july 2020/media/files/... · 1 day ago · 3 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000...
TRANSCRIPT
Proven Team, Assets and Opportunity
July 2020
2
Why GeoPark
PLATFORM
PEOPLE
VALUE
UPSIDE SELF-FUNDING
PROVEN CAPABILITIES
ACROSS FULL E&P VALUE
CHAIN
PROVEN OIL AND GAS
ASSETS WITH 2P NAV OF
$2.5 BILLION ($42.5/SHARE)1
ORGANIC EXPLORATION AND
NEW ACQUISITION GROWTH
PROJECTS
UNIQUE LONG-ESTABLISHED, HIGH-IMPACT, RISK-BALANCED
ASSET AND OPERATING BASE ACROSS LATIN AMERICA
CASH FLOW PAYS FOR
BUILDING THE BUSINESS
TRACK RECORD
17-YEAR CONTINUOUS
OPERATIONAL AND FINANCIAL
GROWTH
1Based on D&M 2019.
3
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
True Latin American Independent
Net
Avera
ge
Dail
y P
rod
uc
tio
n (
bo
ep
d)
Historical Production
2020E3
ONLY PUBLIC
INDEPENDENT
POSITIONED ACROSS
LATIN AMERICA - THE
MOST ATTRACTIVE
OIL & GAS
INVESTMENT REGION
TODAY
ONLY PUBLIC
INDEPENDENT
POSITIONED ACROSS
LATIN AMERICA - THE
MOST ATTRACTIVE OIL
& GAS INVESTMENT
REGION TODAY
3Annual average of 40,000-42,000 boepd, assuming Brent of $30/bbl and Vasconia differential of $5/bbl from April to December 2020.
ARGENTINA
BRAZIL
COLOMBIA
ECUADOR
1GeoPark: DeGolyer & MacNaughton (D&M) December
2019 Amerisur: McDaniel July 2019.2Non-producing asset. On July 15, 2020, GeoPark
formally initiated a process to irrevocably retire from the
Morona block in Peru.
2P RESERVES AND NPV101
2.1
0.3
0.30.10.10.3 Pro Forma Amerisur
Argentina
Brazil
Peru
Chile
Colombia
2P RESERVES
(MMBOE)
NPV10
($BN)
129
25
31
4822
219 3.1
2
4
17-Year Track Record
6
16 1715
20 21 20
24
29
4043
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
CAGR 22%
PRODUCTION (MBOEPD) RESERVES (2P, MMBOE)
NET PRESENT VALUE1 ($ BILLION) NET ASSET VALUE PER SHARE1,2 ($/SH.)
PROVEN RISK MANAGEMENT = CONSISTENT VALUE CREATION
Embracing & Managing Volatility
4250 50
57
70
122 125
143
159
184
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Gas Oil
CAGR 17%
219
Pro Forma Amerisur (22 mmboe)
6 7 8
1114
2122 22
28
36
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Gas Oil
CAGR 21%
Pro Forma Amerisur (6 mboepd)
46
0.3
0.9 0.91.0
1.3
1.7 1.6
1.9
2.3
2.7
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
CAGR 25%
3.1
Pro Forma Amerisur ($0.3 billion)
12P D&M 2019. 2Calculated as net debt-adjusted 2P NPV10 divided by number of shares outstanding. 2019 does not include the effect of the Amerisur acquisition.
5
People = Results
v
DRILLING SUCCESS RATE
280+ wells
Llanos 34
75+%
90+%
FINDING & DEVELOPMENT COSTS1
Consolidated
Llanos 34
/boe
$2.6 /boe
DRILL, COMPLETE & PUT-ON-
PRODUCTION WELL COST
Llanos 34
OPEX3
Consolidated
Llanos 34
$7.9/boe
$4.5 /boe
OIL & GAS DISCOVERED
2P Gross
2P 2019 RRR2
~$3.6 mm/well
OPERATED PRODUCTION3
Gross 80,000+ boepd
155%
$4.5
440+ mmboe
1Estimated by dividing total capital expenditures in 2019 by 2P Reserves added (based on D&M 2019). 2Reserve Replacement Ratio. 31Q2020.
Proven 17-Year Performance
5
COUNTRIES
11
HYDROCARBON
BASINSBLOCKS
49
ACRES
6.5+million
6
Much More than ESG
All metrics above correspond to 2018. Comparisons refer to 2017, except when specified. For additional ESG performance details, refer to 2018 SPEED / ESG Report (GRI Standards) on https://www.geo-park.com/en/publications/
7
Risk Management Business Through Thick and Thin
OPERATIONAL
• Experienced people
• 17-year track record
• 100+ mmboe produced and 280+ wells drilled
• Low-cost operator
• Oil vs gas, light-mid-heavy balance
• Low capital commitments
SOCIAL & ENVIRONMENTAL
• SPEED/ESG in-house value system
• Licensed operator in five countries
ECONOMIC
• Low breakevens
• Flexible work programs
• Self-funded organic growth
• Oil hedging contracts in place
• Effective capital allocation
• Strong balance sheet
• Partnerships
GEOPOLITICAL - MACROECONOMIC - REGULATORY
• Multi-country, multi-project, risk-balanced portfolio approach
• 49 blocks, 11 basins, 5 countries, 6.5+ million acres
• OECD / Investment grade countries
• Strategic partners
COMMERCIAL
• Top-tier secure offtakers
• Limited demand risk
RESERVOIR - RESOURCE AVAILABILITY
• Leading oil and gas finding team
• 800+ mmboe discovered in 30+ years
• Sustainable reservoir management
• PDP RLI > 3.6 years; 2P RLI > 13.5 years
• 50+ oil and gas fields in production
Surface
Risk
Sub-surface
Risk
Macro
Risk
8
Plan Ahead for 2020
• $157.7 million1 cash
• Up to $75 million oil
prepayment facility
• 27,500 bopd production
hedged 3Q2020
• $130.7 million uncommitted
credit lines2
• No long-term debt principal
payments until 2024
• High production base
• 90% production cash flow
positive at $20-30/bbl
• Low-cost conventional
fields
• Continuity of operations
plan in place
• 50% G&A and G&G
reduction
DOING MORE
FOR LESS
• High-quality growth
platform
• Diversified asset base
• Deep new project
inventory
CAPITAL ALLOCATION
FOCUS
• CAPEX cut 65-75%
• Dividend and buyback
suspended
• Self-funded business
model
• Prioritize most profitable
and strategic projects
• Renegotiating contracts
• Cost reduction plan
• New operational
efficiencies
• Voluntary salary and
bonus reduction
• $290+ million capital and
costs reductions
implemented
FLEXIBLE, SELF-FUNDED & CAPITAL EFFICIENT
2020 WORK PROGRAM ($MM)
PROFITABLE
OPERATIONS
VALUE GROWTH
OPPORTUNITIES
FINANCIAL
STRENGTH
ABILITY TO QUICKLY ADJUST UP OR DOWN TO
MITIGATE RISK AND BALANCE CASH FLOWS
Cash Flow Positive at Lowest Oil Prices
ROBUST PRODUCTION BASE
Pro
du
cti
on
100%
90%
15%
Oil ($30+/bbl)
Gas
(Unaffected by oil price)
100%
0
90% PRODUCTION CASH FLOW
POSITIVE AT $20-30/BBL
180-200
45-50
Brent $60-65/bbl Brent $25-30/bbl
1 June 30, 2020.
PROTECTING BASE OIL PRICE
EXTENSIVE HEDGING POSITION
HEDGED OIL PRODUCTIONIMMEDIATE CAPEX REDUCTION
Oil ($20-30/bbl)26,000bopd
27,500bopd
25,500bopd
2Q2020 3Q2020 4Q2020
~80% ~75% ~70%
2 March 31, 2020.
20-25
65-75July 2020
Expansion
May 2020
Review
Brent $25-35/bbl
9
Risk Managed Response in Downturn
9
Preparing for Recovery
• Temporary production shut-in of 6,500-7,500 boepd (2Q2020)
• Ability to quickly bring back production to pre-shut-in levels
PRODUCTION MANAGEMENT TO PRESERVE VALUE
40,000-42,000 boepd2
2020E PRODUCTION PROFILE
16
7 ~7
2
2014 2019 2020E
QUICKLY ADAPTING TO LOWEST OIL PRICES
Doubled size,
from 20,557 to
40,046 boepd59
80
50
22
2014 2019 2020E
AMER G&A Costs
FULL FLEXIBILITY TO EXPAND 2020 WORK PROGRAM
IF OIL PRICE RECOVERS
-65-75%
-29%
E&P Industry Average1
• 2020 work program reduced by 65-75%
• Targeting 40,000-42,000 boepd average
2020E CAPEX CUTS
25% down~50% down
1Stifel Report over 129 E&P companies, May 22, 2020.
50-55
2Brent $35/bbl and Vasconia differential averaging $5/bbl from June to December 2020.
OPERATING COST DOWN BY 25% ($/BOE) G&A/G&G COSTS DOWN BY 50% ($MM)
CONSISTENTLY STREAMLINING AND IMPROVING BUSINESS ACROSS THE ENTIRE PORTFOLIO
GeoPark
Weighted average effect of adding Amerisur into GeoPark operating costs Amerisur Pro Forma
1Q2020 2Q2020 3Q2020E 4Q2020E
10
Best-In-Class Capital Efficient Growth High Return Assets
POSITIONED TO GENERATE FREE CASH FLOW AT LOWEST OIL PRICES
CASH GENERATION > CAPEX BY 2-3X
EFFICIENT WORK PROGRAMS IN EVERY OIL PRICE ENVIRONMENT
1Assuming Brent of $35/bbl and Vasconia differential averaging $5/bbl from June to December 2020.
2020E OPERATING NETBACKS ($/BOE)
LOW BREAKEVENS Brent $35/bbl - Gas $3-4/mcf 1
$50/bbl $46/bbl $55/bbl $70/bbl $64/bbl $35/bbl 1
Brent
150170
210230
250
$20/bbl $25/bbl $30/bbl $35/bbl $40/bbl
118 122
228
398447
220-240
49 38
106 125 12665-75
2015 2016 2017 2018 2019 2020E
Operating Netback ($mm) Capex ($mm)
2020E FREE CASH FLOW* ($MM)
Low Capital
Intensity
1
CAPEX ($mm)
140-160160-180
200-220 220-240240-260
2X+ 3X+
2X+
3X+
3X+
3X+
10
$50-60 mm are
tax obligations of
fiscal year 2019
with higher Brent
2020E OPERATING NETBACK2 SENSITIVITIES ($MM)
2Assuming specified Brent oil prices and Vasconia differential averaging $5/bbl from April to December 2020.
166
15
(6)
(14)(7)
(3) (3) (3)
(5) (4)
38
23
35
Op. Netback OPEX Selling/Royalties Discounts
Colombia
(Pacific Region)
Brazil-Argentina-Chile
(Atlantic Region)
Consolidated
(10) (8)
Op. NetbackOPEXSelling/Royalties Realized Hedge Gains
Transportation & Commercial DiscountsVasconia Differential
2 2
*Excluding working capital changes, debt service and other payments
220-240
(65-75)
(50-55)
(65-70)
35-50
Op. Netback CAPEX
11Incurrence Covenants (x times)
Preserving Balance Sheet Strength Tools & Safety Nets in Place
• $157.7 million1 cash position
• Up to $75 million oil prepayment
facility ($50 million committed)
• Extensive hedging position
• $130.7 million uncommitted
credit lines2
• 1P 2019 NPV10 of $2.0 billion
• 2P 2019 NPV10 of $2.8 billion
Assets Liabilities
• $425 million 6.5% senior notes2 due 2024
• $350 million 5.5% senior notes2 due 2027
- $2.2 billion oversubscribed
- Top tier investors
- Lowest pricing ever achieved by a
single B company
• B+ rating reaffirmed by credit rating
agencies
LIQUIDITY AND FLEXIBILITY
1 June 30, 2020.2 144-A/Reg-S.
LONG-TERM DEBT PROFILE
0 0 0
425
0 0
350
2021 2022 2023 2024 2025 2026 2027
4+ YEARS UNTIL
FIRST PRINCIPAL
PAYMENT
3.25
CONSERVATIVE BUSINESS APPROACH
1.7
4.0
3.6
1.7
1.0 0.9
1.7
2014 2015 2016 2017 2018 2019 LTM1Q2020
Net Debt to Adjusted Ebitda Ratio (x times)
RESERVE LIFE FAR EXCEEDING DEBT MATURITIES
RESERVE LIFE INDEX (D&M 2019) NET LEVERAGE RATIO (X TIMES)
8.9Years
13.5Years
2019
1P 2P11
PRINCIPAL PAYMENTS ($MM)
2 March 31, 2020.
12
Colombia and EcuadorAsset Base Pacific Region
• Key Assets: Llanos 34, CPO-5
(Llanos basin)
• 23 blocks - 19 operated / 3.8
mm acres
• 2019 D&M 2P and 3P net
reserves: 129 mmboe and 169
mmboe
• 2019 D&M 2P and 3P NPV10:
$2.1 billion and $2.6 billion
• RLI: 1P 8.1 years; 2P 10.9
years; 3P 14.3 years
• Grew from 0 to 75,000+ boepd
gross since 2012
• New flowline in place connecting
Llanos 34 to regional infrastructure
• 1.4+ million new strategic acres
added in 2019 near or adjacent to
Llanos 34
• Recent Amerisur acquisition,
providing reserves, production,
upside and valuable partnerships
(Oxy/ONGC)
COLOMBIA
• Key Assets: Perico and Espejo
blocks (Oriente basin)
• 2 blocks - 1 operated / 0.03
mm acres
• 5+ multilayer ready-to-drill light-
oil prospects and leads
identified
• Significant exploration
opportunities, surrounded by
big producing oil fields
• Infrastructure in place with
spare capacity
• Established business
environment
• Upcoming bid rounds
ECUADOR
C O L O M B I A
200km
Pipelines
LLANOS 34
Pacific
Ocean
PLATANILLO
CPO-5
Pacific
Ocean
E C U A D O R
ESPEJO
PERICO
LLANOS BASIN
PUTUMAYO BASIN
PUTUMAYO, ORIENTE
& MARAÑON BASINS
13
229353
640 655
1,006
1,393
1,8842,100
2012 2013 2014 2015 2016 2017 2018 2019
C O L O M B I A
200km
Pipelines
LLANOS 34
Pacific
Ocean
PLATANILLO
CPO-5
Colombia Core Value Foundation and Growth Source
KEY METRICS
Finding and Development Cost
(as of Dec. 2019)$2.6/boe
2P Reserve Life Index
(2019)10.9 years
2P Reserve Replacement Ratio
(2019)203%
Adjusted EBITDA
(2019)
CAPEX
(2019)
$367 million
$77 million
LLANOS BASIN
PUTUMAYO BASIN
12 17
3947
67
88
111129
2012 2013 2014 2015 2016 2017 2018 2019
3,4406,491
10,80713,189
15,590
21,788
28,545
32,304
2012 2013 2014 2015 2016 2017 2018 2019
PRODUCTION (BOEPD)
CAGR: 38%
2P RESERVES1 (MMBOE)
CAGR: 41%
VALUE ($MM)
2P PV101
CAGR: 37%
NET RESERVES, PRODUCTION AND VALUE GROWTH
229353
640 655
1,006
1,393
1,8842,100
2012 2013 2014 2015 2016 2017 2018 2019
1 2P D&M 2019.
14
Colombia
PRODUCTION HISTORY LLANOS 34 BLOCK
Largest & Most Economic Oil Discovery in 20+ Years
0.8-1 BILLION BARRELS ORIGINAL OIL IN PLACE 14
2013-2015
BIG TIGANA & JACANA DISCOVERIES
• 8 oil fields discovered since 2012
• 20+ gross mmbbl produced
2012
BRINGING NEW IDEAS TO THE BASIN
• Zero production, zero reserves
• First oil field discovered - Max
2019-2020
EXPANDING TO ADJACENT BLOCKS
• 13 oil fields discovered to date
• 100+ gross mmbbl produced
1.4+ million acres
added around
Llanos 34
LLANOS 34
BLOCK
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
55,000
60,000
65,000
70,000
75,000
80,000
0
10,000,000
20,000,000
30,000,000
40,000,000
50,000,000
60,000,000
70,000,000
80,000,000
90,000,000
Jun-12 Jun-13 Jun-14 Jun-15 Jun-16 Jun-17 Jun-18 Jun-19
Daily P
rod
uc
tio
n (
bo
pd
)
Cu
mm
ula
tiv
e P
rod
ucti
on
(b
bl)
1 2P D&M 2019. 2 Brent $40/bbl.Oil ProductionCumulative Production
100 mmbbl
Production Milestone
WELL ECONOMICS
EUR/well 2-3 mmbbl
IP Rate 1,000-2,000 bopd
Payback2 4-6 months
Drilling Locations 1201
LLANOS 34 GROWTH 2012 2019
2P net reserves 0 122 mmbbl
Purchase price $30 million 0
2P NPV10 0 $2.0 billion
Dec-19
15
Colombia Expanding Footprint Around Core Llanos 34
LLANOS BASIN
LLANOS 34LLANOS 104
LLANOS 32
LLANOS 87
LLANOS 86
Tigana
Jacana
Mariposa
IndicoCPO-5
LLANOS 94
LLANOS 123
LLANOS 124
10 Km
LLANOS BASIN ASSETS OVERVIEW
• Building on GeoPark’s technical, operational and commercial
expertise
• Low-risk development opportunities
• High-impact, low-cost exploration potential
• NOCs Partnership: ONGC, Ecopetrol
CPO-5 PROVIDING MULTIPLE GROWTH OPPORTUNITIES
• CPO-5 block on trend with Tigana / Jacana complex
• Gross 8,000 bopd produced from 2 wells
• Resilient light oil production with breakevens of ~$6-7/bbl1
• Only 50% of 3D seismic coverage
1 Vasconia oil price. Assuming $5/bbl differential, breakeven ~$11-12/bbl Brent.
1.4+
million
acres
Producing oil fields
GeoPark producing blocks
Exploration blocks
16
E C U A D O R10 Km
ANDAQUIES
PUT-30
TACACHO
TERECAYPUT-9
PUT-12
MECAYA
PLATANILLO
PUT-8
COATI
PUT-14
C O L O M B I A
PUT-36
PERICO ESPEJO
OBARODA
P E R U
1 Oriente oil price. Assuming $6/bbl differential, breakeven of ~$20-22/bbl Brent.
Colombia New Entry into Putumayo Basin
PUTUMAYO BASIN
PUTUMAYO BASIN ASSETS OVERVIEW
• Existing production with cost-effective transportation infrastructure in place
• 300–600 mmboe certified resources contiguous to existing production
• Key partner Oxy to invest (and carry GeoPark) $93 million in Terecay,
Tacacho, Mecaya and Put 9 blocks
HIGH IMPACT EXPLORATION PORTFOLIO
• Platanillo: 3,000-4,000 bopd light oil production
• Principal oil fields in Platanillo with breakeven price of ~$14-16/bbl1
(transport costs of $4/bbl via OBA pipeline)
• High-impact exploration portfolio across 11 blocks
2.0+
million
acres
Producing oil fields
GeoPark producing blocks
Exploration blocks
Pipelines
17
Chile, Argentina and BrazilAsset Base Atlantic Region
• Key asset: Fell block (Magallanes
basin)
• 5 operated blocks / 0.8 mm acres
• Long-term gas contract at
attractive prices
• First private E&P operator,
partnering ENAP
• Stable, self-funded production
base of 3,000-3,500 boepd
• Unconventional upside,
including shale oil and tight gas
(220-600 mmboe)
CHILE
• Key assets: Aguada Baguales, El
Porvenir and Puesto Touquet blocks
(Neuquen basin)
• 7 blocks - 3 operated / 2.2 mm acres
• Producing 2,300-2,500 boepd of oil
and gas
• Development and exploration
opportunities including Vaca Muerta
ARGENTINA
• Key asset: Manati, one of Brazil’s
largest gas producing fields
• 12 blocks - 11 operated / 0.3 mm
acres
• Partnering with NOC Petrobras
• Producing 1,000-2,000 boepd of gas
• Low-risk, low-cost exploration
acreage
BRAZIL
RECONCAVO BASIN
POTIGUAR BASIN
CAMAMU -
ALMADA BASIN
SERGIPE ALAGOAS BASIN
PARNAIBA BASIN
South Atlantic
Ocean
BRAZIL
ARGENTINA
NEUQUEN BASIN
MAGALLANES
BASINSouth Atlantic
Ocean
South Atlantic
Ocean
Acreage 3.5 million
Production
(2019)7,742 boepd
Adjusted EBITDA
(2019)$21 million
2P Reserves
(2019)37 mmboe
2P Reserves NPV10 $427 million
KEY METRICS
San Francisco
Gas Plant
Gas Pipeline
Compression
Plant MANATI
South Atlantic
Ocean
COLOMBIA
PERU
EC.
B R A Z I L
A R G E N T I N A
C H I L E
18
Opportunity Outperforming the Market Since 2016
MARKET CAP ($BN)
160%
1.3
0.5
CAPITAL RETURNED ($MM)
75
0.4 188x
SHARES OUTSTANDING (MM)
5958
RESERVES (MMBOE)
701
197
181%
PRODUCTION (BOEDP)
20,557
40,046
100%
OPEX ($/BOE)
56%
7
16
CREATING VALUE IN EVERY CORNER OF THE BUSINESS (2014-2019)
1 2013.
+60%
Brent +53%
S&P 500 +12%
S&P Oil&Gas -37%
GRPK +130%
S&P 500 +22%
Brent +18%
S&P Oil&Gas -10%
GRPK
2014 2015 2016 2017 2018 2019
-47%
S&P 500 -1%
Brent -36%
S&P Oil&Gas -37%
GRPK-27%
S&P 500 +12%
S&P Oil&Gas -30%
Brent -48%
GRPK
-
2
4
6
8
10
12
14
16
18
20
22
$/s
hare +60%
S&P 500 +32%
Brent +23%
S&P Oil&Gas -11%
GRPK +40%
S&P 500 -4%
S&P Oil&Gas -10%
Brent -20%
GRPK
VolumeShare price
SHARE PRICE AND VOLUME PERFORMANCE (2014-2019)
19
LATIN AMERICA FOCUSED
Wide-Open Continent
• Region with largest hydrocarbon resource potential after
Middle East
• Big proven underexplored and underdeveloped low-
cost basins
• Growing demand for energy
• Availability of people, capital, infrastructure and services
• Welcoming business environment
• Regulatory stability
• Limited competition
PETROBRASECOPETROL
M&A
Bolt-Ons
Bolt-Ons
Bolt-Ons
PEMEX
Bolt-Ons
PETROPERU
PETROAMAZONAS
Bolt-Ons
ENAP
$4+ Billion New Project Inventory
National Oil
Companies
NOCs
Bolt-OnsCorporate
M&A
BIG UNDERDEVELOPED HYDROCARBON POTENTIAL
M&A
YPF
Bolt-Ons
20
Unique Value Proposition Leading Latin American E&P Independent
ARGENTINA
BRAZIL
COLOMBIA
ECUADOR
PLATFORM
PEOPLE
VALUE
UPSIDE SELF-FUNDING
ALIGNED
LOW-COST
LEADERSBASIN
CHAMPIONS
ROBUST CAPITAL ALLOCATION PROCESS
FCF+ AT $30/BBL
BRENT1
TRACK RECORD
EXPERIENCE
COUNTS
1 Excluding working capital changes and assuming Brent of $30/bbl and Vasconia differential of $5/bbl from April to December 2020.
21
Disclaimer
The material herein comprises information about GeoPark Limited (“GeoPark” or the “Company”) and its subsidiaries, as of
the date of the presentation. It has been prepared solely for informational purposes and should not be treated as giving
legal, tax, investment or other advice to potential investors. The information presented or contained herein is in summary
form and does not purport to be complete.
No representations or warranties, express or implied, are made as to, and no reliance should be placed on, the accuracy,
fairness, or completeness of this information. Neither GeoPark nor any of its affiliates, advisers or representatives accepts
any responsibility whatsoever for any loss or damage arising from any information presented or contained in this
presentation. The information presented or contained in this presentation is current as of the date hereof and is subject to
change without notice, and its accuracy is not guaranteed. Neither GeoPark nor any of its affiliates, advisers or
representatives makes any undertaking to update any such information subsequent to the date hereof.
This presentation contains forward-looking statements, which are based upon GeoPark and/or its management’s current
expectations and projections about future events. When used in this presentation, the words “believe,” “anticipate,”
“intend,” “estimate,” “expect,” “should,” “may” and similar expressions, or the negative of such words and expressions, are
intended to identify forward-looking statements, although not all forward-looking statements contain such words or
expressions. Additionally, all information, other than historical facts included in this presentation, regarding the COVID-19
pandemic, strategy, future operations, drilling plans, estimated reserves, estimated resources, future production, estimated
capital expenditures, projected costs, the potential of drilling prospects, the retirement from the Morona block due to
continued force majeure and other plans and objectives of management is forward-looking information. Such statements
and information are subject to a number of risks, uncertainties and assumptions. Forward-looking statements are not
guarantees of future performance and actual results may differ materially from those anticipated due to many factors,
including oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves and resources,
availability and cost of drilling rigs, production equipment, supplies, personnel and oil field services, availability of capital
resources and other factors. As for forward-looking statements that relate to future financial results and other projections,
actual results may be different due to the inherent uncertainty of estimates, forecasts and projections. Because of these
uncertainties, potential investors should not rely on these forward-looking statements. Neither GeoPark nor any of its
affiliates, directors, officers, agents or employees, nor any of the shareholders shall be liable, in any event, before any third
party (including investors) for any investment or business decision made or action taken in reliance on the information and
statements contained in this presentation or for any consequential, special or similar damages.
Statements related to resources are deemed forward-looking statements as they involve the implied assessment, based
on certain estimates and assumptions, that the resources will be discovered and can be profitably produced in the future.
Specifically, forward-looking information contained herein regarding "resources" may include: estimated volumes and
value of the Company's oil and gas resources and the ability to finance future development; and, the conversion of a
portion of resources into reserves.
The information included in this presentation regarding estimated quantities of proved reserves in Chile, Colombia, Brazil,
Argentina and Peru as of December 31, 2019; is derived, in part, from the reports prepared by DeGolyer and
MacNaughton, or D&M, independent reserves engineers. Certified reserves refers to net reserves independently evaluated
by the petroleum consulting firm, D&M. Certain reserves data, such as those based on the D&M report, were prepared
under SEC standards, and certain other data were prepared under Petroleum Resources Management System (PRMS)
standards.
The information included in this presentation regarding estimated exploration resources in Chile, Colombia, Brazil,
Argentina and Peru as of December 31, 2017, are derived, in part, from the reports prepared by Gaffney, Cline &
Associates, or GCA. The accuracy of any resource estimate is a function of the quality of the available data and of
engineering and geological interpretation. Results of drilling, testing and production that postdate the preparation of the
estimates may justify revisions, some or all of which may be material. Accordingly, resource estimates are often different
from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are
Prospective Resources are those quantities of petroleum that are estimated, as of a given date, to be potentially
recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have
both an associated “chance of discovery” and a “chance of development” (per PRMS). Prospective Resources are further
subdivided in accordance with the level of certainty associated with recoverable estimates, assuming their discovery and
development, and may be sub-classified based on project maturity. There is no certainty that any portion of the
Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce
any portion of the resources. Prospective Resource volumes are presented as unrisked. The risk or chance of finding a
minimum hydrocarbon volume that can flow to surface is presented as Geological Chance of Success (GCoS).
Certain data in this presentation was obtained from various external sources, and neither GeoPark nor its affiliates,
advisers or representatives has verified such data with independent sources. Accordingly, neither GeoPark nor any of its
affiliates, advisers or representatives makes any representations as to the accuracy or completeness of that data, and
such data involves risks and uncertainties and is subject to change based on various factors.
This presentation contains a discussion of Adjusted EBITDA and Operating Netback, which are not IFRS measures. We
define Adjusted EBITDA as profit for the period, before net finance cost, income tax, depreciation, amortization, certain
non-cash items such as impairments and write-offs of unsuccessful exploration efforts, accrual of share-based payment,
unrealized result on commodity risk management contracts and other non-recurring events. Operating Netback is
equivalent to Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical (G&A/G&G)
and Other operating expenses. Adjusted EBITDA and Operating Netback are included in this presentation because they
are measures of GeoPark’s operating performance and its management believes that is useful to investors because it is
frequently used by securities analysts, investors and other interested parties in their evaluation of the operating
performance of companies in industries similar to GeoPark’s. Adjusted EBITDA and Operating Netback should not be
considered a substitute for financial information presented or prepared in accordance with IFRS. Adjusted EBITDA or
Operating Netback, as determined and measured by GeoPark, should also not be compared to similarly titled measures
reported by other companies.
This presentation contains a discussion of Free Cash Flow, which is not an IFRS measure. We define Free Cash Flow as
operating netback less CAPEX, G&A/G&G expenses and cash taxes. Free Cash Flow does not include working capital
changes or cash flow used in financing activities, including interest or principal payments on financial debt, or other
financing activities like share buybacks, cash dividends and any payment from transactions with non-controlling interests.
Free Cash Flow is included in this presentation because it is a measure of GeoPark’s operating performance and its
management believes that is useful to investors because it is frequently used by securities analysts, investors and other
interested parties in their evaluation of the operating performance of companies in industries similar to GeoPark’s. Free
Cash Flow should not be considered a substitute for financial information presented or prepared in accordance with IFRS.
Free Cash Flow, as determined and measured by GeoPark, should also not be compared to similarly titled measures
reported by other companies.
Rounding amounts and percentages: Certain amounts and percentages included in this document have been rounded for
ease of presentation. Percentage figures included in this document have not in all cases been calculated on the basis of
such rounded figures but on the basis of such amounts prior to rounding. For this reason, certain percentage amounts in
this document may vary from those obtained by performing the same calculations using the figures in the financial
statements. In addition, certain other amounts that appear in this document may not sum due to rounding.
22
Santiago, Chile
Nuestra Señora de los Ángeles 179,
Las Condes, Santiago, Chile
Phone: +(56 2) 2242 9600
Email: [email protected]
James F. Park
Chief Executive Officer
Andrés Ocampo
Chief Financial Officer
Stacy Steimel
Shareholder Value Director
Company Directory
CONTACTS
Best CFO
Best IR Team
Best ESG Metrics