STRONG FREE CASH FLOW & PROFITS FROM HIGH QUALITY LOW-BREAKEVEN PRODUCTION

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 ended September 30, 2021 (“Third Quarter” or “3Q2021”). A conference call to discuss 3Q2021 financial results will be held on November 11, 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 September 30, 2021, available on the Company’s website.

THIRD QUARTER 2021 HIGHLIGHTS

Operations and Production

• Consolidated oil and gas production of 37,859 boepd, up 4% compared to 2Q2021
• Oil production of 32,844 bopd, up 6% compared to 2Q2021 due to increased production in Colombia
• Full-year 2021 average production revised to 37,000-38,000 boepd (from 38,000-40,000 boepd) due to blockades in the Platanillo block (GeoPark operated, 100% WI) affecting production and development drilling activities since mid-October
• Platanillo production fully restored on November 4, 2021 with drilling activities to restart by mid-November 2021
• Consolidated oil and gas production is currently 39,000 boepd

Cash Flow and Profits

• Revenue of $174.0 million
• Operating Profit of $81.3 million
• Profit of $37.0 million
• Adjusted EBITDA of $86.8 million (including cash hedge losses of $22.4 million)

Investments and Balance Sheet

• Capital expenditures of $30.6 million
• Every $1 invested in Capital expenditures yielded $2.8 in Adjusted EBITDA
• Cash in hand of $76.8 million
• Net debt to LTM Adjusted EBITDA ratio of 2.2x (2.7x in December 2020)

Portfolio Consolidation and Management

• Argentina: accepted an offer to divest non-core Argentina assets for a consideration of $16 million, with closing expected by 2021 year-end or early 2022
• Peru: obtained final approval to transfer 100% of the Morona block to Petroperu following the Supreme Decree issued by the Peruvian Government
• Brazil: Manati gas field divestment process ongoing, expected to close in 1H2022

SPEED / ESG+ Achievements and Recognitions

• Fast, aggressive and immediate actions to reduce emissions: a 35-40% reduction by 2025 or sooner, a 40-60% reduction by 2025-2030 and Net zero emissions intensity by 2050 or sooner (all Scope 1 and 2)
• GeoPark honored with the Equipares Silver Award by Colombian Ministry of Labor, measuring commitment to promote equality, inclusion and diversity
• Released GeoPark’s 2020 annual sustainability report (the SPEED Report), available on the Company’s website

Giving Back to Shareholders and Expanding Investor Base

• Quarterly Dividend of $0.041 per share, or $2.5 million, payable on December 7, 2021
• Completed share buyback program having acquired 692,707 shares for $8.5 million since November 2020, while executing self-funded and flexible work programs, and paying down debt
• Renewed discretionary share buyback program for up to 10% of shares outstanding until November 2022
• In September 2021, GeoPark was included in the S&P Global BMI Index and sub-indexes, including the S&P Emerging BMI, the S&P Colombia BMI, the S&P Latin America BMI, and the S&P Global BMI Energy, among others

James F. Park, Chief Executive Officer of GeoPark, said: “Thanks very much to the GeoPark team for delivering again strong free cash flow and profits from our high-quality low-breakeven production. We also are gearing up for 2022, with a powerful work program consisting of a very active drilling campaign with 40-48 wells, targeting continued production and cash flow growth, as well as 15-20 low cost exploration targets to potentially open up new fields on our big low-risk high-impact acreage position that can quickly be brought to cash flow if successful. We also announced an actionable and concrete roadmap to lower greenhouse gas emissions that provides real results in the short-term – as well as continue to provide tangible shareholder returns by our active dividend and share buy-back programs. This means for 2022 we will be generating significant free cash flow that will self-fund all of our objectives including shareholder returns, balance sheet strengthening, emission reductions, new business efforts, growing our production base, and an exciting exploration drilling program. We believe that being able to self-fund from cash flow and simultaneously achieve these objectives represent the right business model for our industry today and provide GeoPark with a comparative advantage in an energy-transitioning world.”

BLOCKADES IN PUTUMAYO

In mid-October 2021, some communities in the Putumayo basin started protests against the Government and as a result, GeoPark shut in Platanillo production of 2,100 bopd and suspended drilling activities in the block.

Revised 2021 production guidance results from shut in production and delayed drilling of two development wells that were expected to start producing in 4Q2021 and are now expected in late 4Q2021 or early 2022.

Production was fully restored on November 4, 2021 and development drilling activities are expected to restart by mid-November 2021.

SALE OF NON-CORE ASSETS IN ARGENTINA

On November 3, 2021, GeoPark accepted an offer from Oilstone Energía S.A. to purchase GeoPark's 100% WI in the Aguada Baguales, El Porvenir and Puesto Touquet blocks in the Neuquen basin in Argentina for a total consideration of $16 million.

Closing of the transaction is subject to customary regulatory approvals and is expected by the end of 2021 or early in 2022. GeoPark will continue operating the Aguada Baguales, El Porvenir and Puesto Touquet blocks until the completion of the divestment process. The sale of these blocks will allow GeoPark to reallocate resources to its core operations in Colombia and to continue streamlining its operations.

During the first nine months of 2021, the Aguada Baguales, El Porvenir and Puesto Touquet blocks produced approximately 2,200 bopd (58% oil, 42% natural gas), representing 6% of GeoPark's net consolidated oil and gas production during that period.

The Aguada Baguales, El Porvenir and Puesto Touquet blocks have net proven PRMS reserves of approximately 3.7 million barrels of oil equivalent, based on the December 2020 DeGolyer and MacNaughton’s certification, and adjusted by production during the nine month period ended September 30, 2021.

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Production: Oil and gas production in 3Q2021 increased by 4% to 37,859 boepd versus 2Q2021. Compared to 3Q2020, oil and gas production decreased by 3%, resulting from lower production in Chile and Argentina, partially offset by higher production in Colombia and Brazil.

Oil represented 87% and 85% of total reported production in 3Q2021 and 3Q2020, respectively.

For further details, please refer to the 3Q2021 Operational Update published on October 19, 2021.

Reference and Realized Oil Prices: Brent crude oil prices averaged $73.2 per bbl during 3Q2021, and the consolidated realized oil sales price averaged $60.3 per bbl in 3Q2021.

The tables below provide a breakdown of reference and net realized oil prices in Colombia, Chile and Argentina in 3Q2021 and 3Q2020:

Revenue: Consolidated revenue increased by 77% to $174.0 million in 3Q2021, compared to $98.1 million in 3Q2020, reflecting higher oil and gas prices, partially offset by lower oil and gas deliveries (which decreased by 8%, mainly due to lower gas deliveries).

Sales of crude oil: Consolidated oil revenue increased by 83% to $163.5 million in 3Q2021, driven by a 90% increase in realized oil prices, partially offset by a 3% decrease in oil deliveries. Oil revenue was 94% of total revenue in 3Q2021 and 91% in 3Q2020.

• Colombia: In 3Q2021, oil revenue increased by 89% to $156.1 million reflecting higher realized oil prices, partially offset by lower oil deliveries. Realized prices increased by 93% to $60.3 per bbl due to higher Brent oil prices while oil deliveries decreased by 2% to 29,244 bopd. Earn-out payments increased to $6.0 million in 3Q2021, compared to $3.4 million in 3Q2020 in line with higher oil prices.
• Chile: In 3Q2021, oil revenue increased by 30% to $1.5 million reflecting higher realized prices, partially offset by lower oil deliveries. Realized prices increased by 83% to $64.0 per bbl due to higher Brent oil prices while oil deliveries decreased by 29% to 257 bopd.
• Argentina: In 3Q2021, oil revenue increased by 7% to $5.7 million due to higher realized oil prices, partially offset by lower volumes sold. Realized oil prices increased by 41% to $57.1 per bbl. Oil deliveries decreased by 28% to 1,019 bopd.

Sales of gas: Consolidated gas revenue increased by 19% to $10.5 million in 3Q2021 compared to $8.8 million in 3Q2020 reflecting 69% higher gas prices, partially offset by 29% lower gas deliveries. Gas revenue was 6% and 9% of total revenue in 3Q2021 and 3Q2020, respectively.

• Chile: In 3Q2021, gas revenue decreased by 3% to $4.1 million reflecting lower gas deliveries that were partially offset by higher gas prices. Gas prices were 56% higher, at $3.7 per mcf ($22.0 per boe) in 3Q2021. Gas deliveries fell by 38% to 12,037 mcfpd (2,006 boepd).
• Brazil: In 3Q2021, gas revenue increased by 40% to $4.6 million, due to higher gas deliveries and higher gas prices. Gas deliveries increased by 12% from the Manati gas field (GeoPark non-operated, 10% WI) to 9,716 mcfpd (1,619 boepd). Gas prices increased by 25% to $5.2 per mcf ($31.1 per boe) mainly due to the impact of the annual price inflation adjustment effective January 2021.
• Argentina: In 3Q2021, gas revenue increased by 54% to $1.3 million, resulting from higher gas prices and higher gas deliveries. Gas prices increased by 53% to $3.2 per mcf ($19.1 per boe) due to local market conditions while deliveries increased by 1% to 4,351 mcfpd (725 boepd).

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to an $11.7 million loss in 3Q2021, compared to a $2.7 million gain in 3Q2020.

The table below provides a breakdown of realized and unrealized commodity risk management contracts in 3Q2021 and 3Q2020:

The realized portion of the commodity risk management contracts registered a loss of $22.4 million in 3Q2021 compared to a $1.4 million gain in 3Q2020. Realized losses recorded in 3Q2021 reflected the impact of zero cost collar hedges covering a portion of the Company’s oil production with average ceiling prices below actual Brent oil prices during the quarter.

The unrealized portion of the commodity risk management contracts amounted to a $10.6 million gain in 3Q2021, compared to a $1.3 million gain in 3Q2020. Unrealized gains during 3Q2021 resulted from the reclassification of $22.4 million from unrealized to realized losses during 3Q2021, partially offset by unrealized losses during the quarter that resulted from the increase in the forward Brent oil price curve compared to June 30, 2021, which decreased the market value of the Company’s hedging portfolio beyond 3Q2021, as measured on September 30, 2021.

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 Costs¹: Consolidated production and operating costs increased to $49.2 million from $28.4 million, resulting from a $22.5 million increase in cash royalties, partially offset by lower operating costs.

The table below provides a breakdown of production and operating costs in 3Q2021 and 3Q2020:

Consolidated royalties increased to $30.9 million in 3Q2021 compared to $8.4 million in 3Q2020, in line with higher oil and gas prices, partially offset by lower oil and gas deliveries.

Consolidated operating costs decreased by 9% to $18.2 million in 3Q2021 compared to $19.9 million in 3Q2020.

The breakdown of operating costs is as follows:

• Colombia: Operating costs per boe amounted to $5.3 in 3Q2021, compared to $5.9 in 3Q2020. Total operating costs decreased to $11.9 million in 3Q2021 from $15.1 million in 3Q2020 due to lower operating costs per boe and lower deliveries (deliveries in Colombia decreased by 5%).
• Chile: Operating costs per boe increased to $10.6 in 3Q2021 compared to $5.3 in 3Q2020. Total operating costs increased to $2.2 million in 3Q2021 from $1.8 million in 3Q2020, in line with higher operating costs per boe, partially offset by lower oil and gas deliveries (deliveries in Chile decreased by 37%).
• Brazil: Operating costs per boe increased to $7.6 in 3Q2021 compared to $5.8 in 3Q2020. Total operating costs increased to $0.8 million in 3Q2021 from $0.3 million in 3Q2020, due to higher operating costs per boe and reflecting higher gas deliveries in the Manati field (deliveries in Brazil increased by 12%).
• Argentina: Operating costs per boe increased to $20.6 in 3Q2021 compared to $14.9 in 3Q2020. Total operating costs increased to $3.3 million in 3Q2021 from $2.8 million in 3Q2020, due to higher operating costs per boe and lower oil and gas deliveries (deliveries in Argentina decreased by 19%).

Lower operating costs per boe in Chile and Argentina in 3Q2020 mainly resulted from reduced or suspended well intervention and maintenance activities resulting from the lower oil price environment.

Selling Expenses: Consolidated selling expenses increased to $1.8 million in 3Q2021, compared to $1.3 million in 3Q2020.

Administrative Expenses: Consolidated G&A amounted to $11.8 million in 3Q2021 compared to $10.4 million in 3Q2020. Amounts recorded in 3Q2021 include advisory and consultancy fees related to the Annual General Meeting held in July 2021.

Geological & Geophysical Expenses: Consolidated G&G expenses decreased to $2.1 million in 3Q2021 compared to $2.8 million in 3Q2020.

Adjusted EBITDA: Consolidated Adjusted EBITDA² increased by 55% to $86.8 million, or $26.9 per boe, in 3Q2021 compared to $56.1 million, or $15.9 per boe, in 3Q2020.

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 3Q2021 and 3Q2020, on a per country and per boe basis:

Depreciation: Consolidated depreciation charges decreased by 11% to $23.6 million in 3Q2021, compared to $26.7 million in 3Q2020, in line with lower depreciation costs per boe and lower oil and gas volumes delivered, which decreased by 8%.

Write-off of unsuccessful exploration efforts: The consolidated write-off of unsuccessful exploration efforts amounted to $4.2 million in 3Q2021 compared to $0.6 million in 3Q2020. Amounts recorded in 3Q2021 refer to unsuccessful exploration costs incurred in Colombia.

Impairment of non-financial assets: The consolidated impairment charges amounted to a $13.3 million gain in 3Q2021 compared to a $1.0 million loss in 3Q2020. Amounts recorded in 3Q2021 refer to the reversal of previously recognized impairment charges related to the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina.

Other Income (Expenses): Other operating expenses showed a $1.6 million loss in 3Q2021, compared to a $1.3 million loss in 3Q2020.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses decreased to $13.3 million in 3Q2021, compared to $15.8 million in 3Q2020 mainly resulting from the strategic deleveraging process executed in April 2021 that resulted in significant debt reduction with extended maturities and lower costs of debt.

Foreign Exchange: Net foreign exchange charges amounted to a $1.0 million gain in 3Q2021 compared to a $0.7 million loss in 3Q2020.

Income Tax: Income taxes totaled a $31.9 million loss in 3Q2021 compared to a $16.3 million loss in 3Q2020, mainly resulting from the effect of higher profits before tax recorded in 3Q2021 compared to 3Q2020.

Profit: Gain of $37.0 million in 3Q2021 compared to a $4.3 million loss recorded in 3Q2020, mainly due to higher operating profits recorded in 3Q2021 that were partially offset by higher income tax charges.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $76.8 million as of September 30, 2021, compared to $201.9 million as of December 31, 2020.

The net decrease in cash and cash equivalents as of September 30, 2021, compared to December 31, 2020 is explained by the following:

Cash flows from operating activities is shown net of cash taxes paid of $65.1 million.

Cash flows used in investing activities included capital expenditures incurred by the Company as part of its 2021 work program of $125-140 million, partially offset by proceeds from the disposal of assets of $1.1 million.

Cash flows used in financing activities included the strategic deleveraging process executed in April 2021 through a tender to purchase $255.0 million of the 2024 Notes that was funded with a combination of cash and cash equivalents and funds obtained from the reopening of the 2027 Notes.

Financial Debt: Total financial debt net of issuance cost was $674.9 million, including the remainder of the 2024 Notes, the 2027 Notes and other bank loans totaling $13.4 million. Short-term financial debt was $18.1 million as of September 30, 2021.

For further details, please refer to Note 12 of GeoPark’s consolidated financial statements as of September 30, 2021, available on the Company’s website.

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 would meet these tests if it chose to incur more debt.

For further details, please refer to Note 12 of GeoPark’s consolidated financial statements as of September 30, 2021, available on the Company’s website.

COMMODITY RISK OIL MANAGEMENT CONTRACTS

GeoPark has oil hedges in place providing price risk protection over the next 12 months, now reaching 19,500 bopd in 4Q2021, 14,500 bopd in 1Q2022, 12,500 bopd in 2Q2022, 10,000 bopd in 3Q2022 and 4,500 in 4Q2022.

The table below summarizes 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 September 30, 2021, available on the Company’s website.

CONFERENCE CALL INFORMATION

Reporting Date for 3Q2021 Results Release and 2022 Work Program and Investment Guidance

GeoPark management will host a conference call on November 11, 2021, at 10:00 am (Eastern Daylight Time) to discuss the 3Q2021 results and the work program and investment guidance for 2022.

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/3404998/49B85E71C767F2F0CD2B7D8F29290C79

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

United States Participants: 1 844-200-6205

International Participants: +1-929-526-1599

Passcode: 477606

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.

GLOSSARY

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 the sale of assets in Argentina, the Manati gas field divestment, emiision reduction goals, expected or future production, production growth and operating and financial performance, operating netback, future opportunities, our dividend or other distributions and 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.

¹ Operating costs per boe represents the figures used in Adjusted EBITDA calculation with certain adjustments to the reported figures

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