ANNUAL REPORT 2018
EXPLORER
OPERATOR
CONSOLIDATOR
CONTENTS
Bottom Line
Letter to Shareholders
Business Approach and Guidelines
2018 Performance
Our Strengths
Our Platform
Our Approach
Our Value System
Form 20-F
Consolidated Financial Statements
Board of Directors
Management Team
1
4
16
22
24
26
29
30
33
156
210
212
Morona Block, Marañon Basin, Peru
BOTTOM LINE
Oil and Gas
Production
CAGR 21%
Gas
Oil
Oil and Gas
Reserves
Gas
Oil
Value
(2P NPV10)
2009
2010
2011
2012
2013
2014
2015
2016 2017 2018
CAGR 18%
2009
2010
2011
2012
2013
2014
2015
2016 2017 2018
CAGR 26%
35
30
25
20
15
10
5
0
180
150
120
90
60
30
0
2.5
2.0
1.5
1.0
0.5
0
Morona Block, Marañon Basin, Peru
Reserves and NPV figures are based on PRMS criteria
GeoPark 1
2009
2010
2011
2012
2013
2014
2015
2016 2017 2018
2P Reserves (mmboe)$ BillionAverage Daily Production (mboepd) 2 Annual Report 2018
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.
Magallanes Region, Chile
GeoPark 3
LETTER TO SHAREHOLDERS
Dear Fellow Shareholders:
We are pleased to report that GeoPark is a better, stronger, bigger,
us the best performing upstream oil and gas company on the New
smarter, and more valuable Company than last year or ever before.
York Stock Exchange for the second year in a row (a 220% increase in
We are vigorously marching into 2019 with a clear disciplined plan, a
two years).
hungry and capable team, an arsenal of innovative tools, a new
high-potential country platform (our sixth country in Latin America),
Reviewing improvements to key components of our business during
and a strong wind at our backs to do even better next year.
the year:
Let’s please begin by thanking and congratulating the GeoPark team
Alignment
for breaking performance records across the board in 2018:
As described in our Business Guidelines (accompanying every Annual
Report), GeoPark’s long-term value proposition is to build the leading
Record oil and gas production
independent oil and gas company in Latin America – a region of
• Consolidated Production Up 31% to 36,027 boepd
unlimited hydrocarbon resources, with sparse competition and a
• Colombia Production Up 31% to 28,545 boepd
welcoming business environment. An advantage in creating our
Record oil and gas reserves
bold business plan that are supported and shared by our shareholders,
Company has been our consistent long-term vision and a conservative
• 1P Reserves Up 17% to 113.9 mmboe
• 2P Reserves Up 15% to 183.7 mmboe
• 3P Reserves Up 44% to 347.0 mmboe
Record asset values
board of directors, management and employee team. It is our steady
focus on this bigger prize that has allowed us to build the foundation
and tools needed for the long term and to push forward regardless
of any short-term cycles or sentiment. All of our employees are
shareholders and the management and Board (with friends and
• Net Present Value (2P) Up 20% to $2.7 billion
families) own approximately 50% of our Company, creating powerful
• Net Asset Value (Debt-Adjusted) Per Share Up 37% to $40.1
alignment and incentives to perform.
Record cash generation
Culture
• Record Revenues Up 82% to $601.2 million
As an entrepreneurial and battle-tested company that has grown
• Adjusted EBITDA Up 88% to $330.6 million
from scratch, we attribute our achievements to a proud culture based
• Free Cash Flow of $131.5 million
on trust – and which is the catalyst for our continuous record of safe,
Record profits
• Net Income of $102.7 million
• Earnings Per Share of $1.19
clean, neighborly, transparent and successful operations. We believe
long-term success is defined by the underlying character and behavior
of our Company, and our home-grown value system, we call SPEED,
is GeoPark’s competitive advantage. It defines our success, creates
positive interdependence with the communities where we operate,
In the context of GeoPark’s relentless 16-year value-creation track
and ensures safe and environmentally clean operational performance.
record, these results demonstrate a faithful pattern of delivery that
We want and expect to be the partner-of-choice, employer-of-choice
has existed since our Company was founded. And, we believe our
and neighbor-of-choice – and our on-the-ground metrics back this
momentum is just getting stronger and stronger.
up. From 2014 to date, GeoPark is the only major operator in Colombia
The international investment community continued taking increased
GeoPark to lead them back to the upstream utilizing a novel model
notice of GeoPark’s success and rewarded our shareholders by making
of development in concert with indigenous communities. In 2018,
with zero work interruptions. The Peruvian government chose
4 Annual Report 2018 / Letter to Shareholders
GeoPark 5
6 Annual Report 2018 / Letter to Shareholders
Casanare Department, Colombia
GeoPark was recognized for our social commitment with an award
(1P) reserves increasing by 17% to 114 mmboe, total proven and
granted by the United Nations and Colombian government.
probable (2P) reserves increasing by 15% to 184 mmboe, and total
proven, probable and possible (3P) reserves increasing by 44% to 347
People
mmboe.
The oil business begins with people and we have purposefully built
the strongest oil and gas team in Latin America. Our big ambitions
Cost Efficiency
require us to continuously improve our overall business and prepare
Being the safest, lowest-cost operator (driller and producer) of oil and
for the future by increasing our capabilities and know-how in every
gas are the critical factors in achieving long-term industry leadership
skillset and in every country. Last year, we continued to invest in our
and economic success - with an even greater emphasis due to
technical, financial and management excellence and strengthen our
continuously volatile oil markets. GeoPark is built to prosper in a
country business unit teams by training and promoting internally and
$40-50 oil price world, and our operational strength has allowed us to
hiring experienced, high-quality professionals. Our focus on being
relentlessly drive down capital and operating costs to achieve
the best has resulted in 43% of our senior management team being
top-performing metrics. Our 2P finding and development costs
women. We have created a dynamic organizational and leadership
were $3.6 per boe (less than $3 per boe in Colombia), and operating
framework inside GeoPark that allows us to continuously adjust and
costs were $8 per boe ($4 per bbl in Colombia Llanos 34). Our cost
adapt to our growing enterprise and to capture the future.
efficiency has resulted in 90% of GeoPark’s production being cash-
flow positive at oil prices of $25-30 per boe, providing cash flow
Track Record
security under almost any oil price scenario.
GeoPark recognizes and, in fact, welcomes the volatility that is
a permanent characteristic of our industry. We have been built
Value
to prosper and get better in an ‘up-and-down’ world. Our risk
Our preferred basic value metric is the discounted net present value
management approach and our ability to identify and mitigate
(NPV) of our proven and probable oil and gas reserves - since it
subsurface, above-ground and macro risks to our business have
encompasses the most variables impacting the recovery, cost and
resulted in a unique 16-year performance track record that has
financial returns of our discovered oil and gas. (It does not include
prevailed despite whatever crises have been thrown at us – whether
our significant exploration resource value.) With our new oil and gas
from oil industry shocks, turbulent financial markets, or regional
discoveries in 2018 and our increasingly efficient cost structure, the
political turmoil. GeoPark is the only company in its peer group that
independently-certified NPV of GeoPark’s 2P oil and gas reserves (184
can show a steady 10-year record of growth in Production, Reserves,
mmboe) increased by 20% to a value of $2.7 billion. Continuing a
Cash Generation, Net Present Value and Net Asset Value Per Share
multi-year industry-envious capital investment efficiency record, we
(with 18-26% CAGRs). Our team has proven that it has reliably
invested $125 million in capex and $49 million in new acquisitions
delivered over time and can be expected to continue to do so in the
in 2018 and increased our NPV by more than $450 million. On a
future.
Hydrocarbons
‘per share’ basis and deducting outstanding net debt, our net debt
adjusted 2P NPV per share increased by 37% to $40.1 per share (or
nearly $26 per share for Colombia alone). This shows the underlying
Enduring success in our industry means being able to consistently
value of our oil and gas assets continues to grow faster than and
and economically find, develop and produce oil and gas. This requires
significantly ahead of our market share price.
creativity, good science, discipline and the ability to take the right
risks. Our team has drilled over 300 wells with a greater than 75%
Upside
success rate and has discovered over 350 million boe of oil and gas.
GeoPark has steadily and economically built an extensive land
Last year, we drilled 33 wells with an 85% success rate. We increased
position across Latin America in the most prolific hydrocarbon
production by 31% and exited the year with approximately 40,000
basins, with more than five million acres in 29 blocks in 10 proven
boepd. After producing over 13 million boe during the year, we
hydrocarbon basins in six countries – consisting of a risk-balanced
replaced and grew our certified oil and gas reserves with proven
mix of production, development, exploration and unconventional
GeoPark 7
resource projects. With our team’s oil finding abilities, this large
into Ecuador. This large dynamic platform, painstakingly constructed
acreage inventory is a valuable, necessary and realistic asset for
over 16 years, is one of our most powerful assets – one that does
our future. On our acreage, GeoPark has identified new geological
not show up on a balance sheet, but which provides the foundation
plays and prospects – that is, new potential oil and gas fields – with
for our long-term growth. Each country is managed by reputable
externally-audited unrisked exploration resources of 600 million to
and professional local teams, with supporting production and cash
1.2 billion boe.
New Opportunities
flows, attractive underlying reserves and resources, and inventories
of new project opportunities. Our independent country businesses
benefit from the support of our overall corporate organization,
With our focus on scale, GeoPark is always in the hunt to acquire
which improves efficiencies, reduces costs through operational and
new oil and gas upstream opportunities across Latin America and
financial synergies, controls quality, drives performance, and more
we have been patient and selective in identifying and acquiring new
effectively grows our overall company by allocating capital to the
high-quality projects on attractive terms. We begin with a technical
best shareholder value-adding projects.
approach to identify under-exploited proven hydrocarbon basins –
considering geological, infrastructure and regulatory factors – and
Country Businesses
then work to establish strategic positions in the targeted regions.
Our continuous efforts over the last 10+ years have resulted in a
A brief look at each of our businesses:
$4+ billion new project inventory in Colombia, Brazil, Argentina,
Peru, Ecuador and Mexico. We have initiatives with the key Latin
Colombia Business
American national oil companies, which control the biggest and
GeoPark is leading the strongest upstream project in Colombia, one
best hydrocarbon acreage in each country and are reevaluating their
of the most attractive onshore projects in Latin America today. In
portfolios to initiate divestment programs. To enhance our position as
less than five years we grew from zero to become the second-largest
the preferred buyer in the region, GeoPark entered into an acquisition
private oil operator in the country – and are currently proving up
partnership in 2018 with ONGC, the national oil company of India,
what is being called the largest oil field discovery in Colombia in the
to strengthen our expansion efforts. (India is the fastest-growing oil
last 20 years.
consumer in the world.)
Self-Funding
Our key asset is the Llanos 34 Block (GeoPark discovered and
operated), which we have grown from 0 to 70,000+ bopd gross
Differentiating us from most of our industry peers, GeoPark is a
production – following our introduction of a new geological play type
self-funding growing cash-generating company – by which we mean
to the Llanos Basin. During 2018, after successful appraisal drilling
we are getting bigger and better by paying out of our own pocket.
in the Tigana and Jacana oil fields and new oil field discoveries in
This represents an important advantage, which is further bolstered by
Chachalaca Sur and Tigui, we materially increased our Colombian
our capital investment efficiency. Cash flows from operating activities
certified PDP, 1P, 2P and 3P reserves by 61%, 20%, 26% and 43% to
increased 80% to $256.2 million and Adjusted EBITDA increased by
34.7 million boe, 79.5 million boe, 111.2 million boe and 145.6 million
88% to $330.6 million. We had $131.5 million of free cash flow with a
boe respectively. Our 2P reserve life index reached 10.7 years and
15% yield – and profits of $102.7 million. We have a history of raising
the reserve replacement ratio was 321%. Our 1P NPV and 2P NPV in
capital creatively – and our balance sheet is strong with $128 million
Colombia increased to $1.4 billion and $1.9 billion respectively.
in cash and a net debt to Adjusted EBITDA ratio of 1.0X - showing
our ability to effectively manage and use leverage to expand our
Llanos 34 is a highly attractive, low risk, low cost and high netback
business.
Platform
block which provides a large-scale profitable production base even
in low oil price environments. Due to the expertise of our local teams,
net finding and development costs (F&D costs) for 2018 were just $2.9
GeoPark’s business plan and systematic expansion to date has
per boe (2P). We have a big inventory of well sites (80+) to continue
resulted in building stable and growing independent businesses in
growing production, and well economics with three digit IRRs and
Colombia, Chile, Brazil, Argentina and Peru – with a recent new entry
six-month paybacks (assuming a $50-55 per barrel Brent oil price).
8 Annual Report 2018 / Letter to Shareholders
Aguada Baguales Block, Neuquen, Argentina
GeoPark 9
Our return on capital in Llanos 34 is highly profitable and beats
almost any North American conventional or unconventional play.
In a constant effort to reduce costs and improve netbacks, we
constructed a new 30 km flowline to connect Llanos 34 to the main
Colombian pipeline infrastructure which will become operational in
early 2019.
During 2018, GeoPark also added new acreage adjacent to Llanos 34
and acquired LG’s 20% equity interest in our Colombian subsidiary,
which owns our participation in Llanos 34.
Peru Business
GeoPark continues working to prepare for the development of the
Morona Block. This project has become emblematic for Peru and,
because of our operating, environmental and community track
record, GeoPark was selected as the company to lead Petroperu back
to the upstream business and to operate this important and complex
project with a 75% working interest. We are actively engaged with
members of the communities and federations in the area of direct
influence to cooperate on the Environmental Impact Assessment,
which was submitted in 2018. The Smithsonian Institution of
Washington DC entered into a partnership with GeoPark to study and
monitor the biodiversity of the focus area.
Morona is a large block in the proven Marañon Basin with a large
upside potential (approximately 300-500 million boe) with several
high-impact plays and prospects. The block’s key asset is the Situche
Central light oil field, which was discovered and proven up by two
wells (which tested at a combined rate of 7,500 bopd), and which
has certified gross 3P reserves of 198.3 million barrels (with a gross
NPV of $2+ billion) and the opportunity for near-term cash flow.
10 Annual Report 2018 / Letter to Shareholders
Morona represents an important project for GeoPark that significantly
increases our overall inventory of reserves and exploration resources
and can contribute to our long-term durable growth. GeoPark has
designed a phased work program that is expected to put the Situche
Central field into production initially through a long-term test to
begin generating cash flow – with ‘first oil’ targeted for 2020.
Argentina Business
Our team is continuing to strengthen our position in Argentina,
where it has a proven history of exploration success.
In March 2018, we acquired a 100% working interest in and
operatorship of three new blocks (Aguada Baguales, El Porvenir and
Puerto Touquet) in the heart of the Neuquen Basin with production,
development, exploration and unconventional resource potential.
The blocks are currently producing 2,300-2,400 boepd and were
acquired at a value of $4 per boe 2P reserves. Exploration of a new
tight gas play began in early 2019. In addition to its attractive upside
potential, this acquisition represents a good fit with our existing
platform in Argentina with the opportunity for future cost savings
and operational synergies.
GeoPark also entered into a partnership with YPF, the national oil
company of Argentina, on the Los Parlamentos block – a large
high-potential exploration block in the Neuquen Basin with both
conventional and unconventional prospects.
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 7 exploration blocks in onshore mature proven
hydrocarbon basins (Potiguar, Reconcavo, and Sergipe Alagoas).
GeoPark is currently preparing to test a new exploration well drilled in
the Reconcavo Basin.
GeoPark also has identified attractive onshore and shallow offshore
hydrocarbon opportunities in Brazil, and is working with Petrobras in
its ongoing divestment efforts.
Tua Field, Llanos 34 Block, Colombia
GeoPark 11
Chile Business
Ecuador Business
GeoPark is Chile’s first private oil and gas producer. We built the
In March 2019, GeoPark was awarded two low-risk high-potential
business from a flat-footed start-up in 2006 to a solid business with
exploration blocks in north-eastern Ecuador in the Oriente Basin.
current production of approximately 2,800 boepd (80% gas, 20%
Both blocks are covered with 3D seismic and are adjacent to multiple
oil), 2P reserves of 24.7 million boe and 5 blocks with 0.8 million
producing oil fields and existing infrastructure. Ecuador has Latin
acres, consisting of approximately 300-800 million boe of gross
America’s third-largest oil reserves and the Oriente Basin is producing
exploration and unconventional resources. Over 20 million boe have
over 500,000 bopd, with infrastructure with spare capacity and a
already been produced by GeoPark in Chile and we divested 20% of
well-developed service industry. The award of these blocks is subject
our project in 2011 for approximately $150 million. This interest was
to regulatory approval and contract execution – and operational
recently re-acquired by GeoPark in November 2018.
start-up is targeted for late 2019 or early 2020.
In 2018, we discovered the Jauke gas field in the Fell Block, which is
part of the large Dicky geological structure, which has the potential
for multiple development drilling opportunities, some of them to be
tested in 2019.
12 Annual Report 2018 / Letter to Shareholders
Outlook
GeoPark has developed and proven-up a highly effective and robust
The 2019 work program provides for:
capital allocation methodology to manage its six-country portfolio.
This system enables us to review and select from a wide range of
• 35+ gross well drilling program targeting production growth of 15%
projects generated by each business unit team with different returns,
• 27-30 gross well development, appraisal and exploration drilling
potentials, risks, sizes, timelines and geographies. It ensures that
program in the Llanos Basin in Colombia
capital is always directed to our top value-adding projects after
• 6-7 gross well exploration and development drilling program in the
ranking them on technical, strategic and economic criteria. It creates
Neuquen Basin in Argentina in operated and non-operated blocks
a healthy competition between our different business units which
• Early production facilities in the Morona Block in the Marañon Basin
further helps drive performance. It also provides greater security
in Peru with the goal of putting the Situche Central light oil field into
in volatile markets by allowing us to easily add or remove projects
production by 2020, subject to approval of the Environmental Impact
depending on oil prices and project performance – and to fine-tune
Assessment
our desired risk exposure.
• 2-3 gross well exploration and development drilling program on the
Our 2019 work and investment program targets a $220-240 million
• 1-2 gross well shallow exploration drilling program in the onshore
capital investment program (considering Brent oil prices of $65-75
Reconcavo and Potiguar Basins in Brazil
Fell Block in the Magallanes Basin in Chile
per barrel) and is fully funded by cash flows. As always, our flexible
work program includes an accelerated case for higher oil prices and a
reduced program for lower oil prices.
Casanare Department, Colombia
GeoPark 13
14 Annual Report 2018 / Letter to Shareholders
Thank You Thank You
As our history has proved, great people create great results. We are
Our sincere thanks and appreciation to our shareholders and
pleased to recognize and thank the women and men who have
bondholders – old and new alike – who have partnered with us,
built and are continuing to build GeoPark. They are our heart and
believe in our project, and support our efforts. In 2018, we continued
our muscle, and have met every challenge with a professionalism,
our campaign (over 450 meetings) to reach out to new investors
creativity and agility that continues to propel us forward.
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
Our gratitude extends to the persistently supportive families of all
stock performer for the second year in a row and our stock trading
our team members who have contributed immensely to what we
volumes have begun to accelerate (now at levels exceeding $5 million
have achieved and where we are going. We were fortunate to join
per day) which has opened up shareholder participation to the wider
with all employees and spouses in 2018 in Villa de Leyva, Colombia
investment community.
for GeoPark’s Fifteenth Anniversary to express our thanks personally
and to celebrate together our culture, accomplishments and big
As always, your comments and recommendations are welcomed and
expectations for each other.
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.
A special thanks also to our committed and experienced Board of
Directors who work continuously to improve GeoPark. We are very
We look forward to delivering and reporting to you on our results in
pleased to welcome Constantine Papadimitriou who joined our Board
2019.
in 2018 and will also serve on the Audit Committee.
Sincerely,
Gerald E. O’Shaughnessy
Chairman
James F. Park
Chief Executive Officer
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
resources in new geological play types and formations.
and 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
Much of the world still lacks adequate energy supplies for the most
regions 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
exciting technologies and sources are being developed, oil and gas
oil companies, with the presence of only a modest number of
is the most reliable energy source and will be required to support
more-agile independent companies. North America is home to
over half of our planet’s continuous and rising energy needs far into
thousands of independent oil and gas operators, whereas Latin
this century.
America, an area substantially larger and with greater resource
potential, has only a handful of independents taking advantage of
We believe the best places for us to find and develop hydrocarbons
available opportunities. In contrast to many areas of the world, the
are in areas around the world where oil and gas have already
environment and resources for operating and funding a business
been discovered, but which for economic, technical, funding or
are welcoming and increasingly more feasible. Furthermore,
other 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 2018 / Business Approach and Guidelines
El Porvenir Block, Neuquen, Argentina
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
organizational, market, price, partner, shareholder, regulatory and
it 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
price volatility of 2015-2016.
The founders and our management team have a substantial part of
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
other shareholder other than our salaries and stock performance
teams. 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
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
the undertaking of risk in search of significant rewards. To succeed,
professionals and teams with respected reputations. They know
an oil and gas company must effectively identify and manage
both the specific subsurface rocks and conditions and the above-
prevailing risks and uncertainties to capture the available rewards.
ground operating and business environments in each region and
We believe this to be one of GeoPark’s key capabilities; and our
give us the characteristics of a local company. Our pride and care in
GeoPark 17
how we act and perform in our home regions are key elements of
skill sets – as Explorers, Operators and Consolidators – which we
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
hydrocarbons in the subsurface, but also the muscle and experience
by being tied together by an overall corporate organization,
to get the oil and gas out of the ground and profitably to market.
which improves efficiencies, reduces costs with operational and
Our attractive asset portfolio is evidence of our ability to acquire
financial synergies, controls quality, and can more effectively raise
good projects in the right basins in the right countries with the right
capital for our projects. It also is a source for new technologies
partners and at the right price.
and ideas to spread from one region to another. For example, our
team introduced a new geological play-type to the Llanos Basin in
Today, we have an amazing team of employees from Chile, Colombia,
Colombia (an area that has been explored for more than 75 years)
Brazil, Peru and Argentina – each of whom joined GeoPark with the
that resulted in multiple new oil field discoveries, and new oil
purpose of building a unique and special company that is prepared
technology to the 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
The international upstream oil and gas business is not for the
most 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
others have given up or failed. This is the engine and fire of our
attractive investment vehicle for all our shareholders – with a
growth and the true long-term intangible value of our Company.
strong foundation to minimize any downside, a big upside through
We are immensely grateful to all these men and women for their
multiple growth opportunities, and an overall organizational
professionalism, discipline, unity and heart.
system to more 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, Ecuador 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
by 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
18 Annual Report 2018 / Business Approach and Guidelines
GeoPark 19
20 Annual Report 2018 / Business Approach and Guidelines
El Porvenir Block, Neuquen, Argentina
a long-term and continuous effort and we have been building an
Culture
‘Creating Value and Giving Back’ is our motto and represents
attractive inventory of new projects in the region over the last ten
GeoPark’s market-based approach to align our business objectives
years, aided by our team’s 25+ year experience in Latin America.
with our core values and responsibilities. Our in-house designed
program, titled SPEED, targets and integrates the critical elements
Our focus is always to build a larger-scale balanced portfolio that
– Safety, Prosperity, Employees, Environment and Community
includes lower-risk short term cash flow generating properties,
Development – necessary to make our total business plan work. Only
mid-term medium-risk development projects, and longer term
by succeeding equally in each of these interdependent areas can we
higher-risk big upside projects. This permits steady, secure growth
realize our overall success and ambitions. This is important in every
with an opportunity for accelerated high growth ‘home-runs’ from
country where we operate, and we make every effort to achieve
the bigger projects.
the most effective governance, full compliance and consistent
transparency with all relevant authorities. Not only does this allow
Good oil and gas partners are a key element of our new business
us to be a more successful business enterprise over the long term, it
efforts and we like to balance our acquisition risk by including
reflects our pride in carrying out an important mission in the right
experienced partners in our new projects. We operated a strategic
way. The men and women of GeoPark care passionately about how
alliance with LG of Korea to acquire upstream assets and the
our Company acts – both internally and externally – and we all
International Finance Corporation (IFC) of the World Bank has been
consider our culture to be our core asset and the prime source of our
a long-term principal shareholder of (and sometimes lender to and
past success and future opportunity.
working interest partner of ) GeoPark. [In 2018, we established a
long-term strategic partnership with ONGC, the national oil company
The world is continuously moving in a more regulated direction
of India, to build a large-scale portfolio of upstream assets across
with higher expectations, and to be able to operate in this new
Latin America.] We also have developed long-term relationships with
environment is a fundamental part of business today. We believe that
the national oil companies where we operate, such as with ENAP in
GeoPark’s ability to meet these challenges and perform to or beyond
Chile, Ecopetrol in Colombia, Petrobras in Brazil, YPF in Argentina,
these ever-increasing standards represents a competitive advantage
Petroperu in Peru, and Petroamazonas in Ecuador.
for the future. For example, the results from and impact on the
communities of our overall work and efforts in Chile and Colombia
Critical to the success of any new project is to conduct a thorough
provided the rationale and support for the government and regional
technical and economic analysis prior to acquiring any new asset.
community to encourage us to expand our project into new areas.
We make sure we understand the project, its risks and its value –
The World Bank’s IFC, a founding shareholder, has been a constructive
and we buy right. It is difficult to turn a faulty or overpriced project
force in helping us operate and manage our business in consideration
into a good business. Following intensive geological, geophysical,
of the environment and communities around us. The IFC further
engineering, operational, legal and financial analyses and due
assisted us by carrying out annual audits and physical site visits of
diligence, we perform a detailed discounted cash flow (DCF)
both our regulatory compliance and best-practices approach.
valuation. We also consider the option value or strategic benefits
of a project when entering a new region. We do not buy assets on
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.
- James F. Park, 2008+
GeoPark 21
2018 PERFORMANCE
Record Oil and Gas
Production
• Production up 31% to 36,027 boepd
Record Cost and Investment
Efficiencies
• Capital investment program of $174 million
Portfolio Expansion and
Acreage Growth
• Acquired LG’s 20% equity interest in
• Colombia production up 31% to 28,545
generated $454 million in 2P NPV10
GeoPark’s Chilean and Colombian
bopd
• Adjusted EBITDA/capital expenditure ratio of
subsidiaries, including Llanos 34 Block
• Record exit production of 39,600 boepd
1.9x
• Agreed to South American acquisition
Record Oil and Gas
Reserves
• 1P reserves up 17% to 113.9 million boe
• 2P reserves up 15% to 183.7 million boe
• Colombia 2P reserves up 26% to 111.2
million bbl
Record Asset Values
• 1P reserve NPV10 up 17% to $1.8 billion
• 2P Finding and Development costs:
partnership with ONGC, the national oil
Consolidated $3.6/boe; Colombia $2.9/boe
company of India
• OPEX: Consolidated $8 per boe, Llanos 34
• Divested high-cost, non-core La Cuerva and
Block $4 per boe
Yamu Colombian assets
Record Cash Generation
• Revenues up 82% to $601.2 million
• Acquired new low-cost large exploration
acreage in the Neuquen Basin in Argentina
in partnership with YPF
• Adjusted EBITDA up 88% to $330.6 million
• Closing of low-cost, cash flow producing
• Cash flow from operations up 80% to 256.2
acquisition with development, exploration
million
and unconventional resource upside in the
• 2P reserve NPV10 up 20% to $2.7 billion
• Net debt to Adjusted EBITDA ratio decreased
Neuquen basin in Argentina
• 2P reserve Colombian assets NPV10 up 35%
to 1.0x from 1.7x
to $1.9 billion
• Net debt adjusted 2P NPV10 increased by
37% to $40.1 per share
Record Profits
• Net income of $102.7 million
• Earnings per share of $1.19
Market Performance
• Top performing E&P company on NYSE for
second year in a row (220% increase in two
years)
• Free cash flow of $131.5 million
• Continued improving market visibility with
• $127.7 million of cash in hand
an average daily stock trading volume of
$4.3 million
2007
2008
2009
2010
2011
2012
22 Annual Report 2018 / Performance
Oil
Gas
2019 Outlook
• Capital investment program of $220-240
million
• Drilling program of 35+ exploration,
appraisal and development wells in
Colombia, Argentina, Brazil and Chile
• Targeting organic production growth of
~15%
• 2019 work program is fully funded with
cash flows and can be adapted to provide
production growth under different oil price
scenarios
)
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
35
30
25
20
15
10
5
0
2013
2014
2015
2016
2017
2018
GeoPark 23
OUR STRENGTHS
People
Proven Capabilities Across Full
E&P Value Chain
Track-Record
16-Year Continuous Operational
and Financial Growth
Upside
Organic Exploration and
New Acquisition Growth
Projects
Value
Proven Oil and Gas
Assets With 2P NAV of
$2.4 Billion ($40.1/Share)
Self-Funding
Cash Flow Pays for
Building the Business
Platform
Unique Long-Established High-Impact
Risk-Balanced Asset and Operating Base
Across Latin America
24 Annual Report 2018 / Our Strengths
Morona Block, Marañon Basin, Peru
Morona Block, Marañon Basin, Peru
GeoPark 25
OUR PLATFORM
Mexico
26 Annual Report 2018 / Our Platform
Mexico
Ecuador
2 Blocks1
0.03 mm Acres
Peru
1 Block
1.9 mm Acres
30.3 mmboe
Argentina
7 Blocks2
2.2 mm Acres
14.2 mmboe
Chile
5 Blocks
0.8 mm Acres
24.7 mmboe
Colombia
6 Blocks
0.3 mm Acres
111.1 mmboe
Brazil
8 Blocks3
0.3 mm Acres
3.2 mmboe
Latin American Platform
2P Reserves (Dec. 2018)
Production Assets
Development Assets
Exploration Assets
Unconventional Resource Assets
New Project Opportunities
1Subject to final signature of the contracts
2Includes Los Parlamentos Block subject to regulatory approvals
3Includes PN-T-597 Block subject to entry into the concession agreement by ANP
GeoPark 27
28 Annual Report 2018 / Our Approach
Meta Department, 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.
Meta Department, Colombia
GeoPark 29
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
ZERO
Vehicle
accidents in
6 mm km
220%
Stock price
increase since
December
2016
100%
Employees
are
Shareholders
ISO 14001
Certified in
Colombia.
100% Licenses
Approved
OD
O
G
NEIG
H
B
O
R
AN H
GeoPark is committed
GeoPark is committed
GeoPark is committed
GeoPark is committed
GeoPark is committed
to creating a safe and
to delivering
to creating a motivating
to minimizing the
to being the preferred
healthy workplace.
significant bottom-line
workplace for
impact of our projects
neighbor and partner
Simply speaking,
financial value to our
employees. With today’s
on the environment.
by creating a mutually
everybody must return
shareholders. Only
shortage of capable
As our footprint
beneficial exchange
home everyday safe
a financially-healthy
energy professionals, the
becomes cleaner and
with the local
and sound.
company can continue
company which is able
smaller, the more areas
communities where we
to grow, attract needed
to attract, protect, retain
and opportunities will
work. Unlocking local
resources and create real
and train the best team
be opened up for us to
knowledge creates and
long-term benefits.
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.
30 Annual Report 2018 / Our Value System
12015-2019
GeoPark 31
HIGHLIGHTED SECTIONS
44
64
108
127
135
156
Risk Factors
Information on the Company
Operating and Financial Information
Directors and Management
Major Shareholders and Related Parties
Consolidated Financial Statements
32 Annual Report 2018
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, 2018
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.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
Common shares: 60,483,447
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934.
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, every Interactive Data File required to be submitted 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 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 33
Table of Contents
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
FORWARD-LOOKING STATEMENTS
PART I
37
40
41
ITEM 10. ADDITIONAL INFORMATION
A. Share capital
B. Memorandum of association and bye-laws
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
41
Enforcement of Judgments
139
139
139
144
145
145
145
148
148
148
148
148
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
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
148
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
148
148
148
148
148
148
148
148
149
149
149
149
149
149
149
149
149
149
150
150
150
150
151
145
152
152
152
154
159
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
34 GeoPark 20F
41
41
41
41
41
41
41
41
45
45
45
66
66
68
110
110
110
110
110
126
128
128
128
128
129
129
129
134
136
137
137
138
138
138
138
138
138
138
139
139
139
139
139
139
139
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 2024” are to our 2017 issuance of US$425.0 million aggregate
principal amount of 6.50% senior notes due 2024;
• “US$” 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 35
Financial statements
Non IFRS financial measures
Our consolidated financial statements
Adjusted EBITDA
This annual report includes our audited consolidated financial statements as
management and external users of our financial statements, such as industry
of December 31, 2018 and 2017 and for each of the years ended December 31,
analysts, investors, lenders and rating agencies, to assess the performance of
2018, 2017 and 2016 (hereinafter “Consolidated Financial Statements”).
our Company and the operating segments.
Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by
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
unrealized gains in commodity risk management contracts and bargain
Price Waterhouse & Co. S.R.L., Argentina (“PwC”), a member firm of
purchase gain on acquisition of subsidiaries. Adjusted EBITDA is not a measure
PricewaterhouseCoopers Network, an independent registered public
of profit or cash flows as determined by IFRS.
exploration and evaluation assets, accrual of stock options and stock awards,
accounting firm, as stated in their report included elsewhere in this annual
report.
We believe Adjusted EBITDA is useful because it allows us to more effectively
evaluate our operating performance and compare the results of our
Our fiscal year ends December 31. References in this annual report to a fiscal
operations from period to period without regard to our financing methods or
year, such as “fiscal year 2018,” relate to our fiscal year ended on December 31
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 2018, 2017 and 2016.
of that calendar year.
36 GeoPark 20F
Oil and gas reserves and production information
Rounding
DeGolyer and MacNaughton 2018 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
quantities of proved reserves in Colombia, Chile, Brazil, Argentina and Peru
totals in some tables may not be an arithmetic aggregation of the figures that
is derived, in part, from estimates of the proved reserves as of December 31,
precede them.
2018. The reserves estimates described herein are derived from the DeGolyer
and MacNaughton Reserves Report (“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, Aguada
Baguales, El Porvenir and Puesto Touquet Blocks in Argentina 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 37
Forward-looking Statements
This annual report contains statements that constitute forward-looking
for energy;
statements. Many of the forward-looking statements contained in this
• the direct or indirect impact on our business resulting from terrorist
annual report can be identified by the use of forward-looking words such
incidents or responses to such incidents, including the effect on the
as “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,”
availability of and premiums on insurance; and
“estimate” and “potential,” among others.
• other factors discussed under “Item 3. Key Information—D. Risk factors” in
Forward-looking statements appear in a number of places in this annual
this annual report.
report and include, but are not limited to, statements regarding our intent,
Forward-looking statements speak only as of the date they are made, and we
belief or current expectations. Forward-looking statements are based on
do not undertake any obligation to update them in light of new information or
our management’s beliefs and assumptions and on information currently
future developments or to release publicly any revisions to these statements
available to our management. Such statements are subject to risks and
in order to reflect later events or circumstances or to reflect the occurrence of
uncertainties, and actual results may differ materially from those expressed
unanticipated events.
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,
Argentina, Peru 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 pending or future
acquisitions and dispositions;
• 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
38 GeoPark 20F
PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
The selected historical financial data set forth in this section does not include
any results or other financial information of any acquisitions prior to their
A. Directors and senior management
incorporation into our financial statements.
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, 2018 and 2017 and our consolidated statement of income and cash
flow data for the years ended December 31, 2018, 2017 and 2016 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, 2016, 2015, and 2014 and our consolidated statement
of income and cash flow data for the years ended December 31, 2015 and
2014 from our consolidated financial statements not included in this annual
report.
During 2015, 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 2014 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.
GeoPark 39
Consolidated Statement of income data
For the year ended December 31,
(in thousands of US$, except per share numbers)
2018
2017
2016
2015
2014
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 loss reversed/(recognized) for non-financial assets
Other operating expense
Operating profit (loss)
Financial costs
Foreign exchange (loss) gain
Profit (Loss) before tax
Income tax (expense) benefit
Profit (Loss) for the year
Non-controlling interest
Profit (Loss) attributable to owners of the Company
Earnings (Losses) per share for profit attributable
to owners of the Company—Basic
Earnings (Losses) per share for profit attributable
to owners of the Company—Diluted
Weighted average common shares
outstanding—Basic
Weighted average common shares
outstanding—Diluted
545,490
55,671
601,161
16,173
(174,260)
(13,951)
(52,074)
(4,023)
(92,240)
(26,389)
4,982
(2,887)
256,492
(36,262)
(11,323)
208,907
(106,240)
102,667
30,252
72,415
1.19
1.11
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
-
(131,419)
(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
60,612,230
60,093,191
59,777,145
57,759,001
56,396,812
65,370,782
60,093,191
59,777,145
57,759,001
58,840,412
Common Shares outstanding at year-end
60,483,447
60,596,219
59,940,881
59,535,614
57,790,533
40 GeoPark 20F
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
Derivative financial instrument assets
Cash and cash equivalents
Assets held for sale
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
Liabilities associated with assets held for sale
Total current liabilities
Total liabilities
2018
2017
2016
2015
2014
557,170
517,403
473,646
522,611
790,767
3,275
10,570
31,793
219
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
603,027
571,207
519,339
571,955
838,543
898
9,309
16,215
9,489
45,170
27,539
127,727
23,286
259,633
862,660
60
237,840
(94,879)
143,021
–
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
143,021
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
429,027
42,577
14,789
14,801
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
-
-
8,532
36,917
13,993
13,459
-
82,730
127,672
-
131,844
703,799
59
232,005
(85,412)
146,652
53,515
200,167
343,248
42,450
19,556
16,955
-
200,573
1,039,116
58
210,886
164,613
375,557
103,569
479,126
342,440
46,910
16,583
30,065
501,194
493,031
399,434
422,209
435,998
17,975
-
58,776
131,420
10,274
218,445
719,639
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
Total equity and liabilities
862,660
786,163
640,540
703,799
1,039,116
GeoPark 41
Cash flow data
For the year ended December 31,
(In thousands of US$)
Cash provided by (used in)
Operating activities
Investing activities
Financing activities
Net (decrease) increase in cash and cash equivalents
Other financial data
2018
2017
2016
2015
2014
256,206
(164,594)
(97,641)
(6,029)
142,158
(105,604)
23,968
60,522
82,884
(39,306)
(51,136)
(7,558)
25,895
(48,842)
(18,022)
(40,969)
230,746
(344,041)
124,716
11,421
For the year ended December 31,
2018
2017
2016
2015
2014
Adjusted EBITDA(1) (US$ thousands)
Adjusted EBITDA margin(2)
Adjusted EBITDA per boe(3)
330,556
55.0%
26.5
175,776
53.2%
18.4
78,321
40.6%
10.2
73,787
35.2%
10.5
220,077
51.3%
33.0
(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.
42 GeoPark 20F
Exchange rates
In Colombia, Chile, Argentina and Peru, our functional currency is the U.S.
The prices that we receive for our oil and natural gas production heavily
dollar. In Brazil, our functional currency is the real.
influence our revenues, profitability, access to capital and growth rate.
Historically, the markets for oil, natural gas and methanol (which have
Our operations in Brazil accounted for 12% and 8% of our consolidated assets
influenced prices for almost all of our Chilean gas sales) have been volatile and
and 10% and 5% of our revenues for the years ended December 31, 2017
will likely continue to be volatile in the future. International oil, natural gas and
and 2018, respectively. This portion of our business is exposed to losses that
methanol prices have fluctuated widely in recent years and may continue to
may arise from currency fluctuation, as a significant amount of our revenues,
do so in the future.
operating costs, administrative expenses and taxes in Brazil are denominated
in reais.
The prices that we will receive for our production and the levels of our
production depend on numerous factors beyond our control. These factors
The real may depreciate or appreciate substantially against the U.S. dollar.
include, but are not limited, to the following:
We recorded exchange rate losses amounting to US$5.9 million for the year
ended December 31, 2018, principally due to the devaluation of the real
• global economic conditions;
and its impact on US dollar denominated intercompany debt cancelled by
• changes in global supply and demand for oil, natural gas and methanol;
our Brazilian subsidiary in October 2018. We recorded exchange rate losses
• the actions of the Organization of the Petroleum Exporting Countries
amounting to US$1.3 million for the year ended December 31, 2017 as a result
(“OPEC”);
of the devaluation of the local currency in our Brazilian subsidiary which was
• political and economic conditions, including embargoes, in oil-producing
mainly generated by the credit facility with Itaú BBA International plc that
countries or affecting other countries;
we incurred on March 31, 2014 to acquire Rio das Contas, which we repaid in
• the level of oil- and natural gas-producing activities, particularly in the
September 2017. See “—D. Risk factors—Risks relating to our business—Our
Middle East, Africa, Russia, South America and the United States;
results of operations could be materially adversely affected by fluctuations in
• the level of global oil and natural gas exploration and production activity;
foreign currency exchange rates.”
• the level of global oil and natural gas inventories;
Exchange rate fluctuation may affect the US$ value of any distributions we
• availability of markets for natural gas;
make with respect to our common shares. See “—D. Risk factors—Risks
• weather conditions and other natural disasters;
relating to our business—Our results of operations could be materially
• technological advances affecting energy production or consumption;
adversely affected by fluctuations in foreign currency exchange rates.”
• domestic and foreign governmental laws and regulations, including
• the price of methanol;
B. Capitalization and indebtedness
Not applicable.
environmental, health and safety laws and regulations;
• proximity and capacity of oil and natural gas pipelines and other
transportation facilities;
• the price and availability of competitors’ supplies of oil and natural gas in
C. Reasons for the offer and use of proceeds
captive market areas;
Not applicable.
D. Risk factors
• quality discounts for oil production based, among other things, on API,
sulphur and mercury content;
• taxes and royalties under relevant laws and the terms of our contracts;
Our business, financial condition and results of operations could be materially
• our ability to enter into oil and natural gas sales contracts at fixed prices;
and adversely affected if any of the risks described below occur. As a result,
• the level of global methanol demand and inventories and changes in the
the market price of our common shares could decline, and you could lose all
uses of methanol;
or part of your investment. This annual report also contains forward-looking
• the price and availability of alternative fuels; and
statements that involve risks and uncertainties. See “Forward-Looking
• future changes to our hedging policies.
Statements.” The risks below are not the only ones facing our Company.
Additional risks not currently known to us or that we currently deem immaterial
These factors and the volatility of the energy markets make it extremely
may also adversely affect us.
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, 2014 to December 31, 2018, Brent spot prices ranged from
a low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub
A substantial or extended decline in oil, natural gas and methanol prices
natural gas average spot prices ranged from a low of US$1.7 per mmbtu to
may materially adversely affect our business, financial condition or results
a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged
of operations.
GeoPark 43
Risk factors
from a low of US$250.0 per metric ton to a high of US$635.1 per metric
See Note 8 to our Consolidated Financial Statements for details regarding
ton. Furthermore, oil, natural gas and methanol prices do not necessarily
Commodity Risk Management Contracts.
fluctuate in direct relationship to each other.
For the year ended December 31, 2018, 91% of our revenues were derived
from oil. Because we expect that our production mix will continue to be
We face limitations on our ability to increase prices or improve ma rgins
weighted towards oil, our financial results are more sensitive to movements
on the oil and natural gas that we sell. As a consequence of the oil price
The oil price crisis has impacted our operations and corporate strategy.
in oil prices.
crisis which started in the second half of 2014 (WTI and Brent, the main
international oil price markers, fell by more than 60% between August 2014
As of December 31, 2018, natural gas comprised 9% of our revenues. A
and March 2016), the Company took decisive measures to ensure its ability
decline in natural gas prices could negatively affect our future growth,
to both maximize ongoing projects and to preserve its cash.
particularly for future gas sales where we may not be able to secure or
extend our current long-term contracts.
Funding our anticipated capital expenditures relies in part on oil prices
remaining close to our estimates or higher levels and other factors to
Lower oil and natural gas prices may impact our revenues on a per unit
generate sufficient cash flow. Low oil prices affect our revenues, which
basis, and may also reduce the amount of oil and natural gas that can
in turn affect our debt capacity and the covenants in our financing
be produced economically. In addition, changes in oil and natural gas
agreements, as well as the amount of cash we can borrow using our oil
prices can impact the valuation of our reserves and, in periods of lower
reserves as collateral, the amount of cash we are able to generate from
commodity prices, we may curtail production and capital spending or may
current operations and the amount of cash we can obtain from prepayment
defer or delay drilling wells because of lower cash generation. Lower oil
agreements. If we are not able to generate the sales which, together with
and natural gas prices could also affect our growth, including future and
our current cash resources, are sufficient to fund our capital program, we
pending acquisitions. A substantial or extended decline in oil or natural gas
will not be able to efficiently execute our work program, which would cause
prices could adversely affect our business, financial condition and results of
us to further decrease our work program and would harm our business
operations.
outlook, investor confidence and our share price.
For example, during 2014 and 2015, we evaluated the recoverability of our
In addition, actions taken by the company to maximize ongoing projects
fixed assets affected by the oil price decline and recorded an impairment
and to reduce expenses, including renegotiations and reduction of oil
of non-financial assets amounting to, respectively, US$9.4 million and
and gas service contracts and other initiatives such as cost cutting may
US$149.6 million. US$5.7 million of the impairment recorded in 2015 was
expose us to claims and contingencies from interested parties that may
reversed in 2016 due to increased estimated market prices for 2017 and
have a negative impact on our business, financial condition, results of
2018 and improvements in cost structure. After conducting an impairment
operations and cash flows. If oil prices are lower than expected, we may be
test procedure for the year ended December 31, 2018 we recognized US$
unable to meet our contractual obligations with oil and service contracts
11.5 million as reversal of impairment losses due to increases in estimated
and our suppliers. Equally, those third parties may be unable to meet their
market prices and improvements in cost structure, and also the known fair
contractual obligations to us as a result of the oil price crisis, impacting on
value less costs of disposal of the La Cuerva and Yamu Blocks in Colombia,
our operations.
partially offset by an impairment loss in Chile of US$ 6.5 million due to the
termination of the sales agreement for the TdF’s blocks, with no renovation
In budgeting for our future activities, we have relied on a number of
in place as of the date of this annual report. See Note 36 to our Consolidated
assumptions, including, with regard to our discovery success rate, the
Financial Statements for details regarding oil price scenarios, discount rates
number of wells we plan to drill, our working interests in our prospects,
considered and sensitivity analysis affecting the impairment charges.
the costs involved in developing or participating in the development of a
prospect, the timing of third-party projects and our ability to obtain needed
Continuing our hedging strategy, we entered into derivative financial
financing with respect to any further acquisitions and the availability of
instruments to manage exposure to oil price risk. These derivatives were
both suitable equipment and qualified personnel. These assumptions are
zero-premium collars or zero premium three way hedges (put, spread and
inherently subject to significant business, political, economic, regulatory,
call) and were placed with major financial institutions and commodity
environmental and competitive uncertainties, conditions in the financial
traders. We entered into the derivatives under ISDA Master Agreements
markets, contingencies and risks, all of which are difficult to predict and
and Credit Support Annexes, which provide credit lines for collateral
many of which are beyond our control. In addition, we opportunistically
posting thus alleviating possible liquidity needs under the instruments and
seek out new assets and acquisition targets to complement our existing
protecting us from potential non-performance risk by our counterparties.
operations and have financed such acquisitions in the past through
44 GeoPark 20F
the incurrence of additional indebtedness, including additional bank
and our business, financial condition and results of operations will be
credit facilities, equity issuances or the sale of minority stakes in certain
materially adversely affected.
operations to our partners. We may need to raise additional funds more
quickly if one or more of our assumptions prove to be incorrect or if we
We derive a significant portion of our revenues from sales to a few key
choose to expand our hydrocarbon asset acquisition, exploration, appraisal
customers.
or development efforts more rapidly than we presently anticipate, and
we may decide to raise additional funds even before we need them if the
In Colombia, for the year ended December 31, 2018, we made 99% of our oil
conditions for raising capital are favorable. The ultimate amount of capital
sales from operated blocks to C.I. Trafigura Petroleum Colombia S.A.S., a leading
that we will expend may fluctuate materially based on market conditions,
commodity trading and logistics company (“Trafigura”), representing 82% of
our continued production, decisions by the operators in blocks where
our consolidated revenues for the same period. Considering the expiration
we are not the operator, the success of our drilling results and future
of our long-term contract with Trafigura in December 2018, we have started
acquisitions. Our future financial condition and liquidity will be impacted
diversifying our client base in Colombia, allocating sales on a competitive basis
by, among other factors, our level of production of oil and natural gas and
to leading industry participants including traders and other producers. The
the prices we receive from the sale thereof, the success of our exploration
contracts extend through 2019 with no long-term delivery commitments in
and appraisal drilling program, the number of commercially viable oil
place. Delivery points include wellhead and other locations in the Colombian
and natural gas discoveries made and the quantities of oil and natural
pipeline system. We manage the counterparty credit risk associated to sales
gas discovered, the speed with which we can bring such discoveries to
contracts by including early payment conditions which minimize our exposure.
production and the actual cost of exploration, appraisal and development
of our oil and natural gas assets.
In Chile, 100% of our crude oil and condensate sales are made to ENAP. For
the year ended December 31, 2018, sales to ENAP represented 3% of our
Unless we replace our oil and natural gas reserves, our reserves and
total revenues. ENAP imports the majority of the oil it refines and partially
production will decline over time. Our business is dependent on our
supplements those imports with volumes supplied locally by its own operated
continued successful identification of productive fields and prospects and
fields and those operated by us. On April 21, 2017, we renewed our sales
the identified locations in which we drill in the future may not yield oil or
agreement with ENAP. As part of this agreement, ENAP has committed to
natural gas in commercial quantities.
purchase our oil production in the Fell Block in the amounts that we produce,
subject to the limitation of available storage capacity at the Gregorio Terminal.
Production from oil and gas properties declines as reserves are depleted,
The sales agreement provides us with the option to interrupt sales to ENAP
with the rate of decline depending on reservoir characteristics. Accordingly,
periodically if conditions in the export markets allow for more competitive
our current proved reserves will decline as these reserves are produced. As
price levels. While the agreement renews automatically on an annual basis,
of December 31, 2018, our reserves-to-production (or reserve life) ratio for
we typically make an annual revision jointly with ENAP. In addition, for the
net proved reserves in Colombia, Chile, Argentina, Brazil and Peru was 8.2
year ended December 31, 2018, almost all of our natural gas sales in Chile
years. According to estimates, if on January 1, 2019 we ceased all drilling
were made to Methanex Chile SpA., the Chilean subsidiary of the Methanex
and development activities, including recompletions, refracs and workovers,
Corporation (“Methanex”), a leading global methanol producer, under a long-
our proved developed producing reserves base in Colombia, Chile, Brazil,
term contract (the “Methanex Gas Supply Agreement”), which will expire on
Argentina and Peru would decline 34% during the first year.
December 31, 2026. Sales to Methanex represented 3% of our consolidated
revenues for the year ended December 31, 2018.
Our future oil and natural gas reserves and production, and therefore our
cash flows and income, are highly dependent on our success in efficiently
In Brazil, all of our gas and condensate produced in the Manati Field is sold to
developing our current reserves and using cost-effective methods to find
Petróleo Brasileiro S.A. (“Petrobras”), the operator of the Manati Field, pursuant
or acquire additional recoverable reserves. While we have had success in
to a long-term gas off-take contract and a condensate purchase agreement.
identifying and developing commercially exploitable fields and drilling
See “Item 4. Information on the Company—B. Business Overview—Significant
locations in the past, we may be unable to replicate that success in the
Agreements—Brazil—Petrobras Natural Gas Purchase Agreement.”
future. We may not identify any more commercially exploitable fields or
successfully drill, complete or produce more oil or gas reserves, and the
In Argentina, all the gas produced in 2018 was sold to Grupo Albanesi, a leading
wells which we have drilled and currently plan to drill within our blocks or
Argentine privately held conglomerate focused on the energy market that
concession areas may not discover or produce any further oil or gas or may
offers natural gas and power supply and transport services to its customers.
not discover or produce additional commercially viable quantities of oil or
We have an annual agreement effective from May 2018 through April 2019.
gas to enable us to continue to operate profitably. If we are unable to replace
Gas sales in Argentina represented 1% of our total revenue. The oil sales in
our current and future production, the value of our reserves will decrease,
Argentina are diversified across clients and delivery points: i) 30% of the oil
GeoPark 45
produced in Argentina (2% of our total revenue) is sold locally in Neuquén
our business, financial condition and results of operations.
Province, delivered at well-head; and ii) 70% of the oil produced in Argentina
(3% of our total revenues) is sold to major Argentine refineries, and delivered
There are inherent risks and uncertainties relating to the exploration and
via pipeline.
production of oil and natural gas.
If any of our buyers were to decrease or cease purchasing oil or gas from us,
Our performance depends on the success of our exploration and
or if any of them were to decide not to renew their contracts with us or to
production activities and on the existence of the infrastructure that will
renew them at a lower sales price, this could have a material adverse effect on
allow us to take advantage of our oil and gas reserves. Oil and natural
our business, financial condition and results of operations. For example, see
gas exploration and production activities are subject to numerous risks
“Item 4. Information on the Company—B. Business Overview—Significant
beyond our control, including the risk that exploration activities will not
Agreements—Colombia” and “Item 4. Information on the Company—B.
identify commercially viable quantities of oil or natural gas. Our decisions
Business Overview—Significant Agreements—Chile.”
to purchase, explore, develop or otherwise exploit prospects or properties
will depend in part on the evaluation of seismic and other data obtained
Our results of operations could be materially adversely affected by
through geophysical, geochemical and geological analysis, production
fluctuations in foreign currency exchange rates.
data and engineering studies, the results of which are often inconclusive or
subject to varying interpretations.
Although a majority of our net revenues is denominated in US$, unfavorable
fluctuations in foreign currency exchange rates for certain of our expenses in
Furthermore, the marketability of any oil and natural gas production from
Colombia, Chile, Brazil, Argentina and Peru could have a material adverse effect
our projects may be affected by numerous factors beyond our control.
on our results of operations. A portion of the cost reductions that we achieved
These factors include, but are not limited to, proximity and capacity of
in 2015 and 2016 (as compared to 2014) were related to the depreciation of
pipelines and other means of transportation, the availability of upgrading
local currencies, including mainly the Col$, the Ch$ and the Brazilian real. An
and processing facilities, equipment availability and government laws and
appreciation of local currencies can increase our costs and negatively impact
regulations (including, without limitation, laws and regulations relating to
our results from operations.
prices, sale restrictions, taxes, governmental stake, allowable production,
importing and exporting of oil and natural gas, environmental protection
Because our Consolidated Financial Statements are presented in US$, we must
and health and safety). The effect of these factors, individually or jointly,
translate revenues, expenses and income, as well as assets and liabilities, into
cannot be accurately predicted, but may have a material adverse effect on
US$ at exchange rates in effect during or at the end of each reporting period. In
our business, financial condition and results of operations.
December 2018, we decided to manage exposure to local currency fluctuation
with respect to income tax balances in Colombia. Consequently, we entered
There can be no assurance that our drilling programs will produce oil
into a derivative financial instrument with a local bank in Colombia, for an
and natural gas in the quantities or at the costs anticipated, or that our
amount equivalent to US$ 92.1 million, in order to anticipate any currency
currently producing projects will not cease production, in part or entirely.
fluctuation with respect to estimated income taxes to be paid during the first
Drilling programs may become uneconomic as a result of an increase in
half of 2019.
our operating costs or as a result of a decrease in market prices for oil and
natural gas. Our actual operating costs or the actual prices we may receive
Through our Brazilian operations, we are exposed to fluctuations in the
for our oil and natural gas production may differ materially from current
real against the US$, as our Brazilian revenues and expenses are mostly
estimates. In addition, even if we are able to continue to produce oil and
denominated in reais. In the past, the Brazilian Central Bank has occasionally
gas, there can be no assurance that we will have the ability to market our oil
intervened to control unstable movements in foreign exchange rates. We
and gas production. See “—Our inability to access needed equipment and
cannot predict whether the Brazilian Central Bank or the Brazilian government
infrastructure in a timely manner may hinder our access to oil and natural
will continue to permit the real to float freely or will intervene in the exchange
gas markets and generate significant incremental costs or delays in our oil
rate market through the return of a currency band system or otherwise.
and natural gas production” below.
Furthermore, Brazilian law provides that, whenever there is a serious imbalance
in Brazil’s balance of payments or there are reasons to foresee a serious
Our identified potential drilling location inventories are scheduled over
imbalance, temporary restrictions may be imposed on remittances of foreign
many years, making them susceptible to uncertainties that could materially
capital abroad. We cannot assure you that such measures will not be taken by
alter the occurrence or timing of their drilling.
the Brazilian government in the future. The real has experienced frequent and
substantial variations in relation to the US$ and other foreign currencies, which
Our management team has specifically identified and scheduled certain
could materially and adversely affect the growth of the Brazilian economy and
potential drilling locations as an estimation of our future multi-year drilling
46 GeoPark 20F
activities on our existing acreage. These identified potential drilling locations,
Oil and gas operations contain a high degree of risk and we may not be fully
including those without proved undeveloped reserves, represent a significant
insured against all risks we face in our business.
part of our growth strategy.
Oil and gas exploration and production is speculative and involves a high
Our ability to drill and develop these identified potential drilling locations
degree of risk and hazards. In particular, our operations may be disrupted
depends on a number of factors, including oil and natural gas prices, the
by risks and hazards that are beyond our control and that are common
availability and cost of capital, drilling and production costs, the availability
among oil and gas companies, including environmental hazards, blowouts,
of drilling services and equipment, drilling results, lease expirations, the
industrial accidents, occupational safety and health hazards, technical
availability of gathering systems, marketing and transportation constraints,
failures, labor disputes, community protests or blockades, unusual or
refining capacity, regulatory approvals and other factors. Because of the
unexpected geological formations, flooding, earthquakes and extended
uncertainty inherent in these factors, there can be no assurance that the
interruptions due to weather conditions, explosions and other accidents.
numerous potential drilling locations we have identified will ever be drilled or,
if they are, that we will be able to produce oil or natural gas from these or any
While we believe that we maintain customary insurance coverage for
other potential drilling locations.
companies engaged in similar operations, we are not fully insured against
all risks in our business. In addition, insurance that we do and plan to carry
Our business requires significant capital investment and maintenance
may contain significant exclusions from and limitations on coverage. We
expenses, which we may be unable to finance on satisfactory terms or at all.
may elect not to obtain certain non-mandatory types of insurance if we
believe that the cost of available insurance is excessive relative to the risks
Because the oil and natural gas industry is capital intensive, we expect to
presented. The occurrence of a significant event or a series of events against
make substantial capital expenditures in our business and operations for
which we are not fully insured and any losses or liabilities arising from
the exploration and production of oil and natural gas reserves. See “Item 4.
uninsured or underinsured events could have a material adverse effect on
Information on the Company –B. Business Overview—2019 Strategy and
our business, financial condition or results of operations.
Outlook.” We incurred capital expenditures of US$125 million and US$106
million during the years ended December 31, 2018 and 2017, respectively.
The development schedule of oil and natural gas projects is subject to cost
See “Item 5. Operating and Financial Review and Prospects—A. Operating
overruns and delays.
Results—Factors Affecting our Results of Operations—Discovery and
exploitation of reserves.”
Oil and natural gas projects may experience capital cost increases and
overruns due to, among other factors, the unavailability or high cost of drilling
The actual amount and timing of our future capital expenditures may differ
rigs and other essential equipment, supplies, personnel and oil field services.
materially from our estimates as a result of, among other things, commodity
The cost to execute projects may not be properly established and remains
prices, actual drilling results, the availability of drilling rigs and other
dependent upon a number of factors, including the completion of detailed
equipment and services, and regulatory, technological and competitive
cost estimates and final engineering, contracting and procurement costs.
developments. In response to changes in commodity prices, we may increase
Development of projects may be materially adversely affected by one or more
or decrease our actual capital expenditures. We intend to finance our future
of the following factors:
capital expenditures through cash generated by our operations and potential
• shortages of equipment, materials and labor;
future financing arrangements. However, our financing needs may require
• fluctuations in the prices of construction materials;
us to alter or increase our capitalization substantially through the issuance of
• delays in delivery of equipment and materials;
debt or equity securities or the sale of assets.
•
labor disputes;
• political events;
If our capital requirements vary materially from our current plans, we may
• title problems;
require further financing. In addition, we may incur significant financial
• obtaining easements and rights of way;
indebtedness in the future, which may involve restrictions on other financing
• blockades or embargoes;
and operating activities. We may also be unable to obtain financing or
•
litigation;
financing on terms favorable to us. These changes could cause our cost
• compliance with governmental laws and regulations, including
of doing business to increase, limit our ability to pursue acquisition
environmental, health and safety laws and regulations;
opportunities, reduce cash flow used for drilling and place us at a competitive
• adverse weather conditions;
disadvantage. A significant reduction in cash flows from operations or the
• unanticipated increases in costs;
availability of credit could materially adversely affect our ability to achieve our
• natural disasters;
planned growth and operating results.
• accidents;
GeoPark 47
• transportation;
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, Argentina, Brazil,
and Peru as of December 31, 2018 are based on the D&M Reserves Report.
Any of these events or other unanticipated events could give rise to delays in
Although classified as “proved reserves,” the reserves estimates set forth in
development and completion of our projects and cost overruns.
the D&M Reserves Reports are based on certain assumptions that may prove
For example, in 2017, the drilling and completion cost for the exploratory well
in estimates included oil and gas sales prices determined according to SEC
Río Grande Oeste x-1 in our CN-V Block in Argentina was originally estimated
guidelines, future expenditures and other economic assumptions (including
at US$4.2 million, but the actual cost was US$5.5 million, mainly due to
interests, 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
inaccurate. DeGolyer and MacNaughton’s primary economic assumptions
accumulations of oil and gas that cannot be measured in an exact way,
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
be expensive to develop, purchase and implement and may not function
oil and gas, many of which are beyond our control. Results of drilling, testing
as expected. Such uncertainties and operating risks associated with
and production after the date of the estimate may require revisions to be
development projects could have a material adverse effect on our business,
made. For example, if we are unable to sell our oil and gas to customers, this
results of operations or financial condition.
may impact the estimate of our oil and gas reserves. Accordingly, reserves
Competition in the oil and natural gas industry is intense, which makes it
are ultimately recovered, and if such recovered quantities are substantially
difficult for us to attract capital, acquire properties and prospects, market
lower than the initial reserves estimates, this could have a material adverse
oil and natural gas and secure trained personnel.
impact on our business, financial condition and results of operations.
estimates are often materially different from the quantities of oil and gas that
We compete with the major oil and gas companies engaged in the exploration
Our inability to access needed equipment and infrastructure in a timely
and production sector, including state-owned exploration and production
manner may hinder our access to oil and natural gas markets and generate
companies that possess substantially greater financial and other resources
significant incremental costs or delays in our oil and natural gas production.
than we do for researching and developing exploration and production
technologies and access to markets, equipment, labor and capital required
Our ability to market our oil and natural gas production depends substantially
to acquire, develop and operate our properties. We also compete for the
on the availability and capacity of processing facilities, oil tankers,
acquisition of licenses and properties in the countries in which we operate.
transportation facilities (such as pipelines, crude oil unloading stations and
trucks) and other necessary infrastructure, which may be owned and operated
Our competitors may be able to pay more for productive oil and natural
by third parties. Our failure to obtain such facilities on acceptable terms or
gas properties and exploratory prospects and to evaluate, bid for and
on a timely basis could materially harm our business. We may be required to
purchase a greater number of properties and prospects than our financial or
shut down oil and gas wells because access to transportation or processing
personnel resources permit. Our competitors may also be able to offer better
facilities may be limited or unavailable when needed. If that were to occur, then
compensation packages to attract and retain qualified personnel than we are
we would be unable to realize revenue from those wells until arrangements
able to offer. In addition, there is substantial competition for capital available
were made to deliver the production to market, which could cause a material
for investment in the oil and natural gas industry. As a result of each of the
adverse effect on our business, financial condition and results of operations.
aforementioned, we may not be able to compete successfully in the future in
In addition, the shutting down of wells can lead to mechanical problems
acquiring prospective reserves, developing reserves, marketing hydrocarbons,
upon bringing the production back on line, potentially resulting in decreased
attracting and retaining quality personnel or raising additional capital, which
production and increased remediation costs. The exploitation and sale of oil
could have a material adverse effect on our business, financial condition or
and natural gas and liquids will also be subject to timely commercial processing
results of operations. See “Item 4. Information on the Company—B. Business
and marketing of these products, which depends on the contracting, financing,
Overview—Our competition.”
building and operating of infrastructure by third parties.
48 GeoPark 20F
In Colombia, producers of crude oil have historically suffered from tanker
In addition, as the Morona Block is located in a remote area of the tropical
transportation logistics issues and limited pipeline and storage capacity, which
rainforest, the development of the project involves significant infrastructure
cause delays in delivery and transfer of title of crude oil. Such capacity issues
to be built, including processing facilities, storages tanks and a 37 kilometers-
in Colombia may require us to transport crude from our Colombian operations
long flexible pipeline which is required to start production. In addition, the full
via truck, which may increase the costs of those operations. Road infrastructure
development of the project would require a 97 kilometers-long pipeline from
is limited in certain areas in which we operate, and certain communities have
the site to the North Peruvian Pipeline. Also, as there are no roads available
used and may continue to use road blockages, which can sometimes interfere
in the surrounding area, logistics will be performed by helicopters or barges.
with our operations in these areas. For example, in 2018, the main delivery
These issues may lead us to incur significant costs or investments that may not
point for the Colombian production was Oleoducto de Los Llanos “ODL.” During
be recoverable through our commercial activities in the Morona Block.
the last week of July 2018, the operation of the Ocensa Pipeline, which receives
oil flow from the ODL Pipeline, was disrupted because of a contingency.
In Argentina, we deliver a portion of our oil production and all of our gas
Although we were able to enable alternative delivery points and transport oil
production via existing pipeline infrastructure controlled by third parties.
by trucks, avoiding any negative impact in our production during this period,
While both the oil and gas pipeline systems in Argentina are well-developed
we cannot assure we would be able to do so in the future.
and have operated reliably in the past, we cannot guarantee this will continue
In Chile, we transport the crude oil we produce in the Fell Block by truck to
may become insufficient. We also deliver a portion of our crude production
ENAP’s processing, storage and selling facilities at the Gregorio Refinery.
at well-head. This volume is lifted from our loading facilities by third-party
As of the date of this annual report, ENAP purchases all of the crude oil we
operated trucks contracted by our clients. The roads around our fields are in
produce in Chile. We rely upon the continued good condition, maintenance
good condition but changes in those conditions could adversely affect our
and accessibility of the roads we use to deliver the crude oil we produce. If
operations. Our failure to secure transportation or access to pipelines or other
the condition of these roads were to deteriorate or if they were to become
facilities on acceptable terms or on a timely basis could materially harm our
in the future. In addition, as Argentina’s production grows, pipeline capacity
inaccessible for any period of time, this could delay delivery of crude oil in Chile
business.
and materially harm our business.
Through our Brazilian operations, we face operational risks relating to
In the Fell Block, we depend on ENAP-owned gas pipelines to deliver the gas
offshore drilling.
we produce to Methanex, the principal purchaser of the gas we produce. If
ENAP’s pipelines were unavailable, this could have a materially adverse effect
Our operations in the BCAM-40 Concession in Brazil may include shallow-
on our ability to deliver and sell our product to Methanex, which could have a
offshore drilling activity in one area in the Camamu-Almada Basin, which we
material adverse effect on our gas sales. In addition, gas production in some
expect will continue to be operated by Petrobras.
areas in the Tierra del Fuego Blocks and the Tranquilo Block could require us
in the future to build a new network of gas pipelines in order for us to be able
Offshore operations are subject to a variety of operating risks and laws and
to deliver our product to market, which could require us to make significant
regulations, including among other things, with respect to environmental,
capital investments.
health and safety matters, specific to the marine environment, such as
capsizing, collisions and damage or loss from hurricanes or other adverse
While Brazil has a well-developed network of hydrocarbon pipelines, storage
weather conditions. These conditions can cause substantial damage to
and loading facilities, we may not be able to access these facilities when
facilities and interrupt production. As a result, we could incur substantial
needed. Pipeline facilities in Brazil are often full and seasonal capacity
liabilities, compliance costs, fines or penalties that could reduce or eliminate
restrictions may occur, particularly in natural gas pipelines. Our failure to secure
the funds available for exploration, development or leasehold acquisitions, or
transportation or access to pipelines or other facilities once we commence
result in loss of equipment and properties. For example, the Manati Field has
operations in the concessions we were awarded in Brazil on acceptable terms
been subject to administrative infraction notices, which have resulted in fines
or on a timely basis could materially harm our business.
against Petrobras in an aggregate amount of approximately US$12 million,
In Peru, future production in the Morona Block is expected to be transported
Environment and Natural Renewable Resources (Instituto Brasileiro do Meio-
through the existing North Peruvian Pipeline, which was out of service in
Ambiente e dos Recursos Naturais Renováveis). Although the administrative
2017 due to technical issues and presented some interruptions to service
fines were filed against Petrobras, as a party to the concession agreement
during 2018. Though the Peruvian government is implementing a program to
governing the Manati Field, we may be liable up to our participation interest
all of which are pending a final decision of the Brazilian Institute for the
maintain and modernize the pipeline, future technical issues, other general
of 10%.
infrastructure problems or social unrest affecting pipeline operation may
adversely affect the recoverability of our future investments, our future
Additionally, offshore drilling generally requires more time and more
production or revenues related to the Morona Block.
GeoPark 49
advanced drilling technologies, involving a higher-risk of technological
We may suffer delays or incremental costs due to difficulties in negotiations
failure and usually higher drilling costs. Offshore projects often lack proximity
with landowners and local communities, including native communities,
to existing oilfield service infrastructure, necessitating significant capital
where our reserves are located.
investment in flow line infrastructure before we can market the associated oil
or gas of a commercial discovery, increasing both the financial and operational
Access to the sites where we operate requires agreements (including,
risk involved with these operations. Because of the lack and high cost of
for example, assessments, rights of way and access authorizations) with
infrastructure, some offshore reserve discoveries may never be produced
landowners and local communities. If we are unable to negotiate agreements
economically.
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.
Further, because we are not the operator of our offshore fields, all of these
In Chile and in Argentina, for example, we have negotiated the necessary
risks may be heightened since they are outside of our control. We have a
agreements for many of our current operations in the Magallanes Basin, in
10% interest in the Manati Field which limits our operating flexibility in such
Neuquén and in Mendoza (when we had the operatorship of the CN-V Block),
offshore fields. See “—We are not, and may not be in the future, the sole owner
respectively. In Brazil, in the event that social unrest continues or intensifies,
or operator of all of our licensed areas and do not, and may not in the future,
this may lead to delays or damage relating to our ability to operate the assets
hold all of the working interests in certain of our licensed areas. Therefore, we
we have acquired or may acquire in our Brazil Acquisitions.
may not be able to control the timing of exploration or development efforts,
associated costs, or the rate of production of any non-operated and, to an
In Colombia, although we have agreements with many landowners and are
extent, any non-wholly-owned, assets.”
in negotiations with others, we expect our costs to increase following current
Our pending acquisition of the Espejo and Perico blocks in Ecuador is subject
expectations of landowners have generally increased, which may delay
and future negotiations regarding access to our blocks, as the economic
to regulatory approvals.
access to existing or future sites. In addition, the expectations and demands
of local communities on oil and gas companies operating in Colombia may
In March 2019, GeoPark, in consortium with Frontera (50% GeoPark, 50%
also increase. As a result, local communities have demanded that oil and
Frontera) was awarded the Espejo and Perico blocks in the form of production
gas companies invest in remediating and improving public access roads,
sharing contracts in the Intracampos Bid Round carried out on March 12, 2019
compensate them for any damages related to use of such roads and, more
in Quito, Ecuador. The closing of the acquisition is subject to the occurrence of
generally, invest in infrastructure that was previously paid for with public
certain conditions, including obtaining other governmental approvals. Failure
funds. Due to these circumstances, oil and gas companies in Colombia,
to obtain such approvals may result in the termination of the agreement. We
including us, are now dealing with increasing difficulties resulting from
expect the transaction to close in the second quarter of 2019 but we cannot
instances of social unrest, temporary road blockages and conflicts with
guarantee that the regulatory approvals will be obtained by that time or that
landowners.
the acquisition will be completed on this timeline.
There can be no assurance that disputes with landowners and local
Following the eventual completion of this acquisition, conducting operations
communities will not delay our operations or that any agreements we reach
in Ecuador, a new jurisdiction for us, will subject us to risks that are inherent
with such landowners and local communities in the future will not require us
for foreign companies operating in Ecuador, including challenges posed
to incur additional costs, thereby materially adversely affecting our business,
by different laws and customs; lack of familiarity and burdens of complying
financial condition and results of operations. Local communities may also
with such foreign laws, legal standards, regulatory requirements, tariffs
protest or take actions that restrict or cause their elected government to
and other barriers; unexpected changes in regulatory requirements, taxes,
restrict our access to the sites of our operations, which may have a material
trade laws, tariffs, export quotas, custom duties or other trade restrictions;
adverse effect on our operations at such sites.
potential difficulties in collecting accounts receivable; difficulties in managing
and staffing operations; varying expectations as to employee standards;
In Peru, the Morona Block is located in land inhabited by native communities.
potentially adverse tax consequences, including possible restrictions on the
Though we have already signed certain agreements with native communities
repatriation of earnings. Moreover, operations in Ecuador could be interrupted
authorizing the execution of the environmental impact assessment for the
and negatively affected by economic changes, geopolitical regional conflicts,
Morona Project, which the environmental authority is currently analyzing,
terrorist activity, political unrest, civil strife, acts of war and other economic or
similar projects in the Peruvian rainforest have faced significant social conflicts
political uncertainties. All of these risks could result in increased costs which
and work delays due to community claims. Social conflicts or community
could have a material adverse effect on our financial condition, results of
claims could adversely affect the recoverability of our future investments, our
operations and cash flows.
future production and revenues related to the Morona Block.
50 GeoPark 20F
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, the Aguada
establish development areas. Failure to meet these obligations may result in
Baguales Block in Argentina and the Morona Block in Peru.
the loss of our interests in the undeveloped parts of our blocks or concession
areas.
For the year ended December 31, 2018, the Llanos 34 Block contained 67%
of our net proved reserves and generated 76% of our production, the Fell
In order to protect our exploration and production rights in our license areas,
Block contained 6% of our net proved reserves and generated 8% of our total
we must meet various drilling and declaration requirements. In general, unless
production, the BCAM-40 Concession contained 3% of our net proved reserves
we make and declare discoveries within certain time periods specified in our
and generated 8% of our production, the Aguada Baguales Block contained
various special operation contracts (Contratos Especiales de Operación para
3% of our proved reserves and generated 3% of our total production and the
la Exploración y Explotación de Yacimientos de Hidrocarburo; hereinafter
Morona Block contained 17% of our net proved reserves. While our continuing
“CEOP”), E&P Contracts and concession agreements, our interests in the
expansion with new exploratory blocks incorporated in our portfolio mean
undeveloped parts of our license areas may lapse. Should the prospects we
that the above mentioned blocks may be expected to be a less significant
have identified under these contracts and agreements yield discoveries,
component of our overall business, we cannot be sure that we will be able
we may face delays in drilling these prospects or be required to relinquish
to continue diversifying our reserves and production. Resulting from these,
these prospects. The costs to maintain or operate the CEOPs, E&P Contracts
any government intervention, impairment or disruption of our production
and concession agreements over such areas may fluctuate and may increase
due to factors outside of our control or any other material adverse event in
significantly, and we may not be able to meet our commitments under such
our operations in such blocks would have a material adverse effect on our
contracts and agreements on commercially reasonable terms or at all, which
business, financial condition and results of operations.
may force us to forfeit our interests in such areas. For example, in 2016, after
fulfilling the committed exploratory commitments, five exploratory blocks
Our contracts in obtaining rights to explore and develop oil and natural
were relinquished to the ANP. See “Item 4. Information on the Company—B.
gas reserves are subject to contractual expiration dates and operating
Business Overview—Our operations—Operations in Brazil.”
conditions, and our CEOPs, E&P Contracts and concession agreements are
subject to early termination in certain circumstances.
In Peru, the rights to explore and produce hydrocarbons are granted through
a license contract signed with Perupetro. The scope and schedule of such
Under certain CEOPs, E&P Contracts and concession agreements to which
development will depend on us and Petroperu. The license contract could
we are or may in the future become parties, we are or may become subject
be terminated by Perupetro if the development obligations included in
to guarantees to perform our commitments and/or to make payment for
such agreement are not fulfilled. In addition, there is also an exploratory
other obligations, and we may not be able to obtain financing for all such
commitment consisting of the drilling of one exploratory well every two and
obligations as they arise. If such obligations are not complied with when
a half years. Failure to fulfill the exploratory commitment will lead to acreage
due, in addition to any other remedies that may be available to other parties,
relinquishment materially affecting the project. Moreover, we have entered
this could result in cancelation of our CEOPs, E&P Contracts and concession
into a Joint Investment Agreement with Petroperu by which, subject to the
agreements or dilution or forfeiture of interests held by us. As of December
economic and technical feasibility of the Morona Project, we are obliged
31, 2018, the aggregate outstanding amount of this potential liability for
to bear 100% of capital cost required to carry out long test to existing well
guarantees was US$38.9 million, mainly related to capital commitments in
Situche Central 3X, and if we decide to continue with the project after
Isla Norte, Campanario and Flamenco Blocks in Chile, rounds 11, 12 and 13
that, to the existing well Situche Central 2X. In addition, we are required to
concessions in Brazil, the Morona Block in Peru and the VIM-3, and Llanos 34
cover any capital or operational expenditures associated with the project
Blocks in Colombia. See “Item 4. Information on the Company—B. Business
until December 31, 2020. We expect these expenditures to be substantially
Overview—Our operations” and Note 32.2 to our Consolidated Financial
reimbursed by Petroperu from revenues associated with future sales. Failure
Statements.
to fulfill such obligations will result in the loss of our participating interest in
the License Contract of the Morona Block, and subject us to possible damage
Additionally, certain of the CEOPs, E&P Contracts and concession agreements
claims from Petroperu.
to which we are or may in the future become a party are subject to set
expiration dates. Although we may want to extend some of these contracts
For additional details regarding the status of our operations with respect
beyond their original expiration dates, there is no assurance that we can do
to our various special contracts and concession agreements, see “Item 4.
so on terms that are acceptable to us or at all, although some CEOPs contain
Information on the Company—B. Business Overview—Our operations.”
provisions enabling exploration extensions.
GeoPark 51
In Colombia, our E&P Contracts may be subject to early termination for a
compensation to which we are entitled may not be sufficient to compensate
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 the approval of the environmental impact assessment
interfere with our abandonment obligations and excluding certain pipelines
for the project’s development. The expiration of the License Contract will occur
and other assets. See “Item 4. Information on the Company—B. Business
twenty years after the approval of the environmental impact assessment. The
Overview—Significant Agreements—Chile—CEOPs—Fell Block CEOP.” If the
License Contract is also subject to early termination in case of our breach of
CEOP is terminated early due to a breach of our obligations, we may not be
contractual obligations. In such an event, all the existing facilities and wells
entitled to compensation. Our CEOPs for the Tierra del Fuego Blocks, which
located in the block will be transferred, without charge, to Perupetro, and we
are in the exploration phase, may be subject to early termination during this
will have to carry out abandonment plans for remediation and restoration of
phase under certain circumstances, including if we fail to perform under
any polluted area in the block and for de-commission the facilities that are no
the terms of the CEOPs, voluntarily relinquish all areas under the CEOPs or
longer required for 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
In Argentina, hydrocarbon exploration permits and exploitation concessions
are released from all obligations under the CEOPs, except for obligations
are subject to termination for: (a) failure to pay any annual license fees within
regarding the abandonment of fields, if any. See “Item 4. Information on the
three months after they are due; (b) failure to pay royalties within three
Company—B. Business Overview—Significant Agreements—Chile—CEOPs.”
months after they are due; (c) material and unjustified failure to comply with
There can be no assurance that the early termination of any of our CEOPs
the specified obligations in respect to productivity, conservation, investments,
would not have a material adverse effect on us. In addition, according to
works or special benefits; (d) repeated infringement of the obligations to
the Chilean Constitution, Chile is entitled to expropriate our rights in our
submit demandable information, to facilitate inspections by the competent
CEOPs for reasons of public interest. Although Chile would be required to
authority or to employ the proper techniques for the execution of the
indemnify us for such expropriation, there can be no assurance that any such
works; (e) failure to request an exploitation concession after a commercial
indemnification will be paid in a timely manner or in an amount sufficient to
discovery or to submit a development program after obtaining an exploitation
cover the harm to our business caused by such expropriation.
concession; (f ) the bankruptcy of the holder declared by a court; (g) the death
or liquidation of the holder; or, (h) failure to comply with the obligation to
In Brazil, concession agreements in the production phase generally may be
transport hydrocarbons for third parties under open access conditions or
renewed at the ANP’s discretion for an additional period, provided that a
repeated infringement of the tariff regime approved for such transport. Before
renewal request is made at least 12 months prior to the termination of the
declaring the termination under any of the grounds provided under items (a),
concession agreement and there has not been a breach of the terms of the
(b), (c), (d), (e), and (h), notice shall be served, requiring the holder to remedy
concession agreement. We expect that all our concession agreements will
any such infringement. Upon expiration, relinquishment or termination of any
provide for early termination in the event of: (i) government expropriation
permit or concession, the holder of such permit or concession shall surrender
for reasons of public interest; (ii) revocation of the concession pursuant to the
to the government the acreage together with all of the improvements,
terms of the concession agreement; or (iii) failure by us or our partners to fulfill
facilities, wells and other equipment that may have been used in the
all of our respective obligations under the concession agreement (subject to a
performance of the activities.
cure period). Administrative or monetary sanctions may also be applicable, as
determined by the ANP, which shall be imposed based on applicable law and
Early termination or nonrenewal of any CEOP, E&P Contract or concession
regulations. In the event of early termination of a concession agreement, the
agreement could have a material adverse effect on our business, financial
situation or results of operations.
52 GeoPark 20F
We sell almost all of our natural gas in Chile to a single customer, who has in
costs, or the rate of production of any non-operated and, to an extent, any
the past temporarily idled its principal facility.
non-wholly-owned, assets.
For the year ended December 31, 2018, almost all of our natural gas sales
As of December 31, 2018, we are not the operator of 27% or sole owner of
in Chile were made to Methanex under a long-term contract, the Methanex
31% of the blocks included in our portfolio. See “Item 4. Information on the
Gas Supply Agreement, which expires on December 31, 2026. Under the
Company—B. Business Overview—Operations in Colombia, Operations in
agreement, Methanex committed to purchase up to 400,000 SCM/d of gas
Chile, Operations in Brazil, Operations in Peru and Operations in Argentina.”
produced by us. Due to the decline in our gas production, the commitment
was reduced to 315,000 SCM/d in 2018, according to the initial terms of
In addition, the terms of the joint operation agreements or association
our contract. The commitment has remained at 315,000 SCM/d for 2019.
agreements governing our other partners’ interests in almost all of the blocks
We also hold an option to deliver up to 15% above this volume. Sales to
that are not wholly-owned or operated by us require that certain actions be
Methanex represented 3% of our consolidated revenues for the year ended
approved by supermajority vote. The terms of our other current or future
December 31, 2018. Methanex also buys gas from ENAP and a consortium
license or venture agreements may require at least the majority of working
that Methanex has formed with ENAP. If Methanex were to decrease or cease
interests to approve certain actions. As a result, we may have limited ability to
its purchase of gas from us, this would have a material adverse effect on our
exercise influence over operations or prospects in the blocks operated by our
revenues derived from the sale of gas.
partners, or in blocks that are not wholly-owned or operated by us. A breach of
contractual obligations by our partners who are the operators of such blocks
Methanex has two methanol producing facilities at its Cabo Negro
could eventually affect our rights in exploration and production contracts
production facility, near the city of Punta Arenas in southern Chile. Methanex
in some of our blocks in Colombia, Argentina and Brazil. Our dependence
has relied on local suppliers of natural gas, including ENAP, for its operations.
on our partners could prevent us from realizing our target returns for those
We alone cannot supply Methanex with all the natural gas it requires for its
discoveries or prospects.
operations. In 2018, Argentina approved export permits of natural gas to
Chile, including deliveries to Methanex.
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
Acquisitions that we have completed and any future acquisitions,
could have a material adverse effect on our business, financial condition and
strategic investments, partnerships or alliances could be difficult to
results of operations.
integrate and/or identify, could divert the attention of key management
personnel, disrupt our business, dilute stockholder value and adversely
We are not, and may not be in the future, the sole owner or operator of all
affect our financial results, including impairment of goodwill and other
of our licensed areas and do not, and may not in the future, hold all of the
intangible assets.
working interests in certain of our licensed areas. Therefore, we may not be
able to control the timing of exploration or development efforts, associated
One of our principal business strategies includes acquisitions of properties,
GeoPark 53
prospects, reserves and leaseholds and other strategic transactions, including
our competitiveness and growth opportunities. Moreover, if we fail to properly
in jurisdictions in which we do not currently operate. The successful
evaluate acquisitions, alliances or investments, we may not achieve the
acquisition and integration of producing properties requires an assessment of
anticipated benefits of any such transaction, and we may incur costs in excess
several factors, including:
• recoverable reserves;
• future oil and natural gas prices;
• development and operating costs; and
of what we anticipate.
Future acquisitions financed with our own cash could deplete the cash and
working capital available to adequately fund our operations. We may also
finance future transactions through debt financing, the issuance of our equity
• potential environmental and other liabilities.
securities, existing cash, cash equivalents or investments, or a combination
of the foregoing. Acquisitions financed with the issuance of our equity
The accuracy of these assessments is inherently uncertain. In connection
securities could be dilutive, which could affect the market price of our stock.
with these assessments, we perform a review of the subject properties
Acquisitions financed with debt could require us to dedicate a substantial
that we believe to be generally consistent with industry practices. Our
portion of our cash flow to principal and interest payments and could subject
review and the review of advisors and independent reserves engineers
us to restrictive covenants.
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
The PN-T-597 Concession Agreement in Brazil may not close.
their deficiencies and potential recoverable reserves. Inspections may not
always be performed on every well, and environmental conditions are not
In Brazil, GeoPark Brasil is a party to a class action filed by the Federal
necessarily observable even when an inspection is undertaken. We, advisors
Prosecutor’s Office regarding a concession agreement of exploratory Block
or independent reserves engineers may apply different assumptions when
PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and
assessing the same field. Even when problems are identified, the seller
gas bidding round held in November 2013. The Brazilian Federal Court issued
may be unwilling or unable to provide effective contractual protection
an injunction against the ANP and GeoPark Brasil in December 2013 that
against all or part of the problems. We often are not entitled to contractual
prohibited GeoPark Brasil’s execution of the concession agreement until the
indemnification for environmental liabilities and acquire properties on
ANP conducted studies on whether drilling for unconventional resources would
an “as is” basis. Even in those circumstances in which we have contractual
contaminate the dams and aquifers in the region. On July 17, 2015, GeoPark
indemnification rights for pre-closing liabilities, it remains possible that
Brasil, at the instruction of the ANP, signed the concession agreement, which
the seller will not be able to fulfill its contractual obligations. There can be
included a clause prohibiting GeoPark Brasil from conducting unconventional
no assurance that problems related to the assets or management of the
exploration activity in the area. Despite the clause containing the prohibition,
companies and operations we have acquired, or operations we may acquire
the judge in the case concluded that the concession agreement should not
or add to our portfolio in the future, will not arise in future, and these
be executed. Thus, GeoPark Brasil requested that the ANP comply with the
problems could have a material adverse effect on our business, financial
decision and annul the concession agreement, which the ANP’s Board did on
condition and results of operations.
October 9, 2015. The annulment reverted the status of all parties to the status
quo ante, which maintains GeoPark Brasil’s right to the block.
Significant acquisitions and other strategic transactions may involve other
risks, including:
There is no assurance that we will be able to enter into a concession agreement
• diversion of our management’s attention to evaluating, negotiating and
in the PN-T-597 Block that would be favorable to our exploration goals. See
integrating significant acquisitions and strategic transactions;
“Item 8—Financial Information—A. Consolidated statements and other
• challenge and cost of integrating acquired operations, information
financial information—Legal proceedings.”
management and other technology systems and business cultures with ours
while carrying on our ongoing business;
The present value of future net revenues from our proved reserves will not
• contingencies and liabilities that could not be or were not identified during
necessarily be the same as the current market value of our estimated oil
the due diligence process, including with respect to possible deficiencies in
and natural gas reserves.
the internal controls of the acquired operations; and
• challenge of attracting and retaining personnel associated with acquired
You should not assume that the present value of future net revenues from
operations.
our proved reserves is the current market value of our estimated oil and
natural gas reserves. For the year ended December 31, 2018, we have based
It is also possible that we may not identify suitable acquisition targets or
the estimated discounted future net revenues from our proved reserves on
strategic investment, partnership or alliance candidates. Our inability to
the 12-month unweighted arithmetic average of the first-day-of-the-month
identify suitable acquisition targets, strategic investments, partners or
price for the preceding 12 months. Actual future net revenues from our oil and
alliances, or our inability to complete such transactions, may negatively affect
natural gas properties will be affected by factors such as:
54 GeoPark 20F
• 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
• the amount and timing of actual production; and
face in doing business with these customers may increase. Other customers
• changes in governmental regulations, taxation or the taxation invariability
may also be subject to regulatory changes, which could increase the risk of
provisions in our CEOPs.
defaulting on their obligations to us. Financial problems experienced by our
The timing of both our production and our incurrence of expenses in
customers could result in the impairment of our assets, a decrease in our
connection with the development and production of oil and natural gas
operating cash flows and may also reduce or curtail our customers’ future
properties will affect the timing and amount of actual future net revenues from
use of our products and services, which may have an adverse effect on our
proved reserves, and thus their actual value. In addition, the 10% discount
revenues and may lead to a reduction in reserves.
factor we use when calculating discounted future net revenues may not be the
most appropriate discount factor based on interest rates in effect from time to
We may not have the capital to develop our unconventional oil and gas
time and risks associated with us or the oil and natural gas industry in general.
resources.
The development of our proved undeveloped reserves may take longer
We have identified opportunities for analyzing the potential of
and may require higher levels of capital expenditures than we currently
unconventional oil and gas resources in some of our blocks and concessions.
anticipate. Therefore, our proved undeveloped reserves ultimately may not
Our ability to develop this potential depends on a number of factors,
be developed or produced.
including the availability of capital, seasonal conditions, regulatory approvals,
negotiation of agreements with third parties, commodity prices, costs, access
As of December 31, 2018, 38% of our net proved reserves are developed.
to and availability of equipment, services and personnel and drilling results.
Development of our undeveloped reserves may take longer and require
In addition, as we have no previous experience in drilling and exploiting
higher levels of capital expenditures than we currently anticipate. Additionally,
unconventional oil and gas resources, the drilling and exploitation of such
delays in the development of our reserves or increases in costs to drill and
unconventional oil and gas resources depends on our ability to acquire
develop such reserves will reduce the standardized measure value of our
the necessary technology, to hire personnel and other support needed
estimated proved undeveloped reserves and future net revenues estimated
for extraction or to obtain financing and venture partners to develop such
for such reserves, and may result in some projects becoming uneconomic,
activities. Because of these uncertainties, we cannot give any assurance
causing the quantities associated with these uneconomic projects to no
as to the timing of these activities, or that they will ultimately result in the
longer be classified as reserves. This was due to the uneconomic status of the
realization of proved reserves or meet our expectations for success.
reserves, given the proximity to the end of the concessions for these blocks,
which does not allow for future capital investment in the blocks. There can be
Our operations are subject to operating hazards, including extreme weather
no assurance that we will not experience similar delays or increases in costs
events, which could expose us to potentially significant losses.
to drill and develop our reserves in the future, which could result in further
reclassifications of our reserves.
Our operations are subject to potential operating hazards, extreme weather
conditions and risks inherent to drilling activities, seismic registration,
We are exposed to the credit risks of our customers and any material
exploration, production, development and transportation and storage of crude
nonpayment or nonperformance by our key customers could adversely
oil, such as explosions, fires, car and truck accidents, floods, labor disputes,
affect our cash flow and results of operations.
social unrest, community protests or blockades, guerilla attacks, security
Our customers may experience financial problems that could have a
our or third-party facilities. Any of these events could have a material adverse
significant negative effect on their creditworthiness. Severe financial problems
effect on our exploration and production operations or disrupt transportation
encountered by our customers could limit our ability to collect amounts
or other process-related services provided by our third-party contractors.
breaches, pipeline ruptures and spills and mechanical failure of equipment at
owed to us, or to enforce the performance of obligations owed to us under
contractual arrangements.
We are highly dependent on certain members of our management and
technical team, including our geologists and geophysicists, and on our
The combination of declining cash flows as a result of declines in commodity
ability to hire and retain new qualified personnel.
prices, a reduction in borrowing basis under reserves-based credit facilities
and the lack of availability of debt or equity financing may result in a
The ability, expertise, judgment and discretion of our management and our
significant reduction of our customers’ liquidity and limit their ability to make
technical and engineering teams are key in discovering and developing oil and
payments or perform on their obligations to us.
natural gas resources. Our performance and success are dependent to a large
extent upon key members of our management and exploration team, and their
GeoPark 55
loss or departure would be detrimental to our future success. In addition, our
We have contracted with and intend to continue to hire third parties to
ability to manage our anticipated growth depends on our ability to recruit and
perform services related to our operations. We could be held liable for some
retain qualified personnel. Our ability to retain our employees is influenced by
or all environmental, health and safety costs and liabilities arising out of
the economic environment and the remote locations of our exploration blocks,
our actions and omissions as well as those of our block partners, third-party
which may enhance competition for human resources where we conduct our
contractors, predecessors or other operators. To the extent we do not address
activities, thereby increasing our turnover rate. There is strong competition
these costs and liabilities or if we do not otherwise satisfy our obligations, our
in our industry to hire employees in operational, technical and other areas,
operations could be suspended, terminated or otherwise adversely affected.
and the supply of qualified employees is limited in the regions where we
There is a risk that we may contract with third parties with unsatisfactory
operate and throughout Latin America generally. The loss of any of our key
environmental, health and safety records or that our contractors may be
management or other key employees of our technical team or our inability to
unwilling or unable to cover any losses associated with their acts and
hire and retain new qualified personnel could have a material adverse effect
omissions.
on us.
We and our operations are subject to numerous environmental, health and
certain environmental laws and regulations applicable to us in the countries
safety laws and regulations which may result in material liabilities and
in which we operate, we could be held responsible for all of the costs relating
Releases of regulated substances may occur and can be significant. Under
costs.
to any contamination at our past and current facilities and at any third-party
waste disposal sites used by us or on our behalf. Pollution resulting from
We and our operations are subject to various international, foreign, federal,
waste disposal, emissions and other operational practices might require us to
state and local environmental, health and safety laws and regulations
remediate contamination, or retrofit facilities, at substantial cost. We also could
governing, among other things, the emission and discharge of pollutants into
be held liable for any and all consequences arising out of human exposure to
the ground, air or water; the generation, storage, handling, use, transportation
such substances or for other damage resulting from the release of hazardous
and disposal of regulated materials; and human health and safety. Our
substances to the environment, property or to natural resources, or affecting
operations are also subject to certain environmental risks that are inherent
endangered species or sensitive environmental areas. We are currently required
in the oil and gas industry and which may arise unexpectedly and result
to, and in the future may need to, plug and abandon sites in certain blocks in
in material adverse effects on our business, financial condition and results
each of the countries in which we operate, which could result in substantial
of operations. Breach of environmental laws could result in environmental
costs.
administrative investigations and/or lead to the termination of our concessions
and contracts. Other potential consequences include fines and/or criminal or
In addition, we expect continued and increasing attention to climate change
civil environmental actions. For instance, non-governmental organizations
issues. Various countries and regions have agreed to regulate emissions of
seeking to preserve the environment may bring actions against us or other oil
greenhouse gases including methane (a primary component of natural gas)
and gas companies in order to, among other things, halt our activities in any
and carbon dioxide (a byproduct of oil and natural gas combustion). The
of the countries in which we operate or require us to pay fines. Additionally,
regulation of greenhouse gases and the physical impacts of climate change
in Colombia, recent rulings have provided that environmental licenses are
in the areas in which we, our customers and the end-users of our products
administrative acts subject to class actions that could eventually result in their
operate could adversely impact our operations and the demand for our
cancellation, with potential adverse impacts on our E&P Contracts.
products.
We have not been and may not be at all times in complete compliance with
In Peru, the beginning of the construction and development phase of
environmental permits that we are required to obtain for our operations and
the Morona Block is subject to the approval of an environmental impact
the environmental and health and safety laws and regulations to which we
assessment by the Peruvian environmental authority. If such environmental
are subject. If we fail to comply with such requirements, we could be fined
impact assessment is not approved during the first half of 2019, we will not be
or otherwise sanctioned by regulators, including through the revocation of
able to transport all the goods and materials required for the development of
our permits or the suspension or termination of our operations. If we fail to
the project during the fluvial transportation window of the Morona River in
obtain, maintain or renew permits in a timely manner or at all, our operations
2019 and the construction stage of the project will be negatively impacted. If
could be adversely affected, impeded, or terminated, which could have a
this is the case, the beginning of the production stage of the Morona Project
material adverse effect on our business, financial condition or results of
could also be impacted.
operations. Some environmental licenses related to operation of the Manati
Field production system and natural gas pipeline have expired. However, the
Environmental, health and safety laws and regulations are complex and change
operator submitted in a timely manner a request for renewal of those licenses
frequently, and our costs of complying with such laws and regulations may
and as such this operation is not in default as long as the regulator does not
adversely affect our results of operations and financial condition. See “Item
state its final position on the renewal.
56 GeoPark 20F
4. Information on the Company—B. Business Overview—Health, safety and
cash flow to fund acquisitions, working capital, capital expenditures and other
environmental matters” and “Item 4. Information on the Company—B. Business
general corporate purposes;
Overview—Industry and regulatory framework.”
• place us at a competitive disadvantage compared to certain of our
competitors that have less debt;
Legislation and regulatory initiatives relating to hydraulic fracturing and
other drilling activities for unconventional oil and gas resources could
•
•
limit our ability to borrow additional funds;
in the case of our secured indebtedness, lose assets securing such
increase the future costs of doing business, cause delays or impede our
indebtedness upon the exercise of security interests in connection with a
plans, and materially adversely affect our operations.
default;
Hydraulic fracturing of unconventional oil and gas resources is a process
and
that involves injecting water, sand, and small volumes of chemicals into
•
limit our flexibility in planning for, or reacting to, changes in our operations
the wellbore to fracture the hydrocarbon-bearing rock thousands of feet
or business and the industry in which we operate.
• make us more vulnerable to downturns in our business or the economy;
below the surface to facilitate a higher flow of hydrocarbons into the
wellbore. We are contemplating such use of hydraulic fracturing in the
The indenture governing our Notes due 2024 includes covenants
production of oil and natural gas from certain reservoirs, especially shale
restricting dividend payments. For a description, see “Item 5. Operating
formations. We currently are not aware of any proposals in Colombia,
and Financial Review and Prospects—B. Liquidity and Capital Resources—
Chile, Brazil, Argentina or Peru to regulate hydraulic fracturing beyond the
Indebtedness—Notes due 2024.”
regulations already in place. However, various initiatives in other countries
with substantial shale gas resources have been or may be proposed
As a result of these restrictive covenants, we are limited in the manner
or implemented to, among other things, regulate hydraulic fracturing
in which we conduct our business, and we may be unable to engage in
practices, limit water withdrawals and water use, require disclosure of
favorable business activities or finance future operations or capital needs.
fracturing fluid constituents, restrict which additives may be used, or
We have in the past been unable to meet incurrence tests under the
implement temporary or permanent bans on hydraulic fracturing. If any
indenture governing our prior notes, which limited our ability to incur
of the countries in which we operate adopts similar laws or regulations,
indebtedness. Failure to comply with the restrictive covenants included in
which is something we cannot predict right now, such adoption
our Notes due 2024 would not trigger an event of default.
could significantly increase the cost of, impede or cause delays in the
implementation of any plans to use hydraulic fracturing for unconventional
Similar restrictions could apply to us and our subsidiaries when we
oil and gas resources.
refinance or enter into new debt agreements which could intensify the risks
Our indebtedness and other commercial obligations could adversely affect
described above.
our financial health and our ability to raise additional capital and prevent
Our business could be negatively impacted by security threats, including
us from fulfilling our obligations under our existing agreements and
cybersecurity threats as well as other disasters, and related disruptions.
borrowing of additional funds.
As of December 31, 2018, we had US$447 million of total indebtedness
including deliberate attacks or unintentional events, have also increased in
outstanding on a consolidated basis, consisting primarily of our US$425.0
the world. Computer and telecommunications systems are used to conduct
million Notes due 2024, which we issued in September 2017. As of December
our exploration, development and production activities and have become
31, 2018, our annual debt service obligation was US$27.7 million, see “Item
an integral part of our business. Our business processes depend on the
5. Operating and Financial Review and Prospects—B. Liquidity and Capital
availability, capacity, reliability and security of our information technology
As dependence on digital technologies has increased, cyber incidents,
Resources—Indebtedness.”
Our indebtedness could:
infrastructure and our ability to expand and continually update this
infrastructure in response to our changing needs. It is critical to our business
that our facilities and infrastructure remain secure. Although we have
•
limit our capacity to satisfy our obligations with respect to our
implemented internal control procedures to assure the security of our data,
indebtedness, and any failure to comply with the obligations of any of our
we cannot guarantee that these measures will be sufficient for this purpose.
debt instruments, including restrictive covenants and borrowing conditions,
Cyber-attacks could compromise our computers and telecommunications
could result in an event of default under the agreements governing our
systems and result in disruptions to our business operation necessary to
indebtedness;
deliver our production to market or the loss of our data.
• require us to dedicate a substantial portion of our cash flow from operations
to the payments on our indebtedness, thereby reducing the availability of our
Although we have extended our security policy to the main systems of
GeoPark 57
the Company and implemented strategies to mitigate the impact from
problem that may damage our information technology infrastructure.
cybersecurity threats, reinforcing the defenses in case of denial of service and
increasing the monitoring of suspicious activities, our technologies, systems,
Certain cyber incidents, such as surveillance, may remain undetected for
networks, and those of our business partners have been and may continue to
an extended period. A cyber incident involving our information systems
be the target of cyber-attacks or information security breaches, which could
and related infrastructure, or that of our business partners, could disrupt
lead to disruptions in critical systems, unauthorized release of confidential or
our business plans and negatively impact our operations. Although to date
protected information, corruption of data or other disruptions of our business
we have not experienced any significant cyber-attacks, there can be no
operations. The ability of the information technology function to support our
assurance that we will not be the target of cyber-attacks in the future or suffer
business in the event of a security breach or a disaster such as fire or flood
such losses related to any cyber-incident. As cyber threats continue to evolve,
and our ability to recover key systems and information from unexpected
we may be required to expend significant additional resources to continue to
interruptions cannot be fully tested and there is a risk that, if such an event
modify or enhance our protective measures or to investigate and remediate
actually occurs, we may not be able to address immediately the repercussions
any information security vulnerabilities.
of a breach. In the event of a breach, key information and systems may be
unavailable for a number of days leading to an inability to conduct our
Risks relating to the countries in which we operate
business or perform some business processes in a timely manner. We have
implemented strategies to mitigate the impact from these types of events.
Our operations may be adversely affected by political and economic
circumstances in the countries in which we operate and in which we may
In addition, the oil and gas industry has become increasingly dependent
operate in the future.
on digital technologies to conduct day-to-day operations including
certain exploration, development and production activities. For example,
All of our current operations are located in South America. If local, regional
software programs are used to interpret seismic data, manage drilling rigs,
or worldwide economic trends adversely affect the economy of any of the
conduct reservoir modeling and reserves estimation, and to process and
countries in which we have investments or operations, our financial condition
record financial and operating data. We depend on digital technology,
and results from operations could be adversely affected.
including information systems and related infrastructure as well as cloud
application and services, to process and record financial and operating data,
Oil and natural gas exploration, development and production activities are
communicate with our employees and business partners, analyze seismic and
subject to political and economic uncertainties (including but not limited to
drilling information, estimate quantities of oil and gas reserves and for many
changes in energy policies or the personnel administering them), changes
other activities related to our business. Our business partners, including
in laws and policies governing operations of foreign-based companies,
vendors, service providers, co-venturers, purchasers of our production,
expropriation of property, cancellation or modification of contract rights,
and financial institutions, are also dependent on digital technology. As
revocation of consents or approvals, the obtaining of various approvals from
dependence on digital technologies has increased, cyber incidents, including
regulators, foreign exchange restrictions, price controls, currency fluctuations,
deliberate attacks or unintentional events, have also increased.
royalty increases and other risks arising out of foreign governmental
A cyber-attack could include gaining unauthorized access to digital systems
community-based actions, such as protests or blockades, guerilla activities,
for purposes of misappropriating assets or sensitive information, corrupting
terrorism, acts of sabotage, territorial disputes and insurrection. In addition,
data, or causing operational disruption, or result in denial-of-service on
we are subject both to uncertainties in the application of the tax laws in the
websites. Our technologies, systems, networks, and those of our business
countries in which we operate and to possible changes in such tax laws (or
partners may become the target of cyber-attacks or information security
the application thereof ), each of which could result in an increase in our tax
breaches that could result in the unauthorized release, gathering, monitoring,
liabilities. These risks are higher in developing countries, such as those in
sovereignty, as well as to risks of loss due to civil strife, acts of war and
misuse, loss or destruction of proprietary and other information, or other
which we conduct our activities.
disruption of our business operations. Our employees have been and will
continue to be targeted by parties using fraudulent “spam” and “phishing”
The main economic risks we face and may face in the future because of our
emails to misappropriate information or to introduce viruses or other
operations in the countries in which we operate include the following:
malware through “trojan horse” programs to our computers. These emails
• difficulties incorporating movements in international prices of crude oil and
appear to be legitimate emails sent by us but direct recipients to fake
exchange rates into domestic prices;
websites operated by the sender of the email or request that the recipient
• the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s, Peru’s
send a password or other confidential information through email or
or Brazil’s relations with multilateral credit institutions, such as the IMF, will
download malware. Despite our efforts to mitigate “spoof” and “phishing”
impact negatively on capital controls, and result in a deterioration of the
emails through education, “spoof” and “phishing” activities remain a serious
business climate;
58 GeoPark 20F
• 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 5% of our revenues as of December 31,
guerilla activities, social unrest, local economic conditions, political disruption,
2018. 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
production activities may be substantially affected by factors which could have
Prosecutor’s Office in connection with corruption allegations (the “Lava
a material adverse effect on our results of operations and financial condition. We
Jato” investigations). Depending on the duration and outcome of such
cannot guarantee that current programs and policies that apply to the oil and
investigations, the companies involved may face downgrades from rating
gas industry will remain in effect.
agencies, funding restrictions and a reduction in their revenues. Given the
significance of the companies under investigation including Petrobras, this
Our operations may also be adversely affected by laws and policies of the
could adversely affect Brazil’s growth prospects and could have a protracted
jurisdictions, including Bermuda, Colombia, Chile, Brazil, Argentina, Peru, Spain,
effect on the oil and gas industry. In addition to the recent economic crisis,
the United Kingdom, the Netherlands and other jurisdictions in which we do
protests, strikes and corruption scandals have led to a fall in confidence.
business, that affect foreign trade and taxation, and by uncertainties in the
application of, possible changes to (or to the application of) tax laws in these
We depend on maintaining good relations with the respective host
jurisdictions. For example, in 2018 the Colombian government introduced tax
governments and national oil companies in each of our countries of operation.
reforms with provisions that are effective January 1, 2019. See Note 16 to our
Consolidated Financial Statements. With regards to Chile, although our CEOPs
The success of our business and the effective operation of the fields in each of our
have protection against tax changes through invariability tax clauses, potential
countries of operation depend upon continued good relations and cooperation
issues may arise on certain aspects not clearly defined in current or future tax
with applicable governmental authorities and agencies, including national oil
reforms.
companies such as Ecopetrol, ENAP, Petrobras, Petroperu and YPF. For instance,
for the year ended December 31, 2018, 100% of our crude oil and condensate
Changes in any of these laws or policies or the implementation thereof, and
sales in Chile were made to ENAP, the Chilean state-owned oil company. In
uncertainty over potential changes in policy or regulations affecting any
addition, our Brazilian operations in BCAM-40 Concession provide us with a long-
of the factors mentioned above or other factors in the future may increase
term off-take contract with Petrobras, the Brazilian state-owned company that
the volatility of domestic securities markets and securities issued abroad by
covers 100% of net proved gas reserves in the Manati Field, one of the largest
companies operating in these countries, which could materially and adversely
non-associated gas fields in Brazil. If we, the respective host governments and the
affect our financial position, results of operations and cash flows. Furthermore,
national oil companies are not able to cooperate with one another, it could have
we may be subject to the exclusive jurisdiction of courts outside the United
an adverse impact on our business, operations and prospects.
States or may not be successful in subjecting non-U.S. persons to the jurisdiction
of courts in the United States, which could adversely affect the outcome of
Oil and natural gas companies in Colombia, Chile, Brazil, Argentina and Peru
such dispute. Changes in tax laws may result in increases in our tax payments,
do not own any of the oil and natural gas reserves in such countries.
which could materially adversely affect our profitability and increase the
prices of our products and services, restrict our ability to do business in our
Under Colombian, Chilean, Brazilian, Peruvian and Argentine law, all onshore and
existing and target markets and cause our results of operations to suffer. There
offshore hydrocarbon resources in these countries are owned by the respective
GeoPark 59
sovereign. Although we are the operator of the majority of the blocks and
For example, in Brazil there is potential liability for personal injury, property
concessions in which we have a working and/or economic interest and generally
damage and other types of damages. Failure to comply with these laws and
have the power to make decisions as how to market the hydrocarbons we
regulations also may result in the suspension or termination of operations
produce, the Chilean, Colombian, Brazilian, Peruvian and Argentine governments
or our being subjected to administrative, civil and criminal penalties, which
have full authority to determine the rights, royalties or compensation to be paid
could have a material adverse effect on our financial condition and expected
by or to private investors for the exploration or production of any hydrocarbon
results of operations. We expect to also operate in a consortium in some of
reserves located in their respective countries.
our concessions, which, under the Brazilian Petroleum Law, establishes joint
and strict liability among consortium members, and failure to maintain the
If these governments were to restrict or prevent concessionaires, including us,
appropriate licenses may result in fines from the ANP, ranging from R$10
from exploiting oil and natural gas reserves, or otherwise interfered with our
to R$500 million. In addition, there is a contractual requirement in Brazilian
exploration through regulations with respect to restrictions on future exploration
concession agreements regarding local content, which has become a
and production, price controls, export controls, foreign exchange controls,
significant issue for oil and natural gas companies operating in Brazil given
income taxes, expropriation of property, environmental legislation or health
the penalties related with breaches thereof. The local content requirement
and safety, this could have a material adverse effect on our business, financial
will also apply to the production sharing contract regime. See “Item 4.
condition and results of operations.
Information on the Company—B. Business Overview—Our operations—
Additionally, we are dependent on receipt of government approvals or permits to
Operations in Brazil.”
develop the concessions we hold in some countries. There can be no assurance
Significant expenditures may be required to ensure our compliance
that future political conditions in the countries in which we operate will not result
with governmental regulations related to, among other things, licenses
in changes to policies with respect to foreign development and ownership of
for drilling operations, environmental matters, drilling bonds, reports
oil, environmental protection, health and safety or labor relations, which may
concerning operations, the spacing of wells, unitization of oil and natural gas
negatively affect our ability to undertake exploration and development activities
accumulations, local content policy and taxation.
in respect of present and future properties, as well as our ability to raise funds
to further such activities. Any delays in receiving government approvals in such
Colombia has experienced and continues to experience internal security issues
countries may delay our operations or may affect the status of our contractual
that have had or could have a negative effect on the Colombian economy.
arrangements or our ability to meet contractual obligations.
Oil and gas operators are subject to extensive regulation in the countries in
of Colombia (FARC) signed a peace agreement, pursuant to which the
In 2016, the Colombian government and the Revolutionary Armed Forces
which we operate.
FARC agreed to demobilize its troops and to hand over its weapons to a
United Nations mission. Our business, financial condition and results of
The Colombian, Chilean, Brazilian, Peruvian and Argentine hydrocarbons
operations could be adversely affected by rapidly changing economic or
industries are subject to extensive regulation and supervision by their
social conditions, including the Colombian government’s response to current
respective governments in matters such as the environment, social
peace agreements and negotiations with other groups, including the ELN,
responsibility, tort liability, health and safety, labor, the award of exploration
which may result in legislation that increases our tax burden or that of other
and production contracts, the imposition of specific drilling and exploration
Colombian companies.
obligations, taxation, foreign currency controls, price controls, export and
import restrictions, capital expenditures and required divestments. In some
ELN has targeted crude oil pipelines in Colombia, including the Caño Limón-
countries in which we operate, such as Colombia, we are required to pay a
Coveñas pipeline, and other related infrastructure, disrupting the activities of
percentage of our expected production to the government as royalties. See
certain oil and natural gas companies and resulting in unscheduled shut-
“Item 4. Information on the Company—B. Business Overview—Industry and
downs of transportation systems. These activities, their possible escalation
regulatory framework—Colombia” and see Note 32.1 to our Consolidated
and the effects associated with them have had and may have in the future a
Financial Statements. In Argentina, energy regulation gives absolute
negative impact on the Colombian economy or on our business, which may
priority to domestic gas supply, which in case of a gas shortage occurs, will
affect our employees or assets.
restrict our ability to fulfill our export commitments, if any. This regulation
also established subsidies to domestic gas prices, which may negatively
In addition, from time to time, community protests and blockades may arise
affect our revenues considering market prices. See “Item 4. Information
near our operations in Colombia, which could adversely affect our business,
on the Company—B. Business Overview—Industry and regulatory
financial condition or results of operations.
framework—Argentina.”
60 GeoPark 20F
Risks related to our common shares
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
“NYSE”) on February 7, 2014, and as a result have a limited trading history.
of directors and our shareholders, and will depend on many factors, such as
We cannot predict the extent to which investor interest in our company will
our results of operations, financial condition, cash requirements, prospects
maintain an active trading market on the NYSE, or how liquid that market
and other factors. Due to losses resulting from the oil price decline in previous
will be in the future.
years, accumulated losses amount to US$206.7 million as of December 31,
The market price of our common shares may be volatile and may be
2018.
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 in
making distributions to us.
• domestic and international economic, legal and regulatory factors
As a holding company, our only material assets are our cash on hand, the
unrelated to our performance.
equity interests in our subsidiaries and other investments. Our principal
• variations in our quarterly operating results;
source of revenue and cash flow is distributions from our subsidiaries. Thus,
• volatility in our industry, the industries of our customers and the global
our ability to service our debt, finance acquisitions and pay dividends to our
securities markets;
• changes in our dividend policy;
stockholders in the future is dependent on the ability of our subsidiaries
to generate sufficient net income and cash flows to make upstream cash
• risks relating to our business and industry, including those discussed above;
distributions to us. Our subsidiaries are and will be separate legal entities,
• strategic actions by us or our competitors;
and although they may be wholly-owned or controlled by us, they have
• actual or expected changes in our growth rates or our competitors’ growth
no obligation to make any funds available to us, whether in the form of
rates;
loans, dividends, distributions or otherwise. The ability of our subsidiaries
•
investor perception of us, the industry in which we operate, the investment
to distribute cash to us will also be subject to, among other things,
opportunity associated with our common shares and our future performance;
restrictions that are contained in our subsidiaries’ financing and joint
• adverse media reports about us or our directors and officers;
venture agreements, availability of sufficient funds in such subsidiaries
• addition or departure of our executive officers;
and applicable state laws and regulatory restrictions. Claims of creditors
• change in coverage of our company by securities analysts;
of our subsidiaries generally will have priority as to the assets of such
• trading volume of our common shares;
subsidiaries over our claims and claims of our creditors and stockholders.
• future issuances of our common shares or other securities;
To the extent the ability of our subsidiaries to distribute dividends or other
• terrorist acts;
payments to us could be limited in any way, our ability to grow, pursue
• the release or expiration of transfer restrictions on our outstanding
business opportunities or make acquisitions that could be beneficial to our
common shares.
businesses, or otherwise fund and conduct our business could be materially
We have never declared or paid, and do not expect to pay in the
limited.
foreseeable future, cash dividends on our common shares, and,
We may not be able to fully control the operations and the assets of our
consequently, your only opportunity to achieve a return on your
joint ventures and we may not be able to make major decisions or take
GeoPark 61
timely actions with respect to our joint ventures unless our joint venture
concentration of ownership may have the effect of delaying, preventing
partners agree. We may, in the future, enter into joint venture agreements
or deterring a change of control of our company, could deprive our
imposing additional restrictions on our ability to pay dividends.
stockholders of an opportunity to receive a premium for their common
shares as part of a sale of our company and might ultimately affect the
Sales of substantial amounts of our common shares in the public market, or
market price of our common shares. See “Item 7. Major Shareholders and
the perception that these sales may occur, could cause the market price of
Related Party Transactions—A. Major shareholders” for a more detailed
our common shares to decline.
description of our share ownership.
We may issue additional common shares or convertible securities in the
As a foreign private issuer, we are subject to different U.S. securities laws
future, for example, to finance potential acquisitions of assets, which we
and NYSE governance standards than domestic U.S. issuers. This may
intend to continue to pursue. Sales of substantial amounts of our common
afford less protection to holders of our common shares, and you may not
shares in the public market, or the perception that these sales may occur,
receive corporate and company information and disclosure that you are
could cause the market price of our common shares to decline. This could
accustomed to receiving or in a manner in which you are accustomed to
also impair our ability to raise additional capital through the sale of our
receiving it.
equity securities. Under our memorandum of association, we are authorized
to issue up to 5,171,949,000 common shares, of which 60,483,447 common
As a foreign private issuer, the rules governing the information that we
shares were outstanding as of December 31, 2018. We cannot predict the
disclose differ from those governing U.S. corporations pursuant to the
size of future issuances of our common shares or the effect, if any, that
Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although
future sales and issuances of shares would have on the market price of our
we intend to report quarterly financial results and report certain material
common shares.
events, we are not required to file quarterly reports on Form 10-Q or provide
current reports on Form 8-K disclosing significant events within four days
Provisions of the Notes due 2024 could discourage an acquisition of us by
of their occurrence and our quarterly or current reports may contain less
a third party.
information than required under U.S. filings. In addition, we are exempt
from the Section 14 proxy rules, and proxy statements that we distribute will
Certain provisions of the Notes due 2024 could make it more difficult or
not be subject to review by the SEC. Our exemption from Section 16 rules
more expensive for a third party to acquire us or may even prevent a third
regarding sales of common shares by insiders means that you will have less
party from acquiring us. For example, upon the occurrence of a fundamental
data in this regard than shareholders of U.S. companies that are subject to
change, holders of the Notes due 2024 will have the right, at their option, to
the Exchange Act. As a result, you may not have all the data that you are
require us to repurchase all of their notes at a purchase price equal to 101% of
accustomed to having when making investment decisions. For example, our
the principal amount thereof plus any accrued and unpaid interest (including
officers, directors and principal shareholders are exempt from the reporting
any additional amounts, if any) to the date of purchase. By discouraging an
and “short-swing” profit recovery provisions of Section 16 of the Exchange
acquisition of us by a third party, these provisions could have the effect of
Act and the rules thereunder with respect to their purchases and sales of our
depriving the holders of our common shares of an opportunity to sell their
common shares. The periodic disclosure required of foreign private issuers
common shares at a premium over prevailing market prices.
is more limited than that required of domestic U.S. issuers and there may
therefore be less publicly available information about us than is regularly
Certain shareholders have substantial control over us and could limit your
published by or about U.S. public companies. See “Item 10. Additional
ability to influence the outcome of key transactions, including a change of
Information—H. Documents on display.”
control.
As a foreign private issuer, we are exempt from complying with certain
Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief
corporate governance requirements of the NYSE applicable to a U.S. issuer,
Executive Officer, Mr. Jamie Coulter, director, Mr. Constantine Papadimitriou,
including the requirement that a majority of our board of directors consist of
director, and Mr. Juan Cristóbal Pavez, director, control 35.4% of our
independent directors as well as the requirement that shareholders approve
outstanding common shares as of March 15, 2019, holding the shares either
any equity issuance by us which represents 20% or more of our outstanding
directly or through privately held funds. As a result, these shareholders, if
common shares. As the corporate governance standards applicable to us
acting together, would be able to influence or control matters requiring
are different than those applicable to domestic U.S. issuers, you may not
approval by our shareholders, including the election of directors and the
have the same protections afforded under U.S. law and the NYSE rules as
approval of amalgamations, mergers or other extraordinary transactions.
shareholders of companies that do not have such exemptions.
They may also have interests that differ from yours and may vote in a way
with which you disagree and which may be adverse to your interests. The
There are regulatory limitations on the ownership and transfer of our
62 GeoPark 20F
common shares which could result in the delay or denial of any transfers you
law, the purpose of which is the enforcement of a sanction, power or right
might seek to make.
at the instance of the state in its sovereign capacity, will not be entertained
by a Bermuda court. Certain remedies available under the laws of U.S.
The Bermuda Monetary Authority (the “BMA”), must specifically approve all
jurisdictions, including certain remedies under U.S. federal securities laws,
issuances and transfers of securities of a Bermuda exempted company like us
would not be available under Bermuda law or enforceable in a Bermuda
unless it has granted a general permission. We are able to rely on a general
court, as they would be contrary to Bermuda public policy.
permission from the BMA to issue our common shares, and to freely transfer
our common shares as long as the common shares are listed on the NYSE
The transfer of our common shares may be subject to capital gains taxes
and/or other appointed stock exchange, to and among persons who are
pursuant to indirect transfer rules in Chile.
non-residents of Bermuda for exchange control purposes. Any other transfers
remain subject to approval by the BMA and such approval may be denied or
In September 2012, Chile established “indirect transfer rules,” which impose
delayed.
taxes, under certain circumstances, on capital gains resulting from indirect
transfers of shares, equity rights, interests or other rights in the equity,
We are a Bermuda company, and it may be difficult for you to enforce
control or profits of a Chilean entity, as well as on transfers of other assets
judgments against us or against our directors and executive officers.
and property of permanent establishments or other businesses in Chile
(“Chilean Assets”). As we indirectly own Chilean Assets, the indirect transfer
We are incorporated as an exempted company under the laws of Bermuda
rules would apply to transfers of our common shares provided certain
and substantially all of our assets are located in Colombia, Chile, Argentina,
conditions outside of our control are met. If such conditions were present and
Brazil and Peru. In addition, most of our directors and executive officers
as a result the indirect transfer rules were to apply to sales of our common
reside outside the United States and all or a substantial portion of the
shares, such sales would be subject to indirect transfer tax on the capital
assets of such persons are located outside the United States. As a result,
gain realized in connection with such sales. For a description of the indirect
it may be difficult or impossible to effect service of process within the
transfer rules and the conditions of their application see “Item 10. Additional
United States upon us, or to recover against us on judgments of U.S. courts,
Information—E. Taxation—Chilean tax on transfers of shares.”
including judgments predicated upon the civil liability provisions of the
U.S. federal securities laws. Further, no claim may be brought in Bermuda
As an exempted company incorporated under Bermuda law, our operations
against us or our directors and officers in the first instance for violation
may be subject to economic substance requirements.
of U.S. federal securities laws because these laws have no extraterritorial
application under Bermuda law and do not have force of law in Bermuda.
On December 5, 2017, following an assessment of the tax policies of various
However, a Bermuda court may impose civil liability, including the
countries by the Code of Conduct Group for Business Taxation of the European
possibility of monetary damages, on us or our directors and officers if the
Union (the “COCG”), the Council of the EU approved and published Council
facts alleged in a complaint constitute or give rise to a cause of action
conclusions containing a list of non-cooperative jurisdictions for tax purposes
under Bermuda law.
(the “Conclusions”). Although not considered so-called “non-cooperative
jurisdictions,” certain countries, including Bermuda, were listed as having
There is no treaty in force between the United States and Bermuda
“tax regimes that facilitate offshore structures which attract profits without
providing for the reciprocal recognition and enforcement of judgments in
real economic activity.” In connection with the Conclusions, and to avoid
civil and commercial matters. As a result, whether a United States judgment
being placed on the list of “non-cooperative jurisdictions,” the government of
would be enforceable in Bermuda against us or our directors and officers
Bermuda, among others, committed to addressing COCG proposals relating to
depends on whether the U.S. court that entered the judgment is recognized
economic substance for entities doing business in or through their respective
by the Bermuda court as having jurisdiction over us or our directors and
jurisdictions and to pass legislation to implement any appropriate changes by
officers, as determined by reference to Bermuda conflict of law rules. A
the end of 2018.
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
The Economic Substance Act 2018 and the Economic Substance Regulations
judgment debtor had submitted to the jurisdiction of the U.S. court, and
2018 of Bermuda (the “Economic Substance Act” and the “Economic Substance
the issue of submission and jurisdiction is a matter of Bermuda (not U.S.)
Regulations”, respectively) became operative on December 31, 2018. The
law.
Economic Substance Act applies to every registered entity in Bermuda
that engages in a relevant activity and requires that every such entity shall
In addition, and irrespective of jurisdictional issues, the Bermuda courts
maintain a substantial economic presence in Bermuda. Relevant activities for
will not enforce a U.S. federal securities law that is either penal or contrary
the purposes of the Economic Substance Act are banking business, insurance
to Bermuda public policy. An action brought pursuant to a public or penal
business, fund management business, financing business, leasing business,
GeoPark 63
Information on the company
headquarters business, shipping business, distribution and service center
from the list and sanctions or other financial, tax or regulatory measures
business, intellectual property holding business and conducting business as a
were applied by European Member States to countries on the list or further
holding entity, which may include a pure equity holding entity.
economic substance requirements were imposed by Bermuda, our business
The Bermuda Economic Substance Act provides that a registered entity that
carries on a relevant activity complies with economic substance requirements
ITEM 4. INFORMATION ON THE COMPANY
if (a) it is directed and managed in Bermuda, (b) its core income-generating
activities (as may be prescribed) are undertaken in Bermuda with respect to
A. History and development of the company
the relevant activity, (c) it maintains adequate physical presence in Bermuda,
(d) it has adequate full time employees in Bermuda with suitable qualifications
General
could be negatively impacted.
and (e) it incurs adequate operating expenditure in Bermuda in relation to the
We were incorporated as an exempted company pursuant to the laws of
relevant activity.
Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013,
A registered entity that carries on a relevant activity is obliged under the
our shareholders approved a change in our name to GeoPark Limited,
Bermuda Economic Substance Act to file a declaration in the prescribed form
effective from July 31, 2013. We maintain a registered office in Bermuda at
(the “Declaration”) with the Registrar of Companies (the “Registrar”) on an
Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda.
annual basis.
Our principal executive offices are located at Nuestra Señora de los Ángeles
179, Las Condes, Santiago, Chile, telephone number +562 2242 9600, Street
The Economic Substance Regulations provide that minimum economic
94 N° 11-30, 8, 9, 8th floor, Bogotá, Colombia, telephone number +57 1 743
substance requirements shall apply in relation to an entity if the entity is a
2337, and Florida 981, 1st floor, Buenos Aires, Argentina, telephone number
pure equity holding entity which only holds or manages equity participations,
+5411 4312 9400.
and earns passive income from dividends, distributions, capital gains
and other incidental income only. The minimum economic substance
The SEC maintains an internet website that contains reports, proxy,
requirements include a) compliance with applicable corporate governance
information statements and other information about issuers, like us, that
requirements set forth in the Bermuda Companies Act 1981 including
file electronically with the SEC. The address of that website is www.sec.gov.
keeping records of account, books and papers and financial statements and b)
The Company’s website address is www.geo-park.com. The information
submission of an annual economic substance declaration form. Additionally,
contained on, or that can be accessed through, the Company’s website is not
the Economic Substance Regulations provide that a pure equity holding entity
part of, and is not incorporated into, this Annual Report.
complies with economic substance requirements where it also has adequate
employees for holding and managing equity participations, and adequate
Our Company
premises in Bermuda.
We are a leading independent oil and natural gas exploration and production
(“E&P”) company with operations in Latin America and a proven track record
If we fail to comply with our obligations under the Bermuda Economic
of growth in production and reserves since 2006. We operate in Colombia,
Substance Act or any similar law applicable to us in any other jurisdictions,
Chile, Brazil, Argentina and Peru. We are focused on Latin America because
we could be subject to financial penalties and spontaneous disclosure of
we believe it is one of the most important regions globally in terms of
information to foreign tax officials in related jurisdictions and may be struck
hydrocarbon potential, with less presence of independent E&P companies
from the register of companies in Bermuda or such other jurisdiction. Any of
compared to the United Stated and Canada. In this region, much of the
these actions could have a material adverse effect on our business, financial
acreage has historically been controlled or owned by state-owned companies.
condition and results of operations.
We believe that these factors create an opportunity for smaller, more agile
companies like us to build a long-term business.
On March 12, 2019, Bermuda was placed by the EU on its list of non-
cooperative jurisdictions for tax purposes due to an issue with Bermuda’s
We produced a net average of 36.0 mboepd during the year ended December
economic substance legislation which was not resolved in time for the
31, 2018, of which 79%, 8%, 5% and 8% were, respectively, in Colombia, Chile,
EU’s deadline. At present, the impact of being included on the list of non-
Argentina and Brazil, and of which 85% was oil. As of August 31, 2018, we
cooperative jurisdictions for tax purposes is unclear. While Bermuda has
were ranked as the third largest oil operator in Colombia, where we made
now amended its legislation which the Bermuda Government has stated
the largest new oil field discovery in the last 20 years. We are the first private
has addressed this issue and expects to be removed from the list of non-
oil and gas operator in Chile and we are operating the inaugural project of
cooperative jurisdictions at the EU’s Economic and Financial Affairs Council’s
Petroperu in its return to the upstream business in Peru. We partnered with
next meeting which is scheduled to be in May 2019, there can be no assurance
Petrobras in one of Brazil’s largest producing gas fields and we have recently
that Bermuda will be removed from such list. If Bermuda is not removed
increased our activities in Argentina with the acquisition of three blocks in the
Neuquén Basin in March 2018.
64 GeoPark 20F
We have built our company around three principal capabilities:
each of the Otway and Tranquilo Blocks. Then, in 2011, ENAP awarded us the
• as an Explorer, which is our ability, experience, methodology and creativity
opportunity to obtain operating working interests in each of the Isla Norte,
to find and develop oil and gas reserves in the subsurface, based on the best
Flamenco and Campanario Blocks in Tierra del Fuego, Chile, which we refer
science, solid economics and ability to take the necessary managed risks.
to collectively as the Tierra del Fuego Blocks, and in 2012, jointly with ENAP,
• as an Operator, which is our ability to execute in a timely manner and to
we entered into CEOPs with Chile for the exploration and exploitation of
have the know-how to profitably drill for, produce, treat, transport and sell
hydrocarbons within these blocks.
our oil and gas – with the drive and persistence to find solutions, overcome
obstacles, seize opportunities and achieve results.
Also, in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14%
• as a Consolidator, which is our ability and initiative to assemble the right
equity interest in GeoPark TdF for US$148.0 million.
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
Finally, in November 2018, we acquired all of LGI’s equity interest in
the visions and skills to transform and improve value above ground.
GeoPark’s Chilean and Colombian subsidiaries. This acquisition increased
GeoPark’s equity interest to 100% in its Colombian and Chilean businesses.
We believe that our risk and capital management policies have enabled
The acquisition price includes a fixed payment of US$81 million already paid
us to compile a geographically diverse portfolio of properties that
at closing, plus two equal installments of US$15 million each, to be paid in
balances exploration, development and production of oil and gas. These
June 2019 and June 2020. Additionally, three contingent payments of US$5
attributes have also allowed us to raise capital and to partner with premier
million each could be payable over the next three years, subject to certain
international companies. Most importantly, we believe we have developed a
production thresholds being exceeded.
distinctive culture within our organization that promotes and rewards trust,
partnership, entrepreneurship and merit. Consistent with this approach,
Colombia
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
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 of reserves and
Panama, which merged into GeoPark Colombia SAS (“Luna”) and (iii) Hupecol
resources in Colombia.
History
We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park,
In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia
who have over 40 years of international oil and natural gas experience,
Coöperatie U.A by making a US$14.9 million capital contribution and
respectively. Mr. O’Shaughnessy currently serves as our Chairman and Mr.
assuming the existing debt for an amount of US$4.9 million.
Park currently serves as our Chief Executive Officer and Deputy Chairman.
Brazil
We are a leading independent oil and natural gas exploration and
In May 2013, we entered into agreements to expand our operations to Brazil.
production (“E&P”), company with operations in Latin America and a proven
As of 2014, following the Rio das Contas acquisition, we have a 10% working
track record of growth in production and reserves since 2006. We operate in
interest in the BCAM-40 Concession, which includes an interest in the Manati
Colombia, Chile, Brazil, Argentina and Peru.
Field operated by Petrobras.
Our History can be summarized by our growth in each country and our
Since 2013, we have participated in the Brazilian ANP Bid Rounds and have
performance in the capital markets:
been awarded exploratory concessions in each one of them.
Chile
Argentina
In 2006, after demonstrating our technical expertise and committing to an
In August 2014, in partnership with Pluspetrol, a private oil and gas
exploration and development plan, we obtained a 100% operating working
company with strong presence across Latin America, we were awarded two
interest in the Fell Block from the Republic of Chile. In 2008 and 2009, we
exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of
continued our growth in Chile by acquiring operating working interests in
the 2014 Mendoza Bidding Round in Argentina.
GeoPark 65
In July 2015, we signed a farm-in agreement with Wintershall for the CN-V
In September 2017, we issued US$425.0 million aggregate principal amount
Block in the Mendoza Province.
of 6.50% senior notes due 2024. The net proceeds from the Notes were used
by us (i) to make a capital contribution to our wholly-owned subsidiary,
Additionally, in December 2017, we agreed to purchase from Pluspetrol, a
GeoPark Latin America Limited Agencia en Chile, providing it with sufficient
100% working interest and operatorship of the Aguada Baguales, El Porvenir
funds to fully repay the Notes due 2020 and to pay any related fees and
and Puesto Touquet blocks in Argentina. We entered into an asset purchase
expenses, including a call premium, and (ii) for general corporate purposes,
agreement with Pluspetrol, dated December 18, 2017 (the “APA”). The
including capital expenditures, such as the acquisition of Aguada Baguales,
transaction closed on March 27, 2018.
El Porvenir and Puesto Touquet blocks in the Neuquén Basin in Argentina, to
repay existing indebtedness, including the Itaú loan.
Finally, In June 2018, we entered into a partnership with YPF, the state-
owned oil company of Argentina, on the Los Parlamentos block – a large
B. Business Overview
high potential block in the Neuquén Basin with both conventional and
unconventional prospects.
Peru
We have grown our business through drilling, developing and producing oil
and gas, winning new licenses and acquiring strategic assets and businesses.
Since our inception, we have supported our growth through our prospect
In October 2014, we expanded our footprint into Peru by acquiring the
development efforts, drilling program, long-term strategic partnerships and
Morona Block in a joint venture with Petroperu. This transaction awarded us
alliances with key industry participants, accessing debt and equity capital
a 75% working interest of the Morona Block. In December 2016, we obtained
markets, developing and retaining a technical team with vast experience
final regulatory approval for our acquisition of the Morona Block in Peru. The
and creating a successful track record of finding and producing oil and gas
Joint Investment and Operating Agreement dated October 1, 2014 and its
in Latin America. A key factor behind our success ratio is our experienced
amendments were closed on December 1, 2016, following the issuance of
team of geologists, geophysicists and engineers, including professionals with
Supreme Decree 031-2016-MEM.
specialized expertise in the geology of Colombia, Chile, Brazil, Argentina and
New potential country platform
Peru.
In December 2015, as part of our long-term effort to build an upstream
The following map shows the countries in which we have blocks with working
platform in Mexico, we participated in the Mexican Bid Round 1.3 with Grupo
and/or economic interests as of December 31, 2018. For information on our
Alfa for onshore projects, however, no blocks were awarded to us.
working interests in each of these blocks, see “—Our assets” below.
In March 2019, we announced our expected entry into Ecuador through the
acquisition of the Espejo and Perico exploratory blocks in the Intracampos
Bid Round in the Oriente Basin located in the north-eastern part of Ecuador.
The blocks were awarded to the GeoPark and Frontera consortium (50%
GeoPark, 50% Frontera) in the form of production sharing contracts. The
final award is contingent upon regulatory approvals and the execution
of the contracts is expected for the second quarter of 2019. See “Item 3.
Key Information—A. Risk Factors—Risks relating to our business— Our
pending acquisition of the Espejo and Perico blocks in Ecuador is subject to
regulatory approvals.”
Funding
In February 2013, we issued US$300 million aggregate principal amount
of 7.50% senior secured notes due 2020 (the “Notes due 2020”). We
repurchased US$284 million aggregate principal amount of the outstanding
Notes due 2020 in September 2017 and redeemed the remaining US$16
million aggregate principal amount outstanding in October 2017.
In February 2014, we commenced trading on the NYSE and raised US$98
million (before underwriting commissions and expenses), including the over-
allotment option granted to and exercised by the underwriters, through the
issuance of 13,999,700 common shares.
66 GeoPark 20F
Brazil Blocks
POT-T-619
REC-T-94
BCAM-40 Manati
SEAL-T-268
POT-T-747
POT-T-785
REC-T-128
PN-T-597(2)
Argentina Blocks
Sierra del Nevado
Puelen
CN-V
Aguada Baguales
El Porvenir
Puesto Touquet
Los Parlamentos(3)
COLOMBIA
Colombia Blocks
La Cuerva(1)
Llanos 34
Yamu(1)
Llanos 32
Abanico
VIM-3
Peru Blocks
Morona
PERU
BRAZIL
PA CIFIC
OCEAN
ARGENTINA
ATLANTIC
OCEAN
Chile Blocks
Fell
Isla Norte
Campanario
Flamenco
Tranquilo
CHILE
(1) On November 2, 2018, GeoPark and Perenco Oil and Gas executed a
purchase and sale agreement in which Perenco agreed to purchase GeoPark’s
100% working interest in the La Cuerva and Yamu blocks. Closing of the
transaction is subject to customary regulatory approvals. We will continue
operating the blocks until the completion of the divestiture process. See “—
Our operations—Operations in Colombia.”
(2) The PN-T-597 is still subject to the entry into the concession agreement and
absence of legal impediments, by the ANP in the Parnaíba Basin. See “—Our
operations—Operations in Brazil.”
(3) Subject to regulatory approvals. See “—Our operations—Operations in
Argentina.”
GeoPark 67
The following table sets forth our net proved reserves and other data as of and
for the year ended December 31, 2018.
For the year ended December 31 2018
Country
Colombia
Chile
Brazil
Peru
Argentina
Total
Oil (mmbbl)
Gas (bcf )
(mmboe)
Oil equivalent
74.8
3.3
0.1
18.5
3.4
100.1
2.1
20.8
17.3
-
9.4
49.6
75.1
6.8
3.0
18.5
5.0
108.4
Revenues
(in thousands
of US$)
497,870
37,359
30,053
-
35,879
601,161
%Oil
100%
49%
3%
100%
68%
92%
% of total
revenues
83%
6%
5%
-%
6%
100%
(Our commitment to growth has translated into a strong compounded annual
growth rate (“CAGR”), of 16% for production in the period from 2014 to 2018,
as measured by boepd in the table below.
For the year ended December 31,
Average net production (mboepd)
% oil
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, 2018.
Average daily production
For the year ended December 31, 2018
Oil production
Total crude oil production (bopd)
Natural gas production
Total natural gas production (mcf/day)
Oil and natural gas production
2018
36.0
85%
2017
27.6
83%
2016
22.4
75%
2015
20.4
74%
2014
19.7
74%
Colombia
Chile
Brazil
Argentina(1)
Total
28,421
782
42
1,202
30,447
740
11,640
17,300
3,796
33,476
Total oil and natural gas production (mboepd)
28,545
2,722
2,925
1,835
36,027
(1) We acquired the Neuquén Blocks in March 2018. Production figures do not
include production prior to their acquisition by us.
Our assets
We have a well-balanced portfolio of assets that includes working and/or
economic interests in 25 hydrocarbon blocks, 24 of which are onshore blocks,
including 10 in production as of December 31, 2018. 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, 2018, the blocks
in Colombia, Chile, Brazil, Argentina and Peru in which we have a working
interest had 108.4 mmboe of net proved reserves, with 69%, 6%, 3%, 5% and
17% of such net proved reserves located in Colombia, Chile, Brazil, Argentina
and Peru, respectively.
68 GeoPark 20F
We produced a net average of 36.0 mboepd during the year ended December
Situche Central proven oil field, which we believe offers extensive exploration
31, 2018 of which 79%, 8%, 5% and 8%, were in Colombia, Chile, Argentina
potential with several potential high impact prospects and plays. See “—Our
and Brazil, respectively, and of which 85% was oil.
operations—Operations in Peru.”
We are the operator of the majority of the blocks in which we have a working
Significant drilling inventory and resource potential from existing asset
interest.
Our strengths
base
Our portfolio includes large land holdings in high-potential hydrocarbon basins
and blocks with multiple drilling leads and prospects in different geological
We believe that we benefit from the following competitive strengths:
formations, which provide several attractive opportunities with varying levels
of risk. Our drilling inventory and our development plans target locations that
High quality and diversified asset base built through a successful track
provide attractive economics and support a predictable production profile, as
record of organic growth and acquisitions
demonstrated by our expansions in Colombia.
Our assets include a diverse portfolio of oil and natural gas-producing reserves,
operating infrastructure, operating licenses and valuable geological surveys in
Our geoscience team continues to identify new potential accumulations and
Latin America. Throughout our history, we have delivered continuous growth in
expand our inventory of prospects and drilling opportunities.
our production, and our management team has been able to identify under-
exploited assets and turn them into valuable, productive assets, and to allocate
Continue to grow a risk-balanced asset portfolio
resources effectively based on prevailing conditions.
We intend to continue to focus on maintaining a risk-balanced portfolio
of assets, combining cash flow-generating assets with upside potential
• Colombia. In 2012, we acquired assets in Colombia at attractive prices, which
opportunities, and on increasing production and reserves through finding,
gave us access to exploratory and productive acres with many prospects.
developing and producing oil and gas reserves in the countries in which we
In the Llanos Basin, we pioneered a new play type combining structural
operate. In general, when we enter a new country we look for a mix of three
and stratigraphic traps. As a result, in the Llanos 34 Block our average daily
elements: (i) producing fields, or existing discoveries with near-term possibility
production has grown from 0 at the time of acquisition to more than 30,400
of production, to generate cash flows; (ii) an inventory of adjacent low-risk
bopd as of December 31, 2018.
prospects that can offer medium-term upside for steady growth; and (iii) a
• Chile. In 2002, we acquired a non-operating working interest in the Fell Block
periphery of higher-risk projects which have a potential to generate significant
in Chile, which at the time had no material oil and gas production or reserves
upside in the long run.
despite having been actively explored and drilled over the course of more
than 50 years. Since 2006, when we became the operator of the Fell Block
For example, in Colombia, we acquired three companies simultaneously to
we performed active exploration and development drilling that resulted in
pursue a risk-balanced approach: one company had mainly proven production
multiple oil and gas discoveries.
and reserves to provide us with a steady cash flow base, and the remaining
• Brazil. Since 2013, we have participated in the Brazilian ANP Bid Rounds and
had highly prospective exploration license blocks. Within four years of entering
were awarded exploratory concessions in each one of them. In 2014, we
Colombia, we made multiple oil discoveries in block Llanos 34 that allowed us to
acquired Rio das Contas, which gave us a 10% working interest in the BCAM-
increase production and cash flows.
40 Concession, including the shallow-depth offshore Manati and Camarão
Norte Fields in the Camamu-Almada Basin in the State of Bahia, which has
We believe this approach will allow us to sustain continuous and profitable
consistently self-funded its operations. The Manati Field has provided up to
growth and also participate in higher risk growth opportunities with upside
3.7% of total gas produced in Brazil.
potential. See “—Our operations.”
• Argentina. During 2014, GeoPark and Pluspetrol were awarded two
exploration licenses in the Sierra del Nevado and Puelen Blocks as part of
Platform and Funding
the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa
We are focused on continued growth utilizing a disciplined capital structure
Mendocina de Energía S.A. (“EMESA”). In 2015, we acquired a 50% working
and a conservative financial philosophy. Due to the volatile nature of
interest in the CN-V Block in Mendoza from Wintershall Energía S.A. On
commodity prices, expenditure discipline and a focus on disciplined capital
December 18, 2017, we executed an asset purchase agreement (the “APA”)
structure are critical to our business. Our multi-country platform and asset
with Pluspetrol to acquire a 100% working interest and operatorship of
portfolio is managed through our capital allocation methodology, which also
the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina.
allows us to quickly adapt and grow. Under this methodology, each country,
Closing of the transaction occurred on March 27, 2018.
has a local team running the business who recommends and advocates for
• Peru. In December 2016, we expanded our footprint into Peru by acquiring the
the projects with which they want to move forward. The corporate team then
Morona Block in a joint venture with Petroperu. The Morona Block contains the
ranks all of the projects based on economic, technical and strategic criteria,
GeoPark 69
for the purpose of comparing projects. This also creates opportunities for
the principal payments that were due in 2015 (amounting to approximately
improvements in the projects that can, in turn, improve their ranking. Finally,
US$15 million), which were divided pro-rata during the remaining principal
once the production and reserve growth targets are defined, the corporate
installments, starting in March 2016 and (ii) to increase the variable interest
team decides the amount of capital to be invested and allocates that capital
rate equal to the 6-month LIBOR + 4.0%. The loan was fully repaid in
to the highest value-adding projects. As an example, for the 2019 capital
September 2017.
allocation process, over 135 projects were presented with a final selection of
74 which comprise our 2019 work program, under the base capital program.
In February 2014, we commenced trading on the NYSE and raised US$98
Additionally, given the inherent oil price volatility, we design our work
million (before underwriting commissions and expenses), including the over-
programs to be flexible, which means that they can be increased or decreased
allotment option granted to and exercised by the underwriters, through the
depending on the oil price scenario.
issuance of 13,999,700 common shares.
We have historically benefited from access to debt and equity capital markets
Strong cash flow
and cash flows from operations, as well as other funding sources, which have
We benefit from a strong cash flow from operating activities. For the year
provided us with funds to finance our organic growth and the pursuit of
ended December 31, 2018, cash provided by operating activities was
potential new opportunities.
US$256.2 million. Our cash flow from operating activities plays a significant
We generated US$256.2 million and US$142.2 million in cash from operations
in the years ended December 31, 2018 and 2017, respectively, and had
Maintain financial strength
role in funding our capital expenditures.
US$127.7 million and US$134.8 million of cash and cash equivalents as of
We seek to maintain a prudent and sustainable capital structure and a strong
December 31, 2018 and 2017, respectively.
financial position to allow us to maximize the development of our assets
and capitalize on business opportunities as they arise. We intend to remain
As of December 31, 2018, we had US$447.0 million of total outstanding
financially disciplined by limiting substantially all our debt incurrence to
indebtedness and over 96% of our debt had a maturity of 2024.
identified projects with repayment sources. We expect to continue benefiting
from diverse funding sources such as our partners and customers in addition
During October 2018, we entered into a loan agreement with Banco
to the international capital markets.
Santander for Brazilian Real 77.6 million (equivalent to US$ 20 million at
the moment of the loan execution) to repay an existing US$-denominated
Our cash flow generation is complemented by our financial hedging program.
intercompany loan, which matures in October 2020. As a result of this
Since October 2016, we have entered into derivative financial instruments to
transaction, our Brazilian subsidiary has significantly reduced its exposure to
manage our exposure to oil price risk. The purpose of our hedging strategy is
foreign currency fluctuation.
to establish minimum oil prices to secure a stable cash flow and the execution
of our work program. For the period commencing January 2018 to December
In September 2017, we issued US$425.0 million aggregate principal amount
2018, we hedged between 13,000 and 14,000 bopd via zero premium collars
of 6.50% senior notes due 2024 (the “Notes due 2024”). The Notes due 2024
and three-way hedges (US$10/bbl wide put spread and call), with a minimum
contain incurrence-based limitations on the amount of indebtedness we can
average Brent price of US$55 per barrel and a maximum average price of
incur, see “Item 5. Operating and Financial Review and Prospects—Liquidity
US$73 per barrel, representing 44% of our oil production for that period. For
and capital resources—Indebtedness—Notes due 2024—Covenants.”
the period from January 2019 to March 2019, we have secured 15,000 bopd
with a minimum average price of US$64 per barrel and a maximum average
In December 2015, we entered into an offtake and prepayment agreement
price of US$92 per barrel via zero premium collars and three-way hedges
with Trafigura under which we sold and delivered a portion of our Colombian
(US$10/bbl wide put spread and call). For the period from April 2019 to June
crude oil production to Trafigura. The offtake agreement also provided us
2019, we have secured 11,000 bopd with a minimum average price of US$65
with prepayment line of up to US$100 million, subject to applicable volumes
per barrel and a maximum average price of US$91 per barrel via zero premium
corresponding to the terms of the agreement, in the form of prepaid future oil
collars and three-way hedges (US$10/bbl wide put spread and call). For the
sales.
period commencing July 2019 to September 2019, we have secured 5,000
bopd with a minimum average price of US$65 per barrel and a maximum
In March 2014, we borrowed US$70.5 million pursuant to a five-year term
average price of US$92 per barrel via zero premium collars.
variable interest secured loan, secured by the benefits we receive under
the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to
In December 2018 we decided to manage our future exposure to local
6-month LIBOR + 3.9% to finance part of the purchase price of our Rio das
currency fluctuation with respect to income tax balances in Colombia.
Contas acquisition. In March 2015, we reached an agreement to: (i) extend
Consequently, we entered into a derivative financial instrument with a local
70 GeoPark 20F
bank in Colombia, for an amount equivalent to US$ 92.1 million, in order to
us with additional funding flexibility to pursue further acquisitions
anticipate any currency fluctuation with respect to income taxes to be paid
We benefit from a number of strong partnerships and relationships. In
during the first half of 2019.
Chile, we believe we have strong long-term commercial relationships with
Methanex and ENAP, and in Colombia, we believe we have developed a strong
We believe that by maintaining a disciplined capital structure and a
relationship with Ecopetrol, the Colombian state-owned oil and gas company.
conservative financial philosophy, including limiting our debt incurrence to
In Brazil, we believe we will continue to derive benefits from the long-term
specified projects with repayment sources and our use of financial hedges, we
relationship GeoPark Brazil has with Petrobras.
are positioned to maintain sufficient liquidity and remain flexible in volatile
commodity price environments. Our financial flexibility also gives us the ability
In February 2018, we announced the formation of a new long-term strategic
to pursue new opportunities through future potential acquisitions.
partnership to jointly acquire, invest in, and create value from upstream oil
and gas projects with the objective of building a large-scale, economically-
Pursue strategic acquisitions in Latin America
profitable and risk-balanced portfolio of assets and operations across Latin
We have historically benefited from, and intend to continue to grow through,
America with ONGC Videsh, the wholly-owned subsidiary and international
strategic acquisitions in Latin America. These acquisitions have provided us
arm of Oil and Natural Gas Corporation Limited, India’s national oil company.
with additional attractive platforms in the region. Our Colombian acquisitions,
for example, highlight our ability to identify and execute on attractive growth
Maintain our commitment to environmental, safety and social responsibility
opportunities, as we have grown to become the third largest operator in
A major component of our business strategy is our focus on and commitment
Colombia. We acquired our interest in the Llanos 34 Block in the first quarter
to our environmental and social responsibilities, in line with international
of 2012 for US$30 million and have achieved 1P reserve PV-10 of US$1,340
standards. We see this as a fundamental element of ensuring long-term
million as of December 31, 2018. Our enhanced regional portfolio, including
business initiatives. We are committed to minimizing the impact of
investment-grade countries and strong partnerships, position us as a regional
our projects on the environment and aim to create mutually beneficial
consolidator. We intend to continue to grow through strategic acquisitions in
relationships with the local communities in which we operate in order
other countries in Latin America, which we may consider from time to time.
to enhance our ability to create sustainable value in our projects. These
commitments are embodied in our in-house designed Environmental, Health,
Our acquisition strategy is aimed at maintaining a balanced portfolio of lower-
Safety and Security management program, which we refer to as “S.P.E.E.D.”
risk cash flow-generating properties and assets that have upside potential,
(Safety, Prosperity, Employees, Environment and Community Development).
keeping a balanced mix of oil and gas-producing assets (though we expect
Our S.P.E.E.D. program was developed in accordance with several international
to remain weighted towards oil) and focusing on both assets and corporate
quality standards, including ISO 14001 (for environmental management
targets.
issues), OHSAS 18001 (for occupational health and safety management issues),
ISO 26000 (for social accountability and workers’ rights issues), and applicable
Maintain a high degree of operatorship to control production costs
World Bank standards. See “—Health, safety and environmental matters.”
As of the date of this annual report, we are and intend to continue to be
the operator of a majority of the blocks and concessions in which we have
During 2016, we began the ISO 14001 certifying process through programs
working interests. Operating the majority of our blocks and concessions gives
related to the efficient use of natural resources and compliance with
us the flexibility to allocate our capital and resources opportunistically and
environmental regulation. We have also provided training to our staff and the
efficiently within a diversified asset portfolio. We believe that this strategy has
communities in which we operate with respect to these matters.
allowed, and will continue to allow us, to leverage our unique culture, focused
on excellence, and our talented technical, operating and management teams.
In August 2017, we obtained the ISO 14001:2015 certification for our
For example, as commodity prices were projected to decline throughout 2015,
environmental management process for the design, construction, operation,
we announced in the first quarter of 2015 a decision to shift our development
maintenance, modernization and dismantlement of GeoPark Colombia
plan primarily to our operations in the Llanos 34 Block to focus on the Llanos
S.A.S.’s facilities, and the performance of exploration and oil and gas
Basin, which had demonstrated strong returns on capital. Our operating team
production activities in the Llanos 34 and VIM-3 blocks with a commitment to
reacted quickly to pivot our operations that were unburdened by drilling
continuously improve our processes.
obligations and worked with our service partners to coordinate a smooth
and efficient transition to a new plan. Since then we were able to control
Highly committed founding shareholders and technical and management
production costs, as exemplified by our average operating costs for the Llanos
teams with proven industry expertise and technically-driven culture
34 Block, which were US$4.0 per boe for the year ended December 31, 2018.
Our founding shareholders, management and operating teams have
significant experience in the oil and gas industry and a proven technical and
Long-term strategic partnerships and strong strategic relationships provide
commercial performance record in onshore fields, as well as complex projects
GeoPark 71
in Latin America and around the world, including expertise in identifying
application of state-of-the-art technologies, agile processes and creative new
acquisition and expansion opportunities. Moreover, we differentiate
solutions to challenges in both our fields and our offices. Our guiding principle is
ourselves from other E&P companies through our technically-driven culture,
that everyone can innovate, and this is promoted through a cross-collaborative
which fosters innovation, creativity and timely execution. Our geoscientists,
and trust-based work environment. To ensure that this is taken as a key priority,
geophysicists and engineers are pivotal to the success of our business
as of 2018 we have included innovation as one of our metrics in our Balanced
strategy, and we have created an environment and supplied the resources that
Scorecard and have allocated seed money in our annual budget to kick-start
enable our technical team to focus its knowledge, skills and experience on
new projects. As an example of the success we have had, in 2018 we were
finding and developing oil and gas fields.
awarded a prize for innovative road safety measures by the Colombian Council
In addition, we strive to provide a safe and motivating workplace for
technology-based projects, such as cryobox virtual gas technology in Neuquén
employees in order to attract, protect, retain and train a quality team in the
Province, in Argentina, to put into production a well that was previously shut-in
competitive marketplace for capable energy professionals.
due to a lack of facilities, and a gas based artificial lift system for mature wells in
of Security. Additionally, we have successfully implemented multiple new
Our CEO, Mr. James F. Park, has been involved in E&P projects in Latin America
since 1978. He has been closely involved in grass-roots exploration activities,
2019 Strategy and Outlook
Chile that results in low maintenance costs.
drilling and production operations, surface and pipeline construction, legal
Oil prices have been volatile since the end of 2014. In preparation for
and regulatory issues, crude oil marketing and transportation and capital
continued volatility, we have developed multiple scenarios for our 2019 capital
raising for the industry. As of March 15, 2019, Mr. Park held 13.2% of our
expenditure program.
outstanding common shares.
Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the oil
price assumption of US$70 per barrel and calls for approximately US$220-
and gas business internationally and in North America since 1976. As of March
240 million to fund our exploration and development, which we intend to
15, 2019, Mr. O’Shaughnessy held 11.5% of our outstanding common shares.
fund through cash flows from operations and cash-in-hand, to be allocated
Our preliminary base capital program for 2019 considers a reference oil
approximately as follows:
Our management and operating team has an average experience in the
• Colombia: US$85-95 million. Continue to develop and appraise the Tigana
energy industry of more than 25 years in companies such as Chevron, ENAP,
and Jacana oil fields and target new exploration prospects in the Llanos basin.
Petrobras, Pluspetrol, San Jorge, Total and YPF, among others. Throughout our
• Chile: US$17-20 million. Develop and explore oil and gas targets, both
history, our management and operating team has had success in unlocking
conventional and unconventional, in the Fell and Tierra del Fuego blocks.
unexploited value from previously underdeveloped assets.
• Brazil: US$3-4 million. Focus on exploration drilling in onshore blocks.
In addition, as of March 15, 2019, our executive directors and key management
gas targets in the Neuquén Basin.
(excluding our founding shareholders, Mr. Gerald E. O’Shaughnessy and Mr.
• Peru: US$95-105 million. Focus on construction of early production facilities
James F. Park) owned 30.7% of our outstanding common shares, aligning their
in the Morona block with the goal of putting the Situche Central light oil field
interests with those of our shareholders and helping retain the talent we need
into production by 2020, subject to approval of the environmental impact
• Argentina: US$20-25 million. Focus on development and exploration oil and
to continue to support our business strategy. See “Item 6. Directors, Senior
assessment.
Management and Employees—B. Compensation.” Our founding shareholders
are also involved in our daily operations and strategy.
In addition, we have developed downside and upside work program scenarios
based on different oil prices and project performance. The downside scenario
Technically-driven culture and capitalization of local knowledge
work program considers a reference oil price assumption below US$65
We intend to continue to pursue strategies that maximize value. For this
per barrel and consists of an alternative capital expenditure program of
purpose, we intend to continue expanding our technical teams and to foster
approximately US$120 million-US$140 million consisting mainly of certain
a culture that rewards talent according to results. For example, we have been
low risk and quick cash flow generating projects. The upside scenario work
able to maintain the technical teams we inherited through our Colombian and
program considers a reference oil price assumption above US$75 per barrel
Brazilian acquisitions. We believe local technical and professional knowledge is
or higher and consists of an alternative capital expenditure program of
key to operational and long-term success and intend to continue to secure local
approximately US$240 million-US$270 million to be selected from identified
talent as we grow our business in different locations.
projects designed to increase reserves and production.
Innovation
Our operations
We are committed to an innovation culture driven by the continuous search and
We have a well-balanced portfolio of assets that includes working and/or
72 GeoPark 20F
economic interests in 25 hydrocarbon blocks, 24 of which are onshore blocks,
•
In November 2018 we signed an agreement with Perenco Oil and Gas to
including 10 in production as of December 31, 2018, as well as in an additional
divest the La Cuerva and Yamu blocks for $18 million plus a contingent payment
shallow-offshore concession in Brazil that includes the Manati Field. In
of $2 million, based on future oil prices; and
addition, we have one concession in Brazil, the PN-T-597 Block, that is subject
•
In November 2018 we acquired LGI’s 20% equity interest in our Colombian
to the entry into the concession agreement by the ANP and one concession in
subsidiary, which expanded our participation in the valuable Llanos 34 block.
Argentina, the Parlamentos Block, that remains subject to regulatory approval
as of the date of this annual report.
Operations in Colombia
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
Our Colombian assets currently give us access to more than 244,900 gross
participation interests in the net revenues from a given block based on bilateral
exploratory and productive acres across 6 blocks in what we believe to be one of
agreements with the concessionaires.
South America’s most attractive oil and gas geographies.
The map below shows the location of the blocks in Colombia in which we have
Since we entered Colombia in 2012, we have achieved consistent growth in
working and/or economic interests.
our oil production and proved reserves in Colombia, mainly achieved through
successful exploration and development activities we made at our operated
Llanos 34 Block, which as of December 31, 2018 accounts for 95% of our
production and 97% of our proved reserves in Colombia.
The table below shows average production and proved oil and gas reserves
(derived from D&M Reserves Report) in Colombia for the years ended December
31, 2018, 2017 and 2016:
Average net production (mboepd)
Net proved reserves at year-end (mmboe)
2018
28.4
75.1
2017
21.8
65.5
2016
15.5
37.3
Highlights of the year ended December 31, 2018 related to our operations in
Colombia included:
• Successful drilling campaign with 21 gross wells drilled and put into
production in the Jacana and Tigana oil fields in the Llanos 34 Block. This
campaign includes the successful drilling and testing of Tigana Norte 9 appraisal
well;
• Discovery of the Chachalaca Sur oil field, following the successful drilling and
testing of the Chachalaca Sur 1 exploration well, located on a fault trend to the
west of the Tigana and Jacana oil fields;
• Discovery of the new Tigui oil field, following the successful drilling and
testing of the Tigui 1 exploration well;
• Average net production increased by 30%, to 28.4 mboepd in 2018 from 21.8
mboepd in 2017;
• Proved oil and gas reserves increased by 15% to 75.1 mmboe at year-end
(1) On November 2, 2018, GeoPark and Perenco Oil and Gas executed a purchase
and sale agreement in which Perenco agreed to purchase GeoPark’s 100%
2018, from 65.5 mmboe at year-end 2017 after producing 9.4 mmboe;
working interest in the La Cuerva and Yamu blocks. Closing of the transaction
• Capital expenditures increased by 21% to US$97.0 million in 2018 from
is subject to customary regulatory approvals. We will continue operating the
US$80.0 million in 2017;
blocks until the completion of the divestiture process. See “—Our operations—
• Maintenance of production and operating costs levels per barrel from US$5.6
Operations in Colombia.”
in 2017 to US$5.5 in 2018;
• Flowline construction to connect the Llanos 34 block oil fields to regional
The table summarizes information about the blocks in Colombia in which we
pipeline infrastructure is on budget and on schedule and expected to be
have working interests as of and for the year ended December 31, 2018.
operational in 2019;
GeoPark 73
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
82.2
45%
Parex
GeoPark
72.5
27,219
Llanos
Exploration: 2019
Exploitation: 2039-2042(4)
24.5
100%
5.6
100%
—
—
GeoPark
GeoPark
Llanos 32
57.0
12.5%
Parex
Parex
VIM-3
48.9
100%
—
GeoPark
1.2
1.0
0.4
—
606
Llanos
Exploitation: 2038
375
Llanos
Production: 2036
306
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 in
on it, and with 210 sq. km of existing 3D seismic data on which our team had
mapped multiple exploration prospects. From 2012 to 2018 we engaged in
such block.
(2) Partners with working interests.
(3) As of December 31, 2018.
(4) The concession expiration year is set on a field by field basis.
exploration and development activities that resulted in multiple new oil fields
discovered and increased production and proved reserves year by year. Average
net production in 2018 was 27,219 bopd and net reserves of 72.5 mmboe. The
remaining commitment amounts to US$1.9 million at our working interest.
The table summarizes information about the blocks in Colombia in which we
Our partner in the Llanos 34 Block is Parex, which has a 55% interest. See “—
have economic interests as of and for the year ended December 31, 2018
Our operations.” We operate in the block pursuant to an E&P Contract with the
ANH. See “—Significant Agreements—Colombia—E&P Contracts—Llanos 34
Gross acres
(thousand
acres)
26.7
Economic
interest(1)
10%
Block
Abanico
Production
Block E&P Contract.”
Operator
(boepd)
Basin
La Cuerva Block. We are the operator of, and have a 100% working interest
Pacific
39
Magdalena
in, the La Cuerva Block, which covers approximately 24,500 gross acres (99.1
(1) Economic interest corresponds to indirect participation interests in the net
revenues from the block, granted to us pursuant to a joint operating agreement.
sq. km). Average net oil production in 2018 was 606 bopd. We operate in
the block pursuant to an E&P Contract with the ANH. On November 2, 2018
we executed a Sale Purchase Agreement with Perenco to sale the 100%
working interest in the La Cuerva Block. Closing of the transaction is subject to
Eastern Llanos Basin: (Llanos 34, La Cuerva, Yamú, Llanos 32, Abanico, and VIM-3
customary regulatory approvals, which are expected to occur during 2019.
Blocks)
The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region
the Yamú Block, which covers approximately 5,588 gross acres (22.6 sq. km).
of Colombia. Two giant fields (Caño Limón and Castilla), three major fields
For the year ended December 31, 2018, our average net production was 375
(Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had
bopd. On November 2, 2018 we executed a Sale Purchase Agreement with
been discovered. The source rock for the basin is located beneath the east flank
Perenco to sale the 100% working interest in the Yamú Block. Closing of the
of the Eastern Cordillera, as a mixed marine-continental shale basinal facies
transaction is subject to customary regulatory approvals, which are expected
Yamú Block . We are the operator of, and have a 100% working interest in,
of the Gachetá formation. The main reservoirs of the basin are represented
to occur during 2019.
by the Paleogene Carbonera and Mirador sandstones. Within the Cretaceous
sequence, several sandstones are also considered to have good reservoirs.
Llanos 32 Block . We have a 12.5% working interest in the Llanos 32 Block, as
a result of our acquisition of an additional 2.5% interest on August 22, 2017.
Llanos 34 Block . We are the operator of, and have a 45% working interest in,
The Llanos 32 Block covers approximately 57,000 gross acres (230.7 sq. km).
the Llanos 34 Block, which covers approximately 82,200 gross acres (333 sq.
Parex is the operator of this block and has a 87.5% working interest. Since
km). We acquired an interest in and took operatorship of the block in the first
2015, the operator focused on the commissioning of a gas facility on this
quarter of 2012, which at that time had no production, reserves or wells drilled
block to produce natural gas and light crude oil from the Une formation and
74 GeoPark 20F
to facilitate shipment of processed gas south to the adjacent Llanos 34 Block.
Our Chilean blocks are located in the provinces of Ultima Esperanza,
For the year ended December 31, 2018, our average net production in the
Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil
Llanos 32 Block was 306 bopd. The remaining commitment related to this
and gas-producing area. As of December 31, 2018, the Magallanes Basin
block is to drill one exploratory well before August 2018 was already fulfilled.
accounted for all of Chile’s oil and gas production. Although this basin has
On February 19, 2019 the parties to the Llanos 32 contract requested ANH
been in production for over 60 years, we believe that it remains relatively
to grant an extension of one year to phase 2 of the subsequent exploratory
underdeveloped.
program in order to drill an exploratory well amounting to US$ 4.7 million
gross subject to ANH approval. We executed an agreement with Parex by
Substantial technical data (seismic, geological, drilling and production
which we obtained a 25% working interest in the remaining exploration areas
information), developed by us and by ENAP, provides an informed base for
of the block.
new hydrocarbon exploration and development. Shut-in and abandoned
fields may also have the potential to be put back in production by
VIM-3 Block. On July 23, 2014 we were awarded an exploratory license during
constructing new pipelines and plants. Our geophysical analyses suggest
the 2014 Colombia Bidding Round, carried out by the ANH. We are entitled
additional development potential in known fields and exploration potential
to operate the block, in which we have a 100% working interest. The VIM-3
in undrilled prospects and plays, including opportunities in the Springhill,
Block is located in the Lower Magdalena Basin. Our winning bid consisted of
Tertiary, Tobífera and Estratos con Favrella formations. The Springhill
committing to a Royalty X Factor of 3% and a minimum investment program
formation has historically been the source of production in the Fell Block,
of 200 sq. km of 2D seismic data acquisition and drilling one exploratory
though the Estratos con Favrella shale formation is the principal source rock
well, with a total estimated investment of US$22.3 million during the initial
of the Magallanes Basin, and we believe it contains unconventional resource
exploratory period ending February 2019. On June 21, 2017, the ANH
potential.
approved our relinquishment of 79.15% of the VIM 3 Block area. The remaining
area covers 48,950 acres and the commitments described above are not
Highlights of the year ended December 31, 2018 related to our operations in
affected. On September 12, 2018, the ANH accepted our proposal to extend
Chile included:
the first exploratory phase for an additional period ending May 12, 2019.
• Discovery of the Jauke gas field with successful drilling and testing of the
Additionally, we requested the ANH to terminate the E&P Contract due to
Jauke 1 exploration well in the Fell block;
environmental restrictions in the block. These restrictions became apparent
• Discovery of the Uaken gas field with successful drilling and testing of the
once the National Authority of Environmental Licenses (ANLA) issued the
Uaken 1 exploration well in the Fell block;
environmental license. As of the date of this annual report, the termination
• Average net oil and gas production declined to 2,722 boepd in 2018 from
request is under review and the remaining commitment amounts to US$22.3
2,885 boepd in 2017;
million.
• Proved oil and gas reserves decreased by 9% to 6.8 mmboe at year-end
2018, from 7.5 mmboe at year-end 2017 after producing 0.9 mmboe;
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc.
• Capital expenditures decreased by 23% to US$7.9 million in 2018 from
entered into the Abanico Block association contract. Pacific Rubiales Energy
US$10.2 million in 2017; and
is the operator of, and has a 100% working interest in, the Abanico Block,
•
In November 2018 we acquired LGI’s 20% equity interest in our Chilean
which covers an area of approximately 26,658 gross acres (103 sq. km). We do
subsidiary.
not maintain a direct working interest in the Abanico Block, but rather have a
10% economic interest in the net revenues from the block pursuant to a joint
operating agreement initially entered into with Kappa Resources Colombia
Limited (now Pacific, who subsequently assigned its participation interest to
Cespa de Colombia S.A., who then assigned the interest to Explotaciones CMS
Oil & Gas), Maral Finance Corporation and Getionar S.A.
Operations in Chile
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
Magallanes Basin, with existing reserves, production and cash flows.
GeoPark 75
The map below shows the location of the blocks in Chile in which we have
working interests.
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, 2018.
Block
Fell
Tranquilo
Isla Norte
Campanario
Flamenco
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
6.8
2,708
Magallanes
Exploitation: 2032
92.4
50% (4)
Pluspetrol
GeoPark
97.7
144.2
105.9
60%
50%
50%
ENAP
GeoPark
ENAP
GeoPark
ENAP
GeoPark
—
—
—
—
—
Magallanes
Exploitation: 2043
Exploration: 2021
—
Magallanes
Exploitation: 2044
Exploration: 2021
—
Magallanes
Exploitation: 2045
Exploration: 2021
14
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.
(2) Partners with working interests.
(3) As of December 31, 2018.
(4) In December 2018, we increased our working interest to 100%. The approval of the agreement is still under the review of the Ministry of Energy.
76 GeoPark 20F
Fell Block
Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)
In 2006, we became the operator and 100% interest owner of the Fell Block.
In the first and second quarters of 2012, we entered into three CEOPs with
When we first acquired an interest in the Fell Block in 2002, it had no material
ENAP and Chile granting us working interests in the Isla Norte, Campanario
oil and gas production. Since then, we have completed more than 1,100 sq.
and Flamenco Blocks, located in the center-north of the Tierra del Fuego
km of 3D seismic surveys and drilled 117 exploration and development wells.
Province of Chile. We are the operator of all three of these blocks, with
In the year ended December 31, 2018, we produced an average of 2,708
working interests of 60%, 50% and 50%, respectively. We believe that
boepd, in the Fell Block, consisting of 29% oil.
these three blocks, which collectively cover 347,700 gross acres (1,407 sq.
km) and are geologically contiguous to the Fell Block, represent strategic
The Fell Block has an area of approximately 368,000 gross acres (1,488 sq.
acreage with resource potential. We have committed to paying 100% of the
km) and its center is located approximately 140 km northeast of the city of
required minimum investment under the CEOPs covering these blocks, in an
Punta Arenas. It is bordered on the north by the international border between
aggregate amount of US$101.4 million through the end of the first exploratory
Argentina and Chile and on the south by the Magellan Strait.
periods for these blocks, which includes our covering of ENAP’s investment
commitment corresponding to its working interest in the blocks.
From 2006 through August 2011, we successfully explored and developed
the Fell Block, which allowed us to transition approximately 84% of the Fell
Flamenco Block. We are the operator of, and have a 50% working interest in,
Block’s area from an exploration phase into an exploitation phase, which we
the Flamenco Block, in partnership with ENAP. The block covers approximately
expect will last through 2032. During the exploration phase, we exceeded the
105,900 gross acres (428 sq. km). In June 2013, we discovered a new oil and
minimum work and investment commitment required under the Fell Block
gas field in the block following the successful testing of the Chercán 1 well,
CEOP by more than 75 times. There are no minimum work and investment
the first well drilled by us in Tierra del Fuego. As of March 31, 2019, we had
commitments under the Fell Block CEOP associated with the exploitation
completed 100% of the committed 570 sq. km of 3D seismic surveys and the
phase.
drilling activities for the first exploration period under the CEOP governing
the Flamenco Block. In the year ended December 31, 2018, we produced an
The Fell Block is located in the north-eastern part of the Magallanes Basin.
average of 14 boepd in the Flamenco Block.
The principal producing reservoir is composed of sandstones in the Springhill
formation, at depths of 2,200 to 3,500 meters. Additional reservoirs have
On June 30, 2017, the Chilean Ministry accepted our proposal to extend the
been discovered and put into production in the Fell Block—namely, Tobífera
second exploratory period for an additional period of 18 months. As of the
formation volcanoclastic rocks at depths of 2,900 to 3,600 meters, and Upper
date of this annual report, US$2.1 million investment commitments related
Tertiary and Upper Cretaceous sandstones, at depths of 700 to 2,000 meters.
to this block (corresponding to one exploratory well) remain outstanding
and will be entirely assumed by us. On December 20, 2018, we proposed to
Our geosciences team identified and developed an attractive inventory of
extend the second exploratory period for an additional period of 18 months,
prospects and drilling opportunities for both exploration and development in
ending November 7, 2020. As of the date of this annual report the Chilean
the Fell Block.
Ministry has not replied.
During 2018, we successfully drilled and completed the Jauke X-1 exploration
Isla Norte Block. We are the operator of and have a 60% working interest in
well. The well is in production, and the gas is being sold to Methanex through
partnership with ENAP in the Isla Norte Block, which covers approximately
a long-term gas contract. In addition, we continued to focus on maintaining
97,650 gross acres (395 sq. km). As of March 31, 2019, we had completed
production levels, and reducing production, operating costs and workover
100% of the committed 350 sq. km of 3D seismic surveys and drilled one
costs.
exploratory well, which represents the first oil discovery within the block. As
of the date of this annual report, outstanding investment commitments of
The Jauke gas field is part of the large Dicky geological structure in the Fell
US$2.9 million related to this block correspond to two exploratory wells to be
block and has the potential for multiple development drilling opportunities.
executed before May 7, 2019.
Petrophysical analysis also indicates hydrocarbon potential in the shallower El
Salto formation which will be tested in the future. Our 2019 work plan includes
Campanario Block. We are the operator of, and have a 50% working interest
the drilling of an additional well.
in, the Campanario Block, in partnership with ENAP. The block covers
approximately 144,150 gross acres (583 sq. km). As of March 31, 2019, we
The Fell Block also contains the Estratos con Favrella shale reservoir, which we
had completed 100% of the committed 578 sq. km of 3D seismic surveys and
believe represents a high-potential, unconventional resource play for shale oil,
have also drilled five exploratory wells, including the Primavera Sur 1 well that
as a broad area within Fell Block (1,000 sq. km) which appears to be in the oil
marks the first discovery of an oil field on the Campanario Block in addition
window for this play.
to one development well. As of the date of this annual report, outstanding
GeoPark 77
investment commitments of US$4.8 million related to this block correspond
The map below shows the location of our concessions in Brazil in which we
to three exploratory wells to be executed before July 10, 2019.
have a current or future working interest, including the BCAM-40 Concession
and the concessions from bidding rounds 11, 12, 13 and 14.
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 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. In December 2018, we increased our
working interest to 100%. The approval of the agreement with Pluspetrol in
connection with this change is still under review by the Ministry of Energy.
Operations in Brazil
(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.
Our Brazilian assets currently give us access to 68,600 of gross exploratory
Risk factors—Risks relating to our business—The PN-T-597 Concession
and productive acres across 7 blocks (6 exploratory blocks and the BCAM-40
Agreement in Brazil may not close.”
Concession, which is in production phase) in an attractive oil and gas geography.
Highlights of the year ended December 31, 2018 related to our operations in
Brazil included:
• Average net oil and gas production of 2,925 boepd (99% gas) in the year
ended December 31, 2018, as compared to 2,910 boepd in 2017;
• Capital expenditures decreased by 36% to US$2.3 million in 2018 from US$3.6
million in 2017; and
• Praia dos Castelhanos 1 exploration well was drilled in the REC- T-128 block
to a total depth of 8,431 feet and will be completed and tested in the first half of
2019.
78 GeoPark 20F
The following table sets forth information as of December 31, 2018 on our
concessions in Brazil in which we have a current or future working interest,
including the Manati Field and the concessions from bidding rounds 11, 12, 13
and 14.
Concession
REC-T 94
POT-T 619
PN-T-597(2)
SEAL-T-268
REC-T-128
POT-T-747
POT-T-785
Manati
Gross acres
(thousand
acres)
Working
interest(1)
7.7
100%
100%
100%
100%
7.9
188.7
7.8
7.6
—
—
—
—
GeoPark
GeoPark
GeoPark
GeoPark
70%
Geosol
GeoPark
6.9
100%(5)
7.9
100%(5)
—
—
GeoPark
GeoPark
Petrobras;
Net proved
reserves
Production
Partners
Operator
(mmboe)
(boepd)
Basin
Concession
expiration year
Exploration: 2020
—
—
—
—
—
—
—
—
Recôncavo
Exploitation: 2047
—
—
—
Potiguar
Parnaíba
Sergipe
Alagoas
—
Recôncavo
—
—
Potiguar
Potiguar
Camamu-
Exploration: 2020
Exploitation: 2045
—
Exploration: 2020
Exploitation: 2047
Exploration: 2019
Exploitation: 2045
Exploration: 2018(4)
Exploitation: 2045
Exploration: 2023
Exploitation: 2050
22.8
10%
Enauta; Brasoil
Petrobras
3.0
2,925
Almada
Exploitation: 2029
(1) Working interest corresponds to the working interests held by our respective
subsidiaries, net of any working interests held by other parties in such
of concession agreements—BCAM-40 Concession Agreement.” In September
2009, Petrobras announced the relinquishment of BCAM-40’s exploration area
concession. See “Item 3. Key Information—D. Risk factors—Risks relating to
within the concession to the ANP, except for the Manati Field and the Camarão
our business—The PN-T-597 Concession Agreement in Brazil may not close.”
(2) 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
Norte Field. In August 2018, Petrobras announced the relinquishment of the
Camarão Norte Field.
this annual report, confirmation remains subject to final signing and local
The Manati Field is located 65 km south of Salvador, offshore at a water depth
authority approval. See “Item 3. Key Information—D. Risk factors—Risks
of 35 meters. The field was discovered in October 2000, and, in 2002, Petrobras
relating to our business—The PN-T-597 Concession Agreement in Brazil may
declared the field commercially viable. Production began in January 2007. As
not close.”
(3) A 30% working interest of proposed partners is subject to ANP approval.
(4) The exploration period is currently suspended subject to the approval of the
environmental license by the ANP.
Manati Field
of December 31, 2018, 11 wells had been drilled in the Manati Field, 6 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 is sold to Petrobras up to a
maximum volume as determined in the existing Petrobras Gas Sales Agreement
As a result of the Rio das Contas acquisition, we have a 10% working interest
(as defined below). In July 2015, we signed an amendment to the existing Gas
in the BCAM-40 Concession, which originally included interests in the Manati
Sales Agreement with Petrobras that covers 100% of the remaining gas reserves
Field and the Camarão Norte Field, and which is located in the Camamu-Almada
of the Manati Field.
Basin. Petrobras is the operator of, and has a 35% working interest in, the BCAM-
40 Concession, which covers approximately 22,784 gross acres (92.2 sq. km). In
Also, in 2015, in order to improve the field gas recovery and production, Manati’s
addition to us, Petrobras’ partners in the block are Brasoil and Enauta Energia S.A.
consortium built an onshore compression plant that started operating in August
(Enauta), with 10% and 45% working interests, respectively. Petrobras operates
2015. The compression plant involved capital expenditures of approximately
the BCAM-40 Concession pursuant to a concession agreement with the ANP,
US$3.7 million at our working interest and allowed us to classify all existing
executed on August 6, 1998. See “—Significant Agreements—Brazil—Overview
proved undeveloped reserves as proved developed.
GeoPark 79
Some environmental licenses related to operation of the Manati Field
relating to our business—The PN-T-597 Concession Agreement in Brazil may
production system and natural gas pipeline are expired. However, the operator
not close.”
submitted, in a timely manner, the request for renewal of those licenses and as
such this operation is not in default as long as the regulator does not state its
PN-T-597 Concession
final position on the renewal.
Round 11 Concessions
The Parnaiba Basin, which covers an area of approximately 148 million
gross acres (600,000 sq. km), is a basin with large underexplored areas. As of
December 31, 2018, the basin had two fields in production in the basin.
During ANP’s 11th Bid Round, held in May 2013, we were awarded 7
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$2.0 million, at the December 31, 2018 exchange rate of R$3.9 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$17.6 million (approximately US$ 4.5 million,
political and economic circumstances in the countries in which we operate
at the December 31, 2018 exchange rate of R$3.9 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$0.4 million, at the December 31, 2018 exchange rate of R$3.9 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$0.6 million at the December 31, 2018 exchange rate of
remaining committed work program that amounts to US$ 0.2 million.
R$3.9 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
Round 12 Concessions
POT-T-747 and POT-T-882
In November 2013, in the 12th Bid Round, the ANP awarded us two
The POT-T-747 and POT-T-882 blocks are located in the Potiguar Basin and
concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of
encompass an area of 14,829 acres (60 square km). Total commitment to
Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin) in
the ANP was R$8.5 million (approximately US$2.2 million, at the December
the State of Alagoas.
31, 2018 exchange rate of R$3.9 to US$1.00) during the first exploratory
period and is equivalent to acquiring 70 km of 2D seismic and drilling one
For more information, see “Item 3. Key information—D. Risk factors—Risks
well. During 2017 3D seismic was reprocessed and a well was drilled in the
80 GeoPark 20F
POT-T-747 block during 2018 and was abandoned. All the commitments
The Morona Block has DeGolyer and MacNaughton certified net proved
related to POT-T-882 were fulfilled as of the date of this annual report. The
reserves of 18.5 mmboe as of December 31, 2018, composed of 100% oil.
estimated remaining commitment in the POT-T-747 block amounts to US$0.5
The map below shows the location of the Morona Block in Peru.
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$2.7 million at the December 31, 2018 exchange rate of R$3.9 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
geological 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 2018, 3D reprocessing was performed in the
REC-T-128 block and we also drilled the Praia dos Castelhanos 1 exploration
well that will be completed and tested in the first half of 2019. As of December
31, 2018, the estimated remaining commitment in the REC-T-128 block
amounts to US$2.2 million. This commitment was fulfilled in the first quarter
of 2019.
Upon complete fulfillment of the minimum exploratory work program and the
accomplishment of local content commitments, the POT-T-882 and REC-T-93
blocks were relinquished to the ANP in December 2018.
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$0.3 million, at the December 31, 2018 exchange
rate of R$3.9 to US$1.00) during the first exploratory period and is equivalent
to acquiring 4 km2 of 3D seismic and performing geochemical analysis
before January 29, 2023. As of December 31, 2018, the estimated remaining
commitment in the POT-T-785 block amounts to US$0.1 million.
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.
GeoPark 81
The table below summarizes information about the block in Peru.
Block
Morona
Gross acres
(thousand
acres)
1,881
Working
interest(1)
75%
Net proved
reserves
Production
Operator
GeoPark
(mmboe)
(boepd)
Basin
18.5
—
Marañon
Expiration
concession year
Exploitation: 2039(2)
(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
revenues associated to future sales. The beginning of such activities is subject
to the approval of an environmental impact assessment by the Peruvian
of our investments in the block through agreed terms in the Petroperu SPA.
environmental authority.
See “Item 4. Information on the Company—B. Business Overview—Our
operations—Operations in Peru—Morona Block.”
(2) The concession will expire twenty (20) years after EIA approval.
In accordance with the agreement between us and Petroperu, commitments
assumed by GeoPark are subject to certain economical and technical
conditions being met.
Morona Block
The Morona Block covers an area of approximately 1,881 thousand gross acres
The third stage, which will be initiated once production has been established,
(7,600 sq. km). More than 1 billion barrels of oil have been produced from the
is expected to focus on carrying out the full development of the Situche
surrounding blocks in the Marañon Basin.
Central field, including transportation infrastructure.
On October 1, 2014, we entered into an agreement to acquire a 75% working
The exploratory program entails drilling one exploratory well. Exploratory
interest in the Morona Block in Northern Peru. As stated above, this agreement
program capital expenditures will be borne exclusively by us. Expected capital
includes a work program to be executed by us. This program includes 3
expenditures in 2019 for the Morona Block are mainly related to flexible
phases, and we may decide whether to continue or not at the end of each
pipeline installation, temporary access road, location conditioning and the
phase. On December 1, 2016, through Supreme Decree N° 031-2016-MEN,
Morona Camp dock revamping. These activities are subject to the approval of
the Peruvian government approved the amendment to the License Contract
the Environmental Impact Study, which is under review by the local authority
of Morona Block appointing GeoPark as operator and holder of 75% of the
as of the date of this annual report. The approval of the Development
License-Contract.
Environmental Impact Study is expected by the end of the second quarter of
The Morona Block contains the Situche Central oil field, which has been
2019.
delineated by two wells (with short term tests of approximately 2,400 and
Initially we will hold a 75% working interest in the block. However, according
5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the
to the terms of the agreement, Petroperu has the right to increase its working
Situche Central field, the Morona Block has a large exploration potential
interest in the block up to 50%, subject to the recovery of our investments in
with several high impact prospects and plays. The Morona Block includes
the block by certain agreed factors.
geophysical surveys of 2,783 km (2D seismic) and 465 sq. km (3D seismic), and
an operating field camp and logistics infrastructure. The area has undergone
See “Item 3. Key Information—D. Risk factors—Risks relating to our business—
oil and gas exploration activities for the past 40 years, and there exist ongoing
Our inability to access needed equipment and infrastructure in a timely
association agreements and cooperation projects with the local communities.
manner may hinder our access to oil and natural gas markets and generate
The expected work program and development plan for the Situche Central oil
significant incremental costs or delays in our oil and natural gas production”
field is to be completed in three stages.
and “—We may suffer delays or incremental costs due to difficulties in
negotiations with landowners and local communities, including native
The goal of the initial two stages is to start production from the two wells
communities, where our reserves are located.”
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 in 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, 2020. We
expect these expenditures to be substantially reimbursed by Petroperu from
82 GeoPark 20F
Operations in Argentina
The map below shows the location of the blocks in Argentina in which we
have working interests as of December 31, 2018.
(1) Subject to regulatory approvals. See “—Our operations—Operations in
Argentina.”
The table below summarizes information about the blocks in Argentina in
which we have working interests as of December 31, 2018.
Block
Puelen
Sierra del Nevado
Aguada Baguales
Puesto Touquet
El Porvenir
CN-V
Los Parlamentos
Gross acres
(thousand
acres)
260.2
1,399.4
44.0
34.2
58.9
57.2
330.9
Working
interest(1)
18%
18%
100%
100%
100%
50%
50%
Operator
Pluspetrol
Pluspetrol
GeoPark
GeoPark
GeoPark
Wintershall
YPF
Net proved
reserves
Production
(mmboe)
(boepd)
—
—
3.0
1.0
1.0
—
—
—
—
968
495
372
—
—
Basin
Neuquén
Neuquén
Neuquén
Neuquén
Neuquén
Neuquén
Neuquén
Expiration
concession year
Exploration: 2019
Exploration: 2019
Exploitation: 2025
Exploitation: 2027
Exploitation: 2025
Exploration: 2021
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 in
each block.
GeoPark 83
Highlights of the year ended December 31, 2018 related to our operations in
CN-V Block Farm-in Agreement
Argentina included:
On July 22, 2015, we signed a farm-in agreement with Wintershall for the
• Operational takeover of newly acquired Aguada Baguales, El Porvenir and
CN-V Block in Argentina, which complements our existing acreage in the
Puesto Touquet Blocks in the Neuquén Basin with an average net oil and gas
basin. Wintershall is Germany’s largest oil and gas producer and a subsidiary
production of 1,835 boepd in 2018;
of BASF Group. Under the agreement, we committed to operate during the
• Capital expenditures of US$9.0 million in 2018;
exploratory phase and receive a 50% working interest in the CN-V Block in
• Proved oil and gas reserves of 5.0 mmboe at year-end 2018; and
exchange for having to drill and fully fund two exploratory wells for a total of
• Acquired new low-cost large exploration acreage, the Los Parlamentos
US$10 million.
block in the Neuquén Basin, in partnership with YPF S.A. (“YPF”)
Neuquén blocks
The CN-V Block covers an area of approximately 57.2 thousand gross acres
and is located in the Neuquén Basin in southern Argentina. The block has 3D
On March 27, 2018, we acquired a 100% working interest and operatorship
seismic coverage of 180 sq. km and is adjacent to the producing Loma Alta Sur
of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks, which are
oil field, a region and play-type well known to our team. The block includes
located in the Neuquén Basin, for a total consideration of US$52 million,
upside potential in the developing Vaca Muerta unconventional play.
less a working capital adjustment of US$ 3.1 million. The blocks include
production facilities, such as hydrocarboons treatment, storage, and delivery
During 2017, we drilled the first exploratory well, Rio Grande Oeste 1, which
infrastructure.
resulted in the discovery of Rio Grande Oeste oil field. During 2018, we drilled
the second exploratory well, Rio Grande Este 1, which is under evaluation.
Los Parlamentos Block Farm-in Agreement
With these investments GeoPark Argentina has fulfilled the initial commitment
In June 2018, we acquired a 50% working interest in the Los Parlamentos
of US$10 million and the operation of the block was transferred to Wintershall.
exploratory block in partnership with YPF, the largest oil and gas producer in
As of the date of this annual report, the estimated remaining commitment in
Argentina. In accordance with the partnership agreement, YPF assumed the
the CN-V block for the current exploratory period denominated “Field under
operationship of the block and GeoPark assumed a commitment to fund its
evaluation”, ending on November 27, 2021, amounts to US$1.3 million at our
50% working interest of one exploratory well and additional 3D seismic, which
working interest.
amounts to US$6 million at GeoPark’s working interest, over the next three
years.
Oil and natural gas reserves and production
2014 Mendoza Bidding Round
Overview
On August 20, 2014, the consortium of Pluspetrol and us was awarded two
We have achieved consistent growth in oil and gas reserves from our
exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of
investment activities since 2006, when we began production in the Fell Block
the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa
in Chile, followed by successful acquisition, exploration and development
Mendocina de Energía S.A. (“EMESA”).
activities in other countries in which we have a presence, including Colombia,
The consortium consists of Pluspetrol (operator with a 72% working interest),
EMESA (non-operator with a 10% working interest) and us (non-operator
Our reserves
Brazil, Argentina, and Peru.
with an 18% working interest). In accordance with the terms of the bidding,
The following table sets forth our oil and natural gas net proved reserves as of
all of the expenditures related to EMESA’s working interest will be carried by
December 31, 2018, which is based on the D&M Reserves Report.
Pluspetrol and us proportionately to our respective working interests and will
be recovered through EMESA’s participation in future potential production.
We have committed to a minimum aggregate investment of US$6.2 million for
our working interest, which includes the work program commitment on both
blocks during the first three years of the exploratory period. As of December
31, 2018, the remaining commitments in the Sierra del Nevado block for the
first exploratory period amount to between US$0.5 and US$1.0 million at our
working interest. There is no pending commitment in the Puelen block.
84 GeoPark 20F
Net proved reserves
As of December 31, 2018
Total net
During the year ended December 31, 2018, we had 12.8 mmboe of our
Natural
proved
proved undeveloped reserves from December 31, 2017 converted to proved
Oil
(mmbbl)
gas
(bcf )
reserves
(mmboe)(1)
developed reserves due to development drilling in the Jacana and Tigana
% Oil
oil fields in the Llanos 34 Block. For further information relating to the
Net proved developed
Colombia
Chile
Argentina
Brazil
32.3
0.7
2.0
0.1
Total net proved developed
35.1
Net proved undeveloped
42.5
2.6
1.4
18.5
Colombia
Chile
Argentina
Peru
Total net proved
undeveloped (2)
Total net proved
(Colombia, Chile, Peru,
1.8
12.0
6.2
17.3
37.3
0.3
8.8
3.2
-
32.6
2.7
3.1
3.0
41.4
42.5
4.1
1.9
18.5
reconciliation of our net proved reserves for the years ended December 31,
2018, 2017 and 2016, please see Table 5 included in Note 37 (unaudited) to our
Consolidated Financial Statements.
Internal controls over reserves estimation process
99%
26%
65%
3%
85%
We maintain an internal staff of petroleum engineers and geosciences
professionals who work closely with our independent reserves engineers
100%
to ensure the integrity, accuracy and timeliness of data furnished to our
63%
74%
independent reserves engineers in their estimation process and who have
knowledge of the specific properties under evaluation. Our Director of
100%
Exploration, Salvador Minniti, is primarily responsible for overseeing the
preparation of our reserves estimates and for the internal control over our
65.0
12.3
67.0
97%
reserves estimation. He has more than 35 years of industry experience
as an E&P geologist, with broad experience in reserves assessment, field
development, exploration portfolio generation and management and
Argentina and Brazil)
100.1
49.6
108.4
92%
acquisition and divestiture opportunities evaluation. See “Item 6. Directors,
Senior Management and Employees—A. Directors and senior management.”
(1) We calculate one barrel of oil equivalent as six mcf of natural gas.
(2) We plan to put 100% of our reported 2018 year-end proved undeveloped
reserves into production through activities to be implemented within five
years of initial disclosure.
In order to ensure the quality and consistency of our reserves estimates and
reserves disclosures, we maintain and comply with a reserves process that
satisfies the following key control objectives:
• estimates are prepared using generally accepted practices and
methodologies;
We had net proved reserves of 108.4 mmboe at December 31, 2018, compared
• estimates are prepared objectively and free of bias;
to net proved reserves of 95.7 mmboe as of December 31, 2017.
• estimates and changes therein are prepared on a timely basis;
The 13.3% increase in net proved reserves in 2018, not including annual
• estimates and changes therein are properly supported and approved; and
production, is mainly attributable to:
• estimates and related disclosures are prepared in accordance with regulatory
• Better than expected performance from existing wells from the Tigana and
requirements.
Jacana fields in the Llanos 34 Block, which added 15.4 mmboe.
• Extensions and discoveries that resulted in an increase of 9.9 mmboe due to
Throughout each fiscal year, our technical team meets with Independent
the Tigana and Jacana appraisal wells and the Tigui oil field discovery in Llanos
Qualified Reserves Engineers, who are provided with full access to complete
34 Block, the Jauke gas field discovery in the Fell Block and the gas discovery
and accurate information pertaining to the properties to be evaluated and
of the Une Formation in the Llanos 32 Block.
all applicable personnel. This independent assessment of the internally-
• An increase of 5.7 mmboe resulting from the purchase of minerals related
generated reserves estimates is beneficial in ensuring that interpretations
to the acquisitions of the Aguada Baguales, El Porvenir and Puesto Touquet
and judgments are reasonable and that the estimates are free of preparer and
blocks.
management bias.
• An increase of 2.5 mmboe due to higher average oil and gas prices.
This was partially offset by:
Recognizing that reserves estimates are based on interpretations and
• Changes in a previously adopted development plan for the Max, Tua,
judgments, differences between the proved reserves estimates prepared by
Chachalaca Sur, Tilo, and Jacamar fields in the Llanos 34 Block, resulting in a
us and those prepared by an Independent Qualified Reserves Engineer of
6.6 mmboe decrease.
10% or less, in aggregate, are considered to be within the range of reasonable
• Lower than expected performance from existing wells in the Fell and Manati
differences. Differences greater than 10% must be resolved in the technical
Blocks, resulting in a 1.0 mmboe decrease.
meetings. Once differences are resolved, the independent Qualified Reserves
• Revisions in Peru that resulted in a 1.3 mmbbl decrease.
Engineer sends a preliminary copy of the reserves report to be reviewed by
GeoPark 85
the Technical Committee and Directors of each country. A final copy of the
Report based upon its evaluation. D&M’s primary economic assumptions
Reserves Report is sent by the Independent Qualified Reserve Engineer to be
in estimates included oil and gas sales prices determined according to SEC
approved and signed by the Technical Committee and our CEO and CFO. See
guidelines, future expenditures and other economic assumptions (including
“Item 6. Directors, Senior Management and Employees—C. Board Practices—
interests, royalties and taxes) as provided by us. The assumptions, data,
Committees of our board of directors.”
methods and procedures used, including the percentage of our total reserves
Independent reserves engineers
reviewed in connection with the preparation of the D&M Reserves Report
were appropriate for the purpose served by such report, and DeGolyer and
Reserves estimates as of December 31, 2018 for Colombia, Chile, Brazil,
MacNaughton used all methods and procedures as it considered necessary
Argentina and Peru included elsewhere in this annual report are based on the
under the circumstances to prepare such reports.
D&M Reserves Report, dated February 4, 2019 and effective as of December
31, 2018. The D&M Reserves Report, a copy of which has been filed as an
However, uncertainties are inherent in estimating quantities of reserves,
exhibit to this annual report, was prepared in accordance with SEC rules,
including many factors beyond our and our independent reserves engineers’
regulations, definitions and guidelines at our request in order to estimate
control. Reserves engineering is a subjective process of estimating subsurface
reserves and for the areas and period indicated therein.
accumulations of oil and natural gas that cannot be measured in an exact
manner, and the accuracy of any reserves estimate is a function of the quality
DeGolyer and MacNaughton, a Delaware corporation with offices in Dallas,
of available data and its interpretation. As a result, estimates by different
Houston, Moscow, Algiers, Astana and Buenos Aires has been providing
engineers often vary, sometimes significantly. In addition, physical factors
consulting services to the oil and gas industry since 1936. The firm has
such as the results of drilling, testing and production subsequent to the
more than 200 professionals, including engineers, geologists, geophysicists,
date of an estimate, economic factors such as changes in product prices
petrophysicists and economists that are engaged in the appraisal of oil and
or development and production expenses, and regulatory factors, such as
gas properties, the evaluation of hydrocarbon and other mineral prospects,
royalties, development and environmental permitting and concession terms,
basin evaluations, comprehensive field studies and equity studies related to
may require revision of such estimates. Our operations may also be affected
the domestic and international energy industry. DeGolyer and MacNaughton
by unanticipated changes in regulations concerning the oil and gas industry
restricts its activities exclusively to consultation and does not accept
in the countries in which we operate, which may impact our ability to recover
contingency fees, nor does it own operating interests in any oil, gas or mineral
the estimated reserves. Accordingly, oil and natural gas quantities ultimately
properties, or securities or notes of its clients. The firm subscribes to a code
recovered will vary from reserves estimates.
of professional conduct, and its employees actively support their related
technical and professional societies. The firm is a Texas Registered Engineering
Technology used in reserves estimation
Firm.
According to SEC guidelines, proved reserves are those quantities of oil and
gas which, by analysis of geoscience and engineering data, can be estimated
The D&M Reserves Report covered 100% of our total reserves. In
with “reasonable certainty” to be economically producible—from a given date
connection with the preparation of the D&M Reserves Report, DeGolyer
forward, from known reservoirs, and under existing economic conditions,
and MacNaughton prepared its own estimates of our proved reserves. In
operating methods and government regulations—prior to the time at which
the process of the reserves evaluation, DeGolyer and MacNaughton did not
contracts providing the right to operate expire, unless evidence indicates
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.
86 GeoPark 20F
There are various generally accepted methodologies for estimating reserves
The following table shows the evolution of total net proved undeveloped
including volumetrics, decline analysis, material balance, simulation models
(“PUD”) reserves in the year ended December 31, 2018.
and analogies. Estimates may be prepared using either deterministic (single
estimate) or probabilistic (range of possible outcomes and probability of
occurrence) methods. The particular method chosen should be based on
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2017
58.9
the evaluator’s professional judgment as being the most appropriate, given
(All amounts shown in mmboe)
the geological nature of the property, the extent of its operating history and
the quality of available information. It may be appropriate to employ several
Plus: Extensions, discoveries and acquisitions:
methods in reaching an estimate for the property.
-Colombia
-Chile
Estimates must be prepared using all available information (open and cased
-Argentina
hole logs, core analyses, geologic maps, seismic interpretation, production/
Less: PUD Reserves converted
injection data and pressure test analysis). Supporting data, such as working
to proved developed reserves:
interest, royalties and operating costs, must be maintained and updated when
-Colombia
such information materially changes.
Plus/less: PUD Reserves revisions and
movement to/from other categories:
Proved undeveloped reserves
As of December 31, 2018, we had 67.0 mmboe in proved undeveloped
reserves, an increase of 8.1 mmboe, or 14%, over our December 31, 2017
-Colombia
-Chile
-Peru
proved undeveloped reserves of 58.9 mmboe. Changes for the year ended
Total Net Proved Undeveloped (“PUD”)
December 31 2018, include (i) an increase of 8.9 mmboe in Colombia due to
Reserves at December 31, 2018
the Tigana and Jacana appraisal wells, the Tigui field discovery in the Llanos
34 Block and the gas discovery of the Une Formation in the Llanos 32 Block.;
8.9
0.1
2.0
(12.8)
2.1
(1.4)
9.2
67.0
(ii) an increase of 2.0 mmboe in Argentina due to the purchase of minerals in
Production, revenues and price history
place related with the Aguada Baguales, El Porvenir and Puesto Touquet fields
The following table sets forth certain information on our production of oil
acquisitions during 2018; (iii) a decrease of 12.8 mmboe in Colombia due to
and natural gas in Colombia, Chile, Brazil and Argentina for each of the years
the conversion of proved undeveloped reserves to proved developed reserves
ended December 31, 2018, 2017 and 2016.
in the Llanos 34 Block; (iv) an increase of 8.2 mmboe in Peru due to revisions
in the Morona Block; (v) an increase in Peru of 1.0 mmboe due to the impact
of higher average oil prices in the Morona Block (vi) an increase of 8.2 mmboe
due to the better than expected performance from existing wells from the
Tigana and Jacana fields in the Llanos 34 Block in Colombia partially offset by
a removal of 1.4 mmboe of proved undeveloped reserves related to a worse
than expected performance in the Fell Block in Chile; (vii) an increase of 0.2
mmboe in Chile due to the Jauke field discovery in the Fell Block and (viii) a
decrease in reserves of 6.3 mmboe in Colombia due to changes in a previously
adopted development plan in Max, Tua, Chachalaca Sur, Tilo and Jacamar
fields in the Llanos 34 Block.
Of our 67.0 mmboe of net proved undeveloped reserves, 42.5 mmboe (63%),
4.1 mmboe (6%), 1.9 mmboe (3%) and 18.5 mmboe (28%) were located in
Colombia, Chile, Argentina and Peru, respectively.
During 2018, we incurred approximately US$37.8 million in capital
expenditures in Colombia to convert such proved undeveloped reserves to
proved developed reserves.
No net proved undeveloped reserves were located in Brazil as of December 31,
2018.
GeoPark 87
Average daily production(1)
As of December 31
Colombia
Chile
Brazil
2018
Argentina(4)
Colombia
Chile
Brazil
Argentina
Colombia
Chile
2017
2016
Brazil
28,421
782
42
1,202
21,718
1,000
42
4
15,536
1,380
39
52.6
62.3
79.1
65.0
36.1
45.7
60.1
52.3
24.4
37.0
48.0
740
11,640
17,300
3,796
414
11,317
17,209
2.6
5.4
5.0
5.0
5.9
4.5
5.8
-
-
5.6
6.3
22.8
1.6
11.9
24.4
6.1
2.9
9.0
31.2
7.5
38.7
5.6
3.2
8.8
20.3
1.4
7.8
3.2
242.6
10.0
21.7
11.0
252.6
-
-
5.4
1.4
6.7
14,964
17,346
3.8
5.0
15.8
1.1
16.9
5.8
2.8
8.5
Oil production
Average crude oil
production (bopd)
Average sales price of
crude oil (US$/bbl) (3)
Natural Gas production
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)
(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 gas in 2016 does not include our Argentine and Colombian blocks because our gas operations in those countries were not
material during such period.
(4) We acquired the Neuquén Blocks in March 2018. Production figures do not include production prior to their acquisition by us.
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, 2018, 2017 and 2016.
Tigana oil field(1)
Jacana oil field(1)
Rest of Colombia
Chile
Brazil
Argentina
Total
Oil
Mbbl
4,748.0
3,051.0
1,590.0
280.0
15.0
470.0
2018
Gas
Mmcf
-
-
-
3,703.0
5,803.0
1,071.0
Oil
Mbbl
2,767.0
2,566.0
1,870.0
347.0
15.0
-
2017
Gas
Mmcf
-
-
-
3,745.0
5,763.0
-
10,154.0
10,577.0
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
(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.
88 GeoPark 20F
Drilling activities
The following table sets forth the exploratory wells we drilled as operators
during the years ended December 31, 2018, 2017 and 2016.
Exploratory wells(1)
As of December 31
Colombia
Chile
Brazil
Argentina
Colombia
Chile
Brazil
Argentina
Colombia
Chile
2018
2017
Productive(2)
Gross
Net
Dry(3)
Gross
Net
Total
Gross
Net
9.0
4.1
2.0
1.5
11.0
5.6
1.0
1.0
-
-
1.0
1.0
1.0
0.7
1.0
1.0
2.0
1.7
-
-
-
-
-
-
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
-
-
-
-
-
-
(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, 2018, 2017 and 2016.
Development wells
Colombia
Chile
Brazil
Argentina
Colombia
Chile
Brazil
Argentina
Colombia
Chile
2018
2017
Productive(1)
Gross
Net
Dry(2)
Gross
Net
Total
Gross
Net
16
7.2
-
-
16
7.2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
(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.
2016
Brazil
-
-
-
-
-
-
2016
Brazil
-
-
-
-
-
-
GeoPark 89
Developed and undeveloped acreage
mboepd. Of this total production, 81%, 7%, 6% and 6% were in Colombia,
The following table sets forth certain information regarding our total gross
Chile, Argentina and Brazil, respectively.
and net developed and undeveloped acreage in Colombia, Chile, Brazil,
Argentina and Peru as of December 31, 2018.
Acreage(1)
(in thousands of acres)
In March 2019, we announced the entry into Ecuador through the
acquisition of the Espejo and Perico exploratory blocks in the Intracampos
Bid Round in the Oriente Basin located in the north-eastern part of Ecuador.
Colombia
Chile
Perú
Brazil
Argentina
The blocks were awarded to the GeoPark and Frontera consortium (50%
Total developed acreage
Gross
Net
11.6
5.6
6.7
6.7
0.7
0.5
Total undeveloped acreage
Gross
Net
233.3
120.2
801.3
591.0
1,880.3
1,410.3
Total developed and undeveloped acreage
Gross
Net
244.9
125.8
808.0
597.7
1,881.0
1,410.8
4.1
0.4
253.2
234.1
257.3
234.5
GeoPark, 50% Frontera) in the form of production sharing contracts. The
final award is contingent upon regulatory approvals and the execution of
the contracts is expected for the second quarter of 2019.
9.8
9.8
1,844.1
On April 1, 2019, we secured 4,000 bopd through a zero-premium three-way
454.6
structure, with a minimum average price of US$45-US$55 per barrel and a
maximum average price of US$79 per barrel, for the period commencing
1,853.9
April 2019 to March 2020.
464.4
(1) Developed acreage is defined as acreage assignable to productive wells.
Undeveloped acreage is defined as acreage on which wells have not
Marketing and delivery commitments
Colombia
Our production in Colombia consists primarily of crude oil. Sales for the year
been drilled or completed to a point that would permit the production
ended December 31, 2018 were made under a long term sales agreement with
of commercial quantities of oil or gas regardless of whether such acreage
Trafigura.
contains proved reserves. Net acreage based on our working interest.
Productive wells
During 2018, our oil sales were done at wellhead with the delivery point at
the truck-loading station at each field. In Colombia, pipelines have minimum
The following table sets forth our total gross and net productive wells as of
quality conditions for access to the system. Consequently, and because we are
February 28, 2019. Productive wells consist of producing wells and wells capable
mid to heavy oil producers, loading to the pipeline system requires the use of
of producing, including natural gas wells awaiting pipeline connections to
diluents which are blended into our crude. Under the Trafigura Agreement,
commence deliveries and oil wells awaiting connection to production facilities.
we followed agreed priorities for the volumes to be transported through the
Gross wells are the total number of producing wells in which we have an
ODL Pipeline. For the period from January 1, 2018 to December 31, 2018,
interest, and net wells are the sum of our fractional working interests owned in
Trafigura bought 100% of our production. In 2018, we amended the Trafigura
gross wells.
Agreement to include a fixed volume oil sale of 8,000 bopd to Trafigura from
Productive wells (1)
January to December 2019.
Colombia
Chile
Brazil
Peru
Argentina
and Vasconia differential) and discounts that consider transportation costs and
Our oil sales price formula is based on market reference indices (Brent price
Oil wells
Gross
Net
Gas wells
Gross
Net
quality adjustments.
117.0
66.4
2.0
0.3
47.0
44.0
50.0
49.0
-
-
6.0
0.6
-
-
-
-
167.0
166.5
30.0
30.0
With the expiration of the obligation to sell all of our Colombian production to
Trafigura, we have started diversifying our client base in Colombia, allocating
sales on a competitive basis to leading industry participants, including traders
and other producers.
(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
Our sales strategy is aimed at securing the highest available pricing for our
production while securing a reliable and safe execution. To that end, we focus
an exploratory, development, or extension well that is not a dry well.
on developing synergies and strategic partnerships with both clients and
Present activities
the national transport systems, in order to obtain a reduction in costs and
increased revenues by making use of the best alternatives available. Such
Our average oil and gas production in the first quarter of 2019 was 39,558
is the case of the implementation of an unloading facility at Jaguey Station
mboepd, with oil production of 34,358 mbopd and gas production of 5,200
in partnership with Oleoducto de Los Llanos (ODL) in 2015. This unloading
90 GeoPark 20F
facility is located 42 km away from the Llanos 34 block and allowed for
If we were to lose any one of our key customers in Chile, the loss could
reduced trucking distance and associated costs. Additionally, during 2018 we
temporarily delay production and sale of our oil and gas in Chile. For a
developed a project to connect the Llanos 34 field to the ODL pipeline via a
discussion of the risks associated with the loss of key customers, See “Item
flowline, which will be operational by the second quarter of 2019, allowing
3. Key Information—D. Risk factors—Risks relating to our business—We sell
further cost efficiencies and increased operational reliability.
almost all of our natural gas in Chile to a single customer, who has in the past
temporarily idled its principal facility” and “—We derive a significant portion of
If we were to lose any of our customers, the loss could temporarily delay
our revenues from sales to a few key customers.”
production and sale of our oil in the corresponding block. However, given
the wide availability of customers for Colombian crude, we believe we could
Brazil
identify a substitute customer to purchase the impacted production volumes.
Our production in Brazil consists of natural gas and condensate oil. Natural gas
Chile
production is sold through a long-term, extendable agreement with Petrobras,
which provides for the delivery and transportation of the gas produced in the
Our customer base in Chile is limited in number and primarily consists of ENAP
Manati Field to the EVF gas treatment plant in the State of Bahia. The contract
and Methanex. For the year ended December 31, 2018 we sold 100% of our oil
is in effect until delivery of the maximum committed volume or June 2030,
production in Chile to ENAP and 99% of our gas production to Methanex, with
whichever occurs first. The contract allows for sales above the maximum
sales to ENAP and Methanex accounting for 3% and 3%, respectively, of our
committed volume if mutually agreed by both seller and buyer. The price
total revenues in the same period.
for the gas is fixed in reais and is adjusted annually in accordance with the
Brazilian inflation index. In July 2015, we signed an amendment to the existing
On April 21, 2017, we renewed our sales agreement with ENAP. As part of this
Gas Sales Agreement with Petrobras that covers 100% of the remaining gas
agreement, ENAP has committed to purchase our oil production in the Fell
reserves in the Manati Field.
Block in the amounts that we produce, subject to the limitation of available
storage capacity at the Gregorio Terminal. The sales agreement provides us
The Manati Field is developed via a PMNT-1 production platform, which is
with the option to interrupt sales to ENAP periodically if conditions in the
connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant
export markets allow for more competitive price levels. While the agreement
through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd
renews automatically on an annual basis, we typically revise the agreement
(9.5 mm3 per day). The existing pipeline connects the field’s platform to the
every year to reflect changes in the global oil market and make certain
EVF gas treatment plant, which is owned by the field’s current concession
adjustments based on ENAP’s expenses related to storage at the Gregorio
holders. During 2015, in order to improve the field gas recovery and
Terminal.
production, Manatì’s consortium built an onshore compression plant that
started operating in August 2015, which allowed us to classify all existing
General commercial conditions of our contract with ENAP have remained
proved undeveloped reserves as proved developed as of December 31, 2016.
stable over time. We deliver the oil we produce in the Fell Block to ENAP at the
The BCAM-40 Concession, which includes the Manati Field, also benefits from
Gregorio Terminal, where ENAP assumes responsibility for the oil transferred.
the advantages of Petrobras’ size. As the largest onshore and offshore operator
ENAP owns two refineries in Chile in the north central part of the country and
in Brazil, Petrobras has the ability to mobilize the resources necessary to
must ship any oil from the Gregorio Terminal to these refineries unless it is
support its activities in the concession.
consumed locally.
In March 2017, we executed a new gas supply agreement with Methanex
purchase agreement with Petrobras, pursuant to which Petrobras has
effective from May 1, 2017 to December 31, 2026. Under the agreement,
committed to purchase all of our condensate production in the Manati Field,
Methanex commits to purchase up to 400,000 SCM/d of gas produced by us.
but only in the amounts that we produce, without any minimum or maximum
In 2018, due to the decline in gas production, the commitment was reduced
deliverable commitment from us. The agreement is valid through December
to 315,000 SCM/d. We also hold an option to deliver up to 15% above this
31, 2019, and can be renewed upon an amendment signed by Petrobras and
volume.
the seller.
The condensate produced in the Manati Field is subject to a condensate
We gather the gas we produce in several wells through our own flow lines
Peru
and inject it into several gas pipelines owned by ENAP. The transportation of
In Peru, oil production is generally traded on a free market basis and
the gas we sell to Methanex through these pipelines is pursuant to a private
commercial conditions generally follow international markers, normally WTI
contract between Methanex and ENAP. We do not own any natural gas
and Brent. As per the Joint Operating Agreement executed with Petroperu,
pipelines for the transportation of natural gas.
Petroperu has the first option to acquire oil produced by us in the Morona
Block by matching any offer received by third parties regarding such
production.
GeoPark 91
Future production in the Morona Block is expected to be transported through
to pay a royalty to the Colombian government based on our production
the existing North Peruvian Pipeline to be sold to the domestic or export
of hydrocarbons, as of the time a field begins to produce. Under Law 756
markets at the Bayovar port. The North Peruvian Pipeline and the Bayovar
of 2002, as modified by Law 1530 of 2012, the royalties we must pay in
port are owned and operated by Petroperu, and regulated and supervised by
connection with our production of light and medium oil are calculated on a
Osinergmin, the regulatory body in the hydrocarbons sector. Transportation
field-by-field basis. See Note 32.1 to our Consolidated Financial Statements.
rates are negotiated with Petroperu. However, if an agreement cannot be
reached between Petroperu and us, transportation rates will be determined
Additionally, in the event that an exploitation area has produced amounts in
by Osinergmin. The North Peruvian pipeline transported an average of 22,000
excess of an aggregate amount established in the E&P Contract governing
bopd in the first 9 months of 2018. On November 27, 2018, crude shipments
such area, the ANH is entitled to receive a “windfall profit,” to be paid
on the North Line of the North Peruvian Pipeline were interrupted due to a
periodically, calculated pursuant to such E&P Contract.
blockage by a local community which resulted in a spill. In February 27, 2019,
the Peruvian government reached an agreement with the local community
In each of the exploration and exploitation periods, we are also obligated
that allowed the repairs to be made and the pipeline to restart operations in
to pay the ANH a subsoil use fee. During the exploration period, this fee is
March 2019. See “Item 3. Risk factors—Risks relating to our business—Our
scaled depending on the contracted acreage. During the exploitation period,
inability to access needed equipment and infrastructure in a timely manner
the fee is assessed on the amount of hydrocarbons produced, multiplied by
may hinder our access to oil and natural gas markets and generate significant
a specified dollar amount per barrel of oil produced or thousand cubic feet
incremental costs or delays in our oil and natural gas production.”
of gas produced. Further, the ANH has the right to receive an additional fee
when prices for oil or gas, as the case may be, exceed the prices set forth in
Argentina
the relevant E&P Contract.
All the gas produced in Argentina is sold to Grupo Albanesi, a leading
Argentine privately held conglomerate focused on the energy market that
Our E&P Contracts are generally subject to early termination for a breach
offers natural gas and power supply and transport services to its customers.
by the parties, a default declaration, application of any of the contract’s
We have an annual agreement in effect from May 2018 through April 2019.
unilateral termination clauses or termination clauses mandated by
According to local practices, this agreement contains seasonal prices, splitting
Colombian law. Anticipated termination declared by the ANH results in
between winter and summer prices.
the immediate enforcement of monetary guaranties against us and may
result in an action for damages by the ANH. Pursuant to Colombian law, if
Our oil sales in Argentina are diversified across clients and delivery points. 30%
certain conditions are met, the anticipated termination declared by the ANH
of our production in Argentina (2% of consolidated revenues) is sold locally in
may also result in a restriction on the ability to engage contracts with the
the Neuquén Province and delivered at well-head. The remaining 70% (3% of
Colombian government during a certain period of time. See “Item 3. Key
consolidated revenues) is sold to major refineries in Argentina and delivered
Information—D. Risk factors—Risks relating to our business—Our contracts
through pipeline. As usual in the local market, the sales agreements are
in obtaining rights to explore and develop oil and natural gas reserves
executed for short-term renewable periods from one to three months.
are subject to contractual expiration dates and operating conditions, and
Significant Agreements
Colombia
E&P Contracts
our CEOPs, E&P Contracts and concession agreements are subject to early
termination in certain circumstances.”
Llanos 34 Block E&P Contract. Pursuant to an E&P Contract between Unión
We have entered into E&P Contracts granting us the right to explore and
Temporal Llanos 34 (a consortium between Ramshorn and Winchester Oil
operate, as well as working interests in six blocks in Colombia. These E&P
and Gas - now GeoPark Colombia SAS) and the ANH that became effective as
Contracts are generally divided into two periods: (1) the exploration period,
of March 13, 2009 (“Llanos 34 Block E&P Contract”), Unión Temporal Llanos
which may be subdivided into various exploration phases and (2) the
34 was granted the right to explore and operate the Llanos 34 Block, and we
exploitation period, determined on a per-area basis and beginning on the
and Ramshorn were granted a 40% and a 60% working interest, respectively,
date we declare an area to be commercially viable. Commercial viability
in the Llanos 34 Block. We were also granted the right to operate the Llanos
is determined upon the completion of a specified evaluation program
34 Block. On December 16, 2009, Winchester Oil and Gas (now GeoPark
or as otherwise agreed by the parties to the relevant E&P Contract. The
Colombia) entered into a joint operating agreement with Ramshorn and
exploitation period for an area may be extended until such time as such area
P1 Energy with respect to our operations in the block. As of the date of this
is no longer commercially viable and certain other conditions are met.
annual report, the members of the Union Temporal Llanos 34 are GeoPark
Colombia SAS with 45%, and Parex Verano Limited with 55% working
Pursuant to our E&P Contracts, we are required, as are all oil and gas
interest.
companies undertaking exploratory and production activities in Colombia,
92 GeoPark 20F
We are currently in an additional exploration period (the contract provides
two phases: (1) an exploration phase, which is divided into two or more
for two optional exploratory phases of 18 months each, in which the
exploration periods, and which begins on the effectiveness date of the
operator carries out exploratory activities in order to retain areas to
relevant CEOP, and (2) an exploitation phase, which is determined on a per-
explore) of the Llanos 34 Block E&P Contract with an exploitation program
field basis, commencing on the date we declare a field to be commercially
in execution over certain areas. The contract also provides for a six-year
viable and ending with the term of the relevant CEOP. In order to transition
exploration period consisting of two three-year phases. It also provides for a
from the exploration phase to an exploitation phase, we must declare a
24-year exploitation period for each commercial area, which begins on the
discovery of hydrocarbons to the Ministry of Energy. This is a unilateral
date on which such area is declared commercially viable. The exploitation
declaration, which grants us the right to test a field for a limited period of
period may be extended for periods of up to 10 years at a time until such
time for commercial viability. If the field proves commercially viable, we
time as the area is no longer commercially viable and certain conditions are
must make a further unilateral declaration to the Ministry of Energy. In the
met. We have presented evaluation programs to the ANH for the Tilo Field.
exploration phase, we are obligated to fulfill a minimum work commitment,
We presented the declaration of commerciality of Max, Túa, Tarotaro, Tigana,
which generally includes the drilling of wells, the performance of 2D or 3D
Jacana and Chachalaca, respectively.
seismic surveys, minimum capital commitments and guaranties or letters
of credit, as set forth in the relevant CEOP. We also have relinquishment
Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are
obligations at the end of each period in the exploration phase in respect
required to pay a royalty to the ANH based on hydrocarbons produced in the
of those areas in which we have not made a declaration of discovery.
Llanos 34 Block. See Note 32.1 to our Consolidated Financial Statements.
We can also voluntarily relinquish areas in which we have not declared
Additionally, we are required to pay a subsoil use fee to the ANH. ANH
phase, we generally do not face formal work commitments, other than the
also has the right to receive an additional fee when prices for oil or gas,
development plans we file with the Chilean Ministry of Energy for each field
as the case may be, exceed the prices set forth in the Llanos 34 Block E&P
declared to be commercially viable.
discoveries of hydrocarbons at any time, at no cost to us. In the exploitation
Contract. The ANH also has an additional economic right equivalent to 1% of
production, net of royalties.
Our CEOPs provide us with the right to receive a monthly remuneration
from Chile, payable in petroleum and gas, based either on the amount of
In accordance with the Llanos 34 Block operation contract, when the
petroleum and gas production per field or according to Recovery Factor,
accumulated production of each field, including the royalties’ volume,
which considers the ratio of hydrocarbon sales to total cost of production
exceeds 5 million barrels and the WTI exceeds a defined base price, the
(capital expenditures plus operating expenses). Pursuant to Chilean law,
Company should deliver to ANH a share of the production net of royalties in
the rights contained in a CEOP cannot be modified without consent of the
accordance with an established formula. See Note 32.1 to our Consolidated
parties.
Financial Statements.
Our CEOPs are subject to early termination in certain circumstances, which
Winchester and Luna Stock Purchase Agreement
vary depending upon the phase of the CEOP. During the exploration
Pursuant to the stock purchase agreement entered into on February 10, 2012
phase, Chile may terminate a CEOP in circumstances including a failure
(the “Winchester Stock Purchase Agreement”), we agreed to pay the Sellers a
by us to comply with minimum work commitments at the termination
total consideration of US$30.0 million, adjusted for working capital. Additionally,
of any exploration period, or a failure to communicate our intention to
under the terms of the Winchester Stock Purchase Agreement, we are obligated
proceed with the next exploration period 30 days prior to its termination,
to make certain payments to the Sellers based on the production and sale of
a failure to provide the Chilean Ministry of Energy the performance bonds
hydrocarbons discovered by exploration wells drilled after October 25, 2011.
required under the CEOP, a voluntary relinquishment by us of all areas
Once the maximum earn-out amount is reached, we pay the Sellers quarterly
under the CEOP or a failure by us to meet the requirements to enter into
overriding royalties in an amount equal to 4% of our net revenues from any new
the exploitation phase upon the termination of the exploration phase. In
discoveries of oil. For the year ended December 31, 2018, we accrued and paid
the exploitation phase, Chile may terminate a CEOP if we stop performing
US$20.6million and US$19.1 million with regards to this agreement.
any of the substantial obligations assumed under the CEOP without
Chile
CEOPs
cause and do not cure such nonperformance pursuant to the terms of
the concession, following notice of breach from the Chilean Ministry of
Energy. Additionally, Chile may terminate the CEOP due to force majeure
Currently, we have five CEOPs in effect with Chile, one for each of the
circumstances (as defined in the relevant CEOP). If Chile terminates a CEOP
blocks in which we operate, which grant us the right to explore and exploit
in the exploitation phase, we must transfer to Chile, free of charge, any
hydrocarbons in these blocks, determine our working interests in the
productive wells and related facilities, provided that such transfer does not
blocks and appoint the operator of the blocks. These CEOPs are divided into
interfere with our abandonment obligations and excluding certain pipelines
GeoPark 93
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
Neuquén Exploitation Concessions. After receiving authorization in March 27,
are subject to contractual expiration dates and operating conditions, and
2018 from the Province of Neuquén under Provincial Decree 266/2018, we
our CEOPs, E&P Contracts and concession agreements are subject to early
closed the acquisition of a 100% interest in the Aguada Baguales, El Porvenir
termination in certain circumstances.”
and Puesto Touquet hydrocarbon exploitation concessions from Pluspetrol
S.A., together with an ancillary transportation concession over a natural gas
Fell Block CEOP . On November 5, 2002, we acquired a percentage of rights and
pipeline from Puesto Touquet to Plaza Huincul, all in the Neuquén Basin in
interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and
Argentina. These concessions had been originally granted to Pluspetrol S.A.
on May 10, 2006, we became the sole owners, with 100% of the rights and
for a term of 25 years in 1990 (Aguada Baguales and El Porvenir Blocks) and
interest in the Fell Block CEOP. Chile had originally entered into a CEOP for the
1992 (Puesto Touquet Block). In 2008, the Province of Neuquén granted a
Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April 29, 1997,
ten year extension of these concessions in consideration of an investment
which had an effective date of August 25, 1997. The Fell Block CEOP grants us
program which included development, exploration and environmental
the exclusive right to explore and exploit hydrocarbons in the Fell Block and
remediation programs and a payment of a cash bonus in proportion to the
has a term of 35 years, beginning on the effective date. The Fell Block CEOP
in-situ hydrocarbon reserves of the blocks. At least one year prior to the end
provided for a 14-year exploration period, composed of numerous phases that
of the current ten year extension period, we are entitled to request a further
ended in 2011, and an up-to-35-year exploitation phase for each field.
ten year extension to these concessions in consideration for continued
The Fell Block CEOP provides us with a right to receive a monthly retribution
royalty) and a cash bonus equal to 2% of the then existing in-situ reserves.
investments, an incremental 3% royalty (resulting in an aggregate 18%
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
Under these concessions, we are entitled to the exclusive right to develop
5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for
the entire acreage of the concessions, produce, freely dispose and market all
production of up to 882.9 mmcfpd. In the event that we exceed these levels
hydrocarbons we lift under a royalty tax system.
of production, our monthly retribution from Chile will decrease based on a
sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the
LGI Termination Agreement
oil and 60% of the gas that we produce per field.
Pursuant to the sale and purchase agreement entered into on November
28, 2018 (the “LGI Termination Agreement”), we agreed to pay LGI a total
TDF Blocks CEOPs . After an international bidding process led by ENAP and
consideration of up to US$126 million for its entire equity interest in Geopark
the Chilean Ministry of Energy, in March and April, 2012, we, together with
Chile, Geopark TdF and Geopark Colombia Coöperatie U.A. The acquisition
ENAP, signed 3 new CEOPs for the Isla Norte, Campanario and Flamenco
price includes a fixed payment of US$81 million paid at closing, plus two
Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes region.
equal installments of US$15 million each, to be paid in June 2019 and June
Our working interest is 60% in Isla Norte and 50% in Campanario and
2020, respectively, and three contingent payments of US$5 million each,
Flamenco Blocks. The CEOPs have a term of 32 years, with an initial
which could accrue over the next three years, subject to certain production
exploration phase which last for 7 years, including a first exploration period
thresholds being exceeded in the Llanos 34 Block. As a consequence of the
of 3 years in which we are committed to developing several exploration
LGI Termination Agreement we have become sole shareholder of the entities
activities including 1,500 square kilometers of 3D seismic registration, and
referred to above. See “Item 7. Major Shareholders and Related Parties—B.
the drilling of 21 exploratory wells.
Related Party Transactions—LGI Termination Agreement.”
The hydrocarbon discoveries opened up an exploitation phase that lasts
Brazil
up to 32 years. We discovered hydrocarbon fields in the 3 blocks, starting in
Overview of concession agreements
2013 in the Flamenco Block, and in 2014 in both Campanario and Isla Norte
The Brazilian oil and gas industry is governed mainly by the Brazilian
Blocks. The CEOPs provide us with a right to receive a remuneration payable
Petroleum Law, which provides for the granting of concessions to operate
by means of a fraction of the production sold, which in the TDF Blocks is
petroleum and gas fields in Brazil, subject to oversight by the ANP. A
based on a formula depending on the recovery of the total accumulated
concession agreement is divided into two phases: (1) exploration and (2)
expenses incurred (capital expenditure plus operational expenditure plus
development and production. The exploration phase, which is further divided
administrative and general expenses). While the recovery factor is less than
into two subsequent exploratory periods, the first of which begins on the date
1.0, the remuneration is 95% of the hydrocarbons produced, either oil or gas.
of execution of the concession agreement, can last from three to eight years
If the recovery factor surpasses 1.0, a formula applies reducing gradually the
(subject to earlier termination upon the total return of the concession area
94 GeoPark 20F
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 must
concession is subject to the discretion of the ANP.
pay in the event of obtaining high production volumes and/or profitability
from oil fields, according to criteria established by applicable regulations, and is
The main terms and conditions of a concession agreement are set forth
payable on a quarterly basis for each field from the date on which extraordinary
in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of
production occurs. This participation fee, whenever due, varies between 0%
the concession area; (2) validity and terms for exploration and production
and 40% of net revenues depending on (1) the volume of production and (2)
activities; (3) conditions for the return of concession areas; (4) guarantees to
whether the concession is onshore or in shallow water or deep water. Under
be provided by the concessionaire to ensure compliance with the concession
the Brazilian Petroleum Law and applicable regulations issued by the ANP, the
agreement, including required investments during each phase; (5) penalties
special participation fee is calculated based on the quarterly net revenues of
in the event of noncompliance with the terms of the concession agreement;
each field, which consist of gross revenues calculated using reference prices
(6) procedures related to the assignment of the agreement; and (7) rules for
established by the ANP (reflecting international prices and the exchange rate for
the return and vacancy of areas, including removal of equipment and facilities
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
minimum exploration program proposed in the winning bid; (4) activities for
royalty payment equal to 7.5% of the production of oil and natural gas in the
the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments
concession area. In addition, in case the special participation fee of 10% shall
for government participation; and (7) responsibility for the costs associated
be applicable for a field in any quarter of the calendar year, the concessionaire
with the deactivation and abandonment of the facilities in accordance with
is obliged to make qualified research and development investments equivalent
Brazilian law and best practices in the oil industry.
to one percent of the field’s gross revenue. Area retention payments are also
applicable under the concession agreement. We acquired Rio das Contas’ 10%
A concessionaire is required to pay to the Brazilian government the following:
participation interest in the BCAM-40 Concession on March 31, 2014.
• a license fee;
• rent for the occupation or retention of areas;
GeoPark 95
Rounds 11, 12, 13 and 14 Concession Agreements.
is valid until the earlier of Petrobras’ receipt of this total contractual quantity
Under the Rounds 11, 12, 13 and 14 Concession Agreements, the ANP is
or June 30, 2030. The agreement may not be fully or partially assigned except
entitled to a monthly royalty corresponding to up to 10% of the production
upon execution of an assignment agreement with the written consent of the
of oil and natural gas in the concession area, in addition to the special
other parties, which consent may not be unreasonably withheld provided that
participation fee described above, the payment for the occupation of the
certain prerequisites have been met.
concession area of approximately R$7,600 per year and the payment to the
owners of the land of the concession equivalent to one percent of the oil and
The agreement provides for the provision of “daily contractual quantities” to
natural gas produced in the concession area.
Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until
2030. The parties may agree to lower volumes as dictated by Manati Field’s
During bidding, a work program offer is made in the form of work units and
depletion. Pursuant to the agreement, the base price is denominated in reais
the ANP asks for a guarantee of a monetary amount proportional to the
and is adjusted annually for inflation pursuant to the general index of market
offered units. However, depending on the work performed by the operator,
prices (IGPM). Additionally, the gas price applicable on a given day is subject
the actual work program investment might have a different value to the
to reduction as a result of the gas quantity acquired by Petrobras above the
guaranteed value.
volume of the annual TOP commitment (85% of the daily contracted quantity)
in effect on such day. The Petrobras Natural Gas Purchase Agreement provides
Overview of consortium agreements
that all of the Manati Field’s daily production be sold to Petrobras.
A consortium agreement is a standard document describing consortium
members’ respective percentages of participation and appointment of
Peru
the operator. It generally provides for joint execution of oil and natural
Morona Block
gas exploration, development and production activities in each of the
On October 1, 2014, we entered into an agreement with Petroperu to acquire
concession areas. These agreements set forth the allocation of expenses for
an interest in and operate the Morona Block, located in Northern Peru. We will
each of the parties with respect to their respective participation interests
assume a 75% working interest of the Morona Block, with Petroperu retaining
in the concession. The agreements are supplemented by joint operating
a 25% working interest. On December 1, 2016, through Supreme Decree N°
agreements, which are private instruments that typically regulate the
031-2016-MEN the Peruvian government approved the amendment to the
aggregation of funds, the sharing of costs, mitigation of operational risks,
License Contract of Block 64 (Morona Block) appointing GeoPark as operator
preemptive rights and the operator’s activities.
and holder of 75% of the Contract.
An important characteristic of the consortia for exploration and production
In Peru, there is a 5-20% sliding scale royalty rate, depending on production
of oil and natural gas that differs from other consortia (Article 278, paragraph
levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For
1, of the Brazilian Corporate Law) is the joint liability among consortium
production between 5,000 and 100,000 bopd there is a linear sliding scale
members as established in the Brazilian Petroleum Law (Article 38, item II).
between 5% and 20%. Production over 100,000 bopd has a flat royalty of 20%.
BCAM-40 Consortium Agreement
See “Item 4. Information on the Company—B. Business Overview—Our
On January 14, 2000, Petrobras, Enauta and Petroserv entered into a
operations—Operations in Peru—Morona Block.”
consortium agreement, or the BCAM-40 Consortium Agreement, for the
performance of the BCAM-40 Concession Agreement. Petrobras is the
Argentina
operator of the BCAM-40 concession, with a 35% participation interest.
Overview of exploration permits
Enauta, Brasoil and Rio das Contas have a 45%, 10% and 10% participation
Our exploration permits grant to us and our partners the exclusive right to
interest, respectively. The BCAM-40 Consortium Agreement has a specified
explore for hydrocarbons and declare a commercial discovery within the acreage
term of 40 years, terminating on January 14, 2040 and, at the time the
of our permits. Our exploration permits are made up of three subperiods, each
obligations undertaken in the agreement are fully completed, the parties
lasting 3, 2 and 1 year(s), respectively, plus an extension period of up to 5 years.
will have the right to terminate it. The BCAM-40 Concession consortium has
also entered into a joint operating agreement, which sets out the rights and
We are bound to pursue specific minimum work or investment commitments
obligations of the parties in respect of the operations in the concession.
during each of the subperiods of each exploration permit. Such exploration
Petrobras Natural Gas Purchase Agreement
works are valued in work units assigned to each particular type of work under
Enauta, GeoPark Brasil, Brasoil and Petrobras are party to a natural gas
the applicable bidding conditions.
purchase agreement providing for the sale of natural gas by Enauta, GeoPark
Work and investment programs for the permits are required to be assured by
Brasil and Brasoil to Petrobras, in an amount of 812 billion cubic feet (“bcf”)
issuing a performance bond for the value of the committed work plan.
over the term of agreement. The Petrobras Natural Gas Purchase Agreement
96 GeoPark 20F
Under the terms of our exploration permits and concession agreements, we are
Title to properties
entitled to our proportionate share of the hydrocarbons production lifted from
In each of the countries in which we operate, the state is the exclusive owner
each block. The Province of Mendoza’s state owned company, EMESA, has a 10%
of all hydrocarbon resources located in such country and has full authority
carried interest in each of the Puelen and Sierra del Nevado permits and any
to determine the rights, royalties or compensation to be paid by private
future exploitation concessions, while there is no governmental participation
investors for the exploration or production of any hydrocarbon reserves. In
in the CN-V Block. During the term of our exploration permits, we are also
Chile, the Republic of Chile grants such rights through a CEOP. In Colombia,
required, under Argentine law, to pay a 15% royalty to the province on both oil
the Republic of Colombia grants such rights through E&P Contracts or
and gas sales. In case we progress to an exploitation concession, the applicable
contracts of association. In Argentina, the Argentine Republic grants such
royalty rate will reduce to a 12% royalty. We also pay annual surface rental
rights through exploitation concessions. In Brazil, the Federative Republic
fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and
of Brazil grants such rights pursuant to concession agreements. See “Item 3.
Resolution 588/98 of the Argentine Secretariat of Energy and Decree 1454/2007,
Key Information—D. Risk factors—Risks relating to the countries in which
and certain landowner fees.
we operate—Oil and natural gas companies in Colombia, Chile, Brazil,
Argentina and Peru do not own any of the oil and natural gas reserves in
Our Argentine exploration permits have no change of control provisions, though
such countries.” Other than as specified in this annual report, we believe that
any assignment of these concessions is subject to the prior authorization by the
we have satisfactory rights to exploit or benefit economically from the oil
executive branch of the Province of Mendoza and rights of first refusal in favor
and gas reserves in the blocks in which we have an interest in accordance
of our partners and EMESA, in the case of the Puelen and Sierra del Nevado
with standards generally accepted in the international oil and gas industry.
permits. Each of these permits or future concessions can be terminated for
Our CEOPs, E&P Contracts, contracts of association, exploitation concessions
default in payment obligations and/or breach of material statutory or regulatory
and concession agreements are subject to customary royalty and other
obligations. We are subject to the obligation to relinquish at least 50% of the
interests, liens under operating agreements and other burdens, restrictions
acreage of each exploration permit at the end of each exploration subperiod. We
and encumbrances customary in the oil and gas industry that we believe
may also voluntarily relinquish acreage to the provincial authorities.
do not materially interfere with the use of or affect the carrying value of our
Our Argentine exploration permits are governed by the laws of Argentina and
our business—We are not, and may not be in the future, the sole owner or
the resolution of any disputes must be sought in the Mendoza Provincial Courts.
operator of all of our licensed areas and do not, and may not in the future,
interests. See “Item 3. Key Information—D. Risk factors—Risks relating to
If and when we make a commercial discovery in one or more of our exploration
may not be able to control the timing of exploration or development efforts,
permits, we will have the right to request and obtain an exploitation concession
associated costs, or the rate of production of any non-operated and, to an
to produce hydrocarbons in the block for 25 years, with an optional extension
extent, any non-wholly-owned, assets.”
hold all of the working interests in certain of our licensed areas. Therefore, we
of up to 10 years. We also receive the right to be granted a 35-year oil transport
concession to build and make use of pipelines or other transport facilities
Our customers
beyond the boundaries of the concession.
In Colombia, our primary customer is Trafigura, and who represented 82% of
our total revenues for the year ended December 31, 2018. In Chile, our primary
Additionally, oil and gas producers in Argentina must grant a privilege to the
customers are ENAP and Methanex. As of December 31, 2018, ENAP purchased
domestic market to the detriment of the export market, including hydrocarbon
all of our Chilean oil and condensate production and Methanex purchased
export restrictions, domestic price controls, export duties and domestic market
almost all of our natural gas production in Chile, and represented 3% and 3%,
supplier obligations.
Pluspetrol Asset Purchase Agreement
respectively, of our total revenues for the year ended December 31, 2018. In
Brazil, all of our hydrocarbons in Manati are sold to Petrobras. In Argentina, all
Pursuant to the APA that we entered into on December 18, 2017 with
the gas produced is sold to Grupo Albanesi and represented 1% of our total
Pluspetrol, we agreed to acquire a 100% working interest and operatorship
revenues. Our oil production in Argentina is split between local buyers in the
of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina
Neuquén Province, delivered at well-head (2% of consolidated revenues) and
for a total consideration of $52 million. The blocks include estimated oil and
major refineries, delivered through pipeline (3% of consolidated revenues). In
gas production of 2,700 boepd (70% light oil and 30% gas), 137,000 acres
Peru, our primary customers are local refineries (Petroperu or Repsol) or the
well-positioned in the Neuquén Basin and production facilities, including
export market. Petroperu, has the first option to acquire the oil produced by us
hydrocarbons treatment, storage, and delivery infrastructure.
in the Morona Block by matching any offer received by third parties regarding
We paid the consideration using proceeds from the offering of the Notes due
2024. The acquisition of the blocks closed on March 27, 2018.
Seasonality
such production.
Although there is some historical seasonality to the prices that we receive
GeoPark 97
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
•
limit or prohibit seismic and drilling activities in certain locations lying
within or near protected or environmentally sensitive areas;
The oil and gas industry is competitive, and we may encounter strong
• require preventative measures to mitigate pollution from our operations,
competition from other independent operators and from major state-owned
which, if not undertaken, could subject us to substantial penalties; and
oil companies in acquiring and developing licenses in the countries where we
• require us to maintain a safe and healthy working environment for all
operate or plan to operate.
employees, contractors and visitors in accordance with applicable regulations
and industry best practices.
Many of these competitors have financial and technical resources and
personnel substantially larger than ours. As a result, our competitors may be
These laws and regulations may also restrict the rate of oil and natural gas
able to pay more for desirable oil and natural gas assets, or to evaluate, bid
production below the rate that would otherwise be possible. Compliance
for and purchase a greater number of licenses than our financial or personnel
with these laws can be costly. The regulatory burden on the oil and
resources will permit. Furthermore, these companies may also be better able
gas industry increases the cost of doing business in the industry and
to withstand the financial pressures of unsuccessful wells, sustained periods of
consequently affects profitability.
volatility in financial and commodities markets and generally adverse global
and industry-wide economic conditions, and may be better able to absorb the
Public interest in the protection of the environment continues to increase.
burdens resulting from changes in relevant laws and regulations, which may
Drilling in some areas has been opposed by certain community and
adversely affect our competitive position. See “Item 3. Key Information—D.
environmental groups and, in other areas, has been restricted.
Risk factors—Risks relating to our business—Competition in the oil and
natural gas industry is intense, which makes it difficult for us to attract capital,
Climate change
acquire properties and prospects, market oil and natural gas and secure
Both our operations and the combustion of oil and natural gas-based
trained personnel.”
products results in the emission of greenhouse gases, which may contribute
to global climate change. Climate change regulation has gained momentum
We may also be affected by competition for drilling rigs and the availability
in recent years internationally and at the federal, regional, state and local
of related equipment. Higher commodity prices generally increase the
levels. On the international level, various nations have committed to reducing
demand for drilling rigs, supplies, services, equipment and crews, and can
their greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto
lead to shortages of, and increasing costs for, drilling equipment, services and
Protocol was set to expire in 2012. In late 2011, an international climate
personnel. Shortages of, or increasing costs for, experienced drilling crews and
change conference in Durban, South Africa resulted in, among other things,
equipment and services could restrict our ability to drill wells and conduct our
an agreement to negotiate a new climate change regime by 2015 that
operations.
would aim to cover all major greenhouse gas emitters worldwide, including
the U.S., and take effect by 2020. In November and December 2012, at an
Health, safety and environmental matters
international meeting held in Doha, Qatar, the Kyoto Protocol was extended
General
by amendment until 2020. In addition, the Durban agreement to develop
Our operations are subject to various stringent and complex international,
the protocol’s successor by 2015 and implement it by 2020 was reinforced.
federal, state and local environmental, health and safety laws and regulations
We are committed to controlling the emission of greenhouse gases and
in the countries in which we operate. These laws and regulations govern
implementing available technologies to reduce the impact caused by our
matters including the emission and discharge of pollutants into the ground,
operations. For example, during 2016 we began a migration plan to replace
air or water; the generation, storage, handling, use and transportation of
diesel with natural gas and electric generation.
98 GeoPark 20F
Our HSE Management System
purpose of conducting business outside Bermuda from a principal place
Our health, safety and environmental management plan is focused on
of business in Bermuda. As exempted companies, we and our Bermuda
undertaking realistic and practical programs based on recognized world
subsidiaries may not, without a license or consent granted by the Minister of
practices. Our emphasis is on building key principles and company-wide
Finance of Bermuda, participate in certain business transactions, including
ownership and then expanding programs as we continue growing. Our
transactions involving Bermuda landholding rights and the carrying on of
S.P.E.E.D. philosophy and our HSE Plan have been developed with reference to
business of any kind for which we or our Bermuda subsidiaries are not licensed
ISO 14001 for environmental management issues, ISO 45000 for occupational
in Bermuda.
health and safety management issues, SA 8000 for social accountability and
workers’ rights issues and applicable World Bank Standards.
Insurance
Our Environmental Policy
We maintain insurance coverage of types and amounts that we believe to
be customary and reasonable for companies of our size and with similar
Our policy looks forward to meet or exceed environmental regulations
operations in the oil and gas industry. However, as is customary in the
in the countries in which we operate. We believe that oil and gas can be
industry, we do not insure fully against all risks associated with our business,
produced in an environmentally-responsible manner with proper care,
either because such insurance is not available or because premium costs are
understanding and management. Within our S.P.E.E.D. philosophy we
considered prohibitive.
have a team that is exclusively focused on securing the environmental
authorizations and permits for the projects we undertake. This professional
Currently, our insurance program includes, among other things, construction,
and trained team, specialized in environmental issues, is also responsible
fire, vehicle, technical, umbrella liability, director’s and officer’s liability and
for the achievement of the environmental standards set by our Board
employer’s liability coverage. Our insurance includes various limits and
of Directors and for training and supporting our personnel. Our senior
deductibles or retentions, which must be met prior to or in conjunction with
executives, personnel in the field, visitors and contractors have also received
recovery. A loss not fully covered by insurance could have a materially adverse
training in proper environmental management.
effect on our business, financial condition and results of operations. See “Item
Our Health and Safety Policy
3. Key Information—D. Risk factors—Risks relating to our business—Oil and
gas operations contain a high degree of risk and we may not be fully insured
We continue looking for the best tools to manage our health and safety
against all risks we face in our business.”
policy. In 2018 we started the implementation of our program called SOS
(Safety Operational Standards) that contributes to building better practices
Industry and regulatory framework
to control and minimize risks in our daily operations. Since 2016 we have also
Colombia
implemented the Proactive Observation Program, HSE training, work permits,
Regulation of the oil and gas industry
internal audits, drills, pre-job meetings and job safety analysis, among others.
The ANH is responsible for managing all exploration lands not subject to
previously existing association contracts with Ecopetrol. The ANH began
As of December 31, 2018, on the last 12-month basis, our HSE development
offering all undeveloped and unlicensed exploration areas in the country
statistics workforce shows that Lost Time Injury Frequency (LTIF) was 0.42 (out
under E&P Contracts and Technical Evaluation Agreements, or TEAs, which
of every 1,000,000 worked hours), our Total Recordable Incident Rate (TRIR)
resulted in a significant increase in Colombian exploration activity and
was 1.25 (out of every 1,000,000 worked hours) and we had no fatal incidents
competition, according to the ANH. The ANH is also in charge of negotiating
related to operations in 2018.
and executing contracts through “direct negotiation” mechanisms with
In 2016, we subscribed to the International Association of Oil and Gas
attention to special conditions in the areas to be explored, however the
Producers in order to align our Management System and policies with the
ANH has not issued the regulation for such direct granting of contracts. The
best international standards.
Certain Bermuda law considerations
regulatory landscape in Colombia has recently changed. The regime for the
ANH’s contracts is set forth in Agreement 008 of 2004 and Agreement 004
of 2012. Accord 008 of 2004 issued by the Directive Council of the ANH, as
As a Bermuda exempted company, we and our Bermuda subsidiaries are
repealed and replaced by Accord 004 of 2012, sets forth the necessary steps
subject to regulation in Bermuda. We have been designated by the BMA as a
for entering into E&P Contracts with the ANH. This Agreement regulates E&P
non-resident for Bermuda exchange control purposes. This designation allows
contracts entered into from May 4, 2012. E&P contracts entered into before
us to engage in transactions in currencies other than the Bermuda dollar,
that date are still regulated by Agreement 008 of 2004. Due to the oil price
and there are no restrictions on our ability to transfer funds (other than funds
crisis of 2015, the ANH implemented transitory measures through Agreements
denominated in Bermuda dollars) in and out of Bermuda.
002, 003, 004 and 005 of 2015. On May 18, 2017, the ANH issued Agreement
Under Bermuda’s law, “exempted” companies are companies formed for the
measures adopted in 2014 and 2015. Agreement 002 of 2017 established
002, which repealed and replaced Agreement 004 of 2012 and transitory
GeoPark 99
rules for the allocation of hydrocarbon areas and adopted criteria for the
Pursuant to Colombian law, companies are obligated to pay royalties (a
exploration and exploitation of hydrocarbons owned by Colombia, including
percentage of their production) to the ANH in kind or in money as per ANH’s
the selection of contractors, and management, execution, termination,
instruction and pursuant to the E&P Contracts, companies must pay ANH an
liquidation, monitoring, control and supervision of corresponding contracts.
economic right called participating interest in the production, among other
Agreement 002 of 2017 regulates contracts entered into from May 18,
economic rights established in the E&P Contracts (i.e. high price provision,
2017. E&P contracts entered into before that date are still regulated by the
technology transfer, use of the subsurface). Producing fields pay royalties in
Agreements under which they were executed.
accordance with the applicable law at the time of the discovery.
Regulatory framework
Additionally, in February 2019 the ANH published the Terms of Reference for
Regulation of exploration and production activities
the Permanent Competitive Bidding Process in which initially 20 blocks will be
Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon
offered to interested qualified bidders.
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
main taxes currently in effect—after the December 2016 tax reform discussed
Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code,
below—are the income tax (40% for 2017, 37% for 2018 and 33% for 2019
establishes the general procedures and requirements that must be completed
onwards), sales or value added tax (19%), and the tax on financial transaction
by a private investor and disclosure procedures that need to be followed
(0.4%). Additional regional taxes also apply. Colombia has entered into a
during the performance of these activities.
number of international tax treaties to avoid double taxation and prevent tax
evasion in matters of income tax and net asset tax.
Exploration and production activities were governed by Decree 1895 of 1973
Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international
until September 2009. Decree Law 2310 of 1974 (as complemented by Decree
investment regime, regulates foreign capital investment in Colombia.
743 of 1975) governed the contracts and contracting processes carried out by
Resolution 8 of the board of the Colombian Central Bank, or the Exchange
Ecopetrol and the rules applicable to such contracts, and also provided that
Statute, and its amendments contain provisions governing exchange
Ecopetrol was responsible for administering the hydrocarbons resources in the
operations. Articles 48 to 52 of Resolution 8 provide for a special exchange
Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, but
regime for the oil industry that removes the obligation of repayment to the
all agreements entered into by us prior to 2003 with other oil companies are
foreign exchange market currency from foreign currency sales made by
still regulated by Decree 2310 of 1974.
foreign oil companies. Such companies may not acquire foreign currency
in the exchange market under any circumstances and must reinstate in the
Resolution 18-1495 of 2009, modified by Resolution 40048 of 2015, establishes
foreign exchange market the capital required in order to meet expenses in
a series of regulations regarding hydrocarbon exploration and exploitation.
Colombian legal currency. Companies can avoid participating in this special
In the E&P Contracts, operators are afforded access to blocks by committing
oil and gas exchange regime, however, by informing the Colombian Central
to an exploration work program. These E&P Contracts provide companies
Bank, in which case they will be subject to the general exchange regime of
with 100% of new production, less the participation of the ANH, which
Resolution 8 and may not be able to access the special exchange regime for a
participation may differ for each E&P Contract and depends on the percentage
period of 10 years.
that each company has offered to the ANH in order to be granted with a block,
subject to an initial royalty payment of 8% and the payment of income taxes
In December 2018, a new tax reform was enacted in Colombia. The legislation
of 33%. In addition, the Colombian government also introduced TEAs, in which
included significant changes in certain corporate income tax, statutory income
companies that enter into TEAs are the only ones to have the right to explore,
tax and legal provisions. This tax reform became effective on January 1, 2019.
evaluate and select desirable exploration areas by executing seismic and /or
drilling stratigraphic wells and to propose work commitments on those areas,
The legislation included the progressive reduction of the general corporate
and have a preemptive right to enter into an E&P Contract, thereby providing
income tax rate, previously set at 40% for 2017 and 37% for 2018, as follows:
companies with low-cost access to larger areas for preliminary evaluation prior
to committing to broader exploration programs. A preemptive right is granted
33% in 2019, 32% in 2020, 31% in 2021 and 30% in 2022 and onwards.
to convert the TEA into an E&P Contract. Exploration activities can only be
Other changes that affect the Group are the following:
carried out by the TEA contractor.
• The withholding tax rate on dividends for non-resident shareholders was
increased from 5% to 7.5%.
100 GeoPark 20F
• The withholding tax rates were increased from 15% to 20% for payments
1986 of the Ministry of Mines, which set forth the revised text of the Decree
to non-residents, related to consultancies, technical services, technical
Law 1089 of 1975, on CEOPS. However, the right to explore and develop
assistance, software and interest on loans of less than one year (for loans with
fields is granted for each area under a CEOP between Chile and the relevant
more than a year of maturity, the 15% rate remained unchanged).
contractors. The CEOP establishes the legal framework for hydrocarbon
• The withholding tax rate for payments to entities resident in non-cooperative
activities, including, among other things, minimum investment commitments,
countries, with no or low taxation, or subject to a preferential tax regime, was
exploration and exploitation phase durations, compensation for the private
increased from 15% to the corporate income tax rate (33 % for 2019, 32% for
company (either in cash or in kind) and the applicable tax regime. Accordingly,
2020, 31% for 2021 and 30% for 2022 and onwards).
all the provisions governing the exploitation and development of our Chilean
• The deduction of interest attributed to a permanent establishment in
operations are contained in our CEOPs and the CEOPs constitute all the
Colombia by its head office was limited to when they have been subject to
licenses that we need in order to own, operate, import and export any of
withholding tax.
the equipment used in our business and to conduct our gas and petroleum
• Regarding undercapitalization, the debt limit which interests can be
operations in Chile.
deducted, for income tax purposes, was reduced to two times the net equity
of the taxpayer as of December 31 of the previous year.
Under Chilean law, the surface landowners have no property rights over
• Transfers of participations in foreign entities that represent indirect disposals
the minerals found under the surface of their land. Subsurface rights do not
of assets in Colombia are subject to income tax or occasional earnings tax.
generate any surface rights, except the right to impose legal easements or
• VAT paid for acquisition of productive fixed assets can be discounted from
rights of way. Easements or rights of way can be individually negotiated with
the taxpayer’s income tax
individual surface land owners or can be granted without the consent of the
landowner through judicial process. Pursuant to the Chilean Code of Mines, a
An audit benefit was granted by the reform, establishing that tax returns for
judge can permit a party to use an easement pending final adjudication and
the 2019 and 2020 fiscal years showing a net income tax 30% or 20% higher,
settlement of compensation for the affected landowner.
respectively, than the one declared in the previous year would be considered
definitive 6 months or 12 months after they became due, also respectively, if
Taxation
there were no objections or requests from the tax authority.
With regard to indirect taxes on hydrocarbon exploitation, the general rule is
Chile
Regulation of the oil and gas industry
that hydrocarbons are transferred to the contractor (its retribution under the
CEOP), and those re-acquisitions from the contractor performed by Chile or
its enterprises, as well as their corresponding acts, contracts and documents,
Under the Chilean Constitution, the state is the exclusive owner of all mineral
are tax exempt. In addition, hydrocarbon exports by the contractor are also
and fossil substances, including hydrocarbons, regardless of who owns the
tax exempt. With regard to income taxes, as provided by article 5 of Decree
land on which the reserves are located. The exploration and exploitation
Law No. 1,089, the contractor is subject either to a single tax calculated on
of hydrocarbons may be carried out by the state, companies owned by the
its retribution, equal to 50% of such retribution, or to the general income tax
state or private entities through administrative concessions granted by the
regime established in the Income Tax Law (Decree Law No. 824 of 1974), in
President of Chile by Supreme Decree or CEOPs executed by the Minister of
force at the time of the execution of the public deed which contains CEOPs,
Energy. Exploitation rights granted to private companies are subject to special
terms of which will be applicable and invariable throughout the duration of
taxes and/or royalty payments. The hydrocarbon exploration and exploitation
the contract. Income in Chile is subject to corporate tax on an accrual basis and
industry is supervised by the Chilean Ministry of Energy.
has a current rate of 25.5% for fiscal year 2017. The applicable and invariable
corporate income tax rates of our CEOPs range between 15% and 18.5%, as
In Chile, a participant is granted rights to explore and exploit certain assets
follows: the Fell Block is subject to a rate of 15%, the Tranquilo Block is subject to
under a CEOP. If a participant breaches certain obligations under a CEOP, the
a rate of 17% and the Flamenco, Isla Norte and Campanario Blocks are subject
participant may lose the right to exploit certain areas or may be required
to a rate of 18.5% for the income accrued or received during 2012 and 17% for
to return all or a portion of the awarded areas to Chile with no right of
the income accrued or received during 2013 and onward. Dividends or profits
compensation. Although the government of Chile cannot unilaterally modify
distributed to the foreign shareholders of the contractors are subject to 35%
the rights granted in the CEOP once it is signed, exploration and exploitation are
Additional Withholding Tax with a tax credit for the corporate income tax paid
nonetheless subject to significant government regulations, such as regulations
by the contractor. With regard to the value added tax, contractors may obtain
concerning the environment, tort liability, health and safety and labor.
as a refund the value added tax (which is 19% according to the Sales and
Regulatory framework
Services Tax Law contained in Decree Law No. 825 of 1974) supported or paid
Regulation of exploration and production activities
on the import or purchase of goods or services used in connection with the
Oil and gas exploration and development is governed by the Political
exploration and exploitation activities. The applicable tax regime for each CEOP
Constitution of the Republic of Chile and Decree with Law Force No 2 of
remains unchanged throughout the duration of the CEOP.
GeoPark 101
The Chilean Congress approved a reform to the income tax law in September
Taxation
2014 which was amended in February 2016. Under this reform the income tax
The Brazilian Petroleum Law introduced significant modifications and benefits
rate will increase from 20% in 2013 to: 21% in 2014, 22.5% in 2015, 24% in 2016,
to the taxation of oil and natural gas activities. The main component of
25.5% in 2017 and 27% in 2018. The operating subsidiaries that we control in
petroleum taxation is the government take, comprised of license fees, fees
Chile, which are GeoPark TdF S.A., GeoPark Fell S.p.A. and GeoPark Magallanes
payable in connection with the occupation or title of areas, royalties and a
Limitada, are not affected by the income tax reform mentioned since they are
special participation fee. The introduction of the Brazilian Petroleum Law
covered by the tax treatment established in the CEOPs. The above has been
presents certain tax benefits primarily with respect to indirect taxes. Such
confirmed by the Chilean IRS through ruling N°2478/2016.
indirect taxes are very complex and can add significantly to project costs. Direct
taxes are mainly corporate income tax and social contribution on net profit.
Brazil
Regulation of the oil and gas industry
With the effectiveness of the Brazilian Petroleum Law and the regulations
Article 177 of the Brazilian Federal Constitution of 1988 provides for the
promulgated by the ANP, concessionaires are required to pay the Brazilian
Federal Government’s monopoly over the prospecting and exploration of oil,
federal government the following:
natural gas resources and other fluid hydrocarbon deposits, as well as over
• license fees;
the refining, importation, exportation and sea or pipeline transportation of
• rent for the occupation or retention of areas;
crude oil and natural gas. Initially, paragraph one of article 177 barred the
• special participation fee; and
assignment or concession of any kind of involvement in the exploration
• royalties on production.
of oil or natural gas deposits to private industry. On November 9, 1995,
however, Constitutional Amendment Number 9 altered paragraph one of
The minimum value of the license fees is established in the bidding rules for
article 177 so as to allow private or state-owned companies to engage in the
the concessions, and the amount is based on the assessment of the potential,
exploration and production of oil and natural gas, subject to the conditions
as conducted by the ANP. The license fees must be paid upon the execution
to be set forth by legislation.
Regulatory framework
Pricing policy
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
hydrocarbon production.
Until the enactment of the Brazilian Petroleum Law, the Brazilian government
The special participation fee is an extraordinary charge that concessionaires
regulated all aspects of the pricing of oil and oil products in Brazil, from the
must pay in the event of obtaining high production volumes and/or
cost of oil imported for use in refineries to the price of refined oil products
profitability from oil fields, according to criteria established by applicable
charged to the consumer. Under the rules adopted following the Brazilian
regulation, and is payable on a quarterly basis for each field from the date on
Petroleum Law, the Brazilian government changed its price regulation policies.
which extraordinary production occurs. This participation rate, whenever due,
Under these regulations, the Brazilian government: (1) introduced a new
may reach up to 40% of net revenues depending on (i) volume of production
methodology for determining the price of oil products designed to track
and (ii) whether the block is onshore, shallow water or deep water. Under the
prevailing international prices denominated in U.S. dollars, and (2) gradually
Brazilian Petroleum Law and applicable regulations issued by the ANP, the
eliminated controls on wholesale prices.
Concessions
special participation fee is calculated based upon quarterly net revenues of
each field, which consist of gross revenues calculated using reference prices
published by the ANP (reflecting international prices and the exchange rate
In addition to opening the Brazilian oil and natural gas industry to private
for the period) less: royalties paid; investment in exploration; operational costs;
investment, the Brazilian Petroleum Law created new institutions, including
and depreciation adjustments and applicable taxes.
the ANP, to regulate and control activities in the sector. As part of this
mandate, the ANP is responsible for licensing concession rights for the
The ANP is responsible for determining monthly minimum prices for
exploration, development and production of oil and natural gas in Brazil’s
petroleum produced in concessions for purposes of royalties payable with
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.
102 GeoPark 20F
State VAT (ICMS)
taxation, the amount of the tax cannot be considered as a credit (even though
ICMS is a state sales tax. This tax is due on the local sale of oil and gas, based
IPI is under the non-cumulative regime applicable for IPI’s taxpayers), which
on the sale price, including the ICMS itself.
means that this will be a cost for the legal entity acquirer. In relation to the
For intrastate transactions (carried out by a seller and a buyer located in the
be obliged to pay the IPI due on the transaction. For the same aforementioned
same Brazilian state) or imports, the ICMS rate is determined by the legislation
reasons for the O&G companies (upstream), this will be considered as cost
importation, the importer of record will be considered as the taxpayer and will
of the state where the sale is made and generally varies from 17% to 20%.
when the importation is subject to IPI.
Interstate transactions (carried out between a seller and buyer located in
different Brazilian states), in turn, are subject to reduced rates of 4% (if the
ISS is a cumulative tax which is due on provided services and imported
products are imported and not submitted to a manufacturing process or,
services. Usually, regarding local transactions, such tax is included in the price
in case of further manufacturing, if the resulting product has a minimum
of the service charged by the service provider. In relation to the import of
imported content of 40%), 7% or 12%, depending on the states involved. One
service, the Brazilian entity contractor is responsible for the payment of the
exception is that, due to the immunity established by the Brazilian Federal
ISS, which means that, depending on contractual arrangement, the tax burden
Constitution, ICMS is not due on interstate crude oil transactions when
may be supported by the Brazilian contractor or the foreign service provider.
destined to industrialization and commercialization. On the other hand, in
case of consumables or fixed assets, the buyer must pay to the state where the
ISS tax rate may vary from 2% to 5% and will depend on the nature of service,
buyer is located, the ICMS DIFAL, which is calculated based on the difference
as well as where the service provider is located (in general, some exceptions
between the interstate rate and the buyer’s own internal ICMS rate.
may apply).
ICMS is calculated under the noncumulative regime, and therefore some input
Additionally, GeoPark Brazil was granted in 2018 a tax benefit issued by
transactions could result in tax credits (for example the acquisition of inputs
SUDENE (Northeastern Development Superintendence), by means of the
and fixed assets directly used in the company’s activity).
Constitutive Act No. 0069/2018, which approved the tax incentive to reduce by
Social contribution taxes on gross revenue (PIS and COFINS)
profits, based on Article 1 of the Provisory Measure 2,199-14 of August 24,
PIS and COFINS are social contribution taxes charged on gross revenues
2001, in accordance with the requirements established by the Decree 6,539 of
earned by a Brazilian Federal Revenue noncumulative regime of calculation.
August 18, 2008.
75% the Income Tax and Additions, calculated over the company exploration
Under the noncumulative regime, PIS and COFINS are generally charged at
The benefit will be valid for 10 years, starting from January 1, 2018, under
a combined nominal rate of 9.25% (1.65% PIS and 7.6% COFINS) on national
the condition of modernizing the entire project on the SUDENE operating
revenues earned by a legal entity. In that case, certain business costs result
area, observing all provided legal conditions and requirements that includes
in tax credits to offset PIS and COFINS liabilities (e.g., input and services
compliance with labor and social law and with all environmental protection
acquisitions, expenses of depreciation and amortization of machinery,
and control regulations, annual submission of a declaration of income and a
equipment and other fixed assets acquired to be directly used in the
restriction to the distribution to partners or shareholders of the tax amount
company’s activities). PIS and COFINS paid upon the importation of certain
which is not payed due to the tax exemption.
inputs, assets and services contracted that are destined to the company’s
activity are also creditable. Although upstream industries are generally subject
The noncompliance with the requirements provided constitutes a default of
to this regime, it is not clear yet when this benefit is applied according to the
the beneficiary company in respect to SUDENE and shall be subject to the
stage of the field, (exploration or production).
applicable penalties.
Peru
Since July 1, 2015, taxpayers subject to the noncumulative regime must
Regulation of the oil and gas industry
calculate PIS and COFINS over certain financial revenues, applying rates of
The hydrocarbons activities in Peru are mainly regulated by the General
0.65% and 4%, respectively.
Hydrocarbons Law (Law 26,221), and several regulations enacted in order to
develop the provisions included in such law.
Federal Industrialization VAT (IPI) and Municipality VAT (ISS)
IPI is a non-cumulative tax and may be due on goods acquisitions by
According to the Hydrocarbons Law, oil and gas exploration and production
importation or national transactions. The IPI rate will be applied depending
activities are carried out under license or service contracts granted by the
on the NCM classification of the product according to TIPI (Table of IPI). On
government. Under a license contract, the investor pays a royalty, whereas
the acquisition of local goods subject to IPI, such tax is included in the price
under a service contract, the government pays remuneration to the contractor.
of the good. Considering that O&G activity (upstream) is not subject to IPI
As stated by the Peruvian Constitution and the Organic Law for Hydrocarbons,
GeoPark 103
a license contract does not imply a transfer or lease of property over the
in Peru and to promote exploration; as well as defining what will be the
area of exploration or exploitation. By virtue of the license contract, the
treatment on VAT in hydrocarbon exploration projects). At the end of 2018,
contractor acquires the authorization to explore or to exploit hydrocarbons
the Congress approved to extend the VAT refund to this type of projects to
in a determined area, and Perupetro (the entity that holds the Peruvian state
December 2019.
interest) transfers the property right in the extracted hydrocarbons to the
contractor, who must pay a royalty to the state.
The stabilized income tax regime will only cover the activities of the License
Regulatory framework
Agreement (exploration and/or exploitation activities), therefore, the related
activities (i.e., activities related to oil and gas, but not carried out under the
License and service contracts are approved by a supreme decree issued by
terms of the contract) and other activities (i.e., activities not related to oil and
the Peruvian Ministry of Economy and Finance, and the Peruvian Ministry of
gas) will be governed by the income tax rules in force to date.
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
Resident companies (incorporated in Peru), are subject to income tax on
must be duly qualified by Perupetro, in order to determine if it fulfills all the
their worldwide taxable income. Branches and permanent establishments of
requirements needed to develop exploration and production activities under
foreign companies that are located in Peru and non-resident entities are taxed
the contract form requirements mentioned above.
on Peruvian source income only.
License and services agreements may be granted for just an exploitation
With respect to the Morona Agreement, in which we take part, the applicable
stage -when a commercial discovery has been made- or for an exploration
income tax stabilized regime is from 1995, which is the year of subscription
and exploitation stage –when such discovery has not been made yet. In this
of the original License Agreement. The income tax rate in 1995 was 30% and
case, the exploration phase will last no more than 7 years, counted from the
there was no withholding income tax for dividends. Additionally, in 1995
effective date of the contract (60 days after the signing date). This term can
it was stated that the income tax should not be lower than 2% of the net
be divided into several periods as agreed in the contract, and all of them
assets of the Company (the “Minimum Income Tax”). The Minimum Income
with a minimum work obligation that should be fulfilled by a contractor in
Tax was later declared unconstitutional, which is why, even when there was a
order to access the next exploration period. The exploration phase will last
tax stability contract, the Minimum Income Tax has been understood as not
until a declaration of commercial discovery is made by the contractor. The
applicable or enforceable.
exploitation phase will last from the date of such declaration until 30 years
from the date of the contract.
Taxable income is generally computed by reducing gross revenue by cost of
goods sold and all expenses necessary to produce the income or maintain
The Ministry of Energy and Mines may exceptionally authorize an extension
the source of income. Certain types of revenue, however, must be computed
of three years for the exploration stage, if the contractor has fulfilled with the
as specified in the tax law and some expenses are not fully deductible for
minimum work program established in the contract, and also commits to fulfill
tax purposes. Business transactions must be recorded in legally authorized
an additional work program that justifies such extension. The contractor shall
accounting records that are in full compliance with the International
be responsible for providing the technical and economic resources required
Accounting Standards (IAS). Contractors in a license or services contract for
for the execution of the operations of this phase.
the exploration or exploitation of hydrocarbons (Peruvian corporations and
branches) are entitled to keep their accounting records in foreign currency,
The Peruvian regulations also established the roles of the Peruvian
but taxes must be paid in Peruvian Soles (“PEN”).
government agencies that regulate, promote and supervise the oil and
gas industry, including the Ministry of Energy and Mines, Perupetro and
Any investments in a contract area that did not reach the commercial
OSINERGMIN.
Taxation
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
The fiscal regime that applies in Peru to the oil and gas industry consists of a
stage of commercial extraction.
combination of corporate income tax, royalties and other levies.
In general terms, oil and gas companies are subject to the general corporate
chosen by the contractor. If the contractor has entered into a single contract,
income tax regime that is stabilized in the applicable regime on the date of
the accumulated investments are charged as a loss against the results of the
subscription of the original License Agreement (due to a tax stability contract);
contract for the year of total release of the area for any contract that did not
nevertheless, there are certain special tax provisions for the oil and gas sector
reach the commercial extraction stage, with the exception of investments
(the approval of the new Organic Hydrocarbons Law is pending in order to
consisting of buildings, power installations, camps, means of communication,
encourage investments in license agreements that are already operating
equipment and other goods that the contractor keeps or recovers to use in the
These investments are amortized in accordance with the amortization method
104 GeoPark 20F
same operations or in other operations of a different nature.
(ii) the “cost+expense+mark up” structure to deduct the expenses for services
The contractor determines the tax base and the amount of the tax, separately
between related parties will now only be applicable to low added value
and for each contract. If the contractor carries out related activities or other
services, and not to entirety of services between related parties.
activities, the contractor is obligated to determine the tax base and the
amount of tax, separately, and for each activity. The corresponding tax is
• Legislative Decree 1381 updates the concept of tax havens to include “non-
determined based on the income tax provisions that apply in each case
cooperative” countries or countries that have a “preferential regime”. The law
(subject to the tax stability provisions for contract activities and based on the
has established a criterion to qualify a country under this concept.
regular regime for the related activities or other activities). The total income
tax amount that the contractor must pay is the sum of the amounts calculated
In addition, when applying the Comparable Uncontrolled Price (CUP) method
for each contract, for both the related activities and for the other activities.
to cross-border transactions involving commodities, the Legislative Decree
The forms to be used for tax statements and payments are determined by the
establishes that the arm’s-length price for Peruvian income tax purposes
tax administration. If the contractor has more than one contract, it may offset
must be determined by reference to a publicly quoted price. The actual
the tax losses generated by one or more contracts against the profits resulting
pricing date or period of pricing dates should be used as a reference to
from other contracts or related activities. Moreover, the tax losses resulting
determine the price for the transaction, as long as independent parties in
from related activities may be offset against the profits from one or more
comparable circumstances would have relied upon the same pricing date.
contracts.
The taxpayer needs to notify the SUNAT (i.e., Peruvian Tax Authority) of the
actual pricing date or period of pricing dates used to determine the price for
It is possible to choose the allocation of tax losses to one or more of the
the transaction.
contracts or related activities that have generated the profits, provided that
the losses are depleted or compensated to the limit of the profits available.
Legislative Decree 1424 extends the application of sub capitalization rules
This means that if there is another contract or related activity, the taxpayer
(maximum deductible interest determination) to unrelated parties.
can continue compensating tax losses until they are completely offset. A
contractor with tax losses from one or more contracts or related activities may
Likewise, as of 2021, the interest generated in transactions with related or
not offset them against profits generated by the other activities. Furthermore,
unrelated parties that exceeds 30% of EBITDA of the preceding year will not
in no case may tax losses generated by the other activities be offset against
be deductible. Interest that is not deducted may be carried forward for up to
the profits resulting from the contracts or the related activities.
four years.
During the exploration phase, operators are exempt from import duties and
On the other hand, this Legislative Decree introduces in the Income Tax Law
other forms of taxation applicable to goods intended for exploration activities.
scenarios in which Permanent Establishments are triggered.
Exemptions are withdrawn at the production phase, but exceptions are made
in certain instances, and the operator may be entitled to temporarily import
Additionally, other provisions have been included in this Legislative Decree,
goods tax-free for a two-year period (“Temporary Import”). A temporary
for instance, that an indirect transfer of Peruvian shares will always be
Import may be extended for additional one year periods for up to two times
triggered if the amount paid for the shares of a non-resident entity that
upon the request of an operator, approval of the Ministry of Energy and
corresponds to the Peruvian shares is equivalent to or higher than 40,000 Tax
Mines and authorization of the Superintendencia Nacional de Aduanas y de
Units (approximately US$ 50.3 million).
Administracion Tributaria (Peruvian Customs Agency).
• Legislative Decree 1425 establishes a general and specific rules to determine
Several Legislative Decrees were published on September 13, 2018,
when to consider income or expenses as “accrued”.
introducing modifications to the Income Tax Law and the Tax Code.
Tax Code:
Income Tax Law: These dispositions are effective since January 1, 2019.
• Legislative Decree 1422 includes provisions for the implementation of the
• Legislative Decree 1369 allows companies to deduct the payment for technical
General Anti-Avoidance Rule (GAAR) and will be applicable to facts, acts and
assistance, assignment in use and other services provided by non-domiciled
situations from July 19, 2012 onwards and even to tax audits already started.
in the fiscal year that the service is paid, as long as the payment be made
before the deadline for submitting the corresponding Income Tax Affidavit.
In case of entities with a Board of Directors, that Board of Directors will be
Additionally, new transfer pricing rules were established: (i) the obligations to
cannot be delegated. The Board of Directors must evaluate the tax planning
apply the benefit test is now only applicable to operations between related
strategies implemented up to September 14, 2018 in order to ratify or modify
parties and no longer to operations with, towards or through tax havens; and
them. The term for ratify or modify them will end on March 29, 2019.
responsible of approving the tax planning of the entity. That obligation
GeoPark 105
• Legislative Decree 1372 establishes the obligation for legal entities resident
Deregulation Decrees eliminated restrictions on imports and exports of crude
in Peru to identify, obtain, update, report on the identification of their final
oil, deregulated the domestic oil industry, and effective January 1, 1991, the
beneficiaries, maintain that information and present a declaration to the Tax
prices of oil and petroleum products were also deregulated. In 1992, Law
Authority that provides the information that includes the chain of ownership
No. 24,145, referred to as the Privatization Law, privatized YPF and provided
or control, the percentage ownership, among others. This Legislative Decree
for transfer of hydrocarbon reservoirs from the Argentine government to the
is effective since August 03, 2018, and the Resolution that establishes the
provinces, subject to the existing rights of the holders of exploration permits
deadlines for submitting the informative affidavit of final beneficiary is still
and production concessions.
pending.
In May 2018, GeoPark Perú SAC applied for a VAT anticipated refund regime
new state-owned energy company, Energía Argentina S.A. (“ENARSA”). The
that will allow it to recover the tax paid until the first oil is produced. The
corporate purpose of ENARSA was initially the exploration and exploitation of
regime is established by Legislative Decree 973, which demands a minimum
solid, liquid and gaseous hydrocarbons; the transport, storage, distribution,
investment of US$5.0 million, and a preoperative period of 2 years (which for
commercialization and industrialization of these products; as well as
Morona Block starts on December 2016).
the transportation and distribution of natural gas, and the generation,
In October 2004, the Argentine Congress enacted Law No. 25,943, creating a
Environmental Regulation
transportation, distribution and sale of electricity. Moreover, Law No. 25,943
granted ENARSA all offshore areas located beyond 12 nautical miles from the
Before initiating any hydrocarbon activity (e.g. seismic exploration, drilling
coastline up to the outer boundary of the continental shelf that were vacant
of exploration wells, etc.) the contractor must file and obtain an approval for
at the time of the effectiveness of this law (i.e. November 3, 2004). In 2014,
an Environmental Impact Study (EIS), which is the most important permit
all open acreage offshore exploration permits and exploitation concessions
related to HSE for any hydrocarbon project. This study includes technical,
were conveyed to the National Energy Secretary (NSE) and all existing JV
environmental and social evaluations of the project to be executed in order
agreements entered into by ENARSA with private investors were conveyed
to define the activities that should be required for preventing, minimizing,
by ENARSA to YPF in accordance with Section 30, New Hydrocarbons Act No.
mitigating and remediation of the possible negative environmental and social
27,007.
impacts that the hydrocarbon project may generate.
There are general environmental regulations for the protection of water, soils,
Act. This law declared achieving self-sufficiency in the supply of hydrocarbons,
air, endangered species, biodiversity, natural protected areas, etc. In addition,
as well as in the exploitation, industrialization, transportation and sale of
there are specific environmental regulations applicable to the hydrocarbon
hydrocarbons, a national public interest and a priority for Argentina. In
On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty
industry.
Argentina
addition, the law expropriated 51% of the share capital of YPF, the largest
Argentine oil company, from Repsol, the largest Spanish oil company.
Regulatory framework
On July 28, 2012, Presidential Decree 1277/2012, which regulated the
From the 1920s to 1989, the Argentine public sector dominated the upstream
Hydrocarbon Sovereignty Law, was released, creating a Strategic Planning and
segment of the Argentine oil and gas industry and the midstream and
Coordination Committee for the National Hydrocarbon Investment Plan and
downstream segment of the business.
vesting it with the power to set the sector’s reference prices and to develop
investment plans for the country to increase production and reserves. The
The Hydrocarbon Law No. 17,319 enacted in 1967 continues in force until
decree introduced important changes to the rules governing Argentina’s
today, subject to amendments introduced by the Deregulation Decrees and
oil and gas industry, including the repeal of certain articles of Deregulation
Laws No. 24,145, 26,197 and 27,007.
Decrees passed during 1989 relating to free marketability of hydrocarbons
The Hydrocarbon Law No. 17,319 provided for the existence of a state-owned
at negotiated prices, the deregulation of the oil and gas industry, freedom to
oil & gas company (originally, YPF) for whom private companies served
import and export hydrocarbons and the ability to keep proceeds from export
as service contractors or joint venture partners. But it also provided for a
sales in foreign bank accounts.
concession & royalty system which in practice was not used until after the YPF
privatization.
On January 4, 2016, immediately after the new national administration took
office, Presidential Decree 272/2015 was released. This Decree abrogated
In 1989, Argentina enacted certain laws aimed at privatizing the majority
the provisions of the Presidential Decree 1277/2012 which had repealed the
of its state-owned companies and issued a series of presidential decrees
Deregulation Decrees. Thus, the Deregulation Decrees were reinstated.
(namely, Decrees No. 1055/89, 1212/89 and 1589/89 (the “Oil Deregulation
Decrees”), relating specifically to deregulation of energy activities). The Oil
Other measures have also been taken by the new presidential administration
106 GeoPark 20F
aimed at reducing government intervention and reestablishing market forces
• With regards to concessions, three types of concessions are provided, namely,
in the oil & gas industry:
conventional exploitation, unconventional exploitation, and exploitation in
• Effective October 1 2017 both domestic oil prices at the wellhead and
the continental shelf and territorial waters, establishing the respective terms
gasoline prices at the dispenser were allowed to float freely, ending floor
for each type.
pricing schemes sheltering the oil producers during low oil times.
• The terms for hydrocarbon transportation concessions were adjusted in order
• Also, effective October 22, 2018, Resolution 103/2018 established a new
to comply with the exploitation concessions terms.
framework governing natural gas export authorization proceedings,
• With regards to royalties, a maximum of 12% is established, which may reach
including long term and short-term firm export authorizations, interruptible
18% in the case of granted extensions, where the law also establishes the
export authorizations, summer export authorizations and operational
payment of an extension bond for a maximum amount equal to the amount
exchanges. These new natural gas exports were soon put in practice and
resulting from multiplying the remaining proven reserves at the end of
natural gas exports by pipeline to neighbouring countries resumed in 2018.
effective term of the concession by 2% of the average basin price applicable
to the respective hydrocarbons over the 2 years preceding the time on which
Domain and Jurisdiction of hydrocarbons resources
the extension was granted.
After a constitutional reform enacted in 1994, eminent domain over
• The extension of the Investment Promotion Regime for the Exploitation of
hydrocarbon resources lying in the territory of a provincial state is now vested
Hydrocarbons (Decree No. 929/2013) is established for projects representing
in such provincial state, while eminent domain over hydrocarbon resources
a direct investment in foreign currency of at least 250 million dollars,
lying offshore on the continental platform beyond the jurisdiction of the
increasing the benefits for other type of projects.
coastal provincial states is vested in the federal state.
Regulation of transportation activities
Thus, oil and gas exploration permits and exploitation concessions are now
Exploitation concessionaires have the exclusive right to obtain a
granted by each provincial government. A majority of the existing concessions
transportation concession for the transport of oil and gas from the provincial
were granted by the federal government prior to the enactment of Law
states or the federal government, depending on the applicable jurisdiction.
No.26,197 and were thereafter transferred to the provincial states.
Such transportation concessions include storage, ports, pipelines and other
Hydrocarbon Exports and Self Sufficiency
fixed facilities necessary for the transportation of oil, gas and by-products.
Transportation facilities with surplus capacity must transport third parties’
Achieving self-sufficiency has been an energy policy goal from the early days
hydrocarbons on an open-access basis, for a fee which is the same for all users
of the industry.
on similar terms. As a result of the privatizations of YPF and Gas del Estado, a
few common carriers of crude oil and natural gas were chartered and continue
Section 6 of the Hydrocarbon Law No. 17,319 allows the National Executive
to operate to date.
Branch to authorize the export of hydrocarbons. At times when the domestic
production of liquid hydrocarbons is insufficient to cover domestic needs, the
Effective February 8, 2019, to promote transportation capacity expansions,
delivery of the entire availability of such locally produced hydrocarbons to the
Decree 115/2019 allowed interested shippers to reserve transportation
domestic market shall be mandatory, with such exceptions as may be justified
capacity in new or expanded pipelines through freely negotiated capacity
on technical grounds.
reservation agreements.
In turn, Section 3 of the Natural Gas Regulatory Framework 24,076 allows the
Taxation
National Executive Branch to authorize the export of natural gas. The granting
Exploitation concessionaires are subject to the general federal and provincial
of natural gas export permits is regulated in detail.
tax regime. The most relevant federal taxes are the income tax (30%), the value
added tax (21%) and a tax on assets. The most relevant provincial taxes are the
Supply privileges favouring the domestic market to the detriment of the
turnover tax (3% on average) and stamp tax.
export market, including hydrocarbon export restrictions, domestic price
controls, export duties and domestic market supply obligations have been
Tax reform was enacted in Argentina in December 2017. The legislation
implemented several times.
included significant changes to certain corporate income tax and statutory
income tax provisions, including rate reductions. Most of the tax provisions
Regulation of exploration and production activities
were 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% has
of Law No. 27,007, amending the Hydrocarbon Law No. 17,319.
The most relevant aspects of the new law are as follows:
the following rate schedule:
• 30% in 2018 and 2019
GeoPark 107
Operating and financial review and prospects
• 25% in 2020 and 2021 and onwards.
Other changes include the following:
Factors affecting our results of operations
We describe below the year-to-year comparisons of our historical results and
• New withholding tax on dividends—with the applicable rates for
the analysis of our financial condition. Our future results could differ materially
non-resident shareholders of: (1) 7% for dividends distributed out of the
from our historical results due to a variety of factors, including the following:
distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and
(2) 13% for dividends distributed out of the distributing entity’s previously
Discovery and exploitation of reserves
taxed profits of fiscal years 2020 and onwards.
Our results of operations depend on our level of success in finding, acquiring
• Application of inflation adjustment for corporate tax purposes is reinstated
(including through bidding rounds) or gaining access to oil and natural
under certain circumstances (e.g. if the inflation cumulative rate for three
gas reserves. While we have geological reports evaluating certain proved,
consecutive years exceeds 100%).
contingent and prospective resources in our blocks, there is no assurance that
• Possible tax revaluation of investment in fixed assets, under payment of a
we will continue to be successful in the exploration, appraisal, development
special tax.
and commercial production of oil and natural gas. The calculation of our
• Certain restrictions for the deduction of exchange differences on income
geological and petrophysical estimates is complex and imprecise, and it is
tax.
possible that our future exploration will not result in additional discoveries,
• New export taxes applicable to services activities.
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, 2018, we made total capital expenditures
of US$ 124.7 million (US$97.0 million, US$7.9 million, US$9.0 million, US$8.5
We are an exempted company incorporated pursuant to the laws of Bermuda.
million and US$2.3 million in Colombia, Chile, Argentina, Peru and Brazil,
We operate and own our assets directly and indirectly through a number
respectively), consisting of US$43.5 million related to exploration.
of subsidiaries. See an illustration of our corporate structure in Note 21
(“Subsidiary undertakings”) to our Consolidated Financial Statements.
Oil prices were volatile since the end of 2014. In preparation for continued
During 2017, we decided to incorporate a subsidiary in the United Kingdom
volatility, we have developed multiple scenarios for our 2019 capital
(international investor centre) to conduct our businesses and financial
expenditure program. See “Item 4. Information on the Company –B. Business
decisions.
Overview—2019 Strategy and Outlook.”
D. Property, plant and equipment
Funding for our capital expenditures relies in part on oil prices remaining close
See “—B. Business Overview—Title to properties.”
to our estimates or higher levels and other factors to generate sufficient cash
ITEM 4A. UNRESOLVED STAFF COMMENTS
and the covenants in our financing agreements, as well as the amount of cash
flow. Low oil prices affect our revenues, which in turn affect our debt capacity
Not applicable.
we can borrow using our oil reserves as collateral, the amount of cash we
are able to generate from current operations and the amount of cash we can
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
obtain from prepayment agreements such as the Trafigura Agreement, which
A. Operating results
is our offtake and prepayment agreement. If we are not able to generate
the sales which, together with our current cash resources, are sufficient to
fund our capital program, we will not be able to efficiently execute our work
The following discussion of our financial condition and results of operations
program which would cause us to further decrease our work program, which
should be read in conjunction with our Consolidated Financial Statements
could harm our business outlook, investor confidence and our share price.
and the notes thereto as well as the information presented under “Item 3. Key
Information— A. Selected financial data.”
If oil prices average higher than the base budget price, we have the ability
to allocate additional capital to more projects and increase its work and
The following discussion contains forward-looking statements that involve risks
investment program and thereby further increase oil and gas production.
and uncertainties. Our actual results may differ materially from those discussed
in the forward-looking statements as a result of various factors, including those
Our results of operations will be adversely affected in the event that our
set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking
estimated oil and natural gas asset base does not result in additional reserves
statements.”
108 GeoPark 20F
that may eventually be commercially developed. In addition, there can be
no assurance that we will acquire new exploration blocks or gain access to
exploration blocks that contain reserves. Unless we succeed in exploration and
development activities, or acquire properties that contain new reserves, our
based on a formula that takes into account various international prices of
anticipated reserves will continually decrease, which would have a material
methanol, including US Gulf methanol spot barge prices, methanol spot
adverse effect on our business, results of operations and financial condition.
Rotterdam prices and spot prices in Asia. See “Item 3. Key Information—D. Risk
factors—Risks relating to our business—A substantial or extended decline
Oil and gas revenue and international prices
in oil, natural gas and methanol prices may materially adversely affect our
Our revenues are derived from the sale of our oil and natural gas production,
business, financial condition or results of operations.”
as well as of condensate derived from the production of natural gas. The
price realized for the oil we produce is generally linked to Brent or Vasconia.
In Brazil, prices for gas produced in the Manati Field are based on a long-term
The price realized for the natural gas we produce in Chile is linked to the
off-take contract with Petrobras. The price of gas sold under this contract is
international price of methanol, which is settled in the international markets
denominated in reais and is adjusted annually for inflation pursuant to the
in US$. The market price of these commodities is subject to significant
Brazilian General Market Price Index (Índice Geral de Preços—Mercado) (the
fluctuation and has historically fluctuated widely in response to relatively
“IGPM”). See Note 3 to our Consolidated Financial Statements.
minor changes in the global supply and demand for oil and natural gas,
market uncertainty, economic conditions and a variety of additional factors.
In Argentina, the realized oil prices for our production in the Neuquén Basin
follows the “Medanito” blend oil price reference, which has traditionally been
From January 1, 2014 to December 31, 2018, Brent spot prices ranged from a
linked to ICE Brent adjusted by certain marketing and quality discounts based
low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub natural
on API, delivery point and transport costs. Between May and November
gas average spot prices ranged from a low of US$1.7 per mmbtu to a high of
2018, Medanito crude prices were capped industry-wide between US$ 65
US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low of
per barrel and US$ 70 per barrel. Since December 2018, domestic prices have
US$250.0 per metric ton to a high of US$635.1 per metric ton. Furthermore,
reconnected to the international benchmark.
oil, natural gas and methanol prices do not necessarily fluctuate in direct
relationship to each other.
Gas sales in Argentina are carried out through annual contracts that go from
May to April. The price of the gas sold under these contracts depends mainly
As a consequence of the oil price crisis which started in the second half of
on domestic supply and demand and regulation affecting the sector.
2014 (WTI and Brent, the main international oil price benchmarks, fell more
than 60% between October 2014 and February 2016), we took decisive steps
If the market prices of oil and methanol had fallen by 10% as compared to
in 2015 and 2016 to adapt to the new oil price environment. We reduced our
actual prices during the year, with all other variables held constant, and taking
capital expenditure program from US$238 million in 2014 to US$48 million in
into account the impact of the derivative contracts in place, post-tax profit for
2015 and US$39 million in 2016 and implemented significant cost reduction
the year ended December 31, 2018 would have been lower by US$13.7 million
initiatives that resulted in production and operating costs being reduced by
(post-tax loss would have been higher by US$10.4 million in 2017).
49% (2016 versus 2014), and administrative expenses being reduced by 26%
(2016 versus 2014), while increasing average production to approximately 22.4
Production and operating costs
mboepd and increasing our proved reserves to 73.6 mmboe.
Our production and operating costs consist primarily of expenses associated
In October 2016, we decided to manage part of our exposure to the volatile
plant leasing, facilities and wells maintenance (including pulling works),
crude oil price using derivatives. For further information related to Commodity
labor costs, contractor and consultant fees, chemical analysis, royalties and
Risk Management Contracts, please see Note 8 to our Consolidated Financial
products, among others. As commodity prices increase or decrease, our
Statements.
production costs may vary. We have historically not hedged our costs to
with the production of oil and gas, the most significant of which are gas
protect against fluctuations.
Additionally, the oil and gas we sell may be subject to certain discounts. For
example, in Colombia, the price of oil we sell is based on Vasconia, a marker
Availability and reliability of infrastructure
broadly used in the Llanos Basin, adjusted for certain marketing and quality
Our business depends on the availability and reliability of operating and
discounts based on, among other things, API, viscosity, sulfur, delivery point
transportation infrastructure in the areas in which we operate. Prices and
and water content, as well as on certain transportation costs (including
availability for equipment and infrastructure, and the maintenance thereof,
pipeline costs and trucking costs).
affect our ability to make the investments necessary to operate our business,
and thus our results of operations and financial condition. See “Item 3. Key
In Chile, the price of oil we sell to ENAP is based on Brent minus certain
Information—D. Risk factors—Risks relating to our business—Our inability to
marketing and quality discounts. We have a long-term gas supply contract
access needed equipment and infrastructure in a timely manner may hinder
with Methanex. The price of the gas sold under this contract is determined
our access to oil and natural gas markets and generate significant incremental
costs or delays in our oil and natural gas production.”
GeoPark 109
Production levels
Geographical segment reporting
Our oil and gas production levels are heavily influenced by our drilling results,
In the description of our results of operations that follow, our “Other”
our acquisitions and to oil and natural gas prices.
operations reflect our non-Colombian, non-Chilean, non-Argentine and
non-Brazilian operations, primarily consisting of our corporate head office
We expect that fluctuations in our financial condition and results of operations
operations.
will be driven by the rate at which production volumes from our wells decline.
As initial reservoir pressures are depleted, oil and gas production from a given
We divide our business into five geographical segments—Colombia, Chile,
well will decline over time. See “Item 3. Key Information—D. Risk factors—
Brazil, Argentina and Peru—that correspond to our principal jurisdictions of
Risks relating to our business—Unless we replace our oil and natural gas
operation. Activities not falling into these five geographical segments are
reserves, our reserves and production will decline over time. Our business is
reported under a separate corporate segment that primarily includes certain
dependent on our continued successful identification of productive fields and
corporate administrative costs not attributable to another segment.
prospects and the identified locations in which we drill in the future may not
yield oil or natural gas in commercial quantities.”
Description of principal line items
The following is a brief description of the principal line items of our statement
Contractual obligations
of income.
In order to protect our exploration and production rights in our licensed
areas, we must make and declare discoveries within certain time periods
Revenue
specified in our various special contracts, E&P Contracts and concession
Revenue includes the sale of crude oil, condensate and natural gas net of
agreements. The costs to maintain or operate our licensed areas may
value-added tax (“VAT”), and discounts related to the sale (such as API and
fluctuate or increase significantly, and we may not be able to meet our
mercury adjustments) and overriding royalties due to the ex-owners of oil and
commitments under these agreements on commercially reasonable terms
gas properties where the royalty arrangements represent a retained working
or at all, which may force us to forfeit our interests in such areas. If we
interest in the property. Revenue is recognized when control has been
do not succeed in renewing these agreements, or in securing new ones,
transferred to the purchaser and if revenue can be measured reliably and is
our ability to grow our business may be materially impaired. See “Item 3.
expected to be received.
Key Information—D. Risk factors—Risks relating to our business—Under
the terms of some of our various CEOPs, E&P Contracts and concession
Commodity risk management contracts
agreements, we are obligated to drill wells, declare any discoveries and file
Includes realized and unrealized gains and losses arising from commodity risk
periodic reports in order to retain our rights and establish development
management contracts.
areas. Failure to meet these obligations may result in the loss of our interests
in the undeveloped parts of our blocks or concessioned areas.”
Production and operating costs
Acquisitions
Production and operating costs are recognized on the accrual basis of
accounting. These costs include wages and salaries incurred to achieve
As described above, part of our strategy is to acquire and consolidate assets
the revenue for the year. Direct and indirect costs of raw materials and
in Latin America. We intend to continue to selectively acquire companies,
consumables, rentals, leasing and royalties are also included within this
producing properties and concessions. As with our historical acquisitions,
account. For a description of our production and operating costs, see “—
any future acquisitions could make year-to-year comparisons of our results of
Factors affecting our results of operations.”
operations difficult. We may also incur additional debt, issue equity securities
or use other funding sources to fund future acquisitions. We generally
Depreciation and write-off of unsuccessful efforts
incorporate our acquired business into our results of operations at or around
Capitalized costs of proved oil and natural gas properties are depreciated on
the date of closing.
a licensed-area-by-licensed-area basis, using the unit of production method,
based on commercial proved and probable reserves as calculated under the
Functional and presentational currency
Petroleum Resources Management System methodology promulgated by the
Our Consolidated Financial Statements are presented in US$, which is our
Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”),
presentational currency. Items included in the financial information of each
which differs from SEC reporting guidelines pursuant to which certain
of our entities are measured using the currency of the primary economic
information in the forepart of this annual report is presented. The calculation
environment in which the entity operates, or the functional currency, which
of the “unit of production” depreciation takes into account estimated future
is the US$ in each case, except for our Brazil operations, where the functional
discovery and development costs. Changes in reserves and cost estimates are
currency is the real.
recognized prospectively. Reserves are converted to equivalent units on the
basis of approximate relative energy content.
110 GeoPark 20F
In particular, upon completion of the evaluation phase, a prospect is either
Profit or loss for the period attributable to owners of the Company
transferred to oil and gas properties if it contains reserves or is charged to
Profit or loss for the period attributable to owners of the Company consists of
profit and loss in the period in which the determination is made. See “—
profit or losses for the year less non-controlling interest.
Critical accounting policies and estimates—Oil and gas accounting.”
Critical accounting policies and estimates
Geological and geophysical expenses
We prepare our Consolidated Financial Statements in accordance with IFRS
Geological and geophysical expenses are recognized on the accrual basis of
and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as
accounting and consist of geosciences costs, including wages and salaries
adopted by the IASB. The preparation of the financial statements requires
and share-based compensation not subject to capitalization, geological
us to make judgments, estimates and assumptions that affect the reported
consultancy costs and costs relating to independent reservoir engineer
amounts of assets, liabilities, revenue and expenses, and related disclosure
studies.
Administrative expenses
of contingent assets and liabilities. We continually evaluate these estimates
and assumptions based on the most recently available information, our own
historical experience and various other assumptions that we believe to be
Administrative expenses are recognized on the accrual basis of accounting
reasonable under the circumstances. Since the use of estimates is an integral
and consist of corporate costs such as director fees and travel expenses,
component of the financial reporting process, actual results could differ
new project evaluations and back-office expenses principally comprised of
from those estimates.
wages and salaries, share-based compensation, consultant fees and other
administrative costs, including certain costs relating to acquisitions.
An accounting policy is considered critical if it requires an accounting
Our administrative expenses for the year ended December 31, 2018
uncertain at the time such estimate is made, and if different accounting
increased by US$10.0 million, or 24%, compared to the year ended
estimates that reasonably could have been used, or changes in the
December 31, 2017 mainly due to higher staff costs resulting from increased
accounting estimates that are reasonably likely to occur periodically, could
scale of operations. However, administrative costs may increase as a result
materially impact the financial statements. We believe that the following
of our Peruvian and Argentinian operations, other acquisitions, increased
accounting policies represent critical accounting policies as they involve a
activity or the impact of appreciation of local currencies in the countries
higher degree of judgment and complexity in their application and require
estimate to be made based on assumptions about matters that are highly
where we operate.
Selling expenses
us to make significant accounting estimates. The following descriptions of
critical accounting policies and estimates should be read in conjunction
with our Consolidated Financial Statements and the accompanying notes
Selling expenses are recognized on the accrual basis of accounting and consist
and other disclosures.
primarily of transportation, storage costs and selling taxes.
Business combinations
Impairment of non-financial assets
Business combinations are accounted for using the acquisition method.
Assets that are not subject to depreciation and/or amortization (such as
The cost of an acquisition is measured as the fair market value of the assets
exploration and evaluation assets) are tested annually for impairment.
acquired, equity instruments issued and liabilities incurred or assumed on
Assets that are subject to depreciation and/or amortization are reviewed for
the date of completion of the acquisition. Acquisition costs incurred are
impairment whenever events or changes in circumstances indicate that the
recognized directly in the consolidated statement of income. Identifiable
carrying amount may not be recoverable.
assets acquired and liabilities and contingent liabilities assumed in a
An impairment loss is recognized for the amount by which the asset’s carrying
acquisition date. The excess of the cost of acquisitions over fair market value
amount exceeds its recoverable amount. The recoverable amount is the higher
of a company’s share of the identifiable net assets acquired is recorded as
of an asset’s fair value minus costs to sell and value in use.
goodwill. If the cost of the acquisition is less than a company’s share of the
net assets acquired, the difference is recognized directly in the consolidated
business combination are measured initially at their fair market values at the
During 2018 we recognized a net reversal of impairment losses of US$5.0
statement of income.
million, while in 2017 we did not recognize or reverse any impairment losses
and in 2016 we recognized a reversal of impairment losses of US$5.7 million.
The determination of fair value of identifiable acquired assets and assumed
See Note 36 to our Consolidated Financial Statements.
liabilities means that we are to make estimates and use valuation techniques,
Financial costs
including independent appraisers. The valuation assumptions underlying
each of these valuation methods are based on available updated information,
Financial results include interest expenses, interest income, bank charges, the
including discount rates, estimated cash flows, market risk rates and other
amortization of financial assets and liabilities, and foreign exchange gains and
losses.
GeoPark 111
data. As a result, the process of identification and the related determination of
drilling costs of exploratory wells. No depreciation and/or amortization are
fair values require complex judgments and significant estimates.
charged during the exploration and evaluation phase. Upon completion
of the evaluation phase, the prospects are either transferred to oil and gas
Cash flow estimates for impairment assessments
properties or charged to expense in the period in which the determination
Cash flow estimates for impairment assessments require assumptions
is made, depending whether they have found reserves. If not developed,
about two primary elements: future prices and reserves. Estimates of
exploration and evaluation assets are written off after three years, unless
future prices require significant judgments about highly uncertain future
it can be clearly demonstrated that the carrying value of the investment
events. Historically, oil and natural gas prices have exhibited significant
is recoverable. All field development costs are considered construction
volatility. Our forecasts for oil and natural gas revenues are based on prices
in progress until they are finished and capitalized within oil and gas
derived from future price forecasts among industry analysts, as well as our
properties, and are subject to depreciation once completed. Such costs
own assessments. Estimates of future cash flows are generally based on
may include the acquisition and installation of production facilities,
assumptions of long-term prices and operating and development costs.
development drilling costs (including dry holes, service wells and seismic
The process of estimating reserves requires significant judgments and
acquisition costs of rights and concessions related to proved properties.
surveys for development purposes), project-related engineering and the
decisions based on available geological, geophysical, engineering and
economic data. The estimation of economically recoverable oil and natural gas
Workovers of wells made to develop reserves and/or increase production
reserves and related future net cash flows was performed based on the D&M
are capitalized as development costs. Maintenance costs are charged to
Reserves Report. Such estimates incorporate many factors and assumptions
income when incurred.
including:
• expected reservoir characteristics based on geological, geophysical and
Capitalized costs of proved oil and gas properties and production facilities
engineering assessments;
and machinery are depreciated on a licensed area by licensed area basis,
• future production rates based on historical performance and expected future
using the unit of production method, based on commercial proved and
operating and investment activities;
probable reserves. The calculation of the “unit of production” depreciation
• future oil and natural gas prices and quality differentials;
takes into account estimated future finding and development costs, and is
• anticipated effects of regulation by governmental agencies; and
based on current year-end un-escalated price levels. Changes in reserves
• future development and operating costs.
and cost estimates are recognized prospectively. Reserves are converted to
Our management believes these factors and assumptions are reasonable
based on the information available at the time we prepare our estimates.
Oil and gas reserves for purposes of our Consolidated Financial Statements
However, these estimates may change substantially as additional data from
are determined in accordance with PRMS, and were estimated by DeGolyer
ongoing development activities and production performance becomes
and MacNaughton, independent reserves engineers.
equivalent units on the basis of approximate relative energy content.
available and as economic conditions impacting oil and natural gas prices
and costs change.
Depreciation of the remaining property, plant and equipment assets (i.e.,
furniture and vehicles) not directly associated with oil and gas activities
For further information related to impairment of property, plant and
has been calculated by means of the straight line method by applying
equipment, please see Note 36 to our Consolidated Financial Statements.
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.
Oil and gas accounting
Oil and gas exploration and production activities are accounted for in
Asset retirement obligations
accordance with the successful efforts method on a field by field basis.
Obligations related to the plugging and abandonment of wells once operations
We account for exploration and evaluation activities in accordance with
are terminated may result in the recognition of significant liabilities. We record
IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing
the fair value of the liability for asset retirement obligations in the period in
exploration and evaluation costs until such time as the economic viability
which the wells are drilled. When the liability is initially recognized, the cost is
of producing the underlying resources is determined. Costs incurred prior
also capitalized by increasing the carrying amount of the related asset. Over
to obtaining legal rights to explore are expensed immediately to the
time, the liability is accreted to its present value at each reporting date, and the
consolidated statement of income.
capitalized cost is depreciated over the estimated useful life of the related asset.
Estimating the future abandonment costs is difficult and requires management
Exploration and evaluation costs may include: license acquisition,
to make assumptions and judgments because most of the obligations will be
geological and geophysical studies (i.e., seismic), direct labor costs and
settled after many years. Technologies and costs are constantly changing, as
112 GeoPark 20F
are political, environmental, health, safety and public relations considerations.
In addition, we have tax-loss carry-forwards in certain taxing jurisdictions
Consequently, the timing and future cost of dismantling and abandonment
that are available to offset against future taxable profit. However, deferred
are subject to significant modification. Any change in the variables underlying
tax assets are recognized only to the extent that it is probable that taxable
our assumptions and estimates can have a significant effect on the liability
profit will be available against which the unused tax losses can be utilized.
and the related capitalized asset and future charges related to the retirement
Management judgment is exercised in assessing whether this is the case.
obligations. The present value of future costs necessary for well plugging and
abandonment is calculated for each area at the present value of the estimated
To the extent that actual outcomes differ from management’s estimates,
future expenditure. The liability recognized is based upon estimated future
taxation charges or credits may arise in future periods.
abandonment costs, wells subject to abandonment, time to abandonment, and
future inflation rates.
Share-based payments
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,
We provide several equity-settled, share-based compensation plans to certain
commercial, environmental and health & safety matters. For example, from
employees and third-party contractors, composed of payments in the form of
time to time, the Company receives notices of environmental, health and safety
share awards and stock options plans.
violations. Based on what our Management currently knows, such claims are
Fair value of the stock option plans for employee or contractor services
received in exchange for the grant of the options is recognized as an expense.
Recent accounting pronouncements
The total amount to be expensed over the vesting period, which is the period
See Note 2.1.1 to our Consolidated Financial Statements.
over which all specified vesting conditions are to be satisfied, is determined
by reference to the fair value of the options granted calculated using the
We have set up a project team by business unit which has reviewed each
Geometric Brownian Motion method. Determining the total value of our
business unit’s leasing arrangements over the last year in light of the new
not expected to have a material impact on the financial statements.
share-based payments requires the use of highly subjective assumptions,
lease accounting rules in IFRS 16.
including the expected life of the stock options, estimated forfeitures
and the price volatility of the underlying shares. The assumptions used in
As of December 31, 2018, we have non-cancellable operating lease
calculating the fair value of share-based payment represent management’s
commitments of US$ 69.9 million. Of these commitments, we expect to
best estimates, but these estimates involve inherent uncertainties and the
recognize right-of-use assets and lease liabilities, at nominal value, of
application of management’s judgment.
approximately US$ 14.5 million on January 1, 2019. The remaining lease
commitments, in accordance with IFRS 16, will be recognized on a straight-line
Non-market vesting conditions are included in assumptions in respect of
basis as expense in the consolidated statement of income.
the number of options that are expected to vest. At each balance sheet date,
we revise our estimates of the number of options that are expected to vest.
There will not be an impact on Adjusted EBITDA as a consequence of the
We recognize the impact of the revision to original estimates, if any, in the
adoption of this new standard.
consolidated statement of income, with a corresponding adjustment to
equity.
Operating cash flows will increase and financing cash flows will decrease by
approximately US$ 4 million, as repayment of the principal portion of the lease
The fair value of the share awards payments is determined at the grant date by
liabilities will be classified as cash flows from financing activities.
reference of the market value of the shares and recognized as an expense over
the vesting period.
We have applied the standard from the mandatory adoption date of January 1,
2019. We intend to apply the simplified transition approach and as a result, will
When options are exercised, we issue new common shares. The proceeds
not restate comparative amounts for the year prior to first adoption.
received net of any directly attributable transaction costs are credited to share
capital (nominal value) and share premium when the options are exercised.
Results of operations
Taxation
The following discussion is of certain financial and operating data for the
periods indicated. You should read this discussion in conjunction with our
The computation of our income tax expense involves the interpretation of
Consolidated Financial Statements and the accompanying notes.
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 2019 capital expenditure program. See “Item 4. Information on the
difficult to predict the ultimate outcome.
Company –B. Business Overview—2019 Strategy and Outlook.”
GeoPark 113
Year ended December 31, 2018 compared to year ended December 31, 2017
The following table summarizes certain of our financial and operating data for
the years ended December 31, 2018 and 2017.
For the year ended December 31
(in thousands of US$, except for percentages)
% Change
from
2018
2017
prior year
Revenue
Net oil sales
Net gas sales
Revenue
545,490
55,671
279,162
50,960
601,161
330,122
Commodity risk management contracts
16,173
Production and operating costs
(174,260)
Geological and geophysical expenses
Administrative expenses
Selling expenses
Depreciation
Write-off of unsuccessful
exploration efforts
Impairment loss reversed for
non-financial assets
Other operating expense
Operating profit
Financial expenses
Financial income
Foreign exchange loss
Profit before income tax
Income tax expense
Profit (Loss) for the year
Non-controlling interest
Profit (Loss) for the year attributable
to owners of the Company
Net production volumes
Oil (mbbl)(2)
Gas (mcf )(3)
Total net production (mboe)
Average net production (boepd)
Average realized sales price
Oil (US$ per bbl)
Gas (US$ per mmcf )
(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
foreign operations and the attendant royalty regimes. Oil production figures
Average unit costs per boe (US$)
presented on page F-75 are net of royalties.
(3) Corresponds to production measured after separation but prior to
compression, which is the measure we used to monitor business performance.
Gas production presented on page F-76 is gas measured at the point of
Operating cost
Royalties and other
Production costs(1)
Geological and geophysical expenses
delivery.
114 GeoPark 20F
Administrative expenses
Selling expenses
95%
9%
82%
(205)%
76%
81%
24%
254%
23%
(15,448)
(98,987)
(7,694)
(42,054)
(1,136)
(74,885)
(13,951)
(52,074)
(4,023)
(92,240)
(26,389)
(5,834)
352%
4,982
(2,887)
256,492
(39,321)
3,059
(11,323)
208,907
(106,240)
102,667
30,252
-
(5,088)
78,996
(53,511)
2,016
(2,193)
25,308
(43,145)
(17,837)
6,391
100%
(43)%
225%
(27)%
52%
416%
725%
146%
676%
373%
72,415
(24,228)
399%
11,113
12,219
13,150
36,027
8,309
10,562
10,069
27,586
53.0
5.1
8.2
5.8
14.0
1.1
4.2
0.3
36.6
5.3
7.4
3.0
10.4
0.8
4.4
0.1
34%
16%
31%
24%
46%
(4)%
11%
93%
35%
38%
-5%
200%
The following table summarizes certain financial and operating data.
For the year ended December 31,
(in thousands of US$)
2018
2017
Chile
Colombia
Brazil
Argentina
Peru
Other
Total
Chile
Colombia
Brazil
Other
Total
37,359
(28,203)
497,870
30,053
35,879
-
-
601,161
32,738
263,076
34,238
70
330,122
(42,721)
(10,395)
(10,640)
(245)
(36)
(92,240)
(23,730)
(40,010)
(10,809)
(336)
(74,885)
(12,670)
(6,134)
(2,020)
(583)
-
-
(21,407)
(546)
(1,625)
(2,978)
(685)
(5,834)
Revenue
Depreciation
Impairment
and write-off
Revenue
For the year ended December 31, 2018, crude oil sales were our principal
US$51.0 million for the year ended December 31, 2017 to US$55.7 million
source of revenue, with 91% and 9% of our total revenue from crude oil
for the year ended December 31, 2018 due to increased sales volumes, the
and gas sales, respectively. The following chart shows the change in oil and
addition of the acquired blocks in Argentina and higher realized prices.
natural gas sales from the year ended December 31, 2017 to the year ended
December 31, 2018.
The increase in 2018 net revenue of US$271.0 million is mainly explained by:
• an increase of US$234.8 million in sales in Colombia, due to higher realized
For the year ended December 31,
prices and increased deliveries;
(in thousands of US$)
• an increase of US$4.6 million in sales in Chile, due to higher realized prices;
• a decrease of US$4.2 million in gas sales in Brazil, primarily related to lower
2018
2017
gas prices;
• an increase of US$35.8 million in sales in Argentina from the acquired
545,490
55,671
blocks;
279,162
50,960
Revenue attributable to our operations in Colombia for the year ended
601,161
330,122
December 31, 2018 was US$497.9 million, compared to US$263.1 million for
the year ended December 31, 2017, representing 83% and 80% of our total
consolidated sales. The increase is related to an increase in oil deliveries from
Year ended December 31
Change from prior year
7.6 mmbbl to 10.0 mmbbl and an increase in the average realized price per
(in thousands of US$, except for percentages)
barrel of crude oil from US$36.1 per barrel to US$52.6 per barrel, primarily due
2018
2017
%
to higher reference international prices.
497,870
263,076
234,794
37,359
30,053
35,879
32,738
34,238
70
4,621
(4,185)
35,809
89%
14%
Revenue attributable to our operations in Chile for the year ended December
31, 2018 was US$37.4 million, a 14% increase from US$32.7 million for the year
(12)%
ended December 31, 2017, principally due to (1) increased average realized
51,156%
prices per barrel of crude oil from US$45.7 per barrel for the year December 31,
601,161
330,122
271,039
82%
2017 to US$62.3 per barrel for the year ended December 31, 2018 (an increase
of US$16.6 per barrel or a total of 36%), and (2) an increase in gas sales by
Consolidated
Sale of crude oil
Sale of gas
Total
By country
Colombia
Chile
Brazil
Argentina
Total
Revenue increased 82%, from US$330.1 million for the year ended December
US$3.1 million reflecting higher gas prices and higher deliveries, mainly as a
31, 2017 to US$601.1 million for the year ended December 31, 2018, primarily
result of the discovery of the Jauke gas field. This was partially offset by sales
as a result of higher realized prices and additional deliveries. Sales of crude
of crude oil of 0.2 mmbbl for the year ended December 31, 2018 compared
oil increased due to higher realized prices and higher sold volumes of 10.7
to 0.3 mmbbl for the year ended December 31, 2017 (a decrease of 20%) due
mmbbl in the year ended December 31, 2018 compared to 7.9 mmbbl in
to the decline in oil base production. The contribution to our revenue during
the year ended December 31, 2017, and resulted in net revenue of US$545.5
such years from our operations in Chile was 6%, respectively.
million for the year ended December 31, 2018 compared to US$279.2 million
for the year ended December 31, 2017. In addition, sales of gas increased from
GeoPark 115
Revenue attributable to our operations in Brazil for the year ended December
31, 2018 was US$30.0 million, a 12% decrease from US$34.2 million for the
year ended December 31, 2017, principally due to lower gas prices and
deliveries. The contribution to our revenue from our operations in Brazil
during the years ended December 31, 2018 and 2017 was 5% in each year.
Revenue attributable to our operations in Argentina, primarily from the
acquired blocks in Argentina, for the year ended December 31, 2018 was US$
35.9 million, representing 6% of our total consolidated sales. The average
realized price per barrel of crude oil increased from US$52.3 per barrel to
US$65.0 per barrel.
Production and operating costs
The following table summarizes our production and operating costs for the
years ended December 31, 2018 and 2017.
For the year ended December 31
(in thousands of US$, except for percentages)
% Change
from prior
2018
2017
year
Consolidated (including Colombia,
Chile, Argentina, Peru and Brazil)
Royalties
Staff costs
Operation and maintenance
Transportation costs
Well and facilities maintenance
Consumables
Equipment rental
Other costs
Total
(71,836)
(18,603)
(7,756)
(2,628)
(20,262)
(17,444)
(9,317)
(26,414)
(28,697)
(12,358)
(3,116)
(2,969)
(14,722)
(11,902)
(5,818)
(19,405)
(174,260)
(98,987)
150%
51%
149%
(11)%
38%
47%
60%
36%
76%
Year ended December 31
(in thousands of US$)
2018
2017
Chile
Brazil
Argentina
Colombia
Chile
Brazil
Argentina
Colombia
(1,473)
(6,521)
-
(1,250)
(4,095)
(1,712)
(287)
(6,561)
(21,899)
(2,820)
(386)
-
-
(1,286)
-
-
(4,293)
(8,785)
(4,833)
(3,167)
(2,877)
(120)
(6,044)
(1,018)
(1,269)
(5,715)
(62,710)
(8,529)
(4,879)
(1,258)
(8,837)
(14,714)
(7,761)
(9,845)
(1,314)
(5,582)
-
(1,211)
(3,817)
(1,680)
(59)
(7,336)
(3,134)
(241)
-
-
(2,982)
-
-
(4,380)
(13)
(190)
-
(80)
-
(12)
(53)
10
(24,236)
(6,345)
(3,116)
(1,678)
(7,923)
(10,209)
(5,706)
(7,700)
(25,043)
(118,533)
(20,999)
(10,737)
(338)
(66,913)
By country
Royalties
Staff costs
Operation and maintenance
Transportation costs
Well and facilities maintenance
Consumables
Equipment rental
Other costs
Total
116 GeoPark 20F
Consolidated production and operating costs increased 76%, from US$99.0
Administrative costs
million for the year ended December 31, 2017 to US$174.3 million for the year
ended December 31, 2018, primarily due to the new operation of the blocks
Year ended December 31
Change from prior year
in Argentina, higher royalties paid in cash, in line with increased production
(in thousands of US$, except for percentages)
and a higher royalty rate in Colombia, and increased operating costs related to
higher sales volumes.
Production and operating costs in Colombia increased 77%, to US$118.5
Colombia
Chile
Brazil
million for the year ended December 31, 2018, as compared to US$66.9 million
Argentina
for the year ended December 31, 2017, primarily due to higher royalties of
US$38.5 million, in line with increased production, a higher royalty rate and
Other
Total
higher oil prices. In addition, operating costs per boe in Colombia remained at
2018
2017
(24,910)
(17,567)
(7,343)
(5,671)
(2,628)
(2,847)
(6,331)
(2,444)
(2,057)
660
(184)
(790)
(16,018)
(13,655)
(2,363)
(52,074)
(42,054)
(10,020)
%
42%
(10)%
8%
38%
17%
24%
US$5.6 per boe for the year ended December 31, 2018.
Administrative costs increased 24%, from US$42.1 million for the year ended
December 31, 2017 to US$52.1 million for the year ended December 31, 2018,
Production and operating costs in Chile increased by 4% to US$21.9 million
mainly due to higher consultant fees and travel expenses for an amount of
due to higher staff costs expenses and pulling campaign. Costs per boe
US$3.3 million, higher staff costs for an amount of US$2.7 million and higher
increased to US$22.8 per boe from US$20.3 per boe in 2017. In the year ended
other expenses related to our growth strategy and new business.
December 31, 2018, the revenue mix for Chile was 46.6% oil and 53.4% gas,
whereas for the same period in 2017 it was 48.5% oil and 51.5% gas.
Selling expenses
Production and operating costs in Brazil decreased by 18%, to US$8.8 million
for the year ended December 31, 2018, as compared to the year ended
December 31, 2017, mainly resulting from non-recurring maintenance costs in
Colombia
Manati Field. Operating costs per boe decreased to US$6.1 for the year ended
Chile
December 31, 2018 from US$7.8 per boe for the year ended December 31,
Argentina
2017.
Total
Year ended December 31,
Change from prior year
(in thousands of US$, except for percentages)
2018
(1,028)
(533)
(2,462)
(4,023)
2017
(250)
(688)
(198)
(1,136)
(778)
155
(2,264)
(2,887)
%
311%
(23)%
1143%
254%
Production and operating costs in Argentina amounted to US$25.0 million
Selling expenses increased 254%, from US$1.1 million for year ended December
for the year ended December 31, 2018, mainly resulting from the operation
31, 2017 to US$4.0 million for the year ended December 31, 2018, primarily due
of the blocks we acquired in Neuquén. Operating costs per boe amounted to
to transportation costs and selling taxes in the Aguada Baguales, El Porvenir and
US$31.2 for the year ended December 31, 2018.
Puesto Touquet blocks in Argentina.
Geological and geophysical expenses
Commodity risk management contracts
Year ended December 31
Change from prior year
contracts for the year ended December 31, 2018 and a loss of US$15.4 million
(in thousands of US$, except for percentages)
for the year ended December 31, 2017. Realized losses reflect cash settled
We recorded a profit of US$16.2 million related to commodity risk management
%
transactions and unrealized losses reflect non-cash changes between the
contract values and the forward Brent oil curve.
Colombia
Chile
Brazil
Argentina
Other
Total
2018
(6,288)
(733)
(827)
(1,694)
(4,409)
(13,951)
2017
(2,231)
(858)
(1,007)
(22)
(3,576)
(7,694)
(4,057)
125
180
(1,672)
(833)
(6,257)
182%
(15)%
(18)%
7,600%
23%
81%
Geological and geophysical expenses increased 81%, from US$7.7 million
for the year ended December 31, 2017 to US$14.0 million for the year ended
December 31, 2018, primarily as the result of lower allocation to capitalized
Argentina
projects in Colombia due to: (i) decreased exploratory drilling activity levels
totalling US$4.1 million, (ii) the new operation of the blocks in Argentina
Other
Total
which increased US$1.7 million and (iii) a higher level of activities in Peru for an
amount of US$0.5 million.
Depreciation
Colombia
Chile
Brazil
Year ended December 31,
Change from prior year
(in thousands of US$, except for percentages)
2018
(42,721)
(28,203)
(10,395)
(10,640)
(281)
2017
(40,010)
(23,730)
(10,809)
(159)
(177)
(2,711)
(4,473)
414
(10,481)
(104)
(92,240)
(74,885)
(17,355)
%
7%
19%
(4)%
66%
59%
23%
GeoPark 117
Depreciation charges increased by 23% from US$74.9 million for the year ended
real in the 2017 and 2018 period. Foreign exchange differences are mainly
December 31, 2017 to US$92.2 million for the year ended December 31, 2018,
generated from changes in the value of the Brazilian real over the U.S. Dollar-
mainly due to the new operation of the blocks in Argentina and increased
denominated debt incurred at the local subsidiary level, where the functional
volumes. However, depreciation costs per boe decreased from US$7.9 to US$7.1
currency is the Brazilian real.
per boe due to drilling successes and increased reserves in Colombia.
Profit before income tax
Operating profit (loss)
Year ended December 31,
Change from prior year
(in thousands of US$, except for percentages)
2018
309,357
(29,139)
4,370
(6,739)
(21,357)
256,492
2017
116,290
(19,675)
4,434
(3,430)
(18,623)
78,996
193,067
(9,464)
(64)
(3,309)
(2,734)
%
Colombia
166%
48%
(1)%
96%
15%
Chile
Brazil
Argentina
Other
Total
177,496
225%
Colombia
Chile
Brazil
Argentina
Other
Total
Year ended December 31
Change from prior year
(in thousands of US$, except for percentages)
2018
305,409
(40,545)
(6,632)
(13,737)
(35,588)
208,907
2017
113,028
(32,801)
(2,529)
(4,845)
(47,545)
25,308
192,381
(7,744)
(4,103)
(8,892)
11,957
183,599
%
170%
24%
162%
184%
(25)%
725%
We recorded an operating profit of US$256.5 million for the year ended
of US$208.9 million, compared to a profit of US$25.3 million for the year ended
December 31, 2018, a 225% improvement from the operating profit of
December 31, 2017, primarily due to profits recorded in our Colombian operations.
US$79.0 million for the year ended December 31, 2017, primarily due to an
increase in revenue and other gains, as described above.
Income tax expense
Year ended December 31
Change from prior year
For the year ended December 31, 2018, we recorded a profit before income tax
In 2018, we recorded a write-off of unsuccessful exploration efforts of
2018
2017
US$26.4 million that corresponded to nine unsuccessful exploratory wells,
Colombia
(119,730)
(45,406)
(74,324)
four wells drilled in Colombia (Tiple, Llanos 34 and Llanos 32 Blocks), two
wells drilled in Brazil (POT-T-747 and POT-T-619 Blocks) and three wells
Chile
Brazil
drilled in Argentina (Puelen Block). The charge also included the write-off of
Argentina
a well and other exploration costs incurred in the Fell Block in previous years
Other
6,090
1,762
5,752
(114)
856
36
-
5,234
1,726
5,752
1,369
(1,483)
and other exploration costs incurred in the VIM-3 Block, and POT-T-882 and
Total
(106,240)
(43,145)
(63,095)
%
164%
611%
4,794%
100%
(108)%
146%
(in thousands of US$, except for percentages)
REC-T-93 Blocks, for which no additional work would be performed. This was
partially offset by a gain on non-cash impairments reversal of non-financial
assets amounting to US$5.0 million. This amount comprised: (i) US$11.5
million gain in Colombia, resulting from an improved oil price environment
Our effective tax rate was 51% for the year ended December 31, 2018, compared to
and the known fair value less costs of disposal of the La Cuerva and Yamu
170% in 2017. The decrease in the effective tax rate was primarily due to an increase in
Blocks; and (ii) US$6.5 million impairment loss due to the termination of the
profits recorded in our Colombian operations as compared to the other countries and
sales agreement for the TdF’s blocks, with no renovation in place as of the
the incorporation of the Argentine operations.
date of this annual report.
Financial costs
Profit (loss) for the year
Financial costs decreased 30% to US$36.3 million for the year ended December
Year ended December 31
Change from prior year
31, 2018 as compared to US$51.5 million for the year ended December 31,
2017, mainly due to one-time costs on the cancellation of 2020 Notes for an
amount of US$17.6 million recognized in 2017.
Foreign exchange (loss) gain
Colombia
Chile
Brazil
Foreign exchange variation increased from a loss of US$2.2 million for the year
Argentina
ended December 31, 2017 compared to a loss of US$11.3 million for the year
ended December 31, 2018, mainly due to the depreciation of the Brazilian
Other
Total
(in thousands of US$, except for percentages)
2018
185,679
(34,455)
(4,870)
(7,985)
2017
67,622
(31,945)
(2,493)
(4,845)
(35,702)
(46,176)
118,057
(2,510)
(2,377)
(3,140)
10,474
102,667
(17,837)
120,504
%
175%
8%
95%
65%
(23)%
(676)%
118 GeoPark 20F
For the year ended December 31, 2018, we recorded a net profit of US$102.7
million as a result of the reasons described above.
Profit for the year attributable to owners of the Company
For the year ended December 31
(in thousands of US$, except for percentages)
% Change
from
Profit for the year attributable to owners of the Company increased by 399%
2017
2016
prior year
to US$72.4 million, compared to a loss for the year ended December 31,
Revenue
2017 of US$24.2 million for the reasons described above. Profit attributable
Net oil sales
to non-controlling interest increased by 373% to US$30.3 million for the year
Net gas sales
ended December 31, 2018 as compared to a profit of US$6.4 million for the
Revenue
279,162
50,960
145,193
47,477
330,122
192,670
year ended December 31, 2017. In November 2018, we acquired all of LGI’s
Commodity risk management contracts
(15,448)
equity interest in GeoPark’s Chilean and Colombian subsidiaries.
Production and operating costs
Geological and geophysical expenses
Year ended December 31, 2017 compared to year ended December 31, 2016
Administrative expenses
The following table summarizes certain of our financial and operating data for
Selling expenses
the years ended December 31, 2017 and 2016.
Depreciation
(98,987)
(7,694)
(42,054)
(1,136)
(74,885)
(2,554)
(67,235)
(10,282)
(34,170)
(4,222)
(75,774)
92%
7%
71%
505%
47%
(25)%
23%
(73)%
(1)%
Write-off of unsuccessful exploration
efforts
Impairment loss reversed for
non-financial assets
Other operating expense
Operating profit (loss)
Financial costs
Foreign exchange (loss) gain
Profit (Loss) before income tax
Income tax expense
Loss for the year
Non-controlling interest
Loss for the year attributable
(5,834)
(31,366)
(81)%
-
(5,088)
78,996
(51,495)
(2,193)
25,308
(43,145)
5,664
(1,344)
(28,613)
(34,101)
13,872
(48,842)
(11,804)
(17,837)
(60,646)
6,391
(11,554)
(100)%
279%
(376)%
51%
(116)%
(152)%
266%
(71)%
(155)%
to owners of the Company
(24,228)
(49,092)
(51)%
Net production volumes
Oil (mbbl)(2)
Gas (mcf )(3)
Total net production (mboe)
Average net production (boepd)
Average realized sales price
Oil (US$ per bbl)
Gas (US$ per mmcf )
Average unit costs per boe (US$)
Operating cost
Royalties and other
Production costs(1)
Geological and geophysical expenses
Administrative expenses
Selling expenses
8,309
10,562
10,069
27,586
6,189
11,911
8,174
22,394
36.6
5.3
7.4
3.0
10.4
0.8
4.4
0.1
25.6
4.5
7.3
1.5
8.8
1.3
4.5
0.6
34%
(11)%
23%
23%
43%
18%
1%
100%
18%
(38)%
(2)%
(83)%
(1) Calculated pursuant to FASB ASC 932
(2) We present production figures before deduction of royalties, as we believe that net production before royalties is more appropriate in light of our foreign
operations and the attendant royalty regimes. Oil production figures presented on page F-75 are net of royalties.
(3) Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas
production presented on page F-76 is gas measured at the point of delivery.
GeoPark 119
The following table summarizes certain financial information and operating data.
Revenue
Depreciation
Impairment and write-off
Chile
Colombia
32,738
(23,730)
(546)
263,076
(40,010)
(1,625)
Brazil
34,238
(10,809)
(2,978)
Other
70
(336)
(685)
Revenue
For the year ended December 31,
(in thousands of US$)
2017
Total
330,122
(74,885)
(5,834)
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)
For the year ended December 31, 2017, crude oil sales were our principal
for the year ended December 31, 2016 to US$51.0 million for the year ended
source of revenue, with 85% and 15% of our total revenue from crude oil
December 31, 2017 due to increased sales volumes and higher realized prices.
and gas sales, respectively. The following chart shows the change in oil and
natural gas sales from the year ended December 31, 2016 to the year ended
The increase in 2017 net revenue of US$137.5 million is mainly explained by:
December 31, 2017.
• an increase of US$136.8 million in sales in Colombia, due to an increase in
price and volume;
For the year ended December 31,
• a decrease of US$4 million in sales in Chile, including decreases of US$2.9
(in thousands of US$)
million in oil sales and US$1.1 million of gas sales; and
• an increase of US$4.3 million in gas sales in Brazil, related to our Manati
2017
2016
operations;
279,162
50,960
145,193
all of which was due principally to higher oil and gas prices, as further
47,477
described below.
330,122
192,670
Revenue attributable to our operations in Colombia for the year ended
December 31, 2017 was US$263.1 million, compared to US$126.2 million for
Year ended December 31
the year ended December 31, 2016, representing 80% and 66% of our total
(in thousands of US$, except for percentages)
consolidated sales. The increase is related to an increase in oil deliveries from
% Change
5.4 mmbbl to 7.6 mmbbl and an increase in the average realized price per
from prior
barrel of crude oil from US$24.4 per barrel to US$36.1 per barrel, primarily
2017
2016
year
due 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
Consolidated
Sale of crude oil
Sale of gas
Total
By country
Colombia
Chile
Brazil
Other
Total
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
as a result of higher oil revenues. Sales of crude oil increased due to higher
of crude oil from US$37.0 per barrel for the year December 31, 2016 to
realized prices and higher sold volumes of 7.9 mmbbl in the year ended
US$45.7 per barrel for the year ended December 31, 2017 (an increase of
December 31, 2017 compared to 5.9 mmbbl in the year ended December
US$8.7 per barrel or a total of 24%). The increase in the average realized
31, 2016, and resulted in net revenue of US$279.2 million for the year ended
price per barrel was attributable to higher international reference prices. The
December 31, 2017 compared to US$145.2 million for the year ended
contribution to our revenue during such years from our operations in Chile
December 31, 2016. In addition, sales of gas increased from US$47.5 million
was 10% and 19%, respectively.
120 GeoPark 20F
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
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)
GeoPark 121
Consolidated production and operating costs increased 47%, from US$67.2
December 31, 2017, primarily as the result of higher allocation to capitalized
million for the year ended December 31, 2016 to US$99.0 million for the year
projects due to increased drilling activity levels.
ended December 31, 2017, primarily due to higher royalties paid in cash, in
line with increased production (the Jacana oil field accumulated more than 5
Administrative costs
mmbbl during the year ended December 31, 2017, triggering a higher royalty
rate in Colombia), and higher oil prices, and increased operating costs related
to higher sales volumes.
Year ended December 31,
(in thousands of US$, except for percentages)
Production and operating costs in Colombia increased 83%, to US$66.9 million
for the year ended December 31, 2017, as compared to US$36.6 million for the
2017
2016
year ended December 31, 2016, primarily due to (i) higher royalties of US$17.0
Colombia
(17,567)
(14,715)
(2,852)
million, 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 (ii) increased costs
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
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)
% Change
from prior
year
19%
(11)%
(21)%
70%
23%
Block. In addition, operating costs per boe in Colombia increased to US$5.6
Administrative costs increased 23%, from US$34.2 million for the year ended
per boe for the year ended December 31, 2017 from US$5.4 per boe for the
December 31, 2016 to US$42.1 million for the year ended December 31, 2017,
year ended December 31, 2016.
mainly due to higher staff costs and consulting fees resulting from an increased
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
Selling expenses
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
period in 2016 it was 51.1% oil and 48.9% gas.
scale of operations.
Production and operating costs in Brazil increased by 27%, to US$10.7 million
for the year ended December 31, 2017, as compared to the year ended
December 31, 2016, mainly resulting from non-recurring maintenance costs in
Colombia
Manati Field. Operating costs per boe increased to US$7.8 for the year ended
December 31, 2017 from US$5.8 per boe for the year ended December 31,
2016.
Geological and geophysical expenses
Chile
Brazil
Other
Total
Year ended December 31,
(in thousands of US$, except for percentages)
2017
(250)
(688)
-
(198)
(1,136)
2016
(2,830)
(994)
(20)
(378)
2,580
306
20
180
(4,222)
3,086
% Change
from prior
year
(91)%
(31)%
(100)%
(48)%
(73)%
Year ended December 31,
31, 2016 to US$1.1 million for the year ended December 31, 2017, primarily
(in thousands of US$, except for percentages)
due to the Trafigura offtake agreement as sales occur at the wellhead in our
% Change
Colombian operations, which are recorded as a discount to the oil price.
Selling expenses decreased 73%, from US$4.2 million for year ended December
Colombia
Chile
Brazil
Other
Total
2016
(2,231)
(858)
(1,007)
(3,598)
2015
(4,296)
(1,671)
(1,053)
(3,262)
(7,694)
(10,282)
from prior
year
Commodity risk management contracts
2,065
813
46
(336)
2,588
(48)%
(49)%
(4)%
10%
(25)%
We recorded a loss of US$15.4 million related to commodity risk management
contracts for the year ended December 31, 2017. Realized losses reflect cash
settled transactions and unrealized losses reflect non-cash changes between the
contract values and the forward Brent oil curve.
Depreciation
Depreciation charges decreased by 1% from US$75.8 million for the year ended
Geological and geophysical expenses decreased 25%, from US$10.3 million
December 31, 2016 to US$74.9 million for the year ended December 31, 2017,
for the year ended December 31, 2016 to US$7.7 million for the year ended
mainly due to lower production levels in Chile and Brazil. and lower depreciation
122 GeoPark 20F
costs per barrel in Colombia. Depreciation costs per boe decreased from US$9.9
For the year ended December 31, 2017, we recorded a profit before income
to US$7.9 per boe.
Operating profit (loss)
tax of US$25.3 million, compared to a loss of US$48.8 million for the year
ended December 31, 2016, primarily due to profits recorded in our Colombian
Year ended December 31,
operations.
(in thousands of US$, except for percentages)
Income tax (expense)
Colombia
Chile
Brazil
Other
Total
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)
% Change
from prior
year
270%
(56)%
(789)%
52%
Colombia
(28,613)
107,609
(376)%
We recorded an operating profit of US$79.0 million for the year ended
December 31, 2017, a 376% improvement from the operating loss of US$28.6
million for the year ended December 31, 2016, primarily due to an increase in
Chile
Brazil
Other
Total
Year ended December 31,
(in thousands of US$, 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)
% Change
from prior
year
279%
(60)%
(101)%
77%
266%
revenue and other gains and a decrease in certain expenses and depreciation, as
Income tax expense increased 266%, from US$11.8 million for the year ended
described above. In 2016, we recorded a gain on non-cash impairments reversal
December 31, 2016 to US$43.1 million for the year ended December 31, 2017,
of non-financial assets amounting to US$5.7 million in Colombia, resulting from
as a result of higher profits in Colombia.
an improved oil price environment and improvements in cost structure.
Loss for the year
Financial costs
Financial costs increased 51% to US$51.5 million for the year ended December
Year ended December 31,
31, 2017 as compared to US$34.1 million for the year ended December 31, 2016,
(in thousands of US$, except for percentages)
mainly due to one-time costs on the cancellation of 2020 Notes for an amount
of US$17.6 million.
Foreign exchange (loss) gain
Foreign exchange variation decreased from a gain of US$13.9 million for the
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 real
in the 2016 period and its depreciation in the 2017 period. Foreign exchange
differences are mainly generated from changes in the value of the Brazilian real
Colombia
Chile
Brazil
Other
Total
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
% Change
from prior
year
387%
(43)%
(142)%
107%
(71)%
over the U.S. Dollar-denominated debt incurred at the local subsidiary level,
For the year ended December 31, 2017, we recorded a net loss of US$17.8
where the functional currency is the Brazilian real.
million as a result of the reasons described above.
Profit (Loss) before income tax
Loss for the year attributable to owners of the Company
Year ended December 31,
Loss for the year attributable to owners of the Company decreased by 51% to
(in thousands of US$, except for percentages)
US$24.2 million, compared to a loss for the year ended December 31, 2016 of
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)
% Change
US$49.1 million for the reasons described above. Profit attributable to non-
from prior
controlling interest increased by 155% to US$6.4 million for the year ended
year
December 31, 2017 as compared to a loss of US$11.6 million for the year
ended December 31, 2016.
87,183
25,216
(11,291)
(26,958)
74,150
337%
(43)%
(129)%
106%
(152)%
GeoPark 123
B. Liquidity and capital resources
Overview
examine measures such as further capital expenditure program reductions,
pre-sale agreements, disposition of assets, or issuance of equity, among
Our financial condition and liquidity is and will continue to be influenced by a
others.
variety of factors, including:
• changes in oil and natural gas prices and our ability to generate cash flows
Capital expenditures
from our operations;
• our capital expenditure requirements;
In the past, we have funded our capital expenditures with proceeds from
equity offerings, credit facilities, debt issuances and pre-sale agreements,
• the level of our outstanding indebtedness and the interest we are obligated
as well as through cash generated from our operations. We expect to incur
to pay on this indebtedness; and
substantial expenses and capital expenditures as we develop our oil and
• changes in exchange rates which will impact our generation of cash flows
natural gas prospects and acquire additional assets. See “Item 4. Information
from operations when measured in US$, and the real.
on the Company –B. Business Overview—2019 Strategy and Outlook.”
Our principal sources of liquidity have historically been contributed
In the year ended December 31, 2018, we made total capital expenditures
shareholder equity, debt financings and cash generated by our operations. We
of US$124.7 million (US$97.0 million, US$8.0 million, US$9.0 million, US$8.5
have also in the past entered into offtake and prepayment agreements.
million and US$2.3 million in Colombia, Chile, Argentina, Peru and Brazil,
Since 2005 to 2018, we have raised approximately US$200 million in equity
respectively).
offerings at the holding company level and nearly US$1 billion through debt
In the year ended December 31, 2017, we made total capital expenditures of
arrangements with multilateral agencies such as the IFC, gas prepayment
US$105.6 million (US$80.0 million, US$10.2 million, US$8.2 million, US$3.6
facilities with Methanex, international bond issuances and bank financings,
million and US$3.6 million in Colombia, Chile, Argentina, Peru and Brazil,
described further below, which have been used to fund our capital
respectively).
expenditures program and acquisitions and to increase our liquidity.
Cash flows
In February 2014, we commenced trading on the NYSE and raised US$98
The following table sets forth our cash flows for the periods indicated:
million (before underwriting commissions and expenses), including the over-
allotment option granted to and exercised by the underwriters, through the
issuance of 13,999,700 common shares.
Year ended December 31,
(in thousands of US$)
In September 2017, we issued US$425.0 million aggregate principal amount
Operating activities
of senior notes due 2024. The Notes due 2024 mature on September 21,
Investing activities
2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year.
Financing activities
256,206
142,158
(164,594)
(105,604)
(97,641)
23,968
Interest on the Notes due 2024 is payable semi-annually in arrears on March
Net (decrease) increase in
Cash flows provided by (used in)
2018
2017
2016
82,884
(39,306)
(51,136)
21 and September 21 of each year. The Indenture governing our Notes due
cash and cash equivalents
(6,029)
60,522
(7,558)
2024 contains incurrence-based limitations on the amount of indebtedness
we can incur. This limits our capacity to incur additional indebtedness, other
Cash flows provided by operating activities
than permitted debt, as specified in the indenture governing the Notes
For the year ended December 31, 2018, cash provided by operating activities
due 2024. The net proceeds from the Notes due 2024 were used by us (i) to
was US$256.2 million, an 80% increase from US$142.2 million for the year
make a capital contribution to our wholly-owned subsidiary, GeoPark Latin
ended December 31, 2017, resulting from the increase in oil prices and
America Limited Agencia en Chile, providing it with sufficient funds to fully
deliveries in 2018 as compared to 2017, net of increased income taxes paid
repay the Notes due 2020 and to pay any related fees and expenses, including
predominantly from Colombia for an amount of US$60.8 million.
a call premium, and (ii) for general corporate purposes, including capital
expenditures, such as the acquisition of Aguada Baguales, El Porvenir and
For the year ended December 31, 2017, cash provided by operating activities
Puesto Touquet blocks in Neuquén Basin in Argentina, and to repay existing
was US$142.2 million, a 72% increase from US$82.9 million for the year
indebtedness, including the Itaú loan.
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
We believe that our current operations and 2019 capital expenditures program
December 2017 to Pluspetrol, as a security deposit related to the recently
can be funded from cash flow from existing operations and cash on hand.
announced acquisition of Aguada Baguales, El Porvenir and Puesto Touquet
Should our operating cash flow decline due to unforeseen events, including
blocks in Neuquén Basin in Argentina.
delivery restrictions or a protracted downturn in oil and gas prices, we would
124 GeoPark 20F
Cash flows used in investing activities
Notes due 2024
For the year ended December 31, 2018, cash used in investing activities was
US$164.6 million, a 56% increase from US$105.6 million for the year ended
General
December 31, 2017. This increase was related to the acquisition of the blocks
On September 21, 2017, we issued US$425.0 million aggregate principal
in Argentina for an amount of US$48.9 million and capital expenditures
amount of senior notes due 2024. The Notes due 2024 mature on September
related to development, appraisal and exploration activities.
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 arrears on
For the year ended December 31, 2017, cash used in investing activities was
March 21 and September 21 of each year.
US$105.6 million, a 169% increase from US$39.3 million for the year ended
December 31, 2016. This increase was related to higher capital expenditures
Ranking
in Colombia, Chile, Argentina and Peru in 2017 as compared to 2016.
The Notes due 2024 constitute senior unsubordinated obligations of GeoPark
Cash flows from financing activities
Limited, and are guaranteed by Geopark Chile S.A., Geopark Colombia Coöperatie
U.A. (the “Guarantors”). The Notes due 2024 rank equally in right of payment with
Cash from financing activities was US$24.0 million for the year ended
all existing and future senior obligations of GeoPark Limited and the Guarantors
December 31, 2017, compared to US$51.1 million used in financing
(except those obligations preferred by operation of law, including without
activities for the year ended December 31, 2016. This change was
limitation labor and tax claims); rank senior in right of payment to all existing
principally related to net proceeds from the issuance of 2024 Notes of
and future subordinated indebtedness of GeoPark Limited and the Guarantors;
US$418.3 million offset by principal paid of US$355.0 million related to the
and rank effectively junior to any secured obligations of GeoPark Limited, the
payment of 2020 Notes and the prepayment of the Itaú loan.
Guarantors and their respective subsidiaries to the extent of the value of the
Cash from financing activities was US$97.6 million for the year ended
December 31, 2018, compared to US$24.0 million used in financing
Optional redemption
collateral securing such obligations.
activities for the year ended December 31, 2017. This increase was
We may, at our option, redeem all or part of the Notes due 2024, at the
principally related to acquisition of the LGI non-controlling interest in
redemption prices, expressed as percentages of principal amount, set forth
Colombia and Chile’s equity interest for which we paid US$81.0 million. In
below, plus accrued and unpaid interest thereon (including additional
addition, we paid US$8.0 million for dividends to LGI prior to the acquisition
amounts), if any, to the applicable redemption date, if redeemed during the
and used US$1.8 million to purchase our own equity securities during 2018.
12-month period beginning on September 21 of the years indicated below:
Indebtedness
As of December 31, 2018 and 2017, we had total outstanding indebtedness
of US$447.0 million and US$426.2 million, respectively, as set forth in the
table below.
Year
2021
2022
2023 and after
Percentage
103.250%
101.625%
100.000%
As of December 31, (in thousands of US$)
Change of control
Bond GeoPark Limited (Notes due 2024)
BCI Loans (1)
Banco Santander
2018
2017
Upon the occurrence of certain events constituting a change of control, we
426,993
426,124
are required to make an offer to repurchase all outstanding Notes due 2024,
3
20,006
80
-
at a purchase price equal to 101% of the principal amount thereof plus any
accrued and unpaid interest (including any additional amounts payable in
Total
447,002
426,204
respect thereof ) thereon to the date of purchase. If holders of not less than
(1) Repaid in February 2019.
90% in aggregate principal amount of the outstanding Notes due 2024 validly
tender and do not withdraw such notes and we repurchase all such notes,
we may redeem the Notes due 2024 that remain outstanding following such
purchase at a price in cash equal to 101% of the principal amount thereof plus
Our material outstanding indebtedness as of December 31, 2018 is
accrued and unpaid interest to but excluding the date of such redemption.
described below.
Covenants
The Notes due 2024 contain customary covenants, which include, among
others, limitations on the incurrence of debt and disqualified or preferred stock,
restricted payments (including restrictions on our ability to pay dividends),
GeoPark 125
incurrence of liens, guarantees of additional indebtedness, the ability of certain
semi-annually, with final maturity in October 2020.
subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging
in certain businesses and merger or consolidation with or into another
Other Agreements
company.
In December 2015, we entered into an offtake and prepayment agreement with
Trafigura under which we sell and deliver a portion of our Colombian crude
In the event the Notes due 2024 receive investment-grade ratings from at least
oil production. Pricing will be determined by future spot market prices, net of
two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch,
transportation costs. The agreement also provided us with prepayment of up
and no default has occurred or is continuing under the indenture governing
to US$100 million from Trafigura. Funds committed will be made available to
the Notes due 2024, certain of these restrictions, including, among others, the
us upon request and will be repaid by us on a monthly basis through future oil
limitations on incurrence of debt and disqualified or preferred stock, restricted
deliveries over the period of the contract, which is 2.5 years, including a 6-month
payments (including restrictions on our ability to pay dividends), the ability of
grace period. According to the terms of the prepayment agreement, we are
certain subsidiaries to pay dividends, asset sales and certain transactions with
required to pay interest of LIBOR plus 5% per year on outstanding amounts. In
affiliates will no longer be applicable.
addition, under the prepayment agreement, we are required to maintain certain
coverage ratios linking: (i) future payments to the value of estimated future
The indenture governing our Notes due 2024 includes incurrence test
oil deliveries (net of transportation discounts) during the term of the offtake
covenants that provide, among other things, that, the net debt to EBITDA ratio
agreement and (ii) collections to payments within specified periods, with the
should not exceed (i) 3.50 until September 21, 2019, (ii) 3.25 from September
possibility of delivering additional volumes to meet such ratios in the upcoming
21, 2019 to September 21, 2021, and (iii) 3.00 thereafter until maturity, and the
3-month period. As of December 31, 2018, it was fully repaid.
EBITDA to interest ratio should exceed (i) 2.00 until September 21, 2019, (ii) 2.25
from September 21, 2019 to September 21, 2021 and (iii) 2.50 thereafter until
C. Research and development, patents and licenses, etc.
maturity. Failure to comply with the incurrence test covenants does not trigger
See “Item 4. Information on the Company——B. Business Overview” and “Item 4.
an event of default. However, this situation may limit our capacity to incur
Information on the Company—B. Business Overview—Title to Properties.”
additional indebtedness, as specified in the indenture governing the Notes due
2024, other than certain categories of permitted debt. We must test incurrence
D. Trend information
covenants before incurring additional debt or performing certain corporate
For a discussion of Trend information, see “—A. Operating Results—Factors
actions including but not limited to making dividend payments, restricted
affecting our results of operations” and “Item 4. Information on the Company
payments and others (in each case with certain specific exceptions).
–B. Business Overview—2019 Strategy and Outlook.”
Events of default
E. Off-balance sheet arrangements
Events of default under the indenture governing the Notes due 2024 include:
We did not have any off-balance sheet arrangements as of December 31, 2018
the nonpayment of principal when due; default in the payment of interest,
or as of December 31, 2017.
which continues for a period of 30 days; failure to make an offer to purchase
and thereafter accept tendered notes following the occurrence of a change
F. Tabular disclosure of contractual obligations
of control or as required by certain covenants in the indenture governing
In accordance with the terms of our concessions, we are required to pay
the Notes due 2024; cross payment default relating to debt with a principal
royalties in connection with our crude oil and natural gas production. See
amount of US$30.0 million or more, and cross-acceleration default following
Note 32.1 to our Consolidated Financial Statements.
a judgment for US$30.0 million or more; bankruptcy and insolvency events;
and invalidity or denial or disaffirmation of a guarantee of the notes. The
occurrence of an event of default would permit or require the principal of and
accrued interest on the Notes due 2024 to become or to be declared due and
payable.
Banco Santander
During October 2018, we executed a loan agreement with Banco Santander
for Brazilian Real 77,640,000 (equivalent to US$ 20,000,000 at the moment of
the loan execution) to repay an existing US$-denominated intercompany loan.
The interest rate applicable to this loan is the Interbank Certificate of Deposit
Rate (“CDI”) plus 2.25% per annum. CDI represents the average rate of all inter-
bank overnight transactions in Brazil. The principal and the interest are paid
126 GeoPark 20F
Directors, senior management and employees
The table below sets forth our committed cash payment obligations as of
December 31, 2018.
Debt obligations(1)
Operating lease obligations(2)
Pending investment commitments(3)
Asset retirement obligations
Total contractual obligations
Total
613,693
69,938
45,949
40,317
769,897
Less than one year
(in thousands of US$)
Three to five years
More than five years
One to three years
39,545
47,450
37,629
-
124,624
66,273
18,032
8,230
-
92,535
55,250
2,500
90
-
57,840
452,625
1,956
-
40,317
494,898
(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$39.5 million; one to three years: US$66.3 million and three to five years:
US$55.3 million. At December 31, 2018, 96% of the 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 the Isla Norte, Campanario and Flamenco
blocks in Chile of US$9.7 million, in the REC-T-94, POT-T-747, REC-T-128
and POT-T-785 blocks in Brazil of US$3.7 million, in the Sierra del Nevado,
CN-V and Los Parlamentos blocks in Argentina of US$8.3 million and in the
VIM-3 and Llanos 34 blocks in Colombia of US$24.2 million. See “Item 4.
Information on the Company—B. Business Overview—Our operations” and
Note 32.2 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 eight 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
2019.
The current members of the board of directors were appointed at our annual
general meeting held on July 27, 2018. The table below sets forth certain
information concerning our current board of directors. All ages are as of
March 31, 2019.
GeoPark 127
Name
Position
Gerald E. O’Shaughnessy
Chairman and Director
James F. Park
Chief Executive Officer, Deputy Chairman and Director
Carlos A. Gulisano
Juan Cristóbal Pavez (1)(2)
Robert Bedingfield (1)(2)
Pedro E. Aylwin Chiorrini
Jamie B. Coulter (2)
Constantine Papadimitriou (2) (3)
Director
Director
Director
Director, Director of Legal and Governance, Corporate Secretary
Director
Director
Age
At the Company since
70
63
68
48
70
59
78
58
2002
2002
2010
2008
2015
2003
2017
2018
(1) Member of the Audit Committee.
(2) Independent director under SEC Audit Committee rules.
(3) Member of the Audit Committee, appointed on March 6, 2019.
Science degree in 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
Biographical information of the current members of our board of directors is
oil and gas exploration company, in Guatemala. He remained a member of the
set forth below. Unless otherwise indicated, the current business addresses for
board of directors of Basic Resources International Limited until the company
our directors is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile.
was sold in 1997. Mr. Park is also a member of the board of directors of Energy
Holdings and has also been involved in oil and gas projects in North America,
Gerald E. O’Shaughnessy has been our Chairman and a member of our
South America, Europe, Middle East and Asia. Mr. Park is a member of the
board of directors since he co-founded the company in 2002. Following his
AAPG and SPE and has lived in 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
portfolio analyst at Moneda Asset Management. In 1998, he joined Santana,
of our board of directors since co-founding the Company in 2002. He has
an investment company, as Chief Executive Officer, where he focused mainly
more than 40 years of experience in all phases of the upstream oil and gas
on investments in capital markets and real estate. While at Santana, he was
business, with a strong background in the acquisition, implementation
appointed Chief Executive Officer of Laboratorios Andrómaco, one of Santana’s
and management of international projects and teams in North America,
main assets. In 1999, Mr. Pavez co-founded Eventures, an internet company.
South America, Asia, Europe and the Middle East. He received a Bachelor of
Since 2001, he has served as Chief Executive Officer at Centinela, a company
128 GeoPark 20F
with a diversified global portfolio of investments. Mr. Pavez is also a board
an active participant as an investor in North American shale plays during the
member of Grupo Security, Vida Security and Hidroelétrica Totoral. Over the
last ten years. Mr. Coulter currently serves as a Director of the Federal Law
last few years he has been a board member of several companies, including
Enforcement Foundation and is a member of the Board of Trustees for HCA
Quintec, Enaex, CTI and Frimetal.
Wesley Medical Center, and has previously served on a number of boards of
directors, including as a Director of Jimmy Johns LLC, Chairman of the Board
Robert Bedingfield has been a member of our board of directors since March
of the International Pizza Hut Franchise Holders’ Association, a member of the
2015. He holds a degree in Accounting from the University of Maryland and
Board of Advisors of The Wichita State University Center for Entrepreneurship
is a Certified Public Accountant. Until his retirement in June 2013, he was one
and a member of the Board of Trustees for the University of Kansas School of
of Ernst & Young’s most senior Global Lead Partners with more than 40 years
Business, among others.
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
Constantine Papadimitriou as been a member of our board of directors
Board. He has extensive experience serving Fortune 500 companies; including
since May 2018. He is a respected and successful international investor
acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin,
and businessman, with more than 30 years of investment experience in
AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US
global capital markets and in resource and industrial projects and was an
Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times
early investor in GeoPark. Mr. Papadimitriou is currently CEO of General
an Executive Committee Member, and the Audit Committee Chair of the
Oriental Investments S.A., the Investment Manager of the Cavenham Group
University of Maryland at College Park Board of Trustees. Mr. Bedingfield
of Funds. Previously, he was CEO of Cavamont Geneva. During his tenure
served on the National Executive Board (1995 to 2003) and National Advisory
at the Cavamont group, Mr. Papadimitriou was responsible for Treasury
Council (since 2003) of the Boy Scouts of America. Since 2013, Mr. Bedingfield
Management, the Private Equity Portfolio as well as representing the group
has also served as Board Member and Chairman of the Audit Committee of
on the Boards of associated companies including investments in the oil and
NYSE-listed Science Applications International Corp (SAIC).
gas, mining, real estate and gaming sectors (including Basic Petroleum, a
Pedro E. Aylwin Chiorrini has served as a member of our board of directors
of Diorasis International, a company focusing on investments in Greece and
since July 2013 and as our Director of Legal and Governance since April 2011.
the broader Balkans and he also chairs the Greek Language School of Geneva
From 2003 to 2006, Mr. Aylwin worked for us as an advisor on governance
and Lausanne. Mr Papadimitriou holds an Economics and Finance degree and
and legal matters. Mr. Aylwin holds a degree in law from the Universidad de
a post-graduate Diploma in European Studies from Geneva University.
Nasdaq-listed Guatemalan oil and gas company). He is also founding partner
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
Senior management
law firm Aylwin, Mendoza, Luksic, Valencia Abogados in Santiago, Chile, where
Our senior management is responsible for the management and
he represented mining, chemical and oil and gas companies in numerous
representation of our company. The table below sets forth certain information
transactions. From 2006 until 2011, he served as Lead Manager and General
concerning our senior management. All ages are as of March 31, 2019.
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.
Jamie B. Coulter is a well-respected businessman, who has spearheaded
the growth of a variety of businesses in diverse sectors. He holds a business
degree from Wichita State University and is a graduate of the Stanford
University Executive Program. Mr. Coulter currently serves as Managing
Member of Coulter Enterprises LLC., a private investment firm. Mr. Coulter
has been an investor in GeoPark since 2006. Mr. Coulter has more than 46
years of experience in the food retail and restaurant business, serving as Chief
Executive Officer of Lone Star Steakhouse & Saloon and having developed
and operated Pizza Hut and Kentucky Fried Chicken restaurants. Mr. Coulter
is a former Restaurants & Institutions CEO of the year. Mr. Coulter has
operating and investment experience in the oil and gas business, including
the founding of Sunburst Exploration, a US upstream oil and gas company
that he built throughout the 1980s and sold in 1994. Mr. Coulter also has been
GeoPark 129
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
Rodolfo Martín Terrado
Alberto Matamoros
Livia Valverde
Adriana La Rotta
Barbara Bruce
Marcela Vaca
Carlos Murut
Salvador Minniti
Horacio Fontana
Agustina Wisky
Guillermo Portnoi
Stacy Steimel
Chief Operating Officer
Director of Operations
Director for Argentina and Chile
Director for Brazil
Director of Connections
Director for Peru
Director for Colombia
Director of Reserves and Development
Director of Exploration
Director of Drilling and Workover
Director of Capacities and Culture
Director of New Business
Director of Shareholder Value
Age
At the Company since
63
41
59
49
44
47
41
56
62
50
62
64
61
42
43
59
2002
2010
2003
2006
2018
2014
2013
2018
2017
2012
2006
2007
2008
2002
2006
2017
Biographical information of the members of our senior management is set
on electrical submersible pump optimization, corrosion control, water
forth below. Unless otherwise indicated, the current business addresses for
handling and intelligent production systems.
members of our senior management is Nuestra Señora de los Ángeles 179,
Las Condes, Santiago, Chile.
Rodolfo Martín Terrado joined GeoPark in August 2018. Mr. Terrado has
over 20 years of experience in asset development and operations. Prior
Andrés Ocampo has served as our Chief Financial Officer since November
to joining GeoPark, Mr. Terrado worked for Petrolera Argentina San
2013. He previously served as our Director of Growth and Capital (from
Jorge and Chevron in different international operations, including in
January 2011 through October 2013), and has been with our company since
Argentina, the United States and Venezuela. Mr. Terrado previously led
July 2010. Mr. Ocampo graduated with a degree in Economics from the
heavy oil operations in Venezuela assets and his prior responsibilities
Universidad Católica Argentina. He has more than 16 years of experience in
include waterflooding, CO2 flooding and unconventionals. Mr. Terrado
business and finance. Before joining our company, Mr. Ocampo worked at
holds a Petroleum Engineering degree from ITBA and an MBA from IAE in
Citigroup and served as Vice President Oil & Gas and Soft Commodities at
Argentina.
Crédit Agricole Corporate & Investment Bank.
Alberto Matamoros has been our Director for Argentina and Chile since
Augusto Zubillaga has served as our Chief Operating Officer since May
March 2016 and Director for Chile since January 2015. He is an industrial
2015. He previously served in other management positions throughout
engineer and has an MBA, with more than 20 years of experience in the Oil
the Company including as Operations Director, Argentina Director and
& Gas industry. He started his career in the Argentinian oil company ASTRA,
Production Director. He previously served as our Production Director. He is
as a Production Engineer of La Ventana-Vizcacheras Block in the Province
a petroleum engineer with more than 23 years of experience in production,
of Mendoza (1997-2000). He then joined Chevron, where he worked as
engineering, well completions, corrosion control, reservoir management
a Production Engineer in El Trapial Block in the Province of Neuquén for
and field development. He has a degree in petroleum engineering from
three years. Later, he became a Field Engineering Manager, also for three
the Instituto Tecnológico de Buenos Aires. Prior to joining our company,
years, in Buenos Aires, and then moved to Kern County, California, to lead
Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. and Chevron
the production team. His experience in Chevron enabled him to manage
San Jorge S.A. At Chevron San Jorge S.A., he led multi-disciplinary teams
different technical and administrative teams, designing and executing
focused on improving production, costs and safety, and was the leader of
working plans focused in the optimization of resources. In 2014, he joined
the Asset Development Team, which was responsible for creating the field
GeoPark to be part of the Corporate Operation team before being selected
development plan and estimating and auditing the oil and gas reserves of
as the new Director for Chile. Matamoros holds a degree in Industrial
the Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron San
Engineering from the Universidad Nacional del Sur and an MBA in IAE, from
Jorge S.A. team that was responsible for identifying business opportunities
the Business School of Universidad Austral of Buenos Aires, Argentina.
and working with the head office on the establishment of best business
practices. He has authored several industry papers, including papers
Livia Valverde has been our Director for Brazil since 2018. Mrs. Valverde
130 GeoPark 20F
previously served as our Legal Manager and has been with us since 2013.
previously served as our Development Manager. Mr. Murut holds a master’s
She holds a law degree from the Catholic University of Salvador in Brazil
degree in petroleum geology from the University of Buenos Aires where he
and holds a Master´s Degree in Corporate Law from the Brazilian Institute
also undertook postgraduate studies in reservoir engineering, specializing
of Capital Markets – IBMEC and a MBA in Environmental Management from
in field exploitation. He also completed a Business Management
the Getulio Vargas Foundation. Mrs. Valverde has more than 17 years of
Development Program at Austral University. Mr. Murut has over 40 years of
experience in the oil and gas industry, and previously served as manager at
experience working for international and major oil companies, including
several international E&P companies based in Rio de Janeiro, where she was
YPF S.A., Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San
responsible for legal, environmental and regulatory matters.
Jorge S.A.
Adriana La Rotta has been our Director of Connections since November
Salvador Minniti has been our Director of Exploration since January 2012.
2018. Ms. La Rotta is a communications professional and award-winning
He previously served as our Exploration Manager. He holds a bachelor
journalist with broad experience in Latin America, Asia, and the United
degree in geology from National University of La Plata and has a graduate
States. For over six years she led the media relations strategy for the
degree from the Argentine Oil and Gas Institute in oil geology. Mr. Minniti
Americas Society/Council of the Americas, a New York-headquartered
has over 35 years of experience in oil exploration and has worked with YPF
business organization whose members are international corporations
S.A., Petrolera Argentina San Jorge S.A. and Chevron Argentina.
representing a broad range of industries. Previously she was a TV reporter
and anchor in her native Colombia and worked as a foreign correspondent
Horacio Fontana has been our Corporate Drilling Manager since March
in Brazil, the United States, Japan, and Hong Kong. She holds a BA in
2012. He previously served as our Engineer Manager. He holds a degree in
Journalism from Colombia’s Universidad Javeriana and a certificate in NGO
civil engineering from Rosario National University and is also a graduate
Management from Temple University-Japan.
from the Argentine Oil and Gas Institute, National University of Buenos
Aires, with a specialty in oilfield exploitation and an extensive background
Barbara Bruce has been our Director for Peru since June 2017. Ms. Bruce
in drilling operations. He has recently taken part in a Management
holds a degree in Geology from the Universidad Nacional de Ingeniería,
Development Program at IAE Business School of Austral University. Mr.
Lima, Peru, a Master’s degree in Reservoirs from Colorado School of Mines,
Fontana has over 31 years of drilling experience in major Argentine
USA and an MBA from Universidad Adolfo Ibañez, USA/Chile. Before joining
companies such as YPF S.A., Petrolera Argentina San Jorge and Chevron.
GeoPark, she previously worked with Occidental Petroleum in different
international operations, including in the Caño Limon field in Colombia
Agustina Wisky has worked with our Company since it was founded in
and the Dhurnal and Bhangali gas fields in Pakistan. Ms. Bruce later worked
November 2002. She is currently our Director of Capacities and Culture and
as deputy President of an offshore operation by Petrotech Peruana, joined
she previously has served in other management positions throughout the
Hunt Oil and as General Manager of Peru LNG, leading the construction and
Company as Director of People and Director of Business Management. Mrs.
startup of operation of Peru´s first LNG plant and managed the exploration
Wisky is a public accountant, and also holds a degree in human resources
venture of Hunt Oil in Madre de Dios, Peru.
from the Universidad Austral—IAE. She has 19 years of experience in the oil
industry. Before joining our Company, Mrs. Wisky worked at AES Gener and
Marcela Vaca has been our Director for Colombia since August 2012. Ms.
PricewaterhouseCoopers.
Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá,
Colombia, a Master’s Degree in commercial law from the same university
Guillermo Portnoi has worked with our Company since June 2006 and has
and an LLM from Georgetown University. She has served in the legal
been our Director of Business Management since May 2015 until December
departments of a number of companies in Colombia, including Empresa
2016 and is currently our Director of New Business. Previously, he also
Colombiana de Carbon Ltda (which later merged with INGEOMINAS), and
served as our Director of Administration and Finance. Mr. Portnoi is a public
from 2000 to 2003, she served as Legal and Administrative Manager at GHK
accountant and holds an MBA from Universidad Austral—IAE. He has more
Company Colombia. Prior to joining our Company in 2012, Ms. Vaca served
than 14 years of experience in the oil industry. Before joining our Company,
for nine years as General Manager of the Hupecol Group where she was
Mr. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers,
responsible for supervising all areas of the Company as well as managing
where he counted several major oil companies as his clients.
relationships with Ecopetrol, ANH, the Colombian Ministry of Mines and
Energy, the Colombian Ministry of Environment and other governmental
Stacy Steimel joined GeoPark in February 2017 as our Shareholder Value
agencies. At the Hupecol Group, Ms. Vaca was also involved in the
Director. Mrs. Steimel has more than 20 years of experience in the financial
structuring of the Hupecol Group’s asset development and sales strategy.
sector as Fund Manager and subsequently as regional CEO for PineBridge
Investments, ex-AIG Investments in Latin America. Before AIG, Mrs. Steimel
Carlos Murut has been our Director of Development since January 2012. He
held positions in the US Treasury Department and at the InterAmerican
GeoPark 131
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
May 7, 2018 and reflect discretionary cash bonus payment made based on
Texas at Austin and a BA from the College of William and Mary.
our performance in 2017. Additionally, Mr. Park´s compensation includes an
B. Compensation
annual equity award with an aggregate value equal to one year of base salary,
based on the previous year’s average share price, and with a three year vesting
Senior management and director compensation
period. Due to the foregoing, on May 7, 2018, Mr. Park was awarded 104,439
For the year ended December 31, 2018, we accrued or paid approximately
shares based on the 2017 average share price, and; on March 6, 2019, Mr. Park
US$4.6 million, in the aggregate, to the members of our board of directors
was awarded 52,049 shares, based on the 2018 average share price.
(including our executive directors) for their services in all capacities. During
this same period, we accrued or paid approximately US$11.0 million, in
Non-Executive Director Contracts
the aggregate, to the members of our senior management (excluding our
The current annual fees paid to our non-executive Directors correspond to
executive directors) for their services in all capacities. An amount of US$0.8
US$80,000 to be settled in cash and US$100,000 to be settled in stock, paid
million corresponds to the accrual or payment for discretionary bonus
quarterly in equal installments. In the event that a non-executive Director
cash payments granted to the Company’s executive directors based on the
serves as Chairman of any Board Committees, an additional annual fee
Company’s performance in 2018. Gerald E. O’Shaughnessy, James F. Park and
of US$20,000 applies. A Director who serves as a member of any Board
Pedro E. Aylwin Chiorrini are our executive directors.
Committees receives an annual fee of US$10,000. Total payment due shall
Executive Director Contracts
be calculated on an aggregate basis for Directors serving in more than one
Committee. The Chairman fee is not added to the member’s fee while serving
It is our current policy that executive directors enter into indefinite term
for the same Committee. Payments of Chairmen and Committee members’
contracts with the Company that may be terminated at any time by either
fees are made quarterly in arrears and settled in cash only.
party subject to certain notice requirements.
The following chart summarizes payments made to our non-executive
Gerald E. O’Shaughnessy has entered into a service contract with the
directors for the year ended December 31, 2018.
Company to act as Chairman at an annual salary of US$400,000. James F.
Park has entered into a service contract with the Company to act as Chief
Non-Executive Directors’
Executive Officer at an annual salary of US$800,000. They each also received
equity awards described below under “Equity Incentive Compensation.” Our
agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that
restrict them, for a period of 12 months following termination of employment,
from soliciting senior employees of the Company and, for a period of six
months following a termination of employment, from competing with the
Non-Executive Director
Juan Cristóbal Pavez (2)
Carlos Gulisano (3)
Robert Bedingfield (4)
Constantine Papadimitriou (5)
Jamie B. Coulter (6)
Fees in US$
110,000
110,000
110,000
45,000
75,000
Fees paid
in Common Shares (1)
7,596
7,596
7,596
2,761
7,596
Company.
Pedro E. Aylwin Chiorrini, who was appointed as an executive director in July
2013, has entered into a service contract with the Company to act as Director
of Legal and Governance, and as such has decided to forego his director fees.
He received in 2018 a salary of US$0.4 million and bonus of US$0.1 million for
his services as a member of senior management.
The following chart summarizes payments made to our executive directors for
the year ended December 31, 2018:
(1) The numbers in this column are equal to 33,145 Common Shares (which
amount equals to US$450,000).
(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) Member of the Audit Committee, appointed on March 6, 2019.
(6) Member of the Compensation Committee.
Cash
Payment in
Pension and retirement benefits
payment
shares
We do not maintain any defined benefit pension plans or any other retirement
Gerald E. O’Shaughnessy
Executive
Directors’ Fees
US$400,000
Bonus
—
programs for our employees or directors.
Bonus
—
Equity Incentive Compensation
James F. Park
US$800,000
US$695,506
US$800,000
Pedro E. Aylwin Chiorrini
US$26,000
—
—
Performance-Based Employee Long-Term Incentive Program
132 GeoPark 20F
Given the expiration of our Stock Awards Plan on November 3, 2018, in
Our executive directors, senior management and employees who have
December 2018, we adopted the 2018 Equity Incentive Plan (the “Plan”) to
received option awards or common share awards under the Stock Awards
motivate and reward those participating employees, directors, consultants
Plan authorize the Company to deposit any common shares they have
and advisors of our Group to perform at the highest level and to further the
received under this plan in our Employee Benefit Trust (“EBT”). The EBT is
best interests of the Company and our shareholders. The Plan is designed as
held to facilitate holdings and dispositions of those common shares by the
an omnibus plan, with a 10-year term, and encompasses all forms of equity
participants thereof. Under the terms of the EBT, each participant is entitled
incentive that the Company may wish to implement throughout such term.
to receive any dividends we may pay which correspond to their common
The maximum number of shares available for issuance under the Plan is
shares held by the trust, according to instructions sent by the Company to the
5,000,000 shares.
Stock Awards Plan
trust administrator. The trust provides that Mr. James F. Park is entitled to vote
all the common shares held in the trust. Although Mr. Park has voting rights
with respect to all the common shares held on the trust, Mr. Park disclaims
Under the Stock Awards Plan, the board of directors, or its designee, could
beneficial ownership over the shares in the trust as described under “-E. Share
award options or stock awards. An option confers the right to acquire a
Ownership.”
specified number of common shares of the Company at an exercise price
equal to the par value of the common shares subject to such an option. A
Value Creation Plan
performance share confers a conditional right to acquire a specified number of
On December 10, 2015, our Board of Directors approved a renewal of the
common shares for zero or nominal consideration, subject to the achievement
VCP for a new period of three years, with new awards granted on January 1,
of performance conditions and other vesting terms.
2016. Under the VCP, if as of December 31, 2018, our share price has increased
On December 17, 2014, we registered 3,435,600 shares with the U.S. SEC for
management) will receive awards with an aggregate value equal to 10% of
shares to be issued under the Stock Awards Plan. On December 12, 2018
the excess above the market capitalization threshold (12%) generated by this
we registered an additional 4,313,645 shares to be issued under such plan.
share price (assuming that our share capital remained at the same level as
The following table sets forth the common share awards granted to our
applicable at the time of establishment of the VCP: 59,535,614 shares). The
executive directors, management and employees under the Stock Awards Plan
VCP Performance Goals were satisfied and awards thereunder have therefore
commencing in 2008 through March 31, 2019.
vested. As per the terms of the VCP, (i) on January 2 2019, 50% of the vested
by 12% per year according to the plan conditions, VCP participants (key
Number of underlying
common shares
outstanding
817,600(1)
478,000(1)
379,500
490,000
1,619,105 (3)
104,439 (4)
200,000 (3)
52,049 (4)
Grant date
12/15/2010
12/15/2011
12/15/2012
12/31/2014
06/30/2016
05/07/2018
05/31/2018
03/06/2019
awards, representing 1,488,390 shares, was issued to participants (including
439,075 issued to directors involved in the performance of the Company), and
(ii) in January 2020, the remaining 50% of the awards will be issued. For further
Vesting date
Expiration date
details, see Note 30 to our consolidated financial statements. On January
12/15/2014
12/15/2015
12/15/2016
12/31/2017
06/30/2019
05/07/2021
06/30/2019
03/06/2022
12/15/2020
2, 2019, James F. Park received 193,491 shares; Mr. O’Shaughnessy received
12/15/2021
89,303 shares; Mr. Aylwin received 111,629 shares and Mr. Gulisano received
12/15/2022
44,652 shares due to the VCP issuance.
12/31/2022
06/30/2026
Non-Executive Director Plan
03/15/2022
In August 2014, our Board of Directors adopted the Non-Executive Director
06/30/2026
Plan in order to grant shares to non-executive directors as part of their
03/15/2023
compensation program for serving as directors. The Non-Executive Director
(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 ran from 2016 to 2018.
(4) James F. Park received these awards on May 5, 2018 and March 6, 2018,
respectively, as part of his long-term equity incentive compensation. For
further details, please see item 6.B.
Plan was amended and restated in October 2016, when additional 1,000,000
shares were registered as the maximum number of shares available to be
issued under this plan. 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
committee may award common shares, restricted share units and other share-
based awards that may be denominated or payable in common shares or
factors that influence the value of common shares.
Potential dilution resulting from Equity Incentive Compensation Plans
In accordance with the equity awards granted by the Company under its stock
GeoPark 133
awards plan, as of December 31, 2018 there were approximately five million
relating to our performance; (c) assessing the independence, objectivity
and five hundred thousand outstanding shares that had been awarded but
and effectiveness of our external auditors; (d) making recommendations for
which had not yet vested, representing approximately 9% of the total issued
the appointment, re-appointment and removal of our external auditors and
share capital as of that date.
C. Board practices
Overview
approving their remuneration and terms of engagement; (e) implementing
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
Our Board of Directors is responsible for establishing our listed company
expertise if it considers it necessary; and (g) reviewing our arrangements
goals, ensuring that the necessary resources are in place to achieve
for our employees to raise concerns about possible wrongdoing in financial
these goals and reviewing our management and financial performance.
reporting or other matters and the procedures for handling such allegations,
Our board of directors directs and monitors the company in accordance
and ensuring that these arrangements allow proportionate and independent
with a framework of controls, which enable risks to be assessed and
investigation of such matters and appropriate follow-up action.
managed through clear procedures, lines of responsibility and delegated
authority. Our board of directors also has responsibility for establishing
Compensation Committee
our core values and standards of business conduct and for ensuring that
The Compensation Committee is composed of three directors. The current
these, together with our obligations to our shareholders, are understood
members of the compensation committee are Mr. Juan Cristóbal Pavez
throughout the company.
(who serves as Chairman of the committee), Jamie B. Coulter and Mr. Carlos
Board composition
Gulisano.
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 27, 2018. 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 2019. 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).
Audit Committee
The Audit Committee is composed of three directors. As of 31 December 2018,
The Nomination Committee meets at least twice a year and its responsibilities
the members of the Audit Committee were Mr. Juan Cristóbal Pavez and Mr.
include: (a) reviewing the structure, size and composition of the board of
Robert Bedingfield (who currently serves as Chairman of the committee). On
directors and making recommendations to the board of directors in respect of
March 6, 2019 we appointed Constantine Papadimitriou to fill the vacancy.
any required changes; (b) identifying, nominating and submitting for approval
We have determined that Mr. Juan Cristóbal Pavez, Robert Bedingfield and
by the board of directors candidates to fill vacancies on the board of directors
Constantine Papadimitriou are independent, as such term is defined under
as and when they arise; (c) making recommendations to the board of directors
SEC rules applicable to foreign private issuers.
with respect to the membership of the Audit Committee and Compensation
The Audit Committee’s responsibilities include: (a) approving our financial
respect to the appointment of any director or executive officer or other officer
statements; (b) reviewing financial statements and formal announcements
other than the position of the Chairman and Chief Executive Officer and (d)
Committee in consultation with the chairman of each committee, and with
succession planning for directors and senior executives.
134 GeoPark 20F
Major shareholders and related party transactions
Technical Committee
E. Share ownership
The Technical Committee is composed of three directors along with the
As of March 15, 2019, members of our board of directors and our senior
Chief Operating Officer. The members of the Technical Committee are Mr.
management held as a group 21,769,498 of our common shares and 35.5% of
Carlos Gulisano (who serves as Chairman of the committee), Mr. Gerald
our outstanding share capital.
O´Shaughnessy, Mr. James F. Park and Mr. Augusto Zubillaga.
The Technical Committee’s responsibilities include: (a) overseeing the
of directors and senior management as of March 15, 2019.
The following table shows the share ownership of each member of our board
technical studies and evaluations of the Company’s properties and proposals
to acquire new properties and/or relinquish existing ones as well as reviewing
project plans; (b) reviewing the Annual Reserve Report, the Company’s
environmental programs and their effectiveness and the Company’s health
and safety program and its effectiveness; and (c) providing a forum for ideas
and solutions for the key technical people within the Company.
Disclosure Committee
(1) Shareholder
James F. Park(1)
Gerald E. O’Shaughnessy(2)
Juan Cristóbal Pavez(3)
Jamie B. Coulter
Pedro E. Aylwin Chiorrini
The Disclosure Committee is composed of Mr. James F. Park, Mr. Andrés
Carlos Gulisano
Ocampo, and certain other officers or managers per request.
The Disclosure Committee’s responsibilities include (a) review and approval of
Robert Bedingfield
Constantine Papadimitriou(4)
Augusto Zubillaga
filings with the SEC and press releases, (b) review of presentations to analysts,
Alberto Matamoros
investors and rating agencies and (c) establishment of disclosure controls and
Marcela Vaca
procedures.
Liability insurance
Barbara Bruce
Carlos Murut
Salvador Minniti
We maintain liability insurance coverage for all of our directors and officers,
Stacy Steimel
the level of which is reviewed annually.
D. Employees
Horacio Fontana
Agustina Wisky
Guillermo Portnoi
Livia Valverde
As of December 31, 2018, we had 457 employees, representing an increase of
Adriana La Rotta
13% from December 31, 2017.
Rodolfo Martín Terrado
Andrés Ocampo
Common
Percentage of outstanding
shares
8,084,760
7,032,619
2,970,725
1,524,150
332,488
204,542
94,058
22,761
*
*
*
*
*
*
*
*
*
*
*
*
*
*
common shares
13.2%
11.5%
4.8%
2.5%
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
The following table sets forth a breakdown of our employees by geographic
Sub-total senior management
segment for the periods indicated.
ownership of less than 1%
Total
1,503,395
21,769,498
2.5%
35.5%
Colombia
Chile
Brazil
Argentina
Peru
Corporate
Total
Year ended December 31,
2018
178
100
12
137
28
2
457
2017
180
102
12
92
19
-
2016
* Indicates ownership of less than 1% of outstanding common shares.
146
102
10
77
10
-
(1) Held directly and indirectly 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 reflect 1,573,800 of common
shares held as of March 15, 2019 in the employee benefit trust described
under “Item 6. Directors, Senior Management and Employees—B.
405
345
Compensation— Stock Awards Plan.” Although Mr. Park has voting rights
with respect to all the common shares held on the trust, Mr. Park disclaims
From time to time, we also utilize the services of independent contractors
beneficial ownership over 1,573,800 of these shares. 1,073,201 of Mr. Park’s
to perform various field and other services as needed. As of December 31,
2018, 58 of our employees were represented by labor unions or covered
by collective bargaining agreements. We believe that relations with our
shares have been pledged pursuant to lending arrangements.
(2) Held directly and indirectly through GP Investments LLP, GPK Holdings
LLC, The Globe Resources Group, Inc. and other investment vehicles.
employees are satisfactory.
GeoPark 135
5,350,000 of these common shares have been pledged pursuant to lending
We have entered into the following transactions with related parties:
arrangements.
(3) Held through Socoservin Overseas Ltd, which is controlled by Juan
Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez
include 92,921 common shares held by him personally.
(4) Due to Constantine Papadimitriou´s position as CEO of General Oriental
Investments S.A., he may be deemed to have beneficial ownership over an
LGI Chile Shareholders’ Agreements
In November 2018, we acquired all of LGI’s equity interest in GeoPark’s
Chilean and Colombian subsidiaries.
additional 2,082,605 shares held by Cavenham Group of Funds.
Pursuant to the sale and purchase agreement entered into on November
28, 2018 (the “LGI Termination Agreement”), we agreed to pay LGI a total
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
consideration of up to US$126 million for its entire equity interest in Geopark
A. Major shareholders
Chile, Geopark TdF and Geopark Colombia Coöperatie U.A. The acquisition
price includes a fixed payment of US$81 million paid at closing, plus two
The following table presents the beneficial ownership of our common shares
equal installments of US$15 million each, to be paid in June 2019 and June
as of March 15, 2019, except for certain shareholders whose last public
2020, respectively, and three contingent payments of US$5 million each,
available data is as of December 31, 2018, as noted below:
which could accrue over the next three years, subject to certain production
Common
Percentage of outstanding
LGI Termination Agreement we have become sole shareholder of the entities
thresholds being exceeded in the Llanos 34 Block. As a consequence of the
Shareholder
James F. Park(1)
Gerald E. O’Shaughnessy(2)
Manchester Financial Group, L.P.(3)
Compass Group LLC(4)
Renaissance Technologies
Holdings Corporation(5)
Other shareholders
Total
shares
8,084,760
7,032,619
5,246,296
3,899,301
3,527,000
33,525,273
61,315,249
common shares
referred to above. The LGI Chile Shareholders’ Agreement, the LGI Colombia
Shareholders’ Agreement and the LGI line credit, each described in our annual
report on the 20-F for the fiscal year ended December 31, 2017 were also
terminated.
13.2%
11.5%
8.6%
6.4%
Executive Directors’ Service Agreements
5.8%
We have entered into service contracts with certain of our executive
54.5%
directors. See “Item 6. Directors, Senior Management and Employees—B.
100.0%
Compensation—Executive compensation—Director Contracts.”
(1) See Footnote (1) to the share ownership table included in Item 6.E above.
(2) See Footnote (2) to the share ownership table included in Item 6.E above.
(3) Held directly and indirectly through Manchester Financial Group, L.P.,
Manchester Financial Group, Inc., Douglas F. Manchester and Papa Doug Trust
u/t/d/ January 11, 2010. This information is as of December 31, 2018.
(4) The information set forth above and listed in the table is as of December 31,
2018 and based solely on the disclosure set forth in Compass Group LLC’s most
recent Schedule 13F filed with the SEC on February 6, 2019.
(5) Held directly and indirectly through Renaissance Technologies LLC and
Renaissance Technologies Holdings Corporation. This information is as of
December 31, 2018 and based solely on the disclosure set forth in the most
For further information relating to our related party transactions and balances
outstanding as of December 31, 2018, 2017 and 2016, please see Note 33 to
our Consolidated Financial Statements.
C. Interests of Experts and Counsel
Not applicable.
ITEM 8. FINANCIAL INFORMATION
A. Consolidated statements and other financial information
recent Schedule 13G filed with the SEC on February 12, 2019.
Financial statements
See “Item 18. Financial Statements,” which contains our audited financial
Principal shareholders do not have any different or special voting rights in
statements prepared in accordance with IFRS.
comparison to any other common shareholder.
Legal proceedings
According to our transfer agent, as of March 15, 2019, we had 19 registered
From time to time, we may be subject to various lawsuits, claims and
shareholders, out of which 6 are registered as U.S. shareholders. Since some
proceedings that arise in the normal course of business, including
of the shares are held by nominees, the number of shareholders may not be
employment, commercial, environmental, safety and health matters. For
representative of the number of beneficial owners.
example, from time to time, we receive notice of environmental, health and
B. Related party transactions
136 GeoPark 20F
safety violations. It is not presently possible to determine whether any such
matters will have a material adverse effect on our consolidated financial
position and results of operations.
In Brazil, GeoPark Brasil is a party to a class action filed by the Federal
consequently, your only opportunity to achieve a return on your investment
Prosecutor’s Office regarding a concession agreement of exploratory Block
is if the price of our stock appreciates” and “—We are a holding company
PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil
dependent upon dividends from our subsidiaries, which may be limited by
and gas bidding round held in November 2013. The Brazilian Federal Court
law and by contract from making distributions to us, which would affect our
issued an injunction against the ANP and GeoPark Brasil in December 2013
financial condition, including the ability to pay dividends on the common
that prohibited GeoPark Brasil’s execution of the concession agreement
shares,” as well as “Item 10. Additional Information—B. Memorandum of
until the ANP conducted studies on whether drilling for unconventional
association and bye-laws.”
resources would contaminate the dams and aquifers in the region. On July
17, 2015, GeoPark Brasil, at the instruction of the ANP, signed the concession
B. Significant changes
agreement, which included a clause prohibiting GeoPark Brasil from
conducting unconventional exploration activity in the area. Despite the
A discussion of the significant changes in our business can be found under
clause containing the prohibition, the judge in the case concluded that the
“Item 4. Information on the Company—B. Business Overview.”
concession agreement should not be executed. Thus, GeoPark Brasil requested
that the ANP comply with the decision and annul the concession agreement,
ITEM 9. THE OFFER AND LISTING
which the ANP´s Board did on October 9, 2015. The annulment reverted the
status of all parties to the status quo ante, which maintains GeoPark Brasil’s
A. Offering and listing details
right to the block.
Not applicable.
Dividends and dividend policy
B. Plan of distribution
Holders of common shares will be entitled to receive dividends, if any, paid on
Not applicable.
the common shares.
C. Markets
We have never declared or paid any cash dividends on our common shares.
Our common shares have been listed on the NYSE under the symbol “GPRK”
We intend to retain all of our future earnings, if any, generated by our
since February 7, 2014.
operations for the development and growth of our business. Accordingly, we
do not expect to pay cash dividends on our common shares in the foreseeable
D. Selling shareholders
future. Because we are a holding company with no direct operations, we will
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
E. Dilution
us from paying dividends. We have recorded accumulated losses amounting
Not applicable.
to US$206.7 million as of December 31, 2018, which further limits our ability to
pay dividends in the foreseeable future.
F. Expenses of the issue
Not applicable.
Under the Bermuda Companies Act, we may not declare or pay a dividend
if there are reasonable grounds for believing that we are, or would after the
ITEM 10. ADDITIONAL INFORMATION
payment be, unable to pay our liabilities as they become due or that the
realizable value of our assets would thereafter be less than our liabilities. We
A. Share capital
do not presently have any reasonable grounds for believing that, if we were
Not applicable.
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
B. Memorandum of association and bye-laws
realizable value of our assets would thereafter be less than our liabilities.
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
Additionally, any decision to pay dividends in the future, and the amount
to, all of the provisions of our memorandum of association and bye-laws.
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
General
operations, financial condition, cash requirements, prospects and other
We are an exempted company with limited liability incorporated under the laws
factors. See “Item 3. Key Information—D. Risk factors—Risks related to our
of Bermuda with registration number 33273 from the Registrar of Companies.
common shares—We have never declared or paid, and do not intend to
The rights of our shareholders will be governed by Bermuda law and by our
pay in the foreseeable future, cash dividends on our common shares, and,
memorandum of association and bye-laws. Bermuda company law differs
GeoPark 137
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
Act also imposes a duty on directors of a Bermuda company, to act honestly
preference on any outstanding preference shares.
and in good faith, with a view to the best interests of the company, and to
Board composition
exercise the care, diligence and skill that a reasonably prudent person would
Our bye-laws provide that our board of directors will determine the
exercise in comparable circumstances. In addition, the Bermuda Companies
maximum size of the board, provided that it shall be not be composed of
Act imposes various duties on directors with respect to certain matters of
management and administration of the company.
138 GeoPark 20F
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
directors in defending any civil or criminal proceeding against them on the
The duty of care requires that directors act in an informed and deliberate
condition that the officers and directors repay the monies if any allegation
manner and to inform themselves, prior to making a business decision, of
of fraud or dishonesty is proved against them provided, however, that, if
all relevant material information reasonably available to them. The duty of
the Bermuda Companies Act requires, an advancement of expenses shall be
care also requires that directors exercise care in overseeing the conduct of
made only upon delivery to the Company of an undertaking, by or on behalf
corporate employees. The duty of loyalty is the duty to act in good faith, not
of such indemnitee, to repay all amounts so advanced if it shall ultimately
out of self-interest, and in a manner which the director reasonably believes
be determined by final judicial decision from which there is no further
to be in the best interests of the shareholders. A party challenging the
right to appeal that such indemnitee is not entitled to be indemnified for
propriety of a decision of a board of directors bears the burden of rebutting
such expenses under this Bye-law or otherwise. Our bye-laws provide that
the presumptions afforded to directors by the “business judgment rule.” If
the company and the shareholders waive all claims or rights of action that
the presumption is not rebutted, the business judgment rule attaches to
they might have, individually or in right of the company, against any of the
protect the directors and their decisions. Where, however, the presumption is
company’s directors or officers for any act or failure to act in the performance
rebutted, the directors bear the burden of demonstrating the fairness of the
of such director’s or officers’ duties, except with respect to any fraud or
relevant transaction. Notwithstanding the foregoing, Delaware courts subject
dishonesty, or to recover any gain, personal profit or advantage to which such
directors’ conduct to enhanced scrutiny in respect of defensive actions taken
director is not legally entitled.
in response to a threat to corporate control and approval of a transaction
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
meeting of shareholders each calendar year, unless the shareholders in
Pursuant to our bye-laws, a director shall declare the nature of his interest in
a general meeting, elect to dispense with the holding of annual general
any contract or arrangement with the company as required by the Bermuda
meetings. Under Bermuda law and our bye-laws, a special general meeting of
Companies Act. A director so interested shall not, except in particular
shareholders may be called by the board of directors and may be called upon
circumstances set out in our bye-laws, be entitled to vote or be counted in the
the requisition of shareholders holding not less than 10% of the paid-up capital
quorum at a meeting in relation to any resolution in which he has an interest,
of the company carrying the right to vote at general meetings of shareholders.
which is to his knowledge, a material interest (otherwise than by virtue of
his interest in shares or debentures or other securities of or otherwise in or
Our bye-laws provide that, at any general meeting of the shareholders, the
through the company). A director will be liable to us for any secret profit
presence in person or by proxy of two or more shareholders representing in
realized from the transaction. In contrast, under Delaware law, such a contract
excess of 50% of the total issued voting shares of the company shall constitute
or arrangement is voidable unless it is approved by a majority of disinterested
a quorum for the transaction of business unless the company only has one
directors or by a vote of shareholders, in each case if the material facts as to
shareholder, in which case such shareholder shall constitute a quorum. Unless
the interested director’s relationship or interests are disclosed or are known to
otherwise required by law or by our bye-laws, shareholder action requires a
the disinterested directors or shareholders, or such contract or arrangement
resolution adopted by a majority of votes cast by shareholders at a general
is fair to the corporation as of the time it is approved or ratified. Additionally,
meeting at which a quorum is present.
such interested director could be held liable for a transaction in which such
director derived an improper personal benefit.
GeoPark 139
Shareholder proposals
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,
vote in person or by proxy at any general meeting of the shareholders in
a company cannot purchase its own shares if there are reasonable grounds for
accordance with the provisions of the bye-laws. Under Bermuda law, in the
believing that the company is, or after the repurchase would be, unable to pay
event of an amalgamation or merger of a Bermuda company with another
its liabilities as they become due.
company or corporation, a shareholder who did not vote in favor of the
amalgamation or merger and who is not satisfied that fair value has been
Shareholder suits
offered for such shareholder’s shares may, within one month of the notice
Class actions and derivative actions are generally not available to
140 GeoPark 20F
shareholders under Bermuda law. The Bermuda courts, however, would
arrangement with the company. Our bye-laws further provide that a director
ordinarily be expected to permit a shareholder to commence an action
so interested shall not, except in particular circumstances, be entitled to
in the name of a company to remedy a wrong to the company where
vote or be counted in the quorum at a meeting in relation to any resolution
the act complained of is alleged to be beyond the corporate power of
in which he has an interest, which is to his knowledge, a material interest
the company or illegal, or would result in the violation of the company’s
(otherwise than by virtue of his interest in shares or debentures or other
memorandum of association or bye-laws. Furthermore, consideration
securities of or otherwise in or through the company). A director will be
would be given by a Bermuda court to acts that are alleged to constitute
liable to us for any secret profit realized from the transaction. See “Item
a fraud against the minority shareholders or where an act requires the
10—B. Memorandum of association 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
fiduciary duty, except in respect of any fraud or dishonesty of such director
Bermuda company who did not vote in favor of the amalgamation or merger
or officer.
and who is 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
Comparison of Bermuda law to Delaware corporate law
Supreme Court of 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
admission of its common shares on AIM. Because the following statements
of the company or illegal, or would result in the violation of the company’s
are summaries, they do not discuss all aspects of Bermuda law that may be
memorandum of association or bye-laws. When the affairs of a company
relevant to us and our shareholders.
are being conducted in a manner which is oppressive or prejudicial to
the interests of some part of the shareholders, one or more shareholders
Interested Directors. Under our bye-laws and the Bermuda Companies
may apply for an order of the Supreme Court of Bermuda regulating the
Act, a director shall declare the nature of his interest in any contract or
conduct of the company’s affairs in the future or an order to purchase the
GeoPark 141
shares of any shareholders by other shareholders or by the company and,
incorporated in the United States.
in the case of a purchase by the company, for the reduction accordingly
of the company’s capital, or otherwise. See “Item 10—B. Memorandum of
Tax matters. Under current Bermuda law, we are not subject to tax on income
association and bye-laws—Shareholder Suits.”
or capital gains. We have received from the Minister of Finance under The
Exempted Undertaking Tax Protection Act 1966, as amended, an assurance
Our bye-laws contain a provision by virtue of which we and our shareholders
that, in the event that Bermuda enacts legislation imposing tax computed
waive any claim or right of action that they have, both individually and on
on profits, income, any capital asset, gain or appreciation, or any tax in the
our behalf, against any director or officer in relation to any action or failure to
nature of estate duty or inheritance, then the imposition of any such tax shall
take action by such director or officer, including the breach of any fiduciary
not be applicable to us or to any of our operations or shares, debentures
duty, except in respect of any fraud or dishonesty of such director or officer.
or other obligations, until March 31, 2035. We could be subject to taxes in
Class actions and derivative actions generally are available to shareholders
Bermuda after that date. This assurance is subject to the provision that it is
under Delaware law for, among other things, breach of fiduciary duty,
not to be construed to prevent the application of any tax or duty to such
corporate waste and actions not taken in accordance with applicable law. In
persons as are ordinarily resident in Bermuda or to prevent the application
such actions, the court has discretion to permit the winning party to recover
of any tax payable in accordance with the provisions of the Land Tax Act
attorneys’ fees incurred in connection with such action.
1967 or otherwise payable in relation to any property leased to us. We are
incorporated in Bermuda as an exempted company and pay annual Bermuda
Indemnification of Directors. We may indemnify our directors and officers in
government fees. In addition, all entities employing individuals in Bermuda
their capacity as directors or officers for any loss arising or liability attaching
are required to pay a payroll tax and there are other sundry taxes payable,
to them by virtue of any rule of law in respect of any negligence, default,
directly or indirectly, to the Bermuda government. Neither we nor our
breach of duty or breach of trust of which a director or officer may be
Bermuda subsidiaries employ individuals in Bermuda as at the date of this
guilty in relation to the company other than in respect of his own fraud or
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, to
the general public without charge. A company is required to maintain its
repay all amounts if it shall ultimately be determined by final decision that
share register in Bermuda but may, subject to the provisions of the Bermuda
such indemnitee is not entitled to be indemnified for such expenses under
Companies Act, establish a branch register outside of Bermuda. Bermuda
our Bye-laws or otherwise. Under Delaware law, a corporation may indemnify
law does not, however, provide a general right for shareholders to inspect or
a director or officer of the corporation against expenses (including attorneys’
obtain copies of any other corporate records.
fees), judgments, fines and amounts paid in settlement actually and
reasonably incurred in defense of an action, suit or proceeding by reason of
Registrar or transfer agent
such position if such director or officer acted in good faith and in a manner
A register of holders of the common shares is maintained by Coson Corporate
he or she reasonably believed to be in or not opposed to the best interests
Services Limited in Bermuda, and a branch register is maintained in the
of the corporation and, with respect to any criminal action or proceeding,
United States by Computershare Trust Company, N.A., who serves as branch
such director or officer had no reasonable cause to believe his or her conduct
registrar and transfer agent.
was unlawful. In addition, we have entered into customary indemnification
agreements with our directors.
Enforcement of Judgments
As a result of these differences, investors could have more difficulty
under the laws of Bermuda, and substantially all of our assets are located
protecting their interests than would shareholders of a corporation
in Colombia, Chile, Brazil, Argentina and Peru. In addition, most of our
We are incorporated as an exempted company with limited liability
142 GeoPark 20F
directors and executive officers reside outside the United States, and all or
Our bye-laws contain provisions whereby we and our shareholders waive
a substantial portion of the assets of such persons are located outside the
any claim or right of action that we have, both individually and on our behalf,
United States. As a result, it may be difficult for investors to effect service of
against any director or officer in relation to any action or failure to take action
process on those persons in the United States or to enforce in the United
by such director or officer, except in respect of any fraud or dishonesty of
States judgments obtained in U.S. courts against us or those persons based
such director or officer. We may also indemnify our directors and officers
on the civil liability provisions of the U.S. securities laws.
in their capacity as directors and officers for any loss arising or liability
There is no treaty in force between the United States and Bermuda providing
default, breach of trust of which a director or officer may be guilty in relation
for the reciprocal recognition and enforcement of judgments in civil
to the company other than in respect of his own fraud or dishonesty. We
and commercial matters. As a result, whether a U.S. judgment would be
have entered into customary indemnification agreements with our directors.
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
on whether the U.S. court that entered the judgment is recognized by the
No treaty exists between the United States and Chile for the reciprocal
Bermuda court as having jurisdiction over us or our directors and officers, as
recognition and enforcement of foreign judgments. Chilean courts, however,
determined by reference to Bermuda conflict of law rules and the judgment
have enforced valid and conclusive judgments for the payment of money
is not contrary to public policy in Bermuda, has not been obtained by fraud
rendered by competent U.S. courts by virtue of the legal principles of
in proceedings contrary to natural justice and is not based on an error
reciprocity and comity, subject to review in Chile of the U.S. judgment in
in Bermuda law. A judgment debt from a U.S. court that is final and for a
order to ascertain whether certain basic principles of due process and public
sum certain based on U.S. federal securities laws will not be enforceable in
policy have been respected, without retrial or review of the merits of the
Bermuda unless the judgment debtor had submitted to the jurisdiction of
subject matter. If a U.S. court grants a final judgment, enforceability of this
the U.S. court, and the issue of submission and jurisdiction is a matter of
judgment in Chile will be subject to obtaining the relevant exequatur (i.e.,
Bermuda (not U.S.) law.
recognition and enforcement of the foreign judgment) according to Chilean
civil procedure law in effect at that time, and depending on certain factors
An action brought pursuant to a public or penal law, the purpose of which is
(the satisfaction or non-satisfaction of which would be determined by the
the enforcement of a sanction, power or right at the instance of the state in
Supreme Court of Chile). Currently, the most important of such factors are:
its sovereign capacity, may not be entertained by a Bermuda court. Certain
the existence of reciprocity (if it can be proved that there is no reciprocity
remedies available under the laws of U.S. jurisdictions, including certain
in the recognition and enforcement of the foreign judgment between the
remedies under U.S. federal securities laws, may not be available under
United States and Chile, that judgment would not be enforced in Chile); the
Bermuda law or enforceable in a Bermuda court, as they may be contrary
absence of any conflict between the foreign judgment and Chilean laws
to Bermuda public policy. Further, no claim may be brought in Bermuda
(excluding for this purpose the laws of civil procedure) and Chilean public
against us or our directors and officers in the first instance for violations
policy; the absence of a conflicting judgment by a Chilean court relating
of U.S. federal securities laws because these laws have no extraterritorial
to the same parties and arising from the same facts and circumstances;
jurisdiction under Bermuda law and do not have force of law in Bermuda. A
the Chilean court’s determination that the U.S. courts had jurisdiction, that
Bermuda court may, however, impose civil liability on us or our directors and
process was appropriately served on the defendant and that the defendant
officers if the facts alleged in a complaint constitute or give rise to a cause of
was afforded a real opportunity to appear before the court and defend its
action under Bermuda law. However, section 281 of the Bermuda Companies
case; and the judgment being final under the laws of the country in which
Act allows a Bermuda court, in certain circumstances, to relieve officers and
it was rendered. Nonetheless, we have been advised by our Chilean counsel
directors of Bermuda companies of liability for acts of negligence, breach of
that there is doubt as to the enforceability in original actions in Chilean
duty or trust or other defaults.
courts of liabilities predicated solely upon U.S. federal or state securities laws.
Section 98 of the Bermuda Companies Act provides generally that a Bermuda
C. Material contracts
company may indemnify its directors, officers and auditors against any
See “Item 4. Information on the Company—B. Business Overview—Significant
liability which by virtue of any rule of law would otherwise be imposed on
Agreements.”
them in respect of any negligence, default, breach of duty or breach of trust,
except in cases where such liability arises from fraud or dishonesty of which
D. Exchange controls
such director, officer or auditor may be guilty in relation to the company.
Not applicable.
Section 98 further provides that a Bermuda company may indemnify its
directors, officers and auditors against any liability incurred by them in
E. Taxation
defending any proceedings, whether civil or criminal, in which judgment
The following summary contains a description of certain Bermudian, U.S.
is awarded in their favor or in which they are acquitted or granted relief by
federal income, and Chilean tax consequences of the acquisition, ownership and
the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda
Companies Act.
GeoPark 143
disposition of our common shares. The summary is based upon the tax laws of
purposes holds common shares, the U.S. federal income tax treatment of a
Bermuda, the United States, and Chile, and regulations thereunder as of the date
partner will generally depend on the status of the partner and the activities
hereof, which are subject to change.
Bermuda tax consideration
of the partnership. Partnerships holding common shares and partners in such
partnerships should consult their tax advisers as to the particular U.S. federal
income tax consequences of their investment in our common shares.
At the date of this annual report, there is no Bermuda income or profits tax,
withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance
This discussion is based on the Internal Revenue Code of 1986, as amended
tax payable by us or by our shareholders in respect of our common shares. We
(the “Code”), administrative pronouncements, judicial decisions, and final,
have obtained an assurance from the Minister of Finance of Bermuda under
temporary and proposed Treasury regulations, all as of the date hereof, any
the Exempted Undertakings Tax Protection Act 1966 that, in the event that
of which is subject to change, possibly with retroactive effect. U.S. Holders
any legislation is enacted in Bermuda imposing any tax computed on profits
should consult their tax advisers concerning the U.S. federal, state, local and
or income, or computed on any capital asset, gain or appreciation or any tax in
foreign tax consequences of owning and disposing of our common shares in
the nature of estate duty or inheritance tax, such tax shall not, until March 31,
their particular circumstances.
2035, be applicable to us or to any of our operations or to our common shares,
debentures or other obligations except insofar as such tax applies to persons
A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal
ordinarily resident in Bermuda or is payable by us in respect of real property
income tax purposes that is:
owned or leased by us in Bermuda. We pay annual Bermuda government fees.
• a citizen or individual resident of the United States;
Material U.S. federal income tax considerations
in or under the laws of the United States, any state therein or the District of
The following is a description of the material U.S. federal income tax
Columbia; or
consequences to U.S. Holders (as defined below) of owning and disposing of
• an estate or trust the income of which is subject to U.S. federal income
• a corporation, or other entity taxable as a corporation, created or organized
our common shares. This discussion is not a comprehensive description of
taxation regardless of its source.
all tax considerations that may be relevant to a particular person’s decision
to hold our common shares. This discussion applies only to a U.S. Holder that
This discussion assumes that we are not, and will not become, a passive
holds our common shares as capital assets for tax purposes. In addition, it
foreign investment company, as described below.
does not describe all of the tax consequences that may be relevant in light of
the U.S. Holder’s particular circumstances, including alternative minimum tax
Taxation of distributions
and Medicare contribution tax consequences and differing tax consequences
Distributions paid on our common shares, other than certain pro rata
applicable to a U.S. Holder subject to special rules, such as:
distributions of common shares, will generally be treated as dividends to
• certain financial institutions;
the extent paid out of our current or accumulated earnings and profits (as
• a dealer or trader in securities who uses a mark-to-market method of tax
determined under U.S. federal income tax principles). Because we do not
accounting;
maintain calculations of our earnings and profits under U.S. federal income tax
• a person holding common shares as part of a straddle, wash sale or
principles, it is expected that distributions will generally be reported to U.S.
conversion transaction or entering into a constructive sale with respect to the
Holders as dividends. Subject to the passive foreign investment company rules
common shares;
described below, dividends paid by qualified foreign corporations to certain non-
• a person whose functional currency for U.S. federal income tax purposes is
corporate U.S. Holders may be taxable at favorable rates. A foreign corporation is
not the US$;
treated as a qualified foreign corporation with respect to dividends paid on stock
• a partnership or other entities classified as partnerships for U.S. federal
that is readily tradable on a securities market in the United States, such as the
income tax purposes;
NYSE where our common shares are traded. Non-corporate U.S. Holders should
• a tax-exempt entity, including an “individual retirement account” or “Roth
consult their tax advisers to determine whether the favorable rate will apply to
IRA;”
dividends they receive and whether they are subject to any special rules that
• a person that owns or is deemed to own 10% or more of our shares by vote
limit their ability to be taxed at this favorable rate.
or value;
A dividend generally will be included in a U.S. Holder’s income when received,
• a person who acquired our shares pursuant to the exercise of an employee
will be treated as foreign-source income to U.S. Holders and will not be eligible
stock option or otherwise as compensation; or
for the dividends-received deduction generally available to U.S. corporations
• a person holding common shares in connection with a trade or business
under the Code with respect to dividends paid by domestic corporations.
conducted outside of the United States.
If an entity that is classified as a partnership for U.S. federal income tax
Sale or other taxable disposition of common shares
144 GeoPark 20F
Gain or loss realized on the sale or other taxable disposition of our common
treated as a PFIC for the taxable year in which we paid a dividend or the prior
shares will be capital gain or loss, and will be long-term capital gain or loss if
taxable year, the preferential dividend rates discussed above with respect to
the U.S. Holder held our common shares for more than one year. Long-term
dividends paid to certain non-corporate U.S. Holders would not apply.
capital gain of a non-corporate U.S. Holder is generally taxed at preferential
rates. The deductibility of capital losses is subject to limitations. The amount
Information reporting and backup withholding
of the gain or loss will equal the difference between the U.S. Holder’s tax
Payments of dividends and sales proceeds that are made within the United
basis in the common shares disposed of and the amount realized on the
States or through certain U.S.-related financial intermediaries generally are
disposition. If a Chilean tax is withheld on the sale or disposition of common
subject to information reporting, and may be subject to backup withholding,
shares, a U.S. Holder’s amount realized will include the gross amount of the
unless (1) the U.S. Holder is a corporation or other exempt recipient or
proceeds of the sale or disposition before deduction of the Chilean tax. See
(2) in the case of backup withholding, the U.S. Holder provides a correct
“—Chilean tax on transfers of shares” for a description of when a disposition
taxpayer identification number and certifies that it is not subject to backup
may be subject to taxation by Chile. This gain or loss will generally be
withholding. The amount of any backup withholding from a payment to a
U.S.-source gain or loss for foreign tax credit purposes. U.S. Holders should
U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal
consult their tax advisers as to whether the Chilean tax on gains may be
income tax liability and may entitle it to a refund, provided that the required
creditable against the U.S. Holder’s U.S. federal income tax on foreign-source
information is timely furnished to the Internal Revenue Service.
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.
We believe that we were not a “passive foreign investment company,” or PFIC,
824 of 1974, or the indirect transfer rules, were enacted, and impose taxes
for U.S. federal income tax purposes for 2018, and we do not expect to be
on the indirect transfer of shares, equity rights, interests or other rights in
a PFIC in the foreseeable future. However, because the composition of our
the equity, control or profits of a Chilean entity as well as transfers of other
income and assets will vary over time, there can be no assurance that we will
assets and property of permanent establishments or other businesses in Chile.
not be a PFIC for any taxable year. The determination of whether we are a PFIC
Reforms introduced in 2014 imposed a measure which obliges the company
is made annually and is based upon the composition of our income and assets
from which shares are transferred to pay taxes if the entity which undertakes
(including the income and assets of, among others, entities in which we hold
the transfer of shares fails to do so.
at least a 25% interest), and the nature of our activities.
The indirect transfer rules apply to sales of shares of an entity:
If we were a PFIC for any taxable year during which a U.S. Holder held our
•
If such entity is an offshore holding company located in a black-listed
common shares, gain recognized by a U.S. Holder on a sale or other disposition
tax haven jurisdiction as determined by Chilean tax law, or a black-listed
(including certain pledges) of our common shares would generally be
jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean
allocated ratably over the U.S. Holder’s holding period for the common shares.
resident holds 5% or more of such entity, or such entity’s rights to equity,
The amounts allocated to the taxable year of the sale or other disposition
control or profits, or 50% or more of such entity’s rights to equity or profits are
and to any year before we became a PFIC would be taxed as ordinary income.
held by residents in black-listed jurisdictions; or
The amount allocated to each other taxable year would be subject to tax
• the shares or rights transferred represent 10% or more of the offshore
at the highest rate in effect for individuals or corporations for that year, as
holding company (considering dispositions by related persons and over the
appropriate, and an interest charge would be imposed on the tax on such
preceding 12-month period) and the underlying Chilean Assets indirectly
amount. Further, to the extent that any distribution received by a U.S. Holder
transferred, in the proportion indirectly owned by the seller, (a) are valued
on its common shares exceeds 125% of the average of the annual distributions
in an amount equal to or higher than UTA 210,000 (approximately US$200
on the shares received during the preceding three years or the U.S. Holder’s
million) (adjusted by the Chilean inflation unit of reference) or (b) represent
holding period, whichever is shorter, that distribution would be subject to
20% or more of the market value of the interest held by such seller in such
taxation in the same manner as gain, as described immediately above. Certain
offshore holding company.
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 tests are met. This rate might be subject to change in the short term.
be available and, if so, what the consequences of the alternative treatments
See “Item 4. Information on the Company—B. Business overview—Industry
would be in their particular circumstances.
and regulatory framework —Chile.”
As of December 31, 2018, our Chilean Assets represented more than UTA
Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were
210,000 and represent more than 32% of our total assets.
GeoPark 145
PART II
The 35% rate is calculated pursuant to one of the following methods, as
F. Dividends and paying agents
determined by the seller:
Not applicable.
• the sale price of the shares minus the acquisition cost of such shares,
multiplied by the percentage or proportion of the part of the underlying Chilean
G. Statement by experts
Assets’ fair market value (which assets are deemed to be “indirectly transferred”
Not applicable.
by virtue of the sale of shares) to the fair market value of the shares of the seller;
or
H. Documents on display
• the portion of the sales price of the shares equal to the proportion of the
We are subject to the informational requirements of the Exchange Act.
fair market value of the underlying Chilean Assets, minus the corresponding
Accordingly, we are required to file reports and other information with the
proportion in the tax cost of such Chilean Assets for the corresponding holding
SEC, including annual reports on Form 20-F and reports on Form 6-K. The SEC
entity.
maintains an Internet website that contains reports and other information
about issuers, like us, that file electronically with the SEC. The address of that
However, the seller may opt to be taxed as if the underlying Chilean Assets
website is www.sec.gov.
had been sold directly in which case a different set of tax rules may apply.
I. Subsidiary information
The tax is payable by the seller of the shares; however, the buyer shall make a
Not applicable.
provisional withholding unless the seller declares and pays the tax within the
month following the sale, payment, remittance or it is credited into its account
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
or is put at its disposal. Also, if the seller fails to declare and pay this tax, and
MARKET RISK
the buyer has not complied with its withholding obligations, the Chilean tax
authority (Servicio de Impuestos Internos) may charge such tax directly to any
We are exposed to a variety of market risks, including commodity price risk,
of them. In addition, the Chilean tax authority may require us, the seller, the
interest rate risk, currency risk and credit (counterparty and customer) risk.
buyer, or its representative in Chile, to file an affidavit with the information
The term “market risk” refers to the risk of loss arising from adverse changes in
necessary to assess this tax.
interest rates, oil and natural gas prices and foreign currency exchange rates.
Based on information available to us, (i) no Chilean resident holds 5% or
For further information on our market risks, please see Note 3 to our
more of our rights to equity, control or profits; and (ii) residents in black-listed
Consolidated Financial Statements.
jurisdictions do not hold 50% or more of our rights to equity, control or profits.
Therefore, we do not believe the indirect transfer rules will apply to transfers
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
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
A. Debt securities
(considering dispositions by related persons and over the preceding 12-month
Not applicable.
period).
However, there can be no assurance that, at any time in the future, a Chilean
Not applicable.
resident will not hold 5% or more of our rights to equity, control or profits or
that residents in black-listed jurisdictions will not hold 50% or more of our
C. Other securities
rights to equity, control or profits. If this were to occur, all sales of our common
Not applicable.
shares would be subject to the indirect transfer tax referred to above.
D. American Depositary Shares
B. Warrants and rights
Our expectations regarding the indirect transfer rules are based on our
Not applicable.
understandings, analysis and interpretation of these enacted indirect transfer
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
rules, which are subject to additional interpretation and rule-making by the
Chilean authorities. As such, there is uncertainty relating to the application by
A. Defaults
Chilean authorities of the indirect transfer rules on us.
No matters to report.
See “Item 3. Key Information—D. Risk Factors—Risks related to our common
B. Arrears and delinquencies
shares—The transfer of our common shares may be subject to capital gains
No matters to report.
taxes pursuant to indirect transfer rules in Chile.”
146 GeoPark 20F
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, 2018, 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, 2018, 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,
2018, 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,
The effectiveness of the Company´s internal control over financial reporting as
processed, summarized and reported within the time periods specified in
of December 31, 2018, has been audited by Price Waterhouse & Co. S.R.L., an
the SEC’s rules and forms and (2) accumulated and communicated to our
independent registered public accounting firm, as stated in their report which
management to allow timely decisions regarding required disclosures.
is included on page F-2 of our Consolidated Financial Statements herein.
B. Management’s Annual Report on Internal Control over Financial
D. Changes in Internal Control over Financial Reporting
Reporting
There have been no changes in our internal control over financial reporting
Our management is responsible for establishing and maintaining an
during the period covered by this annual report on Form 20-F that have
adequate internal control over financial reporting as defined in Rule
materially affected or reasonably likely to materially affect our internal control
13a-15(f ) under the Exchange Act.
over financial reporting.
Our internal control over financial reporting is a process designed by, or
ITEM 16. RESERVED
under the supervision of, our principal executive and principal financial
officers, management and other personnel, to provide reasonable assurance
ITEM 16A. Audit committee financial expert
regarding the reliability of financial reporting and the preparation of our
financial statements for external reporting purposes, in accordance with
We have determined that Mr. Juan Cristóbal Pavez, Mr. Constantine
generally accepted accounting principles. These include those policies and
Papadimitriou and Mr. Robert Bedingfield are independent, as such term is
procedures that:
defined under SEC rules applicable to foreign private issuers. In addition, Mr.
• pertain to the maintenance of records that, in reasonable detail, accurately
Robert Bedingfield is regarded as audit committee financial expert.
and fairly reflect transactions and dispositions of our assets;
• provide reasonable assurance that transactions are recorded as necessary
ITEM 16B. Code of Conduct
to permit preparation of financial statements, in accordance with generally
accepted accounting principles, and that receipts and expenditures are being
We have adopted a code of conduct applicable to the board of directors and
made only in accordance with authorization of our management and directors;
all employees. Since its effective date on September 24, 2012, we have not
and
waived compliance with or amended the code of conduct.
• provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have a
ITEM 16C. Principal Accountant Fees and Services
material effect on our financial statements.
GeoPark 147
Amounts billed by PwC for audit and other services were as follows:
ITEM 16E. Purchases of equity securities by the issuer and affiliated
purchasers.
2018
2017
The following table presents purchases of our common shares by the company
(in millions of US$)
and “affiliated purchasers” (as that term is defined in Rule 10b-18(a)(3) under the
Audit fees
Audit related fees
Tax services fees
Other fees paid
Total
Audit Fees
0.80
-
0.21
-
1.01
0.73
0.14
0.21
0.03
1.11
Securities Exchange Act of 1934, as amended) during 2018:
Total Number
Maximum Number
of Shares
(or Approximate
Purchased as
Dollar Value) of
Total
Part of Publicly
Shares that May
Audit fees are fees billed for professional services rendered by the principal
Number
Average
Announced
Yet be Purchased
accountant for the audit of the registrant’s annual financial statements or
of Shares
Price Paid
Plans or
Under the Plans or
services that are normally provided by the accountant in connection with
2018
Purchased
per Share
Programs
Programs
statutory and regulatory filings or engagements for those fiscal years. It includes
December 21
the audit of our Consolidated Financial Statements and other services that
to December
generally only the independent accountant reasonably can provide, such as
31, 2018
145,917
12.0
145,917
6,063,000 shares
comfort letters, statutory audits, consents and assistance with and review of
documents filed with the SEC.
ITEM 16F. Change in registrant’s certifying accountant
Audit-Related Fees
Not applicable.
Audit-related fees are fees billed for assurance and related services that are
reasonably related to the performance of the audit or review of our Consolidated
ITEM 16G. Corporate governance
Financial Statements and not reported under the previous category. These
services would include, among others: accounting consultations and audits
Our common shares are listed on the NYSE. We are therefore required to
in connection with acquisitions, internal control reviews, attest services that
comply with certain of the NYSE’s corporate governance listing standards
are not required by statue or regulation and consultation concerning financial
(the “NYSE Standards”). As a foreign private issuer, we may follow our
accounting and reporting standards.
Tax Fees
home country’s corporate governance practices in lieu of most of the NYSE
Standards. Our corporate governance practices differ in certain significant
respects from those that U.S. companies must adopt in order to maintain
Tax fees are fees billed for professional services for tax compliance, tax advice
NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed
and tax planning.
Company Manual, a brief, general summary of those differences is provided
Pre-Approval Policies and Procedures
Following the listing of our common shares on the NYSE, the Audit
Director independence
as follows.
Committee proposes the appointment of the independent auditor to the
The NYSE Standards require a majority of the membership of NYSE-listed
Board to be put to shareholders for approval at the Annual General meeting.
company boards to be composed of independent directors. Neither
The committee oversees the auditor selection process for new auditors
Bermuda law, the law of our country of incorporation, nor our memorandum
and ensures key partners in the appointed firm are rotated in accordance
of association or bye-laws require a majority of our board to consist of
with best practices. Also, following our NYSE listing, the Audit Committee
independent directors.
is required to pre-approve the audit and non-audit fees and services
Non-management directors’ executive sessions
performed by the Company’s auditors in order to be sure that the provision
The NYSE Standards require non-management directors of NYSE-listed
of such services does not impair the audit firm’s independence.
companies to meet at regularly scheduled executive sessions without
management. Our memorandum of association and bye-laws do not require
All of the audit fees, audit-related fees and tax fees described in this item
our non-management directors to hold such meetings.
16C have been approved by the Audit Committee.
ITEM 16D. Exemptions from the listing standards for audit committees
The NYSE Standards require domestic NYSE-listed domestic companies to
Committee member composition
None.
148 GeoPark 20F
have a nominating/corporate governance committee and a compensation
committee that are composed entirely of independent directors. Bermuda law,
purposes and responsibilities or performance evaluations in a manner that
the law of our country of incorporation, does not impose similar requirements.
would satisfy the NYSE’s requirements; acquire shareholder approval of equity
compensation plans in certain cases; or adopt and make publicly available
Independence of the compensation committee and its advisers
corporate governance guidelines.
On January 11, 2013, the SEC approved NYSE listing standards that require
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
GeoPark 149
PART III
ITEM 17. Financial statements
We have responded to Item 18 in lieu of this item.
No. Description
(incorporated herein by reference to Exhibit 4.22 to the Company’s
Annual Report on Form 20-F filed with the SEC on April 11, 2017). †
ITEM 18. Financial statements
4.5
Prepayment Agreement for an Amount of up to US$100,000,000,
Financial Statements are filed as part of this annual report, see pages F-1 to
dated December 18, 2015, among C.I. Trafigura Petroleum Colombia
F-79 to this annual report.
ITEM 19. Exhibits
No. Description
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).
4.6 Amendment Agreement No. 1 among GeoPark Colombia SAS, C.I.
Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated September
1.1 Certificate of Incorporation (incorporated herein by reference to Exhibit
1, 2016 relating to the Prepayment Agreement dated December
3.1 to the Company’s Registration Statement on Form F-1 (File No. 333-
18, 2015 (incorporated herein by reference to Exhibit 4.27 to the
191068) filed with the SEC on September 9, 2013).
Company’s Annual Report on Form 20-F filed with the SEC on April 11,
1.2 Memorandum of Association (incorporated herein by reference to
2017).
Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File
4.7
Amendment Agreement No. 2 among GeoPark Colombia SAS, C.I.
No. 333-191068) filed with the SEC on September 9, 2013).
Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated December
1.3 Current bye-laws (incorporated herein by reference to Exhibit 3.3 to the
16, 2016 relating to the Prepayment Agreement dated December
Company’s Registration Statement on Form F-1 (File No. 333-191068)
18, 2015 (incorporated herein by reference to Exhibit 4.28 to the
filed with the SEC on September 9, 2013).
Company’s Annual Report on Form 20-F filed with the SEC on April 11,
1.4 Form of amended and restated bye-laws (incorporated herein by
2017).
reference to Exhibit 3.4 to the Company’s Registration Statement on
4.8 Amendment Agreement No. 2 among GeoPark Colombia SAS, C.I.
Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).
Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated December
2.2
Indenture, dated September 21, 2017, among GeoPark Limited, the
16, 2016 relating to the Prepayment Agreement dated December
Bank of New York Mellon and Lord Securities Corporation (incorporated
18, 2015 (incorporated herein by reference to Exhibit 4.28 to the
herein by reference to Exhibit 2.2 to the Company’s Annual Report on
Company’s Annual Report on Form 20-F filed with the SEC on April 11,
Form 20-F filed with the SEC on April 12, 2018).
2017).
2.3
Supplemental Indenture, dated as of January 28, 2019, among GeoPark
4.9
Asset Purchase Agreement between GeoPark Argentina Ltd. and
Limited, Geopark Chile S.A., Geopark Colombia Coöperatie U.A. and the
Pluspetrol S.A., dated December 18, 2017 (incorporated herein by
Bank of New York Mellon.
reference to Exhibit 4.23 to the Company’s Annual Report on Form 20-F
4.1
Special Contract for the Exploration and Exploitation of
filed with the SEC on April 12, 2018).
Hydrocarbons, Fell Block, dated April 29, 1997, among the Republic
4.10 Purchase and Sale Agreement for Crude Oil and Condensate of Fell
of Chile, the Chilean Empresa Nacional de Petróleo (ENAP) and
Block between Empresa Nacional del Petróleo (ENAP) and GeoPark Fell
Cordex Petroleums Inc. (incorporated herein by reference to Exhibit
S.p.A., dated April 21, 2017 (incorporated herein by reference to Exhibit
10.1 to the Company’s Registration Statement on Form F-1 (File No.
4.24 to the Company’s Annual Report on Form 20-F filed with the SEC
333-191068) filed with the SEC on September 9, 2013).
on April 12, 2018).
4.2
Exploration and Production Contract regarding exploration for and
4.11 Sale and Purchase Agreement between LGI International Corp. and
exploitation of hydrocarbons in the La Cuerva Block, dated April 16,
Geopark Limited, dated November 28, 2018.*
2008, between the Colombian Agencia Nacional de Hidrocarburos and
Hupecol Caracara LLC (incorporated herein by reference to Exhibit 10.2
to the Company’s Registration Statement on Form F-1 (File No. 333-
191068) filed with the SEC on September 9, 2013).
4.3
Exploration and Production Contract regarding exploration for and
exploitation of hydrocarbons in the Llanos 34 Block, dated March 13,
2009, between the Colombian Agencia Nacional de Hidrocarburos and
Unión Temporal Llanos 34 (incorporated herein by reference to Exhibit
10.3 to the Company’s Registration Statement on Form F-1 (File No.
333-191068) filed with the SEC on September 9, 2013).
4.4
Contract for the sale and Purchase of Natural Gas 2017-2027 between
GeoPark Fell SpA and Methanex Chile SpA dated March 31, 2017
150 GeoPark 20F
No. Description
8.1
Subsidiaries of GeoPark Limited.*
12.1 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*
12.2 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*
13.1 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to
section 906 of the Sarbanes-Oxley Act of 2002.*
13.2 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to
section 906 of the Sarbanes-Oxley Act of 2002.*
15.1 Consent of Price Waterhouse & Co. S.R.L., Argentina.*
15.2 Consents of DeGolyer and MacNaughton to use its report.*
99.1 Reserves Report of DeGolyer and MacNaughton dated February
4, 2019, for reserves in Chile, Colombia, Peru, Argentina and Brazil
as of December 31, 2018.*
101.INS XBRL Instance Document*
101.SCH XBRL Taxonomy Extension Schema Document*
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document*
101.DEF XBRL Taxonomy Extension Definition Linkbase Document*
101.LAB XBRL Taxonomy Extension Label Linkbase Document*
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document*
*
†
Filed with this Annual Report on Form 20-F.
Confidential treatment of certain provisions of these exhibits has
been requested with the SEC. Omitted material for which confidential
treatment has been requested has been filed separately with the SEC.
GeoPark 151
Glossary of Oil and Natural Gas Terms
The terms defined in this section are used throughout this annual report:
grouped on or related to the same individual geological structural feature
“appraisal well” means a well drilled to further confirm and evaluate the
and/or stratigraphic condition. There may be two or more reservoirs in a field
presence of hydrocarbons in a reservoir that has been discovered.
that are separated vertically by intervening impervious strata, or laterally by
“API” means the American Petroleum Institute’s inverted scale for denoting the
local geologic barriers, or by both. Reservoirs that are associated by being
“light” or “heaviness” of crude oils and other liquid hydrocarbons.
in overlapping or adjacent fields may be treated as a single or common
“bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used herein
operational field. The geological terms structural feature and stratigraphic
in reference to crude oil, condensate or natural gas liquids.
condition are intended to identify localized geological features as opposed to
“bcf” means one billion cubic feet of natural gas.
the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
“bcm” means billion cubic meters.
“formation” means a layer of rock which has distinct characteristics that differ
“boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas
from nearby rock.
being equivalent to one barrel of oil.
“mbbl” means one thousand barrels of crude oil, condensate or natural gas
“boepd” means barrels of oil equivalent per day.
liquids.
“bopd” means barrels of oil per day.
“mboe” means one thousand barrels of oil equivalent.
“British thermal unit” or “btu” means the heat required to raise the temperature
“mcf” means one thousand cubic feet of natural gas.
of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
“Measurements” include:
“basin” means a large natural depression on the earth’s surface in which
• “m” or “meter” means one meter, which equals approximately 3.28084 feet;
sediments generally brought by water accumulate.
• “km” means one kilometer, which equals approximately 0.621371 miles;
“CEOP” (Contrato Especial de Operación) means a special operating contract
• “sq. km” means one square kilometer, which equals approximately 247.1
the Chilean signs with a company or a consortium of companies for the
acres;
exploration and exploitation of hydrocarbon wells
• “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent
“completion” means the process of treating a drilled well followed by the
to approximately 0.15898 cubic meters;
installation of permanent equipment for the production of natural gas or oil,
• “boe” means one barrel of oil equivalent, which equals approximately
or in the case of a dry hole, the reporting of abandonment to the appropriate
160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of
agency.
natural gas to one barrel of oil;
“developed acreage” means the number of acres that are allocated or
• “cf” means one cubic foot;
assignable to productive wells or wells capable of production.
• “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf,
“developed reserves” are expected quantities to be recovered from existing
respectively;
wells and facilities. Reserves are considered developed only after the
• “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf,
necessary equipment has been installed or when the costs to do so are
respectively;
relatively minor compared to the cost of a well. Where required facilities
• “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf,
become unavailable, it may be necessary to reclassify developed reserves as
respectively; and
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
152 GeoPark 20F
oil nor natural gas will be present, at least not in commercial volumes.
“stratigraphic test well” means a drilling effort, geologically directed, to obtain
“proved developed reserves” means those proved reserves that can be
information pertaining to a specific geologic condition. Such wells customarily
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.
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, 2019
154 GeoPark 20F
GeoPark 155
Consolidated Financial Statements
As of and for the year ended 31 December 2018
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
160
161
161
162
163
164
165
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, 2018 and 2017, 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, 2018, 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, 2018 and
2017, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2018, 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) Fernando Alberto Rodríguez
Autonomous City of Buenos Aires, Argentina
March 6, 2019
We have served as the Company’s auditor since 2009.
158 GeoPark 20F
Consolidated Statement of Income
Amounts in US$ ´000
Note
2018
2017
2016
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 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
PROFIT (LOSS) FOR THE YEAR
Attributable to:
Owners of the Company
Non-controlling interest
Earnings (Losses) per share (in US$) for profit (loss)
attributable to owners of the Company. Basic
Earnings (Losses) per share (in US$) for profit (loss)
attributable to owners of the Company. Diluted
Consolidated Statement of Comprehensive Income
Amounts in US$ ´000
Profit (loss) for the year
Other comprehensive income:
Items that may be subsequently reclassified to profit or loss
Currency translation differences
Total comprehensive (loss) for the year
Attributable to:
Owners of the Company
Non-controlling interest
The notes on pages 8 to 79 are an integral part of these Consolidated Financial Statements.
7
8
9
12
13
14
20
20-36
601,161
16,173
(174,260)
(13,951)
(52,074)
(4,023)
(92,240)
(26,389)
4,982
(2,887)
256,492
330,122
(15,448)
(98,987)
(7,694)
(42,054)
(1,136)
(74,885)
(5,834)
-
(5,088)
78,996
192,670
(2,554)
(67,235)
(10,282)
(34,170)
(4,222)
(75,774)
(31,366)
5,664
(1,344)
(28,613)
15
15
15
(39,321)
(53,511)
(36,229)
3,059
(11,323)
208,907
2,016
(2,193)
25,308
2,128
13,872
(48,842)
17
(106,240)
(43,145)
(11,804)
102,667
(17,837)
(60,646)
72,415
30,252
(24,228)
6,391
(49,092)
(11,554)
19
19
1.19
(0.40)
(0.82)
1.11
(0.40)
(0.82)
2018
2017
2016
102,667
(17,837)
(60,646)
(4,401)
98,266
(512)
7,102
(18,349)
(53,544)
68,014
30,252
(24,740)
6,391
(41,990)
(11,554)
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
Derivative financial instrument assets
Other financial assets
Cash and cash equivalents
Assets held for sale
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
Liabilities associated with assets held for sale
TOTAL CURRENT LIABILITIES
TOTAL LIABILITIES
TOTAL EQUITY AND LIABILITIES
The notes on pages XX to XX are an integral part of these Consolidated Financial Statements.
160 GeoPark 20F
Note
2018
2017
20
22
25
18
24
23
24
24
22
25
25
25
35.2
26
35.1
27
28
18
29
27
25
29
35.2
557,170
517,403
3,275
10,570
31,793
219
3,823
22,110
27,636
235
603,027
571,207
9,309
16,215
9,489
45,170
27,539
898
127,727
23,286
259,633
862,660
5,738
19,519
7,518
26,048
-
21,378
134,755
-
214,956
786,163
60
237,840
111,809
61
239,191
129,606
(206,688)
(283,933)
143,021
-
84,925
41,915
143,021
126,840
429,027
418,540
42,577
14,801
14,789
46,284
2,286
25,921
501,194
493,031
17,975
-
58,776
131,420
10,274
218,445
719,639
862,660
7,664
19,289
42,942
96,397
-
166,292
659,323
786,163
Consolidated Statement of Changes in Equity
Amount in US$ ‘000
Equity at 1 January 2016
Comprehensive income:
Loss for the year
Currency translation differences
Total Comprehensive profit (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) Profit for the year
Currency translation differences
Total Comprehensive (loss) profit 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
Comprehensive income:
Profit for the year
Currency translation differences
Total Comprehensive (loss) profit for the year 2018
Transactions with owners:
Share-based payment (Note 30)
Repurchase of shares (Note 26)
Dividends distribution to non-controlling interest
Transactions with non-controlling interest (Note 35.1)
Total 2018
Balances at 31 December 2018
Attributable to owners of the Company
(Accumulated
Losses)
Non-
Share
Share
Other
Translation
Retained
controlling
Capital
Premium
Reserve
Reserve
Earnings
59
232,005
127,527
(4,511)
(208,428)
Interest
53,515
Total
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
-
-
-
-
(1)
-
-
(1)
60
-
-
-
449
(1,800)
-
-
(1,351)
237,840
-
-
-
-
-
-
(13,396)
(13,396)
114,131
-
72,415
30,252
(4,401)
(4,401)
-
-
72,415
30,252
-
-
-
-
-
4,830
-
-
-
167
-
(8,089)
(64,245)
4,830
(72,167)
(2,322)
(206,688)
-
102,667
(4,401)
98,266
5,446
(1,801)
(8,089)
(77,641)
(82,085)
143,021
The notes on pages 8 to 79 are an integral part of these Consolidated Financial Statements.
GeoPark 161
Consolidated Statement of Cash Flow
Amounts in US$ ‘000
Note
2018
2017
2016
Cash flows from operating activities
Profit (Loss) for the year
Adjustments for:
Income tax expense
Depreciation
Loss on disposal of property, plant and equipment
Impairment loss reversed for non-financial assets
Write-off of unsuccessful exploration efforts
Accrual of borrowing’s interests
Borrowings cancellation costs
Amortization of other long-term liabilities
Unwinding of long-term liabilities
Accrual of share-based payment
Foreign exchange loss (gain)
Unrealized (gain) 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
Acquisition of business
Proceeds from disposal of long-term assets
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
Payments for transactions with non-controlling interest
Cash flows (used in) from financing activities - net
Net (decrease) increase 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 8 to 79 are an integral part of these Consolidated Financial Statements.
162 GeoPark 20F
102,667
(17,837)
(60,646)
17
20-36
20
15
28
28
8
5
106,240
92,240
272
(4,982)
26,389
30,444
-
(1,005)
3,505
5,446
11,323
(42,271)
(67,704)
(6,358)
256,206
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
(13,872)
3,068
(1,956)
11,920
82,884
(124,744)
(105,604)
(39,306)
35.3
35.2
(48,850)
9,000
-
-
-
-
(164,594)
(105,604)
(39,306)
36,017
425,000
-
-
(1,801)
(15,073)
(27,695)
-
(8,089)
(81,000)
(97,641)
(6,029)
134,755
(999)
35.1
(6,683)
1,155
-
(355,022)
(27,688)
(12,315)
-
23,968
60,522
73,563
670
127,727
134,755
186
-
5,210
(1,991)
(22,645)
(25,490)
-
-
(51,136)
(7,558)
82,730
(1,609)
73,563
(479)
(6,406)
127,707
134,734
73,551
20
21
12
127,727
134,755
73,563
Notes to Consolidated Financial Statements
Note 1
General Information
• Classification and Measurement of Share-based Payment Transactions –
Amendments to IFRS 2
GeoPark Limited (the “Company”) is a company incorporated under the law
• Annual Improvements 2014-2016 cycle
of Bermuda. The Registered Office address is Cumberland House, 9th Floor, 1
• Interpretation 22 Foreign Currency Transactions and Advance Consideration
Victoria Street, Hamilton HM11, Bermuda.
The principal activities of the Company and its subsidiaries (the “Group” or
“GeoPark”) are exploration, development and production for oil and gas
• Annual Improvements to IFRS Standards 2015-2017 Cycle.
reserves in Colombia, Chile, Brazil, Argentina and Peru.
These Consolidated Financial Statements were authorized for issue by the
classification and measurement of financial assets and financial liabilities,
Board of Directors on 6 March 2019.
derecognition of financial instruments, impairment of financial assets and
IFRS 9 replaces the provisions of IAS 39 related to the recognition,
The Group also elected to adopt the following amendments early:
hedge accounting.
Note 2
The adoption of IFRS 9 from 1 January 2018 resulted in changes in accounting
Summary of significant accounting policies
policies (see Note 2.16 and Note 2.18) and a reclassification of a measurement
The principal accounting policies applied in the preparation of these
category (see below), but no adjustments to the amounts recognized in the
Consolidated Financial Statements are set out below. These policies have been
Consolidated Financial Statements.
consistently applied to the years presented, unless otherwise stated.
2.1 Basis of preparation
On 1 January 2018, the Group classified money market funds for US$
44,123,000 accounted within Cash and cash equivalents as of 31 December
The Consolidated Financial Statements of GeoPark Limited have been
2017, as Financial assets at fair value through profit or loss that were
prepared in accordance with International Financial Reporting Standards
previously classified as Loans and receivables. No results were generated as a
(“IFRS”) as issued by the International Accounting Standards Board (“IASB”),
consequence of this change. As of 31 December 2018, the Group holds money
under the historical cost convention.
market funds for US$ 53,794,000.
The Consolidated Financial Statements are presented in thousands of United
IFRS 15 replaces IAS 18 which covered contracts for goods and services and
States Dollars (US$’000) and all values are rounded to the nearest thousand
IAS 11 which covered construction contracts. The new standard is based on
(US$’000), except in the footnotes and where otherwise indicated.
the principle that revenue is recognized when control of a good or service
transfers to a customer, so the notion of control replaces the existing notion of
The preparation of financial statements in conformity with IFRS requires the
risks and rewards.
use of certain critical accounting estimates. It also requires management to
exercise its judgement in the process of applying the Group’s accounting
The adoption of IFRS 15 from 1 January 2018 resulted in no changes in
policies. The areas involving a higher degree of judgement or complexity, or
accounting policies or adjustments to the amounts recognized in the
areas where assumptions and estimates are significant to the Consolidated
Consolidated Financial Statements.
Financial Statements are disclosed in this note under the title “Accounting
estimates and assumptions”.
The adoption of the other amendments listed above did not have any
impact on the amounts recognized in prior periods and are not expected to
All the information included in these Consolidated Financial Statements
significantly affect the current or future periods.
corresponds to the Group, except where otherwise indicated.
New standards, amendments and interpretations issued but not effective for the
2.1.1 Changes in accounting policy and disclosure
financial year beginning 1 January 2018 and not early adopted.
New and amended standards adopted by the Group
The following standards have been adopted by the Group for the first time for
in the recognition of almost all leases on the balance sheet. The standard
the financial year beginning on or after 1 January 2018:
removes the current distinction between operating and financing leases
• IFRS 9 Financial Instruments
and requires recognition of an asset (the right to use the leased item) and a
financial liability to pay rentals for virtually all lease contracts. An optional
• IFRS 15 Revenue from Contracts with Customers
exemption exists for short-term and low-value leases. The accounting by
•
IFRS 16 Leases: will affect primarily the accounting by lessees and will result
GeoPark 163
lessors will not significantly change. Some differences may arise as a result of
Considering macroeconomic environment conditions, the performance
the new guidance on the definition of a lease.
of the operations, the US$ 425,000,000 debt fundraising completed in
The Group has set up a project team by business unit which has reviewed
total indebtedness matures in 2024, the Directors have formed a judgement,
each business unit’s leasing arrangements over the last year in light of the
at the time of approving the financial statements, that there is a reasonable
new lease accounting rules in IFRS 16. The standard will affect primarily the
expectation that the Group has adequate resources to meet all its obligations
accounting for the Group’s operating leases.
for the foreseeable future. For this reason, the Directors have continued
September 2017, the Group’s cash position, and the fact that over 95% of its
to adopt the going concern basis in preparing the Consolidated Financial
As at the reporting date, the Group has non-cancellable operating lease
Statements.
commitments of US$ 69,938,000, see Note 32.3. Of these commitments, the
Group expects to recognize right-of-use assets and lease liabilities, at nominal
2.3 Consolidation
value, of approximately US$ 14,449,000 on 1 January 2019. The remaining
Subsidiaries are all entities (including structured entities) over which the
lease commitments, in accordance with IFRS 16, will be recognized on a
Group has control. The Group controls an entity when the Group is exposed
straight-line basis as expense in the Consolidated Statement of Income.
to, or has rights to, variable returns from its involvement with the entity
and has the ability to affect those returns through its power over the
There will not be an impact on Adjusted EBITDA as a consequence of the
entity. Subsidiaries are fully consolidated from the date on which control is
adoption of this new standard. This measure is used to assess the performance
transferred to the Group. They are deconsolidated from the date that control
of the operating segments and is also considered for the calculation of the
ceases.
incurrence test covenants included in the indenture governing the Group’s
main financial debt. Therefore, Management decided to modify the definition
The Group applies the acquisition method to account for business
of this measure since the adoption of IFRS 16 in 2019 in order to ensure
combinations. The consideration transferred for the acquisition of a subsidiary
comparability with previous periods.
is the fair value of the assets transferred, the liabilities incurred by the former
owners of the acquiree and the equity interests issued by the Group. The
Operating cash flows will increase and financing cash flows decrease by
consideration transferred includes the fair value of any asset or liability
approximately US$ 4,000,000 as repayment of the principal portion of the
resulting from a contingent consideration arrangement. Identifiable assets
lease liabilities will be classified as cash flows from financing activities.
acquired, and liabilities and contingent liabilities assumed in a business
combination are measured initially at their fair values at the acquisition date.
The Group will apply the standard from its mandatory adoption date of 1
Acquisition-related costs are expensed as incurred.
January 2019. The Group intends to apply the simplified transition approach
and will not restate comparative amounts for the year prior to first adoption.
The excess of the consideration transferred over the fair value of the
Lease liability for property leases will be measured on transition at the
identifiable net assets acquired is recorded as goodwill. If the total of
present value of the remaining lease payments, discounted using the lessee’s
consideration transferred is less than the fair value of the net assets of the
incremental borrowing rate at the date of initial application. The right-of-
subsidiary acquired in the case of a bargain purchase, the difference is
use asset on transition (on a lease-by-lease basis) will be measure at an
recognized directly in the income statement.
amount equal to the lease liability (adjusted for any prepaid or accrued lease
expenses).
Intercompany transactions, balances and unrealized gains on transactions
between the Group and its subsidiaries are eliminated. Unrealized losses are
There are no other standards that are not yet effective and that would be
also eliminated unless the transaction provides evidence of an impairment
expected to have a material impact on the entity in the current or future
of the asset transferred. Amounts reported in the financial statements of
reporting periods and on foreseeable future transactions.
subsidiaries have been adjusted where necessary to ensure consistency with
the accounting policies adopted by the Group.
2.2 Going concern
The Directors regularly monitor the Group’s cash position and liquidity risks
2.4 Segment reporting
throughout the year to ensure that it has sufficient funds to meet forecast
Operating segments are reported in a manner consistent with the internal
operational and investment funding requirements. Sensitivities are run to
reporting provided to the chief operating decision-maker. The chief operating
reflect latest expectations of expenditures, oil and gas prices and other factors
decision-maker, who is responsible for allocating resources and assessing
to enable the Group to manage the risk of any funding short falls and/or
performance of the operating segments, has been identified as the Executive
potential debt covenant breaches.
164 GeoPark 20F
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
2.9 Financial results
in order to assess performance and allocate resources. Management has
Financial results include interest expenses, interest income, bank charges,
determined the operating segments based on these reports.
the amortization of financial assets and liabilities, and foreign exchange
2.5 Foreign currency translation
gains and losses. The Group has capitalized the borrowing cost for wells and
facilities that were initiated after 1 January 2009. The capitalization rate used
2.5.1. Functional and presentation currency
to determine the amount of borrowing costs to be capitalized is the weighted
The Consolidated Financial Statements are presented in US Dollars, which is
average interest rate applicable to the Group’s general borrowings during the
the Group’s presentation currency.
year, which was 6.90% at year-end 2018 (6.90% at year-end 2017 and 7.98%
in 2016). Amounts capitalized during the year amounted to US$ 257,507 (US$
Items included in the financial statements of each of the Group’s entities
610,841 in 2017 and US$ 254,950 in 2016).
are measured using the currency of the primary economic environment in
which the entity operates (the “functional currency”). The functional currency
2.10 Property, plant and equipment
of Group companies incorporated in Chile, Colombia, Peru and Argentina is
Property, plant and equipment are stated at historical cost less depreciation
the US Dollar, meanwhile for the Group´s Brazilian company the functional
and impairment charges, if applicable. Historical cost includes expenditure
currency is the local currency, which is the Brazilian Real.
that is directly attributable to the acquisition of the items; including provisions
for asset retirement obligation.
2.5.2. Transactions and balances
Foreign currency transactions are translated into the functional currency
Oil and gas exploration and production activities are accounted for in
using the exchange rates prevailing at the dates of the transactions. Foreign
accordance with the successful efforts method on a field by field basis. The
exchange gains and losses resulting from the settlement of such transactions
Group accounts for exploration and evaluation activities in accordance with
and from the translation at period-end exchange rates of monetary assets
IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing
and liabilities denominated in foreign currencies are recognized in the
exploration and evaluation costs until such time as the economic viability
Consolidated Statement of Income.
of producing the underlying resources is determined. Costs incurred prior
to obtaining legal rights to explore are expensed immediately to the
2.6 Joint arrangements
Consolidated Statement of Income.
Under IFRS 11 investments in joint arrangements are classified as either
joint operations or joint ventures depending on the contractual rights and
Exploration and evaluation costs may include: license acquisition, geological
obligations of each investor.
and geophysical studies (i.e.: seismic), direct labour costs and drilling costs of
exploratory wells. No depreciation and/or amortization are charged during the
The Group has assessed the nature of its joint arrangements and determined
exploration and evaluation phase. Upon completion of the evaluation phase,
them to be joint operations. The Group combines its share in the joint
the prospects are either transferred to oil and gas properties or charged to
operations individual assets, liabilities, results and cash flows on a line-by-line
expense (exploration costs) in the period in which the determination is made,
basis with similar items in its financial statements.
depending whether they have discovered reserves or not. If not developed,
2.7 Revenue recognition
exploration and evaluation assets are written off after three years, unless
it can be clearly demonstrated that the carrying value of the investment is
Revenue from the sale of crude oil and gas is recognized in the
recoverable.
Consolidated Statement of Income when control is transferred to the
purchaser, and if the revenue can be measured reliably and is expected
A charge of US$ 26,389,000 has been recognized in the Consolidated
to be received. Revenue is shown net of VAT, discounts related to the sale
Statement of Income within Write-off of unsuccessful exploration efforts (US$
and overriding royalties due to the ex-owners of oil and gas properties
5,834,000 in 2017 and US$ 31,366,000 in 2016). See Note 20.
where the royalty arrangements represent a retained working interest in
the property. See Note 32.1.
2.8 Production and operating costs
All field development costs are considered construction in progress until they
are finished and capitalized within oil and gas properties, and are subject to
depreciation once completed. Such costs may include the acquisition and
Production and operating costs are recognized in the Consolidated Statement
installation of production facilities, development drilling costs (including dry
of Income on the accrual basis of accounting. These costs include wages
holes, service wells and seismic surveys for development purposes), project-
and salaries incurred to achieve the revenue for the year. Direct and indirect
related engineering and the acquisition costs of rights and concessions related
costs of raw materials and consumables, rentals, leasing and royalties are also
to proved properties.
included within this account.
GeoPark 165
Workovers of wells made to develop reserves and/or increase production
the environment, the Group has considered it appropriate to periodically
are capitalized 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
Capitalized 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 recognized in the Consolidated
estimates are recognized 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 amounts used in 2017 correspond to the deferred
furniture and vehicles) not directly associated with oil and gas activities has
income related to the take-or-pay provision associated to gas sales in Brazil.
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
2.12 Impairment of non-financial assets
useful lives. The useful lives range between 3 years and 10 years.
Assets that are not subject to depreciation and/or amortization (i.e.:
the Consolidated Statement of Income simultaneously with the amortization
Depreciation is allocated in the Consolidated Statement of Income as a
Assets that are subject to depreciation and/or amortization are reviewed for
separate line to better follow the performance of the business.
impairment whenever events or changes in circumstances indicate that the
exploration and evaluation assets) are tested annually for impairment.
carrying amount may not be recoverable.
An asset’s carrying amount is written down immediately to its recoverable
amount if the asset’s carrying amount is greater than its estimated recoverable
An impairment loss is recognized for the excess of the asset’s carrying
amount (see Impairment of non-financial assets in Note 2.12).
amount over its recoverable amount. The recoverable amount is the higher
of an asset’s fair value less costs to sell and value in use. For the purposes
2.11 Provisions and other long-term liabilities
of assessing impairment, assets are grouped at the lowest levels for which
Provisions for asset retirement obligations, deferred income, restructuring
there are separately identifiable cash flows (cash-generating units), generally
obligations and legal claims are recognized when the Group has a present
a licensed area. Non-financial assets other than goodwill that suffered
legal or constructive obligation as a result of past events; it is probable that
impairment are reviewed for possible reversal of the impairment at each
an outflow of resources will be required to settle the obligation; and the
reporting date.
amount has been reliably estimated. Restructuring provisions comprise lease
termination penalties and employee termination payments.
No asset should be kept as an exploration and evaluation asset for a period
of more than three years, except if it can be clearly demonstrated that the
Provisions are measured at the present value of the expenditures expected to
carrying value of the investment will be 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
During 2018, impairment loss was reversed for US$ 4,982,000 (no impairment
the obligation. The increase in the provision due to the passage of time is
loss recognized or reversed in 2017 and impairment loss reversed for US$
recognized as financial expense.
5,664,000 in 2016). See Note 36. The write-offs are detailed in Note 20.
2.11.1 Asset Retirement Obligation
2.13 Lease contracts
The Group records the fair value of the liability for asset retirement obligations
All current lease contracts are considered to be operating leases on the basis
in the period in which the wells are drilled. When the liability is initially
that the lessor retains substantially all the risks and rewards related to the
recorded, the Group capitalizes the cost by increasing the carrying amount of
ownership of the leased asset. Payments related to operating leases and other
the related long-lived asset. Over time, the liability is accreted to its present
rental agreements are recognized in the Consolidated Income Statement
value at each reporting period, and the capitalized cost is depreciated over
on a straight-line basis over the term of the contract. The Group’s total
the estimated useful life of the related asset. According to interpretations
commitment relating to operating leases and rental agreements is disclosed
and the application of current legislation, and on the basis of the changes in
in Note 32.3.
technology and the variations in the costs of restoration necessary to protect
166 GeoPark 20F
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 recognize an amount receivable equal to the
not expect taxable profit. Hence deferred tax is recognized 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 recognize amounts to
Crude oil is measured at the lower of cost and net realizable value. Materials
approximately US$ 11,400,000.
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, first-
out (FIFO) method.
2.16 Non-current assets or disposal groups held for sale
Non-current assets or disposal groups are classified as held for sale if their
2.15 Current and deferred income tax
carrying amount will be recovered principally through a sale transaction rather
The tax expense for the year comprises current and deferred tax. Tax is
than through continuing use and a sale is considered highly probable. They
recognized in the Consolidated Statement of Income.
are measured at the lower of their carrying amount and fair value less costs to
sell, except for assets such as deferred tax assets, assets arising from employee
The current income tax charge is calculated on the basis of the tax laws
benefits, financial assets and investment property that are carried at fair
enacted or substantially enacted at the balance sheet date in the countries
value and contractual rights under insurance contracts, which are specifically
where the Company’s subsidiaries operate and generate taxable income.
exempt from this requirement.
The computation of the income tax expense involves the interpretation of
applicable tax laws and regulations in many jurisdictions. The resolution of
An impairment loss is recognized for any initial or subsequent write-down of
tax positions taken by the Group, through negotiations with relevant tax
the asset or disposal group to fair value less costs to sell. A gain is recognized
authorities or through litigation, can take several years to complete and, in
for any subsequent increases in fair value less costs to sell of an asset or
some cases, it is difficult to predict the ultimate outcome.
disposal group, but not in excess of any cumulative impairment loss previously
Deferred income tax is recognized, using the liability method, on temporary
sale of the non-current asset or disposal group is recognized at the date of
recognized. A gain or loss not previously recognized by the date of the
differences arising between the tax bases of assets and liabilities and their
derecognition.
carrying amounts in the Consolidated Financial Statements. Deferred income
tax is determined using tax rates (and laws) that have been enacted or
Non-current assets (including those that are part of a disposal group) are not
substantially enacted as of the balance sheet date and are expected to apply
depreciated or amortized while they are classified as held for sale. Interest and
when the related deferred income tax asset is realized, or the deferred income
other expenses attributable to the liabilities of a disposal group classified as
tax liability is settled.
held for sale continue to be recognized.
In addition, the Group has tax-loss carry-forwards in certain tax jurisdictions
Non-current assets classified as held for sale and the assets of a disposal group
that are available to be offset against future taxable profit. However, deferred
classified as held for sale are presented separately from the other assets in the
tax assets are recognized only to the extent that it is probable that taxable
Consolidated Statement of Financial Position. The liabilities of a disposal group
profit will be available against which the unused tax losses can be utilized.
classified as held for sale are presented separately from other liabilities in the
Management judgment is exercised in assessing whether this is the case. To
Consolidated Statement of Financial Position.
the extent that actual outcomes differ from management’s estimates, taxation
charges or credits may arise in future periods.
2.17 Financial assets
Deferred income tax liabilities are provided on taxable temporary differences
financial assets at fair value through profit or loss and fair value through other
arising from investments in subsidiaries and joint arrangements, except
comprehensive income. The classification depends on the Group’s business
for deferred income tax liability where the timing of the reversal of the
model for managing the financial assets and the contractual terms of the
temporary difference is controlled by the Group and it is probable that the
cash flows. The Group reclassifies debt investments when and only when its
Financial assets are divided into the following categories: amortized cost;
GeoPark 167
business model for managing those assets changes.
2.20 Cash and cash equivalents
All financial assets not at fair value through profit or loss are initially
Cash and cash equivalents includes cash in hand, deposits held at call with
recognized at fair value, plus transaction costs. Transaction costs of financial
banks, other short-term highly liquid investments with original maturities
assets carried at fair value through profit or loss, if any, are expensed to profit
of three months or less, and bank overdrafts. Bank overdrafts, if any, are
or loss.
shown within borrowings in the current liabilities section of the Consolidated
Derecognition of financial assets occurs when the rights to receive cash flows
from the investments expire or are transferred and substantially all of the
2.21 Trade and other payables
Statement of Financial Position.
risks and rewards of ownership have been transferred. An assessment for
Trade payables are obligations to pay for goods or services that have been
impairment is undertaken at each balance sheet date.
acquired in the ordinary course of the business from suppliers. Accounts
Interest and other cash flows resulting from holding financial assets are
less (or in the normal operating cycle of the business if longer). If not, they are
payable are classified as current liabilities if payment is due within one year or
recognized in the Consolidated Statement of Income when receivable,
presented as non-current liabilities.
regardless of how the related carrying amount of financial assets is measured.
Amortized cost are non-derivative financial assets with fixed or determinable
measured at amortized cost using the effective interest method.
Trade payables are recognized initially at fair value and subsequently
payments that are not quoted in an active market. They are included in current
assets, except for maturities greater than twelve months after the balance
2.22 Derivatives
sheet date. These are classified as non-current assets. These financial assets
Derivative financial instruments are recognized in the statement of financial
comprise trade receivables, prepayments and other receivables and cash
position as assets or liabilities and initially and subsequently measured at fair value
and cash equivalents in the Consolidated Statement of Financial Position.
through profit and loss. They are presented as current assets or liabilities if they are
They arise when the Group provides money, goods or services directly to a
expected to be settled within 12 months after the end of the reporting period.
debtor with no intention of trading the receivables. These financial assets are
subsequently measured at amortized cost using the effective interest method,
The mark-to-market fair value of the Group’s outstanding derivative instruments
less provision for impairment, if applicable.
is based on independently provided market rates and determined using standard
Any change in their value through impairment or reversal of impairment
within level 2 of the fair value hierarchy. Gains and losses arising from changes
is recognized in the Consolidated Statement of Income. All of the Group’s
in fair value are recognized in the Consolidated Statement of Income within
financial assets are classified as amortized cost.
Commodity risk management contracts.
valuation techniques, including the impact of counterparty credit risk and are
2.18 Other financial assets
For more information about derivatives please refer to Note 8.
Non-current other financial assets include contributions made for
environmental obligations according to a Colombian and Brazilian
2.23 Borrowings
government request and are restricted for those purposes.
Borrowings are obligations to pay cash and are recognized when the Group
becomes a party to the contractual provisions of the instrument.
Current other financial assets include short-term investments with original
maturities up to twelve months and over three months. As of 31 December
Borrowings are recognized initially at fair value, net of transaction costs
2017, they also included the security deposit granted in relation to the
incurred. Borrowings are subsequently stated at amortized cost; any difference
purchase of Argentinian assets (see Note 35.3).
between the proceeds (net of transaction costs) and the redemption value is
2.19 Impairment of financial assets
borrowings using the effective interest method.
The Group assesses on a forward-looking basis the expected credit losses
associated with its debt instruments. The impairment methodology applied
Direct issue costs are charged to the Consolidated Statement of Income on an
depends on whether there has been a significant increase in credit risk. For
accrual basis using the effective interest method.
recognized in the Consolidated Statement of Income over the period of the
trade receivables, the Group applies the simplified approach permitted by
IFRS 9, which requires expected lifetime losses to be recognized from initial
2.24 Share capital
recognition of the receivables.
Equity comprises the following:
• “Share capital” representing the nominal value of equity shares.
• “Share premium” representing the excess over nominal value of the fair value
168 GeoPark 20F
of consideration received for equity shares, net of expenses of the share
The policy for managing these risks is set by the Board of Directors. Certain
issuance.
• “Other reserve” representing:
risks are managed centrally, while others are managed locally following
guidelines communicated from the corporate department. The policy for each
– the equity element attributable to shares granted according to IFRS 2 but
of the above risks is described in more detail below.
not issued at year end or,
– the difference between the proceeds from the transaction with non-
Currency risk
controlling interests received against the book value of the shares acquired
In Colombia, Chile, Argentina and Peru the functional currency is the US Dollar.
in the Chilean and Colombian subsidiaries.
The fluctuation of the local currencies of these countries against the US Dollar
• “Translation reserve” representing the differences arising from translation of
does not impact the loans, costs and revenue held in US Dollars; but it does
investments in overseas subsidiaries.
impact the balances denominated in local currencies. Such is the case of the
• “(Accumulated losses) Retained earnings” representing accumulated earnings
prepaid taxes.
and losses.
2.25 Share-based payment
In Colombian, Chilean, Argentinean and Peruvian subsidiaries most of the
balances are denominated in US Dollars, and since it is the functional currency
The Group operates a number of equity-settled share-based compensation
of the subsidiaries, there is no exposure to currency fluctuation except from
plans comprising share awards payments to certain employees and other
receivables or payables originated in local currency mainly corresponding to
third-party contractors. Share-based payment transactions are measured in
VAT and income tax.
accordance with IFRS 2.
Fair value of the stock option plan for employee or contractors services
Argentina and Peru by seeking to balance local and foreign currency assets
received in exchange for the grant of the options is recognized as an expense.
and liabilities. However, tax receivables (VAT) seldom match with local
The total amount to be expensed over the vesting period is determined
currency liabilities. Therefore, the Group maintains a net exposure to them,
by reference to the fair value of the options granted calculated using the
except for what it is described below.
The Group minimises the local currency positions in Colombia, Chile,
Geometric Brownian Motion method.
Non-market vesting conditions are included in assumptions about the
currency fluctuation with respect to income tax balances in Colombia.
number of options that are expected to vest. At each balance sheet date, the
Consequently, the Group entered into a derivative financial instrument with a
entity revises its estimates of the number of options that are expected to
local bank in Colombia, for an amount equivalent to US$ 92,050,000, in order
vest. It recognizes the impact of the revision to original estimates, if any, in
to anticipate any currency fluctuation with respect to income taxes to be paid
the Consolidated Statement of Income, with a corresponding adjustment to
during the first half of 2019. The Group’s derivatives are accounted for as non-
In December 2018, GeoPark decided to manage its future exposure to local
equity.
hedge derivatives as of 31 December 2018 and therefore all changes in the fair
values of its derivative contracts are recognized as gains or losses in the results
The fair value of the share awards payments is determined at the grant date
of the periods in which they occur. Considering that the instrument was
by reference of the market value of the shares and recognized as an expense
subscribed by year-end, as of 31 December 2018 the impact was not material.
over the vesting period. When the awards are exercised, the Company issues
new shares. The proceeds received net of any directly attributable transaction
Most of the Group’s assets held in those countries are associated with oil and
costs are credited to share capital (nominal value) and share premium when
gas productive assets. Those assets, even in the local markets, are generally
the options are exercised.
settled in US Dollar equivalents.
Note 3
Financial Instruments-risk management
During 2018, the Colombian Peso devalued by 9% (revalued by 1% in 2017
and 5% in 2016) against the US Dollar, the Chilean Peso devalued by 13%
The Group is exposed through its operations to the following financial risks:
(revalued by 8% in 2017 and devalued by 6% in 2016), the Argentine Peso
• Currency risk
• Price risk
• Credit risk – concentration
• Funding and liquidity risk
• Interest rate risk
• Capital risk management
devalued by 102% (17% and 22% in 2017 and 2016) and the Peruvian Peso
devalued by 4% (revalued by 4% in 2017 and 2% in 2016).
If the Colombian Peso, the Chilean Peso, the Argentine Peso and the Peruvian
Peso had each devalued an additional 10% against the US dollar, with all other
variables held constant, post-tax profit for the year would have been lower by
US$ 57,000 (post-tax loss higher by US$ 1,538,000 in 2017 and US$ 2,683,400
in 2016).
GeoPark 169
In Brazil, the functional currency is the local currency, which is the Brazilian
In Argentina, the realized oil prices for our production in the Neuquen
Real. The fluctuation of the US Dollars against the Brazilian Real does not
Basin follows the “Medanito” blend oil price reference, which has
impact the loans, costs and revenues held in Brazilian Real; but it does impact
traditionally been linked to ICE Brent adjusted by certain marketing
the balances denominated in US Dollars. Such is the case of the provision
and quality discounts based on API, delivery point and transport costs.
for asset retirement obligation and the intercompany loan, which was fully
Between May and November 2018, Medanito crude prices were capped
cancelled in October 2018, reducing significantly the exposure to foreign
industry-wide between US$ 65 per barrel and US$ 70 per barrel. Since
currency fluctuation. The exchange loss generated by the Brazilian subsidiary
December 2018, domestic prices have reconnected to the international
during 2018 amounted to US$ 5,862,000 (loss of US$ 1,274,000 in 2017 and
benchmark.
gain of US$ 14,542,000 in 2016).
During 2018, the Brazilian Real devalued by 17% against the US Dollar
go from May to April. The price of the gas sold under these contracts
(devalued by 2% in 2017 and revalued by 17% in 2016, respectively). If the
depends mainly on domestic supply and demand and regulation affecting
Gas sales in Argentina are carried out through annual contracts that
Brazilian Real had devalued 10% against the US dollar, with all other variables
the sector.
held constant, post-tax profit for the year would have been lower by US$
515,000 (post-tax loss higher by US$ 3,100,000 in 2017 and US$ 5,300,000 in
If oil and methanol prices had fallen by 10% compared to actual prices
2016).
during the year, with all other variables held constant, considering the
impact of the derivative contracts in place, post-tax profit for the year
As currency rate changes between the US Dollar and the local currencies, the
would have been lower by US$ 13,709,000 (post-tax loss higher by
Group recognizes gains and losses in the Consolidated Statement of Income.
US$ 10,423,000 in 2017 and US$ 23,655,000 in 2016).
Price risk
Since October 2016, GeoPark decided to manage part of the exposure
The realized oil price for the Group is linked to US dollar denominated
to crude oil price volatility using derivatives. The Group considers these
crude oil international benchmarks. The market price of this commodity
derivative contracts to be an effective manner of properly managing
is subject to significant volatility and has historically fluctuated widely in
commodity price risk. The price risk management activities mainly employ
response to relatively minor changes in the global supply and demand for
combinations of options and key parameters are based on forecasted
oil, the geopolitical landscape, the economic conditions and a variety of
production and budget price levels. GeoPark has also obtained credit
additional factors. The main factors affecting realized prices for gas sales
lines from industry leading counterparties to minimize the potential cash
vary across countries with some closely linked to international references
exposure of the derivative contracts (see Note 8).
while others are more domestically driven.
In Colombia, the realized oil price is linked to the Vasconia crude reference
The Group’s credit risk relates mainly to accounts receivable where the
price, a marker broadly used in the Llanos basin, adjusted for certain
credit risks correspond to the recognized values of commodities sold.
marketing and quality discounts based on, among other things, API,
GeoPark considers that there is no significant risk associated to the Group’s
viscosity, sulphur content, water content, delivery point and transport
major customers and hedging counterparties.
Credit risk – concentration
costs.
In Colombia, during 2018, the Colombian subsidiary made 99% of the oil
In Chile, the oil price is based on Dated Brent minus certain marketing and
sales to Trafigura (one of the world’s leading independent commodity
quality discounts such as, API, sulphur content and others.
trading and logistics houses), with Trafigura accounting for 82% of the
GeoPark has signed a long-term Gas Supply Contract with Methanex in
term contract with Trafigura in December 2018, GeoPark begun diversifying
Chile. The price of the gas sold under this contract is determined by a
its client base in Colombia, allocating sales on a competitive basis to
formula that considers a basket of international methanol prices, including
industry leading participants including traders and other producers. The
US Gulf methanol spot barge prices, methanol spot Rotterdam prices and
contracts extend through 2019 with no longer term delivery commitments
consolidated revenue for the same period. With the expiration of our long-
spot prices in Asia.
in place. Delivery points include wellhead and other locations on the
Colombian pipeline system. GeoPark manages its counterparty credit risk
In Brazil, prices for gas produced in the Manati Field are based on a long-
associated to sales contracts by including early payment conditions to
term off-take contract with Petrobras. The price of gas sold under this
minimize the exposure.
contract is denominated in Brazilian Real and is adjusted annually for
inflation pursuant to the Brazilian General Market Price Index (Indice Geral
All the oil produced in Chile as well as the gas produced by TdF blocks (3%
de Preços do Mercado), or IGPM.
170 GeoPark 20F
of the consolidated revenue, 5% in 2017 and 10% in 2016) is sold to ENAP,
test covenants related to compliance with certain thresholds of Net Debt to
the State-owned oil and gas company. In Chile, most of gas production is
Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply
sold to the local subsidiary of Methanex, a Canadian public company (3% of
with the incurrence test covenants does not trigger an event of default.
the consolidated revenue, 5% in 2017 and 9% in 2016).
However, this situation may limit the Group’s capacity to incur additional
In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the
date of these Consolidated Financial Statements, the Group is in compliance
State-owned company, which is the operator of the Manati Field (5% of the
with all the indenture’s provisions and covenants.
indebtedness, as specified in the indenture governing the Notes. As of the
consolidated revenue, 10% in 2017 and 15% in 2016).
The most significant funding transactions executed during 2018 and 2017
In Argentina, all the gas produced is sold to Grupo Albanesi, a leading
include:
Argentine privately-held conglomerate focused on the energy market that
offers natural gas, power supply and transport services to its customers.
In October 2018, the Brazilian subsidiary executed a loan agreement with
GeoPark has an annual agreement in effect from May 2018 through April
Banco Santander for Brazilian Real 77,640,000 (equivalent to US$ 20,000,000
2019. Gas sales in Argentina account for 1% of the consolidated revenues.
at the moment of the loan execution) to repay an existing US$-denominated
The oil sales in Argentina are diversified across clients and delivery points:
The interest rate applicable to this loan is CDI plus 2.25% per annum. “CDI”
i) 30% of the oil produced in Argentina (2% of the consolidated revenue)
(Interbank certificate of deposit) represents the average rate of all inter-bank
is sold locally in Neuquen, delivered at well-head; and ii) 70% of the oil
overnight transactions in Brazil. The principal and the interest are paid semi-
produced in Argentina (3% of the consolidated revenue) is sold to major
annually, with final maturity in October 2020.
intercompany loan to GeoPark Latin America Limited - Agencia en Chile.
Argentinean refineries, delivered via pipeline. GeoPark manages the
counterparty credit risk associated to sales contracts by limiting payment
In April 2018, the Colombian subsidiary executed an offtake and prepayment
terms offered to minimize the exposure.
agreement with Trafigura, one of its customers. The prepayment agreement
provided GeoPark with access to up to US$ 25,000,000 in the form of prepaid
The forementioned companies all have a good credit standing and despite
future oil sales. The availability period for the prepayment agreement expires
the concentration of the credit risk, the Directors do not consider there to
on 31 March 2019. As of the date of these Consolidated Financial Statements,
be a significant collection risk.
GeoPark has not withdrawn any amount from this prepayment agreement.
Since October 2016, the Group has executed oil prices hedges via over-the-
In September 2017, the Company successfully placed US$ 425,000,000 Notes.
counter derivatives. Should oil prices drop, the Group could stand to collect
These Notes carry a coupon of 6.50% per annum and their final maturity will
from its counterparties under the derivative contracts. The Group’s hedging
be 21 September 2024. The net proceeds from the Notes were used by the
counterparties are leading financial institutions and trading companies,
Group to fully repay the 7.50% senior secured Notes due 2020 and for general
therefore the Directors do not consider there to be a significant collection
corporate purposes, including capital expenditures and to repay other existing
risk.
See disclosure in Notes 8 and 25.
Funding and Liquidity risk
indebtedness.
Interest rate risk
The Group’s interest rate risk arises from long-term borrowings issued at
variable rates, which expose the Group to interest rate risk.
In the past, the Group was able to raise capital through different sources of
funding including equity, strategic partnerships and financial debt. During
The Group does not face interest rate risk on its US$ 425,000,000 Notes which
2017, the Group placed US$ 425,000,000 Notes (see Note 27).
carry a fixed rate coupon of 6.50% per annum. Consequently, the accruals and
interest payment are not substantially affected by the market interest rate
The Group is positioned at the end of 2018 with a cash balance of US$
changes.
127,727,000 and over 95% of its total indebtedness matures in 2024. In
addition, the Group has a large portfolio of attractive and largely discretional
At 31 December 2018, the outstanding long-term borrowing affected by
projects - both oil and gas - in multiple countries with over 39,000 boepd in
a variable rate amounted to US$ 19,750,000, representing 4.5% of total
production at year end. This scale and positioning permit the Group to protect
borrowings. It corresponds to a loan from Santander Bank taken by the
its financial condition and selectively allocate capital to the optimal projects
Brazilian subsidiary that has a floating interest rate based on CDI (Interbank
subject to prevailing macroeconomic conditions.
certificate of deposit), which represents the average rate of all inter-bank
The Indenture governing the Company Notes 2024 includes incurrence
overnight transactions in Brazil.
GeoPark 171
The Group analyses its interest rate exposure on a dynamic basis. Various
Statements are noted below:
scenarios are simulated taking into consideration refinancing, renewal
of existing positions, alternative financing and hedging. Based on these
• Cash flow estimates for impairment assessments of non-financial
scenarios, the Group calculates the impact on profit and loss of a defined
assets require assumptions about two primary elements: future prices
interest rate. For each simulation, the same interest rate is used for all
and reserves. Estimates of future prices require significant judgments
currencies. The scenarios are run only for liabilities that represent the major
about highly uncertain future events. Historically, oil and gas prices
interest-bearing positions.
have exhibited significant volatility. The Group’s forecasts for oil and gas
revenues are based on prices derived from future price forecasts amongst
At 31 December 2018, if 1% is added to interest rates on currency-
industry analysts and internal assessments. Estimates of future cash flows
denominated borrowings with all other variables held constant, post-tax
are generally based on assumptions of long-term prices and operating and
profit for the year would have been lower by US$ 21,000 (no exposure to
development costs.
fluctuations in the interest rate in 2017 and post-tax loss higher by US$
467,000 in 2016).
Capital risk management
Given the significant assumptions required and the possibility that
actual conditions may differ, management considers the assessment of
impairment to be a critical accounting estimate (see Note 36).
The Group’s objectives when managing capital are to safeguard the Group’s
ability to continue as a going concern in order to provide returns for
The process of estimating reserves is complex. It requires significant
shareholders and benefits for other stakeholders and to maintain an optimal
judgements and decisions based on available geological, geophysical,
capital structure to reduce the cost of capital.
engineering and economic data. The estimation of economically
Consistent with others in the industry, the Group monitors capital on the basis
was performed based on the Reserve Report as of 31 December 2018
of the gearing ratio. This ratio is calculated as net debt divided by total capital.
prepared by DeGolyer and MacNaughton, an independent international
Net debt is calculated as total borrowings (including ‘current and non-current
consultancy to the oil and gas industry based in Dallas. It incorporates
borrowings’ as shown in the consolidated balance sheet) less cash and cash
many factors and assumptions including:
equivalents. Total capital is calculated as ‘equity’ as shown in the consolidated
balance sheet plus net debt.
– expected reservoir characteristics based on geological, geophysical and
recoverable oil and natural gas reserves and related future net cash flows
The Group’s strategy, due to the market conditions prevailing during the last
– future production rates based on historical performance and expected
years and the growth strategy of the Group, is to keep the gearing ratio within
future operating and investment activities;
a 60% to 80% range.
– future oil and gas prices and quality differentials;
– assumed effects of regulation by governmental agencies; and
The gearing ratios at 31 December 2018 and 2017 were as follows:
– future development and operating costs.
engineering assessments;
Amounts in US$ ‘000
Net Debt
Total Equity
Total Capital
Gearing Ratio
Note 4
Accounting estimates and assumptions
2018
319,275
143,021
462,296
69%
2017
Management believes these factors and assumptions are reasonable based
291,449
on the information available to them at the time of preparing the estimates.
126,840
However, these estimates may change substantially as additional data from
418,289
ongoing development activities and production performance becomes available
70%
and as economic conditions impacting oil and gas prices and costs change.
• The Group adopts the successful efforts method of accounting. The
Management of the Group makes assessments and estimates regarding
Estimates and assumptions are used in preparing the financial statements.
whether an exploration and evaluation asset should continue to be carried
Although these estimates are based on management’s best knowledge
forward as such when insufficient information exists. This assessment is made
of current events and actions, actual results may differ. Estimates and
on a quarterly basis considering the advice from qualified experts.
judgements are continually evaluated and are based on historical experience
and other factors, including expectations of future events that are believed
• Oil and gas assets held in property plant and equipment are mainly
to be reasonable under the circumstances.
depreciated on a unit of production basis at a rate calculated by reference to
The key estimates and assumptions used in these Consolidated Financial
of developing and extracting those reserves. Future development costs are
proven and probable reserves and incorporating the estimated future cost
172 GeoPark 20F
estimated using assumptions as to the numbers of wells required to produce
Amounts in US$ ‘000
2018
2017
2016
those reserves, the cost of the wells and future production facilities.
(Decrease) Increase in asset
• Obligations related to the abandonment of wells once operations are
(Decrease) Increase in provisions
terminated may result in the recognition of significant obligations. Estimating
for other long-term liabilities
(60)
the future abandonment costs is difficult and requires management to
Purchase of property, plant and equipment
1,100
2,053
11,759
3,468
(4,657)
make estimates and judgments because most of the obligations are many
years in the future. Technologies and costs are constantly changing as well
Changes in working capital shown in the Consolidated Statement of Cash
retirement obligation
(4,355)
5,943
1,195
as political, environmental, safety and public relations considerations. The
Flow are disclosed as follows:
Group has adopted the following criterion for recognizing well plugging and
abandonment related costs: The present value of future costs necessary for
Amounts in US$ ‘000
well plugging and abandonment is calculated for each area at the present
Increase in Prepaid taxes
value of the estimated future expenditure. The liabilities recognized are based
Decrease (Increase) in Inventories
upon estimated future abandonment costs, wells subject to abandonment,
Decrease (Increase) in Trade receivables
time to abandonment, and future inflation rates.
Decrease (Increase) in Prepayments and
2018
2017
(36,716)
(14,802)
511
3,423
(2,031)
(1,344)
2016
(2,351)
466
(4,811)
• From time to time, the Group may be subject to various lawsuits, claims
and proceedings that arise in the normal course of business, including
employment, commercial, tax, environmental, safety and health matters.
Customer advance (repayments)
payments (a)
Security deposit utilised
For example, from time to time, the Group receives notice of environmental,
(granted) (Note 35.3)
health and safety violations. Based on what the Management of the Group
Increase in Trade and other payables
currently knows, it is not expected any material impact on the financial
(10,000)
(10,000)
20,000
15,600
20,169
(15,600)
27,122
-
374
(6,358)
(25,278)
11,920
other receivables and Other assets
655
(8,623)
(1,758)
statements.
Note 5
Consolidated Statement of Cash Flow
(a) In December 2015, the Colombian subsidiary entered into a prepayment
agreement with Trafigura under which GeoPark sells and deliver a portion
of its Colombian crude oil production. Funds committed were repaid by the
The Consolidated Statement of Cash Flow shows the Group’s cash flows for the
Group on a monthly basis through future oil deliveries until December 2018.
year for operating, investing and financing activities and the change in cash
and cash equivalents during the year.
Note 6
Segment information
Cash flows from operating activities are computed from the results for the
Operating segments are reported in a manner consistent with the internal
year adjusted for non-cash operating items, changes in net working capital,
reporting provided to the chief operating decision-maker. The chief operating
and corporate tax. Income tax paid is presented as a separate item under
decision-maker, who is responsible for allocating resources and assessing
operating activities.
performance of the operating segments, has been identified as the Executive
Committee. This committee is integrated by the CEO, COO, CFO and managers
Cash flows from investing activities include payments in connection with the
in charge of the Geoscience, Operations, Corporate Governance, Finance and
purchase and sale of property, plant and equipment and cash flows relating to
People departments. This committee reviews the Group’s internal reporting
the purchase and sale of enterprises to third parties, if any.
in order to assess performance and to allocate resources. Management has
determined the operating segments based on these reports. The committee
Cash flows from financing activities include changes in equity, and proceeds
considers the business from a geographic perspective.
from borrowings and repayment of loans.
Cash and cash equivalents include bank overdraft and liquid funds with a term
based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit
The Executive Committee assesses the performance of the operating segments
of less than three months.
for the period before net finance cost, income tax, depreciation, amortization,
certain non-cash items such as impairments and write-offs of unsuccessful
The following chart describes non-cash transactions related to the
efforts, accrual of share-based payment, unrealized result on commodity risk
Consolidated Statement of Cash Flow:
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.
GeoPark 173
Segment areas (geographical segments):
Amounts in US$ ‘000
2018
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 operating costs
Operating profit (loss)
Operating netback
Adjusted EBITDA
Depreciation
Reversal (recognition) of
impairment losses
Write-off
Total assets
Employees (average)
Employees at year end
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 operating costs
Operating profit (loss)
Operating netback
Adjusted EBITDA
Depreciation
Write-off
Total assets
Employees (average)
Employees at year end
174 GeoPark 20F
Colombia
Chile
Brazil
Argentina
Peru
Corporate
Total
497,870
496,341
1,529
37,359
17,402
19,957
(26,098)
-
(118,533)
(21,899)
(62,710)
(1,258)
(461)
(54,104)
309,357
352,672
319,447
(1,473)
(1,250)
(226)
(18,950)
(29,139)
15,153
8,784
30,053
1,198
28,855
-
(8,785)
(2,820)
-
(37)
(5,928)
4,370
21,306
17,908
35,879
30,549
5,330
-
(25,043)
(4,833)
(120)
(154)
(19,936)
(6,739)
8,527
4,576
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(4,529)
(16,828)
-
-
(7,077)
(13,082)
601,161
545,490
55,671
(26,098)
(174,260)
(71,836)
(2,628)
(878)
(98,918)
256,492
397,658
330,556
(42,721)
(28,203)
(10,395)
(10,640)
(245)
(36)
(92,240)
11,531
(17,665)
383,450
(6,549)
(6,121)
276,449
182
178
101
100
-
(2,020)
70,424
12
12
-
(583)
87,259
121
137
-
-
-
-
35,817
9,261
4,982
(26,389)
862,660
27
28
2
2
445
457
Colombia
Chile
Brazil
Argentina
Peru
Corporate
Total
263,076
262,309
767
(2,148)
(66,913)
(24,236)
(1,678)
(248)
(40,751)
116,290
194,013
168,303
(40,010)
(1,625)
288,429
32,738
15,873
16,865
-
(20,999)
(1,314)
(1,211)
(170)
(18,304)
(19,675)
11,222
4,070
34,238
910
33,328
-
(10,737)
(3,134)
-
(39)
(7,564)
4,434
23,540
20,166
(23,730)
(10,809)
(546)
301,931
(2,978)
91,604
70
70
-
-
(338)
(13)
(80)
-
(245)
(3,430)
(467)
(2,183)
(159)
(685)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(3,850)
(14,773)
-
-
(3,505)
(11,075)
(139)
-
(38)
-
30,924
22,099
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
164
180
102
102
12
12
88
92
13
19
-
-
379
405
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 operating costs
Operating profit (loss)
Operating netback
Adjusted EBITDA
Depreciation
Reversal of impaiment losses
Write-off
Total assets
Employees (average)
Employees at year end
Colombia
Chile
Brazil
Argentina
Peru
Corporate
Total
126,228
125,731
497
514
36,723
18,774
17,949
-
(36,607)
(22,169)
(7,281)
(1,111)
(413)
(27,802)
31,463
87,523
66,921
(1,495)
(1,170)
(138)
(19,366)
(44,969)
13,696
5,159
29,719
688
29,031
-
(8,459)
(2,721)
-
(71)
(5,667)
(645)
21,356
17,487
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
370
(378)
1,848
(3,147)
(11,685)
41
(91)
(2,607)
(10,487)
192,670
145,193
47,477
514
(67,235)
(11,497)
(2,281)
(622)
(52,835)
(28,613)
122,147
78,321
(31,148)
(31,355)
(12,974)
(150)
(130)
(17)
(75,774)
5,664
(7,394)
182,784
-
(19,389)
317,969
138
146
102
102
-
(4,583)
99,904
10
10
-
-
-
-
-
-
6,071
5,020
28,792
5,664
(31,366)
640,540
80
77
11
10
-
-
341
345
Approximately 78% of capital expenditure was incurred by Colombia (76% in 2017 and 67% in 2016), 6% was incurred by Chile (10% in 2017 and 20% in 2016),
2% was incurred by Brazil (3% in 2017 and 9% in 2016), 7% was incurred by Argentina (8% in 2017 and 4% in 2016) and 7% was incurred by Peru ( 3% in 2017 and
nil in 2016).
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
2018
2017
2016
Amounts in US$ ‘000
397,658
228,308
122,147
Sale of crude oil
(48,028)
(19,074)
(38,937)
(13,595)
(32,323)
Sale of gas
(11,503)
2018
545,490
55,671
2017
279,162
50,960
2016
145,193
47,477
601,161
330,122
192,670
for reportable segments
330,556
175,776
78,321
Note 8
Unrealized gain (loss) on commodity
Commodity risk management contracts
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
42,271
(92,240)
(5,446)
(21,407)
2,758
256,492
(39,321)
3,059
(11,323)
(13,300)
(74,885)
(4,075)
(5,834)
1,314
78,996
(53,511)
2,016
(2,193)
(3,068)
The Group has entered into derivative financial instruments to manage its
(75,774)
exposure to oil price risk. These derivatives are zero-premium collars or zero-
(3,367)
premium 3 ways (put spread plus call), and were placed with major financial
institutions and commodity traders. The Group entered into the derivatives
(25,702)
under ISDA Master Agreements and Credit Support Annexes, which provide
977
credit lines for collateral posting thus alleviating possible liquidity needs
(28,613)
under the instruments and protect the Group from potential non-performance
(36,229)
risk by its counterparties. The Group’s derivatives are accounted for as non-
2,128
hedge derivatives as of 31 December 2018 and therefore all changes in the fair
13,872
values of its derivative contracts are recognised as gains or losses in the results
Profit (Loss) before tax
(a) Net of capitalized costs for oil stock included in Inventories.
(b) Includes allocation to capitalized projects.
208,907
25,308
(48,842)
of the periods in which they occur.
GeoPark 175
The following table presents the Group’s derivative contracts in force as of 31 December 2018:
Period
1 April 2018 - 31 December 2018
1 April 2018 - 31 December 2018
1 July 2018 - 31 March 2019
1 July 2018 - 31 March 2019
1 October 2018 - 30 June 2019
1 October 2018 - 30 June 2019
1 October 2018 - 30 June 2019
1 January 2019 - 30 September 2019
1 January 2019 - 30 September 2019
Reference
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
Type
Volume bbl/d
Price US$/bbl
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium 3 Way
Zero Premium Collar
Zero Premium Collar
3,000
1,000
2,000
2,000
3,700
1,000
1,300
2,000
3,000
45.00-55.00 Put 77.15 Call
45.00-55.00 Put 77.50 Call
50.00-60.00 Put 97.00 Call
50.00-60.00 Put 97.05 Call
55.00-65.00 Put 90.00 Call
55.00-65.00 Put 90.10 Call
55.00-65.00 Put 90.50 Call
65.00 Put 92.50 Call
65.00 Put 92.26 Call
The table below summarizes the gain (loss) on the commodity risk management contracts:
Realized (loss) gain on commodity risk management contracts
Unrealized gain (loss) on commodity risk management contracts
2018
(26,098)
42,271
16,173
2017
(2,148)
(13,300)
(15,448)
2016
514
(3,068)
(2,554)
Note 10
Depreciation
2016
Amounts in US$ ‘000
13,160
Oil and gas properties
2,137
Production facilities and machinery
8,722
Furniture, equipment and vehicles
622
Buildings and improvements
2018
72,130
17,958
1,579
996
2017
57,725
14,558
1,948
844
2016
61,080
10,788
2,702
920
11,497
8,283
2,281
3,868
2,222
6,300
1,687
1,082
5,374
Depreciation of property,
plant and equipment (a)
92,663
75,075
75,490
Related to:
Productive assets
Administrative assets
Depreciation total (a)
90,088
2,575
92,663
72,283
2,792
75,075
71,868
3,622
75,490
(a) Depreciation without considering capitalized costs for oil stock
included in Inventories.
2017
14,722
3,116
11,901
457
28,697
11,902
2,969
5,818
2,591
6,069
2,377
1,213
7,155
98,987
67,235
Total
Note 9
Production and operating costs
Amounts in US$ ‘000
Well and facilities maintenance
Operation and maintenance
Staff cost (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
2018
20,262
7,756
17,725
878
71,836
17,444
2,628
9,317
3,878
5,967
2,959
1,327
12,283
174,260
176 GeoPark 20F
Note 11
Staff costs and Directors Remuneration
Number of employees at year end
Amounts in US$ ‘000
Wages and salaries
Share-based payments (Note 30)
Social security charges
Director’s fees and allowance
Recognised as follows:
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Board of Directors’ and key
managers’ remuneration
Salaries and fees
Share-based payments
Other benefits in kind
2018
457
2017
405
2016
345
52,644
41,775
33,922
5,446
7,464
2,876
4,075
5,364
3,458
3,367
3,792
2,088
68,430
54,672
43,169
18,603
15,527
34,300
68,430
12,358
11,026
31,288
54,672
9,344
10,439
23,386
43,169
12,452
2,918
272
9,674
2,322
287
15,642
12,283
7,337
1,211
112
8,660
Directors’ Remuneration
Gerald O’Shaughnessy
James F. Park
Pedro Aylwin (a)
Juan Cristóbal Pavez (b)
Carlos Gulisano (c)
Robert Bedingfield (d)
Jamie Coulter
Constantine Papadimitriou
Executive Directors’
Executive Directors’
Non-Executive
Director Fees Paid in
Cash Equivalent Total
Fees (in US$)
Bonus (in US$)
Directors’ Fees (in US$)
Shares (No. of Shares)
Remuneration (in US$)
400,000
800,000
26,000
-
-
-
-
-
-
695,506
-
-
-
-
-
-
-
-
-
110,000
110,000
110,000
75,000
40,000
-
-
-
7,596
7,596
7,596
7,596
2,761
400,000
1,495,506
26,000
210,000
210,000
210,000
175,000
90,000
a Pedro E. Aylwin has a service contract that provides for him to act as Director of Legal and Governance.
b Compensation Committee Chairman.
c Technical Committee Chairman.
d Audit Committee Chairman.
On 2 January 2019, 439,075 shares were issued to Directors as a consequence of the vesting of the Value Creation Plan (”VCP”). See Note 30.
GeoPark 177
Note 12
Geological and geophysical expenses
Note 15
Financial results
Amounts in US$ ‘000
Staff costs (Note 11)
Share-based payment (Notes 11)
Allocation to capitalized project
Other services
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
2018
15,005
522
(5,645)
4,069
13,951
2018
27,378
4,046
7,427
3,021
3,730
2,876
2,395
(7,774)
8,975
52,074
2017
10,525
501
(6,402)
3,070
7,694
2017
24,713
3,117
5,120
2,506
2,772
3,458
2,109
(7,646)
5,905
42,054
2016
9,541
Amounts in US$ ‘000
Financial expenses
898
Interest and amortization
(2,119)
of debt issue costs
1,962
Interest with related parties
10,282
Less: amounts capitalized
on qualifying assets
Borrowings cancellation costs
Bank charges and other financial results
Unwinding of long-term liabilities
2016
19,451
Financial income
Interest received
Foreign exchange gains and losses
Foreign exchange (loss) gain
1,847
3,894
2,217
1,717
2,088
2,013
2018
2017
2016
(28,955)
(1,606)
(27,823)
(2,224)
(28,984)
(1,587)
258
-
(5,513)
(3,505)
611
(17,575)
(3,721)
(2,779)
255
-
(3,220)
(2,693)
(39,321)
(53,511)
(36,229)
3,059
3,059
2,016
2,016
2,128
2,128
(11,323)
(11,323)
(2,193)
(2,193)
13,872
13,872
(4,365)
Total Financial results
(47,585)
(53,688)
(20,229)
5,308
34,170
Note 16
Tax reforms
Colombia
2018
2,638
1,385
4,023
2017
864
272
1,136
In December 2018, a tax reform was enacted in Colombia. The approved
legislation included significant changes in the corporate income tax but
also in other taxes and in tax related matters (as procedural rules and special
2016
3,559
663
regimes). This tax reform was effective 1 January 2019.
4,222
The new legislation includes a progressive reduction of the general corporate
income tax rate, previously established at 40% for 2017 and 37% for 2018, as
follows:
• 33% in 2019
• 32% in 2020
• 31% in 2021
• 30% in 2022 and onwards.
Other changes that could affect the Group are the following:
• The withholding tax rate on dividends for non-resident shareholders was
increased from 5% to 7.5%.
• The withholding tax rates applicable on payments to non-residents on behalf
of consultancy, technical services, technical assistance, software and interests
on loans of less than one year were increased from 15% to 20% (for loans with
maturity exceeding one year, the 15% rate remained unchanged).
• The withholding tax rate applicable on payments to entities resident
of countries considered to be tax havens, non-cooperative or to grant a
Note 14
Selling expenses
Amounts in US$ ‘000
Transportation
Selling taxes and other
178 GeoPark 20F
preferential tax regime was increased from 15% to the corporate income
Note 17
tax rate (33 % for 2019, 32% for 2020, 31% for 2021 and 30% for 2022 and
Income tax
onwards).
• The deduction of interest attributed to a permanent establishment in
Amounts in US$ ‘000
Colombia on behalf of its head office debt was limited to interest that had
Current tax
2018
2017
2016
(101,456)
(48,449)
(12,359)
been subject to Colombian withholding tax.
Deferred income tax (Note 18)
(4,784)
5,304
555
• Regarding thin capitalization for income tax purposes, the maximum
amount of debt which interest can be deducted was reduced from 3 to 2
(106,240)
(43,145)
(11,804)
times the net equity of the taxpayer as of 31 December of the previous year.
The tax on the Group’s profit (loss) before tax differs from the theoretical
• Transfers of participations in foreign entities that represent indirect disposals
amount that would arise using the weighted average tax rate applicable to
of assets in Colombia became subject to income tax or to the occasional
profits of the consolidated entities as follows:
earnings tax, depending on certain circumstances.
• VAT paid for acquisition of productive fixed assets could be credited against
corporate income tax.
Amounts in US$ ‘000
• An audit benefit was granted by the reform, establishing that tax returns of
Profit (loss) before tax
2018
208,907
2017
25,308
2016
(48,842)
FY 2019 and 2020 showing a net income tax 30% or 20% higher, respectively,
Tax losses from non-taxable
than the one declared in the previous year would be considered definitive 6
jurisdictions
months or 12 months after became due, also respectively, if there were no
Taxable profit (loss)
42,808
251,715
22,708
48,016
12,318
(36,524)
objections or requests from the tax authority.
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
(102,211)
(31,107)
(809)
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
tax benefit is recognized
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.
Previously unrecognized tax losses
Non-taxable results (a)
Income tax
(7,344)
3,336
(1,874)
4,882
(3,029)
(8,111)
(2,330)
(6,616)
(2,840)
542
-
220
-
(2,139)
(1,759)
(106,240)
(43,145)
(11,804)
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
(Colombia, Chile, Brazil, Argentina and Peru) ranges from 15% to 37%.
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
Chile (a)
Brazil (a)
Argentina (b)
Total tax losses at 31 December
2018
2017
2016
315,733
345,104
280,290
38,011
5,490
33,721
4,849
16,057
2,908
359,234
383,674
299,255
(a) Taxable losses have no expiration date.
GeoPark 179
Expiring date
2021
2022
(b) Expiring dates for tax losses accumulated at 31 December 2018 are:
Note 18
Amounts in US$ ‘000
The gross movement on the deferred income tax account is as follows:
Deferred income tax
372
5,118
Amounts in US$ ‘000
Deferred tax at 1 January
2018
25,350
(3,574)
(4,784)
2017
20,283
(237)
5,304
At the balance sheet date deferred tax assets in respect of tax losses in certain
Currency translation differences
companies in Chile have not been recognized as there is insufficient evidence
Income statement (charge) credit
of future taxable profits to offset them.
Deferred tax at 31 December
16,992
25,350
The breakdown and movement of deferred tax assets and liabilities as of 31 December 2018 and 2017 are as follows:
Amounts in US$ ‘000
Deferred tax assets
Difference in depreciation rates and other
Taxable losses
Total 2018
Total 2017
Amounts in US$ ‘000
Deferred tax liabilities
Difference in depreciation rates and other
Taxable losses
Total 2018
Total 2017
Note 19
Earnings per share
At the beginning
(Charged) /
Currency translation
Reclassification
At the end of year
of year
credited to net profit
differences
16,171
11,465
27,636
23,053
(16,383)
4,869
(11,514)
4,820
(1,897)
(1,677)
(3,574)
(237)
(968)
20,213
19,245
-
(3,077)
34,870
31,793
27,636
At the beginning
(Charged) /
Reclassification
At the end of year
of year
credited to net profit
(20,074)
17,788
(2,286)
(2,770)
4,305
2,425
6,730
484
968
(20,213)
(19,245)
-
(14,801)
-
(14,801)
(2,286)
Amounts in US$ ‘000 except for shares
Numerator Profit (Loss) for the year attributable to owners
Denominator: Weighted average number of shares used in basic EPS
Earnings (Losses) after tax per share (US$) – basic
Amounts in US$ ‘000 except for shares
Weighted average number of shares used in basic EPS
Effect of dilutive potential common shares (a)
Stock awards at US$ 0.001
Weighted average number of common shares for the purposes of diluted earnings per shares
Earnings (Losses) after tax per share (US$) – diluted
2018
72,415
2017
2016
(24,228)
(49,092)
60,612,230
60,093,191
59,777,145
1.19
(0.40)
(0.82)
2018
60,612,230
2017 (a)
60,093,191
2016 (a)
59,777,145
4,758,552
-
-
65,370,782
60,093,191
59,777,145
1.11
(0.40)
(0.82)
(a) For the year ended 31 December 2017, there were 4,564,777 (1,390,706 in 2016) of potential shares that could have a dilutive impact. They were considered
antidilutive due to negative earnings.
180 GeoPark 20F
Note 20
Property, plant and equipment
Amounts in US$ ‘000
Cost at 1 January 2016
Additions
Currency translation differences
Disposals
Write-off / Impairment reversal
Transfers
Cost at 31 December 2016
Additions
Currency translation differences
Disposals
Write-off
Transfers
Cost at 31 December 2017
Additions
Acquisitions (Note 35.3)
Currency translation differences
Disposals
Write-off / Impairment reversal
Transfers
Assets held for sale (Note 35.2)
Cost at 31 December 2018
Oil & gas
Furniture,
Production
Buildings and
Construction
Exploration
Total
properties
equipment
facilities and
improvements
in progress
648,992
(3,531) (a)
16,132
-
5,664
24,984
692,241
7,997 (a)
(1,142)
-
-
77,408
776,504
(5,753) (a)
52,925
(11,525)
-
5,109
63,794
(163,544)
717,510
and vehicles
machinery
13,745
124,832
10,518
406
126
(22)
-
102
466
2,077
-
-
5,038
-
35
-
-
-
14,357
132,413
10,553
954
(12)
(112)
-
211
15,398
1,706
254
(130)
(46)
-
566
-
17,748
(7,317)
(2,702)
8
(38)
-
(147)
-
-
25,130
157,396
-
1,616
(884)
(417)
(120)
14,503
-
172,094
(60,614)
(10,788)
-
(296)
(71,698)
(14,558)
-
24
-
(3)
(189)
-
-
10,361
-
134
(30)
-
-
-
11,554
(3,195)
(920)
-
(16)
(4,131)
(844)
38
5
(4,932)
(996)
-
26
-
1,089
(59,332)
and evaluation
assets(b)
87,000
18,181
790
-
(31,366) (c)
(12,832)
61,773
49,455
(104)
-
(5,834) (d)
(40,922)
914,910
35,844
19,233
(22)
(25,702)
-
944,263
125,359
(1,470)
(301)
(5,834)
-
64,368
1,062,017
43,515
-
(882)
-
(26,389) (e)
(20,620)
121,429
54,929
(13,466)
(463)
(21,407)
-
29,823
20,322
73
-
-
(17,292)
32,926
66,953
(62)
-
-
(61,827)
37,990
81,961
-
(15)
-
(7)
-
-
(163,544)
60,597
59,992
1,039,495
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(392,299)
(75,490)
8
(2,836)
(470,617)
(75,075)
111
967
(544,614)
(92,663)
191
6,747
148,014
(482,325)
473,646
517,403
557,170
Depreciation and write-down at 1 January 2016
(321,173)
Depreciation
Disposals
Currency translation differences
(61,080)
-
(2,486)
Depreciation and write-down at 31 December 2016
(384,739)
(10,049)
Depreciation
Disposals
Currency translation differences
(57,725)
(1,948)
-
930
73
8
Depreciation and write-down at 31 December 2017
(441,534)
Depreciation
Disposals
Currency translation differences
Assets held for sale (Note 35.2)
(72,130)
-
6,292
148,014
(11,916)
(1,579)
(86,232)
(17,958)
42
92
-
149
337
-
Depreciation and write-down at 31 December 2018
(359,358)
(13,361)
(103,704)
(5,902)
Carrying amount at 31 December 2016
Carrying amount at 31 December 2017
Carrying amount at 31 December 2018
307,502
334,970
358,152
4,308
3,482
4,387
60,715
71,164
68,390
6,422
5,429
5,652
32,926
37,990
60,597
61,773
64,368
59,992
(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$ 48,779,000 (US$ 53,764,000 in
2017 and US$ 53,523,000 in 2016).
GeoPark 181
Amounts in US$ ‘000
Exploration wells at 31 December 2016
Additions
Write-offs
Transfers
Exploration wells at 31 December 2017
Additions
Write-offs
Transfers
Exploration wells at 31 December 2018
Total
8,250
35,299
(3,664)
(29,281)
10,604
43,103
(23,733)
(18,761)
11,213
As of 31 December 2018, there were nine exploratory wells that have been
capitalized for a period less than a year amounting to US$ 10,069,000 and
three exploratory wells that have been capitalized for a period over a year
amounting to US$ 1,144,000.
(c) 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.
(d) 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.
(e) Corresponds to nine unsuccessful exploratory wells, four wells drilled in
Colombia (Tiple, Llanos 34 and Llanos 32 Blocks), two wells drilled in Brazil
(POT-T-747 and POT-T-619 Blocks) and three wells drilled in Argentina (Puelen
Block). The change also includes the write-off of a well and other exploration
costs incurred in the Fell Block (Chile) in previous years and other exploration
costs incurred in the VIM-3 Block (Colombia), and POT-T-882 and REC-T-93
Blocks (Brazil), for which no additional work would be performed.
182 GeoPark 20F
Note 21
Subsidiary undertakings
The following chart illustrates main companies of the Group structure as of 31 December 2018:
GeoPark Limited
(Bermuda)
100%
100%
GeoPark Latin
America Limited
(Bermuda)
GeoPark Argentina
Limited
(Bermuda)
100%
100%
GeoPark Latin
America Limited
Agencia en Chile
GeoPark Argentina
Limited - Argentinean
Branch
100%
GeoPark (UK)
Limited
100%
100%
100%
GeoPark Latin America
S.L.U. (Spain)
GeoPark Brazil S.L.U.
(Spain)
GeoPark Perú S.L.U.
(Spain)
91%
GeoPark Chile S.A.
(Chile)
9%
100%
100%
99.9%
99.9%
GeoPark Colombia
Coöperatie U.A.
(The Netherlands)
GeoPark Colombia
E&P S.A. (Panama)
GeoPark Brazil
Exploração e Produção
de Petróleo e Gás Ltda.
(Brazil)
GeoPark S.A.C.
(Perú)
100%
100%
99%
100%
100%
GeoPark TdF S.A.
(Chile)
GeoPark Fell SpA.
(Chile)
GeoPark
Magallanes
Limitada (Chile)
GeoPark Colombia
SAS (Colombia)
GeoPark Colombia
E&P S.A.
Sucursal Colombia
99.9%
99.9%
GeoPark Perú S.A.C.
(Perú)
GeoPark Operadora
del Perú S.A.C. (Perú)
Non-controlling interest that used to be held by LG International until 28 November 2018:
• Consolidated Statement of Comprehensive Income: Total comprehensive income for the year 2018 includes a profit of US$ 35,284,000 (US$ 13,536,000 in 2017
and US$ 2,791,000 in 2016), a loss of US$ 4,273,000 (US$ 6,200,000 in 2017 and US$ 10,379,000 in 2016) and a loss of US$ 758,000 (US$ 945,000 in 2017 and US$
3,966,000 in 2016) corresponding to non-controlling interest that used to be 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 included US$ 29,330,000, US$ 15,953,000 and a negative amount of US$
3,368,000 corresponding to non-controlling interest that used to be 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$ 8,089,000 in 2018 (US$ 479,000 in 2017 and US$
6,406,000 in 2016) correspond to non-controlling interest that used to be held by LGI in GeoPark Colombia Coöperatie U.A.
GeoPark 183
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 (Argentina)
GeoPark Latin America Limited (Bermuda)
GeoPark Latin America Limited – Agencia en Chile (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 S.A.S. (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 Brasil 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)
Llanos 34 Block (Colombia)
Llanos 32 Block (Colombia)
Puelen Block (Argentina)
Sierra del Nevado Block (Argentina)
CN-V Block (Argentina)
Manati Field (Brazil)
POT-T-747 Block (Brazil)
REC-T-128 Block (Brazil)
(a) Indirectly owned.
(b) Dormant companies.
(c) GeoPark is the operator.
Corporate structure reorganization
Ownership interest
100%
100% (a)
100%
100% (a)
100% (a) (b)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a) (b)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a)
100% (a) (b)
100% (a) (b)
100%
50% (c)
50% (c)
50% (c)
60% (c)
45% (c)
12.5%
18%
18%
50%
10%
70% (c)
70% (c)
During 2017, the Company decided to incorporate a subsidiary in the United Kingdom (international investor centre) to actively conduct the strategic business
and financial decisions of the Group. Also, to enhance protection to the Group’s investments in Latin America and because of a predicted change of the Dutch
dividend withholding tax act that would unjustifiably affect the Group’s operating cash flow, GeoPark decided to re-domiciliate the Group´s sub-holdings from
the Netherlands to Spain (jurisdiction with a broad network of Investment Promotion and Protection Agreements with Latin American countries).
184 GeoPark 20F
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
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
2018
16,215
16,215
1,819
-
7,889
9,708
Amounts in US$ ‘000
At 1 January
Foreign exchange income
2017
2018
594
(48)
546
2017
741
(147)
594
27,674
The credit period for trade receivables is 30 days. The maximum exposure to
1,258
credit risk at the reporting date is the carrying value of each class of receivable.
939
The Group does not hold any collateral as security related to trade receivables.
2018
37,811
9,668
966
48,445
29,871
The carrying value of trade receivables is considered to represent a reasonable
26,048
approximation of its fair value due to their short-term nature.
45,170
3,275
48,445
3,823
29,871
Note 25
Financial instruments by category
Amounts in US$ ‘000
2018
3,369
5,940
9,309
2017
1,969
3,769
5,738
Financial assets at fair value through profit or loss
Derivative financial instrument assets
Cash and cash equivalents
Other financial assets at amortized cost
Trade receivables
To be recovered from co-venturers (Note 33)
Other financial assets (a)
Cash and cash equivalents
2017
19,519
Total financial assets
Assets as per statement
of financial position
2018
2017
27,539
53,794
81,333
16,215
1,819
11,468
73,933
-
44,123
44,123
19,519
2,455
43,488
90,632
103,435
184,768
156,094
200,217
19,519
2,455
56
(a) Non-current other financial assets relate to contributions made for
environmental obligations according to Colombian and Brazilian government
5,242
regulations. Current other financial assets corresponds to short-term
7,753
investments with original maturities up to twelve months and over three
Total
25,923
27,272
months. At 31 December 2017, Current other financial assets also included
the security deposit granted in relation to the purchase of Argentinian assets
Classified as follows:
Current
Non-current
Total
25,704
219
25,923
(Note 35.3).
27,037
235
Amounts in US$ ‘000
27,272
Liabilities at fair value through profit and loss
Trade receivables that are aged by less than three months are not considered
Derivative financial instrument liabilities
impaired. As of 31 December 2018 and 2017, there are no balances that were
aged by more than 3 months, but not impaired. These relate to customers for
Other financial liabilities at amortized cost
whom there is no recent history of default. There are no balances overdue
Trade payables
between 31 days and 90 days as of 31 December 2018 and 2017.
Payables to related parties (Note 33)
Movements on the Group provision for impairment are as follows:
To be paid to co-venturers (Note 33)
Payables to LGI (Note 35.1)
Borrowings
Total financial liabilities
Liabilities as per statement
of financial position
2018
2017
-
-
19,289
19,289
69,142
-
29,509
8,449
447,002
554,102
554,102
52,557
31,184
-
10,015
426,204
519,960
539,249
GeoPark 185
25.1 Credit quality of financial assets
the contractual maturity date. The amounts disclosed in the table are the
The credit quality of financial assets that are neither past due nor impaired can
contractual undiscounted cash flows.
be assessed by reference to external credit ratings (if available) or to historical
information about counterparty default rates:
Amounts in US$ ‘000
Less than
Between 1
Between 2
1 year
and 2 years
and 5 years
Over 5
years
Amounts in US$ ‘000
Trade receivables
Counterparties with an external credit rating (Moody’s)
B2
Ba2
Ba3
Baa3
Counterparties without an external credit rating
Group1 (a)
Total trade receivables
2018
2017
At 31 December 2018
Borrowings
Trade payables
Payables to LGI (Note 35.1)
At 31 December 2017
Borrowings
Trade payables
70
-
8,788
3,614
7,047
Payables to related parties
19,519
39,545
68,862
15,000
123,407
27,625
52,557
7,331
87,513
38,648
280
15,000
53,928
82,875
452,625
-
-
-
-
82,875
452,625
27,625
82,875
480,250
-
-
2,068
27,087
-
-
29,693
109,962
480,250
1,196
5,511
3,734
-
5,774
16,215
(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
denominated in Brazilian Real.
25.3 Fair value measurement of financial instruments
Accounting policies for financial instruments have been applied to classify
as either: loans and receivables, held-to-maturity, available-for-sale, or fair
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
Cash at bank and other financial assets (a)
Amounts in US$ ‘000
2018
2017
of fair value measurements by level according to the following fair value
Counterparties with an external credit rating (Moody’s,
measurement hierarchy:
S&P, Fitch, BRC Investor Services)
A1
A2
A3
Aaa
Aaa-mf
Aa1
Aa3
AAA
B2
Ba1
Ba2
Baa1
Baa1+
Baa2
Ba3
B3
BBB
Counterparties without an external credit rating
1,315
595
765
-
52,563
4,732
17,431
14,307
-
4,033
1
13,903
4,138
6,534
212
-
3,199
15,448
• Level 1 - Quoted prices (unadjusted) in active markets for identical assets or
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).
• Level 3 - Inputs for the asset or liability that are not based on observable
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 annual financial report.
553
298
63,853
15,040
-
-
11,401
19,634
31
18
7
307
-
25.3.1 Fair value hierarchy
4,078
2,815
The following table presents the Group’s financial assets and financial liabilities
measured and recognized at fair value at 31 December 2018 and 2017 on a
-
recurring basis:
15,064
45,123
Amounts in US$ ‘000
Total
139,176
178,222
(a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to
cash on hand amounting to US$ 19,000 (US$ 21,000 in 2017).
Assets
Cash and cash equivalents
Money market funds
25.2 Financial liabilities - contractual undiscounted cash flows
Derivative financial instrument liabilities
The table below analyses the Group’s financial liabilities into relevant
Commodity risk management contracts
maturity groupings based on the remaining period at the balance sheet to
Total Liabilities
186 GeoPark 20F
Level 1
Level 2
December
At 31
2018
53,794
-
53,794
-
53,794
27,539
27,539
27,539
81,333
Amounts in US$ ‘000
Level 1
Level 2
At 31
Note 26
December
Share capital
2017
Assets
Cash and cash equivalents
Money market funds
Total Assets
Liabilities
Derivative financial instrument liabilities
Commodity risk management contracts
Total Liabilities
Issued share capital
Common stock (amounts in US$ ‘000)
2018
60
2017
61
44,123
44,123
-
-
44,123
The share capital is distributed as follows:
44,123
Common shares, of nominal US$ 0.001
Total common shares in issue
60,483,447
60,483,447
60,596,219
60,596,219
-
-
19,289
19,289
19,289
Authorized share capital
19,289
US$ per share
0.001
0.001
There were no transfers between Level 2 and 3 during the period.
Number of common shares
The Group did not measure any financial assets or financial liabilities at fair
Amount in US$
value on a non-recurring basis as at 31 December 2018.
(US$ 0.001 each)
5,171,949,000
5,171,949,000
5,171,949
5,171,949
Details regarding the share capital of the Company are set out below:
25.3.2 Valuation techniques used to determine fair values
Specific valuation techniques used to value financial instruments include:
Common shares
• The use of quoted market prices or dealer quotes for similar instruments.
following rights on the holder:
• The mark-to-market fair value of the Group’s outstanding derivative
• the right to one vote per share;
instruments is based on independently provided market rates and
• ranking pari passu, the right to any dividend declared and payable on
As of 31 December 2018, the outstanding common shares confer the
determined using standard valuation techniques, including the impact of
common shares;
counterparty credit risk and are within level 2 of the fair value hierarchy.
• The fair value of the remaining financial instruments is determined using
discounted cash flow analysis. All of the resulting fair value estimates are
GeoPark common
included in level 2.
shares history
Shares outstanding
Shares
issued
Shares
closing
US$(`000)
Date
(millions)
(millions)
Closing
25.3.3 Fair values of other financial instruments (unrecognised)
at the end of 2016
The Group also has a number of financial instruments which are not
measured at fair value in the balance sheet. For the majority of these
instruments, the fair values are not materially different to their carrying
Stock awards
Stock awards
Stock awards
Jan 2017
Dec 2017
Dec 2017
0.1
0.1
0.5
amounts, since the interest receivable/payable is either close to current
Shares outstanding
market rates or the instruments are short-term in nature.
at the end of 2017
Stock awards
Borrowings are comprised primarily of fixed rate debt and variable rate debt
Buyback program
with a short-term portion where interest has already been fixed. They are
Shares outstanding
classified under other financial liabilities and measured at their amortized
at the end of 2018
Dec 2018
Dec 2018
0.1
(0.2)
59.9
60.0
60.1
60.6
60.6
60.7
60.5
60.5
60
60
60
61
61
61
60
60
cost.
The fair value of these financial instruments at 31 December 2018 amounts to
Stock Award Program and Other Share Based Payments
US$ 445,582,000 (US$ 425,118,000 in 2017). The fair values are based on cash
Non-Executive Directors Fees
flows discounted using a rate based on the borrowing rate of 6.94% (6.90% in
During 2018, the Company issued 33,145 (70,485 in 2017 and 137,897 in
2017) and are within level 2 of the fair value hierarchy.
2016) shares to Non-Executive Directors in accordance with contracts as
compensation, generating a share premium of US$ 449,000 (US$ 257,000 in
2017 and US$ 541,848 in 2016). The amount of shares issued is determined
considering the contractual compensation and the fair value of the shares for
each relevant period.
GeoPark 187
Stock Award Program and Other Share Based Payments
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 guarantee granted by
On 14 December 2017, 490,000 (379,500 in 2016) common shares were
GeoPark Colombia Coöperatie U.A. and GeoPark Chile S.A.. The debt issuance
allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a
cost for this transaction amounted to US$ 6,683,000 (debt issuance effective
share premium of US$ 2,513,000 (US$ 3,940,000 in 2016).
rate: 6.90%). The indenture governing the Notes due 2024 includes incurrence
On 13 September 2017, 12,546 (8,333 in 2016) shares were issued pursuant
years from the issuance date, the Net Debt to Adjusted EBITDA ratio should
to a consulting agreement for services rendered to GeoPark Limited
not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed
generating a share premium of US$ 43,000 (US$ 38,000 in 2016).
2 times. Failure to comply with the incurrence test covenants does not trigger
In January 2017, 82,306 shares were issued to key management as bonus
to incur additional indebtedness, as specified in the indenture governing the
compensation, generating a share premium of US$ 332,000.
Notes. Incurrence covenants as opposed to maintenance covenants must
an event of default. However, this situation may limit the Company’s capacity
test covenants that provides among other things, that, during the first two
On 8 February 2016, 468,405 shares were issued to Executive Directors and
certain corporate actions including but not limited to dividend payments,
key management as bonus compensation, generating a share premium of
restricted payments and others. As of the date of these Consolidated Financial
be tested by the Company before incurring additional debt or performing
US$ 1,512,000.
Buyback Program
Statements, the Company is in compliance of all the indenture’s provisions and
covenants.
On 20 December 2018, the Company approved a program to repurchase
up to 10% of its shares outstanding or approximately 6,063,000 shares. The
(b) During February 2016, GeoPark Fell S.p.A. executed a loan agreement with
Banco de Crédito e Inversiones for US$ 186,000 to finance the acquisition of
repurchase program begun on 21 December 2018 and will expire on 31
vehicles for the Chilean operation. The interest rate applicable to this loan is
December 2019. During 2018, the Company purchased 145,917 common
4.14% per annum. The interest and the principal are paid on a monthly basis,
shares for a total amount of US$ 1,801,000. These transactions had no impact
with the final maturity in February 2019.
on the Group’s results.
During 2016, the Repurchase Program began on 6 April 2016 and then was
(c) During October 2018, GeoPark Brazil Exploração y Produção de Petróleo
e Gás Ltda. executed a loan agreement with Banco Santander for Brazilian
resumed during the year until November 2016, the Company purchased
Real 77,640,000 (equivalent to US$ 20,000,000 at the moment of the loan
588,868 common shares for a total amount of US$ 1,991,000.
execution) to repay an existing US$-denominated intercompany loan to
Note 27
Borrowings
GeoPark Latin America Limited - Agencia en Chile. The interest rate applicable
to this loan is CDI plus 2.25% per annum. “CDI” (Interbank certificate of
deposit) represents the average rate of all inter-bank overnight transactions in
Brazil. The principal and the interest are paid semi-annually, with final maturity
Amounts in US$ ‘000
2018
2017
in October 2020. Resulting from this transaction, the Brazilian subsidiary has
Outstanding amounts as of 31 December
2024 Notes (a)
Banco de Crédito e Inversiones (b)
Banco Santander (c)
426,993
426,124
that its functional currency is the Brazilian Real (see Note 3).
significantly reduced its exposure to foreign currency fluctuation, considering
3
20,006
80
-
As of the date of these Consolidated Financial Statements, the Group has
Classified as follows:
Current
Non-current
447,002
426,204
available credit lines for over
US$ 80,000,000.
17,975
429,027
7,664
418,540
(a) During September 2017, the Company successfully placed US$ 425,000,000
Notes which were offered to qualified institutional buyers in accordance with
Rule 144A under the United States Securities Act, and outside the United
States to non-U.S. persons in accordance with Regulation S under the United
States Securities Act.
188 GeoPark 20F
Note 28
Provisions and other long-term liabilities
Amounts in US$ ‘000
Asset
retirement
Deferred
obligation
29,862
Income
3,484
At 1 January 2017
Addition to provision
Exchange difference
5,943
134
Foreign currency translation
(134)
Amortization
Unwinding of discount
Unused amounts reversed
Amounts used during
the year
At 31 December 2017
Addition to provision
Recovery of abandonment
costs
Acquisitions
Exchange difference
Foreign currency translation
-
2,607
-
(337)
38,075
462
(4,817)
9,738
1,823
1,648
-
-
-
(657)
-
-
(1,375)
1,452
-
-
-
-
-
Amortization
-
(1,005)
Unwinding of discount
Unused amounts reversed
Amounts used during
the year
3,250
-
(750)
Liabilities associated with
assets held for sale
At 31 December 2018
(5,816)
40,317
-
-
-
-
447
Note 29
Trade and other payables
Amounts in US$ ‘000
V.A.T
Total
42,509
8,163
1,288
(134)
(657)
Trade payables
Payables to related parties (Note 33) (a)
Payables to LGI (Note 35.1)
Customer advance payments
Other short-term advance payments (b)
Staff costs to be paid
2,779
Royalties to be paid
(2,535)
Taxes and other debts to be paid
To be paid to co-venturers (Note 33)
(5,129)
46,284
Classified as follows:
1,501
Current
Non-current
2018
852
69,142
-
29,509
6,300
9,000
12,049
6,238
4,670
8,449
2017
1,118
52,557
31,184
-
10,000
-
9,143
4,110
4,191
10,015
146,209
122,318
131,420
14,789
96,397
25,921
(5,916)
9,738
1,777
(1,648)
(1,005)
3,423
(2,093)
(a) The outstanding amount at 31 December 2017 corresponded to advanced
cash call payments granted by LGI to GeoPark Chile S.A. for financing Chilean
operations in TdF’s blocks and was fully cancelled on 28 November 2018 (see
Note 35.1).
(b) Advance payment collected in relation with the sale of La Cuerva and Yamu
Blocks (see Note 35.2).
Other
9,163
2,220
1,154
-
-
172
(2,535)
(3,417)
6,757
1,039
(1,099)
-
(46)
-
-
173
(2,093)
(124)
(874)
The average credit period (expressed as creditor days) during the year ended
(2,794)
1,813
(8,610)
31 December 2018 was 83 days (2017: 95 days).
42,577
The fair value of these short-term financial instruments is not individually
The provision for asset retirement obligation relates to the estimation of future
determined as the carrying amount is a reasonable approximation of fair value.
disbursements related to the abandonment and decommissioning of oil and
gas wells (see Note 4).
Note 30
Share-based payment
Deferred income relates to contributions received to improve the project
The Group has established different stock awards programs and other share-
economics of the gas wells in Chile. The amortization is in line with the related
based payment plans to incentivize the Directors, senior management and
asset. The amount used in 2017 corresponds to the deferred income related to
employees, enabling them to benefit from the increased market capitalization
the take-or-pay provision associated to gas sales in Brazil.
of the Company.
During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”)
to motivate and reward those employees, directors, consultants and advisors
of the Group to perform at the highest level and to further the best interests of
the Company and its shareholders. This Plan is designed as a master plan, with
a 10-year term, and embraces all equity incentive programs that the Company
decides to implement throughout such term. The maximum number of Shares
available for issuance under the Plan is 5,000,000 Shares.
GeoPark 189
During 2018, the Group approved a share-based compensation program
Also during 2016, the Group approved a plan named Value Creation Plan
for approximately 200,000 shares. Main characteristics of the Stock Awards
(“VCP”) oriented to Top Management. VCP was subject to certain market
Programs are:
conditions, among others, reaching a stock market price for the Company
• Employees hired since July 2016 are eligible.
shares of US$ 4.05 at vesting date. VCP has been classified as an equity-settled
• Exercise price is equal to the nominal value of shares.
plan. On 2 January 2019, 50% of the shares, representing 1,488,391 shares,
• Vesting date is 30 June 2019.
were issued since the plan vested. The remaining 50% will be issued in January
• Each employee could receive up to three salaries (to be pro-rated between
2020, as set up in the plan.
the hiring date and the vesting date divided by 3 years) by achieving the
following conditions: continue to be an employee, the stock market price at
Details of these costs and the characteristics of the different stock awards
the date of vesting should be higher than the share price at the date of grant
programs and other share-based payments are described in the following
and obtain the Group minimum production, adjusted EBITDA and reserves
table and explanations:
target for the year of vesting.
During 2016, the Group approved a share-based compensation program for
1,619,105 shares. Main characteristics of the Stock Awards Programs are:
• All employees are eligible.
• Exercise price is equal to the nominal value of shares.
• Vesting date is 30 June 2019.
• 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.
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
2018
2016
2014
2012
Subtotal
Shares granted
to Non-Executive Directors
VCP 2016
Executive Directors Bonus
Key Management Bonus
Stock awards for service contracts
-
200,000
1,587,996
-
-
-
-
-
-
(5,570)
-
-
1,587,996
200,000
(5,570)
-
-
-
-
-
200,000
1,582,426
-
-
2018
1,662
886
-
-
2017
2016
-
865
838
-
-
445
821
855
1,782,426
2,528
1,703
2,121
-
-
-
-
-
33,145
2,976,781
104,439
-
-
-
-
-
-
-
(33,145)
-
-
-
-
-
2,976,781
104,439
-
-
450
1,868
600
-
-
454
1,868
-
-
50
400
934
(325)
202
35
1,587,996
3,314,365
(5,570)
(33,145)
4,863,646
5,446
4,075
3,367
The awards that are forfeited correspond to employees that had left the Group
before vesting date.
190 GeoPark 20F
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
31,266
30,053
17,963
Note 31
Interests in Joint operations
operator in all the blocks. In Argentina, GeoPark used to be the operator in
CN-V Block until October 2018.
The Group has interests in joint operations, which are engaged in the
exploration of hydrocarbons in Chile, Colombia, Brazil and Argentina.
The following amounts represent the Group’s share in the assets, liabilities
In Colombia, GeoPark is the operator in Llanos 34. In Chile, GeoPark is the
Consolidated Statement of Financial Position and Statement of Income:
and results of the joint operations which have been recognized in the
Interest
PP&E
Other
Assets
Total
Total
Net Assets/
Operating
Assets
Liabilities
(Liabilities)
Revenue
profit (loss)
45%
12.5%
174,895
2,011
3,133
178,028
175,732
469,404
347,772
2,011
1,562
5,764
(2,296)
(449)
Subsidiary /
Joint operation
2018
Colombia SAS
Llanos 34 Block
Llanos 32 Block
GeoPark Magallanes Ltda.
Tranquilo Block
GeoPark TdF S.A.
Flamenco Block
Campanario Block
Isla Norte Block
50%
50%
50%
60%
10%
70%
70%
50%
18%
18%
45%
12.5%
89.5%
50%
50%
50%
60%
Manati Field
POT-T-747
REC-T-128
GeoPark Argentina Limited – Argentinean Branch
CN-V Block
Puelen Block
Sierra del Nevado Block
GeoPark Perú S.A.C.
Morona
2017
Colombia SAS
Llanos 34 Block
Llanos 32 Block
Yamu/Carupana Block
GeoPark Magallanes Ltda.
Tranquilo Block
GeoPark TdF S.A.
Flamenco Block
Campanario Block
Isla Norte 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
10%
70%
50%
18%
18%
-
55
-
-
-
6,364
-
-
328
13
10
-
4,803
16,477
8,920
25,741
202
1,398
8,577
1,881
995
835
4,741
-
9,893
17,347
9,553
44,167
849
6,819
1,138
568
209
1
55
-
-
-
19,126
358
347
72
169
55
(428)
(373)
4,803
16,477
8,920
32,105
202
1,398
8,905
1,894
1,005
(1,173)
(278)
(72)
3,630
16,199
8,848
(839)
-
(648)
(577)
(246)
(91)
202
750
8,328
1,648
914
623
(46)
(5,647)
(1,008)
(778)
-
263
40
7
-
-
-
-
-
-
-
-
(922)
(159)
(134)
-
55
(432)
(377)
-
(48)
9,893
17,347
9,553
63,293
1,207
7,166
1,390
737
(1,223)
(233)
(60)
(11,444)
(1,091)
(984)
(232)
(837)
8,670
17,114
9,493
51,849
116
6,182
1,158
(100)
879
(1,422)
-
-
(150)
(161)
34,238
12,731
-
70
-
-
-
(1,163)
(546)
(474)
GeoPark 191
75%
6,446
-
6,446
(7,016)
(570)
131,193
4,563
135,756
1,044
4,742
(5,847)
(492)
(2,993)
129,909
259,815
163,917
552
1,749
1,784
3,072
(319)
(2,721)
Subsidiary /
Joint operation
2016
Colombia SAS
Llanos 34 Block
Llanos 32 Block
Yamu/Carupana Block
GeoPark Magallanes Ltda.
Tranquilo Block
GeoPark TdF S.A.
Flamenco Block
Campanario Block
Isla Norte Block
Interest
PP&E
Other
Assets
Total
Total
Net Assets/
Operating
Assets
Liabilities
(Liabilities)
Revenue
profit (loss)
45%
10%
89.5%
50%
50%
50%
60%
79,811
3,819
3,418
-
15,108
29,718
9,920
693
-
-
55
-
-
-
80,504
3,819
3,418
(3,943)
(211)
(2,289)
76,561
125,400
3,608
1,129
2,303
18
83,193
1,043
(307)
55
(424)
(369)
-
(40)
15,108
29,718
9,920
(93)
(1)
(1)
15,015
29,717
9,919
1,004
(1,988)
-
5
(399)
(438)
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
Capital commitments are disclosed in Note 32.2.
Note 32
Commitments
32.1 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.
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$/barrel)
30.22
31.39
32.56
46.50
Table A
Table B
WTI (P)
Po < P < 2Po
2Po < P < 3Po
3Po < P < 4Po
4Po < P < 5Po
5Po < P
S
30%
35%
40%
45%
50%
Additionally, under the terms of the Winchester Stock Purchase Agreement,
Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties on
GeoPark is obligated to make certain payments to the previous owners of
Colombian production of light and medium oil are calculated on a field-by-
Winchester based on the production and sale of hydrocarbons discovered
field basis, using the following sliding scale:
by exploration wells drilled after 25 October 2011. These payments involve
Average daily production in barrels
Production Royalty rate
the vendor. As at the balance sheet date and based on preliminary internal
Up to 5,000
5,000 to 125,000
125,000 to 400,000
400,000 to 600,000
Greater than 600,000
8%
estimates of additions of 2P reserves since acquisition, the Group’s best
8% + (production - 5,000) * 0.1
estimate of the total commitment over the remaining life of the concession is
20%
in a range between US$ 150,000,000 and US$ 160,000,000. During 2018, the
20% + (production - 400,000) * 0.025
Group has accrued US$ 20,551,000 (US$ 11,369,000 in 2017 and US$ 5,414,000
25%
in 2016) and paid US$ 19,128,000 (US$ 9,981,000 in 2017 and US$ 3,772,000 in
an overriding royalty equal to an estimated 4% carried interest on the part of
When the API is lower than 15°, the payment is reduced to the 75% of the
total calculation.
2016).
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
table A, the Group should deliver to ANH a share of the production net of
In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency
royalties in accordance with the following formula: Q = ((P – Po) / P) x S; where
(ANP) is responsible for determining monthly minimum prices for petroleum
192 GeoPark 20F
produced in concessions for purposes of royalties payable with respect
Campanario and Isla Norte Blocks as well as the guarantees related to those
to production. Royalties generally correspond to a percentage ranging
commitments. Consequently, the future investment commitments assumed
between 5% and 10% applied to reference prices for oil or natural gas,
by GeoPark for the second exploratory period are up to:
as established in the relevant bidding guidelines (edital de licitação) and
•
Campanario Block: 3 exploratory wells before 10 July 2019 (US$
concession agreement. In determining the percentage of royalties applicable
4,758,000)
to a concession, the ANP takes into consideration, among other factors, the
•
Isla Norte Block: 2 exploratory wells before 7 May 2019 (US$ 2,855,000)
geological risks involved and the production levels expected. In the Manati
Block, royalties are calculated at 7.5% of gas production.
As of 31 December 2018, the Group has established guarantees for its total
In Argentina, crude oil and gas production accrues royalties payable to the
commitments.
Provinces of Mendoza and Neuquen equivalent to 15% on estimated value
On 20 December 2018, GeoPark proposed to extend the second exploratory
at well head of those products. This value is equivalent to final sales price less
period for an additional period of 18 months, ending 11 January 2021 and 7
transport, storage and treatment costs.
November 2020, respectively. As of the date of these consolidated financial
32.2 Capital commitments
statements the Chilean Ministry has not replied.
32.2.4 Brazil
32.2.1 Colombia
The future investment commitments assumed by GeoPark are up to:
The VIM 3 Block minimum investment program consists of 200 km of 2D
• REC-T-94 Block: 1 exploratory well before 7 February 2020 (US$ 930,000).
seismic and drilling one exploratory well, with a total estimated investment
• REC-T-128 Block: 1 exploratory well before 20 December 2018 (US$
of US$ 22,290,800 during the initial three-year exploratory period ending
2,200,000). As of the date of these Consolidated Financial Statements, GeoPark
2 September 2018. On 12 September 2018, the Colombian National
has already drilled the committed well, with testing expected for the first
Hydrocarbons Agency (“ANH”) accepted GeoPark’s proposal to extend the first
quarter of 2019.
exploratory phase for an additional period ending 12 May 2019. Additionally,
• POT-T-747 Block: 1 exploratory well before 20 December 2018 (US$ 490,000).
GeoPark requested ANH to terminate the E&P Contract due to environmental
On 15 January 2019, the Brazilian National Agency of Petroleum, Natural Gas
restrictions in the block. These restrictions became apparent once the National
and Biofuels (“ANP”) notified the suspension of the exploratory period to fulfil
Authority of Environmental Licenses (ANLA) issued the environmental
the commitments in the block.
license. As of the date of these consolidated financial statements, GeoPark’s
• POT-T-785 Block: 3D seismic and electromagnetic survey before 29 January
termination request is under review.
2023 (US$ 90,000).
The Llanos 34 Block (45% working interest) has committed to drill an
32.2.5 Argentina
exploratory well, which amounts to US$ 1,935,000 at GeoPark’s working
The remaining commitment in the Sierra del Nevado Block (18% working
interest, before 19 September 2019.
32.2.2 Chile
interest) for the first exploratory period, ending on 20 August 2019, amounts
to between US$ 500,000 and US$ 1,000,000 at GeoPark’s working interest
The remaining investment commitment for the second exploratory phase
The investment commitment in the CN-V Block (50% working interest) for the
in the Flamenco Block relates to the drilling of one exploratory well to be
current exploratory period denominated as “Field under evaluation”, ending
assumed 100% by GeoPark and amounts to US$ 2,100,000. On 30 June 2017,
on 27 November 2021, amounts to US$ 1,300,000 at GeoPark’s working
the Chilean Ministry accepted GeoPark’s proposal to extend the second
interest.
exploratory phase for an additional period of 18 months, ending on 7 May
2019. On 20 December 2018, GeoPark proposed to extend the second
The investment commitment in the Los Parlamentos Block (50% working
exploratory period for an additional period of 18 months, ending 7 November
interest) for the first exploratory period, ending on 30 October 2021, which
2020. As of the date of these consolidated financial statements the Chilean
includes 2 exploratory wells and additional 3D seismic, amounts to US$
Ministry has not replied.
6,000,000, at GeoPark’s working interest.
The investment commitment for the first exploratory period in the
32.3 Operating lease commitments – Group company as lessee
Campanario and Isla Norte Blocks has already been fulfilled. The
investments to be made in the second exploratory period will be assumed
The Group leases various plant and machinery under non-cancellable
100% by GeoPark. On 29 May 2017, the Chilean Ministry accepted
operating lease agreements. The Group also leases offices under non-
GeoPark’s proposal to update the value of the commitments in both the
cancellable operating lease agreements. The lease terms are between 2 and
GeoPark 193
3 years, and most of lease agreements are renewable at the end of the lease
vehicles. The information set forth above and listed in the table is based solely
period at market rate.
on the disclosure set forth in Mr. O´Shaughnessy’s most recent Schedule 13G
During 2018 a total amount of US$ 12,485,000 (US$ 46,195,000 in 2017
and US$ 47,871,000 in 2016) was charged to the income statement and
US$ 38,229,000 of operating leases were capitalized as Property, plant and
(c) The information set forth above and listed in the table is based solely on the
disclosure set forth in Compass Group LLC’s most recent Schedule 13F filed
equipment related to rental of drilling equipment and machinery (US$
with the SEC on 6 February 2019.
34,160,000 in 2017 and US$ 32,058,000 in 2016).
filed with the SEC on 13 February 2019.
The future aggregate minimum lease payments under non-cancellable
operating leases are as follows:
Amounts in US$ ‘000
Falling due within 1 year
Falling due within 1 – 3 years
Falling due within 3 – 5 years
Falling due over 5 years
(d) Beneficially owned by Renaissance Technologies Holdings Corporation and
Renaissance Technologies LLC (jointly “Renaissance”). The in-formation set
forth above and listed in the table is based solely on the disclosure set forth
in Renaissance’s most recent Schedule 13G filed with the SEC on 12 February
2018
47,450
18,032
2,500
1,956
2017
32,180
5,777
2,793
-
2016
2019.
67,752
14,031
5,066
(e) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal
Pavez. The common shares reflected as being held by Mr. Pavez include 91,312
114
common shares held by him personally.
Total minimum lease payments
69,938
40,750
86,963
Note 33
Related parties
Controlling interest
The main shareholders of GeoPark Limited, a company registered in Bermuda,
as of 31 December 2018, are:
Shareholder
James F. Park (a)
Gerald E. O’Shaughnessy (b)
Manchester Financial Group, LP
Compass Group LLC (c)
Renaissance Technologies
Holdings Corporation (d)
Juan Cristóbal Pavez (e)
Other shareholders
Common
shares
7,891,269
6,943,316
5,246,296
3,899,301
3,527,000
2,969,116
30,007,149
60,483,447
Percentage
of outstanding
common shares
13.05%
11.48%
8.67%
6.45%
5.83%
4.91%
49.61%
100.00%
(a) Held by Energy Holdings, LLC, which is controlled by James F. Park. The
number of common shares held by Mr. Park does not reflect the 1,533,927
common shares held as of 31 December 2018 in the Company´s employee
benefit trust and to which Mr. Park has voting power. The information set forth
above and listed in the table is based solely on the disclosure set forth in Mr.
Park’s most recent Schedule 13G filed with the SEC on 13 February 2019.
(b) Held by Mr. O’Shaughnessy directly and indirectly through GP Investments
LLP, GPK Holdings, The Globe Resources Group, Inc., and other investment
194 GeoPark 20F
Balances outstanding and transactions with related parties
Account (Amounts in ´000)
Transaction in the year
Balances at year end
Related Party
Relationship
2018
To be recovered from co-venturers
To be paid to co-venturers
Financial results
Geological and geophysical expenses
Administrative expenses
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
-
-
1,606
170
547
-
-
-
-
2,224
170
411
-
-
-
-
1,587
113
371
1,819
(8,449)
-
-
-
2,455
56
(31,184)
(10,015)
-
-
-
3,311
42
(27,801)
(1,614)
-
-
-
Joint Operations
Joint Operations
LGI
Carlos Gulisano
Pedro E. Aylwin
Joint Operations
Joint Operations
Partner
Non-Executive Director (a)
Executive Director (b)
Joint Operations
Joint Operations
LGI
LGI
Joint Operations
LGI
Carlos Gulisano
Pedro E. 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 E. Aylwin
Partner
Partner
Joint Operations
Partner
Non-Executive Director (a)
Executive Director (b)
(a) Corresponding to consultancy services.
(b) Corresponding to wages and salaries for US$ 417,000 (US$ 271,000 in 2017
and US$ 246,000 in 2016) and bonus for US$ 130,000 (US$ 140,000 in 2017 and
Note 35
Business transactions
US$ 125,000 in 2016).
35.1 General
There have been no other transactions with the Board of Directors, Executive
Acquisition of Non-controlling interest in Colombia and Chile’s business from
officers, significant shareholders or other related parties during the year
LG International
besides the intercompany transactions which have been eliminated in the
On 28 November 2018, GeoPark executed an agreement to acquire the LG
Consolidated Financial Statements, the normal remuneration of Board of
International Corporation (“LGI”) interest in GeoPark’s Colombian and Chilean
Directors and other benefits informed in Note 11.
operations and subsidiaries.
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
The acquisition price includes a fixed payment of US$ 81,000,000 paid at
closing, plus two equal installments of US$ 15,000,000 each, to be paid in
2017
2016
June 2019 and June 2020. Additionally, three contingent payments of US$
726
137
212
39
487
5,000,000 each could be payable over the next three years, subject to certain
-
production thresholds being exceeded.
134
-
Through this transaction, GeoPark acquired the shares that used to be held
2018
797
-
209
-
1,006
1,114
621
by LGI representing 20% equity interest in GeoPark Colombia Coöperatie
U.A., 20% equity interest in GeoPark Chile S.A. and 14% equity interest in
GeoPark TdF S.A. In addition to that, the outstanding amount corresponding
Non-audit services fees relate to consultancy and other services for 2017.
to advanced cash call payments granted in the past by LGI to GeoPark Chile
GeoPark 195
S.A. for financing Chilean operations in TdF’s blocks were considered as part of
12.5% WI). The farm-in agreement provided for the drilling of an exploration
the transaction.
well to be funded by GeoPark and, in the event of a commercial discovery,
GeoPark would increase its economic interest to 56.25% in the Zamuro field
The transaction mentioned above has been accounted for as a transaction
area. The well was spudded with unsuccessful results during 2018.
with non-controlling interest in accordance with IFRS 10. Consequently, the
difference between the amount by which the non-controlling interest was
Acquisition of Tiple Block
stated and the fair value of the consideration paid was recognized directly in
GeoPark executed a joint operation agreement related to certain exploration
Equity and attributed to the owners of the Company.
activities in an exploration acreage (“Tiple Block Acreage”) in the Llanos Basin
The following table summarizes the result of this transaction:
of CEPSA SAU, the Spanish integrated energy and petrochemical company).
in Colombia, through a partnership with CEPSA Colombia S.A. (a subsidiary
The agreement provided for GeoPark to drill one exploration well, which was
Amounts in US$ ‘000
Cash
Additional installments to be paid
Total consideration
Equity attributable to non-controlling interest
Trade and other payables
Total book value of the transaction
Total
spudded with unsuccessful results during 2018.
81,000
29,427
Incremental interest in Llanos 32 Block
110,427
On 22 August 2017, GeoPark acquired an additional 2.5% interest in the Llanos
32 Block. No gain or loss has been generated by this transaction.
64,245
32,786
97,031
35.3 Argentina
Result of the transaction recognized in Equity
13,396
35.2 Colombia
Sale of La Cuerva and Yamu Blocks
Acquisition of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks
On 27 March 2018, GeoPark acquired 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$
On 2 November 2018, GeoPark executed a purchase and sale agreement to
52,000,000, less a working capital adjustment of US$ 3,150,000. The Group has
sell its 100% working interest in the La Cuerva and Yamu Blocks, in Colombia.
estimated that there are no any future contingent payments at the acquisition
The total consideration is US$ 18,000,000, plus a contingent payment of
date and as of the date of these consolidated financial statements either.
US$ 2,000,000 (depending on the oil price performance) and subject to
working capital adjustments. As of the date of these Consolidated Financial
In accordance with the acquisition method of accounting, the acquisition
Statements, GeoPark has collected an advance payment of US$ 9,000,000.
cost was allocated to the underlying assets acquired and liabilities assumed
Closing of the transaction is subject to customary regulatory approvals, which
based primarily upon their estimated fair values at the date of acquisition. An
are expected to occur during 2019.
income approach (being the net present value of expected future cash flows)
was adopted to determine the fair values of the mineral interest. Estimates
The following table summarizes the book value of the assets and liabilities
of expected future cash flows reflect estimates of projected future revenues,
related to these blocks as of 31 December 2018:
production costs and capital expenditures based on our business model.
Amounts in US$ ‘000
Property, plant and equipment (a)
Inventories
Other assets (a)
Provision for other long-term liabilities (b)
Other liabilities (b)
Total identifiable net assets
(a) Classified as “Assets held for sale”.
(b) Classified as “Liabilities associated with assets held for sale”.
Zamuro Farm-in agreement
Total
The following table summarizes the combined consideration paid for the
15,530
acquired blocks and the final allocation of fair value of the assets acquired and
1,033
7,756
(8,610)
(1,664)
14,045
liabilities assumed for the abovementioned transaction:
Amounts in US$ ‘000
Cash (a)
Total consideration
Property, plant and equipment (including mineral interest)
Inventories
Provision for other long-term liabilities
Total identifiable net assets
Total
48,850
48,850
54,929
3,659
(9,738)
48,850
GeoPark executed a farm-in agreement to drill the Zamuro exploration
prospect, which is located in the Llanos 32 Block (GeoPark non-operated,
(a) In December 2017, GeoPark granted a security deposit of US$ 15,600,000. In
March 2018, the Group completed the total consideration with an additional
196 GeoPark 20F
payment of US$ 36,400,000. In September 2018, Geo-Park collected a working
capital adjustment of US$ 3,150,000.
In accordance with disclosure requirements for business combinations, the
to carry Petroperu on a work program that provides for testing and start-
Group has calculated its consolidated revenue and profit, considering as if the
up production of one of the existing wells in the field, subject to certain
mentioned acquisition had occurred at the beginning of the reporting period.
technical and economic conditions being met. During 2017, GeoPark
recognized an initial consideration owed to Petroperu of US$ 10,684,000.
The following table summarizes both results:
In 2018, after GeoPark’s review and approval of supporting documentation,
Amounts in US$ ‘000
Revenue
Profit for the period
the consideration was reduced in US$ 806,000, resulting in a total amount of
2018
US$ 9,878,000. This amount will be offset by the Petroperu’s interest in the
612,401
operation expenses to be incurred by GeoPark in the block. Expected capital
102,873
expenditures in 2019 for the Morona Block are mainly related to flexible
pipeline installation, temporary access road, location conditioning and
The revenue included in the consolidated statement of comprehensive
Morona Camp dock revamping. These activities are subject to the approval of
income since acquisition date contributed by the acquired business is US$
the Environmental Impact Study, which is under review by the local authority
35,879,000. The acquired business has also contributed profit of US$ 124,000
as of the date of these consolidated financial statements.
over the same period.
Note 36
As a consequence of this transaction, the Group considers that there is
Impairment test on Property, plant and equipment
sufficient evidence of future taxable profits to offset tax losses and recognize
a deferred tax asset for US$ 1,346,000 in respect of tax losses from previous
As a result of the oil price crisis which started in the second half of 2014,
years which can be utilised against future taxable profit.
the Group recognized an impairment loss of US$ 149,574,000 in 2015 after
Los Parlamentos Block
evaluating the recoverability of its fixed assets affected by oil price drop, as
such situation constitutes an impairment indicator according to IAS 36 and,
In June 2018, GeoPark acquired a 50% working interest in the Los Parlamentos
consequently, it triggers the need of assessing the fair value of the assets
exploratory block in partnership with YPF S.A. (YPF), the largest oil and gas
involved against their carrying amount.
producer in Argentina. In accordance with the partnership agreement, YPF
assumed the operationship of the block and GeoPark assumed a commitment
The Management of the Group considers as Cash Generating Unit (CGU) each
to fund its 50% working interest of one exploratory well and additional 3D
of the blocks in which the Group has working or economic interests. The
seismic, which amounts to US$ 6,000,000 at GeoPark’s working interest, over
blocks with no material investment on fixed assets or with operations that are
the next three years.
not linked to oil prices were not subject to the impairment test.
35.4 Peru
Entry in Peru
During 2016, 2017 and 2018 the impairment tests were reviewed. The main
assumptions taken into account for the impairment tests for the blocks below
mentioned were:
The Group has executed a Joint Investment Agreement and Joint Operating
Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an interest in
· The future oil prices have been calculated taking into consideration the
and operate the Morona Block located in northern Peru. GeoPark will assume
oil price curves available in the market, provided by international advisory
a 75% working interest (“WI”) of the Morona Block, with Petroperu retaining
companies, weighted through internal estimations in accordance with price
a 25% WI. The transaction has been approved by the Board of Directors of
curves used by D&M;
both Petroperu and GeoPark. The agreement was subject to Peru regulatory
· Three oil price scenarios were projected and weighted in order to minimize
approval, which was completed on 1 December 2016 following the issuance of
misleading estimations: low-price, middle-price and high-price (see below
Supreme Decree 031-2016-MEM.
table “Oil price scenarios”);
· The table “Oil price scenarios” was based on Brent future price estimations;
The Morona Block, also known as Lote 64, covers an area of 1.9 million
the Group adjusted this marker price on its model valuation to reflect the
acres on the western side of the Marañón Basin, one of the most prolific
effective price applicable in each location (see Note 3 “Price risk”);
hydrocarbon basins in Peru. It contains the Situche Central oil field, which has
· The model valuation was based on the expected cash flow approach;
been delineated by two wells (with short-term tests of approximately 2,400
· The revenues were calculated linking price curves with levels of production
and 5,200 bopd of 35-36° API oil each) and by 3D seismic.
according to certified reserves (see below table “Oil price scenarios”);
· The levels of production have been linked to certified risked 1P, 2P and 3P
In accordance with the terms of the agreement, GeoPark has committed
reserves (see Note 4);
GeoPark 197
· Production and structure costs were estimated considering internal
Note 37
historical data according to GeoPark’s own records and aligned to the 2019
Supplemental information on oil and gas activities (unaudited).
approved budget;
· The capital expenditures were estimated considering the drilling campaign
The following information is presented in accordance with ASC No. 932
necessary to develop the certified reserves;
“Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and
· The assets subject to impairment test are the ones classified as Oil and Gas
Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in
properties and Production facilities and machinery;
order to align the current estimation and disclosure requirements with the
· The carrying amount subject to impairment test includes mineral interest, if
requirements set in the SEC final rules and interpretations, published on 31
any;
December 2008. This information includes the Group’s oil and gas production
· The income tax charges have considered future changes in the applicable
activities carried out in Colombia, Chile, Brazil, Argentina and Peru.
income tax rates (see Note 16).
Table Oil price scenarios (a):
Table 1 - Costs incurred in exploration, property acquisitions and development (a)
Amounts in US$ per Bbl.
that were incurred during each of the years ended as of 31 December 2018,
The following table presents those costs capitalized as well as expensed
Low price
Middle price
High price
Weighted market
2017 and 2016. The acquisition of properties includes the cost of acquisition
(15%)
(60%)
(25%)
price used for the
of proved or unproved oil and gas properties. Exploration costs include
Year
2019
2020
2021
Over 2022
63.9
51.2
53.3
55.1
63.9
68.2
71.0
73.4
63.9
75.0
78.1
80.7
impairment test
geological and geophysical costs, costs necessary for retaining undeveloped
63.9
67.3
70.1
72.5
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.
(a) The percentages indicated between brackets represent the Group
estimation regarding each price scenario.
As a consequence of the evaluation, the following amounts of impairment loss
were reversed (recognized):
Amounts in US$ ‘000
Colombia (a)
Chile (b)
Total
2018
11,531
(6,549)
4,982
2017
-
-
-
2016
5,664
-
5,664
(a) Reversal of impairment losses due to increases in estimated market prices
and improvements in cost structure, and also the known fair value less costs of
disposal of the La Cuerva and Yamu Blocks (see Note 35.2).
(b) Recognition of impairment loss due to the termination of the sales
agreement for the TdF’s blocks, with no renovation in place as of the date of
these consolidated financial statements.
198 GeoPark 20F
Amounts in US$ ‘000
Year ended 31 December 2018
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development
Total costs incurred
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
(a) Includes capitalized amounts related to asset retirement obligations.
Table 2 - Capitalized costs related to oil and gas producing activities
The following table presents the capitalized costs as at 31 December 2018,
2017 and 2016, for proved and unproved oil and gas properties, and the
related accumulated depreciation as of those dates.
Amounts in US$ ‘000
At 31 December 2018
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
Other uncompleted projects (b)
Unproved properties
Gross capitalized costs
Accumulated depreciation
Total net capitalized costs
Colombia
Chile
Brazil
Argentina
Perú
Total
-
-
-
34,242
65,174
99,416
Colombia
-
-
-
37,017
49,268
86,285
Colombia
-
-
-
6,221
3,033
9,254
Chile
-
-
-
3,283
10,231
13,514
Chile
-
-
-
3,217
(2,220)
997
54,541
-
54,541
9,383
1,836
11,219
Brazil
Argentina
-
-
-
-
-
-
-
-
-
1,269
8,385
9,654
Perú
-
-
-
54,541
-
54,541
54,332
76,208
130,540
Total
-
-
-
5,207
1,210
6,417
Brazil
8,080
167
8,247
Argentina
743
14,074
14,817
Perú
54,330
74,950
129,280
Total
-
-
-
-
-
-
15,233
12,500
27,733
5,519
4,566
10,085
-
-
-
2,555
191
2,746
-
-
-
1,894
-
1,894
-
-
-
-
-
-
-
-
-
25,201
17,257
42,458
Colombia
Chile
Brazil
Argentina
Total
83,023
189,514
24,061
1,676
81,459
400,338
12,233
41,162
298,274
535,192
(122,479)
(281,062)
175,795
254,130
5,154
63,574
-
7,073
75,801
(43,158)
32,643
2,458
64,084
1,836
10,081
78,459
172,094
717,510
38,130
59,992
987,726
(16,363)
(463,062)
62,096
524,664
(a) Includes capitalized amounts related to asset retirement obligations, impairment loss in Chile for US$ 6,549,000 and impairment loss reversal in Colombia for
US$ 11,531,000.
(b) Do not include Peru capitalized costs.
GeoPark 199
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 capitalized costs
Accumulated depreciation
Total net capitalized costs
(a) Includes capitalized amounts related to asset retirement obligations.
(b) Do not include Peru capitalized 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 capitalized costs
Accumulated depreciation
Total net capitalized costs
Colombia
Chile
Brazil
Argentina
Total
69,906
291,050
11,290
4,106
80,611
397,031
12,508
49,702
376,352
539,852
(228,793)
(253,764)
147,559
286,088
6,036
77,264
70
7,585
90,955
(39,509)
51,446
843
11,159
48
2,975
157,396
776,504
23,916
64,368
15,025
1,022,184
(5,700)
9,325
(527,766)
494,418
Colombia
Chile
Brazil
Argentina
Total
46,785
230,100
12,534
4,503
80,611
380,037
18,274
48,908
293,922
527,830
(190,025)
(230,917)
103,897
296,913
4,174
77,255
2,082
6,468
89,979
(29,803)
60,176
843
4,849
36
1,894
7,622
(5,692)
1,930
132,413
692,241
32,926
61,773
919,353
(456,437)
462,916
(a) Includes capitalized amounts related to asset retirement obligations and impairment loss reversal in Colombia for US$ 5,664,000.
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 2018, 2017 and 2016. Income tax for the years presented was calculated utilizing the statutory tax rates.
Amounts in US$ ‘000
Year ended 31 December 2018
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
200 GeoPark 20F
Colombia
Chile
Brazil
Argentina
Total
497,870
37,359
30,053
35,879
601,161
(55,823)
(62,710)
(20,426)
(1,473)
(118,533)
(21,899)
(23,953)
(892)
11,531
(6,855)
(1,105)
(6,549)
(5,965)
(2,820)
(8,785)
(2,846)
(918)
-
(41,850)
(27,298)
(10,278)
324,173
(26,347)
(119,944)
3,952
204,229
(22,395)
7,226
(2,457)
4,769
(20,210)
(102,424)
(4,833)
(71,836)
(25,043)
(174,260)
(2,277)
(508)
-
(10,662)
(2,611)
(35,931)
(3,423)
4,982
(90,088)
302,441
783
(117,666)
(1,828)
184,775
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)
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
Colombia
Chile
Brazil
Argentina
Total
263,076
32,738
34,238
70
330,122
(42,677)
(24,236)
(19,685)
(1,314)
(7,603)
(3,134)
(66,913)
(20,999)
(10,737)
(3,856)
(855)
(1,404)
(994)
(3,985)
(930)
(38,721)
(22,705)
(10,659)
152,731
(13,364)
(61,161)
91,570
2,005
(11,359)
7,927
(2,695)
5,232
(325)
(13)
(338)
(707)
-
(8)
(983)
344
(639)
(70,290)
(28,697)
(98,987)
(9,952)
(2,779)
(72,093)
146,311
(61,507)
84,804
Colombia
Chile
Brazil
Argentina
Total
126,228
36,723
29,719
(29,326)
(7,281)
(20,674)
(1,495)
(36,607)
(22,169)
(11,690)
(21,060)
(459)
5,664
(29,439)
53,697
(21,479)
32,218
(897)
-
(29,890)
(37,293)
5,594
(31,699)
(5,738)
(2,721)
(8,459)
(5,636)
(1,198)
-
(12,785)
1,641
(558)
1,083
-
-
-
-
-
-
-
-
-
-
-
192,670
(55,738)
(11,497)
(67,235)
(38,386)
(2,554)
5,664
(72,114)
18,045
(16,443)
1,602
(a) Do not include Peru costs.
(b) Represents accretion of ARO and other environmental liabilities.
The Group believes that its estimates of remaining proved recoverable
oil and gas reserve volumes are reasonable and such estimates have
been prepared in accordance with the SEC Modernization of Oil and Gas
Table 4 - Reserve quantity information
Reporting rules, which were issued by the SEC at the end of 2008.
Estimated oil and gas reserves
The Group estimates its reserves at least once a year. The Group’s reserves
estimation as of 31 December 2018, 2017 and 2016 was based on the
Proved reserves represent estimated quantities of oil (including crude
DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”).
oil and condensate) and natural gas, which available geological and
DeGolyer and MacNaughton prepared its proved oil and natural gas reserve
engineering data demonstrates with reasonable certainty to be recoverable
estimates in accordance with Rule 4-10 of Regulation S–X, promulgated
in the future from known reservoirs under existing economic and operating
by the SEC, and in accordance with the oil and gas reserves disclosure
conditions. Proved developed reserves are proved reserves that can
provisions of ASC 932 of the FASB Accounting Standards Codification
reasonably be expected to be recovered through existing wells with existing
(ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69
equipment and operating methods. The choice of method or combination
Disclosures about Oil and Gas Producing Activities).
of methods employed in the analysis of each reservoir was determined
by the stage of development, quality and reliability of basic data, and
Reserves engineering is a subjective process of estimation of hydrocarbon
production history.
accumulation, which cannot be exactly measured, and the reserve
estimation depends on the quality of available information and the
GeoPark 201
interpretation and judgement of the engineers and geologists. Therefore,
the reserves estimations, as well as future production profiles, are often
different than the quantities of hydrocarbons which are finally recovered.
The accuracy of such estimations depends, in general, on the assumptions
on which they are based.
The estimated GeoPark net proved reserves for the properties evaluated as
of 31 December 2018, 2017 and 2016 are summarized as follows, expressed
in thousands of barrels (Mbbl) and millions of cubic feet (MMcf ):
As of 31 December 2018
As of 31 December 2017
As of 31 December 2016
Oil and
Oil and
Oil and
condensate
Natural gas
condensate
Natural gas
condensate
Natural gas
(Mbbl)
(MMcf )
(Mbbl)
(MMcf )
(Mbbl)
(MMcf )
32,326.0
696.0
55.0
2,058.0
-
1,763.0
11,944.0
17,339.0
6,207.0
-
35,135.0
37,253.0
42,449.0
2,622.0
1,440.0
18,460.0
64,971.0
100,106.0
359.0
8,823.0
3,174.0
-
12,356.0
49,609.0
21,101.0
720.0
76.0
-
9,502.0
31,399.0
44,398.0
3,423.0
-
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
9,502.0
547.0
72.0
-
9,316.0
19,437.0
27,838.0
6,052
-
9,305.0
43,195.0
62,632.0
-
6,610.0
29,525.0
-
-
36,135.0
-
29,690.0
-
-
29,690.0
65,825.0
Net proved developed
Colombia (a)
Chile (b)
Brazil (c)
Argentina (d)
Peru (e)
Total consolidated
Net proved undeveloped
Colombia (f )
Chile (g)
Argentina (h)
Peru (e)
Total consolidated
Total proved reserves
(a) Llanos 34 Block, La Cuerva Block, Yamu Block and Llanos 32 Block account
for 96%, 1.5%, 1.5% and 1% (Llanos 34 Block, La Cuerva Block and Yamu Block
(f ) Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2% and
1% (Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2%
account for 98%, 1% and 1% in 2017, and Llanos 34 Block and Llanos 32
and 1% in 2017, and Llanos 34 Block accounts for 100% in 2016) of the proved
Block accounts for 99% and 1% in 2016) of the proved developed reserves,
undeveloped reserves, respectively.
respectively.
(b) Fell Block accounts for 100% (Fell Block and Flamenco Block account for 98%
and 2% in 2017, and Fell Block and Flamenco Block account for 99% and 1% in
2016) of the proved developed reserves, respectively.
(g) Fell Block accounts for 100% (Fell Block and Flamenco Block account for 97%
and 3% in 2017, and Fell Block and Flamenco Block account for 99% and 1% in
2016) of the proved undeveloped reserves, respectively.
(c) BCAM-40 Block accounts for 100% of the reserves.
(h) Aguada Baguales Block and El Porvenir Block account for 75% and 25% of
the proved undeveloped reserves, respectively.
(d) Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account
for 48%, 33% and 19% of the proved developed reserves, respectively.
(e) Morona Block accounts for 100% of the reserves.
202 GeoPark 20F
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 2015
Increase (decrease) attributable to:
Revisions (a)
Extensions and discoveries (b)
Purchases of Minerals in place (c)
Production
Reserves as of 31 December 2016
Increase (decrease) attributable to:
Revisions (d)
Extensions and discoveries (e)
Production
Reserves as of 31 December 2017
Increase (decrease) attributable to:
Revisions (f )
Extensions and discoveries (g)
Purchases of Minerals in place (h)
Production
Reserves as of 31 December 2018
Colombia
30,423.3
Chile
5,953.8
Brazil
120.0
1,148.0
(34.0)
5,779.0
6,311.0
-
(5,173.3)
37,340.0
29,047.0
(7,203.0)
65,499.0
9,826.0
8,839.0
-
(9,389.0)
74,775.0
-
-
(502.8)
6,599.0
-
(347.0)
4,143.0
-
-
(14.0)
72.0
19.0
-
(15.0)
76.0
(586.0)
(6.0)
41.0
-
(280.0)
3,318.0
-
-
(15.0)
55.0
6,315.0
(2,109.0)
Argentina
Peru
Total
-
-
-
-
-
-
-
-
-
-
-
-
3,968.0
(470.0)
-
-
-
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
(257.0)
-
-
-
8,977.0
8,880.0
3,968.0
(10,154.0)
3,498.0
18,460.0
100,106.0
(a) 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
minor fields in the Llanos 34 Block, and 1 mmbbl was from the Fell Block in
Chile.
a change in a previously adopted development plan in the Fell Block in Chile,
resulting in a 2.4 mmbbl decrease.
(e) In Colombia, the extensions and discoveries are primary due to the
Chiricoca, Jacamar, and Curucucu field discoveries in the Llanos 34 Block and
the Tigana and Jacana field extensions in the Llanos 34 Block.
(f ) For the year ended 31 December 2018, the Group’s oil and condensate
proved reserves were revised upward by 9.0 mmbbl. The primary factors
- Such increase was partially offset by lower average oil prices impacting the La
leading to the above were:
Cuerva and Yamu Blocks in Colombia, resulting in a 2 mmbbl decrease.
(b) In Colombia, the extensions and discoveries are primarily due to the Jacana
field appraisal wells in the Llanos 34 Block.
(c) In December 2016, we obtained final regulatory approval for our acquisition
of the Morona Block in Peru. The Joint Investment and Operating Agreement
- Better than expected performance from existing wells, from the Tigana and
Jacana fields in the Llanos 34 Block, resulting in an increase of 15.4 mmbbl.
- The impact of higher average oil prices resulting in a 0.7 mmbbl, 1.0 mmbbl
and 0.3 mmbbl increase in reserves from the blocks in Colombia, Peru and
Chile, respectively.
dated 1 October 2014 and its amendments were closed on 1 December 2016
- Such increase was partially offset by a decrease in reserves mainly related to
following the issuance of Supreme Decree 031-2016-MEM.XXX.
(d) 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
a change in a previously adopted development plan in Max, Tua, Chachalaca
Sur, Tilo, and Jacamar fields in the Llanos 34 Block, resulting in a 6.3 mmbbl
decrease. Also, lower than expected performance from existing wells in Fell
leading to the above were:
- Better than expected performance from existing wells, from the Tigana and
Jacana fields in the Llanos 34 Block, resulting in an increase of 3.8 mmbbl.
- 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
Block, resulted in a 0.8 mmbbl decrease. Finally, revisions in Peru resulted in a
1.3 mmbbl decrease.
(g) In Colombia, the extensions and discoveries are primary due to the Tigana
and Jacana fields appraisal wells and the Tigui field discovery in the Llanos 34
Block.
(h) Purchase of Minerals in place refers to the Aguada Baguales, El Porvenir,
and Puesto Touquet fields acquisition during 2018. See Note 35.3 for further
details.
GeoPark 203
Net proved reserves (developed and undeveloped) of natural gas:
Millions of cubic feet
Reserves as of 31 December 2015
Increase (decrease) attributable to:
Revisions (a)
Production
Reserves as of 31 December 2016
Increase (decrease) attributable to:
Revisions (b)
Extensions and discoveries (c)
Production
Reserves as of 31 December 2017
Increase (decrease) attributable to:
Revisions (d)
Extensions and discoveries (e)
Purchase of Minerals in place (f )
Production
Reserves as of 31 December 2018
Colombia
Chile
Brazil
Argentina
Total
-
-
-
-
-
-
-
-
-
2,122.0
-
-
36,515.0
36,158.0
5,078.0
(319.0)
(5,293.0)
(6,314.0)
36,300.0
29,525.0
(13,725.0)
1,187.0
59.0
-
(3,745.0)
(5,763.0)
20,017.0
23,821.0
544.0
3,909.0
-
(679.0)
-
-
-
-
-
-
-
-
-
-
-
-
72,673.0
4,759.0
(11,607.0)
65,825.0
(13,666.0)
1,187.0
(9,508.0)
43,838.0
(135.0)
6,031.0
10,452.0
10,452.0
(3,703.0)
(5,803.0)
(1,071.0)
(10,577.0)
2,122.0
20,767.0
17,339.0
9,381.0
49,609.0
(a) 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
driven by better than expected performance from existing wells, primarily the
Ache field in the Fell Block in Chile, resulting in an addition of 9 billion cubic
feet. This increase was partially offset by a reduction of 4 billion cubic feet in
resulting in a decrease of 0.7 billion cubic feet.
- The above was partially offset by higher average prices that resulted in an
increase of 2.5 billion cubic feet in the Fell Block in Chile.
(e) The extensions and discoveries are primary due to the Jauke Field discovery
in the Fell Block, in Chile, and the gas discovery of the Une Formation in the
the Pampa Larga field, also in the Fell Block.
(b) 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
Llanos 32 Block, in Colombia.
(f ) Purchase of Minerals in place refers to the Aguada Baguales, El Porvenir,
and Puesto Touquet fields acquisition during 2018. See Note 35.3 for further
combined effect of:
details.
- Removal of proved undeveloped reserves due to changes in previously
adopted development plan in the Fell Block in Chile and unsuccessful proved
Revisions refer to changes in interpretation of discovered accumulations and
undeveloped executions in the Fell Block in Chile (totalling 21.3 billion cubic
some technical and logistical needs in the area obliged to modify the timing
feet).
and development plan of certain fields under appraisal and development
- The above was partially offset by an increase of 6.8 billion cubic feet due
phases.
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
Table 6 - Standardized measure of discounted future net cash flows related to
increase of 0.8 billion cubic feet.
(c) In Chile, the extensions and discoveries are primary due to the Uaken Field
discovery in the Fell Block.
(d) For the year ended 31 December 2018, the Group’s proved natural gas
reserves were revised downwards by 0.1 billion cubic feet. This was the
combined effect of:
proved oil and gas reserves
The following table discloses estimated future net cash flows from future
production of proved developed and undeveloped reserves of crude oil,
condensate and natural gas. As prescribed by SEC Modernization of Oil
and Gas Reporting rules and ASC 932 of the FASB Accounting Standards
- Removal of proved undeveloped reserves due to changes in previously
Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly
adopted development plan in the Fell Block in Chile and lower than expected
SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future
performance from existing wells in the Fell Block in Chile (totalling 2.0 billion
net cash flows were estimated using the average first day-of-the-month
cubic feet).
price during the 12-month period for 2018, 2017 and 2016 and using a 10%
- Lower than expected performance from existing wells in BCAM-40 Block,
annual discount factor. Future development and abandonment costs include
204 GeoPark 20F
estimated drilling costs, development and exploitation installations and
projections. It is important to point out that this information does not include,
abandonment costs. These future development costs were estimated based
among other items, the effect of future changes in prices, costs and tax rates,
on evaluations made by the Group. The future income tax was calculated by
which past experience indicates that are likely to occur, as well as the effect of
applying the statutory tax rates in effect in the respective countries in which
future cash flows from reserves which have not yet been classified as proved
we have interests, as of the date this supplementary information was filed.
reserves, of a discount factor more representative of the value of money
This standardized measure is not intended to be and should not be
gas. These future changes may have a significant impact on the future net
interpreted as an estimate of the market value of the Group’s reserves. The
cash flows disclosed below. For all these reasons, this information does not
purpose of this information is to give standardized data to help the users of
necessarily indicate the perception the Group has on the discounted future
the financial statements to compare different companies and make certain
net cash flows derived from the reserves of hydrocarbons.
over the lapse of time and of the risks inherent to the production of oil and
Amounts in US$ ‘000
At 31 December 2018
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 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
Colombia
Chile
Brazil
Argentina
Peru
Total
4,059,619
317,437
102,104
277,429
1,352,159
6,108,748
(983,782)
(156,724)
(49,255)
(173,053)
(441,801)
(1,804,615)
(207,630)
(848,519)
(39,360)
(2,515)
2,019,688
118,838
(640,625)
1,379,063
(29,008)
89,830
2,434,954
284,711
(531,751)
(131,788)
(187,414)
(558,226)
1,157,563
(343,561)
814,002
(57,690)
(656)
94,577
(19,338)
75,239
873,771
394,993
(229,593)
(186,700)
(69,996)
(149,785)
(191,096)
383,086
(113,584)
269,502
(8,344)
50,164
(14,709)
35,455
(3,752)
(2,231)
46,866
(5,317)
41,549
157,527
(56,311)
(7,524)
(10,442)
83,250
(13,293)
69,957
200,713
(74,116)
(16,352)
(21,041)
89,204
(15,688)
73,516
(54,400)
(293,468)
(598,610)
(6,610)
43,366
(8,499)
34,867
(189,922)
(1,049,797)
426,968
2,655,726
(188,435)
(871,884)
238,533
1,783,842
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,047,540
3,924,732
(466,110)
(1,185,960)
(235,920)
(488,548)
(107,294)
(676,618)
238,216
1,573,606
(147,682)
(523,874)
90,534
1,049,732
941,463
2,410,940
(497,187)
(987,596)
(234,328)
(470,461)
(69,698)
(290,179)
140,250
662,704
(109,321)
(253,302)
30,929
409,402
GeoPark 205
Brazil
Argentina
Peru
Total
72,316
(20,945)
16,366
542
-
2,214
(1,872)
-
(4,020)
8,915
73,516
(26,979)
(3,000)
8,385
-
-
603
7,976
9,456
69,957
(24,781)
(15,170)
(1,426)
-
-
(1,879)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
30,929
-
-
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
1,133
605,764
(11,828)
(256,597)
10,063
69,959
90,534
1,049,732
(21,243)
-
(445,776)
-
-
-
737
-
191,288
9,611
-
-
(7,098)
-
589,275
(10,034)
284,256
89,597
244,046
55,373
-
55,373
6,808
8,040
-
-
(65,585)
(245,263)
19,783
172,636
41,549
34,867
238,533
1,783,842
Colombia
300,097
(91,163)
(171,131)
14,941
76,641
17,302
70,180
-
3,030
49,605
269,502
(198,631)
289,199
(124,053)
49,574
67,571
Chile
68,155
(15,127)
(16,854)
(49,763)
-
9,417
22,765
-
8,256
8,606
35,455
(14,251)
26,928
79,078
-
7,146
673,622
(69,594)
(258,842)
46,060
814,002
(380,829)
397,064
(18,632)
271,933
85,880
257,540
-
(185,118)
137,223
1,379,063
6,097
4,380
75,239
(18,923)
16,093
413
12,323
2,980
(4,517)
-
(1,368)
7,590
89,830
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 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
Net changes in income taxes
Accretion of discount
Present value at 31 December 2017
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 2018
206 GeoPark 20F
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, 2019
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
for the company and have:
and 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,
d. Disclosed in this report any change in the company’s internal control over
to ensure that material information relating to the company, including its
financial reporting that occurred during the period covered by the annual
consolidated subsidiaries, is made known to us by others within those entities,
report that has materially affected, or is reasonably likely to materially affect,
particularly during the period in which this report is being prepared;
the company’s internal control over financial reporting; and
5. The company’s other certifying officer(s) and I have disclosed, based on
internal control over financial reporting to be designed under our supervision,
our most recent evaluation of internal control over financial reporting, to
to provide reasonable assurance regarding the reliability of financial
the company’s auditors and the audit committee of the company’s board of
reporting and the preparation of financial statements for external purposes in
directors (or persons performing the equivalent functions):
accordance with generally accepted accounting principles;
b. Designed such internal control over financial reporting, or caused such
GeoPark 207
Exhibit 12.2
c. Evaluated the effectiveness of the company’s disclosure controls
Certification by the Principal Executive Officer Pursuant to 18 U.s.c.
and 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, 2018 (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
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
2. the information contained in the Report fairly presents, in all material
the company’s auditors and the audit committee of the company’s board of
respects, the financial condition and results of operations of the Company.
1. the Report fully complies with the requirements of Section 13(a) or 15(d) of
directors (or persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or
Andrés Ocampo
operation of internal control over financial reporting which are reasonably
Chief Financial Officer
likely to adversely affect the company’s ability to record, process, summarize
(Principal Financial Officer)
and report financial information; and
Date: April 11, 2019
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, 2018 (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, 2019
James F. Park
Chief Executive Officer
(Principal Executive Officer)
208 GeoPark 20F
209 Annual Report 2018 / Board of Directors
Casanare Department, Colombia
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
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.
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.
210 Annual Report 2018
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
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).
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.
211 Annual Report 2018 / Management Team
REC-128 Block, Praia Dos Castelhanos, Brazil
MANAGEMENT TEAM
JAMES F. PARK
Chief Executive Officer
MARCELA VACA
Colombia
SALVADOR MINNITI
Exploration
AGUSTINA WISKY
Capacities & Culture
AUGUSTO ZUBILLAGA
Chief Operating Officer
ALBERTO MATAMOROS
Argentina, Chile
CARLOS MURUT
Reserves & Development
GUILLERMO PORTNOI
New Business
ANDRÉS OCAMPO
Chief Financial Officer
BARBARA BRUCE
Peru
MARTÍN TERRADO
Operations & Safety
STACY STEIMEL
Shareholder Value
PEDRO E. AYLWIN
Legal & Governance
LIVIA VALVERDE
Brazil
NORMA SÁNCHEZ
Social & Environment
ADRIANA LA ROTTA
Connections
Our Offices
Argentina
Buenos Aires Office
Florida 981 – 1st floor
C1005AAS Buenos Aires
+ 54 11 4312 9400
Chile
Santiago Office
Brazil
Rio de Janeiro Office
Registered Office
Cumberland House 9th floor,
1 Victoria Street
Praia de Botafogo, 288, Bloque A, Sala
Hamilton HM11 - Bermuda
801, Botafogo, Río de Janeiro
+ 55 21 3078 7475
Peru
Lima Office
Corporate Secretary
Pedro E. Aylwin
Independent Auditors
Price Waterhouse & Co. S.R.L.
Bouchard 557, 8th floor
Buenos Aires
Argentina
Petroleum Consultant
DeGolyer and MacNaughton
Counsel to the Company
5001 Spring Valley Road Suite 800 East
Nuestra Señora de los Ángeles 176
Av. Santa Cruz 300, San Isidro, Lima
as to New York Law
Dallas, Texas 75244
Las Condes, Santiago
+ 56 2 242 9600
Punta Arenas Office
Lautaro Navarro 1021, Punta Arenas
Magallanes Region
+ 56 61 745 100
Colombia
Bogota Office
Street 94 N° 11-30, 8th floor
Bogota
+ 57 1 743 2337
+ 51 1 713 6100
Davis Polk & Wardwell LLP
USA
England
London Office
18 Upper Brook St., 5th floor
London W1K 7PU
+ 44 207 629 8466
Spain
Madrid Office
Calle Jorge Juan 8, 3H
Madrid 28001
+ 34 91 104 83 93
450 Lexington Avenue
New York, NY 10017
USA
Solicitors to the Company
as to Bermuda Law
Cox Hallett Wilkinson
Cumberland House 9th floor,
1 Victoria Street
Hamilton HM11 - Bermuda
P.O. Box HM 1561
Hamilton HMFX - Bermuda
Registrar
Computershare Investor Services
Queensway House
480 Washington Blvd.
Jersey City, NJ 07310
213 Annual Report 2018
Jacana Field, Llanos 34 Block, Colombia
Challacó Bajo, Neuquén Province, Argentina
ANNUAL REPORT 2018
WWW.GEO-PARK.COM