Profitable Low-breakeven Production

Debt Reduction and Balance Sheet Strengthening

Positioned to Accelerate Free Cash Flow Growth in 2H2021

Increasing Capital Returns 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 ended June 30, 2021 ("Second Quarter" or "2Q2021"). A conference call to discuss 2Q2021 financial results will be held on August 5, 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 June 30, 2021 available on the Company's website.

SECOND QUARTER 2021 HIGHLIGHTS

Oil and Gas Production and Operations

Consolidated oil and gas production of 36,489 boepd, impacted by managed curtailments due to extensive protests and demonstrations that affected overall logistics throughout Colombia¹
Production restored by the end of 2Q2021
Drilling and field operations normalized by the end of 2Q2021 and currently fully active with three operated drilling rigs and three workover rigs in Colombia

Strong Free Cash Flow from Profitable Barrels

Revenue of $165.6 million
Operating Profit of $19.2 million / Net Loss of $2.5 million
Operating Netback of $74.2 million / Adjusted EBITDA of $60.5 million (both including protective cash hedge losses of $35.7 million)
Capital expenditures of $34.4 million

Accelerating Production and Cash Flow

Full-year 2021 work program of $125-140 million, targeting 38,000-40,000² boepd average production and operating netbacks of $340-390 million assuming Brent at $60-65 per bbl³
2H2021 production expected to average 39,000-42,000 boepd (excluding the potential production from the 2H2021 exploration drilling program)
2H2021 drilling program includes exploration prospects in the CPO-5 (GeoPark non-operated, 30% WI) and Llanos 94 (GeoPark non-operated, 50% WI) blocks

Successful Debt Reduction and Cost Savings

$85.0 million of cash & cash equivalents as of June 30, 2021
Strategic deleveraging executed in April 2021 resulted in significant debt reduction with extended maturities and lower cost of debt

Continuous Portfolio Consolidation and Management

Peru: Executed agreement to transfer the Morona block contract and operatorship to Petroperu
Brazil: Manati gas field divestment process expected to close by the end of 2021
Brazil: REC-T-128 block farm-out closed during May 2021
Argentina: initiated a process during May 2021 to evaluate farm-out/divestment opportunities
Asset management restructuring initiative providing cost improvements

ESG+ Actions

National electric grid connection and PV solar projects currently underway to continue improving industry-leading cost and carbon footprint performance in the Llanos 34 block (GeoPark operated, 45% WI)
Currently developing strategic medium and long-term greenhouse gas reduction policy
GeoPark's annual sustainability report (SPEED/ESG 2020 report) to be published in August 2021

Leading Corporate Governance

Shareholders reelected all GeoPark directors at the AGM⁴ held on July 15, 2021, with every director receiving at least 70% of the shares voted
Newly appointed Independent Chair of the Board, Ms. Sylvia Escovar
GeoPark's Board is now composed of a majority of independent directors and key committees consist solely of independent directors (Nomination and Corporate Governance, Audit, and Compensation committees)

Increased Capital Returns to Shareholders

Quarterly Dividend of $0.0205 per share ($1.25 million), paid on May 28, 2021
Doubling of Quarterly Dividend to $0.041 (from $0.0205 per share), or $2.5 million (from $1.25 million), to be paid on August 31, 2021
Resumed discretionary share buyback program, having acquired 241,927 shares for $2.9 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 women and men of GeoPark for their efforts, backbone and professionalism in managing our business - including through any volatility, such as the recent unrest in Colombia - and continuing to consistently deliver value growth over our 19 year history. We also want to thank our shareholders for their important support and for the many constructive conversations we had with them prior to our Annual General Meeting. Their votes and messages were clear - and we see this as further positive momentum for all the changes and continuous improvements that we have been pushing for and carrying out. On the ground now, we have six rigs operating in Colombia and are looking forward to an active second half of 2021 with increased production and cash flows - and increased returns to our shareholders. We also are beginning our capital allocation exercise to build our 2022 work program and budget, selecting the best shareholder value-adding projects based on strategic, technical, economic and environmental and social parameters. Our huge organic land base and our rich inventory of new inorganic projects provides us an abundant and exciting opportunity set."

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Key Indicators	2Q2021	1Q2021	2Q2020	1H2021	1H2020
Oil production^a (bopd)	30,962	32,877	32,504	31,914	36,683
Gas production (mcfpd)	33,162	31,522	26,448	32,348	27,827
Average net production (boepd)	36,489	38,131	36,912	37,305	41,322
Brent oil price ($ per bbl)	68.7	61.1	33.1	64.6	42.0
Combined realized price ($ per boe)	50.7	44.7	17.8	47.7	27.0
⁻ Oil ($ per bbl)	57.0	49.8	18.6	53.4	28.9
⁻ Gas ($ per mcf)	4.2	3.6	2.8	3.9	3.3
Sale of crude oil ($ million)	153.8	137.3	49.0	291.2	172.8
Sale of gas ($ million)	11.7	9.3	6.6	21.0	16.1
Revenue ($ million)	165.6	146.6	55.7	312.2	188.9
Commodity risk management contracts^b ($ million)	-47.7	-47.3	-9.1	-95.0	22.9
Production & operating costs^c ($ million)	-53.0	-44.3	-20.7	-96.0	-61.8
G&G, G&A^d and selling expenses ($ million)	-16.7	-14.8	-15.9	-32.8	-35.0
Adjusted EBITDA ($ million)	60.5	66.5	27.8	126.9	105.5
Adjusted EBITDA ($ per boe)	18.5	20.3	8.9	19.4	15.1
Operating Netback ($ per boe)	22.7	24.2	13.0	23.4	19.1
Net Profit (loss) ($ million)	-2.5	-10.3	-19.9	-12.8	-109.4
Capital expenditures ($ million)	34.4	20.3	5.8	54.7	39.5
Amerisur acquisition^e ($ million)	-	-	-	-	272.3
Cash and cash equivalents ($ million)	85.0	187.6	157.5	85.0	157.5
Short-term financial debt ($ million)	27.5	5.9	19.9	27.5	19.9
Long-term financial debt ($ million)	656.2	767.1	763.5	656.2	763.5
Net debt ($ million)	598.7	585.4	625.9	598.7	625.9

a)	Includes royalties paid in kind in Colombia for approximately 1,245, 1,101 and 1,286 bopd in 2Q2021, 1Q2021 and 2Q2020, respectively. No royalties were paid in kind in other countries.
b)	Please refer to the Commodity Risk Management section included below.
c)	Production and operating costs include operating costs and royalties paid in cash.
d)	G&A and G&G expenses include non-cash, share-based payments for $1.6 million, $2.0 million and $2.0 million in 2Q2021, 1Q2021 and 2Q2020, respectively. These expenses are excluded from the Adjusted EBITDA calculation.
e)	The Amerisur acquisition is shown net of cash acquired.

Production: Oil and gas production in 2Q2021 decreased by 1% to 36,489 boepd from 36,912 boepd in 2Q2020, mainly resulting from lower oil and gas production in Colombia and Chile, partially offset by increased production in Brazil and Argentina. Oil represented 85% and 88% of total reported production in 2Q2021 and 2Q2020, respectively.

The Company's production in Colombia during 2Q2021 was affected by extensive protests and demonstrations that impacted overall logistics, restricting the Company's crude oil transportation, drilling and the mobilization of personnel, equipment, and supplies, causing the Company to manage production curtailments that started in early May and normalized towards the end of June.

For further details, please refer to the 2Q2021 Operational Update published on July 22, 2021.

Reference and Realized Oil Prices: Brent crude oil prices averaged $68.7 per bbl during 2Q2021 and the consolidated realized oil sales price averaged $57.0 per bbl in 2Q2021.

The tables below provide a breakdown of reference and net realized oil prices in Colombia, Chile and Argentina in 2Q2021 and 2Q2020:

2Q2021 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina
Brent oil price (*)	68.7	69.1	68.7
Local marker differential	(3.2)	-	-
Commercial, transportation discounts & Other	(8.5)	(8.7)	(12.1)
Realized oil price	57.0	60.4	56.6
Weight on oil sales mix	95%	1%	4%

2Q2020 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina
Brent oil price*	33.1	29.2	33.1
Local marker differential	(6.5)	-	-
Commercial and transportation discounts	(8.6)	(7.2)	-
Other	-	-	(1.1)
Realized oil price	18.0	22.0	32.0
Weight on oil sales mix	95%	1%	4%

(*)

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

Revenue: Consolidated revenue increased by 198% to $165.6 million in 2Q2021, compared to $55.7 million in 2Q2020, reflecting higher oil and gas prices and to a lesser extent higher oil and gas deliveries (which increased by 4%)

Sales of crude oil: Consolidated oil revenue increased by 214% to $153.8 million in 2Q2021, driven by a 206% increase in realized oil prices and a 3% increase in oil deliveries. Oil revenue was 93% of total revenue in 2Q2021 and 88% in 2Q2020.

(In millions of $)	2Q2021	2Q2020
Colombia	145.9	44.6
Chile	1.2	0.5
Argentina	6.6	3.7
Brazil	0.2	0.2
Oil Revenue	153.8	49.0

Colombia: In 2Q2021, oil revenue increased by 227% to $145.9 million reflecting higher realized oil prices and higher oil deliveries. Realized prices increased by 217% to $57.0 per bbl due to higher Brent oil prices while oil deliveries increased by 3% to 29,267 bopd. Earn-out payments increased to $6.0 million in 2Q2021, compared to $1.9 million in 2Q2020 in line with higher oil prices.
Chile: In 2Q2021, oil revenue increased by 131% to $1.2 million reflecting higher realized prices, partially offset by lower volumes sold. Realized prices increased by 174% to $60.4 per bbl due to higher Brent oil prices while oil deliveries decreased by 16% to 212 bopd.
Argentina: In 2Q2021, oil revenue increased by 79% to $6.6 million due to higher deliveries and higher realized oil prices. Realized oil prices increased by 75% to $56.0 per bbl. Oil deliveries increased by 2% to 1,297 bopd.

Sales of gas: Consolidated gas revenue increased by 77% to $11.7 million in 2Q2021 compared to $6.6 million in 2Q2020 reflecting 53% higher gas prices and 16% higher gas deliveries. Gas revenue was 7% and 12% of total revenue in 2Q2021 and 2Q2020, respectively.

(In millions of $)	2Q2021	2Q2020
Chile	4.5	4.1
Brazil	5.6	1.4
Argentina	1.2	0.8
Colombia	0.6	0.4
Gas Revenue	11.7	6.6

Chile: In 2Q2021, gas revenue increased by 10% to $4.5 million reflecting higher gas prices offset by lower gas deliveries. Gas prices were 39% higher, at $3.6 per mcf ($21.8 per boe) in 2Q2021. Gas deliveries fell by 21% to 13,490 mcfpd (2,248 boepd).
Brazil: In 2Q2021, gas revenue increased by 312% to $5.6 million, due to higher gas deliveries and higher gas prices. Gas deliveries increased by 214% from the Manati gas field (GeoPark non-operated, 10% WI) to 11,284 mcfpd (1,881 boepd). Gas prices increased by 31% to $5.4 per mcf ($32.6 per boe) mainly due to the impact of the annual price inflation adjustment effective January 2021.
Argentina: In 2Q2021, gas revenue increased by 43% to $1.2 million, resulting from higher gas prices and higher gas deliveries. Gas prices increased by 13% to $2.8 per mcf ($17.0 per boe) due to local market conditions while deliveries increased by 26% to 4,467 mcfpd (744 boepd).

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to a $47.7 million loss in 2Q2021, compared to a $9.1 million loss in 2Q2020.

The table below provides a breakdown of realized and unrealized commodity risk management contracts in 2Q2021 and 2Q2020:

(In millions of $)	2Q2021	2Q2020
Realized (loss) gain	(35.7)	8.7
Unrealized loss	(12.0)	(17.9)
Commodity risk management contracts	(47.7)	(9.1)

The realized portion of the commodity risk management contracts registered a loss of $35.7 million in 2Q2021 compared to a $8.7 million gain in 2Q2020. Realized losses recorded in 2Q2021 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 $12.0 million loss in 2Q2021, compared to a $17.9 million loss in 2Q2020. Unrealized losses during 2Q2021 resulted from the increase in the forward Brent oil price curve compared to March 31, 2021 which caused the market value of the Company's hedging portfolio for 3Q2021 onwards to decrease, as measured on June 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 Costs⁵: Consolidated production and operating costs increased to $53.0 million from $20.7 million, mainly resulting from higher cash royalties that increased by $21.4 million, and to a lesser extent from increased operating costs.

Lower operating costs in the comparative period mainly resulted from the temporary shut ins of higher cost wells (which were gradually brought back in 2H2020 in line with the partial recovery in oil prices) in addition to the suspension of well intervention and maintenance activities due to the lower oil price environment.

Consolidated royalties increased to $24.6 million in 2Q2021 compared to $3.2 million in 2Q2020, in line with higher oil and gas prices and increased oil and gas deliveries.

Consolidated operating costs increased to $28.3 million in 2Q2021 compared to $17.4 million in 2Q2020.

The breakdown of operating costs is as follows:

Colombia: Operating costs per boe amounted to $7.3 in 2Q2021, compared to $7.4 in 1Q2021 or $4.8 in 2Q2020. Lower costs per boe in the comparative period are explained by temporary shut-ins of higher cost wells and suspended well intervention and maintenance activities due to the lower oil price environment. Total operating costs increased to $21.0 million in 2Q2021 from $11.7 in 2Q2020 due to higher operating costs per boe and to a lesser extent, to higher deliveries (which increased by 2%).
Chile: Operating costs per boe increased to $14.6 in 2Q2021 compared to $6.2 in 2Q2020 due to well intervention and maintenance activities that were suspended in the comparative period due to the lower oil price environment. Total operating costs increased to $3.3 million in 2Q2021 from $1.7 million in 2Q2020, in line with higher operating costs per boe, partially offset by lower oil and gas deliveries (which decreased by 21%).
Brazil: Operating costs per boe decreased to $7.1 in 2Q2021 compared to $20.5 in 2Q2020. The comparative period was affected by the impact of fixed costs over lower production and deliveries in Manati gas field. Total operating costs increased to $0.9 million in 2Q2021 from $0.7 million in 2Q2020, reflecting higher gas deliveries in the Manati field (deliveries in Brazil increased by 181%) and lower operating costs per boe.
Argentina: Operating costs per boe decreased to $17.5 in 2Q2021 compared to $20.1 in 2Q2020 due to successful cost reduction efforts and the local currency devaluation. Total operating costs decreased to $3.1 million in 2Q2021 from $3.3 million in 2Q2020, due to lower operating costs per boe and higher oil and gas deliveries, which increased by 10%.

Selling Expenses: Consolidated selling expenses increased to $1.8 million in 2Q2021, compared to $1.6 million in 2Q2020.

Administrative Expenses: Consolidated G&A amounted to $12.7 million in 2Q2021 compared to $11.3 million. Amounts recorded in 2Q2021 include advisory and consultancy fees related to the strategic deleveraging process executed in April 2021 and the Annual General Meeting.

Geological & Geophysical Expenses: Consolidated G&G expenses decreased to $2.1 million in 2Q2021 compared to $3.0 million in 2Q2020.

Adjusted EBITDA: Consolidated Adjusted EBITDA⁶ increased by 118% to $60.5 million, or $18.5 per boe, in 2Q2021 compared to $27.8 million, or $8.9 per boe, in 2Q2020.

(In millions of $)	2Q2021	2Q2020
Colombia	57.3	28.4
Chile	1.4	2.3
Brazil	3.7	-0.2
Argentina	1.6	0.4
Corporate, Ecuador and Other	-3.5	-3.1
Adjusted EBITDA	60.5	27.8

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 2Q2021 and 2Q2020, on a per country and per boe basis:

Adjusted EBITDA/boe	Colombia		Chile		Brazil		Argentina		Total
	2Q21	2Q20	2Q21	2Q20	2Q21	2Q20	2Q21	2Q20	2Q21	2Q20
Production (boepd)	29,571	31,072	2,584	3,101	2,080	679	2,254	2,060	36,489	36,912
Inventories, RIK^a& Other	(75)	(2,262)	(124)	(3)	(170)	-	(212)	(198)	(581)	(2,464)
Sales volume (boepd)	29,496	28,810	2,460	3,098	1,910	679	2,042	1,862	35,908	34,448
% Oil	99.2%	98.7%	9%	8%	2%	12%	64%	68%	86%	87%
($ per boe)
Realized oil price	57.0	18.0	60.4	22.0	71.3	29.0	56.0	32.0	57.0	18.6
Realized gas price^b	26.9	12.8	21.8	15.7	32.6	24.8	17.0	15.0	25.3	16.6
Earn-out	(2.2)	(0.7)	-	-	-	-	-	-	(2.1)	(0.7)
Combined Price	54.6	17.2	25.1	16.2	33.2	25.3	41.8	26.6	50.7	17.8
Realized commodity risk management contracts	(13.3)	3.3	-	-	-	-	-	-	(10.9)	2.8
Operating costs	(7.3)	(4.8)	(14.6)	(6.2)	(7.1)	(20.5)	(17.5)	(20.1)	(8.4)	(6.0)
Royalties in cash	(8.7)	(0.9)	(0.9)	(0.5)	(3.0)	(0.9)	(6.1)	(3.9)	(7.7)	(1.0)
Selling & other expenses	(0.9)	(0.5)	(0.3)	(0.2)	(0.0)	(0.1)	(1.9)	(0.9)	(0.9)	(0.5)
Operating Netback/boe	24.2	14.3	9.3	9.2	23.1	3.9	16.2	1.7	22.7	13.0
G&A, G&G & other									(4.2)	(4.1)
Adjusted EBITDA/boe									18.5	8.9

a)		Includes royalties paid in kind in Colombia for approximately 1,245 and 1,286 bopd in 2Q2021 and 2Q2020, respectively. No royalties were paid in kind in other countries.
b)		Conversion rate of $mcf/$boe=1/6.

Depreciation: Consolidated depreciation charges decreased by 12% to $20.6 million in 2Q2021, compared to $23.3 million in 2Q2020, in line with lower depreciation costs per boe, partially offset by higher oil and gas volumes delivered, which increased by 4%.

Write-off of unsuccessful exploration efforts: The consolidated write-off of unsuccessful exploration efforts amounted to $8.1 million in 2Q2021 compared to zero in 2Q2020. Amounts recorded in 2Q2021 refer to unsuccessful exploration costs incurred in the Llanos 32 block in Colombia and other exploration costs incurred in the Fell block in Chile.

Other Income (Expenses): Other operating expenses showed a $0.4 million loss in 2Q2021, compared to a $7.4 million loss in 2Q2020. The comparative period includes the write-down of $6.0 million of value-added tax credits in Peru.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses increased to $20.6 million in 2Q2021, compared to $15.9 million in 2Q2020. Amounts recorded in 2Q2021 include $6.3 million related to one-time costs associated with the strategic deleveraging process executed in April 2021 that resulted in significant debt reduction with extended maturities and lower costs of debt.

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

Foreign Exchange: Net foreign exchange charges amounted to a $1.8 million gain in 2Q2021 compared to a $4.7 million gain in 2Q2020.

Income Tax: Income taxes totaled a $2.9 million loss in 2Q2021 compared to a $12.1 million gain in 2Q2020, mainly resulting from the effect of operating losses and losses before tax recorded in the comparative period compared to gains recorded in 2Q2021.

Profit: Losses of $2.5 million in 2Q2021 compared to a $19.9 million loss recorded in 2Q2020, mainly due to higher operating profits recorded in 2Q2021, partially offset by higher financial costs and income taxes.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $85.0 million as of June 30, 2021 compared to $201.9 million as of December 31, 2020.

The net decrease in cash and cash equivalents as of June 30, 2021 is explained by the following:

(In millions of $)	June 30, 2021
Cash flows from operating activities	78.9
Cash flows used in investing activities	-53.6
Cash flows used in financing activities	-141.9
Net decrease in cash & cash equivalents	-116.6

Cash flows from operating activities is shown net of cash taxes paid of $61.3 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 $683.7 million, including the remainder of the 2024 Notes, the 2027 Notes and other bank loans totaling $13.2 million. Short-term financial debt was $27.5 million as of June 30, 2021.

(In millions of $)	June 30, 2021	Dec 31, 2020
2024 Notes	171.7	428.7
2027 Notes	498.8	352.1
Other bank loans	13.2	3.7
Financial debt	683.7	784.6

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

FINANCIAL RATIOS^a

(In millions of $)
Period-end	Financial Debt	Cash and Cash Equivalents	Net Debt	Net Debt/LTM Adj. EBITDA	LTM Interest Coverage
2Q2020	783.4	157.5	625.9	2.3x	7.2x
3Q2020	772.2	163.7	608.4	2.5x	5.7x
4Q2020	784.6	201.9	582.7	2.7x	4.5x
1Q2021	773.0	187.6	585.4	2.8x	4.1x
2Q2021	683.7	85.0	598.7	2.5x	4.9x

Based on trailing last twelve-month financial results ("LTM").

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 June 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 20,000 bopd in 3Q2021, 19,500 bopd in 4Q2021, 14,500 bopd in 1Q2022, 8,000 bopd in 2Q2022 and 1,000 in 3Q2022. Hedges include a portion providing protection to the Vasconia local marker in Colombia.

The table below summarizes commodity risk management contracts in place as of the date of this release:

Period	Type	Reference	Volume (bopd)	Contract Terms (Average $ per bbl)
				Purchased Put	Sold Call
3Q2021	Zero cost collar	Brent	18,000	43.2	60.6
	Zero cost collar	Vasconia	2,000	41.5	68.6
4Q2021	Zero cost collar	Brent	19,500	43.7	62.7
1Q2022	Zero cost collar	Brent	14,500	49.1	74.8
2Q2022	Zero cost collar	Brent	8,000	50.6	77.3
3Q2022	Zero cost collar	Brent	1,000	52.0	80.0

For further details, please refer to Note 4 of GeoPark's consolidated financial statements for the period ended June 30, 2021, available on the Company's website.

SELECTED INFORMATION BY BUSINESS SEGMENT

(UNAUDITED)

Colombia (In millions of $)	2Q2021	2Q2020
Sale of crude oil	145.9	44.6
Sale of gas	0.6	0.4
Revenue	146.4	45.0
Production and operating costs^a	-43.8	-14.0
Adjusted EBITDA	57.3	28.4
Capital expenditure	32.7	4.7

Chile (In millions of $)	2Q2021	2Q2020
Sale of crude oil	1.2	0.5
Sale of gas	4.5	4.1
Revenue	5.6	4.6
Production and operating costs^a	-3.5	-1.9
Adjusted EBITDA	1.4	2.3
Capital expenditure	1.6	0.9

Brazil (In millions of $)	2Q2021	2Q2020
Sale of crude oil	0.2	0.2
Sale of gas	5.6	1.4
Revenue	5.8	1.6
Production and operating costs^a	-1.4	-0.8
Adjusted EBITDA	3.7	-0.2
Capital expenditure	0.0	0.0

Argentina (In millions of $)	2Q2021	2Q2020
Sale of crude oil	6.6	3.7
Sale of gas	1.2	0.8
Revenue	7.8	4.5
Production and operating costs^a	-4.3	-4.0
Adjusted EBITDA	1.6	0.4
Capital expenditure	0.0	0.0

Production and operating costs = Operating costs + Royalties + Share-based payments

CONSOLIDATED STATEMENT OF INCOME

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	2Q2021	2Q2020	1H2021	1H2020
REVENUE
Sale of crude oil	153.9	49.0	291.2	172.8
Sale of gas	11.8	6.6	21.0	16.1
TOTAL REVENUE	165.6	55.7	312.2	188.9
Commodity risk management contracts	-47.7	-9.1	-95.0	22.9
Production and operating costs	-53.0	-20.7	-96.0	-61.8
Geological and geophysical expenses (G&G)	-2.1	-3.0	-5.2	-7.4
Administrative expenses (G&A)	-12.7	-11.3	-24.0	-24.0
Selling expenses	-1.8	-1.6	-3.6	-3.6
Depreciation	-20.6	-23.3	-43.2	-62.6
Write-off of unsuccessful exploration efforts	-8.1	-	-8.1	-3.2
Impairment loss on non-financial assets	-	-	-	-97.5
Other operating	-0.4	-7.4	-2.1	-7.7
OPERATING PROFIT (LOSS)	19.2	-20.9	35.1	-56.0

Financial costs, net	-20.6	-15.9	-36.1	-29.2
Foreign exchange gain (loss)	1.8	4.7	4.5	-6.1
PROFIT (LOSS) BEFORE INCOME TAX	0.4	-32.0	3.5	-91.3

Income tax	-2.9	12.1	-16.3	-18.1
LOSS FOR THE PERIOD	-2.5	-19.9	-12.8	-109.4

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	Jun '21	Dec '20

Non-Current Assets
Property, plant and equipment	615.1	614.7
Other non-current assets	56.1	54.0
Total Non-Current Assets	671.2	668.7

Current Assets
Inventories	9.2	13.3
Trade receivables	47.4	46.9
Other current assets	19.4	29.5
Cash at bank and in hand	85.0	201.9
Total Current Assets	160.9	291.6

Total Assets	832.1	960.3

Equity
Equity attributable to owners of GeoPark	-120.1	-109.2
Total Equity	-120.1	-109.2

Non-Current Liabilities
Borrowings	656.2	766.9
Other non-current liabilities	94.8	105.9
Total Non-Current Liabilities	751.0	872.8

Current Liabilities
Borrowings	27.5	17.7
Other current liabilities	173.8	179.0
Total Current Liabilities	201.3	196.7

Total Liabilities	952.3	1,069.5

Total Liabilities and Equity	832.1	960.3

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOW

(UNAUDITED)

(In millions of $)	2Q2021	2Q2020	1H2021	1H2020

Cash flow from operating activities	42.5	7.9	78.9	45.9
Cash flow used in investing activities	-33.3	-5.8	-53.6	-311.8
Cash flow (used in) from financing activities	-112.2	-9.5	-141.9	313.7

RECONCILIATION OF ADJUSTED EBITDA

TO PROFIT (LOSS) BEFORE INCOME TAX

1H2021 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other^(a)	Total
Adjusted EBITDA	121.6	3.1	6.8	2.7	-7.3	126.9
Depreciation	-27.0	-7.2	-2.1	-6.8	-0.1	-43.2
Unrealized commodity risk management contracts	-38.6	0.0	0.0	0.0	0.0	-38.6
Write-off of unsuccessful exploration efforts	-3.6	-4.4	0.0	0.0	0.0	-8.1
Share based payment	-0.3	0.0	0.0	0.0	-3.3	-3.6
Lease Accounting - IFRS 16	2.2	0.3	0.9	0.5	0.1	4.0
Others	-1.3	-0.1	-0.2	0.1	-0.8	-2.2
OPERATING PROFIT (LOSS)	52.9	-8.3	5.5	-3.5	-11.4	35.1
Financial costs, net						-36.1
Foreign exchange charges, net						4.5
PROFIT BEFORE INCOME TAX						3.5

1H2020 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other^(a)	Total
Adjusted EBITDA	104.7	5.2	0.6	2.5	-7.6	105.5
Depreciation	-35.6	-16.1	-1.6	-9.0	-0.3	-62.6
Unrealized commodity risk management contracts	8.6	0.0	0.0	0.0	0.0	8.6
Write-off of unsuccessful exploration efforts & impairment	0.0	-53.5	0.0	-16.2	-31.0	-100.7
Share based payment	-0.2	0.0	0.0	-0.1	-3.6	-3.9
Lease Accounting - IFRS 16	2.9	0.1	1.1	0.5	0.3	4.8
Others	-1.2	0.1	0.0	-0.3	-6.1	-7.6
OPERATING PROFIT (LOSS)	79.2	-64.3	0.1	-22.6	-48.4	-56.0
Financial costs, net						-29.2
Foreign exchange charges, net						-6.1
LOSS BEFORE INCOME TAX						-91.3

Includes Peru, Ecuador and Corporate.

DIRECTORS REELECTED AT THE 2021 ANNUAL GENERAL MEETING

At the Annual General Meeting held on July 15, 2021, shareholders reelected all of GeoPark's highly qualified Directors to serve for a term ending at the 2022 Annual General Meeting of Shareholders. Every GeoPark Director received the affirmative support of at least 70.9% of the shares voted and the overall quorum was 84.3% of shares outstanding.

In addition, shareholders approved the appointment of Pistrelli, Henry Martin y Asociados S.R.L. (Member of Ernst & Young Global) as independent auditor of the Company for the fiscal year ending December 31, 2021 and certain changes to the Company's bylaws.

For additional information regarding the 2021 Annual General Meeting of Shareholders, please refer to the Form 6-K filed with the Securities and Exchange Commission on July 22, 2021.

CONFERENCE CALL INFORMATION

GeoPark management will host a conference call on August 5, 2021 at 10:00 am (Eastern Daylight Time) to discuss the 2Q2021 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/3329548/DD55368837B5F74936B9ACBDB1945AE1

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

United States Participants: 1 844-200-6205

International Participants: +44 208-0682-558

Passcode: 931620

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

2024 Notes	6.500% Senior Notes due 2024

2027 Notes	5.500% Senior Notes due 2027

Adjusted EBITDA	Adjusted EBITDA is defined as profit for the period before net finance costs, income tax, depreciation, amortization, the effect of IFRS 16, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payments, unrealized results on commodity risk management contracts and other non-recurring events

Adjusted EBITDA per boe	Adjusted EBITDA divided by total boe deliveries

Operating Netback per boe	Revenue, less production and operating costs (net of depreciation charges and accrual of stock options and stock awards, the effect of IFRS 16), selling expenses, and realized results on commodity risk management contracts, divided by total boe deliveries. Operating Netback is equivalent to Adjusted EBITDA net of cash expenses included in Administrative, Geological and Geophysical and Other operating costs

Bbl	Barrel

Boe	Barrels of oil equivalent

Boepd	Barrels of oil equivalent per day

Bopd	Barrels of oil per day

D&M	DeGolyer and MacNaughton

Free Cash Flow	Operating cash flow less cash flow used in investment activities

F&D costs	Finding and Development costs, calculated as capital expenditures divided by the applicable net reserve additions before changes in Future Development Capital

G&A	Administrative Expenses

G&G	Geological & Geophysical Expenses

Mboe	Thousand barrels of oil equivalent

Mmbo	Million barrels of oil

Mmboe	Million barrels of oil equivalent

Mcfpd	Thousand cubic feet per day

Mmcfpd	Million cubic feet per day

Mm³/day	Thousand cubic meters per day

PRMS	Petroleum Resources Management System

WI	Working interest

NPV10	Present value of estimated future oil and gas revenue, net of estimated direct expenses, discounted at an annual rate of 10%

Sqkm	Square kilometers

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, our increased dividend 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 Please refer to the Company's releases on May 17, June 1, and July 1, 2021.

² 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.

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

⁴ Annual General Meeting.

⁵ Operating costs per boe represents the figures used in Adjusted EBITDA calculation with certain adjustments to the reported figures.

⁶ 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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