ANNUAL REPORT 2017
EXPLORER
OPERATOR
CONSOLIDATOR
CONTENTS
Bottom Line
Letter to Shareholders
1
4
16
Business Approach
& Guidelines
22
24
25
27
2017 Performance
Our Strengths
Our Platform
Our Approach
28
Our Value System
31
Form 20-F
156
Consolidated Financial
Statements
208
209
Board of Directors
Corporate Management Team,
Secretary & Advisors
BOTTOM LINE
Oil and Gas Production
25
20
15
10
5
0
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P
y
l
i
a
D
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g
a
r
e
v
A
2011
2012
2013
2014
2015
2016
2017
Oil and Gas Reserves
150
120
90
60
30
0
)
e
o
b
M
M
(
s
e
v
r
e
s
e
R
P
2
2011
2012
2013
2014
2015
2016
2017
Gas
Oil
Gas
Oil
Magallanes Region, Chile
“As an entrepreneurial and battle-tested
company that has grown from scratch
into one of Latin America’s leading
independents, we attribute our success to
a proud culture based on trust - and which
is the catalyst for our continuous record of
safe, clean, neighborly, transparent, and
successful operations”
GeoPark 3
LETTER TO SHAREHOLDERS
Dear Fellow Shareholders:
Más Cash / Capital Strength
We are pleased to report that our GeoPark team again outperformed
Differentiating us from most of our industry peers, GeoPark is a self-
in 2017 – making us a better, stronger, more capable, and more
funding growing cash-generating company - meaning our own cash
valuable Company than ever before.
flows are sufficient to pay for and expand our business. Cash flows
from operating activities were up 72% to $142 million and Adjusted
The international investment community began taking increased
EBITDA more than doubled to $176 million. We also successfully
notice of our enduring growth track record and GeoPark was the best
lowered borrowing costs and extended debt maturities by issuing
performing upstream oil and gas company on the New York Stock
a new bond for $425 million, at 6.5% due in 2024, and which was
Exchange in 2017 with a 130% share price increase.
substantially oversubscribed by top tier international investors. We
closed 2017 with $135 million in cash.
A continuous theme of GeoPark is ‘Vamos por Más’ (‘Let’s Go for
More’) and our 2017 performance delivered más (more) in all key
Más Value
fundamentals of our business:
With our new oil and gas discoveries in 2017 and increasingly-efficient
Más Oil and Gas
cost structure, the independently-certified net present value (NPV) of
GeoPark’s 2P oil and gas reserves increased by 21% to a value of $2.3
Success in our industry begins by being able to consistently find,
billion (despite using lower price decks compared to 2016). Last year
develop and produce oil and gas. Last year, GeoPark extended its
we invested $106 million and increased our NPV by $404 million. On
exceptional 15 year growth track record and increased production
a ‘per share’ basis and deducting outstanding net debt and minority
by 23% to a record 27,586 boepd with an exit production of 31,977
interests, our net debt adjusted 2P NPV per share increased by 24%
boepd. In Colombia, production grew by 39% to 21,787 boepd. After
to $29.2 per share (or $15.8 per share for Colombia alone). This means
producing over 10 million boe during the year, we replaced and grew
our market share price is still significantly below the underlying value
our certified oil and gas reserves with proven (1P) reserves increasing
of our oil and gas assets.
by 24% to 97 million boe and total proven and probable (2P) reserves
increasing by 11% to 159 million boe. In Colombia, 2P reserves
Más Acreage / Upside
increased by 31% from the continuing extension of the large Tigana
GeoPark has steadily and economically built an extensive land
and Jacana oil fields.
position across Latin America – with more than five million acres in
29 blocks in 9 proven hydrocarbon basins in 5 countries, consisting
Más Efficiencies / Lower Costs
of a risk-balanced mix of production, development, exploration and
Being the safest lowest-cost driller and producer of oil and gas are
unconventional resource projects. This large acreage platform is one
the critical factors in achieving long-term industry leadership and
of our most powerful assets – one that does not show up on a balance
economic success - with an even greater emphasis in today’s world
sheet – but which provides the foundation for long-term growth.
of oil price volatility. GeoPark’s operational strength has allowed us
On our acreage, GeoPark has identified new geological plays and
to relentlessly drive down capital and operating costs to achieve top-
prospects – that is, new potential oil and gas fields – with audited
performing metrics, with 2P finding and development costs of $4.0
exploration resources of 700 million to 1.3 billion boe.
per boe (consolidated) and $2.8 per boe (Colombia), and operating
costs of $7.3 per boe (consolidated) and $4.3 per bbl (Colombia Llanos
Más Opportunity
34). Our passion for cost efficiency has resulted in 90% of GeoPark’s
One of the pillars of GeoPark’s business plan is our success in
production being cash flow positive at oil prices of just $25-30 per
identifying and acquiring new high-quality projects on attractive
barrel.
terms. Our continuous efforts to uncover new business opportunities
over the last 10+ years in targeted hydrocarbon basins has built a
4 Annual Report 2017 / Letter to Shareholders
GeoPark 5
6 Annual Report 2017 / Letter to Shareholders
Jacana Field, Llanos 34 Block, Colombia
$2+ billion new project inventory in Colombia, Brazil, Argentina, Peru,
forward regardless of any short-term cycles or sentiment. We believe
Ecuador and Mexico – with an active focus on initiatives with Latin
our strength and unique position across the region today results from
American national oil companies. In early 2018, GeoPark entered into
this alignment and gives us even more advantages in achieving our
a new acquisition partnership with ONGC, the national oil company
ambitious goals.
of India, to support and join our efforts to expand our upstream
portfolio across Latin America.
Más Capabilities
People
As our history has proved, great people create great results. We are
Our big ambitions require us to prepare for our future by
pleased to recognize and thank the women and men who have built
continuously investing in our capacities and know-how and to
and are continuing to build GeoPark. They are our heart and engine,
become the best at every component of our business. Last year we
and have faced and met every challenge with a professionalism,
continued to invest in our technical, financial and management
creativity and agility that keeps propelling us forward.
excellence and strengthen our country business unit teams, including
new leadership in Peru and Argentina. This includes dynamically
As an entrepreneurial and battle-tested company that has grown
structuring our organizational and leadership framework to more
from scratch into one of Latin America’s leading independents, we
effectively manage our growing enterprise and capture the future.
attribute our success to a proud culture based on trust – and which
is the catalyst for our continuous record of safe, clean, neighborly,
Más Safe, Clean and Neighborly Operations
transparent and successful operations.
Our in-house-designed value system called SPEED is GeoPark’s
competitive advantage. SPEED represents our character, guides our
Our gratitude extends to the persistently supportive families of all
behavior and defines our success. It creates positive interdependence
our team members who have contributed immensely to where we
with the communities where we operate and ensures safe and
have been and where we are going. We were fortunate to join with all
environmentally-clean operational performance – with the goal to be
employees and spouses this year for GeoPark’s Fifteenth Anniversary
the partner-of-choice, employer-of-choice and neighbor-of-choice.
to express our thanks personally and to celebrate together our
From 2015 to date, GeoPark is the only major operator in Colombia
powerful culture, impressive accomplishments and big expectations
with zero work interruptions. In 2017, GeoPark was awarded the ISO
for each other.
14001 environmental management certification in Colombia.
Vision and Alignment
As described in our Business Guidelines which accompany every
Annual Report, GeoPark’s long-term value proposition is to build
the leading oil and gas independent company in Latin America – a
A special thanks also to our hard-working Board of Directors. We are
saddened by the unfortunate passing of Peter Ryalls and Michael
Dingman and sincerely grateful for their important and valuable
contribution to our Company.
region of unlimited hydrocarbon resources, a welcoming business
environment, and little competition. An advantage in creating our
Business Platform
GeoPark’s business plan follows a technical approach to identify
Company has been a consistent long-term vision and conservative
high-value under-exploited proven hydrocarbon basins – based on
business plan that are supported and shared by our shareholders,
geological, infrastructure and regulatory factors. We then work to
Board of Directors, management and employee team.
establish strategic positions in the targeted regions. Our systematic
expansion to date has resulted in building stable and growing
It is our steady focus on this bigger prize that has allowed us to build
businesses in Colombia, Chile, Brazil, Argentina and Peru. Each
the foundation and tools needed for the long-term and to push
country is managed by reputable and professional local teams, with
Jacana Field, Llanos 34 Block, Colombia
GeoPark 7
supporting production and cash flows, attractive underlying reserves
commitment to drill two exploration wells in 2018.
and resources, and inventories of new project opportunities.
Our independent country businesses are further enhanced by being
Argentina Business
supported by an overall corporate organization, which improves
Our team is continuing to strengthen our position in Argentina,
efficiencies, reduces costs through operational and financial
where it has a proven history of exploration success.
synergies, controls quality, drives performance, and more effectively
grows our overall company by allocating capital to the best
In August 2017, we made a successful new light oil field discovery
shareholder value-adding projects.
with the Rio Grande Oeste exploration well in the CN-V Block in the
Briefly looking at each of our businesses:
Colombia Business
Neuquen Basin. An adjacent prospect will be drilled in 2018.
In December 2017, GeoPark acquired a 100% working interest in and
operatorship of three new blocks (Aguada Baguales, El Porvenir and
GeoPark is leading the strongest upstream project in Colombia and
Puerto Touquet) in the heart of the Neuquen Basin with production,
one of the most attractive onshore projects in Latin America today.
development, exploration and unconventional resource potential.
In less than five years we grew from zero to be the third largest oil
The blocks are currently producing 2,400-2,500 boepd and were
operator in the country – and are currently proving up what is being
acquired at a value of $4 per boe 2P reserves. In addition to its
called the largest oil field discovery in Colombia in the last 20 years.
attractive upside potential, this acqusition represents a good fit with
our existing platform in Argentina with cost savings and operational
Our key asset is the Llanos 34 Block (GeoPark operated), which we
synergies.
have grown from 0 to 50,000+ bopd gross production. During 2017,
following successful appraisal drilling in the Tigana and Jacana oil
Peru Business
fields and new oilfield discoveries – Curucucu, Chiricoca, and Jacamar
GeoPark continues working to prepare for the development of the
– we materially increased our Colombian certified 1P and 2P reserves
Morona Block. This project has become emblematic for Peru and
by 64% and 31% to 66 million boe and 88 million boe respectively.
represents PetroPeru’s return to upstream activity. GeoPark was
Our 2P reserve life index reached 11 years and the reserve
selected as the partner-of-choice and awarded the operatorship with
replacement ratio was 360%. Our 1P NPV and 2P NPV in Colombia
a 75% working interest. We recently signed a cooperation agreement
increased to $1.1 billion and $1.4 billion respectively.
with the local indigenous communities to work together to complete
the Environmental Impact Assessment which is expected to be
Llanos 34 is a highly-attractive, low risk, low cost and high netback
submitted in 2018.
block which provides a large scale profitable production base even in
low oil price environments. Due to the expertise of our local teams,
Morona is a large block in the proven Maranon Basin with a large
net finding and development costs (F&D costs) for 2017 were just $2.4
upside potential (approximately 320-500 million boe) with several
per boe (1P). We have a big inventory of well sites (75+) to continue
high impact plays and prospects. The block’s key asset is the Situche
growing production, with IRRs exceeding 500% and six-month
Central oil field, which was discovered and proven up by two wells
paybacks (assuming a $50 per barrel Brent oil price). Our economics
(which tested at a combined rate of 7,500 bopd), and which has
and return on capital in Llanos 34 are highly profitable and beat
certified gross 3P reserves of 83 million barrels, a big 200 million
almost any North American conventional or unconventional play.
barrel potential, and the opportunity for near-term cash flow. Morona
In a constant effort to reduce transportation costs and improve
increases our overall inventory of reserves and exploration resources
netbacks, we are constructing a new 30 km flow line to connect
and can contribute to our long-term durable growth. GeoPark has
Llanos 34 to the main Colombian pipeline infrastructure.
designed a phased work program that is expected to put the Situche
represents an important acquisition for GeoPark that significantly
Central field into production initially through a long-term test to
During 2017, GeoPark also acquired attractive exploration acreage
begin generating cash flow – with ‘first oil’ targeted for 2019.
(Tiple and Zamuro), adjacent to Llanos 34, by farming-in with a
8 Annual Report 2017 / Letter to Shareholders
Magallanes Region, Chile
GeoPark 9
Brazil Business
Our Brazil business represents a strategic base with a fully-developed,
secure, cash flow-producing asset (a non-operated interest in the
Manati field, one of Brazil’s largest producing gas fields, operated
by Petrobras) and 8 exploration blocks in onshore mature proven
hydrocarbon basins (Potiguar, Reconcavo, and Sergipe Alagoas).
GeoPark will drill 2-3 exploration wells in 2018 to continue testing this
potential.
GeoPark also has identified attractive onshore hydrocarbon
opportunities in Brazil and is working with Petrobras in its divestment
efforts with the objective of expanding our asset base.
Chile Business
We are Chile’s first private oil and gas producer. We built the business
from a flat-footed start-up in 2006 to a solid business with current
production of approximately 2,900 boepd (66% gas, 34% oil),
2P reserves of 34 million boe and 5 blocks with 0.8 million acres,
consisting of approximately 375-700 million boe of exploration and
unconventional resources. Over 20 million boe have already been
produced by GeoPark in Chile and we divested 20% of our project in
2011 for approximately $150 million.
Our Chilean team has done an excellent job improving efficiencies
and maintaining production stability with very little new investment.
Production and reserves decreased in 2017 due the natural decline of
the fields and limited drilling activity since the end of 2014. In early
2017, GeoPark extended its gas off-take contract with Methanex to
2026 to supply its large methanol plant in Punta Arenas.
In early 2018, GeoPark drilled and tested a new shallow El Salto
formation prospect and discovered the Uaken gas field; which creates
a new low cost gas play across the Fell Block.
10 Annual Report 2017 / Letter to Shareholders
New Projects and Countries
With our focus on achieving scale, GeoPark is always in the hunt to
acquire attractively-valued new oil and gas upstream opportunities
across Latin America and we have built an impressive inventory of
new projects over the last ten years. Following the lower oil price
environment, national oil companies, which control the biggest
and best hydrocarbon acreage, are reevaluating their portfolios and
initiating divestment programs. Our regional platform, expertise and
reputation give us first mover advantage in potentially acquiring
these attractive projects.
We are also working towards establishing new platforms in Mexico
and Ecuador, where regulatory reforms have opened the door for
private companies to access highly attractive hydrocarbon assets –
many of which are an excellent fit for GeoPark’s skill set.
As a result of our existing large and diversified organic asset portfolio,
GeoPark has the advantage of being a patient asset acquirer, and can
wait for the right market opportunities to acquire the right projects at
the right prices. To enhance our position as the preferred buyer in the
region, we have also created strategic acqusition partnerships with
strong players, such as ONGC from India.
Tua Field, Llanos 34 Block, Colombia
GeoPark 11
Outlook
As a Company, GeoPark is built to prosper in a $40-45 oil price world.
The current increased price environment allows us to further expand
our programs and achieve greater returns – while maintaining our
inherent discipline and focus on cost and value.
Our 2018 work and investment program targets a $140-150 million
capital investment program (considering Brent oil prices of $60 per
barrel), and is fully funded by operating cash flows.
The work program provides for a 40+ well drilling program targeting
production growth of 25-30% (including the new Argentine assets)
and an exit production of 38,000-39,000 boepd, and includes:
• 29-31 gross well development, appraisal and exploration drilling
program and new flowline construction in the Llanos 34 and adjacent
blocks in the Llanos Basin in Colombia
• 6-7 gross well exploration drilling program in the Neuquen Basin in
Argentina
• Environmental impact assessment and preliminary engineering and
facility work on the Morona Block in the Maranon Basin in Peru
• 2-3 gross well exploration drilling program in the onshore
Reconcavo and Potiguar Basins in Brazil
• 1-2 gross well exploration and development drilling program on the
Fell Block in the Magallanes Basin in Chile
GeoPark has developed and proven-up a highly-effective capital
allocation methodology to manage its five country portfolio. This
system enables us to review and select from a wide range of projects
generated by each business unit team with different returns,
potentials, risks, sizes, timelines and geographies. It ensures that
capital is always directed to our top value-adding projects after
ranking them on technical, strategic and economic criteria. It creates
a healthy competition between our different business units which
further helps drive performance. It also provides greater security
in volatile markets by allowing us to easily add or remove projects
depending on oil prices and project performance – and to fine-tune
our desired risk exposure.
12 Annual Report 2017 / Letter to Shareholders
Magallanes Region, Chile
GeoPark 13
Thank You
Our sincere thanks and appreciation to our shareholders and
bondholders – old and new alike – who have partnered with us,
believe in our project, and support our efforts. In 2017, we
continued our campaign to reach out to new investors and better
align our market value with the underlying asset value we have
unlocked in the field. As a result, we were the leading E&P stock
performer last year and our stock trading volumes have begun
to accelerate (now at levels exceeding $5 million per day) which
has opened up shareholder participation to the wider investment
community.
As always, your comments and recommendations are welcomed and
appreciated. We please invite you to visit us in the field or at any of
our offices to get to know us better and learn first-hand how we work.
We look forward to delivering and reporting to you on our results in
2018.
Sincerely,
Gerald E. O’Shaughnessy
Chairman
James F. Park
Chief Executive Officer
14 Annual Report 2017 / Letter to Shareholders
GeoPark 15
BUSINESS APPROACH AND GUIDELINES
Strategic Context
GeoPark’s objective is to create value by building the leading Latin
opportunities. By applying new technology and investment,
American upstream independent oil and gas company. By this, we
creating stable markets and better economic conditions, and/or
mean an action-oriented, persistent, aware and caring company
more efficient operations, an under-performing or bypassed asset
with the best ‘shareholder value-adding’ oil and gas assets.
can be converted into an attractive economic project. Work in these
proven areas also frequently opens up exciting new hydrocarbon
We believe the energy business – specifically the upstream oil and
resources in new geological play types and formations.
gas industry – is one of the most exciting, necessary, and
economically-rewarding businesses today. No undertaking or
We are focused on Latin America because of the abundance of
society can advance without the supply of energy, and energy
these types of opportunities throughout the region. Latin America
remains the critical element in allowing people to better their lives.
ranks as one of the highest potential hydrocarbon resource regions
Much of the world still lacks adequate energy supplies for the most
in the world and its economies are thirsty for new energy.
basic needs and demand is continually increasing. Although new
Historically, it has been dominated by larger major and national oil
exciting technologies and sources are being developed, oil and gas
companies, with the presence of only a modest number of more-
is the most reliable energy source and will be required to support
agile independent companies. North America is home to thousands
over half of our planet’s continuous and rising energy needs far into
of independent oil and gas operators, whereas Latin America, an
this century.
area substantially larger and with greater resource potential, has
only a handful of independents taking advantage of available
We believe the best places for us to find and develop hydrocarbons
opportunities. In contrast to many areas of the world, the
are in areas around the world where oil and gas have already been
environment and resources for operating and funding a business
discovered, but which for economic, technical, funding or other
are welcoming and increasingly more feasible. Furthermore,
reasons have been inadequately developed or prematurely
numerous good oil and gas assets in Latin America are available,
abandoned. These projects have proven hydrocarbon systems,
undervalued and at very attractive prices now.
valuable technical information, existing infrastructure, and, in many
cases, unexploited low-risk exploration and re-development
GeoPark has been conservatively built for the long-term. We did not
16 Annual Report 2017 / Business Approach and Guidelines
start with a short term ‘exit strategy’ in mind and we have focused
year-over-year track record is evidence of our success in effectively
on building a team and sustainable business. Our approach has
balancing risk among the subsurface, geological, funding,
required patience in order to create the necessary foundation, but it
organizational, market, price, partner, shareholder, regulatory and
has enabled us to stay solidly ‘ in the game’ and be positioned to
political environments. For example, GeoPark was able to respond
now have the chance to grab the bigger prizes.
constructively to the 2008/9 financial crisis and, again, to the oil
The founders and our management team have a substantial part of
volatility of 2015-2016.
our net worth invested in GeoPark. (The CEO founder has never sold
We believe the best results in the upstream business are achieved
a share of GeoPark stock.) The management team has no special
with a larger scale portfolio approach with multiple attractive
class of stock or arrangements that benefit us differently from any
projects in multiple regions managed by talented oil and gas teams.
other shareholder other than our salaries and stock performance
This diversification reflects both a defensive and offensive
incentive programs. The entire GeoPark team (100% of our
approach. It is protective of any downside because the collective
employees have received GeoPark share awards) is solidly aligned
strength of our projects limits the negative impact of any
with all of our shareholders to build real and enduring value for
underperforming asset or timing delay. It also has an exciting
every share of GeoPark.
Opportunity Enhancement
and Risk Diversification
By its very nature, the upstream oil and gas business represents the
multiplier effect on the potential upside because of the increased
number of opportunities independently marching ahead. These
represent important advantages given the nature of the oil
exploration and production business.
Our country businesses are managed by experienced local
undertaking of risk in search of significant rewards. To succeed, an
professionals and teams with respected reputations. They know both
oil and gas company must effectively identify and manage
the specific subsurface rocks and conditions and the above-ground
prevailing risks and uncertainties to capture the available rewards.
operating and business environments in each region and give us the
We believe this to be one of GeoPark’s key capabilities; and our
characteristics of a local company. Our pride and care in how we act
Casanare Department, Colombia
GeoPark 17
and perform in our home regions are key elements of our success.
deem critical for enduring success in the oil and gas business. Our
team has consistently demonstrated the science and creativity to find
These generally independent businesses are further enhanced by
hydrocarbons in the subsurface, but also the muscle and experience
being tied together by an overall corporate organization, which
to get the oil and gas out of the ground and profitably to market.
improves efficiencies, reduces costs with operational and financial
Our attractive asset portfolio is evidence of our ability to acquire
synergies, controls quality, and can more effectively raise capital for
good projects in the right basins in the right countries with the right
our projects. It is also a source for new technologies and ideas to
partners and at the right price.
spread from one region to another. For example, our team introduced
a new geological play-type to the Llanos Basin in Colombia (an
Today, we have an amazing team of employees from Chile, Colombia,
area that has been explored for more than 75 years) that resulted
Brazil, Peru and Argentina – each of whom joined GeoPark with the
in multiple new oil field discoveries, and new oil technology to the
purpose of building a unique and special company that is prepared
Magallanes Basin in Chile.
to handle challenges and seize opportunities. As a quickly growing
company, we have repeatedly seen individuals step-up to the new
Importantly, through effective and controlled capital allocation, our
responsibilities presented – and we have a deep and powerful
projects within each country business can be ranked against each
leadership team taking GeoPark to the next level.
other on economic, technical and strategic criteria and, therefore,
ensure our capital resources flow to the highest performing and most
The international upstream oil and gas business is not for the
attractive projects.
fainthearted or easily discouraged. Time-after-time, the GeoPark
team has been able to push ahead to find solutions where often
We believe this business approach makes GeoPark a more attractive
others have given-up or failed. This is the engine and fire of our
investment vehicle for all our shareholders – with a strong foundation
growth and the true long-term intangible value of our Company.
to minimize any downside, a big upside through multiple growth
We are immensely grateful to all these men and women for their
opportunities, and an overall organizational system to more
professionalism, discipline, unity and heart.
efficiently run and grow the individual businesses. GeoPark’s model
allows our investors to be exposed to and benefit from the results of
multiple supporting and aligned businesses across diverse geologies
and geographies.
Capabilities
Our experience in the oil and gas business has repeatedly
New Projects and Countries
We are excited about potential new business opportunities in
Latin America with its high resource potential, attractive business
environment, and limited competition. We are actively pursuing
new projects in targeted proven hydrocarbon basins throughout
the region – selected in consideration of geological, infrastructure
demonstrated the need for good people with commitment and
and regulatory factors – with our principal efforts in Colombia, Brazil,
real oil and gas know-how. We believe in and have experienced the
Chile, Peru, Argentina, and Mexico.
amazing capacity of people to excel in an environment of expanding
opportunity and trust. GeoPark is blessed to have an incredible group
With our overall growth targets and portfolio approach, new project
of men and women who truly work day and night to make us better
acquisitions are an important part of our business. Our acquisition
in every way. Our results speak to the daily heroics (mostly unseen)
efforts begin with a technical approach to define the hydrocarbon
of our team that keep us together and have moved us consistently
basins where our geological and engineering teams identify an
closer to our goals.
attractive potential. After screening for political risks, our new
business teams proactively ‘scratch and dig’ to locate interests or
Our record of delivery is based on three fundamental and distinct
opportunities within those areas and to establish a position. It is
skill sets – as Explorers, Operators and Consolidators – which we
a long-term and continuous effort and we have been building an
18 Annual Report 2017 / Business Approach and Guidelines
Tua Field, Llanos 34 Block, Colombia
GeoPark 19
20 Annual Report 2017 / Business Approach and Guidelines
Morona River, Morona Project, Peru
attractive inventory of new projects in the region over the last ten
by succeeding equally in each of these interdependent areas can we
years, aided by our team’s 25+ year experience in Latin America.
realize our overall success and ambitions. This is important in every
Our focus is always to build a larger scale balanced portfolio that
the most effective governance, full compliance and consistent
includes lower-risk short term cash flow generating properties, mid-
transparency with all relevant authorities. Not only does this allow
term medium-risk development projects, and longer-term higher-
us to be a more successful business enterprise over the long-term,
risk big upside projects. This permits steady secure growth with an
it reflects our pride in carrying out an important mission in the right
opportunity for accelerated high growth ‘home-runs’ from the bigger
way. The men and women of GeoPark care passionately about how
country where we operate, and we make every effort to achieve
projects.
our Company acts – both internally and externally – and we all
consider our culture to be our core asset and the prime source of our
Good oil and gas partners are a key element of our new business
past success and future opportunity.
efforts and we like to balance our acquisition risk by including
experienced partners in our new projects. We have developed a long-
The world is continuously moving in a more regulated direction
term strategic alliance with ONGC to build a portfolio of upstream
with higher expectations, and to be able to operate in this new
assets across Latin America and the International Finance Corporation
environment is a fundamental part of business today. We believe that
(IFC) of the World Bank is a long-term principal shareholder of (and
GeoPark’s ability to meet these challenges and perform to or beyond
sometimes lender to and working interest partner of ) GeoPark. We
these ever increasing standards represents a competitive advantage
also have developed long-term relationships with the national oil
for the future. For example, the manner of, results from, and impact
companies where we operate, such as ENAP in Chile, Ecopetrol in
on the communities of our overall work in Chile and Colombia
Colombia, Petrobras in Brazil, YPF in Argentina and Petroperu in Peru.
provided the rationale and support for the government and regional
community to allow us to expand our project into new areas. It
Critical to the success of any new project is to conduct a thorough
can also be meaningful and fun, such as with our full scholarships
technical and economic analysis prior to acquiring any new asset.
targeting young women, in the local communities near our field
We make sure we understand the project, its risks and its value –
operations, for training in the sciences.
and we buy right. It is difficult to turn a faulty or overpriced project
into a good business. Following intensive geological, geophysical,
The IFC of the World Bank, our long time shareholder, has been a
engineering, operational, legal and financial analyses and due
constructive force in helping us operate and manage our business in
diligence, we perform a detailed discounted cash flow (DCF)
consideration of the environment and communities around us. The
valuation. We also consider the option value or strategic benefits
IFC further assists us by carrying out annual audits and physical site
of a project when entering a new region. We do not buy assets on
visits of both our regulatory compliance and best-practices approach.
simplified ‘$ per barrel’ metrics which we believe do not properly
account for multiple factors (including technical, cost, tax, and time)
that impact the economics of oil and gas projects. We also avoid
markets or ‘bubbles’ when assets are over-priced.
Culture
‘Creating Value and Giving Back’ is our motto and represents
GeoPark’s market-based approach to align our business objectives
with our core values and responsibilities. Our in-house designed
program, titled SPEED, targets and integrates the critical elements
– Safety, Prosperity, Employees, Environment and Community
Development – necessary to make our total business plan work. Only
- James F. Park (2008*)
Morona River, Morona Project, Peru
GeoPark 21
2017 PERFORMANCE
Record Oil and Gas
Production
• Production up 23% to 27,586 boepd.
Record Capital Investment
and Costs Efficiencies
• 2P Finding and development costs:
New Opportunities
• Argentina: low-cost, cash flow-producing
acquisition in the prolific Neuquen basin
• Colombia production up 39% to 21,788
Consolidated $4.0/boe; Colombia $2.8/boe.
with production, development, exploration
bopd.
• Operating netback/capital expenditure ratio
and unconventional opportunities.
• Record exit production of 31,977 boepd.
of 2.2x.
• Colombia: Tiple and Zamuro high-impact
Record Oil and Gas
Reserves
• 1P reserves up 24% to 97.0 million boe.
• 2P reserves up 11% to 159.2 million boe.
• Colombia 2P reserves up 31% to 88.2 million
boe.
• Capital investment program of $105.6
exploration acreage added adjacent to
million generated $404 million in 2P NPV10.
Llanos 34 Block.
• OPEX: $7.3 per boe, Colombia $5.6 per boe.
• Long-term Latin American acquisition
partnership with ONGC (India’s national oil
company).
Record Cash Flow/EBITDA
Growth
• Adjusted EBITDA up 124% to $175.8 million.
• Operating Netback up 87% to $228.3 million.
2018 Outlook
• Capital investment program of $140-150
• Cash Flow from operations up 72% to $142.2
million.
Record Oil and Gas Asset
Valuation
• 1P reserve NPV10 up 38% to $1.5 billion.
• 2P reserve NPV10 up 21% to $2.3 billion.
• 2P reserve Colombian assets NPV10
up 38% to $1.4 billion.
million.
Strengthened Balance
Sheet and Credit Rating
• $134.8 million of cash in hand.
• Net debt adjusted 2P NPV10 increased by
• new $425 million 2024 bond issued, with
24% to $29.2 per share.
longer maturities and lower cost.
• Drilling program of 40+ exploration,
appraisal and development wells in
Colombia, Argentina, Brazil and Chile.
• Targeted production growth of 25-30%
(including Argentina) and exit production of
38,000-39,000 boepd.
• Net debt to Adjusted EBITDA ratio
decreased from 3.6x to 1.7x.
• Upgraded credit rating to B+ with a stable
outlook.
2006
2007
2008
2009
2010
2011
22 Annual Report 2017 / Performance
Oil
Gas
2012
2013
2014
2015
2016
2017
28
27
26
25
24
23
22
21
20
19
18
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
s
a
G
d
n
a
l
i
O
y
l
i
a
D
e
g
a
r
e
v
A
GeoPark 23
Know-How
Strong Team, Capabilities,
Approach and Culture.
Capital
Supporting Cash Flow,
Access to Funding
and Strategic Partners.
Track Record
Consistent Operational
and Financial Growth /
Ability to Unlock Value
from Assets.
Assets
Diversified Risk-Balanced
Asset Base with Proven
Value, Scale and Upside.
OUR STRENGTHS
24 Annual Report 2017 / Our Strengths
MEXICO
COLOMBIA
88.2
MMBOE
PERU
31.5
MMBOE
CHILE
34.0
MMBOE
OUR PLATFORM
BRAZIL
4.4
MMBOE
GeoPark 25
ARGENTINA
1.1
MMBOE
Latin American Platform
2P Reserves (Dec. 2017)
Production Assets
Development Assets
Exploration Assets
Unconventional Resource Assets
New Project Opportunities
26 Annual Report 2017 / Our Approach
Jacana Field, Llanos 34 Block, Colombia
OUR APPROACH
GeoPark has been built around five fundamental
and distinct capabilities:
Explorer
The ability, experience, methodology and creativity to find and develop
oil and gas reserves in the subsurface – based on the best science, solid
economics and ability to take the necessary managed risks.
Operator
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, overcome obstacles,
seize opportunities and achieve results.
Consolidator
The ability and initiative to assemble the right balance and portfolio of
upstream assets in the right hydrocarbon basins in the right
regions with the right partners and at the right price – coupled with
the vision and skills to transform and improve value above ground.
Value Risk Management
The comprehensive management approach to consistently and
significantly grow and build economic value per share by effective
planning, balanced work programs, cost efficiency focus, secure access
to capital sources, reliable communication with shareholders, and by
accommodating risk among the subsurface, funding, organizational,
market, partner/shareholder, and regulatory/political environments.
Culture
The commitment to build a unique performance-driven trust-based
culture which values and protects our shareholders, employees,
environment and communities to underpin and enhance our
long-term plan for success. Our SPEED program reflects this value
system and represents an integrated approach to align our business
objectives with our core principles and responsibilities.
Jacana Field, Llanos 34 Block, Colombia
GeoPark 27
OUR VALUE SYSTEM
SPEED represents GeoPark’s underlying value system which provides
us the leadership, confidence and foundation required for long-term
success. It is our competitive advantage. And, it reflects our pride
in achieving an important mission in the right way. If we are the true
performer, the best place to work, the preferred partner and the
cleanest operator – our future is bigger, better and more secure.
Safety
Prosperity
Employees
Environment
Community
Development
GeoPark is committed
GeoPark is committed
GeoPark is committed
GeoPark is committed
GeoPark is committed
to creating a safe and
to delivering significant
to creating a motivating
to minimizing the impact
to being the preferred
healthy workplace.
bottom-line financial
workplace for employees.
of our projects on
neighbor and partner
Simply speaking,
value to our shareholders.
With today’s shortage
the environment.
by creating a mutually
everybody must return
Only a financially-healthy
of capable energy
As our footprint becomes
beneficial exchange
home everyday safe
company can continue
professionals, the
cleaner and smaller,
with the local
and sound.
to grow, attract needed
company which is able
the more areas and
communities where we
resources and create real
to attract, protect, retain
opportunities will be
work. Unlocking local
long-term benefits.
and train the best team
opened up for us to
knowledge creates and
with the best attitude
work in. Our long-term
supports long-term
will always prevail.
well-being requires
sustainable value in our
us to properly fit within
projects. If our efforts
our surroundings.
enhance local goals
and customs, we will
be invited to do more.
28 Annual Report 2017 / Our Value System
GeoPark 29
HIGHLIGHTED SECTIONS
42
62
106
126
134
156
Risk Factors
Information on the Company
Operating and Financial Information
Directors and Management
Major Shareholders and Related Parties
Consolidated Financial Statements
30 Annual Report 2017
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
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2017
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
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 E. Aylwin Chiorrini
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.
Yasin Keshvargar, 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: 60,596,219
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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
Yes
No
Securities Exchange Act of 1934.
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.
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):
Large accelerated filer
Accelerated filer
Non-accelerated filer
Emerging growth company
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to
use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards
Codification after April 5, 2012.
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
US GAAP
International Financial Reporting Standards as issued by Other
the International Accounting Standards Board
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.
Item 17
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
No
GeoPark 31
Table of Contents
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
FORWARD-LOOKING STATEMENTS
PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A. Directors and senior management
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
E. Share ownership
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
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
D. Selling shareholders
E. Dilution
F. Expenses of the issue
32 GeoPark 20-F
33
36
37
37
37
37
37
37
37
37
37
37
41
41
42
62
62
64
106
106
106
106
106
121
125
125
125
125
126
126
126
130
132
133
133
134
134
134
136
136
136
137
137
137
137
137
137
137
137
ITEM 10. ADDITIONAL INFORMATION
A. Share capital
B. Memorandum of association and bye-laws
Enforcement of Judgments
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
ABOUT MARKET RISK
137
137
137
143
143
144
144
146
146
146
146
146
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
146
A. Debt securities
B. Warrants and rights
C. Other securities
D. American Depositary Shares
PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
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
Index to Consolidated Financial Statements
146
146
146
146
147
147
147
147
147
147
147
147
147
147
147
147
147
148
148
148
148
148
149
150
150
150
150
152
157
Presentation of Financial and Other Information
Certain definitions
Unless otherwise indicated or the context otherwise requires, all references in
this annual report to:
• “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words of a
similar effect, are to GeoPark Limited (formerly GeoPark Holdings Limited), an
exempted company incorporated under the laws of Bermuda, together with
its consolidated subsidiaries;
• “Agencia” are to GeoPark Latin America Limited Agencia en Chile, an
established branch, under the laws of Chile, of GeoPark Latin America Limited
(“GeoPark Latin America”), an exempted company incorporated under the
laws of Bermuda;
• “GeoPark Colombia” are prior to our internal corporate reorganization of our
Colombian operations, to our subsidiary GeoPark Colombia S.A., a sociedad
anónima cerrada incorporated under the laws of Chile and subsequent to
such reorganization, to GeoPark Colombia Coöperatie U.A., a cooperative
duly incorporated under the laws of the Netherlands;
• “LGI” are to LG International Corp., a company incorporated under the laws
of Korea”;
• “Notes due 2020” are to our 2013 issuance of US$300.0 million aggregate
principal amount of 7.50% senior secured notes due 2020;
• “Notes due 2024” are to our 2017 issuance of US$425.0 million aggregate
principal amount of 6.50% senior secured notes due 2024;
• “US$” and “U.S. dollar” are to the official currency of the United States of
America;
• “Col$” is the official currency of Colombia;
• “Ch$” and “Chilean pesos” are to the official currency of Chile;
• “AR$” and “Argentine pesos” are to the official currency of Argentina;
• “real,” “reais” and “R$” are to the official currency of Brazil;
• “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels
Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis);
• “ANH” are to the Colombian National Hydrocarbons Agency (Agencia
Nacional de Hidrocarburos);
• “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional de
Petróleo)
• “UTA” are to Unidad Tributaria Anual;
• “economic interest” means an indirect participation interest in the net
revenues from a given block based on bilateral agreements with the
concessionaires; and
• “working interest” means the right granted to the lessee of a property to
explore for and to produce and own oil, gas, or other minerals. The working
interest owners bear the exploration, development and operating costs on
either a cash, penalty or carried basis.
GeoPark 33
Financial statements
Non IFRS financial measures
Our consolidated financial statements
Adjusted EBITDA
This annual report includes our audited consolidated financial statements as
Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by
of December 31, 2017 and 2016 and for each of the years ended December 31,
management and external users of our financial statements, such as industry
2017, 2016 and 2015 (hereinafter “Consolidated Financial Statements”).
analysts, investors, lenders and rating agencies.
Our Consolidated Financial Statements are presented in US$ and have been
We define Adjusted EBITDA as profit for the period before net finance cost,
prepared in accordance with International Financial Reporting Standards
income tax, depreciation, amortization and certain non-cash items such
(“IFRS”), as issued by the International Accounting Standards Board (“IASB”).
as impairment charges or impairment reversals, write-offs of unsuccessful
Our Consolidated Financial Statements have been audited by Price
unrealized gains in commodity risk management contracts and bargain
Waterhouse & Co. S.R.L., Argentina, a member firm of PricewaterhouseCoopers
purchase gain on acquisition of subsidiaries. Adjusted EBITDA is not a measure
Network (“PwC”), an independent registered public accounting firm, as stated
of profit or cash flows as determined by IFRS.
exploration and evaluation assets, accrual of stock options and stock awards,
in their report included elsewhere in this annual report.
Our fiscal year ends December 31. References in this annual report to a fiscal
evaluate our operating performance and compare the results of our
year, such as “fiscal year 2017,” relate to our fiscal year ended on December 31
operations from period to period without regard to our financing methods or
We believe Adjusted EBITDA is useful because it allows us to more effectively
capital structure. We exclude the items listed above from profit for the period
in arriving at Adjusted EBITDA because these amounts can vary substantially
from company to company within our industry depending upon accounting
methods and book values of assets, capital structures and the method by
which the assets were acquired. Adjusted EBITDA should not be 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 or as
an indicator of our operating performance or liquidity. Certain items excluded
from Adjusted EBITDA are significant components in understanding and
assessing a company’s financial performance, such as a company’s cost of
capital and tax structure and significant and/or recurring write-offs, as well
as the historic costs of depreciable assets, or unrealized gains in commodity
risk management contracts, none of which are components of Adjusted
EBITDA. Our computation of Adjusted EBITDA may not be comparable to other
similarly titled measures of other companies.
For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit
for the year, see Note 6 to our Consolidated Financial Statements as of and for
the years ended 2017, 2016 and 2015.
of that calendar year.
34 GeoPark 20-F
Oil and gas reserves and production information
Rounding
DeGolyer and MacNaughton 2017 Year-end Reserves Report
We have made rounding adjustments to some of the figures included
The information included elsewhere in this annual report regarding estimated
elsewhere in this annual report. Accordingly, numerical figures shown as totals
quantities of proved reserves in Colombia, Chile, Brazil and Peru is derived,
in some tables may not be an arithmetic aggregation of the figures that
in part, from estimates of the proved reserves as of December 31, 2017.
precede them.
The reserves estimates described herein are derived from the DeGolyer and
MacNaughton Reserves Report (the “D&M Reserves Report”), which was
prepared for us by the independent reserves engineering team of DeGolyer
and MacNaughton and is included as an exhibit to this annual report. The
D&M Reserves Report presents oil and gas reserves estimates located in the
Fell, Campanario, Flamenco and Isla Norte Blocks in Chile, Llanos 32, Llanos 34,
Yamú and La Cuerva Blocks in Colombia, BCAM-40 (Manati) in Brazil and the
Morona Block in Peru.
Market share and other information
Market data, other statistical information, information regarding recent
developments in Chile, Colombia, Brazil, Peru and Argentina and certain
industry forecast data used in this annual report were obtained from internal
reports and studies, where appropriate, as well as estimates, market research,
publicly available information and industry publications. Industry publications
generally state that the information they include has been obtained from
sources believed to be reliable, but that the accuracy and completeness of
such information is not guaranteed. Similarly, internal reports and studies,
estimates and market research, which we believe to be reliable and accurately
extracted by us for use in this annual report, have not been independently
verified. However, 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 reproduction in this annual report.
In addition, we have provided definitions for certain industry terms used in
this annual report in the “Glossary of oil and natural gas terms” included as
Appendix A to this annual report.
GeoPark 35
Forward-looking Statements
This annual report contains statements that constitute forward-looking
• the direct or indirect impact on our business resulting from terrorist
statements. Many of the forward-looking statements contained in this
incidents or responses to such incidents, including the effect on the
annual report can be identified by the use of forward-looking words such
availability of and premiums on insurance; and
as “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,”
• other factors discussed under “Item 3. Key Information—D. Risk factors” in
“estimate” and “potential,” among others.
this annual report.
Forward-looking statements appear in a number of places in this annual
Forward-looking statements speak only as of the date they are made, and we
report and include, but are not limited to, statements regarding our intent,
do not undertake any obligation to update them in light of new information or
belief or current expectations. Forward-looking statements are based on
future developments or to release publicly any revisions to these statements
our management’s beliefs and assumptions and on information currently
in order to reflect later events or circumstances or to reflect the occurrence of
available to our management. Such statements are subject to risks and
unanticipated events.
uncertainties, and actual results may differ materially from those expressed
or implied in the forward-looking statements due to various factors,
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:
• the volatility of oil and natural gas prices;
• 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, Peruvian and Argentine
governments to us;
• uncertainties inherent in making estimates of our oil and natural gas data;
• 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 Colombia, Chile, Brazil, Peru,
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;
• market or business conditions and fluctuations in global and local demand
for energy;
36 GeoPark 20-F
PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
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 balance sheet data as of December
31, 2017 and 2016 and our income statement and cash flow data for the years
ended December 31, 2017, 2016 and 2015 from our 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, 2015, 2014, and 2013 and our income statement and cash flow data for the
years ended December 31, 2014 and 2013 from our Consolidated Financial
Statements not included elsewhere in this annual report.
During 2015, our Management changed the presentation of the Consolidated
Statement of Income by reordering the profit and loss line items, eliminating
gross profit and presenting depreciation and write-off of unsuccessful efforts
as separate line items. This change is intended to provide readers of our
financial statements with more relevant information and a better explanation
of the elements of performance. This change has been applied to comparative
figures for the years 2014 and 2013 presented in this document.
We maintain our books and records in US$ 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.
The selected historical financial data set forth in this section does not include
any results or other financial information of our Colombian, Brazilian or
Peruvian acquisitions prior to their incorporation into our financial statements.
GeoPark 37
Statement of income data
For the year ended December 31,
(in thousands of US$, except per share numbers)
2017
2016
2015
2014
2013
279,162
50,960
330,122
(15,448)
(98,987)
(7,694)
(42,054)
(1,136)
(74,885)
(5,834)
-
(5,088)
78,996
(51,495)
(2,193)
25,308
(43,145)
(17,837)
6,391
(24,228)
145,193
47,477
192,670
(2,554)
(67,235)
(10,282)
(34,170)
(4,222)
(75,774)
(31,366)
5,664
(1,344)
162,629
47,061
209,690
-
(86,742)
(13,831)
(37,471)
(5,211)
(105,557)
(30,084)
(149,574)
(13,711)
(28,613)
(232,491)
(34,101)
13,872
(48,842)
(35,655)
(33,474)
(301,620)
(11,804)
(60,646)
17,054
(284,566)
(11,554)
(49,092)
(50,535)
(234,031)
(0.40)
(0.82)
(4.05)
(0.40)
(0.82)
(4.05)
367,102
61,632
428,734
315,435
22,918
338,353
-
-
(131,419)
(111,296)
(13,002)
(45,867)
(24,428)
(100,528)
(30,367)
(9,430)
(1,849)
71,844
(27,622)
(23,097)
21,125
(5,195)
15,930
7,845
8,085
0.14
0.14
(5,292)
(44,962)
(17,252)
(69,968)
(10,962)
–
5,343
83,964
(33,115)
(761)
50,088
(15,154)
34,934
12,413
22,521
0.52
0.48
60,093,191
59,777,145
57,759,001
56,396,812
43,603,846
60,093,191
59,777,145
57,759,001
58,840,412
46,532,049
60,596,219
59,940,881
59,535,614
57,790,533
43,861,614
Revenue
Net oil sales
Net gas sales
Net revenue
Commodity risk management contracts
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Selling expenses
Depreciation
Write-off of unsuccessful exploration efforts
Impairment for non-financial assets
Other operating (expense)/income
Operating profit/(loss)
Financial costs
Foreign exchange loss /gain
Profit (Loss) before tax
Income tax (expense) benefit
(Loss) Profit for the year
Non-controlling interest
(Loss) Profit attributable to owners of the Company
(Losses) Earnings per share for profit attributable
to owners of the Company—Basic
(Losses) Earnings per share for profit attributable
to owners of the Company—Diluted(1)
Weighted average common shares
outstanding—Basic
Weighted average common shares
outstanding—Diluted(1)
Common Shares outstanding at year-end
(1) See Note 19 to our Consolidated Financial Statements.
38 GeoPark 20-F
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
Derivative financial instrument liabilities
Current income tax
Trade and other payables
Total current liabilities
Total liabilities
2017
2016
2015
2014
2013
517,403
473,646
522,611
790,767
595,446
3,823
22,110
27,636
235
2,852
19,547
23,053
241
1,172
13,306
34,646
220
1,253
12,979
33,195
349
11,454
5,168
13,358
6,361
571,207
519,339
571,955
838,543
631,787
21,378
5,738
19,519
7,518
26,048
134,755
214,956
786,163
61
239,191
(154,327)
84,925
41,915
126,840
2,480
3,515
18,426
7,402
15,815
73,563
121,201
640,540
60
236,046
(130,341)
105,765
35,828
141,593
418,540
46,284
25,921
2,286
319,389
42,509
34,766
2,770
1,118
4,264
13,480
11,057
19,195
82,730
131,844
703,799
59
232,005
(85,412)
146,652
53,515
200,167
343,248
42,450
19,556
16,955
—
8,532
36,917
13,993
13,459
127,672
200,573
1,039,116
58
210,886
164,613
375,557
103,569
479,126
342,440
46,910
16,583
30,065
—
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
493,031
399,434
422,209
435,998
354,964
7,664
19,289
42,942
96,397
166,292
659,323
39,283
3,067
5,155
52,008
99,513
498,947
35,425
–
208
45,790
81,423
503,632
27,153
–
7,935
88,904
123,992
559,990
26,630
–
7,231
91,633
125,494
480,458
Total equity and liabilities
786,163
640,540
703,799
1,039,116
846,415
GeoPark 39
Cash flow data
For the year ended December 31,
(In thousands of US$)
Cash provided by (used in)
Operating activities
Investing activities
Financing activities
Net increase (decrease) in cash
Other financial data
2017
2016
2015
2014
2013
142,158
(105,604)
23,968
60,522
82,884
(39,306)
(51,136)
(7,558)
25,895
(48,842)
(18,022)
(40,969)
230,746
(344,041)
124,716
11,421
127,295
(208,500)
164,018
82,813
For the year ended December 31,
2017
2016
2015
2014
2013
Adjusted EBITDA(1) (US$ thousands)
Adjusted EBITDA margin(2)
Adjusted EBITDA per boe(3)
175,776
53.2%
18.4
78,321
40.6%
10.2
73,787
35.2%
10.5
220,077
51.3%
33.0
167,253
49.4%
33.9
(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 Consolidated Financial Statements.
(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 boe.
40 GeoPark 20-F
Exchange rates
In Colombia, Chile, Argentina and Peru, our functional currency is the U.S.
Recent exchange rates
Period
dollar. In Brazil, our functional currency is the real.
of Real per US$
Month:
Our operations in Brazil accounted for 16% and 12% of our consolidated assets
October 2017
and 15% and 10% of our revenues for the years ended December 31, 2016
November 2017
and 2017, respectively. This portion of our business is exposed to losses that
December 2017
may arise from currency fluctuation, as a significant amount of our revenues,
January 2018
operating costs, administrative expenses and taxes in Brazil are denominated
February 2018
in reais.
March 2018
April 2018
End
Average
Low
High
3.2769
3.2616
3.3080
3.1624
3.2449
3.3238
3.1912
3.2594
3.2919
3.2106
3.2415
3.2792
3.1315
3.2136
3.2322
3.1391
3.1730
3.2246
3.2801
3.2920
3.3332
3.2697
3.2821
3.3380
The real may depreciate or appreciate substantially against the U.S. dollar.
(through April 6, 2018)
3.3666
3.3329
3.3104
3.3666
We recorded exchange rate losses amounting to US$1.3 million for the year
ended December 31, 2017, due to devaluation of the local currency in our
Source: Central Bank of Brazil.
Brazilian subsidiary. This result was mainly generated by the credit facility with
Itaú BBA International plc that we incurred on March 31, 2014 to acquire Rio
The following table presents the average R$ per U.S. dollar representative
das Contas, which we repaid in September 2017. We recorded exchange rate
market rate for each of the five most recent years, calculated by using the
gains amounting to US$14.5 million for the year ended December 31, 2016 as
average of the exchange rates on the last day of each month during the
a result of the appreciation that occurred. See “—D. Risk factors—Risks relating
period, and the representative year-end market rate for each of the five most
to our business—Our results of operations could be materially adversely
recent years.
affected by fluctuations in foreign currency exchange rates.”
The following tables show the selling rate for the U.S. dollar for the periods
Period/
and dates indicated. The information in the “Average” column represents
Real per US$
Year End
Average
Low
High
the average of the daily exchange rates during the periods presented. The
Period:
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 6, 2018, the
exchange rate for the purchase of the U.S. dollar as reported by the Central
Bank of Brazil was R$3.3666 per U.S. dollar.
2013
2014
2015
2016
2017
The following table presents the monthly high and low representative market
First quarter 2018
rate during the months indicated.
Second quarter 2018
2.3426
2.6562
3.9048
3.2591
3.3080
3.3238
2.1579
2.3564
3.3876
3.4500
3.2031
3.2437
1.9528
2.1974
2.5690
3.1193
3.0510
3.1391
2.4457
2.7403
4.1949
4.1558
3.3807
3.3380
(through April 6, 2018)
3.3666
3.3329
3.3104
3.3666
Source: Central Bank of Brazil.
Exchange rate fluctuation may affect the US$ value of any distributions we
make with respect to our common shares. See “—D. Risk factors—Risks
relating to our business—Our results of operations could be materially
adversely affected by fluctuations in foreign currency exchange rates.”
B. Capitalization and indebtedness
Not applicable.
C. Reasons for the offer and use of proceeds
Not applicable.
GeoPark 41
Risk factors
D. Risk factors
Our business, financial condition and results of operations could be
• taxes and royalties under relevant laws and the terms of our contracts;
materially and adversely affected if any of the risks described below occur.
• our ability to enter into oil and natural gas sales contracts at fixed prices;
As a result, the market price of our common shares could decline, and you
• the level of global methanol demand and inventories and changes in the
could lose all or part of your investment. This annual report also contains
uses of methanol;
forward-looking statements that involve risks and uncertainties. See
• the price and availability of alternative fuels; and
“Forward-Looking Statements.” The risks below are not the only ones facing
• future changes to our hedging policies.
our Company. Additional risks not currently known to us or that we currently
deem immaterial may also adversely affect us.
These factors and the volatility of the energy markets make it extremely
Risks relating to our business
difficult to predict future oil, natural gas and methanol price movements. For
example, recently, oil and natural gas prices have fluctuated significantly.
From January 1, 2013 to December 31, 2017, Brent spot prices ranged from
A substantial or extended decline in oil, natural gas and methanol prices
a low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub
may materially adversely affect our business, financial condition or results
natural gas average spot prices ranged from a low of US$1.7 per mmbtu to
of operations.
a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged
from a low of US$250.0 per metric ton to a high of US$635.1 per metric
The prices that we receive for our oil and natural gas production heavily
ton. Furthermore, oil, natural gas and methanol prices do not necessarily
influence our revenues, profitability, access to capital and growth rate.
fluctuate in direct relationship to each other.
Historically, the markets for oil, natural gas and methanol (which have
For the year ended December 31, 2017, 85% of our revenues were derived
influenced prices for almost all of our Chilean gas sales) have been volatile and
from oil. Because we expect that our production mix will continue to be
will likely continue to be volatile in the future. International oil, natural gas and
weighted towards oil, our financial results are more sensitive to movements
methanol prices have fluctuated widely in recent years and may continue to
in oil prices.
do so in the future.
As of December 31, 2017, natural gas comprised 15% of our revenues. A
decline in natural gas prices could negatively affect our future growth,
The prices that we will receive for our production and the levels of our
particularly for future gas sales where we may not be able to secure or
production depend on numerous factors beyond our control. These factors
extend our current long-term contracts.
include, but are not limited, to the following:
Lower oil and natural gas prices may impact our revenues on a per unit
• global economic conditions;
basis, and may also reduce the amount of oil and natural gas that can
be produced economically. In addition, changes in oil and natural gas
• changes in global supply and demand for oil, natural gas and methanol;
prices can impact the valuation of our reserves and, in periods of lower
• the actions of the Organization of the Petroleum Exporting Countries
commodity prices, we may curtail production and capital spending or may
(“OPEC”);
defer or delay drilling wells because of lower cash generation. Lower oil
• political and economic conditions, including embargoes, in oil-producing
and natural gas prices could also affect our growth, including future and
countries or affecting other countries;
pending acquisitions. A substantial or extended decline in oil or natural gas
• the level of oil- and natural gas-producing activities, particularly in the
prices could adversely affect our business, financial condition and results of
Middle East, Africa, Russia, South America and the United States;
operations.
• the level of global oil and natural gas exploration and production activity;
For example, during 2014 and 2015, we evaluated the recoverability of our
• the level of global oil and natural gas inventories;
fixed assets affected by the oil price decline and recorded an impairment of
• the price of methanol;
• availability of markets for natural gas;
non-financial assets amounting to, respectively, US$9.4 million and US$149.6
million. US$5.7 million of the impairment recorded in 2015 was reversed
• weather conditions and other natural disasters;
in 2016 due to increased estimated market prices for 2017 and 2018 and
• technological advances affecting energy production or consumption;
improvements in cost structure. After conducting an impairment test
• domestic and foreign governmental laws and regulations, including
procedure for the year ended December 31, 2017, no additional impairment
environmental, health and safety laws and regulations;
of non-financial assets was recognized. See Note 36 to our Consolidated
• proximity and capacity of oil and natural gas pipelines and other
Financial Statements for details regarding oil price scenarios, discount rates
transportation facilities;
considered and sensitivity analysis affecting the impairment charges.
• the price and availability of competitors’ supplies of oil and natural gas in
Continuing our hedging strategy, we entered into derivative financial
captive market areas;
instruments to manage exposure to oil price risk. These derivatives were
• quality discounts for oil production based, among other things, on API and
zero-premium collars or zero premium three way hedges (put, spread and
mercury content;
42 GeoPark 20-F
call) and were placed with major financial institutions and commodity
traders. We entered into the derivatives under ISDA Master Agreements
and Credit Support Annexes, which provide credit lines for collateral
the incurrence of additional indebtedness, including additional bank
posting thus alleviating possible liquidity needs under the instruments and
credit facilities, equity issuances or the sale of minority stakes in certain
protecting us from potential non-performance risk by our counterparties.
operations to our partners. We may need to raise additional funds more
See Note 8 to our Consolidated Financial Statements for details regarding
quickly if one or more of our assumptions prove to be incorrect or if we
Commodity Risk Management Contracts.
choose to expand our hydrocarbon asset acquisition, exploration, appraisal
or development efforts more rapidly than we presently anticipate, and
The oil price crisis has impacted our operations and corporate strategy.
we may decide to raise additional funds even before we need them if the
conditions for raising capital are favorable. The ultimate amount of capital
We face limitations on our ability to increase prices or improve margins
that we will expend may fluctuate materially based on market conditions,
on the oil and natural gas that we sell. As a consequence of the oil price
our continued production, decisions by the operators in blocks where
crisis which started in the second half of 2014 (WTI and Brent, the main
we are not the operator, the success of our drilling results and future
international oil price markers, fell by more than 60% between August 2014
acquisitions. Our future financial condition and liquidity will be impacted
and March 2016), the Company took decisive measures to ensure its ability
by, among other factors, our level of production of oil and natural gas and
to both maximize ongoing projects and to preserve its cash.
the prices we receive from the sale thereof, the success of our exploration
Funding our anticipated capital expenditures relies in part on oil prices
and appraisal drilling program, the number of commercially viable oil
remaining close to our estimates or higher levels and other factors to
and natural gas discoveries made and the quantities of oil and natural
generate sufficient cash flow. Low oil prices affect our revenues, which
gas discovered, the speed with which we can bring such discoveries to
in turn affect our debt capacity and the covenants in our financing
production and the actual cost of exploration, appraisal and development
agreements, as well as the amount of cash we can borrow using our oil
of our oil and natural gas assets.
reserves as collateral, the amount of cash we are able to generate from
current operations and the amount of cash we can obtain from prepayment
Unless we replace our oil and natural gas reserves, our reserves and
agreements. If we are not able to generate the sales which, together with
production will decline over time. Our business is dependent on our
our current cash resources, are sufficient to fund our capital program, we
continued successful identification of productive fields and prospects and
will not be able to efficiently execute our work program, which would cause
the identified locations in which we drill in the future may not yield oil or
us to further decrease our work program and would harm our business
natural gas in commercial quantities.
outlook, investor confidence and our share price.
In addition, actions taken by the company to maximize ongoing projects
Production from oil and gas properties declines as reserves are depleted,
and to reduce expenses, including renegotiations and reduction of oil
with the rate of decline depending on reservoir characteristics. Accordingly,
and gas service contracts and other initiatives such as cost cutting may
our current proved reserves will decline as these reserves are produced. As of
expose us to claims and contingencies from interested parties that may
December 31, 2017, our reserves-to-production (or reserve life) ratio for net
have a negative impact on our business, financial condition, results of
proved reserves in Colombia, Chile, Brazil and Peru was 9.5 years. According
operations and cash flows. If oil prices are lower than expected, we may be
to estimates, if on January 1, 2018 we ceased all drilling and development
unable to meet our contractual obligations with oil and service contracts
activities, including recompletions, refracs and workovers, our proved
and our suppliers. Equally, those third parties may be unable to meet their
developed producing reserves base in Colombia, Chile, Brazil and Peru
contractual obligations to us as a result of the oil price crisis, impacting on
would decline 35% during the first year.
our operations.
In budgeting for our future activities, we have relied on a number of
Our future oil and natural gas reserves and production, and therefore our
assumptions, including, with regard to our discovery success rate, the
cash flows and income, are highly dependent on our success in efficiently
number of wells we plan to drill, our working interests in our prospects,
developing our current reserves and using cost-effective methods to find
the costs involved in developing or participating in the development of a
or acquire additional recoverable reserves. While we have had success in
prospect, the timing of third-party projects and our ability to obtain needed
identifying and developing commercially exploitable fields and drilling
financing with respect to any further acquisitions and the availability of
locations in the past, we may be unable to replicate that success in the
both suitable equipment and qualified personnel. These assumptions are
future. We may not identify any more commercially exploitable fields or
inherently subject to significant business, political, economic, regulatory,
successfully drill, complete or produce more oil or gas reserves, and the
environmental and competitive uncertainties, conditions in the financial
wells which we have drilled and currently plan to drill within our blocks or
markets, contingencies and risks, all of which are difficult to predict and
concession areas may not discover or produce any further oil or gas or may
many of which are beyond our control. In addition, we opportunistically
not discover or produce additional commercially viable quantities of oil or
seek out new assets and acquisition targets to complement our existing
gas to enable us to continue to operate profitably. If we are unable to replace
operations, and have financed such acquisitions in the past through
our current and future production, the value of our reserves will decrease,
GeoPark 43
and our business, financial condition and results of operations will be
fluctuations in foreign currency exchange rates.
materially adversely affected.
We derive a significant portion of our revenues from sales to a few key
fluctuations in foreign currency exchange rates for certain of our expenses in
Although a majority of our net revenues is denominated in US$, unfavorable
customers.
Colombia, Chile, Brazil, Peru and Argentina could have a material adverse effect
on our results of operations. A portion of the cost reductions that we achieved
In Colombia, for the year ended December 31, 2017, we made 100% of our
in 2015 and 2016 (as compared to 2014) were related to the depreciation of
oil sales from operated blocks to C.I. Trafigura Petroleum Colombia S.A.S., a
local currencies, including mainly the Col$, the Ch$ and the Brazilian real. An
leading commodity trading and logistics company (“Trafigura”), representing
appreciation of local currencies can increase our costs and negatively impact
79% of our consolidated revenues for the same period. Sales for the year ended
our results from operations.
December 31, 2017 were made mostly under long-term agreements. For 2018,
all of the oil production from the blocks we operate in Colombia is committed
Furthermore, we have not entered, into derivative transactions to hedge the
to Trafigura under the Trafigura Sales Agreement.
effect of changes in the exchange rate of local currencies to the US$. Because
our Consolidated Financial Statements are presented in US$, we must translate
In Chile, 100% of our crude oil and condensate sales are made to ENAP. For
revenues, expenses and income, as well as assets and liabilities, into US$ at
the year ended December 31, 2017, sales to ENAP represented 5% of our
exchange rates in effect during or at the end of each reporting period.
total revenues. ENAP imports the majority of the oil it refines and partially
supplements those imports with volumes supplied locally by its own operated
Through our Brazilian operations, we are exposed to fluctuations in the
fields and those operated by us. On April 21, 2017, we renewed our sales
real against the US$, as our Brazilian revenues and expenses are mostly
agreement with ENAP. As part of this agreement, ENAP has committed to
denominated in reais. In the past, the Brazilian Central Bank has occasionally
purchase our oil production in the Fell Block in the amounts that we produce,
intervened to control unstable movements in foreign exchange rates. We
subject to the limitation of available storage capacity at the Gregorio Terminal.
cannot predict whether the Brazilian Central Bank or the Brazilian government
The sales agreement provides us with the option to interrupt sales to ENAP
will continue to permit the real to float freely or will intervene in the exchange
periodically if conditions in the export markets allow for more competitive
rate market through the return of a currency band system or otherwise.
price levels. While the agreement renews automatically on an annual basis,
Furthermore, Brazilian law provides that, whenever there is a serious imbalance
we typically make an annual revision jointly with ENAP. In addition, for the
in Brazil’s balance of payments or there are reasons to foresee a serious
year ended December 31, 2017, almost all of our natural gas sales in Chile
imbalance, temporary restrictions may be imposed on remittances of foreign
were made to Methanex Chile SpA., the Chilean subsidiary of the Methanex
capital abroad. We cannot assure you that such measures will not be taken by
Corporation (“Methanex”), a leading global methanol producer, under a
the Brazilian government in the future. The real has experienced frequent and
long-term contract (the “Methanex Gas Supply Agreement”) which expired on
substantial variations in relation to the US$ and other foreign currencies, which
April 30, 2017. In March 2017, we executed a new gas supply agreement with
could materially and adversely affect the growth of the Brazilian economy and
Methanex effective from May 1, 2017 to December 31, 2026. Sales to Methanex
our business, financial condition and results of operations.
represented 5% of our consolidated revenues for the year ended December 31,
2017.
There are inherent risks and uncertainties relating to the exploration and
production of oil and natural gas.
In Brazil, all of our gas and condensate produced in the Manati Field is sold
to Petróleo Brasileiro S.A. (“Petrobras”), the operator of the Manati Field,
Our performance depends on the success of our exploration and
pursuant to a long-term gas off-take contract. See “Item 4. Information on the
production activities and on the existence of the infrastructure that will
Company—B. Business Overview—Significant Agreements—Brazil—Petrobras
allow us to take advantage of our oil and gas reserves. Oil and natural
Natural Gas Purchase Agreement.”
gas exploration and production activities are subject to numerous risks
beyond our control, including the risk that exploration activities will not
If any of our buyers were to decrease or cease purchasing oil or gas from us,
identify commercially viable quantities of oil or natural gas. Our decisions
or if any of them were to decide not to renew their contracts with us or to
to purchase, explore, develop or otherwise exploit prospects or properties
renew them at a lower sales price, this could have a material adverse effect on
will depend in part on the evaluation of seismic and other data obtained
our business, financial condition and results of operations. For example, see
through geophysical, geochemical and geological analysis, production
“Item 4. Information on the Company—B. Business Overview—Significant
data and engineering studies, the results of which are often inconclusive or
Agreements—Colombia” and “Item 4. Information on the Company—B.
subject to varying interpretations.
Business Overview—Significant Agreements—Chile.”
Our results of operations could be materially adversely affected by
our projects may be affected by numerous factors beyond our control.
Furthermore, the marketability of any oil and natural gas production from
44 GeoPark 20-F
These factors include, but are not limited to, proximity and capacity of
make substantial capital expenditures in our business and operations for
pipelines and other means of transportation, the availability of upgrading
the exploration and production of oil and natural gas reserves. See “Item 4.
and processing facilities, equipment availability and government laws and
Information on the Company –B. Business Overview—2018 Strategy and
regulations (including, without limitation, laws and regulations relating to
Outlook.” We incurred capital expenditures of US$106 million and US$39
prices, sale restrictions, taxes, governmental stake, allowable production,
million during the years ended December 31, 2017 and 2016, respectively.
importing and exporting of oil and natural gas, environmental protection
See “Item 5. Operating and Financial Review and Prospects—A. Operating
and health and safety). The effect of these factors, individually or jointly,
Results—Factors Affecting our Results of Operations—Discovery and
cannot be accurately predicted, but may have a material adverse effect on
exploitation of reserves.”
our business, financial condition and results of operations.
The actual amount and timing of our future capital expenditures may differ
There can be no assurance that our drilling programs will produce oil
materially from our estimates as a result of, among other things, commodity
and natural gas in the quantities or at the costs anticipated, or that our
prices, actual drilling results, the availability of drilling rigs and other
currently producing projects will not cease production, in part or entirely.
equipment and services, and regulatory, technological and competitive
Drilling programs may become uneconomic as a result of an increase in
developments. In response to changes in commodity prices, we may increase
our operating costs or as a result of a decrease in market prices for oil and
or decrease our actual capital expenditures. We intend to finance our future
natural gas. Our actual operating costs or the actual prices we may receive
capital expenditures through cash generated by our operations and potential
for our oil and natural gas production may differ materially from current
future financing arrangements. However, our financing needs may require
estimates. In addition, even if we are able to continue to produce oil and
us to alter or increase our capitalization substantially through the issuance of
gas, there can be no assurance that we will have the ability to market our oil
debt or equity securities or the sale of assets.
and gas production. See “—Our inability to access needed equipment and
infrastructure in a timely manner may hinder our access to oil and natural gas
If our capital requirements vary materially from our current plans, we may
markets and generate significant incremental costs or delays in our oil and
require further financing. In addition, we may incur significant financial
natural gas production” below.
indebtedness in the future, which may involve restrictions on other financing
and operating activities. We may also be unable to obtain financing or
Our identified potential drilling location inventories are scheduled over
financing on terms favorable to us. These changes could cause our cost
many years, making them susceptible to uncertainties that could materially
of doing business to increase, limit our ability to pursue acquisition
alter the occurrence or timing of their drilling.
opportunities, reduce cash flow used for drilling and place us at a competitive
disadvantage. A significant reduction in cash flows from operations or the
Our management team has specifically identified and scheduled certain
availability of credit could materially adversely affect our ability to achieve our
potential drilling locations as an estimation of our future multi-year drilling
planned growth and operating results.
activities on our existing acreage. These identified potential drilling locations,
including those without proved undeveloped reserves, represent a significant
Oil and gas operations contain a high degree of risk and we may not be fully
part of our growth strategy.
insured against all risks we face in our business.
Our ability to drill and develop these identified potential drilling locations
Oil and gas exploration and production is speculative and involves a high
depends on a number of factors, including oil and natural gas prices, the
degree of risk and hazards. In particular, our operations may be disrupted
availability and cost of capital, drilling and production costs, the availability
by risks and hazards that are beyond our control and that are common
of drilling services and equipment, drilling results, lease expirations, the
among oil and gas companies, including environmental hazards, blowouts,
availability of gathering systems, marketing and transportation constraints,
industrial accidents, occupational safety and health hazards, technical
refining capacity, regulatory approvals and other factors. Because of the
failures, labor disputes, community protests or blockades, unusual or
uncertainty inherent in these factors, there can be no assurance that the
unexpected geological formations, flooding, earthquakes and extended
numerous potential drilling locations we have identified will ever be drilled or,
interruptions due to weather conditions, explosions and other accidents.
if they are, that we will be able to produce oil or natural gas from these or any
other potential drilling locations.
While we believe that we maintain customary insurance coverage for
companies engaged in similar operations, we are not fully insured against
Our business requires significant capital investment and maintenance
all risks in our business. In addition, insurance that we do and plan to carry
expenses, which we may be unable to finance on satisfactory terms or at all.
may contain significant exclusions from and limitations on coverage. We
Because the oil and natural gas industry is capital intensive, we expect to
believe that the cost of available insurance is excessive relative to the risks
may elect not to obtain certain non-mandatory types of insurance if we
GeoPark 45
presented. The occurrence of a significant event or a series of events against
be expensive to develop, purchase and implement and may not function
which we are not fully insured and any losses or liabilities arising from
as expected. Such uncertainties and operating risks associated with
uninsured or underinsured events could have a material adverse effect on
development projects could have a material adverse effect on our business,
our business, financial condition or results of operations.
results of operations or financial condition.
The development schedule of oil and natural gas projects is subject to cost
Competition in the oil and natural gas industry is intense, which makes it
overruns and delays.
difficult for us to attract capital, acquire properties and prospects, market
oil and natural gas and secure trained personnel.
Oil and natural gas projects may experience capital cost increases and
overruns due to, among other factors, the unavailability or high cost of drilling
We compete with the major oil and gas companies engaged in the exploration
rigs and other essential equipment, supplies, personnel and oil field services.
and production sector, including state-owned exploration and production
The cost to execute projects may not be properly established and remains
companies that possess substantially greater financial and other resources
dependent upon a number of factors, including the completion of detailed
than we do for researching and developing exploration and production
cost estimates and final engineering, contracting and procurement costs.
technologies and access to markets, equipment, labor and capital required
Development of projects may be materially adversely affected by one or more
to acquire, develop and operate our properties. We also compete for the
of the following factors:
• shortages of equipment, materials and labor;
acquisition of licenses and properties in the countries in which we operate.
• fluctuations in the prices of construction materials;
Our competitors may be able to pay more for productive oil and natural
• delays in delivery of equipment and materials;
gas properties and exploratory prospects and to evaluate, bid for and
•
labor disputes;
• political events;
• title problems;
• obtaining easements and rights of way;
• blockades or embargoes;
•
litigation;
purchase a greater number of properties and prospects than our financial or
personnel resources permit. Our competitors may also be able to offer better
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
• compliance with governmental laws and regulations, including
acquiring prospective reserves, developing reserves, marketing hydrocarbons,
environmental, health and safety laws and regulations;
attracting and retaining quality personnel or raising additional capital, which
• adverse weather conditions;
• unanticipated increases in costs;
• natural disasters;
• accidents;
• transportation;
could have a material adverse effect on our business, financial condition or
results of operations. See “Item 4. Information on the Company—B. Business
Overview—Our competition.”
Our estimated oil and gas reserves are based on assumptions that may
• unforeseen engineering and drilling complications;
prove inaccurate.
• environmental or geological uncertainties; and
• other unforeseen circumstances.
Our oil and gas reserves estimates in Colombia, Chile, Brazil, and Peru as
of December 31, 2017 are based on the D&M Reserves Report. Although
Any of these events or other unanticipated events could give rise to delays in
classified as “proved reserves,” the reserves estimates set forth in the D&M
development and completion of our projects and cost overruns.
Reserves Reports are based on certain assumptions that may prove inaccurate.
For example, in 2017, the drilling and completion cost for the exploratory well
included oil and gas sales prices determined according to SEC guidelines,
Río Grande Oeste x-1 in our CN-V Block in Argentina was originally estimated
future expenditures and other economic assumptions (including interests,
at US$4.2 million, but the actual cost was US$5.5 million, mainly due to
royalties and taxes) as provided by us.
mechanical issues related to failures with an electric submersible pump, as
well as testing of additional formations which had not been budgeted.
Oil and gas reserves engineering is a subjective process of estimating
DeGolyer and MacNaughton’s primary economic assumptions in estimates
Delays in the construction and commissioning of projects or other technical
and estimates of other engineers may differ materially from those set out
difficulties may result in future projected target dates for production being
herein. Numerous assumptions and uncertainties are inherent in estimating
delayed or further capital expenditures being required. These projects
quantities of proved oil and gas reserves, including projecting future rates of
may often require the use of new and advanced technologies, which can
production, timing and amounts of development expenditures and prices of
oil and gas, many of which are beyond our control. Results of drilling, testing
accumulations of oil and gas that cannot be measured in an exact way,
46 GeoPark 20-F
and production after the date of the estimate may require revisions to be
produce in Chile. We rely upon the continued good condition, maintenance
made. For example, if we are unable to sell our oil and gas to customers, this
and accessibility of the roads we use to deliver the crude oil we produce. If
may impact the estimate of our oil and gas reserves. Accordingly, reserves
the condition of these roads were to deteriorate or if they were to become
estimates are often materially different from the quantities of oil and gas that
inaccessible for any period of time, this could delay delivery of crude oil in Chile
are ultimately recovered, and if such recovered quantities are substantially
and materially harm our business.
lower than the initial reserves estimates, this could have a material adverse
impact on our business, financial condition and results of operations.
In the Fell Block, we depend on ENAP-owned gas pipelines to deliver the gas
we produce to Methanex, the sole purchaser of the gas we produce. If ENAP’s
Our inability to access needed equipment and infrastructure in a timely
pipelines were unavailable, this could have a materially adverse effect on our
manner may hinder our access to oil and natural gas markets and generate
ability to deliver and sell our product to Methanex, which could have a material
significant incremental costs or delays in our oil and natural gas production.
adverse effect on our gas sales. In addition, gas production in some areas in
the Tierra del Fuego Blocks and the Tranquilo Block could require us to build a
Our ability to market our oil and natural gas production depends substantially
new network of gas pipelines in order for us to be able to deliver our product to
on the availability and capacity of processing facilities, oil tankers,
market, which could require us to make significant capital investments.
transportation facilities (such as pipelines, crude oil unloading stations and
trucks) and other necessary infrastructure, which may be owned and operated
While Brazil has a well-developed network of hydrocarbon pipelines, storage
by third parties. Our failure to obtain such facilities on acceptable terms or
and loading facilities, we may not be able to access these facilities when
on a timely basis could materially harm our business. We may be required to
needed. Pipeline facilities in Brazil are often full and seasonal capacity
shut down oil and gas wells because access to transportation or processing
restrictions may occur, particularly in natural gas pipelines. Our failure to secure
facilities may be limited or unavailable when needed. If that were to occur, then
transportation or access to pipelines or other facilities once we commence
we would be unable to realize revenue from those wells until arrangements
operations in the concessions we were awarded in Brazil on acceptable terms
were made to deliver the production to market, which could cause a material
or on a timely basis could materially harm our business.
adverse effect on our business, financial condition and results of operations.
In addition, the shutting down of wells can lead to mechanical problems
In Peru, future production in the Morona Block is expected to be transported
upon bringing the production back on line, potentially resulting in decreased
through the existing North Peruvian Pipeline, which was out of service in 2017
production and increased remediation costs. The exploitation and sale of oil
due to technical issues. Though the Peruvian government is implementing
and natural gas and liquids will also be subject to timely commercial processing
a program to maintain the pipeline, future technical issues, other general
and marketing of these products, which depends on the contracting, financing,
infrastructure problems or social unrest affecting pipeline operation may
building and operating of infrastructure by third parties.
adversely affect the recoverability of our future investments, our future
production or revenues related to the Morona Block.
In Colombia, producers of crude oil have historically suffered from tanker
transportation logistics issues and limited storage capacity, which cause delays
In addition, as the Morona Block is located in a remote area of the tropical
in delivery and transfer of title of crude oil. Such capacity issues in Colombia
rainforest, the development of the project involves that significant
may require us to transport crude from our Colombian operations via truck,
infrastructure has to be built, as processing facilities, storages tanks and an
which may increase the costs of those operations. Road infrastructure is limited
approximately 97 km pipeline from the site to the North Peruvian Pipeline.
in certain areas in which we operate, and certain communities have used and
Also, as there are no roads available in the surrounding area, logistics will be
may continue to use road blockages, which can sometimes interfere with our
performed by helicopters or barges during specific seasons of the year. These
operations in these areas. For example, in 2017, the main delivery point for the
issues may lead us to incur significant costs or investments that may not be
Colombian production was Oleoducto de Los Llanos “ODL.” Between November
recoverable through our commercial activities in the Morona Block.
8, 2017 and November 11, 2017, a disruption of the operation of this pipeline
occurred and affected its capacity to transport any volume of crude oil. Our
Our use of seismic data is subject to interpretation and may not accurately
Colombian production was impacted by approximately 5,800 bbls during that
identify the presence of oil and natural gas.
period. Although we were able to increase the delivery volumes the following
days to mitigate the impact, we cannot assure you we would be able to do so
Even when properly used and interpreted, seismic data and visualization
in the future.
techniques are tools only used to assist geoscientists in identifying subsurface
structures as well as eventual hydrocarbon indicators, and do not enable
In Chile, we transport the crude oil we produce in the Fell Block by truck to
the interpreter to know whether hydrocarbons are, in fact, present in those
ENAP’s processing, storage and selling facilities at the Gregorio Refinery.
structures. In addition, the use of seismic and other advanced technologies
As of the date of this annual report, ENAP purchases all of the crude oil we
requires significant expenditures and we could incur losses as a result of
GeoPark 47
these expenditures. Because of these uncertainties associated with our
We may suffer delays or incremental costs due to difficulties in negotiations
use of seismic data, some of our drilling activities may not be successful
with landowners and local communities, including native communities,
or economically viable, and our overall drilling success rate or our drilling
where our reserves are located.
success rate for activities in a particular area could decline, which could have a
material adverse effect on us.
Access to the sites where we operate requires agreements (including,
for example, assessments, rights of way and access authorizations) with
Through our Brazilian operations, we face operational risks relating to
landowners and local communities. If we are unable to negotiate agreements
offshore drilling.
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 sites.
Our operations in the BCAM-40 Concession in Brazil may include shallow-
In Chile and in Argentina, for example, we have negotiated the necessary
offshore drilling activity in two areas in the Camamu-Almada Basin, which we
agreements for many of our current operations in the Magallanes Basin and
expect will continue to be operated by Petrobras.
CN-V Block in Mendoza, respectively. In Brazil, in the event that social unrest
Offshore operations are subject to a variety of operating risks and laws and
ability to operate the assets we have acquired or may acquire in our Brazil
continues or intensifies, this may lead to delays or damage relating to our
regulations, including among other things, with respect to environmental,
Acquisitions.
health and safety matters, specific to the marine environment, such as
capsizing, collisions and damage or loss from hurricanes or other adverse
In Colombia, although we have agreements with many landowners and are
weather conditions. These conditions can cause substantial damage to
in negotiations with others, we expect our costs to increase following current
facilities and interrupt production. As a result, we could incur substantial
and future negotiations regarding access to our blocks, as the economic
liabilities, compliance costs, fines or penalties that could reduce or eliminate
expectations of landowners have generally increased, which may delay
the funds available for exploration, development or leasehold acquisitions, or
access to existing or future sites. In addition, the expectations and demands
result in loss of equipment and properties. For example, the Manati Field has
of local communities on oil and gas companies operating in Colombia may
been subject to administrative infraction notices, which have resulted in fines
also increase. As a result, local communities have demanded that oil and
against Petrobras in an aggregate amount of approximately US$12 million,
gas companies invest in remediating and improving public access roads,
all of which are pending a final decision of the Brazilian Institute for the
compensate them for any damages related to use of such roads and, more
Environment and Natural Renewable Resources (Instituto Brasileiro do Meio-
generally, invest in infrastructure that was previously paid for with public
Ambiente e dos Recursos Naturais Renováveis). Although the administrative
funds. Due to these circumstances, oil and gas companies in Colombia,
fines were filed against Petrobras, as a party to the concession agreement
including us, are now dealing with increasing difficulties resulting from
governing the Manati Field, we may be liable up to our participation interest
instances of social unrest, temporary road blockages and conflicts with
of 10%.
landowners.
Additionally, offshore drilling generally requires more time and more
There can be no assurance that disputes with landowners and local
advanced drilling technologies, involving a higher-risk of technological
communities will not delay our operations or that any agreements we reach
failure and usually higher drilling costs. Offshore projects often lack proximity
with such landowners and local communities in the future will not require us
to existing oilfield service infrastructure, necessitating significant capital
to incur additional costs, thereby materially adversely affecting our business,
investment in flow line infrastructure before we can market the associated oil
financial condition and results of operations. Local communities may also
or gas of a commercial discovery, increasing both the financial and operational
protest or take actions that restrict or cause their elected government to
risk involved with these operations. Because of the lack and high cost of
restrict our access to the sites of our operations, which may have a material
infrastructure, some offshore reserve discoveries may never be produced
adverse effect on our operations at such sites.
economically.
Further, because we are not the operator of our offshore fields, all of these
Though we have already signed certain agreements with native communities
risks may be heightened since they are outside of our control. We have a
authorizing the execution of the Environmental Impact Assessment for
10% interest in the Manati Field which limits our operating flexibility in such
the Morona Project, similar projects in the Peruvian rainforest have faced
offshore fields. See “—We are not, and may not be in the future, the sole owner
significant social conflicts and work delays due to community claims. Social
or operator of all of our licensed areas and do not, and may not in the future,
conflicts or community claims could adversely affect the recoverability of our
hold all of the working interests in certain of our licensed areas. Therefore, we
future investments, our future production and revenues related to the Morona
In Peru, the Morona Block is located in land inhabited by native communities.
may not be able to control the timing of exploration or development efforts,
Block.
associated costs, or the rate of production of any non-operated and, to an
extent, any non-wholly-owned, assets.”
48 GeoPark 20-F
Under the terms of some of our various CEOPs, E&P Contracts and
A significant amount of our reserves or production have been derived from
concession agreements, we are obligated to drill wells, declare any
our operations in certain blocks, including the Llanos 34 Block in Colombia,
discoveries and file periodic reports in order to retain our rights and
the Fell Block in Chile, the BCAM-40 Concession in Brazil and the Morona
establish development areas. Failure to meet these obligations may result in
Block in Peru.
the loss of our interests in the undeveloped parts of our blocks or concession
areas.
For the year ended December 31, 2017, the Llanos 34 Block contained 66% of
our net proved reserves and generated 75% of our production, the Fell Block
In order to protect our exploration and production rights in our license areas,
contained 8% of our net proved reserves and generated 10% of our total
we must meet various drilling and declaration requirements. In general, unless
production, the BCAM-40 Concession contained 4% of our net proved reserves
we make and declare discoveries within certain time periods specified in our
and generated 11% of our production and the Morona Block contained 20% of
various special operation contracts (Contratos Especiales de Operación para
our net proved reserves. While our continuing expansion with new exploratory
la Exploración y Explotación de Yacimientos de Hidrocarburo; hereinafter
blocks incorporated in our portfolio mean that the above mentioned blocks
“CEOP”), E&P Contracts and concession agreements, our interests in the
may be expected to be a less significant component of our overall business,
undeveloped parts of our license areas may lapse. Should the prospects we
we cannot be sure that we will be able to continue diversifying our reserves
have identified under these contracts and agreements yield discoveries,
and production. Resulting from these, any government intervention,
we may face delays in drilling these prospects or be required to relinquish
impairment or disruption of our production due to factors outside of our
these prospects. The costs to maintain or operate the CEOPs, E&P Contracts
control or any other material adverse event in our operations in such blocks
and concession agreements over such areas may fluctuate and may increase
would have a material adverse effect on our business, financial condition and
significantly, and we may not be able to meet our commitments under such
results of operations.
contracts and agreements on commercially reasonable terms or at all, which
may force us to forfeit our interests in such areas. For example, in 2016, after
Our contracts in obtaining rights to explore and develop oil and natural
fulfilling the committed exploratory commitments, five exploratory blocks
gas reserves are subject to contractual expiration dates and operating
were relinquished to the ANP. See “Item 4. Information on the Company—B.
conditions, and our CEOPs, E&P Contracts and concession agreements are
Business Overview—Our operations—Operations in Brazil.”
subject to early termination in certain circumstances.
In Peru, the rights to explore and produce hydrocarbons are granted through
Under certain CEOPs, E&P Contracts and concession agreements to which
a license contract signed with Perupetro. The scope and schedule of such
we are or may in the future become parties, we are or may become subject
development will depend on us and Petroperu. The license contract could
to guarantees to perform our commitments and/or to make payment for
be terminated by Perupetro if the development obligations included in
other obligations, and we may not be able to obtain financing for all such
such agreement are not fulfilled. In addition, there is also an exploratory
obligations as they arise. If such obligations are not complied with when
commitment consisting of the drilling of one exploratory well every two and
due, in addition to any other remedies that may be available to other parties,
a half years. Failure to fulfill the exploratory commitment will lead to acreage
this could result in cancelation of our CEOPs, E&P Contracts and concession
relinquishment materially affecting the project. Moreover, we have entered
agreements or dilution or forfeiture of interests held by us. As of December
into a Joint Investment Agreement with Petroperu by which, subject to the
31, 2017, the aggregate outstanding amount of this potential liability for
economic and technical feasibility of the Morona Project, we are obliged
guarantees was US$28.4 million, mainly related to capital commitments in
to bear 100% of capital cost required to carry out long test to existing well
Isla Norte, Campanario and Flamenco Blocks in Chile, rounds 11, 12 and 13
Situche Central 3X, and if we decide to continue with the project after
concessions in Brazil, the Morona Block in Peru and the Llanos 32, VIM-3, and
that, to the existing well Situche Central 2X. In addition, we are required to
Llanos 34 Blocks in Colombia. See “Item 4. Information on the Company—B.
cover any capital or operational expenditures associated with the project
Business Overview—Our operations” and Note 32(b) to our Consolidated
until December 31, 2020. We expect these expenditures to be substantially
Financial Statements.
reimbursed by Petroperu from revenues associated with future sales. Failure
to fulfill such obligations will result in the loss of our participating interest in
Additionally, certain of the CEOPs, E&P Contracts and concession agreements
the License Contract of the Morona Block, and subject us to possible damage
to which we are or may in the future become a party are subject to set
claims from Petroperu.
expiration dates. Although we may want to extend some of these contracts
beyond their original expiration dates, there is no assurance that we can do
For additional details regarding the status of our operations with respect
so on terms that are acceptable to us or at all, although some CEOPs contain
to our various special contracts and concession agreements, see “Item 4.
provisions enabling exploration extensions.
Information on the Company—B. Business Overview—Our operations.”
In Colombia, our E&P Contracts may be subject to early termination for a
GeoPark 49
breach by the parties, a default declaration, application of any of the contracts’
us for the full value of our assets. Moreover, in the event of early termination of
unilateral termination clauses or pursuant to termination clauses mandated
any concession agreement due to failure to fulfill obligations thereunder, we
by Colombian law. Anticipated termination declared by the ANH results in the
may be subject to fines and/or other penalties.
immediate enforcement of monetary guaranties against us and may result in
an action for damages by the ANH and/or a restriction on our ability to engage
In Peru, License Contracts for hydrocarbon exploitation are in force and will
in contracts with the Colombian government during a certain period of time.
remain in effect for 30 years. This term is non-renewable. With regard to the
See “Item 4. Information on the Company—B. Business Overview—Significant
Morona Block, approximately one-third of the contract term has already
Agreements—Colombia—E&P Contracts.”
elapsed, and twenty years remain. Nevertheless, since May 14, 2013, the
License Contract related to the Morona Block is under force majeure. During a
In Chile, our CEOPs provide for early termination by Chile in certain
force majeure period contract terms are suspended (including the term time)
circumstances, depending upon the phase of the CEOP. For example, pursuant
as long as the party to the contract is fulfilling certain obligations related to
to the Fell Block CEOP, Chile has the right to terminate the CEOP under certain
obtaining environmental permits, as is currently the case with the Morona
circumstances if we fail to perform. If the Fell Block CEOP is terminated in
Block. The term of the agreement will be extended by the same amount of
the exploitation phase, we will have to transfer to Chile, free of charge, any
time it has been suspended by a force majeure event. The concession year
productive wells and related facilities, provided that such transfer does not
expiration is related to approval of environmental impact assessment (EIA)
interfere with our abandonment obligations and excluding certain pipelines
study for project development. The expiration of the License Contract will
and other assets. See “Item 4. Information on the Company—B. Business
occur twenty years after EIA approval. The License Contract is also subject
Overview—Significant Agreements—Chile—CEOPs—Fell Block CEOP.” If the
to early termination in case of our breach of contractual obligations. In
CEOP is terminated early due to a breach of our obligations, we may not be
such an event, all the existing facilities and wells located in the block will
entitled to compensation. Our CEOPs for the Tierra del Fuego Blocks, which
be transferred, without charge, to Perupetro, and we will have to carry out
are in the exploration phase, may be subject to early termination during this
abandonment plans for remediation and restoration of any polluted area in
phase under certain circumstances, including if we fail to perform under
the block and for de-commission the facilities that are no longer required for
the terms of the CEOPs, voluntarily relinquish all areas under the CEOPs or
the block’s operations.
if we cease to operate in the CEOP area or declare bankruptcy. If the Tierra
del Fuego Block CEOPs are terminated within the exploration phase, we
Early termination or nonrenewal of any CEOP, E&P Contract or concession
are released from all obligations under the CEOPs, except for obligations
agreement could have a material adverse effect on our business, financial
regarding the abandonment of fields, if any. See “Item 4. Information on the
situation or results of operations.
Company—B. Business Overview—Significant Agreements—Chile—CEOPs.”
There can be no assurance that the early termination of any of our CEOPs
We may not be able to meet delivery requirements under the crude sale
would not have a material adverse effect on us. In addition, according to
agreements in Colombia.
the Chilean Constitution, Chile is entitled to expropriate our rights in our
CEOPs for reasons of public interest. Although Chile would be required to
We historically sold to several customers in Colombia, including sales made
indemnify us for such expropriation, there can be no assurance that any such
through wellhead or pipeline. For 2018, we expect to sell almost all of our
indemnification will be paid in a timely manner or in an amount sufficient to
Colombian production under long-term agreements with Trafigura. The
cover the harm to our business caused by such expropriation.
Trafigura offtake contract began in March 2016 and expires in December 2018.
In Brazil, concession agreements in the production phase generally may be
The amended Trafigura Agreement sets the current volumes to be delivered
renewed at the ANP’s discretion for an additional period, provided that a
to Trafigura to 12,000 bopd until December 2018. Nonperformance of our
renewal request is made at least 12 months prior to the termination of the
obligations of delivery to Trafigura in terms, amounts and quality of the crude
concession agreement and there has not been a breach of the terms of the
may lead us to pay ship-or-pay commitments in the ODL Pipeline for the
concession agreement. We expect that all our concession agreements will
transport, dilution and download of crude as well as compensation for other
provide for early termination in the event of: (i) government expropriation
costs. Additionally, such nonperformance may lead to early termination of the
for reasons of public interest; (ii) revocation of the concession pursuant to the
crude sales agreement as well as the immediate repayment of any amounts
terms of the concession agreement; or (iii) failure by us or our partners to fulfill
outstanding under the prepayment agreement of up to US$100 million,
all of our respective obligations under the concession agreement (subject to a
as well as compensation for other damages. As of December 31, 2017, the
cure period). Administrative or monetary sanctions may also be applicable, as
outstanding balance was US$10 million, relating to the amount we agreed to
determined by the ANP, which shall be imposed based on applicable law and
prepay Trafigura.
regulations. In the event of early termination of a concession agreement, the
compensation to which we are entitled may not be sufficient to compensate
We sell almost all of our natural gas in Chile to a single customer, who has in
the past temporarily idled its principal facility.
50 GeoPark 20-F
For the year ended December 31, 2017, almost all of our natural gas sales
Company—B. Business Overview—Operations in Colombia, Operations in
in Chile were made to Methanex under a long-term contract, the Methanex
Chile, Operations in Brazil, Operations in Peru and Operations in Argentina.”
Gas Supply Agreement, which expires on December 31, 2026. Under the
agreement, Methanex committed to purchase up to 400,000 SCM/d of gas
In addition, the terms of the joint venture agreements or association
produced by us. For 2018, the commitment was reduced to 315,000 SCM/d,
agreements governing our other partners’ interests in almost all of the blocks
due to the decline in the gas production. We also hold an option to deliver
that are not wholly-owned or operated by us require that certain actions be
up to 15% above this volume. Sales to Methanex represented approximately
approved by supermajority vote. The terms of our other current or future
5% of our consolidated revenues for the year ended December 31, 2017.
license or venture agreements may require at least the majority of working
Methanex also buys gas from ENAP and a consortium that Methanex has
interests to approve certain actions. As a result, we may have limited ability to
formed with ENAP. If Methanex were to decrease or cease its purchase of gas
exercise influence over operations or prospects in the blocks operated by our
from us, this would have a material adverse effect on our revenues derived
partners, or in blocks that are not wholly-owned or operated by us. A breach of
from the sale of gas.
contractual obligations by our partners who are the operators of such blocks
could eventually affect our rights in exploration and production contracts in
Methanex has two methanol producing facilities at its Cabo Negro
some of our blocks in Colombia and Brazil. Our dependence on our partners
production facility, near the city of Punta Arenas in southern Chile. Methanex
could prevent us from realizing our target returns for those discoveries or
relies on local suppliers of natural gas, including ENAP, for its operations.
prospects.
We alone cannot supply Methanex with all the natural gas it requires for its
operations.
Moreover, as we are not the sole owner or operator of all of our properties,
we may not be able to control the timing of exploration or development
In the past, the Methanex plant was idled due to an anticipated insufficient
activities or the amount of capital expenditures and may therefore not be able
supply of natural gas. The supply of natural gas decreased during the winter
to carry out our key business strategies of minimizing the cycle time between
months of 2015 due to the increase in seasonal gas demand from the city
discovery and initial production at such properties. The success and timing of
of Punta Arenas, to which gas producers, including us, gave priority by
exploration and development activities operated by our partners will depend
delivering gas to the city through Methanex which re-sold our gas to ENAP.
on a number of factors that will be largely outside of our control, including:
In May 2017, the Methanex plant shut down because of a technical failure
• the timing and amount of capital expenditures;
which affected our natural gas production and sales for 20 days. See “Item
• the operator’s expertise and financial resources;
4. Information on the Company—B. Business Overview—Marketing and
• approval of other block partners in drilling wells;
delivery commitments—Chile.”
• the scheduling, pre-design, planning, design and approvals of activities and
However, we cannot be sure that Methanex will continue to purchase the
• selection of technology; and
gas from us, including the above committed levels, or that its efforts to
• the rate of production of reserves, if any.
reduce the risk of future shut-downs will be successful, which could have a
processes;
material adverse effect on our gas revenues. Additionally, we cannot be sure
This limited ability to exercise control over the operations on some of our
that Methanex will have sufficient supplies of gas to operate its plant and
license areas may cause a material adverse effect on our financial condition
continue to purchase our gas production or that methanol prices would be
and results of operations.
sufficient to cover the operating costs. We cannot be sure that we would be
able to sell our gas production to other parties or on similar terms, which
LGI, our strategic partner in Chile and Colombia, may not consent to our
could have a material adverse effect on our business, financial condition and
taking certain actions or may eventually decide to sell its interest in our
results of operations.
Chilean and Colombian operations to a third party.
We are not, and may not be in the future, the sole owner or operator of all
We have a strategic partnership with LGI, which has a 20% equity interest
of our licensed areas and do not, and may not in the future, hold all of the
in GeoPark Chile S.A., (a sociedad anónima cerrada incorporated under
working interests in certain of our licensed areas. Therefore, we may not be
the laws of Chile; hereinafter “GeoPark Chile”), a 14% direct equity interest
able to control the timing of exploration or development efforts, associated
in GeoPark TdF S.A. (“GeoPark TdF”) (31.2% taking into account direct
costs, or the rate of production of any non-operated and, to an extent, any
and indirect participation through GeoPark Chile) and a 20% equity
non-wholly-owned, assets.
interest in GeoPark Colombia SAS, through its equity interest in GeoPark
Colombia Coöperatie. Our shareholders’ agreements with LGI in each
As of December 31, 2017, we are not the operator of 21% or sole owner of
of Chile and Colombia provides that we have a right of first offer if LGI
38% of the blocks included in our portfolio. See “Item 4. Information on the
decides to sell any of its interest in GeoPark Chile or GeoPark Colombia
GeoPark 51
Coöperatie. There can be no assurance, however, that we will have the
with these assessments, we perform a review of the subject properties
funds to purchase LGI’s interest in Chile and/or Colombia and that LGI will
that we believe to be generally consistent with industry practices. Our
not decide to sell its shares to a third party whose interests may not be
review and the review of advisors and independent reserves engineers
aligned with ours.
will not reveal all existing or potential problems nor will it permit us or
them to become sufficiently familiar with the properties to fully assess
In addition, our shareholders’ agreements with LGI in Chile and Colombia
their deficiencies and potential recoverable reserves. Inspections may not
contain provisions that require GeoPark Chile and GeoPark Colombia
always be performed on every well, and environmental conditions are not
Coöperatie, the sole shareholder of GeoPark Colombia SAS, to obtain
necessarily observable even when an inspection is undertaken. We, advisors
LGI’s consent before undertaking certain actions. For example, under
or independent reserves engineers may apply different assumptions when
the terms of the shareholders’ agreement with LGI in Colombia, LGI must
assessing the same field. Even when problems are identified, the seller
approve GeoPark Colombia’s annual budget and work programs and
may be unwilling or unable to provide effective contractual protection
mechanisms for funding any such budget or program, the entering into
against all or part of the problems. We often are not entitled to contractual
any borrowings other than those provided in an approved budget or
indemnification for environmental liabilities and acquire properties on
incurred in the ordinary course of business to finance working capital
an “as is” basis. Even in those circumstances in which we have contractual
needs, the granting of any guarantee or indemnity to secure liabilities of
indemnification rights for pre-closing liabilities, it remains possible that
parties other than those of our Colombian subsidiary and disposing of
the seller will not be able to fulfill its contractual obligations. There can be
any material assets other than those provided for in an approved budget
no assurance that problems related to the assets or management of the
and work program.
companies and operations we have acquired, or operations we may acquire
or add to our portfolio in the future, will not arise in future, and these
Additionally, pursuant to our agreement with LGI in Colombia, we
problems could have a material adverse effect on our business, financial
and LGI have agreed to vote our common shares or otherwise cause
condition and results of operations.
GeoPark Colombia Coöperatie to declare dividends only after allowing
for retentions of cash for approved work programs and budgets
Significant acquisitions and other strategic transactions may involve other
capital adequacy requirements, working capital requirements, banking
risks, including:
covenants associated with any loan entered into by GeoPark Colombia
• diversion of our management’s attention to evaluating, negotiating and
Coöperatie and GeoPark Colombia SAS and operational requirements.
integrating significant acquisitions and strategic transactions;
Our inability or failure to obtain LGI’s consent or a delay by LGI in granting
• challenge and cost of integrating acquired operations, information
its consent may restrict or delay the ability of GeoPark Chile, GeoPark TdF
management and other technology systems and business cultures with ours
or GeoPark Colombia to take certain actions, which may have an adverse
while carrying on our ongoing business;
effect on our operations in such countries and on our business, financial
• contingencies and liabilities that could not be or were not identified during
condition and results of operations.
the due diligence process, including with respect to possible deficiencies in
Acquisitions that we have completed and any future acquisitions, strategic
• challenge of attracting and retaining personnel associated with acquired
the internal controls of the acquired operations; and
investments, partnerships or alliances could be difficult to integrate and/or
operations.
identify, could divert the attention of key management personnel, disrupt
our business, dilute stockholder value and adversely affect our financial
For example, we recently acquired a 100% working interest and operatorship
results, including impairment of goodwill and other intangible assets.
of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina.
Our estimates regarding the oil and gas production capabilities of these
One of our principal business strategies includes acquisitions of properties,
blocks could prove to be incorrect. In addition, development and operating
prospects, reserves and leaseholds and other strategic transactions, including
costs may be greater than we expect, and we may not be able to successfully
in jurisdictions in which we do not currently operate. The successful
integrate these blocks. If we fail to realize the benefits we anticipate from this
acquisition and integration of producing properties requires an assessment
or other acquisitions, our results of operations may be adversely affected.
of several factors, including:
• recoverable reserves;
• future oil and natural gas prices;
• development and operating costs; and
It is also possible that we may not identify suitable acquisition targets or
strategic investment, partnership or alliance candidates. Our inability to
identify suitable acquisition targets, strategic investments, partners or
• potential environmental and other liabilities.
alliances, or our inability to complete such transactions, may negatively affect
our competitiveness and growth opportunities. Moreover, if we fail to properly
The accuracy of these assessments is inherently uncertain. In connection
evaluate acquisitions, alliances or investments, we may not achieve the
52 GeoPark 20-F
anticipated benefits of any such transaction and we may incur costs in excess
• the amount and timing of actual production; and
of what we anticipate.
• changes in governmental regulations, taxation or the taxation invariability
provisions in our CEOPs.
Future acquisitions financed with our own cash could deplete the cash and
working capital available to adequately fund our operations. We may also
The timing of both our production and our incurrence of expenses in
finance future transactions through debt financing, the issuance of our equity
connection with the development and production of oil and natural gas
securities, existing cash, cash equivalents or investments, or a combination
properties will affect the timing and amount of actual future net revenues from
of the foregoing. Acquisitions financed with the issuance of our equity
proved reserves, and thus their actual value. In addition, the 10% discount
securities could be dilutive, which could affect the market price of our stock.
factor we use when calculating discounted future net revenues may not be the
Acquisitions financed with debt could require us to dedicate a substantial
most appropriate discount factor based on interest rates in effect from time to
portion of our cash flow to principal and interest payments and could subject
time and risks associated with us or the oil and natural gas industry in general.
us to restrictive covenants
The PN-T-597 Concession Agreement in Brazil may not close.
and may require higher levels of capital expenditures than we currently
The development of our proved undeveloped reserves may take longer
anticipate. Therefore, our proved undeveloped reserves ultimately may not
In Brazil, GeoPark Brasil is a party to a class action filed by the Federal
be developed or produced.
Prosecutor’s Office regarding a concession agreement of exploratory Block
PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and
As of December 31, 2017, approximately 39% of our net proved reserves are
gas bidding round held in November 2013. The Brazilian Federal Court issued
developed. Development of our undeveloped reserves may take longer and
an injunction against the ANP and GeoPark Brasil in December 2013 that
require higher levels of capital expenditures than we currently anticipate.
prohibited GeoPark Brasil’s execution of the concession agreement until the
Additionally, delays in the development of our reserves or increases in costs
ANP conducted studies on whether drilling for unconventional resources would
to drill and develop such reserves will reduce the standardized measure
contaminate the dams and aquifers in the region. On July 17, 2015, GeoPark
value of our estimated proved undeveloped reserves and future net revenues
Brasil, at the instruction of the ANP, signed the concession agreement, which
estimated for such reserves, and may result in some projects becoming
included a clause prohibiting GeoPark Brasil from conducting unconventional
uneconomic, causing the quantities associated with these uneconomic
exploration activity in the area. Despite the clause containing the prohibition,
projects to no longer be classified as reserves. This was due to the uneconomic
the judge in the case concluded that the concession agreement should not
status of the reserves, given the proximity to the end of the concessions for
be executed. Thus, GeoPark Brasil requested that the ANP comply with the
these blocks, which does not allow for future capital investment in the blocks.
decision and annul the concession agreement, which the ANP’s Board did on
There can be no assurance that we will not experience similar delays or
October 9, 2015. The annulment reverted the status of all parties to the status
increases in costs to drill and develop our reserves in the future, which could
quo ante, which maintains GeoPark Brasil’s right to the block.
result in further reclassifications of our reserves.
There is no assurance that we will be able to enter into a concession agreement
We are exposed to the credit risks of our customers and any material
in the PN-T-597 Block that would be favorable to our exploration goals. See
nonpayment or nonperformance by our key customers could adversely
“Item 8—Financial Information—A. Consolidated statements and other
affect our cash flow and results of operations.
financial information—Legal proceedings.”
The present value of future net revenues from our proved reserves will not
significant negative effect on their creditworthiness. Severe financial problems
necessarily be the same as the current market value of our estimated oil
encountered by our customers could limit our ability to collect amounts
and natural gas reserves.
owed to us, or to enforce the performance of obligations owed to us under
Our customers may experience financial problems that could have a
contractual arrangements.
You should not assume that the present value of future net revenues from our
proved reserves is the current market value of our estimated oil and natural
The combination of declining cash flows as a result of declines in commodity
gas reserves. For the year ended December 31, 2017, we have based the
prices, a reduction in borrowing basis under reserves-based credit facilities
estimated discounted future net revenues from our proved reserves on the 12
and the lack of availability of debt or equity financing may result in a
month unweighted arithmetic average of the first-day-of-the-month price for
significant reduction of our customers’ liquidity and limit their ability to make
the preceding 12 months. Actual future net revenues from our oil and natural
payments or perform on their obligations to us.
gas properties will be affected by factors such as:
• actual prices we receive for oil and natural gas;
Furthermore, some of our customers may be highly leveraged, and, in any
• actual cost of development and production expenditures;
event, are subject to their own operating expenses. Therefore, the risk we
GeoPark 53
face in doing business with these customers may increase. Other customers
retain qualified personnel. Our ability to retain our employees is influenced by
may also be subject to regulatory changes, which could increase the risk of
the economic environment and the remote locations of our exploration blocks,
defaulting on their obligations to us. Financial problems experienced by our
which may enhance competition for human resources where we conduct our
customers could result in the impairment of our assets, a decrease in our
activities, thereby increasing our turnover rate. There is strong competition
operating cash flows and may also reduce or curtail our customers’ future
in our industry to hire employees in operational, technical and other areas,
use of our products and services, which may have an adverse effect on our
and the supply of qualified employees is limited in the regions where we
revenues and may lead to a reduction in reserves.
operate and throughout Latin America generally. The loss of any of our key
management or other key employees of our technical team or our inability to
We may not have the capital to develop our unconventional oil and gas
hire and retain new qualified personnel could have a material adverse effect
resources.
on us.
We have identified opportunities for analyzing the potential of
We and our operations are subject to numerous environmental, health and
unconventional oil and gas resources in some of our blocks and concessions.
safety laws and regulations which may result in material liabilities and
Our ability to develop this potential depends on a number of factors,
costs.
including the availability of capital, seasonal conditions, regulatory approvals,
negotiation of agreements with third parties, commodity prices, costs, access
We and our operations are subject to various international, foreign, federal,
to and availability of equipment, services and personnel and drilling results.
state and local environmental, health and safety laws and regulations
In addition, as we have no previous experience in drilling and exploiting
governing, among other things, the emission and discharge of pollutants into
unconventional oil and gas resources, the drilling and exploitation of such
the ground, air or water; the generation, storage, handling, use, transportation
unconventional oil and gas resources depends on our ability to acquire
and disposal of regulated materials; and human health and safety. Our
the necessary technology, to hire personnel and other support needed
operations are also subject to certain environmental risks that are inherent
for extraction or to obtain financing and venture partners to develop such
in the oil and gas industry and which may arise unexpectedly and result
activities. Because of these uncertainties, we cannot give any assurance
in material adverse effects on our business, financial condition and results
as to the timing of these activities, or that they will ultimately result in the
of operations. Breach of environmental laws could result in environmental
realization of proved reserves or meet our expectations for success.
administrative investigations and/or lead to the termination of our concessions
Our operations are subject to operating hazards, including extreme weather
civil environmental actions. For instance, non-governmental organizations
events, which could expose us to potentially significant losses.
seeking to preserve the environment may bring actions against us or other oil
and contracts. Other potential consequences include fines and/or criminal or
Our operations are subject to potential operating hazards, extreme weather
of the countries in which we operate or require us to pay fines. Additionally,
conditions and risks inherent to drilling activities, seismic registration,
in Colombia, recent rulings have provided that environmental licenses are
exploration, production, development and transportation and storage of crude
administrative acts subject to class actions that could eventually result in their
oil, such as explosions, fires, car and truck accidents, floods, labor disputes,
cancellation, with potential adverse impacts on our E&P Contracts.
and gas companies in order to, among other things, halt our activities in any
social unrest, community protests or blockades, guerilla attacks, security
breaches, pipeline ruptures and spills and mechanical failure of equipment at
We have not been and may not be at all times in complete compliance with
our or third-party facilities. Any of these events could have a material adverse
environmental permits that we are required to obtain for our operations and
effect on our exploration and production operations, or disrupt transportation
the environmental and health and safety laws and regulations to which we
or other process-related services provided by our third-party contractors.
are subject. If we fail to comply with such requirements, we could be fined
or otherwise sanctioned by regulators, including through the revocation of
We are highly dependent on certain members of our management and
our permits or the suspension or termination of our operations. If we fail to
technical team, including our geologists and geophysicists, and on our
obtain, maintain or renew permits in a timely manner or at all, our operations
ability to hire and retain new qualified personnel.
could be adversely affected, impeded, or terminated, which could have a
The ability, expertise, judgment and discretion of our management and our
operations. Some environmental licenses related to operation of the Manati
technical and engineering teams are key in discovering and developing oil and
Field production system and natural gas pipeline have expired. However, the
natural gas resources. Our performance and success are dependent to a large
operator submitted in a timely manner a request for renewal of those licenses
extent upon key members of our management and exploration team, and their
and as such this operation is not in default as long as the regulator does not
material adverse effect on our business, financial condition or results of
loss or departure would be detrimental to our future success. In addition, our
state its final position on the renewal.
ability to manage our anticipated growth depends on our ability to recruit and
54 GeoPark 20-F
We have contracted with and intend to continue to hire third parties to perform
below the surface to facilitate a higher flow of hydrocarbons into the
services related to our operations. We could be held liable for some or all
wellbore. We are contemplating such use of hydraulic fracturing in the
environmental, health and safety costs and liabilities arising out of our actions
production of oil and natural gas from certain reservoirs, especially shale
and omissions as well as those of our block partners, third-party contractors,
formations. We currently are not aware of any proposals in Colombia,
predecessors or other operators. To the extent we do not address these costs
Chile, Brazil, Argentina or Peru to regulate hydraulic fracturing beyond the
and liabilities or if we do not otherwise satisfy our obligations, our operations
regulations already in place. However, various initiatives in other countries
could be suspended, terminated or otherwise adversely affected. There is a
with substantial shale gas resources have been or may be proposed
risk that we may contract with third parties with unsatisfactory environmental,
or implemented to, among other things, regulate hydraulic fracturing
health and safety records or that our contractors may be unwilling or unable to
practices, limit water withdrawals and water use, require disclosure of
cover any losses associated with their acts and omissions.
fracturing fluid constituents, restrict which additives may be used, or
implement temporary or permanent bans on hydraulic fracturing. If any
Releases of regulated substances may occur and can be significant. Under
of the countries in which we operate adopts similar laws or regulations,
certain environmental laws and regulations applicable to us in the countries
which is something we cannot predict right now, such adoption
in which we operate, we could be held responsible for all of the costs relating
could significantly increase the cost of, impede or cause delays in the
to any contamination at our past and current facilities and at any third-party
implementation of any plans to use hydraulic fracturing for unconventional
waste disposal sites used by us or on our behalf. Pollution resulting from
oil and gas resources.
waste disposal, emissions and other operational practices might require us to
remediate contamination, or retrofit facilities, at substantial cost. We also could
Our indebtedness and other commercial obligations could adversely affect
be held liable for any and all consequences arising out of human exposure to
our financial health and our ability to raise additional capital, and prevent
such substances or for other damage resulting from the release of hazardous
us from fulfilling our obligations under our existing agreements and
substances to the environment, property or to natural resources, or affecting
borrowing of additional funds.
endangered species or sensitive environmental areas. We are currently required
to, and in the future may need to, plug and abandon sites in certain blocks in
As of December 31, 2017, we had US$426.2 million of total indebtedness
each of the countries in which we operate, which could result in substantial
outstanding on a consolidated basis, consisting primarily of our $425.0
costs.
million Notes due 2024, which we issued in September 2017. Substantially
all of our debt is secured. As of December 31, 2017, our annual debt service
In addition, we expect continued and increasing attention to climate change
obligation was US$30.0 million, which mainly consists of the interest
issues. Various countries and regions have agreed to regulate emissions of
payments under the now repaid Notes due 2020, the now repaid credit
greenhouse gases including methane (a primary component of natural gas)
facility with Itaú BBA International plc and the Notes due 2024. See “Item
and carbon dioxide (a byproduct of oil and natural gas combustion). The
5. Operating and Financial Review and Prospects—B. Liquidity and Capital
regulation of greenhouse gases and the physical impacts of climate change
Resources—Indebtedness.” Using cash provided by the offering of the Notes
in the areas in which we, our customers and the end-users of our products
due 2024, we (i) repurchased US$284.0 million aggregate principal amount
operate could adversely impact our operations and the demand for our
products.
of the outstanding Notes due 2020 in September 2017 and redeemed the
remaining US$16.0 million aggregate principal amount outstanding in
October 2017 and (ii) repaid the credit facility with Itaú BBA International
Environmental, health and safety laws and regulations are complex and change
plc in September 2017. We are also restricted from entering into financial
frequently, and our costs of complying with such laws and regulations may
arrangements in some circumstances such as in Colombia where LGI must
adversely affect our results of operations and financial condition. See “Item
approve GeoPark Colombia’s financial arrangements. See “Item 4. Information
4. Information on the Company—B. Business Overview—Health, safety and
on the Company—B. Business Overview—Significant Agreements—
environmental matters” and “Item 4. Information on the Company—B. Business
Agreements with LGI—LGI Colombia Agreements” for more information.
Overview—Industry and regulatory framework.”
Legislation and regulatory initiatives relating to hydraulic fracturing and
•
limit our capacity to satisfy our obligations with respect to our
other drilling activities for unconventional oil and gas resources could
indebtedness, and any failure to comply with the obligations of any of our
increase the future costs of doing business, cause delays or impede our
debt instruments, including restrictive covenants and borrowing conditions,
plans, and materially adversely affect our operations.
could result in an event of default under the agreements governing our
Our indebtedness could:
indebtedness;
Hydraulic fracturing of unconventional oil and gas resources is a process
• require us to dedicate a substantial portion of our cash flow from operations
that involves injecting water, sand, and small volumes of chemicals into
to the payments on our indebtedness, thereby reducing the availability of our
the wellbore to fracture the hydrocarbon-bearing rock thousands of feet
cash flow to fund acquisitions, working capital, capital expenditures and other
GeoPark 55
general corporate purposes;
In addition, the oil and gas industry has become increasingly dependent
• place us at a competitive disadvantage compared to certain of our
on digital technologies to conduct day-to-day operations including
competitors that have less debt;
certain exploration, development and production activities. For example,
•
•
limit our ability to borrow additional funds;
software programs are used to interpret seismic data, manage drilling rigs,
in the case of our secured indebtedness, lose assets securing such
conduct reservoir modeling and reserves estimation, and to process and
indebtedness upon the exercise of security interests in connection with a
record financial and operating data. We depend on digital technology,
default;
including information systems and related infrastructure as well as cloud
• make us more vulnerable to downturns in our business or the economy;
application and services, to process and record financial and operating data,
and
communicate with our employees and business partners, analyze seismic and
•
limit our flexibility in planning for, or reacting to, changes in our operations
drilling information, estimate quantities of oil and gas reserves and for many
or business and the industry in which we operate.
other activities related to our business. Our business partners, including
The indenture governing our Notes due 2024 includes covenants
and financial institutions, are also dependent on digital technology. As
restricting dividend payments. For a description, see “Item 5. Operating
dependence on digital technologies has increased, cyber incidents, including
and Financial Review and Prospects—B. Liquidity and Capital Resources—
deliberate attacks or unintentional events, have also increased.
vendors, service providers, co-venturers, purchasers of our production,
Indebtedness—Notes due 2024.”
A cyber-attack could include gaining unauthorized access to digital systems
As a result of these restrictive covenants, we are limited in the manner
for purposes of misappropriating assets or sensitive information, corrupting
in which we conduct our business, and we may be unable to engage
data, or causing operational disruption, or result in denial-of-service on
in favorable business activities or finance future operations or capital
websites. Our technologies, systems, networks, and those of our business
needs. We have in the past been unable to meet incurrence tests under
partners may become the target of cyber-attacks or information security
the indenture governing our now repaid Notes due 2020, which limited
breaches that could result in the unauthorized release, gathering, monitoring,
our ability to incur indebtedness. Failure to comply with the restrictive
misuse, loss or destruction of proprietary and other information, or other
covenants included in our Notes due 2024 would not trigger an event of
disruption of our business operations. Our employees have been and will
default.
continue to be targeted by parties using fraudulent “spam” and “phishing”
emails to misappropriate information or to introduce viruses or other
Similar restrictions could apply to us and our subsidiaries when we
malware through “trojan horse” programs to our computers. These emails
refinance or enter into new debt agreements which could intensify the risks
appear to be legitimate emails sent by us but direct recipients to fake
described above.
websites operated by the sender of the email or request that the recipient
send a password or other confidential information through email or
Our business could be negatively impacted by security threats, including
download malware. Despite our efforts to mitigate “spoof” and “phishing”
cybersecurity threats as well as other disasters, and related disruptions.
emails through education, “spoof” and “phishing” activities remain a serious
problem that may damage our information technology infrastructure.
Our business processes depend on the availability, capacity, reliability
and security of our information technology infrastructure and our ability
Certain cyber incidents, such as surveillance, may remain undetected for
to expand and continually update this infrastructure in response to
an extended period. A cyber incident involving our information systems
our changing needs. It is critical to our business that our facilities and
and related infrastructure, or that of our business partners, could disrupt
infrastructure remain secure. Although we have implemented internal control
our business plans and negatively impact our operations. Although to date
procedures to assure the security of our data, we cannot guarantee that these
we have not experienced any significant cyber-attacks, there can be no
measures will be sufficient for this purpose. The ability of the information
assurance that we will not be the target of cyber-attacks in the future or suffer
technology function to support our business in the event of a security breach
such losses related to any cyber-incident. As cyber threats continue to evolve,
or a disaster such as fire or flood and our ability to recover key systems and
we may be required to expend significant additional resources to continue to
information from unexpected interruptions cannot be fully tested and there
modify or enhance our protective measures or to investigate and remediate
is a risk that, if such an event actually occurs, we may not be able to address
any information security vulnerabilities.
immediately the repercussions of a breach. In the event of a breach, key
information and systems may be unavailable for a number of days leading to
Risks relating to the countries in which we operate
an inability to conduct our business or perform some business processes in a
timely manner. We have implemented strategies to mitigate the impact from
Our operations may be adversely affected by political and economic
these types of events.
circumstances in the countries in which we operate and in which we may
operate in the future.
56 GeoPark 20-F
All of our current operations are located in South America. If local, regional
production activities may be substantially affected by factors which could have
or worldwide economic trends adversely affect the economy of any of the
a material adverse effect on our results of operations and financial condition. We
countries in which we have investments or operations, our financial condition
cannot guarantee that current programs and policies that apply to the oil and
and results from operations could be adversely affected.
gas industry will remain in effect.
Oil and natural gas exploration, development and production activities are
Our operations may also be adversely affected by laws and policies of the
subject to political and economic uncertainties (including but not limited to
jurisdictions, including Bermuda, Colombia, Chile, Brazil, Peru, Argentina, Spain,
changes in energy policies or the personnel administering them), changes
the United Kingdom, the Netherlands and other jurisdictions in which we do
in laws and policies governing operations of foreign-based companies,
business, that affect foreign trade and taxation, and by uncertainties in the
expropriation of property, cancellation or modification of contract rights,
application of, possible changes to (or to the application of) tax laws in these
revocation of consents or approvals, the obtaining of various approvals
jurisdictions. For example, in 2016 the Colombian government introduced tax
from regulators, foreign exchange restrictions, price controls, currency
reforms with provisions that are effective January 1, 2017. See Note 16 to our
fluctuations, royalty increases and other risks arising out of foreign
Consolidated Financial Statements. With regards to Chile, although our CEOPs
governmental sovereignty, as well as to risks of loss due to civil strife, acts of
have protection against tax changes through invariability tax clauses, potential
war and community-based actions, such as protests or blockades, guerilla
issues may arise on certain aspects not clearly defined in current or future tax
activities, terrorism, acts of sabotage, territorial disputes and insurrection.
reforms.
In addition, we are subject both to uncertainties in the application of the
tax laws in the countries in which we operate and to possible changes in
Changes in any of these laws or policies or the implementation thereof, and
such tax laws (or the application thereof ), each of which could result in an
uncertainty over potential changes in policy or regulations affecting any
increase in our tax liabilities. These risks are higher in developing countries,
of the factors mentioned above or other factors in the future may increase
such as those in which we conduct our activities.
the volatility of domestic securities markets and securities issued abroad by
companies operating in these countries, which could materially and adversely
The main economic risks we face and may face in the future because of our
affect our financial position, results of operations and cash flows. Furthermore,
operations in the countries in which we operate include the following:
we may be subject to the exclusive jurisdiction of courts outside the United
• difficulties incorporating movements in international prices of crude oil and
States or may not be successful in subjecting non-U.S. persons to the jurisdiction
exchange rates into domestic prices;
of courts in the United States, which could adversely affect the outcome of
• the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s, Peru’s
such dispute. Changes in tax laws may result in increases in our tax payments,
or Brazil’s relations with multilateral credit institutions, such as the IMF, will
which could materially adversely affect our profitability and increase the
impact negatively on capital controls, and result in a deterioration of the
prices of our products and services, restrict our ability to do business in our
business climate;
existing and target markets and cause our results of operations to suffer. There
• inflation, exchange rate movements (including devaluations), exchange
can be no assurance that we will be able to maintain our projected cash flow
control policies (including restrictions on remittance of dividends), price
and profitability following any increase in taxes applicable to us and to our
instability and fluctuations in interest rates;
• liquidity of domestic capital and lending markets;
• tax policies; and
operations.
The political and economic uncertainty in Brazil along with the ongoing “Lava
• the possibility that we may become subject to restrictions on repatriation of
Jato” investigations regarding corruption at Petrobras may hinder the growth
earnings from the countries in which we operate in the future.
of the Brazilian economy and could have an adverse effect on our business.
In addition, our operations in these areas increase our exposure to risks of
Our Brazilian operations represent 10% of our revenues as of December 31,
guerilla activities, social unrest, local economic conditions, political disruption,
2017. The Brazilian economy has been experiencing a slowdown. Inflation,
civil disturbance, community protests or blockades, expropriation, piracy, tribal
unemployment and interest rates have increased more recently and the
conflicts and governmental policies that may: disrupt our operations; require
Brazilian reais has weakened significantly in comparison to the US$. Our
us to incur greater costs for security; restrict the movement of funds or limit
results of operations and financial condition may be adversely affected by the
repatriation of profits; lead to U.S. government or international sanctions; limit
economic conditions in Brazil.
access to markets for periods of time; or influence the market’s perception of
the risk associated with investments in these countries. Some countries in the
Petrobras and certain other Brazilian companies in the energy and
geographic areas where we operate have experienced, and may experience
infrastructure sectors are facing investigations by the Securities Commission
in the future, political instability, and losses caused by these disruptions may
of Brazil (Comissão de Valores Mobiliários), the U.S. Securities and Exchange
not be covered by insurance. Consequently, our exploration, development and
Commission (the “SEC”), the Brazilian Federal Police and the Brazilian Federal
Prosecutor’s Office in connection with corruption allegations (the “Lava
GeoPark 57
Jato” investigations). Depending on the duration and outcome of such
development and ownership of oil, environmental protection, health
investigations, the companies involved may face downgrades from rating
and safety or labor relations, which may negatively affect our ability to
agencies, funding restrictions and a reduction in their revenues. Given the
undertake exploration and development activities in respect of present
significance of the companies under investigation including Petrobras, this
and future properties, as well as our ability to raise funds to further such
could adversely affect Brazil’s growth prospects and could have a protracted
activities. Any delays in receiving government approvals in such countries
effect on the oil and gas industry. In addition to the recent economic crisis,
may delay our operations or may affect the status of our contractual
protests, strikes and corruption scandals have led to a fall in confidence.
arrangements or our ability to meet contractual obligations.
We depend on maintaining good relations with the respective host
Oil and gas operators are subject to extensive regulation in the countries in
governments and national oil companies in each of our countries of operation.
which we operate.
The success of our business and the effective operation of the fields in each of our
The Colombian, Chilean, Brazilian, Peruvian and Argentine hydrocarbons
countries of operation depend upon continued good relations and cooperation
industries are subject to extensive regulation and supervision by their
with applicable governmental authorities and agencies, including national oil
respective governments in matters such as the environment, social
companies such as Ecopetrol, ENAP, Petrobras, Petroperu and YPF. For instance,
responsibility, tort liability, health and safety, labor, the award of exploration
for the year ended December 31, 2017, 100% of our crude oil and condensate
and production contracts, the imposition of specific drilling and exploration
sales in Chile were made to ENAP, the Chilean state-owned oil company. In
obligations, taxation, foreign currency controls, price controls, capital
addition, our Brazilian operations in BCAM-40 Concession provide us with a long-
expenditures and required divestments. In some countries in which
term off-take contract with Petrobras, the Brazilian state-owned company that
we operate, such as Colombia, we are required to pay a percentage of
covers 100% of net proved gas reserves in the Manati Field, one of the largest
our expected production to the government as royalties. See “Item 4.
non-associated gas fields in Brazil. If we, the respective host governments and the
Information on the Company—B. Business Overview—Industry and
national oil companies are not able to cooperate with one another, it could have
regulatory framework—Colombia” and see Note 32(a) to our Consolidated
an adverse impact on our business, operations and prospects.
Financial Statements.
Oil and natural gas companies in Colombia, Chile, Brazil, Peru and Argentina
For example, in Brazil there is potential liability for personal injury, property
do not own any of the oil and natural gas reserves in such countries.
damage and other types of damages. Failure to comply with these laws and
regulations also may result in the suspension or termination of operations
Under Colombian, Chilean, Brazilian, Peruvian and Argentine law, all
or our being subjected to administrative, civil and criminal penalties, which
onshore and offshore hydrocarbon resources in these countries are owned
could have a material adverse effect on our financial condition and expected
by the respective sovereign. Although we are the operator of the majority
results of operations. We expect to also operate in a consortium in some of
of the blocks and concessions in which we have a working and/or economic
our concessions, which, under the Brazilian Petroleum Law, establishes joint
interest and generally have the power to make decisions as how to market
and strict liability among consortium members, and failure to maintain the
the hydrocarbons we produce, the Chilean, Colombian, Brazilian, Peruvian
appropriate licenses may result in fines from the ANP, ranging from R$10
and Argentine governments have full authority to determine the rights,
to R$500 million. In addition, there is a contractual requirement in Brazilian
royalties or compensation to be paid by or to private investors for the
concession agreements regarding local content, which has become a
exploration or production of any hydrocarbon reserves located in their
significant issue for oil and natural gas companies operating in Brazil given
respective countries.
the penalties related with breaches thereof. The local content requirement
will also apply to the production sharing contract regime. See “Item 4.
If these governments were to restrict or prevent concessionaires, including
Information on the Company—B. Business Overview—Our operations—
us, from exploiting oil and natural gas reserves, or otherwise interfered
Operations in Brazil.”
with our exploration through regulations with respect to restrictions on
future exploration and production, price controls, export controls, foreign
Significant expenditures may be required to ensure our compliance
exchange controls, income taxes, expropriation of property, environmental
with governmental regulations related to, among other things, licenses
legislation or health and safety, this could have a material adverse effect on
for drilling operations, environmental matters, drilling bonds, reports
our business, financial condition and results of operations.
concerning operations, the spacing of wells, unitization of oil and natural gas
Additionally, we are dependent on receipt of government approvals or
permits to develop the concessions we hold in some countries. There can
Colombia has experienced and continues to experience internal security issues
be no assurance that future political conditions in the countries in which
that have had or could have a negative effect on the Colombian economy.
accumulations, local content policy and taxation.
we operate will not result changes to policies with respect to foreign
58 GeoPark 20-F
In 2016, the Colombian government and the Revolutionary Armed Forces
• domestic and international economic, legal and regulatory factors
of Colombia (FARC) signed a peace agreement, pursuant to which the FARC
unrelated to our performance.
agreed to demobilize its troops and to hand over its weapons to a United
• variations in our quarterly operating results;
Nations mission within 180 days. Our business, financial condition and results
• volatility in our industry, the industries of our customers and the global
of operations could be adversely affected by rapidly changing economic or
securities markets;
social conditions, including the Colombian government’s response to current
• changes in our dividend policy;
peace agreements and negotiations with other groups, including the ELN,
• risks relating to our business and industry, including those discussed above;
which may result in legislation that increases our tax burden or that of other
• strategic actions by us or our competitors;
Colombian companies.
• actual or expected changes in our growth rates or our competitors’ growth
rates;
ELN has targeted crude oil pipelines in Colombia, including the Caño Limón-
•
investor perception of us, the industry in which we operate, the investment
Coveñas pipeline, and other related infrastructure, disrupting the activities of
opportunity associated with our common shares and our future performance;
certain oil and natural gas companies and resulting in unscheduled shut-
• adverse media reports about us or our directors and officers;
downs of transportation systems. These activities, their possible escalation
• addition or departure of our executive officers;
and the effects associated with them have had and may have in the future a
• change in coverage of our company by securities analysts;
negative impact on the Colombian economy or on our business, which may
• trading volume of our common shares;
affect our employees or assets.
• future issuances of our common shares or other securities;
In addition, from time to time, community protests and blockades may arise
• the release or expiration of transfer restrictions on our outstanding
near our operations in Colombia, which could adversely affect our business,
common shares.
• terrorist acts;
financial condition or results of operations.
Risks related to our common shares
We have never declared or paid, and do not expect to pay in the
foreseeable future, cash dividends on our common shares, and,
consequently, your only opportunity to achieve a return on your
An active, liquid and orderly trading market for our common shares may not
investment is if the price of our stock appreciates.
develop and the price of our stock may be volatile, which could limit your
ability to sell our common shares.
We have never paid, and do not expect to pay in the foreseeable future,
cash dividends on our common shares. Any decision to pay dividends in the
Our common shares began to trade on the New York Stock Exchange (the
future, and the amount of any distributions, is at the discretion of our board of
“NYSE”) on February 7, 2014, and as a result have a limited trading history.
directors and our shareholders, and will depend on many factors, such as our
We cannot predict the extent to which investor interest in our company will
results of operations, financial condition, cash requirements, prospects and
maintain an active trading market on the NYSE, or how liquid that market
other factors. Due to losses resulting from the oil price decline, accumulated
will be in the future.
losses amount to US$283.9 million as of December 31, 2017.
The market price of our common shares may be volatile and may be
influenced by many factors, some of which are beyond our control,
We are also subject to Bermuda legal constraints that may affect our ability
including:
to pay dividends on our common shares and make other payments. Under
• our operating and financial performance and identified potential drilling
the Companies Act, 1981 (as amended) of Bermuda (“Bermuda Companies
locations, including reserve estimates;
Act”), we may not declare or pay a dividend if there are reasonable grounds
• quarterly variations in the rate of growth of our financial indicators, such as
for believing that we are, or would after the payment be, unable to pay our
net income per common share, net income and revenues;
liabilities as they become due or that the realizable value of our assets would
• changes in revenue or earnings estimates or publication of reports by
thereafter be less than our liabilities. We are also subject to contractual
equity research analysts;
• fluctuations in the price of oil or gas;
restrictions under certain of our indebtedness.
• speculation in the press or investment community;
We are a holding company and our only material assets are our equity
• sales of our common shares by us or our shareholders, or the perception
interests in our operating subsidiaries and our other investments; as a
that such sales may occur;
•
involvement in litigation;
• changes in personnel;
• announcements by the company;
result, our principal source of revenue and cash flow is distributions from
our subsidiaries; our subsidiaries may be limited by law and by contract,
including our and their agreements with LGI, in making distributions to us.
GeoPark 59
As a holding company, our only material assets are our cash on hand, the
shares were outstanding as of December 31, 2017. We cannot predict the
equity interests in our subsidiaries and other investments. Our principal
size of future issuances of our common shares or the effect, if any, that
source of revenue and cash flow is distributions from our subsidiaries. Thus,
future sales and issuances of shares would have on the market price of our
our ability to service our debt, finance acquisitions and pay dividends to our
common shares.
stockholders in the future is dependent on the ability of our subsidiaries
to generate sufficient net income and cash flows to make upstream cash
Provisions of the Notes due 2024 could discourage an acquisition of us by
distributions to us. Our subsidiaries are and will be separate legal entities,
a third party.
and although they may be wholly-owned or controlled by us, they have
no obligation to make any funds available to us, whether in the form of
Certain provisions of the Notes due 2024 could make it more difficult or
loans, dividends, distributions or otherwise. The ability of our subsidiaries
more expensive for a third party to acquire us, or may even prevent a third
to distribute cash to us will also be subject to, among other things,
party from acquiring us. For example, upon the occurrence of a fundamental
restrictions that are contained in our subsidiaries’ financing and joint
change, holders of the Notes due 2024 will have the right, at their option, to
venture agreements, availability of sufficient funds in such subsidiaries
require us to repurchase all of their notes at a purchase price equal to 101% of
and applicable state laws and regulatory restrictions. Claims of creditors
the principal amount thereof plus any accrued and unpaid interest (including
of our subsidiaries generally will have priority as to the assets of such
any additional amounts, if any) to the date of purchase. By discouraging an
subsidiaries over our claims and claims of our creditors and stockholders.
acquisition of us by a third party, these provisions could have the effect of
To the extent the ability of our subsidiaries to distribute dividends or other
depriving the holders of our common shares of an opportunity to sell their
payments to us could be limited in any way, our ability to grow, pursue
common shares at a premium over prevailing market prices.
business opportunities or make acquisitions that could be beneficial to our
businesses, or otherwise fund and conduct our business could be materially
Certain shareholders have substantial control over us and could limit your
limited.
ability to influence the outcome of key transactions, including a change of
We may not be able to fully control the operations and the assets of
control.
our joint ventures and we may not be able to make major decisions or
Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief
take timely actions with respect to our joint ventures unless our joint
Executive Officer, Mr. Jamie Coulter, director, and Mr. Juan Cristóbal Pavez,
venture partners agree. For example, we have entered into a shareholders’
director, control 32.3% of our outstanding common shares as of March 15,
agreement and members’ agreement with LGI in Chile and Colombia,
2018, holding the shares either directly or through privately held funds. As
respectively, that set the bases for the amount of dividends to be declared
a result, these shareholders, if acting together, would be able to influence
or returned to us, certain aspects related to the management of our Chilean
or control matters requiring approval by our shareholders, including the
and Colombian businesses, respectively, the incurrence of indebtedness,
election of directors and the approval of amalgamations, mergers or other
liens and our ability to sell certain assets. See “—Risks relating to our
extraordinary transactions. They may also have interests that differ from
business—LGI, our strategic partner in Chile and Colombia, may not consent
yours and may vote in a way with which you disagree and which may
to our taking certain actions or may eventually decide to sell its interest
be adverse to your interests. The concentration of ownership may have
in our Chilean and Colombian operations to a third party.” We may, in the
the effect of delaying, preventing or deterring a change of control of our
future, enter into other joint venture agreements imposing additional
company, could deprive our stockholders of an opportunity to receive a
restrictions on our ability to pay dividends.
premium for their common shares as part of a sale of our company and
Sales of substantial amounts of our common shares in the public market, or
Major Shareholders and Related Party Transactions—A. Major shareholders”
the perception that these sales may occur, could cause the market price of
for a more detailed description of our share ownership.
might ultimately affect the market price of our common shares. See “Item 7.
our common shares to decline.
We may issue additional common shares or convertible securities in the
and NYSE governance standards than domestic U.S. issuers. This may
future, for example, to finance potential acquisitions of assets, which we
afford less protection to holders of our common shares, and you may not
intend to continue to pursue. Sales of substantial amounts of our common
receive corporate and company information and disclosure that you are
shares in the public market, or the perception that these sales may occur,
accustomed to receiving or in a manner in which you are accustomed to
As a foreign private issuer, we are subject to different U.S. securities laws
could cause the market price of our common shares to decline. This could
receiving it.
also impair our ability to raise additional capital through the sale of our
equity securities. Under our memorandum of association, we are authorized
As a foreign private issuer, the rules governing the information that we
to issue up to 5,171,949,000 common shares, of which 60,596,219 common
disclose differ from those governing U.S. corporations pursuant to the
60 GeoPark 20-F
Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although
exemption from new or revised accounting standards, and, therefore, we will
we intend to report quarterly financial results and report certain material
be subject to the same new or revised accounting standards as other public
events, we are not required to file quarterly reports on Form 10-Q or provide
companies that are not emerging growth companies.
current reports on Form 8-K disclosing significant events within four days
of their occurrence and our quarterly or current reports may contain less
Our internal controls over financial reporting may not be effective which
information than required under U.S. filings. In addition, we are exempt
could have a significant and adverse effect on our business and reputation.
from the Section 14 proxy rules, and proxy statements that we distribute will
not be subject to review by the SEC. Our exemption from Section 16 rules
We have evaluated our internal controls for our financial reporting and have
regarding sales of common shares by insiders means that you will have less
determined our controls were effective for the fiscal year ended December
data in this regard than shareholders of U.S. companies that are subject to
31, 2017. As long as we qualify as an “emerging growth company” as defined
the Exchange Act. As a result, you may not have all the data that you are
by the JOBS Act, we will not be required to obtain an auditor’s attestation
accustomed to having when making investment decisions. For example, our
report on our internal controls in future annual reports on Form 20-F as
officers, directors and principal shareholders are exempt from the reporting
otherwise required by Section 404(b) of the Sarbanes-Oxley Act. Accordingly,
and “short-swing” profit recovery provisions of Section 16 of the Exchange
our independent registered public accounting firm did not perform an
Act and the rules thereunder with respect to their purchases and sales of our
audit of our internal control over financial reporting for the fiscal year ended
common shares. The periodic disclosure required of foreign private issuers
December 31, 2017. Had our independent registered public accounting firm
is more limited than that required of domestic U.S. issuers and there may
performed an attestation on our internal control over financial reporting, it is
therefore be less publicly available information about us than is regularly
possible that their opinion on our internal controls could have differed from
published by or about U.S. public companies. See “Item 10. Additional
ours which could harm our reputation and share value.
Information—H. Documents on display.”
As a foreign private issuer, we will be exempt from complying with certain
common shares which could result in the delay or denial of any transfers you
There are regulatory limitations on the ownership and transfer of our
corporate governance requirements of the NYSE applicable to a U.S. issuer,
might seek to make.
including the requirement that a majority of our board of directors consist of
independent directors as well as the requirement that shareholders approve
The Bermuda Monetary Authority (the “BMA”), must specifically approve all
any equity issuance by us which represents 20% or more of our outstanding
issuances and transfers of securities of a Bermuda exempted company like us
common shares. As the corporate governance standards applicable to us
unless it has granted a general permission. We are able to rely on a general
are different than those applicable to domestic U.S. issuers, you may not
permission from the BMA to issue our common shares, and to freely transfer our
have the same protections afforded under U.S. law and the NYSE rules as
common shares as long as the common shares are listed on the NYSE and/or
shareholders of companies that do not have such exemptions.
other appointed stock exchange, to and among persons who are non-residents
of Bermuda for exchange control purposes. Any other transfers remain subject
We are an “emerging growth company,” and we cannot be certain if the
to approval by the BMA and such approval may be denied or delayed.
reduced disclosure requirements applicable to emerging growth companies
will make our common shares less attractive to investors.
We are a Bermuda company, and it may be difficult for you to enforce
judgments against us or against our directors and executive officers.
We are an “emerging growth company,” as defined in the Jumpstart our
Business Startups Act of 2012 (the “JOBS Act”), and for as long as we continue
We are incorporated as an exempted company under the laws of Bermuda
to be an “emerging growth company” we may choose to take advantage of
and substantially all of our assets are located in Colombia, Chile, Argentina,
certain exemptions from various reporting requirements that are applicable to
Brazil and Peru. In addition, most of our directors and executive officers
other public companies that are not “emerging growth companies,” including,
reside outside the United States and all or a substantial portion of the
but not limited to, not being required to comply with the auditor attestation
assets of such persons are located outside the United States. As a result,
requirements of Section 404(b) of the Sarbanes Oxley Act. We cannot predict
it may be difficult or impossible to effect service of process within the
if investors will find our common shares less attractive because we will rely on
United States upon us, or to recover against us on judgments of U.S. courts,
these exemptions. If some investors find our common shares less attractive as
including judgments predicated upon the civil liability provisions of the
a result, there may be a less active trading market for our common shares and
U.S. federal securities laws. Further, no claim may be brought in Bermuda
our share price may be more volatile.
against us or our directors and officers in the first instance for violation
of U.S. federal securities laws because these laws have no extraterritorial
Under the JOBS Act, emerging growth companies can delay adopting new
application under Bermuda law and do not have force of law in Bermuda.
or revised accounting standards until such time as those standards apply to
However, a Bermuda court may impose civil liability, including the
private companies. We have irrevocably elected not to avail ourselves of this
GeoPark 61
Information on the company
possibility of monetary damages, on us or our directors and officers if the
We were incorporated as an exempted company pursuant to the laws of
facts alleged in a complaint constitute or give rise to a cause of action
Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013,
under Bermuda law.
our shareholders approved a change in our name to GeoPark Limited,
effective from July 31, 2013. We maintain a registered office in Bermuda at
There is no treaty in force between the United States and Bermuda
Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda.
providing for the reciprocal recognition and enforcement of judgments in
Our principal executive offices are located at Nuestra Señora de los Ángeles
civil and commercial matters. As a result, whether a United States judgment
179, Las Condes, Santiago, Chile, telephone number +562 2242 9600, Street
would be enforceable in Bermuda against us or our directors and officers
94 N° 11-30, 8, 9, 8th floor, Bogotá, Colombia, telephone number +57 1 743
depends on whether the U.S. court that entered the judgment is recognized
2337, and Florida 981, 1st floor, Buenos Aires, Argentina, telephone number
by the Bermuda court as having jurisdiction over us or our directors and
+5411 4312 9400. Our website is www.geo-park.com. The information on our
officers, as determined by reference to Bermuda conflict of law rules. A
website does not constitute part of this annual report.
judgment debt from a U.S. court that is final and for a sum certain based on
U.S. federal securities laws will not be enforceable in Bermuda unless the
Our Company
judgment debtor had submitted to the jurisdiction of the U.S. court, and
We are a leading independent oil and natural gas exploration and production
the issue of submission and jurisdiction is a matter of Bermuda (not U.S.)
(“E&P”) company with operations in Latin America and a proven track record
law.
of growth in production and reserves since 2006. We operate in Colombia,
Chile, Brazil, Peru and Argentina. We are focused on Latin America because
In addition, and irrespective of jurisdictional issues, the Bermuda courts
we believe it is one of the most important regions globally in terms of
will not enforce a U.S. federal securities law that is either penal or contrary
hydrocarbon potential, with less presence of independent E&P companies
to Bermuda public policy. An action brought pursuant to a public or penal
compared to the United Stated and Canada. In this region, much of the
law, the purpose of which is the enforcement of a sanction, power or right
acreage has historically been controlled or owned by state-owned companies.
at the instance of the state in its sovereign capacity, will not be entertained
We believe that these factors create an opportunity for smaller, more agile
by a Bermuda court. Certain remedies available under the laws of U.S.
companies like us to build a long-term business.
jurisdictions, including certain remedies under U.S. federal securities laws,
would not be available under Bermuda law or enforceable in a Bermuda
We produced a net average of 27.6 mboepd during the year ended December
court, as they would be contrary to Bermuda public policy.
31, 2017, of which 79%, 10% and, 11% were, respectively, in Colombia, Chile,
and Brazil, and of which 83% was oil. As of the third quarter of 2017, we were
The transfer of our common shares may be subject to capital gains taxes
ranked as the second largest private oil operator in Colombia, where we made
pursuant to indirect transfer rules in Chile.
the largest new oil field discovery in the last 20 years. We are the first private
In September 2012, Chile established “indirect transfer rules,” which impose
Petroperu in its return to the upstream business in Peru. We partnered with
taxes, under certain circumstances, on capital gains resulting from indirect
Petrobras in one of Brazil’s largest producing gas fields and we have recently
transfers of shares, equity rights, interests or other rights in the equity,
increased our activities in Argentina with a new oil field discovery and project
oil and gas operator in Chile and we are operating the inaugural project of
control or profits of a Chilean entity, as well as on transfers of other assets and
acquisition.
property of permanent establishments or other businesses in Chile (“Chilean
Assets”). As we indirectly own Chilean Assets, the indirect transfer rules
We have built our company around three principal capabilities:
would apply to transfers of our common shares provided certain conditions
• as an Explorer, which is our ability, experience, methodology and creativity
outside of our control are met. If such conditions were present and as a
to find and develop oil and gas reserves in the subsurface, based on the best
result the indirect transfer rules were to apply to sales of our common shares,
science, solid economics and ability to take the necessary managed risks.
such sales would be subject to indirect transfer tax on the capital gain that
• as an Operator, which is our ability to execute in a timely manner and to
may be determined in each transaction. For a description of the indirect
have the know-how to profitably drill for, produce, treat, transport and sell
transfer rules and the conditions of their application see “Item 10. Additional
our oil and gas – with the drive and persistence to find solutions, overcome
Information—E. Taxation—Chilean tax on transfers of shares.”
obstacles, seize opportunities and achieve results.
ITEM 4. INFORMATION ON THE COMPANY
balance and portfolio of upstream assets in the right hydrocarbon basins in
• as a Consolidator, which is our ability and initiative to assemble the right
the right regions with the right partners and at the right price – coupled with
A. History and development of the company
the visions and skills to transform and improve value above ground.
General
62 GeoPark 20-F
We believe that our risk and capital management policies have enabled
us to compile a geographically diverse portfolio of properties that
Also in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14%
balances exploration, development and production of oil and gas. These
equity interest in GeoPark TdF for US$148.0 million. Our agreement with
attributes have also allowed us to raise capital and to partner with premier
LGI in the Tierra del Fuego Blocks allows us to earn back up to 12% equity
international companies. Most importantly, we believe we have developed a
participation in GeoPark TdF, depending on the success of our operations in
distinctive culture within our organization that promotes and rewards trust,
Tierra del Fuego. See “Item 10. Additional Information—C. Material contracts.”
partnership, entrepreneurship and merit. Consistent with this approach,
all of our employees are eligible to participate in our long-term incentive
In the first quarter of 2012, we moved into Colombia by acquiring three
program, which is the Performance-Based Employee Long-Term Incentive
privately held E&P companies: (i) Winchester Oil and Gas S.A., a Colombian
Program. See “Item 6. Directors, Senior Management and Employees—B.
branch of a sociedad anónima incorporated under the laws of Panama,
Compensation—Equity Incentive Compensation—Performance-Based
which merged into GeoPark Colombia SAS (“Winchester”), (ii) La Luna Oil
Employee Long-Term Incentive Program.”
Company Limited S.A., a sociedad anónima incorporated under the laws of
Panama, which merged into GeoPark Colombia SAS (“Luna”) and (iii) GeoPark
Our regional platform and risk-balanced portfolio has been built following
Cuerva LLC, a limited liability company incorporated under the laws of the
a proactive but conservative long term technical approach, converting
state of Delaware, which merged into GeoPark Colombia SAS (“Cuerva”).
projects into successful value-generating assets.
These acquisitions provided us with an attractive platform in Colombia
History
that currently includes working interests and/or economic interests in 6
blocks located in the Llanos and Magdalena Basins. We have also a right to
We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park,
acquire and operate 85% of the Tiple Block in Colombia, subject to drilling an
who have over 30 years of international oil and natural gas experience,
exploratory well resulting in a commercial discovery.
respectively, and who collectively hold approximately 25% of our common
shares as of the date of this annual report. Mr. O’Shaughnessy currently serves
In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia
as our Chairman and Mr. Park currently serves as our Chief Executive Officer
by making a US$14.9 million capital contribution and assuming the existing
and Deputy Chairman.
debt for an amount of US$4.9 million and the commitment to provide
additional funding to cover LGI’s share of required future investments in
In 2006, after demonstrating our technical expertise and committing to
Colombia. Our agreement with LGI in Colombia allows us to earn back up to
an exploration and development plan, we obtained a 100% operating
12% equity participation in GeoPark Colombia, depending on the success
working interest in the Fell Block from the Republic of Chile. Also in 2006,
of our operations in Colombia. See “Item 10. Additional Information—C.
the International Finance Corporation (the “IFC”), a member of the World
Material contracts.” We believe our partnership with LGI represents a positive
Bank Group, became one of our principal shareholders, and we listed our
independent assessment and validation of the quality of our Chilean and
common shares on AIM, a market operated by the London Stock Exchange
Colombian asset inventory, the extent of our technical and operational
plc, in an initial public offering of common shares outside the United States.
expertise and the ability of our management to structure and effect
Subsequently, in 2008 and 2009, we issued and sold additional common
significant transactions.
shares outside the United States.
In 2008 and 2009, we continued our growth in Chile by acquiring operating
of 7.50% senior secured notes due 2020. We repurchased US$284.0 million
working interests in each of the Otway and Tranquilo Blocks, and by forming
aggregate principal amount of the outstanding Notes due 2020 in September
partnerships with Pluspetrol, Wintershall, Methanex and IFC.
2017 and redeemed the remaining US$16.0 million aggregate principal
In February 2013, we issued US$300.0 million aggregate principal amount
amount outstanding in October 2017.
In 2010, we formed a strategic partnership with LGI, a Korean conglomerate,
to jointly acquire and develop upstream oil and gas projects in Latin America.
In May 2013, we entered into agreements to expand our operations to Brazil.
LGI’s business includes a portfolio of energy and raw material projects,
including oil and gas projects in the Middle East and in Southeast and Central
See “—B. Business Overview—Our operations—Operations in Brazil.”
Asia.
In February 2014, we commenced trading on the NYSE and raised US$98
million (before underwriting commissions and expenses), including the over-
In 2011, ENAP awarded us the opportunity to obtain operating working
allotment option granted to and exercised by the underwriters, through the
interests in each of the Isla Norte, Flamenco and Campanario Blocks in Tierra
issuance of 13,999,700 common shares.
del Fuego, Chile, which we refer to collectively as the Tierra del Fuego Blocks,
and in 2012, jointly with ENAP, we entered into CEOPs with Chile for the
In August 2014, we and Pluspetrol were awarded two exploration licenses
exploration and exploitation of hydrocarbons within these blocks.
in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza
GeoPark 63
Bidding Round in Argentina. The blocks are located in the Neuquén Basin,
In December 2017, we agreed to purchase from Pluspetrol, a private oil and
Argentina’s largest producing hydrocarbon basin.
gas company with strong presence across Latin America, a 100% working
interest and operatorship of the Aguada Baguales, El Porvenir and Puesto
In October 2014, we entered into an agreement to expand our footprint
Touquet blocks in Argentina. We entered into an asset purchase agreement
into Peru through the acquisition of Morona Block in a joint operation with
with Pluspetrol, dated December 18, 2017 (the “APA”). The transaction closed
Petroperu. Petroperu awarded a 75% working interest in and operatorship of
on March 27, 2018.
the Morona Block to us. The agreement was subject to regulatory approval,
which was completed in December 2016, as described below.
See “Item 3. Key Information—D. Risk factors—Risks relating to our business.”
In July 2015, we signed a farm-in agreement with Wintershall for the CN-V
B. Business Overview
Block in Argentina.
In October 2015, we were awarded four exploratory blocks in the Brazilian
(“E&P”), company with operations in Latin America and a proven track record
ANP Bid Round 13 in the Reconcavo and Potiguar Basins.
of growth in production and reserves since 2006. We operate in Colombia,
We are a leading independent oil and natural gas exploration and production
Chile, Brazil, Peru and Argentina.
In December 2015, as part of our long term effort to build an upstream
platform in Mexico, we participated in the Mexican Bid Round 1.3 with Grupo
We have grown our business through drilling, developing and producing oil
Alfa for onshore projects, however, no blocks were awarded.
and gas, winning new licenses and acquiring strategic assets and businesses.
In December 2016, we obtained final regulatory approval for our acquisition
development efforts, drilling program, long-term strategic partnerships and
of the Morona Block in Peru. The Joint Investment and Operating Agreement
alliances with key industry participants, accessing debt and equity capital
dated October 1, 2014 and its amendments were closed on December 1, 2016
markets, developing and retaining a technical team with vast experience
following the issuance of Supreme Decree 031-2016-MEM.
and creating a successful track record of finding and producing oil and gas
Since our inception, we have supported our growth through our prospect
In September 2017, we issued US$425.0 million aggregate principal amount
team of geologists, geophysicists and engineers, including professionals
of 6.50% senior secured notes due 2024. The net proceeds from the Notes
with specialized expertise in the geology of Colombia, Chile, Brazil, Peru and
in Latin America. A key factor behind our success ratio is our experienced
were used by us (i) to make a capital contribution to our wholly-owned
Argentina.
subsidiary, GeoPark Latin America Limited Agencia en Chile, providing it
with sufficient funds to fully repay the 7.50% senior secured notes due 2020
The following map shows the countries in which we have blocks with working
and to pay any related fees and expenses, including a call premium, and (ii)
and/or economic interests as of December 31, 2017. For information on our
for general corporate purposes, including capital expenditures, such as the
working interests in each of these blocks, see “—Our assets” below.
acquisition of Aguada Baguales, El Porvenir and Puesto Touquet blocks in
Neuquen basin in Argentina, and to repay existing indebtedness, including
the Itaú loan. Additionally, we were awarded one exploratory block in the
Brazilian ANP Bid Round 14 in the Potiguar Basin.
64 GeoPark 20-F
Brazil Blocks
POT-T-619
REC-T-94
BCAM-40 Manati
SEAL-T-268
POT-T-747
POT-T-882
POT-T-785
REC-T-93
REC-T-128
PN-T-597(2)
ATLANTIC
OCEAN
Argentina Blocks
Sierra del Nevado
Puelen
CN-V
Colombia Blocks
COLOMBIA
La Cuerva
Llanos 34
Yamu
Llanos 32
Abanico
VIM-3
Tiple(1)
Chile Blocks
Fell
Isla Norte
Campanario
Flamenco
Tranquilo
Peru Block
Morona
PERU
BRAZIL
PA CIFIC
OCEAN
ARGENTINA
CHILE
(1) The Tiple Block is subject to drilling an exploratory well resulting in a
commercial discovery. See “—Our operations—Operations in Colombia.”
(2) The PN-T-597 is still subject to the entry into the concession agreement and
absence of legal impediments, by the ANP in the Parnaíba Basin. See “—Our
operations—Operations in Brazil.”
GeoPark 65
The following table sets forth our net proved reserves and other data as of and
for the year ended December 31, 2017.
For the year ended December 31 2017 (1)
Country
Colombia
Chile
Brazil
Peru
Total
Oil (mmbbl)
Gas (bcf )
(mmboe)
Oil equivalent
65.5
4.1
0.1
18.7
88.4
-
20.0
23.8
-
43.8
65.5
7.5
4.0
18.7
95.7
Revenues
(in thousands
of US$)
263,076
32,738
34,238
—
330,052
%Oil
100%
55%
3%
100%
92%
% of total
revenues
80%
10%
10%
-%
100%
(1) Does not include Argentina, as reserves in Argentina have not been declared
commercially viable as of December 31, 2017.
Our commitment to growth has translated into a strong compounded annual
growth rate (“CAGR”), of 20% for production in the period from 2013 to 2017,
as measured by boepd in the table below.
For the year ended December 31,
Average net production (mboepd)
% oil
2017
27.6
83%
2016
22.4
75%
2015
20.4
74%
2014
19.7
74%
2013
13.5
82%
The following table sets forth our production of oil and natural gas in the blocks
in which we have a working and/or economic interest as of December 31, 2017.
Average daily production
For the year ended December 31, 2017
Oil production
Total crude oil production (bopd)
Natural gas production
Total natural gas production (mcf/day)
Oil and natural gas production
Colombia
Chile
Brazil
Argentina
Total
21,718
1,000
42
414
11,317
17,209
4
-
4
22,764
28,940
27,586
Total oil and natural gas production (mboed)
21,787
2,885
2,910
Our assets
We have a well-balanced portfolio of assets that includes working and/or
economic interests in 24 hydrocarbon blocks, 23 of which are onshore blocks,
including 7 in production as of December 31, 2017. Our assets give us access
to more than 5 million gross exploratory and productive acres.
According to the D&M Reserves Report, as of December 31, 2017, the blocks in
Colombia, Chile, Brazil and Peru in which we have a working interest had 95.7
mmboe of net proved reserves, with 68%, 8%, 4% and 20% of such net proved
reserves located in Colombia, Chile, Brazil and Peru, respectively.
We produced a net average of 27.6 mboepd during the year ended December
31, 2017 of which 79%, 10%, and 11%, were in Colombia, Chile and Brazil,
66 GeoPark 20-F
respectively, and of which 83% was oil.
and plays. See “—Our operations—Operations in Peru.”
We are the operator of a majority of the blocks in which we have a working
Strong cash flow
interest.
Our strengths
We benefit from strong cash flow from operating activities. For the year ended
December 31, 2017, cash provided by operating activities was US$142.2
million. Our cash flow from operating activities plays a significant role in
We believe that we benefit from the following competitive strengths:
funding our capital expenditures.
High quality and diversified asset base built through a successful track
Significant drilling inventory and resource potential from existing asset base
record of organic growth and acquisitions
Our portfolio includes large land holdings in high-potential hydrocarbon basins
Our assets include a diverse portfolio of oil- and natural gas-producing reserves,
and blocks with multiple drilling leads and prospects in different geological
operating infrastructure, operating licenses and valuable geological surveys in
formations, which provide a number of attractive opportunities with varying
Latin America. Throughout our history, we have delivered continuous growth in
levels of risk. Our drilling inventory and our development plans target locations
our production, and our management team has been able to identify under-
that provide attractive economics and support a predictable production profile ,
exploited assets and turn them into valuable, productive assets, and to allocate
as demonstrate by our recent expansions in Colombia and Peru.
resources effectively based on prevailing conditions.
Our geoscience team continues to identify new potential accumulations and
• Chile. In 2002, we acquired a non-operating working interest in the Fell Block
expand our inventory of prospects and drilling opportunities.
in Chile, which at the time had no material oil and gas production or reserves
despite having been actively explored and drilled over the course of more
Platform and Funding
than 50 years. Since 2006, when we became the operator of the Fell Block
We are focused on continued growth utilizing a disciplined capital structure
we performed active exploration and development drilling that resulted in
and a conservative financial philosophy. Due to the volatile nature of
multiple oil and gas discoveries.
commodity prices, fiscal discipline and a focus on disciplined capital structure
• Colombia. In 2012, we acquired assets in Colombia at attractive prices, which
are critical to our business. Our multi-country platform and asset portfolio
gave us access to exploratory and productive acres with high prospects.
is managed through our capital allocation methodology, which also allows
In the Llanos Basin, we pioneered a new play type combining structural
us to quickly adapt and grow. Under this methodology, each country, has
and stratigraphic traps. As a result, in the Llanos 34 Block our average daily
a local team running the business who recommends and advocates for the
production has grown from 0 at the time of acquisition to more than 24,200
projects they want to move forward. The corporate team then ranks all of the
bopd as of December 31, 2017. During 2016, following the successful
projects based on economic, technical and strategic criteria, for the purpose
appraisal drilling in the Tigana and Jacana oil fields, we materially increased
of comparing projects. This also creates opportunities for improvements
the field size.
in the projects that can, in turn, improve their ranking. Finally, once the
• Brazil. In 2014, we acquired Rio das Contas, which gave us a 10% working
production and reserve growth targets are defined, the corporate team
interest in the BCAM-40 Concession, including the shallow-depth offshore
decides the amount of capital to be invested and allocates that capital to the
Manati and Camarão Norte Fields in the Camamu-Almada Basin in the State
highest value-adding projects. As an example, for the 2018 capital allocation
of Bahia, which has consistently self-funded its operations. The Manati Field
process, over 100 projects were presented with a final selection of 50 which
has provided up to 4.5% of total gas produced in Brazil.
comprise our 2018 work program, under the preliminary base capital program.
• Argentina. During 2014, GeoPark and Pluspetrol were awarded two
Additionally, given the inherent oil price volatility, we design our work
exploration licenses in the Sierra del Nevado and Puelen Blocks as part of
programs to be flexible, which means that they can be increased or decreased
the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa
depending on the oil price scenario.
Mendocina de Energía S.A. (“EMESA”). In 2015, we acquired a 50% working
interest in Block CN-V in Mendoza from Wintershall Energía S.A. On December
We have historically benefited from access to debt and equity capital markets
18, 2017, we executed an asset purchase agreement (the “APA”) with
and cash flows from operations, as well as other funding sources, which have
Pluspetrol, a private oil and gas company with strong presence across Latin
provided us with funds to finance our organic growth and the pursuit of
America, to acquire a 100% working interest and operatorship of the Aguada
potential new opportunities.
Baguales, El Porvenir and Puesto Touquet blocks in Argentina. Closing of the
transaction occurred on March 27, 2018.
We generated US$142.2 million and US$82.9 million in cash from operations in
• Peru. In December 2016, we expanded our footprint into Peru by acquiring
the years ended December 31, 2017 and 2016, respectively, and had US$134.8
the Morona Block in a joint venture with Petroperú. The Morona Block
million and US$73.6 million of cash and cash equivalents as of December 31,
contains the Situche Central proven oil field, which we believe offers
2017 and 2016, respectively.
extensive exploration potential with several potential high impact prospects
GeoPark 67
As of December 31, 2017, we had US$426.2 million of total outstanding
enable our technical team to focus its knowledge, skills and experience on
indebtedness and over 99% of our debt had a maturity of 2024.
finding and developing oil and gas fields.
In February 2013, we issued US$300.0 million aggregate principal amount of
In addition, we strive to provide a safe and motivating workplace for
7.50% senior secured notes due 2020 (the “Notes due 2020”). We repurchased
employees in order to attract, protect, retain and train a quality team in the
US$284.0 million aggregate principal amount of the outstanding Notes
competitive marketplace for capable energy professionals.
due 2020 in September 2017, and redeemed the remaining US$16.0 million
aggregate principal amount outstanding in October 2017.
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 February 2014, we commenced trading on the NYSE and raised US$98
drilling and production operations, surface and pipeline construction, legal
million (before underwriting commissions and expenses), including the over-
and regulatory issues, crude oil marketing and transportation and capital
allotment option granted to and exercised by the underwriters, through the
raising for the industry. As of March 15, 2018, Mr. Park held 13.0% of our
issuance of 13,999,700 common shares.
outstanding common shares.
In March 2014, we borrowed US$70.5 million pursuant to a five-year term
Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the oil
variable interest secured loan, secured by the benefits we receive under
and gas business internationally and in North America since 1976. As of March
the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to
15, 2018, Mr. O’Shaughnessy held 11.9% of our outstanding common shares.
6-month LIBOR + 3.9% to finance part of the purchase price of our Rio das
Our management and operating team has an average experience in the
Contas acquisition. In March 2015, we reached an agreement to: (i) extend
energy industry of more than 25 years in companies such as Chevron, ENAP,
the principal payments that were due in 2015 (amounting to approximately
Petrobras, Pluspetrol, San Jorge, Total and YPF, among others. Throughout our
US$15 million), which were divided pro-rata during the remaining principal
history, our management and operating team has had success in unlocking
installments, starting in March 2016 and (ii) to increase the variable interest
unexploited value from previously underdeveloped assets.
rate equal to the 6-month LIBOR + 4.0%. The loan was fully repaid in
September 2017.
In addition, as of March 15, 2018, our executive directors, management and
employees (excluding our founding shareholders, Mr. Gerald E. O’Shaughnessy
In December 2015, we entered into an offtake and prepayment agreement
and Mr. James F. Park) owned 1.7% of our outstanding common shares,
with Trafigura under which we sell and deliver a portion of our Colombian
aligning their interests with those of our shareholders and helping retain
crude oil production to Trafigura. The offtake agreement also provides us
the talent we need to continue to support our business strategy. See “Item
with prepayment of up to US$100 million, subject to applicable volumes
6. Directors, Senior Management and Employees—B. Compensation.” Our
corresponding to the terms of the agreement, in the form of prepaid future oil
founding shareholders are also involved in our daily operations and strategy.
sales. Following subsequent amendments, the availability period under the
prepayment agreement was extended until September 30, 2017.
Long-term strategic partnerships and strong strategic relationships, such
In September 2017, we issued US$425.0 million aggregate principal amount
as with LGI, provide us with additional funding flexibility to pursue further
of 6.50% senior secured notes due 2024 (the “Notes due 2024”). The Notes due
acquisitions
2024 contain incurrence-based limitations on the amount of indebtedness
We benefit from a number of strong partnerships and relationships. In
we can incur See “Item 5. Operating and Financial Review and Prospects—
March 2010, we entered into a framework agreement with LGI, a Korean
Liquidity and capital resources—Indebtedness—Notes due 2024—Covenants.”
conglomerate, to establish a strategic growth partnership to jointly acquire
and invest in oil and natural gas projects throughout Latin America. In May
Highly committed founding shareholders and technical and management
2011, our partnership with LGI was strengthened by LGI’s acquisition of a
teams with proven industry expertise and technically-driven culture
10% equity interest in our existing Chilean operations. In October 2011, LGI
Our founding shareholders, management and operating teams have
acquired an additional 10% equity interest in GeoPark Chile and a 14% equity
significant experience in the oil and gas industry and a proven technical and
interest in GeoPark TdF, and agreed to provide additional financial support for
commercial performance record in onshore fields, as well as complex projects
the further development of the Tierra del Fuego Blocks. In December 2012,
in Latin America and around the world, including expertise in identifying
LGI acquired a 20% equity interest in our Colombian business. As of the date
acquisition and expansion opportunities. Moreover, we differentiate
of this annual report, we believe we are the only independent E&P company
ourselves from other E&P companies through our technically-driven culture,
in which LGI has equity investments in Latin America. See “—Significant
which fosters innovation, creativity and timely execution. Our geoscientists,
Agreements—Agreements with LGI” for additional information relating to
geophysicists and engineers are pivotal to the success of our business
these agreements.
strategy, and we have created an environment and supplied the resources that
68 GeoPark 20-F
In addition, IFC has been one of our shareholders since 2006, holding a 5.7%
We intend to continue to focus on maintaining a risk-balanced portfolio
equity interest in us as of December 31, 2017. In Chile, we believe we have
of assets, combining cash flow-generating assets with upside potential
strong long-term commercial relationships with Methanex and ENAP, and in
opportunities, and on increasing production and reserves through finding,
Colombia, we believe we have developed a strong relationship with Ecopetrol,
developing and producing oil and gas reserves in the countries in which
the Colombian state-owned oil and gas company. In Brazil, we believe we will
we operate. In general, when we enter a new country we look for a mix of
continue to derive benefit from the long-term relationship GeoPark Brazil has
three elements: (i) producing fields, or existing discoveries with near-term
with Petrobras.
possibility of production, to generate cash flows; (ii) an inventory of adjacent
low-risk prospects that can offer medium-term upside for steady growth; and
On February 26, 2018, we announced the formation of a new long-term
(iii) a periphery of higher-risk projects which have a potential to generate
strategic partnership to jointly acquire, invest in, and create value from
significant upside in the long run.
upstream oil and gas projects with the objective of building a large-scale,
economically-profitable and risk-balanced portfolio of assets and operations
For example, in Colombia, we acquired three companies simultaneously
across Latin America with the ONGC Videsh, the wholly-owned subsidiary and
to pursue a risk-balanced approach: one company had mainly proven
international arm of Oil and Natural Gas Corporation Limited (“ONGC”), India’s
production and reserves to provide us with a steady cash flow base, and the
national oil company.
remaining had highly prospective exploration license blocks. Within four years
of entering Colombia, we made multiple oil discoveries in block Llanos 34 that
2018 Strategy and Outlook
allowed us to increase production and cash flows.
Oil prices were volatile since the end of 2014. In preparation for continued
volatility, we have developed multiple scenarios for our 2018 capital
We believe this approach will allow us to sustain continuous and profitable
expenditure program.
growth and also participate in higher risk growth opportunities with upside
Our preliminary base capital program for 2018 considers a reference oil price
assumption of US$50-55 per barrel and calls for approximately US$100-
Maintain financial strength
potential. See “—Our operations.”
110 million to fund our exploration and development, which we intend to
We seek to maintain a prudent and sustainable capital structure and a strong
fund through cash flows from operations and cash-in-hand, to be allocated
financial position to allow us to maximize the development of our assets
approximately as follows:
and capitalize on business opportunities as they arise. We intend to remain
• Colombia: US$85-90 million. Focus on Llanos 34 Block to develop, appraise
financially disciplined by limiting substantially all our debt incurrence to
and further explore potential of the Tigana/Jacana oil play and target new
identified projects with repayment sources. We expect to continue benefiting
exploration prospects in Llanos 34 block.
from diverse funding sources such as our partners and customers in addition
• Chile: US$1-2 million. Focus on business optimization as well as
to the international capital markets.
environmental and unconventional studies in the Fell Block.
• Brazil: US$3-4 million. Focus on exploration drilling in onshore blocks.
Our cash flow generation is complemented by our financial hedging program.
• Argentina: US$5-8 million. Focus on exploration drilling in CN-V, Sierra del
During 2016 and 2017, we entered into derivative financial instruments to
Nevado and Puelen blocks in the Neuquen Basin.
manage our exposure to oil price risk. The purpose of our hedging strategy is
• Peru: US$6-9 million. Focus on environmental impact studies and
to establish minimum oil prices to secure stable cash flow and the execution
preliminary engineering works and facilities in the Morona block.
of our work program. For the period commencing January 2017 to December
2017, we hedged 12,000 bopd through a zero premium collar structure
In addition, we have developed downside and upside work program scenarios
with a minimum average Brent price of US$52 per barrel and a maximum
based on different oil prices and project performance. The downside scenario
average price of US$58 per barrel, representing 53% of our oil production
work program considers a reference oil price assumption below US$50
for that period. For the period from January 2018 to March 2018, we have
per barrel and consists of an alternative capital expenditure program of
secured 13,000 bopd with a minimum average price of US$51.4 per barrel
approximately US$50 million-US$90 million consisting mainly of certain
and a maximum average price of US$52.8 per barrel via zero premium collars
low risk and quick cash flow generating projects. The upside scenario work
and three-way hedges (US$10/bbl wide put spread and call). For the period
program considers a reference oil price assumption of US$60 per barrel
from April 2018 to June 2018, we have secured 10,000 bopd with a minimum
or higher and consists of an alternative capital expenditure program of
average price of US$52.4 per barrel and a maximum average price of US$60.3
approximately US$120 million-US$150 million to be selected from identified
per barrel via zero premium collars and three-way hedges (US$10/bbl wide
projects designed to increase reserves and production.
put spread and call). For the period commencing July 2018 to September
2018, we have secured 5,000 bopd with a minimum average price of US$53
Continue to grow a risk-balanced asset portfolio
per barrel and a maximum average price of US$69 per barrel via zero premium
three-way hedges (US$10/bbl wide put spread and call).
GeoPark 69
We believe that by maintaining a disciplined capital structure and
obligations and worked with our service partners to coordinate a smooth and
conservative financial philosophy, including limiting our debt incurrence to
efficient transition to a new plan. This has enabled us to control production
specified projects with repayment sources and our use of financial hedges, we
costs, as our average operating costs for the Llanos 34 Block were US$4.3 per
are positioned to maintain sufficient liquidity and remain flexible in volatile
boe for the year ended December 31, 2017.
commodity price environments. Our financial flexibility also gives us the ability
to pursue new opportunities through future potential acquisitions.
Maintain our commitment to environmental, safety and social responsibility
A major component of our business strategy is our focus on and
Pursue strategic acquisitions in Latin America
commitment to our environmental and social responsibilities, in line with
We have historically benefited from, and intend to continue to grow
the IFC’s standards. We see this as a fundamental element of ensuring long
through, strategic acquisitions in Latin America. These acquisitions
term business initiatives. We are committed to minimizing the impact of
have provided us with additional attractive platforms in the region. Our
our projects on the environment and aim to create mutually beneficial
Colombian acquisitions, for example, highlight our ability to identify
relationships with the local communities in which we operate in order
and execute on attractive growth opportunities, and we have grown to
to enhance our ability to create sustainable value in our projects. These
become the second largest private operator in Colombia. We acquired
commitments are embodied in our in-house designed Environmental, Health,
our interest in the Llanos 34 Block in the first quarter of 2012 for US$30
Safety and Security management program, which we refer to as “S.P.E.E.D.”
million and have achieved 1P reserve growth corresponding to PV-10 of
(Safety, Prosperity, Employees, Environment and Community Development).
US$814 million as of December 31, 2017. Our enhanced regional portfolio,
Our S.P.E.E.D. program was developed in accordance with several international
primarily in investment-grade countries, and strong partnerships position
quality standards, including ISO 14001 for environmental management issues,
us as a regional consolidator. We intend to continue to grow through
OHSAS 18001 for occupational health and safety management issues, ISO
strategic acquisitions and potentially in other countries in Latin America,
26000 for social accountability and workers’ rights issues, and applicable World
which we may consider from time to time. Our acquisition strategy is aimed
Bank standards. See “—Health, safety and environmental matters.”
at maintaining a balanced portfolio of lower-risk cash flow-generating
properties and assets that have upside potential, keeping a balanced mix
During 2016, we began the process of certifying ISO 14001 through programs
of oil- and gas-producing assets (though we expect to remain weighted
related to the efficient use of natural resources and compliance with
towards oil) and focusing on both assets and corporate targets.
environmental regulation. We have also provided training to our staff and the
communities in which we operate with respect to these matters.
Continue to foster a technically-driven culture and to capitalize on local
knowledge
In August 2017, we obtained the certification ISO 14001:2015 for our
We intend to continue to deliberately and collectively pursue strategies
Environmental Management Process (“SGA”) with the following scope:
that maximize value. For this purpose, we intend to continue expanding
“Design, construction, operation, maintenance, modernization and
our technical teams and to foster a culture that rewards talent according
dismantlement of GeoPark Colombia S.A.S.’s facilities, for the performance of
to results. For example, we have been able to maintain the technical teams
exploration and oil and gas production activities in the Llanos 34 and VIM-3
we inherited through our Colombian and Brazilian acquisitions. We believe
blocks, with a commitment to continuously improve our processes.”
local technical and professional knowledge is key to operational and long-
term success and intend to continue to secure local talent as we grow our
Our operations
business in different locations.
We have a well-balanced portfolio of assets that includes working and/or
economic interests in 24 hydrocarbon blocks, 23 of which are onshore blocks,
Maintain a high degree of operatorship to control production costs
including 7 in production as of December 31, 2017, as well as in an additional
As of the date of this annual report, we are and intend to continue to be
shallow-offshore concession in Brazil that includes the Manati Field. In
the operator of a majority of the blocks and concessions in which we have
addition, we have one concession in Brazil, the PN-T-597 Block that is subject
working interests. Operating the majority of our blocks and concessions gives
to the entry into the concession agreement by the ANP. We also have the right
us the flexibility to allocate our capital and resources opportunistically and
to acquire and operate 85% of the Tiple Block in Colombia, subject to drilling
efficiently within a diversified asset portfolio. We believe that this strategy has
an exploratory well resulting in a commercial discovery.
allowed, and will continue to allow, us to leverage our unique culture, focus
on excellence and our talented technical, operating and management teams.
Operations in Colombia
For example, as commodity prices were projected to decline throughout 2015,
Our Colombian assets currently give us access to more than 248,300 gross
we announced in the first quarter of 2015 a decision to shift our development
exploratory and productive acres across 6 blocks in what we believe to be one of
plan primarily to our operations in the Llanos 34 Block to focus on the Llanos
South America’s most attractive oil and gas geographies.
Basin, which had demonstrated strong returns on capital. Our operating team
reacted quickly to pivot our operations that were unburdened by drilling
Since we entered Colombia in 2012, we have achieved consistent growth in
70 GeoPark 20-F
our oil production and proved reserves in Colombia, mainly achieved through
successful exploration and development activities we made at our operated
CARIBBEAN SEA
Llanos 34 Block, which as of December 31, 2017 accounts for 95% of our
production and 99% of our proved reserves in Colombia.
PANAMA
The table below shows average production and proved oil reserves (derived
from D&M Reserves Report) in Colombia for the years ended December 31, 2017,
2016 and 2015:
VIM - 3
VENEZUELA
Average net production (mboepd)
Net proved reserves at year-end (mmbbl)
2017
21.8
65.5
2016
15.5
37.3
2015
13.2
30.4
PACIFIC
OCEAN
Yamu
La Cuerva
Abanico
Llanos 32
Tiple
Highlights of the year ended December 31, 2017 related to our operations in
Colombia included:
• Successful drilling campaign with 19 gross wells drilled and put into
production in the Jacana and Tigana oil fields in the Llanos 34 Block;
• Discovery of the new Chiricoca oil field, following the successful drilling and
ECUADOR
testing of the Chiricoca 1 exploration well;
• Discovery of the new Jacamar oil field, located in a fault trend southeast of
the Tigana/Jacana oil fields, following the successful drilling and testing of the
Jacamar 1 exploration well. The well is producing from the Guadalupe formation.
Oil shows during drilling and petrophysical analysis also indicate the potential
Llanos 34
COLOMBIA
PERU
BRAZIL
for hydrocarbon production in the shallower Mirador and the deeper Gacheta
The Tiple Block is subject to drilling an exploratory well resulting in a
formations;
commercial discovery.
• Discovery of the new Curucucu oil field, following the successful drilling and
testing of the Curucucu 1 exploration well. To minimize surface construction
The table summarizes information about the blocks in Colombia in which we
costs and share production facilities, the Curucucu 1 exploration well was drilled
have working interests as of and for the year ended December 31, 2017.
from an existing well pad in the Jacamar oil field. The well was drilled with a
horizontal extension of more than 9,000 feet, representing a record for the
Llanos 34 block;
• Average net production increased by 41%, to 21.8 mboepd in 2017 from 15.5
mboepd in 2016;
• Proved oil reserves increased by 76% to 65.5 mmbbls at year-end 2017, from
37.3 mmbbls at year-end 2016 after producing 7.2 mmbbl;
• Capital expenditures increased by 205% to US$80.0 million in 2017 from
US$26.2 million in 2016; and
• Maintenance of production and operating costs levels per barrel from US$5.4
in 2016 to US$5.6 in 2017.
Our interests in Colombia include working interests and economic interests.
“Working interests” are direct participation interests granted to us pursuant
to an E&P Contract with the ANH, whereas “economic interests” are indirect
participation interests in the net revenues from a given block based on bilateral
agreements with the concessionaires.
The map below shows the location of the blocks in Colombia in which we have
working and/or economic interests.
GeoPark 71
Block
Llanos 34
La Cuerva
Yamú
Gross acres
(thousand
acres)
Working
interest(1)
Partners(2)
Operator
Net proved
reserves
(mmboe)(3)
Production
(boepd)
Basin
Concession
expiration year
Exploration: 2017
82.2
45.0%
Parex
GeoPark
63.6
20,676
Llanos
Exploitation: 2039
24.5
5.6
100.0%
89.5/
100%(4)
—
—
GeoPark
GeoPark
Llanos 32
57.0
12.5%
Parex
Parex
VIM-3
46.9
100%
—
GeoPark
1.1
0.7
0.1
—
585
Llanos
Exploitation: 2038
Exploration: 2014
267
Llanos
Exploration: 2013
Production: 2036
Exploration: 2015
209
Llanos
Exploitation: 2039
—
Magdalena
Exploitation: 2045
Exploration: 2021
(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
of the Gachetá formation. The main reservoirs of the basin are represented
by the Paleogene Carbonera and Mirador sandstones. Within the Cretaceous
in such block. LGI currently has a 20% direct equity interest in our Colombian
sequence, several sandstones are also considered to have good reservoirs.
operations through GeoPark Colombia SAS. However, we can earn back
up to 12% additional equity interests in GeoPark Colombia depending on
Llanos 34 Block . We are the operator of, and have a 45% working interest in, the
the success of our Colombian operations. See “—Significant Agreements—
Llanos 34 Block, which covers approximately 82,200 gross acres (333 sq. km).
Agreements with LGI—LGI Colombia Agreements.”
(2) Partners with working interests.
(3) As of December 31, 2017.
(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
We acquired an interest in and took operatorship of the block in the first quarter
of 2012, which at the time had no production, reserves or wells drilled on it, and
with 210 sq. km of existing 3D seismic data on which our team had mapped
multiple exploration prospects. From 2012 to 2016 we engaged in exploration
and development activities that resulted in multiple new oil fields discovered
block. Taking those other parties’ interests into account, we have a 89.5%
and increased production and proved reserves year by year until 2016. Average
interest in the Carupana Field and a 100% interest in the Yamú and Potrillo
net production in 2016 was 14,890 bopd and net reserves of 37.1 mmbbl. The
Fields, both located in the Yamú Block.
remaining commitment amounts to US$6.3 million at our working interest. As
of the date of this Annual Report, we are awaiting the ANH’s approval of US$3.6
The table summarizes information about the blocks in Colombia in which we
million related to one well already drilled that was presented as fulfilment of
have economic interests as of and for the year ended December 31, 2017.
the commitment to be performed before September 2019.
Gross acres
(thousand
acres)
32.1
Economic
interest(1)
10%
Block
Abanico
Production
Our operations.” We operate in the block pursuant to an E&P Contract with the
Operator
(boepd)
Basin
ANH. See “—Significant Agreements—Colombia—E&P Contracts—Llanos 34
Our partner in the Llanos 34 Block is Parex, which has a 55% interest. See “—
Pacific
50
Magdalena
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 24,500 gross acres (99.1 sq.
km). Due to the impact of low oil prices, we temporarily ceased operations in
Eastern Llanos Basin: (Llanos 34, La Cuerva, Yamú, Llanos 32, Llanos 17, Jagüeyes
some fields during 2015 and 2016. Average net oil production in 2017 was 585
3432A, Abanico, and VIM-3 Blocks)
bopd. As of February 28, 2018, 22 wells were productive. We operate in the
block pursuant to an E&P Contract with the ANH.
The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region
of Colombia. Two giant fields (Caño Limón and Castilla), three major fields
Yamú Block . We are the operator of, and have a 100% working interest in,
(Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had
the Yamú Block, which covers approximately 5,588 gross acres (22.6 sq. km).
been discovered. The source rock for the basin is located beneath the east flank
Economic rights to certain fields in the Yamú Block have been granted to other
of the Eastern Cordillera, as a mixed marine-continental shaly basinal facies
parties. In May 2013, we successfully drilled and completed the Potrillo 1 well.
72 GeoPark 20-F
For the year ended December 31, 2017, our average net production was 267
Operations in Chile
bopd. We resumed operations in this block in March 2017.
Our Chilean assets currently give us access to 808,000 of gross exploratory and
productive acres across 5 blocks in a large fully-operated land base across the
Llanos 17 Block . We had a 40% working interest in the Llanos 17 Block, which
Magallanes Basin, with existing reserves, production and cash flows.
covered approximately 108,800 gross acres (440 sq. km) pursuant to an E&P
Contract with the ANH. In October 2017, ANH confirmed that the contract was
Our Chilean blocks are located in the provinces of Ultima Esperanza,
liquidated.
Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil-
and gas-producing area. As of December 31, 2017, the Magallanes Basin
Llanos 32 Block . We have a 12.5% working interest in the Llanos 32 Block, as a
accounted for all of Chile’s oil and gas production. Although this basin has
result of our acquisition of an additional 2.5% interest on August 22, 2017. The
been in production for over 60 years, we believe that it remains relatively
Llanos 32 Block covers approximately 57,000 gross acres (230.7 sq. km). Parex
underdeveloped.
is the operator of this block, and has a 70% working interest. Pluspetrol has a
20% working interest. Since 2015, the operator focused on the commissioning
Substantial technical data (seismic, geological, drilling and production
of a gas facility on this block to produce natural gas and light crude oil from
information), developed by us and by ENAP, provides an informed base for
the Une formation and to facilitate shipment of processed gas south to
new hydrocarbon exploration and development. Shut-in and abandoned
the adjacent Llanos 34 Block. For the year ended December 31, 2017, our
fields may also have the potential to be put back in production by
average net production in the Llanos 32 Block was 209 bopd. The remaining
constructing new pipelines and plants. Our geophysical analyses suggest
commitment related to this block is to drill one exploratory well before August
additional development potential in known fields and exploration potential
2018 amounting to US$0.6 million at our working interest.
in undrilled prospects and plays, including opportunities in the Springhill,
Tertiary, Tobífera and Estratos con Favrella formations. The Springhill
Jagüeyes 3432A Block . We had a 5% working interest in the Jagüeyes 3432A
formation has historically been the source of production in the Fell Block,
Block, which covered approximately 61,000 acres (247 sq. km). In December
though the Estratos con Favrella shale formation is the principal source rock
2017, ANH confirmed that the contract was liquidated.
of the Magallanes Basin, and we believe it contains unconventional resource
Abanico Block . In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc.
potential.
entered into the Abanico Block association contract. Pacific is the operator of,
Highlights of the year ended December 31, 2017 related to our operations in
and has a 100% working interest in, the Abanico Block, which covers an area of
Chile included:
approximately 32,100 gross acres. We do not maintain a direct working interest in
• Average net oil and gas production declined to 2,885 boepd in 2017 from
the Abanico Block, but rather have a 10% economic interest in the net revenues
3,874 boepd in 2016;
from the block pursuant to a joint operating agreement initially entered into with
• Proved oil and gas reserves decreased by 40% to 7.5 mmboe at year-end
Kappa Resources Colombia Limited (now Pacific, who subsequently assigned its
2017, from 12.6 mmboe at year-end 2016 after producing 1.0 mmboe;
participation interest to Cespa de Colombia S.A., who then assigned the interest
• Capital expenditures were increased by 31% to US$10.2 million in 2017
to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A.
from US$7.8 million in 2016; and
• Drilling and completion of the Uaken 1 exploration well to a total depth of
VIM-3 Block. On July 23, 2014 we were awarded a new exploratory license
3,658 feet. The Uaken gas field discovery in the shallower El Salto formation
during the 2014 Colombia Bidding Round, carried out by the ANH. We are
provides additional low-cost production and creates a new gas play across
entitled to operate the block, in which we have a 100% working interest.
the Fell block that can be tested in identified leads and prospects. In addition,
The VIM-3 Block is located in the Lower Magdalena Basin, covering an area
there are multiple wells in already discovered oil and gas fields within the Fell
of approximately 225,000 acres. Our winning bid consisted of committing to
block that can be re-entered to test this formation.
a Royalty X Factor of 3% and a minimum investment program of 200 sq. km
• Successful cost reduction efforts impacting production and operating costs
of 2D seismic data acquisition and drilling one exploratory well, with a total
that represented a 5% reduction, to US$21.0 million in 2017 as compared to
estimated investment of US$22.3 million during the initial exploratory period
US$22.2 million in 2016.
ending February 2019. On June 21, 2017, ANH approved our relinquishment of
79.15% of the VIM 3 Block area. The remaining area will cover 46,881 acres and
the commitments described above are not affected.
GeoPark 73
The map below shows the location of the blocks in Chile in which we have
working interests.
CHILE
ARGENTINA
Tranquilo
Fell
Isla Norte
Campanario
Flamenco
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, 2017.
Block
Fell
Tranquilo
Isla Norte
Gross acres
(thousand
acres)
Working
interest(1)
Partners(2)
Operator
Net proved
reserves
(mmboe)(3)
Production
(boepd)
Basin
Concession
expiration year
367.8
100%
—
GeoPark
7.3
2,835
Magallanes
Exploitation: 2032
92.4
50%
Pluspetrol
GeoPark
97.7
60%(4)
ENAP
GeoPark
Campanario
144.2
50%(4)
ENAP
GeoPark
Flamenco
105.9
50%(4)
ENAP
GeoPark
—
—
—
0.2
—
Magallanes
Exploitation: 2043
—
Magallanes
—
Magallanes
Exploration: 2021
Exploitation: 2044
Exploration: 2021
Exploitation: 2045
Exploration: 2021
50
Magallanes
Exploitation: 2044
(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
(3) As of December 31, 2017.
(4) LGI has a 14% direct equity interest in our Tierra del Fuego operations
through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, for
Chilean operations through GeoPark Chile. See “—Significant Agreements—
a total effective equity interest of 31.2% in our Tierra del Fuego operations.
Agreements with LGI—LGI Chile Shareholders’ Agreements.”
(2) Partners with working interests.
See “—Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco
Blocks)” and “—Significant Agreements—Agreements with LGI—LGI Chile
Shareholders’ Agreements.”
74 GeoPark 20-F
Fell Block
In 2006, we became the operator and 100% interest owner of the Fell Block.
The Fell Block also contains the Estratos con Favrella shale reservoir, which we
When we first acquired an interest in the Fell Block in 2002, it had no material
believe represents a high-potential, unconventional resource play for shale oil,
oil and gas production. Since then, we have completed more than 1,100 sq.
as a broad area within Fell Block (1,000 sq. km) which appears to be in the oil
km of 3D seismic surveys and drilled 117 exploration and development wells.
window for this play.
In the year ended December 31, 2017, we produced an average of 2,835
boepd, in the Fell Block, consisting of 54% oil.
In February 2018, Methanex announced the reopening of their second plant
in Punta Arenas, which is estimated to reopen by the end of the third quarter
The Fell Block has an area of approximately 368,000 gross acres (1,488 sq.
of 2018.
km) and its center is located approximately 140 km northeast of the city of
Punta Arenas. It is bordered on the north by the international border between
Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)
Argentina and Chile and on the south by the Magellan Strait.
In the first and second quarters of 2012, we entered into three CEOPs with
ENAP and Chile granting us working interests in the Isla Norte, Campanario
From 2006 through August 2011, we successfully explored and developed
and Flamenco Blocks, located in the center-north of the Tierra del Fuego
the Fell Block, which allowed us to transition approximately 84% of the Fell
province of Chile. We are the operator of all three of these blocks, with
Block’s area from an exploration phase into an exploitation phase, which we
working interests of 60%, 50% and 50%, respectively. We believe that these
expect will last through 2032. During the exploration phase, we exceeded the
three blocks, which collectively cover 347,700 gross acres (1,407 sq. km) and
minimum work and investment commitment required under the Fell Block
are geologically contiguous to the Fell Block, represent strategic acreage
CEOP by more than 75 times. There are no minimum work and investment
with resource potential. We have committed to paying 100% of the required
commitments under the Fell Block CEOP associated with the exploitation
minimum investment under the CEOPs covering these blocks, in an aggregate
phase.
amount of US$101.4 million through the end of the first exploratory periods
for these blocks, which occurred in November 2015 for the Flamenco Block,
The Fell Block is located in the north-eastern part of the Magallanes Basin.
in May 2017 for the Isla Norte Block and in July 2017 for the Campanario
The principal producing reservoir is composed of sandstones in the Springhill
Block, which includes our covering of ENAP’s investment commitment
formation, at depths of 2,200 to 3,500 meters. Additional reservoirs have
corresponding to its working interest in the blocks. Under Article 5.3 of CEOP,
been discovered and put into production in the Fell Block—namely, Tobífera
at the end of the first exploration period, the contractor defines the area to
formation volcanoclastic rocks at depths of 2,900 to 3,600 meters, and Upper
be retained and we were required to return to the state at least 25% of the
Tertiary and Upper Cretaceous sandstones, at depths of 700 to 2,000 meters.
original area of the contract. The first exploration period of Isla Norte and
Our geosciences team identified and developed an attractive inventory of
Campanario Blocks ended in 2017, at which point we relinquished 80.6 gross
prospects and drilling opportunities for both exploration and development
acres (583 sq. km).
in the Fell Block. Previous oil discoveries in the Konawentru, Yagán, Yagán
Norte, Copihue and Guanaco fields have opened up new oil and gas potential
Isla Norte Block . We are the operator of, and have a 60% working interest in
in the Fell Block. An important discovery during 2011 was the Konawentru
partnership with ENAP in the Isla Norte Block, which covers approximately
1 well, which we initially tested to have in excess of 2,000 bopd from the
97,650 gross acres (395 sq. km). As of March 2018, we had completed 100% of
Tobífera formation, and which has opened up additional potentially attractive
the committed 350 sq. km of 3D seismic surveys and drilled one exploratory
opportunities (workovers, well-deepening’s and new exploration and
well, which represents the first oil discovery within the block. As of the date
development wells) in the Tobífera formation throughout the Fell Block.
of this annual report, outstanding investment commitments of US$2.9 million
From 2012 to 2014, we focused our exploration and development plan in the
related to this block correspond to two exploratory wells to be executed
Tobífera formation by drilling wells in Konawentru, Yagán and Yagán Norte
before May 7, 2019.
fields, as well as deepening existing wells in Ovejero and Molino. Exploration
efforts in 2014 resulted in the discoveries of the Ache gas field and the Loij oil
Campanario Block . We are the operator of, and have a 50% working interest
field.
in, the Campanario Block, in partnership with ENAP. The block covers
approximately 144,150 gross acres (583 sq. km). As of March 31, 2018, we
During 2015, although there were no wells drilled, we put into production a
had completed 100% of the committed 578 sq. km of 3D seismic surveys and
new gas field, Ache, that was discovered in 2014. During 2016, we successfully
have also drilled five exploratory wells, including the Primavera Sur 1 well that
drilled the Pampa Larga 16 well and continued focusing on maintaining
marks the first discovery of an oil field on the Campanario Block in addition
production levels and reducing production and operating costs. During 2017,
to one development well. As of the date of this annual report, outstanding
we drilled three wells; two of them were put into production (Kimiriaike 4
investment commitments of US$4.8 million related to this block correspond to
and Uaken X-1) and the remaining well (Ache-3) is still under evaluation.
three exploratory wells to be executed before July 10, 2019.
In addition, we continued to focus on maintaining production levels and
reducing production and operating costs.
GeoPark 75
Flamenco Block . We are the operator of, and have a 50% working interest in,
Operations in Brazil
the Flamenco Block, in partnership with ENAP. The block covers approximately
Our Brazilian assets currently give us access to 84,300 of gross exploratory
105,900 gross acres (428 sq. km). In June 2013, we discovered a new oil and gas
and productive acres across 9 blocks (8 exploratory blocks and the BCAM-40
field in the block following the successful testing of the Chercán 1 well, the first
Concession, which is in production phase) in an attractive oil and gas geography.
well drilled by us in Tierra del Fuego. As of March 31, 2018, we had completed
Highlights of the year ended December 31, 2017 related to our operations in
100% of the committed 570 sq. km of 3D seismic surveys. We have also
Brazil included:
committed to drilling ten wells during the first exploration period under the
• Average net oil and gas production of 2,910 boepd (99% gas) in the year
CEOP governing the Flamenco Block. In the year ended December 31, 2017,
ended December 31, 2017, as compared to 2,930 boepd in 2016;
we produced an average of 50 boepd in the Flamenco Block.
• Capital expenditures remained at US$3.6 million in 2017;
On June 30, 2017, the Chilean Ministry accepted our proposal to extend the
total depth of 7,654 feet. Main targets, Sergi and Agua Grande formations, were
second exploratory period for an additional period of 18 months. As of the
found to be water bearing with reservoir thicknesses of 36 feet and 46 feet,
date of this annual report, outstanding investment commitments related
respectively. In addition, 47 feet of reservoir with oil traces were encountered in
to this block correspond to 1 exploratory well until May 7, 2019 for US$2.1
a secondary target, in the Gomo formation. Following an in-depth geological
million, to be assumed 100% by us.
and geophysical analysis, a decision was made to plug and abandon the well
• Praia do Espelho exploration prospect in Reconcavo Basin was drilled to a
Otway and Tranquilo Blocks
In relation to the Otway Block, we have informed the Ministry of Energy
during the second quarter of 2017; and
• A new block awarded in Round 14 (POT-T-785 Block).
the termination of the CEOP due to the fact that the two provisional areas
The map below shows the location of our concessions in Brazil in which we
of Tatiana and Cabo Negro have expired in September and October 2017,
have a current or future working interest, including the BCAM-40 Concession
respectively. There were no pending obligations at the end of the CEOP.
and the concessions from bidding rounds 11, 12, 13 and 14.
We are the operator of the Tranquilo Block.
In the Tranquilo Block, as of December 31, 2017, we had a 50% working
interest alongside our partner Pluspetrol.
In the Tranquilo Block we completed a seismic program consisting of 163 sq.
km of 3D seismic and 371 sq. km of 2D seismic survey work, and drilled four
wells, including the Palos Quemados and Marcou Sur well. We discovered gas
in the El Salto formation of the Palos Quemado well. At the Palos Quemados
well, we completed a 22-week commercial feasibility test aimed at defining
BRAZIL
its productive potential. As the test was not conclusive, we were granted
permission by the Chilean Ministry of Energy to extend the testing period
for an additional six months. Upon such testing period, we kept 4 provisional
protection areas, which enabled continued analysis of the area prior the
declaration of its commercial viability for a period of 5 years. On January 17,
2013, we formally announced to the Chilean Ministry of Energy our decision
not to proceed with the second exploratory period and to terminate the
exploratory phase of the Tranquilo Block CEOP. Subsequently, we relinquished
all areas of the Tranquilo Block, except for a remaining area of 92,417 gross
acres, for the exploitation of the Renoval, Marcou Sur, Estancia Maria Antonieta
and Palos Quemados Fields, which we have identified as the areas with the
most potential for prospects in the block. In November 2017, we proposed to
the Ministry of Energy to extend the period to declare the commerciality of
discoveries in the areas of Palos Quemados, Maria Antonieta and Marcou Sur
for an additional period of 24 months. In February 2018, the Ministry approved
our proposal.
76 GeoPark 20-F
POT - T 747
POT-T-785
POT - T 882
PN - T 597(1)
REC - T 94
REC - T 93
REC- T 128
POT - T 619
SEAL - T 268
BCAM - 40 (Manati)
PARAGUAY
ARGENTINA
(1)The PN-T-597 Block is subject to an injunction and our bid for the
concession has been suspended. See “Item 3. Key Information—D.
Risk factors—Risks relating to our business—The PN-T-597 Concession
Agreement in Brazil may not close.”
The following table sets forth information as of December 31, 2017 on our
concessions in Brazil in which we have a current or future working interest,
including the BCAM-40 Concession and the concessions from bidding rounds
11, 12, 13 and 14.
Gross acres
(thousand
acres)
Working
interest(1)
7.7
100%
100%
100%
100%
100%
7.9
188.7
7.8
7.8
7.6
—
—
—
—
—
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
70%
Geosol
GeoPark
6.9
100%(5)
7.9
100%(5)
7.9
100%(5)
—
—
—
GeoPark
GeoPark
GeoPark
Petrobras;
Concession
REC-T 94
POT-T 619
PN-T-597(4)
SEAL-T-268
REC-T-93
REC-T-128
POT-T-747
POT-T-882
POT-T-785
BCAM-40
Partners
Operator
Net proved
reserves
(mmboe)(3)
Production
(boepd)
Basin
Concession
expiration year
Exploration: 2020
—
—
—
—
—
—
—
—
—
—
Recôncavo
Exploitation: 2047
—
—
—
Potiguar
Parnaíba
Sergipe
Alagoas
Exploration: 2018
Exploitation: 2045
—
Exploration: 2020
Exploitation: 2047
Exploration: 2018
—
Recôncavo
Exploitation: 2045
Exploration: 2018
—
Recôncavo
Exploitation: 2045
Exploration: 2018
Potiguar
Exploitation: 2045
Exploration: 2018
Potiguar
Exploitation: 2045
Potiguar
Camamu-
Exploration: 2023
Exploitation: 2050
Exploitation:
2029(2) - 2034(3)
—
—
—
22.8
10%
QGEP; Brasoil
Petrobras
4.0
2,910
Almada
(1) Working interest corresponds to the working interests held by our
respective subsidiaries, net of any working interests held by other parties in
and 45% working interests, respectively. Petrobras operates the BCAM-40
Concession pursuant to a concession agreement with the ANP, executed on
such concession. See “Item 3. Key Information—D. Risk factors—Risks relating
August 6, 1998. See “—Significant Agreements—Brazil—Overview of concession
to our business—The PN-T-597 Concession Agreement in Brazil may not close.”
(2) Corresponds to Manati Field.
(3) Corresponds to Camarão Norte Field.
(4) PN-T-597 Block subject to the entry into the concession agreement by
the ANP and absence of any legal impediments to signing. As of the date of
agreements—BCAM-40 Concession Agreement.” In September 2009, Petrobras
announced the relinquishment of BCAM-40’s exploration area within the
concession to the ANP, except for the Manati Field and the Camarão Norte Field.
The Manati Field is located 65 km south of Salvador, offshore at a 35 meter
this annual report, confirmation remains subject to final signing and local
water depth. The field was discovered in October 2000, and, in 2002, Petrobras
authority approval. See “Item 3. Key Information—D. Risk factors—Risks
declared the field commercially viable. Production began in January 2007.
relating to our business—The PN-T-597 Concession Agreement in Brazil may
As of December 31, 2017, 11 wells had been drilled in the Manati Field,
not close.”
(5) A 30% working interest of proposed partners is subject to ANP approval.
BCAM-40 Concession
six of which are productive and connected to a fixed production platform
installed at a depth of 35 meters, located 9 km from the coast of the State of
Bahia. From the platform, the gas flows by sea and land through a 125 km
pipeline to the Estação Vandemir Ferreira or EVF gas treatment plant. The gas
As a result of the Rio das Contas acquisition, we have a 10% working interest
is sold to Petrobras up to a maximum volume as determined in the existing
in the BCAM-40 Concession, which includes interests in the Manati Field and
Petrobras Gas Sales Agreement (as defined below). In July 2015, we signed an
the Camarão Norte Field, and which is located in the Camamu-Almada Basin.
amendment to the existing Gas Sales Agreement with Petrobras that covers
Petrobras is the operator, and has a 35% working interest in, the BCAM-40
100% of the remaining gas reserves of the Manati Field.
Concession, which covers approximately 22,784 gross acres (92.2 sq. km). In
addition to us, Petrobras’ partners in the block are Brasoil and QGEP, with 10%
Also in 2015, in order to improve the field gas recovery and production,
GeoPark 77
Manatì’s consortium built an onshore compression plant that started
Round 12 Concessions
operating in August 2015. The compression plant involved capital
In November 2013, in the 12th Bid Round, the ANP awarded us two new
expenditures of approximately US$3.7 million at our working interest and
concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of
allowed us to classify all existing proved undeveloped reserves as proved
Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin) in
developed as of December 31, 2016.
the State of Alagoas.
Some environmental licenses related to operation of the Manati Field
For more information, see “Item 3. Key information—D. Risk factors—Risks
production system and natural gas pipeline are expired. However, the operator
relating to our business—The PN-T-597 Concession Agreement in Brazil may
submitted, in a timely manner, the request for renewal of those licenses and as
not close.”
such this operation is not in default as long as the regulator does not state its
final position on the renewal. The Camarão Norte Field is in the development
PN-T-597 Concession
phase and is not yet subject to the environmental licensing requirement.
The Parnaiba Basin, which covers an area of approximately 148 million
Round 11 Concessions
During ANP’s 11th Bid Round, held in May 2013, we were awarded 7
gross acres (600,000 sq. km), is a basin with large underexplored areas. As of
December 31, 2017, the basin had two fields in production in the basin.
exploratory blocks, of which 2 were in the Reconcavo Basin in the state of
In the PN-T-597 Concession we committed R$7.7 million (approximately
Bahia and 5 were in the Potiguar Basin in the state of Rio Grande do Norte.
US$2.3 million, at the December 31, 2017 exchange rate of R$3.3 to US$1.00)
The exploratory phase for these concessions is divided into two exploratory
for the first exploratory period, equivalent to 180 km of 2D seismic.
periods, the first of which lasts for three years and the second of which is non-
obligatory and can last for up to two years.
The exploratory phase for this concession is divided into two exploratory
In 2016, after fulfilling the committed exploratory commitments and
ANP, the first exploratory period lasts four years, and the second exploratory
further reevaluation of commercial potential, five exploratory blocks were
period, which is optional, can last for up to two years.
relinquished to the ANP (REC T 85, POT T 620, POT T 663, POT T 664 and POT T
periods. Given that Parnaiba Basin is considered as a “new frontier” area by the
665).
REC-T 94 Concession
See “Item 3. Key Information—D. Risk factors—Risks relating to our business—
The PN-T-597 may not close” and “—D. Risk factors—Risks relating to the
countries in which we operate—Our operations may be adversely affected by
In the REC-T 94 we committed R$17.6 million (approximately US$5.3 million,
political and economic circumstances in the countries in which we operate
at the December 31, 2017 exchange rate of R$3.3 to US$1.00) during the first
and in which we may operate in the future” for more information.
exploratory period consisting of drilling two exploratory wells and 31 sq. km
of 3D seismic surveys.
SEAL-T-268 Concession
During the year 2014 we executed a 3D seismic survey. Seismic data
US$0.5 million, at the December 31, 2017 exchange rate of R$3.3 to
interpretation in 2015 and 2016 defined two well locations, one of which was
US$1.00) for the first exploratory period. The exploratory phase for this
drilled in 2017. The estimated remaining commitment amounts to US$0.9
concession is divided into two exploratory periods, the first lasting three
In the SEAL-T-268 Concession we committed R$1.6 million (approximately
million.
POT-T 619 Concession
years, and the second, which is optional, can last for up to two years. During
2016, an electromagnetic survey acquisition of 70 stations and reprocessing
of 58 km of vintage 2D seismic was performed and, after ANP approval
In the POT-T 619 Concession we committed investments of R$2.3 million
of the extension of the first exploratory phase, we will fulfill part of the
(approximately US$0.7 million at the December 31, 2017 exchange rate of
remaining committed work program that amounts to US$ 0.2 million.
R$3.3 to US$1.00) during the first exploratory period, equivalent to 46 km of
2D seismic work.
Round 13 Concessions
During the year 2014 we executed a 2D seismic survey. Seismic data
exploratory concessions, of which two were in the Potiguar Basin in the state
processing was concluded in 2015. After seismic interpretation, we decided to
of Rio Grande do Norte and two were in the Reconcavo Basin in the state
continue to the second exploratory period in September 2016, which lasts for
of Bahia. The exploratory phase for these concessions is divided into two
two years with a commitment to drill one exploratory well. The well was drilled
exploratory periods, the first of which lasts for three years and the second of
during 2018 and was abandoned. There is no pending commitment.
which is non-obligatory and can last for up to two years.
During ANP’s 13th Bid Round held in October 2015, we were awarded four
78 GeoPark 20-F
POT-T-747 and POT-T-882
The POT-T-747 and POT-T-882 blocks are located in the Potiguar Basin and
The map below shows the location of the Morona Block in Peru.
encompass an area of 14,829 acres (60 square km). Total commitment to
the ANP was R$8.5 million (approximately US$2.6 million, at the December
31, 2017 exchange rate of R$3.3 to US$1.00) during the first exploratory
period and is equivalent to acquiring 70 km of 2D seismic, and drilling one
well. During 2017 3D seismic was reprocessed and a well was drilled in the
POT-T-747 block during 2018 and was abandoned. The estimated remaining
commitment amounts to US$0.2 million.
REC-T-128 and REC-T-93
Both blocks are part of the Reconcavo Basin and have a combined area of
15,405 acres (62.3 square km). The block REC-T-128 was bid for in partnership
with Geosol with a 70% working interest for us and 30% working interest for
Geosol. The total commitment to the ANP was R$10.7 million (approximately
US$3.2 million at the December 31, 2017 exchange rate of R$3.3 to US$1.00)
during the first exploratory period and consists of acquiring 9 km2 of 3D
seismic, drilling one well and performing geochemical analysis at two levels.
During 2016, regional interpretation studies were performed in the area. Part
of the minimum exploratory program of Block REC-T-93 has been fulfilled and
approved by ANP with the 3D regional seismic acquisition which also covered
Block REC T 94 (Round 11). During 2017, 3D reprocessing was performed in the
REC-T-128 block. The estimated remaining commitment amounts to US$2.9
million.
Round 14 Concessions
During ANP’s 14th Bid Round held in September 2017, we were awarded one
exploratory concession, in the Potiguar Basin in the state of Rio Grande do
Norte.
POT-T-785
The POT-T-785 block covers an area of 7,875 acres in the Potiguar Basin,
surrounded by producing fields operated by Petrobras. Total commitment to
the ANP was R$1.2 million (US$0.4 million, at the December 31, 2017 exchange
rate of R$3.3 to US$1.00) during the first exploratory period and is equivalent
to acquiring 4 km2 of 3D seismic, and performing geochemical analysis.
Operations in Peru
In October 2014, we entered into an agreement to expand our footprint into
Peru (our fifth country platform in Latin America) through the acquisition of
Morona Block in a joint venture with Petroperu.
The Morona Block has DeGolyer and MacNaughton certified net proved
reserves of 18.7 mmboe as of December 31, 2017, composed of 100% oil.
ECUA DOR
COLOMBIA
Morona
BRAZIL
PERU
PACIFIC
OCEAN
BOLIVIA
CHILE
GeoPark 79
The table below summarizes information about the block in Peru.
Block
Morona
Gross acres
(thousand
acres)
1,881
Working
interest(1)
75%
Operator
GeoPark
Net proved
reserves
(mmboe)(2)
18.7
Production
(boepd)
Basin
—
Marañon
Expiration
concession year
Exploitation: 2038 (3)
(1) Corresponds to the initial working interest. Petroperu will have the right to
increase its working interest in the block by up to 50%, subject to the recovery
of our investments in the block through agreed terms in the Petroperu SPA.
2020. We expect these expenditures to be substantially reimbursed by
Petroperu from revenues associated to future sales.
See “Item 4. Information on the Company—B. Business Overview—Our
In accordance with the agreement between us and Petroperu, commitments
operations—Operations in Peru—Morona Block.”
(2) Certified by DeGolyer and MacNaughton as of December 31, 2017.
(3) The concession will expire twenty (20) years after EIA approval.
assumed by GeoPark are subject to certain economical and technical
conditions being met.
Morona Block
The third stage, which will be initiated once production has been established,
is expected to focus on carrying out the full development of the Situche
The Morona Block covers an area of approximately 1,881 thousand gross acres
Central field, including transportation infrastructure.
(7,600 sq. km). More than 1 billion barrels of oil have been produced from the
surrounding blocks in the Marañon Basin.
The exploratory program entails drilling one exploratory well. Exploratory
program capital expenditures will be borne exclusively by us. Expected
On October 1, 2014, we entered into an agreement to acquire a 75% working
capital expenditures in 2018 for the Morona Block are mainly related to facility
interest in the Morona Block in Northern Peru. As stated above, this agreement
maintenance and environmental and engineering studies in order to get the
includes a work program to be executed by us. This program includes 3
approval of the Development Environmental Impact Study by the end of the
phases, and we may decide whether to continue or not at the end of each
year.
phase. On December 1, 2016, through Supreme Decree N° 031-2016-MEN,
the Peruvian government approved the amendment to the License Contract
Initially we will hold a 75% working interest in the block. However, according
of Morona Block appointing GeoPark as operator and holder of 75% of the
to the terms of the agreement, Petroperu has the right to increase its working
License-Contract.
interest in the block by up to 50%, subject to the recovery of our investments
in the block by certain agreed factors.
The Morona Block contains the Situche Central oil field, which has been
See “Item 3. Key Information—D. Risk factors—Risks relating to our business—
delineated by two wells (with short term tests of approximately 2,400 and
“Our inability to access needed equipment and infrastructure in a timely
5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the
manner may hinder our access to oil and natural gas markets and generate
Situche Central field, the Morona Block has a large exploration potential
significant incremental costs or delays in our oil and natural gas production”
with several high impact prospects and plays. The Morona Block includes
and “—We may suffer delays or incremental costs due to difficulties in
geophysical surveys of 2,783 km (2D seismic) and 465 sq. km (3D seismic), and
negotiations with landowners and local communities, including native
an operating field camp and logistics infrastructure. The area has undergone
communities, where our reserves are located.”
oil and gas exploration activities for the past 40 years, and there exist ongoing
association agreements and cooperation projects with the local communities.
The expected work program and development plan for the Situche Central oil
field is to be completed in three stages.
The goal of the initial two stages is to start production from the two wells
already drilled in the field, in order to determine the most effective overall
development plan and to begin to generate cash flow. These initial stages
require an investment of approximately US$100 million to US$150 million and
are expected to be completed by the first half of 2020. We have committed
to carry Petroperu, by paying its portion of the required investment in these
initial phases. In addition, we are required to cover any capital or operational
expenditures of Petroperu associated with the project until December 31,
80 GeoPark 20-F
Operations in Argentina
The map below shows the location of the blocks in Argentina in which we
have working interests as of December 31, 2017.
BOLIVIA
PARAGUAY
ARGENTINA
BRAZIL
URUGUAY
Sierra del Nevado
Puelen
CV-V
CHILE
The table below summarizes information about the blocks in Argentina in
which we have working interests as of December 31, 2017.
Block
Puelen
Sierra del Nevado
CN-V
Gross acres
(thousand
acres)
305.4
1,433.2
117.0
Working
interest(1)
18%
18%
50%
Operator
Pluspetrol
Pluspetrol
GeoPark
Net proved
reserves
(mmboe)(2)
—
—
—
Production
(boepd)
—
—
4
Basin
Neuquén
Neuquén
Neuquén
Expiration
concession year
Exploration: 2020
Exploration: 2020
Exploration: 2018
(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
each block.
(2) As of December 31, 2017.
GeoPark 81
Highlights of the year ended December 31, 2017 related to our operations in
another exploratory well before the end of the second exploration period, for
Argentina included:
a total of US$10 million.
• Discovery of the Rio Grande Oeste oil field in CN-V block following the
successful drilling and testing of the exploratory well Rio Grande Oeste 1; and
The CN-V Block covers an area of approximately 117,000 acres and is located in
• Execution of an asset purchase agreement with Pluspetrol to acquire 100%
the Neuquén Basin in southern Argentina. The block has 3D seismic coverage
working interest and operatorship of the Aguada Baguales, El Porvenir and
of 180 sq. km and is adjacent to the producing Loma Alta Sur oil field, a region
Puesto Touquet blocks (“the blocks”) for a total consideration of US$52 million.
and play-type well known to our team. The block includes upside potential in
The blocks include:
the developing Vaca Muerta unconventional play.
- estimated oil and gas production of approximately 2,700 boepd -
70% light oil and 30% gas;
During 2017, we drilled the first exploratory well, Rio Grande Oeste 1, which
- 137,000 acres in the Neuquen Basin; and
resulted in the discovery of Rio Grande Oeste oil field. These investments
- production facilities, including hydrocarbons treatment, storage,
represent the fulfilment of 50% of the commitment for the block.
and delivery infrastructure.
Del Mosquito Block
2014 Mendoza Bidding Round
On April 2016 the concession of the Del Mosquito expired and we relinquished
On August 20, 2014, the consortium of Pluspetrol and us was awarded two
the entire remaining acreage to provincial authorities. As of the date of this
exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of
annual report, the approval of the abandonment plan for remediation and
the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa
restoration of the block is still pending.
Mendocina de Energía S.A. (“EMESA”).
The consortium consists of Pluspetrol (operator with a 72% working
Overview
interest), EMESA (non-operator with a 10% working interest) and us (non-
We have achieved consistent growth in oil and gas reserves from our
operator with an 18% working interest). In accordance with the terms of
investment activities since 2007, when we began production in the Fell Block,
the bidding, all of the expenditures related to EMESA’s working interest will
followed by successful acquisition, exploration and development activities in
be carried by Pluspetrol and us proportionately to our respective working
other countries in which we have a presence, including Colombia, Brazil and
Oil and natural gas reserves and production
interests, and will be recovered through EMESA’s participation in future
Peru.
potential production.
Our reserves
Puelen Block : The Puelen Block covers an area of approximately 305.4
The following table sets forth our oil and natural gas net proved reserves as of
thousand gross acres, and is located in the Neuquén Basin in southern
December 31, 2016, which is based on the D&M Reserves Report.
Argentina.
Sierra del Nevado Block : The Sierra del Nevado Block covers an area of
As of December 31, 2017
approximately 1,433.2 thousand gross acres, and is located in the Neuquén
Basin in southern Argentina.
Net proved reserves
We have committed to a minimum aggregate investment of US$6.2 million for
Net proved developed
our working interest, which includes the work program commitment on both
Colombia
blocks during the first three years of the exploratory period. As of December
31, 2017, the remaining commitments in these blocks for the first exploratory
period amount to US$1.2 million at our working interest.
Chile
Peru
Brazil
Oil
(mmbbl)
21.1
0.7
9.5
0.1
CN-V Block Farm-in Agreement
Total net proved developed
31.4
Net proved undeveloped
On July 22, 2015, we signed a farm-in agreement with Wintershall for the
Colombia
CN-V Block in Argentina, which complements our existing acreage in the
basin. Wintershall is Germany’s largest oil and gas producer and a subsidiary
of BASF Group. We will operate during the exploratory phase and receive a
50% working interest in the CN-V Block in exchange for having drilled one
exploratory well before the end of the second quarter of 2017 and to drill
Chile
Peru
Brazil
Total net proved
undeveloped (2)
Total net proved
44.4
3.4
9.2
-
Total net
Natural
proved
gas
(bcf )
reserves
(mmboe)(1)
-
8.7
-
23.8
32.5
-
11.3
-
-
21.1
2.2
9.5
4.0
36.8
44.4
5.3
9.2
-
% Oil
100%
32%
100%
3%
85%
100%
64%
100%
-
57.0
11.3
58.9
97%
82 GeoPark 20-F
(Colombia, Chile, Peru, Brazil)
88.4
43.8
95.7
92%
(1) We calculate one barrel of oil equivalent as six mcf of natural gas.
(2) We plan to put 100% of our reported 2017 year-end proved undeveloped
reserves into production through activities to be implemented within five
years of initial disclosure.
Throughout each fiscal year, our technical team meets with Independent
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-
generated reserves estimates is beneficial in ensuring that interpretations
Changes for the year ended December 31, 2017 not including annual
and judgments are reasonable and that the estimates are free of preparer and
production, include (i) an increase of 3.8 mmboe resulting from better than
management bias.
expected performance from existing wells, from the Tigana and Jacana
fields in the Llanos 34 Block; (ii) an increase of 3.0 mmboe resulting from
Recognizing that reserves estimates are based on interpretations and
the impact of higher average prices; (iii) an increase of 1.5 mmboe due to
judgments, differences between the proved reserves estimates prepared by
a better performance in the proved reserves in Chile and (iv) an increase of
us and those prepared by an Independent Qualified Reserves Engineer of
29.0 mmboe due to extensions and discoveries from the Chiricoca, Jacamar,
10% or less, in aggregate, are considered to be within the range of reasonable
and Curucucu fields in the Llanos 34 Block and the Tigana and Jacana field
differences. Differences greater than 10% must be resolved in the technical
extensions in the Llanos 34 Block. Such increase was partially offset by a
meetings. Once differences are resolved, the independent Qualified Reserves
decrease in reserves mainly related to a change in a previously adopted
Engineer sends a preliminary copy of the reserves report to be reviewed by
development plan and unsuccessful proved undeveloped execution in the Fell
the Technical Committee and Directors of each country. A final copy of the
Block in Chile, resulting in a 6.0 mmboe decrease.
Reserves Report is sent by the Independent Qualified Reserve Engineer to be
During the year ended December 31, 2017, we had 12.5 mmboe of our
“Item 6. Directors, Senior Management and Employees—C. Board Practices—
approved and signed by the Technical Committee and our CEO and CFO. See
proved undeveloped reserves from December 31, 2016 converted to proved
Committees of our board of directors.”
developed reserves due to development drilling in the Jacana and Tigana
oil fields in the Llanos 34 Block. For further information relating to the
Independent reserves engineers
reconciliation of our net proved reserves for the years ended December 31,
Reserves estimates as of December 31, 2017 for Colombia, Chile, Brazil and
2017, 2016 and 2015, please see Table 5 included in Note 37 (unaudited) to our
Peru included elsewhere in this annual report are based on the D&M Reserves
Consolidated Financial Statements.
Report, dated February 15, 2018 and effective as of December 31, 2017.
The D&M Reserves Report, a copy of which has been filed as an exhibit to
Internal controls over reserves estimation process
this annual report, was prepared in accordance with SEC rules, regulations,
We maintain an internal staff of petroleum engineers and geosciences
definitions and guidelines at our request in order to estimate reserves and for
professionals who work closely with our independent reserves engineers
the areas and period indicated therein.
to ensure the integrity, accuracy and timeliness of data furnished to our
independent reserves engineers in their estimation process and who have
DeGolyer and MacNaughton, a Delaware corporation with offices in Dallas,
knowledge of the specific properties under evaluation. Our Director of
Houston, Moscow, Algiers, Astana and Buenos Aires has been providing
Development, Carlos Alberto Murut, is primarily responsible for overseeing
consulting services to the oil and gas industry since 1936. The firm has
the preparation of our reserves estimates and for the internal control over
more than 200 professionals, including engineers, geologists, geophysicists,
our reserves estimation. He has more than 30 years of industry experience
petrophysicists and economists that are engaged in the appraisal of oil and
as an E&P geologist, with broad experience in reserves assessment, field
gas properties, the evaluation of hydrocarbon and other mineral prospects,
development, exploration portfolio generation and management and
basin evaluations, comprehensive field studies and equity studies related to
acquisition and divestiture opportunities evaluation. See “Item 6. Directors,
the domestic and international energy industry. DeGolyer and MacNaughton
Senior Management and Employees—A. Directors and senior management.”
restricts its activities exclusively to consultation and does not accept
In order to ensure the quality and consistency of our reserves estimates and
properties, or securities or notes of its clients. The firm subscribes to a code
reserves disclosures, we maintain and comply with a reserves process that
of professional conduct, and its employees actively support their related
satisfies the following key control objectives:
technical and professional societies. The firm is a Texas Registered Engineering
contingency fees, nor does it own operating interests in any oil, gas or mineral
• estimates are prepared using generally accepted practices and
Firm.
methodologies;
• estimates are prepared objectively and free of bias;
The D&M Reserves Report covered 100% of our total reserves. In
• estimates and changes therein are prepared on a timely basis;
connection with the preparation of the D&M Reserves Report, DeGolyer
• estimates and changes therein are properly supported and approved; and
and MacNaughton prepared its own estimates of our proved reserves. In
• estimates and related disclosures are prepared in accordance with regulatory
the process of the reserves evaluation, DeGolyer and MacNaughton did not
requirements.
GeoPark 83
independently verify the accuracy and completeness of information and data
that renewal is reasonably certain, regardless of whether deterministic or
furnished by us with respect to ownership interests, oil and gas production,
probabilistic methods are used for the estimation.
well test data, historical costs of operation and development, product prices,
or any agreements relating to current and future operations of the fields and
The project to extract the hydrocarbons must have commenced or the
sales of production. However, if in the course of the examination something
operator must be reasonably certain that it will commence the project
came to the attention of DeGolyer and MacNaughton that brought into
within a reasonable time. The term “reasonable certainty” implies a high
question the validity or sufficiency of any such information or data, DeGolyer
degree of confidence that the quantities of oil and/or natural gas actually
and MacNaughton did not rely on such information or data until it had
recovered will equal or exceed the estimate. Reasonable certainty can be
satisfactorily resolved its questions relating thereto or had independently
established using techniques that have been proved effective by actual
verified such information or data. DeGolyer and MacNaughton independently
production from projects in the same reservoir or an analogous reservoir
prepared reserves estimates to conform to the guidelines of the SEC,
or by other evidence using reliable technology that establishes reasonable
including the criteria of “reasonable certainty,” as it pertains to expectations
certainty. Reliable technology is a grouping of one or more technologies
about the recoverability of reserves in future years, under existing economic
(including computational methods) that have been field tested and have been
and operating conditions, consistent with the definition in Rule 4-10(a)(2)
demonstrated to provide reasonably certain results with consistency and
of Regulation S-X. DeGolyer and MacNaughton issued the D&M Reserves
repeatability in the formation being evaluated or in an analogous formation.
Report based upon its evaluation. D&M’s primary economic assumptions
in estimates included oil and gas sales prices determined according to SEC
There are various generally accepted methodologies for estimating reserves
guidelines, future expenditures and other economic assumptions (including
including volumetrics, decline analysis, material balance, simulation models
interests, royalties and taxes) as provided by us. The assumptions, data,
and analogies. Estimates may be prepared using either deterministic (single
methods and procedures used, including the percentage of our total reserves
estimate) or probabilistic (range of possible outcomes and probability of
reviewed in connection with the preparation of the D&M Reserves Report
occurrence) methods. The particular method chosen should be based on
were appropriate for the purpose served by such report, and DeGolyer and
the evaluator’s professional judgment as being the most appropriate, given
MacNaughton used all methods and procedures as it considered necessary
the geological nature of the property, the extent of its operating history and
under the circumstances to prepare such reports.
the quality of available information. It may be appropriate to employ several
However, uncertainties are inherent in estimating quantities of reserves,
including many factors beyond our and our independent reserves engineers’
Estimates must be prepared using all available information (open and cased
control. Reserves engineering is a subjective process of estimating subsurface
hole logs, core analyses, geologic maps, seismic interpretation, production/
accumulations of oil and natural gas that cannot be measured in an exact
injection data and pressure test analysis). Supporting data, such as working
manner, and the accuracy of any reserves estimate is a function of the quality
interest, royalties and operating costs, must be maintained and updated when
methods in reaching an estimate for the property.
of available data and its interpretation. As a result, estimates by different
such information changes materially.
engineers often vary, sometimes significantly. In addition, physical factors
such as the results of drilling, testing and production subsequent to the
Proved undeveloped reserves
date of an estimate, economic factors such as changes in product prices
As of December 31, 2017, we had 58.9 mmboe in proved undeveloped
or development and production expenses, and regulatory factors, such as
reserves, an increase of 10.8 mmboe, or 22%, over our December 31, 2016
royalties, development and environmental permitting and concession terms,
proved undeveloped reserves of 48.1 mmboe. Changes for the year ended
may require revision of such estimates. Our operations may also be affected
December 31 2017, include (i) an increase of 28.4 mmboe in Colombia due
by unanticipated changes in regulations concerning the oil and gas industry
to the Chiricoca, Jacamar and Curucucú Field discoveries in the Llanos 34
in the countries in which we operate, which may impact our ability to recover
Block and the Tigana and Jacana field extensions in the Llanos 34 Block; (ii) an
the estimated reserves. Accordingly, oil and natural gas quantities ultimately
increase of 1.2 mmboe due to the impact of higher average oil prices partially
recovered will vary from reserves estimates.
offset by a removal of 0.6 mmboe of proved undeveloped reserves related to
Technology used in reserves estimation
changes in the development plan in Colombia and (iii) a decrease in reserves
of 5.9 mmboe from the Fell Block mainly related to a change in a previously
According to SEC guidelines, proved reserves are those quantities of oil and
adopted development plan and unsuccessful proved undeveloped executions.
gas which, by analysis of geoscience and engineering data, can be estimated
with “reasonable certainty” to be economically producible—from a given date
During the year ended December 31, 2017, we had 12.5 mmboe of our
forward, from known reservoirs, and under existing economic conditions,
proved undeveloped reserves from December 31, 2016 converted to proved
operating methods and government regulations—prior to the time at which
developed reserves due to development drilling in the Jacana and Tigana
contracts providing the right to operate expire, unless evidence indicates
oil fields in the Llanos 34 Block. See Note 37 to our Consolidated Financial
Statements.
84 GeoPark 20-F
Of our 58.9 mmboe of net proved undeveloped reserves, 44.4 mmboe (75%),
5.3 mmboe (9%), and 9.2 mmboe (16%) were located in Colombia, Chile and
Peru, respectively.
During 2017, we incurred approximately US$19.1 million in capital
expenditures to convert such proved undeveloped reserves to proved
developed reserves, of which approximately US$15.9 million, and US$3.2
million were made in Colombia and Chile, respectively.
No net proved undeveloped reserves were located in Argentina and Brazil as
of December 31, 2017.
The following table shows the evolution of total net proved undeveloped
(“PUD”) reserves in the year ended December 31, 2017.
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2016
48.1
(All amounts shown in mmboe)
Plus: Extensions, discoveries and acquisitions:
-Colombia
-Chile
-Brazil
-Peru
Less: PUD Reserves converted
to proved developed reserves:
-Colombia
-Chile
-Brazil
Plus/less: PUD Reserves revisions
and movement to/from other categories:
-Colombia
-Chile
-Brazil
-Peru
Total Net Proved Undeveloped (“PUD”) Reserves
at December 31, 2017
28.4
0.3
-
-
(12.5)
-
-
0.6
(5.9)
-
(0.1)
58.9
Production, revenues and price history
The following table sets forth certain information on our production of oil
and natural gas in Colombia, Chile, Brazil and Argentina for each of the years
ended December 31, 2017, 2016 and 2015.
GeoPark 85
Average daily production(1)
As of December 31
2017
Colombia
Chile
Brazil
Argentina
Colombia
Chile
2016
Brazil
Colombia
Chile
2015
Brazil
21,718
1,000
42
4
15,536
1,380
39
13,183
1,938
48
36.1
45.7
60.1
52.3
24.4
37.0
48.0
30.4
42.2
53.1
414
11,317
17,209
11,380
19,672
4.5
20.3
1.4
5.8
7.8
3.2
-
-
242.6
10.0
-
-
5.4
1.4
6.7
14,964
17,346
3.8
15.8
1.1
16.9
5.0
5.8
2.8
8.5
-
-
8.8
1.8
4.5
21.0
1.5
4.7
4.4
2.6
7.1
21.7
11.0
252.6
10.6
22.5
Oil production
Average crude oil
production (bopd)
Average sales price of
crude oil (US$/bbl) (3)
Natural gas
Average natural gas
production (mcfpd)
Average sales price of
natural gas (US$/mcf ) (3)
Oil and gas production cost
Average operating cost
(US$/boe)
Average royalties and Other
(US$/boe)
Average production cost
(US$/boe)(2)
5.9
5.6
3.2
8.8
(1) We present production figures net of interests due to others, but before deduction of royalties, as we believe that net production before royalties is more
appropriate in light of our foreign operations and the attendant royalty regimes.
(2) Calculated pursuant to FASB ASC 932.
(3) Averaged realized sales price for oil does not include our Argentine blocks because our Argentine operations were not material during such periods. Averaged
realized sales price for gas does not include our Argentine and Colombian blocks because our gas operations in those countries were not material during such
period.
The following table sets forth certain information on our production of oil and natural gas by final product sold in Colombia, Chile, Brazil and Argentina for each
of the years ended December 31, 2017, 2016 and 2015.
Tigana oil field(1)
Jacana oil field(1)
Rest of Colombia
Chile
Brazil
Argentina(2)
Total
Oil
Mbbl
2,767.0
2,566.0
1,870.0
347.0
15.0
-
2017
Gas
Mmcf
-
-
-
3,745.0
5,763.0
-
7,565.0
9,508.0
Oil
Mbbl
2016
Gas
Mmcf
1,871.5
-
1,188.6
-
2,113.2
-
502.8
5,293.0
14.0
6,314.0
-
-
5,690.1
11,607.0
Oil
Mbbl
1,809.7
151.3
2,615.0
2015
Gas
Mmcf
-
-
-
707.1
4,025.4
17.6
7,213.0
-
-
5,300.7
11,238.4
(1) The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields
in Colombia are separately included in the table above as those oil fields
individually contain more than 15% of our total proved reserves as of each of
the years indicated above.
(2) Production from CN-V Block is related to Río Grande Oeste x1 well. Declaration
of commerciality is still pending as of December 31, 2017.
86 GeoPark 20-F
Drilling activities
The following table sets forth the exploratory wells we drilled as operators
during the years ended December 31, 2017, 2016 and 2015.
Exploratory wells(1)
As of December 31
2017
Colombia
Chile
Brazil
Argentina
Colombia
Chile
2016
Brazil
Colombia
Chile
2015
Brazil
5.0
2.3
1.0
0.5
6.0
2.8
1.0
1.0
-
-
1.0
1.0
-
-
1.0
1.0
1.0
1.0
1.0
0.5
-
-
1.0
0.5
3.0
1.4
-
-
3.0
1.4
-
-
-
-
-
-
-
-
-
-
-
-
3.0
1.4
1.0
0.5
4.0
1.9
-
-
-
-
-
-
-
-
-
-
-
-
Productive(2)
Gross
Net
Dry(3)
Gross
Net
Total
Gross
Net
(1) Includes appraisal wells.
(2) A productive well is an exploratory, development, or extension well that is
not a dry well.
(3) A dry well is an exploratory, development, or extension well that proves to
be incapable of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
The following table sets forth the development wells we drilled as operators
during the years ended December 31, 2017, 2016 and 2015.
Development wells(1)
As of December 31
2017
Colombia
Chile
Brazil
Argentina
Colombia
Chile
2016
Brazil
Colombia
Chile
2015
Brazil
17.0
7.7
1.0
0.5
18.0
8.2
1.0
1.0
-
-
1.0
1.0
-
-
-
-
-
-
-
-
-
-
-
-
3.0
1.4
-
-
3.0
1.4
1.0
1.0
-
-
1.0
1.0
-
-
-
-
-
-
2.0
0.9
-
-
2.0
0.9
-
-
-
-
-
-
-
-
-
-
-
-
Productive(2)
Gross
Net
Dry(3)
Gross
Net
Total
Gross
Net
(1) A productive well is an exploratory, development, or extension well that is
not a dry well.
(2) A dry well is an exploratory, development, or extension well that proves to
be incapable of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
(3) A dry well is an exploratory, development, or extension well that proves to
be incapable of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
GeoPark 87
Developed and undeveloped acreage
Present activities
The following table sets forth certain information regarding our total gross
Our average oil and gas production in the first quarter of 2018 was 32,195
and net developed and undeveloped acreage in Colombia, Chile, Brazil and
mboepd, with oil production of 27,345 mbopd and gas production of 4,850
Peru as of December 31, 2017.
mboepd. Of this total production, 82%, 9% and 9% were in Colombia, Chile
and Brazil, respectively.
Colombia
Chile
Total developed acreage
Acreage(1) (in thousands of acres)
Argentina
Brazil
Perú
During the first quarter of 2018, we drilled and put into production three
wells in Colombia in the Llanos 34 Block, as follows:
Gross
Net
8.5
4.4
8.2
7.7
1.1
0.8
Total undeveloped acreage
Gross
Net
239.8
119.9
799.8
590.0
1,879.9
1,410.0
Total developed and undeveloped acreage
Gross
Net
248.3
124.3
808.0
597.7
1,881.0
1,410.8
4.1
0.4
268.9
249.8
273.0
250.2
-
-
• Tigana Norte 6 development well was drilled to a total depth of 11,596
feet. A production test conducted with an electric submersible pump in
the Guadalupe formation resulted in a production rate of 1,360 bopd of
1,855.6
14.3 degrees API, with 0.6% water cut.
371.4
• Tigana Norte 7 development well was drilled to a total depth of 12,050
feet. A production test conducted with an electric submersible pump in
1,855.6
the Guadalupe formation resulted in a production rate of 424 bopd of 13.5
371.4
degrees API, with 15% water cut.
• Jacana 20 development well was drilled to a total depth of 11,521 feet.
(1)Developed acreage is defined as acreage assignable to productive wells.
Undeveloped acreage is defined as acreage on which wells have not
A production test conducted with an electric submersible pump in the
Guadalupe formation resulted in a production rate of 590 bopd of 16.8
been drilled or completed to a point that would permit the production
degrees API, with 17% water cut.
of commercial quantities of oil or gas regardless of whether such acreage
contains proved reserves. Net acreage based on our working interest.
Additional production history is required to determine stabilized flow rates
of the above mentioned wells.
Productive wells
The following table sets forth our total gross and net productive wells as of
Also, during the first quarter of 2018, we commenced drilling Jet 1 in the
February 28, 2018. Productive wells consist of producing wells and wells capable
POT-T-747 block and 619-AB-1 in the POT-T-619 block exploration wells, which
of producing, including natural gas wells awaiting pipeline connections to
have been abandoned as of the date of this annual report. Jet 1 resulted in a
commence deliveries and oil wells awaiting connection to production facilities.
non-commercial oil discovery, while 619-AB-1 was abandoned after logging
Gross wells are the total number of producing wells in which we have an
as there was no hydrocarbon production potential. Drilling, completion and
interest, and net wells are the sum of our fractional working interests owned in
abandonment costs of these two wells amounted to approximately US$1.7
gross wells.
million.
Productive wells(1)
Marketing and delivery commitments
Colombia
Colombia(2)
Chile
Brazil
Peru
Argentina
Our production in Colombia consists primarily of crude oil. Sales for the year
Oil wells
Gross
Net
Gas wells
Gross
Net
90
54.8
2
0.3
47
44
49
48
-
-
6
0.6
-
-
-
-
1
0.5
-
-
(1)Includes wells drilled by other operators, prior to our commencing operations,
and wells drilled in blocks in which we are not the operator. A productive well is
ended December 31, 2017 were made under a long term sales agreements as
described below.
Evacuation of the oil produced is structured under two types of sales:
wellhead and pipeline. For wellhead sales, delivery point is at the loading
station at fields. For pipeline sales, delivery point is at the uploading station
that discharges to the national pipeline network. In Colombia, pipelines have
minimum quality conditions that restrict access to the system. Consequently,
and because we are mid to heavy oil producers, our entrance to the pipeline
an exploratory, development, or extension well that is not a dry well.
requires the use of diluents which are blended into our crude. For the year
ended December 31, 2017, we sold 99% of our operated production directly at
(2)We acquired Winchester and Luna in February 2012 and Cuerva in March
2012. Figures include wells drilled by Winchester, Luna and Cuerva prior to their
the wellhead.
acquisition by us.
88 GeoPark 20-F
Oil sales are structured under a price formula based on a market reference
Index (Brent or Vasconia) and discounts that consider market fees, quality,
handling fees and transportation among other associated costs.
We signed the Methanex Gas Supply Agreement in Chile in 2009, which
Under the Trafigura Agreement, we followed agreed priorities for the volumes
expired in April 30, 2017. In March 2017, we executed a new gas supply
to be transported through the ODL Pipeline. For the period from March 1,
agreement with Methanex effective from May 1, 2017 to December 31, 2026.
2016 to September 1, 2016, Trafigura received 10,000 bopd of our production.
Under the agreement, Methanex commits to purchase up to 400,000 SCM/d
In 2016 and 2017, the Trafigura Agreement was amended setting the current
of gas produced by us. In 2018, due to the decline in gas production, the
volumes to be delivered to Trafigura to 12,000 bopd until December 2018.
commitment was reduced to 315,000 SCM/d. We also hold an option to deliver
Nonperformance of our obligations of delivery in terms, amounts and quality
up to 15% above this volume.
of the crude to Trafigura may require us to pay Trafigura’s fare commitments in
ODL Pipeline for the transport, dilution and download of crude, and may lead
We gather the gas we produce in several wells through our own flow lines
to early termination of the crude sales agreement as well as the immediate
and inject it into several gas pipelines owned by ENAP. The transportation of
repayment of any amounts outstanding under the prepayment agreement, as
the gas we sell to Methanex through these pipelines is pursuant to a private
well as compensation for other damages.
contract between Methanex and ENAP. We do not own any principal natural
gas pipelines for the transportation of natural gas.
The evacuation strategy is aimed at developing synergies with both the client
and the national systems, in order to obtain a reduction in costs and better
If we were to lose any one of our key customers in Chile, the loss could
revenues by making use of the best practices. In order to achieve this purpose,
temporarily delay production and sale of our oil and gas in Chile. For a
strategic alliances have been established with different agents in the transport
discussion of the risks associated with the loss of key customers, See “Item
chain in order to guarantee direct access to the national network. Such is
3. Key Information—D. Risk factors—Risks relating to our business—We sell
the case of the implementation of an unloading facility in partnership with
almost all of our natural gas in Chile to a single customer, who has in the past
Oleoducto de Los Llanos. This unloading facility is located 42 km away from
temporarily idled its principal facility” and “—We derive a significant portion of
the Llanos 34 block. Therefore, a reduction in transportation costs has been
our revenues from sales to a few key customers.”
gained since the distance for trucking has been reduced significantly.
If we were to lose our key customers, the loss could temporarily delay
Brazil
production and sale of our oil in the corresponding block. However, given
Our production in Brazil consists of natural gas and condensate oil. Natural gas
the wide availability of customers for Colombian crude, we believe we could
production is sold through a long-term, extendable agreement with Petrobras,
identify a substitute customer to purchase the impacted production volumes.
which provides for the delivery and transportation of the gas produced in the
Chile
Manati Field to the EVF gas treatment plant in the State of Bahia. The contract
is in effect until delivery of the maximum committed volume or June 2030,
Our customer base in Chile is limited in number and primarily consists of ENAP
whichever occurs first. The contract allows for sales above the maximum
and Methanex. For the year ended December 31, 2017 we sold 100% of our oil
committed volume if mutually agreed by both seller and buyer. The price
production in Chile to ENAP and 95% of our gas production to Methanex, with
for the gas is fixed in reais and is adjusted annually in accordance with the
sales to ENAP and Methanex accounting for 10% and 9%, respectively, of our
Brazilian inflation index. In July 2015, we signed an amendment to the existing
total revenues in the same period.
Gas Sales Agreement with Petrobras that covers 100% of the remaining gas
reserves in the Manati Field.
On April 21, 2017, we renewed our sales agreement with ENAP. As part of this
agreement, ENAP has committed to purchase our oil production in the Fell
The Manati Field is developed via a PMNT-1 production platform, which is
Block in the amounts that we produce, subject to the limitation of available
connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant
storage capacity at the Gregorio Terminal. The sales agreement provides us
through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd
with the option to interrupt sales to ENAP periodically if conditions in the
(9.5 mm3 per day). The existing pipeline connects the field’s platform to the
export markets allow for more competitive price levels. While the agreement
EVF gas treatment plant, which is owned by the field’s current concession
renews automatically on an annual basis, we typically revise the agreement
holders. During 2015, in order to improve the field gas recovery and
every year to reflect changes in the global oil market and make certain
production, Manatì’s consortium built an onshore compression plant that
adjustments based on ENAP’s expenses related to storage at the Gregorio
started operating in August 2015, which allowed us to classify all existing
Terminal.
proved undeveloped reserves as proved developed as of December 31, 2016.
The BCAM-40 Concession, which includes the Manati Field, also benefits from
Commercial conditions of the new agreement are similar to the previous
the advantages of Petrobras’ size. As the largest onshore and offshore operator
one in effect. We deliver the oil we produce in the Fell Block to ENAP at the
in Brazil, Petrobras has the ability to mobilize the resources necessary to
Gregorio Terminal, where ENAP assumes responsibility for the oil transferred.
support its activities in the concession.
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
The condensate produced in the Manati Field is subject to a condensate
consumed locally.
GeoPark 89
purchase agreement with Petrobras, pursuant to which Petrobras has
exploitation period for an area may be extended until such time as such area
committed to purchase all of our condensate production in the Manati Field,
is no longer commercially viable and certain other conditions are met.
but only in the amounts that we produce, without any minimum or maximum
Pursuant to our E&P Contracts, we are required, as are all oil and gas
deliverable commitment from us. The agreement is valid through December
companies undertaking exploratory and production activities in Colombia,
31, 2018, and can be renewed upon an amendment signed by Petrobras and
to pay a royalty to the Colombian government based on our production
the seller.
Peru
of hydrocarbons, as of the time a field begins to produce. Under Law 756
of 2002, as modified by Law 1530 of 2012, the royalties we must pay in
connection with our production of light and medium oil are calculated on a
In Peru, oil production is generally traded on a free market basis and
field-by-field basis. See Note 32(a) to our Consolidated Financial Statements.
commercial conditions generally follow international markers, normally WTI
Additionally, in the event that an exploitation area has produced amounts in
and Brent. As per the Joint Operating Agreement executed with Petroperu,
excess of an aggregate amount established in the E&P Contract governing
Petroperu has the first option to acquire oil produced by us in the Morona
such area, the ANH is entitled to receive a “windfall profit,” to be paid
Block by matching any offer received by third parties regarding such
periodically, calculated pursuant to such E&P Contract.
production.
Future production in the Morona Block is expected to be transported through
to pay the ANH a subsoil use fee. During the exploration period, this fee is
the existing North Peruvian Pipeline. This transportation system is owned
scaled depending on the contracted acreage. During the exploitation period,
and operated by Petroperu, and regulated and supervised by OSINERGMIN,
the fee is assessed on the amount of hydrocarbons produced, multiplied by
the regulatory body in the hydrocarbons sector. Transportation rates are
a specified dollar amount per barrel of oil produced or thousand cubic feet
negotiated with Petroperu. However, if an agreement cannot be reached
of gas produced. Further, the ANH has the right to receive an additional fee
between Petroperu and us, transportation rates will be determined by
when prices for oil or gas, as the case may be, exceed the prices set forth in
In each of the exploration and exploitation periods, we are also obligated
OSINERGMIN. The North Peruvian pipeline was out of service in 2017 due to
the relevant E&P Contract.
technical issues. The Peruvian government has enacted a law declaring that
the pipeline’s operation is a matter of national interest, and is implementing a
Our E&P Contracts are generally subject to early termination for a breach
maintenance program accordingly. See “Item 3. Risk factors—Risks relating to
by the parties, a default declaration, application of any of the contract’s
our business—Our inability to access needed equipment and infrastructure
unilateral termination clauses or termination clauses mandated by
in a timely manner may hinder our access to oil and natural gas markets and
Colombian law. Anticipated termination declared by the ANH results in
generate significant incremental costs or delays in our oil and natural gas
the immediate enforcement of monetary guaranties against us and may
production.”
Argentina
result in an action for damages by the ANH. Pursuant to Colombian law, if
certain conditions are met, the anticipated termination declared by the ANH
may also result in a restriction on the ability to engage contracts with the
The crude produced in our CN-V block in Mendoza is sold to YPF SA (“YPF”)
Colombian government during a certain period of time. See “Item 3. Key
under short term agreements that can be renewed by the parties. The
Information—D. Risk factors—Risks relating to our business—Our contracts
Argentine crude market standard has been to transact under short term
in obtaining rights to explore and develop oil and natural gas reserves
agreements over the past years, making our agreement with YPF aligned to
are subject to contractual expiration dates and operating conditions, and
outstanding domestic market practices. YPF additionally provides us with
our CEOPs, E&P Contracts and concession agreements are subject to early
receipt and treatment services for a fee.
termination in certain circumstances.”
Significant Agreements
Colombia
E&P Contracts
Llanos 34 Block E&P Contract . Pursuant to an E&P Contract between Unión
Temporal Llanos 34 (a consortium between Ramshorn and Winchester Oil and
Gas - now GeoPark Colombia SAS) and the ANH that became effective as of
We have entered into E&P Contracts granting us the right to explore and
March 13, 2009 (“Llanos 34 Block E&P Contract”), Unión Temporal Llanos 34
operate, as well as working interests in six blocks in Colombia. These E&P
was granted the right to explore and operate the Llanos 34 Block, and we and
Contracts are generally divided into two periods: (1) the exploration period,
Ramshorn were granted a 40% and a 60% working interest, respectively, in the
which may be subdivided into various exploration phases and (2) the
Llanos 34 Block. We were also granted the right to operate the Llanos 34 Block.
exploitation period, determined on a per-area basis and beginning on the
On December 16, 2009, Winchester Oil and Gas (now GeoPark Colombia)
date we declare an area to be commercially viable. Commercial viability
entered into a joint operating agreement with Ramshorn and P1 Energy with
is determined upon the completion of a specified evaluation program
respect to our operations in the block. As of the date of this annual report, the
or as otherwise agreed by the parties to the relevant E&P Contract. The
members of the Union Temporal Llanos 34 are GeoPark Colombia SAS with
90 GeoPark 20-F
45%, and Parex Verano Limited with 55% working interest.
transportation costs; (iii) simplifying logistics and reducing risks; and (iv)
improving working capital. Pricing is determined at future spot market prices,
We are currently in an additional exploration period (the contract provides
net of transportation costs. The agreement has given us access to funding up
for two optional exploratory phases of 18 months each, in which the operator
to US$100 million from Trafigura, subject to applicable volumes corresponding
carries out exploratory activities in order to retain areas to explore) of the
to the terms of the agreement, in the form of prepaid future oil sales. Funds
Llanos 34 Block E&P Contract with an exploitation program in execution
committed by Trafigura will be made available to us upon request and will be
over certain areas. The contract also provides for a six-year exploration
repaid by us through future oil deliveries over the period of the contract, until
period consisting of two three-year phases. It also provides for a 24-year
December 31, 2018, with a 6-month grace period.
exploitation period for each commercial area, which begins on the date on
which such area is declared commercially viable. The exploitation period may
During 2016 and 2017 we executed successive amendments to the Trafigura
be extended for periods of up to 10 years at a time until such time as the area
offtake and prepayment agreement which increased volumes delivered,
is no longer commercially viable and certain conditions are met. We have
improved pricing and extended the availability period for funding.
presented evaluation programs to the ANH for the Tilo Field. We presented
the declaration of commerciality of Max, Túa, Tarotaro, Tigana, Jacana and
Chachalaca, respectively.
Chile
CEOPs
Currently, we have five CEOPs in effect with Chile, one for each of the
Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are
blocks in which we operate, which grant us the right to explore and exploit
required to pay a royalty to the ANH based on hydrocarbons produced in the
hydrocarbons in these blocks, determine our working interests in the
Llanos 34 Block. See Note 32(a) to our Consolidated Financial Statements.
blocks and appoint the operator of the blocks. These CEOPs are divided into
Additionally, we are required to pay a subsoil use fee to the ANH. ANH also
two phases: (1) an exploration phase, which is divided into two or more
has the right to receive an additional fee when prices for oil or gas, as the case
exploration periods, and which begins on the effectiveness date of the
may be, exceed the prices set forth in the Llanos 34 Block E&P Contract. The
relevant CEOP, and (2) an exploitation phase, which is determined on a per-
ANH also has an additional economic right equivalent to 1% of production,
field basis, commencing on the date we declare a field to be commercially
net of royalties.
viable and ending with the term of the relevant CEOP. In order to transition
from the exploration phase to an exploitation phase, we must declare a
In accordance with the Llanos 34 Block operation contract, when the
discovery of hydrocarbons to the Ministry of Energy. This is a unilateral
accumulated production of each field, including the royalties’ volume, exceeds
declaration, which grants us the right to test a field for a limited period of
5 million barrels and the WTI exceeds a defined base price, the Company
time for commercial viability. If the field proves commercially viable, we
should deliver to ANH a share of the production net of royalties in accordance
must make a further unilateral declaration to the Ministry of Energy. In the
with an established formula. See Note 32(a) to our Consolidated Financial
exploration phase, we are obligated to fulfill a minimum work commitment,
Statements.
which generally includes the drilling of wells, the performance of 2D or 3D
seismic surveys, minimum capital commitments and guaranties or letters
Winchester and Luna Stock Purchase Agreement
of credit, as set forth in the relevant CEOP. We also have relinquishment
Pursuant to the stock purchase agreement entered into on February 10, 2012
obligations at the end of each period in the exploration phase in respect
(the “Winchester Stock Purchase Agreement”), we agreed to pay the Sellers a
of those areas in which we have not made a declaration of discovery.
total consideration of US$30.0 million, adjusted for working capital. Additionally,
We can also voluntarily relinquish areas in which we have not declared
under the terms of the Winchester Stock Purchase Agreement, we are obligated
discoveries of hydrocarbons at any time, at no cost to us. In the exploitation
to make certain payments to the Sellers based on the production and sale of
phase, we generally do not face formal work commitments, other than the
hydrocarbons discovered by exploration wells drilled after October 25, 2011.
development plans we file with the Chilean Ministry of Energy for each field
Once the maximum earn-out amount is reached, we pay the Sellers quarterly
declared to be commercially viable.
overriding royalties in an amount equal to 4% of our net revenues from any new
discoveries of oil. For the year ended December 31, 2017, we accrued and paid
Our CEOPs provide us with the right to receive a monthly remuneration
US$11.4 million and US$10.0 million with regards to this agreement.
from Chile, payable in petroleum and gas, based either on the amount of
Trafigura offtake and prepayment agreement
petroleum and gas production per field or according to Recovery Factor,
which considers the ratio of hydrocarbon sales to total cost of production
In December 2015, we entered into an offtake and prepayment agreement
(capital expenditures plus operating expenses). Pursuant to Chilean law,
with Trafigura. The agreement provides that we sell and deliver a portion
the rights contained in a CEOP cannot be modified without consent of the
of our Colombian crude oil production to Trafigura. This benefits us by (i)
parties.
improving crude oil sales prices; (ii) improving operating netbacks by reducing
GeoPark 91
Our CEOPs are subject to early termination in certain circumstances, which
ENAP, signed 3 new CEOPs for the Isla Norte, Campanario and Flamenco
vary depending upon the phase of the CEOP. During the exploration
Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes region.
phase, Chile may terminate a CEOP in circumstances including a failure
Our working interest is 60% in Isla Norte and 50% in Campanario and
by us to comply with minimum work commitments at the termination
Flamenco Blocks. The CEOPs have a term of 32 years, with an initial
of any exploration period, or a failure to communicate our intention to
exploration phase which last for 7 years, including a first exploration period
proceed with the next exploration period 30 days prior to its termination,
of 3 years in which we are committed to developing several exploration
a failure to provide the Chilean Ministry of Energy the performance bonds
activities including 1,500 square kilometers of 3D seismic registration, and
required under the CEOP, a voluntary relinquishment by us of all areas
the drilling of 21 exploratory wells.
under the CEOP or a failure by us to meet the requirements to enter into
the exploitation phase upon the termination of the exploration phase. In
The hydrocarbon discoveries opened up an exploitation phase that lasts
the exploitation phase, Chile may terminate a CEOP if we stop performing
up to 32 years. We discovered hydrocarbon fields in the 3 blocks, starting
any of the substantial obligations assumed under the CEOP without
2013 in the Flamenco Block, and in 2014 in both Campanario and Isla Norte
cause and do not cure such nonperformance pursuant to the terms of
Blocks. The CEOPs provide us with a right to receive a remuneration payable
the concession, following notice of breach from the Chilean Ministry of
by means of a fraction of the production sold, which in the TDF Blocks is
Energy. Additionally, Chile may terminate the CEOP due to force majeure
based on a formula depending on the recovery of the total accumulated
circumstances (as defined in the relevant CEOP). If Chile terminates a CEOP
expenses incurred (capital expenditure plus operational expenditure plus
in the exploitation phase, we must transfer to Chile, free of charge, any
administrative and general expenses). While the recovery factor is less than
productive wells and related facilities, provided that such transfer does not
1.0, the remuneration is 95% of the hydrocarbons produced, either oil or gas.
interfere with our abandonment obligations and excluding certain pipelines
If the recovery factor surpasses 1.0, a formula applies reducing gradually the
and other assets. Other than as provided in the relevant CEOP, Chile cannot
remuneration fraction to a minimum of 75% when the recovery factor is 2.5
unilaterally terminate a CEOP without due compensation. See “Item 3. Key
times the total accumulated expenses.
Information—D. Risk factors—Risks relating to our business—Our contracts
in obtaining rights to explore and develop oil and natural gas reserves
Brazil
are subject to contractual expiration dates and operating conditions, and
Rio das Contas Quota Purchase Agreement
our CEOPs, E&P Contracts and concession agreements are subject to early
Pursuant to the Rio das Contas Quota Purchase Agreement we entered into
termination in certain circumstances.”
on May 14, 2013, we agreed to acquire from Panoro all of the quotas issued
by Rio das Contas for a purchase price of US$140 million (subject to working
Fell Block CEOP . On November 5, 2002, we acquired a percentage of rights and
capital adjustments at closing and further earn-out payments, if any) upon
interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and
satisfaction of certain conditions. With respect to the earn-out payments, the
on May 10, 2006, we became the sole owners, with 100% of the rights and
Rio das Contas Quota Purchase Agreement provides that during the calendar
interest in the Fell Block CEOP. Chile had originally entered into a CEOP for the
periods beginning on January 1, 2013 and ending as late as December 31,
Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April 29, 1997,
2017, we will make annual earn-out payments to Panoro in an amount equal
which had an effective date of August 25, 1997. The Fell Block CEOP grants us
to 45% of “net cash flow,” calculated as EBITDA less the aggregate of capital
the exclusive right to explore and exploit hydrocarbons in the Fell Block and
expenditures and corporate income taxes, with respect to the BCAM-40
has a term of 35 years, beginning on the effective date. The Fell Block CEOP
Concession of any amounts in excess of US$25.0 million, up to a maximum
provided for a 14-year exploration period, composed of numerous phases that
cumulative earn-out amount of US$20.0 million in a five-year period. Once the
ended in 2011, and an up-to-35-year exploitation phase for each field.
maximum earn-out amount is reached or the five-year period has elapsed, no
further earn-out amounts will be payable. For the year ended December 31,
The Fell Block CEOP provides us with a right to receive a monthly retribution
2017, there were no earn-out payments with regards to this agreement.
from Chile payable in petroleum and gas, based on the following per-
field formula: 95% of the oil produced in the field, for production of up to
We financed our Rio das Contas acquisition in part through our Brazilian
5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for
subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas
production of up to 882.9 mmcfpd. In the event that we exceed these levels
Credit Facility”) with Itaú BBA International plc, which is secured by the
of production, our monthly retribution from Chile will decrease based on a
benefits we receive under the Purchase and Sale Agreement for Natural Gas
sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the
with Petrobras. See “Item 5. Operating and Financial Review and Prospects—B.
oil and 60% of the gas that we produce per field.
Liquidity and capital resources—Indebtedness—Rio das Contas Credit Facility.”
The loan was fully repaid in September 2017.
TDF Blocks CEOPs . After an international bidding process led by ENAP and
the Chilean Ministry of Energy, in March and April, 2012, we, together with
92 GeoPark 20-F
Overview of concession agreements
minimum exploration program proposed in the winning bid; (4) activities for
The Brazilian oil and gas industry is governed mainly by the Brazilian
the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments
Petroleum Law, which provides for the granting of concessions to operate
for government participation; and (7) responsibility for the costs associated
petroleum and gas fields in Brazil, subject to oversight by the ANP. A
with the deactivation and abandonment of the facilities in accordance with
concession agreement is divided into two phases: (1) exploration and (2)
Brazilian law and best practices in the oil industry.
development and production. The exploration phase, which is further divided
into two subsequent exploratory periods, the first of which begins on the date
A concessionaire is required to pay to the Brazilian government the following:
of execution of the concession agreement, can last from three to eight years
• a license fee;
(subject to earlier termination upon the total return of the concession area
• rent for the occupation or retention of areas;
or the declaration of commercial viability with respect to a given area), while
• a special participation fee;
the development and production phase, which begins for each field on the
• royalties; and
date a declaration of commercial viability is submitted to the ANP, can last up
• taxes.
to 27 years. Upon each declaration of commercial viability, a concessionaire
must submit to the ANP a development plan for the field within 180 days. The
Rental fees for the occupation and maintenance of the concession areas are
concessions may be renewed for an additional period equal to their original
payable annually. For purposes of calculating these fees, the ANP takes into
term if renewal is requested with at least 12 months’ notice, and provided
consideration factors such as the location and size of the relevant concession, the
that a default under the concession agreement has not occurred and is then
sedimentary basin and the geological characteristics of the relevant concession.
continuing. Even if obligations have been fulfilled under the concession
agreement and the renewal request was appropriately filed, renewal of the
A special participation fee is an extraordinary charge that concessionaires
concession is subject to the discretion of the ANP.
must pay in the event of obtaining high production volumes and/or
profitability from oil fields, according to criteria established by applicable
The main terms and conditions of a concession agreement are set forth
regulations, and is payable on a quarterly basis for each field from the date
in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of
on which extraordinary production occurs. This participation fee, whenever
the concession area; (2) validity and terms for exploration and production
due, varies between 0% and 40% of net revenues depending on (1) the
activities; (3) conditions for the return of concession areas; (4) guarantees to
volume of production and (2) whether the concession is onshore or in shallow
be provided by the concessionaire to ensure compliance with the concession
water or deep water. Under the Brazilian Petroleum Law and applicable
agreement, including required investments during each phase; (5) penalties
regulations issued by the ANP, the special participation fee is calculated
in the event of noncompliance with the terms of the concession agreement;
based on the quarterly net revenues of each field, which consist of gross
(6) procedures related to the assignment of the agreement; and (7) rules for
revenues calculated using reference prices established by the ANP (reflecting
the return and vacancy of areas, including removal of equipment and facilities
international prices and the exchange rate for the period) less:
and the return of assets. Assignments of participation interests in a concession
• royalties paid;
are subject to the approval of the ANP, and the replacement of a performance
• investment in exploration;
guarantee is treated as an assignment.
• operational costs; and
• depreciation adjustments and applicable taxes.
The main rights of the concessionaires (including us in our concession
agreements) are: (1) the exclusive right of drilling and production in the
The Brazilian Petroleum Law also requires that the concessionaire of onshore
concession area; (2) the ownership of the hydrocarbons produced; (3) the
fields pay to the landowners a special participation fee that varies between
right to sell the hydrocarbons produced; and (4) the right to export the
0.5% to 1.0% of the net operational income originated by the field production.
hydrocarbons produced. However, a concession agreement set forth that,
in the event of a risk of a fuel supply shortage in Brazil, the concessionaire
BCAM-40 Concession Agreement . On August 6, 1998, the ANP and Petrobras
must fulfill the needs of the domestic market. In order to ensure the domestic
executed the concession agreement governing the BCAM-40 Concession, or
supply, the Brazilian Petroleum Law granted the ANP the power to control the
the BCAM-40 Concession Agreement, following the first round of bidding,
export of oil, natural gas and oil products.
referred to as Bid Round Zero, under the regime established by the Brazilian
Petroleum Law. The exploitation phase will end in November 2029. On
Among the main obligations of the concessionaire are: (1) the assumption of
September 11, 2009, Petrobras announced the termination of BCAM-40
costs and risks related to the exploration and production of hydrocarbons,
Concession’s exploration phase and the return of the exploratory area of the
including responsibility for environmental damages; (2) compliance with the
concession to the ANP, except for the Manati Field and the Camarão Norte Field.
requirements relating to acquisition of assets and services from domestic
suppliers; (3) compliance with the requirements relating to execution of the
Under the BCAM-40 Concession Agreement, the ANP is entitled to a monthly
GeoPark 93
royalty payment equal to 7.5% of the production of oil and natural gas in the
right to terminate it. The BCAM-40 Concession consortium has also entered
concession area. In addition, in case the special participation fee of 10% shall
into a joint operating agreement, which sets out the rights and obligations of
be applicable for a field in any quarter of the calendar year, the concessionaire
the parties in respect of the operations in the concession.
is obliged to make qualified research and development investments equivalent
to one percent of the field’s gross revenue. Area retention payments are also
Petrobras Natural Gas Purchase Agreement
applicable under the concession agreement. We acquired Rio das Contas’ 10%
QGEP, GeoPark Brasil, Brasoil and Petrobras are party to a natural gas purchase
participation interest in the BCAM-40 Concession on March 31, 2014.
agreement providing for the sale of natural gas by QGEP, GeoPark Brasil and
Rounds 11, 12, 13 and 14 Concession Agreements.
term of agreement. The Petrobras Natural Gas Purchase Agreement is valid
Under the Rounds 11, 12, 13 and 14 Concession Agreements, the ANP is
until the earlier of Petrobras’ receipt of this total contractual quantity or June
entitled to a monthly royalty corresponding to up to 10% of the production
30, 2030. The agreement may not be fully or partially assigned except upon
of oil and natural gas in the concession area, in addition to the special
execution of an assignment agreement with the written consent of the other
participation fee described above, the payment for the occupation of the
parties, which consent may not be unreasonably withheld provided that
Brasoil to Petrobras, in an amount of 812 billion cubic feet (“bcf”) over the
concession area of approximately R$7,600 per year and the payment to the
certain prerequisites have been met.
owners of the land of the concession equivalent to one percent of the oil and
natural gas produced in the concession area.
The agreement provides for the provision of “daily contractual quantities” to
Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until
During bidding, a work program offer is made in the form of work units and
2030. The parties may agree to lower volumes as dictated by Manati Field’s
the ANP asks for a guarantee of a monetary amount proportional to the
depletion. Pursuant to the agreement, the base price is denominated in reais
offered units. However, depending on the work performed by the operator,
and is adjusted annually for inflation pursuant to the general index of market
the actual work program investment might have a different value to the
prices (IGPM). Additionally, the gas price applicable on a given day is subject
guaranteed value.
Overview of consortium agreements
to reduction as a result of the gas quantity acquired by Petrobras above the
volume of the annual TOP commitment (85% of the daily contracted quantity)
in effect on such day. The Petrobras Natural Gas Purchase Agreement provides
A consortium agreement is a standard document describing consortium
that all of the Manati Field’s daily production be sold to Petrobras.
members’ respective percentages of participation and appointment of
the operator. It generally provides for joint execution of oil and natural
Peru
gas exploration, development and production activities in each of the
Morona Block
concession areas. These agreements set forth the allocation of expenses for
On October 1, 2014, we entered into an agreement with Petroperu to acquire
each of the parties with respect to their respective participation interests
an interest in and operate the Morona Block, located in Northern Peru. We will
in the concession. The agreements are supplemented by joint operating
assume a 75% working interest of the Morona Block, with Petroperu retaining
agreements, which are private instruments that typically regulate the
a 25% working interest. On December 1, 2016, through Supreme Decree N°
aggregation of funds, the sharing of costs, mitigation of operational risks,
031-2016-MEN the Peruvian government approved the amendment to the
preemptive rights and the operator’s activities.
License Contract of Block 64 (Morona Block) appointing GeoPark as operator
and holder of 75% of the Contract.
An important characteristic of the consortia for exploration and production
of oil and natural gas that differs from other consortia (Article 278, paragraph
In Peru, there is a 5-20% sliding scale royalty rate, depending on production
1, of the Brazilian Corporate Law) is the joint liability among consortium
levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For
members as established in the Brazilian Petroleum Law (Article 38, item II).
production between 5,000 and 100,000 bopd there is a linear sliding scale
between 5% and 20%. Production over 100,000 bopd has a flat royalty of 20%.
BCAM-40 Consortium Agreement
On January 14, 2000, Petrobras, QG Perfurações and Petroserv entered
See “Item 4. Information on the Company—B. Business Overview—Our
into a consortium agreement, or the BCAM-40 Consortium Agreement, for
operations—Operations in Peru—Morona Block.”
the performance of the BCAM-40 Concession Agreement. Petrobras is the
operator of the BCAM-40 concession, with a 35% participation interest. QGEP,
Argentina
Brasoil and Rio das Contas have a 45%, 10% and 10% participation interest,
Overview of exploration permits
respectively. The BCAM-40 Consortium Agreement has a specified term of
Our exploration permits grant to us and our partners the exclusive right to
40 years, terminating on January 14, 2040 and, at the time the obligations
explore for hydrocarbons and declare a commercial discovery within the acreage
undertaken in the agreement are fully completed, the parties will have the
of our permits. Our exploration permits are made up of three subperiods, each
lasting 3, 2 and 1 year(s), respectively, plus an extension period of up to 5 years.
94 GeoPark 20-F
We are bound to pursue specific minimum work or investment commitments
gas production of 2,700 boepd (70% light oil and 30% gas), 137,000 acres
during each of the subperiods of each exploration permit. Such exploration
well-positioned in the Neuquen Basin and production facilities, including
works are valued in work units assigned to each particular type of work under
hydrocarbons treatment, storage, and delivery infrastructure.
the applicable bidding conditions.
Work and investment programs for the permits are required to be assured by
We paid the consideration using proceeds from the offering of the Notes due
issuing a performance bond for the value of the committed work plan.
2024. The acquisition of the blocks closed on March 27, 2018.
Under the terms of our exploration permits and concession agreements, we are
Agreements with LGI
entitled to our proportionate share of the hydrocarbons production lifted from
LGI Colombia Agreements
each block. The Province of Mendoza’s state owned company, EMESA, has a 10%
In December 2012, we agreed with LGI to extend our strategic partnership
carried interest in each of the Puelen and Sierra del Nevado permits and any
to build a portfolio of upstream oil and gas assets throughout Latin America.
future exploitation concessions, while there is no governmental participation
On December 18, 2012, LGI agreed to acquire a 20% equity interest in
in the CN-V Block. During the term of our exploration permits, we are also
GeoPark Colombia SAS by making a US$14.9 million capital contribution
required, under Argentine law, to pay a 15% royalty to the province on both oil
and a US$4.9 million loan to GeoPark Colombia SAS and miscellaneous
and gas sales. In case we progress to an exploitation concession, the applicable
reimbursements. Concurrently, we entered into a shareholders’ agreement
royalty rate will reduce to a 12% royalty. We also pay annual surface rental
with LGI (the “LGI Colombia Shareholders’ Agreement”) setting forth
fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and
LGI’s and our respective obligations in connection with LGI’s investment
Resolution 588/98 of the Argentine Secretariat of Energy and Decree 1454/2007,
in our Colombian oil and gas business through GeoPark Colombia SAS.
and certain landowner fees.
Furthermore, LGI and Winchester (now GeoPark Colombia SAS) entered
into a loan agreement, whereby, upon the closing of LGI’s subscription of
Our Argentine exploration permits have no change of control provisions, though
shares in GeoPark Colombia SAS, LGI granted a credit line (of which US$4.9
any assignment of these concessions is subject to the prior authorization by the
million was drawn at closing) to Winchester of up to US$12.0 million, to
executive branch of the Province of Mendoza and rights of first refusal in favor
be used for the acquisition, development and operation of oil and gas
of our partners and EMESA, in the case of the Puelen and Sierra del Nevado
assets in Colombia. Further, on January 8, 2014, following an internal
permits. Each of these permits or future concessions can be terminated for
corporate reorganization of our Colombian operations, GeoPark Colombia
default in payment obligations and/or breach of material statutory or regulatory
Coöperatie U.A. and GeoPark Latin America entered into a new members’
obligations. We are subject to the obligation to relinquish at least 50% of the
agreement with LGI, or the LGI Colombia Members’ Agreement, that sets out
acreage of each exploration permit at the end of each exploration subperiod. We
substantially similar rights and obligations to the LGI Colombia Shareholders’
may also voluntarily relinquish acreage to the provincial authorities.
Agreement in respect of our oil and gas business through GeoPark Colombia
SAS only. We refer to the LGI Colombia Shareholders’ Agreement and the LGI
Our Argentine exploration permits are governed by the laws of Argentina and
Colombia Members’ Agreement collectively as the LGI Colombia Agreements.
the resolution of any disputes must be sought in the Mendoza Provincial Courts.
If and when we make a commercial discovery in one or more of our exploration
Under the LGI Colombia Agreements, LGI agreed to assume its share of the
permits, we will have the right to request and obtain an exploitation concession
existing debt of GeoPark Colombia SAS and to provide additional funding
to produce hydrocarbons in the block for 25 years, with an optional extension
to cover LGI’s share of required future investments in Colombia through
of up to 10 years. We also receive the right to be granted a 35-year oil transport
GeoPark Colombia SAS. In addition, we can earn back up to 12% additional
concession to build and make use of pipelines or other transport facilities
equity interests in GeoPark Colombia depending on the success of our
beyond the boundaries of the concession.
Colombian operations.
Additionally, oil and gas producers in Argentina must grant a privilege to the
Currently, GeoPark Colombia Coöperatie has four directors, out of which one
domestic market to the detriment of the export market, including hydrocarbon
Director is elected by LGI. The LGI Colombia Agreements require the consent
export restrictions, domestic price controls, export duties and domestic market
of LGI or the LGI-appointed director for GeoPark Colombia SAS to take certain
supplier obligations.
actions, including, among others:
Pluspetrol Asset Purchase Agreement
• making any decision to terminate or permanently or indefinitely suspend
operations in or surrender our blocks in Colombia (other than as required
Pursuant to the APA that we entered into on December 18, 2017 with
under the terms of the relevant concessions for such blocks);
Pluspetrol, we agreed to acquire a 100% working interest and operatorship
• creating of a security interest over our blocks in Colombia;
of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina
• approving of GeoPark Colombia’s annual budget and work programs and
for a total consideration of $52 million. The blocks include estimated oil and
the mechanisms for funding any such budget or program;
• entering into of any borrowings other than those provided in an approved
GeoPark 95
budget or incurred in the ordinary course of business to finance working
The respective boards of each of GeoPark Chile and GeoPark TdF supervise
capital needs;
their day-to-day operations. Each of these boards has four directors. As long
• granting any guarantee or indemnity to secure liabilities of parties other
as LGI holds at least 5% of the voting shares of GeoPark Chile, LGI has the
than those of our Colombian subsidiaries;
right to elect one director and such director’s alternate, and the remaining
• changing the dividend, voting or other rights that would give preference to
directors, and alternates, are elected by us. As long as LGI holds at least 5%
or discriminate against the shareholders of GeoPark Colombia;
of the voting shares of GeoPark TdF, LGI has the right to elect one director
• entering into certain related party transactions;
and such director’s alternate, and the remaining directors, and alternates, are
• paying dividends from GeoPark Colombia Coöperatie; and
elected by GeoPark Chile.
• disposing of any material assets other than those provided for in an
approved budget and work program.
The LGI Chile Shareholders’ Agreements require the consent of LGI or the LGI
appointed director in order for GeoPark Chile and GeoPark TdF, as the case
We have also agreed to ensure that the board of directors and rules and
may be, to take certain actions, including, among others:
management of our other subsidiaries engaged in our Colombian oil and gas
• making any decision to terminate or permanently or indefinitely suspend
business are subject to the same principlesa nd restrictions outlined above.
operations in or surrender our blocks in Chile (other than as required under
the terms of the relevant CEOP for such blocks or required by law);
The LGI Colombia Agreements provide that if either we or LGI decide to sell
• selling our blocks in Chile to our affiliates;
our respective participation in GeoPark Colombia Coöperatie, the transferring
• any change to the dividend, voting or other rights that would give
party must make an offer to sell its participation to the other party before
preference to or discriminate against the shareholders of GeoPark Chile and
selling those shares to a third party. In addition, any sale to a third party is
GeoPark TdF;
subject to tag-along and drag-along rights, and the non-transferring party has
• entering into certain related party transactions; and
the right to object to a sale to the third-party if it considers such third-party to
• creating a security interest over our blocks in Chile (other than in
be not of a good reputation or one of our direct competitors.
connection with a financing that benefits our Chilean subsidiaries).
Under the LGI Colombia Agreements, we have agreed, along with LGI, to
The LGI Chile Shareholders’ Agreements provide that if LGI or either Agencia
vote or otherwise cause GeoPark Colombia SAS to declare dividends only
or GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark TdF, as
after allowing for retentions for approved work programs and budgets and
the case may be, the transferring shareholder must make an offer to sell those
capital adequacy requirements of GeoPark Colombia Coöperatie, working
shares to the other shareholder before selling those shares to a third party. In
capital requirements, banking covenants associated with any loan entered
addition, any sale to a third party is subject to tag-along and drag-along rights,
into by GeoPark Colombia Coöperatie and its subsidiary. See “Item 3. Key
and the non-transferring shareholder has the right to object to a sale to the
Information—D. Risk factors—Risks relating to our business—LGI, our
third-party if it considers such third-party to be not of a good reputation or
strategic partner in Chile and Colombia, may not consent to our taking
one of our direct competitors. Under the LGI Chile Shareholders’ Agreements,
certain actions or may eventually decide to sell its interest in our Chilean and
we and LGI have also agreed to vote our common shares or otherwise cause
Colombian operations to a third party.”
LGI Chile Shareholders’ Agreements
GeoPark Chile or GeoPark TdF, as the case may be, to declare dividends only
after allowing for retentions to meet anticipated future investments, costs
and obligations. See “Item 3. Key Information—D. Risk factors—Risks relating
In 2010, we formed a strategic partnership with LGI to jointly acquire and
to our business—LGI, our strategic partner in Chile and Colombia, may not
develop upstream oil and gas projects in Latin America. In 2011, LGI acquired
consent to our taking certain actions or may eventually decide to sell its
a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark
interest in our Chilean and Colombian operations to a third party.”
TdF, for a total consideration of US$148.0 million, plus additional equity
funding of US$18.0 million over the following three years. On May 20, 2011,
Title to properties
in connection with LGI’s investment in GeoPark Chile, we entered into a
In each of the countries in which we operate, the state is the exclusive owner
shareholders’ agreement with LGI (as amended on July 4, 2011 and October
of all hydrocarbon resources located in such country and has full authority
4, 2011, the “GeoPark Chile Shareholders’ Agreement”) and a subscription
to determine the rights, royalties or compensation to be paid by private
agreement (as amended on July 4, 2011 and October 4, 2011), On October
investors for the exploration or production of any hydrocarbon reserves. In
2011, in connection with LGI’s investment in GeoPark TdF, we entered
Chile, the Republic of Chile grants such rights through a CEOP. In Colombia,
into a shareholder´s agreement with LGI (the “GeoPark TdF Shareholders
the Republic of Colombia grants such rights through E&P Contracts or
Agreement”, and together with the GeoPark Chile Shareholders’ Agreement,
contracts of association. In Argentina, the Argentine Republic grants such
the “LGI Chile Shareholders’ Agreements”), setting forth LGI’s and our
rights through exploitation concessions. In Brazil, the Federative Republic
respective rights and obligations in connection with LGI’s investment in our
of Brazil grants such rights pursuant to concession agreements. See “Item 3.
Chilean oil and gas business.
96 GeoPark 20-F
Key Information—D. Risk factors—Risks relating to the countries in which
competition from other independent operators and from major state-owned
we operate—Oil and natural gas companies in Colombia, Chile, Brazil, Peru
oil companies in acquiring and developing licenses in the countries where we
and Argentina do not own any of the oil and natural gas reserves in such
operate or plan to operate.
countries.” Other than as specified in this annual report, we believe that we
have satisfactory rights to exploit or benefit economically from the oil and
Many of these competitors have financial and technical resources and
gas reserves in the blocks in which we have an interest in accordance with
personnel substantially larger than ours. As a result, our competitors may be
standards generally accepted in the international oil and gas industry. Our
able to pay more for desirable oil and natural gas assets, or to evaluate, bid
CEOPs, E&P Contracts, contracts of association, exploitation concessions
for and purchase a greater number of licenses than our financial or personnel
and concession agreements are subject to customary royalty and other
resources will permit. Furthermore, these companies may also be better able
interests, liens under operating agreements and other burdens, restrictions
to withstand the financial pressures of unsuccessful wells, sustained periods of
and encumbrances customary in the oil and gas industry that we believe
volatility in financial and commodities markets and generally adverse global
do not materially interfere with the use of or affect the carrying value of our
and industry-wide economic conditions, and may be better able to absorb the
interests. See “Item 3. Key Information—D. Risk factors—Risks relating to
burdens resulting from changes in relevant laws and regulations, which may
our business—We are not, and may not be in the future, the sole owner or
adversely affect our competitive position. See “Item 3. Key Information—D.
operator of all of our licensed areas and do not, and may not in the future,
Risk factors—Risks relating to our business—Competition in the oil and
hold all of the working interests in certain of our licensed areas. Therefore, we
natural gas industry is intense, which makes it difficult for us to attract capital,
may not be able to control the timing of exploration or development efforts,
acquire properties and prospects, market oil and natural gas and secure
associated costs, or the rate of production of any non-operated and, to an
trained personnel.”
extent, any non-wholly-owned, assets.”
Our customers
We may also be affected by competition for drilling rigs and the availability
of related equipment. Higher commodity prices generally increase the
In Colombia, our primary customer is Trafigura, and who represented 79%,
demand for drilling rigs, supplies, services, equipment and crews, and can
of our total revenues for the year ended December 31, 2017. In Chile, our
lead to shortages of, and increasing costs for, drilling equipment, services and
primary customers are ENAP and Methanex. As of December 31, 2017, ENAP
personnel. Shortages of, or increasing costs for, experienced drilling crews and
purchased all of our oil and condensate production and Methanex purchased
equipment and services could restrict our ability to drill wells and conduct our
almost all of our natural gas production in Chile, and represented 5% and 5%,
operations.
respectively, of our total revenues for the year ended December 31, 2017.
In Brazil, all of our hydrocarbons in Manati are sold to Petrobras. In Peru, our
Health, safety and environmental matters
primary customer may be Petroperu, has the first option to acquire the oil
General
produced by us in the Morona Block by matching any offer received by third
Our operations are subject to various stringent and complex international,
parties regarding such production.
Seasonality
federal, state and local environmental, health and safety laws and regulations
in the countries in which we operate. These laws and regulations govern
matters including the emission and discharge of pollutants into the ground,
Although there is some historical seasonality to the prices that we receive
air or water; the generation, storage, handling, use and transportation of
for our production, the impact of such seasonality has not been material.
regulated materials; and human health and safety. These laws and regulations
Seasonality has also not played a significant role in our ability to conduct our
may, among other things:
operations, including drilling and completion activities.
• require the acquisition of various permits or other authorizations or the
However, as the Morona Block is located in a remote area, the development
closure plans) before seismic or drilling activity commences;
of the project depends on significant infrastructure being built which can
• enjoin some or all of the operations of facilities deemed not in compliance
be impacted by seasonal weather patterns, including rain. Since there are
with permits;
no roads available in the surrounding area, logistics will be performed by
• restrict the types, quantities or concentration of various substances that
helicopters or barges during specific seasons of the year.
can be released into the environment related to oil and natural gas drilling,
preparation of environmental assessments, studies or plans (such as well
We take such seasonality into account in planning for and conducting our
• require establishing and maintaining bonds, reserves or other
operations, such that the impact on our overall business is not material.
commitments to plug and abandon wells;
production and transportation activities;
Our competition
The oil and gas industry is competitive, and we may encounter strong
•
limit or prohibit seismic and drilling activities in certain locations lying
within or near protected or environmentally sensitive areas;
GeoPark 97
• require preventative measures to mitigate pollution from our operations,
understanding and management. Within our S.P.E.E.D. philosophy we
which, if not undertaken, could subject us to substantial penalties; and
have a team that is exclusively focused on securing the environmental
• require us to maintain a safe and healthy working environment for all
authorizations and permits for the projects we undertake. This professional
employees, contractors and visitors in accordance with applicable regulations
and trained team, specialized in environmental issues, is also responsible
and industry best practices.
for the achievement of the environmental standards set by our Board
of Directors and for training and supporting our personnel. Our senior
These laws and regulations may also restrict the rate of oil and natural gas
executives, personnel in the field, visitors and contractors have also received
production below the rate that would otherwise be possible. Compliance
training in proper environmental management.
with these laws can be costly. The regulatory burden on the oil and
gas industry increases the cost of doing business in the industry and
Our Health and Safety Policy
consequently affects profitability.
We believe that the implementation of additional safety tools in our
operations in 2016 has significantly contributed to control and minimizing
Public interest in the protection of the environment continues to increase.
risks in our operations. Actions taken by us included the development of a
Drilling in some areas has been opposed by certain community and
new Proactive Observation Program, HSE training, permits to work, internal
environmental groups and, in other areas, has been restricted.
audits, drills, pre-job meetings and job safety analysis, among others. As
Climate change
of December 31, 2017, on the last 12-month basis, our HSE development
statistics workforce shows that Lost Time Injury Frequency (LTIF) was 1.14 (out
Both our operations and the combustion of oil and natural gas-based
of every 1,000,000 worked hours), our Total Recordable Incident Rate (TRIR)
products results in the emission of greenhouse gases, which may contribute
was 2.86 (out of every 1,000,000 worked hours) and we had no fatal incidents
to global climate change. Climate change regulation has gained momentum
related to operations in 2017.
in recent years internationally and at the federal, regional, state and local
levels. On the international level, various nations have committed to reducing
In 2016, we subscribed to the International Association of Oil and Gas
their greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto
Producers in order to align our Management System and policies with the
Protocol was set to expire in 2012. In late 2011, an international climate
best international standards.
change conference in Durban, South Africa resulted in, among other things,
an agreement to negotiate a new climate change regime by 2015 that
Certain Bermuda law considerations
would aim to cover all major greenhouse gas emitters worldwide, including
As a Bermuda exempted company, we and our Bermuda subsidiaries are
the U.S., and take effect by 2020. In November and December 2012, at an
subject to regulation in Bermuda. We have been designated by the BMA as a
international meeting held in Doha, Qatar, the Kyoto Protocol was extended
non-resident for Bermuda exchange control purposes. This designation allows
by amendment until 2020. In addition, the Durban agreement to develop
us to engage in transactions in currencies other than the Bermuda dollar,
the protocol’s successor by 2015 and implement it by 2020 was reinforced.
and there are no restrictions on our ability to transfer funds (other than funds
We are committed to controlling the emission of greenhouse gases and
denominated in Bermuda dollars) in and out of Bermuda.
implementing available technologies to reduce the impact caused by our
operations. For example, during 2016 we began a migration plan to replace
Under Bermuda’s law, “exempted” companies are companies formed for the
diesel with natural gas and electric generation.
purpose of conducting business outside Bermuda from a principal place
Our HSE Management System
of business in Bermuda. As exempted companies, we and our Bermuda
subsidiaries may not, without a license or consent granted by the Minister of
Our health, safety and environmental management plan is focused on
Finance of Bermuda, participate in certain business transactions, including
undertaking realistic and practical programs based on recognized world
transactions involving Bermuda landholding rights and the carrying on of
practices. Our emphasis is on building key principles and company-wide
business of any kind for which we or our Bermuda subsidiaries are not licensed
ownership and then expanding programs as we continue growing. Our
in Bermuda.
S.P.E.E.D. philosophy and our HSE Plan have been developed with reference
to ISO 14001 for environmental management issues, OHSAS 18001 for
Insurance
occupational health and safety management issues, SA 8000 for social
We maintain insurance coverage of types and amounts that we believe to
accountability and workers’ rights issues and applicable World Bank Standards.
be customary and reasonable for companies of our size and with similar
Our Environmental Policy
operations in the oil and gas industry. However, as is customary in the
industry, we do not insure fully against all risks associated with our business,
Our policy looks forward to meet or exceed environmental regulations
either because such insurance is not available or because premium costs are
in the countries in which we operate. We believe that oil and gas can be
considered prohibitive.
produced in an environmentally-responsible manner with proper care,
98 GeoPark 20-F
Currently, our insurance program includes, among other things, construction,
Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code,
fire, vehicle, technical, umbrella liability, director’s and officer’s liability and
establishes the general procedures and requirements that must be completed
employer’s liability coverage. Our insurance includes various limits and
by a private investor and disclosure procedures that need to be followed
deductibles or retentions, which must be met prior to or in conjunction with
during the performance of these activities.
recovery. A loss not fully covered by insurance could have a materially adverse
effect on our business, financial condition and results of operations. See “Item
Exploration and production activities were governed by Decree 1895 of 1973
3. Key Information—D. Risk factors—Risks relating to our business—Oil and
until September 2009. Decree Law 2310 of 1974 (as complemented by Decree
gas operations contain a high degree of risk and we may not be fully insured
743 of 1975) governed the contracts and contracting processes carried out by
against all risks we face in our business.”
Ecopetrol and the rules applicable to such contracts, and also provided that
Industry and regulatory framework
Colombia
Regulation of the oil and gas industry
Ecopetrol was responsible for administering the hydrocarbons resources in the
Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, but
all agreements entered into by us prior to 2003 with other oil companies are
still regulated by Decree 2310 of 1974.
The ANH is responsible for managing all exploration lands not subject to
previously existing association contracts with Ecopetrol. The ANH began
The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 and
offering all undeveloped and unlicensed exploration areas in the country
Agreement 004 of 2012. Accord 008 of 2004, as repealed and replaced by
under E&P Contracts and Technical Evaluation Agreements, or TEAs, which
Accord 004 of 2012, issued by the Directive Council of the ANH, sets forth the
resulted in a significant increase in Colombian exploration activity and
necessary steps for entering into E&P Contracts with the ANH. This Agreement
competition, according to the ANH. The ANH is also in charge of negotiating
only regulates the contracts entered into as of May 4, 2012. Prior contracts are
and executing contracts through “direct negotiation” mechanisms with
still ruled by Agreement 008 of 2004. Due to the oil prices crisis of 2015, the
attention to special conditions in the areas to be explored. The regulatory
ANH implemented transitory measures through Agreements 002, 003, 004 and
landscape in Colombia has recently changed. The regime for the ANH’s
005 of 2015, which are still in place. The ANH is working on a new Agreement
contracts is set forth in Agreement 008 of 2004 and Agreement 004 of 2012.
that compiles the relevant rulings in one document.
Accord 008 of 2004 issued by the Directive Council of the ANH, as repealed
and replaced by Accord 004 of 2012, sets forth the necessary steps for entering
Resolution 18-1495 of 2009 establishes a series of regulations regarding
into E&P Contracts with the ANH. This Agreement regulates E&P contracts
hydrocarbon exploration and exploitation. In the E&P Contracts, operators are
entered into from May 4, 2012. E&P contracts entered into before that date are
afforded access to non-contracted blocks by committing to an exploration
still regulated by Agreement 008 of 2004. Due to the oil price crisis of 2015, the
work program. These E&P Contracts provide companies with 100% of new
ANH implemented transitory measures through Agreements 002, 003, 004 and
production, less the participation of the ANH, which participation may differ
005 of 2015. On May 18, 2017, the ANH issued Agreement 002, which repealed
for each E&P Contract and depends on the percentage that each company
and replaced Agreement 004 of 2012 and transitory measures adopted in
has offered to the ANH in order to be granted with a block, subject to an initial
2014 and 2015. Agreement 002 of 2017 established rules for the allocation of
royalty payment of 8% and the payment of income taxes of 33%. In addition,
hydrocarbon areas and adopted criteria for the exploration and exploitation
the Colombian government also introduced TEAs, in which companies that
of hydrocarbons owned by Colombia, including the selection of contractors,
enter into TEAs are the only ones to have the right to explore, evaluate and
and management, execution, termination, liquidation, monitoring, control
select desirable exploration areas and to propose work commitments on
and supervision of corresponding contracts. Agreement 002 of 2017 regulates
those areas, and have a preemptive right to enter into an E&P Contract,
contracts entered into from May 18, 2017. E&P contracts entered into before
thereby providing companies with low-cost access to larger areas for
that date are still regulated by the Agreements under which they were
preliminary evaluation prior to committing to broader exploration programs.
executed, except for any modification, addition, extension, assignment and
A preemptive right is granted to convert the TEA into an E&P Contract.
other action related to the execution of contracts submitted by the parties to
Exploration activities can only be carried out by the TEA contractor.
the ANH after May 18, 2017, which are regulated by Agreement 002 of 2017.
Regulatory framework
Pursuant to Colombian law, companies are obligated to pay a percentage
of their production to the ANH as royalties and an economic right as ANH’s
Regulation of exploration and production activities
participating interest in the production. Producing fields pay royalties in
Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon
accordance with the applicable royalty program at the time of the discovery.
resources located in Colombia and has full authority to determine the rights,
royalties or compensation to be paid by private investors for the exploration or
Taxation
production of any hydrocarbon reserves. The Ministry of Mines and Energy is
The Tax Statute and Law 9 of 1991 provide the primary features of the oil and
the authority responsible for regulating all activities related to the exploration
gas industry’s tax and exchange system in Colombia. Generally, national taxes
and production of hydrocarbons in Colombia.
under the general tax statute apply to all taxpayers, regardless of industry. The
GeoPark 99
main taxes currently in effect—after the December 2016 tax reform discussed
year.
below—are the income tax (40% for 2017, 37% for 2018 and 33% for 2019
• IFRS is the basis for tax purposes with certain exceptions, such as:
onwards), sales or value added tax (19%), and the tax on financial transaction
– Depreciation: The general rule is that the term of depreciation is
(0.4%). Additional regional taxes also apply. Colombia has entered into a
determined according to IFRS, but with a depreciation percentage cap
number of international tax treaties to avoid double taxation and prevent tax
per year for tax purposes. Assets held before 2017 will be depreciated
evasion in matters of income tax and net asset tax.
according to the previous rules.
Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international
– Amortization: Amortization of investments in the oil and gas industry to be
investment regime, regulates foreign capital investment in Colombia.
depleted according to the “units of production method” beginning 2028.
Resolution 8 of the board of the Colombian Central Bank, or the Exchange
Beginning in fiscal year 2017 and until 2027 , exploratory investments will be
Statute, and its amendments contain provisions governing exchange
amortized by the straight line method in a period of 5 years. Grandfather rule
operations. Articles 48 to 52 of Resolution 8 provide for a special exchange
was established for undepleted investments held before fiscal year 2017
regime for the oil industry that removes the obligation of repayment to the
• Goodwill in the acquisition of shares is no longer subject to amortization.
foreign exchange market currency from foreign currency sales made by
Goodwill generated before 2017 will be subject to amortization according to
foreign oil companies. Such companies may not acquire foreign currency
the rules enforceable at the moment of generation of the goodwill, however
in the exchange market under any circumstances and must reinstate in the
amortization of the undepleted values as of January 1, 2017 may not take
foreign exchange market the capital required in order to meet expenses in
more than five years, and must be done through the straight line method.
Colombian legal currency. Companies can avoid participating in this special
• VAT modifications: (a) general rate increased to 19%; (b) eight month window
oil and gas exchange regime, however, by informing the Colombian Central
period to credit input tax; (c) input tax, on the acquisition or importation of
Bank, in which case they will be subject to the general exchange regime of
fixed assets may be deductible for income tax purposes, unless it is to be
Resolution 8 and may not be able to access the special exchange regime for a
treated as creditable, or as part of the tax cost of the asset; and (d) sale of
period of 10 years.
crude oil to refineries subject to VAT at a rate of 19%.
• Banking tax (4x1000), to become permanent.
In December 2016, the Colombian Congress approved a tax reform (Law 1819
• Benefits for the oil and gas industry: taxpayers that increase investments in
of 2016). The main aspects of the reform are summarized below.
exploration of new hydrocarbon reserves, incorporation of new recoverable
• The enterprise contribution on equality (“CREE” for its Spanish acronym) tax is
reserves, and the addition of proven reserves, would have the right to a Tax
eliminated, but a carry forward of CREE receivables and losses for income tax
Refund Certificate (CERT), which could be used to pay taxes administered
purposes will be permitted.
by the Colombian Tax Office or sold in the market to
• Income tax rates will be 34% plus a 6% surcharge for fiscal year 2017, 33% plus
other taxpayers.
a 4% surcharge for fiscal year 2018 and 33% for fiscal year 2019 and beyond.
• Tax may be paid according to the following two options:
• A dividend tax is included on distributions from Colombian corporations
– Paying up to 50% of the amount of the tax of one fiscal year, by investing
for non-resident shareholders, with tax rates of 5%, for dividends which
in social projects.
were taxed at the corporate level and 35% and then a 5% on the remaining
– Using the value of the investment to pay 50% of the tax, during a period
amount for dividends which were not taxed at the corporate level.
of 10 years in equal installments.
• Grandfather rules prevent the application of the 5% dividend tax on profits
In either case, the investments may not be of the nature of those that
obtained before fiscal year 2017. The tax rate for profits obtained before that
constitute deductible expenses.
date which were not taxed at the corporate level would be 33% instead of
35%.
Chile
• Tax losses to be carried forward up to 12 years, losses generated before 2017
Regulation of the oil and gas industry
are grandfathered.
Under the Chilean Constitution, the state is the exclusive owner of all mineral
• Presumptive taxable base increases to 3.5% of the net equity at the end of
and fossil substances, including hydrocarbons, regardless of who owns the
the prior year.
land on which the reserves are located. The exploration and exploitation
• Cross border payments withholding tax suffered modifications. The general
of hydrocarbons may be carried out by the state, companies owned by the
rule on services is that there will be a 15% withholding tax, which includes
state or private entities through administrative concessions granted by the
management fees, even if the service is rendered form abroad. Additionally,
President of Chile by Supreme Decree or CEOPs executed by the Minister of
services rendered from abroad will be subject to VAT if the beneficiary is in
Energy. Exploitation rights granted to private companies are subject to special
Colombia (for example services rendered to GeoPark Colombia from abroad
taxes and/or royalty payments. The hydrocarbon exploration and exploitation
would be subject to such treatment).
industry is supervised by the Chilean Ministry of Energy.
• The net wealth tax is still set to expire in fiscal year 2017 for corporations,
but it remains unclear if its term will be extended. The tax is not enforceable
In Chile, a participant is granted rights to explore and exploit certain assets
for 2018, but may be enforceable in 2019 if a law is passed by the end of this
under a CEOP. If a participant breaches certain obligations under a CEOP, the
100 GeoPark 20-F
participant may lose the right to exploit certain areas or may be required
the income accrued or received during 2013 and onward. Dividends or profits
to return all or a portion of the awarded areas to Chile with no right of
distributed to the foreign shareholders of the contractors are subject to 35%
compensation. Although the government of Chile cannot unilaterally modify
Additional Withholding Tax with a tax credit for the corporate income tax paid
the rights granted in the CEOP once it is signed, exploration and exploitation are
by the contractor. With regard to the value added tax, contractors may obtain
nonetheless subject to significant government regulations, such as regulations
as a refund the value added tax (which is 19% according to the Sales and
concerning the environment, tort liability, health and safety and labor.
Services Tax Law contained in Decree Law No. 825 of 1974) supported or paid
Regulatory framework
on the import or purchase of goods or services used in connection with the
exploration and exploitation activities. The applicable tax regime for each CEOP
Regulation of exploration and production activities
remains unchanged throughout the duration of the CEOP.
Oil and gas exploration and development is governed by the Political
Constitution of the Republic of Chile and Decree with Law Force No 2 of
The Chilean Congress approved a reform to the income tax law in September
1986 of the Ministry of Mines, which set forth the revised text of the Decree
2014 which was amended in February 2016. Under this reform the income tax
Law 1089 of 1975, on CEOPS. However, the right to explore and develop
rate will increase from 20% in 2013 to: 21% in 2014, 22.5% in 2015, 24% in 2016,
fields is granted for each area under a CEOP between Chile and the relevant
25.5% in 2017 and 27% in 2018. The operating subsidiaries that we control in
contractors. The CEOP establishes the legal framework for hydrocarbon
Chile, which are GeoPark TdF S.A., GeoPark Fell S.p.A. and GeoPark Magallanes
activities, including, among other things, minimum investment commitments,
Limitada, are not affected by the income tax reform mentioned since they are
exploration and exploitation phase durations, compensation for the private
covered by the tax treatment established in the CEOPs. The above has been
company (either in cash or in kind) and the applicable tax regime. Accordingly,
confirmed by the Chilean IRS through ruling N°2478/2016.
all the provisions governing the exploitation and development of our Chilean
operations are contained in our CEOPs and the CEOPs constitute all the
Brazil
licenses that we need in order to own, operate, import and export any of
Regulation of the oil and gas industry
the equipment used in our business and to conduct our gas and petroleum
Article 177 of the Brazilian Federal Constitution of 1988 provides for the
operations in Chile.
Federal Government’s monopoly over the prospecting and exploration of oil,
natural gas resources and other fluid hydrocarbon deposits, as well as over
Under Chilean law, the surface landowners have no property rights over
the refining, importation, exportation and sea or pipeline transportation of
the minerals found under the surface of their land. Subsurface rights do not
crude oil and natural gas. Initially, paragraph one of article 177 barred the
generate any surface rights, except the right to impose legal easements or
assignment or concession of any kind of involvement in the exploration
rights of way. Easements or rights of way can be individually negotiated with
of oil or natural gas deposits to private industry. On November 9, 1995,
individual surface land owners or can be granted without the consent of the
however, Constitutional Amendment Number 9 altered paragraph one of
landowner through judicial process. Pursuant to the Chilean Code of Mines, a
article 177 so as to allow private or state-owned companies to engage in the
judge can permit a party to use an easement pending final adjudication and
exploration and production of oil and natural gas, subject to the conditions
settlement of compensation for the affected landowner.
to be set forth by legislation.
Taxation
Regulatory framework
With regard to indirect taxes on hydrocarbon exploitation, the general rule is
Pricing policy
that hydrocarbons are transferred to the contractor (its retribution under the
Until the enactment of the Brazilian Petroleum Law, the Brazilian government
CEOP), and those re-acquisitions from the contractor performed by Chile or
regulated all aspects of the pricing of oil and oil products in Brazil, from the
its enterprises, as well as their corresponding acts, contracts and documents,
cost of oil imported for use in refineries to the price of refined oil products
are tax exempt. In addition, hydrocarbon exports by the contractor are also
charged to the consumer. Under the rules adopted following the Brazilian
tax exempt. With regard to income taxes, as provided by article 5 of Decree
Petroleum Law, the Brazilian government changed its price regulation policies.
Law No. 1,089, the contractor is subject either to a single tax calculated on
Under these regulations, the Brazilian government: (1) introduced a new
its retribution, equal to 50% of such retribution, or to the general income tax
methodology for determining the price of oil products designed to track
regime established in the Income Tax Law (Decree Law No. 824 of 1974), in force
prevailing international prices denominated in U.S. dollars, and (2) gradually
at the time of the execution of the public deed which contains CEOPs, terms of
eliminated controls on wholesale prices.
which will be applicable and invariable throughout the duration of the contract.
Income in Chile is subject to corporate tax on an accrual basis and has a current
Concessions
rate of 25.5% for fiscal year 2017. The applicable and invariable corporate
In addition to opening the Brazilian oil and natural gas industry to private
income tax rates of our CEOPs range between 15% and 18.5%, as follows: the
investment, the Brazilian Petroleum Law created new institutions, including
Fell Block is subject to a rate of 15%, the Tranquilo Block is subject to a rate of
the ANP, to regulate and control activities in the sector. As part of this
17% and the Flamenco, Isla Norte and Campanario Blocks are subject to a rate
mandate, the ANP is responsible for licensing concession rights for the
of 18.5% for the income accrued or received during 2012 and 17% for
exploration, development and production of oil and natural gas in Brazil’s
GeoPark 101
sedimentary basins through a transparent and competitive bidding process.
respect to production. Royalties generally correspond to a percentage
The ANP has conducted 14 bidding rounds for exploration concessions
ranging between 5% and 10% applied to reference prices for oil or natural
from 1999 through 2017. Our PN-T-597 is still subject to the entry into the
gas, as established in the relevant bidding guidelines (edital de licitação) and
concession agreement. See “—Our operations—Operations in Brazil” and
concession agreement. In determining the percentage of royalties applicable
“Item 3. Key information—D. Risk factors—Risks relating to our business—The
to a particular concession, the ANP takes into consideration, among other
PN-T-597 concession is subject to an injunction and may not close” for more
factors, the geological risks involved and the production levels expected.
information.
Taxation
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
The Brazilian Petroleum Law introduced significant modifications and benefits
at reducing the tax burden on companies involved in exploring and extracting
to the taxation of oil and natural gas activities. The main component of
oil and natural gas, through the total suspension of federal taxes due on the
petroleum taxation is the government take, comprised of license fees, fees
importation of equipment (platforms, subsea equipment, among others),
payable in connection with the occupation or title of areas, royalties and a
under leasing agreements, subject to the compliance with applicable legal
special participation fee. The introduction of the Brazilian Petroleum Law
requirements. The period in which the goods are allowed to remain in Brazil
presents certain tax benefits primarily with respect to indirect taxes. Such
under the REPETRO regime may vary depending on the importer, but usually
indirect taxes are very complex and can add significantly to project costs. Direct
corresponds to the duration of the contract executed between the Brazilian
taxes are mainly corporate income tax and social contribution on net profit.
company and the foreign entity, or the period for which the company was
authorized to exploit or produce oil and gas.
Government take. With the effectiveness of the Brazilian Petroleum Law and
the regulations promulgated by the ANP, concessionaires are required to pay
In 2007, the legislation regarding the State Value Added Tax—ICMS imposed
the Brazilian federal government the following:
taxation on the import of equipment into Brazil under the REPETRO regime
• license fees;
was significantly changed by ICMS Convention No. 130/2007. This regulation
• rent for the occupation or retention of areas;
allows each State to grant the ICMS tax calculation basis reduction (generating
• special participation fee; and
• royalties on production.
a tax burden of 7.5% with the recoverability of credits or 3%, without the
recoverability of credits) for goods purchased under the REPETRO regime for
the production phase and the total exemption or ICMS tax calculation basis
The minimum value of the license fees is established in the bidding rules for
reduction (generating a tax burden of 1.5%, without the recoverability of
the concessions, and the amount is based on the assessment of the potential,
credits) for the exploration phase. In order to be in force, the ICMS Convention
as conducted by the ANP. The license fees must be paid upon the execution
No. 130/07 must be included in each state’s legislation.
of the concession contract. Additionally, concessionaires are required to
pay a rental fee to landowners varying from 0.5% to 1.0% of the respective
For example, currently, based on Convention No. 130/2007, the state of Rio de
hydrocarbon production.
Janeiro grants tax calculation basis reduction for the exploitation (generating
a tax burden of 7.5%, with the recoverability of credits or 3%, without
The special participation fee is an extraordinary charge that concessionaires
the recoverability of credits) and production of oil and gas (generating a
must pay in the event of obtaining high production volumes and/or
tax burden of 1.5%, without the recoverability of credits). For production
profitability from oil fields, according to criteria established by applicable
activities, the legislation previously granted an exemption of ICMS, which
regulation, and is payable on a quarterly basis for each field from the date on
was changed to a tax calculation basis reduction, according to Resolution
which extraordinary production occurs. This participation rate, whenever due,
Sefaz No. 631, dated May 14, 2013. Taxpayers, however, have challenged this
may reach up to 40% of net revenues depending on (i) volume of production
change and received favorable decisions in court in order to avoid collecting
and (ii) whether the block is onshore, shallow water or deep water. Under the
ICMS on REPETRO imports as, according to STF (Supreme Court of Justice), the
Brazilian Petroleum Law and applicable regulations issued by the ANP, the
temporary imports on REPETRO do not constitute an ICMS triggering event.
special participation fee is calculated based upon quarterly net revenues of
each field, which consist of gross revenues calculated using reference prices
It is important to mention that before the enactment of the Convention
published by the ANP (reflecting international prices and the exchange rate
No. 130/2007, the State of Rio de Janeiro has attempted to impose ICMS on
for the period) less: royalties paid; investment in exploration; operational costs;
production activities, based on State Law No. 4,117, dated June, 27, 2003,
and depreciation adjustments and applicable taxes.
which was regulated by Decree No. 34,761, dated February 3, 2004, and was
The ANP is responsible for determining monthly minimum prices for
undetermined period of time. This legislation has been revoked in 2015 when
petroleum produced in concessions for purposes of royalties payable with
Rio de Janeiro State created Law No. 7,183/2015 aiming to collect ICMS on
subsequently suspended by Decree No. 34,783 of February 4, 2004 for an
102 GeoPark 20-F
the extraction of oil and Law No. 7,182/2015 creating a new fee per barrel
and exploitation stage –when such discovery has not been made yet. In this
of oil produced in the state. The constitutionality of these laws is currently
case, the exploration phase will last no more than 7 years, counted from the
being challenged by taxpayers. It is important to highlight that, while such
effective date of the contract (60 days after the signing date). This term can
legislation applies for oil fields operated in the State of Rio de Janeiro,
be divided into several periods as agreed in the contract, and all of them
legislation may vary in other states.
with a minimum work obligation that should be fulfilled by a contractor in
order to access the next exploration period. The exploration phase will last
Pursuant to the Brazilian Petroleum Law and subsequent legislation, the
until a declaration of commercial discovery is made by the contractor. The
federal government enacted Law No. 10,336/01, to impose the Contribution
exploitation phase will last from the date of such declaration until 30 years
for Intervention in the Economic Sector, or CIDE, an excise tax payable by
from the date of the contract.
producers, blenders and importers on transactions with some oil and fuel
products, which is imposed at a flat rate based on the specific quantities
The Ministry of Energy and Mines may exceptionally authorize an extension
of each product. Currently, the CIDE rates are zero, based on Decree No.
of three years for the exploration stage, if the contractor has fulfilled with the
7,764/2012.
minimum work program established in the contract, and also commits to fulfill
an additional work program that justifies such extension. The contractor shall
Brazil has enacted a corporate tax reform, Law 12.973 of 13 May 2014. On
be responsible for providing the technical and economic resources required
upstream operations, as from 2015 fiscal year, the new tax law may generate
for the execution of the operations of this phase.
timing effects for income tax purposes on the deduction of pre-operational
costs as well as depreciation of fixed assets and amortization of intangibles.
The Peruvian regulations also established the roles of the Peruvian
The new law imposes restrictions for the tax deduction of goodwill arising
government agencies that regulate, promote and supervise the oil and
from in-house operations and brings several changes to the Brazilian CFC
gas industry, including the Ministry of Energy and Mines, Perupetro and
rules.
Peru
OSINERGMIN.
Taxation
Regulation of the oil and gas industry
The fiscal regime that applies in Peru to the oil and gas industry consists of a
The hydrocarbons activities in Peru are mainly regulated by the General
combination of corporate income tax, royalties and other levies.
Hydrocarbons Law (Law 26,221), and several regulations enacted in order to
In general terms, oil and gas companies are subject to the general corporate
develop the provisions included in such law.
income tax regime that is stabilized in the applicable regime on the date of
According to the Hydrocarbons Law, oil and gas exploration and production
nevertheless, there are certain special tax provisions for the oil and gas sector.
activities are carried out under license or service contracts granted by the
Resident companies (incorporated in Peru), are subject to income tax on
government. Under a license contract, the investor pays a royalty, whereas
their worldwide taxable income. Branches and permanent establishments of
under a service contract, the government pays remuneration to the contractor.
foreign companies that are located in Peru and non-resident entities are taxed
subscription of the original License Agreement (due to a tax stability contract);
As stated by the Peruvian Constitution and the Organic Law for Hydrocarbons,
on Peruvian source income only.
a license contract does not imply a transfer or lease of property over the
area of exploration or exploitation. By virtue of the license contract, the
With respect to the Morona Agreement, in which we take part, the applicable
contractor acquires the authorization to explore or to exploit hydrocarbons
income tax stabilized regime is from 1995, which is the year of subscription
in a determined area, and Perupetro (the entity that holds the Peruvian state
of the original License Agreement. The income tax rate in 1995 was 30% and
interest) transfers the property right in the extracted hydrocarbons to the
there was no withholding income tax for dividends. Additionally, in 1995
contractor, who must pay a royalty to the state.
it was stated that the income tax should not be lower than 2% of the net
Regulatory framework
assets of the Company (the “Minimum Income Tax”). The Minimum Income
Tax was later declared unconstitutional, which is why, even when there was a
License and service contracts are approved by a supreme decree issued by
tax stability contract, the Minimum Income Tax has been understood as not
the Peruvian Ministry of Economy and Finance, and the Peruvian Ministry of
applicable or enforceable.
Energy and Mining, and can only be modified by a written agreement signed
by the parties. Before initiating any negotiation, every oil and gas company
Taxable income is generally computed by reducing gross revenue by cost of
must be duly qualified by Perupetro, in order to determine if it fulfills all the
goods sold and all expenses necessary to produce the income or maintain
requirements needed to develop exploration and production activities under
the source of income. Certain types of revenue, however, must be computed
the contract form requirements mentioned above.
as specified in the tax law and some expenses are not fully deductible for
License and services agreements may be granted for just an exploitation
tax purposes. Business transactions must be recorded in legally authorized
stage -when a commercial discovery has been made- or for an exploration
GeoPark 103
accounting records that are in full compliance with the International
Exemptions are withdrawn at the production phase, but exceptions are made
Accounting Standards (IAS). Contractors in a license or services contract for
in certain instances, and the operator may be entitled to temporarily import
the exploration or exploitation of hydrocarbons (Peruvian corporations and
goods tax-free for a two-year period (“Temporary Import”). A temporary
branches) are entitled to keep their accounting records in foreign currency,
Import may be extended for additional one year periods for up to two times
but taxes must be paid in Peruvian Nuevos Soles (“PEN”).
upon the request of an operator, approval of the Ministry of Energy and
Mines and authorization of the Superintendencia Nacional de Aduanas y de
Any investments in a contract area that did not reach the commercial
Administracion Tributaria (Peruvian Customs Agency).
extraction stage and that were totally released, can be accumulated with the
same type of investments made in another contract area that has reached the
Environmental Regulation
stage of commercial extraction.
Before initiating any hydrocarbon activity (e.g. seismic exploration, drilling
of exploration wells, etc.) the contractor must file and obtain an approval for
These investments are amortized in accordance with the amortization method
an Environmental Impact Study (EIS), which is the most important permit
chosen by the contractor. If the contractor has entered into a single contract,
related to HSE for any hydrocarbon project. This study includes technical,
the accumulated investments are charged as a loss against the results of the
environmental and social evaluations of the project to be executed in order
contract for the year of total release of the area for any contract that did not
to define the activities that should be required for preventing, minimizing,
reach the commercial extraction stage, with the exception of investments
mitigating and remediation of the possible negative environmental and social
consisting of buildings, power installations, camps, means of communication,
impacts that the hydrocarbon project may generate.
equipment and other goods that the contractor keeps or recovers to use in the
same operations or in other operations of a different nature.
There are general environmental regulations for the protection of water, soils,
air, endangered species, biodiversity, natural protected areas, etc. In addition,
The contractor determines the tax base and the amount of the tax, separately
there are specific environmental regulations applicable to the hydrocarbon
and for each contract. If the contractor carries out related activities (i.e.,
industry.
activities related to oil and gas, but not carried out under the terms of the
contract) or other activities (i.e., activities not related to oil and gas), the
Argentina
contractor is obligated to determine the tax base and the amount of tax,
Regulatory framework
separately, and for each activity. The corresponding tax is determined based
From the 1920s to 1989, the Argentine public sector dominated the upstream
on the income tax provisions that apply in each case (subject to the tax
segment of the Argentine oil and gas industry and the midstream and
stability provisions for contract activities and based on the regular regime for
downstream segment of the business.
the related activities or other activities). The total income tax amount that the
contractor must pay is the sum of the amounts calculated for each contract,
In 1989, Argentina enacted certain laws aimed at privatizing the majority
for both the related activities and for the other activities. The forms to be used
of its state-owned companies and issued a series of presidential decrees
for tax statements and payments are determined by the tax administration.
(namely, Decrees No. 1055/89, 1212/89 and 1589/89 (the “Oil Deregulation
Decrees”), relating specifically to deregulation of energy activities). The Oil
If the contractor has more than one contract, it may offset the tax losses
Deregulation Decrees eliminated restrictions on imports and exports of crude
generated by one or more contracts against the profits resulting from other
oil, deregulated the domestic oil industry, and effective January 1, 1991, the
contracts or related activities. Moreover, the tax losses resulting from related
prices of oil and petroleum products were also deregulated. In 1992, Law
activities may be offset against the profits from one or more contracts.
No. 24,145, referred to as the Privatization Law, privatized YPF and provided
It is possible to choose the allocation of tax losses to one or more of the
for transfer of hydrocarbon reservoirs from the Argentine government to the
contracts or related activities that have generated the profits, provided that
provinces, subject to the existing rights of the holders of exploration permits
the losses are depleted or compensated to the limit of the profits available.
and production concessions.
This means that if there is another contract or related activity, the taxpayer
can continue compensating tax losses until they are completely offset. A
In October 2004, the Argentine Congress enacted Law No. 25,943, creating
contractor with tax losses from one or more contracts or related activities may
a new state-owned energy company, Energía Argentina S.A. (“ENARSA”).
not offset them against profits generated by the other activities. Furthermore,
The corporate purpose of ENARSA is the exploration and exploitation of
in no case may tax losses generated by the other activities be offset against
solid, liquid and gaseous hydrocarbons; the transport, storage, distribution,
the profits resulting from the contracts or the related activities.
commercialization and industrialization of these products; as well as
the transportation and distribution of natural gas, and the generation,
During the exploration phase, operators are exempt from import duties and
transportation, distribution and sale of electricity. Moreover, Law No. 25,943
other forms of taxation applicable to goods intended for exploration activities.
granted ENARSA all offshore areas located beyond 12 nautical miles from the
104 GeoPark 20-F
coastline up to the outer boundary of the continental shelf that were vacant at
conventional exploitation, unconventional exploitation, and exploitation in
the time of the effectiveness of this law (i.e. November 3, 2004).
the continental shelf and territorial waters, establishing the respective terms
for each type.
On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty
• The terms for hydrocarbon transportation concessions were adjusted in order
Act. This law declared achieving self-sufficiency in the supply of hydrocarbons,
to comply with the exploitation concessions terms.
as well as in the exploitation, industrialization, transportation and sale of
• With regards to royalties, a maximum of 12% is established, which may reach
hydrocarbons, a national public interest and a priority for Argentina. In
18% in the case of granted extensions, where the law also establishes the
addition, the law expropriated 51% of the share capital of YPF, the largest
payment of an extension bond for a maximum amount equal to the amount
Argentine oil company, from Repsol, the largest Spanish oil company.
resulting from multiplying the remaining proven reserves at the end of
On July 28, 2012, Presidential Decree 1277/2012, which regulated the
to the respective hydrocarbons over the 2 years preceding the time on which
Hydrocarbon Sovereignty Law, was released, creating a Strategic Planning and
the extension was granted.
Coordination Committee for the National Hydrocarbon Investment Plan and
• The extension of the Investment Promotion Regime for the Exploitation of
vesting it with the power to set the sector’s reference prices and to develop
Hydrocarbons (Decree No. 929/2013) is established for projects representing
investment plans for the country to increase production and reserves. The
a direct investment in foreign currency of at least 250 million dollars,
effective term of the concession by 2% of the average basin price applicable
decree introduced important changes to the rules governing Argentina’s
increasing the benefits for other type of projects.
oil and gas industry, including the repeal of certain articles of Deregulation
Decrees passed during 1989 relating to free marketability of hydrocarbons
Regulation of transportation activities
at negotiated prices, the deregulation of the oil and gas industry, freedom to
Exploitation concessionaires have the exclusive right to obtain a
import and export hydrocarbons and the ability to keep proceeds from export
transportation concession for the transport of oil and gas from the provincial
sales in foreign bank accounts.
states or the federal government, depending on the applicable jurisdiction.
Such transportation concessions include storage, ports, pipelines and other
On January 4, 2016, immediately after the new national administration took
fixed facilities necessary for the transportation of oil, gas and by-products.
office, Presidential Decree 272/2015 was released. This Decree abrogated
Transportation facilities with surplus capacity must transport third parties’
the provisions of the Presidential Decree 1277/2012 which had repealed the
hydrocarbons on an open-access basis, for a fee which is the same for all users
Deregulation Decrees. Thus, the Deregulation Decrees were reinstated.
on similar terms. As a result of the privatizations of YPF and Gas del Estado, a
Other measures have also been taken by the new presidential administration
few common carriers of crude oil and natural gas were chartered and continue
aimed at reducing government intervention and reestablishing market forces
to operate to date.
in the oil & gas industry.
Taxation
Domain and Jurisdiction of hydrocarbons resources
Exploitation concessionaires are subject to the general federal and provincial
After a constitutional reform enacted in 1994, eminent domain over
tax regime. The most relevant federal taxes are the income tax (35%), the value
hydrocarbon resources lying in the territory of a provincial state is now vested
added tax (21%) and a tax on assets. The most relevant provincial taxes are the
in such provincial state, while eminent domain over hydrocarbon resources
turnover tax (1% to 3%) and stamp tax. In 2002, in response to the economic
lying offshore on the continental platform beyond the jurisdiction of the
crisis, the federal government adopted new taxes on oil and gas products,
coastal provincial states is vested in the federal state.
including export taxes ranging from 5% for by-products to 45% for crude
oil. Such export taxes lapsed and terminated on January 6, 2016 on the 15th
Thus, oil and gas exploration permits and exploitation concessions are now
anniversary of their enactment.
granted by each provincial government. A majority of the existing concessions
were granted by the federal government prior to the enactment of Law
Tax reform has been enacted in Argentina during December 2017. The
No.26,197 and were thereafter transferred to the provincial states.
legislation included significant changes to certain corporate income tax and
statutory income tax provisions, including rate reductions. Most of the tax
Regulation of exploration and production activities
provisions are effective as of the beginning of fiscal year 2018.
New Hydrocarbon Act:
In October 31, 2014 the Argentine Republic Official Gazette published the text
With this tax reform, the corporate income tax, which was previously 35%. will
of Law No. 27,007, amending the Hydrocarbon Law No. 17,319.
have the following rate schedule:
The most relevant aspects of the new law are as follows:
• 25% in 2020 and 2021 and onwards.
• With regards to concessions, three types of concessions are provided, namely,
Other changes include the following:
• 30% in 2018 and 2019
• New withholding tax on dividends—with the applicable rates for
GeoPark 105
Operating and financial review and prospects
non-resident shareholders of: (1) 7% for dividends distributed out of the
(including through bidding rounds) or gaining access to oil and natural
distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and
gas reserves. While we have geological reports evaluating certain proved,
(2) 13% for dividends distributed out of the distributing entity’s previously
contingent and prospective resources in our blocks, there is no assurance that
taxed profits of fiscal years 2020 and onwards.
we will continue to be successful in the exploration, appraisal, development
• Application of inflation adjustment for corporate tax purposes is reinstated
and commercial production of oil and natural gas. The calculation of our
under certain circumstances.
geological and petrophysical estimates is complex and imprecise, and it is
• Possible tax revaluation of investment in fixed assets, under payment of a
possible that our future exploration will not result in additional discoveries,
special tax.
and, even if we are able to successfully make such discoveries, there is no
• Allow for short term recovery of VAT paid on acquisitions or imports of
certainty that the discoveries will be commercially viable to produce.
capital goods, when non-recoverable with VAT on usual sales.
C. Organizational structure
For the year ended December 31, 2017, we made total capital expenditures
of US$105.6 million (US$80.0 million, US$10.2 million, US$8.2 million, US$3.6
We are an exempted company incorporated pursuant to the laws of Bermuda.
million and US$3.6 million in Colombia, Chile, Argentina, Peru and Brazil,
We operate and own our assets directly and indirectly through a number
respectively), consisting of US$49.5 million related to exploration.
of subsidiaries. See an illustration of our corporate structure in Note 21
(“Subsidiary undertakings”) to our Consolidated Financial Statements. During
Oil prices were volatile since the end of 2014. In preparation for continued
2017, we decided to incorporate a subsidiary in the United Kingdom to
volatility, we have developed multiple scenarios for our 2018 capital
conduct our businesses in Latin America by adopting all the key resolutions
expenditure program. See “Item 4. Information on the Company –B. Business
and decisions necessary for such purpose. In addition, as a result of tax reform
Overview—2018 Strategy and Outlook.”
enacted in the Netherlands during 2017, we decided to re-domicile our 100%
owned Dutch subsidiaries to Spain.
D. Property, plant and equipment
Funding for our capital expenditures relies in part on oil prices remaining close
to our estimates or higher levels and other factors to generate sufficient cash
flow. Low oil prices affect our revenues, which in turn affect our debt capacity
See “—B. Business Overview—Title to properties.”
and the covenants in our financing agreements, as well as the amount of cash
ITEM 4A. UNRESOLVED STAFF COMMENTS
are able to generate from current operations and the amount of cash we can
we can borrow using our oil reserves as collateral, the amount of cash we
Not applicable.
obtain from prepayment agreements such as the Trafigura Agreement, which
is our offtake and prepayment agreement. If we are not able to generate
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
the sales which, together with our current cash resources, are sufficient to
A. Operating results
fund our capital program, we will not be able to efficiently execute our work
program which would cause us to further decrease our work program, which
could harm our business outlook, investor confidence and our share price.
The following discussion of our financial condition and results of operations
should be read in conjunction with our Consolidated Financial Statements
If oil prices average higher than the base budget price, we have the ability
and the notes thereto as well as the information presented under “Item 3. Key
to allocate additional capital to more projects and increase its work and
Information— A. Selected financial data.”
investment program and thereby further increase oil and gas production.
The following discussion contains forward-looking statements that involve risks
Our results of operations will be adversely affected in the event that our
and uncertainties. Our actual results may differ materially from those discussed
estimated oil and natural gas asset base does not result in additional reserves
in the forward-looking statements as a result of various factors, including those
that may eventually be commercially developed. In addition, there can be
set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking
no assurance that we will acquire new exploration blocks or gain access to
statements.”
exploration blocks that contain reserves. Unless we succeed in exploration and
development activities, or acquire properties that contain new reserves, our
Factors affecting our results of operations
anticipated reserves will continually decrease, which would have a material
We describe below the year-to-year comparisons of our historical results and
adverse effect on our business, results of operations and financial condition.
the analysis of our financial condition. Our future results could differ materially
from our historical results due to a variety of factors, including the following:
Oil and gas revenue and international prices
Discovery and exploitation of reserves
as well as of condensate derived from the production of natural gas. The
Our results of operations depend on our level of success in finding, acquiring
price realized for the oil we produce is generally linked to Brent or Vasconia.
Our revenues are derived from the sale of our oil and natural gas production,
106 GeoPark 20-F
The price realized for the natural gas we produce in Chile is linked to the
year ended December 31, 2017 would have been higher by US$10.4 million
international price of methanol, which is settled in the international markets
(US$23.7 million in 2016).
in US$. The market price of these commodities is subject to significant
fluctuation and has historically fluctuated widely in response to relatively
In Brazil, prices for gas produced in the Manati Field are based on a long-term
minor changes in the global supply and demand for oil and natural gas,
off-take contract with Petrobras. The price of gas sold under this contract is
market uncertainty, economic conditions and a variety of additional factors.
denominated in reais and is adjusted annually for inflation pursuant to the
From January 1, 2013 to December 31, 2017, Brent spot prices ranged from a
Brazilian General Market Price Index (Índice Geral de Preços—Mercado) (the
low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub natural
“IGPM”). See Note 3 to our Consolidated Financial Statements.
gas average spot prices ranged from a low of US$1.7 per mmbtu to a high of
US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low of
Production and operating costs
US$250.0 per metric ton to a high of US$635.1 per metric ton. Furthermore,
Our production and operating costs consist primarily of expenses associated
oil, natural gas and methanol prices do not necessarily fluctuate in direct
with the production of oil and gas, the most significant of which are gas
relationship to each other.
plant leasing, facilities and wells maintenance (including pulling works),
labor costs, contractor and consultant fees, chemical analysis, royalties and
As a consequence of the oil price crisis which started in the second half of
products, among others. As commodity prices increase or decrease, our
2014 (WTI and Brent, the main international oil price markers, fell more than
production costs may vary. We have historically not hedged our costs to
60% between October 2014 and February 2016), we took decisive steps in
protect against fluctuations.
2015 and 2016 to adapt to the new oil price environment. We reduced our
capital expenditure program from US$238 million in 2014 to US$48 million in
Availability and reliability of infrastructure
2015 and US$39 million in 2016 and implemented significant cost reduction
Our business depends on the availability and reliability of operating and
initiatives that resulted in production and operating costs being reduced by
transportation infrastructure in the areas in which we operate. Prices and
49% (2016 versus 2014), and administrative expenses being reduced by 26%
availability for equipment and infrastructure, and the maintenance thereof,
(2016 versus 2014), while increasing average production to approximately 22.4
affect our ability to make the investments necessary to operate our business,
mboepd and increasing our proved reserves to 73.6 mmboe.
and thus our results of operations and financial condition. See “Item 3. Key
In October 2016, we decided to manage part of our exposure to the volatile
Information—D. Risk factors—Risks relating to our business—Our inability to
crude oil price using derivatives. For further information related to Commodity
access needed equipment and infrastructure in a timely manner may hinder
Risk Management Contracts, please see Note 8 to our Consolidated Financial
our access to oil and natural gas markets and generate significant incremental
Statements.
costs or delays in our oil and natural gas production.”
Additionally, the oil and gas we sell may be subject to certain discounts. For
In order to mitigate the risk of unavailability of operating and transportation
example, in Colombia, the price of oil we sell is based on Vasconia, a marker
infrastructure, we have invested in the construction of plant and pipeline
broadly used in the Llanos Basin, adjusted for certain marketing and quality
infrastructure to produce, process and store hydrocarbon reserves and to
discounts based on, among other things, API, viscosity, sulfur, delivery point
transport them to market.
and water content, as well as on certain transportation costs (including
pipeline costs and trucking costs).
Production levels
Our oil and gas production levels are heavily influenced by our drilling results,
In Chile, the price of oil we sell to ENAP is based on Brent minus certain
our acquisitions and to oil and natural gas prices.
marketing and quality discounts. We have a long-term gas supply contract
with Methanex. The price of the gas sold under this contract is determined
We expect that fluctuations in our financial condition and results of operations
based on a formula that takes into account various international prices of
will be driven by the rate at which production volumes from our wells decline.
methanol, including US Gulf methanol spot barge prices, methanol spot
As initial reservoir pressures are depleted, oil and gas production from a given
Rotterdam prices and spot prices in Asia. See “Item 3. Key Information—D. Risk
well will decline over time. See “Item 3. Key Information—D. Risk factors—
factors—Risks relating to our business—A substantial or extended decline
Risks relating to our business—Unless we replace our oil and natural gas
in oil, natural gas and methanol prices may materially adversely affect our
reserves, our reserves and production will decline over time. Our business is
business, financial condition or results of operations.”
dependent on our continued successful identification of productive fields and
prospects and the identified locations in which we drill in the future may not
If the market prices of oil and methanol had fallen by 10% as compared to
yield oil or natural gas in commercial quantities.”
actual prices during the year, with all other variables held constant, taking into
account the impact of the derivative contracts in place, post-tax loss for the
Contractual obligations
In order to protect our exploration and production rights in our license
GeoPark 107
areas, we must make and declare discoveries within certain time periods
Description of principal line items
specified in our various special contracts, E&P Contracts and concession
The following is a brief description of the principal line items of our statement
agreements. The costs to maintain or operate our license areas may fluctuate
of income.
or increase significantly, and we may not be able to meet our commitments
under these agreements on commercially reasonable terms or at all, which
Revenue
may force us to forfeit our interests in such areas. If we do not succeed in
Revenue includes the sale of crude oil, condensate and natural gas net of
renewing these agreements, or in securing new ones, our ability to grow
value-added tax (“VAT”), and discounts related to the sale (such as API and
our business may be materially impaired. See “Item 3. Key Information—D.
mercury adjustments) and overriding royalties due to the ex-owners of oil
Risk factors—Risks relating to our business—Under the terms of some of our
and gas properties where the royalty arrangements represent a retained
various CEOPs, E&P Contracts and concession agreements, we are obligated
working interest in the property. Revenue is recognized when the significant
to drill wells, declare any discoveries and file periodic reports in order to
risks and rewards of ownership have been transferred to the buyer, the
retain our rights and establish development areas. Failure to meet these
associated costs and amount of revenue can be estimated reliably, recovery
obligations may result in the loss of our interests in the undeveloped parts
of the consideration is probable, and there is no continuing management
of our blocks or concession areas.”
involvement with the goods.
Acquisitions
Commodity risk management contracts
Our results of operations are significantly affected by our past acquisitions. We
Includes realized and unrealized gains and losses arising from commodity risk
generally incorporate our acquired business into our results of operations at
management contracts.
or around the date of closing, such as our Colombian acquisitions in 2012 and
our Rio das Contas acquisition in 2014, which limits the comparability of the
Production and operating costs
period including such acquisitions with prior or future periods.
For a description of our production and operating costs, see “—Factors
affecting our results of operations.”
As described above, part of our strategy is to acquire and consolidate assets
in Latin America. We intend to continue to selectively acquire companies,
Depreciation and write-off of unsuccessful efforts
producing properties and concessions. As with our historical acquisitions,
Capitalized costs of proved oil and natural gas properties are depreciated on
any future acquisitions could make year-to-year comparisons of our results of
a licensed-area-by-licensed-area basis, using the unit of production method,
operations difficult. We may also incur additional debt, issue equity securities
based on commercial proved and probable reserves as calculated under the
or use other funding sources to fund future acquisitions.
Petroleum Resources Management System methodology promulgated by the
Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”),
Functional and presentational currency
which differs from SEC reporting guidelines pursuant to which certain
Our Consolidated Financial Statements are presented in US$, which is our
information in the forepart of this annual report is presented. The calculation
functional and presentational currency. Items included in the financial
of the “unit of production” depreciation takes into account estimated future
information of each of our entities are measured using the currency of the
discovery and development costs. Changes in reserves and cost estimates are
primary economic environment in which the entity operates, or the functional
recognized prospectively. Reserves are converted to equivalent units on the
currency, which is the US$ in each case, except for our Brazil operations, where
basis of approximate relative energy content.
the functional currency is the real.
Geographical segment reporting
In particular, upon completion of the evaluation phase, a prospect is either
transferred to oil and gas properties if it contains reserves, or is charged to
In the description of our results of operations that follow, our “Other”
profit and loss in the period in which the determination is made. See “—
operations reflect our non-Colombian, non-Chilean and non-Brazilian
Critical accounting policies and estimates—Oil and gas accounting.”
operations, primarily consisting of our Argentine, Peruvian (mainly related
to the start-up of our operations in such country) and corporate head office
Geological and geophysical expenses
operations.
Geological and geophysical expenses consist of geosciences costs,
including wages and salaries and share-based compensation not subject to
We divide our business into five geographical segments—Colombia, Chile,
capitalization, geological consultancy costs and costs relating to independent
Brazil, Peru and Argentina—that correspond to our principal jurisdictions of
reservoir engineer studies.
operation. Activities not falling into these four geographical segments are
Administrative expenses
reported under a separate corporate segment that primarily includes certain
Administrative costs consist of corporate costs such as director fees
corporate administrative costs not attributable to another segment.
and travel expenses, new project evaluations and back-office expenses
108 GeoPark 20-F
principally comprised of wages and salaries, share-based compensation,
of contingent assets and liabilities. We continually evaluate these estimates
consultant fees and other administrative costs, including certain costs
and assumptions based on the most recently available information, our own
relating to acquisitions.
historical experience and various other assumptions that we believe to be
reasonable under the circumstances. Since the use of estimates is an integral
Our administrative expenses for the year ended December 31, 2017
component of the financial reporting process, actual results could differ
increased by US$7.9 million, or 23%, compared to the year ended December
from those estimates.
31, 2016 mainly due to higher staff costs resulting from increased scale of
operations. However, administrative costs may increase as a result of our
An accounting policy is considered critical if it requires an accounting
Peruvian and Argentinian operations, other acquisitions, increased activity
estimate to be made based on assumptions about matters that are highly
or the impact of appreciation of local currencies in the countries where we
uncertain at the time such estimate is made, and if different accounting
operate.
Selling expenses
estimates that reasonably could have been used, or changes in the
accounting estimates that are reasonably likely to occur periodically, could
materially impact the financial statements. We believe that the following
Selling expenses consist primarily of transportation and storage costs.
accounting policies represent critical accounting policies as they involve a
Impairment of non-financial assets
higher degree of judgment and complexity in their application and require
us to make significant accounting estimates. The following descriptions of
Assets that are not subject to depreciation and/or amortization (such as
critical accounting policies and estimates should be read in conjunction
exploration and evaluation assets) are tested annually for impairment.
with our Consolidated Financial Statements and the accompanying notes
Assets that are subject to depreciation and/or amortization are reviewed for
and other disclosures.
impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable.
Business combinations
Business combinations are accounted for using the acquisition method.
An impairment loss is recognized for the amount by which the asset’s carrying
The cost of an acquisition is measured as the fair market value of the assets
amount exceeds its recoverable amount. The recoverable amount is the higher
acquired, equity instruments issued and liabilities incurred or assumed on the
of an asset’s fair value minus costs to sell and value in use.
date of completion of the acquisition. Acquisition costs incurred are expensed
During 2017, we did not recognize an additional impairment, while in 2016 we
liabilities and contingent liabilities assumed in a business combination are
recognized a reversal of impairment losses of US$5.7 million and in 2015 we
measured initially at their fair market values at the acquisition date. The
recognized impairment losses amounting to US$149.6 million. See Note 36 to
excess of the cost of acquisitions over fair market value of a company’s share
and included in administrative expenses. Identifiable assets acquired and
our Consolidated Financial Statements.
Financial costs
Financial costs consist of financial income offset by financial expenses.
of the identifiable net assets acquired is recorded as goodwill. If the cost of
the acquisition is less than a company’s share of the net assets required, the
difference is recognized directly in the statement of income.
Financial income includes interest received from bank time deposits. Financial
The determination of fair value of identifiable acquired assets and assumed
expenses principally include interest expense not subject to capitalization,
liabilities means that we are to make estimates and use valuation techniques,
bank charges and the unwinding of long-term liabilities.
including independent appraisers. The valuation assumptions underlying
Foreign exchange gain or loss
each of these valuation methods are based on available updated information,
including discount rates, estimated cash flows, market risk rates and other
Foreign exchange gain or loss represents the effect of exchange rate differences.
data. As a result, the process of identification and the related determination of
fair values require complex judgments and significant estimates.
Loss or profit for the period attributable to owners of the Company
Loss or profit for the period attributable to owners of the Company consists of
Cash flow estimates for impairment assessments
losses or profit for the year less non-controlling interest.
Cash flow estimates for impairment assessments require assumptions
about two primary elements: future prices and reserves. Estimates of
Critical accounting policies and estimates
future prices require significant judgments about highly uncertain future
We prepare our Consolidated Financial Statements in accordance with IFRS
events. Historically, oil and natural gas prices have exhibited significant
and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as
volatility. Our forecasts for oil and natural gas revenues are based on prices
adopted by the IASB. The preparation of the financial statements requires
derived from future price forecasts among industry analysts, as well as our
us to make judgments, estimates and assumptions that affect the reported
own assessments. Estimates of future cash flows are generally based on
amounts of assets, liabilities, revenue and expenses, and related disclosure
assumptions of long-term prices and operating and development costs.
GeoPark 109
The process of estimating reserves requires significant judgments and
Workovers of wells made to develop reserves and/or increase production
decisions based on available geological, geophysical, engineering and
are capitalized as development costs. Maintenance costs are charged to
economic data. The estimation of economically recoverable oil and natural gas
income when incurred.
reserves and related future net cash flows was performed based on the D&M
Reserves Report. Such estimates incorporate many factors and assumptions
Capitalized costs of proved oil and gas properties and production facilities
including:
and machinery are depreciated on a licensed area by licensed area basis,
• expected reservoir characteristics based on geological, geophysical and
using the unit of production method, based on commercial proved and
engineering assessments;
probable reserves. The calculation of the “unit of production” depreciation
• future production rates based on historical performance and expected future
takes into account estimated future finding and development costs, and is
operating and investment activities;
based on current year-end un-escalated price levels. Changes in reserves
• future oil and natural gas prices and quality differentials;
and cost estimates are recognized prospectively. Reserves are converted to
• anticipated effects of regulation by governmental agencies; and
equivalent units on the basis of approximate relative energy content.
• future development and operating costs.
Oil and gas reserves for purposes of our Consolidated Financial Statements
are determined in accordance with PRMS, and were estimated by DeGolyer
Our management believes these factors and assumptions are reasonable
and MacNaughton, independent reserves engineers.
based on the information available at the time we prepare our estimates.
However, these estimates may change substantially as additional data from
Depreciation of the remaining property, plant and equipment assets (i.e.,
ongoing development activities and production performance becomes
furniture and vehicles) not directly associated with oil and gas activities
available and as economic conditions impacting oil and natural gas prices
has been calculated by means of the straight line method by applying
and costs change.
such annual rates as required to write-off their value at the end of their
estimated useful lives. The useful lives range between three and 10 years.
For further information related to impairment of property, plant and
equipment, please see Note 36 to our Consolidated Financial Statements.
Asset retirement obligations
Oil and gas accounting
Obligations related to the plugging and abandonment of wells once operations
are terminated may result in the recognition of significant liabilities. We record
Oil and gas exploration and production activities are accounted for in
the fair value of the liability for asset retirement obligations in the period in
accordance with the successful efforts method on a field by field basis.
which the wells are drilled. When the liability is initially recognized, the cost is
We account for exploration and evaluation activities in accordance with
also capitalized by increasing the carrying amount of the related asset. Over
IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing
time, the liability is accreted to its present value at each reporting date, and the
exploration and evaluation costs until such time as the economic viability
capitalized cost is depreciated over the estimated useful life of the related asset.
of producing the underlying resources is determined. Costs incurred prior
Estimating the future abandonment costs is difficult and requires management
to obtaining legal rights to explore are expensed immediately to the
to make assumptions and judgments because most of the obligations will be
income statement.
settled after many years. Technologies and costs are constantly changing, as
are political, environmental, health, safety and public relations considerations.
Exploration and evaluation costs may include: license acquisition,
Consequently, the timing and future cost of dismantling and abandonment
geological and geophysical studies (i.e., seismic), direct labor costs and
are subject to significant modification. Any change in the variables underlying
drilling costs of exploratory wells. No depreciation and/or amortization are
our assumptions and estimates can have a significant effect on the liability
charged during the exploration and evaluation phase. Upon completion
and the related capitalized asset and future charges related to the retirement
of the evaluation phase, the prospects are either transferred to oil and gas
obligations. The present value of future costs necessary for well plugging and
properties or charged to expense in the period in which the determination
abandonment is calculated for each area at the present value of the estimated
is made, depending whether they have found reserves. If not developed,
future expenditure. The liability recognized is based upon estimated future
exploration and evaluation assets are written off after three years, unless
abandonment costs, wells subject to abandonment, time to abandonment, and
it can be clearly demonstrated that the carrying value of the investment
future inflation rates.
is recoverable. All field development costs are considered construction
in progress until they are finished and capitalized within oil and gas
Share-based payments
properties, and are subject to depreciation once completed. Such costs
We provide several equity-settled, share-based compensation plans to certain
may include the acquisition and installation of production facilities,
employees and third-party contractors, composed of payments in the form of
development drilling costs (including dry holes, service wells and seismic
surveys for development purposes), project-related engineering and the
acquisition costs of rights and concessions related to proved properties.
110 GeoPark 20-F
share awards and stock options plans.
commercial, environmental and health & safety matters. For example, from
time to time, the Company receives notices of environmental, health and safety
Fair value of the stock option plans for employee or contractor services
violations. Based on what our Management currently knows, such claims are
received in exchange for the grant of the options is recognized as an expense.
not expected to have a material impact on the financial statements.
The total amount to be expensed over the vesting period, which is the period
over which all specified vesting conditions are to be satisfied, is determined
Recent accounting pronouncements
by reference to the fair value of the options granted calculated using the
See Note 2.1.1 to our Consolidated Financial Statements.
Geometric Brownian Motion method. Determining the total value of our
share-based payments requires the use of highly subjective assumptions,
Results of operations
including the expected life of the stock options, estimated forfeitures
The following discussion is of certain financial and operating data for the
and the price volatility of the underlying shares. The assumptions used in
periods indicated. You should read this discussion in conjunction with our
calculating the fair value of share-based payment represent management’s
Consolidated Financial Statements and the accompanying notes.
best estimates, but these estimates involve inherent uncertainties and the
As a consequence of the oil price crisis which started in the second half of
application of management’s judgment.
2014 (WTI and Brent, the main international oil price markers, fell more than
60% between August 2014 and March 2016), we have undertaken decisive
Non-market vesting conditions are included in assumptions in respect of
measures to ensure our ability to both maximize the work program and
the number of options that are expected to vest. At each balance sheet date,
preserve our cash.
we revise our estimates of the number of options that are expected to vest.
We recognize the impact of the revision to original estimates, if any, in the
During 2015 and 2016, we took decisive steps to adapt to the new oil
statement of income, with a corresponding adjustment to equity.
price environment. We reduced our capital expenditure program from
The fair value of the share awards payments is determined at the grant date by
US$238 million in 2014 to US$48 million in 2015 and US$39 million in 2016
reference of the market value of the shares and recognized as an expense over
and implemented significant cost reduction initiatives that resulted in
the vesting period.
production and operating costs being reduced by 49% (2016 versus 2014),
and administrative expenses being reduced by 26% (2016 versus 2014), while
When options are exercised, we issue new common shares. The proceeds
increasing average production to approximately 22.4 mboepd and increasing
received net of any directly attributable transaction costs are credited to share
our proved reserves to 73.6 mmboe. For 2017, we designated a self-funded
capital (nominal value) and share premium when the options are exercised.
program that could be adapted to and provide production growth in different
Taxation
oil price scenarios. The main focus of the 2017 work program was to unlock
the potential of the Tigana/Jacana oil field complex with a drilling program for
The computation of our income tax expense involves the interpretation of
20 wells and new facility construction.
applicable tax laws and regulations in many jurisdictions. The resolution of tax
positions taken by us, through negotiations with relevant tax authorities or
In preparation for continued volatility, we have developed multiple scenarios
through litigation, can take several years to complete and in some cases it is
for our 2018 capital expenditure program. See “Item 4. Information on the
difficult to predict the ultimate outcome.
Company –B. Business Overview—2018 Strategy and Outlook.”
In addition, we have tax-loss carry-forwards in certain taxing jurisdictions
Year ended December 31, 2017 compared to year ended December 31, 2016
that are available to offset against future taxable profit. However, deferred
The following table summarizes certain of our financial and operating data for
tax assets are recognized only to the extent that it is probable that taxable
the years ended December 31, 2017 and 2016.
profit will be available against which the unused tax losses can be utilized.
Management judgment is exercised in assessing whether this is the case.
To the extent that actual outcomes differ from management’s estimates,
taxation charges or credits may arise in future periods.
Contingencies
From time to time, we may be subject to various lawsuits, claims and
proceedings that arise in the normal course of business, including employment,
GeoPark 111
For the year ended December 31
(in thousands of US$, except for percentages)
(1)Calculated pursuant to FASB ASC 932
(2)We present production figures before deduction of royalties, as we believe
that net production before royalties is more appropriate in light of our
% Change
foreign operations and the attendant royalty regimes. Oil production figures
2017
2016
prior year
from
presented on page F-76 are net of royalties.
(3)Corresponds to production measured after separation but prior to
compression, which is the measure we used to monitor business performance.
145,193
47,477
192,670
(2,554)
(67,235)
(10,282)
(34,170)
(4,222)
(75,774)
(31,366)
5,664
(1,344)
(28,613)
(34,101)
13,872
(48,842)
(11,804)
(60,646)
(11,554)
(49,092)
6,189
11,911
8,174
22,394
25.6
4.5
7.3
1.5
8.8
1.3
4.5
0.6
92%
Gas production presented on page F-77 is gas measured at the point of
7%
delivery.
71%
505%
47%
(25)%
23%
(73)%
(1)%
(81)%
(100)%
279%
(376)%
51%
(116)%
(152)%
266%
(71)%
(155)%
(51)%
34%
(11)%
23%
23%
43%
18%
1%
100%
18%
(38)%
(2)%
(83)%
Revenue
Net oil sales
Net gas sales
Revenue
279,162
50,960
330,122
Commodity risk management contracts
(15,448)
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Selling expenses
Depreciation
Write-off of unsuccessful efforts
Impairment loss reversed for
non-financial assets
Other operating expense
Operating profit (loss)
Financial costs
Foreign exchange (loss) gain
Profit (Loss) before income tax
Income tax expense
Loss for the year
Non-controlling interest
Loss for the year attributable
to owners of the Company
Net production volumes
Oil (mbbl) (2)
Gas (mcf ) (3)
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$)
Operating cost
Royalties and other
Production costs(1)
Geological and geophysical expenses
Administrative expenses
Selling expenses
(98,987)
(7,694)
(42,054)
(1,136)
(74,885)
(5,834)
-
(5,088)
78,996
(51,495)
(2,193)
25,308
(43,145)
(17,837)
6,391
(24,228)
8,309
10,562
10,069
27,586
36.6
5.3
7.4
3.0
10.4
0.8
4.4
0.1
112 GeoPark 20-F
The following table summarizes certain financial and operating data.
For the year ended December 31,
(in thousands of US$)
Chile
Colombia
32,738
(23,730)
263,076
(40,010)
Brazil
34,238
(10,809)
Other
70
(336)
2017
Total
330,122
(74,885)
Chile
Colombia
36,723
(31,355)
126,228
(31,148)
Brazil
29,719
(12,974)
Other
-
(297)
2016
Total
192,670
(75,774)
(546)
(1,625)
(2,978)
(685)
(5,834)
(19,389)
(1,730)
(4,583)
-
(25,702)
Revenue
Depreciation
Impairment
and write-off
Revenue
For the year ended December 31, 2017, crude oil sales were our principal
December 31, 2017 due to increased sales volumes and higher realized prices.
source of revenue, with 85% and 15% of our total revenue from crude oil
The increase in 2017 net revenue of US$137.5 million is mainly explained by:
and gas sales, respectively. The following chart shows the change in oil and
• an increase of US$136.8 million in sales in Colombia, due to an increase in
natural gas sales from the year ended December 31, 2016 to the year ended
price and volume;
December 31, 2017.
• a decrease of US$4 million in sales in Chile, including decreases of US$2.9
For the year ended December 31,
million in oil sales and US$1.1 million of gas sales; and
(in thousands of US$)
• an increase of US$4.3 million in gas sales in Brazil, related to our Manati
Consolidated
Sale of crude oil
Sale of gas
Total
By country
Colombia
Chile
Brazil
Other
Total
2017
2016
operations;
all of which was due principally to higher oil and gas prices, as further
279,162
50,960
described below.
145,193
47,477
Revenue attributable to our operations in Colombia for the year ended
330,122
192,670
December 31, 2017 was US$263.1 million, compared to US$126.2 million for
the year ended December 31, 2016, representing 80% and 66% of our total
consolidated sales. The increase is related to an increase in oil deliveries from
Year ended December 31
Change from prior year
5.4 mmbbl to 7.6 mmbbl and an increase in the average realized price per
(in thousands of US$, except for percentages)
barrel of crude oil from US$24.4 per barrel to US$36.1 per barrel, primarily due
2017
2016
%
to higher reference international prices.
263,076
126,228
136,848
32,738
34,238
70
36,723
29,719
-
(3,985)
4,519
70
108%
(11)%
Revenue attributable to our operations in Chile for the year ended December
31, 2017 was US$32.7 million, a 11% decrease from US$36.7 million for the
15%
year ended December 31, 2016, principally due to (1) decreased sales of
100%
crude oil of 0.3 mmbbl for the year ended December 31, 2017 compared to
330,122
192,670
137,452
71%
0.5 mmbbl for the year ended December 31, 2016 (a decrease of 40%) due
to the decline in oil base production, (2) a decrease in gas sales by US$1.1
Revenue increased 71%, from US$192.7 million for the year ended December
million, due to decreased gas production levels as compared to the previous
31, 2016 to US$330.1 million for the year ended December 31, 2017, primarily
year. This was partially offset by increased average realized prices per barrel of
as a result of higher oil revenues. Sales of crude oil increased due to higher
crude oil from US$37.0 per barrel for the year December 31, 2016 to US$45.7
realized prices and higher sold volumes of 7.9 mmbbl in the year ended
per barrel for the year ended December 31, 2017 (an increase of US$8.7 per
December 31, 2017 compared to 5.9 mmbbl in the year ended December
barrel or a total of 24%). The increase in the average realized price per barrel
31, 2016, and resulted in net revenue of US$279.2 million for the year ended
was attributable to higher international reference prices. The contribution to
December 31, 2017 compared to US$145.2 million for the year ended
our revenue during such years from our operations in Chile was 10% and 19%,
December 31, 2016. In addition, sales of gas increased from US$47.5 million
respectively.
for the year ended December 31, 2016 to US$51.0 million for the year ended
GeoPark 113
Revenue attributable to our operations in Brazil for the year ended December
31, 2017 was US$34.2 million, a 15% increase from US$29.7 million for the
year ended December 31, 2016, principally due to higher gas prices. The
contribution to our revenue from our operations in Brazil during the years
ended December 31, 2017 and 2016 was 10% and 15%, respectively.
Production and operating costs
The following table summarizes our production and operating costs for the
years ended December 31, 2017 and 2016.
For the year ended December 31
(in thousands of US$, except for percentages)
% Change
from prior
2017
2016
year
Consolidated (including Colombia,
Chile, Argentina, Peru and Brazil)
Royalties
Staff costs
Transportation costs
Well and facilities maintenance
Consumables
Equipment rental
Other costs
Total
(28,697)
(15,474)
(2,969)
(14,722)
(11,902)
(5,818)
(19,405)
(11,497)
(10,859)
(2,281)
(13,160)
(8,283)
(3,868)
(17,287)
(98,987)
(67,235)
150%
42%
30%
12%
44%
50%
12%
47%
By country
Royalties
Staff costs
Transportation costs
Well and facilities maintenance
Consumables
Equipment rental
Other costs
Total
Consolidated production and operating costs increased 47%, from US$67.2
million for the year ended December 31, 2016 to US$99.0 million for the year
ended December 31, 2017, primarily due to higher royalties paid in cash, in
line with increased production (the Jacana oil field accumulated more than 5
mmbbl during the year ended December 31, 2017, triggering a higher royalty
rate in Colombia), and higher oil prices, and increased operating costs related
to higher sales volumes.
114 GeoPark 20-F
Year ended December 31
(in thousands of US$)
2017
2016
Chile
Brazil
Colombia
Chile
Brazil
Colombia
(1,314)
(5,582)
(1,211)
(3,817)
(1,680)
(59)
(7,336)
(3,134)
(241)
-
(2,982)
-
-
(4,380)
(24,236)
(9,461)
(1,678)
(7,923)
(10,209)
(5,706)
(7,700)
(1,495)
(5,866)
(1,170)
(6,122)
(1,405)
(42)
(6,069)
(20,999)
(10,737)
(66,913)
(22,169)
(2,721)
(85)
-
(1,419)
-
-
(4,234)
(8,459)
(7,281)
(5,530)
(1,111)
(5,619)
(6,878)
(3,826)
(6,362)
(36,607)
Production and operating costs in Colombia increased 83%, to US$66.9 million
Administrative costs increased 23%, from US$34.2 million for the year ended
for the year ended December 31, 2017, as compared to US$36.6 million for the
December 31, 2016 to US$42.1 million for the year ended December 31,
year ended December 31, 2016, primarily due to (i) higher royalties of US$17.0
2017, mainly due to higher staff costs and consulting fees resulting from an
million, in line with increased production (the Jacana oil field accumulated
increased scale of operations.
more than 5 mmbbl during the year ended December 31, 2017, triggering a
higher royalty rate in Colombia) and higher oil prices, and (ii) increased costs
Selling expenses
associated with higher production and the reopening of the Cuerva and Yamu
Blocks, which are mature fields with higher operating costs than the Llanos 34
Year ended December 31,
Change from prior year
Block. In addition, operating costs per boe in Colombia increased to US$5.6
per boe for the year ended December 31, 2017 from US$5.4 per boe for the
year ended December 31, 2016.
Production and operating costs in Chile decreased by 5% to US$21.0 million
due to lower oil and gas production levels. Costs per boe increased to US$20.3
per boe from US$15.8 per boe in 2016. In the year ended December 31, 2017,
the revenue mix for Chile was 48.5% oil and 51.5% gas, whereas for the same
Colombia
Chile
Brazil
Other
Total
(in thousands of US$, except for percentages)
2017
(250)
(688)
-
(198)
(1,136)
2016
(2,830)
(994)
(20)
(378)
2,580
306
20
180
(4,222)
3,086
%
(91)%
(31)%
(100)%
(48)%
(73)%
period in 2016 it was 51.1% oil and 48.9% gas.
Selling expenses decreased 73%, from US$4.2 million for year ended December
Production and operating costs in Brazil increased by 27%, to US$10.7 million
due to the Trafigura offtake agreement as sales occur at the wellhead in our
for the year ended December 31, 2017, as compared to the year ended
Colombian operations, which are recorded as a discount to the oil price.
31, 2016 to US$1.1 million for the year ended December 31, 2017, primarily
December 31, 2016, mainly resulting from non-recurring maintenance costs in
Manati Field. Operating costs per boe increased to US$7.8 for the year ended
Commodity risk management contracts
December 31, 2017 from US$5.8 per boe for the year ended December 31,
We recorded a loss of US$15.4 million related to commodity risk management
2016.
contracts for the year ended December 31, 2017. Realized losses reflect cash
settled transactions and unrealized losses reflect non-cash changes between the
Geological and geophysical expenses
contract values and the forward Brent oil curve.
Year ended December 31
Change from prior year
Depreciation
(in thousands of US$, except for percentages)
Depreciation charges decreased by 1% from US$75.8 million for the year ended
2017
(2,231)
(858)
(1,007)
(3,598)
2016
(4,296)
(1,671)
(1,053)
(3,262)
(7,694)
(10,282)
2,065
813
46
(336)
2,588
%
December 31, 2016 to US$74.9 million for the year ended December 31, 2017,
mainly due to lower production levels in Chile and Brazil. and lower depreciation
costs per barrel in Colombia. Depreciation costs per boe decreased from US$9.9
to US$7.9 per boe.
(48)%
(49)%
(4)%
10%
(25)%
Operating profit (loss)
Colombia
Chile
Brazil
Other
Total
Geological and geophysical expenses decreased 25%, from US$10.3 million
for the year ended December 31, 2016 to US$7.7 million for the year ended
December 31, 2017, primarily as the result of higher allocation to capitalized
projects due to increased drilling activity levels.
Administrative costs
Year ended December 31
Change from prior year
(in thousands of US$, except for percentages)
Year ended December 31,
Change from prior year
(in thousands of US$, except for percentages)
2017
116,290
(19,675)
4,434
(22,053)
78,996
2016
31,464
(44,969)
(644)
(14,464)
84,826
25,294
5,078
(7,589)
%
270%
(56)%
(789)%
52%
(28,613)
107,609
(376)%
Colombia
Chile
Brazil
Other
Total
Colombia
(17,567)
(14,715)
(2,852)
19%
December 31, 2017, a 376% improvement from the operating loss of
2017
2016
%
We recorded an operating profit of US$79.0 million for the year ended
Chile
Brazil
Other
Total
(6,331)
(2,444)
(15,712)
(7,153)
(3,085)
(9,217)
(42,054)
(34,170)
822
641
(6,495)
(7,884)
(11)%
(21)%
70%
23%
US$28.6 million for the year ended December 31, 2016, primarily due to
an increase in revenue and other gains and a decrease in certain expenses
GeoPark 115
and depreciation, as described above. In 2016, we recorded a gain on non-
Loss Profit for the year
cash impairments reversal of non-financial assets amounting to US$5.7
million in Colombia, resulting from an improved oil price environment and
improvements in cost structure.
Financial costs
Financial costs increased 51% to US$51.5 million for the year ended December
31, 2017 as compared to US$34.1 million for the year ended December 31,
2016, mainly due to one-time costs on the cancellation of 2020 Notes for an
amount of US$17.6 million.
Colombia
Chile
Brazil
Other
Total
Year ended December 31
Change from prior year
(in thousands of US$, except for percentages)
2017
67,622
(31,945)
(2,493)
(51,021)
2016
13,876
(55,862)
5,998
(24,658)
(17,837)
(60,646)
53,746
23,917
(8,491)
(26,363)
42,809
%
387%
(43)%
(142)%
107%
(71)%
Foreign exchange (loss) gain
For the year ended December 31, 2017, we recorded a net loss of US$17.8
Foreign exchange variation decreased from a gain of US$13.9 million for the
million as a result of the reasons described above.
year ended December 31, 2016 compared to a loss of US$2.2 million for the
year ended December 31, 2017, mainly due to the appreciation of the Brazilian
Loss Profit for the year attributable to owners of the Company
real in the 2016 period and its depreciation in the 2017 period. Foreign
Loss for the year attributable to owners of the Company decreased by 51%
exchange differences are mainly generated from changes in the value of the
to US$24.2 million, compared to a loss for the year ended December 31,
Brazilian real over the U.S. Dollar-denominated debt incurred at the local
2016 of US$49.1 million for the reasons described above. Profit attributable
subsidiary level, where the functional currency is the Brazilian real.
to non-controlling interest increased by 155% to US$6.4 million for the year
ended December 31, 2017 as compared to a loss of US$11.6 million for the
Profit (Loss) before income tax
year ended December 31, 2016.
Year ended December 31
Change from prior year
Year ended December 31, 2016 compared to year ended December 31, 2015
(in thousands of US$, except for percentages)
The following table summarizes certain of our financial and operating data for
Colombia
Chile
Brazil
Other
Total
2017
113,028
(32,801)
(2,529)
(52,390)
25,308
2016
25,845
(58,017)
8,762
(25,432)
(48,842)
%
the years ended December 31, 2016 and 2015.
87,183
25,216
(11,291)
(26,958)
74,150
337%
(43)%
(129)%
106%
(152)%
For the year ended December 31, 2017, we recorded a profit before income tax of
US$25.3 million, compared to a loss of US$48.8 million for the year ended December
31, 2016, primarily due to profits recorded in our Colombian operations.
Income tax (expense)
Colombia
Chile
Brazil
Other
Total
Year ended December 31
Change from prior year
(in thousands of US$, except for percentages)
2017
2016
(45,406)
(11,969)
856
36
1,369
2,155
(2,764)
774
(33,437)
(1,299)
2,800
595
(43,145)
(11,804)
(31,341)
%
279%
(60)%
(101)%
77%
266%
Income tax expense increased 266%, from US$11.8 million for the year ended
December 31, 2016 to US$43.1 million for the year ended December 31, 2017, as a
result of higher profits in Colombia.
116 GeoPark 20-F
For the year ended December 31
(in thousands of US$, except for percentages)
% Change
(1) Calculated pursuant to FASB ASC 932.
(2) We present production figures before deduction of royalties, as we believe
that net production before royalties is more appropriate in light of our
from
foreign operations and the attendant royalty regimes. Oil production figures
2016
2015
prior year
145,193
47,477
162,629
47,061
(11)%
192,670
209,690
(8)%
delivery.
presented on page F-76 are net of royalties.
(3) Corresponds to production measured after separation but prior to
compression, which is the measure we used to monitor business performance.
1%
Gas production presented on page F-77 is gas measured at the point of
Revenue
Net oil sales
Net gas sales
Net revenue
The following table summarizes certain financial information and
operating data.
Commodity risk management contracts
(2,554)
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Selling expenses
Depreciation
Write-off of unsuccessful efforts
(67,235)
(10,282)
(34,170)
(4,222)
(75,774)
(31,366)
—
(86,742)
(13,831)
(37,471)
(5,211)
(105,557)
(30,084)
Impairment loss for non-financial assets
5,664
(149,574)
Other operating expense
Operating loss
Financial costs
Foreign exchange gain (loss)
Loss before income tax
Income tax (expense) benefit
Loss for the year
Non-controlling interest
Loss for the year attributable
(1,344)
(28,613)
(34,101)
13,872
(13,711)
(232,491)
(35,655)
(33,474)
(48,842)
(301,620)
(11,804)
17,054
(60,646)
(11,554)
(284,566)
(50,535)
100%
(22)%
(26)%
(9)%
(19)%
(28)%
4%
(104)%
(90)%
(88)%
(4)%
(141)%
(84)%
(169)%
(79)%
(77)%
to owners of the Company
(49,092)
(234,031)
(79)%
Net production volumes
Oil (mbbl) (3)
Gas (mcf ) (2)
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$)
Operating cost
Royalties and other
Production costs(1)
Geological and geophysical expenses
Administrative expenses
Selling expenses
6,189
11,911
8,174
22,394
5,518
11,493
7,434
20,367
25.6
4.5
7.3
1.5
8.8
1.3
4.5
0.6
32.1
4.6
10.5
1.9
12.4
2.0
5.4
0.7
12%
4%
10%
10%
(20)%
(2)%
(30)%
(21)%
(29)%
(35)%
(17)%
(14)%
GeoPark 117
Net revenue
Depreciation
Impairment and write-off
Chile
Colombia
36,723
(31,355)
(19,389)
126,228
(31,148)
(1,730)
Brazil
29,719
(12,974)
(4,583)
Other
—
(297)
—
2016
Total
192,670
(75,774)
(25,702)
Year ended December 31
(in thousands of US$)
2015
Chile
Colombia
44,808
(39,227)
(130,266)
131,897
(52,434)
(49,392)
Brazil
32,388
(13,568)
—
Other
597
(328)
Total
209,690
(105,557)
—
(179,658)
Revenue
For the year ended December 31, 2016, crude oil sales were our principal
December 31, 2016 due to higher production.
source of revenue, with 75% and 25% of our total revenue from crude oil
and gas sales, respectively. The following chart shows the change in oil and
The decrease in 2016 net revenue of US$17.0 million is mainly explained by:
natural gas sales from the year ended December 31, 2015 to the year ended
• a decrease of US$5.7 million in oil sales in Colombia
December 31, 2016.
Consolidated
Sale of crude oil
Sale of gas
Total
By country
Colombia
Chile
Brazil
Other
Total
• a decrease of US$8.1 million in sales in Chile, including US$10.4 million in
oil sales partially offset by an increase of US$2.3 million of gas sales.
For the year ended December 31
• a decrease of US$2.7 million in sales in Brazil, related to our Manati
(in thousands of US$)
operations and including US$0.3 million of oil sales and US$2.4 million of
gas sales, all of which was due principally to lower oil and gas prices, as
2016
2015
further described below.
145,193
47,477
162,629
Revenue attributable to our operations in Colombia for the year ended
47,061
December 31, 2016 was US$126.2 million, compared to US$131.9 million
192,670
209,690
for the year ended December 31, 2015, representing 66% and 63% of our
total consolidated sales. The decrease is related to a decrease in the average
realized prices per barrel of crude oil from US$28.8 per barrel to US$24.4 per
Year ended December 31
barrel, primarily due to lower reference international prices. This was partially
(in thousands of US$, except for percentages)
offset by increased sales of crude oil, from 4.6 mmbbl for the year ended
% Change
December 31, 2015 to 5.4 mmbbl for the year ended December 31, 2016, an
from prior
increase of 17%. This increase resulted mainly from the development and
2016
2015
year
appraisal of the Jacana and Tigana fields in the Llanos 34 Block.
126,228
131,897
36,723
29,719
—
44,808
32,388
597
(5,669)
(8,085)
(2,669)
(597)
(4)%
Revenue attributable to our operations in Chile for the year ended December
(18)%
31, 2016 was US$36.7 million, a 18% decrease from US$44.8 million for the
(8)%
year ended December 31, 2015, principally due to (1) decreased sales of
(100)%
crude oil of 0.5 mmbbl for the year ended December 31, 2016 compared to
192,670
209,690
(17,020)
(8)%
0.7 mmbbl for the year ended December 31, 2015 (a decrease of 29%) due to
the decline in oil base production, (2) decreased average realized prices per
Revenue decreased 8%, from US$209.7 million for the year ended December
barrel of crude oil from US$42.2 per barrel for the year December 31, 2015
31, 2015 to US$192.7 million for the year ended December 31, 2016, primarily
to US$37.0 per barrel for the year ended December 31, 2016 (a decrease of
as a result of lower prices. Sales of crude oil increased to 5.9 mmbbl in the
US$5.2 per barrel or a total of 12%). The decrease in the average realized price
year ended December 31, 2016 compared to 5.3 mmbbl in the year ended
per barrel was attributable to lower international reference prices. This was
December 31, 2015, and resulted in net revenue of US$145.2 million for the
partially offset by an increase in gas sales by US$2.3 million, due to increased
year ended December 31, 2016 compared to US$162.6 for the year ended
gas production levels as compared to the previous year. The contribution
December 31, 2015. In addition, sales of gas increased from US$47.1 million
to our revenue during such years from our operations in Chile was 19% and
for the year ended December 31, 2015 to US$47.5 million for the year ended
21%, respectively.
118 GeoPark 20-F
Revenue attributable to our operations in Brazil for the year ended
December 31, 2016 was US$29.7 million, a 8% decrease from US$32.4 million
for the year ended December 31, 2015, principally due to decreased sales
of gas of 5.8 mmcf for the year ended December 31, 2016 compared to 6.7
mmcf for the year ended December 31, 2015 (a decrease of 13%) due to
lower industrial demand. The contribution to our revenue during such years
from our operations in Brazil was 15%.
Production and operating costs
The following table summarizes our production and operating costs for the
years ended December 31, 2016 and 2015.
For the year ended December 31
(in thousands of US$, except for percentages)
% Change
from prior
2016
2015
year
Consolidated (including Colombia,
Chile, Argentina, Peru and Brazil)
Royalties
Staff costs
Transportation costs
Well and facilities maintenance
Consumables
Equipment rental
Other costs
Total
(11,497)
(10,859)
(2,281)
(13,160)
(8,283)
(3,868)
(13,155)
(18,562)
(4,511)
(19,974)
(8,591)
(3,517)
(17,287)
(18,432)
(13)%
(41)%
(49)%
(34)%
(4)%
10%
(6)%
(67,235)
(86,742)
(22)%
Year ended December 31
(in thousands of US$)
2016
2015
Chile
Brazil
Colombia
Chile
Brazil
Colombia
By country
Royalties
Staff costs
Transportation costs
Well and facilities maintenance
Consumables
Equipment rental
Other costs
Total
(1,495)
(5,866)
(1,170)
(6,122)
(1,405)
(42)
(6,069)
(22,169)
(2,721)
(85)
—
(1,419)
—
—
(4,234)
(8,459)
(7,281)
(5,530)
(1,111)
(5,619)
(6,878)
(3,826)
(6,362)
(1,973)
(7,680)
(2,441)
(2,998)
—
—
(10,628)
(1,651)
(1,851)
(101)
(4,030)
—
—
(36,607)
(28,704)
(8,150)
(9,322)
(2,068)
(7,611)
(6,726)
(3,404)
(3,407)
(8,056)
(11,253)
(48,534)
GeoPark 119
Consolidated production and operating costs decreased 22%, from US$86.7
Administrative costs
million for the year ended December 31, 2015 to US$67.2 million for the
year ended December 31, 2016, primarily due to cost reduction efforts and
efficiencies, partially offset by increased volume sold.
Production and operating costs in Colombia decreased 25%, to US$36.6
million for the year ended December 31, 2016, as compared to the year
ended December 31, 2015, primarily due to cost reduction efforts. In addition,
operating costs per boe in Colombia decreased to US$5 per boe for the year
Colombia
ended December 31, 2016 from US$9 per boe for the year ended December
31, 2015.
Production and operating costs in Chile decreased by 23%, due to cost
reduction initiatives and operating costs per boe decreased to US$16 per
Chile
Brazil
Other
Total
For the year ended December 31
(in thousands of US$, except for percentages)
2016
(14,715)
(7,153)
(3,085)
(9,217)
2015
(10,579)
(10,978)
(2,936)
(12,978)
(34,170)
(37,471)
(4,136)
3,825
(149)
3,761
3,301
% Change
from prior
year
39%
(35)%
5%
(29)%
(9)%
boe from US$21 per boe in 2015. In the year ended December 31, 2016, the
Administrative costs decreased 9%, from US$37.5 million for the year ended
revenue mix for Chile was 51.1% oil and 48.9% gas, whereas for the same
December 31, 2015 to US$34.2 million for the year ended December 31, 2016,
period in 2015 it was 65.1% oil and 34.9% gas.
primarily as a result of continuing financial discipline.
Production and operating costs in Brazil increased by 5%, to US$8.4 million for
Selling expenses
the year ended December 31, 2016, as compared to the year ended December
31, 2015, primarily due to decrease in production. Operating costs per boe
increased to US$6 for the year ended December 31, 2016 from US$4 per boe
for the year ended December 31, 2015.
Geological and geophysical expenses
For the year ended December 31
(in thousands of US$, except for percentages)
Colombia
Chile
Brazil
% Change
Other
from prior
Total
For the year ended December 31
(in thousands of US$, except for percentages)
2016
(2,830)
(994)
(20)
(378)
2015
(3,658)
(1,085)
—
(468)
(4,222)
(5,211)
% Change
from prior
year
(23)%
(8)%
100%
(19)%
(19)%
828
91
(20)
90
989
Colombia
Chile
Brazil
Other
Total
2016
(4,296)
(1,671)
(1,053)
(3,262)
2015
(2,798)
(4,749)
(1,103)
(5,181)
(10,282)
(13,831)
(1,498)
3,078
50
1,919
3,549
year
54%
Selling expenses decreased 19%, from US$5.2 million for year ended December
(65)%
31, 2015 to US$4.2 million for the year ended December 31, 2016, primarily due
(5)%
to a change in the commercialization mix increasing sales at wellhead in our
(37)%
Colombian operations. In our Chilean operations, selling expenses were 8%
(26)%
lower compared to prior year, primarily as a result of lower oil production levels.
Geological and geophysical expenses decreased 26%, from US$13.8 million
for the year ended December 31, 2015 to US$10.3 million for the year ended
December 31, 2016, primarily as the result of higher allocation to capitalized
projects and lower staff costs.
Operating (loss) profit
Colombia
Chile
Brazil
Other
Total
For the year ended December 31
(in thousands of US$, except for percentages)
2016
31,464
2015
(37,227)
(44,969)
(180,264)
(644)
6,639
(14,464)
(21,639)
68,691
135,295
(7,283)
7,175
(28,613)
(232,491)
203,878
% Change
from prior
year
(185)%
(75)%
(110)%
(33)%
(88)%
120 GeoPark 20-F
We recorded an operating loss of US$28.6 million for the year ended December
Income tax (expense) benefit
31, 2016, an 88% improvement from the operating loss of US$232.5 million for
the year ended December 31, 2015, primarily due to the recognition in 2015 of
non-cash impairments of non-financial assets amounting to US$149.6 million
(US$104.5 million recorded in Chile and US$45.1 million in Colombia). In 2016,
we recorded a gain on non-cash impairments reversal of non-financial assets
amounting to US$5.7 million in Colombia, resulting from an improved oil price
environment and improvements in cost structure.
Financial costs
Financial costs decreased 4% to US$34.1 million for the year ended December
Colombia
Chile
Brazil
Other
31, 2016 as compared to US$35.7 million for the year ended December 31, 2015,
Total
mainly due to the impact of lower bank charges and higher interest gains.
For the year ended December 31
(in thousands of US$, except for percentages)
2016
(11,969)
2,155
(2,764)
774
(11,804)
2015
(620)
16,893
8,357
(7,576)
17,054
(11,349)
(14,738)
(11,121)
8,350
(28,858)
% Change
from prior
year
1,830%
(87)%
(133)%
(110)%
(169)%
Foreign exchange gain (loss)
Income tax expense decreased 169%, from US$17.1 million for the year ended
December 31, 2015 to a loss of US$11.8 million for the year ended December
Foreign exchange variation was 141% to a gain of US$13.9 million for the year
31, 2016, as a result of increased results of operations, mainly related to
ended December 31, 2016 as compared to US$33.5 million loss for the year
Colombia and Brazil.
ended December 31, 2015, mainly because of the appreciation of the real over
US$ denominated net debt incurred at the local subsidiary level, where the
(Loss) Profit for the year
functional currency is the real.
(Loss) Profit before income tax
For the year ended December 31
(in thousands of US$, except for percentages)
Colombia
% Change
Chile
from prior
Brazil
Other
Total
year
(167)%
(70)%
2016
25,845
2015
(38,339)
(58,017)
(193,683)
8,762
(25,432)
(37,980)
(31,618)
64,184
135,666
46,742
6,186
Colombia
Chile
Brazil
Other
Total
For the year ended December 31
(in thousands of US$, except for percentages)
2016
13,876
2015
(38,959)
(55,862)
(176,789)
5,998
(24,658)
(29,623)
(39,195)
52,835
120,927
35,621
14,537
(60,646)
(284,566)
223,920
% Change
from prior
year
(136)%
(68)%
(120)%
(37)%
(79)%
(123)%
For the year ended December 31, 2016, we recorded a loss of US$60.6 million
(20)%
as a result of the reasons described above.
(48,842)
(301,620)
252,778
(84)%
(Loss) Profit for the year attributable to owners of the Company
For the year ended December 31, 2016, we recorded a loss before income
tax of US$48.8 million, compared to a loss of US$301.6 million for the year
Loss for the year attributable to owners of the Company decreased by 79%
ended December 31, 2015, primarily due to decreased losses from our Chilean
to US$49.1 million, for the reasons described above. Loss attributable to non-
and Other operations and profits recorded in our Colombian and Brazilian
controlling interest decreased by 77% to US$11.6 million for the year ended
operations.
December 31, 2016 as compared to the prior year.
B. Liquidity and capital resources
Overview
Our financial condition and liquidity is and will continue to be influenced by a
variety of factors, including:
• changes in oil and natural gas prices and our ability to generate cash flows
from our operations;
• our capital expenditure requirements;
• the level of our outstanding indebtedness and the interest we are obligated
GeoPark 121
to pay on this indebtedness; and
March 21 2018, we made a semi-annual interest payment on the Notes due
• changes in exchange rates which will impact our generation of cash flows
2024 in the amount of US$13.8 million.
from operations when measured in US$, and the real.
We repurchased US$284.0 million aggregate principal amount of the
Our principal sources of liquidity have historically been contributed
outstanding Notes due 2020 in September 2017, and redeemed the remaining
shareholder equity, debt financings and cash generated by our operations.
US$16.0 million aggregate principal amount outstanding in October 2017,
Since 2005 to 2017, we have raised approximately US$200 million in equity
using funds received in connection with the settlement of the Notes due 2024.
offerings at the holding company level and nearly US$1 billion through debt
The total consideration paid for the validly tendered and accepted Notes due
arrangements with multilateral agencies such as the IFC, gas prepayment
2020 was US$1,041.25 per US$1,000 principal amount of 2020 Notes, which
facilities with Methanex, international bond issuances and bank financings,
included an early tender payment of US$30 per US$1,000 principal amount
described further below, which have been used to fund our capital
of 2020 Notes for holders who tendered their notes by September 19, 2017,
expenditures program and acquisitions and to increase our liquidity.
plus accrued and unpaid interest to, but not including, September 21, 2017.
We have also raised US$182.1 million to date through our strategic partnership
We redeemed the remaining US$16.0 million aggregate principal amount
with LGI following the sale of minority interests in our Colombian and Chilean
outstanding of the Notes due 2020 at a price equal to 103.75% of the principal
operations.
amount thereof, plus accrued and unpaid interest (including additional
In February 2014, we commenced trading on the NYSE and raised US$98
amounts, if any) from August 11, 2017 to, but excluding October 21, 2017.
million (before underwriting commissions and expenses), including the over-
allotment option granted to and exercised by the underwriters, through the
We believe that our current operations and 2018 capital expenditures program
issuance of 13,999,700 common shares.
can be funded from cash flow from existing operations and cash on hand.
Should our operating cash flow decline due to unforeseen events, including
In February 2013, we issued US$300.0 million aggregate principal amount of
delivery restrictions or a protracted downturn in oil and gas prices, we would
7.50% senior secured notes due 2020 (the “Notes due 2020”).
examine measures such as further capital expenditure program reductions,
pre-sale agreements, disposition of assets, or issuance of equity, among
In December 2015, we entered into an offtake and prepayment agreement
others.
with Trafigura under which we will sell a portion of our Colombian crude oil
production to Trafigura in exchange for advance payments of up to US$100
Capital expenditures
million, subject to applicable volumes corresponding to the terms of the
In the past, we have funded our capital expenditures with proceeds from
agreement. Funds committed by Trafigura were available to us upon request
equity offerings, credit facilities, debt issuances and pre-sale agreements,
until September 2017 to be repaid by us on a monthly basis through future
as well as through cash generated from our operations. We expect to incur
oil deliveries until December 2018. As of October 2017, we are no longer
substantial expenses and capital expenditures as we develop our oil and
obligated to pay a commitment fee for any unused commitment under the
natural gas prospects and acquire additional assets. See “Item 4. Information
Trafigura Agreement.
on the Company –B. Business Overview—2018 Strategy and Outlook.”
In September 2017, we issued US$425.0 million aggregate principal amount
In the year ended December 31, 2017, we made total capital expenditures of
of senior secured notes due 2024. The Notes due 2024 mature on September
US$105.6 million (US$80.0 million, US$10.2 million, US$8.2 million, US$3.6
21, 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per
million and US$3.6 million in Colombia, Chile, Argentina, Peru and Brazil,
year. Interest on the Notes due 2024 is payable semi-annually in arrears
respectively).
on March 21 and September 21 of each year. The Indenture governing our
Notes due 2024 contains incurrence-based limitations on the amount of
In the year ended December 31, 2016, we made total capital expenditures of
indebtedness we can incur. This situation may limit our capacity to incur
US$39.3 million (US$26.2 million, US$7.8 million, US$1.7 million and US$3.6
additional indebtedness, other than permitted debt, as specified in the
million in Colombia, Chile, Argentina and Brazil, respectively).
indenture governing the Notes. The net proceeds from the Notes were used
by us (i) to make a capital contribution to our wholly-owned subsidiary,
Cash flows
GeoPark Latin America Limited Agencia en Chile, providing it with sufficient
The following table sets forth our cash flows for the periods indicated:
funds to fully repay the 7.50% senior secured notes due 2020 and to pay
any related fees and expenses, including a call premium, and (ii) for general
corporate purposes, including capital expenditures, such as the acquisition
of Aguada Baguales, El Porvenir and Puesto Touquet blocks in Neuquen basin
in Argentina, and to repay existing indebtedness, including the Itaú loan. On
122 GeoPark 20-F
Year ended December 31,
Indebtedness
(in thousands of US$)
As of December 31, 2017 and 2016, we had total outstanding indebtedness
2015
of US$426.2 million and US$358.7 million, respectively, as set forth in the
Cash flows provided by (used in)
Operating activities
Investing activities
Financing activities
Net increase (decrease)
2017
142,158
(105,604)
23,968
2016
82,884
(39,306)
(51,136)
25,895
table below.
(48,842)
(18,022)
BCI Loans
Bond GeoPark Latin America Agencia
in cash and cash equivalents
60,522
(7,558)
(40,969)
en Chile (Notes due 2020)
Bond GeoPark Limited (Notes due 2024)
Cash flows provided by operating activities
Banco de Chile
For the year ended December 31, 2017, cash provided by operating activities
Rio das Contas Credit Facility
was US$142.2 million, a 72% increase from US$82.9 million for the year
Total
ended December 31, 2016, resulting from the increase in oil prices in 2017
as compared to 2016, net of a US$15.6 million advance payment paid in
As of December 31, (in thousands of US$)
2016
80
—
426,124
—
—
2017
141
304,059
—
4,709
49,763
426,204
358,672
December 2017 to Pluspetrol, as a security deposit related to the recently
Our material outstanding indebtedness as of December 31, 2017 is
announced acquisition of Aguada Baguales, El Porvenir and Puesto Touquet
described below.
blocks in Neuquen basin in Argentina.
Notes due 2024
For the year ended December 31, 2016, cash provided by operating activities
was US$82.9 million, a 220% increase from US$25.9 million for the year ended
General
December 31, 2015, resulting from cost reduction efforts, lower income tax
On September 21, 2017, we issued US$425.0 million aggregate principal
paid and increased funds from working capital, including customer advance
amount of senior secured notes due 2024. The Notes due 2024 mature on
payments from Trafigura.
September 21, 2024 and bear interest at a fixed rate of 6.50% and a yield of
6.50% per year. Interest on the Notes due 2024 is payable semi-annually in
Cash flows used in investing activities
arrears on March 21 and September 21 of each year.
For the year ended December 31, 2017, cash used in investing activities was
US$105.6 million, a 169% increase from US$39.3 million for the year ended
Ranking
December 31, 2016. This increase was related to higher capital expenditures
The Notes due 2024 constitute senior unsubordinated obligations of GeoPark
in Colombia, Chile, Argentina and Peru in 2017 as compared to 2016.
Limited, secured by a first lien on the Collateral (as described below). The Notes
due 2024 rank equally in right of payment with all existing and future senior
For the year ended December 31, 2016, cash used in investing activities was
obligations of GeoPark Limited (except those obligations preferred by operation
US$39.3 million, a 20% decrease from US$48.8 million for the year ended
of Bermuda law, including without limitation labor and tax claims); rank senior
December 31, 2015. This decrease was related to lower capital expenditures
to all unsecured debt of GeoPark Limited to the extent of the value of the
in Colombia, Chile and Brazil in 2016 as compared to 2015, despite having
Collateral; rank senior in right of payment to all existing and future subordinated
similar activity levels.
indebtedness of GeoPark Limited; and rank effectively junior to any future
secured obligations of GeoPark Limited and its subsidiaries with a security
Cash flows from financing activities
interest on assets not constituting Collateral, in each case, to the extent of the
Cash from financing activities was US$24.0 million for the year ended
value of the collateral securing such obligations.
December 31, 2017, compared to US$51.1 million used in financing
activities for the year ended December 31, 2016. This change was
Collateral
principally related to net proceeds from the issuance of 2024 Notes of
The notes are secured by a first-priority perfected security interest in certain
US$418.3 million offset by principal paid of US$355.0 million related to the
collateral (the “Collateral”), which consists of 80% of the equity interests of
payment of 2020 Notes and the prepayment of the Itaú loan.
each of GeoPark Chile and GeoPark Colombia.
Cash used in financing activities was US$51.1 million for the year ended
Optional redemption
December 31, 2016, compared to US$18.0 million for the year ended
We may, at our option, redeem all or part of the Notes due 2024, at the
December 31, 2015. This change was principally the result of principal
redemption prices, expressed as percentages of principal amount, set forth
payments related to Itaú loan and dividends distribution to non-controlling
below, plus accrued and unpaid interest thereon (including additional
interest.
amounts), if any, to the applicable redemption date, if redeemed during the
12-month period beginning on September 21 of the years indicated below:
GeoPark 123
Year
2021
2022
2023 and after
Change of control
Percentage
Events of default under the indenture governing the Notes due 2024 include:
103.250%
the nonpayment of principal when due; default in the payment of interest,
101.625%
which continues for a period of 30 days; failure to make an offer to purchase
100.000%
and thereafter accept tendered notes following the occurrence of a change
of control or as required by certain covenants in the indenture governing
the Notes due 2024; the notes, or the security documents in relation thereto
Upon the occurrence of certain events constituting a change of control, we
that continues for a period of 60 consecutive days after written notice; cross
are required to make an offer to repurchase all outstanding Notes due 2024,
payment default relating to debt with a principal amount of US$30.0 million
at a purchase price equal to 101% of the principal amount thereof plus any
or more, and cross-acceleration default following a judgment for US$30.0
accrued and unpaid interest (including any additional amounts payable in
million or more; bankruptcy and insolvency events; invalidity or denial or
respect thereof ) thereon to the date of purchase. If holders of not less than
disaffirmation of a guarantee of the notes; and failure to maintain a perfected
90% in aggregate principal amount of the outstanding Notes due 2024 validly
security interest in any collateral having a fair market value in excess of
tender and do not withdraw such notes and we repurchase all such notes,
US$15.0 million, among others. The occurrence of an event of default would
we may redeem the Notes due 2024 that remain outstanding following such
permit or require the principal of and accrued interest on the Notes due 2024
purchase at a price in cash equal to 101% of the principal amount thereof plus
to become or to be declared due and payable.
accrued and unpaid interest to but excluding the date of such redemption.
Banco de Chile
Covenants
During December 2015, we entered into a loan agreement with Banco de
The Notes due 2024 contain customary covenants, which include, among
Chile for US$7.0 million to finance the start-up of the new Ache gas field in
others, limitations on the incurrence of debt and disqualified or preferred stock,
the Fell Block. The interest rate applicable to this loan is LIBOR plus 2.35% per
restricted payments (including restrictions on our ability to pay dividends),
year. The interest and the principal have been paid on a monthly basis with a
incurrence of liens, guarantees of additional indebtedness, the ability of certain
6-month grace period and final maturity on December 2017.
subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging
in certain businesses and merger or consolidation with or into another
BCI Loan
company.
During February 2016, we executed a loan agreement with Banco de Crédito e
Inversiones (BCI) to finance the acquisition of vehicles for our Chilean operations.
In the event the Notes due 2024 receive investment-grade ratings from at least
The interest rate applicable to this loan is 4.14% per annum. The interest and the
two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch,
principal will be paid on monthly basis, with final maturity on February 2019.
and no default has occurred or is continuing under the indenture governing
the Notes due 2020, certain of these restrictions, including, among others, the
LGI Line of Credit
limitations on incurrence of debt and disqualified or preferred stock, restricted
As of December 31, 2017, the aggregate outstanding amount under the LGI Line
payments (including restrictions on our ability to pay dividends), the ability of
of Credit was US$31.2 million. This corresponds to advanced cash call payments
certain subsidiaries to pay dividends, asset sales and certain transactions with
granted by LGI to GeoPark Chile for financing Chilean operations in our Tierra
affiliates will no longer be applicable.
del Fuego blocks. The maturity of this balances is July 2020 and the applicable
The indenture governing our Notes due 2024 includes incurrence test
covenants that provide, among other things, that, the net debt to EBITDA ratio
See “Item 4. Information on the Company—B. Business Overview—Significant
interest rate is 8% per year.
should not exceed (i) 3.50 until September 21, 2019, (ii) 3.25 from September
Agreements—Agreements with LGI.”
21, 2019 to September 21, 2021, and (iii) 3.00 thereafter until maturity, and the
EBITDA to interest ratio should exceed (i) 2.00 until September 21, 2019, (ii) 2.25
Rio das Contas Credit Facility
from September 21, 2019 to September 21, 2021 and (iii) 2.50 thereafter until
We financed our Rio das Contas acquisition in part through our Brazilian
maturity. Failure to comply with the incurrence test covenants does not trigger
subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas
an event of default. However, this situation may limit our capacity to incur
Credit Facility”) with Itaú BBA International plc, which was secured by the
additional indebtedness, as specified in the indenture governing the Notes due
benefits GeoPark receives under the Purchase and Sale Agreement for Natural
2024, other than certain categories of permitted debt. We must test incurrence
Gas with Petrobras. The loan was fully repaid in September 2017.
covenants before incurring additional debt or performing certain corporate
actions including but not limited to making dividend payments, restricted
Other Agreements
payments and others (in each case with certain specific exceptions).
In December 2015, we entered into an offtake and prepayment agreement with
Events of default
124 GeoPark 20-F
Trafigura under which we sell and deliver a portion of our Colombian crude
oil production. Pricing will be determined by future spot market prices, net of
transportation costs. The agreement also provides us with prepayment of up
to US$100 million from Trafigura. Funds committed will be made available to
us upon request and will be repaid by us on a monthly basis through future oil
deliveries over the period of the contract, which is 2.5 years, including a 6-month
grace period. According to the terms of the prepayment agreement, we are
required to pay interest of LIBOR plus 5% per year on outstanding amounts. In
addition, under the prepayment agreement, we are required to maintain certain
coverage ratios linking: (i) future payments to the value of estimated future
oil deliveries (net of transportation discounts) during the term of the offtake
agreement and (ii) collections to payments within specified periods, with the
possibility of delivering additional volumes to meet such ratios in the upcoming
3-month period. As of March 31, 2018, outstanding amounts related to the
prepayment agreement amount to US$7.5 million.
C. Research and development, patents and licenses, etc.
See “Item 4. Information on the Company——B. Business Overview” and “Item 4.
Information on the Company—B. Business Overview—Title to Properties.”
D. Trend information
For a discussion of Trend information, see “—A. Operating Results—Factors
affecting our results of operations” and “Item 4. Information on the Company
–B. Business Overview—2018 Strategy and Outlook.”
E. Off-balance sheet arrangements
We did not have any off-balance sheet arrangements as of December 31, 2017
or as of December 31, 2016.
F. Tabular disclosure of contractual obligations
In accordance with the terms of our concessions, we are required to pay
royalties in connection with our crude oil and natural gas production. See
Note 32(a) to our Consolidated Financial Statements.
GeoPark 125
Directors, senior management and employees
The table below sets forth our committed cash payment obligations as of
December 31, 2017.
Debt obligations(1)
Operating lease obligations(2)
Pending investment commitments(3)
Asset retirement obligations
Total contractual obligations
Total
618,455
40,750
53,791
38,075
751,071
Less than one year
(in thousands of US$)
Three to five years
More than five years
One to three years
27,693
32,180
31,338
—
91,211
55,262
5,777
22,453
—
83,492
55,250
2,793
—
—
58,043
480,250
—
—
38,075
518,325
(1) Refers to principal and interest undiscounted cash flows. Interest payment
breakdown included in Debt Obligations is as follows (i) less than one year:
US$27.7 million; one to three years: US$55.3 million and three to five years:
US$55.3 million. At December 31, 2017, outstanding long-term borrowings
were issued at fixed rates. See Note 3: “Interest rate risk” to our Consolidated
Financial Statements.
(2) Reflects the future aggregate minimum lease payments under non-
cancellable operating lease agreements.
(3) Includes capital commitments in Isla Norte, Campanario and Flamenco
Blocks in Chile, rounds 11, 12 and 13 concessions in Brazil, three blocks
in Argentina and the Llanos 32, VIM-3, and Llanos 34 Blocks in Colombia.
See “Item 4. Information on the Company—B. Business Overview—Our
operations” and Note 32(b) to our Consolidated Financial Statements.
G. Safe harbor
See “Forward-Looking Statements.”
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A. Directors and senior management
Board of directors
Our board of directors is currently composed of seven members. At every
annual general meeting, one-third of the Directors retire from office. Our
Directors can 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 Directors whose term has expired may offer themselves for
re-election at each election of Directors. The term for the current Directors
expires on the date of our next annual shareholders’ meeting, to be held in
2018.
The current members of the board of directors were appointed at our annual
general meeting held on July 19, 2017. Two previously elected members, Mr.
Peter Ryalls and Mr. Michael D. Dingman, passed away following the 2017
annual general meeting, generating two vacancies on our board of directors.
The table below sets forth certain information concerning our current board of
directors. All ages are as of March 31, 2018.
126 GeoPark 20-F
Name
Gerald E. O’Shaughnessy
James F. Park
Carlos A. Gulisano (3)
Juan Cristóbal Pavez (1)(2)
Robert Bedingfield (1)(2)
Pedro E. Aylwin Chiorrini
Jamie B. Coulter (2)
Position
Chairman and Director
Chief Executive Officer, Deputy Chairman and Director
Director
Director
Director
Director, Director of Legal and Governance, Corporate Secretary
Director
Age
At the Company since
69
62
67
47
69
58
77
2002
2002
2010
2008
2015
2003
2017
(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.
geophysics from the University of California at Berkeley and previously worked
as a research scientist in earthquake and tectonic at the University of Texas.
In 1978, Jim helped pioneer the development of commercial oil and gas
production in Central America with Basic Resources, an oil and gas exploration
Biographical information of the current members of our Board of Directors is
company, in Guatemala. He remained a member of the board of directors of
set forth below. Unless otherwise indicated, the current business addresses for
Basic Resources International Limited until the company was sold in 1997. Mr.
our directors is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile.
Park is also a member of the board of directors of Energy Holdings and has
Gerald E. O’Shaughnessy has been our Chairman and a member of our
Yemen and China. Mr. Park is a member of the AAPG and SPE and has lived in
also been involved in oil and gas projects in California, Louisiana, Argentina,
board of directors since he co-founded the company in 2002. Following his
Latin America since 2002.
graduation from the University of Notre Dame with degrees in government
(1970) and law (1973), Mr. O’Shaughnessy was engaged in the practice of
Carlos Gulisano has been a member of our board of directors since June
law in Minnesota. Mr. O’Shaughnessy has been active in the oil and gas
2010. Dr. Gulisano holds a bachelor’s degree in geology, a post-graduate
business over his entire business career, starting in 1976 with Lario Oil and
degree in petroleum engineering and a PhD in geology from the University
Gas Company, where he served as Senior Vice President and General Counsel.
of Buenos Aires and has authored or co-authored over 40 technical papers.
He later formed The Globe Resources Group, a private venture firm whose
He is a former adjunct professor at the Universidad del Sur, a former thesis
subsidiaries provided seismic acquisition and processing, well rehabilitation
director at the University of La Plata, and a former scholarship director at
services, sophisticated logistical operations and submersible pump works
CONICET, the national technology research council, in Argentina. Dr. Gulisano
for Lukoil and other companies active in Russia during the 1990s. Mr.
is a respected leader in the fields of petroleum geology and geophysics in
O’Shaughnessy is also founder and owner of BOE Midstream, LLC, which owns
South America and has over 40 years of successful exploration, development
and operates the Bakken Oil Express, a crude by rail transloading and storage
and management experience in the oil and gas industry. In addition to
terminal in North Dakota, serving oil producers and marketing companies in
serving as an advisor to GeoPark since 2002 and as Managing Director from
the Bakken Shale Oil play. Over the past 25 years, Mr. O’Shaughnessy has also
February 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera
founded and operated companies engaged in banking, wealth management
Argentina San Jorge S.A. and Chevron San Jorge S.A. and has led teams
products and services, investment desktop software, computer and network
credited with significant oil and gas discoveries, including those in the
security, and green clean technology, as well as other venture investments, Mr.
Trapial field in Argentina. He has worked in Argentina, Bolivia, Peru, Ecuador,
O’Shaughnessy has also served on a number of non-profit boards of directors,
Colombia, Venezuela, Brazil, Chile and the United States. Mr. Gulisano is also an
including the Board of Economic Advisors to the Governor of Kansas, the I.A.
independent consultant on oil and gas exploration and production.
O’Shaughnessy Family Foundation, the Wichita Collegiate School, the Institute
for Humane Studies, The East West Institute and The Bill of Rights Institute, the
Juan Cristóbal Pavez has been a member of our board of directors since
Timothy P. O’Shaughnessy Foundation and is a member of the Intercontinental
August 2008. He holds a degree in commercial engineering from the Pontifical
Chapter of Young Presidents Organization and World Presidents’ Organization.
Catholic University of Chile and an MBA from the Massachusetts Institute of
Technology. He has worked as a research analyst at Grupo CB and later as a
James F. Park has served as our Chief Executive Officer and as a member of
portfolio analyst at Moneda Asset Management. In 1998, he joined Santana,
our board of directors since co-founding the Company in 2002. He has over
an investment company, as Chief Executive Officer, where he focused mainly
40 years of experience in all phases of the upstream oil and gas business, with
on investments in capital markets and real estate. While at Santana, he was
a strong background in the acquisition, implementation and management
appointed Chief Executive Officer of Laboratorios Andrómaco, one of Santana’s
of international projects and teams in North America, South America, Asia,
main assets. In 1999, Mr. Pavez co-founded Eventures, an internet company.
Europe and the Middle East. He received a bachelor of science degree in
Since 2001, he has served as Chief Executive Officer at Centinela, a company
GeoPark 127
with a diversified global portfolio of investments. Mr. Pavez is also a board
Counsel at BHP Billiton, Base Metals, where he was in charge of legal and
member of Grupo Security, Vida Security and Hidroelétrica Totoral. Over the
corporate governance matters on BHP Billiton’s projects, operations and
last few years he has been a board member of several companies, including
natural resource assets in South America, North America, Asia, Africa and
Quintec, Enaex, CTI and Frimetal.
Australia.
Robert Bedingfield has been a member of our board of directors since March
Jamie B. Coulter is a well-respected businessman, who has spearheaded
2015. He holds a degree in Accounting from the University of Maryland and
the growth of a variety of businesses in diverse sectors. He holds a business
is a Certified Public Accountant. Until his retirement in June 2013, he was one
degree from Wichita State University and is a graduate of the Stanford
of Ernst & Young’s most senior Global Lead Partners with more than 40 years
University Executive Program. Mr. Coulter currently serves as Managing
of experience, including 32 years as a partner in Ernst & Young’s accounting
Member of Coulter Enterprises LLC., a private investment firm. Mr. Coulter
and auditing practices, as well as serving on Ernst & Young’s Senior Governing
has been an investor in GeoPark since 2006. Mr. Coulter has more than 46
Board. He has extensive experience serving Fortune 500 companies; including
years of experience in the food retail and restaurant business, serving as Chief
acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin,
Executive Officer of Lone Star Steakhouse & Saloon and having developed
AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US
and operated Pizza Hut and Kentucky Fried Chicken restaurants. Mr. Coulter
Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times
is a former Restaurants & Institutions CEO of the year. Mr. Coulter has
an Executive Committee Member, and the Audit Committee Chair of the
operating and investment experience in the oil and gas business, including
University of Maryland at College Park Board of Trustees. Mr. Bedingfield
the founding of Sunburst Exploration, a US upstream oil and gas company
served on the National Executive Board (1995 to 2003) and National Advisory
that he built throughout the 1980s and sold in 1994. Mr. Coulter also has been
Council (since 2003) of the Boy Scouts of America. Since 2013, Mr. Bedingfield
an active participant as an investor in North American shale plays during the
has also served as Board Member and Chairman of the Audit Committee of
last ten years. Mr. Coulter currently serves as a Director of the Federal Law
NYSE-listed Science Applications International Corp (SAIC).
Enforcement Foundation and is a member of the Board of Trustees for HCA
Pedro E. Aylwin Chiorrini has served as a member of our board of directors
directors, including as a Director of Jimmy Johns LLC, Chairman of the Board
since July 2013 and as our Director of Legal and Governance since April 2011.
of the International Pizza Hut Franchise Holders’ Association, a member of the
From 2003 to 2006, Mr. Aylwin worked for us as an advisor on governance
Board of Advisors of The Wichita State University Center for Entrepreneurship
and legal matters. Mr. Aylwin holds a degree in law from the Universidad de
and a member of the Board of Trustees for the University of Kansas School of
Wesley Medical Center, and has previously served on a number of boards of
Chile and an LLM from the University of Notre Dame. Mr. Aylwin has extensive
Business, among others.
experience in the natural resources sector. Mr. Aylwin is also a partner at the
law firm Aylwin, Mendoza, Luksic, Valencia Abogados in Santiago, Chile, where
Executive officers
he represented mining, chemical and oil and gas companies in numerous
Our executive officers are responsible for the management and representation
transactions. From 2006 until 2011, he served as Lead Manager and General
of our company. The table below sets forth certain information concerning our
executive officers. All ages are as of March 31, 2018.
Name
James F. Park
Andrés Ocampo
Position
Chief Executive Officer and Director
Chief Financial Officer
Pedro E. Aylwin Chiorrini
Director, Director of Legal and Governance, and Corporate Secretary
Augusto Zubillaga
Alberto Matamoros
Barbara Bruce
Marcela Vaca
Carlos Murut
Salvador Minniti
Horacio Fontana
Agustina Wisky
Guillermo Portnoi
Stacy Steimel
128 GeoPark 20-F
Chief Operating Officer
Director for Argentina, Brazil and Chile
Director for Peru
Director for Colombia
Director of Development
Director of Exploration
Director of Drilling
Director of Business Management
Director of New Business
Director of Shareholder Value
Age
At the Company since
62
40
58
48
46
61
49
61
63
60
41
42
58
2002
2010
2003
2006
2014
2017
2012
2006
2007
2008
2002
2006
2017
Biographical information of the members of our executive officers is set
in IAE, from the Business School of Universidad Austral of Buenos Aires,
forth below. Unless otherwise indicated, the current business addresses
Argentina.
for our executive officers is Nuestra Señora de los Ángeles 179, Las Condes,
Santiago, Chile.
Barbara Bruce has been our Director for Peru since June 2017. Ms. Bruce
holds a degree in Geology from the Universidad Nacional de Ingeniería,
Andrés Ocampo has served as our Chief Financial Officer since November
Lima, Peru, a Master’s degree in Reservoirs from Colorado School of Mines,
2013. He previously served as our Director of Growth and Capital (from
USA and an MBA from Universidad Adolfo Ibañez, USA/Chile. Before joining
January 2011 through October 2013), and has been with our company since
GeoPark, she previously worked with Occidental Petroleum in different
July 2010. Mr. Ocampo graduated with a degree in Economics from the
international operations, including in the Caño Limon field in Colombia
Universidad Católica Argentina. He has more than 16 years of experience in
and the Dhurnal and Bhangali gas fields in Pakistan. Ms. Bruce later worked
business and finance. Before joining our company, Mr. Ocampo worked at
as deputy President of an offshore operation by Petrotech Peruana, joined
Citigroup and served as Vice President Oil & Gas and Soft Commodities at
Hunt Oil and as General Manager of Peru LNG, leading the construction and
Crédit Agricole Corporate & Investment Bank.
startup of operation of Peru´s first LNG plant and managed the exploration
venture of Hunt Oil in Madre de Dios, Peru.
Augusto Zubillaga has served as our Chief Operating Officer since May
2015. He previously served in other management positions throughout
Marcela Vaca has been our Director for Colombia since August 2012. Ms.
the Company including as Operations Director, Argentina Director and
Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá,
Production Director. He previously served as our Production Director. He is
Colombia, a Master’s Degree in commercial law from the same university
a petroleum engineer with more than 23 years of experience in production,
and an LLM from Georgetown University. She has served in the legal
engineering, well completions, corrosion control, reservoir management
departments of a number of companies in Colombia, including Empresa
and field development. He has a degree in petroleum engineering from
Colombiana de Carbon Ltda (which later merged with INGEOMINAS), and
the Instituto Tecnológico de Buenos Aires. Prior to joining our company,
from 2000 to 2003, she served as Legal and Administrative Manager at GHK
Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. and Chevron
Company Colombia. Prior to joining our company in 2012, Ms. Vaca served
San Jorge S.A. At Chevron San Jorge S.A., he led multi-disciplinary teams
for nine years as General Manager of the Hupecol Group where she was
focused on improving production, costs and safety, and was the leader of
responsible for supervising all areas of the company as well as managing
the Asset Development Team, which was responsible for creating the field
relationships with Ecopetrol, ANH, the Colombian Ministry of Mines and
development plan and estimating and auditing the oil and gas reserves of
Energy, the Colombian Ministry of Environment and other governmental
the Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron San
agencies. At the Hupecol Group, Ms. Vaca was also involved in the
Jorge S.A. team that was responsible for identifying business opportunities
structuring of the Hupecol Group’s asset development and sales strategy.
and working with the head office on the establishment of best business
practices. He has authored several industry papers, including papers
Carlos Murut has been our Director of Development since January 2012. He
on electrical submersible pump optimization, corrosion control, water
previously served as our Development Manager. Mr. Murut holds a master’s
handling and intelligent production systems.
degree in petroleum geology from the University of Buenos Aires where he
Alberto Matamoros has been our Director for Argentina, Brazil, Chile and
in field exploitation. He also completed a Business Management
Peru since March 2016 and Director for Chile since January 2015. He is an
Development Program at Austral University. Mr. Murut has over 40 years of
industrial engineer and has an MBA, with more than 20 years of experience
experience working for international and major oil companies, including
in the Oil & Gas industry. He started his career in the Argentinian oil
YPF S.A., Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San
also undertook postgraduate studies in reservoir engineering, specializing
company ASTRA, as a Production Engineer of La Ventana-Vizcacheras Block
Jorge S.A.
in the province of Mendoza (1997-2000). He then joined Chevron, where
he worked as a Production Engineer in El Trapial Block in the province of
Salvador Minniti has been our Director of Exploration since January 2012.
Neuquén for three years. Later, he became a Field Engineering Manager,
He previously served as our Exploration Manager. He holds a bachelor
also for three years, in Buenos Aires, and then moved to Kern County,
degree in geology from National University of La Plata and has a graduate
California, to lead the production team. His experience in Chevron enabled
degree from the Argentine Oil and Gas Institute in oil geology. Mr. Minniti
him to manage different technical and administrative teams, designing
has over 35 years of experience in oil exploration and has worked with YPF
and executing working plans focused in the optimization of resources. In
S.A., Petrolera Argentina San Jorge S.A. and Chevron Argentina.
2014, he joined GeoPark to be part of the Corporate Operation team before
being selected as the new Director for Chile. Matamoros holds a degree in
Horacio Fontana has been our Corporate Drilling Manager since March
Industrial Engineering from the Universidad Nacional del Sur and an MBA
2012. He previously served as our Engineer Manager. He holds a degree in
GeoPark 129
civil engineering from Rosario National University and is also a graduate
It is our current policy that executive directors enter into indefinite term
from the Argentine Oil and Gas Institute, National University of Buenos
contracts with the Company that may be terminated at any time by either
Aires, with a specialty in oilfield exploitation and an extensive background
party subject to certain notice requirements.
in drilling operations. He has recently taken part in a Management
Development Program at IAE Business School of Austral University. Mr.
Gerald E. O’Shaughnessy has entered into a service contract with the
Fontana has over 31 years of drilling experience in major Argentine
Company to act as Chairman at an annual salary of US$400,000. James F.
companies such as YPF S.A., Petrolera Argentina San Jorge and Chevron.
Park has entered into a service contract with the Company to act as Chief
Agustina Wisky has worked with our Company since it was founded in
equity awards described below under “Equity Incentive Compensation.” Our
November 2002, and has served as our Director of People since 2012 until
agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that
December 2016 and is currently our Director of Business Management. Mrs.
restrict them, for a period of 12 months following termination of employment,
Wisky is a public accountant, and also holds a degree in human resources
from soliciting senior employees of the Company and, for a period of six
from the Universidad Austral—IAE. She has 15 years of experience in the oil
months following a termination of employment, from competing with the
Executive Officer at an annual salary of US$800,000. They each also received
industry. Before joining our company, Mrs. Wisky worked at AES Gener and
Company.
PricewaterhouseCoopers.
Guillermo Portnoi has worked with our Company since June 2006 and has
2013, has entered into a service contract with the Company to act as Director
been our Director of Business Management since May 2015 until December
of Legal and Governance, and as such has decided to forego his director fees.
2016 and is currently our Director of New Business. Previously, he also
He instead received in 2017 a salary of US$0.3 million and bonus of US$0.1
served as our Director of Administration and Finance. Mr. Portnoi is a public
million for his services as a member of senior management.
accountant and holds an MBA from Universidad Austral—IAE. He has more
than 14 years of experience in the oil industry. Before joining our company,
The following chart summarizes payments made to our executive directors for
Pedro E. Aylwin Chiorrini, who was appointed as an executive director in July
Mr. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers,
the year ended December 31, 2017:
where he counted several major oil companies as his clients.
Stacy Steimel joined GeoPark in February 2017 as our Shareholder Value
Executive Directors’ Fees
Director. Mrs. Steimel has more than 20 years of experience in the financial
Gerald E. O’Shaughnessy
US$400,000
Cash payment
Bonus
—
sector as Fund Manager and subsequently as regional CEO for PineBridge
James F. Park
Investments, ex-AIG Investments in Latin America. Before AIG, Mrs. Steimel
Pedro E. Aylwin Chiorrini
US$800,000
US$800,000
—
—
held positions in the US Treasury Department and at the InterAmerican
Development Bank. She holds an MBA from the Pontificia Universidad
Bonus payments above were approved by the Compensation Committee on
Católica de Chile, an MA in Latin American Studies from the University of
March, 16 2017 and reflect awards for previous years’ performance including
Texas at Austin and a BA from the College of William and Mary.
the discretionary bonus payments made based on our performance in 2016.
B. Compensation
Executive compensation
Non-Executive Director Contracts
The current annual fees paid to our non-executive Directors correspond to
US$80,000 to be settled in cash and US$100,000 to be settled in stock, paid
For the year ended December 31, 2017, we accrued or paid approximately
quarterly in equal installments. In the event that a non-executive Director
US$4.5 million, in the aggregate, to the members of our board of directors
serves as Chairman of any Board Committees, an additional annual fee
(including our executive directors) for their services in all capacities. During
of US$20,000 applies. A Director who serves as a member of any Board
this same period, we accrued or paid approximately US$7.8 million, in the
Committees receives an annual fee of US$10,000. Total payment due shall
aggregate, to the members of our senior management (excluding our
be calculated on an aggregate basis for Directors serving in more than one
executive directors) for their services in all capacities. An amount of US$0.9
Committee. The Chairman fee is not added to the member’s fee while serving
million corresponds to the accrual or payment for discretionary bonus
for the same Committee. Payments of Chairmen and Committee members’
cash payments granted to the Company’s executive directors based on the
fees are made quarterly in arrears and settled in cash only.
Company’s performance in 2017. Gerald E. O’Shaughnessy, James F. Park and
Pedro E. Aylwin Chiorrini are our executive directors.
The following chart summarizes payments made to our non-executive
directors for the year ended December 31, 2017.
Executive Director Contracts
130 GeoPark 20-F
Number of underlying
common shares
Non-Executive Director
Juan Cristóbal Pavez (2)
Carlos Gulisano (3)
Robert Bedingfield (4)
Peter Ryalls(5)
Michael D. Dingman(5)
Jamie B. Coulter
Non-Executive Directors’
Fees in US$
110,000
110,000
102,500
115,000
46,667
50,000
Fees paid
in Common Shares (1)
15,408
15,408
15,408
9,388
8,853
6,020
outstanding
976,211(1)
817,600(1)
478,000(1)
720,000(2)
379,500
490,000
1,619,105 (3)
Grant date
12/15/2008
12/15/2010
12/15/2011
11/23/2012
12/15/2012
12/31/2014
06/30/2016
Vesting date
Expiration date
12/15/2012
12/15/2014
12/15/2015
11/23/2015
12/15/2016
12/31/2017
06/30/2019
12/15/2018
12/15/2020
12/15/2021
11/23/2016
12/15/2022
12/31/2022
06/30/2026
(1) The numbers in this column are equal to 70,485 Common Shares (which
amount equals to US$454,058).
(2) Compensation Committee Chairman and Member of Audit Committee.
(3) Technical Committee Chairman and Member of Compensation Committee.
(4) Audit Committee Chairman and Member of Nomination Committee.
(5) Mr. Peter Ryalls and Mr. Michael D. Dingman passed away following the 2017
annual general meeting.
(1) Pedro E. Aylwin Chiorrini holds 40,000 shares of the 2008 award, 25,000
shares of the 2010 award and 12,000 shares of the 2011 award.
(2) James F. Park received 450,000 shares of such awards, and Gerald E.
O’Shaughnessy received 270,000 shares of such awards.
(3) Vesting of these common share awards was subject to the achievement
of certain minimum financial and operational targets during a performance
period that runs through 2016 to 2018. If such conditions are not achieved as
of the vesting date, only the equivalent of one monthly salary will be issued in
Pension and retirement benefits
shares.
We do not maintain any defined benefit pension plans or any other retirement
programs for our employees or directors.
Equity Incentive Compensation
Our executive directors, senior management and employees who have
received option awards or common share awards under the Stock Awards
Plan authorize the Company to deposit any common shares they have
received under this plan in our Employee Benefit Trust (“EBT”). The EBT is
Performance-Based Employee Long-Term Incentive Program
held to facilitate holdings and dispositions of those common shares by the
participants thereof. Under the terms of the EBT, each participant is entitled to
In November 2007, our shareholders voted to authorize the board of directors
receive any dividends we may pay which correspond to their common shares
to use up to a maximum of 12% of our issued share capital for the purposes
held by the trust, according to instructions sent by the Company to the trust
of granting equity awards to our employees and other service providers. The
administrator. The trust provides that Mr. James F. Park is entitled to vote all
shareholders also authorized the board of directors to adopt programs for this
the common shares held in the trust.
purpose and to determine specific conditions and broadly defined guidelines
for such programs.
Stock Awards Plan
Value Creation Plan
On December 10, 2015, the Board of Directors approved a renewal of the
VCP for a new period of three years, with new rewards granted on January 1,
The purpose of the Stock Awards Plan is to align the interests of our
2016. Under the current VCP, if as of December 31, 2018, our share price has
management, employees and key advisors with those of shareholders. Under
increased by 12% per year according to the plan conditions, VCP participants
the Stock Awards Plan, the board of directors, or its designee, may award
(key management) will receive awards with an aggregate value equal to 10%
options or stock awards. An option confers the right to acquire a specified
of the excess above the market capitalization threshold generated by this
number of common shares of the Company at an exercise price equal to the
share price (assuming that the share capital of the Company had remained
par value of the common shares subject to such an option. A performance
at the same level as applicable at the time of establishment of the VCP:
share confers a conditional right to acquire a specified number of common
59,535,614 shares). The awards will vest and be paid in common shares 50%
shares for zero or nominal consideration, subject to the achievement of
on December 31, 2018, and the remaining 50% on December 31, 2019. As in
performance conditions and other vesting terms.
the previous VCP, the total number of common shares granted pursuant to
this plan shall not exceed 5% of the issued share capital of the Company. For
On December 17, 2014, we registered 3,435,600 shares with the U.S. SEC for
further details see Note 30 to our Consolidated Financial Statements.
shares to be issued under the Stock Awards Plan. The following table sets forth
the common share awards granted to our executive directors, management
Non-Executive Director Plan
and employees under the Stock Awards Plan commencing in 2008 through
In August 2014, our Board of Directors adopted the Non-Executive Director
March 31, 2018.
Plan in order to grant shares to non-executive directors as part of their
compensation program for serving as directors, which was amended and
restated in October 2016. In accordance with the resolutions adopted by our
board of directors on May 20, 2014, our non-executive directors are paid their
quarterly fees in the form of equity awards granted under the Non-Executive
Director Plan. Under the Non-Executive Director Plan, the compensation
GeoPark 131
committee may award common shares, restricted share units and other share-
Audit Committee
based awards that may be denominated or payable in common shares or
The Audit Committee is composed of three directors. The current members of
factors that influence the value of common shares. The maximum number of
the Audit Committee are Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield
common shares available for issuance under the Non-Executive Director Plan
(who currently serves as Chairman of the committee). We have determined
is 1,000,000 common shares.
that Mr. Juan Cristóbal Pavez and Robert Bedingfield are independent, as such
term is defined under SEC rules applicable to foreign private issuers. Currently,
Potential dilution resulting from Equity Incentive Compensation Plans
there is a vacancy created by the passing of Mr. Peter Ryalls on July 25, 2017.
The percentage of total share capital that could be awarded to our directors,
management and key employees under the Stock Awards Plan described
The Audit Committee’s responsibilities include: (a) approving our financial
above would represent approximately 14% of our issued common shares
statements; (b) reviewing financial statements and formal announcements
as of December 31, 2017. In accordance with existing equity compensation
relating to our performance; (c) assessing the independence, objectivity
plans as of the date of this annual report, there are approximately 4.6 million
and effectiveness of our external auditors; (d) making recommendations for
outstanding shares that have been awarded but which have not yet vested,
the appointment, re-appointment and removal of our external auditors and
representing approximately 7.5% of the total issued share capital as of
approving their remuneration and terms of engagement; (e) implementing
December 31, 2017.
C. Board practices
Overview
and monitoring policy on the engagement of external auditors supplying
non-audit services to us; (f ) obtaining, at our expense, outside legal or other
professional advice on any matters within its terms of reference and securing
the attendance at its meetings of outsiders with relevant experience and
expertise if it considers it necessary; and (g) reviewing our arrangements
Our Board of Directors is responsible for establishing our listed company
for our employees to raise concerns about possible wrongdoing in financial
goals, ensuring that the necessary resources are in place to achieve
reporting or other matters and the procedures for handling such allegations,
these goals and reviewing our management and financial performance.
and ensuring that these arrangements allow proportionate and independent
Our board of directors directs and monitors the company in accordance
investigation of such matters and appropriate follow-up action.
with a framework of controls, which enable risks to be assessed and
managed through clear procedures, lines of responsibility and delegated
Compensation Committee
authority. Our board of directors also has responsibility for establishing
The Compensation Committee is composed of three directors. The current
our core values and standards of business conduct and for ensuring that
members of the compensation committee are Mr. Juan Cristóbal Pavez
these, together with our obligations to our shareholders, are understood
(who serves as Chairman of the committee) and Mr. Carlos Gulisano.
throughout the company.
Currently there is one vacancy created by the passing of Mr. Peter Ryalls on
Board composition
July 25, 2017.
Our bye-laws and board resolutions provide that the board of directors consist
The Compensation Committee meets at least twice a year, and its specific
of a minimum of three and a maximum of nine members. All of our directors
responsibilities include: (a) reviewing and recommending to the board
were elected at our annual shareholders’ meeting held on July 19, 2017. Their
of directors the remuneration policy for the Chief Executive Officer,
term expires on the date of our next annual shareholders’ meeting, to be held
the Chairman, our executive directors and other members of executive
in 2018. The board of directors meets at least on a quarterly basis.
management; (b) reviewing the performance of our executive directors
Committees of our board of directors
and members of executive management; and (c) reviewing all incentive
compensation plans, equity-based plans, and all modifications to such
Our board of directors has established an Audit Committee, a Compensation
plans as well as administering and granting awards under all such plans and
Committee, a Nomination Committee, a Technical Committee and a Disclosure
approving plan payouts; and (d) reviewing and making recommendations
Committee. The composition and responsibilities of each committee are
to the Board with respect to the adoption or modification of executive
described below. Members serve on the Audit Committee for a period of three
officer and director share ownership guidelines and monitor compliance
years. For the Nomination Committee, members serve for a period of one
with any adopted share ownership guidelines.
year. For the Compensation Committee, members serve for the same period
as their board term. For the Technical Committee and Disclosures Committee,
Nomination Committee
members serve on these committees until their resignation or until otherwise
The Nomination Committee is composed of four directors. The members of
determined by our board of directors. In the future, our board of directors may
the Nomination Committee are Mr. Gerald E. O’Shaughnessy, Mr. James F.
establish other committees to assist with its responsibilities.
Park, Mr. Robert Bedingfield and Mr. Pedro E. Aylwin Chiorrini (who serves as
Chairman of the committee).
132 GeoPark 20-F
The Nomination Committee meets at least twice a year and its responsibilities
The following table sets forth a breakdown of our employees by geographic
include: (a) reviewing the structure, size and composition of the board of
segment for the periods indicated.
directors and making recommendations to the board of directors in respect of
any required changes; (b) identifying, nominating and submitting for approval
by the board of directors candidates to fill vacancies on the board of directors
as and when they arise; (c) making recommendations to the board of directors
Colombia
with respect to the membership of the Audit Committee and Compensation
Committee in consultation with the chairman of each committee, and with
Chile
Brazil
respect to the appointment of any director or executive officer or other officer
Argentina
other than the position of the Chairman and Chief Executive Officer and (d)
succession planning for directors and senior executives.
Peru
Total
Year ended December 31,
2017
180
102
12
92
19
405
2016
146
102
10
77
10
345
2015
133
106
12
90
11
352
Technical Committee
From time to time, we also utilize the services of independent contractors
The Technical Committee is composed of three directors along with the
to perform various field and other services as needed. As of December 31,
Chief Operating Officer. The members of the Technical Committee are Mr.
2017, 37 of our employees were represented by labor unions or covered
Carlos Gulisano (who serves as Chairman of the committee), Mr. Gerald
by collective bargaining agreements. We believe that relations with our
O´Shaughnessy, Mr. James F. Park and Mr. Augusto Zubillaga.
employees are satisfactory.
The Technical Committee’s responsibilities include: (a) overseeing the
E. Share ownership
technical studies and evaluations of the Company’s properties and proposals
As of March 15, 2018, members of our board of directors and our senior
to acquire new properties and/or relinquish existing ones as well as reviewing
management held as a group 20,881,731 of our common shares and 34.5% of
project plans; (b) reviewing the Annual Reserve Report, the Company’s
our outstanding share capital.
environmental programs and their effectiveness and the Company’s health
and safety program and its effectiveness; and (c) providing a forum for ideas
The following table shows the share ownership of each member of our board
and solutions for the key technical people within the Company.
of directors and senior management as of March 15, 2018.
Common
Percentage of outstanding
Disclosure Committee
The Disclosure Committee is composed of Mr. James F. Park, Mr. Andrés
Ocampo, and certain other officers or managers per request.
The Disclosure Committee’s responsibilities include (a) review and approval of
Shareholder
James F. Park(1)
Gerald E. O’Shaughnessy(2)
Juan Cristóbal Pavez(3)
Carlos Gulisano
filings with the SEC and press releases, (b) review of presentations to analysts,
Pedro E. Aylwin Chiorrini
investors and rating agencies and (c) establishment of disclosure controls and
Robert Bedingfield
procedures.
Liability insurance
Jamie B. Coulter
Augusto Zubillaga
Alberto Matamoros
We maintain liability insurance coverage for all of our directors and officers,
Marcela Vaca
the level of which is reviewed annually.
D. Employees
Barbara Bruce
Carlos Murut
Salvador Minniti
Stacy Steimel
As of December 31, 2017, we had 405 employees, representing an increase of
Horacio Fontana
17% from December 31, 2016.
Agustina Wisky
Guillermo Portnoi
Andrés Ocampo
shares
7,891,269
7,213,316
2,964,162
193,327
220,859
82,495
1,517,587
*
*
*
*
*
*
*
*
*
*
*
Sub-total senior management
ownership of less than 1%
Total
798,716
20,881,731
common shares
13.0%
11.9%
4.9%
0.3%
0.4%
0.1%
2.5%
*
*
*
*
*
*
*
*
*
*
*
1.3%
34.5%
GeoPark 133
Major shareholders and related party transactions
* Indicates ownership of less than 1% of outstanding common shares.
the table is based solely on the disclosure set forth in Mr. O’Shaughnessy’s most
(1) Held by Energy Holdings, LLC, which is controlled by James F. Park, a
member of our Board of Directors. The number of common shares held by
recent Schedule 13G filed with the SEC on February 13, 2018.
(3) Held directly and indirectly through Manchester Financial Group, L.P.,
Manchester Financial Group, Inc., Douglas F. Manchester and Papa Doug Trust
Mr. Park does not reflect the 1,533,927 common shares held as of March 15,
u/t/d/ January 11, 2010. This information is based solely on the disclosure set
2018 in the employee benefit trust described under “Item 6. Directors,
forth in Manchester Financial Group, L.P.’s most recent Schedule 13G filed with
Senior Management and Employees—B. Compensation— Stock Awards
Plan.” 1,073,201 of these common shares have been pledged pursuant to
lending arrangements. The information set forth above is based solely on
the SEC on February 8, 2017.
(4) IFC Equity Investments voting decisions are made through a portfolio
management process which involves consultation from investment officers,
the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the
credit officers, managers and legal staff. This information is based solely on the
SEC on February 13, 2018.
(2) Held directly and indirectly through GP Investments LLP, GPK Holdings
LLC and other investment vehicles. 6,975,957 of these common shares have
disclosure set forth in the IFC’s most recent Schedule 13G/A filed with the SEC on
March 23, 2018.
(5) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal
Pavez. The common shares reflected as being held by Mr. Pavez include 86,358
been pledged pursuant to lending arrangements. The information set forth
common shares held by him personally.
above is based solely on the disclosure set forth in Mr. O’Shaughnessy’s
most recent Schedule 13G filed with the SEC on February 13, 2018.
Principal shareholders do not have any different or special voting rights in
comparison to any other common shareholder.
(3) Held through Socoservin Overseas Ltd, which is controlled by Juan
Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez
According to our transfer agent, as of February 28, 2018, we had 22 registered
include 86,358 common shares held by him personally.
shareholders, out of which 6 are registered as U.S. shareholders. Since some
of the shares are held by nominees, the number of shareholders may not be
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
representative of the number of beneficial owners.
A. Major shareholders
B. Related party transactions
The following table presents the beneficial ownership of our common shares
We have entered into the following transactions with related parties:
as of March 15, 2018:
Common
Percentage of outstanding
In 2010, we formed a strategic partnership with LGI to acquire and develop
LGI Chile Shareholders’ Agreements
Shareholder
James F. Park(1)
Gerald E. O’Shaughnessy(2)
Manchester Financial Group, L.P.(3)
IFC Equity Investments(4)
Juan Cristóbal Pavez(5)
Other shareholders
Total
shares
7,891,269
7,193,316
5,103,439
2,998,633
2,964,162
34,439,653
60,606,787
common shares
jointly upstream oil and gas projects in Latin America. In 2011, LGI acquired
13.0%
11.9%
8.4%
4.9%
4.9%
a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark
TdF, for a total consideration of US$148.0 million, plus additional equity
funding of US$18.0 million through 2014. On May 20, 2011, in connection
with LGI’s investment in GeoPark Chile, we and LGI entered into the LGI Chile
Shareholders’ Agreements, setting forth our and LGI’s respective rights and
56.8%
obligations in connection with LGI’s investment in our Chilean oil and gas
100.0%
business. Specifically, the LGI Chile Shareholders’ Agreements provide that
the boards of each of GeoPark Chile and GeoPark TdF will consist of four
(1) Held by Energy Holdings, LLC, which is controlled by James F. Park, a member of
our Board of Directors. The number of common shares held by Mr. Park does not
directors; as long as LGI holds at least 5% of the voting shares of GeoPark Chile
or GeoPark TdF, as applicable, LGI has the right to elect one director and such
reflect the 1,533,927 common shares held as of March 15, 2018 in the employee
director’s alternate, while the remaining directors, and alternates, are elected
benefit trust described under “Item 6. Directors, Senior Management and
by us. Additionally, the agreements require the consent of LGI or its appointed
Employees—B. Compensation— Stock Awards Plan.” 1,073,201 of these common
director in order for GeoPark Chile or GeoPark TdF, as applicable, to be able
shares have been pledged pursuant to lending arrangements. The information
to take certain actions, including, among others: making any decision to
set forth above and listed in the table is based solely on the disclosure set forth in
terminate or permanently or indefinitely suspend operations in or surrender
Mr. Park’s most recent Schedule 13G filed with the SEC on February 13, 2018.
(2) Held directly and indirectly through GP Investments LLP, GPK Holdings LLC and
other investment vehicles. 6,975,957 of these common shares have been pledged
our blocks in Chile (other than as required under the terms of the relevant
CEOP for such blocks); selling our blocks in Chile to our affiliates; making any
change to the dividend, voting or other rights that would give preference to
pursuant to lending arrangements. The information set forth above and listed in
or discriminate against the shareholders of these companies; entering into
certain related party transactions; and creating a security interest over our
134 GeoPark 20-F
blocks in Chile (other than in connection with a financing that benefits our
the other shareholder before selling those shares to a third party; and (ii) any
Chilean subsidiaries). The LGI Chile Shareholders’ Agreements also provide
sale to a third party is subject to tag-along and drag-along rights, and the
that: (i) if LGI or either Agencia or GeoPark Chile decides to sell its shares in
non-transferring shareholder has the right to object to a sale to the third-party
GeoPark Chile or GeoPark TdF, as applicable, the transferring shareholder
if it considers such third-party to be not of a good reputation or one of our
must make an offer to sell those shares to the other shareholder before selling
direct competitors. We and LGI also agreed to vote our common shares or
them to a third party; and (ii) any sale to a third party is subject to tag-along
otherwise cause GeoPark Colombia to declare dividends only after allowing
and drag-along rights, and the non-transferring shareholder has the right to
for retentions for approved work programs and budgets, capital adequacy and
object to a sale to the third-party if it considers such third-party to be not of
tied surplus requirements of GeoPark Colombia, working capital requirements,
a good reputation or one of our direct competitors. We and LGI also agreed
banking covenants associated with any loan entered into by GeoPark
to vote our common shares or otherwise cause GeoPark Chile or GeoPark TdF,
Colombia or our other Colombian subsidiaries and operational requirements.
as applicable, to declare dividends only after allowing for retentions to meet
anticipated future investments, costs and obligations. See “Item 4. Information
In addition, our agreement with LGI in Colombia allows us to earn back up
on the Company—B. Business Overview—Significant Agreements—
to 12% of our equity participation in GeoPark Colombia, following certain
Agreements with LGI—LGI Chile Shareholders’ Agreements.”
recovery factors of LGI `s initial investments as follows: (i) if the recovery
LGI Colombia Agreements
factor is between one and two times, our incremental equity share is 4%; if
the recovery factor is between two to three, three to four, four to five, and
On December 18, 2012, we, Agencia, GeoPark Colombia and LGI entered
above five, our incremental equity increases by an additional 2% each time,
into the LGI Colombia Shareholders’ Agreement and a subscription share
for up to a 12%, so that LGI participation could be reduced from current 20%
agreement, pursuant to which LGI acquired a 20% interest in GeoPark
to 8%. Recovery factor is measured considering realized dividends or other
Colombia SAS. Further, on January 8, 2014, following an internal corporate
distributions over the original investments.
reorganization of our Colombian operations, GeoPark Colombia Coöperatie
U.A. and GeoPark Latin America entered into a new members’ agreement
See “Item 4. Information on the Company—B. Business Overview—Significant
with LGI (the “LGI Colombia Members’ Agreement”), that sets out substantially
Agreements—Agreements with LGI—LGI Colombia Agreements.”
similar rights and obligations to the LGI Colombia Shareholders’ Agreement in
respect of our oil and gas business in Colombia. We refer to the LGI Colombia
IFC Subscription and Shareholders’ Agreement
Shareholders’ Agreement and the LGI Colombia Members’ Agreement
On February 7, 2006, in order to finance the exploration, development
collectively as the LGI Colombia Agreements. The LGI Colombia Members’
and exploitation of our blocks in Chile and Argentina and the acquisition
Agreements provide that the board of GeoPark Colombia Coöperatie U.A.
of additional exploration, development and exploitation blocks in Latin
will consist of four directors; as long as LGI holds at least 14% of GeoPark
America, we, IFC and Gerald E. O’Shaughnessy and James F. Park, as Lead
Colombia SAS, LGI has the right to elect one director and such director’s
Investors, entered into an agreement (the “IFC Subscription and Shareholders’
alternate, while the remaining directors, and alternates, are elected by us.
Agreement”), pursuant to which IFC agreed to subscribe and pay for 2,507,161
Additionally, the LGI Colombia Agreements require the consent of LGI or the
of our common shares, representing approximately 10.5% of our then-
LGI appointed director for GeoPark Colombia SAS to be able to take certain
outstanding common shares, at an aggregate subscription price of US$10.0
actions, including, among others: making any decision to terminate or
million (or approximately US$3.99 per common share).
permanently or indefinitely suspend operations in or surrender our blocks in
Colombia (other than as required under the terms of the relevant concessions
We agreed, for so long as IFC is a shareholder in the company, among
for such blocks); creating a security interest over our blocks in Colombia;
other things, to: ensure that our operations are in compliance with certain
approving of GeoPark Colombia SAS’ annual budget and work programs and
environmental and social guidelines; appoint and maintain a technically
the mechanisms for funding any such budget or program; entering into any
qualified individual to be responsible for the environmental and social
borrowings other than those provided in an approved budget or incurred in
management of our activities; maintain certain forms of insurance coverage,
the ordinary course of business to finance working capital needs; granting
including coverage for public liability and director’s and officer’s liability
any guarantee or indemnity to secure liabilities of parties other than those
reasonably acceptable to IFC, and in respect of certain of our operations;
of our Colombian subsidiaries; changing the dividend, voting or other rights
not undertake certain prohibited activities; and ensure that no prohibited
that would give preference to or discriminate against the shareholders of
payments are made by us or on our or the Lead Investors’ behalf, in respect of
GeoPark Colombia SAS; entering into certain related party transactions; and
our operations.
disposing of any material assets other than those provided for in an approved
budget and work program. The LGI Colombia Agreements also provide that:
We also agreed to provide to IFC, within 30 days of the end of the first half
(i) if either we or LGI decide to sell our respective shares in GeoPark Colombia
of the year, copies of our unaudited consolidated financial statements for
SAS, the transferring shareholder must make an offer to sell those shares to
the period (prepared under IFRS), a report on our capital expenditures for
GeoPark 135
the period, a comprehensive report on the progress of the exploration,
employment, commercial, environmental, safety and health matters. For
development and exploitation of our blocks in Latin America and a statement
example, from time to time, we receive notice of environmental, health and
of all related party transactions during the period, with a certification by a
safety violations. It is not presently possible to determine whether any such
company officer that these were on an arm’s-length basis; within 90 days
matters will have a material adverse effect on our consolidated financial
of the end of our fiscal year, copies of our audited consolidated financial
position and results of operations.
statements for the year (prepared under IFRS), a management letter from
our auditors in respect of our financial control procedures, accounting and
In Brazil, GeoPark Brasil is a party to a class action filed by the Federal
management information systems and any litigation, an annual monitoring
Prosecutor’s Office regarding a concession agreement of exploratory Block
report confirming compliance with national or local requirements and the
PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil
environmental and social requirements mandated by the agreement, a
and gas bidding round held in November 2013. The Brazilian Federal Court
report indicating any payments in the year to any governmental authority in
issued an injunction against the ANP and GeoPark Brasil in December 2013
connection with the documents governing our Chilean and Argentine blocks
that prohibited GeoPark Brasil’s execution of the concession agreement
and certificates of insurance, with a certificate of our insurer confirming that
until the ANP conducted studies on whether drilling for unconventional
effectiveness of our policies and payment of all applicable premiums; within
resources would contaminate the dams and aquifers in the region. On July
45 days before each fiscal year begins, a proposed annual business plan and
17, 2015, GeoPark Brasil, at the instruction of the ANP, signed the concession
budget for the upcoming year; within 3 days after its occurrence, notification
agreement, which included a clause prohibiting GeoPark Brasil from
of any incident that had or may reasonably be expected to have an adverse
conducting unconventional exploration activity in the area. Despite the
effect on the environment, health or safety; copies of notices, reports or other
clause containing the prohibition, the judge in the case concluded that the
communications between us and our board of directors or shareholders; and,
concession agreement should not be executed. Thus, GeoPark Brasil requested
within five days of receipt thereof, copies of any reports, correspondence,
that the ANP comply with the decision and annul the concession agreement,
documentation or notices from any third-party, governmental authority or
which the ANP´s Board did on October 9, 2015. The annulment reverted the
state-owned company that could reasonably be expected to materially impact
status of all parties to the status quo ante, which maintains GeoPark Brasil’s
our operations. Mr. O’Shaughnessy and Mr. Park have also agreed to procure
right to the block.
that shareholders holding 51% of our common shares cause us to comply with
the covenants above.
Dividends and dividend policy
Holders of common shares will be entitled to receive dividends, if any, paid on
Executive Directors’ Service Agreements
the common shares.
We have entered into service contracts with certain of our executive
directors. See “Item 6. Directors, Senior Management and Employees—B.
We have never declared or paid any cash dividends on our common shares.
Compensation—Executive compensation—Director Contracts.”
We intend to retain all of our future earnings, if any, generated by our
For further information relating to our related party transactions and balances
do not expect to pay cash dividends on our common shares in the foreseeable
outstanding as of December 31, 2017, 2016 and 2015, please see Note 33 to
future. Because we are a holding company with no direct operations, we will
operations for the development and growth of our business. Accordingly, we
our Consolidated Financial Statements.
C. Interests of Experts and Counsel
Not applicable.
only be able to pay dividends from our available cash on hand and any funds
we receive from our subsidiaries. The terms of our indebtedness may restrict
us from paying dividends. Mainly resulting from the impact of the decline
in oil prices, we have recorded accumulated losses amounting to US$283.9
million as of December 31, 2017, which further limits our ability to pay
ITEM 8. FINANCIAL INFORMATION
dividends in the foreseeable future.
A. Consolidated statements and other financial information
Under the Bermuda Companies Act, we may not declare or pay a dividend
Financial statements
if there are reasonable grounds for believing that we are, or would after the
payment be, unable to pay our liabilities as they become due or that the
See “Item 18. Financial Statements,” which contains our audited financial
realizable value of our assets would thereafter be less than our liabilities. We
statements prepared in accordance with IFRS.
do not presently have any reasonable grounds for believing that, if we were
Legal proceedings
to declare or pay a dividend on our common shares outstanding, we would
thereafter be unable to pay our liabilities as they became due or that the
From time to time, we may be subject to various lawsuits, claims and
realizable value of our assets would thereafter be less than our liabilities.
proceedings that arise in the normal course of business, including
Additionally, any decision to pay dividends in the future, and the amount
136 GeoPark 20-F
of any distributions, is at the discretion of our board of directors and our
shareholders, and will depend on many factors, such as our results of
operations, financial condition, cash requirements, prospects and other
factors. See “Item 3. Key Information—D. Risk factors—Risks related to our
High
Low
(US$ per share)
Common shares
Average daily
trading volume
(in shares)
common shares—We have never declared or paid, and do not intend to
Annual price history
pay in the foreseeable future, cash dividends on our common shares, and,
2014 (from February 7
consequently, your only opportunity to achieve a return on your investment
through December 31, 2014)
11.00
is if the price of our stock appreciates” and “—We are a holding company
dependent upon dividends from our subsidiaries, which may be limited by
law and by contract from making distributions to us, which would affect our
2015
2016
2017
financial condition, including the ability to pay dividends on the common
2018 (through April 6, 2018)
shares,” as well as “Item 10. Additional Information—B. Memorandum of
Quarterly price history
association and bye-laws.”
B. Significant changes
1st Quarter 2017
2nd Quarter 2017
3rd Quarter 2017
4th Quarter 2017
A discussion of the significant changes in our business can be found under
1st Quarter 2018
“Item 4. Information on the Company—B. Business Overview.”
2nd Quarter 2018
5.59
5.06
10.05
12.58
7.18
8.89
9.52
10.05
12.40
4.92
2.70
2.25
4.50
9.24
4.50
6.55
7.54
8.05
9.24
ITEM 9. THE OFFER AND LISTING
Monthly price history
(through April 6, 2018)
12.58
12.18
A. Offering and listing details
Not applicable.
B. Plan of distribution
Not applicable.
C. Markets
November 2017
December 2017
January 2018
February 2018
March 2018
April 2018
9.83
10.05
10.88
10.36
12.40
8.48
8.60
9.60
9.24
9.35
(through April 6, 2018)
12.58
12.18
On February 6, 2014 we completed our initial public offering and listed our
common shares on the NYSE.
Source: NYSE Connect
Our common shares have been listed on the NYSE under the symbol “GPRK”
D. Selling shareholders
since February 7, 2014. They were previously listed on the AIM under the
Not applicable.
symbol “GPK” until February 19, 2014, and, from 2009 to 2015 had been
admitted to trade on the Santiago Offshore Stock Exchange (Bolsa Offshore de
E. Dilution
la Bolsa de Comercio de Santiago).
Not applicable.
The table below presents, for the periods indicated, the annual, quarterly and
F. Expenses of the issue
monthly high and low closing prices (in US$) of our common shares on the
Not applicable.
NYSE.
47,795
23,838
103,283
142,158
162,292
149,187
202,151
115,768
101,643
153,916
264,481
142,290
72,795
125,886
108,468
223,067
264,481
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 137
General
preference on any outstanding preference shares.
We are an exempted company with limited liability incorporated under the laws
of Bermuda with registration number 33273 from the Registrar of Companies.
Board composition
The rights of our shareholders will be governed by Bermuda law and by our
Our bye-laws provide that our board of directors will determine the
memorandum of association and bye-laws. Bermuda company law differs
maximum size of the board, provided that it shall be not be composed of
in some material respects from the laws generally applicable to Delaware
fewer than three directors. The maximum number of directors currently
corporations. Below is a summary of some of those material differences.
allowed is nine directors and our board of directors currently consists of
Because the following statements are summaries, they do not discuss all
aspects of Bermuda law that may be relevant to us and to our shareholders.
Election and removal of directors
seven directors.
Share capital and bye-laws
Our bye-laws provide that our directors shall hold office for such term as
the shareholders shall determine or, in the absence of such determination,
Our share capital consists of common shares only. Our authorized share capital
until the next annual general meeting or until their successors are elected
consists of 5,171,949,000 common shares of par value US$0.001 per share.
or appointed or their office is otherwise vacated. Directors whose term has
As of the date of this annual report, there are 60,606,787 common shares
expired may offer themselves for re-election at each election of the directors.
outstanding. All of our issued and outstanding common shares are fully paid
and non-assessable. We also have an employee incentive program, pursuant to
Under our bye-laws, a director may be removed by a resolution adopted by
which we have granted share awards to our senior management and certain
65% or more of the votes cast by shareholders who (being entitled to do
key employees. See “Item 6. Directors, Senior Management and Employees.”
so) vote in person or by proxy at any general meeting of the shareholders
According to our bye-laws, if our share capital is divided into different classes
purpose of removing the director, containing a statement of the intention
of shares, the rights attached to any class (unless otherwise provided by the
to do so, must be served on such director not less than 14 days before the
in accordance with the provisions of our bye-laws. Notice convened for the
terms of issue of the shares of that class) may, whether or not the Company
meeting.
is being wound-up, be varied with the consent in writing of the holders of
at least two-thirds of the issued shares of that class or with the sanction of a
Any vacancy created by the removal of a director at a special general meeting
resolution passed by a majority of the votes cast at a separate general meeting
may be filled at that meeting by the election of another director in his or her
of the holders of the shares of the class at which meeting the necessary
place or, in the absence of any such election, by the board of directors. Any
quorum shall be two persons at least, in person or by proxy, holding or
other vacancy, including a newly created directorship, may be filled by our
representing one-third of the issued shares of the class. The rights conferred
board of directors.
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
Proceedings of board of directors
the shares of that class, be deemed to be varied by the creation or issue of
Our bye-laws provide that our business shall be managed by or under the
further shares ranking pari passu therewith.
direction of our board of directors. Our board of directors may act by the
Our bye-laws give our board of directors the power to issue any unissued
a quorum is present. The quorum necessary for the transaction of business
shares of the company on such terms and conditions as it may determine,
at meetings of the board of directors shall be the presence of a majority
subject to the terms of the bye-laws and any resolution of the shareholders to
of the board of directors from time to time. Our bye-laws also provide that
affirmative vote of a majority of the directors present at a meeting at which
the contrary.
Common shares
resolutions unanimously signed by all directors are valid as if they had been
passed at a meeting of the board duly called and constituted.
Holders of our common shares are entitled to one vote per share on all
Duties of directors
matters submitted to a vote of holders of common shares. Subject to
Under Bermuda common law, members of a board of directors owe a fiduciary
preferences that may be applicable to any issued and outstanding preference
duty to the Company to act in good faith in their dealings with or on behalf
shares, holders of common shares are entitled to receive such dividends,
of the company, and to exercise their powers and fulfill the duties of their
if any, as may be declared from time to time by our board of directors
office honestly. This duty has the following essential elements: (1) a duty to
out of funds legally available for dividend payments. Holders of common
act in good faith in the best interests of the company; (2) a duty not to make
shares have no redemption, sinking fund, conversion, exchange or other
a personal profit from opportunities that arise from the office of director; (3)
subscription rights. In the event of our liquidation, the holders of common
a duty to avoid conflicts of interest; and (4) a duty to exercise powers for the
shares are entitled to share equally and ratably in our assets, if any, remaining
purpose for which such powers were intended. The Bermuda Companies
after the payment of all of our debts and liabilities, subject to any liquidation
138 GeoPark 20-F
Act also imposes a duty on directors of a Bermuda company, to act honestly
directors or by a vote of shareholders, in each case if the material facts as to
and in good faith, with a view to the best interests of the company, and to
the interested director’s relationship or interests are disclosed or are known to
exercise the care, diligence and skill that a reasonably prudent person would
the disinterested directors or shareholders, or such contract or arrangement
exercise in comparable circumstances. In addition, the Bermuda Companies
is fair to the corporation as of the time it is approved or ratified. Additionally,
Act imposes various duties on directors with respect to certain matters of
such interested director could be held liable for a transaction in which such
management and administration of the company.
director derived an improper personal benefit.
The Bermuda Companies Act provides that in any proceedings for negligence,
Indemnification of directors and officers
default, breach of duty or breach of trust against any director, if it appears
Bermuda law provides generally that a Bermuda company may indemnify its
to a court that such officer is or may be liable in respect of the negligence,
directors and officers against any loss arising from or liability which by virtue
default, breach of duty or breach of trust, but that he has acted honestly
of any rule of law would otherwise be imposed on them in respect of any
and reasonably, and that, having regard to all the circumstances of the case,
negligence, default, breach of duty or breach of trust except in cases where
including those connected with his appointment, he ought fairly to be
such liability arises from fraud or dishonesty of which such director or officer
excused for the negligence, default, breach of duty or breach of trust, that
may be guilty in relation to the company.
court may relieve him, either wholly or partly, from any liability on such terms
as the court may think fit. This provision has been interpreted to apply only to
Our bye-laws provide that we shall indemnify our officers and directors in
actions brought by or on behalf of the company against the directors.
respect of their actions and omissions, except in respect of their fraud or
dishonesty, or to recover any gain, personal profit or advantage to which
By comparison, under Delaware law, the business and affairs of a corporation
such director is not legally entitled, and (by incorporation of the provisions
are managed by or under the direction of its board of directors. In exercising
of the Bermuda Companies Act) that we may advance monies to our officers
their powers, directors are charged with a duty of care and a duty of loyalty.
and directors for costs, charges and expenses incurred by our officers and
The duty of care requires that directors act in an informed and deliberate
directors in defending any civil or criminal proceeding against them on the
manner and to inform themselves, prior to making a business decision, of
condition that the officers and directors repay the monies if any allegation
all relevant material information reasonably available to them. The duty of
of fraud or dishonesty is proved against them provided, however, that, if
care also requires that directors exercise care in overseeing the conduct of
the Bermuda Companies Act requires, an advancement of expenses shall be
corporate employees. The duty of loyalty is the duty to act in good faith, not
made only upon delivery to the Company of an undertaking, by or on behalf
out of self-interest, and in a manner which the director reasonably believes
of such indemnitee, to repay all amounts so advanced if it shall ultimately
to be in the best interests of the shareholders. A party challenging the
be determined by final judicial decision from which there is no further
propriety of a decision of a board of directors bears the burden of rebutting
right to appeal that such indemnitee is not entitled to be indemnified for
the presumptions afforded to directors by the “business judgment rule.” If
such expenses under this Bye-law or otherwise. Our bye-laws provide that
the presumption is not rebutted, the business judgment rule attaches to
the company and the shareholders waive all claims or rights of action that
protect the directors and their decisions. Where, however, the presumption is
they might have, individually or in right of the company, against any of the
rebutted, the directors bear the burden of demonstrating the fairness of the
company’s directors or officers for any act or failure to act in the performance
relevant transaction. Notwithstanding the foregoing, Delaware courts subject
of such director’s or officers’ duties, except with respect to any fraud or
directors’ conduct to enhanced scrutiny in respect of defensive actions taken
dishonesty, or to recover any gain, personal profit or advantage to which such
in response to a threat to corporate control and approval of a transaction
director is not legally entitled.
resulting in a sale of control of the corporation.
Meetings of shareholders
Interested directors
Under Bermuda law, a company is required to convene the annual general
Pursuant to our bye-laws, a director shall declare the nature of his interest in
meeting of shareholders each calendar year, unless the shareholders in
any contract or arrangement with the company as required by the Bermuda
a general meeting, elect to dispense with the holding of annual general
Companies Act. A director so interested shall not, except in particular
meetings. Under Bermuda law and our bye-laws, a special general meeting of
circumstances set out in our bye-laws, be entitled to vote or be counted in the
shareholders may be called by the board of directors and may be called upon
quorum at a meeting in relation to any resolution in which he has an interest,
the requisition of shareholders holding not less than 10% of the paid-up capital
which is to his knowledge, a material interest (otherwise than by virtue of
of the company carrying the right to vote at general meetings of shareholders.
his interest in shares or debentures or other securities of or otherwise in or
through the company). A director will be liable to us for any secret profit
Our bye-laws provide that, at any general meeting of the shareholders, the
realized from the transaction. In contrast, under Delaware law, such a contract
presence in person or by proxy of two or more shareholders representing in
or arrangement is voidable unless it is approved by a majority of disinterested
excess of 50% of the total issued voting shares of the company shall constitute
GeoPark 139
a quorum for the transaction of business unless the company only has one
vote in person or by proxy at any general meeting of the shareholders in
shareholder, in which case such shareholder shall constitute a quorum. Unless
accordance with the provisions of the bye-laws. Under Bermuda law, in the
otherwise required by law or by our bye-laws, shareholder action requires a
event of an amalgamation or merger of a Bermuda company with another
resolution adopted by a majority of votes cast by shareholders at a general
company or corporation, a shareholder who did not vote in favor of the
meeting at which a quorum is present.
Shareholder proposals
amalgamation or merger and who is not satisfied that fair value has been
offered for such shareholder’s shares may, within one month of the notice
of the shareholders meeting, apply to the Supreme Court of Bermuda to
Under Bermuda law, shareholders holding at least 5% of the total voting rights
appraise the value of those shares.
of all the shareholders having at the date of the requisition a right to vote at
the meeting to which the requisition relates or any group composed of at
Under the Bermuda Companies Act, we are not required to seek the
least 100 or more shareholders may require a proposal to be submitted to an
approval of our shareholders for the sale of all or substantially all of our
annual general meeting of shareholders. Under our bye-laws, any shareholders
assets. However, Bermuda courts will view decisions of the English courts
wishing to nominate a person for election as a director or propose business to
as highly persuasive and English authorities suggest that such sales do
be transacted at a meeting of shareholders must provide (among other things)
require shareholder approval. Our bye-laws provide that the directors shall
advance notice, as set out in our bye-laws. Shareholders may only propose a
manage the business of the Company and may exercise all such powers as
person for election as a director at an annual general meeting.
are not, by the Bermuda Companies Act or by these Bye-laws, required to
Shareholder action by written consent
be exercised by the Company in general meeting and may pay all expenses
incurred in promoting and incorporating the company and may exercise
Our bye-laws provide that, except for the removal of auditors and
all the powers of the Company including, but not by way of limitation, the
directors, any actions which shareholders may take at a general meeting
power to borrow money and to mortgage or charge all or any part of the
of shareholders may be taken by the shareholders through the unanimous
undertaking property and assets (present and future) and uncalled capital
written consent of the shareholders who would be entitled to vote on the
of the Company and to issue debentures and other securities, whether
matter at the general meeting.
outright or as collateral security for any debt, liability or obligation of the
Company or any other persons.
Amendment of memorandum of association and bye-laws
Our memorandum of association and bye-laws may be amended with the
Under Bermuda law, where an offer is made for shares of a company and,
approval of a majority of our board of directors and by a resolution by a
within four months of the offer, the holders of not less than 90% of the
majority of the votes cast by shareholders who (being entitled to do so) vote in
shares not owned by the offeror, its subsidiaries or their nominees accept
person or by proxy at any general meeting of the shareholders in accordance
such offer, the offeror may by notice require the non-tendering shareholders
with the provisions of the bye-laws.
Business combinations
to transfer their shares on the terms of the offer. Dissenting shareholders
do not have express appraisal rights but are entitled to seek relief (within
one month of the compulsory acquisition notice) from the court, which has
A Bermuda company may engage in a business combination pursuant to a
power to make such orders as it thinks fit. Additionally, where one or more
tender offer, amalgamation, merger or sale of assets. The amalgamation or
parties hold not less than 95% of the shares of a company, such parties
merger of a Bermuda company with another company generally requires
may, pursuant to a notice given to the remaining shareholders, acquire the
the amalgamation or merger agreement to be approved by the company’s
shares of such remaining shareholders. Dissenting shareholders have a right
board of directors and by its shareholders. Shareholder approval is not
to apply to the court for appraisal of the value of their shares within one
required where (a) a holding company and one or more of its wholly-owned
month of the compulsory acquisition notice. If a dissenting shareholder is
subsidiary companies amalgamate or merge or (b) two or more wholly-
successful in obtaining a higher valuation, that valuation must be paid to all
owned subsidiary companies of the same holding company amalgamate
shareholders being squeezed out or the purchaser may cancel the purchase
or merge. Under the Bermuda Companies Act (save for such “short-form
notice sent.
amalgamations”), unless a company’s bye-laws provide otherwise, the
approval of 75% of the shareholders voting at a meeting is required to pass
Dividends and repurchase of shares
a resolution to approve the amalgamation or merger agreement, and the
Pursuant to our bye-laws, our board of directors has the authority to declare
quorum for such meeting must be two persons holding or representing
dividends and authorize the repurchase of shares subject to applicable law.
more than one-third of the issued shares of the company. Our bye-laws
Under Bermuda law, a company may not declare or pay a dividend if there
provide that an amalgamation or merger will require the approval of our
are reasonable grounds for believing that the company is, or would after the
board of directors and of our shareholders by a resolution adopted by 65%
payment be, unable to pay its liabilities as they become due or the realizable
or more of the votes cast by shareholders who (being entitled to do so)
value of its assets would thereby be less than its liabilities. Under Bermuda law,
140 GeoPark 20-F
a company cannot purchase its own shares if there are reasonable grounds for
admission of its common shares on AIM. Because the following statements
believing that the company is, or after the repurchase would be, unable to pay
are summaries, they do not discuss all aspects of Bermuda law that may be
its liabilities as they become due.
relevant to us and our shareholders.
Shareholder suits
Interested Directors . Under our bye-laws and the Bermuda Companies Act, a
Class actions and derivative actions are generally not available to
director shall declare the nature of his interest in any contract or arrangement
shareholders under Bermuda law. The Bermuda courts, however, would
with the company. Our bye-laws further provide that a director so interested
ordinarily be expected to permit a shareholder to commence an action
shall not, except in particular circumstances, be entitled to vote or be counted
in the name of a company to remedy a wrong to the company where
in the quorum at a meeting in relation to any resolution in which he has an
the act complained of is alleged to be beyond the corporate power of
interest, which is to his knowledge, a material interest (otherwise than by
the company or illegal, or would result in the violation of the company’s
virtue of his interest in shares or debentures or other securities of or otherwise
memorandum of association or bye-laws. Furthermore, consideration
in or through the company). A director will be liable to us for any secret profit
would be given by a Bermuda court to acts that are alleged to constitute
realized from the transaction. See “Item 10—B. Memorandum of association
a fraud against the minority shareholders or where an act requires the
and bye-laws—Interested Directors.”
approval of a greater percentage of the company’s shareholders than that
which actually approved it.
Amalgamations, Mergers and Similar Arrangements . Pursuant to the Bermuda
Companies Act, the amalgamation or merger of a Bermuda company with
When the affairs of a company are being conducted in a manner which is
another company or corporation requires the amalgamation or merger
oppressive or prejudicial to the interests of some part of the shareholders,
agreement to be approved by the company’s board of directors and,
one or more shareholders may apply under the Bermuda Companies
under certain circumstances, by its shareholders. Under our bye-laws, an
Act for an order of the Supreme Court of Bermuda, which may make
amalgamation or merger will require the approval of our board of directors
such order as it sees fit, including an order regulating the conduct of the
and our shareholders by Special Resolution, which is a resolution adopted
company’s affairs in the future or ordering the purchase of the shares of
by 65% of more of the votes cast by shareholders who (being entitled to do
any shareholders by other shareholders or by the company.
so) vote in person or by proxy at any general meeting of the shareholders
in accordance with the provisions of the bye-laws and the quorum for
Our bye-laws contain a provision through which we and our shareholders
any general meeting must be two or more persons, in person or by proxy,
waive any claim or right of action that we or they have, both individually
representing in excess of 50% of the total of our issued voting shares. Under
and on our behalf, against any director or officer in relation to any action or
Bermuda law, in the event of an amalgamation or merger of a Bermuda
failure to take action by such director or officer, including the breach of any
company with another company or corporation, a shareholder of the Bermuda
fiduciary duty, except in respect of any fraud or dishonesty of such director
company who did not vote in favor of the amalgamation or merger and who is
or officer.
not satisfied that he has been offered fair value for his shares may, within one
month of notice of the shareholders meeting, apply to the Supreme Court of
Comparison of Bermuda law to Delaware corporate law
Bermuda to appraise the fair value of those shares.
Bermuda law differs from the laws in effect in the United States and might
Under Delaware law, with certain exceptions, a merger, consolidation or
afford less protection to shareholders.
sale of all or substantially all the assets of a corporation must be approved
Our shareholders could have more difficulty protecting their interests
by the board of directors and a majority of the issued and outstanding
than would shareholders of a corporation incorporated in a jurisdiction
shares entitled to vote thereon. Under Delaware law, a shareholder of a
of the United States. As a Bermuda company, we are governed by our
corporation participating in certain major corporate transactions may, under
memorandum of association and bye-laws and Bermuda company
certain circumstances, be entitled to appraisal rights pursuant to which
law. The provisions of the Bermuda Companies Act, which applies to
such shareholder may receive cash in the amount of the fair value of the
us, differs in some material respects from laws generally applicable to
shares held by such shareholder (as determined by a court) in lieu of the
U.S. corporations and shareholders, including the provisions relating to
consideration such shareholder would otherwise receive in the transaction.
interested directors, mergers and acquisitions, takeovers, shareholder
lawsuits and indemnification of directors. Set forth below is a summary of
Shareholders’ Suit . Class actions and derivative actions are generally not
these provisions, as well as modifications adopted pursuant to our bye-laws,
available to shareholders under Bermuda law. The Bermuda courts, however,
which differ in certain respects from provisions of Delaware corporate law.
would ordinarily be expected to permit a shareholder to commence an
Our shareholders approved the adoption of new bye-laws which came into
action in the name of a company to remedy a wrong to the company
effect on February 19, 2014, being the date on which the company cancelled
where the act complained of is alleged to be beyond the corporate power
GeoPark 141
of the company or illegal, or would result in the violation of the company’s
proceeding, such director or officer had no reasonable cause to believe his
memorandum of association or bye-laws. When the affairs of a company
or her conduct was unlawful. In addition, we have entered into customary
are being conducted in a manner which is oppressive or prejudicial to the
indemnification agreements with our directors.
interests of some part of the shareholders, one or more shareholders may
apply for an order of the Supreme Court of Bermuda regulating the conduct
As a result of these differences, investors could have more difficulty
of the company’s affairs in the future or an order to purchase the shares of
protecting their interests than would shareholders of a corporation
any shareholders by other shareholders or by the company and, in the case of
incorporated in the United States.
a purchase by the company, for the reduction accordingly of the company’s
capital, or otherwise. See “Item 10—B. Memorandum of association and bye-
Tax matters . Under current Bermuda law, we are not subject to tax on
laws—Shareholder Suits.”
income or capital gains. We have received from the Minister of Finance
under The Exempted Undertaking Tax Protection Act 1966, as amended,
Our bye-laws contain a provision by virtue of which we and our shareholders
an assurance that, in the event that Bermuda enacts legislation imposing
waive any claim or right of action that they have, both individually and on
tax computed on profits, income, any capital asset, gain or appreciation,
our behalf, against any director or officer in relation to any action or failure to
or any tax in the nature of estate duty or inheritance, then the imposition
take action by such director or officer, including the breach of any fiduciary
of any such tax shall not be applicable to us or to any of our operations or
duty, except in respect of any fraud or dishonesty of such director or officer.
shares, debentures or other obligations, until March 31, 2035. We could be
Class actions and derivative actions generally are available to shareholders
subject to taxes in Bermuda after that date. This assurance is subject to the
under Delaware law for, among other things, breach of fiduciary duty,
provision that it is not to be construed to prevent the application of any tax
corporate waste and actions not taken in accordance with applicable law. In
or duty to such persons as are ordinarily resident in Bermuda or to prevent
such actions, the court has discretion to permit the winning party to recover
the application of any tax payable in accordance with the provisions of the
attorneys’ fees incurred in connection with such action.
Land Tax Act 1967 or otherwise payable in relation to any property leased
Indemnification of Directors . We may indemnify our directors and officers in
pay annual Bermuda government fees. In addition, all entities employing
their capacity as directors or officers for any loss arising or liability attaching
individuals in Bermuda are required to pay a payroll tax and there are other
to them by virtue of any rule of law in respect of any negligence, default,
sundry taxes payable, directly or indirectly, to the Bermuda government.
breach of duty or breach of trust of which a director or officer may be
Neither we nor our Bermuda subsidiaries employ individuals in Bermuda as
to us. We are incorporated in Bermuda as an exempted company and
guilty in relation to the company other than in respect of his own fraud or
at the date of this annual report.
dishonesty. See “Item 10—B. Memorandum of association and bye-laws—
Enforcement of Judgments.” Our bye-laws provide that we shall indemnify
Access to books and records and dissemination of information
our officers and directors in respect of their acts and omissions, except
Members of the general public have a right to inspect the public documents
in respect of their fraud or dishonesty, or to recover any gain, personal
of a company available at the office of the Registrar of Companies in
profit or advantage to which such Director is not legally entitled, and (by
Bermuda. These documents include the company’s memorandum of
incorporation of the provisions of the Bermuda Companies Act) that we
association and any amendments thereto. The shareholders have the
may advance money to our officers and directors for the costs, charges
additional right to inspect the bye-laws of the company, minutes of general
and expenses incurred by our officers and directors in defending any civil
meetings of shareholders and the company’s audited financial statements.
or criminal proceedings against them on condition that the directors and
The company’s audited financial statements must be presented at the
officers repay the money if any allegations of fraud or dishonesty is proved
annual general meeting of shareholders, unless the board and all the
against them provided, however, that, if the Bermuda Companies Act
shareholders agree to the waiving of the audited financials. The company’s
requires, an advancement of expenses shall be made only upon delivery
share register is open to inspection by shareholders and by members of
to the Company of an undertaking, by or on behalf of such indemnitee,
the general public without charge. A company is required to maintain its
to repay all amounts if it shall ultimately be determined by final decision
share register in Bermuda but may, subject to the provisions of the Bermuda
that such indemnitee is not entitled to be indemnified for such expenses
Companies Act, establish a branch register outside of Bermuda. Bermuda
under our Bye-laws or otherwise. Under Delaware law, a corporation
law does not, however, provide a general right for shareholders to inspect or
may indemnify a director or officer of the corporation against expenses
obtain copies of any other corporate records.
(including attorneys’ fees), judgments, fines and amounts paid in settlement
actually and reasonably incurred in defense of an action, suit or proceeding
Registrar or transfer agent
by reason of such position if such director or officer acted in good faith and
A register of holders of the common shares is maintained by Coson Corporate
in a manner he or she reasonably believed to be in or not opposed to the
Services Limited in Bermuda, and a branch register is maintained in the
best interests of the corporation and, with respect to any criminal action or
United States by Computershare Trust Company, N.A., who serves as branch
registrar and transfer agent.
142 GeoPark 20-F
Enforcement of Judgments
Section 98 further provides that a Bermuda company may indemnify its
We are incorporated as an exempted company with limited liability
directors, officers and auditors against any liability incurred by them in
under the laws of Bermuda, and substantially all of our assets are located
defending any proceedings, whether civil or criminal, in which judgment
in Colombia, Chile, Brazil, Peru and Argentina. In addition, most of our
is awarded in their favor or in which they are acquitted or granted relief by
directors and executive officers reside outside the United States, and all or
the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda
a substantial portion of the assets of such persons are located outside the
Companies Act.
United States. As a result, it may be difficult for investors to effect service of
process on those persons in the United States or to enforce in the United
Our bye-laws contain provisions whereby we and our shareholders waive
States judgments obtained in U.S. courts against us or those persons based
any claim or right of action that we have, both individually and on our behalf,
on the civil liability provisions of the U.S. securities laws.
against any director or officer in relation to any action or failure to take action
by such director or officer, except in respect of any fraud or dishonesty of
There is no treaty in force between the United States and Bermuda providing
such director or officer. We may also indemnify our directors and officers
for the reciprocal recognition and enforcement of judgments in civil
in their capacity as directors and officers for any loss arising or liability
and commercial matters. As a result, whether a U.S. judgment would be
attaching to them by virtue of any rule of law in respect of any negligence,
enforceable in Bermuda against us or our directors and officers depends
default, breach of trust of which a director or officer may be guilty in relation
on whether the U.S. court that entered the judgment is recognized by the
to the company other than in respect of his own fraud or dishonesty. We
Bermuda court as having jurisdiction over us or our directors and officers, as
have entered into customary indemnification agreements with our directors.
determined by reference to Bermuda conflict of law rules and the judgment
is not contrary to public policy in Bermuda, has not been obtained by fraud
No treaty exists between the United States and Chile for the reciprocal
in proceedings contrary to natural justice and is not based on an error
recognition and enforcement of foreign judgments. Chilean courts, however,
in Bermuda law. A judgment debt from a U.S. court that is final and for a
have enforced valid and conclusive judgments for the payment of money
sum certain based on U.S. federal securities laws will not be enforceable in
rendered by competent U.S. courts by virtue of the legal principles of
Bermuda unless the judgment debtor had submitted to the jurisdiction of
reciprocity and comity, subject to review in Chile of the U.S. judgment in
the U.S. court, and the issue of submission and jurisdiction is a matter of
order to ascertain whether certain basic principles of due process and public
Bermuda (not U.S.) law.
policy have been respected, without retrial or review of the merits of the
subject matter. If a U.S. court grants a final judgment, enforceability of this
An action brought pursuant to a public or penal law, the purpose of which is
judgment in Chile will be subject to obtaining the relevant exequatur (i.e.,
the enforcement of a sanction, power or right at the instance of the state in
recognition and enforcement of the foreign judgment) according to Chilean
its sovereign capacity, may not be entertained by a Bermuda court. Certain
civil procedure law in effect at that time, and depending on certain factors
remedies available under the laws of U.S. jurisdictions, including certain
(the satisfaction or non-satisfaction of which would be determined by the
remedies under U.S. federal securities laws, may not be available under
Supreme Court of Chile). Currently, the most important of such factors are:
Bermuda law or enforceable in a Bermuda court, as they may be contrary
the existence of reciprocity (if it can be proved that there is no reciprocity
to Bermuda public policy. Further, no claim may be brought in Bermuda
in the recognition and enforcement of the foreign judgment between the
against us or our directors and officers in the first instance for violations
United States and Chile, that judgment would not be enforced in Chile); the
of U.S. federal securities laws because these laws have no extraterritorial
absence of any conflict between the foreign judgment and Chilean laws
jurisdiction under Bermuda law and do not have force of law in Bermuda. A
(excluding for this purpose the laws of civil procedure) and Chilean public
Bermuda court may, however, impose civil liability on us or our directors and
policy; the absence of a conflicting judgment by a Chilean court relating
officers if the facts alleged in a complaint constitute or give rise to a cause of
to the same parties and arising from the same facts and circumstances;
action under Bermuda law. However, section 281 of the Bermuda Companies
the Chilean court’s determination that the U.S. courts had jurisdiction, that
Act allows a Bermuda court, in certain circumstances, to relieve officers and
process was appropriately served on the defendant and that the defendant
directors of Bermuda companies of liability for acts of negligence, breach of
was afforded a real opportunity to appear before the court and defend its
duty or trust or other defaults.
case; and the judgment being final under the laws of the country in which
it was rendered. Nonetheless, we have been advised by our Chilean counsel
Section 98 of the Bermuda Companies Act provides generally that a Bermuda
that there is doubt as to the enforceability in original actions in Chilean
company may indemnify its directors, officers and auditors against any
courts of liabilities predicated solely upon U.S. federal or state securities laws.
liability which by virtue of any rule of law would otherwise be imposed on
them in respect of any negligence, default, breach of duty or breach of trust,
C. Material contracts
except in cases where such liability arises from fraud or dishonesty of which
See “Item 4. Information on the Company—B. Business Overview—Significant
such director, officer or auditor may be guilty in relation to the company.
Agreements.”
GeoPark 143
D. Exchange controls
Not applicable.
E. Taxation
• a person holding common shares in connection with a trade or business
conducted outside of the United States.
If an entity that is classified as a partnership for U.S. federal income tax
The following summary contains a description of certain Bermudian, U.S.
purposes holds common shares, the U.S. federal income tax treatment of a
federal income, and Chilean tax consequences of the acquisition, ownership and
partner will generally depend on the status of the partner and the activities
disposition of our common shares. The summary is based upon the tax laws of
of the partnership. Partnerships holding common shares and partners in such
Bermuda, the United States, and Chile, and regulations thereunder as of the date
partnerships should consult their tax advisers as to the particular U.S. federal
hereof, which are subject to change.
income tax consequences of their investment in our common shares.
Bermuda tax consideration
This discussion is based on the Internal Revenue Code of 1986, as amended
At the date of this annual report, there is no Bermuda income or profits tax,
(the “Code”), administrative pronouncements, judicial decisions, and final,
withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance
temporary and proposed Treasury regulations, all as of the date hereof, any
tax payable by us or by our shareholders in respect of our common shares. We
of which is subject to change, possibly with retroactive effect. U.S. Holders
have obtained an assurance from the Minister of Finance of Bermuda under
should consult their tax advisers concerning the U.S. federal, state, local and
the Exempted Undertakings Tax Protection Act 1966 that, in the event that
foreign tax consequences of owning and disposing of our common shares in
any legislation is enacted in Bermuda imposing any tax computed on profits
their particular circumstances.
or income, or computed on any capital asset, gain or appreciation or any tax in
the nature of estate duty or inheritance tax, such tax shall not, until March 31,
A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal
2035, be applicable to us or to any of our operations or to our common shares,
income tax purposes that is:
debentures or other obligations except insofar as such tax applies to persons
• a citizen or individual resident of the United States;
ordinarily resident in Bermuda or is payable by us in respect of real property
• a corporation, or other entity taxable as a corporation, created or organized
owned or leased by us in Bermuda. We pay annual Bermuda government fees.
in or under the laws of the United States, any state therein or the District of
Columbia; or
Material U.S. federal income tax considerations
• an estate or trust the income of which is subject to U.S. federal income
The following is a description of the material U.S. federal income tax
taxation regardless of its source.
consequences to U.S. Holders (as defined below) of owning and disposing of
our common shares. This discussion is not a comprehensive description of
This discussion assumes that we are not, and will not become, a passive
all tax considerations that may be relevant to a particular person’s decision
foreign investment company, as described below.
to hold our common shares. This discussion applies only to a U.S. Holder that
holds our common shares as capital assets for tax purposes. In addition, it
Taxation of distributions
does not describe all of the tax consequences that may be relevant in light of
Distributions paid on our common shares, other than certain pro rata
the U.S. Holder’s particular circumstances, including alternative minimum tax
distributions of common shares, will generally be treated as dividends to
and Medicare contribution tax consequences and differing tax consequences
the extent paid out of our current or accumulated earnings and profits (as
applicable to a U.S. Holder subject to special rules, such as:
determined under U.S. federal income tax principles). Because we do not
• certain financial institutions;
maintain calculations of our earnings and profits under U.S. federal income tax
• a dealer or trader in securities who uses a mark-to-market method of tax
principles, it is expected that distributions will generally be reported to U.S.
accounting;
Holders as dividends. Subject to the passive foreign investment company rules
• a person holding common shares as part of a straddle, wash sale or
described below, dividends paid by qualified foreign corporations to certain non-
conversion transaction or entering into a constructive sale with respect to the
corporate U.S. Holders may be taxable at favorable rates. A foreign corporation is
common shares;
treated as a qualified foreign corporation with respect to dividends paid on stock
• a person whose functional currency for U.S. federal income tax purposes is
that is readily tradable on a securities market in the United States, such as the
not the US$;
NYSE where our common shares are traded. Non-corporate U.S. Holders should
• a partnership or other entities classified as partnerships for U.S. federal
consult their tax advisers to determine whether the favorable rate will apply to
income tax purposes;
dividends they receive and whether they are subject to any special rules that
• a tax-exempt entity, including an “individual retirement account” or “Roth IRA;”
limit their ability to be taxed at this favorable rate.
• a person that owns or is deemed to own 10% or more of our voting stock;
• a person who acquired our shares pursuant to the exercise of an employee
A dividend generally will be included in a U.S. Holder’s income when received,
stock option or otherwise as compensation; or
144 GeoPark 20-F
will be treated as foreign-source income to U.S. Holders and will not be eligible
be available and, if so, what the consequences of the alternative treatments
for the dividends-received deduction generally available to U.S. corporations
would be in their particular circumstances.
under the Code with respect to dividends paid by domestic corporations.
Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were
Sale or other taxable disposition of common shares
treated as a PFIC for the taxable year in which we paid a dividend or the prior
Gain or loss realized on the sale or other taxable disposition of our common
taxable year, the preferential dividend rates discussed above with respect to
shares will be capital gain or loss, and will be long-term capital gain or loss if
dividends paid to certain non-corporate U.S. Holders would not apply.
the U.S. Holder held our common shares for more than one year. Long-term
capital gain of a non-corporate U.S. Holder is generally taxed at preferential
Information reporting and backup withholding
rates. The deductibility of capital losses is subject to limitations. The amount
Payments of dividends and sales proceeds that are made within the United
of the gain or loss will equal the difference between the U.S. Holder’s tax
States or through certain U.S.-related financial intermediaries generally are
basis in the common shares disposed of and the amount realized on the
subject to information reporting, and may be subject to backup withholding,
disposition. If a Chilean tax is withheld on the sale or disposition of the
unless (1) the U.S. Holder is a corporation or other exempt recipient or
common shares, a U.S. Holder’s amount realized will include the gross
(2) in the case of backup withholding, the U.S. Holder provides a correct
amount of the proceeds of the sale or disposition before deduction of the
taxpayer identification number and certifies that it is not subject to backup
Chilean tax. See “—Chilean tax on transfers of shares” for a description of
withholding. The amount of any backup withholding from a payment to a
when a disposition may be subject to taxation by Chile. This gain or loss
U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal
will generally be U.S.-source gain or loss for foreign tax credit purposes. U.S.
income tax liability and may entitle it to a refund, provided that the required
Holders should consult their tax advisers as to whether the Chilean tax on
information is timely furnished to the Internal Revenue Service.
gains may be creditable against the U.S. Holder’s U.S. federal income tax on
foreign-source income from other sources.
Chilean tax on transfers of shares
Passive foreign investment company rules
In September 2012, Article 10 of the Chilean Income Tax Law Decree Law No.
824 of 1974, or the indirect transfer rules, were enacted, and impose taxes on
We believe that we were not a “passive foreign investment company,” or PFIC,
the indirect transfer of shares, equity rights, interests or other rights in the
for U.S. federal income tax purposes for 2017, and we do not expect to be
equity, control or profits of a Chilean entity as well as transfers of other assets
a PFIC in the foreseeable future. However, because the composition of our
and property of permanent establishments or other businesses in Chile. The
income and assets will vary over time, there can be no assurance that we will
2014 tax reform introduces a measure which obliges the company from which
not be a PFIC for any taxable year. The determination of whether we are a PFIC
shares are transferred to pay taxes if the entity which undertakes the transfer
is made annually and is based upon the composition of our income and assets
of shares fails to do so.
(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
If we were a PFIC for any taxable year during which a U.S. Holder held our
tax 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 disposition
jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean
(including certain pledges) of our common shares would generally be
resident holds 5% or more of such entity, or such entity’s rights to equity,
allocated ratably over the U.S. Holder’s holding period for the common shares.
control or profits, or 50% or more of such entity’s rights to equity or profits are
The amounts allocated to the taxable year of the sale or other disposition
held by residents in black-listed jurisdictions; or
and to any year before we became a PFIC would be taxed as ordinary income.
• the shares or rights transferred represent 10% or more of the offshore
The amount allocated to each other taxable year would be subject to tax
holding company (considering dispositions by related persons and over the
at the highest rate in effect for individuals or corporations for that year, as
preceding 12-month period) and the underlying Chilean Assets indirectly
appropriate, and an interest charge would be imposed on the tax on such
transferred, in the proportion indirectly owned by the seller, (a) are valued
amount. Further, to the extent that any distribution received by a U.S. Holder
in an amount equal to or higher than UTA 210,000 (approximately US$200
on its common shares exceeds 125% of the average of the annual distributions
million) (adjusted by the Chilean inflation unit of reference) or (b) represent
on the shares received during the preceding three years or the U.S. Holder’s
20% or more of the market value of the interest held by such seller in such
holding period, whichever is shorter, that distribution would be subject to
offshore holding company.
taxation in the same manner as gain, as described immediately above. Certain
elections may be available that would result in alternative treatments (such
As a result of these rules, a capital gain tax of 35% will be applied by the
as mark-to-market treatment) of our common shares. U.S. Holders should
Chilean tax authorities to the sale of any of our common shares if either of the
consult their tax advisers to determine whether any of these elections would
above alternative are met. This rate might be subject to change in the short
GeoPark 145
term. See “Item 4. Information on the Company—B. Business overview—
shares—The transfer of our common shares may be subject to capital gains
Industry and regulatory framework —Chile.”
taxes pursuant to indirect transfer rules in Chile.”
As of December 31, 2017, our Chilean Assets represented more than UTA
F. Dividends and paying agents
210,000 and represent more than 38% of our total assets.
Not applicable.
The 35% rate is calculated pursuant to one of the following methods, as
determined by the seller:
G. Statement by experts
• the sale price of the shares minus the acquisition cost of such shares,
Not applicable.
multiplied by the percentage or proportion of the part of the underlying Chilean
Assets’ fair market value (which assets are deemed to be “indirectly transferred”
H. Documents on display
by virtue of the sale of shares) to the fair market value of the shares of the seller;
We are subject to the informational requirements of the Exchange Act.
or
Accordingly, we are required to file reports and other information with the
• the portion of the sales price of the shares equal to the proportion
SEC, including annual reports on Form 20-F and reports on Form 6-K. You may
of the fair market value of the underlying Chilean Assets, minus the
inspect and copy reports and other information filed with the SEC at the Public
corresponding proportion in the tax cost of such Chilean Assets for the
Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on
corresponding holding entity.
the operation of the Public Reference Room may be obtained by calling the
SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website
However, the seller may opt to be taxed as if the underlying Chilean Assets
that contains reports and other information about issuers, like us, that file
had been sold directly in which case a different set of tax rules may apply.
electronically with the SEC. The address of that website is www.sec.gov.
The tax is payable by the seller of the shares; however, the buyer shall make a
provisional withholding unless the seller declares and pays the tax within the
I. Subsidiary information
month following the sale, payment, remittance or it is credited into its account
Not applicable.
or is put at its disposal. Also, if the seller fails to declare and pay this tax, and
the buyer has not complied with its withholding obligations, the Chilean tax
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
authority (Servicio de Impuestos Internos) may charge such tax directly to any
MARKET RISK
of them. In addition, the Chilean tax authority may require us, the seller, the
buyer, or its representative in Chile, to file an affidavit with the information
We are exposed to a variety of market risks, including commodity price risk,
necessary to assess this tax.
interest rate risk, currency risk and credit (counterparty and customer) risk.
Based on information available to us, (i) no Chilean resident holds 5% or
The term “market risk” refers to the risk of loss arising from adverse changes in
more of our rights to equity, control or profits; or (ii) residents in black-listed
interest rates, oil and natural gas prices and foreign currency exchange rates.
jurisdictions hold 50% or more of our rights to equity, control or profits.
For further information on our market risks, please see Note 3 to our
Therefore, we do not believe the indirect transfer rules will apply to transfers
Consolidated Financial Statements.
of our common shares, unless the shares or rights transferred represent 10%
or more of the company and the other conditions described above are met
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
(considering dispositions by related persons and over the preceding 12-month
period).
A. Debt securities
Not applicable.
However, there can be no assurance that, at any time in the future, a Chilean
resident will not hold 5% or more of our rights to equity, control or profits or
B. Warrants and rights
that residents in black-listed jurisdictions will not hold 50% or more of our
Not applicable.
rights to equity, control or profits. If this were to occur, all sales of our common
shares would be subject to the indirect transfer tax referred to above.
C. Other securities
Our expectations regarding the indirect transfer rules are based on our
Not applicable.
understandings, analysis and interpretation of these enacted indirect transfer
rules, which are subject to additional interpretation and rule-making by the
D. American Depositary Shares
Chilean authorities. As such, there is uncertainty relating to the application by
Not applicable.
Chilean authorities of the indirect transfer rules on us.
See “Item 3. Key Information—D. Risk Factors—Risks related to our common
146 GeoPark 20-F
PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
• provide reasonable assurance that transactions are recorded as necessary to
A. Defaults
No matters to report.
B. Arrears and delinquencies
No matters to report.
permit preparation of financial statements, in accordance with generally accepted
accounting principles, and that receipts and expenditures are being made only in
accordance with authorization of our management and directors; and
• provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have a
material effect on our financial statements.
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY
Because of its inherent limitations, internal control over financial reporting
HOLDERS AND USE OF PROCEEDS
Not applicable.
ITEM 15. CONTROLS AND PROCEDURES
A. Disclosure Controls and Procedures
may not prevent or detect misstatements. Therefore, effective control over
financial reporting cannot, and does not, provide absolute assurance of
achieving our control objectives. Also, projections of, and any evaluation of
effectiveness of the internal controls in future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
As of December 31, 2017, under the supervision and with the participation
Under the supervision and with the participation of our management,
of our management, including our Chief Executive Officer and Chief Financial
including our Chief Executive Officer, our Chief Financial Officer, and our
Officer, we performed an evaluation of the effectiveness of the design and
Director of Legal and Governance, we conducted an evaluation of the
operation of our disclosure controls and procedures (as defined in Rule
effectiveness of our internal control over financial reporting as of December
13a-15(e) under the Exchange Act). There are inherent limitations to the
31, 2017, based on the criteria established in Internal Control - Integrated
effectiveness of any disclosure controls and procedures system, including
Framework of the Committee of Sponsoring Organizations of the Treadway
the possibility of human error and circumventing or overriding them. Even
Commission (2013).
if effective, disclosure controls and procedures can provide only reasonable
assurance of achieving their control objectives.
Based on this assessment, management believes that, as of December 31,
2017, its internal control over financial reporting was effective based on those
Based on such evaluation, our Chief Executive Officer and Chief Financial
criteria.
Officer concluded that our disclosure controls and procedures are effective to
provide reasonable assurance that the information we are required to disclose
C. Attestation Report of the Registered Public Accounting Firm
in the reports we file or submit under the Exchange Act is (1) recorded,
Not applicable.
processed, summarized and reported within the time periods specified in
the SEC’s rules and forms and (2) accumulated and communicated to our
D. Changes in Internal Control over Financial Reporting
management to allow timely decisions regarding required disclosures.
There have been no changes in our internal control over financial reporting
during the period covered by this annual report on Form 20-F that have
B. Management’s Annual Report on Internal Control over Financial
materially affected or reasonably likely to materially affect our internal control
Reporting
over financial reporting.
Our management is responsible for establishing and maintaining an
adequate internal control over financial reporting as defined in Rule
ITEM 16. RESERVED
13a-15(f ) under the Exchange Act.
Our internal control over financial reporting is a process designed by, or
under the supervision of, our principal executive and principal financial
We have determined that Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield
officers, management and other personnel, to provide reasonable assurance
are independent, as such term is defined under SEC rules applicable to foreign
regarding the reliability of financial reporting and the preparation of our
private issuers. In addition, Mr. Robert Bedingfield and Mr. Juan Cristobal Pavez
financial statements for external reporting purposes, in accordance with
are regarded as audit committee financial experts.
ITEM 16A. Audit committee financial expert
generally accepted accounting principles. These include those policies and
procedures that:
ITEM 16B. Code of Conduct
• pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect transactions and dispositions of our assets;
We have adopted a code of conduct applicable to the board of directors and
GeoPark 147
all employees. Since its effective date on September 24, 2012, we have not
16C have been approved by the Audit Committee.
waived compliance with or amended the code of conduct.
ITEM 16C. Principal Accountant Fees and Services
ITEM 16D. Exemptions from the listing standards for audit committees
Amounts billed by PwC for audit and other services were as follows:
None.
Audit fees
Audit related fees
Tax services fees
Other fees paid
Total
Audit Fees
ITEM 16E. Purchases of equity securities by the issuer and affiliated
2017
2016
purchasers
(in millions of US$)
0.73
0.14
0.21
0.03
1.11
0.49
During 2017, no purchases of our common shares were made by or on behalf of
—
us or by any affiliated purchaser.
0.13
—
ITEM 16F. Change in registrant’s certifying accountant
0.62
Not applicable.
Audit fees are fees billed for professional services rendered by the principal
ITEM 16G. Corporate governance
accountant for the audit of the registrant’s annual financial statements or
services that are normally provided by the accountant in connection with
Our common shares are listed on the NYSE. We are therefore required to
statutory and regulatory filings or engagements for those fiscal years. It includes
comply with certain of the NYSE’s corporate governance listing standards
the audit of our Consolidated Financial Statements and other services that
(the “NYSE Standards”). As a foreign private issuer, we may follow our
generally only the independent accountant reasonably can provide, such as
home country’s corporate governance practices in lieu of most of the
comfort letters, statutory audits, consents and assistance with and review of
NYSE Standards. Our corporate governance practices differ in certain
documents filed with the SEC.
Audit-Related Fees
significant respects from those that U.S. companies must adopt in order to
maintain NYSE listing and, in accordance with Section 303A.11 of the NYSE
Listed Company Manual, a brief, general summary of those differences is
Audit-related fees are fees billed for assurance and related services that are
provided as follows.
reasonably related to the performance of the audit or review of our Consolidated
Financial Statements and not reported under the previous category. These
Director independence
services would include, among others: accounting consultations and audits
The NYSE Standards require a majority of the membership of NYSE-listed
in connection with acquisitions, internal control reviews, attest services that
company boards to be composed of independent directors. Neither
are not required by statue or regulation and consultation concerning financial
Bermuda law, the law of our country of incorporation, nor our memorandum
accounting and reporting standards.
Tax Fees
of association or bye-laws require a majority of our board to consist of
independent directors.
Tax fees are fees billed for professional services for tax compliance, tax advice
Non-management directors’ executive sessions
and tax planning.
The NYSE Standards require non-management directors of NYSE-listed
companies to meet at regularly scheduled executive sessions without
Pre-Approval Policies and Procedures
management. Our memorandum of association and bye-laws do not require
Following the listing of our common shares on the NYSE, the Audit
our non-management directors to hold such meetings.
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
Committee member composition
The NYSE Standards require domestic NYSE-listed domestic companies to
and ensures key partners in the appointed firm are rotated in accordance
have a nominating/corporate governance committee and a compensation
with best practices. Also, following our NYSE listing, the Audit Committee
committee that are composed entirely of independent directors. Bermuda law,
is required to pre-approve the audit and non-audit fees and services
the law of our country of incorporation, does not impose similar requirements.
performed by the Company’s auditors in order to be sure that the provision
of such services does not impair the audit firm’s independence.
Independence of the compensation committee and its advisers
All of the audit fees, audit-related fees and tax fees described in this item
On January 11, 2013, the SEC approved NYSE listing standards that require
148 GeoPark 20-F
that the board of directors of a domestic listed company consider two factors
We are incorporated under, and are governed by, the laws of Bermuda.
(in addition to the existing general independence tests) in the evaluation of
For a summary of some of the differences between provisions of Bermuda
the independence of compensation committee members: (i) the source of
law applicable to us and the laws applicable to companies incorporated in
compensation of the director, including any consulting, advisory or other
Delaware and their shareholders, See “Item 10. Additional Information—B.
compensatory fees paid by the listed company, and (ii) whether the director
Memorandum of association and bye-laws.”
has an affiliate relationship with the listed company, a subsidiary of the listed
company or an affiliate of a subsidiary of the listed company. In addition,
ITEM 16H. Mine safety disclosure
before selecting or receiving advice from a compensation consultant or
other adviser, the compensation committee of a listed company will be
Not applicable.
required to take into consideration six specific factors, as well as all other
factors relevant to an adviser’s independence.
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 NYSE
listing standards relating to compensation committees of domestic listed
companies. All of the members of our compensation committee are
independent, and the charter of our compensation committee does not
require the compensation 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.
Foreign private issuers such as us are exempt from these additional
requirements if home country practice is followed. Bermuda law does not
impose similar requirements, and consequently, our audit committee does
not perform these additional functions. Our Audit Committee is composed
exclusively of independent auditors.
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
would satisfy the NYSE’s requirements; acquire shareholder approval of equity
compensation plans in certain cases; or adopt and make publicly available
corporate governance guidelines.
GeoPark 149
PART III
ITEM 17. Financial statements
No. Description
We have responded to Item 18 in lieu of this item.
among the International Finance Corporation, GeoPark Holdings
ITEM 18. Financial statements
Limited, Gerald O’Shaughnessy and James F. Park (incorporated herein
by reference to Exhibit 10.4 to the Company’s Registration Statement
Financial Statements are filed as part of this annual report, see pages 156 to
on Form F-1 (File No. 333-191068) filed with the SEC on September 9,
205 to this annual report.
2013).
ITEM 19. Exhibits
No. Description
4.5
Shareholders’ Agreement, dated May 20, 2011, among LG International
Corporation, GeoPark Chile Limited Agencia en Chile and GeoPark
Chile S.A. (incorporated herein by reference to Exhibit 10.7 to the
Company’s Registration Statement on Form F-1 (File No. 333-191068)
1.1
Certificate of Incorporation (incorporated herein by reference to Exhibit
filed with the SEC on September 9, 2013).
3.1 to the Company’s Registration Statement on Form F-1 (File No. 333-
4.6
Shareholders’ Agreement, dated December 18, 2012, among LG
191068) filed with the SEC on September 9, 2013).
International Corporation, GeoPark Chile Limited Agencia en Chile and
1.2 Memorandum of Association (incorporated herein by reference to
GeoPark Colombia S.A. (incorporated herein by reference to Exhibit 10.9
Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File
to the Company’s Registration Statement on Form F-1 (File No. 333-
No. 333-191068) filed with the SEC on September 9, 2013).
191068) filed with the SEC on September 9, 2013).
1.3
Current bye-laws (incorporated herein by reference to Exhibit 3.3 to the
4.7
Subscription Agreement, dated October 18, 2011, among LG
Company’s Registration Statement on Form F-1 (File No. 333-191068)
International Corporation and GeoPark TdF S.A. (incorporated herein
filed with the SEC on September 9, 2013).
by reference to Exhibit 10.11 to the Company’s Registration Statement
1.4
Form of amended and restated bye-laws (incorporated herein by
on Form F-1 (File No. 333-191068) filed with the SEC on September 9,
reference to Exhibit 3.4 to the Company’s Registration Statement on
2013).
Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).
4.8
Shareholders’ Agreement, dated October 4, 2011, among LG
2.2
Indenture, dated September 21, 2017, among GeoPark Limited, the
International Corporation, GeoPark TdF S.A. and GeoPark Chile S.A.
Bank of New York Mellon and Lord Securities Corporation.*
(incorporated herein by reference to Exhibit 10.12 to the Company’s
2.3
Contract of Pledge without Conveyance on Shares between GeoPark
Registration Statement on Form F-1 (File No. 333-191068) filed with the
Latin America Limited Agencia en Chile and Lord Securities Corporation,
SEC on September 9, 2013).
dated September 21, 2017.*
4.9
Purchase and Sale Agreement for Natural Gas between GeoPark Chile
2.4 Deed of Pledge of Membership Interest among GeoPark Latin America
Limited Agencia en Chile and Methanex Chile SpA. (incorporated herein
Coöperatie U.A., Stichting Collateral Agent Geopark and GeoPark Colombia
by reference to Exhibit 10.15 to the Company’s Registration Statement
Coöperatie U.A.*
on Form F-1/A (File No. 333-191068) filed with the SEC on October 10,
4.1
Special Contract for the Exploration and Exploitation of
2013). †
Hydrocarbons, Fell Block, dated April 29, 1997, among the Republic
4.10 First Addendum and Amendment to Purchase and Sale Agreement
of Chile, the Chilean Empresa Nacional de Petróleo (ENAP) and
for Natural Gas between GeoPark Chile Limited Agencia en Chile and
Cordex Petroleums Inc. (incorporated herein by reference to Exhibit
Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.16
10.1 to the Company’s Registration Statement on Form F-1 (File No.
to the Company’s Registration Statement on Form F-1/A (File No. 333-
333-191068) filed with the SEC on September 9, 2013).
191068) filed with the SEC on October 10, 2013). †
4.2
Exploration and Production Contract regarding exploration for and
4.11 Second Addendum and Amendment to Purchase and Sale Agreement
exploitation of hydrocarbons in the La Cuerva Block, dated April 16,
for Natural Gas between GeoPark Chile Limited Agencia en Chile and
2008, between the Colombian Agencia Nacional de Hidrocarburos and
Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.7
Hupecol Caracara LLC (incorporated herein by reference to Exhibit 10.2
to the Company’s Registration Statement on Form F-1/A (File No. 333-
to the Company’s Registration Statement on Form F-1 (File No. 333-
191068) filed with the SEC on September 26, 2013).
191068) filed with the SEC on September 9, 2013).
4.12 Third Addendum and Amendment to Purchase and Sale Agreement
4.3
Exploration and Production Contract regarding exploration for and
for Natural Gas between GeoPark Chile Limited Agencia en Chile and
exploitation of hydrocarbons in the Llanos 34 Block, dated March 13,
Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.18
2009, between the Colombian Agencia Nacional de Hidrocarburos and
to the Company’s Registration Statement on Form F-1/A (File No. 333-
Unión Temporal Llanos 34 (incorporated herein by reference to Exhibit
191068) filed with the SEC on October 10, 2013). †
10.3 to the Company’s Registration Statement on Form F-1 (File No.
4.13 Fourth Addendum and Amendment to Purchase and Sale Agreement
333-191068) filed with the SEC on September 9, 2013).
for Natural Gas between GeoPark Chile Limited Agencia en Chile and
4.4
Subscription and Shareholders Agreement, dated February 7, 2006,
Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.19
150 GeoPark 20-F
No. Description
No. Description
to the Company’s Registration Statement on Form F-1/A (File No. 333-
4.23 Asset Purchase Agreement between GeoPark Argentina Ltd. and
191068) filed with the SEC on October 10, 2013). †
Pluspetrol S.A., dated December 18, 2017.*
4.14 Fifth Addendum and Amendment to Purchase and Sale Agreement
4.24 Purchase and Sale Agreement for Crude Oil and Condensate of Fell Block
for Natural Gas between GeoPark Chile Limited Agencia en Chile and
between Empresa Nacional del Petróleo (ENAP) and GeoPark Fell S.p.A.,
Methanex Chile SpA. dated April 1, 2014. (incorporated herein by
dated April 21, 2017.*
reference to Exhibit 4.23 to the Company’s Annual Report on Form 20-F
8.21 Subsidiaries of GeoPark Limited.*
filed with the SEC on April 30, 2015). †
12.1 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*
4.15 Sixth Addendum and Amendment to Purchase and Sale Agreement
12.2 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*
for Natural Gas between GeoPark Chile Limited Agencia en Chile
13.1 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to
and Methanex Chile SpA. dated May 1, 2015 (incorporated herein by
section 906 of the Sarbanes-Oxley Act of 2002.*
reference to Exhibit 4.21 to the Company’s Annual Report on Form 20-F
13.2 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to
filed with the SEC on April 15, 2016). †
section 906 of the Sarbanes-Oxley Act of 2002.*
4.16 Seventh Addendum and Amendment to Purchase and Sale Agreement
15.1 Consent of Price Waterhouse & Co. S.R.L., Argentina.*
for Natural Gas between GeoPark Chile Limited Agencia en Chile and
15.2 Consents of DeGolyer and MacNaughton to use its report.*
Methanex Chile SpA. dated April 1, 2016 (incorporated herein by
99.1 Reserves Report of DeGolyer and MacNaughton dated February 15,
reference to Exhibit 4.21 to the Company’s Annual Report on Form 20-F
2018, for reserves in Chile, Colombia, Peru, Brazil as of December 31,
filed with the SEC on April 11, 2017). †
2017.*
4.17 Contract for the sale and Purchase of Natural Gas 2017-2027 between
GeoPark Fell SpA and Methanex Chile SpA dated March 31, 2017
(incorporated herein by reference to Exhibit 4.22 to the Company’s
*
†
Filed with this Annual Report on Form 20-F.
Confidential treatment of certain provisions of these exhibits has
Annual Report on Form 20-F filed with the SEC on April 11, 2017). †
been requested with the SEC. Omitted material for which confidential
4.18 Members’ Agreement, dated January 8, 2014, among GeoPark Latin
treatment has been requested has been filed separately with the SEC.
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).
4.19 Prepayment Agreement for an Amount of up to US$100,000,000,
dated December 18, 2015, among C.I. Trafigura Petroleum Colombia
SAS, GeoPark Colombia SAS and GeoPark Ltd. (incorporated herein by
reference to Exhibit 4.25 to the Company’s Annual Report on Form 20-F
filed with the SEC on April 15, 2016).
4.20 Amendment Agreement No. 1 among GeoPark Colombia SAS, C.I.
Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated September
1, 2016 relating to the Prepayment Agreement dated December
18, 2015 (incorporated herein by reference to Exhibit 4.27 to the
Company’s Annual Report on Form 20-F filed with the SEC on April 11,
2017).
4.21 Amendment Agreement No. 2 among GeoPark Colombia SAS, C.I.
Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated December
16, 2016 relating to the Prepayment Agreement dated December
18, 2015 (incorporated herein by reference to Exhibit 4.28 to the
Company’s Annual Report on Form 20-F filed with the SEC on April 11,
2017).
4.22 Amendment Agreement No. 3 among GeoPark Colombia SAS, C.I.
Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated February 13,
2017 relating to the Prepayment Agreement dated December 18, 2015
(incorporated herein by reference to Exhibit 4.29 to the Company’s
Annual Report on Form 20-F filed with the SEC on April 11, 2017).
GeoPark 151
Glossary of Oil and Natural Gas Terms
The terms defined in this section are used throughout this annual report:
that are separated vertically by intervening impervious strata, or laterally by
“appraisal well” means a well drilled to further confirm and evaluate the
local geologic barriers, or by both. Reservoirs that are associated by being
presence of hydrocarbons in a reservoir that has been discovered.
in overlapping or adjacent fields may be treated as a single or common
“API” means the American Petroleum Institute’s inverted scale for denoting the
operational field. The geological terms structural feature and stratigraphic
“light” or “heaviness” of crude oils and other liquid hydrocarbons.
condition are intended to identify localized geological features as opposed to
“bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used herein
the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
in reference to crude oil, condensate or natural gas liquids.
“formation” means a layer of rock which has distinct characteristics that differ
“bcf” means one billion cubic feet of natural gas.
from nearby rock.
“bcm” means billion cubic meters.
“mbbl” means one thousand barrels of crude oil, condensate or natural gas
“boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being
liquids.
equivalent to one barrel of oil.
“boepd” means barrels of oil equivalent per day.
“bopd” means barrels of oil per day.
“mboe” means one thousand barrels of oil equivalent.
“mcf” means one thousand cubic feet of natural gas.
“Measurements” include:
“British thermal unit” or “btu” means the heat required to raise the temperature
• “m” or “meter” means one meter, which equals approximately 3.28084 feet;
of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
• “km” means one kilometer, which equals approximately 0.621371 miles;
“basin” means a large natural depression on the earth’s surface in which
• “sq. km” means one square kilometer, which equals approximately 247.1
sediments generally brought by water accumulate.
acres;
“CEOP” ( Contrato Especial de Operación ) means a special operating contract
• “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent
the Chilean signs with a company or a consortium of companies for the
to approximately 0.15898 cubic meters;
exploration and exploitation of hydrocarbon wells
• “boe” means one barrel of oil equivalent, which equals approximately
“completion” means the process of treating a drilled well followed by the
160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of
installation of permanent equipment for the production of natural gas or oil, or in
natural gas to one barrel of oil;
the case of a dry hole, the reporting of abandonment to the appropriate agency.
• “cf” means one cubic foot;
“developed acreage” means the number of acres that are allocated or
• “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf,
assignable to productive wells or wells capable of production.
respectively;
“developed reserves” are expected quantities to be recovered from existing
• “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf,
wells and facilities. Reserves are considered developed only after the necessary
respectively;
equipment has been installed or when the costs to do so are relatively minor
• “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf,
compared to the cost of a well. Where required facilities become unavailable, it
respectively; and
may be necessary to reclassify developed reserves as undeveloped.
• “pd” means per day.
“development well” means a well drilled within the proved area of an oil or gas
“metric ton” or “MT” means one thousand kilograms. Assuming standard
reservoir to the depth of a stratigraphic horizon known to be productive.
quality oil, one metric ton equals 7.9 bbl.
“dry hole” means a well found to be incapable of producing hydrocarbons
“mmbbl” means one million barrels of crude oil, condensate or natural gas liquids.
in sufficient quantities such that proceeds from the sale of such production
“mmboe” means one million barrels of oil equivalent.
exceed production expenses and taxes.
“mmbtu” means one million British thermal units.
“E&P Contract” means exploration and production contract
“NYMEX” means The New York Mercantile Exchange.
“economic interest” means an indirect participation interest in the net
“net acres” means the percentage of total acres an owner has out of a
revenues from a given block based on bilateral agreements with the
particular number of acres, or a specified tract. An owner who has a 50%
concessionaires.
interest in 100 acres owns 50 net acres.
“economically producible” means a resource that generates revenue that
“productive well” means a well that is found to be capable of producing
exceeds, or is reasonably expected to exceed, the costs of the operation.
hydrocarbons in sufficient quantities such that proceeds from the sale of the
“exploratory well” means a well drilled to find and produce oil or gas in
production exceed production expenses and taxes.
an unproved area, to find a new reservoir in a field previously found to be
“prospect” means a potential trap which may contain hydrocarbons and is
productive of oil or gas in another reservoir, or to extend a known reservoir.
supported by the necessary amount and quality of geologic and geophysical
Generally, an exploratory well is any well that is not a development well, a
data to indicate a probability of oil and/or natural gas accumulation ready to
service well, or a stratigraphic test well as those items are defined below.
be drilled. The five required elements (generation, migration, reservoir, seal
“field” means an area consisting of a single reservoir or multiple reservoirs all
and trap) must be present for a prospect to work and if any of them fail neither
grouped on or related to the same individual geological structural feature
oil nor natural gas will be present, at least not in commercial volumes.
and/or stratigraphic condition. There may be two or more reservoirs in a field
“proved developed reserves” means those proved reserves that can be
152 GeoPark 20-F
expected to be recovered through existing wells and facilities and by
are drilled without the intention of being completed for hydrocarbon
existing operating methods.
production. This classification also includes tests identified as core tests and all
“proved reserves” means estimated quantities of crude oil, natural gas, and
types of expendable holes related to hydrocarbon exploration. Stratigraphic
natural gas liquids which geological and engineering data demonstrate with
test wells are classified as (i) exploratory-type, if not drilled in a proved area, or
reasonable certainty to be economically recoverable in future years from
(ii) development-type, if drilled in a proved area.
known reservoirs under existing economic and operating conditions, as well
“tcm” means trillion cubic meters.
as additional reserves expected to be obtained through confirmed improved
“undeveloped reserves” are quantities expected to be recovered through
recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).
future investments: (1) from new wells on undrilled acreage in known
“proved undeveloped reserves” means are those proved reserves that are
accumulation, (2) from deepening existing wells to a different (but known)
expected to be recovered from future wells and facilities, including future
reservoir, (3) from infill wells that will increase recover, or (4) where a relatively
improved recovery projects which are anticipated with a high degree of
large expenditure ( e.g. , when compared to the cost of drilling a new well)
certainty in reservoirs which have previously shown favorable response to
is required to (a) recomplete an existing well or (b) install production or
improved recovery projects.
transportation facilities for primary or improved recovery projects.
“reasonable certainty” means a high degree of confidence.
“unit” means the joining of all or substantially all interests in a reservoir or
“recompletion” means the process of re-entering an existing wellbore that
field, rather than a single tract, to provide for development and operation
is either producing or not producing and completing new reservoirs in an
without regard to separate property interests. Also, the area covered by a
attempt to establish or increase existing production.
unitization agreement.
“reserves” means estimated remaining quantities of oil and gas and related
“wellbore” means the hole drilled by the bit that is equipped for oil or gas
substances anticipated to be economically producible, as of a given date, by
production on a completed well. Also called well or borehole.
application of development projects to known accumulations. In addition,
“working interest” means the right granted to the lessee of a property to
there must exist, or there must be a reasonable expectation that there will
explore for and to produce and own oil, gas, or other minerals. The working
exist, a revenue interest in the production, installed means of delivering oil,
interest owners bear the exploration, development, and operating costs on
gas, or related substances to market, and all permits and financing required
either a cash, penalty, or carried basis.
to implement the project.
“workover” means operations in a producing well to restore or increase
“reservoir” means a porous and permeable underground formation
production.
containing a natural accumulation of producible oil and/or gas that 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
rock types and thus has the potential to become rich hydrocarbon source
rock. Its fine grain size and lack of permeability can allow shale to form a good
cap rock for hydrocarbon traps.
“spacing” means the distance between wells producing from the same
reservoir. Spacing is often expressed in terms of acres ( e.g. , 40-acre spacing,
and is often established by regulatory agencies).
“spud” means the very beginning of drilling operations of a new well,
occurring when the drilling bit penetrates the surface utilizing a drilling rig
capable of drilling the well to the authorized total depth.
“stratigraphic test well” means a drilling effort, geologically directed, to obtain
information pertaining to a specific geologic condition. Such wells customarily
GeoPark 153
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on
Form 20-F and that it has duly caused and authorized the undersigned
to sign this annual report on its behalf.
GEOPARK LIMITED
By: /s/ James F. Park
Name: James F. Park
Title: Chief Executive Officer and Deputy Chairman
Date: April 11, 2018
154 GeoPark 20-F
GeoPark 155
Consolidated Financial Statements
As of and for the year ended 31 December 2017
156 GeoPark 20-F
Contents
Report of Independent Registered Public Accounting Firm
Consolidated Statement of Income
Consolidated Statement of Comprehensive Income
Consolidated Statement of Financial Position
Consolidated Statement of Changes in Equity
Consolidated Statement of Cash Flow
Notes to the Consolidated Financial Statements
158
159
159
160
161
162
163
GeoPark 157
Report of Independent Registered
Public Accounting Firm
To the Board of Directors and Shareholders of GeoPark Limited
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statement of financial
position of GeoPark Limited and its subsidiaries (the “Company”) as of
December 31, 2017 and 2016, the related consolidated statements of income
and of comprehensive income, changes in equity and cash flows, for each of
the three years in the period ended December 31, 2017, including the related
notes (collectively referred to as the “consolidated financial statements”). In
our opinion, the consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2017 and
2016, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2017, in conformity with International
Financial Reporting Standards as issued by the International Accounting
Standards Board.
Basis for Opinion
These consolidated financial statements are the responsibility of the
Company’s management. Our responsibility is to express an opinion on the
Company’s consolidated financial statements based on our audits. We are
a public accounting firm registered with the Public Company Accounting
Oversight Board (United States) (“PCAOB”) and are required to be independent
with respect to the Company in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in
accordance with the standards of the PCAOB. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement, whether
due to error or fraud.
Our audits included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to
error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding
the amounts and disclosures in the consolidated financial statements.
Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. We believe that our
audits provide a reasonable basis for our opinion.
PRICE WATERHOUSE & CO. S.R.L.
By (Partner) Ezequiel Luis Mirazon
Autonomous City of Buenos Aires, Argentina
March 7, 2018
We have served as the Company’s auditor since 2009.
158 GeoPark 20-F
Consolidated Statement of Income
Amounts in US$ ´000
Note
2017
2016
2015
REVENUE
Commodity risk management contracts
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Selling expenses
Depreciation
Write-off of unsuccessful exploration efforts
Impairment loss reversed (recognised) for non-financial assets
Other expenses
OPERATING PROFIT (LOSS)
Financial expenses
Financial income
Foreign exchange (loss) gain
PROFIT (LOSS) BEFORE INCOME TAX
Income tax (expense) benefit
LOSS FOR THE YEAR
Attributable to:
Owners of the Company
Non-controlling interest
Losses per share (in US$) for loss attributable
to owners of the Company. Basic
Losses per share (in US$) for loss attributable
to owners of the Company. Diluted
Consolidated Statement of Comprehensive Income
Amounts in US$ ´000
Loss for the year
Other comprehensive income:
Items that may be subsequently reclassified to profit or loss
Currency translation difference
Total comprehensive loss for the year
Attributable to:
Owners of the Company
Non-controlling interest
The notes on pages 163 to 205 are an integral part of these Consolidated Financial Statements.
7
8
9
12
13
14
20
330,122
(15,448)
(98,987)
(7,694)
(42,054)
(1,136)
(74,885)
(5,834)
192,670
(2,554)
(67,235)
(10,282)
(34,170)
(4,222)
(75,774)
(31,366)
209,690
-
(86,742)
(13,831)
(37,471)
(5,211)
(105,557)
(30,084)
20-36
-
5,664
(149,574)
(5,088)
78,996
(1,344)
(13,711)
(28,613)
(232,491)
15
15
15
(53,511)
(36,229)
(36,924)
2,016
(2,193)
25,308
2,128
13,872
1,269
(33,474)
(48,842)
(301,620)
17
(43,145)
(11,804)
17,054
(17,837)
(60,646)
(284,566)
(24,228)
6,391
(49,092)
(11,554)
(234,031)
(50,535)
19
19
(0.40)
(0.82)
(4.05)
(0.40)
(0.82)
(4.05)
2017
2016
2015
(17,837)
(60,646)
(284,566)
(512)
7,102
(1,001)
(18,349)
(53,544)
(285,567)
(24,740)
6,391
(41,990)
(11,554)
(235,032)
(50,535)
GeoPark 159
Consolidated Statement of Financial Position
Amounts in US$ ´000
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
Other financial assets
Cash and cash equivalents
TOTAL CURRENT ASSETS
TOTAL ASSETS
TOTAL EQUITY
Equity attributable to owners of the Company
Share capital
Share premium
Reserves
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
Derivative financial instrument liabilities
Current income tax liabilities
Trade and other payables
TOTAL CURRENT LIABILITIES
TOTAL LIABILITIES
TOTAL EQUITY AND LIABILITIES
The Consolidated Financial Statements were approved by the Board of Directors on 7 March 2018.
The notes on pages 163 to 205 are an integral part of these Consolidated Financial Statements.
160 GeoPark 20-F
Note
2017
2016
20
22
25
18
24
23
24
24
22
25
25
26
27
28
18
29
27
25
29
517,403
473,646
3,823
22,110
27,636
235
2,852
19,547
23,053
241
571,207
519,339
5,738
19,519
7,518
26,048
21,378
134,755
214,956
786,163
3,515
18,426
7,402
15,815
2,480
73,563
121,201
640,540
61
239,191
129,606
60
236,046
130,118
(283,933)
(260,459)
84,925
41,915
105,765
35,828
126,840
141,593
418,540
319,389
46,284
2,286
25,921
42,509
2,770
34,766
493,031
399,434
7,664
19,289
42,942
96,397
166,292
659,323
786,163
39,283
3,067
5,155
52,008
99,513
498,947
640,540
Consolidated Statement of Changes in Equity
Amount in US$ ‘000
Equity at 1 January 2015
Comprehensive income:
Loss for the year
Currency translation differences
Total Comprehensive Income for the Year 2015
Transactions with owners:
Share-based payment (Note 30)
Repurchase of shares (Note 26)
Total 2015
Balances at 31 December 2015
Comprehensive income:
Loss for the year
Currency translation differences
Total Comprehensive Loss for the Year 2016
Transactions with owners:
Share-based payment (Note 30)
Repurchase of shares (Note 26)
Dividends distribution to non-controlling interest
Total 2016
Balances at 31 December 2016
Comprehensive income:
Loss for the year
Currency translation differences
Total Comprehensive Loss for the Year 2017
Transactions with owners:
Share-based payment (Note 30)
Dividends distribution to non-controlling interest
Total 2017
Balances at 31 December 2017
Attributable to owners of the Company
(Accumulated
Losses)
Non-
Share
Share
Other
Translation
Retained
controlling
Capital
Premium
Reserve
Reserve
Earnings
58
210,886
127,527
(3,510)
40,596
Interest
103,569
Total
479,126
-
-
-
1
-
1
-
-
-
22,734
(1,615)
21,119
-
-
-
-
-
-
-
(234,031)
(50,535)
(284,566)
(1,001)
-
-
(1,001)
(1,001)
(234,031)
(50,535)
(285,567)
-
-
-
(14,993)
-
(14,993)
481
-
481
8,223
(1,615)
6,608
59
232,005
127,527
(4,511)
(208,428)
53,515
200,167
-
-
-
1
-
1
-
-
-
6,032
(1,991)
-
4,041
-
-
-
-
-
-
-
-
(49,092)
(11,554)
(60,646)
7,102
7,102
-
-
7,102
(49,092)
(11,554)
(53,544)
-
-
-
-
(2,939)
-
-
(2,939)
273
-
(6,406)
(6,133)
35,828
3,367
(1,991)
(6,406)
(5,030)
141,593
60
236,046
127,527
2,591
(260,459)
-
-
-
1
-
1
-
-
-
3,145
-
3,145
-
-
-
-
-
-
-
(24,228)
6,391
(17,837)
(512)
(512)
-
-
(512)
(24,228)
6,391
(18,349)
-
-
-
754
-
754
175
(479)
(304)
4,075
(479)
3,596
61
239,191
127,527
2,079
(283,933)
41,915
126,840
The notes on pages 163 to 205 are an integral part of these Consolidated Financial Statements.
GeoPark 161
Consolidated Statement of Cash Flow
Amounts in US$ ‘000
Note
2017
2016
2015
Cash flows from operating activities
Loss for the year
Adjustments for:
Income tax expense (benefit)
Depreciation
Loss on disposal of property, plant and equipment
Impairment loss (reversed) recognised for non-financial assets
Write-off of unsuccessful exploration efforts
Accrual of borrowing’s interests
Borrowings cancellation costs
Amortisation of other long-term liabilities
Unwinding of long-term liabilities
Accrual of share-based payment
Foreign exchange loss (gain)
Unrealized loss on commodity risk management contracts
Income tax paid
Changes in working capital
Cash flows from operating activities – net
Cash flows from investing activities
Purchase of property, plant and equipment
Cash flows used in investing activities – net
Cash flows from financing activities
Proceeds from borrowings
Debt issuance costs paid
Proceeds from cash calls from related parties
Repurchase of shares
Principal paid
Interest paid
Borrowings cancellation costs paid
Dividends distribution to non-controlling interest
Cash flows from / (used in) / from financing activities - net
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at 1 January
Currency translation differences
Cash and cash equivalents at the end of the year
Ending Cash and cash equivalents are specified as follows:
Cash in bank and bank deposits
Cash in hand
Cash and cash equivalents
The notes on pages 163 to 205 are an integral part of these Consolidated Financial Statements.
162 GeoPark 20-F
(17,837)
(60,646)
(284,566)
17
20-36
20
15
28
28
8
5
43,145
74,885
190
-
5,834
28,879
17,575
(657)
2,779
4,075
2,193
13,300
(6,925)
(25,278)
142,158
11,804
75,774
14
(5,664)
31,366
27,940
-
(2,924)
2,693
3,367
(17,054)
105,557
2,000
149,574
30,084
28,460
-
(703)
2,575
8,223
(13,872)
33,474
3,068
(1,956)
11,920
82,884
-
(7,625)
(24,104)
25,895
(105,604)
(39,306)
(48,842)
(105,604)
(39,306)
(48,842)
425,000
(6,683)
1,155
-
(355,022)
(27,688)
(12,315)
186
-
5,210
(1,991)
(22,645)
(25,490)
-
(479)
(6,406)
7,036
-
2,400
(1,615)
(89)
(25,754)
-
-
23,968
(51,136)
(18,022)
60,522
73,563
670
134,755
(7,558)
(40,969)
82,730
(1,609)
73,563
127,672
(3,973)
82,730
134,734
73,551
82,720
21
12
10
134,755
73,563
82,730
Notes to the Consolidated Financial Statements
Note 1
General Information
The adoption of these amendments did not have any impact on the current
GeoPark Limited (the “Company”) is a company incorporated under the law
period or any prior period and is not likely to affect future periods.
of Bermuda. The Registered Office address is Cumberland House, 9th Floor, 1
Victoria Street, Hamilton HM11, Bermuda.
New standards, amendments and interpretations issued but not effective for the
The principal activities of the Company and its subsidiaries (the “Group” or
“GeoPark”) are exploration, development and production for oil and gas
•
IFRS 2 Share based payments: amended in June 2016 to clarify the
reserves in Chile, Colombia, Brazil, Peru and Argentina.
measurement basis for cash-settled share-based payments and the
financial year beginning 1 January 2017 and not early adopted.
accounting for modifications that change an award from cash-settled to
These Consolidated Financial Statements were authorised for issue by the
equity-settled. It also introduces an exception to IFRS 2 principles by requiring
Board of Directors on 7 March 2018.
Note 2
an award to be treated as if it was wholly equity-settled, where an employer is
obliged to withhold an amount for the employee’s tax obligation associated
with a share-based payment and pay that amount to the tax authority. It is
effective for annual periods beginning on or after January 1, 2018. The Group
Summary of significant accounting policies
estimates that these amendments will not have a material impact on the
The principal accounting policies applied in the preparation of these
Group’s operating results or financial position.
Consolidated Financial Statements are set out below. These policies have been
consistently applied to the years presented, unless otherwise stated.
•
IFRS 9 Financial Instruments and associated amendments to various other
2.1 Basis of preparation
standards: IFRS 9 replaces the multiple classification and measurement
models in IAS 39. Classification of debt assets will be driven by the entity’s
The Consolidated Financial Statements of GeoPark Limited have been
business model for managing the financial assets and the contractual cash
prepared in accordance with International Financial Reporting Standards
flow characteristics of the financial assets. A debt instrument is measured
(“IFRS”) as issued by the International Accounting Standards Board (“IASB”),
at amortised cost if: a) the objective of the business model is to hold the
under the historical cost convention.
financial asset for the collection of the contractual cash flows, and b) the
contractual cash flows under the instrument solely represent payments
The Consolidated Financial Statements are presented in thousands of United
of principal and interest. All other debt and equity instruments, including
States Dollars (US$’000) and all values are rounded to the nearest thousand
investments in complex debt instruments and equity investments, must be
(US$’000), except in the footnotes and where otherwise indicated.
recognised at fair value.
The preparation of financial statements in conformity with IFRS requires the
All fair value movements on financial assets are taken through the statement
use of certain critical accounting estimates. It also requires management to
of profit or loss, except for equity investments that are not held for trading,
exercise its judgement in the process of applying the Group’s accounting
which may be recorded in the statement of profit or loss or in reserves
policies. The areas involving a higher degree of judgement or complexity, or
(without subsequent recycling to profit or loss). For financial liabilities that are
areas where assumptions and estimates are significant to the Consolidated
measured under the fair value option entities will need to recognise the part
Financial Statements are disclosed in this note under the title “Accounting
of the fair value change that is due to changes in their own credit risk in other
estimates and assumptions”.
comprehensive income rather than profit or loss.
All the information included in these Consolidated Financial Statements
The new hedge accounting rules (released in December 2013) align hedge
corresponds to the Group, except where otherwise indicated.
accounting more closely with common risk management practices. As a
2.1.1 Changes in accounting policy and disclosure
New and amended standards adopted by the Group
general rule, it will be easier to apply hedge accounting going forward.
The new impairment model under IFRS 9 requires the recognition of
impairment provisions based on expected credit losses rather than only
The following standards have been adopted by the Group for the first time for
incurred credit losses as is the case under IAS 39. It applies to financial assets
the financial year beginning on or after 1 January 2017:
classified at amortised cost, debt instruments measured at fair value through
other comprehensive income, contract assets under IFRS 15, lease receivables,
• Recognition of Deferred Tax Assets for Unrealised Losses – Amendments to
loan commitments and certain financial guarantee contracts.
IAS 12
• Disclosure initiative – Amendments to IAS 7
GeoPark 163
The new standard also introduces expanded disclosure requirements and
•
IFRIC 22 Foreign Currency Transactions and Advance Consideration:
changes in presentation.
issued in December 2016. The interpretation addresses how to determine
the date of the transaction for the purpose of determining the exchange
Management has assessed the effects of applying the new standard on the
rate to use on initial recognition of the related asset, expense or income
Group’s Consolidated Financial Statements and concluded that no material
related to an entity that has received or paid an advance consideration
impact will be expected.
in a foreign currency. The date of the transaction is the date on which an
entity initially recognises the non-monetary asset or non-monetary liability
•
IFRS 15 Revenue from contracts with customers and associated
arising from the payment or receipt of advance consideration. It is effective
amendments to various other standards: The IASB has issued a new standard
for annual periods beginning on January 1, 2018. The Group estimates
for the recognition of revenue. This will replace IAS 18 which covers contracts
that these interpretations will not have a material impact on the Group’s
for goods and services and IAS 11 which covers construction contracts. The
operating results or financial position.
new standard is based on the principle that revenue is recognised when
control of a good or service transfers to a customer so the notion of control
• Sale or contribution of assets between an investor and its associate or
replaces the existing notion of risks and rewards.
joint venture – Amendments to IFRS 10 and IAS 28: The amendments clarify
These accounting changes may have flow-on effects on the entity’s business
investor and its associates or joint ventures.
practices regarding systems, processes and controls, compensation and bonus
plans, contracts, tax planning and investor communications. Entities will have
•
Improvements to IFRSs – 2014-2016 Cycle: amendments issued in
a choice of full retrospective application, or prospective application with
December 2016 that are effective for periods beginning on or after January
the accounting treatment for sales or contribution of assets between an
additional disclosures.
1, 2018. The Group estimates that these amendments will not have an
impact on the Group’s operating results or financial position.
It is mandatory for financial years commencing on or after 1 January 2018.
The Group intends to adopt the standard using the modified retrospective
There are no other standards that are not yet effective and that would be
approach which means that the cumulative impact of the adoption will be
expected to have a material impact on the entity in the current or future
recognised in retained earnings as of 1 January 2018 and that comparatives
reporting periods and on foreseeable future transactions.
will not be restated.
2.2 Going concern
Management has assessed the effects of applying the new standard on the
The Directors regularly monitor the Group’s cash position and liquidity risks
Group’s Consolidated Financial Statements and concluded that no material
throughout the year to ensure that it has sufficient funds to meet forecast
impact will be expected.
operational and investment funding requirements. Sensitivities are run to
reflect latest expectations of expenditures, oil and gas prices and other factors
•
IFRS 16 Leases: will affect primarily the accounting by lessees and will result
to enable the Group to manage the risk of any funding short falls and/or
in the recognition of almost all leases on balance sheet. The standard removes
potential debt covenant breaches.
the current distinction between operating and financing leases and requires
recognition of an asset (the right to use the leased item) and a financial
Considering macroeconomic environment conditions, the performance
liability to pay rentals for virtually all lease contracts. An optional exemption
of the operations, the US$ 425,000,000 debt fund raising completed in
exists for short-term and low-value leases. The accounting by lessors will
September 2017, the Group’s cash position, and the fact that over 99% of its
not significantly change. Some differences may arise as a result of the new
total indebtedness maturing in 2024, the Directors have formed a judgement,
guidance on the definition of a lease.
at the time of approving the financial statements, that there is a reasonable
expectation that the Group has adequate resources to meet all its obligations
The Group has not yet determined to what extent its commitments will result
for the foreseeable future. For this reason, the Directors have continued
in the recognition of an asset and a liability for future payments and how
to adopt the going concern basis in preparing the Consolidated Financial
this will affect the Group’s profit and classification of cash flows. Some of the
Statements.
commitments may be covered by the exception for short-term and low-value
leases and some commitments may relate to arrangements that will not
2.3 Consolidation
qualify as leases under IFRS 16. At this stage, the Group does not intend to
Subsidiaries are all entities (including structured entities) over which the group
adopt the standard before its effective date. The Group intends to apply the
has control. The Group controls an entity when the Group is exposed to, or
simplified transition approach and will not restate comparative amounts for
has rights to, variable returns from its involvement with the entity and has the
the year prior to first adoption.
ability to affect those returns through its power over the entity. Subsidiaries
164 GeoPark 20-F
are fully consolidated from the date on which control is transferred to the
the US Dollar, meanwhile for the Group´s Brazilian company the functional
Group. They are deconsolidated from the date that control ceases.
currency is the local currency, which is the Brazilian Real.
The Group applies the acquisition method to account for business
b) Transactions and balances
combinations. The consideration transferred for the acquisition of a subsidiary
Foreign currency transactions are translated into the functional currency
is the fair value of the assets transferred, the liabilities incurred by the former
using the exchange rates prevailing at the dates of the transactions. Foreign
owners of the acquiree and the equity interests issued by the Group. The
exchange gains and losses resulting from the settlement of such transactions
consideration transferred includes the fair value of any asset or liability
and from the translation at period end exchange rates of monetary assets
resulting from a contingent consideration arrangement. Identifiable assets
and liabilities denominated in foreign currencies are recognised in the
acquired and liabilities and contingent liabilities assumed in a business
Consolidated Statement of Income.
combination are measured initially at their fair values at the acquisition date.
Acquisition-related costs are expensed as incurred.
2.6 Joint arrangements
The excess of the consideration transferred, the amount of any non-
joint operations or joint ventures depending on the contractual rights and
Under IFRS 11 investments in joint arrangements are classified as either
controlling interest in the acquired entity, and the acquisition-date fair
obligations of each investor.
value of any previous equity interest in the acquired entity over the fair
value of the identifiable net assets acquired is recorded as goodwill. If the
The Group has assessed the nature of its joint arrangements and determined
total of consideration transferred, non-controlling interest recognised and
them to be joint operations. The Group combines its share in the joint
previously held interest measured is less than the fair value of the net assets
operations individual assets, liabilities, results and cash flows on a line-by-line
of the subsidiary acquired in the case of a bargain purchase, the difference is
basis with similar items in its financial statements.
recognised directly in the income statement.
2.7 Revenue recognition
Intercompany transactions, balances and unrealised gains on transactions
Revenue from the sale of crude oil and gas is recognised in the
between the Group and its subsidiaries are eliminated. Unrealised losses are
Consolidated Statement of Income when risk is transferred to the
also eliminated unless the transaction provides evidence of an impairment
purchaser, and if the revenue can be measured reliably and is expected
of the asset transferred. Amounts reported in the financial statements of
to be received. Revenue is shown net of VAT, discounts related to the sale
subsidiaries have been adjusted where necessary to ensure consistency with
and overriding royalties due to the ex-owners of oil and gas properties
the accounting policies adopted by the Group.
where the royalty arrangements represent a retained working interest in
the property. See Note 32 (a).
2.4 Segment reporting
Operating segments are reported in a manner consistent with the internal
2.8 Production and operating costs
reporting provided to the chief operating decision-maker. The chief operating
Production costs include wages and salaries incurred to achieve the revenue
decision-maker, who is responsible for allocating resources and assessing
for the year. Direct and indirect costs of raw materials and consumables,
performance of the operating segments, has been identified as the Executive
rentals, leasing and royalties are also included within this account.
Committee. This committee is integrated by the CEO, COO, CFO and managers
in charge of the Geoscience, Operations, Corporate Governance, Finance and
2.9 Financial results
People departments. This committee reviews the Group’s internal reporting
Financial results include interest expenses, interest income, bank charges, the
in order to assess performance and allocate resources. Management has
amortisation of financial assets and liabilities, and foreign exchanges gain
determined the operating segments based on these reports.
and losses. The Group has capitalised borrowing cost for wells and facilities
2.5 Foreign currency translation
a) Functional and presentation currency
that were initiated after 1 January 2009. The capitalisation rate used to
determine the amount of borrowing costs to be capitalised is the weighted
average interest rate applicable to the Group’s general borrowings during the
The Consolidated Financial Statements are presented in US Dollars, which is
year, which was 6.90% at year end 2017 (7.98% at year end 2016 and 2015).
the Group’s presentation currency.
Amounts capitalised during the year amounted to US$ 610,841 (US$ 254,950
Items included in the financial statements of each of the Group’s entities
are measured using the currency of the primary economic environment in
2.10 Property, plant and equipment
in 2016 and US$ 637,390 in 2015).
which the entity operates (the “functional currency”). The functional currency
Property, plant and equipment are stated at historical cost less depreciation
of Group companies incorporated in Chile, Colombia, Peru and Argentina is
and impairment charge, if applicable. Historical cost includes expenditure that
GeoPark 165
is directly attributable to the acquisition of the items; including provisions for
furniture and vehicles) not directly associated with oil and gas activities has
asset retirement obligation.
been calculated by means of the straight line method by applying such annual
rates as required to write-off their value at the end of their estimated useful
Oil and gas exploration and production activities are accounted for in
lives. The useful lives range between 3 years and 10 years.
accordance with the successful efforts method on a field by field basis. The
Group accounts for exploration and evaluation activities in accordance with
Depreciation is allocated in the Consolidated Statement of Income as a
IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalising
separate line to better follow up the performance of the business.
exploration and evaluation costs until such time as the economic viability
of producing the underlying resources is determined. Costs incurred prior
An asset’s carrying amount is written down immediately to its recoverable
to obtaining legal rights to explore are expensed immediately to the
amount if the asset’s carrying amount is greater than its estimated recoverable
Consolidated Statement of Income.
amount (see Impairment of non-financial assets in Note 2.12).
Exploration and evaluation costs may include: license acquisition, geological
2.11 Provisions and other long-term liabilities
and geophysical studies (i.e.: seismic), direct labour costs and drilling costs of
Provisions for asset retirement obligations, deferred income, restructuring
exploratory wells. No depreciation and/or amortisation are charged during
obligations and legal claims are recognised when the Group has a present
the exploration and evaluation phase. Upon completion of the evaluation
legal or constructive obligation as a result of past events; it is probable that
phase, the prospects are either transferred to oil and gas properties or charged
an outflow of resources will be required to settle the obligation; and the
to expense (exploration costs) in the period in which the determination is
amount has been reliably estimated. Restructuring provisions comprise lease
made depending whether they have found reserves or not. If not developed,
termination penalties and employee termination payments.
exploration and evaluation assets are written off after three years, unless
it can be clearly demonstrated that the carrying value of the investment is
Provisions are measured at the present value of the expenditures expected to
recoverable.
be required to settle the obligation using a pre-tax rate that reflects current
market assessments of the time value of money and the risks specific to
A charge of US$ 5,834,000 has been recognised in the Consolidated Statement
the obligation. The increase in the provision due to the passage of time is
of Income within Write-off of unsuccessful exploration efforts (US$ 31,366,000
recognised as financial expense.
in 2016 and US$ 30,084,000 in 2015). See Note 20.
2.11.1 Asset Retirement Obligation
All field development costs are considered construction in progress until they
The Group records the fair value of the liability for asset retirement obligations
are finished and capitalised within oil and gas properties, and are subject to
in the period in which the wells are drilled. When the liability is initially
depreciation once completed. Such costs may include the acquisition and
recorded, the Group capitalises the cost by increasing the carrying amount of
installation of production facilities, development drilling costs (including dry
the related long-lived asset. Over time, the liability is accreted to its present
holes, service wells and seismic surveys for development purposes), project-
value at each reporting period, and the capitalised cost is depreciated over
related engineering and the acquisition costs of rights and concessions related
the estimated useful life of the related asset. According to interpretations
to proved properties.
and application of current legislation and on the basis of the changes in
technology and the variations in the costs of restoration necessary to protect
Workovers of wells made to develop reserves and/or increase production
the environment, the Group has considered it appropriate to periodically
are capitalised as development costs. Maintenance costs are charged to the
re-evaluate future costs of well-capping. The effects of this recalculation are
Consolidated Statement of Income when incurred.
included in the financial statements in the period in which this recalculation
is determined and reflected as an adjustment to the provision and the
Capitalised costs of proved oil and gas properties and production facilities and
corresponding property, plant and equipment asset.
machinery are depreciated on a licensed area by the licensed area basis, using
the unit of production method, based on commercial proved and probable
2.11.2 Deferred Income
reserves. The calculation of the “unit of production” depreciation takes into
Relates to contributions received in cash from the Group’s clients to improve
account estimated future finding and development costs and is based on
the project economics of gas wells. The amounts collected are reflected as
current year end unescalated price levels. Changes in reserves and cost
a deferred income in the balance sheet and recognised in the Consolidated
estimates are recognised prospectively. Reserves are converted to equivalent
Statement of Income over the productive life of the associated wells. The
units on the basis of approximate relative energy content.
depreciation of the gas wells that generated the deferred income is charged to
Depreciation of the remaining property, plant and equipment assets (i.e.
of the deferred income. The addition in 2016 and the amounts used in 2017
the Consolidated Statement of Income simultaneously with the amortisation
166 GeoPark 20-F
correspond to the deferred income related to the take or pay provision
first-out (FIFO) method.
associated to gas sales in Brazil.
2.15 Current and deferred income tax
2.12 Impairment of non-financial assets
The tax expense for the year comprises current and deferred tax. Tax is
Assets that are not subject to depreciation and/or amortisation (i.e.:
recognised in the Consolidated Statement of Income.
exploration and evaluation assets) are tested annually for impairment.
Assets that are subject to depreciation and/or amortisation are reviewed for
The current income tax charge is calculated on the basis of the tax laws
impairment whenever events or changes in circumstances indicate that the
enacted or substantially enacted at the balance sheet date in the countries
carrying amount may not be recoverable.
where the Company’s subsidiaries operate and generate taxable income.
The computation of the income tax expense involves the interpretation of
An impairment loss is recognised for the amount by which the asset’s carrying
applicable tax laws and regulations in many jurisdictions. The resolution of
amount exceeds its recoverable amount. The recoverable amount is the higher
tax positions taken by the Group, through negotiations with relevant tax
of an asset’s fair value less costs to sell and value in use. For the purposes
authorities or through litigation, can take several years to complete and in
of assessing impairment, assets are grouped at the lowest levels for which
some cases it is difficult to predict the ultimate outcome.
there are separately identifiable cash flows (cash-generating units), generally
a licensed area. Non-financial assets other than goodwill that suffered
Deferred income tax is recognised, using the liability method, on temporary
impairment are reviewed for possible reversal of the impairment at each
differences arising between the tax bases of assets and liabilities and their
reporting date.
carrying amounts in the Consolidated Financial Statements. Deferred income
tax is determined using tax rates (and laws) that have been enacted or
No asset should be kept as an exploration and evaluation asset for a period
substantially enacted as of the balance sheet date and are expected to apply
of more than three years, except if it can be clearly demonstrated that the
when the related deferred income tax asset is realised or the deferred income
carrying value of the investment will be recoverable.
tax liability is settled.
During 2017, no impairment loss was recognised (impairment loss reversed for
In addition, the Group has tax-loss carry-forwards in certain taxing
US$ 5,664,000 in 2016 and impairment loss recognised for US$ 149,574,000 in
jurisdictions that are available to be offset against future taxable profit.
2015). See Note 36. The write-offs are detailed in Note 20.
However, deferred tax assets are recognised only to the extent that it is
2.13 Lease contracts
probable that taxable profit will be available against which the unused
tax losses can be utilized. Management judgment is exercised in assessing
All current lease contracts are considered to be operating leases on the basis
whether this is the case. To the extent that actual outcomes differ from
that the lessor retains substantially all the risks and rewards related to the
management’s estimates, taxation charges or credits may arise in future
ownership of the leased asset. Payments related to operating leases and other
periods.
rental agreements are recognised in the Consolidated Income Statement
on a straight line basis over the term of the contract. The Group’s total
Deferred income tax liabilities are provided on taxable temporary differences
commitment relating to operating leases and rental agreements is disclosed
arising from investments in subsidiaries and joint arrangements, except
in Note 32.
for deferred income tax liability where the timing of the reversal of the
temporary difference is controlled by the Group and it is probable that the
Leases in which substantially all of the risks and rewards of ownership are
temporary difference will not reverse in the foreseeable future. The Group is
transferred to the lessee are classified as finance leases. Under a finance
able to control the timing of dividends from its subsidiaries and hence does
lease, the Group as lessor has to recognise an amount receivable equal to the
not expect taxable profit. Hence deferred tax is recognised in respect of the
aggregate of the minimum lease payments plus any unguaranteed residual
retained earnings of overseas subsidiaries only if at the date of the statements
value accruing to the lessor, discounted at the interest rate implicit in the
of financial position, dividends have been accrued as receivable or a binding
lease.
2.14 Inventories
agreement to distribute past earnings in future has been entered into by
the subsidiary. As mentioned above the Group does not expect that the
temporary differences will revert in the foreseeable future. In the event that
Inventories comprise crude oil and materials.
these differences revert in total (e.g. dividends are declared and paid), the
deferred tax liability which the Group would have to recognise amounts to
Crude oil is measured at the lower of cost and net realisable value. Materials
approximately US$ 12,300,000.
are measured at the lower of cost and recoverable amount. The cost of
materials and consumables is calculated at acquisition price with the addition
Deferred tax balances are provided in full, with no discounting.
of transportation and similar costs. Cost is determined using the first-in,
GeoPark 167
2.16 Financial assets
write-down is determined as the difference between the asset’s carrying
Financial assets are divided into the following categories: loans and
amount and the present value of estimated future cash flows.
receivables; financial assets at fair value through profit or loss; available-for-
sale financial assets; and held-to-maturity investments. Financial assets are
2.19 Cash and cash equivalents
assigned to the different categories by management on initial recognition,
Cash and cash equivalents includes cash in hand, deposits held at call with
depending on the purpose for which the investments were acquired. The
banks, other short-term highly liquid investments with original maturities
designation of financial assets is re-evaluated at every reporting date at which
of three months or less, and bank overdrafts. Bank overdrafts, if any, are
a choice of classification or accounting treatment is available.
shown within borrowings in the current liabilities section of the Consolidated
All financial assets are recognised when the Group becomes a party to the
contractual provisions of the instrument.
2.20 Trade and other payables
Statement of Financial Position.
All financial assets are initially recognised at fair value, plus transaction costs.
acquired in the ordinary course of the business from suppliers. Accounts
Derecognition of financial assets occurs when the rights to receive cash flows
less (or in the normal operating cycle of the business if longer). If not, they are
from the investments expire or are transferred and substantially all of the
presented as non-current liabilities.
risks and rewards of ownership have been transferred. An assessment for
impairment is undertaken at each balance sheet date.
Trade payables are recognised initially at fair value and subsequently
payable are classified as current liabilities if payment is due within one year or
Trade payables are obligations to pay for goods or services that have been
measured at amortised cost using the effective interest method.
Interest and other cash flows resulting from holding financial assets are
recognised in the Consolidated Statement of Income when receivable,
2.21 Derivatives
regardless of how the related carrying amount of financial assets is measured.
Derivative financial instruments are recognised in the statement of financial
Loans and receivables are non-derivative financial assets with fixed or
through profit and loss. They are presented as current assets or liabilities if they are
determinable payments that are not quoted in an active market. They are
expected to be settled within 12 months after the end of the reporting period.
position as assets or liabilities and initially and subsequently measured at fair value
included in current assets, except for maturities greater than twelve months
after the balance sheet date. These are classified as non-current assets. The
The market-to-market fair value of the Group’s outstanding derivative instruments
Group’s loans and receivables comprise trade receivables, prepayments
is based on independently provided market rates and determined using standard
and other receivables and cash and cash equivalents in the balance sheet.
valuation techniques, including the impact of counterparty credit risk and are
They arise when the Group provides money, goods or services directly to a
within level 2 of the fair value hierarchy. Gains and losses arising from changes
debtor with no intention of trading the receivables. Loans and receivables are
in fair value are recognised in the Consolidated Statement of Income within
subsequently measured at amortised cost using the effective interest method,
Commodity risk management contracts.
less provision for impairment. Any change in their value through impairment
or reversal of impairment is recognised in the Consolidated Statement of
For more information about derivatives please refer to Note 8.
Income. All of the Group’s financial assets are classified as loan and receivables.
2.22 Borrowings
2.17 Other financial assets
Borrowings are obligations to pay cash and are recognised when the Group
Non current other financial assets include contributions made for
becomes a party to the contractual provisions of the instrument.
environmental obligations according to a Colombian and Brazilian
government request and are restricted for those purposes.
Borrowings are recognised initially at fair value, net of transaction costs
Current other financial assets include the security deposit granted in
between the proceeds (net of transaction costs) and the redemption value is
relation to the purchase of Argentinian assets (see Note 35) and short term
recognised in the Consolidated Statement of Income over the period of the
investments with original maturities up to twelve months and over three
borrowings using the effective interest method.
incurred. Borrowings are subsequently stated at amortised cost; any difference
months.
2.18 Impairment of financial assets
accruals basis using the effective interest method.
Direct issue costs are charged to the Consolidated Statement of Income on an
Provision against trade receivables is made when objective evidence is
received that the Group will not be able to collect all amounts due to it in
accordance with the original terms of those receivables. The amount of the
168 GeoPark 20-F
2.23 Share capital
Equity comprises the following:
Note 3
Financial Instruments-risk management
• “Share capital” representing the nominal value of equity shares.
The Group is exposed through its operations to the following financial risks:
• “Share premium” representing the excess over nominal value of the fair
value of consideration received for equity shares, net of expenses of the share
• Currency risk
issuance.
• “Other reserve” representing:
• Price risk
• Credit risk – concentration
– the equity element attributable to shares granted according to IFRS 2 but
• Funding and liquidity risk
not issued at year end or,
• Interest rate risk
– the difference between the proceeds from the transaction with non-
• Capital risk management
controlling interests received against the book value of the shares acquired
in the Chilean and Colombian subsidiaries.
The policy for managing these risks is set by the Board of Directors. Certain
• “Translation reserve” representing the differences arising from translation of
risks are managed centrally, while others are managed locally following
investments in overseas subsidiaries.
guidelines communicated from the corporate department. The policy for each
• “(Accumulated losses) Retained earnings” representing accumulated
of the above risks is described in more detail below.
earnings and losses.
Currency risk
2.24 Share-based payment
In Argentina, Colombia, Chile and Peru the functional currency is the US Dollar.
The Group operates a number of equity-settled and cash-settled share-based
The fluctuation of the local currencies of these countries against the US Dollar
compensation plans comprising share awards payments to certain employees
does not impact the loans, costs and revenue held in US Dollars; but it does
and other third party contractors. Share-based payment transactions are
impact the balances denominated in local currencies. Such is the case of the
measured in accordance with IFRS 2.
prepaid taxes.
Fair value of the stock option plan for employee or contractors services
In Chile, Colombia and Argentina subsidiaries most of the balances are
received in exchange for the grant of the options is recognised as an expense.
denominated in US Dollars, and since it is the functional currency of the
The total amount to be expensed over the vesting period is determined
subsidiaries, there is no exposure to currency fluctuation except from
by reference to the fair value of the options granted calculated using the
receivables or payables originated in local currency mainly corresponding to
Geometric Brownian Motion method.
VAT.
Non-market vesting conditions are included in assumptions about the
The Group minimises the local currency positions in Argentina, Colombia and
number of options that are expected to vest. At each balance sheet date, the
Chile by seeking to equilibrate local and foreign currency assets and liabilities.
entity revises its estimates of the number of options that are expected to
However, tax receivables (VAT) seldom match with local currency liabilities.
vest. It recognises the impact of the revision to original estimates, if any, in
Therefore the Group maintains a net exposure to them.
the Consolidated Statement of Income, with a corresponding adjustment to
equity.
Most of the Group’s assets held in those countries are associated with oil and
gas productive assets. Those assets, even in the local markets, are generally
The fair value of the share awards payments is determined at the grant date
settled in US Dollar equivalents.
by reference of the market value of the shares and recognised as an expense
over the vesting period. When the awards are exercised, the Company issues
During 2017, the Argentine Peso devaluated by 17% (22% and 52% in
new shares. The proceeds received net of any directly attributable transaction
2016 and 2015) against the US Dollar, the Chilean Peso revaluated by 8%
costs are credited to share capital (nominal value) and share premium when
(revaluated by 6% in 2016 and devaluated by 16% in 2015) and the Colombian
the options are exercised.
Peso revaluated by 1% (revaluated by 5% in 2016 and devaluated by 32% in
For cash-settled share-based payment transactions, if any, the Company
2015).
measures the services acquired for amounts that are based on the price of the
If the Argentine Peso, the Chilean Peso and the Colombian Peso had each
Company’s shares. The fair value of the liability incurred is measured using
devaluated an additional 10% against the US dollar, with all other variables
Geometric Brownian Motion method. Until the liability is settled, the Company
held constant, post-tax loss for the year would have been higher by
is required to remeasure the fair value of the liability at each reporting date
US$ 1,538,000 (US$ 2,683,400 in 2016 and US$ 1,003,300 in 2015).
and at the date of settlement, with any changes in value recognised in profit
or loss for the period.
In Brazil, the functional currency is the local currency, which is the Brazilian
GeoPark 169
Real. The fluctuation of the US Dollars against the Brazilian Real does not
inflation pursuant to the Brazilian General Market Price Index (Indice Geral
impact the loans, costs and revenues held in Brazilian Real; but it does
de Preços do Mercado), or IGPM.
impact the balances denominated in US Dollars. Such is the case of the Itaú,
which was fully repaid in September 2017, and intercompany loans. Most of
If oil and methanol prices had fallen by 10% compared to actual prices
the balances are denominated in Brazilian Real, and since it is the functional
during the year, with all other variables held constant, considering the
currency of the Brazilian subsidiary, there is no exposure to currency
impact of the derivative contracts in place, post-tax loss for the year
fluctuation except from the intercompany loan and the Itaú loan described
would have been higher by US$ 10,423,000 (US$ 23,655,000 in 2016 and
in Note 27. The exchange loss generated by the Brazilian subsidiary during
US$ 23,940,000 in 2015).
2017 amounted to US$ 1,274,000 (gain of US$ 14,542,000 in 2016 and loss of
US$ 35,605,000 in 2015).
As of October 2016, GeoPark considered it was appropriate to manage
part of the exposure to crude oil price volatility using derivatives. The
During 2017, the Brazilian Real devaluated by 2% against the US Dollar
Group considers these derivative contracts to be an effective manner of
(revaluated by 17% in 2016 and devaluated by 47% in 2015, respectively). If
properly managing commodity price risk. The price risk management
the Brazilian Real had devaluated 10% against the US dollar, with all other
activities mainly employ combinations of options and key parameters are
variables held constant, post-tax loss for the year would have been higher by
based on forecasted production and budget price levels. GeoPark has also
US$ 3,100,000 (US$ 5,300,000 in 2016 and US$ 7,400,000 in 2015).
obtained credit lines from industry leading counterparties to minimize
the potential cash exposure of the derivative contracts (see Note 8).
As of 31 December 2017, the balances denominated in the Peruvian local
currency (Peruvian Soles) are not material.
Credit risk – concentration
As currency rate changes between the US Dollar and the local currencies, the
credit risks correspond to the recognised values. There is not considered
Group recognises gains and losses in the Consolidated Statement of Income.
to be any significant risk in respect of the Group’s major customers and
The Group’s credit risk relates mainly to accounts receivable where the
hedging counterparties.
Price risk
The price realised for the oil produced by the Group is linked to US dollar
In Colombia, during 2017, the Colombian subsidiary made 99% of the oil
denominated crude oil international benchmarks. The market price of
sales to Trafigura (one of the world’s leading independent commodity
these commodities is subject to significant volatility and has historically
trading and logistics houses), with Trafigura accounting for 79% of
fluctuated widely in response to relatively minor changes in the global
consolidated revenues for the same period.
supply and demand for oil and natural gas, geopolitical landscape,
economic conditions and a variety of additional factors.
All the oil produced in Chile as well as the gas produced by TdF Blocks
(5% of total revenue, 10% in 2016 and 15% in 2015) is sold to ENAP, the
In Colombia, the realised oil price is linked to the Vasconia crude reference
State owned oil and gas company. In Chile, most of gas production is sold
price, a marker broadly used in the Llanos basin, adjusted for certain
to the local subsidiary of Methanex, a Canadian public company (5% of
marketing and quality discounts based on, among other things, API,
consolidated revenue, 9% in 2016 and 7% in 2015).
viscosity, sulphur content, water content, delivery point and transport
costs.
In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the
State owned company, which is the operator of the Manati Field (10% of the
In Chile, the oil price is based on Dated Brent minus certain marketing and
consolidated revenue, 15% in 2016 and 2015).
quality discounts such as, API, sulphur content and others.
GeoPark has signed a long-term Gas Supply Contract with Methanex in
the concentration of the credit risk, the Directors do not consider there to
The forementioned companies all have good credit standing and despite
Chile. The price of the gas sold under this contract is determined by a
be a significant collection risk.
formula that considers a basket of international methanol prices, including
US Gulf methanol spot barge prices, methanol spot Rotterdam prices and
In 2016 and 2017, the Group executed oil prices hedges via over-the-
spot prices in Asia.
counter derivatives. Should oil prices drop, the Group could stand to collect
from its counterparties under the derivative contracts. The Group’s hedging
In Brazil, prices for gas produced in the Manati Field are based on a long-
counterparties are leading financial institutions and trading companies,
term off-take contract with Petrobras. The price of gas sold under this
therefore the Directors do not consider there to be a significant collection
contract is denominated in Brazilian Real and is adjusted annually for
risk.
See disclosure in Notes 8 and 25.
170 GeoPark 20-F
Funding and Liquidity risk
The Group analyses its interest rate exposure on a dynamic basis. Various
In the past, the Group was able to raise capital through different sources of
scenarios are simulated taking into consideration refinancing, renewal
funding including equity, strategic partnerships and financial debt. During
of existing positions, alternative financing and hedging. Based on these
2017, the Group placed US$ 425,000,000 notes (see Note 27).
scenarios, the Group calculates the impact on profit and loss of a defined
The Group is positioned at the end of 2017 with a cash balance of US$
all currencies. The scenarios are run only for liabilities that represent the major
interest rate shift. For each simulation, the same interest rate shift is used for
134,755,000 and over 99% of its total indebtedness maturing in 2024. In
interest-bearing positions.
addition, the Group has a large portfolio of attractive and largely discretional
projects - both oil and gas - in multiple countries with over 31,000 boepd in
At 31 December 2017, the Group has no exposure to fluctuations in the
production at year end. This scale and positioning permit the Group to protect
interest rate, since its long-term borrowings were issued at fixed rate. At
its financial condition and selectively allocate capital to the optimal projects
31 December 2016 and 2015, if 1% had been added to interest rates on
subject to prevailing macroeconomic conditions.
currency-denominated borrowings with all other variables held constant, post
tax loss for the year would have been US$ 467,000 and US$ 507,000 higher,
The indenture governing the Company Notes 2024 includes incurrence test
respectively.
covenants related to the compliance with certain thresholds of Net Debt to
Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply
Capital risk management
with the incurrence test covenants does not trigger an event of default.
The Group’s objectives when managing capital are to safeguard the Group’s
However, this situation may limit the Group’s capacity to incur additional
ability to continue as a going concern in order to provide returns for
indebtedness, as specified in the indenture governing the Notes. As of the
shareholders and benefits for other stakeholders and to maintain an optimal
date of these Consolidated Financial Statements, the Group is in compliance
capital structure to reduce the cost of capital.
with all the indenture’s provisions and covenants.
The most significant funding transactions executed in 2017, 2016 and 2015
of the gearing ratio. This ratio is calculated as net debt divided by total capital.
Consistent with others in the industry, the Group monitors capital on the basis
include:
Net debt is calculated as total borrowings (including ‘current and non-current
borrowings’ as shown in the consolidated balance sheet) less cash and cash
On September 2017, the Group successfully placed US$ 425,000,000 notes.
equivalents. Total capital is calculated as ‘equity’ as shown in the consolidated
These Notes carry a coupon of 6.50% per annum and their final maturity will
balance sheet plus net debt.
be 21 September 2024. The net proceeds from the Notes were used by the
Group to fully repay the 7.50% senior secured notes due 2020 and for general
The Group’s strategy is to keep the gearing ratio within a 30% to 45% range,
corporate purposes, including capital expenditures and repay other existing
in normal market conditions. Due to the market conditions prevailing during
indebtedness.
2017 and 2016 and the growing strategy of the Group, the gearing ratio at
On December 2015, the Group announced the execution of an offtake and
prepayment agreement with Trafigura, one of its customers. The prepayment
The gearing ratios at 31 December 2017 and 2016 were as follows:
year end is above such range.
agreement provided GeoPark with access to up to US$ 100,000,000 in the
form of prepaid future oil sales. The availability period for the prepayment
Amounts in US$ ‘000
agreement expired on 30 September 2017. Funds committed by Trafigura
are being repaid by the Group through future oil deliveries over 2.5 years
Net Debt
Total Equity
with a six-month grace period. As of the date of these Consolidated Financial
Total Capital
Statements, outstanding balances related to the prepayment agreement
Gearing Ratio
2017
291,449
126,840
418,289
70%
2016
285,109
141,593
426,702
67%
amount to US$ 10,000,000.
Interest rate risk
Note 4
4. Accounting estimates and assumptions
The Group’s interest rate risk arises from long-term borrowings issued at
Estimates and assumptions are used in preparing the financial statements.
variable rates, which expose the Group to cash flow to interest rate risk.
Although these estimates are based on management’s best knowledge of
The Group does not face interest rate risk on its US$ 425,000,000 Notes which
and judgements are continually evaluated and are based on historical
carry a fixed rate coupon of 6.50% per annum. As a consequence, the accruals
experience and other factors, including expectations of future events that
and interest payment are no substantially affected to the market interest rate
are believed to be reasonable under the circumstances.
current events and actions, actual results may differ from them. Estimates
changes.
GeoPark 171
The key estimates and assumptions used in these Consolidated Financial
proven and probable reserves and incorporating the estimated future cost
Statements are noted below:
of developing and extracting those reserves. Future development costs are
estimated using assumptions as to the numbers of wells required to produce
• Cash flow estimates for impairment assessments of non-financial
those reserves, the cost of the wells and future production facilities.
assets require assumptions about two primary elements - future prices
and reserves. Estimates of future prices require significant judgments
• Obligations related to the abandonment of wells once operations are
about highly uncertain future events. Historically, oil and gas prices
terminated may result in the recognition of significant obligations. Estimating
have exhibited significant volatility. The Group’s forecasts for oil and gas
the future abandonment costs is difficult and requires management to
revenues are based on prices derived from future price forecasts amongst
make estimates and judgments because most of the obligations are many
industry analysts and own assessments. Estimates of future cash flows are
years in the future. Technologies and costs are constantly changing as well
generally based on assumptions of long-term prices and operating and
as political, environmental, safety and public relations considerations. The
development costs.
Group has adopted the following criterion for recognising well plugging and
abandonment related costs: The present value of future costs necessary for
Given the significant assumptions required and the possibility that actual
well plugging and abandonment is calculated for each area at the present
conditions will differ, management considers the assessment of impairment
value of the estimated future expenditure. The liabilities recognised are based
to be a critical accounting estimate (see Note 36).
upon estimated future abandonment costs, wells subject to abandonment,
time to abandonment, and future inflation rates.
The process of estimating reserves is complex. It requires significant
judgements and decisions based on available geological, geophysical,
• From time to time, the Group may be subject to various lawsuits, claims
engineering and economic data. The estimation of economically
and proceedings that arise in the normal course of business, including
recoverable oil and natural gas reserves and related future net cash flows
employment, commercial, tax, environmental, safety and health matters.
was performed based on the Reserve Report as of 31 December 2017
For example, from time to time, the Group receives notice of environmental,
prepared by DeGolyer and MacNaughton, an international consultancy to
health and safety violations. Based on what the Management of the Group
the oil and gas industry based in Dallas. It incorporates many factors and
currently knows, it is not expected any material impact on the financial
assumptions including:
statements.
– expected reservoir characteristics based on geological, geophysical and
Note 5
engineering assessments;
Consolidated Statement of Cash Flow
– future production rates based on historical performance and expected
The Consolidated Statement of Cash Flow shows the Group’s cash flows for the
future operating and investment activities;
year for operating, investing and financing activities and the change in cash
– future oil and gas prices and quality differentials;
and cash equivalents during the year.
– assumed effects of regulation by governmental agencies; and
– future development and operating costs.
Cash flows from operating activities are computed from the results for the
year adjusted for non-cash operating items, changes in net working capital,
Management believes these factors and assumptions are reasonable based
and corporate tax. Income tax paid is presented as a separate item under
on the information available to them at the time of preparing the estimates.
operating activities.
However, these estimates may change substantially as additional data from
ongoing development activities and production performance becomes available
Cash flows from investing activities include payments in connection with the
and as economic conditions impacting oil and gas prices and costs change.
purchase and sale of property, plant and equipment and cash flows relating to
the purchase and sale of enterprises to third parties, if any.
• The Group adopts the successful efforts method of accounting. The
Management of the Group makes assessments and estimates regarding
Cash flows from financing activities include changes in equity, and proceeds
whether an exploration asset should continue to be carried forward as an
from borrowings and repayment of loans.
exploration and evaluation asset not yet determined or when insufficient
information exists for this type of cost to remain as an asset. In making this
Cash and cash equivalents include bank overdraft and liquid funds with a term
assessment Management takes professional advice from qualified experts.
of less than three months.
• Oil and gas assets held in property plant and equipment are mainly
The following chart describes non-cash transactions related to the
depreciated on a unit of production basis at a rate calculated by reference to
Consolidated Statement of Cash Flow:
172 GeoPark 20-F
Amounts in US$ ‘000
Increase in asset retirement obligation
2017
5,943
Increase in provisions for other long-term liabilities
2,053
2016
1,195
3,468
2015
985
Amounts in US$ ‘000
-
Increase in Prepaid taxes
Purchase of property, plant and equipment
11,759
(4,657)
830
(Increase) Decrease in Inventories
(Increase) Decrease in Trade receivables
(Increase) Decrease in Prepayments and
2017
2016
2015
(14,802)
(2,351)
(16,611)
(2,031)
(1,344)
466
(4,811)
2,752
22,470
Statement of Cash Flow are disclosed as follows:
Changes in working capital shown in the Consolidated
Note 6
Segment information
other receivables and Other assets
(8,623)
Customer advance (repayments) payments
(10,000)
Security deposit granted (Note 35)
(15,600)
(1,758)
20,000
-
405
-
-
Increase (Decrease) in Trade
and other payables
27,122
374
(33,120)
(25,278)
11,920
(24,104)
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-
maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This
committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance, Finance and People departments.
This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments
based on these reports. The committee considers the business from a geographic perspective.
The Executive Committee assesses the performance of the operating segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit for
the period before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful efforts,
accrual of share-based payment, unrealized result on commodity risk management contracts and other non recurring events. Operating Netback is equivalent to
Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical and Other operating expenses. Other information provided, except
as noted below, to the Executive Committee is measured in a manner consistent with that in the financial statements.
Segment areas (geographical segments):
Amounts in US$ ‘000
2017
Revenue
Sale of crude oil
Sale of gas
Realized loss on commodity risk management contracts
Production and operating costs
Royalties
Transportation costs
Share-based payment
Other costs
Operating (loss) profit
Operating netback
Adjusted EBITDA
Depreciation
Write-off
Total assets
Employees (average)
Employees at year end
Chile
Brazil
Colombia
Peru
Argentina
Corporate
Total
32,738
15,873
16,865
-
34,238
263,076
910
262,309
33,328
-
767
(2,148)
(20,999)
(10,737)
(66,913)
(3,134)
(24,236)
(1,314)
(1,211)
(170)
(18,304)
(19,675)
11,222
4,070
-
(39)
(7,564)
4,434
23,540
20,166
(23,730)
(10,809)
(546)
301,931
(2,978)
91,604
(1,678)
(248)
(40,751)
116,290
194,013
168,303
(40,010)
(1,625)
288,429
-
-
-
-
-
-
-
-
-
70
70
-
-
(338)
(13)
(80)
-
(245)
-
-
-
-
-
-
-
-
-
(3,850)
(3,430)
(14,773)
-
(467)
-
(3,505)
(2,183)
(11,075)
(139)
-
(159)
(685)
(38)
-
22,099
30,924
51,176
330,122
279,162
50,960
(2,148)
(98,987)
(28,697)
(2,969)
(457)
(66,864)
78,996
228,308
175,776
(74,885)
(5,834)
786,163
102
102
12
12
164
180
13
19
88
92
-
-
379
405
GeoPark 173
Amounts in US$ ‘000
2016
Revenue
Sale of crude oil
Sale of gas
Realized gain on commodity risk management contracts
Production and operating costs
Royalties
Transportation costs
Share-based payment
Other costs
Operating (loss) profit
Operating netback
Adjusted EBITDA
Depreciation
Reversal of impaiment losses
Write-off
Total assets
Employees (average)
Employees at year end
Amounts in US$ ‘000
2015
Revenue
Sale of crude oil
Sale of gas
Production costs
Royalties
Transportation costs
Share-based payment
Other costs
Operating (loss) profit
Operating netback
Adjusted EBITDA
Depreciation
Impairment loss
Write-off
Total assets
Employees (average)
Employees at year end
Chile
Brazil
Colombia
Peru
Argentina
Corporate
Total
36,723
18,774
17,949
-
(22,169)
(1,495)
(1,170)
(138)
(19,366)
(44,969)
13,696
5,159
29,719
126,228
688
125,731
29,031
-
(8,459)
(2,721)
-
(71)
(5,667)
(645)
21,356
17,487
497
514
(36,607)
(7,281)
(1,111)
(413)
(27,802)
31,463
87,523
66,921
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(3,147)
41
(2,607)
370
(11,685)
(378)
1,848
(91)
(10,487)
192,670
145,193
47,477
514
(67,235)
(11,497)
(2,281)
(622)
(52,835)
(28,613)
122,147
78,321
(31,355)
(12,974)
(31,148)
(130)
(150)
(17)
(75,774)
-
(19,389)
317,969
102
102
-
(4,583)
99,904
5,664
(7,394)
182,784
-
-
-
-
-
-
5,020
6,071
28,792
5,664
(31,366)
640,540
10
10
138
146
11
10
80
77
-
-
341
345
Chile
Brazil
Colombia
Peru
Argentina
Corporate
Total
32,388
131,897
955
131,897
44,808
29,180
15,628
(28,704)
(1,973)
(2,441)
(132)
(24,158)
(180,264)
15,254
(183)
31,433
(8,056)
(2,998)
-
-
(5,058)
6,639
24,393
20,460
(39,227)
(13,568)
(104,515)
(25,751)
381,143
-
-
114,974
-
(48,534)
(8,150)
(2,068)
(234)
(38,082)
(37,227)
80,355
66,736
(52,434)
(45,059)
(4,333)
153,071
-
-
-
-
-
-
-
-
(6,719)
44
(6,520)
597
597
-
(1,448)
(34)
(2)
(197)
(1,215)
(2,350)
(1,732)
(684)
-
-
-
-
-
-
-
-
209,690
162,629
47,061
(86,742)
(13,155)
(4,511)
(563)
(68,513)
(12,570)
(232,491)
(287)
118,027
(6,022)
73,787
(129)
(199)
-
-
-
-
-
-
-
4,287
3,181
47,143
(105,557)
(149,574)
(30,084)
703,799
153
106
11
12
130
133
16
11
93
90
-
-
403
352
Approximately 76% of capital expenditure was incurred by Colombia (67% in 2016 and 66% in 2015), 10% was incurred by Chile (20% in 2016 and 22% in 2015),
8% was incurred by Argentina (4% in 2016 and nil in 2015), 3% was incurred by Brazil (9% in 2016 and 12% in 2015) and 3% was incurred by Peru (nil in 2016 and
2015).
174 GeoPark 20-F
A reconciliation of total Operating netback to total profit (loss) before income
Note 7
tax is provided as follows:
Amounts in US$ ‘000
Operating netback
Administrative expenses
Geological and geophysical expenses
Adjusted EBITDA
Revenue
2017
2016
2015
Amounts in US$ ‘000
228,308
122,147
118,027
Sale of crude oil
(38,937)
(13,595)
(32,323)
(11,503)
(30,590)
Sale of gas
(13,650)
2017
279,162
50,960
2016
145,193
47,477
2015
162,629
47,061
330,122
192,670
209,690
for reportable segments
175,776
78,321
73,787
Unrealized loss on commodity
risk management contracts
Depreciation (a)
Share-based payment
Impairment and write-off
of unsuccessful efforts
Others (b)
Operating profit (loss)
Financial expenses
Financial income
Foreign exchange (loss) profit
Profit (Loss) before tax
(13,300)
(74,885)
(4,075)
(5,834)
1,314
78,996
(53,511)
2,016
(2,193)
25,308
(3,068)
-
Note 8
(75,774)
(105,557)
Commodity risk management contracts
(3,367)
(8,223)
The Group has entered into derivative financial instruments to manage its
exposure to oil price risk. These derivatives are zero-premium collars or zero-
(25,702)
(179,658)
premium 3 ways (put spread plus call), and were placed with major financial
977
(12,840)
institutions and commodity traders. The Group entered into the derivatives
(28,613)
(232,491)
under ISDA Master Agreements and Credit Support Annexes, which provide
(36,229)
(36,924)
credit lines for collateral posting thus alleviating possible liquidity needs
2,128
13,872
1,269
under the instruments and protect the Group from potential non-performance
(33,474)
risk by its counterparties. The Group’s derivatives are accounted for as non-
(48,842)
(301,620)
hedge derivatives as of 31 December 2017 and therefore all changes in the fair
values of its derivative contracts are recognised as gains or losses in the results
(a) Net of capitalised costs for oil stock included in Inventories.
(b) In 2015 includes termination costs (see Note 36). Also includes internally
capitalised costs.
The following table presents the Group’s derivative contracts in force as of 31
of the periods in which they occur.
December 2017:
Period
1 October 2017 - 31 March 2018
1 October 2017 - 31 March 2018
1 January 2018 - 30 June 2018
1 January 2018 - 30 June 2018
1 April 2018 - 30 June 2018
1 January 2018 - 30 June 2018
1 January 2018 - 30 June 2018
1 April 2018 - 30 June 2018
1 January 2018 - 30 June 2018
1 July 2018 - 30 September 2018
Reference
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
Type
Volume bbl/d
Price US$/bbl
Zero Premium Collar
Zero Premium Collar
Zero Premium Collar
Zero Premium Collar
Zero Premium Collar
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
4,000
2,000
2,000
1,000
2,000
1,000
1,000
1,000
2,000
5,000
50.00 Put 54.90 Call
50.00 Put 54.95 Call
52.00 Put 60.00 Call
52.00 Put 58.40 Call
52.00 Put 58.25 Call
42.00-52.00 Put 59.55 Call
42.00-52.00 Put 59.50 Call
42.00-52.00 Put 59.60 Call
43.00-53.00 Put 64.55 Call
43.00-53.00 Put 69.00 Call
The table below summarizes the gain (loss) on the commodity risk management contracts:
Realized (loss) gain on commodity risk management contracts
Unrealized loss on commodity risk management contracts
Total
2017
(2,148)
(13,300)
(15,448)
2016
514
(3,068)
(2,554)
2015
-
-
-
GeoPark 175
Note 9
Production and operating costs
Amounts in US$ ‘000
Well and facilities maintenance
Staff costs (Note 11)
Share-based payment (Notes 11)
Royalties
Consumables
Transportation costs
Equipment rental
Safety and Insurance costs
Gas plant costs
Field camp
Non operated blocks costs
Other costs
Note 10
Depreciation
Amounts in US$ ‘000
Oil and gas properties
Production facilities and machinery
Furniture, equipment and vehicles
Buildings and improvements
Depreciation of property,
plant and equipment (a)
Related to:
Productive assets
Administrative assets
Depreciation total (a)
Directors’ Remuneration
Note 11
Staff costs and Directors Remuneration
2015
19,974
17,999
Number of employees at year end
Amounts in US$ ‘000
2017
405
2016
345
2015
352
563
Wages and salaries
44,891
36,059
40,574
2017
14,722
15,017
457
28,697
11,902
2,969
5,818
2,591
6,069
2,377
1,213
7,155
2016
13,160
10,859
622
11,497
8,283
2,281
3,868
2,222
6,300
1,687
1,082
5,374
13,155
Share-based payments (Note 30)
8,591
4,511
3,517
3,239
2,878
2,645
2,127
7,543
Social security charges
Director’s fees and allowance
Recognised as follows:
Production and operating costs
Geological and geophysical expenses
Administrative expenses
98,987
67,235
86,742
Board of Directors’ and key
managers’ remuneration
Salaries and fees
2015
Share-based payments
Other benefits in kind
84,849
15,467
2,850
874
2017
57,725
14,558
1,948
844
2016
61,080
10,788
2,702
920
4,075
5,364
3,458
3,367
3,792
2,088
8,223
6,197
1,238
57,788
45,306
56,232
15,474
11,026
31,288
57,788
11,481
10,439
23,386
45,306
18,562
11,336
26,334
56,232
9,674
2,322
287
12,283
7,337
1,211
112
8,660
6,549
6,544
167
13,260
75,075
75,490
104,040
72,283
2,792
75,075
71,868
3,622
100,316
3,724
75,490
104,040
(a) Depreciation without considering capitalised costs for oil stock
included in Inventories.
Executive Directors’
Executive Directors’
Non-Executive
Director Fees Paid in
Cash Equivalent
Fees
Bonus
Directors’ Fees (in US$)
Shares (No. of Shares)
Total Remuneration
Gerald O’Shaughnessy
James F. Park
Pedro Aylwin (a)
Peter Ryalls (b)
Juan Cristóbal Pavez (c)
Carlos Gulisano
Robert Bedingfield (d)
Michael Dingman
Jamie Coulter
US$ 400,000
US$ 800,000
-
US$ 800,000
-
-
-
-
-
-
-
-
-
-
-
-
-
US$ 115,000
US$ 110,000
US$ 110,000
US$ 102,500
US$ 46,667
US$ 50,000
-
-
-
9,388
15,408
15,408
15,408
8,853
8,015
US$ 400,000
US$ 1,600,000
-
US$ 165,010
US$ 210,020
US$ 210,020
US$ 202,520
US$ 105,012
US$ 112,519
a Pedro Aylwin has a service contract that provides for him to act as Manager of Corporate Governance so he resigned his fees as Director. b Technical Committee
Chairman until his death. Afterwards the Chairman is Carlos Gulisano. c Compensation Committee Chairman. d Audit Committee Chairman.
176 GeoPark 20-F
The non-executive Directors annual fees correspond to US$ 80,000 to be
Note 15
settled in cash and US$ 100,000 to be settled in stocks, paid quarterly in equal
Financial costs
installments. In the event that a non-executive Director serves as Chairman
of any Board Committees, an additional annual fee of US$ 20,000 shall apply.
Amounts in US$ ‘000
2017
2016
2015
A Director who serves as a member of any Board Committees shall receive
Financial expenses
an annual fee of US$ 10,000. Total payment due shall be calculated in an
Interest and amortisation
aggregate basis for Directors serving in more than one Committee. The
of debt issue costs
Chairman fee shall not be added to the member’s fee for the same Committee.
Interest with related parties
Payments of Chairmen and Committee members’ fees shall be made quarterly
Less: amounts capitalised
in arrears and settled in cash only.
Note 12
on qualifying assets
Borrowings cancellation costs
Bank charges and other financial costs
Unwinding of long-term liabilities
Geological and geophysical expenses
(Note 28)
Amounts in US$ ‘000
Staff costs (Note 11)
Share-based payment (Notes 11)
Allocation to capitalised project
Other services
2017
10,525
501
(6,402)
3,070
7,694
2016
9,541
898
(2,119)
1,962
10,282
2015
Financial income
10,557
Interest received
779
(598)
3,093
13,831
Foreign exchange gains and losses
Foreign exchange (loss) gain
Total Financial results
(27,823)
(2,224)
(28,984)
(1,587)
(28,983)
(1,560)
611
(17,575)
(3,721)
255
-
637
-
(3,220)
(4,443)
(2,779)
(2,693)
(2,575)
(53,511)
(36,229)
(36,924)
2,016
2,016
2,128
2,128
1,269
1,269
(2,193)
(2,193)
13,872
13,872
(53,688)
(20,229)
(33,474)
(33,474)
(69,129)
Note 13
Administrative expenses
Amounts in US$ ‘000
Staff costs (Note 11)
Share-based payment (Notes 11)
Consultant fees
Office expenses
Travel expenses
Director’s fees and allowance (Note 11)
Communication and IT costs
Allocation to joint operations
Other administrative expenses
Note 14
Selling expenses
Amounts in US$ ‘000
Transportation
Selling taxes and other
Note 16
Tax reforms in Colombia
2017
24,713
3,117
5,120
2,506
2,772
3,458
2,109
(7,646)
5,905
42,054
2016
19,451
1,847
3,894
2,217
1,717
2,088
2,013
(4,365)
5,308
34,170
2015
A tax reform has been enacted in Colombia during December 2016. The
18,215
legislation included significant changes to certain corporate income tax and
statutory income tax provisions, including rate reductions and the repeal of
certain corporate-level taxes. The legislation also aimed to raise tax revenue
mostly by increasing the rate of the value added tax (VAT) to 19% (from
16%) and through a variety of excise taxes. Most of the tax provisions were
effective 1 January 2017.
6,881
4,115
2,535
1,497
1,238
1,791
(4,203)
The legislation also included the following provisions that are intended to
5,402
simplify the corporate income tax system by:
37,471
• Eliminating the “CREE” tax on corporations and the CREE surtax (CREE is the
Spanish acronym for the “fairness tax”).
• Introducing a temporary income surtax of 6% for 2017 and 4% for 2018.
2017
864
272
1,136
2016
3,559
663
4,222
2015
4,760
451
5,211
Accordingly, with this tax reform, the corporate income tax will have the
following rate schedule (applied beyond a limited profit threshold):
– 40% in 2017 (34% income tax plus 6% income surtax)
– 37% in 2018 (33% income tax plus 4% income surtax)
– 33% in 2019.
There is an increase in the tax rate on deemed income relating to increases in
a taxpayer’s net worth (i.e., the increase in the value of a taxpayer’s assets); the
rate is increased from 3% to 3.5%.
GeoPark 177
Other changes to the income tax law are the following:
• New withholding tax on dividends—with the applicable rates for
non-resident shareholders of: (1) 5% for dividends distributed out of the
Note 17
Income tax
distributing entity’s previously taxed profits; and (2) 35% for dividends
Amounts in US$ ‘000
distributed out of the distributing entity’s previously untaxed profits, plus an
Current tax
additional 5% after having applied and deducted the initial 35% withholding.
Deferred income tax (Note 18)
• A general 15% withholding tax rate for taxable income accrued by non-
residents without a permanent establishment (certain special rates may
2017
2016
(48,449)
(12,359)
5,304
555
(43,145)
(11,804)
2015
(7,262)
24,316
17,054
apply).
The tax on the Group’s profit (loss) before tax differs from the theoretical
• Lengthen the statute of limitations with respect to tax returns and
amount that would arise using the weighted average tax rate applicable to
assessments.
• Limit loss carryforwards to 12 years.
• Allow for a deduction of VAT paid on certain acquisitions or imports of
profits of the consolidated entities as follows:
capital goods when calculating the taxpayer’s income tax liability.
Amounts in US$ ‘000
• Retain the tax on long-term capital gains at 10% for both corporations and
Profit (loss) before tax
2017
25,308
2016
2015
(48,842)
(301,620)
non-residents.
Tax losses
from non-taxable jurisdictions
The legislation also revises and refines tax accounting standards based on
Taxable loss (profit)
22,708
48,016
12,318
15,852
(36,524)
(285,768)
IFRS rules.
Tax reforms in Argentina
Income tax calculated at domestic
tax rates applicable to Profit (Losses)
A tax reform has been enacted in Argentina during December 2017. The
in the respective countries
(31,107)
(809)
62,589
legislation included significant changes to certain corporate income tax and
Tax losses where no deferred
statutory income tax provisions, including rate reductions. Most of the tax
income tax is recognised
provisions are effective from fiscal year 2018.
Effect of currency translation on tax base
Changes in the income tax rate
With this tax reform, the corporate income tax -previously 35%- will have the
(Note 16)
following rate schedule:
• 30% in 2018 and 2019
• 25% in 2020 and 2021 and onwards.
Non recoverable tax loss carry-forwards
Non-taxable results (a)
Income tax
(8,111)
(2,330)
(6,616)
(2,840)
(16,325)
(6,776)
542
-
220
-
(2,139)
(1,759)
(43,145)
(11,804)
(625)
(15,537)
(6,272)
17,054
Other changes include the following:
• New withholding tax on dividends—with the applicable rates for
non-resident shareholders of: (1) 7% for dividends distributed out of the
(a) Includes non-deductible expenses in each jurisdiction and changes in the
estimation of deferred tax assets and liabilities.
distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and
Under current Bermuda law, the Company is not required to pay any taxes
(2) 13% for dividends distributed out of the distributing entity’s previously
in Bermuda on income or capital gains. The Company has received an
taxed profits of fiscal years 2020 and onwards.
undertaking from the Minister of Finance in Bermuda that, in the event of
• Application of inflation adjustment for corporate tax purposes is reinstated
any taxes being imposed, they will be exempt from taxation in Bermuda until
under certain circumstances.
March 2035. Income tax rates in those countries where the Group operates
• Possible tax revaluation of investment in fixed assets, under payment of a
(Argentina, Brazil, Colombia, Peru and Chile) ranges from 15% to 40%.
special tax.
• Allow for short term recovery of VAT paid on acquisitions or imports of
The Group has significant tax losses available which can be utilised against
capital goods, when non recoverable with VAT on usual sales.
future taxable profit in the following countries:
Amounts in US$ ‘000
Argentina
Chile (a)
Brazil (a)
Total tax losses at 31 December
2017
4,849
345,104
33,721
2016
2,908
280,290
16,057
2015
3,834
209,910
-
383,674
299,255
213,744
178 GeoPark 20-F
(a) Taxable losses have no expiration date.
At the balance sheet date deferred tax assets in respect of tax losses in
Note 18
Argentina and in certain Companies in Chile have not been recognised as
Deferred income tax
there is insufficient evidence of future taxable profits to offset them (in the
The gross movement on the deferred income tax account is as follows:
case of Argentina, before the statute of limitation of these tax losses causes
them to expire).
Expiring dates for tax losses accumulated at 31 December 2017 are:
Amounts in US$ ‘000
Deferred tax at 1 January
Reclassification (a)
Currency translation differences
Amounts in US$ ‘000
Income statement credit
2017
20,283
-
(237)
5,304
2016
17,691
574
1,463
555
754
Deferred tax at 31 December
25,350
20,283
1,446
2,649
(a) Corresponds to differences between income tax provision and the final tax
return presented.
Expiring date
2020
2021
2022
The breakdown and movement of deferred tax assets and liabilities as of 31 December 2017 and 2016 are as follows:
Amounts in US$ ‘000
Deferred tax assets
Difference in depreciation rates and other
Taxable losses
Total 2017
Total 2016
Amounts in US$ ‘000
Deferred tax liabilities
Difference in depreciation rates and other
Taxable losses
Total 2017
At the beginning
Currency translation
(Charged) /
At end of year
of year
19,225
3,828
23,053
34,646
differences
credited to net profit
(237)
-
(237)
1,463
(2,817)
7,637
4,820
(13,056)
16,171
11,465
27,636
23,053
At the beginning
Credited to net profit
Reclassification (a)
At end of year
of year
(17,308)
14,538
(2,770)
(2,766)
3,250
484
13,611
-
-
-
574
(20,074)
17,788
(2,286)
(2,770)
Total 2016
(a) Corresponds to differences between income tax provision and the final tax return presented.
(16,955)
Note 19
Earnings per share
Amounts in US$ ‘000 except for shares
2017 (a)
2016
2015
Weighted average number
of shares used in basic EPS
60,093,191
59,777,145
57,759,001
Amounts in US$ ‘000 except for shares
2017
2016
2015
Numerator:
Loss for the year attributable to owners
(24,228)
(49,092)
(234,031)
Effect of dilutive potential
common shares (a)
Weighted average number
of common shares for the purposes
of diluted earnings
Denominator:
Weighted average number of shares
used in basic EPS
(Losses) after tax
60,093,191
59,777,145
57,759,001
per shares
60,093,191
59,777,145
57,759,001
(Losses) Earnings after tax
per share (US$) – basic
(0.40)
(0.82)
(4.05)
per share (US$) – diluted
(0.40)
(0.82)
(4.05)
(a) For the year ended 31 December 2017, there were 4,564,777 (1,390,706 in
2016 and 1,032,279 in 2015) of potential shares that could have a dilutive
impact but were considered antidilutive due to negative earnings.
GeoPark 179
Note 20
Property, plant and equipment
Amounts in US$ ‘000
Cost at 1 January 2015
Additions
Currency translation differences
Disposals
Write-off / Impairment loss
Transfers
Cost at 31 December 2015
Additions
Currency translation differences
Disposals
Write-off / Impairment reversal
Transfers
Cost at 31 December 2016
Additions
Currency translation differences
Disposals
Write-off / Impairment reversal
Transfers
Cost at 31 December 2017
Depreciation and write-down at 1 January 2015
(240,439)
Depreciation
Disposals
Currency translation differences
(84,849)
-
4,115
Depreciation and write-down at 31 December 2015
(321,173)
Depreciation
Disposals
Currency translation differences
(61,080)
-
(2,486)
Depreciation and write-down at 31 December 2016
(384,739)
Depreciation
Disposals
Currency translation differences
(57,725)
-
930
Oil & gas
Furniture,
Production
Buildings and
Construction
Exploration
Total
properties
equipment
facilities and
improvements
in progress
749,947
(4,640)(a)
(27,522)
(241)
(128,956)
60,404
648,992
(3,531) (a)
16,132
-
5,664
24,984
692,241
7,997 (a)
(1,142)
-
-
77,408
776,504
and vehicles
machinery
12,057
111,646
9,527
954
(182)
(13)
-
929
13,745
406
126
(22)
-
102
-
(2,577)
(1,685)
(13,242)
30,690
124,832
466
2,077
-
-
5,038
272
(92)
(84)
-
895
10,518
-
35
-
-
-
14,357
132,413
10,553
954
(12)
(112)
-
211
15,398
(4,449)
(2,850)
8
(26)
(7,317)
(2,702)
8
(38)
(10,049)
(1,948)
73
8
-
(147)
-
-
25,130
157,396
(45,147)
(15,467)
-
-
(60,614)
(10,788)
-
(296)
(71,698)
(14,558)
-
24
-
(3)
(189)
-
-
10,361
(2,244)
(874)
15
(92)
(3,195)
(920)
-
(16)
(4,131)
(844)
38
5
59,425
36,543
-
-
(7,376)
(58,769)
29,823
20,322
73
-
-
(17,292)
32,926
66,953
(62)
-
-
(61,827)
37,990
-
-
-
-
-
-
-
-
-
-
-
-
-
and evaluation
assets(b)
140,444
12,299
(1,510)
-
(30,084) (c)
(34,149)
87,000
18,181
790
-
(31,366) (d)
(12,832)
61,773
49,455
(104)
-
(5,834) (e)
(40,922)
1,083,046
45,428
(31,883)
(2,023)
(179,658)
-
914,910
35,844
19,233
(22)
(25,702)
-
944,263
125,359
(1,470)
(301)
(5,834)
-
64,368
1,062,017
-
-
-
-
-
-
-
-
-
-
-
-
-
(292,279)
(104,040)
23
3,997
(392,299)
(75,490)
8
(2,836)
(470,617)
(75,075)
111
967
(544,614)
522,611
473,646
517,403
Depreciation and write-down at 31 December 2017
(441,534)
(11,916)
(86,232)
(4,932)
Carrying amount at 31 December 2015
Carrying amount at 31 December 2016
Carrying amount at 31 December 2017
327,819
307,502
334,970
6,428
4,308
3,482
64,218
60,715
71,164
7,323
6,422
5,429
29,823
32,926
37,990
87,000
61,773
64,368
(a) Corresponds to the effect of change in estimate of assets retirement obligations.
(b) Exploration wells movement and balances are shown in the table below; seismic and other exploratory assets amount to US$ 53,764,000 (US$ 53,523,000 in
2016 and US$ 64,094,000 in 2015).
180 GeoPark 20-F
Amounts in US$ ‘000
Exploration wells at 31 December 2015
Additions
Write-offs
Transfers
Exploration wells at 31 December 2016
Additions
Write-offs
Transfers
Exploration wells at 31 December 2017
Total
22,906
15,088
(19,949)
(9,795)
8,250
35,299
(3,664)
(29,281)
10,604
As of 31 December 2017, there were two exploratory wells that have been
capitalised for a period less than a year amounting to US$ 4,488,000 and
two exploratory wells that have been capitalised for a period over a year
amounting to US$ 6,116,000.
(c) Corresponds to the cost of two unsuccessful exploratory wells in Colombia
(one well in CPO4 Block and one well in Llanos 32). The charge also includes
the loss generated by the write-off of the seismic cost for Flamenco Block in
Chile generated by the relinquishment of 143 sq km in November 2015 and
the write off of two wells drilled in previous years in the same block for which
no additional work would be performed.
(d) Corresponds to the write-off of five wells drilled in previous years in the
Chilean blocks for which no additional work would be performed, the loss
generated by the write-off of the seismic cost for Llanos 62 Block in Colombia
generated by the relinquishment of the area in September 2016. In addition,
during September 2016, five blocks in Brazil were relinquished so the
associated investment was written off.
(e) Corresponds to five unsuccessful exploratory wells, one well drilled in
Colombia (Llanos 34 Block), one well drilled in Brazil (REC-T-94 Block) and three
non-operated wells drilled in Argentina (Puelen and Sierra del Nevado Blocks)
in 2017. The charge also includes the loss generated by the write-off of the
seismic cost for Campanario and Isla Norte Blocks in Chile generated by the
relinquishment of 327 sq km in 2017.
GeoPark 181
Note 21
Subsidiary undertakings
The following chart illustrates main companies of the Group structure as of 31 December 2017 (a):
(a) LGI is not a subsidiary, it is Non-controlling interest.
Non controlling interest held by LGI:
• Consolidated Statement of Comprehensive Income: Total comprehensive income for the year 2017 include a profit of US$ 13,536,000 (profit of US$ 2,791,000
in 2016 and loss of US$ 7,085,000 in 2015), a loss of US$ 6,200,000 (US$ 10,379,000 in 2016 and US$ 33,260,000 in 2015) and a loss of US$ 945,000 (US$ 3,966,000
in 2016 and US$ 10,190,000 in 2015) corresponding to non-controlling interest held by LGI in GeoPark Colombia Coöperatie U.A., GeoPark Chile S.A. and GeoPark
TdF S.A., respectively.
• Consolidated Statement of Financial Position: Total Equity as of 31 December 2017 includes US$ 29,330,000 (US$ 16,168,000 in 2016), US$ 15,953,000 (US$
22,082,000 in 2016) and a negative amount of US$ 3,368,000 (US$ 2,422,000 in 2016) corresponding to non-controlling interest held by LGI in GeoPark Colombia
Coöperatie U.A., GeoPark Chile S.A. and GeoPark TdF S.A., respectively.
• Consolidated Statement of Changes in Equity: Dividends distributed to non-controlling interest of US$ 479,000 in 2017 (US$ 6,406,000 in 2016) correspond to
non-controlling interest held by LGI in GeoPark Colombia Coöperatie U.A.
182 GeoPark 20-F
Details of the subsidiaries and joint operations of the Group are set out below:
Subsidiaries
GeoPark Argentina Limited (Bermuda)
Name and registered office
GeoPark Argentina Limited – Argentinean Branch
GeoPark Latin America Limited (Bermuda)
GeoPark Latin America Limited – Agencia en Chile
GeoPark S.A. (Chile)
GeoPark Brazil Exploração y Produção de Petróleo e Gás 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 Latin America S.L.U. (Spain)
GeoPark Colombia Coöperatie U.A. (The Netherlands)
GeoPark S.A.C. (Peru)
GeoPark Perú S.A.C. (Peru)
GeoPark Operadora del Perú S.A.C. (Peru)
GeoPark Peru S.L.U. (Spain)
GeoPark Brazil S.L.U. (Spain)
GeoPark Colombia E&P S.A.(Panama)
GeoPark Colombia E&P Sucursal Colombia (Colombia)
GeoPark Mexico S.A.P.I. de C.V. (Mexico)
Ogarrio E&P S.A.P.I. de C.V. (Mexico)
GeoPark (UK) Limited (United Kingdom)
Joint operations
Tranquilo Block (Chile)
Flamenco Block (Chile)
Campanario Block (Chile)
Isla Norte Block (Chile)
Yamu/Carupana Block (Colombia)
Llanos 34 Block (Colombia)
Llanos 32 Block (Colombia)
CPO-4 Block (Colombia)
Puelen Block (Argentina)
Sierra del Nevado Block (Argentina)
CN-V Block (Argentina)
Manati Field (Brazil)
(a) Indirectly owned.
(b) Dormant companies.
(c) LG International has 20% interest.
(d) LG International has 20% interest through GeoPark Chile S.A. and a 14% direct interest, totaling 31.2%.
(e) GeoPark is the operator.
Corporate structure reorganization
Ownership interest
100%
100% (a)
100%
100% (a)
100% (a) (b)
100% (a)
80% (a) (c)
80% (a) (c)
80% (a) (c)
68.8% (a) (d)
100% (a) (b)
80% (a) (c)
100% (a)
80% (a) (c)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a) (b)
100% (a) (b)
100% (b)
51% (a) (b)
100%
50% (e)
50% (e)
50% (e)
60% (e)
89.5%/100% (e)
45% (e)
12.5%
50% (e)
18%
18%
50% (e)
10%
During 2017, the Company decided to incorporate a subsidiary in the United Kingdom to conduct the businesses in Latin America by adopting all the key
resolutions and decisions necessary for such purpose. Also, a tax reform enacted in The Netherlands during September 2017 that would harm the Group´s
cashflow, forced the Group to decide the re-domiciliation of its 100% owned Dutch subsidiaries to Spain.
GeoPark 183
Note 22
Prepaid taxes
Amounts in US$ ‘000
V.A.T.
Income tax payments in advance
Other prepaid taxes
Total prepaid taxes
Classified as follows:
Current
Non current
Total prepaid taxes
Note 23
Inventories
Amounts in US$ ‘000
Crude oil
Materials and spares
Amounts in US$ ‘000
At 1 January
Foreign exchange (income) loss
2016
14,052
2017
741
(147)
594
2016
596
145
741
4,517
The credit period for trade receivables is 30 days. The maximum exposure to
98
credit risk at the reporting date is the carrying value of each class of receivable.
2017
27,674
1,258
939
29,871
18,667
The Group does not hold any collateral as security related to trade receivables.
26,048
3,823
29,871
15,815
The carrying value of trade receivables is considered to represent a reasonable
2,852
approximation of its fair value due to their short-term nature.
18,667
Note 25
Financial instruments by category
2017
1,969
3,769
5,738
2016
1,521
1,994
3,515
Amounts in US$ ‘000
Loans and receivables
Trade receivables
To be recovered from co-venturers (Note 33)
Other financial assets (a)
Cash and cash equivalents
Assets as per statement of
financial position
2017
2016
19,519
2,455
43,488
134,755
18,426
3,311
22,027
73,563
200,217
117,327
Liabilities as per statement
of financial position
2017
2016
19,289
19,289
52,557
31,184
10,015
3,067
3,067
23,650
27,801
1,614
426,204
358,672
519,960
411,737
Note 24
Trade receivables and Prepayments and other receivables
Amounts in US$ ‘000
Trade receivables
To be recovered from co-venturers (Note 33)
Related parties receivables (Note 33)
Prepayments and other receivables
Total
Classified as follows:
Current
Non current
Total
2017
19,519
19,519
2,455
56
5,242
7,753
27,272
27,037
235
27,272
(a) Non current other financial assets relate to contributions made for
environmental obligations according to Colombian and Brazilian government
2016
18,426
regulations and also include a non current account receivable with the
18,426
previous owners of one of the Colombian subsidiaries (see Note 28). Current
3,311
other financial assets corresponds to the security deposit granted in relation to
42
the purchase of Argentinian assets (see Note 35) and short term investments
4,290
with original maturities up to twelve months and over three months.
7,643
26,069
Amounts in US$ ‘000
25,828
Liabilities at fair value through profit and loss
241
Derivative financial instrument liabilities
26,069
Other financial liabilities at amortised cost
Trade receivables that are aged by less than three months are not considered
Trade payables
impaired. As of 31 December 2017 and 2016, there are no balances that were
Payables to related parties (Note 33)
aged by more than 3 months, but not impaired. These relate to customers for
To be paid to co-venturers (Note 33)
whom there is no recent history of default. There are no balances overdue
Borrowings
between 31 days and 90 days as of 31 December 2017 and 2016.
Movements on the Group provision for impairment are as follows:
Total financial liabilities
539,249
414,804
184 GeoPark 20-F
Credit quality of financial assets
Amounts in US$ ‘000
Less than
Between 1
Between 2
The credit quality of financial assets that are neither past due nor impaired can
1 year
and 2 years
and 5 years
Over 5
years
be assessed by reference to external credit ratings (if available) or to historical
At 31 December 2017
information about counterparty default rates:
Amounts in US$ ‘000
Trade receivables
Borrowings
Trade payables
Payables
2017
2016
to related parties
Counterparties with an external credit rating (Moody’s)
At 31 December 2016
B2
Ba3
Baa3
Counterparties without an external credit rating
Group1 (a)
Total trade receivables
70
8,788
3,614
7,056
Borrowings
-
Trade payables
3,729
Payables
to related parties
7,047
19,519
7,641
18,426
27,625
52,557
7,331
87,513
48,958
23,650
27,625
82,875
480,250
-
-
-
-
2,068
27,087
29,693
109,962
480,250
43,304
355,064
-
-
1,561
74,169
1,561
22,018
44,865
377,082
-
-
-
-
(a) Group 1 – existing customers (more than 6 months) with no defaults in the past.
All trade receivables are denominated in US Dollars, except in Brazil where are
Accounting policies for financial instruments have been applied to classify
as either: loans and receivables, held-to-maturity, available-for-sale, or fair
Fair value measurement of financial instruments
denominated in Brazilian Real.
Cash at bank and other financial assets (a)
Amounts in US$ ‘000
Counterparties with an external credit rating (Moody’s,
value through profit and loss. For financial instruments that are measured in
the statement of financial position at fair value, IFRS 13 requires a disclosure
of fair value measurements by level according to the following fair value
2017
2016
measurement hierarchy:
S&P, Fitch, BRC Investor Services)
• Level 1 - Quoted prices (unadjusted) in active markets for identical assets or
A1
A2
A3
Aaa
Aa3
AAA
B2
Ba1
Ba2
Baa1
Baa2
Ba3
B3
BBB
Counterparties without an external credit rating
553
298
63,853
15,040
11,401
19,634
31
18
7
307
4,078
2,815
-
15,064
45,123
813
liabilities.
-
-
-
• Level 2 - Inputs other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly (that is, as prices) or
indirectly (that is, derived from prices).
42,798
• Level 3 - Inputs for the asset or liability that are not based on observable
14
market data (that is, unobservable inputs).
-
-
-
This note provides an update on the judgements and estimates made by the
Group in determining the fair values of the financial instruments since the last
100
annual financial report.
4,094
3,497
10
-
(a) Fair value hierarchy
The following table presents the Group’s financial assets and financial liabilities
measured and recognised at fair value at 31 December 2017 and 2016 on a
44,252
recurring basis:
Total
178,222
95,578
Amounts in US$ ‘000
Level 2
At 31 December 2017
(a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to
cash on hand amounting to US$ 21,000 (US$ 12,000 in 2016).
Liabilities
Financial liabilities - contractual undiscounted cash flows
Derivative financial instrument liabilities
Commodity risk management contracts
The table below analyses the Group’s financial liabilities into relevant
Total Liabilities
maturity groupings based on the remaining period at the balance sheet to
the contractual maturity date. The amounts disclosed in the table are the
contractual undiscounted cash flows.
19,289
19,289
19,289
19,289
GeoPark 185
Amounts in US$ ‘000
Level 2
At 31 December 2016
Note 26
Liabilities
Derivative financial instrument liabilities
Commodity risk management contracts
Total Liabilities
3,067
3,067
Share capital
Issued share capital
3,067
Common stock (amounts in US$ ‘000)
3,067
The share capital is distributed as follows:
2017
61
2016
60
There were no transfers between Level 2 and 3 during the period.
Total common shares in issue
60,596,219
59,940,881
Common shares, of nominal US$ 0.001
60,596,219
59,940,881
The Group did not measure any financial assets or financial liabilities at fair
Authorised share capital
value on a non-recurring basis as at 31 December 2017.
US$ per share
0.001
0.001
(b) Valuation techniques used to determine fair values
Number of common shares
Specific valuation techniques used to value financial instruments include:
(US$ 0.001 each)
Amount in US$
The use of quoted market prices or dealer quotes for similar instruments.
5,171,949,000
5,171,949,000
5,171,949
5,171,949
The market-to-market fair value of the Group’s outstanding derivative
Details regarding the share capital of the Company are set out below:
instruments is based on independently provided market rates and
determined using standard valuation techniques, including the impact of
Common shares
counterparty credit risk and are within level 2 of the fair value hierarchy.
As of 31 December 2017, the outstanding common shares confer the
The fair value of the remaining financial instruments is determined using
following rights on the holder:
discounted cash flow analysis. All of the resulting fair value estimates are
• the right to one vote per share;
included in level 2.
• ranking pari passu, the right to any dividend declared and payable on
(c) Fair values of other financial instruments (unrecognised)
The Group also has a number of financial instruments which are not
measured at fair value in the balance sheet. For the majority of these
GeoPark common
common shares;
Shares
issued
Shares
closing
US$(`000)
instruments, the fair values are not materially different to their carrying
shares history
Date
(millions)
(millions)
Closing
amounts, since the interest receivable/payable is either close to current
Shares outstanding
market rates or the instruments are short-term in nature.
at the end of 2015
Stock awards
Borrowings are comprised primarily of fixed rate debt and variable rate debt
Stock awards
with a short term portion where interest has already been fixed. They are
Stock awards
classified under other financial liabilities and measured at their amortized
Buyback program
cost.
Shares outstanding
at the end of 2016
The fair value of these financial instruments at 31 December 2017 amounts to
Stock awards
US$ 425,118,000 (US$ 346,180,000 in 2016). The fair values are based on cash
Stock awards
flows discounted using a rate based on the borrowing rate of 6.90% (7.60% in
Stock awards
2016) and are within level 2 of the fair value hierarchy.
Shares outstanding
at the end of 2016
Feb 2016
Dec 2016
Dec 2016
Dec 2016
Jan 2017
Dec 2017
Dec 2017
0.4
0.5
0.1
(0.6)
0.1
0.1
0.5
59.5
59.9
60.4
60.5
59.9
59.9
60.0
60.1
60.6
60.6
59
60
60
60
60
60
60
60
61
61
Stock Award Program and Other Share Based Payments
On 14 December 2017, 490,000 common shares were allotted to the trustee
of the Employee Beneficiary Trust (“EBT”), generating a share premium of
US$ 2,513,000.
On 15 December 2016, 379,500 common shares were allotted to the trustee
of the Employee Beneficiary Trust (“EBT”), generating a share premium of
US$ 3,940,000.
186 GeoPark 20-F
On 12 November 2015 and 22 December 2015, 817,600 and 478,000
Note 27
common shares were allotted to the trustee of the Employee Beneficiary
Borrowings
Trust (“EBT”), generating a share premium of US$ 11,359,000 and US$
3,577,000, respectively.
Amounts in US$ ‘000
2017
2016
In January 2017, 82,306 shares were issued to key management as bonus
compensation, generating a share premium of US$ 332,000.
On 8 February 2016, 468,405 shares were issued to Executive Directors and
key management as bonus compensation, generating a share premium of
US$ 1,512,000.
Outstanding amounts as of 31 December
2024 Notes (a)
Notes GeoPark Latin America Agencia en Chile (b)
Banco Itaú (c)
Banco de Chile (d)
Banco de Crédito e Inversiones (e)
Classified as follows:
On 13 September 2017, 12,546 shares were issued pursuant to a consulting
Current
agreement for services rendered to GeoPark Limited generating a share
Non current
premium of US$ 43,000.
426,124
-
-
-
80
-
304,059
49,763
4,709
141
426,204
358,672
7,664
418,540
39,283
319,389
On 6 September 2016, 8,333 shares were issued pursuant to a consulting
(a) During September 2017, the Company successfully placed US$ 425,000,000
notes which were offered to qualified institutional buyers in accordance with
agreement for services rendered to GeoPark Limited generating a share
Rule 144A under the United States Securities Act, and outside the United
premium of US$ 38,000.
States to non-U.S. persons in accordance with Regulation S under the United
States Securities Act.
On 30 November 2015, 720,000 new common shares were issued to the
Executive Directors, generating a share premium of US$ 7,309,000.
The Notes carry a coupon of 6.50% per annum. Final maturity of the notes
will be 21 September 2024. The Notes are secured with a pledge of all
During 2017, the Company issued 70,485 (137,897 in 2016 and 99,555 in
of the equity interests of the Company, directly or indirectly, in GeoPark
2015) shares to Non-Executive Directors in accordance with contracts as
Colombia Coöperatie U.A. and GeoPark Chile S.A.. The debt issuance cost for
compensation, generating a share premium of US$ 257,000 (US$ 541,848 in
this transaction amounted to US$ 6,683,000 (debt issuance effective rate:
2016 and US$ 486,692 in 2015). The amount of shares issued is determined
6.90%). The indenture governing the Notes due 2024 includes incurrence test
considering the contractual compensation and the fair value of the shares for
covenants that provides among other things, that, during the first two years
each relevant period.
Buyback Program
from the issuance date, the Net Debt to Adjusted EBITDA ratio should not
exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed 2
times. Failure to comply with the incurrence test covenants does not trigger
On 19 December 2014, the Company approved a program to repurchase
an event of default. However, this situation may limit the Company’s capacity
up to US$ 10,000,000 of common shares, par value US$ 0.001 per share of
to incur additional indebtedness, as specified in the indenture governing the
the Company (the “Repurchase Program”). The Repurchase Program began
Notes. Incurrence covenants as opposed to maintenance covenants must be
on 19 December 2014 and was resumed on 14 April 2015 and then on
tested by the Company before incurring additional debt or performing certain
10 June 2015, expiring on 18 August 2015. During 2016, the Repurchase
corporate actions including but not limited to dividend payments, restricted
Program began on 6 April 2016 and then was resumed during the year until
payments and others, (other than in each case, certain specific exceptions).
November 2016. The Shares repurchased will be used to offset, in part, any
As of the date of these Consolidated Financial Statements, the Company is in
expected dilution effects resulting from the Group’s employee incentive
compliance of all the indenture’s provisions and covenants.
schemes, including grants under the Company’s Stock Award Plan and the
Limited Non-Executive Director Plan. In 2017, no shares were repurchased.
The net proceeds from the Notes were used by the Company (i) to make a
During 2016 and 2015, the Company purchased 588,868 and 370,074 73,082
capital contribution to its wholly-owned subsidiary, GeoPark Latin America
common shares for a total amount of US$ 1,991,000 and US$ 1,615,000,
Limited Agencia en Chile (“GeoPark LA Agencia”), providing it with sufficient
respectively. These transactions had no impact on the Group’s results.
funds to fully repay the 7.50% senior secured notes due 2020 and to pay
any related fees and expenses, including call premium, and (ii) for general
corporate purposes, including capital expenditures and to repay existing
indebtedness.
(b) During February 2013, the Group successfully placed US$ 300,000,000 notes
which were offered under Rule 144A and Regulation S exemptions of the
GeoPark 187
United States Securities laws. The Notes carried a coupon of 7.50% per annum
The provision for asset retirement obligation relates to the estimation of future
and mature on 11 February 2020. These Notes were fully repaid in September
disbursements related to the abandonment and decommissioning of oil and
2017.
gas wells (see Note 4).
(c) During March 2014, GeoPark executed a loan agreement with Itaú BBA
International for US$ 70,450,000 to finance the acquisition of a 10% working
Deferred income relates to contributions received to improve the project
economics of the gas wells in Chile. The amortisation is in line with the related
interest in the Manatí field in Brazil. The loan was fully repaid in September
asset. The addition in 2016 and the amounts used in 2017 correspond to the
2017.
deferred income related to the take or pay provision associated to gas sales in
Brazil.
(d) During December 2015, GeoPark executed a loan agreement with Banco
de Chile for US$ 7,028,000 to finance the start-up of new Ache gas field
As of 31 December 2016, Other included a provision for an amount of US$
in GeoPark-operated Fell Block. The interest rate applicable to this loan is
5,636,000 related to fiscal controversies associated to income taxes in one of
LIBOR plus 2.35% per annum. The interest and the principal have been paid
the Colombian subsidiaries. These controversies related to fiscal periods prior
on monthly basis; with a six months grace period, with final maturity on
to the acquisition of these subsidiaries by the Group. During 2017, GeoPark
December 2017. As of the date of these Consolidated Financial Statements,
settled the controversies by paying a total amount of US$ 3,389,000 to the tax
the loan was fully repaid.
authority, under a valid tax amnesty. In connection to this, the Group recorded
an account receivable with the previous owners for the amount paid under
(e) During February 2016, GeoPark executed a loan agreement with Banco de
Crédito e Inversiones for US$ 186,000 to finance the acquisition of vehicles
the tax amnesty, considering the contractual right of recovering amounts
paid related to fiscal years prior to the acquisition. This account receivable
for the Chilean operation. The interest rate applicable to this loan is 4.14% per
is recognised under other financial assets in the balance sheet. In addition,
annum. The interest and the principal will be paid on monthly basis, with final
actions taken by the Group to maximize ongoing work projects and to reduce
maturity on February 2019.
expenses, including renegotiations and reduction of oil and gas service
contracts and other initiatives included in the cost cutting program adopted
As of the date of these Consolidated Financial Statements, the Group has
may expose the Group to claims and contingencies from interested parties
available credit lines for over US$ 33,000,000.
that may have a negative impact on its business, financial condition, results
of operations and cash flows. So, the additions in 2016 reflects the future
contingent payments in connection with claims of third parties.
Note 28
Provisions and other long-term liabilities
Amounts in US$ ‘000
Asset
retirement
Deferred
obligation
Income
At 1 January 2016
Addition to provision
Recovery of abandonments
costs
Exchange difference
31,617
1,195
(5,504)
(1,614)
Foreign currency translation
1,614
5,033
1,375
-
-
-
Amortisation
Unwinding of discount
At 31 December 2016
Addition to provision
Exchange difference
Foreign currency translation
Amortisation
Unwinding of discount
Unused amounts reversed
Amounts used during
-
(2,924)
2,554
29,862
-
3,484
5,943
134
(134)
-
2,607
-
-
-
-
(657)
-
-
the year
At 31 December 2017
(337)
38,075
(1,375)
1,452
188 GeoPark 20-F
Other
5,800
2,686
-
538
-
-
139
9,163
2,220
1,154
-
-
172
(2,535)
(3,417)
6,757
Note 29
Trade and other payables
Total
Amounts in US$ ‘000
42,450
V.A.T
5,256
(5,504)
(1,076)
Trade payables
Payables to related parties(a) (Note 33)
Customer advance payments (Note 3)
Staff costs to be paid
1,614
Royalties to be paid
(2,924)
Taxes and other debts to be paid
2,693
To be paid to co-venturers (Note 33)
Classified as follows:
Current
Non current
42,509
8,163
1,288
(134)
(657)
2,779
(2,535)
(a)The outstanding amount corresponds to advanced cash call payments
granted by LGI to GeoPark Chile S.A. for financing Chilean operations in
TdF’s blocks. The expected maturity of these balances is July 2020 and the
(5,129)
applicable interest rate is 8% per annum.
46,284
2017
1,118
52,557
31,184
10,000
9,143
4,110
4,191
10,015
122,318
96,397
25,921
2016
1,102
23,650
27,801
20,000
7,749
1,503
3,355
1,614
86,774
52,008
34,766
The average credit period (expressed as creditor days) during the year ended
During 2016, the Group approved a share-based compensation program for
31 December 2017 was 95 days (2016: 83 days)
1,619,105 shares. Main characteristics of the Stock Awards Programs are:
The fair value of these short-term financial instruments is not individually
• Exercise price is equal to the nominal value of shares.
determined as the carrying amount is a reasonable approximation of fair value.
• Vesting period is three years.
• All employees are eligible.
Note 30
Share-based payment
• Each employee could receive up to three salaries by achieving the following
conditions: continue to be an employee, the stock market price at the date of
vesting should be above US$ 3 and obtain the Group minimum production,
adjusted EBITDA and reserves target for the year of vesting.
IPO Award Program and Executive Stock Option plan
The Group has established different stock awards programs and other share-
Also during 2016, the Group approved a plan named Value Creation Plan
based payment plans to incentivise the Directors, senior management and
(“VCP”) oriented to Top Management. Main characteristics of the VCP are:
employees, enabling them to benefit from the increased market capitalisation
• Awards payables in a variable number of shares which shall not exceed the
of the Company.
quantity of 2,976,781 shares.
• Subject to certain market conditions, among others, reaching a stock
Stock Award Program and Other Share Based Payments
market price for the Company shares of US$ 4.05 at vesting date.
During 2008, GeoPark Shareholders voted to authorize the Board to use up
• Vesting date: 31 December 2018.
to 12% of the issued share capital of the Company at the relevant time for the
• VCP has been classified as an equity-settled plan.
purposes of the Performance-based Employee Long-Term Incentive Plan.
Details of these costs and the characteristics of the different stock awards
programs and other share based payments are described in the following
table and explanations:
Awards
at the
Awards
granted
Awards
Awards
Awards
Charged to net loss / profit
Year of issuance
beginning
in the year
forfeited
exercised
at year end
2016
2014
2013
2012
2011
Subtotal
Stock options
to Executive Directors
Shares granted
to Non-Executive Directors
VCP 2013
VCP 2016
Executive Directors Bonus
Key Management Bonus
Stock awards for service contracts
1,619,105
490,000
-
-
-
-
-
-
-
-
-
82,306
-
2,191,411
-
-
-
-
-
-
-
70,485
-
-
-
-
12,546
83,031
The awards that are forfeited correspond to employees that had left the Group
before vesting date.
31,109
-
1,587,996
-
-
-
-
-
-
-
-
-
-
-
-
490,000
-
-
-
-
-
70,485
-
-
-
82,306
12,546
-
-
-
-
-
-
-
-
-
-
-
-
2017
865
838
-
-
-
2016
2015
445
821
-
855
-
-
898
594
636
879
1,703
2,121
3,007
-
-
2,390
454
-
1,868
-
-
50
400
-
934
(325)
202
35
371
617
-
400
1,438
-
8,223
31,109
655,337
1,587,996
4,075
3,367
GeoPark 189
Note 31
Interests in Joint operations
The Group has interests in joint operations, which are engaged in the
exploration of hydrocarbons in Chile, Colombia, Brazil and Argentina.
In Chile, GeoPark is the operator in all the blocks. In Colombia, GeoPark is the
operator in Llanos 34 and Yamu/Carupana blocks. In Argentina, GeoPark is the
operator in CN-V block.
The following amounts represent the Group’s share in the assets, liabilities and
results of the joint operations which have been recognised in the Consolidated
Statement of Financial Position and Statement of Income:
Subsidiary /
Joint operation
2017
GeoPark Magallanes Ltda.
Tranquilo Block
GeoPark TdF S.A.
Flamenco Block
Campanario Block
Isla Norte Block
Colombia SAS
Yamu/Carupana Block
Llanos 34 Block
Llanos 32 Block
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field
POT-T-747
GeoPark Argentina Limited – Argentinean Branch
CN-V Block
Puelen Block
Sierra del Nevado Block
2016
GeoPark Magallanes Ltda.
Tranquilo Block
GeoPark TdF S.A.
Flamenco Block
Campanario Block
Isla Norte Block
Colombia SAS
Yamu/Carupana
Block
Llanos 34 Block
Llanos 32 Block
10%
70%
50%
18%
18%
50%
50%
50%
60%
89.5%
45%
10%
PP&E
Interest
E&E Assets
Other
Assets
Total
Total
NET ASSETS/
Operating
Assets
Liabilities
(LIABILITIES)
Revenue
(loss) profit
-
55
55
(432)
(377)
-
(48)
50%
50%
50%
60%
89.5%
45%
12.5%
9,893
17,347
9,553
4,741
131,193
835
44,167
849
6,819
1,318
568
-
-
-
1
4,563
209
19,126
358
347
72
169
9,893
17,347
9,553
4,742
135,756
1,044
(1,223)
(233)
(60)
(2,993)
(5,847)
(492)
63,293
1,207
(11,444)
(1,091)
7,166
1,390
737
(984)
(232)
(837)
8,670
17,114
9,493
879
(1,422)
-
-
(150)
(161)
1,749
3,072
129,909
259,815
552
1,784
(2,721)
163,917
(319)
51,849
34,238
12,731
116
6,182
1,158
(100)
-
70
-
-
-
-
(1,163)
(546)
(474)
(40)
-
55
55
(424)
(369)
15,108
29,718
9,920
3,418
79,811
3,819
-
-
-
-
693
-
15,108
29,718
9,920
3,418
80,504
3,819
(93)
(1)
(1)
15,015
29,717
9,919
1,004
(1,988)
-
5
(399)
(438)
(2,289)
(3,943)
(211)
1,129
18
76,561
125,400
3,608
2,303
(307)
83,193
1,043
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field
10%
54,166
15,791
69,957
(8,442)
61,515
29,719
20,945
190 GeoPark 20-F
Subsidiary /
Joint operation
2015
GeoPark Magallanes Ltda.
Tranquilo Block
GeoPark TdF S.A.
Flamenco Block
Campanario Block
Isla Norte Block
Colombia SAS
Llanos 17 Block
Yamu/Carupana
Block
Llanos 34 Block
Llanos 32 Block
PP&E
Interest
E&E Assets
Other
Assets
Total
Total
NET ASSETS/
Operating
Assets
Liabilities
(LIABILITIES)
Revenue
(loss) profit
50%
-
45
45
50%
50%
60%
14,932
27,570
8,583
36.84%
-
-
-
-
-
89.5%
45%
10%
3,569
76,667
3,106
2,061
429
96
14,932
27,570
8,583
-
5,630
77,096
3,202
(2)
(53)
(10)
(16)
(93)
43
-
(69)
14,879
27,560
8,567
1,810
(51,411)
13
355
(7,267)
(5,661)
(93)
3
(6,325)
(2,235)
(3,295)
(213)
3,395
1,409
(16,552)
73,801
114,276
2,989
8,258
53,049
(1,343)
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field
10%
50,801
12,930
63,731
(10,395)
53,336
32,388
20,354
Capital commitments are disclosed in Note 32 (b).
table A, the Group should deliver to ANH a share of the production net of
Note 32
Commitments
(a) Royalty commitments
In Colombia, royalties on production are payable to the Colombian
Government and are determined on a field-by-field basis using a level
of production sliding scale at a rate which ranges between 6%-8%. The
Colombian National Hydrocarbons Agency (“ANH”) also has an additional
economic right equivalent to 1% of production, net of royalties.
royalties in accordance with the following formula: Q = ((P – Po) / P) x S; where
Q = Economic right to be delivered to ANH, P = WTI, Po = Base price (see table
A) and S = Share (see table B).
°API
>29°
>22°<29°
>15°<22°
>10°<15°
Po (US$/barrel)
30.22
31.39
32.56
46.50
Table A
Table B
WTI (P)
Po < P < 2Po
2Po < P < 3Po
3Po < P < 4Po
4Po < P < 5Po
5Po < P
S
30%
35%
40%
45%
50%
Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties on
GeoPark is obligated to make certain payments to the previous owners of
Colombian production of light and medium oil are calculated on a field-by-
Winchester based on the production and sale of hydrocarbons discovered
field basis, using the following sliding scale:
by exploration wells drilled after 25 October 2011. These payments involve
Average daily production in barrels
Production Royalty rate
the vendor. As at the balance sheet date and based on preliminary internal
an overriding royalty equal to an estimated 4% carried interest on the part of
Additionally, under the terms of the Winchester Stock Purchase Agreement,
Up to 5,000
5,000 to 125,000
125,000 to 400,000
400,000 to 600,000
Greater than 600,000
8%
estimates of additions of 2P reserves since acquisition, the Group’s best
8% + (production - 5,000)*0.1
estimate of the total commitment over the remaining life of the concession
20%
is in a range between US$ 80,000,000 and US$ 90,000,000. During 2017,
20% + (production - 400,000)*0.025
the Group has accrued and paid US$ 11,369,000 (US$ 5,414,000 in 2016
25%
and US$ 7,100,000 in 2015) and US$ 9,981,000 (US$ 3,772,000 in 2016 and
US$ 9,200,000 in 2015), respectively.
When the API is lower than 15°, the payment is reduced to the 75%
of the total calculation.
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
In accordance with Llanos 34 Block operation contract, when the
production. In the Flamenco Block, Campanario Block and Isla Norte Block,
accumulated production of each field, including the royalties’ volume,
royalties are calculated at 5% of gas and oil production.
exceeds 5,000,000 of barrels and the WTI exceeds the base price settled in
GeoPark 191
In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency
On 22 July 2015, GeoPark signed a farm-in agreement with Wintershall for
(ANP) is responsible for determining monthly minimum prices for petroleum
the CN-V Block in Argentina. GeoPark will operate during the exploratory
produced in concessions for purposes of royalties payable with respect
phase and receive a 50% working interest in the CN-V Block in exchange for
to production. Royalties generally correspond to a percentage ranging
its commitment to drill two exploratory wells, for a total of US$ 10,000,000. As
between 5% and 10% applied to reference prices for oil or natural gas,
of the date of these Consolidated Financial Statements, GeoPark has already
as established in the relevant bidding guidelines (edital de licitação) and
drilled and completed one of the two committed exploratory wells for a total
concession agreement. In determining the percentage of royalties applicable
amount of US$ 5,455,000.
to a concession, the ANP takes into consideration, among other factors, the
geological risks involved and the production levels expected. In the Manatí
Chile
Block, royalties are calculated at 7.5% of gas production.
The remaining investment commitment for the second exploratory phase
in the Flamenco Block relates to the drilling of one exploratory well to be
In Argentina, crude oil production accrues royalties payable to the Province
assumed 100% by GeoPark and amounts to US$ 2,100,000. On 30 June 2017,
of Mendoza equivalent to 12% on estimated value at well head of those
the Chilean Ministry accepted GeoPark’s proposal to extend the second
products. This value is equivalent to final sales price less transport, storage and
exploratory phase for an additional period of 18 months, ending on 7 May
treatment costs.
(b) Capital commitments
Colombia
2019.
The investment commitment for the first exploratory period in the
Campanario and Isla Norte Blocks has already been fulfilled. The
investments to be made in the second exploratory period will be assumed
The VIM 3 Block minimum investment program consists of 200 sq km of 2D
100% by GeoPark. On 29 May 2017, the Chilean Ministry accepted
seismic and drilling one exploratory well, with a total estimated investment
GeoPark’s proposal to update the value of the commitments in both the
of US$ 22,290,800 during the initial three year exploratory period ending 2
Campanario and Isla Norte Blocks as well as the guarantees related to those
September 2018.
commitments. Consequently, the future investment commitments assumed
by GeoPark for the second exploratory period are up to:
The Llanos 34 Block (45% working interest) has committed to drill two
• Campanario Block: 3 exploratory wells before 10 July 2019 (US$
exploratory wells, one before 15 March 2017 and the other before 14
4,758,000)
September 2019. The remaining commitment amounted to US$ 6,255,000
•
Isla Norte Block: 2 exploratory wells before 7 May 2019 (US$ 2,855,000)
at GeoPark’s working interest. As of the date of these Consolidated Financial
Statements, GeoPark is awaiting the ANH’s approval of the wells already drilled
As of 31 December 2017, the Group has established guarantees for its total
that were presented as fulfilment of the commitments to be performed in the
commitments.
block. After this approval, the remaining commitment would amount to US$
3,008,000.
Brazil
The Llanos 32 Block (12% working interest) has committed to drill one
• SEAL-T-268 Block: before 15 May 2017 (US$ 230,000). On 12 May 2017, the
exploratory well before 20 August 2018. The remaining commitment amounts
Brazilian National Agency of Petroleum, Natural Gas and Biofuels (“ANP”)
to US$ 587,500 at GeoPark’s working interest.
notified the suspension of the exploratory period to fulfill the commitments in
The future investment commitments assumed by GeoPark are up to:
the block.
Argentina
• REC-T-94 Block: 2 exploratory wells before 12 July 2017 (US$ 2,300,000).
On 20 August 2014, the consortium of GeoPark and Pluspetrol was awarded
An exploratory well was drilled and completed in April 2017. On 12 July
two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part
2017, the ANP notified the suspension of the exploratory period to fulfill the
of the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa
commitments in the block.
Mendocina de Energia S.A. (“EMESA”). The consortium consists of Pluspetrol
• REC-T-93 Block: 3D seismic before 20 December 2018 (US$ 50,000).
(Operator with a 72% working interest (“WI”), EMESA (Non-operated with a
• REC-T-128 Block: 1 exploratory well before 20 December 2018 (US$
10% WI) and GeoPark (Non-operated with an 18% WI). As of the date of these
2,690,000).
Consolidated Financial Statements, the remaining commitments in the blocks
• POT-T-747 Block: 1 exploratory well before 20 December 2018 (US$
for the first exploratory period amount to US$ 1,200,000 at GeoPark’s working
1,840,000). An exploratory well was drilled in December 2017.
interest.
• POT-T-882 Block: 35 sq km of 2D seismic before 20 December 2018 (US$
480,000).
• POT-T-619 Block: 1 well before 16 September 2018 (US$ 700,000).
192 GeoPark 20-F
(c) Operating lease commitments – Group company as lessee
The Group leases various plant and machinery under non-cancellable
operating lease agreements.
Investments LLP, GPK Holdings, and other investment vehicles.
(c) IFC Equity Investments voting decisions are made through a portfolio
management process which involves consultation from investment officers,
The Group also leases offices under non-cancellable operating lease
agreements. The lease terms are between 2 and 3 years, and most of lease
agreements are renewable at the end of the lease period at market rate.
credit officers, managers and legal staff.
(d) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal
Pavez. The common shares reflected as being held by Mr. Pavez include 83,716
common shares held by him personally.
During 2017 a total amount of US$ 46,195,000 (US$ 47,871,000 in 2016
and US$ 16,731,000 in 2015) was charged to the income statement and
US$ 34,160,000 of operating leases were capitalised as Property, plant and
equipment related to rental of drilling equipment and machinery (US$
32,058,000 in 2016 and US$ 7,102,000 in 2015).
The future aggregate minimum lease payments under non-cancellable
operating leases are as follows:
Amounts in US$ ‘000
2017
2016
2015
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
32,180
5,777
2,793
-
67,752
14,031
5,066
114
12,878
8,257
2,456
309
Total minimum lease payments
40,750
86,963
23,900
Note 33
Related parties
Controlling interest
The main shareholders of GeoPark Limited, a company registered in Bermuda,
as of 31 December 2017, are:
Shareholder
James F. Park (a)
Gerald E. O’Shaughnessy (b)
Manchester Financial Group, LP
IFC Equity Investments(c)
Juan Cristóbal Pavez(d)
Other shareholders
Common
shares
7,891,269
7,193,316
5,103,439
3,422,476
2,961,520
34,024,199
60,596,219
Percentage
of outstanding
common shares
13.02%
11.87%
8.42%
5.65%
4.89%
56.15%
100.00%
(a) Held by Energy Holdings, LLC, which is controlled by James F. Park, a
member of our Board of Directors.
(b) Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP
GeoPark 193
Balances outstanding and transactions with related parties
Account (Amounts in ´000)
Transaction in the year
Balances at year end
Related Party
Relationship
2017
To be recovered from co-venturers
Prepayments and other receivables
Payables account
To be paid to co-venturers
Financial results
Geological and geophysical expenses
Administrative expenses
2016
To be recovered from co-venturers
Prepayments and other receivables
Payables account
To be paid to co-venturers
Financial results
Geological and geophysical expenses
Administrative expenses
2015
To be recovered from co-venturers
Prepayments and other receivables
Payables account
To be paid to co-venturers
Financial results
Geological and geophysical expenses
Administrative expenses
Administrative expenses
-
-
-
-
2,224
170
411
-
-
-
-
1,587
113
371
-
-
-
-
1,560
101
66
377
2,455
56
(31,184)
(10,015)
-
-
-
3,311
42
(27,801)
(1,614)
-
-
-
4,634
38
(21,045)
(113)
-
-
-
-
Joint Operations
Joint Operations
LGI
LGI
Joint Operations
LGI
Carlos Gulisano
Pedro Aylwin
Partner
Partner
Joint Operations
Partner
Non-Executive Director (a)
Executive Director (b)
Joint Operations
Joint Operations
LGI
LGI
Joint Operations
LGI
Carlos Gulisano
Pedro Aylwin
Partner
Partner
Joint Operations
Partner
Non-Executive Director (a)
Executive Director (b)
Joint Operations
Joint Operations
LGI
LGI
Joint Operations
LGI
Carlos Gulisano
Carlos Gulisano
Pedro Aylwin
Partner
Partner
Joint Operations
Partner
Non-Executive Director (a)
Non-Executive Director (a)
Executive Director (b)
(a) Corresponding to consultancy services.
(b) Corresponding to wages and salaries for US$ 271,000 (US$ 246,000 in 2016
and US$ 317,000 in 2015) and bonus for US$ 140,000 (US$ 125,000 in 2016 and
US$ 60,000 in 2015).
There have been no other transactions with the Board of Directors, 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 other
benefits informed in Note 11.
194 GeoPark 20-F
Note 34
Fees paid to Auditors
Amounts in US$ ‘000
Audit fees
Audit related fees
Tax services fees
Non-audit services fees
Fees paid to auditors
held by Trayectoria, the counterpart in the Yamú Block, operated by GeoPark,
that includes a 10% economic interest in all of the Yamú fields. According to
the terms of the swap operation, GeoPark had written off a receivable with
2017
726
137
212
39
1,114
2016
487
-
134
-
621
2015
Trayectoria.
557
-
Following this transaction, GeoPark continued to be the operator and have
129
an 89.5% interest in the Carupana Field and 100% in Yamú and Potrillo Fields.
-
The Group recognised, during 2015, a loss of US$ 296,000 generated by this
686
transaction.
Non-audit services fees relate to consultancy and other services for 2017.
Acquisition of Tiple Block
Note 35
Business transactions
a. Peru
Entry in Peru
GeoPark executed a joint operation agreement related to certain exploration
activities in a new high-potential exploration acreage (“Tiple Block Acreage”)
in the Llanos Basin in Colombia, through a partnership with CEPSA Colombia
S.A. (a subsidiary of CEPSA SAU, the Spanish integrated energy and
petrochemical company).
The Tiple Block Acreage is located adjacent to GeoPark’s Llanos 34 Block
The Group has executed a Joint Investment Agreement and Joint Operating
(GeoPark operated, 45% WI). This exploration area covers approximately
Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an interest in
21,000 acres and has full 3D seismic coverage.
and operate the Morona Block located in northern Peru. GeoPark will assume
a 75% working interest (“WI”) of the Morona Block, with Petroperu retaining
The agreement provides for GeoPark to drill one exploration well, which is
a 25% WI. The transaction has been approved by the Board of Directors of
scheduled to be drilled in the first half of 2018. The total estimated investment
both Petroperu and GeoPark. The agreement was subject to Peru regulatory
amounts to between US$ 7,000,000 and US$ 8,000,000 (including drilling,
approval, which was completed on 1 December 2016 following the issuance of
completion, civil works and other facilities).
Supreme Decree 031-2016-MEM.
Incremental interest in Llanos 32 Block
The Morona Block, also known as Lote 64, covers an area of 1.9 million
On 22 August 2017, GeoPark acquired an additional 2.5% interest in the Llanos
acres on the western side of the Marañón Basin, one of the most prolific
32 Block. No gain or loss has been generated by this transaction.
hydrocarbon basins in Peru. It contains the Situche Central oil field, which has
been delineated by two wells (with short term tests of approximately 2,400
Zamuro Farm-in agreement
and 5,200 bopd of 35-36° API oil each) and by 3D seismic.
GeoPark executed a farm-in agreement to drill the Zamuro exploration
prospect, which is located in the Llanos 32 block (GeoPark non-operated,
In accordance with the terms of the agreement, GeoPark has committed to
12.5% WI). The farm-in agreement provides for the drilling of an exploration
carry Petroperu on a work program that provides for testing and start-up
well to be funded by GeoPark and, in the event of a commercial discovery,
production of one of the existing wells in the field, subject to certain technical
GeoPark would increase its economic interest to 56.25% in the Zamuro field
and economic conditions being met. During 2017, GeoPark recognised an
area. The well is scheduled to be drilled in the second half of 2018.
initial consideration owed to Petroperu that could be up to US$ 10,684,000,
subject to GeoPark’s review and approval of supporting documentation. This
c. Argentina
amount will be offset by the Petroperu’s interest in the operation expenses
to be incurred by GeoPark in the block. Expected capital expenditures in
Acquisition of the Aguada Baguales, El Porvenir and Puesto Touquet blocks
2018 for the Morona Block are mainly related to facility maintenance and
On 18 December 2017, GeoPark executed an asset purchase agreement to
environmental and engineering studies.
b. Colombia
Swap operation
acquire a 100% working interest and operatorship of the Aguada Baguales,
El Porvenir and Puesto Touquet blocks, which are located in the Neuquen
Basin, for a total consideration of US$ 52,000,000. Closing of the transaction is
subject to customary regulatory approvals, and is expected in the first quarter
2018.
On 19 November 2015, the Colombian subsidiary agreed to exchange its
10% non-operating economic interest in Cerrito Block for additional interests
GeoPark 195
As of the date of these Consolidated Financial Statements, GeoPark has
• The future oil prices have been calculated taking into consideration the
recorded the security deposit of US$ 15,600,000 granted to the seller within
oil curves prices available in the market, provided by international advisory
“Other financial assets” in the Consolidated Statement of Financial Position. No
companies, weighted through internal estimations in accordance with price
other amounts are recorded in relation with this transaction until its closing.
curves used by D&M;
Note 36
• Three price scenarios were projected and weighted in order to minimize
misleading: low price, middle price and high price (see below table “Oil price
Impairment test on Property, plant and equipment
scenarios”);
Oil price crisis started in the second half of 2014 and prices fell dramatically,
the Group adjusted this marker price on its model valuation to reflect the
WTI and Brent, the main international oil price markers, fell more than
effective price applicable in each location (see Note 3 “Price risk”);
60% between October 2014 and February 2016. Because of those market
• The model valuation was based on the expected cash flow approach;
conditions, during 2015, the Group undertook a decisive cost cutting program
• The revenues were calculated linking price curves with levels of production
to ensure its ability to both maximize the work program and preserve its
according to certified reserves (see below table “Oil price scenarios”);
liquidity. The main decisions included:
• The levels of production have been linked to certified risked 1P, 2P and 3P
• The table “Oil price scenarios” was based on Brent future price estimations;
reserves (see Note 4);
– Reduction of its capital investment taking advantage of the discretionary
• Production and structure costs were estimated considering internal
work program.
historical data according to GeoPark’s own records and aligned to 2018
– Deferment of capital projects by regulatory authority and partner
approved budget;
agreement.
• The capital expenditures were estimated considering the drilling campaign
– Renegotiation and reduction of oil and gas service contracts, including
necessary to develop the certified reserves;
drilling and civil work contractors, as well as transportation trucking and
• The assets subject to impairment test are the ones classified as Oil and Gas
pipeline costs.
properties and Production facilities and machinery;
– Operating cost improved efficiencies and temporary suspension of certain
• The carrying amount subject to impairment test includes mineral interest,
marginal producing oil and gas fields.
if any;
• The income tax charges have considered future changes in the applicable
During February 2015, the Group reduced its workforce significantly. This
income tax rates (see Note 16).
reduction streamlined certain internal functions and departments for
creating a more efficient workforce in the current economic environment.
Table Oil price scenarios (a):
As a result, the Group achieved cost savings associated with the reduction of
full-time and temporary employees, excluding one-time termination costs.
Continuous efforts and actions to reduce costs and preserve liquidity have
continued since.
As a result of the situation described, the Group recognised an impairment
loss of US$ 149,574,000 in 2015 after evaluating the recoverability of its fixed
assets affected by oil price drop, as such situation constitutes an impairment
Year
2018
2019
2020
indicator according to IAS 36 and, consequently, it triggers the need of
Over 2021
assessing fair value of the assets involved against their carrying amount.
Amounts in US$ per Bbl.
Low price
Middle price
High price
(15%)
(60%)
(25%)
64.9
53.2
54.4
54.3
64.9
62.5
63.9
63.7
64.9
71.7
73.4
73.2
The Management of the Group considers as Cash Generating Unit (CGU) each
of the blocks in which the Group has working or economic interests. The
(a) The percentages indicated between brackets represent the Company
estimation regarding each price scenario.
blocks with no material investment on fixed assets or with operations that are
As a consequence of the evaluation no additional impairment loss was
not linked to oil prices were not subject to impairment test.
recognised in 2017. In 2016, part of the impairment recorded in Colombia was
reversed for an amount of US$ 5,664,000 due to increase in estimated market
During 2016 and 2017 the impairment tests were reviewed. The main
prices and improvements in cost structure.
assumptions taken into account for the impairment tests for the blocks below
mentioned were:
196 GeoPark 20-F
Note 37
Supplemental information on oil and gas activities (unaudited).
The following information is presented in accordance with ASC No. 932
“Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas
Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to
align the current estimation and disclosure requirements with the requirements
set in the SEC final rules and interpretations, published on 31 December 2008.
This information includes the Group’s oil and gas production activities carried
out in Chile, Colombia, Brazil, Argentina and Peru.
Table 1 - Costs incurred in exploration, property acquisitions and development (a)
The following table presents those costs capitalised as well as expensed that
were incurred during each of the years ended as of 31 December 2017, 2016 and
2015. The acquisition of properties includes the cost of acquisition of proved
or unproved oil and gas properties. Exploration costs include geological and
geophysical costs, costs necessary for retaining undeveloped properties, drilling
costs and exploratory wells equipment. Development costs include drilling
costs and equipment for developmental wells, 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 2017
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development
Total costs incurred
Amounts in US$ ‘000
Year ended 31 December 2016
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development
Total costs incurred
Chile
Colombia
Argentina
Brazil
Perú
Total
-
-
-
-
-
-
3,283
10,231
13,514
37,017
49,268
86,285
-
-
-
8,080
167
8,247
Chile
Colombia
Argentina
-
-
-
-
5,519
4,566
10,085
15,233
12,500
27,733
-
-
1,894
-
1,894
-
-
-
5,207
1,210
6,417
Brazil
-
-
2,555
191
2,746
-
-
-
-
-
-
743
14,074
14,817
Perú
54,330
74,950
129,280
Total
-
-
-
-
-
-
-
25,201
17,257
42,458
GeoPark 197
Amounts in US$ ‘000
Year ended 31 December 2015
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development
Total costs incurred
Chile
Colombia
Argentina
Brazil
Perú
Total
-
-
-
-
3,598
13,315
16,913
14,845
14,752
29,597
-
-
1,103
56
1,159
-
-
2,562
3,780
6,342
-
-
-
-
-
-
-
22,108
31,903
54,011
(a) Includes capitalised amounts related to asset retirement obligations.
Table 2 - Capitalised costs related to oil and gas producing activities
The following table presents the capitalised costs as at 31 December 2017,
2016 and 2015, for proved and unproved oil and gas properties, and the related
accumulated depreciation as of those dates.
Amounts in US$ ‘000
At 31 December 2017
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
Other uncompleted projects (b)
Unproved properties
Gross capitalised costs
Accumulated depreciation
Total net capitalised costs
(a) Includes capitalised amounts related to asset retirement obligations.
(b) Do not include Peru capitalised costs.
Amounts in US$ ‘000
At 31 December 2016
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
Other uncompleted projects
Unproved properties
Gross capitalised costs
Accumulated depreciation
Total net capitalised costs
Chile
Colombia
Argentina
Brazil
Total
80,611
397,031
12,508
49,702
69,906
291,050
11,290
4,106
539,852
376,352
(253,764)
(228,793)
286,088
147,559
843
11,159
48
2,975
15,025
(5,700)
9,325
6,036
77,264
70
7,585
157,396
776,504
23,916
64,368
90,955
1,022,184
(39,509)
(527,766)
51,446
494,418
Chile
Colombia
Argentina
Brazil
Total
80,611
380,037
18,274
48,908
46,785
230,100
12,534
4,503
527,830
293,922
(230,917)
(190,025)
296,913
103,897
843
4,849
36
1,894
7,622
(5,692)
1,930
4,174
77,255
2,082
6,468
132,413
692,241
32,926
61,773
89,979
919,353
(29,803)
(456,437)
60,176
462,916
(a) Includes capitalised amounts related to asset retirement obligations and impairment loss reversal in Colombia for US$ 5,664,000.
198 GeoPark 20-F
Amounts in US$ ‘000
At 31 December 2015
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
Other uncompleted projects
Unproved properties
Gross capitalised costs
Accumulated depreciation
Total net capitalised costs
Chile
Colombia
Argentina
Brazil
Total
79,040
367,722
21,830
70,062
42,852
213,480
7,703
8,180
538,654
272,215
(201,138)
(160,759)
337,516
111,456
843
4,849
290
-
5,982
(5,654)
328
2,097
62,941
-
8,758
124,832
648,992
29,823
87,000
73,796
890,647
(14,236)
(381,787)
59,560
508,860
(a) Includes capitalised amounts related to asset retirement obligations and impairment loss in Chile and Colombia for US$ 104,515,000 and US$ 45,059,000,
respectively.
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 2017, 2016 and 2015. Income tax for the years presented was calculated utilizing the statutory tax rates.
Amounts in US$ ‘000
Year ended 31 December 2017
Revenue
Production costs, excluding depreciation
Operating costs
Royalties
Total production costs
Exploration expenses (a)
Accretion expense (b)
Impairment loss reversal for non-financial assets
Depreciation, depletion and amortization
Results of operations before income tax
Income tax benefit (expense)
Results of oil and gas operations
Amounts in US$ ‘000
Year ended 31 December 2016
Revenue
Production costs, excluding depreciation
Operating costs
Royalties
Total production costs
Exploration expenses (a)
Accretion expense (b)
Impairment loss for non-financial assets
Depreciation, depletion and amortization
Results of operations before income tax
Income tax benefit (expense)
Results of oil and gas operations
Chile
Colombia
Argentina
Brazil
Total
32,738
263,076
70
34,238
330,122
(19,685)
(1,314)
(42,677)
(24,236)
(20,999)
(66,913)
(1,404)
(994)
-
(22,705)
(13,364)
2,005
(11,359)
(3,856)
(683)
-
(38,721)
152,903
(61,161)
91,742
(7,603)
(3,134)
(70,290)
(28,697)
(10,737)
(98,987)
(325)
(13)
(338)
(707)
-
-
(3,985)
(930)
-
(8)
(10,659)
(983)
344
(639)
7,927
(2,695)
5,232
(9,952)
(2,607)
-
(72,093)
146,483
(61,507)
84,976
Chile
Colombia
Argentina
Brazil
Total
36,723
126,228
(20,674)
(1,495)
(29,326)
(7,281)
(22,169)
(36,607)
(21,060)
(11,690)
(897)
-
(29,890)
(37,293)
5,594
(31,699)
(459)
5,664
(29,439)
53,697
(21,479)
32,218
-
-
-
-
-
-
-
-
-
-
-
29,719
192,670
(5,738)
(2,721)
(55,738)
(11,497)
(8,459)
(67,235)
(5,636)
(1,198)
-
(12,785)
1,641
(558)
1,083
(38,386)
(2,554)
5,664
(72,114)
18,045
(16,443)
1,602
GeoPark 199
Amounts in US$ ‘000
Year ended 31 December 2015
Revenue
Production costs, excluding depreciation
Operating costs
Royalties
Total production costs
Exploration expenses (a)
Accretion expense (b)
Impairment loss for non-financial assets
Depreciation, depletion and amortization
Results of operations before income tax
Income tax expense
Results of oil and gas operations
(a) Do not include Peru costs.
(b) Represents accretion of ARO liability.
Table 4 - Reserve quantity information
Estimated oil and gas reserves
Chile
Colombia
Argentina
Brazil
Total
44,808
131,897
597
32,388
209,690
(26,731)
(1,973)
(40,384)
(8,150)
(28,704)
(48,534)
(30,499)
(789)
(104,515)
(37,664)
(7,132)
(890)
(45,059)
(50,675)
(1,414)
(34)
(1,448)
(1,159)
-
-
(5,058)
(2,998)
(8,056)
(1,103)
(896)
(73,587)
(13,155)
(86,742)
(39,893)
(2,575)
-
(149,574)
(91)
(13,401)
(101,831)
(157,363)
(20,393)
(2,101)
8,932
(170,925)
23,604
7,953
735
(3,037)
29,255
(133,759)
(12,440)
(1,366)
5,895
(141,670)
Proved reserves represent estimated quantities of oil (including crude
Reserves engineering is a subjective process of estimation of hydrocarbon
oil and condensate) and natural gas, which available geological and
accumulation, which cannot be accurately measured, and the reserve
engineering data demonstrates with reasonable certainty to be recoverable
estimation depends on the quality of available information and the
in the future from known reservoirs under existing economic and operating
interpretation and judgment of the engineers and geologists. Therefore,
conditions. Proved developed reserves are proved reserves that can
the reserves estimations, as well as future production profiles, are often
reasonably be expected to be recovered through existing wells with existing
different than the quantities of hydrocarbons which are finally recovered.
equipment and operating methods. The choice of method or combination
The accuracy of such estimations depends, in general, on the assumptions
of methods employed in the analysis of each reservoir was determined
on which they are based.
by the stage of development, quality and reliability of basic data, and
production history.
The estimated GeoPark net proved reserves for the properties evaluated as
of 31 December 2017, 2016 and 2015 are summarised as follows, expressed
The Group believes that its estimates of remaining proved recoverable
in thousands of barrels (Mbbl) and millions of cubic feet (MMcf ):
oil and gas reserve volumes are reasonable and such estimates have
been prepared in accordance with the SEC Modernization of Oil and Gas
Reporting rules, which were issued by the SEC at the end of 2008.
The Group estimates its reserves at least once a year. The Group’s reserves
estimation as of 31 December 2017, 2016 and 2015 was based on the
DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”).
DeGolyer and MacNaughton prepared its proved oil and natural gas reserve
estimates in accordance with Rule 4-10 of Regulation S–X, promulgated
by the SEC, and in accordance with the oil and gas reserves disclosure
provisions of ASC 932 of the FASB Accounting Standards Codification
(ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69
Disclosures about Oil and Gas Producing Activities).
200 GeoPark 20-F
As of 31 December 2017
As of 31 December 2016
As of 31 December 2015
Oil and
Oil and
Oil and
condensate
Natural gas
condensate
Natural gas
condensate
Natural gas
(Mbbl)
(MMcf )
(Mbbl)
(MMcf )
(Mbbl)
(MMcf )
720.0
21,101.0
76.0
9,502.0
31,399.0
3,423.0
44,398.0
-
9,215.0
57,036.0
88,435.0
8,688.0
-
23,821.0
-
32,509.0
11,329.0
-
-
-
11,329.0
43,838.0
547.0
9,502.0
72.0
9,316.0
6,610.0
-
29,525.0
-
19,437.0
36,135.0
6,052
27,838.0
-
9,305.0
43,195.0
62,632.0
29,690.0
-
-
-
29,690.0
65,825.0
498.0
8,177.8
120.0
-
8,795.8
5,455.8
22,245.5
-
-
27,701.3
36,497.1
4,922.0
-
36,158
-
41,080.0
31,593.0
-
-
-
31.593.0
76,673.0
Net proved developed
Chile (a)
Colombia (b)
Brazil (c)
Peru (d)
Total consolidated
Net proved undeveloped
Chile (e)
Colombia (f )
Brazil (c)
Peru (d)
Total consolidated
Total proved reserves
(a) Fell Block accounts for 98% of the reserves (99% in 2016 and 91% in 2015)
(LGI owns a 20% interest) and Flamenco Block accounts for 2% (1% in 2016
and 9% in 2015) (LGI owns 31.2% interest).
(b) Llanos 34 Block, Cuerva Block and Yamu Block account for 98%, 1% and 1%
(Llanos 34 Block and Llanos 32 Block account for 99% and 1% in 2016, and
Llanos 34 Block and Cuerva Block account for 94% and 3% in 2015) of the
proved developed reserves, respectively (LGI owns a 20% interest).
(c) BCAM-40 Block accounts for 100% of the reserves.
(d) Morona Block accounts for 100% of the reserves.
(e) Fell Block accounts for 97% of the reserves (99% in 2016 and 100% in 2015)
(LGI owns a 20% interest), Flamenco Block accounts for 3% in 2017 (1% in 2016
and nil in 2015) (LGI owns 31.2% interest).
(f ) Llanos 34, Cuerva Block and Yamu Block account for 97%, 2% and 1%
(Llanos 34 Block accounts for 100% in 2016 and Llanos 34 Block and Cuerva
Block account for 95% and 4% in 2015) of the proved undeveloped reserves,
respectively (LGI owns a 20% interest).
The amounts of proved reserves disclosed herein as of 31 December 2017
include 13,934.1 thousand barrels of crude oil condensate (8,796.2 in 2016
and 7,281.3 in 2015) and natural gas liquids and 4,101.5 million cubic feet
of natural gas (7,356.0 in 2016 and 7,345.8 in 2015) corresponding to non-
controlling interest held by LGI.
GeoPark 201
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 2014
Increase (decrease) attributable to:
Revisions (a)
Extensions and discoveries (b)
Production
Reserves as of 31 December 2015
Increase (decrease) attributable to:
Revisions (c)
Extensions and discoveries (d)
Purchases of minerals in place (e)
Production
Reserves as of 31 December 2016
Increase (decrease) attributable to:
Revisions (f )
Extensions and discoveries (g)
Production
Reserves as of 31 December 2017
Chile
Colombia
6,441.9
24,735.3
119.0
100.0
(707.1)
(225.0)
10,489.0
(4,576.0)
5,953.8
30,423.3
1,148.0
-
-
5,779.0
6,311.0
-
(502.8)
(5,173.3)
6,599.0
37,340.0
(2,109.0)
-
(347.0)
6,315.0
29,047.0
(7,203.0)
4,143.0
65,499.0
Brazil
130.0
7.6
-
(17.6)
120.0
(34.0)
-
-
(14.0)
72.0
19.0
-
(15.0)
76.0
Peru
Total
-
-
-
-
-
-
-
31,307.2
(98.4)
10,589.0
(5,300.7)
36,497.1
6,893.0
6,311.0
18,621.0
18,621.0
-
(5,690.1)
18,621.0
62,632.0
96.0
-
-
4,321.0
29,047.0
(7,565.0)
18,717.0
88,435.0
(a) For the year ended 31 December 2015, the Group’s oil and condensate
proved reserves were revised downwards by 0.1 mmbbl. The primary factors
(e) In December 2016, we obtained final regulatory approval for our acquisition
of the Morona Block in Peru. The Joint Investment and Operating Agreement
leading to the above were:
dated 1 October 2014 and its amendments were closed on 1 December 2016
- The impact of lower average oil prices resulting in a 2 mmbbl decrease in
reserves from the La Cuerva and Yamu blocks in Colombia, and a 1 mmbbl
decrease in reserves related to a change in a previously adopted development
following the issuance of Supreme Decree 031-2016-MEM.XXX.
(f ) For the year ended 31 December 2017, the Group’s oil and condensate
proved reserves were revised upward by 4.3 mmbbl. The primary factors
plan in the Fell Block in Chile.
leading to the above were:
- Such decrease was partially offset by better than expected performance from
- Better than expected performance from existing wells, from the Tigana and
existing wells, of which 2 mmbbl was from the Llanos 34 Block in Colombia
Jacana fields in the Llanos 34 Block, resulting in an increase of 3.8 mmbbl.
and 1 mmbbl from the Fell Block in Chile.
(b) In Colombia, the extensions and discoveries are primarily due to the Tilo,
Jacana, and Chachalaca field discoveries in the Llanos 34 Block.
(c) For the year ended 31 December 2016, the Group’s oil and condensate
proved reserves were revised upward by 7 mmbbl. The primary factors leading
to the above were:
- Better than expected performance from existing wells, resulting in an
increase of 9 mmbbl, of which 8 mmbbl was from the Tigana, Jacana and other
- The impact of higher average oil prices resulting in a 2.5 mmbbl and
0.4 mmbbl increase in reserves from the blocks in Colombia and Chile,
respectively.
- Such increase was partially offset by a decrease in reserves mainly related to
a change in a previously adopted development plan in the Fell Block in Chile,
resulting in a 2.4 mmbbl decrease.
(g) In Colombia, the extensions and discoveries are primary due to the
Chiricoca, Jacamar, and Curucucu field discoveries in the Llanos 34 Block and
minor fields in the Llanos 34 Block, and 1 mmbbl was from the Fell Block in
the Tigana and Jacana field extentions in the Llanos 34 Block.
Chile.
- Such increase was partially offset by lower average oil prices impacting the
La Cuerva and Yamu blocks in Colombia, resulting in a 2 mmbbl decrease.
(d) In Colombia, the extensions and discoveries are primarily due to the Jacana
field appraisal wells in the Llanos 34 Block.
202 GeoPark 20-F
Net proved reserves (developed and undeveloped) of natural gas:
(e) In Chile, the extensions and discoveries are primary due to the Uaken Field
discovery in the Fell Block.
Millions of cubic feet
Chile
Brazil
Total
Reserves as of 31 December 2014
33,970.0
40,464.0
74,434.0
Revisions refer to changes in interpretation of discovered accumulations and
Increase (decrease) attributable to:
Revisions (a)
Extensions and discoveries (b)
Production
(2,807.6)
9,378.0
2,907.0
99.4
development plan of certain fields under appraisal and development phases.
some technical and logistical needs in the area obliged to modify the timing and
-
9,378.0
(4,025.4)
(7,213.0)
(11,238.4)
Table 6 - Standardized measure of discounted future net cash flows related to
Reserves as of 31 December 2015
36,515.0
36,158.0
72,673.0
proved oil and gas reserves
Increase (decrease) attributable to:
Revisions (c)
Production
5,078.0
(319.0)
4,759.0
The following table discloses estimated future net cash flows from future
(5,293.0)
(6,314.0)
(11,607.0)
production of proved developed and undeveloped reserves of crude oil,
Reserves as of 31 December 2016
36,300.0
29,525.0
65,825.0
condensate and natural gas. As prescribed by SEC Modernization of Oil
Increase (decrease) attributable to:
Revisions (d)
Extensions and discoveries (e)
Production
and Gas Reporting rules and ASC 932 of the FASB Accounting Standards
(13,725.0)
1,187.0
59.0
(13,666.0)
Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly
-
1,187.0
SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future
(3,745.0)
(5,763.0)
(9,508.0)
net cash flows were estimated using the average first day-of-the-month
Reserves as of 31 December 2017
20,017.0
23,821.0
43,838.0
price during the 12-month period for 2017, 2016 and 2015 and using a 10%
(a) For the year ended 31 December 2015, the Group’s proved natural gas
reserves were revised by 0.1 billion cubic feet. This was the combined effect of:
annual discount factor. Future development and abandonment costs include
estimated drilling costs, development and exploitation installations and
abandonment costs. These future development costs were estimated based
on evaluations made by the Group. The future income tax was calculated by
applying the statutory tax rates in effect in the respective countries in which
- Better than expected performance from existing wells that resulted in an
we have interests, as of the date this supplementary information was filed.
increase of 13 billion cubic feet (3 billion cubic feet from the Manati field in
Brazil and 10 billion cubic feet from the Fell Block in Chile).
This standardized measure is not intended to be and should not be
- The above was partially offset by a decrease of 13 billion cubic feet due to
interpreted as an estimate of the market value of the Group’s reserves. The
lower average gas prices in the Fell and Tierra del Fuego (TdF) blocks in Chile
purpose of this information is to give standardized data to help the users of
(totalling 3 billion cubic feet) and changes in previously adopted development
the financial statements to compare different companies and make certain
plan in the Fell Block in Chile (totalling 10 billion cubic feet).
(b) In Chile, the extensions and discoveries are primary due to the Ache Field
discovery and from the extension well in the Fell Block.
(c) For the year ended 31 December 2016, the Group’s proved natural gas
reserves were revised upwards by 5 billion cubic feet. This increase was mainly
projections. It is important to point out that this information does not include,
among other items, the effect of future changes in prices, costs and tax rates,
which past experience indicates that are likely to occur, as well as the effect of
future cash flows from reserves which have not yet been classified as proved
reserves, of a discount factor more representative of the value of money
driven by better than expected performance from existing wells, primarily the
over the lapse of time and of the risks inherent to the production of oil and
Ache field in the Fell Block in Chile, resulting in an addition of 9 billion cubic
gas. These future changes may have a significant impact on the future net
feet. This increase was partially offset by a reduction of 4 billion cubic feet in
cash flows disclosed below. For all these reasons, this information does not
necessarily indicate the perception the Group has on the discounted future
net cash flows derived from the reserves of hydrocarbons.
the Pampa Larga field, also in the Fell Block.
(d) For the year ended 31 December 2017, the Group’s proved natural gas
reserves were revised downwards by 13.7 billion cubic feet. This was the
combined effect of:
- Removal of proved undeveloped reserves due to changes in previously
adopted development plan in the Fell Block in Chile and unsuccessful proved
undeveloped executions in the Fell Block in Chile (totalling 21.3 billion cubic
feet).
- The above was partially offset by an increase of 6.8 billion cubic feet due
to a better performance in the proved developed producing reserves in the
Fell Block in Chile and the impact of higher average prices that resulted in an
increase of 0.8 billion cubic feet.
GeoPark 203
Amounts in US$ ‘000
At 31 December 2017
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 2016
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 2015
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
Brazil
Peru
Total
284,711
2,434,954
157,527
1,047,540
3,924,732
(131,788)
(531,751)
(56,311)
(466,110)
(1,185,960)
(57,690)
(187,414)
(7,524)
(235,920)
(488,548)
(656)
(558,226)
(10,442)
(107,294)
(676,618)
94,577
1,157,563
83,250
238,216
1,573,606
(19,338)
(343,561)
(13,293)
(147,682)
(523,874)
75,239
814,002
69,957
90,534
1,049,732
394,993
873,771
(186,700)
(229,593)
(149,785)
(69,996)
(8,344)
50,164
(191,096)
383,086
200,713
(74,116)
(16,352)
(21,041)
89,204
941,463
2,410,940
(497,187)
(987,596)
(234,328)
(470,461)
(69,698)
(290,179)
140,250
662,704
(14,709)
(113,584)
(15,688)
(109,321)
(253,302)
35,455
269,502
73,516
30,929
409,402
403,199
1,032,339
(186,933)
(309,394)
(112,312)
(99,305)
(17,904)
(195,957)
86,050
427,683
(17,895)
(127,586)
68,155
300,097
221,206
(99,832)
(16,360)
(16,837)
88,177
(15,861)
72,316
-
-
-
-
-
-
-
1,656,744
(596,159)
(227,977)
(230,698)
601,910
(161,342)
440,568
204 GeoPark 20-F
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 2014
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 2015
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
Present value at 31 December 2016
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
Present value at 31 December 2017
The amounts of the standardized measure of discounted future net cash flows
herein for the year ended 31 December 2017, 2016 and 2015 include $178.1
million, $61.4 million and $73.9 million that correspond to the non-controlling
interest held by LGI.
Chile
Colombia
227,658
(20,948)
584,071
(97,152)
(256,828)
(547,379)
28,227
23,595
15,093
(5,463)
28,611
28,210
68,155
(15,127)
(16,854)
(49,763)
-
9,417
22,765
-
8,256
8,606
(20,123)
174,951
29,965
(14,528)
101,576
88,716
300,097
(91,163)
(171,131)
14,941
76,641
17,302
70,180
-
3,030
49,605
35,455
269,502
(14,251)
(198,631)
26,928
79,078
-
7,146
289,199
(124,053)
49,574
67,571
Brazil
112,145
(37,428)
(27,404)
542
-
4,872
4,845
1,573
13,171
72,316
(20,945)
16,366
542
-
2,214
(1,872)
(4,020)
8,915
73,516
(26,979)
(3,000)
8,385
-
-
Peru
Total
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
923,874
(155,528)
(831,611)
8,646
198,546
49,930
(15,146)
131,760
130,097
440,568
(127,235)
(171,619)
(34,280)
76,641
28,933
91,073
30,929
7,266
67,126
30,929
409,402
-
(239,861)
69,962
(9,725)
-
-
383,089
(46,315)
49,574
74,717
-
30,929
(69,594)
673,622
603
1,133
605,764
6,097
4,380
(258,842)
46,060
7,976
9,456
(11,828)
(256,597)
10,063
69,959
75,239
814,002
69,957
90,534
1,049,732
GeoPark 205
Other
Exhibit 12.1
Certification by the Principal Executive Officer Pursuant to Section 302 of
a. All significant deficiencies and material weaknesses in the design or
the Sarbanes-Oxley act of 2002
I, James F. Park, certify that:
1. I have reviewed this annual report on Form 20-F of GeoPark Limited;
operation of internal control over financial reporting which are reasonably
likely to adversely affect the company’s ability to record, process, summarize
and report financial information; and
b. Any fraud, whether or not material, that involves management or other
2. Based on my knowledge, this report does not contain any untrue statement
employees who have a significant role in the company’s internal control over
of a material fact or omit to state a material fact necessary to make the
financial reporting.
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
Date: April 11, 2018
James F. Park
3. Based on my knowledge, the financial statements, and other financial
Chief Executive Officer
information included in this report, fairly present in all material respects the
(Principal Executive Officer)
financial condition, results of operations and cash flows of the company as of,
and for, the periods presented in this report;
Certification by the Principal Financial Officer Pursuant to Section 302 of
4. The company’s other certifying officer(s) and I are responsible for
I, Andrés Ocampo, certify that:
establishing and maintaining disclosure controls and procedures (as defined
The Sarbanes-Oxley Act of 2002
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
1. I have reviewed this annual report on Form 20-F of GeoPark Limited;
financial reporting (as defined in Exchange Act Rules 13a 15(f ) and 15d 15(f ))
for the company and have:
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
a. Designed such disclosure controls and procedures, or caused such
statements made, in light of the circumstances under which such statements
disclosure controls and procedures to be designed under our supervision,
were made, not misleading with respect to the period covered by this report;
to ensure that material information relating to the company, including its
consolidated subsidiaries, is made known to us by others within those entities,
3. Based on my knowledge, the financial statements, and other financial
particularly during the period in which this report is being prepared;
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the company as of,
b. Designed such internal control over financial reporting, or caused such
and for, the periods presented in this report;
internal control over financial reporting to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial
4. The company’s other certifying officer(s) and I are responsible for
reporting and the preparation of financial statements for external purposes in
establishing and maintaining disclosure controls and procedures (as defined
accordance with generally accepted accounting principles;
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a 15(f ) and 15d 15(f ))
c. Evaluated the effectiveness of the company’s disclosure controls and
for the company and have:
procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the
a. Designed such disclosure controls and procedures, or caused such
period covered by this report based on such evaluation; and
disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the company, including its
d. Disclosed in this report any change in the company’s internal control over
consolidated subsidiaries, is made known to us by others within those entities,
financial reporting that occurred during the period covered by the annual
particularly during the period in which this report is being prepared;
report that has materially affected, or is reasonably likely to materially affect,
the company’s internal control over financial reporting; and
b. Designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision,
5. The company’s other certifying officer(s) and I have disclosed, based on
to provide reasonable assurance regarding the reliability of financial
our most recent evaluation of internal control over financial reporting, to
reporting and the preparation of financial statements for external purposes in
the company’s auditors and the audit committee of the company’s board of
accordance with generally accepted accounting principles;
directors (or persons performing the equivalent functions):
206 GeoPark 20-F
Exhibit 12.2
c. Evaluated the effectiveness of the company’s disclosure controls and
Certification by the Principal Executive Officer Pursuant to 18 U.s.c.
procedures and presented in this report our conclusions about the
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
effectiveness of the disclosure controls and procedures, as of the end of the
act of 2002
period covered by this report based on such evaluation; and
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
d. Disclosed in this report any change in the company’s internal control over
fiscal year ended December 31, 2017 (the “Report”), I, Andrés Ocampo, certify
financial reporting that occurred during the period covered by the annual
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
report that has materially affected, or is reasonably likely to materially affect,
Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:
the company’s internal control over financial reporting; and
1. the Report fully complies with the requirements of Section 13(a) or 15(d) of
5. The company’s other certifying officer(s) and I have disclosed, based on
the Securities Exchange Act of 1934; and
our most recent evaluation of internal control over financial reporting, to
the company’s auditors and the audit committee of the company’s board of
2. the information contained in the Report fairly presents, in all material
directors (or persons performing the equivalent functions):
respects, the financial condition and results of operations of the Company.
a. All significant deficiencies and material weaknesses in the design or
Date: April 11, 2018
operation of internal control over financial reporting which are reasonably
Andrés Ocampo
likely to adversely affect the company’s ability to record, process, summarize
Chief Financial Officer
and report financial information; and
(Principal Financial Officer)
b. Any fraud, whether or not material, that involves management or other
employees who have a significant role in the company’s internal control over
financial reporting.
Date: April 11, 2018
Andrés Ocampo
Chief Financial Officer
(Principal Financial Officer)
Certification by the Principal Executive Officer Pursuant to 18 U.s.c.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
act of 2002
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 fiscal
year ended December 31, 2017 (the “Report”), I, James F. Park, certify pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of 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) of
the Securities Exchange Act of 1934; and
2. the information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the Company.
Date: April 11, 2018
James F. Park
Chief Executive Officer
(Principal Executive Officer)
GeoPark 207
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 entire business career, starting in 1976 with Lario Oil and Gas Company.
He later formed The Globe Resources Group, a private venture firm whose
subsidiaries provided seismic acquisition and processing, well rehabilitation
services, logistical operations and submersible pump works for Lukoil and
Robert A. Bedingfield | Non-Executive Director
Mr. Bedignfield has been a member of our board of directors since March
2015. He holds a degree in Accounting from the University of Maryland and
is a Certified Public Accountant. Until his retirement in June 2013, he was
one of Ernst & Young’s most senior Global Lead Partners with more than
40 years of experience, including 32 years as a partner in Ernst & Young’s
accounting and auditing practices, as well as serving on Ernst & Young’s
Senior Governing Board. He has extensive experience serving Fortune
500 companies; including acting as Lead Audit Partner or Senior Advisory
Partner for Lockheed Martin, AES, Gannett, General Dynamics, Booz Allen
other companies active in Russia during the 1990s. Mr. O’Shaughnessy is also founder of BOE Midstream,
which owns and operates the Bakken Oil Express, a crude by rail transloading and storage terminal in North
Dakota, serving oil producers and marketing companies in the Bakken Shale Oil play. 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, the Timothy P. O’Shaughnessy
Foundation and is a member of the Intercontinental Chapter of Young Presidents Organization and World
Presidents’ Organization.
Hamilton, Marriott and the US Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at
times an Executive Committee Member, and the Audit Committee Chair of the University of Maryland
at College Park Board of Trustees. Mr. Bedingfield served on the National Executive Board (1995 to 2003)
and National Advisory Council (since 2003) of the Boy Scouts of America. Since 2013, Mr. Bedingfield has
also served as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications
International Corp (SAIC).
Pedro E. 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 us 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 Aylwin, Mendoza, Luksic, Valencia 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.
Carlos A. 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 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 35 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.
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 an 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, where 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. 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 Hidroelétrica Totoral and founder
board member of several companies, including Quintec, Enaex, CTI and Frimetal.
Jamie B. Coulter | Non-Executive Director
Mr. Coulter has been a member of our board of directors since May 2017. He
currently serves as Chairman and CEO of Coulter Enterprises Inc., a private
investment firm and has been an investor in and supporter of GeoPark since
2006. He built and became the CEO of Lone Star Steakhouse & Saloon, a
company that was awarded IPO of the year and Forbes Magazine #1 Best
Small Company in America for 3 consecutive years. He developed and
operated Pizza Hut and Kentucky Fried Chicken restaurants and became
the largest Pizza Hut franchisee, was inducted to the Pizza Hut Hall of Fame,
and was named the Restaurants & Institutions CEO of the year. Mr. Coulter
has both operating and investment experience in the oil and gas business, including, the founding of
Sunburst Exploration, a US upstream oil and gas company and also has a successful track record as an oil
and gas investor in the North American shale plays.
Mr. Coulter currently serves as a Director of the Federal Law Enforcement Foundation; Director of Jimmy
Johns, LLC; Director of Realm Cellars; Director of Cirq Estates, LLC; Director of KB Wines, LLC; Member
of the Board of Trustee for HCA Wesley Medical Center and Member of the Texas Heart Institute
Foundation Board.
Constantin Papadimitriou | Non-Executive Director
Mr. Papadimitriou has been a member of our board of directors since May
2018. Mr. Papadimitriou holds an Economics and Finance degree from
Geneva University and post graduate Diploma in European Studies also
from Geneva University. Mr. Papadimitriou is a respected and successful
international investor and businessman, with more than 30 years of
investment experience in global capital markets and in resource and
industrial projects. Mr. Papadimitriou was one of the original “friends and
family” investors in GeoPark in its early days in 2004. Mr. Papadimitriou is
currently CEO of General Oriental Investments S.A., the Investment Manager
of the Cavenham Group of Funds. Previously he was CEO of Cavamont Geneva. During his tenure
at the Cavamont group, Mr. Papadimitriou was responsible for Treasury Management, the Private
Equity Portfolio as well as representing the group on the Boards of associated companies including
investments in the oil and gas, mining, real estate and gaming sectors (including Basic Petroleum, a
Nasdaq-listed Guatemalan oil and gas company). Mr. Papadimitriou is also founding partner of Diorasis
International, a company focusing on investments in Greece and the broader Balkans and he also chairs
the Greek language school of Geneva and Lausanne.
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 and has
led the Company´s expansion into Chile, Argentina, Colombia, Brazil and
Peru. 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 studies at the University of Texas. Mr. Park helped
pioneer the development of commercial oil and gas production in Central America, as a senior
executive of Basic Resources International where he remained as a board member until the company
was successfully sold in 1997. Mr. Park has experience 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. Mr.
Park is also a member of the board of directors of Energy Holdings and has served on various non-profit
organizations, including as a board member of S.E.E. International. Mr. Park is a member of the AAPG
and SPE and has lived in Latin America since 2002.
208 Annual Report 2017 / Board of Directors
CORPORATE MANAGEMENT TEAM
JAMES F. PARK
Chief Executive Officer
ALBERTO MATAMOROS
Argentina, Chile
AUGUSTO ZUBILLAGA
Chief Operating Officer
ANDRÉS OCAMPO
Chief Financial Officer
PEDRO E. AYLWIN
Legal & Governance
BARBARA BRUCE
Peru
LIVIA VALVERDE
Brazil
SALVADOR MINNITI
Exploration
MARCELA VACA
Colombia
CARLOS MURUT
Reserves & Development
JUAN CARLOS FERRERO
Operations
HORACIO FONTANA
Drilling & Workover
AGUSTINA WISKY
Capacities
GUILLERMO PORTNOI
New Business
STACY STEIMEL
Shareholder Value
SECRETARY & ADVISORS
Registered Office
Corporate Offices
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
Bogota Office
Street 94 N° 11-30, 8th floor
Bogota
Colombia | +57 1 743 2337
Corporate Secretary
Pedro E. Aylwin
Counsel to the Company
Davis Polk & Wardwell LLP
as to New York Law
Solicitors to the Company
as to Bermuda Law
Independent Auditors
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
Petroleum Consultant
DeGolyer and MacNaughton
5001 Spring Valley Road Suite 800 East
Dallas, Texas 75244
USA
Registrar
Computershare Investor Services
Queensway House
480 Washington Blvd.
Jersey City, NJ 07310
GeoPark 209
ANNUAL REPORT 2017
WWW.GEO-PARK.COM