit 10.12
to the Company’s Registration Statement on Form F-1
to the Company’s Registration Statement on Form F-1
(File No. 333-191068) filed with the SEC on September 9, 2013).
(File No. 333-191068) filed with the SEC on September 9, 2013).
4.5
Purchase and Sale Agreement, dated March 26, 2012, between
4.13
Quota Purchase Agreement, dated May 14, 2013, between
Hupecol Cuerva Holdings LLC and GeoPark Llanos S.A.S.
Panoro Energy do Brasil Ltda. and GeoPark Brazil Exploracão
(incorporated herein by reference to Exhibit 10.5 to the
e Producão de Petróleo e Gás Ltda (incorporated herein
Company’s Registration Statement on Form F-1 (File No. 333
191068) filed with the SEC on September 9, 2013).
by reference to Exhibit 10.13 to the Company’s Registration
Statement on Form F-1 (File No. 333-191068) filed with the
4.6
Subscription Agreement, dated May 20, 2011, among LG
SEC on September 9, 2013).
International Corporation, GeoPark Chile Limited Agencia en
4.14
Purchase and Sale Agreement for Crude Oil and Condensate
Chile, GeoPark Chile S.A. and GeoPark Holdings Limited
of Fell Block between Empresa Nacional del Petróleo (ENAP) and
(incorporated herein by reference to Exhibit 10.6 to the
GeoPark Fell SpA (incorporated herein by reference to Exhibit
Company’s Registration Statement on Form F-1 (File No. 333
10.14 to the Company’s Registration Statement on Form F-1
191068) filed with the SEC on September 9, 2013).
(File No. 333-191068) filed with the SEC on September 9, 2013).
4.7
Shareholders’ Agreement, dated May 20, 2011, among LG
4.15
Purchase and Sale Agreement for Natural Gas between
International Corporation, GeoPark Chile Limited Agencia
GeoPark Chile Limited, Agencia en Chile and Methanex Chile S.A.
en Chile and GeoPark Chile S.A. (incorporated herein
(incorporated herein by reference to Exhibit 10.15 to the
by reference to Exhibit 10.7 to the Company’s Registration
Company’s Registration Statement on Form F-1/A (File No. 333
Statement on Form F-1 (File No. 333-191068) filed with
191068) filed with the SEC on October 10, 2013).†
the SEC on September 9, 2013).
174 GeoPark 20F
Exhibit no. Description
4.16
First Addendum and Amendment to Purchase and Sale
Exhibit no. Description
13.2
Certification pursuant to 18 U.S.C. section 1350, as adopted
Agreement for Natural Gas between GeoPark Chile Limited,
pursuant to section 906 of the Sarbanes-Oxley Act of 2002.*
Agencia en Chile and Methanex Chile S.A. (incorporated herein
99.1
Reserves Report of DeGolyer and MacNaughton for reserves in
by reference to Exhibit 10.16 to the Company’s Registration
Brazil, Chile, Colombia and Argentina as of December 31, 2013.**
Statement on Form F-1/A (File No. 333-191068) filed with the
SEC on October 10, 2013).†
* Filed with this Annual Report on Form 20-F.
4.17
Second Addendum and Amendment to Purchase and Sale
** This information can be found in our 20-F filing to the SEC on April 30, 2014
Agreement for Natural Gas between GeoPark Chile Limited,
at www.sec.gov or at www.geo-park.com
Agencia en Chile and Methanex Chile S.A. (incorporated herein
† Confidential treatment of certain provisions of these exhibits has been
by reference to Exhibit 10.7 to the Company’s Registration
requested with the SEC. Omitted material for which confidential treatment
Statement on Form F-1/A (File No. 333-191068) filed with the
has been requested has been filed separately with the SEC.
SEC on September 26, 2013).
4.18
Third Addendum and Amendment to Purchase and Sale
Agreement for Natural Gas between GeoPark Chile Limited,
Agencia en Chile and Methanex Chile S.A. (incorporated herein
by reference to Exhibit 10.18 to the Company’s Registration
Statement on Form F-1/A (File No. 333-191068) filed with the
SEC on October 10, 2013).†
4.19
Fourth Addendum and Amendment to Purchase and Sale
Agreement for Natural Gas between GeoPark Chile Limited,
Agencia en Chile and Methanex Chile S.A. (incorporated herein
by reference to Exhibit 10.19 to the Company’s Registration
Statement on Form F-1/A (File No. 333-191068) filed with the
SEC on October 10, 2013).†
4.20
Members’ Agreement, dated January 8, 2014, among GeoPark
Latin America Coöperatie U.A., GeoPark Colombia
Coöperatie U.A. and LG International Corporation (incorporated
herein by reference to Exhibit 10.20 to the Company’s
Registration Statement on Form F-1/A (File No. 333-191068)
filed with the SEC on January 21, 2014).
4.21
Loan Agreement no. 4131, dated March 28, 2014, between
Itau BBA International plc and GeoPark Brasil Exploracão
e Produção de Petróleo e Gás Ltda.**
8.1
Subsidiaries of GeoPark Limited (incorporated herein by
reference to Exhibit 10.20 to the Company’s Registration
Statement on Form F-1/A (File No. 333-191068) filed
with the SEC on February 6, 2014).**
12.1
Certification pursuant to section 302 of the Sarbanes-Oxley
Act of 2002.*
12.2
Certification pursuant to section 302 of the Sarbanes-Oxley
Act of 2002.*
13.1
Certification pursuant to 18 U.S.C. section 1350, as adopted
pursuant to section 906 of the Sarbanes-Oxley Act of 2002.*
GeoPark 20F 175
Glossary of Oil and Natural Gas Terms
The terms defined in this section are used throughout this annual report:
Generally, an exploratory well is any well that is not a development well, a
service well, or a stratigraphic test well as those items are defined below.
“appraisal well” means a well drilled to further confirm and evaluate the
“field” means an area consisting of a single reservoir or multiple reservoirs all
presence of hydrocarbons in a reservoir that has been discovered.
grouped on or related to the same individual geological structural feature
“API” means the American Petroleum Institute’s inverted scale for denoting
and/or stratigraphic condition. There may be two or more reservoirs in a field
the “light” or “heaviness” of crude oils and other liquid hydrocarbons.
that are separated vertically by intervening impervious strata, or laterally by
“bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used
local geologic barriers, or by both.
herein in reference to crude oil, condensate or natural gas liquids.
Reservoirs that are associated by being in overlapping or adjacent fields
“bcf” means one billion cubic feet of natural gas.
may be treated as a single or common operational field. The geological terms
“boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas
structural feature and stratigraphic condition are intended to identify
being equivalent to one barrel of oil.
localized geological features as opposed to the broader terms of basins,
“boepd” means barrels of oil equivalent per day.
trends, provinces, plays, areas-of-interest, etc.
“bopd” means barrels of oil per day.
“formation” means a layer of rock which has distinct characteristics that differ
“British thermal unit” or “btu” means the heat required to raise the
from nearby rock.
temperature of a one-pound mass of water from 58.5 to 59.5 degrees
“mbbl” means one thousand barrels of crude oil, condensate or natural gas
Fahrenheit.
liquids.
“basin” means a large natural depression on the earth’s surface in which
“mboe” means one thousand barrels of oil equivalent.
sediments generally brought by water accumulate.
“mcf” means one thousand cubic feet of natural gas.
“CEOP” (Contrato Especial de Operación) means a special operating contract
“Measurements” include:
the Chilean signs with a company or a consortium of companies for the
• “m” or “meter” means one meter, which equals approximately 3.28084 feet;
exploration and exploitation of hydrocarbon wells.
• “km” means one kilometer, which equals approximately 0.621371 miles;
“completion” means the process of treating a drilled well followed by the
• “sq. km” means one square kilometer, which equals approximately 247.1
installation of permanent equipment for the production of natural gas or oil,
acres;
or in the case of a dry hole, the reporting of abandonment to the
• “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent
appropriate agency.
to approximately 0.15898 cubic meters;
“developed acreage” means the number of acres that are allocated or
• “boe” means one barrel of oil equivalent, which equals approximately
assignable to productive wells or wells capable of production.
160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of
“developed reserves” are expected quantities to be recovered from
natural gas to one barrel of oil;
existing wells and facilities. Reserves are considered developed only after
• “cf” means one cubic foot;
the necessary equipment has been installed or when the costs to do so
• “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf,
are relatively minor compared to the cost of a well. Where required facilities
respectively;
become unavailable, it may be necessary to reclassify developed reserves
as undeveloped.
• “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf,
respectively;
“development well” means a well drilled within the proved area of an oil or
• “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf,
gas reservoir to the depth of a stratigraphic horizon known to be productive.
respectively; and
“dry hole” means a well found to be incapable of producing hydrocarbons
• “pd” means per day.
in sufficient quantities such that proceeds from the sale of such production
“metric ton” or “MT” means one thousand kilograms. Assuming standard
exceed production expenses and taxes.
quality oil, one metric ton equals 7.9 bbl.
“E&P Contract” means exploration and production contract.
“mmbbl” means one million barrels of crude oil, condensate or natural gas
“economic interest” means an indirect participation interest in the net
liquids.
revenues from a given block based on bilateral agreements with the
“mmboe” means one million barrels of oil equivalent.
concessionaires.
“mmbtu” means one million British thermal units.
“economically producible” means a resource that generates revenue that
“NYMEX” means The New York Mercantile Exchange.
exceeds, or is reasonably expected to exceed, the costs of the operation.
“net acres” means the percentage of total acres an owner has out of a
“exploratory well” means a well drilled to find and produce oil or gas in an
particular number of acres, or a specified tract. An owner who has a 50%
unproved area, to find a new reservoir in a field previously found to be
interest in 100 acres owns 50 net acres.
productive of oil or gas in another reservoir, or to extend a known reservoir.
“productive well” means a well that is found to be capable of producing
176 GeoPark 20F
hydrocarbons in sufficient quantities such that proceeds from the sale of the
rock types and thus has the potential to become rich hydrocarbon source
production exceed production expenses and taxes.
rock. Its fine grain size and lack of permeability can allow shale to form a good
“prospect” means a potential trap which may contain hydrocarbons and is
cap rock for hydrocarbon traps.
supported by the necessary amount and quality of geologic and geophysical
“spacing” means the distance between wells producing from the same
data to indicate a probability of oil and/or natural gas accumulation ready
reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing,
to be drilled. The five required elements (generation, migration, reservoir, seal
and is often established by regulatory agencies).
and trap) must be present for a prospect to work and if any of them fail
“spud” means the very beginning of drilling operations of a new well,
neither oil nor natural gas will be present, at least not in commercial volumes.
occurring when the drilling bit penetrates the surface utilizing a drilling rig
“proved developed reserves” means those proved reserves that can be
capable of drilling the well to the authorized total depth.
expected to be recovered through existing wells and facilities and by existing
“stratigraphic test well” means a drilling effort, geologically directed, to
operating methods.
obtain information pertaining to a specific geologic condition. Such wells
“proved reserves” means estimated quantities of crude oil, natural gas, and
customarily are drilled without the intention of being completed for
natural gas liquids which geological and engineering data demonstrate with
hydrocarbon production. This classification also includes tests identified
reasonable certainty to be economically recoverable in future years from
as core tests and all types of expendable holes related to hydrocarbon
known reservoirs under existing economic and operating conditions, as well
exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not
as additional reserves expected to be obtained through confirmed improved
drilled in a proved area, or (ii) development-type, if drilled in a proved area.
recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).
“undeveloped reserves” are quantities expected to be recovered through
“proved undeveloped reserves” means are those proved reserves that
future investments: (1) from new wells on undrilled acreage in known
are expected to be recovered from future wells and facilities, including future
accumulation, (2) from deepening existing wells to a different (but known)
improved recovery projects which are anticipated with a high degree of
reservoir, (3) from infill wells that will increase recover, or (4) where a
certainty in reservoirs which have previously shown favorable response to
relatively large expenditure (e.g., when compared to the cost of drilling a new
improved recovery projects.
well) is required to (a) recomplete an existing well or (b) install production
“reasonable certainty” means a high degree of confidence.
or transportation facilities for primary or improved recovery projects.
“recompletion” means the process of re-entering an existing wellbore that is
“unit” means the joining of all or substantially all interests in a reservoir or
either producing or not producing and completing new reservoirs in an
field, rather than a single tract, to provide for development and operation
attempt to establish or increase existing production.
without regard to separate property interests. Also, the area covered
“reserves” means estimated remaining quantities of oil and gas and related
by a unitization agreement.
substances anticipated to be economically producible, as of a given date,
“wellbore” means the hole drilled by the bit that is equipped for oil or gas
by application of development projects to known accumulations. In addition,
production on a completed well. Also called well or borehole.
there must exist, or there must be a reasonable expectation that there will
“working interest” means the right granted to the lessee of a property to
exist, a revenue interest in the production, installed means of delivering oil,
explore for and to produce and own oil, gas, or other minerals. The working
gas, or related substances to market, and all permits and financing required
to implement the project.
interest owners bear the exploration, development, and operating costs
on either a cash, penalty, or carried basis.
“reservoir” means a porous and permeable underground formation
“workover” means operations in a producing well to restore or increase
containing a natural accumulation of producible oil and/or gas that
production.
is confined by impermeable rock or water barriers and is individual and
separate from other reservoirs.
“royalty” means a fractional undivided interest in the production of oil and
natural gas wells or the proceeds therefrom, to be received free and clear
of all costs of development, operations or maintenance.
“service well” means a well drilled or completed for the purpose of supporting
production in an existing field. Specific purposes of service wells include
gas injection, water injection, steam injection, air injection, saltwater disposal,
water supply for injection, observation, or injection for in-situ combustion.
“shale” means a fine grained sedimentary rock formed by consolidation of
clay- and silt-sized particles into thin, relatively impermeable layers. Shale
can include relatively large amounts of organic material compared with other
GeoPark 20F 177
Index to Consolidated Financial Statements
Audited Annual Consolidated Financial Statements—GeoPark Limited
Report of Independent Registered Public Accounting Firm
180
Consolidated Statements of Income and
Comprehensive Income for the Fiscal Years
Ended December 31, 2013, 2012 and 2011
Consolidated Statement of Financial Position
as of December 31, 2013 and 2012
Consolidated Statements of Changes in Equity
for the Fiscal Years Ended
December 31, 2013, 2012 and 2011
Consolidated Statements of Cash Flows
for the Fiscal Years Ended
December 31, 2013, 2012 and 2011
Notes to the Audited Annual Consolidated
Financial Statements for the Fiscal Years
Ended December 31, 2013 and 2012
181
182
183
184
185
178 GeoPark 20F
GeoPark 20F 179
Report of Independent Registered
Public Accounting Firm
To the Board of Directors and Shareholders of GeoPark Limited
In our opinion, the accompanying consolidated statement of financial
position and the related consolidated statements of income, comprehensive
income, changes in equity, and cash flow present fairly, in all material
respects, the financial position of GeoPark Limited and its subsidiaries at
December 31, 2013 and 2012, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2013
in conformity with International Financial Reporting Standards as issued
by the International Accounting Standards Board. These financial statements
are the responsibility of the Company’s management. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made
by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
/s/ PRICE WATERHOUSE & CO. S.R.L.
By /s/ Carlos Martín Barbafina (Partner)
Carlos Martín Barbafina
Autonomous City of Buenos Aires, Argentina
April 29, 2014
180 GeoPark 20F
Consolidated Statement of Income
Amounts in US$ ’000
Note
2013
2012
2011
7
8
11
12
13
14
15
34
16
Net Revenue
Production costs
Gross Profit
Exploration costs
Administrative costs
Selling expenses
Other operating income
Operating Profit
Financial income
Financial expenses
Bargain purchase gain on acquisition of subsidiaries
Profit before Income Tax
Income tax
Profit for the year
Attributable to:
Owners of the Company
Non-controlling interest
Earnings per share (in US$) for
profit attributable to owners of the Company. Basic
18
Earnings per share (in US$) for
profit attributable to owners of the Company. Diluted
18
338,353
(179,643)
158,710
250,478
(129,235)
121,243
(16,254)
(46,584)
(17,252)
5,344
83,964
4,893
(38,769)
—
50,088
(15,154)
34,934
22,012
12,922
0.50
0.47
(27,890)
(28,798)
(24,631)
823
40,747
892
(17,200)
8,401
32,840
(14,394)
18,446
11,879
6,567
0.28
0.27
111,580
(54,513)
57,067
(10,066)
(18,232)
(2,546)
(439)
25,784
162
(13,678)
—
12,268
(7,206)
5,062
54
5,008
0.00
0.00
Consolidated Statement of Comprehensive Income
Amounts in US$ ’000
2013
2012
2011
Income for the year
Other comprehensive income:
Items that may be subsequently reclassified to profit
Currency translation difference
Total comprehensive Income for year
Attributable to:
Owners of the Company
Non-controlling interest
34,934
18,446
5,062
(1,956)
32,978
—
18,446
20,056
12,922
11,879
6,567
—
5,062
54
5,008
The notes on pages 185 to 228 are an integral part of these consolidated financial statements.
GeoPark 20F 181
Consolidated Statement of Financial Position
Amounts in US$ ’000
Note
2013
2012
Assets
Non Current Assets
Property, plant and equipment
Prepaid taxes
Other financial assets
Deferred income tax asset
Prepayments and other receivables
Total Non Current Assets
Current Assets
Inventories
Trade receivables
Prepayments and other receivables
Prepaid taxes
Cash at bank and in hand
Total Current Assets
Total Assets
Total Equity
Equity attributable to owners of the Company
Share capital
Share premium
Reserves
Retained earnings (accumulated losses)
Attributable to owners of the Company
Non-controlling interest
Total Equity
Liabilities
Non Current Liabilities
Borrowings
Provisions and other long-term liabilities
Deferred income tax liability
Trade and other payables
Total Non Current Liabilities
Current Liabilities
Borrowings
Current income tax liabilities
Trade and other payables
Total Current Liabilities
Total Liabilities
Total Equity and Liabilities
19
21
24
17
23
22
23
23
21
24
25
26
27
17
28
26
28
595,446
457,837
11,454
5,168
13,358
6,361
10,707
7,791
13,591
510
631,787
490,436
8,122
42,628
35,764
6,979
121,135
214,628
846,415
44
120,426
126,465
23,906
270,841
95,116
365,957
3,955
32,271
49,620
3,443
48,292
137,581
628,017
43
116,817
128,421
(5,860)
239,421
72,665
312,086
290,457
165,046
33,076
23,087
8,344
25,991
17,502
—
354,964
208,539
26,630
7,231
91,633
125,494
480,458
846,415
27,986
7,315
72,091
107,392
315,931
628,017
The financial statements were approved by the Board of Directors on 28 March 2014.
The notes on pages 185 to 228 are an integral part of these consolidated financial statements.
182 GeoPark 20F
Consolidated Statement of Changes in Equity
Attributable to owners of the Company
Retained
earnings
Non-
Other
Translation
(accumulated
controlling
Reserve
3,025
Reserve
894
losses)
(19,527)
Interest
—
Total
92,292
Share
Capital(1)
42
—
—
—
1
1
43
—
—
—
—
—
43
—
—
—
—
1
—
1
44
Amount in US$ '000
Equity at 1 January 2011
Comprehensive income:
Profit for the year
Total Comprehensive
Income for the Year 2011
Transactions with owners:
Proceeds from transaction
with Non-controlling
interest (Notes 25 and 34)
Share-based payment
(Note 29)
Total 2011
Balances at 31December 2011
Comprehensive income:
Profit for the year
Total Comprehensive
Income for the Year 2012
Transactions with owners:
Proceeds from transaction
with Noncontrolling interest
(Notes 25 and 34)
Share-based payment (Note 29)
Total 2012
Balances at 31December 2012
Comprehensive income:
Profit for the year
Currency translation differences
Total Comprehensive
Income for the Year 2013
Transactions with owners:
Proceeds from transaction
with Noncontrolling
interest (Notes 25 and 34)
Share-based payment (Note 29)
Repurchase of shares (Note 25)
Total 2013
Balances at 31 December 2013
(1) See Note 1.
Share
Premium
107,858
—
—
—
—
—
111,245
4,373
4,373
112,231
—
111,245
114,270
—
—
—
—
—
4,586
4,586
116,817
13,257
—
13,257
127,527
—
—
—
—
4,049
(440)
3,609
—
—
—
—
—
—
—
120,426
127,527
(1,062)
The notes on pages 185 to 228 are an integral part of these consolidated financial statements.
54
54
5,008
5,062
5,008
5,062
—
36,755
148,000
924
924
—
36,755
41,763
5,298
153,298
250,652
894
(18,549)
11,879
6,567
18,446
11,879
6,567
18,446
—
810
810
894
(5,860)
—
(1,956)
22,012
—
24,335
—
24,335
72,665
12,922
—
37,592
5,396
42,988
312,086
34,934
(1,956)
(1,956)
22,012
12,922
32,978
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
7,754
—
7,754
23,906
9,529
—
—
9,529
95,116
9,529
11,804
(440)
20,893
365,957
GeoPark 20F 183
Consolidated Statement of Cash Flow
Amounts in US$ ’000
Note
2013
2012
2011
Cash flows from operating activities
Income for the year
Adjustments for:
Income tax for the year
Depreciation of the year
Loss on disposal of property, plant and equipment
Write-off of unsuccessful efforts
Impairment loss
Accrual of interest on borrowings
Amortisation of other long-term liabilities
Unwinding of long-term liabilities
Accrual of share-based payment
Bargain purchase gain on acquisition of subsidiaries
Deferred income
Income tax paid
Changes in working capital
Cash flows from operating activities – net
Cash flows from investing activities
Purchase of property, plant and equipment
Acquisitions of companies, net of cash acquired
Purchase of financial assets
Collections related to financial leases
16
9
11
27
27
10
34
27
5
34
24
34,934
18,446
5,062
15,154
70,200
575
10,962
—
22,085
(1,165)
1,523
9,167
—
—
(4,040)
(19,301)
140,094
(228,033)
—
—
6,734
14,394
53,317
546
25,552
—
12,513
(2,143)
1,262
5,396
(8,401)
5,550
(408)
5,778
7,206
26,408
2,010
5,919
1,344
11,115
(1,038)
350
5,298
—
5,000
—
89
131,802
68,763
(198,204)
(105,303)
—
—
(98,651)
—
(2,625)
—
Cash flows used in investing activities – net
(221,299)
(303,507)
(101,276)
Cash flows from financing activities
Proceeds from borrowings
Proceeds from transaction with non-controlling interest(1)
Proceeds from loans from related parties
Proceeds from issuance of shares
Repurchase of shares
Principal paid
Interest paid
Cash flows from financing activities - net
307,259
40,667
8,344
3,442
(440)
(179,360)
(15,894)
164,018
37,200
12,452
—
—
—
(12,382)
(10,895)
26,375
9,668
142,000
—
—
—
(9,150)
(10,779)
131,739
Net increase (decrease) in cash and cash equivalents
82,813
(145,330)
99,226
Cash and cash equivalents at 1 January
Cash and cash equivalents at the end of the year
38,292
121,105
183,622
38,292
84,396
183,622
Ending Cash and cash equivalents are specified as follows:
Cash in bank
Cash in hand
Bank overdrafts
Cash and cash equivalents
121,113
22
(30)
121,105
48,268
24
(10,000)
38,292
193,642
8
(10,028)
183,622
(1) Proceeds from transaction with Non-controlling interest for the year ended 31 December 2013 includes:
US$9,529,000 from capital contributions received in the period; and US$31,138,000 as result of collection
of receivables included in Prepayment and other receivables as of 31 December 2012, relating to equity
transactions made in 2012 and 2011.
The notes on pages 185 to 228 are an integral part of these consolidated financial statements.
184 GeoPark 20F
Notes
Note 1
General Information
On 7 February 2014, the Securities and Exchange Commission (“SEC”)
declared effective the Company’s registration statement upon which
13,999,700 shares were issued at a price of US$7 per share, including over-
GeoPark Limited (the Company) is a company incorporated under the laws
allotment option. Gross proceeds from the offering totalled US$98 million.
of Bermuda. The Registered office address is Cumberland House, 9th Floor,
As a result, the Company commenced trading on the New York Stock
1 Victoria Street, Hamilton HM 11, Bermuda.
Exchange (“NYSE”) under the ticker symbol GPRK. Also its shares
On 30 July 2013 the shareholders approved the change of the Company’s
name from GeoPark Holdings Limited to GeoPark Limited.
Subsequently, the Company listing cancellation on the AIM London Stock
are authorized for trading on the Santiago Off-Shore Stock Exchange.
The principal activity of the Company and its subsidiaries (“the Group”)
are exploration, development and production for oil and gas reserves in Chile,
These consolidated financial statements were authorised for issue by the
Colombia, Brazil and Argentina. The Group has working interests and/or
Board of Directors on 28 March 2014.
Exchange became effective on 19 February 2014.
economic interests in 28 hydrocarbon blocks.
The Group was founded in 2002. The first acquisition was the purchase of
Note 2
AES Corporation’s upstream oil and natural gas assets in Chile and Argentina.
Summary of significant accounting policies
Those assets included a non-operating working interest in the Fell Block in
Chile, which at that time was operated by Empresa Nacional de Petróleo
The principal accounting policies applied in the preparation of these
(“ENAP”), the Chilean state-owned hydrocarbon company, and operating
consolidated financial statements are set out below. These policies have been
working interests in the Del Mosquito, Cerro Doña Juana and Loma Cortaderal
consistently applied to the years presented, unless otherwise stated.
blocks in Argentina. In 2006, the Group was awarded a 100% operating
working interest in the Fell Block by the Republic of Chile. In 2008 and 2009,
the Group continued the growth in Chile by acquiring operating working
2.1 Basis of preparation
The consolidated financial statements of GeoPark Limited have been
interests in each of the Otway and Tranquilo blocks. In 2011, the Group was
prepared in accordance with International Financial Reporting Standards
awarded operating working interests in each of the Isla Norte, Flamenco
(“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
and Campanario blocks in Tierra del Fuego, Chile, and in 2012, the Group
formalized and entered into special operation contracts (Contratos
The consolidated financial statements are presented in thousands (US$ ’000)
Especiales de Operación para la Exploración y Explotación de Yacimientos
of United States Dollars and all values are rounded to the nearest thousand
de Hidrocarburos) (each, a “CEOP”) with Chile for the exploitation and
(US$’000), except where otherwise indicated.
exploration of these blocks. In the first quarter of 2012, GeoPark extended its
footprint to Colombia by acquiring three privately held Exploration and
Production (“E&P”) companies, Winchester, La Luna and Cuerva, that includes
The consolidated financial statements have been prepared on a historical
cost basis.
working interests and/or economic interests in 10 blocks located in the
Llanos, Magdalena and Catatumbo basins.
The preparation of financial statements in conformity with IFRS requires the
use of certain critical accounting estimates. It also requires management
In May 2013, the Company has extended its footprint into Brazil since it has
to exercise its judgement in the process of applying the Group’s accounting
been awarded seven new licenses in the Brazilian Round 11 of which two
policies. The areas involving a higher degree of judgement or complexity,
are in the Reconcavo Basin in the State of Bahia and five are in the Potiguar
or areas where assumptions and estimates are significant to the consolidated
Basin in the State of Rio Grande do Norte. In addition, in November 2013,
financial statements are disclosed in this note under the title “Accounting
the Company has also been awarded two new concessions in a new
estimates and assumptions”.
international bidding round, Round 12, in the Parnaíba Basin in the State of
Maranhão and Sergipe Alagoas Basin in the State of Alagoas (see Note 34).
GeoPark 20F 185
2.1.1 Changes in accounting policy and disclosure
New standards, amendments and interpretations issued but not effective for the
New and amended standards adopted by the Group
financial year beginning 1 January 2013 and not early adopted
IFRS 9, ‘Financial instruments’, addresses the classification, measurement
The following standards have been adopted by the Group for the first
and recognition of financial assets and financial liabilities. IFRS 9 was issued
time for the financial year beginning on or after 1 January 2013 and have
in November 2009 and October 2010. It replaces the parts of IAS 39 that
no material impact on the Group:
relate to the classification and measurement of financial instruments. IFRS 9
requires financial assets to be classified into two measurement categories:
Amendment to IAS 1, ‘Financial statement presentation’ regarding other
those measured at fair value and those measured at amortised cost. The
comprehensive income. The main change resulting from these amendments
determination is made at initial recognition. The classification depends
is a requirement for entities to group items presented in ‘other
on the entity’s business model for managing its financial instruments and
comprehensive income’ (OCI) on the basis of whether they are potentially
the contractual cash flow characteristics of the instrument. For financial
reclassifiable to profit or loss subsequently (reclassification adjustments).
liabilities, the standard retains most of the IAS 39 requirements.
IFRS 10, ‘Consolidated financial statements’ builds on existing principles
The main change is that, in cases where the fair value option is taken for
by identifying the concept of control as the determining factor in whether an
financial liabilities, the part of a fair value change due to an entity’s own credit
entity should be included within the consolidated financial statements of
risk is recorded in other comprehensive income rather than the income
the parent company. The standard provides additional guidance to assist in
statement, unless this creates an accounting mismatch. The Group is yet to
the determination of control where this is difficult to assess.
assess IFRS 9’s full impact and intends to adopt IFRS 9 no later than the
accounting period beginning on or after 1 January 2015.
IFRS 11, ‘Joint arrangements’ focuses on the rights and obligations of the
parties to the arrangement rather than its legal form. There are two types
Amendment to IAS 32, ‘Financial instruments: Presentation’ on asset and
of joint arrangements: joint operations and joint ventures. Joint operations
liability offsetting. These amendments are to the application guidance in
arise where the investors have rights to the assets and obligations for
IAS 32, ‘Financial instruments: Presentation’, and clarify some of the
the liabilities of an arrangement. A joint operator accounts for its share of
requirements for offsetting financial assets and financial liabilities on the
the assets, liabilities, revenue and expenses. Joint ventures arise where
balance sheet. The Company has assessed IAS 32’s impact and concluded
the investors have rights to the net assets of the arrangement; joint ventures
there will be no material impact on the Group.
are accounted for under the equity method. Proportional consolidation
of joint arrangements is no longer permitted.
Amendment to IAS 36, ‘Impairment of assets’ on recoverable amount
IFRS 12, ‘Disclosures of interests in other entities’ includes the disclosure
the recoverable amount of impaired assets if that amount is based on fair
requirements for all forms of interests in other entities, including joint
arrangements, associates, structured entities and other off balance sheet
value less costs of disposal. The Company has assessed IAS 36’s impact and
concluded there will be no material impact on the Group.
disclosures. This amendment addresses the disclosure of information about
vehicles.
IFRIC 21, ‘Levies’, is an interpretation of IAS 37, ‘Provisions, contingent
IFRS 13, ‘Fair value measurement’, aims to improve consistency and reduce
liabilities and contingent assets’. IAS 37 sets out criteria for the recognition of
complexity by providing a precise definition of fair value and a single source
a liability, one of which is the requirement for the entity to have a present
of fair value measurement and disclosure requirements for use across IFRSs.
obligation as a result of a past event (known as an obligating event). The
The requirements, which are largely aligned between IFRSs and US GAAP,
interpretation clarifies that the obligating event that gives rise to a liability to
do not extend the use of fair value accounting but provide guidance on how
pay a levy is the activity described in the relevant legislation that triggers the
it should be applied where its use is already required or permitted by other
payment of the levy. The Company has assessed IFRIC 21’s impact and
standards within IFRSs.
concluded there will be no material impact on the Group.
186 GeoPark 20F
There are no other IFRSs or IFRIC interpretations that are not yet effective that
Acquisition-related costs are expensed as incurred.
would be expected to have a material impact on the Group.
Management assessed the relevance of other new standards, amendments
controlling interest in the acquiree and the acquisition-date fair value of
or interpretations not yet effective and concluded that they are not relevant
any previous equity interest in the acquiree over the fair value of the
The excess of the consideration transferred, the amount of any non-
to Group.
identifiable net assets acquired is recorded as goodwill. If the total of
consideration transferred, noncontrolling interest recognized and previously
2.2 Going concern
The Directors regularly monitor the Group's cash position and liquidity risks
held interest measured is less than the fair value of the net assets of the
subsidiary acquired in the case of a bargain purchase, the difference is
throughout the year to ensure that it has sufficient funds to meet forecast
recognized directly in the income statement.
operational and investment funding requirements. Sensitivities are run
to reflect latest expectations of expenditures, oil and gas prices and other
Intercompany transactions, balances and unrealised gains on transactions
factors to enable the Group to manage the risk of any funding short falls
between the Group and its subsidiaries are eliminated. Unrealised
and/or potential loan covenant breaches.
losses are also eliminated unless the transaction provides evidence of an
impairment of the asset transferred. Amounts reported in the financial
Considering macroeconomic environment conditions, the performance of
statements of subsidiaries have been adjusted where necessary to ensure
the operations, the US$300 million debt fund raising completed in February
consistency with the accounting policies adopted by the Group.
2013, the proceeds from the registration statement with the SEC (see
Note 1) and Group’s cash position, the Directors have formed a judgement,
at the time of approving the financial statements, that there is a reasonable
2.4 Segment reporting
Operating segments are reported in a manner consistent with the internal
expectation that the Group has adequate resources to continue with
reporting provided to the chief operating decision-maker. The chief
its investment programme to increase oil and gas reserves, production and
operating decision-maker, who is responsible for allocating resources and
revenues and meeting all its obligations for the foreseeable future. For
assessing performance of the operating segments, has been identified
this reason, the Directors have continued to adopt the going concern basis
as the strategic steering committee that makes strategic decisions. This
in preparing the consolidated financial statements.
committee consists of the CEO, COO, CFO and managers in charge
of the Exploration, Development, Drilling, Operations, SPEED and Finance
2.3 Consolidation
Subsidiaries are all entities (including structured entities) over which the
departments. This committee reviews the Group’s internal reporting
in order to assess performance and allocate resources. Management has
group has control. The group controls an entity when the group is exposed
determined the operating segments based on these reports.
to, or has rights to, variable returns from its involvement with the entity
and has the ability to affect those returns through its power over the entity.
2.5 Foreign currency translation
Subsidiaries are fully consolidated from the date on which control
is transferred to the group. They are deconsolidated from the date that
control ceases.
The Group applies the acquisition method to account for business
a) Functional and presentation currency
The consolidated financial statements are presented in US Dollars, which is
the Group’s presentation currency.
combinations. The consideration transferred for the acquisition of a subsidiary
Items included in the financial statements of each of the Group’s entities are
is the fair values of the assets transferred, the liabilities incurred to the
measured using the currency of the primary economic environment in
former owners of the acquiree and the equity interests issued by the Group.
which the entity operates (the “functional currency”). The functional currency
The consideration transferred includes the fair value of any asset or liability
of Group companies incorporated in Chile, Colombia and Argentina is
resulting from a contingent consideration arrangement. Identifiable assets
the US Dollar, meanwhile for the Group Brazilian company the functional
acquired and liabilities and contingent liabilities assumed in a business
currency is the local currency, which is the Brazilian Real.
combination are measured initially at their fair values at the acquisition date.
GeoPark 20F 187
b) Transactions and balances
Foreign currency transactions are translated into the functional currency
2.10 Property, plant and equipment
Property, plant and equipment are stated at historical cost less depreciation,
using the exchange rates prevailing at the dates of the transactions. Foreign
and impairment if applicable. Historical cost includes expenditure that is
exchange gains and losses resulting from the settlement of such transactions
directly attributable to the acquisition of the items; including provisions for
and from the translation at period end exchange rates of monetary assets
asset retirement obligation.
and liabilities denominated in foreign currencies are recognised in the
Consolidated Statement of Income.
2.6 Joint arrangements
The company has applied IFRS 11 to all joint arrangements as of 1 January
Oil and gas exploration and production activities are accounted for in
accordance with the successful efforts method on a field by field basis. The
Group accounts for exploration and evaluation activities in accordance
with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing
2013. Under IFRS 11 investments in joint arrangements are classified as either
exploration and evaluation costs until such time as the economic viability
joint operations or joint ventures depending on the contractual rights and
of producing the underlying resources is determined. Costs incurred prior to
obligations each investor.
obtaining legal rights to explore are expensed immediately to the
Consolidated Statement of Income.
The Company has assessed the nature of its joint arrangements and
determined them to be joint operations. The company combines its share in
Exploration and evaluation costs may include: license acquisition, geological
the joint operations individual assets, liabilities, results and cash flows on a
and geophysical studies (i.e.: seismic), direct labour costs and drilling
line-by-line basis with similar items in its financial statements.
costs of exploratory wells. No depreciation and/or amortisation are charged
2.7 Revenue recognition
Revenue from the sale of crude oil and gas is recognised in the Statement
during the exploration and evaluation phase. Upon completion of the
evaluation phase, the prospects are either transferred to oil and gas
properties or charged to expense (exploration costs) in the period in which
of Income when risk transferred to the purchaser, and if the revenue
the determination is made depending whether they have found reserves
can be measured reliably and is expected to be received. Revenue is shown
or not. If not developed, exploration and evaluation assets are written
net of VAT, discounts related to the sale and overriding royalties due to
off after three years unless, it can be clearly demonstrated that the carrying
the ex-owners of oil and gas properties where the royalty arrangements
value of the investment is recoverable.
represent a retained working interest in the property.
2.8 Production costs
Production costs include wages and salaries incurred to achieve the
Statement of Income within Exploration costs (US$25,552,000 in 2012 and
US$5,919,000 in 2011) for write-offs in Argentina, Colombia and Chile
net revenue for the year. Direct and indirect costs of raw materials
(see Note 11).
A charge of US$10,962,000 has been recognised in the Consolidated
and consumables, rentals and leasing, property, plant and equipment
depreciation and royalties are also included within this account.
All field development costs are considered construction in progress until
they are finished and capitalised within oil and gas properties, and are subject
2.9 Financial costs
Financial costs include interest expenses, realised and unrealised gains and
to depreciation once complete. Such costs may include the acquisition and
installation of production facilities, development drilling costs (including dry
losses arising from transactions in foreign currencies and the amortisation
holes, service wells and seismic surveys for development purposes), project-
of financial assets and liabilities. The Company has capitalised borrowing cost
related engineering and the acquisition costs of rights and concessions
for wells and facilities that were initiated after 1 January 2009. Amounts
related to approved properties.
capitalised during the year totalled US$1,312,953 (US$1,368,952 in 2012
and US$597,127 in 2011).
Work overs of wells made to develop reserves and/or increase production
are capitalized as development costs. Maintenance costs are charged to
income when incurred.
188 GeoPark 20F
Capitalised costs of proved oil and gas properties and production facilities
changes in technology and the variations in the costs of restoration necessary
and machinery are depreciated on a licensed area by the licensed area basis,
to protect the environment, the Group has considered it appropriate to
using the unit of production method, based on commercial proved and
periodically re-evaluate future costs of well-capping. The effects of this
probable reserves. The calculation of the “unit of production” depreciation
recalculation are included in the financial statements in the period in which
takes into account estimated future finding and development costs and is
this recalculation is determined and reflected as an adjustment to the
based on current year end unescalated price levels. Changes in reserves
provision and the corresponding property, plant and equipment asset.
and cost estimates are recognised prospectively. Reserves are converted to
equivalent units on the basis of approximate relative energy content.
2.11.2 Deferred Income
Relates to contributions received in cash from the Group’s clients to improve
Depreciation of the remaining property, plant and equipment assets (i.e.
the project economics of gas wells. The amounts collected are reflected
furniture and vehicles) not directly associated with oil and gas activities has
as a deferred income in the balance sheet and recognised in the Consolidated
been calculated by means of the straight line method by applying such
Statement of Income over the productive life of the associated wells. The
annual rates as required to write-off their value at the end of their estimated
depreciation of the gas wells that generated the deferred income is charged
useful lives. The useful lives range between 3 years and 10 years.
to the Consolidated Statement of Income simultaneously with the
Depreciation is allocated in the Consolidated Statement of Income as
production, exploration and administrative expenses, based on the nature
of the associated asset.
amortisation of the deferred income.
2.12 Impairment of non-financial assets
Assets that are not subject to depreciation and/or amortisation
(i.e.: exploration and evaluation assets) are tested annually for impairment.
An asset’s carrying amount is written down immediately to its recoverable
Assets that are subject to depreciation and/or amortisation are reviewed
amount if the asset’s carrying amount is greater than its estimated
for impairment whenever events or changes in circumstances indicate that
recoverable amount (see Impairment of non-financial assets in Note 2.12).
the carrying amount may not be recoverable.
2.11 Provisions and other long-term liabilities
Provisions for asset retirement obligations, deferred income, restructuring
An impairment loss is recognised for the amount by which the asset’s
carrying amount exceeds its recoverable amount. The recoverable amount is
obligations and legal claims are recognised when the Group has a present
the higher of an asset’s fair value less costs to sell and value in use. For the
legal or constructive obligation as a result of past events; it is probable
purposes of assessing impairment, assets are grouped at the lowest levels for
that an outflow of resources will be required to settle the obligation; and
which there are separately identifiable cash flows (cash-generating units),
the amount has been reliably estimated. Restructuring provisions comprise
generally a licensed area. Non-financial assets other than goodwill that
lease termination penalties and employee termination payments.
suffered impairment are reviewed for possible reversal of the impairment at
each reporting date.
Provisions are measured at the present value of the expenditures expected
to be required to settle the obligation using a pre-tax rate that reflects current
No asset should be kept as an exploration and evaluation asset for a period
market assessments of the time value of money and the risks specific to the
of more than three years, except if it can be clearly demonstrated that the
obligation. The increase in the provision due to passage of time is recognised
carrying value of the investment will be recoverable.
as interest expense.
2.11.1 Asset Retirement Obligation
The Group records the fair value of the liability for asset retirement
No impairment loss has been recognised during 2013; only write-offs
(see Note 11). In 2011, a charge of US$1,344,000 was recognised within
exploration costs as a result of the impairment test performed regarding
obligations in the period in which the wells are drilled. When the liability
operating fields in Argentina (see Note 11).
is initially recorded, the Group capitalises the cost by increasing the carrying
amount of the related long-lived asset. Over time, the liability is accreted
to its present value at each reporting period, and the capitalized cost is
depreciated over the estimated useful life of the related asset. According to
interpretations and application of current legislation and on the basis of the
GeoPark 20F 189
2.13 Lease contracts
All current lease contracts are considered to be operating leases on the
In addition, the Group has tax-loss carry-forwards in certain taxing
jurisdictions that are available to offset against future taxable profit. However,
basis that the lessor retains substantially all the risks and rewards related to
deferred tax assets are recognized only to the extent that it is probable
the ownership of the leased asset. Payments related to operating leases
that taxable profit will be available against which the unused tax losses can
and other rental agreements are recognised in the Consolidated Income
be utilized. Management judgment is exercised in assessing whether this
Statement on a straight line basis over the term of the contract. The Group's
is the case.
total commitment relating to operating leases and rental agreements is
disclosed in Note 31.
To the extent that actual outcomes differ from management’s estimates,
taxation charges or credits may arise in future periods.
Leases in which substantially all of the risks and rewards of ownership are
transferred to the lessee are classified as finance leases. Under a finance lease,
Deferred income tax liabilities are provided on taxable temporary
the Company as lessor has to recognize an amount receivable equal to the
differences arising from investments in subsidiaries and joint arrangements,
aggregate of the minimum lease payments plus any unguaranteed residual
except for deferred income tax liability where the timing of the reversal of the
value accruing to the lessor, discounted at the interest rate implicit in the lease.
temporary difference is controlled by the Group and it is probable that the
2.14 Inventories
Inventories comprise crude oil and materials.
temporary difference will not reverse in the foreseeable future. The Group
is able to control the timing of dividends from its subsidiaries and hence does
not expect taxable profit. Hence deferred tax is recognized in respect of the
retained earnings of overseas subsidiaries only if at the date of the statements
Crude oil is measured at the lower of cost and net realisable value. Materials
of financial position, dividends have been accrued as receivable or a binding
are measured at the lower of cost and recoverable amount. The cost of
agreement to distribute past earnings in future has been entered into by
materials and consumables is calculated at acquisition price with the addition
the subsidiary.
of transportation and similar costs. Cost is determined using the first-in,
firstout (FIFO) method.
Deferred tax liabilities are provided in full, with no discounting.
2.15 Current and deferred income tax
The tax expense for the year comprises current and deferred tax. Tax is
2.16 Financial assets
Financial assets are divided into the following categories: loans and
recognised in the Consolidated Statement of Income.
receivables; financial assets at fair value through the profit or loss; available-
for-sale financial assets; and held-to-maturity investments. Financial assets
The current income tax charge is calculated on the basis of the tax laws
are assigned to the different categories by management on initial
enacted or substantially enacted at the balance sheet date in the countries
recognition, depending on the purpose for which the investments were
where the Company’s subsidiaries operate and generate taxable income.
acquired. The designation of financial assets is re-evaluated at every reporting
The computation of the income tax expense involves the interpretation of
applicable tax laws and regulations in many jurisdictions. The resolution
date at which a choice of classification or accounting treatment is available.
of tax positions taken by the Group, through negotiations with relevant tax
All financial assets are recognised when the Group becomes a party to the
authorities or through litigation, can take several years to complete and
contractual provisions of the instrument. All financial assets are initially
in some cases it is difficult to predict the ultimate outcome.
recognised at fair value, plus transaction costs.
Deferred income tax is recognised, using the liability method, on temporary
Derecognition of financial assets occurs when the rights to receive cash
differences arising between the tax bases of assets and liabilities and their
flows from the investments expire or are transferred and substantially all of
carrying amounts in the consolidated financial statements. Deferred income
the risks and rewards of ownership have been transferred. An assessment
tax is determined using tax rates (and laws) that have been enacted or
for impairment is undertaken at each balance sheet date.
substantially enacted by the balance sheet date and are expected to apply
when the related deferred income tax asset is realised or the deferred income
Interest and other cash flows resulting from holding financial assets are
tax liability is settled.
recognised in the Consolidated Income Statement when receivable,
regardless of how the related carrying amount of financial assets is measured.
190 GeoPark 20F
Loans and receivables are non-derivative financial assets with fixed or
determinable payments that are not quoted in an active market. They are
2.21 Borrowings
Borrowings are obligations to pay cash and are recognised when the Group
included in current assets, except for maturities greater than twelve months
becomes a party to the contractual provisions of the instrument.
after the balance sheet date. These are classified as non-current assets.
The Group’s loans and receivables comprise trade receivables, prepayments
Borrowings are recognised initially at fair value, net of transaction costs
and other receivables and cash at bank and in hand in the balance sheet.
incurred. Borrowings are subsequently stated at amortised cost;
They arise when the Group provides money, goods or services directly to a
any difference between the proceeds (net of transaction costs) and the
debtor with no intention of trading the receivables. Loans and receivables are
redemption value is recognised in the Consolidated Statement of Income
subsequently measured at amortised cost using the effective interest
over the period of the borrowings using the effective interest method.
method, less provision for impairment. Any change in their value through
impairment or reversal of impairment is recognised in the Consolidated
Direct issue costs are charged to the Consolidated Statement of Income
Statement of Income. All of the Group’s financial assets are classified as loan
on an accruals basis using the effective interest method.
and receivables.
2.17 Other financial assets
Non-current other financial assets include contributions made for
2.22 Share capital
Equity comprises the following:
• "Share capital" representing the nominal value of equity shares.
environmental obligations according to a Colombian government request.
• "Share premium" representing the excess over nominal value of the fair
For 2012, noncurrent other financial assets also relate to the cash collateral
value of consideration received for equity shares, net of expenses of the
account required under the terms of the Bond issued in 2010. This investment
share issue.
was intended to guarantee interest payments and was recovered at
• "Other reserve" representing:
repayment date (see Note 26).
- the equity element attributable to shares granted according to IFRS 2 but
not issued at year end or,
2.18 Impairment of financial assets
Provision against trade receivables is made when objective evidence is
- the difference between the proceeds from the transaction with non-
controlling interests received against the book value of the shares acquired
received that the Group will not be able to collect all amounts due to
in the subsidiaries GeoPark Chile S.A. and GeoPark Colombia S.A.
it in accordance with the original terms of those receivables. The amount
(see Note 34).
of the write-down is determined as the difference between the asset's
• "Translation reserve" representing the differences arising from translation
carrying amount and the present value of estimated future cash flows.
of investments in overseas subsidiaries.
• "Retained earnings (accumulated losses)" representing accumulated
2.19 Cash and cash equivalents
Cash and cash equivalents includes cash in hand, deposits held at call with
earnings and losses.
banks, other short-term highly liquid investments with original maturities of
three months or less, and bank overdrafts. Bank overdrafts, if any, are shown
2.23 Share-based payment
The Group operates a number of equity-settled and cash-settled share-based
within borrowings in the current liabilities section of the Consolidated
compensation plans comprising share awards payments and stock options
Statement of Financial Position.
plans to certain employees and other third party contractors.
2.20 Trade and other payables
Trade payables are obligations to pay for goods or services that have been
Share-based payment transactions are measured in accordance with IFRS 2.
acquired in the ordinary course of the business from suppliers. Accounts
Fair value of the stock option plan for employee or contractors services
payable are classified as current liabilities if payment is due within one year
received in exchange for the grant of the options is recognised as an expense.
or less (or in the normal operating cycle of the business if longer). If not,
The total amount to be expensed over the vesting period is determined by
they are presented as non-current liabilities.
reference to the fair value of the options granted calculated using the Black-
Trade payables are recognised initially at fair value and subsequently
measured at amortised cost using the effective interest method.
Scholes model.
GeoPark 20F 191
Non-market vesting conditions are included in assumptions about the
number of options that are expected to vest. At each balance sheet date,
Currency risk
In Argentina, Colombia and Chile the functional currency is the US Dollar.
the entity revises its estimates of the number of options that are expected
The fluctuation of the local currencies of these countries against the US Dollar
to vest. It recognises the impact of the revision to original estimates,
does not impact the loans, costs and revenues held in US Dollars; but it
if any, in the Consolidated Statement of Income, with a corresponding
does impact the balances denominated in local currencies. Such is the case
adjustment to equity.
of the prepaid taxes.
The fair value of the share awards payments is determined at the grant date
In Chile, Colombia and Argentina subsidiaries most of the balances are
by reference of the market value of the shares and recognised as an expense
denominated in US Dollars, and since it is the functional currency of the
over the vesting period.
subsidiaries, there is no exposure to currency fluctuation except from
receivables or payables originated in local currency mainly corresponding
When the options are exercised, the Company issues new shares. The
to VAT. The balances as of 31 December 2013 of VAT were credits for
proceeds received net of any directly attributable transaction costs
US$3,177,000 (US$3,624,000 in 2012) in Argentina, credits for US$5,288,000
are credited to share capital (nominal value) and share premium when
(US$221,000 in 2012) in Chile and VAT payable for US$5,870,000
the options are exercised.
(US$2,418,000 in 2012) in Colombia.
For cash-settled share-based payment transactions, the Company measures
The Group minimises the local currency positions in Argentina, Colombia and
the services acquired for amounts that are based on the price of the
Chile by seeking to equilibrate local and foreign currency assets and liabilities.
Company’s shares. The fair value of the liability incurred is measured using
However, tax receivables (VAT) are very difficult to match with local currency
Geometric Brownian Motion method. Until the liability is settled, the
liabilities. Therefore the Group maintains a net exposure to them.
Company is required to re-measure the fair value of the liability at each
reporting date and at the date of settlement, with any changes in value
Most of the Group's assets held in those countries are associated with oil
recognized in profit or loss for the period.
and gas productive assets. Such assets in the oil and gas industry even in the
Note 3
Financial Instruments-risk management
local markets are usually settled in US Dollar equivalents.
During 2013, the Argentine Peso weakened by 33% (weakened by 16%
and 8% in 2012 and 2011 respectively) against the US Dollar, the Chilean
Peso weakened by 10% (strengthened by 8% in 2012 and weakened by 11%
The Group is exposed through its operations to the following financial risks:
in 2011) and the Colombian Peso weakened by 9% (strengthened by 9%
• Currency risk
• Price risk
• Credit risk – concentration
• Funding and liquidity risk
• Interest rate risk
• Capital risk management
in 2012). If the Argentine Peso, the Chilean Peso and the Colombian Peso
had each weakened an additional 5% against the US dollar, with all other
variables held constant, post-tax profit for the year would have been higher
by US$139,500 (lower by US$45,500 in 2012 and by US$41,000 in 2011
respectively).
During 2014, the Argentine Peso weakened by approximately 22% against
The policy for managing these risks is set by the Board. Certain risks are
the US Dollar. The Company estimates that this devaluation will not impact
managed centrally, while others are managed locally following guidelines
significantly the results of the Company.
communicated from the corporate office. The policy for each of the
above risks is described in more detail below.
In Brazil the functional currency is the local currency, which is the Brazilian
Real. The fluctuation of the US Dollars against the Brazilian Real does not
impact the loans, costs and revenues held in Brazilian Real; but it does impact
the balances denominated in US Dollars. Such is the case of the cash at bank.
Most of the balances are denominated in Brazilian Real, and since it is the
192 GeoPark 20F
functional currency of the Brazilian subsidiary, there is no exposure to
currency fluctuation except from cash at bank held in US Dollars.
Credit risk – concentration
The Group’s credit risk relates mainly to accounts receivable where the credit
risks correspond to the recognised values. There is not considered to be any
During 2013, the Brazilian Real weakened by 6% against the US Dollar. If the
significant risk in respect of the Group’s major customers.
Brazilian Real had weakened an additional 5% against the US dollar, with
all other variables held constant, post-tax profit for the year would have been
In Chile, most of gas production is sold to the local subsidiary of the
higher by US$1,826,000.
Methanex Corporation, a Canadian public company (7% of total revenue,
12% in 2012 and 34% in 2011). All the oil produced in Chile is sold to ENAP
As currency rate changes between the U.S. Dollar and the local currencies, the
(40% of total revenue, 48% in 2012 and 65% in 2011), the State owned
Group recognizes gains and losses in the Consolidated Statement of Income.
oil and gas company. In Colombia, 21% of the oil we produced there, was
sold to Hocol, a subsidiary of Ecopetrol, the Colombian Sate owned oil
Price risk
The price realised for the oil produced by the Group is linked to WTI (West
Company (11% of total revenue, 31% in 2012). The mentioned companies all
have good credit standing and despite the concentration of the credit risk,
Texas Intermediate) and Brent, which is settled in the international markets in
the Directors do not consider there to be a significant collection risk.
US dollars. The market price of these commodities is subject to significant
fluctuation but the Board does not consider it appropriate to manage the
See disclosure in Note 24.
Group’s risk to such fluctuation through futures contracts or similar because
to do so would not have been efficiently economic at the achieved
production levels.
Funding and Liquidity risk
The Group has strong support from its financial partners and maintains
flexibility in adjusting the programme to ensure the development of the key
In Chile, the oil price is based on WTI minus certain marketing and quality
properties.
discounts such as, inter alia, API quality and mercury content; the price
formula also includes adjustments for differences between the WTI and Brent
During 2012, LGI made a capital subscription in GeoPark Colombia S.A. for an
at certain price levels. In Argentina, the oil price is also subject to the impact
amount of US$14,920,000 for the 20% of the Colombian business. In addition,
of the retention tax on oil exports defined by the Argentine government
as part of the transaction, US$5,000,000 was transferred directly to the
which limits the direct correlation to the WTI.
Colombian subsidiary as a loan (see Note 34).
The Company has signed a long-term Gas Supply Contract with Methanex in
In addition, during 2013 the Company placed US$300 million notes (see Note
Chile. The price of the gas under this contract is indexed to the international
26) and on February 2014 collected US$98 million from the registration
methanol price.
statement with the SEC (see Note 1).
If the market prices of WTI, Brent and methanol had fallen by 10% compared
to actual prices during the year, with all other variables held constant,
Interest rate risk
The Group’s profit and operating cash flows are substantially independent
post-tax profit for the year would have been lower by US$27,179,000
of changes in market interest rates. The Group’s interest rate risk arises from
(US$18,784,000 in 2012 and US$9,501,000 in 2011).
long-term borrowings issued at variable rates, which expose the Group to
The Board will consider adopting a hedging policy against commodity price
risk, when deemed appropriate, according to the size of the business and
The Group does not face interest rate risk on its US$300,000,000 Notes
market implied volatility.
which carry a fixed rate coupon of 7.50% per annum.
cash flow to interest rate risk.
The Group analyses its interest rate exposure on a dynamic basis. Various
scenarios are simulated taking into consideration refinancing, renewal
of existing positions, alternative financing and hedging. Based on these
scenarios, the Group calculates the impact on profit and loss of a defined
interest rate shift. For each simulation, the same interest rate shift
is used for all currencies. The scenarios are run only for liabilities that
represent the major interest-bearing positions.
GeoPark 20F 193
At 31 December 2012, if interest rates on currency-denominated borrowings
Note 4
had been 1% higher with all other variables held constant, post-tax profit
Accounting estimates and assumptions
for the year would have been US$160,866 lower (US$144,267 in 2011).
At 31 December 2013, the Group has no exposure to fluctuations in the
Although these estimates are based on management's best knowledge of
interest rate, since its long-term borrowings were issued at fixed rate.
current events and actions, actual results may differ from them. Estimates and
Estimates and assumptions are used in preparing the financial statements.
Capital risk management
The Group’s objectives when managing capital are to safeguard the Group’s
ability to continue as a going concern in order to provide returns for
judgements are continually evaluated and are based on historical experience
and other factors, including expectations of future events that are believed to
be reasonable under the circumstances.
shareholders and benefits for other stakeholders and to maintain an optimal
The key estimates and assumptions used in these consolidated financial
capital structure to reduce the cost of capital.
statements are noted below:
Consistent with others in the industry, the Group monitors capital on the
• The Group adopts the successful efforts method of accounting. The
basis of the gearing ratio. This ratio is calculated as net debt divided by total
Management of the Company makes assessments and estimates regarding
capital. Net debt is calculated as total borrowings (including ‘current and
whether an exploration asset should continue to be carried forward as an
non-current borrowings’ as shown in the consolidated balance sheet) less
exploration and evaluation asset not yet determined or when insufficient
cash at bank and in hand. Total capital is calculated as ‘equity’ as shown
information exists for this type of cost to remain as an asset. In making this
in the consolidated balance sheet plus net debt.
assessment the Management takes professional advice from qualified experts.
The Group’s strategy is to keep the gearing ratio within a 30% to 45% range.
• Cash flow estimates for impairment assessments require assumptions
about two primary elements - future prices and reserves. Estimates of future
Particularly, in 2011 the gearing ratio has been affected by the transactions
prices require significant judgments about highly uncertain future events.
with non-controlling interests, by which the Group received proceeds of
Historically, oil and gas prices have exhibited significant volatility. Our
US$142,000,000.
forecasts for oil and gas revenues are based on prices derived from future
price forecasts amongst industry analysts and our own assessments.
The gearing ratios at 31 December 2013 and 2012 were as follows:
Our estimates of future cash flows are generally based on our assumptions
Amounts in US$ ’000
Net Debt
Total Equity
Total Capital
Gearing Ratio
2013
(a)265,952
365,957
631,909
42%
of long-term prices and operating and development costs.
2012
144,740
Given the significant assumptions required and the possibility that actual
312,086
conditions will differ, we consider the assessment of impairment to be a
456,826
32%
critical accounting estimate.
The process of estimating reserves is complex. It requires significant
(a) For the calculation of the gearing ratio the Group does not consider the
judgements and decisions based on available geological, geophysical,
cash that has been allocated for future M&A activities. In 2013, the Group has
engineering and economic data. The estimation of economically recoverable
allocated US$70 million for the acquisition of Río Das Contas (see Note 34).
oil and natural gas reserves and related future net cash flows was performed
based on the Reserve Report dated December 2013 prepared by DeGolyer
and MacNaughton, an international consultancy to the oil and gas industry
based in Dallas. It incorporates many factors and assumptions including:
- expected reservoir characteristics based on geological, geophysical and
engineering assessments;
- future production rates based on historical performance and expected
future operating and investment activities;
- future oil and gas prices and quality differentials;
194 GeoPark 20F
- assumed effects of regulation by governmental agencies; and
Amounts in US$ ’000
- future development and operating costs.
Increase in asset retirement obligation
Transactions with
Management believes these factors and assumptions are reasonable based
non-controlling interests
on the information available to us at the time we prepare our estimates.
Financial leases (Note 19)
However, these estimates may change substantially as additional data from
2013
7,183
—
14,133
2012
3,440
—
—
2011
1,948
6,000
—
ongoing development activities and production performance becomes
Cash flows from investing activities include payments in connection with
available and as economic conditions impacting oil and gas prices and costs
the purchase and sale of property, plant and equipment, cash flows relating
change.
to the purchase and sale of enterprises to third parties and cash flows
from financial lease transactions. Cash flows from financing activities include
• Oil and gas assets held in property plant and equipment are mainly
changes in Shareholders’ equity, and proceeds from borrowings and
depreciated on a unit of production basis at a rate calculated by reference to
repayment of loans. Cash and cash equivalents include bank overdraft and
proven and probable reserves and incorporating the estimated future cost
liquid funds with a term of less than three months.
of developing and extracting those reserves. Future development costs are
estimated using assumptions as to the numbers of wells required to produce
Changes in working capital shown in the Consolidated Statement of Cash
those reserves, the cost of the wells and future production facilities.
Flow are disclosed as follows:
• Obligations related to the plugging of wells once operations are terminated
Amounts in US$ ’000
may result in the recognition of significant obligations. Estimating the
Change in Prepaid taxes
future abandonment costs is difficult and requires management to make
Change in Inventories
estimates and judgments because most of the obligations are many
Change in Trade receivables
years in the future. Technologies and costs are constantly changing as well
Change in Prepayments and other
as political, environmental, safety and public relations considerations.
receivables and Other assets
The Company has adopted the following criterion for recognising well
Change in liabilities
plugging and abandonment related costs: The present value of future costs
necessary for well plugging and abandonment is calculated for each
area on the basis of a cash flow that is discounted at an average interest
rate applicable to Company’s indebtedness. The liabilities recognised
Note 6
are based upon estimated future abandonment costs, wells subject to
Segment information
abandonment, time to abandonment, and future inflation rates.
2013
(4,283)
(4,166)
(10,357)
(13,330)
12,835
(19,301)
2012
(11,046)
8,837
(7,842)
2011
892
(332)
(2,858)
9,759
6,070
5,778
(16,350)
18,737
89
Note 5
Management has determined the operating segments based on the reports
reviewed by the strategic steering committee that are used to make
strategic decisions. The committee considers the business from a geographic
Consolidated Statement of Cash Flow
perspective.
The Consolidated Statement of Cash Flow shows the Group's cash flows
The strategic steering committee assesses the performance of the operating
for the year for operating, investing and financing activities and the change
segments based on a measure of adjusted earnings before interest, tax,
in cash and cash equivalents during the year.
depreciation, amortisation and certain non-cash items such as write-offs,
impairments and share-based payments (Adjusted EBITDA). This
Cash flows from operating activities are computed from the results for the
measurement basis excludes the effects of non-recurring expenditure from
year adjusted for non-cash operating items, changes in net working
the operating segments, such as impairments when it is the result of an
capital, and corporation tax. Tax paid is presented as a separate item under
isolated, non-recurring event. Interest income and expenses are not included
operating activities.
in the result for each operating segment that is reviewed by the strategic
steering committee. Other information provided, except as noted below, to
The following chart describes non-cash transactions related to the
the strategic steering committee is measured in a manner consistent with
Consolidated Statement of Cash Flow:
that in the financial statements.
GeoPark 20F 195
Segment areas (geographical segments):
Amount in US$ ’000
Argentina
Brazil
Colombia
Chile
Corporate
Total
2013
Net revenue
Gross profit
Operating (loss) / profit
Adjusted EBITDA
Depreciation
Impairment and write-off
Total assets
Employees (average)
2012
Net revenue
Gross profit
Operating (loss) / profit
Adjusted EBITDA
Depreciation
Impairment and write-off
Total assets
Employees (average)
2011
Net revenue
Gross profit
Operating (loss) / profit
Adjusted EBITDA
Depreciation
Impairment and write-off
Total assets
Employees (average)
1,538
1,192
(1,942)
166
(225)
—
7,977
97
1,050
(2,194)
(6,129)
2,051
(3,408)
(1,915)
6,108
100
1,477
179
(5,973)
(1,081)
(1,083)
(1,344)
10,895
83
—
—
(3,107)
(3,037)
(2)
—
29,222
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
179,324
67,612
38,811
82,611
(39,406)
(3,258)
259,421
107
99,501
39,304
8,500
34,474
(21,050)
(5,147)
213,202
80
—
—
—
—
—
—
—
—
157,491
89,906
63,110
96,348
(30,471)
(7,704)
477,263
184
149,927
84,133
47,915
93,908
(28,734)
(18,490)
405,674
144
110,103
56,888
39,425
70,421
(25,297)
(5,919)
(1)453,384
98
—
—
(12,908)
(8,835)
(96)
—
72,532
—
—
—
(9,539)
(9,029)
(125)
—
3,033
—
—
—
(7,668)
(5,949)
(28)
—
7,990
1
338,353
158,710
83,964
167,253
(70,200)
(10,962)
846,415
391
250,478
121,243
40,747
121,404
(53,317)
(25,552)
628,017
324
111,580
57,067
25,784
63,391
(26,408)
(7,263)
472,269
182
(1) Includes cash received from disposal of 20% of the Chilean business
in 2011.
Approximately 63% of capital expenditure was allocated to Chile (70% in
2012 and 95% in 2011) and 37% was allocated to Colombia (30% in 2012
and 0% in 2011).
196 GeoPark 20F
A reconciliation of total Adjusted EBITDA to total profit before income tax
Note 9
is provided as follows:
Amounts in US$ ’000
Adjusted EBITDA for
reportable segments
Depreciation
Share-based payment
Impairment and write-off of
unsuccessful efforts
Others(a)
Operating profit
Financial results
Bargain purchase gain on
acquisition of subsidiaries
Profit before tax
Depreciation
2013
2012
2011
Amounts in US$ ’000
Oil and gas properties
167,253
(70,200)
(9,167)
121,404
(53,317)
(5,396)
63,391
(26,408)
Production facilities and machinery
Furniture, equipment and vehicles
(5,298)
Buildings and improvements
(10,962)
7,040
83,964
(33,876)
(25,552)
3,608
40,747
(16,308)
(7,263)
1,362
25,784
(13,516)
Depreciation of property,
plant and equipment
Recognised as follows:
Production costs
Administrative costs
—
50,088
8,401
32,840
—
Depreciation total
12,268
2013
59,234
9,341
964
661
2012
44,552
7,708
713
344
2011
20,096
5,767
343
202
70,200
53,317
26,408
68,579
1,621
70,200
52,307
1,010
53,317
25,844
564
26,408
(a) Includes internally capitalised costs.
Note 10
Staff costs and Directors Remuneration
Note 7
Net Revenue
Amounts in US$ ’000
Sale of crude oil
Sale of gas
Note 8
Production costs
Amounts in US$ ’000
Depreciation
Well and facilities maintenance
Royalties
Consumables
Staff costs (Note 10)
Transportation costs
Equipment rental
Non operated blocks costs
Safety and Insurance costs
Field camp
Gas plant costs
Cost of crude oil sold from
acquired business
Other costs
2013
315,435
22,918
2012
221,564
28,914
Average number of employees
Amounts in US$ ’000
2011
Wages and salaries
73,508
38,072
Share-based payment (Note 29)
Share-based payment – Cash awards
338,353
250,478
111,580
Social security charges
Board of Directors’ and key
managers’ remuneration
Salaries and fees
Share-based payment
Other benefits
2013
68,579
20,662
17,239
14,855
14,202
11,392
7,139
5,635
4,843
4,805
3,217
—
7,075
2012
52,307
9,385
11,424
9,884
14,171
7,211
5,936
1,030
1,428
2,407
3,371
3,826
6,855
179,643
129,235
2011
25,844
5,080
4,843
1,687
6,015
2,541
—
—
316
1,009
3,242
—
3,936
54,513
2013
391
29,504
8,362
805
5,291
43,962
7,702
2,971
742
11,415
2012
324
19,132
5,396
—
3,636
28,164
5,711
846
—
6,557
2011
182
9,914
5,298
—
2,228
17,440
4,045
2,257
—
6,302
GeoPark 20F 197
Directors’ Remuneration
Gerald O’Shaughnessy
James F. Park
Pedro Aylwin1
Sir Michael Jenkins2
Peter Ryalls
Christian Weyer3
Juan Cristóbal Pavez4
Carlos Gulisano
Steven J. Quamme
Executive Directors’
Executive Directors’
Non-Executive
Director Fees Paid in
Cash Equivalent Total
2013 Cash Payment
Stock Payment
Fees
US$250,000
US$500,000
Bonus
US$150,000
US$300,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Directors’ Fees
Shares No. of Shares
Remuneration
—
—
—
£5,813
£17,500
£18,678
£23,250
£37,875
£20,375
—
—
—
1,712
2,906
—
2,906
—
2,906
US$400,000
US$800,000
—
US$27,234
US$55,414
US$29,697
US$64,484
US$59,902
US$59,902
1 Pedro Aylwin has a service contract that provides for him to act as Manager
of Legal and Governance.
2 Audit Committee Chairman until his death on 31 March 2013. Afterwards
the Chairman is Steven J. Quamme.
3 Nomination Committee Chairman until his resignation on 15 April 2013.
Afterwards the Chairman is Carlos Gulisano.
4 Remuneration Committee Chairman.
Name
Stock Awards to Executive Directors
The following Stock Options were issued to Executive Directors during 2012:
N° of
Underlying
Common
Shares
Grant
Date
23 Nov
2012
23 Nov
2012
Exercise
Price
(US$)
0.001
0.001
Earliest
Exercise
Date
23 Nov
2015
23 Nov
2015
Non-executive director fee includes a fee of £5,750 for holding a committee
Gerald O’Shaughnessy
270,000
chairman position during the year.
James F. Park
450,000
IPO Stock Options to Executive Directors
The following Stock Options were issued to Executive Directors during 2006:
Name
N° of
Underlying
Common
Shares
153,345
Gerald O’Shaughnessy
306,690
153,345
James F. Park
306,690
Exercise
Price (£)
3.20
4.00
3.20
4.00
In addition, Dr Carlos Gulisano holds the following interests in stock options
and awards as a result of the services that he has previously provided to
the Company:
Earliest
Exercise
Date
15 May
2008
Expiry
Date
• 50,000 IPO Stock Options issued on 15 May 2008 at an exercise price
of £4.00 to be exercised between 15 May 2008 and 15 May 2013. These were
15 May
fully exercised during 2013.
2013
• 100,000 Stock awards issued on 15 December 2008 at an exercise price of
15 May
15 May
$0.001 to be exercised between 15 December 2012 and 15 December 2018.
2008
15 May
2008
15 May
2008
2013
15 May
2013
15 May
2013
During 2013 the abovementioned stock options were fully exercised by the
Executive Directors.
198 GeoPark 20F
Note 11
Exploration costs
Amounts in US$ ’000
Write-off of unsuccessful efforts(a)
Staff costs (Note 10)
Other services
Allocation to capitalised project
Amortisation of other
long-term liabilities related
to unsuccessful efforts
Impairment loss(b)
Recovery of abandonments costs
Note 12
Administrative costs
2013
10,962
7,676
1,406
(2,437)
(600)
—
(753)
2012
25,552
4,418
1,269
(1,849)
(1,500)
—
—
2011
5,919
3,277
1,597
Amounts in US$ ’000
Staff costs (Note 10)
Consultant fees
New projects
(1,471)
Office expenses
Director’s fees and allowance
Travel expenses
Depreciation
Other administrative expenses
(600)
1,344
—
16,254
27,890
10,066
(a) The 2013 charge corresponds to the cost of five unsuccessful exploratory
Note 13
wells: two of them in Chile (one in Fell Block and one in Tranquilo Block)
Selling expenses
and three of them in Colombia (one well in Cuerva Block, one well in each of
the non-operated blocks, Arrendajo and Llanos 32). The 2012 charge
Amounts in US$ ’000
corresponds to the costs of eight unsuccessful exploratory wells: five of them
Transportation
in Chile (two in Fell Block, two in Otway Block and the remaining in Tranquilo
Delivery or pay penalty
Block) and three of them in Colombia (one well in Cuerva Block, one well
Storage
in Arrendajo Block and the remaining in Llanos 17 Block). The 2012 charge
Selling taxes
also includes the loss generated by the relinquishment of an area in the
Del Mosquito Block in Argentina. The 2011 charge corresponds to the write-
off of exploration and evaluation assets in the Fell Block. The charge includes
the cost of an unsuccessful exploratory well amounting to US$2,331,000
Note 14
and also in accordance with the Group’s accounting policy and considering
Financial income
that no additional work would be performed, wells from previous years
were written-off for an amount of US$3,588,000.
Amounts in US$ ’000
(b) The impairment charge relates to assets located in Del Mosquito Block
Exchange difference
based on the impairment test performed in 2011.
Interest received
2013
22,084
6,424
3,720
2,652
1,426
1,258
1,621
7,399
2012
9,575
5,122
2,927
3,293
1,516
1,563
1,010
3,792
46,584
28,798
2011
8,148
1,896
1,726
1,172
903
686
564
3,137
18,232
2013
16,181
—
665
406
2012
22,066
1,718
645
202
2011
1,886
—
508
152
17,252
24,631
2,546
2013
1,468
3,425
4,893
2012
348
544
892
2011
32
130
162
GeoPark 20F 199
Note 15
Financial expenses
Amounts in US$ ’000
Bank charges and other financial costs
Exchange difference
Bond GeoPark Fell SpA
cancellation costs (Note 26)
Unwinding of long-term liabilities
2013
2,519
2,228
8,603
1,523
2012
1,764
2,429
—
1,262
2011
1,856
496
—
350
Under current Bermuda law, the Company is not required to pay any taxes
in Bermuda on income or capital gains. The Company has received an
undertaking from the Minister of Finance in Bermuda that, in the event of
any taxes being imposed, they will be exempt from taxation in Bermuda
until March 2035.
Income tax rates in those countries where the Group operates (Argentina,
Brazil, Colombia and Chile) ranges from 15% to 35%.
Interest and amortisation
of debt issue costs
Less: amounts capitalised
on qualifying assets
Note 16
Income tax
Amounts in US$ ’000
Current tax
Deferred income tax (Note 17)
25,209
13,114
11,573
future taxable profit in the following countries:
The Group has significant tax losses available which can be utilised against
(1,313)
38,769
(1,369)
17,200
(597)
Amounts in US$ ’000
13,678
Argentina
Total tax losses at 31 December
2013
10,259
10,259
2012
11,645
11,645
2011
18,656
18,656
2013
13,337
1,817
15,154
2012
7,536
6,858
14,394
At the balance sheet date deferred tax assets in respect of tax losses in
Argentina have not been recognised as there is insufficient evidence
of future taxable profits before the statute of limitation of these tax losses
2011
causes them to expire.
187
7,019
7,206
Expiring dates for tax losses accumulated at 31 December 2013 are:
Expiring date
Amounts in US$ ’000
477
3,778
1,985
2,617
1,402
2014
2015
2016
2017
2018
The tax on the Group’s profit before tax differs from the theoretical amount
that would arise using the weighted average tax rate applicable to profits
of the consolidated entities as follows:
Amounts in US$ ’000
Profit before tax
Tax losses from
non-taxable jurisdictions
Taxable profit
2013
50,088
2012
32,840
2011
12,268
14,348
64,436
8,373
41,213
8,565
20,833
Income tax calculated at domestic
tax rates applicable to profits in the
respective countries
14,011
6,290
5,473
Tax losses where no deferred
income tax is recognised
Effect of currency translation
on tax base
Expiration of tax loss carry-forwards
Non-taxable results(1)
Income tax
328
2,864
2,560
(5,146)
1,988
3,973
2,436
—
2,804
15,154
14,394
(761)
—
(66)
7,206
(1) Includes non-deductible expenses in each jurisdiction and changes in the
estimation of deferred tax assets and liabilities.
200 GeoPark 20F
Note 17
Deferred income tax
Note 18
Earnings per share
The gross movement on the deferred income tax account is as follows:
Amounts in US$ ’000
2013
2012
2011
Amounts in US$ ’000
Deferred tax at 1 January
Acquisition of subsidiaries
Reclassification(1)
Income statement charge
Deferred tax at 31 December
2013
(3,911)
—
(4,001)
(1,817)
(9,729)
2012
(12,659)
15,606
—
(6,858)
(3,911)
Numerator:
2011
Profit for the year
(5,640)
Denominator:
22,012
11,879
54
—
—
Weighted average number
of shares used in basic EPS
43,603,846
42,673,981
41,912,685
(7,019)
Earnings after tax per
(12,659)
share (US$) – basic and diluted
0.50
0.28
0.00
The breakdown and movement of deferred tax assets and liabilities as of
Amounts in US$ ’000
2013
2012
2011
31 December 2013, 2012 and 2011 are as follows:
Weighted average number
of shares used in basic EPS
43,603,846
42,673,981
41,912,685
At the Acquisition (Charged) /
Effect of dilutive potential
Amounts in US$ ’000
of year
sidiaries
net profit
beginning
of sub-
credited to
Deferred tax assets
Difference in depreciation
rates and other
Taxable losses(2)
Total 2013
Total 2012
Total 2011
9,211
4,380
13,591
450
374
—
—
—
15,606
—
(11,788)
11,555
(233)
(2,465)
76
At end
of year
(2,577)
15,935
common shares
Stock award at US$0.001
2,928,203
1,435,324
2,004,482
Weighted average number
of common shares for the
purposes of diluted earnings
per shares
46,532,049
44,109,305
43,917,167
13,358
Earnings after tax
13,591
per share (US$) – diluted
0.47
0.27
0.00
450
At the (Charged) /
beginning credited to
Amounts in US$ ’000
of year
net profit
Reclassi-
fication(1)
At end
of year
Deferred tax liabilities
Difference in depreciation
rates and other
Total 2013
Total 2012
Total 2011
(17,502)
(17,502)
(13,109)
(6,014)
(1,584)
(1,584)
(4,393)
(7,095)
(4,001)
(4,001)
(23,087)
(23,087)
— (17,502)
— (13,109)
(1) Corresponds to the difference between 2012 income tax provision and
the final form presented, which resulted in a higher deferred income tax
liability and lower income tax payable.
(2) In Chile, taxable losses have no expiration date.
GeoPark 20F 201
Note 19
Property, plant and equipment
Amount in US$ ’000
Cost at 1 January 2011
Additions
Disposals
Write-off / Impairment
Transfers
Cost at 31 December 2011
Additions
Disposals
Write-off / Impairment
Acquisition of subsidiaries
Transfers
Cost at 31 December 2012
Additions
Disposals
Write-off / Impairment
Transfers
Cost at 31 December 2013
Depreciation and write-down
at 1 January 2011
Depreciation
Depreciation and write-down
at 31 December 2011
Depreciation
Depreciation and write-down
at 31 December 2012
Depreciation
Depreciation and write-down
Furniture,
Production
Buildings
Oil & gas
equipment
facilities and
and
Construction in
properties
and vehicles
machinery
improvements
126,626
2,318
(227)
—
43,239
171,956
4,071
(416)
—
62,449
106,311
344,371
9,367
(553)
—
140,075
493,260
(33,508)
(20,096)
(53,604)
(44,552)
(98,156)
(59,234)
1,445
825
(177)
—
82
2,175
637
—
—
389
375
3,576
2,060
(22)
—
117
5,731
(851)
(343)
(1,123)
(713)
(1,836)
(964)
38,142
1,261
(1,852)
—
9,551
47,102
32,335
(130)
—
10,865
(3,223)
86,949
512
(*)(15,870)
—
27,246
98,837
(13,308)
(5,767)
(18,628)
(7,708)
(26,336)
(9,341)
2,076
156
—
—
205
2,437
—
—
—
—
761
3,198
—
—
—
3,820
7,018
(514)
(202)
(716)
(344)
(1,060)
(661)
Exploration
and evaluation
assets(1)
23,412
39,469
—
(7,263)
(13,478)
42,140
83,360
—
(25,552)
27,818
(34,660)
93,106
133,301
—
(10,962)
(67,686)
Total
207,898
100,599
(2,528)
(7,263)
—
298,706
201,644
(546)
(25,552)
110,973
—
585,225
235,216
(16,445)
(10,962)
—
147,759
793,034
—
—
—
—
—
—
—
(48,181)
(26,408)
(74,071)
(53,317)
(127,388)
(70,200)
(197,588)
progress
16,197
56,570
(272)
—
(39,599)
32,896
81,241
—
—
9,452
(69,564)
54,025
89,976
—
—
(103,572)
40,429
—
—
—
—
—
—
—
at 31 December 2013
(157,390)
(2,800)
(35,677)
(1,721)
118,352
1,052
28,474
1,721
32,896
42,140
224,635
246,215
1,740
60,613
2,138
54,025
93,106
457,837
335,870
2,931
63,160
5,297
40,429
147,759
595,446
Carrying amount at
31 December 2011
Carrying amount at
31 December 2012
Carrying amount at
31 December 2013
202 GeoPark 20F
As of 31 December 2013, the Group has pledged, as security for a mortgage
Amounts in US$ ’000
obtained for the acquisition of the operating base in Chile, assets amounting
to US$493,000 (US$692,000 in 2012 and US$638,000 in 2011). See Note 26.
Exploration wells at 31 December 2010
Additions
On 25 August 2011 the exploratory period in the Fell Block ended. The
exploration programme carried out during the exploration period enabled
the Company to declare commerciality on approximately 84% of the
total area of the Block. The remaining area not declared as commercial
was relinquished, which did not generate any loss for the Group.
(*) During 2013, the Company entered into a finance lease for which it has
transferred a substantial portion of the risk and rewards of some assets
Write-offs
Transfers
Exploration wells at 31 December 2011
Additions
Write-offs
Transfers
Acquisition of subsidiaries
Exploration wells at 31 December 2012
Additions
which had a book value of US$14.1 million. As of 31 December 2013,
Write-offs
prepayments and other receivables include receivables under finance leases
Transfers
amounting to US$8.0 million, which US$6.5 million are maturity no later
Exploration wells at 31 December 2013
than one year and US$1.5 million between one and five years. Total
Total
5,787
35,400
(5,919)
(13,027)
22,241
47,891
(21,339)
(23,496)
1,868
27,165
77,933
(7,934)
(67,246)
29,918
unearned interest income amounts to US$1.2 million.
As of 31 December 2013, there were five exploratory wells that have been
capitalised for a period over a year amounting to US$11,251,000 (nil in 2012)
(1) Exploration wells movement and balances are shown in the below
and six exploratory wells that have been capitalised for a period less than a
table; seismic and other exploratory assets amount to US$117,841,000
year amounting to US$18,667,000 (US$27,165,000 in 2012).
(US$65,941,000 in 2012 and US$39,899,000 in 2011).
GeoPark 20F 203
Note 20
Subsidiary undertakings
The following chart illustrates main companies of the Group structure as of
31 December 2013:
GeoPark Limited
(Bermuda)
100%
100%
99.9%
99.9%
GeoPark Latin
America
Limited – Bermuda
(Bermuda)
100%
GeoPark Latin
America Limited
Agencia en Chile
(Chile)
1%
GeoPark Argentina
Limited – Bermuda
(Bermuda)
GeoPark Latin
America
Coöperatie U.A.
(Netherlands)
100%
80%
GeoPark Argentina
Limited -
Argentinean
Branch (Argentina)
GeoPark Colombia
Coöperatie
U.A.
(Netherlands)
20%
LG
International
GeoPark Brazil
Coöperatie U.A.
(Netherlands)
99.9%
GeoPark Brazil
Exploração e
Produção de Petróleo
e Gás Ltda. (Brazil)
80%
99.9%
LG
International
20% GeoPark Chile S.A.
(Chile)
GeoPark S.A.
(Chile)
14%
86%
100%
99%
GeoPark TdF S.A.
(Chile)
GeoPark Fell SpA.
(Chile)
GeoPark
Magallanes
Limitada (Chile)
100%
GeoPark Colombia
SAS (Chile)
204 GeoPark 20F
Details of the subsidiaries and joint operations of the Company are
set out below:
Subsidiaries
Associates
Joint operations
Name and registered office
GeoPark Argentina Ltd. – Bermuda
GeoPark Argentina Ltd. – Argentine Branch
GeoPark Latin America
GeoPark Latin America – Agencia en Chile
GeoPark S.A. (Chile)
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. (Brazil)
GeoPark Chile S.A. (Chile)
GeoPark Fell S.p.A. (Chile)
GeoPark Magallanes Limitada (Chile)
GeoPark TdF S.A. (Chile)
GeoPark Colombia S.A. (Chile)
GeoPark Colombia SAS (Colombia)
GeoPark Brazil S.p.A. (Chile)
GeoPark Latin America Cooperatie U.A. (The Netherlands)
GeoPark Colombia Cooperatie U.A. (The Netherlands)
GeoPark Brazil Cooperatie U.A. (The Netherlands)
Raven Pipeline Company LLC (United States)
Tranquilo Block (Chile)
Otway Block (Chile)
Flamenco Block (Chile)
Isla Norte Block (Chile)
Campanario Block (Chile)
Llanos 17 Block (Colombia)
Yamu/Carupana Block (Colombia)
Llanos 34 Block (Colombia)
Llanos 32 Block (Colombia)
Ownership interest
100%
100%(a)
100%(h)
100%(a)(h)
100%(a)(b)
100%
80%(a)(c)
80%(a)(c)
80%(a)(c)
68.8%(a)(d)
80%(a)(e)
100%(a)(e)(i)
100%(a)(b)
100%(b)
100%(b)
100%(b)
23.5%(b)
29%(j)(g)
25%(f)(g)
50%(g)
60%(g)
50%(g)
36.84%
75%/54.5%(g)
45%(g)
10%
(a) Indirectly owned.
(b) Dormant companies.
(g) GeoPark is the operator in all blocks.
(h) Formerly named GeoPark Chile Limited.
(c) LG International has 20% interest.
(i) During 2013, the Company has finalized a merger process by which
(d) LG International has 20% interest through GeoPark Chile S.A. and a 14%
GeoPark Colombia SAS will continue the operations related to GeoPark Luna
direct interest, totalling 31.2%.
SAS (Colombia), GeoPark Llanos SAS (Colombia), La Luna Oil Co. Ltd.
(e) During the first quarter of 2012, the Company entered into a business
(Panama), Winchester Oil and Gas S.A. (Panama), GeoPark Cuerva LLC
combination acquiring 100% interest in each entity. In December 2012,
(United States), Sucursal La Luna Oil Co. Ltd. (Colombia), Sucursal Winchester
LG International acquired 20% equity.
Oil and Gas S.A. (Colombia) and Sucursal GeoPark Cuerva LLC (Colombia).
(f) In April 2013, the Group voluntarily relinquished to the Chilean Government all
(j) At 31 December 2013, the Consortium members and interest were:
of our acreage in the Otway Block, except for 49,421 acres. In May 2013, our
GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. During
partners under the joint operating agreement governing the Otway Block decided
2014, Methanex announced its decision to abandon the Consortium.
to withdraw from such joint operating agreement and to apply to withdraw
The new ownership will be as follows: GeoPark 37.5%, Pluspetrol 34.9% and
from the Otway Block CEOP, such that, subject to the Chilean Ministry of Energy’s
Wintershall 27.6%.
approval, the Group will be the sole participant, and have a working interest of
100%, in the remaining areas in the Otway Block.
GeoPark 20F 205
Note 21
Prepaid taxes
Amounts in US$ ’000
V.A.T.
Withholding tax
Income tax credits
Other prepaid taxes
Total prepaid taxes
Classified as follows:
Current
Non-current
Total prepaid taxes
Note 22
Inventories
Amounts in US$ ’000
Crude oil
Materials and spares
Note 23
At 31 December 2013, the Group has no receivables for which exist
impairment indicators. Therefore, the Group has no recognised any provision
for receivables impairment.
2012
5,962
3,347
4,692
The credit period for trade receivables is 30 days. The maximum exposure
to credit risk at the reporting date is the carrying value of each class
of receivable. The Group does not hold any collateral as security related to
149
trade receivables.
2013
10,635
4,601
344
2,853
18,433
14,150
6,979
11,454
18,433
The carrying value of trade receivables is considered to represent a
3,443
reasonable approximation of its fair value due to their short-term nature.
10,707
14,150
Note 24
Financial instruments by category
2013
4,464
3,658
8,122
2012
3,838
117
3,955
Amounts in US$ ’000
Assets as per statement of financial position
Trade receivables
To be recovered from co-venturers
Other financial assets (*)
Cash at bank and in hand
Loans and receivables
2013
2012
42,628
15,508
5,168
121,135
184,439
32,271
8,773
7,791
48,292
97,127
Trade receivables and Prepayments and other receivables
(*) Other financial assets relate to contributions made for environmental
obligations according to Colombian government regulations. For 2012, they
2012
also include the cash collateral account required under the terms of the
32,271
Bond issued in 2010. This investment was intended to guarantee interest
payments and was recovered at repayment date (see Note 26).
82,401
Amounts in US$ ’000
Liabilities as per statement of financial position
Trade payables
81,891
510
To be paid to co-venturers
82,401
Borrowings
Other financial
liabilities at
amortised cost
2013
2012
61,130
1,201
50,590
2,007
317,087
193,032
379,418
245,629
Amounts in US$ ’000
Trade accounts receivable
To be recovered from co-venturers
Related parties receivables (Note 32)
Prepayments and other receivables
Total
Classified as follows:
Current
Non-current
Total
2013
42,628
42,628
15,508
—
26,617
42,125
84,753
78,392
6,361
84,753
32,271
8,773
31,138
10,219
50,130
Trade receivables that are aged by less than three months are not considered
impaired. As of 31 December 2013, trade receivables of US$1,143,393
(US$31,984 in 2012) were aged by more than 3 months, but not impaired.
These relate to customers for whom there is no recent history of default.
There are no balances due between 31 days and 90 days as of 31 December
2013 and 2012.
206 GeoPark 20F
Credit quality of financial assets
The credit quality of financial assets that are neither past due nor impaired
Financial liabilities - contractual undiscounted cash flows
The table below analyses the Group’s financial liabilities into relevant
can be assessed by reference to external credit ratings (if available) or to
maturity groupings based on the remaining period at the balance sheet to
historical information about counterparty default rates:
the contractual maturity date. The amounts disclosed in the table are the
Amounts in US$ ’000
Trade receivables
Counterparties with an
external credit rating (Moody’s)
Ba1
Baa1
Baa2
Baa3
Counterparties without an
external credit rating Group1(*)
Total trade receivables
2013
2012
contractual undiscounted cash flows.
Between
Between
Less than
1 and 2
2 and 5
Amounts in US$ ’000
1 year
years
years
Over
5 years
—
—
2,048
17,321
23,259
42,628
4,769
13,488
At 31 December 2013
Borrowings
4,781
Trade payables
—
9,233
At 31 December 2012
Borrowings
32,271
Trade payables
39,585
61,130
22,600
67,500
345,000
—
—
—
100,715
22,600
67,500
345,000
36,031
50,590
86,621
10,437
181,100
—
—
10,437
181,100
—
—
—
(*) Group 1 – existing customers (more than 6 months) with no defaults in the
past.
All trade receivables are denominated in US Dollars.
Cash at bank and other financial assets(1)
Amounts in US$ ’000
2013
2012
Counterparties with an external credit rating
(Moody’s, Fitch, BRC Investor Services)
Note 25
Share capital
Issued share capital
Common stock
(amounts in US$ ’000)
The share capital is distributed
as follows:
2013
44
2012
43
A1
A3
Aa1
Aa3
P1
P2
P3
AA+
BRC 1+
4,812
7,408
Common shares, of nominal US$0.001
—
—
11
102,390
460
3,789
2,643
3,546
366
Total common shares in issue
2,131
38,952
2,537
—
—
—
—
Authorised share capital
US$ per share
Number of common shares
(US$0.001 each)
Amount in US$
43,861,614
43,861,614
43,495,585
43,495,585
0.001
0.001
5,171,949,000
5,171,969,000
5,171,949
5,171,969
Counterparties without an external
Details regarding the share capital of the Company are set out below:
credit rating
Total
8,631
126,282
4,665
56,059
Common shares
As of 31 December 2013 the outstanding common shares confer the
(1) The rest of the balance sheet item ‘cash at bank and in hand’ is cash on
following rights on the holder:
hand amounting to US$21,000 (US$24,000 in 2012).
•
•
the right to one vote per share;
ranking pari passu, the right to any dividend declared and payable on
common shares;
GeoPark 20F 207
GeoPark
Shares
issued
Shares
closing
US$
for the account of the EBT. This Purchase Program expired on 31 December
(`000)
2013. The common shares purchased under the program will be used to
common shares history
Date
(millions)
(millions)
Closing
satisfy future awards under the incentive schemes. During 2013, the Company
Shares outstanding
at the end of 2010
Issue of shares to
Non-Executive Directors
2011
May 2011
Oct 2011
Oct 2011
Stock awards
Stock awards
IPO stock options
Shares outstanding
at the end of 2011
Issue of shares to
Non-Executive Directors
2012
Stock awards
Oct 2012
Shares outstanding
at the end of 2012
Issue of shares to
Non-Executive Directors
2013
Stock awards
Sept 2013
Shares outstanding
at the end of 2013
41.7
41.7
41.8
41.9
42.5
42.5
42.5
43.5
43.5
43.5
43.9
0.01
0.06
0.10
0.60
0.02
1.01
0.01
0.36
42
42
42
42
43
43
43
43
purchased 50,000 common shares for a total amount of US$440,000.
The accounting treatment of the shares is in line with the Group’s policy on
share-based payments.
Other Reserve
During 2011, LGI acquired a 20% interest in GeoPark Chile S.A., the subsidiary
that owns the Chilean assets for a total consideration of US$148,000,000.
During 2012, LGI acquired a 20% interest in GeoPark Colombia S.A., the
subsidiary that owns the Colombian assets by making a capital contribution
in GeoPark Colombia S.A. for an amount of US$14,920,000. In addition,
as part of the transaction, US$5,000,000 was transferred directly to the
43
Colombian subsidiary as a loan. The differences between total consideration
and the net equity of the Companies as per the book value were recorded
as Other Reserve in the Consolidated Statement of Changes in Equity.
43
44
44
Note 26
Borrowings
During 2013, the Company issued 10,430 (15,100 in 2012 and 12,028 in 2011)
shares to Non-Executive Directors in accordance with contracts as
Issued share capital
2013
2012
compensation, generating a share premium of US$100,988 (US$142,492
in 2012 and US$130,733 in 2011). The amount of shares issued is determined
considering the contractual compensation and the fair value of the shares
for each relevant period.
Under the stock awards programmes and other share based payments,
during 2013, 60,000 (30,000 in 2012 and 158,000 in 2011) new common
shares were issued, pursuant to a consulting agreement for services
rendered to GeoPark Limited generating a share premium of US$506,630
(US$253,315 in 2012 and US$1,730,000 in 2011).
Outstanding amounts as of 31 December
Bond GeoPark Latin America Agencia en Chile(a)
Methanex Corporation(b)
Banco de Crédito e Inversiones(c)
Banco de Chile(d)
Overdrafts(e)
Banco Itaú(f)
Bond GeoPark Fell SpA(g)
Classified as follows:
Non-current
On 17 September 2013, 295,599 common shares were allotted to the trustee
Current
of the Employee Beneficiary Trust (“EBT”), generating a share premium of
299,912
—
2,143
15,002
30
—
—
—
8,036
7,859
—
10,000
37,685
129,452
317,087
193,032
290,457
26,630
165,046
27,986
US$3,441,689. On 22 October 2012, 976,211 common shares were allotted to
The fair value of these financial instruments at 31 December 2013 amounts
the trustee of the EBT, generating a share premium of US$4,191,000. On 6
to US$312,208,000 (US$190,188,000 in 2012). The fair values are based
October 2011, 601,235 common shares were allotted to the trustee of the EBT
on cash flows discounted using a rate based on the borrowing rate of 7.81%
in anticipation of the exercise of the 2006 Stock Option Plan (see Note 29).
(2012: 9.63%) and are within level 2 of the fair value hierarchy.
On 29 October 2013, the Company put into place an irrevocable, non-
(a) During February 2013, the Company successfully placed US$300 million
discretionary share purchase program for the purchase of its common shares
notes which were offered under Rule 144A and Regulation S exemptions of
the United States Securities laws.
208 GeoPark 20F
The Notes, issued by the Company's wholly-owned subsidiary GeoPark Latin
Note 27
America Limited Agencia en Chile ("the Issuer"), were priced at 99.332% and
Provisions and other long-term liabilities
carry a coupon of 7.50% per annum to yield 7.625% per annum. Final maturity
of the notes will be 11 February 2020. The Notes are guaranteed by GeoPark
Limited and GeoPark Latin America Cooperatie U.A. and are secured with
Asset
retirement
Deferred
a pledge of all of the equity interests of the Issuer in GeoPark Chile S.A. and
Amounts in US$ ’000
obligation
income
Other
3,153
—
GeoPark Colombia S.A. and a pledge of certain intercompany loans. Notes
were rated single B by both Standard & Poor's and Fitch Ratings. The debt
issuance cost for this transaction amounted to US$7,637,000.
The net proceeds of the notes were partially used to repay debt of
approximately US$170 million, including the existing Regulation S Notes
due 2015 and the Itaú loan. The remaining proceeds are being used
At 1 January 2011
Addition to provision /
Contributions received
Amortisation
Unwinding of discount
At 31 December 2011
Addition to provision /
to finance the Company’s expansion plans in the region. The transaction
Contributions received
extended GeoPark's debt maturity significantly, allowing the Company
Acquisition of subsidiaries
to allocate more resources to its investment and inorganic growth programs
Amortisation
in the coming years.
(b) The financing obtained in 2007, for development and investing activities
Unwinding of discount
At 31 December 2012
Addition to provision /
1,947
—
350
5,450
3,440
6,061
—
1,262
16,213
on the Fell Block, was structured as a gas pre-sale agreement with a six
Contributions received
7,183
year pay-back period and an interest rate of LIBOR flat. The loan has been
Recovery of
fully repaid during 2013.
abandonments costs
Amortisation
(c) Facility to establish the operational base in the Fell Block. This facility
Unwinding of discount
(753)
—
1,523
was acquired though a mortgage loan granted by the Banco de Crédito e
At 31 December 2013
24,166
Inversiones (BCI), a Chilean private bank (Note 19). The loan was granted
5,000
(1,038)
—
3,962
5,550
—
(2,143)
—
7,369
—
—
(1,165)
—
6,204
—
—
—
—
—
100
2,309
—
—
2,409
Total
3,153
6,947
(1,038)
350
9,412
9,090
8,370
(2,143)
1,262
25,991
297
7,480
—
—
—
2,706
(753)
(1,165)
1,523
33,076
in Chilean Pesos and is repayable over a period of 8 years. The interest rate
The provision for asset retirement obligation relates to the estimation of
applicable to this loan is 6.6%. The outstanding amount at 31 December
future disbursements related to the abandonment and decommissioning of
2013 is US$212,000 (US$344,000 in 2012). In addition, during 2011, GeoPark
oil and gas wells.
TdF obtained financing from BCI to start the operations in the newly acquired
blocks. The outstanding amount at 31 December 2013 is US$1,931,000
Deferred income and other mainly relates to contributions received to
(US$7,515,000 in 2012). This financing was structured as letter of credit and
was fully repaid in February 2014.
improve the project economics of the gas wells. The amortisation is in line
with the related asset.
(d) Short term financing obtained in December 2013 and fully repaid in
January 2014. The interest rate applicable to this loan was 0.71% per annum.
(e) The Group has been granted with credit lines for over US$76,000,000.
(f) GeoPark Limited executed a loan agreement with Banco Itaú BBA S.A.,
Nassau Branch for US$37,500,000. GeoPark used the proceeds to finance the
acquisition and development of the La Cuerva and Llanos 62 blocks in
Colombia. This loan was fully repaid in February 2013.
(g) Private placement of US$133,000,000 of Regulation S Notes on December
2, 2010. The Notes carried a coupon of 7.75% per annum and mature on
15 December 2015. These Notes were fully repaid in March 2013.
GeoPark 20F 209
Note 28
Trade and other payables
Amounts in US$ ’000
V.A.T
Trade payables
Payables to related parties(1)
Staff costs to be paid
Royalties to be paid
Taxes and other debts to be paid
To be paid to co-ventures
Classified as follows:
Non-current
Current
Note 29
Share-based payments
2013
8,074
61,130
8,456
8,551
3,375
9,190
1,201
2012
4,300
IPO Award Programme and Executive Stock Option plan
The Group has established different stock awards programmes and other
50,590
share-based payment plans to incentivise the Directors, senior management
—
and employees, enabling them to benefit from the increased market
5,867
3,909
5,418
2,007
capitalization of the Company.
Stock Award Programmes and Other Share Based Payments
During 2008, GeoPark Shareholders voted to authorize the Board to use up
99,977
72,091
to 12% of the issued share capital of the Company at the relevant time for
the purposes of the Performance-based Employee Long-Term Incentive Plan.
8,344
91,633
—
72,091
Main characteristics of the Stock Awards Programmes are:
(1) In December 2012, LGI entered into GeoPark’s operations in Colombia
• All employees are eligible.
through the acquisition of a 20% of interest in Colombian business. As part
• Exercise price is equal to the nominal value of shares.
of the transaction, LGI committed to fund the operations in Colombia
• Vesting period is four years.
through loans (see Note 34). The maturity of these loans is December 2015
• Specific Award amounts are reviewed and approved by the Executive
and the applicable interest rate is 8% per annum.
Directors and the Remuneration Committee of the Board of Directors.
The average credit period (expressed as creditor days) during the year ended
Additionally, during 2013 the Company approved two new share-based
31 December 2013 was 58 days (2012: 69 days)
compensation programs: i.) a stock awards plan oriented to Managers (non-
Top Management) and key employees which qualifies as an equity-settled
The fair value of these short-term financial instruments is not individually
plan and ii.) a cash awards plan, oriented to all non-management employees
determined as the carrying amount is a reasonable approximation of
which qualifies as a cash-settled plan.
fair value.
Main characteristics of these news plans are:
- Exercise price: US$0.001
- Grant date: July 2013
- Grant price: £ 5.8
- Vesting date: 31 December 2015
- Conditions to be able to exercise:
• Continue to be an employee
• Obtain the Company minimum Production, Adjusted EBITDA and Reserves
target for the year of vesting
• The stock market price at the date of vesting should be higher than the
share price at the price of grant
- Amount of shares for equity-settled plan: 500,000
- Estimated equivalent amount of shares for cash-settled plan: 500,000
Also during 2013, the Company approved a plan named Value creation plan
(“VCP”) oriented to Top Management. The VCP establishes awards payables in
a variable number of shares with some limitation, subject to certain market
conditions, among others, reach certain stock market price for the Company
share at vesting date. VCP has been classified as an equity-settled plan.
210 GeoPark 20F
Details of these costs and the characteristics of the different stock awards
programmes and other share based payments are described in the following
table and explanations:
Year
2013
2012
2011
2010
2008
Subtotal
Stock awards for
service contracts
Stock options to
Executive Directors
Shares granted to
Awards
at the
beginning
Awards
granted in
the year
500,000
500,000
500,000
852,100
—
60,000
720,000
—
—
—
—
—
—
Non-Executive Directors
VCP
—
—
10,430
—
Awards
forfeited
Awards
Awards at
exercised
year end
57,000
6,000
16,500
—
—
—
—
—
—
—
—
—
60,000
500,000
443,000
494,000
835,600
—
—
2013
619
1,296
893
2,779
—
5,587
—
—
720,000
2,365
10,430
—
—
—
101
309
8,362
The awards that are forfeited correspond to employees that had left the
Group before vesting date.
On 23 November 2012, the Remuneration Committee and the board of
directors approved granting 720,000 options over ordinary shares of
US$0.001 each to the Executive Directors. Options granted vest on the third
anniversary of the date on which they are granted and have an exercise
price of US$0.001.
Other share-based payments
As it is mentioned in Note 25, the Company granted 10,430 (15,100 in
2012 and 12,028 in 2011) shares for services rendered by the Non-Executive
Directors of the Company. Fees paid in shares were directly expensed
in the Administrative costs line in the amount of US$100,988 (US$142,492
in 2012 and US$130,745 in 2011).
In August 2011 the Company issued a total of 180,000 options over US$0.001
shares with an exercise price equal to their nominal value in consideration
for certain consultancy services.
Charged to net profit
2012
—
55
926
2,929
1,087
4,997
—
257
142
—
5,396
2011
—
—
37
2,776
925
3,738
1,429
—
131
—
5,298
GeoPark 20F 211
Note 30
Interests in Joint operations
The Group has interests in nine joint operations, which are involved in the
exploration of hydrocarbons in Chile and Colombia.
GeoPark is the operator of all of the Chilean blocks.
Joint operation
Subsidiary
Interest(*)
Assets
PP&E / E&E
The following amounts represent the Company’s share in the assets, liabilities
Other assets
and results of the joint operations which have been consolidated line by line
Total Assets
in the consolidated statement of financial position and statement of income:
Chile
Liabilities
Current liabilities
Total Liabilities
Net Assets/(Liabilities)
Joint operation
Tranquilo Block
Otway Block
Sales
Flamenco Campanario
Isla Norte
Block
GeoPark
TdF S.A.
50%
2013
Block
GeoPark
TdF S.A.
50%
2013
Block
GeoPark
TdF S.A.
60%
2013
42,048
17,172
—
—
42,048
17,172
(2,537)
(2,537)
39,511
243
(239)
(405)
(405)
16,767
—
—
4,497
—
4,497
(303)
(303)
4,194
—
—
GeoPark
Magallanes Ltda.
29%
29%
GeoPark
Magallanes Ltda.(1)
25%
100%
Net loss
2013
2012
2013
2012
period, the above balances and operations were consolidated at 100%
(*) As the activity on the three blocks corresponds to the first exploratory
Subsidiary
Interest
Assets
PP&E / E&E
Other assets
Total Assets
Liabilities
Current liabilities
Total Liabilities
Net Assets/(Liabilities)
Sales
Net loss
15,255
210
15,465
(391)
(391)
15,074
—
(275)
13,328
1,467
14,795
(3,252)
(3,252)
11,543
—
(544)
6,009
175
6,184
(48)
(48)
6,136
—
(100)
6,516
1,326
7,842
(2,412)
(2,412)
5,430
—
(386)
(see Note 31).
Colombia
31 December 2013
Yamu/
Joint operation
Block
Block
Block
Block
Llanos 17
Carupana
Llanos 34
Llanos 32
GeoPark
GeoPark
GeoPark
GeoPark
Colombia
Colombia
Colombia
Colombia
Subsidiary
SAS
SAS
75%/
SAS
SAS
Interest
Assets
PP&E / E&E
Other assets
Total Assets
Liabilities
Current liabilities
Total Liabilities
Net Assets /
(Liabilities)
Sales
Net profit / (loss)
36.84%
54.50%
45%
10%
6,448
29
6,477
—
—
6,477
1,407
(544)
15,476
482
15,958
51,963
1,129
53,092
—
—
—
—
15,958
17,727
2,127
53,092
78,390
39,192
4,993
—
4,993
—
—
4,993
5,507
1,035
(1) Included for comparative purposes. See Note 20.
212 GeoPark 20F
31 December 2012
In Colombia, royalties on production are payable to the Colombian
Yamu/
Government and are determined on a field-by-field basis using a level of
Llanos 17
Carupana
Llanos 34
Llanos 32
production sliding scale and a rate which ranges between 6%-8%. The
Joint operation
Block
Block
Block
Block
Colombian National Hydrocarbons Agency (“ANH”) also has an additional
GeoPark
economic right equivalent to 1% of production, net of royalties. Additionally,
Colombia
GeoPark
under the terms of the Winchester Stock Purchase Agreement, we are
GeoPark
and
Colombia
GeoPark
obligated to make certain payments to the previous owners of Winchester
Subsidiary
Luna SAS
Luna SAS
SAS
Luna SAS
based on the production and sale of hydrocarbons discovered by exploration
Interest
Assets
PP&E / E&E
Other assets
Total Assets
Liabilities
Current liabilities
Total Liabilities
Net assets /
(Liabilities)
Sales
Net profit / (loss)
36.84%
75%/
54.50%
wells drilled after October 25, 2011. These payments involve both an earnings
45%
10%
based measure and an overriding royalty equal to an estimated 4% carried
interest on the part of the vendor. As at the balance sheet date and based
3,872
144
4,016
(224)
(224)
3,792
144
144
12,626
25,178
26
72
4,384
1,484
on preliminary internal estimates of additions of 2P reserves since acquisition,
the Company’s best estimate of the total commitment over the remaining
12,652
25,250
5,868
life of the concession is a range of US$40 million - US$50 million
—
—
—
—
(assuming a discount rate of 10% and oil price of US$94 per barrel). During
(1,509)
2013, the Company has accrued and paid US$11.5 million and US$7.8
(1,509)
million, respectively.
12,652
23,283
4,034
25,250
10,362
3,767
4,359
2,900
1,207
(b) Capital commitments
Chile
As of 31 December 2013 the only remaining commitments in Chile are related
Capital commitments are disclosed in Note 31 (b).
to Tierra del Fuego blocks. The future investment commitments assumed
Note 31
Commitments
by GeoPark outstanding are:
• Flamenco Block: 6 exploratory wells (US$19,440,000)
• Campanario Block: 8 exploratory wells (US$30,666,000)
• Isla Norte Block: 3 exploratory wells and 221 km2 of seismic surveys
(a) Royalty commitments
In Argentina, crude oil production accrues royalties payable to the Provinces
(US$13,857,000)
of Santa Cruz and Mendoza equivalent to 12% on estimated value at
The investments made in the first exploratory period will be assumed 100%
well head of those products. This value is equivalent to final sales price less
transport, storage and treatment costs.
by GeoPark.
In Argentina crude oil sales accrue private royalties payable to EPP
Colombia
The Llanos 32 Block Consortium has committed to drill two exploratory wells
Petróleo S.A. (2.5% on invoiced amount of crude oil obtained from wells at
between 2013 and 2014.
“Del Mosquito”, Province of Santa Cruz, Argentina) and to Occidental
Petroleum Argentina INC, formerly Vintage Argentina Ltd. (8% on invoiced
The Llanos 17 Block Consortium has committed to drill either two exploratory
amount of crude oil obtained from wells at “Loma Cortaderal” and “Cerro
wells or one exploratory well and perform 3D seismic between 2013 and
Doña Juana”, Province of Mendoza, Argentina).
2014. The joint operation estimates that the remaining commitment amounts
In Chile, royalties are payable to the Chilean Government. In the Fell
Block, royalties are calculated at 5% of crude oil production and 3% of gas
The Llanos 62 Block (100% working interest) has committed to drill two
production. In the Flamenco Block, royalties are calculated at 5% of gas
exploratory wells before August 2014. The remaining commitment amounts
production.
to US$3,000,000.
to US$1,225,000 at GeoPark’s working interest (36.84%).
GeoPark 20F 213
Brazil
On 14 May 2013, the ANP awarded GeoPark seven new concessions in Brazil
Note 32
Related parties
in an international bidding round, Round 11. For these seven concessions,
GeoPark committed to invest a minimum of US$15,300,000 (including
bonuses and work program commitment) during the first three years of the
Controlling interest
The main shareholders of GeoPark Limited, a company registered in Bermuda,
exploratory period for the concessions.
as of 31 December 2013, are:
On 28 November 2013, the ANP awarded GeoPark two new concessions in
a new international bidding round, Round 12. For these two concessions,
GeoPark have committed to invest a minimum of US$4,000,000 (including
bonus and work program commitments) during the first exploratory period
(see Note 34)
(c) Operating lease commitments – Group company as lessee
The Group leases various plant and machinery under non-cancellable
operating lease agreements.
Shareholder
Gerald E. O’Shaughnessy(1)
James F. Park(2)
Steven J. Quamme(3)
IFC Equity Investments(4)
Moneda A.F.I.(5)
Juan Cristóbal Pavez(6)
BTG Pactual
The Group also leases offices under non-cancellable operating lease
Charles Schwab & Co.
agreements. The lease terms are between 2 and 3 years, and the majority of
Other shareholders
lease agreements are renewable at the end of the lease period at market rate.
Common
shares
7,533,907
7,156,269
4,984,394
3,456,594
2,241,650
2,171,363
2,097,257
1,393,361
12,826,819
43,861,614
Percentage of
outstanding
common shares
17.18%
16.32%
11.36%
7.88%
5.11%
4.95%
4.78%
3.18%
29.24%
100.00%
During 2013 a total amount of US$19,110,000 (US$ 4,531,000 in 2012 and
(1) Held directly and indirectly through GP Investments LLP, Vidacos
US$3,313,000 in 2011) was charged to the income statement and
Nominees Limited and Globe Resources Group Inc., all of which are controlled
US$37,263,000 of operating leases were capitalised as Property, plant and
by Mr. O’Shaughnessy.
equipment (US$32,706,000 in 2012 and US$28,132,000 in 2011).
(2) Held by Energy Holdings, LLC, which is controlled by James F. Park, a
The future aggregate minimum lease payments under non-cancellable
Mr. Park does not reflect the 782,702 common shares held as of January 10,
operating leases are as follows:
2014 in the employee benefit trust described under ‘‘Management—
member of our Board of Directors. The number of common shares held by
Amounts in US$ ’000
Operating lease commitments
Falling due within 1 year
Falling due within 1 – 3 years
Falling due within 3 – 5 years
Falling due over 5 years
Total minimum lease payments
Compensation—Employee Benefit Trust’’.
2013
2012
(3) Held through certain private investment funds managed and controlled
by Cartica Management, LLC. The common shares reflected as being held
68,817
56,556
31,145
505
26,464
3,709
by Mr. Quamme include 7,422 common shares held by him personally.
Mr. Steven Quamme, one of our principal shareholders and a member of our
443
895
board of directors, is the Senior Managing Director of Cartica Management,
LLC, and therefore may be deemed to have voting and investment power
157,023
31,511
over the common shares of GeoPark held by Cartica Management, LLC.
(4) IFC Equity Investments voting decisions are made through a portfolio
management process which involves consultation from investment officers,
credit officers, managers and legal staff.
(5) Held through various funds managed by Moneda A.F.I. (Administradora
de Fondos de Inversión), an asset manager.
(6) Held through Socoservin Overseas Ltd, which is controlled by Juan
Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez
include 8,559 common shares held by him personally.
214 GeoPark 20F
Balances outstanding and transactions with related parties
Transaction in the year
Balances at year end
Related Party
Relationship
Account (Amounts in ’000)
2013
To be recovered from co-ventures
Payables account
To be paid to co-venturers
Financial expenses
2012
To be recovered from co-ventures
Prepayment and other receivables
To be paid to co-venturers
Exploration costs
Administrative costs
2011
To be recovered from co-ventures
Prepayment and other receivables
Exploration costs
(*) Corresponding to consultancy services.
—
—
—
112
—
—
31
219
—
—
138
There have been no other transactions with the Board of Directors, Executive
Board, Executive officers, significant shareholders or other related parties
during the year besides the intercompany transactions which have been
eliminated in the consolidated financial statements, the normal remuneration
of Board of Directors and Executive Board and other benefits informed in
Note 10.
15,508
(8,456)
(1,201)
—
8,773
31,138
(2,007)
—
—
537
6,000
Joint Operations
Joint Operations
LGI
Partner
Joint Operations
Joint Operations
LGI
Partner
Joint Operations
Joint Operations
LGI
Partner
Joint Operations
Joint Operations
Carlos Gulisano
Carlos Gulisano
Non-Executive
Director(*)
Non-Executive
Director(*)
Joint Operations
Joint Operations
LGI
—
Carlos Gulisano
Partner
Non-Executive
Director(*)
GeoPark 20F 215
Note 33
Fees paid to Auditors
Amounts in US$ ’000
Fees payable to the Group’s
auditors for the audit of
the consolidated financial
statements(*)
Fees payable to the Group’s
auditors for the review of
interim financial results
Fees payable for the audit
of the Group’s subsidiaries
pursuant to legislation
Non-audit services
Fees paid to auditors
income approach (being the net present value of expected future cash flows)
was adopted to determine the fair values of the mineral interest. Estimates
of expected future cash flows reflect estimates of projected future revenues,
2013
2012
2011
production costs and capital expenditures based on our business model.
Under the terms of the sale and purchase agreement entered into in 2012
in respect of the acquisition of Winchester Luna, the Company has to make
668
346
120
certain payments to the former owners arising from the production and sale
of hydrocarbons discovered by exploration wells drilled after 25 October
2011 on the working interests of the companies at that date. These payments
150
52
32
which involve both, an earnings based measure and an overriding revenue
royalty, equate to an estimated 4% carried interest on the part of the vendor.
273
337
298
713
1,428
1,409
113
239
504
The following table summarises the combined consideration paid for
Winchester Luna and Hupecol, the fair value of assets acquired and liabilities
assumed for these transactions:
(*) Include fees related to the IPO process
Winchester
Amounts in US$ ’000
Hupecol
Luna
Total
Non-audit services relates to tax services for US$292,000 (US$121,000
Cash (including working
in 2012 and US$123,000 in 2011) and due diligence and other services for
capital adjustments)
US$45,000 (US$592,000 in 2012 and US$116,000 in 2011).
Note 34
Business transactions
Acquisitions in Colombia
On 14 February 2012, GeoPark acquired two privately-held exploration and
Total consideration
Cash and cash equivalents
Property, plant and equipment
(including mineral interest)
Trade receivables
Prepayments and
other receivables
Deferred income tax assets
production companies operating in Colombia, Winchester Oil and Gas S.A.
Inventories
and La Luna Oil Company Limited S.A. (“Winchester Luna”). For accounting
Trade payables and other debt
purposes, these acquisitions were computed as if they had occurred on 1
February 2012.
Borrowings
Provision for other
long-term liabilities
On 27 March 2012, a second acquisition occurred with the purchase of
Total identifiable net assets
Hupecol Cuerva LLC (“Hupecol”), a privately-held company with two
exploration and production blocks in Colombia. For accounting purposes,
Bargain purchase gain on
acquisition of subsidiaries(1)
this acquisition was computed as if it had occurred on 1 April 2012.
79,630
79,630
976
73,791
4,402
5,640
10,344
10,596
(20,487)
—
32,243
32,243
5,594
111,873
111,873
6,570
37,182
4,098
110,973
8,500
2,983
5,262
1,612
(11,981)
(1,368)
8,623
15,606
12,208
(32,468)
(1,368)
(5,632)
79,630
(2,738)
40,644
(8,370)
120,274
—
8,401
8,401
In accordance with the acquisition method of accounting, the acquisition
a full market price for the proved reserves but received a discount on
cost was allocated to the underlying assets acquired and liabilities assumed
the probable and possible reserves and resource base acquired due to the
based primarily upon their estimated fair values at the date of acquisition. An
vendor’s limited ability to fund the future development of these assets.
(1) The bargain purchase gain is related to the fact that the Company paid
216 GeoPark 20F
The purchase price allocation above mentioned is final.
("Rio das Contas"), the direct owner of 10% of the BCAM-40 Block
(the "Block"), which includes the shallow-depth offshore Manati Field in the
Acquisition-related costs have been charged to administrative expenses in
Camamu-Almada basin.
the consolidated income statement for the year ended 31 December 2012.
LGI partnership
The Manati Field is a strategically important, profitable upstream asset in
Brazil and currently provides approximately 50% of the gas supplied to
On 12 March 2010, LGI and the Company agreed to form a new strategic
the northeastern region of Brazil and more than 75% of the gas supplied to
partnership to jointly acquire and develop upstream oil and gas projects in
Salvador, the largest city and capital of the northeastern state of Bahia.
Latin America.
The field is largely developed with existing producing wells and an extensive
pipeline, treatment and delivery infrastructure and is not expected to
During 2011, GeoPark and LGI entered into several agreements through
require significant future capital expenditures to meet current production
which LGI acquires an equity interest in the Chilean Business of the Group.
estimates. Additional reserve development may be possible.
In December 2012, LGI has also joined GeoPark’s operations in Colombia
The Manati Field is operated by Petrobras (35% working interest),
through the acquisition of a 20% interest in GeoPark Colombia S.A., a
the Brazilian national company, largest oil and gas operator in Brazil and
company that holds GeoPark’s Colombian assets and which includes interests
internationally-respected offshore operator. Other partners in the block
in 10 hydrocarbon blocks. A capital contribution in GeoPark Colombia S.A.
include Queiroz Galvao Exploração e Produção (45% working interest) and
for an amount of US$14,920,000 was made in 2013. In addition, as part
Brasoil Manati Exploração Petrolífera S.A. (10% working interest).
of the transaction, US$5,000,000 was transferred directly to the Colombian
subsidiary as a loan.
GeoPark has agreed to pay a cash consideration of US$140 million at closing,
which will be adjusted for working capital with an effective date of
In addition, in March 2013 GeoPark and LGI announced their agreement
April 30, 2013. The agreement also provides for possible future contingent
to extend their strategic alliance to build a portfolio of upstream oil and gas
payments by GeoPark over the next five years, depending on the economic
assets throughout Latin America through 2015.
performance and cash generation of the Block. On 26 March 2014 the
Further, on 8 January 2014, following an internal corporate reorganization
consented with the transaction. The closing of the acquisition occurred on
Brazilian National Petroleum, Natural Gas and Biofuels Agency ("ANP")
of our Colombian operations, GeoPark Colombia Coöperatie U.A. and GeoPark
March 31, 2014.
Latin America entered into a new members’ agreement with LGI, or the LGI
Colombia Members’ Agreement, that sets out substantially similar rights and
The Company afforded the acquisition from existing cash resources as of
obligations to the LGI Colombia Shareholders’ Agreement in respect of our
31 December 2013 (see Note 3) and through its Brazilian subsidiary's entrance
oil and gas business in Colombia.
Entry in Brazil
Acquisition in Brazil
into a loan pre-approved on February 2014 by Itaú BBA International for
US$70.5 million. The interest rate applicable to this loan will be LIBOR plus
3.9% per annum. The interests will be paid semi-annually; principal will
be cancelled semi-annually with one year grace period. The facility agreement
includes customary events of default, and subject our Brazilian subsidiary
GeoPark entered into Brazil with the acquisition of a ten percent working
to customary covenants, including the requirement that it maintain a ratio
interest in the offshore Manati gas field ("Manati Field"), the largest natural
of net debt to EBITDA of up to 3.5x the first two years and up to 3.0x
gas producing field in Brazil. On May 14, 2013, GeoPark executed a stock
thereafter. The credit facility also limits the borrower’s ability to pay dividends
purchase agreement ("SPA") with Panoro Energy do Brazil Ltda., the subsidiary
if the ratio of net debt to EBITDA is greater than 2.5x. The facility can be
of Panoro Energy ASA, ("Panoro"), a Norwegian listed company with assets
prepaid in whole or in part, at any time, subject to a pre-payment fee to
in Brazil and Africa, to acquire all of the issued and outstanding shares of its
be determined under the contract.
wholly-owned Brazilian subsidiary, Rio das Contas Produtora de Petróleo Ltda
GeoPark 20F 217
The Manati Field acquisition provides GeoPark with:
According to the terms of the Court’s injunction, the ANP will first need to
take certain actions, such as conducting studies that prove that drilling
- A solid foundational platform in Brazil to support future growth and
unconventional resources will not contaminate the dams and aquifers in the
expansion in Brazil - one of the world's most attractive hydrocarbon regions.
region. On February 21, 2014, GeoPark Brazil requested that the board of
- Participation in an economically-attractive and strategic asset representing
the ANP suspend the execution of the concession agreement (which entails
the largest non-associated gas producing field in Brazil, with a gross
delivery of the financial guarantee and performance guarantee and
production of over 200 million cubic feet per day of gas and a secure
payment of the signing bonus) for six months with a possible extension of
attractively-priced long term off take contract that covers 75% of proven
an additional six months, or until a firm court decision is reached that does
reserves (100% of proven developed reserves).
not prevent GeoPark Brazil from entering into the concession agreement.
- A low-risk and fully-developed producing gas field with no significant
On April 16, 2014, the ANP’s Board enacted a resolution stating that
drilling or capital expenditure investments expected.
all proceedings related to the award of the concession of Block PN-T-597
- A valuable partnership with Petrobras, the largest operator in Brazil.
to GeoPark Brazil were suspended.
- An established geoscience and administrative team to manage the assets -
and seek new growth opportunities.
New operations in Brazil
On 14 May 2013, the Company has been awarded seven new licenses in the
Note 35
Agreement with Methanex
Brazilian Round 11 of which two are in the Reconcavo Basin in the State
In March 2012, the Company and Methanex signed a third addendum and
of Bahia and five are in the Potiguar Basin in the State of Rio Grande do Norte.
amendment to the Gas Supply Agreement to incentivise the development
of gas reserves. Through this new agreement, the Company completed
The licensing round was organized by the ANP and all proceedings and
the drilling of five new gas wells during 2012. Methanex contributed to the
bids have been made public. On 17 September 2013, the winning bids were
cost of drilling the wells in order to improve the project economics. The
approved by the ANP.
Company fulfilled all the commitments under this agreement.
For its winning bids on the seven blocks, GeoPark has committed to invest
The Agreement also includes monthly commitments for delivering certain
a minimum of US$15.3 million (including bonus and work program
volumes of gas and in case of failure; the Company could satisfy the
commitment) during the first 3 years of the exploratory period. The new
obligation from future deliveries without penalty during a period of three
blocks cover an area of approximately 54,850 acres.
months. As of 31 December 2012, the accrued penalty for under delivered
volumes amount to US$1.7 million which was recorded in Provisions
On November 28, 2013, the ANP awarded GeoPark with two new concessions
for other liabilities in the Statement of Financial Position.
in a new international bidding round, Round 12, in the following basins:
• Parnaíba Basin in the State of Maranhão: PN-T-597 Concession; and
On August 30, 2013, the Company signed a fourth amendment to the
Methanex Gas Supply Agreement, pursuant to which Methanex has
• Sergipe Alagoas Basin in the State of Alagoas: SEAL-T-268 Concession.
committed, for a period of six months commencing September 15, 2013,
to purchase an increased volume, in a total amount of 400,000 SCM/d per
In Brazil, GeoPark Brasil Exploração e Produção de Petróleo (“GeoPark Brazil”)
month (subject to reduction for deliveries above 200,000 SCM/d to Methanex
is currently a party to a legal proceeding related to the concession agreement
or ENAP made between April 29 and September 15, 2013), at an additional
of Block PN-T-597 that the ANP initially awarded to GeoPark Brazil in the 12th
price per month of US$1.50 per mmbtu for volumes in excess of 180,000
oil and gas bidding round. As a result of a class action filed by the Federal
SCM/d, or an additional price per month of US$2.00 per mmbtu in any month
Prosecutor’s Office, an injunction was issued by a Brazilian Federal Court
in which we commit to deliver at least 500,000 SCM/d (subject to certain
against the ANP, the Federal Government and GeoPark Brazil on December
exceptions based on methanol prices). The amendment also provides for
13, 2013. Due to the injunction GeoPark Brazil could not proceed to execute
temporary DOP and TOP thresholds of 100% and 50%, respectively. As of 31
the concession agreement, and cannot do so until the injunction is lifted.
December 2013, the Company has fulfilled the delivery volume commitment.
218 GeoPark 20F
Note 36
Note 37
Drilling operations start-up in Tierra del Fuego
Strategic alliance with Tecpetrol in Brazil
In April 2013, the Company has started the exploration drilling in Tierra del
On 30 September 2013, the Company and Tecpetrol S.A. ("Tecpetrol")
Fuego in Chile in its partnership with Empresa Nacional de Petroleo de Chile
announced the formation of a new strategic alliance to jointly identify, study
("ENAP") with the spudding of the Chercán 1 well on the Flamenco Block.
and potentially acquire upstream oil and gas opportunities in Brazil, with a
Chercán 1 is the first of 21 exploratory wells on the Flamenco, Campanario
specific focus on the Parnaiba, Sao Francisco, Reconcavo, Potiguar and
and Isla Norte Blocks in Tierra del Fuego as part of an estimated US$100
Sergipe- Alagoas basins.
million investment commitment during the First Exploration Period.
As of March 2014, 8 wells have been drilled and 1,500 sq km of 3D seismic
oilfield and steel conglomerate) with an extensive track-record as an
have been carried out over the three blocks; which represent the total 3D
oil and gas explorer and operator with its portfolio of assets currently
Tecpetrol is the oil and gas subsidiary of the Techint Group (a multinational
seismic program commitment.
in Argentina, Peru, Colombia, Ecuador, Mexico, Bolivia, Venezuela and the
United States, and with a current net production of over 85,000 barrels
of oil equivalent per day.
At 31 December 2013, there is no accounting impact of the creation of
the alliance.
GeoPark 20F 219
Note 38
Supplemental information on oil and gas activities (unaudited)
Table 1 - Costs incurred in exploration, property acquisitions and
development(1)
The following table presents those costs capitalized as well as expensed that
The following information is presented in accordance with ASC No. 932
were incurred during each of the years ended as of 31 December 2013,
“Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and
2012 and 2011. The acquisition of properties includes the cost of acquisition
Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010
of proved or unproved oil and gas properties. Exploration costs include
in order to align the current estimation and disclosure requirements with the
geological and geophysical costs, costs necessary for retaining undeveloped
requirements set in the SEC final rules and interpretations, published on
properties, drilling costs and exploratory well equipment. Development
December 31, 2008. This information includes the Company’s oil and gas
costs include drilling costs and equipment for developmental wells,
production activities carried out in Chile, Colombia and Argentina.
the construction of facilities for extraction, treatment and storage of
hydrocarbons and all necessary costs to maintain facilities for the existing
developed reserves.
Amounts in US$ ’000
Year ended 31 December 2013
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development
Total costs incurred
Amounts in US$ ’000
Year ended 31 December 2012
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development
Total costs incurred
Amounts in US$ ’000
Year ended 31 December 2011
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development
Total costs incurred
Chile
Colombia
Argentina
Brazil
Total
—
—
—
91,140
61,748
152,888
—
—
—
47,668
37,983
85,651
—
—
—
(1,917)
124
(1,793)
—
—
—
1,702
—
1,702
—
—
—
138,593
99,855
238,448
Chile
Colombia
Argentina
Total
—
—
—
58,301
89,669
147,970
82,766
27,818
110,584
28,999
27,479
167,062
—
—
—
(1,602)
499
(1,103)
82,766
27,818
110,584
85,698
117,647
313,929
Chile
Colombia
Argentina
Total
—
—
—
38,601
60,002
98,603
—
—
—
—
—
—
—
—
—
3,671
147
3,818
—
—
—
42,272
60,149
102,421
(1) Includes capitalized amounts related to asset retirement obligations.
220 GeoPark 20F
Table 2 - Capitalized costs related to oil and gas producing activities
The following table presents the capitalized costs as at 31 December 2013,
2012 and 2011, for proved and unproved oil and gas properties, and the
related accumulated depreciation as of those dates.
Amounts in US$ ’000
At 31 December 2013
Proved properties
- Equipment, camps and other facilities
- Mineral interest and wells(1)
- Other uncompleted projects
Unproved properties
Gross capitalised costs
Accumulated depreciation(1)
Total net capitalised costs
Chile
Colombia
Argentina
Brazil
Total
77,481
310,364
33,176
109,862
530,883
(127,447)
403,436
20,514
178,048
7,053
37,853
243,468
(60,150)
183,318
843
4,849
—
31
5,723
(5,470)
253
—
—
—
13
13
—
13
98,838
493,261
40,229
147,759
780,087
(193,067)
587,020
(1) Includes capitalized amounts related to asset retirement obligations.
Amounts in US$ ’000
At 31 December 2012
Proved properties
- Equipment, camps and other facilities
- Mineral interest and wells(1)
- Other uncompleted projects
Unproved properties
Gross capitalised costs
Accumulated depreciation(1)
Total net capitalised costs
(1) Includes capitalized amounts related to asset retirement obligations.
Amounts in US$ ’000
At 31 December 2011
Proved properties
- Equipment, camps and other facilities
- Mineral interest and wells(1)
- Other uncompleted projects
Unproved properties
Gross capitalised costs
Accumulated depreciation(1)
Total net capitalised costs
(1) Includes capitalized amounts related to asset retirement obligations.
Chile
Colombia
Argentina
Total
69,755
236,499
44,806
59,924
410,984
(98,161)
312,823
16,351
103,023
8,520
33,151
161,045
(20,917)
140,128
843
4,849
—
31
5,723
(5,414)
309
86,949
344,371
53,326
93,106
577,752
(124,492)
453,260
Chile
Colombia
Argentina
Total
46,259
166,679
32,697
37,755
283,390
(67,559)
215,831
—
—
—
—
—
—
—
843
5,277
199
4,385
10,704
(4,673)
6,031
47,102
171,956
32,896
42,140
294,094
(72,232)
221,862
GeoPark 20F 221
Table 3 - Results of operations for oil and gas producing activities
The breakdown of results of the operations shown below summarizes
revenues and expenses directly associated with oil and gas producing
activities for the years ended 31 December 2013, 2012 and 2011. Income
tax for the years presented was calculated utilizing the statutory tax rates.
Chile
Colombia
Argentina
Brazil
Total
157,491
179,324
(30,915)
(7,383)
(38,298)
(13,138)
(429)
(29,287)
76,339
(11,451)
64,888
(62,818)
(9,661)
(72,479)
(3,341)
(880)
(39,233)
63,391
(20,919)
42,472
1,538
(92)
(195)
(287)
1,928
(214)
(59)
2,906
(1,017)
1,889
—
—
—
—
(1,702)
—
—
(1,702)
579
(1,123)
338,353
(93,825)
(17,239)
(111,064)
(16,253)
(1,523)
(68,579)
140,934
(32,808)
108,126
Chile
Colombia
Argentina
Total
149,927
99,501
1,050
250,478
(30,586)
(7,088)
(37,674)
(22,080)
(265)
(28,120)
61,788
(9,268)
52,520
(35,069)
(4,164)
(39,233)
(5,528)
(803)
(20,964)
32,973
(10,881)
22,092
151
(172)
(21)
(282)
(194)
(3,223)
(2,670)
935
(1,735)
(65,504)
(11,424)
(76,928)
(27,890)
(1,262)
(52,307)
92,091
(19,214)
72,877
Amounts in US$ ’000
Year ended 31 December 2013
Net revenue
Production costs
Operating costs
Royalties and other
Total production costs
Exploration expenses
Accretion expense(1)
Depreciation, depletion and amortization
Results of operations before income tax
Income tax
Results of oil and gas operations
Amounts in US$ ’000
Year ended 31 December 2012
Net revenue
Production costs
Operating costs
Royalties and other
Total production costs
Exploration expenses
Accretion expense(1)
Depreciation, depletion and amortization
Results of operations before income tax
Income tax
Results of oil and gas operations
222 GeoPark 20F
Amounts in US$ ’000
Year ended 31 December 2011
Net revenue
Production costs
Operating costs
Royalties and other
Total production costs
Exploration expenses
Accretion expense(1)
Depreciation, depletion and amortization
Results of operations before income tax
Income tax
Results of oil and gas operations
(1) Represents accretion of ARO liability.
Chile
Colombia
Argentina
Total
110,103
(23,623)
(4,634)
(28,257)
(8,487)
(178)
(24,958)
48,223
(7,233)
40,990
—
—
—
—
—
—
—
—
—
—
1,477
111,580
(203)
(209)
(412)
(1,579)
(172)
(886)
(1,572)
550
(1,022)
(23,826)
(4,843)
(28,669)
(10,066)
(350)
(25,844)
46,651
(6,683)
39,968
Table 4 - Reserve quantity information
The Company estimates its reserves at least once a year. The Company’s
Estimated oil and gas reserves
Proved reserves represent estimated quantities of oil (including crude oil and
DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”).
DeGolyer and MacNaughton prepared its proved oil and natural gas reserve
condensate) and natural gas, which available geological and engineering
estimates in accordance with Rule 4-10 of Regulation S–X, promulgated by
data demonstrates with reasonable certainty to be recoverable in the future
the SEC, and in accordance with the oil and gas reserves disclosure provisions
from known reservoirs under existing economic and operating conditions.
of ASC 932 of the FASB Accounting Standards Codification (ASC) relating to
Proved developed reserves are proved reserves that can reasonably be
Extractive Activities—Oil and Gas (formerly SFAS no. 69 Disclosures about
reserves estimation as of 31 December 2013, 2012 and 2011 was based on the
expected to be recovered through existing wells with existing equipment
Oil and Gas Producing Activities).
and operating methods. The choice of method or combination of methods
employed in the analysis of each reservoir was determined by the stage
Reserves engineering is a subjective process of estimation of hydrocarbon
of development, quality and reliability of basic data, and production history.
accumulation, which cannot be accurately measured, and the reserve
The Company believes that its estimates of remaining proved recoverable
estimation depends on the quality of available information and the
interpretation and judgment of the engineers and geologists. Therefore,
oil and gas reserve volumes are reasonable and such estimates have been
the reserves estimations, as well as future production profiles, are often
prepared in accordance with the SEC Modernization of Oil and Gas Reporting
different than the quantities of hydrocarbons which are finally recovered.
rules, which were issued by the SEC at the end of 2008.
The accuracy of such estimations depends, in general, on the
assumptions on which they are based.
GeoPark 20F 223
The estimated GeoPark net proved reserves for the properties evaluated
as of 31 December 2013, 2012 and 2011 are summarized as follows, expressed
in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
Net proved developed
Chile(1)
Colombia(2)
Argentina
Total consolidated
Net proved undeveloped
Chile(1)
Colombia(3)
Argentina
Total consolidated
Total proved reserves
As of 31 December 2013
As of 31 December 2012
As of 31 December 2011
Oil and
Oil and
Oil and
condensate
Natural gas
condensate
Natural gas
condensate
Natural gas
(Mbbl)
(MMcf)
(Mbbl)
(MMcf)
(Mbbl)
(MMcf)
2,236.6
3,250.9
—
5,487.5
3,138.4
6,175.7
—
9,314.1
14,801.6
10,037.0
—
—
10,037.0
22,122.0
—
—
22,122.0
32,159.0
2,104.8
2,008.6
—
4,113.4
3,153.3
4,618.4
—
7,771.7
11,885.1
12,768.0
—
—
12,768.0
2,133.2
—
—
2,133.2
24,476.0
—
—
24,476.0
16,813.0
3,120.9
32,681.0
—
—
16,813.0
29,581.0
—
—
3,120.9
5,254.1
—
—
32,681.0
57,157.0
(1) Fell Block accounts for 100% of the reserves (LGI owns a 20% interest).
(2) Llanos 34 Block and Cuerva Block account for 58% and 36% (31%
and 53% in 2012) of the proved developed reserves, respectively (LGI owns
a 20% interest).
(3) Llanos 34 Block and Cuerva Block account for 74% and 23% (72% and
25% in 2012) of the proved undeveloped reserves, respectively (LGI owns a
20% interest).
224 GeoPark 20F
Chile
5,349.9
(1,253.8)
2,022.0
(864.0)
5,254.1
(1,250.8)
2,670.0
—
(1,415.2)
5,258.1
271.1
1,431.0
(1,585.2)
5,375.0
Colombia
Argentina
—
—
—
—
—
—
—
7,522.8
(895.8)
6,627.0
(277.0)
5,210.0
(2,133.4)
9,426.6
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Total
5,349.9
(1,253.8)
2,022.0
(864.0)
5,254.1
(1,250.8)
2,670.0
7,522.8
(2,311.0)
11,885.1
(5.9)
6,641.0
(3,718.6)
14,801.6
Table 5 - Net proved reserves of oil, condensate and natural gas
Net proved reserves (developed and undeveloped) of oil and condensate:
Thousands of barrels
Reserves as of 31 December 2010(1)
Increase (decrease) attributable to:
Revisions(2)
Extensions and discoveries
Production
Reserves as of 31 December 2011
Increase (decrease) attributable to:
Revisions(3)
Extensions and discoveries
Purchases of minerals in place
Production
Reserves as of 31 December 2012
Increase (decrease) attributable to:
Revisions
Extensions and discoveries(4)
Production
Reserves as of 31 December 2013
(1) Includes 1,377 of developed reserves.
(2) The revisions are primarily due to the following adjustments in the
Fell Block:
• Monte Aymond Field – Proved undeveloped oil reserves: Reduced
expected recovery based on offset performance (approximately -600 mbo);
and,
• Other miscellaneous revisions, including the reduced condensate
related to the gas field reserves reductions.
(3) The revisions are primarily related to condensate from the reduced gas
and two fields in the Fell Block (Copihue and Guanaco) where there were
reductions in proved recovery based on performance.
(4) Primarily due to 2013 discoveries in Llanos 34 (Taro Taro, Tigana and
Tigana Sur) and Yamú (Potrillo).
GeoPark 20F 225
Net proved reserves (developed and undeveloped) of natural gas:
Millions of cubic feet
Reserves as of 31 December 2010(1)
Increase (decrease) attributable to:
Revisions(2)
Extensions and discoveries
Production
Reserves as of 31 December 2011
Increase (decrease) attributable to:
Revisions(3)
Extensions and discoveries
Purchases
Production
Reserves as of 31 December 2012
Increase (decrease) attributable to:
Revisions(4)
Extensions and discoveries
Production
Reserves as of 31 December 2013
Chile
76,974.0
(15,817.0)
5,690.0
(9,690.0)
57,157.0
(21,860.0)
2,256.0
—
(7,972.0)
29,581.0
4,691.0
2,219.0
(4,332.0)
32,159.0
Colombia
Argentina
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Total
76,974.0
(15,817.0)
5,690.0
(9,690.0)
57,157.0
(21,860.0)
2,256.0
(7,972.0)
29,581.0
4,691.0
2,219.0
(4,332.0)
32,159.0
(1) Includes 30,691 of developed reserves.
(3) The revisions are primarily due to the effect of having reduced the
(2) The revisions are primarily due to the following adjustments in the
Company’s future gas production profile in Chile because of expected
Fell Block:
reduced deliveries to the Methanex plant. This causes a significant portion
• Dicky Field – Proved developed gas reserves: Reduced proved developed
of the gas reserves to be produced below an economic level later in the
reserves based on performance (approximately -2100 mmcf);
productive life of the Fell Block and after the expiration of the Methanex
• Dicky Oeste Field – Proved undeveloped gas reserves: Reduced expected
Gas Supplies Agreement.
recovery based on offset performance (approximately -3750 mmcf);
(4) The revisions are primarily due to adjustments in the Fell Block as a
• Ovejero Field – Proved developed gas reserves: Producing well shut-in -
response to a workover in Monte Aymond field, and associated gas from
Moved reserves to probable (approximately -1000 mmcf);
drilling campaigns in Konawentru and Yagán Norte fields.
• Pampa Field – Proved undeveloped gas reserves: Reduced recovery based
on offset performance (approximately -5500 mmcf);
• Santiago Norte Field – Proved undeveloped gas reserves: Reduced recovery
Revisions refer to changes in interpretation of discovered accumulations and
some technical / logistical needs in the area obliged to modify the timing and
based on offset performance (approximately -3000 mmcf); and
development plan of certain fields under appraisal and development phases.
• Other miscellaneous revisions.
226 GeoPark 20F
Table 6 - Standardized measure of discounted future net cash flows related to
This standardized measure is not intended to be and should not be
proved oil and gas reserves
interpreted as an estimate of the market value of the Company’s reserves.
The following table discloses estimated future net cash flows from future
The purpose of this information is to give standardized data to help the
production of proved developed and undeveloped reserves of crude oil,
users of the financial statements to compare different companies and make
condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas
certain projections. It is important to point out that this information does
Reporting rules and ASC 932 of the FASB Accounting Standards Codification
not include, among other items, the effect of future changes in prices, costs
(ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69
and tax rates, which past experience indicates that are likely to occur, as
Disclosures about Oil and Gas Producing Activities), such future net cash flows
well as the effect of future cash flows from reserves which have not yet
were estimated using the average first day- of-the-month price during
been classified as proved reserves, of a discount factor more representative
the 12-month period for 2013, 2012 and 2011 and using a 10% annual discount
of the value of money over the lapse of time and of the risks inherent to
factor. Future development and abandonment costs include estimated drilling
the production of oil and gas. These future changes may have a significant
costs, development and exploitation installations and abandonment costs.
impact on the future net cash flows disclosed below. For all these reasons,
These future development costs were estimated based on evaluations
this information does not necessarily indicate the perception the Company
made by the Company. The future income tax was calculated by applying
has on the discounted future net cash flows derived from the reserves of
the statutory tax rates in effect in the respective countries in which we have
hydrocarbons.
interests, as of the date this supplementary information was filed.
Amounts in US$ ’000
At 31 December 2013
Future cash inflows
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows
At 31 December 2012
Future cash inflows
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows
At 31 December 2011
Future cash inflows
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows
Chile
Colombia
Argentina
Total
610,106
(164,820)
(215,426)
(38,599)
191,261
(27,401)
163,860
568,647
(135,525)
(149,100)
(44,218)
239,804
(37,355)
202,449
681,269
(130,786)
(112,014)
(76,544)
361,925
(76,332)
285,603
686,227
(274,246)
(82,964)
(118,104)
210,913
(37,121)
173,792
491,578
(181,780)
(45,966)
(98,773)
165,059
(31,414)
133,645
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,296,333
(439,066)
(298,390)
(156,703)
402,174
(64,522)
337,652
1,060,225
(317,305)
(195,066)
(142,991)
404,863
(68,769)
336,094
681,269
(130,786)
(112,014)
(76,544)
361,925
(76,332)
285,603
GeoPark 20F 227
Chile
226,784
(83,199)
145,391
(39,039)
87,266
56,566
(114,297)
(20,058)
28,085
(1,896)
285,603
(110,331)
45,100
(73,255)
108,768
57,055
(174,757)
—
23,250
36,215
4,801
202,449
(128,993)
(4,925)
(118,760)
63,948
83,983
37,389
4,102
24,667
163,860
Colombia
Argentina
—
—
—
—
—
—
—
—
—
—
—
(10,015)
—
—
—
—
—
143,660
—
—
—
133,645
(144,087)
4,754
(42,667)
186,738
39,922
(9,928)
(17,827)
23,242
173,792
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Total
226,784
(83,199)
145,391
(39,039)
87,266
56,566
(114,297)
(20,058)
28,085
(1,896)
285,603
(120,346)
45,100
(73,255)
108,768
57,055
(174,757)
143,660
23,250
36,215
4,801
336,094
(273,080)
(171)
(161,427)
250,686
123,905
27,461
(13,725)
47,909
337,652
Table 7 - Changes in the standardized measure of discounted future net cash
flows from proved reserves
Amounts in US$ ’000
Present value at 31 December 2010
Sales of hydrocarbon, net of production costs
Net changes in sales price and production costs
Changes in estimated future development costs
Extensions and discoveries less related costs
Development costs incurred
Revisions of previous quantity estimates
Net changes in income taxes
Accretion of discount
Other changes
Present value at 31 December 2011
Sales of hydrocarbon , net of production costs
Net changes in sales price and production costs
Changes in estimated future development costs
Extensions and discoveries less related costs
Development costs incurred
Revisions of previous quantity estimates
Purchase of minerals in place
Net changes in income taxes
Accretion of discount
Other changes
Present value at 31 December 2012
Sales of hydrocarbon , net of production costs
Net changes in sales price and production costs
Changes in estimated future development costs
Extensions and discoveries less related costs
Development costs incurred
Revisions of previous quantity estimates
Net changes in income taxes
Accretion of discount
Present value at 31 December 2013
228 GeoPark 20F
Exhibit 12.1
Exhibit 12.2
CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER
CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, James F. Park, certify that:
I, Andrés Ocampo, certify that:
1. I have reviewed this annual report on Form 20-F of GeoPark Limited;
1. I have reviewed this annual report on Form 20-F of GeoPark Limited;
2. Based on my knowledge, this report does not contain any untrue statement
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the company
financial condition, results of operations and cash flows of the company
as of, and for, the periods presented in this report;
as of, and for, the periods presented in this report;
4. The company’s other certifying officer(s) and I are responsible for
4. The company’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the company and have:
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the company and have:
a. Designed such disclosure controls and procedures, or caused such
a. Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision,
disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the company, including its
to ensure that material information relating to the company, including its
consolidated subsidiaries, is made known to us by others within those
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
entities, particularly during the period in which this report is being prepared;
b. [Reserved]
b. [Reserved]
c. Evaluated the effectiveness of the company’s disclosure controls and
c. Evaluated the effectiveness of the company’s disclosure controls and
procedures and presented in this report our conclusions about the
procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of
effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and
the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the company’s internal control over
d. Disclosed in this report any change in the company’s internal control over
financial reporting that occurred during the period covered by the annual
financial reporting that occurred during the period covered by the annual
report that has materially affected, or is reasonably likely to materially affect,
report that has materially affected, or is reasonably likely to materially affect,
the company’s internal control over financial reporting; and
the company’s internal control over financial reporting; and
5. The company’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
5. The company’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the company’s auditors and the audit committee of the company’s board
to the company’s auditors and the audit committee of the company’s board
of directors (or persons performing the equivalent functions):
of directors (or persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or
a. All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
operation of internal control over financial reporting which are reasonably
likely to adversely affect the company’s ability to record, process,
likely to adversely affect the company’s ability to record, process,
summarize and report financial information; and
summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other
b. Any fraud, whether or not material, that involves management or other
employees who have a significant role in the company’s internal control
employees who have a significant role in the company’s internal control
over financial reporting.
over financial reporting.
Date: April 30, 2014
/s/ James F. Park
James F. Park
Chief Executive Officer
(Principal Executive Officer)
Date: April 30, 2014
/s/Andrés Ocampo
Andrés Ocampo
Chief Financial Officer
(Principal Financial Officer)
GeoPark 20F 229
Exhibit 13.1
Exhibit 13.2
CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER
CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
The certification set forth below is being submitted in connection with the
The certification set forth below is being submitted in connection with the
Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the
Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the
fiscal year ended December 31, 2013 (the “Report”), I, James F. Park, certify
fiscal year ended December 31, 2013 (the “Report”), I, Andrés Ocampo, certify
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:
the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:
1. the Report fully complies with the requirements of Section 13(a) or 15(d)
1. the Report fully complies with the requirements of Section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
of the Securities Exchange Act of 1934; and
2. the information contained in the Report fairly presents, in all material
2. the information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the Company.
respects, the financial condition and results of operations of the Company.
Date: April 30, 2014
/s/ James F. Park
James F. Park
Chief Executive Officer
(Principal Executive Officer)
Date: April 30, 2014
/s/ Andrés Ocampo
Andrés Ocampo
Chief Financial Officer
(Principal Financial Officer)
230 GeoPark 20F
GeoPark 20F 231
Peter Ryalls | Non-Executive Director
Mr. ryalls has been a member of our board of directors since april 2006.
He holds a master’s degree in petroleum engineering from imperial
college in london. Mr. ryalls has worked for schlumberger limited in
angola, Gabon and nigeria, as well as for Mobil north sea. He has also
worked for unocal corporation where he held increasingly senior
positions, including as Managing director in aberdeen, scotland, and
where he developed extensive experience in offshore production and
drilling operations. in 1994, Mr. ryalls represented unocal corporation in
the azerbaijan international operating company as Vice president of
operations and was responsible for production, drilling, reservoir
engineering and logistics. in 1998, Mr. ryalls became General Manager
for unocal in argentina. He also served as Vice president of unocal’s Gulf
of Mexico onshore oil and gas business and as Vice president of Global
Engineering and construction, where he was responsible for the
implementation of all major capital projects ranging from deep water
developments in indonesia and the Gulf of Mexico to conventional oil
and gas projects in thailand. Mr. ryalls is also an independent petroleum
consultant advising on international oil and gas development projects
both onshore and offshore.
Steven J. Quamme | Non-Executive Director
Mr. Quamme has been a member of our board of directors since June
2011. He has 25 years of experience as a fund manager, securities and
corporate lawyer, and investment banker. Mr. Quamme holds a B.a. in
economics from northwestern university and a J.d. from the
northwestern university school of law, where he is a member of the
law school Board. Mr. Quamme is a member of the board of directors of
cartica Management, llc, as well as the board of trustees of the
potomac school and of the sibley Memorial Hospital Foundation. He has
previously served as a member of the boards of directors of Equivest
Finance, Milestone Merchant partners, llc, Kerrco inc., atlantic
Entertainment Group, rausch industries, rompetrol, and Einstein noah
Bagel corp, lp. From 2005 to 2007, Mr. Quamme served as the chief
operating officer of Breeden partners, a corporate governance fund.
From 2002 to 2007, Mr. Quamme also served as senior Managing
director of richard c. Breeden & co., a professional services firm, which
focuses on corporate governance and crisis management. in 2000,
Mr. Quamme founded Milestone Merchant partners, a merchant bank
based in Washington d.c., where he served as its cEo until 2005.
Mr. Quamme is presently a co-founder and senior Managing director
of cartica Management, a registered investment advisor focused on
emerging markets and a Geopark shareholder.
James F. Park | Chief Executive Officer and Deputy Chairman
Mr. park has served as our chief Executive officer and as a member of
our board of directors since co-founding the company in 2002. He has
extensive experience in all phases of the upstream oil and gas business,
with a strong background in the acquisition, implementation and
management of international joint ventures in north america, south
america, asia, Europe and the Middle East. He holds a degree in
geophysics from the university of california at Berkeley and has worked
as a research scientist in earthquake and tectonic studies. in 1978,
Mr. park joined Basic resources international limited, an oil and gas
exploration company, which pioneered the development of commercial
oil and gas production in central america. as a senior executive of
Basic resources international limited, Mr. park was closely involved in
the development of grass-roots exploration activities, drilling and
production operations, surface and pipeline construction and crude oil
marketing and transportation, legal and regulatory issues, and raising
substantial investment funds. He remained a member of the board of
directors of Basic resources international limited until the company was
sold in 1997. Mr. park is also a member of the board of directors of
Energy Holdings. Mr. park has also been involved in oil and gas projects
in california, louisiana, argentina, Yemen and china. Mr. park has
lived in argentina and chile since 2002.
Board of directors
Gerald E. O’Shaughnessy | Chairman
Mr. o’shaughnessy has been our chairman and a member of our board
of directors since he co-founded the company in 2002. Following his
graduation from the university of notre dame with degrees in
government (1970) and law (1973), Mr. o’shaughnessy was engaged
in the practice of law in Minnesota. Mr. o’shaughnessy has been active
in the oil and gas business over his business career, starting in 1976 with
lario oil and Gas company, where he served as senior Vice president
and General counsel. He later formed the Globe resources Group, a
private venture firm whose subsidiaries provided seismic acquisition
and processing, well rehabilitation services, sophisticated logistical
operations and submersible pump works for lukoil in russia during the
1990s. in 2010 Mr. o’shaughnessy founded lario logistics, a u.s.
midstream company which owns and operates the Bakken oil Express,
serving oil producers and service providers in the Bakken oil play. in
addition to his oil and gas activities Mr. o’shaughnessy is also engaged
in investments in banking, wealth management, desktop software,
computer and network security, and green clean technology. over the
past 25 years, Mr. o’shaughnessy has also served on a number of
non-profit boards of directors, including the Board of Economic advisors
to the Governor of Kansas, the i.a. o’shaughnessy Family Foundation,
the Wichita collegiate school, the institute for Humane studies, the
East West institute and the Bill of rights institute. Mr. o’shaughnessy is
a member of the intercontinental chapter of Young presidents
organization and World presidents’ organization.
Pedro Aylwin | Executive Director
Mr. aylwin has served as a member of our board of directors since July
2013 and as our director of legal and Governance since april 2011.
From 2003 to 2006, Mr. aylwin worked for Geopark as an advisor on
governance and legal matters. Mr. aylwin holds a degree in law from
the universidad de chile and an llM from the university of notre dame.
Mr. aylwin has extensive experience in the natural resources sector.
Mr. aylwin is also a partner at the law firm of aylwin abogados in
santiago, chile, where he represented mining, chemical and oil and gas
companies in numerous transactions. From 2006 until 2011, he served
as lead Manager and General counsel at BHp Billiton, Base Metals,
where he was in charge of legal and corporate governance matters on
BHp Billiton’s projects, operations and natural resource assets in
south america, north america, asia, africa and australia. Mr. aylwin is
also a member of the board of directors of Egeda España.
Carlos Gulisano | Non-Executive Director
Mr. Gulisano has been a member of our board of directors since June
2010. dr. Gulisano holds a bachelor’s degree in geology, a post-graduate
degree in petroleum engineering and a phd in geology from the
university of Buenos aires and has authored or co-authored over 40
technical papers. He is a former adjunct professor at the universidad del
sur, a former thesis director at the university of la plata, and a former
scholarship director at conicEt, the national technology research
council, in argentina. dr. Gulisano is a respected leader in the fields of
petroleum geology and geophysics in south america and has over
30 years of successful exploration, development and management
experience in the oil and gas industry. in addition to serving as an
advisor to Geopark since 2002 and as Managing director from February
2008 until June 2010, dr. Gulisano has worked for YpF, petrolera
argentina san Jorge s.a. and chevron san Jorge s.a. and has led teams
credited with significant oil and gas discoveries, including those in the
trapial field in argentina. He has worked in argentina, Bolivia,
peru, Ecuador, colombia, Venezuela, Brazil, chile and the united states.
Mr. Gulisano is also an independent consultant on oil and gas
exploration and production.
Juan Cristóbal Pavez | Non-Executive Director
Mr. pavez has been a member of our board of directors since august
2008. He holds a degree in commercial engineering from the pontifical
catholic university of chile and a MBa from the Massachusetts institute
of technology. He has worked as a research analyst at Grupo cB and
later as a portfolio analyst at Moneda asset Management. in 1998, he
joined santana, an investment company, as chief Executive officer. at
santana he focused mainly on investments in capital markets and real
estate. While at santana, he was appointed chief Executive officer of
laboratorios andrómaco, one of santana’s main assets. in 1999,
Mr. pavez cofounded Eventures, an internet company. since 2001, he
has served as chief Executive officer at centinela, a company with a
diversified global portfolio of investments, with a special focus in the
energy industry, through the development of wind parks and
run-of-the-river hydropower plants. Mr. pavez is also a board member
of Grupo security, Vida security and Hidroeléctrica totoral. over the
last few years he has been a board member of several companies,
including Quintec, Enaex, cti and Frimetal.
232 annual report 2013
directors, secretary & advisors
Directors
Registered Office
Corporate Offices
Director of legal and
Governance and
Corporate Secretary
Counsel to the Company
as to New York law
Solicitors to the Company
as to Bermuda law
Independent Auditors
Petroleum Consultant
Registrar
Gerald E. o’shaughnessy (chairman)
James F. park (chief Executive officer and deputy chairman)
peter ryalls (non-Executive director)
Juan cristóbal pavez (non-Executive director)
carlos Gulisano (non-Executive director)
steven J. Quamme (non-Executive director)
pedro aylwin (Executive director)
cumberland House 9th Floor,
1 Victoria street
Hamilton HM11 - Bermuda
Buenos Aires Office
Florida 981 - 1st Floor
c1005aas Buenos aires
argentina | + 54 11 4312 9400
Santiago Office
nuestra señora de los Ángeles 176
las condes, santiago
chile | + 56 2 242 9600
pedro aylwin chiorrini
davis polk & Wardwell llp
450 lexington avenue
new York, nY 10017
usa
cox Hallett Wilkinson
cumberland House 9th Floor,
1 Victoria street
Hamilton HM11 - Bermuda
p.o. Box HM 1561
Hamilton HMFX - Bermuda
price Waterhouse & co. s.r.l.
Bouchard 557, 8th Floor
Buenos aires
argentina
deGolyer and Macnaughton
5001 spring Valley road suite 800 East
dallas, texas 75244
usa
computershare investor services
480 Washington Blvd.
Jersey city, nJ 07310
usa
designed by:
chiappini + Becker
tel. +54 11 4314 7774
www.ch-b.com
photographer:
diego dicarlo, Geologist
annual rEport 2013
WWW.GEo-parK.coM