Full Cycle Performance:

Growing Production and Free Cash Flow

Reducing Carbon Emissions

Accelerating Deleveraging & Shareholder Returns

GeoPark Limited ("GeoPark" or the "Company") (NYSE:GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator reports its consolidated financial results for the three-month period ended June 30, 2022 ("Second Quarter" or "2Q2022"). A conference call to discuss 2Q2022 financial results will be held on August 11, 2022 at 10:00 am (Eastern Standard 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, 2022, available on the Company's website.

SECOND QUARTER 2022 HIGHLIGHTS

Profitable Production Growth

Consolidated oil and gas production up 14% to 38,940 boepd (up 2% vs 1Q2022)¹
Production in Colombia up 16% to 34,253 boepd (up 2% vs 1Q2022)
CPO-5 block (GeoPark non-operated, 30% WI) gross production up 77% to 20,300 boepd (up 34% vs 1Q2022)
Tigana and Jacana fields in the Llanos 34 block (GeoPark operated, 45% WI) and Indico field in the CPO-5 block, rank among the top 10 oil-producing fields in Colombia²
On track to reach 2022 full-year guidance of 38,500-40,500 boepd

Record Revenue, Adjusted EBITDA, Cash Flow and Net Income

Revenue up 88% to $311.2 million
Adjusted EBITDA up 140% to $144.8 million (including $36.6 million of realized cash hedge losses)
Operating Profit of $143.4 million
Cash flow from operations up 190% to $123.2 million
Net profit of $67.9 million (or $1.13 earnings per share)

Improved Capital and Cost Efficiencies

Capital expenditures of $32.4 million
Every $1 dollar invested in capital expenditures yielded 4.5x in Adjusted EBITDA (3.7x in 1H2022)
G&A costs reduced by 15% to $10.8 million

Fast, Immediate and Aggressive Actions to Minimize Emissions

Main fields in Llanos 34 block interconnected to Colombia's national power grid are fully operational (Tua and Jacana in May 2022, and Tigana in July 2022)
The interconnection of Llanos 34 to Colombia's national power grid (~70% hydroelectric³) is a decisive catalyst to reduce carbon emissions and improve overall operational reliability
Solar photovoltaic plant in the Llanos 34 block to be fully operational in 3Q2022

¹		Percentages are calculated adjusting for divestments in Argentina in 2Q2021 and 1Q2022, respectively.
²		Based on latest available information on Colombia's oil production per field during May 2022, as published by the ANH.
³		Colombian Ministry of Energy and Mines, Report to Congress, p. 14.

2022 Work Program: Strong Cash Flow Generation

Self-funded 2022 capital expenditures program of $200-220 million targets the drilling of 50-55 gross wells, including 18-22 gross exploration/appraisal wells
Using a $90-100 per bbl Brent⁴, GeoPark expects to generate a free cash flow of $250-280⁵million, equivalent to a 35-40% free cash flow yield⁶
Free cash flow funding incremental capital projects, significant debt reduction, increased shareholder returns and other corporate purposes

Reducing Debt and Strengthening the Balance Sheet

Cash in hand of $122.5 million ($114.1 million as of March 31, 2022)
Net leverage of 1.0x (1.5x in March 2022 and 2.5x in June 2021)
Reduced gross debt by $103⁷ million since January 1, 2022 (or $208 million since April 2021), with additional deleveraging expected in 2022 at current market conditions

Returning More Value To Shareholders

Board approved a 50% increase in cash dividends to $7.5 million ($0.127 per share) per quarter, payable on September 8, 2022, a 4%⁸ dividend yield or 11% of net income in 2Q2022
Acquired 1.18 million shares, or 2% of total shares outstanding for $15.1 million since January 1, 2022 ($3.0 million in 1Q2022 and $12.1 million from April 1, 2022 to date)

Strengthened Corporate Governance

Shareholders re-elected five existing Directors and elected four new Directors at the AGM held on July 15, 2022
World-class, well-known oil and gas finders and developers, Brian Maxted and Carlos Macellari join the Board as Independent Directors. Two experienced Executive Directors, Andrés Ocampo and Marcela Vaca also joining, adding significant expertise to GeoPark's Board of Directors
GeoPark's Board is 66.7% independent

Upcoming Catalysts

Drilling 10-12 gross wells in 3Q2022, targeting development, appraisal, and exploration projects in the Llanos and Putumayo basins in Colombia and in the Oriente basin in Ecuador
Exploration drilling includes 2-3 wells in Llanos basin, 1-2 wells in the Putumayo basin and 1 well in the Oriente basin in Ecuador

In the CPO-5 block:

Initiating production tests in the Cante Flamenco exploration well (located 4 kilometers west of the Urraca 1 exploration well), where preliminary logging information indicated hydrocarbons in the Mirador formation
After Cante Flamenco, the drilling rig is expected to move to drill 1-2 development wells in the Indico field to further accelerate production growth
A second drilling rig is expected to start spudding wells in the southeastern part of the block in late August/early September 2022

Andrés Ocampo, Chief Executive Officer of GeoPark, said: "Our second quarter can be best characterized by a successful high-momentum transition, our on-the-ground full cycle performance with record results, and a lot of good work and drilling underway opening up even more opportunities for the rest of the year. We are proud of the GeoPark team for ending the first half of the year with: exploration success, production growth, cost discipline, cash flow growth, net profits, significant debt reduction and more value going back to shareholders. We are also just initiating our 2023 capital allocation process - one of our most powerful management tools - by which we rank and select the most attractive value-adding projects from our big and diverse organic portfolio to build another successful program for next year."

⁴		Brent oil price assumption corresponds to July to December 2022.
⁵		Free cash flow is used here as Adjusted EBITDA less income tax, capital expenditures and mandatory interest payments.
⁶		Calculated using GeoPark's average market capitalization from July 1 to August 9, 2022.
⁷		$83 million in 1H2022 and $20 million in July and August 2022.
⁸		Calculated using GeoPark's average market capitalization from July 1 to August 9, 2022.

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Key Indicators	2Q2022	1Q2022	2Q2021	1H2022	1H2021
Oil production^a (bopd)	35,238	34,542	30,962	34,892	31,914
Gas production (mcfpd)	22,212	25,096	33,162	23,650	32,348
Average net production (boepd)	38,940	38,726	36,489	38,834	37,305
Brent oil price ($ per bbl)	111.5	96.9	68.7	104.0	64.6
Combined realized price ($ per boe)	90.0	75.8	50.7	83.1	47.7
⁻ Oil ($ per bbl)	98.7	84.3	57.0	91.8	53.4
⁻ Gas ($ per mcf)	5.1	4.8	4.2	4.9	3.9
Sale of crude oil ($ million)	296.4	239.0	153.8	535.4	291.2
Sale of purchased crude oil ($ million)	5.4	-	-	5.4	-
Sale of gas ($ million)	9.4	10.2	11.7	19.6	21.0
Revenue ($ million)	311.2	249.2	165.6	560.4	312.2
Commodity risk management contracts^b ($ million)	(15.5)	(78.1)	(47.7)	(93.7)	(95.0)
Production & operating costs^c ($ million)	(115.1)	(80.6)	(53.0)	(195.7)	(96.0)
G&G, G&A^d ($ million)	(13.8)	(12.7)	(14.8)	(26.5)	(29.2)
Selling expenses ($ million)	(1.2)	(2.0)	(1.8)	(3.2)	(3.6)
Adjusted EBITDA ($ million)	144.8	122.6	60.5	267.4	126.9
Adjusted EBITDA ($ per boe)	41.9	37.3	18.5	39.6	19.4
Operating Netback ($ per boe)	45.4	41.0	22.7	43.3	23.4
Net Profit (loss) ($ million)	67.9	31.0	(2.5)	98.9	(12.8)
Capital expenditures ($ million)	32.4	39.4	34.4	71.8	54.7
Cash and cash equivalents ($ million)	122.5	114.1	85.0	122.5	85.0
Short-term financial debt ($ million)	15.3	8.7	27.5	15.3	27.5
Long-term financial debt ($ million)	570.0	633.9	656.2	570.0	656.2
Net debt ($ million)	462.9	528.4	598.7	462.9	598.7

a)		Includes royalties paid in kind in Colombia for approximately 1,273, 1,115, and 1,245 bopd in 2Q2022, 1Q2022 and 2Q2021, respectively. No royalties were paid in kind in other countries. Production in Ecuador is reported before the Government's production share.
b)		Please refer to the Commodity Risk Management section included below.
c)		Production and operating costs include operating costs, royalties paid in cash, share based payments and purchased crude oil.
d)		G&A and G&G expenses include non-cash, share-based payments for $2.0 million, $0.9 million, and $1.6 million in 2Q2022, 1Q2022 and 2Q2021, respectively. These expenses are excluded from the Adjusted EBITDA calculation.

Production: Oil and gas production in 2Q2022 was 38,940 boepd. Adjusting for recent divestments in Argentina, consolidated oil and gas production increased by 14% compared to 2Q2021, due to higher production in Colombia and recent exploration successes in Ecuador, partially offset by lower production in Chile and Brazil.

Oil represented 90% and 85% of total reported production in 2Q2022 and 2Q2021, respectively.

For further details, please refer to the 2Q2022 Operational Update published on July 21, 2022.

Reference and Realized Oil Prices: Brent crude oil prices averaged $111.5 per bbl during 2Q2022, and the consolidated realized oil sales price averaged $98.7 per bbl in 2Q2022.

A breakdown of reference and net realized oil prices in relevant countries in 2Q2022 and 2Q2021 is shown in the tables below:

2Q2022 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina⁹	Ecuador
Brent oil price (*)	111.5	110.9	-	114.3
Local marker differential	(5.1)	-	-	-
Commercial, transportation discounts & Other	(8.0)	(4.4)	-	(5.5)
Realized oil price	98.5	106.5	-	108.8
Weight on oil sales mix	97%	2%	-	1%

2Q2021 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina	Ecuador
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%	-

(*) Corresponds to average month of sale price ICE Brent for Colombia, Ecuador and Argentina, and Dated Brent for Chile.

Revenue: Consolidated revenue increased by 88% to $311.2 million in 2Q2022, compared to $165.6 million in 2Q2021, reflecting higher oil and gas prices and higher deliveries.

Sales of crude oil: Consolidated oil revenue increased by 93% to $296.4 million in 2Q2022, driven by a 73% increase in realized oil prices and 10% higher oil deliveries. Oil revenue was 95% of total revenue in 2Q2022 and 93% in 2Q2021.

(In millions of $)	2Q2022	2Q2021
Colombia	287.9	145.9
Chile	5.2	1.2
Argentina	-	6.6
Brazil	0.3	0.2
Ecuador	3.1	-
Oil Revenue	296.4	153.8

Colombia: 2Q2022 oil revenue increased by 97% to $287.9 million, reflecting higher realized oil prices and higher oil deliveries. Realized prices increased by 73% to $98.5 per bbl due to higher Brent oil prices while oil deliveries increased by 13% to 33,146 bopd. Earn-out payments increased to $9.1 million in 2Q2022, compared to $6.0 million in 2Q2021 in line with higher oil prices.
Chile: 2Q2022 oil revenue increased by 344% to $5.2 million, reflecting higher realized prices and higher oil deliveries. Realized prices increased by 76% to $106.5 per bbl due to higher Brent oil prices while oil deliveries increased by 152% to 533 bopd.
Ecuador: 2Q2022 oil revenue totaled $3.1 million, reflecting a realized oil price of $108.8 with deliveries of 312 bopd. Deliveries recorded in Ecuador are net of the Government's production share.

Sales of purchased crude oil: 2Q2022 sales of purchased crude oil totaled $5.4 million, which corresponds to oil trading operations (purchasing and selling crude oil from third parties with the cost of the oil purchased being reflected in production and operating costs).

⁹

The divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina was completed on January 31, 2022.

Sales of gas: Consolidated gas revenue decreased by 20% to $9.4 million in 2Q2022 compared to $11.7 million in 2Q2021 reflecting 33% lower gas deliveries, partially offset by 20% higher gas prices. Gas revenue was 3% and 7% of total revenue in 2Q2022 and 2Q2021, respectively.

(In millions of $)	2Q2022	2Q2021
Chile	3.4	4.5
Brazil	5.5	5.6
Argentina	-	1.2
Colombia	0.5	0.6
Gas Revenue	9.4	11.7

Chile: 2Q2022 gas revenue decreased by 23% to $3.4 million, reflecting lower gas deliveries, partially offset by higher gas prices. Gas deliveries fell by 24% to 10,186 mcfpd (1,698 boepd). Gas prices were 2% higher, at $3.7 per mcf ($22.3 per boe) in 2Q2022.
Brazil: 2Q2022 gas revenue decreased by 1% to $5.5 million, due to lower gas deliveries, partially offset by higher gas prices. Gas deliveries decreased by 19% from the Manati gas field to 9,152 mcfpd (1,525 boepd). Gas prices increased by 21% to $6.6 per mcf ($39.6 per boe) in 2Q2022.

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to a $15.5 million loss in 2Q2022, compared to a $47.7 million loss in 2Q2021.

The table below provides a breakdown of realized and unrealized commodity risk management contracts in 2Q2022 and 2Q2021:

(In millions of $)	2Q2022	2Q2021
Realized loss	(36.6)	(35.7)
Unrealized loss	21.1	(12.0)
Commodity risk management contracts	(15.5)	(47.7)

The realized portion registered a loss of $36.6 million in 2Q2022 compared to a $35.7 million loss in 2Q2021. Realized losses in 2Q2022 reflected hedges with average ceiling prices below actual Brent oil prices during the quarter.

The unrealized portion registered a gain of $21.1 million in 2Q2022, compared to a $12.0 million loss in 2Q2021. Unrealized gains in 2Q2022 mainly resulted from reclassifications to realized losses, combined with movements in the forward Brent oil price curve at June 30, 2022, compared to March 31, 2022.

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 Costs¹⁰: Consolidated production and operating costs increased to $115.1 million from $53.0 million, mainly resulting from a $58.1 million increase in royalties in cash, due to higher oil and gas prices.

¹⁰

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

The table below provides a breakdown of production and operating costs in 2Q2022 and 2Q2021:

(In millions of $)	2Q2022	2Q2021
Royalties in cash	82.8	24.6
Operating costs	27.4	28.3
Purchased crude oil	4.4	-
Share-based payments	0.4	0.1
Production and operating costs	115.1	53.0

Consolidated royalties in cash amounted to $82.8 million in 2Q2022 compared to $24.6 million in 2Q2021, in line with higher oil prices. Royalties in cash included base royalties ($18.8 million and $9.4 million in 2Q2022 and 2Q2021), high price participation ($49.4 million and $9.4 million in 2Q2022 and 2Q2021), and economic rights ($14.6 million and $5.8 million in 2Q2022 and 2Q2021).

Consolidated operating costs decreased to $27.4 million in 2Q2022 compared to $28.3 million in 2Q2021. The decrease in consolidated operating costs results from the divestment of assets in Argentina (2Q2021 included $3.1 million related to operating costs in the Aguada Baguales, El Porvenir and Puesto Touquet blocks that were divested in January 2022), partially offset by higher operating costs in Colombia and Chile, and the addition of operating costs coming from Ecuador.

The breakdown of operating costs is as follows:

Colombia: Total operating costs increased to $21.4 million in 2Q2022 from $21.0 million in 2Q2021, mainly due to higher deliveries (deliveries in Colombia increased by 13%).
Chile: Total operating costs increased to $4.4 million in 2Q2022 from $3.3 million in 2Q2021, in line with higher operating costs per boe due to higher well maintenance costs, partially offset by lower oil and gas deliveries (deliveries in Chile decreased by 9%).
Brazil: Total operating costs decreased to $0.8 million in 2Q2022 from $0.9 million in 2Q2021, due to lower gas deliveries in the Manati field (deliveries in Brazil decreased by 19%), partially offset by higher operating costs per boe.
Ecuador: Operating costs per boe amounted to $32.7¹¹ in 2Q2022. Total operating costs were $0.9 million in 2Q2022.
Argentina: The divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks was completed in January 2022. The comparative period, 2Q2021, included $3.1 million in operating costs.

Consolidated purchased crude oil charges amounted to $4.4 million in 2Q2022,which corresponds to oil trading operations (purchasing and selling crude oil from third parties with the sale of purchased oil being reflected in revenue).

Selling Expenses: Consolidated selling expenses decreased to $1.2 million in 2Q2022 compared to $1.8 million in 2Q2021.

Geological & Geophysical Expenses: Consolidated G&G expenses increased to $3.0 million in 2Q2022 compared to $2.1 million in 2Q2021.

Administrative Expenses: Consolidated G&A decreased to $10.8 million in 2Q2022 compared to $12.7 million in 2Q2021 due to lower staff costs, consultant fees and communication and other costs.

Adjusted EBITDA: Consolidated Adjusted EBITDA¹² increased by 140% to $144.8 million, or $41.9 per boe, in 2Q2022 compared to $60.5 million, or $18.5 per boe, in 2Q2021.

11		Operating costs per boe in Ecuador are calculated as total operating costs of barrels delivered, including costs to produce the barrels of the Government's production share, divided by amounts delivered after the Government's production share.
12		See "Reconciliation of Adjusted EBITDA to Profit Before Income Tax and Adjusted EBITDA per boe" included in this press release.

(In millions of $)	2Q2022	2Q2021
Colombia	140.2	57.3
Chile	3.3	1.4
Brazil	3.9	3.7
Argentina	(2.1)	1.6
Ecuador	1.3	(0.5)
Corporate	(1.8)	(3.0)
Adjusted EBITDA	144.8	60.5

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 2Q2022 and 2Q2021, on a per boe basis:

Adjusted EBITDA/boe	Colombia		Chile		Brazil		Ecuador		Total^d
	2Q22	2Q21	2Q22	2Q21	2Q22	2Q21	2Q22	2Q21	2Q22		2Q21
Production (boepd)	34,253	29,571	2,358	2,584	1,695	2,080	634	-	38,940		36,489
Inventories, RIK^a& Other	(907)	(75)	(127)	(124)	(145)	(170)	(322)	-	(950)		(581)
Sales volume (boepd)	33,346	29,496	2,231	2,460	1,550	1,910	312	-	37,990		35,908
% Oil	99.4%	99.2%	24%	9%	2%	2%	100%	-	91%		86%
($ per boe)
Realized oil price	98.5	57.0	106.5	60.4	111.8	71.3	108.8	-	98.7		57.0
Realized gas price^c	27.7	26.9	22.3	21.8	39.6	32.6	-	-	30.3		25.3
Earn-out	(3.0)	(2.2)	-	-	-	-	-	-	(2.9)		(2.1)
Combined Price	95.0	54.6	42.4	25.1	40.7	33.2	108.8	-	90.0		50.7
Realized commodity risk management contracts	(12.1)	(13.3)	-	-	-	-	-	-	(10.6)		(10.9)
Operating costs^e	(7.5)	(7.3)	(21.6)	(14.6)	(7.9)	(7.1)	(32.7)	-	(8.5)		(8.4)
Royalties in cash	(27.0)	(8.7)	(1.8)	(0.9)	(3.1)	(3.0)	0.0	-	(23.9)		(7.7)
Purchased crude oil^b	-	-	-	-	-	-	-	-	(1.3)		-
Selling & other expenses	(0.2)	(0.9)	(0.5)	(0.3)	(0.0)	(0.0)	(14.9)	-	(0.3)		(0.9)
Operating Netback/boe	48.2	24.2	18.6	9.3	29.7	23.1	61.2	-	45.4		22.7
G&A, G&G & other										(3.5)	(4.2)
Adjusted EBITDA/boe										41.9	18.5

a)		RIK (Royalties in kind). Includes royalties paid in kind in Colombia for approximately 1,273 bopd and 1,245 bopd in 2Q2022 and 2Q2021, respectively. No royalties were paid in kind in Chile, Brazil, Argentina or Ecuador. Production in Ecuador is reported before the Government's production share.
b)		Reported in the Corporate business segment.
c)		Conversion rate of $mcf/$boe=1/6.
d)		Includes amounts recorded in the Corporate and Argentina segments.
e)		Operating costs per boe included in this table include certain adjustments to the reported figures (IFRS 16 and other).

Depreciation: Consolidated depreciation charges increased by 13% to $23.2 million in 2Q2022 compared to $20.6 million in 2Q2021, in line with higher deliveries.

Other Income (Expenses): Other operating expenses showed a $0.9 million gain in 2Q2022, compared to a $0.4 million loss in 2Q2021.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses decreased to $15.5 million in 2Q2022 compared to $20.6 million in 2Q2021, mainly resulting from a sustained deleveraging process that started in April 2021 and continued in 2022 (gross debt was reduced by $103¹³ million since January 1, 2022, or $208 million since April 2021).

Foreign Exchange: Net foreign exchange gains amounted to $7.1 million in 2Q2022 compared to $1.8 million in 2Q2021.

Income Tax: Income taxes totaled $67.1 million in 2Q2022 compared to $2.9 million in 2Q2021, mainly resulting from higher profits before income taxes and the effect of fluctuations of local currencies over deferred income taxes.

Net Profit: Profit of $67.9 million in 2Q2022 compared to a $2.5 million loss recorded in 2Q2021.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $122.5 million as of June 30, 2022, compared to $100.6 million as of December 31, 2021.

This net increase is explained by the following:

(In millions of $)	1H2022
Cash flows from operating activities	212.9
Cash flows used in investing activities	(57.4)
Cash flows used in financing activities	(134.9)
Currency Translation	1.2
Net increase in cash & cash equivalents	21.8

Cash flows used in investing activities included $71.8 million in capital expenditures incurred by the Company as part of its 2022 work program, partially offset by proceeds from the disposal of assets in Argentina of $14.4 million.

Cash flows used in financing activities mainly included $92.5 million related to repurchases and redemptions of the 2024 Notes (including borrowing cancellation costs and other costs paid), $19.3 million related to interest payments, $9.5 million related to executing the Company's share buyback program and $9.7 million related to dividend payments.

Financial Debt: Total financial debt net of issuance cost was $585.4 million, including the remainder of the 2024 Notes, the 2027 Notes and other bank loans totaling $1.2 million. Short-term financial debt was $15.3 million as of June 30, 2022.

(In millions of $)	June 30, 2022	December 31, 2021
2024 Notes	83.2	171.9
2027 Notes	501.0	499.9
Other bank loans	1.2	2.3
Financial debt	585.4	674.1

During 1H2022 the Company continued reducing its debt through repurchases and redemptions of its 2024 Notes. After June 30, 2022, the Company repurchased an additional $20 million principal of its 2024 Notes.

For further details, please refer to Note 12 of GeoPark's consolidated financial statements as of June 30, 2022, available on the Company's website.

¹³

$83 million in 1H2022 and $20 million in July and August 2022.

FINANCIAL RATIOS^a

(In millions of $)

Period-end	Financial	Cash and Cash	Net Debt	Net Debt/LTM	LTM Interest
	Debt	Equivalents		Adj. EBITDA	Coverage
2Q2021	683.7	85.0	598.7	2.5x	4.9x
3Q2021	674.9	76.8	598.1	2.2x	5.8x
4Q2021	674.1	100.6	573.5	1.9x	6.7x
1Q2022	642.5	114.1	528.4	1.5x	8.4x
2Q2022	585.4	122.5	462.9	1.0x	10.8x

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.

For further details, please refer to Note 12 of GeoPark's consolidated financial statements as of June 30, 2022, available on the Company's website.

COMMODITY RISK OIL MANAGEMENT CONTRACTS

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
3Q2022	Zero cost collar	Brent	13,000	58.6	86.5
4Q2022	Zero cost collar	Brent	12,000	60.6	92.6
1Q2023	Zero cost collar	Brent	9,500	66.0	112.6
2Q2023	Zero cost collar	Brent	6,500	68.8	115.9

For further details, please refer to Note 4 of GeoPark's consolidated financial statements for the period ended June 30, 2022, available on the Company's website.

SELECTED INFORMATION BY BUSINESS SEGMENT

Colombia (In millions of $)	2Q2022	2Q2021
Sale of crude oil	287.9	145.9
Sale of gas	0.5	0.6
Revenue	288.4	146.4
Production and operating costs^a	(103.7)	(43.8)
Adjusted EBITDA	140.2	57.3
Capital expenditure	23.7	32.7

Chile (In millions of $)	2Q2022	2Q2021
Sale of crude oil	5.2	1.2
Sale of gas	3.4	4.5
Revenue	8.6	5.6
Production and operating costs^a	(4.8)	(3.5)
Adjusted EBITDA	3.3	1.4
Capital expenditure	7.6	1.6

Brazil (In millions of $)	2Q2022	2Q2021
Sale of crude oil	0.3	0.2
Sale of gas	5.5	5.6
Revenue	5.8	5.8
Production and operating costs^a	(1.2)	(1.4)
Adjusted EBITDA	3.9	3.7
Capital expenditure	0.0	0.0

Ecuador (In millions of $)	2Q2022	2Q2021
Sale of crude oil	3.1	-
Sale of gas	0.0	-
Revenue	3.1	-
Production and operating costs^a	(0.9)	-
Adjusted EBITDA	1.3	(0.5)
Capital expenditure	1.2	0.1

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

CONSOLIDATED STATEMENT OF INCOME

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	2Q2022	2Q2021	1H2022	1H2021
REVENUE
Sale of crude oil	296.4	153.9	535.4	291.2
Sale of purchased crude oil	5.4	-	5.4	-
Sale of gas	9.4	11.7	19.6	21.0
TOTAL REVENUE	311.2	165.6	560.4	312.2
Commodity risk management contracts	(15.5)	(47.7)	(93.7)	(95.0)
Production and operating costs	(115.1)	(53.0)	(195.7)	(96.0)
Geological and geophysical expenses (G&G)	(3.0)	(2.1)	(5.7)	(5.2)
Administrative expenses (G&A)	(10.8)	(12.7)	(20.8)	(24.0)
Selling expenses	(1.2)	(1.8)	(3.2)	(3.6)
Depreciation	(23.2)	(20.6)	(44.8)	(43.2)
Write-off of unsuccessful exploration efforts	-	(8.1)	-	(8.1)
Impairment loss on non-financial assets	-	-	-	-
Other	0.9	(0.4)	5.4	(2.1)
OPERATING PROFIT	143.4	19.2	202.0	35.1

Financial costs, net	(15.5)	(20.6)	(30.6)	(36.1)
Foreign exchange gain	7.1	1.8	0.5	4.5
PROFIT BEFORE INCOME TAX	135.0	0.4	171.8	3.5

Income tax	(67.1)	(2.9)	(73.0)	(16.3)
PROFIT (LOSS) FOR THE PERIOD	67.9	(2.5)	98.9	(12.8)

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	Jun '22	Dec '21

Non-Current Assets
Property, plant and equipment	645.6	614.0
Other non-current assets	61.6	49.2
Total Non-Current Assets	707.2	663.2

Current Assets
Inventories	8.8	10.9
Trade receivables	108.1	70.5
Other current assets	20.7	50.6
Cash at bank and in hand	122.5	100.6
Total Current Assets	260.1	232.6

Total Assets	967.3	895.7

Equity
Equity attributable to owners of GeoPark	19.6	(61.9)
Total Equity	19.6	(61.9)

Non-Current Liabilities
Borrowings	570.0	656.2
Other non-current liabilities	107.2	97.8
Total Non-Current Liabilities	677.2	754.0

Current Liabilities
Borrowings	15.3	17.9
Other current liabilities	255.2	185.7
Total Current Liabilities	270.5	203.7

Total Liabilities	947.7	957.7

Total Liabilities and Equity	967.3	895.7

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOW

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	2Q2022	2Q2021	1H2022	1H2021

Cash flow from operating activities	123.2	42.5	212.9	78.9
Cash flow used in investing activities	(32.4)	(33.3)	(57.4)	(53.6)
Cash flow used in financing activities	(82.0)	(112.2)	(134.9)	(141.9)

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT BEFORE INCOME TAX

1H2022 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other^(a)	Total
Adjusted EBITDA	262.0	5.4	7.5	(3.8)	(3.7)	267.4
Depreciation	(35.9)	(7.2)	(1.5)	(0.2)	(0.0)	(44.8)
Unrealized commodity risk management contracts	(26.5)	-	-	-	-	(26.5)
Share based payment	(0.9)	(0.1)	(0)	(0.3)	(2.0)	(3.4)
Lease Accounting - IFRS 16	2.6	0.6	0.7	0.1	0.0	4.0
Others	1.5	0.1	(0.1)	5.0	(1.2)	5.4
OPERATING PROFIT (LOSS)	202.7	(1.1)	6.5	0.8	(6.9)	202.0
Financial costs, net						(30.6)
Foreign exchange charges, net						0.5
PROFIT BEFORE INCOME TAX						171.8
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 & impairment	(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

Includes Ecuador and Corporate.

CONFERENCE CALL INFORMATION

Reporting Date for 2Q2022 Results Release

GeoPark management will host a conference call on August 11, 2022 at 10:00 am (Eastern Standard Time) to discuss the 2Q2022 financial 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/3875109/9264F1764F6E53CCCC198B684E51209A

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

United States Participants: 844-200-6205

International Participants: +1 929-526-1599

Passcode: 215141

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.

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
ANH		Agencia Nacional de Hidrocarburos (Colombia)

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
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

LTM		Last Twelve Months

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, emission reduction goals, expected or future production, production growth and operating and financial performance, operating netback, future opportunities, our deleveraging process, the redemption of the 2024 Notes, the interconnection of the Tigana Field to Colombia's national grid, 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.

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