Strong Free Cash Flow Generation

Funds Increased Development and Exploration Program,

Debt Reduction and Balance Sheet Strengthening,

and Cash Dividends to Shareholders

GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Ecuador, Chile, Brazil and Argentina reports its consolidated financial results for the three-month period (“First Quarter” or “1Q2021”). A conference call to discuss 1Q2021 financial results will be held on May 6, 2021 at 10:00 am (Eastern Daylight Time).

All figures are expressed in US Dollars and growth comparisons refer to the same period of the prior year, except when specified. Definitions and terms used herein are provided in the Glossary at the end of this document. This release does not contain all of the Company’s financial information and should be read in conjunction with GeoPark’s consolidated financial statements and the notes to those statements for the period ended March 31, 2021, available on the Company’s website.

FIRST QUARTER 2021 HIGHLIGHTS

Strong Free Cash Flow from Profitable Low-Breakeven Production

• Consolidated oil and gas production of 38,131 boepd
• Revenue of $146.6 million
• Operating Profit of $15.9 million / Net Loss of $10.3 million
• Operating Netback of $79.4 million / Adjusted EBITDA of $66.5 million (both including protective cash hedge losses of $20.6 million)
• Capital expenditures of $20.3 million
• Every $1 invested yielded $3.9 in Operating Netback

Successful Debt Reduction

• $187.6 million of cash & cash equivalents as of March 31, 2021
• $75 million oil prepayment facility, with $50 million committed and no amounts drawn
• $106.2 million in uncommitted credit lines
• Strategic deleveraging executed in April 2021 resulted in significant debt reduction with extended maturities and lower cost of debt

Self-Funded, Expanded 2021 Work Program

• Full-year 2021 work program of $130-150 million, targeting 41,000-43,000¹ boepd average production and operating netbacks of $330-370 million assuming Brent at $50-55 per bbl²
• Flexible to quickly adapt to any oil price scenario

Shareholder Value Returns

• Quarterly Dividend of $0.0205 per share ($1.25 million), paid on April 13, 2021
• Quarterly Dividend of $0.0205 per share ($1.25 million), to be paid on May 28, 2021
• Resumed discretionary share buyback program, having acquired 119,289 shares for $1.2 million since November 6, 2020, while executing self-funded and flexible work programs, and paying down debt

James F. Park, Chief Executive Officer of GeoPark, said: “Thanks again to the GeoPark team for its relentless discipline and for delivering another period of important achievements, driving forward our performance and improving our Company overall. Our powerful cash generation was again demonstrated by being able to simultaneously carry out three key initiatives: expand our exploration and development investment program; pay down debt, extend maturities and strengthen our balance sheet; and return cash to our shareholders. We appreciate the support of the investment community which has backed our plan and efforts over many years – including just awarding us the lowest yield ever for any B-rated issue in Latin America. With our foundational low-cost, low-risk, big-upside asset inventory, our strong and consistently successful oil and gas operating team, and our ahead-of-the-game SPEED (ESG+) strategy, we are looking forward to the remainder of 2021 and the abundant opportunities ahead.”

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

STRATEGIC DELEVERAGING (APRIL 2021)

In April 2021 GeoPark executed a series of transactions³ that included a successful tender to purchase $255 million of the 2024 Notes that was funded with a combination of cash in hand and a $150 million new issuance from the reopening of the 2027 Notes. The tender also included a consent solicitation to align covenants of the 2024 Notes to those of the 2027 Notes. The new notes offering and the tender offer closed on April 23 and April 26, respectively.

The reopening of the 2027 Notes was priced above par at 101.875%, representing a yield to maturity of 5.117%. This yield reflects a negative concession of 2.3 basis points relative to the yield to maturity of the day before pricing. Total demand reached over $780 million at its peak and ended at over $540 million. The transaction was oversubscribed by more than 3.5 times from diversified, top tier institutional investors.

Rationale and Benefits

• Reduced total financial debt by $105 million
• Annual interest savings of approximately $9 million
• Improved financial profile by extending debt maturities by 2.3 years
• Flexible debt structure with 25% of outstanding financial debt maturing in September 2024 (callable from September 2021) and the remaining 75% of financial debt maturing in January 2027 (callable from January 2024)
• Alignment of covenants

For further details, please refer to the press release published on April 22, 2021.

Production: Oil and gas production in 1Q2021 decreased by 17% to 38,131 boepd from 45,731 boepd in 1Q2020, due to limited drilling and maintenance activities during 2020 in Colombia, Chile and Argentina, as part of the Company’s risk-managed response to preserve shareholder value and to minimize contractor and employee activity in the fields due to the lower oil price environment and the pandemic. Oil represented 86% and 89% of total reported production in 1Q2021 and 1Q2020, respectively.

For further details, please refer to the 1Q2021 Operational Update published on April 13, 2021.

Reference and Realized Oil Prices: Brent crude oil prices averaged $61.1 per bbl during 1Q2021, $10.3 per bbl higher than 1Q2020 levels. However, the consolidated realized oil sales price averaged $49.8 per bbl in 1Q2021, $12.8 per bbl higher than the $37.0 per bbl in 1Q2020, reflecting a lower local marker differential in Colombia and improved commercial and transportation discounts.

The tables below provide a breakdown of reference and net realized oil prices in Colombia, Chile and Argentina in 1Q2021 and 1Q2020:

(*) Specified Brent oil price may differ in each country as sales are priced with different Brent reference prices.

Revenue: Consolidated revenue increased by 10% to $146.6 million in 1Q2021, compared to $133.2 million in 1Q2020 reflecting higher oil prices, partially offset by lower production and deliveries.

Sales of crude oil: Consolidated oil revenue increased by 11% to $137.3 million in 1Q2021, driven by a 34% increase in realized oil prices and a 17% decrease in oil deliveries due to temporary shut-ins and limited drilling and maintenance activity in 2020. Oil revenue was 94% and 93% of total revenue in 1Q2021 and 1Q2020, respectively.

• Colombia: In 1Q2021, oil revenue increased by 15% to $130.1 million reflecting higher realized oil prices and lower oil deliveries. Realized prices increased by 37% to $49.7 per bbl due to higher Brent oil prices while oil deliveries decreased by 17% to 30,087 bopd. Earn-out payments remained flat at $4.5 million in 1Q2021, compared to $4.6 million in 1Q2020.
• Chile: In 1Q2021, oil revenue decreased by 35% to $1.4 million, due to lower volumes sold, partially offset by higher oil prices. Oil deliveries decreased by 38% to 292 bopd. Realized oil prices increased by 6% to $51.9 per bbl, in line with higher Brent prices, partially offset by higher discounts.
• Argentina: In 1Q2021, oil revenue decreased by 26% to $5.8 million due to lower deliveries and lower realized oil prices. Oil deliveries decreased by 23% to 1,267 bopd. Realized oil prices decreased by 2% to $50.6 per bbl reflecting local market conditions.

Sales of gas: Consolidated gas revenue remained flat at $9.3 million in 1Q2021 compared to $9.4 million in 1Q2020 reflecting 8% higher deliveries and 8% lower gas prices. Gas revenue was 6% and 7% of total revenue in 1Q2021 and 1Q2020, respectively.

• Chile: In 1Q2021, gas revenue decreased by 34% to $3.2 million reflecting lower gas prices and lower gas deliveries. Gas prices were 23% lower, at $2.9 per mcf ($17.1 per boe) in 1Q2021. Gas deliveries fell by 14% to 12,492 mcfpd (2,082 boepd).
• Brazil: In 1Q2021, gas revenue increased by 70% to $4.7 million, due to higher gas deliveries and higher gas prices. Gas deliveries increased by 67% from the Manati gas field (GeoPark non-operated, 10% WI) to 10,374 mcfpd (1,789 boepd). Gas prices increased by 3% to $4.9 per mcf ($29.3 per boe) due to the impact of the annual price inflation adjustment effective January 2021, which was partially offset by the devaluation of the local currency.
• Argentina: In 1Q2021, gas revenue decreased by 26% to $0.8 million, resulting from lower gas prices, and lower deliveries. Gas prices decreased by 19% to $2.2 per mcf ($13.4 per boe) due to local market conditions while deliveries decreased by 7% to 4,213 mcfpd (702 boepd).

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to a $47.3 million loss in 1Q2021, compared to a $32.0 million gain in 1Q2020.

The table below provides a breakdown of realized and unrealized commodity risk management contracts in 1Q2021 and 1Q2020:

The realized portion of the commodity risk management contracts registered a loss of $20.6 million in 1Q2021 compared to a $5.6 million gain in 1Q2020. Realized losses recorded in 1Q2021 reflected the impact of zero cost collar hedges covering approximately 77% of oil production with average ceiling prices below Brent oil prices during the quarter.

The unrealized portion of the commodity risk management contracts amounted to a $26.7 million loss in 1Q2021, compared to a $26.4 million gain in 1Q2020. Unrealized losses during 1Q2021 resulted from the increase in the forward Brent oil price curve compared to December 31, 2020 which caused the market value of the Company’s hedging portfolio for 2Q2021 onwards to decrease, as measured on March 31, 2021.

GeoPark continuously monitors market conditions to add new hedges and further increase its risk protection to lower oil prices over the upcoming 12 months. Please refer to the “Commodity Risk Oil Management Contracts” section below for a description of hedges in place as of the date of this release.

Production and Operating Costs⁴: Consolidated production and operating costs increased by 8% to $44.3 million from $41.1 million resulting from higher cash royalties, partially offset by lower operating costs.

The table below provides a breakdown of production and operating costs in 1Q2021 and 1Q2020:

Consolidated royalties increased by 56% or $7.1 million to $19.8 million in 1Q2021 compared to $12.7 million in 1Q2020, mainly resulting from higher oil prices.

Consolidated operating costs decreased by 14%, or $3.8 million to $24.5 million in 1Q2021 compared to $28.3 million in 1Q2020.

The breakdown of operating costs is as follows:

• Colombia: Operating costs per boe increased to $7.4 in 1Q2021 compared to $6.1 in 1Q2020. Total operating costs increased by 3% and amounted to $18.8 million, due to incremental maintenance and well intervention activities in the Llanos 34 block.
• Chile: Operating costs per boe decreased by 27% to $9.2 in 1Q2021 compared to $12.7 in 1Q2020, due to successful cost reduction efforts implemented during 2020 (including fewer well intervention activities, efficiencies and the renegotiation of existing contracts). Total operating costs decreased by 41% to $2.0 million in 1Q2021, in line with lower operating costs per boe and lower oil and gas deliveries (which decreased by 18%).
• Brazil: Operating costs per boe decreased by 56% to $6.0 in 1Q2021 compared to $13.5 in 1Q2020. Total operating costs decreased by 46% to $0.5 million in 1Q2021, reflecting higher gas deliveries in the Manati gas field (which increased by 53%) and lower operating costs per boe.
• Argentina: Operating costs per boe decreased by 29% to $18.8 in 1Q2021 compared to $26.7 in 1Q2020 due to successful cost reduction efforts implemented during 2020 (including fewer well intervention activities, efficiencies and the renegotiation of existing contracts) and to a lesser extent, because of local currency devaluation. Total operating costs decreased by 44% to $3.2 million in 1Q2021 due to lower operating costs per boe and lower oil and gas deliveries, which decreased by 18%.

Selling Expenses: Consolidated selling expenses decreased by $1.6 million to $0.4 million in 1Q2021, compared to $2.0 million in 1Q2020 mainly due to lower sales at the wellhead and resulting from the connection of the Tigana field in the Llanos 34 block to the ODCA pipeline, which further reduces costs and overall operational risk.

Administrative Expenses: Consolidated G&A decreased by 11% to $11.3 million in 1Q2021 due to cost reduction initiatives implemented during 2020.

Geological & Geophysical Expenses: Consolidated G&G expenses decreased by 31% to $3.1 million in 1Q2021 due to cost reduction initiatives implemented during 2020.

Adjusted EBITDA: Consolidated Adjusted EBITDA⁵ decreased by 14% to $66.5 million, or $20.3 per boe, in 1Q2021 compared to $77.7 million, or $20.1 per boe, in 1Q2020.

• Colombia: Adjusted EBITDA of $64.3 million in 1Q2021
• Chile: Adjusted EBITDA of $1.7 million in 1Q2021
• Brazil: Adjusted EBITDA of $3.2 million in 1Q2021
• Argentina: Adjusted EBITDA of $1.1 million in 1Q2021
• Corporate, Ecuador and Peru: Adjusted EBITDA of negative $3.8 million in 1Q2021

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 1Q2021 and 1Q2020, on a per country and per boe basis:

Depreciation: Consolidated depreciation charges decreased by 43% to $22.6 million in 1Q2021, compared to $39.3 million in 1Q2020, in line with lower volumes delivered and lower depreciation costs per boe.

Write-off of unsuccessful exploration efforts: The consolidated write-off of unsuccessful exploration efforts was zero in 1Q2021 compared to $3.2 million in 1Q2020. Amounts recorded in 1Q2020 refer to unsuccessful exploration costs incurred in Chile in the Huillin exploration prospect on the Isla Norte block.

Impairment of Non-Financial Assets: Consolidated non-cash impairment of non-financial assets was zero in 1Q2021 compared to $97.5 million in 1Q2020. Amounts recorded in 1Q2020 included $50.3 million in Chile, $31.0 million in Peru and $16.2 million in Argentina, resulting from the significant decrease in crude oil prices caused by the Covid-19 pandemic and its effect on global energy prices.

Other Income (Expenses): Other operating expenses showed a $1.8 million loss in 1Q2021, compared to a $0.2 million loss in 1Q2020.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses increased to $15.5 million in 1Q2021, compared to $13.3 million in 1Q2020 mainly resulting from higher interest expenses related to the issuance of the 2027 Notes in mid- January 2020.

Foreign Exchange: Net foreign exchange charges amounted to a $2.7 million gain in 1Q2021 compared to a $10.8 million loss in 1Q2020.

Income Tax: Income taxes totaled a $13.4 million loss in 1Q2021 compared to a $30.3 million loss in 1Q2020, mainly resulting from the effect of fluctuations of local currencies over deferred income taxes, partially offset by higher profit before income tax.

Profit: Losses of $10.3 million in 1Q2021 compared to a $89.5 million loss recorded in 1Q2020, mainly due to the impact of impairments and write-offs recorded in 1Q2020.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $187.6 million as of March 31, 2021 compared to $201.9 million as of December 31, 2020. Cash generated from operating activities equaled $36.4 million while cash used in financing activities equaled $29.7 million and cash used in investing activities equaled $20.3 million.

Cash used in financing activities of $29.7 million mainly included interest payments of $23.5 million, lease payments of $2.5 million and $3.6 million related to the acquisition of the LG International Corp’s non-controlling interest in Colombia and Chile that closed in 2018.

Financial Debt: Total financial debt net of issuance cost was $773.0 million, including the 2024 Notes, the 2027 Notes and other bank loans totaling $3.4 million. Short-term financial debt was $5.9 million as of March 31, 2021.

For further details, please refer to Note 12 of GeoPark’s consolidated financial statements as of March 31, 2021, available on the Company’s website.

FINANCIAL RATIOS^a

Covenants in the 2024 and 2027 Notes: The 2024 and 2027 Notes include incurrence test covenants that provide, among other things, that the Net Debt to Adjusted EBITDA ratio should not exceed 3.25 times and the Adjusted EBITDA to Interest ratio should exceed 2.5 times. As of the date of this release, the Company is compliant with both covenants.

For further details, please refer to Note 12 and 16 of GeoPark’s consolidated financial statements as of March 31, 2021, available on the Company’s website.

COMMODITY RISK OIL MANAGEMENT CONTRACTS

GeoPark recently added new oil hedges further increasing its price risk protection over the next 12 months, now reaching 25,500 bopd in 2Q2021, 20,000 bopd in 3Q2021, 19,500 bopd in 4Q2021, 8,500 bopd in 1Q2022 and 2,000 in 2Q2022. Hedges include a portion providing protection to the Vasconia local marker in Colombia.

The Company has the following commodity risk management contracts in place as of the date of this release:

For further details, please refer to Note 4 of GeoPark’s consolidated financial statements for the period ended March 31, 2021, available on the Company’s website.

SELECTED INFORMATION BY BUSINESS SEGMENT

(UNAUDITED)

CONSOLIDATED STATEMENT OF INCOME

(QUARTERLY INFORMATION UNAUDITED)

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOW

(QUARTERLY INFORMATION UNAUDITED)

RECONCILIATION OF ADJUSTED EBITDA

TO (LOSS) PROFIT BEFORE INCOME TAX

CONFERENCE CALL INFORMATION

GeoPark management will host a conference call on May 6, 2021 at 10:00 am (Eastern Daylight Time) to discuss the 1Q2021 results.

To listen to the call, participants can access the webcast located in the Investor Support section of the Company’s website at www.geo-park.com, or by clicking below:

https://event.on24.com/wcc/r/3138548/E57A81C86661B99A3D71D604FEFF18D5

Interested parties may participate in the conference call by dialing the numbers provided below:

United States Participants: 833-945-1670

International Participants: +1 929-517-9721

Passcode: 2185521

Please allow extra time prior to the call to visit the website and download any streaming media software that might be required to listen to the webcast.

An archive of the webcast replay will be made available in the Investor Support section of the Company’s website at www.geo-park.com after the conclusion of the live call.

NOTICE

Additional information about GeoPark can be found in the “Investor Support” section on the website at www.geo-park.com.

Rounding amounts and percentages: Certain amounts and percentages included in this press release have been rounded for ease of presentation. Percentage figures included in this press release 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 press release 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 press release may not sum due to rounding.

This press release contains certain oil and gas metrics, including information per share, operating netback, reserve life index and others, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

This press release contains statements that constitute forward-looking statements. Many of the forward- looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe,’’ ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters, including our strategic deleveraging process, the cost reduction initiatives, expected or future production, production growth and operating and financial performance, operating netback per boe, future opportunities and our capital expenditures plan. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see filings with the U.S. Securities and Exchange Commission (SEC).

Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses. Annual production per day is obtained by dividing total production by 365 days.

Information about oil and gas reserves: The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proven, probable and possible reserves that meet the SEC's definitions for such terms. GeoPark uses certain terms in this press release, such as "PRMS Reserves" that the SEC's guidelines do not permit GeoPark from including in filings with the SEC. As a result, the information in the Company’s SEC filings with respect to reserves will differ significantly from the information in this press release.

NPV10 for PRMS 1P, 2P and 3P reserves is not a substitute for the standardized measure of discounted future net cash flow for SEC proved reserves.

The reserve estimates provided in this release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. Statements relating to reserves are by their nature forward-looking statements.

Non-GAAP Measures: The Company believes Adjusted EBITDA, free cash flow and operating netback per boe, which are each non-GAAP measures, are useful because they allow the Company to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company’s calculation of Adjusted EBITDA, free cash flow, return on capital employed and operating netback per boe may not be comparable to other similarly titled measures of other companies.

Adjusted EBITDA: The Company defines Adjusted EBITDA as profit for the period before net finance costs, income tax, depreciation, amortization and certain non-cash items such as impairments and write-offs of unsuccessful exploration and evaluation assets, accrual of stock options stock awards, unrealized results on commodity risk management contracts and other non-recurring events. Adjusted EBITDA is not a measure of profit or cash flow as determined by IFRS. The Company excludes 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 flow 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, none of which are components of Adjusted EBITDA. For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.

Operating Netback per boe: Operating netback per boe should not be considered as an alternative to, or more meaningful than, profit for the period or cash flow from operating activities as determined in accordance with IFRS or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from operating netback per boe 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, none of which are components of operating netback per boe. The Company’s calculation of operating netback per boe may not be comparable to other similarly titled measures of other companies. For a reconciliation of operating netback per boe to the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.

Net Debt: Net debt is defined as current and non-current borrowings less cash and cash equivalents.

<sup>________________________________________________________

1</sup> 2021 production assumes full-year production from the Manati gas field in Brazil (currently under a divestiture process that is subject to certain conditions and regulatory approvals) and excludes potential production from the 2021 exploration drilling program.

² Brent price assumption from April to December 2021, assuming $3-4/bbl Vasconia-Brent differential.

³ For further details, please refer to the press releases published on April 6, 14, 19, and 20, 2021.

⁴ Operating costs per boe represents the figures used in Adjusted EBTIDA calculation, as if IFRS 16 had not been adopted.

⁵ See “Reconciliation of Adjusted EBITDA to Profit (Loss) Before Income Tax and Adjusted EBITDA per boe” included in this press release.

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