GeoPark Reports First Quarter 2022 Results

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 March 31, 2022 (“First Quarter” or “1Q2022”). A conference call to discuss 1Q2022 financial results will be held on May 12, 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 March 31, 2022, available on the Company’s website.

FIRST QUARTER 2022 HIGHLIGHTS

Accelerated Profitable Production

• Consolidated oil and gas production of 38,626 boepd – up 6% adjusting for divestments in Argentina
• Production in Colombia of 33,738 boepd, up 6% vs 4Q2021
• CPO-5 block (GeoPark non-operated, 30% WI) in Colombia is producing over 20,000 bopd gross, a 150%+ increase over pre-acquisition production (January 2020)
• Perico block (GeoPark non-operated, 50% WI) in Ecuador added new production from two exploration wells

Generated Record High Revenue, Adjusted EBITDA and Cash Flow from Operations

• Revenue up 70% to $249.2 million
• Adjusted EBITDA up 84% to $122.6 million (including $30.5 million of realized cash hedge losses)
• Cash flow from operations up 147% to $89.7 million
• Free cash flow of $50.3 million¹
• Net profit of $31.0 million

Improved Capital and Cost Efficiencies

• Capital expenditures of $39.4 million
• Adjusted EBITDA to capital expenditures ratio of 3.1x (3.9x excluding realized cash hedge losses)
• G&G and G&A costs reduced by 12% to $12.7 million (26% lower vs 1Q2020)

Reduced Debt and Strengthened the Balance Sheet

• Cash in hand of $114.1 million ($100.6 million in December 2021)
• Net leverage of 1.5x (1.9x in December 2021)
• Repurchased $32.9 million of the 2024 Notes², reducing gross debt and providing financial cost savings
• Sent notice to bondholders to redeem $45 million principal of the 2024 Notes, to be completed in May 2022, with more deleveraging expected in 2H2022

Returned More Value To Shareholders

• Direct returns to shareholders during 1Q2022 totaled $7.9 million³, after doubling cash dividends
• Discretionary share buyback program in place for up to 10% of shares outstanding until November 2022
• New quarterly cash dividend of $5.0 million ($0.082 per share) payable on June 10, 2022

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¹ Operating cash flow less purchase of property, plant and equipment line in cash flow used in investing activities.
² January 1 to May 10, 2022, with $23.1 million repurchased in 1Q2022.
³ $3.1 million in share buybacks plus $4.8 million in quarterly dividends.

Expanded Growth Fairway and Strengthened Portfolio

• Colombia: Acquired the CPO-4-1 block (GeoPark non-operated, 50% WI), an attractive low-risk, low-cost exploration block, approximately 50% covered with 3D seismic, and strategically located adjacent to the CPO-5, the Llanos 94 (GeoPark non-operated, 50% WI) and the Llanos 123 (GeoPark operated, 50% WI) blocks
• Argentina: Completed the divestment of non-core Aguada Baguales, El Porvenir and Puesto Touquet blocks (GeoPark operated, 100% WI) on January 31, 2022⁴

Increased Self-Funded 2022 Work Program and Production Targets

• 2022 annual production guidance revised up by 8%⁵ to 38,500-40,500 boepd (from 35,500-37,500 boepd) not including any potential production from 14-18 exploration wells
• Production guidance reflects ongoing drilling results, new investments and bringing back production from the Manati gas field in Brazil⁶
• 2022 work program expanded to $200-220 million (from $160-180 million) to drill 50-55 gross wells (from 40-48 gross wells)
• At $95-100/bbl Brent, the work program generates $250-280 million free cash flow, a 28-32⁷% yield
• Free cash flow funding incremental capital projects, deleveraging, increased shareholder returns and other corporate purposes

Improved SPEED / ESG+ Performance and Ratings

• Electrification of the Llanos 34 block (GeoPark operated, 45% WI) is 80% complete, a decisive near-term catalyst that will improve overall operational reliability and reduce carbon emissions and energy generation costs
• Solar photovoltaic plant in the Llanos 34 block is 80% complete, and will be operational by mid-2022
• GeoPark rating upgraded to “A” by MSCI ESG Ratings, a multi-year rating improvement (GeoPark was previously rated “B” in 2018, “BB” in 2019 and “BBB” in 2021)
• GeoPark was added to the Bloomberg Gender-Equality Index, covering companies with best-in-class gender-related practices and policies

Upcoming Catalysts

• Drilling 10-12 gross wells in 2Q2022, targeting development, appraisal, and exploration projects, including initiation of the exploration drilling campaign in the CPO-5 block
• Interconnecting Tigana field in the Llanos 34 block to Colombia’s national grid as first phase of the electrification of the block, to be followed by the interconnection of Jacana in early 2H2022

James F. Park, Chief Executive Officer of GeoPark, said: “Tremendous thanks and congratulations to the GeoPark team for doing its job and building value across our complete business again this period, including: growing profitable production, finding new oil fields, drilling wells successfully, carrying out seismic and developing new prospects, keeping our team safe and healthy, reducing costs and increasing capital efficiency, achieving record cash flows, reducing debt, increasing our self-funded work program, managing risks, expanding our acreage footprint, building partnerships, protecting the environment and reducing emissions, being a good community neighbor, improving our ESG ratings, improving our organization, strengthening our culture, attracting new long term investors, increasing dividends, giving back more to all our stakeholders, and implementing an exciting new leadership team. This full-cycle GeoPark approach – always supported by our own cash flows – is the right business model for our industry today - and our consistent delivery provides powerful momentum for a promising and pivotal 2022 and beyond.”

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⁴ GeoPark no longer reports production, revenue or costs from these blocks since the transaction closed.
⁵ Calculated as the middle point of previous and new production guidance.
⁶ The Manati gas field divestment process was not completed before the March 31, 2022 deadline and upon expiry, GeoPark decided not to extend the target date.
⁷ Free cash flow yield is calculated as free cash flow divided by GeoPark’s average market capitalization from January 3 to April 30, 2022.

INCREASED 2022 PRODUCTION GUIDANCE

GeoPark’s 2022 annual average production guidance was revised up by 8%⁸ to 38,500-40,500 boepd (from 35,500-37,500 boepd), not including any potential production from 14-18 exploration wells to be drilled from May to December 2022.

Revised production guidance reflects successful drilling results, new investments due to a higher oil price environment and the reintegration of production from the Manati gas field in Brazil.

The 2022 work program was expanded to $200-220 million (from $160-180 million) to drill 50-55 gross wells. New investments for approximately $40 million include drilling of 8-9 new gross wells plus facilities and other permitting projects.

Incremental investments are expected to be allocated as follows:

• Llanos 34 block - $15-20 million to drill 1-2 gross development, 3 gross injection and 2 gross exploration wells plus infrastructure and facilities
• Platanillo block (GeoPark operated, 100% WI) - $7-10 million to drill 1 exploration well plus facilities and other permitting projects
• Perico block - $5-10 million to drill 1 gross exploration well plus other optimization projects

Free cash flow sensitivities to different Brent oil prices is shown in the table below:

2022 Free Cash Flow9 (in millions of $)	$80-85 per bbl	$95-100 per bbl
Operating Netback	550-580	590-620
Adjusted EBITDA	500-530	540-570
Cash Taxes	(40-45)	(40-45)
Capital Expenditures	(200-220)	(200-220)
Mandatory Debt Service Payments10	(38-42)	(38-42)
Free Cash Flow	210-240	250-280
Free Cash Flow Yield (in %)	24-27%	28-32%

Adjusted EBITDA is defined as profit for the period (determined as if IFRS 16 Leases has not been adopted), before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts, geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. Operating Netback is equivalent to Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical and Other operating expenses.

Free cash flow is used here as Adjusted EBITDA less income tax paid included in cash flows from operating activities, less capital expenditures included in cash flows used in investing activities, less mandatory interest payments included in cash flows used in financing activities.

The free cash flow yield is calculated as free cash flow divided by GeoPark’s average market capitalization from January 3 to April 30, 2022.

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⁸ Calculated as the middle point of previous and new production guidance.
⁹ Brent oil price assumptions refer to May-December 2022 and consider a $3-4 Vasconia/Brent differential. Free cash flow excludes changes in working capital.
¹⁰ Excluding potential and voluntary prepayments on existing financial debt.

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Key Indicators	1Q2022	4Q2021	1Q2021
Oil productiona (bopd)	34,442	33,205	32,877
Gas production (mcfpd)	25,096	28,338	31,522
Average net production (boepd)	38,626	37,928	38,131
Brent oil price ($ per bbl)	96.9	79.0	61.1
Combined realized price ($ per boe)	75.8	59.3	44.7
⁻ Oil ($ per bbl)	84.3	65.9	49.8
⁻ Gas ($ per mcf)	4.8	4.0	3.6
Sale of crude oil ($ million)	239.0	192.9	137.3
Sale of gas ($ million)	10.2	9.5	9.3
Revenue ($ million)	249.2	202.4	146.6
Commodity risk management contracts b ($ million)	(78.1)	(2.5)	(47.3)
Production & operating costsc ($ million)	(80.6)	(67.6)	(42.9)
G&G, G&Ad ($ million)	(12.7)	(11.6)	(14.4)
Selling expenses ($ million)	(2.0)	(3.4)	(1.7)
Adjusted EBITDA ($ million)	122.6	87.1	66.5
Adjusted EBITDA ($ per boe)	37.3	25.5	20.3
Operating Netback ($ per boe)	41.0	29.0	24.2
Net Profit (loss) ($ million)	31.0	36.9	(10.3)
Capital expenditures ($ million)	39.4	43.9	20.3
Cash and cash equivalents ($ million)	114.1	100.6	187.6
Short-term financial debt ($ million)	8.7	17.9	5.9
Long-term financial debt ($ million)	633.9	656.2	767.1
Net debt ($ million)	528.4	573.5	585.4

	a)		Includes royalties paid in kind in Colombia for approximately 1,115, 1,119 and 1,101 bopd in 1Q2022, 4Q2021 and 1Q2021, 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 $0.9 million, $0.9 million and $2.0 million in 1Q2022, 4Q2021 and 1Q2021, respectively. These expenses are excluded from the Adjusted EBITDA calculation.

Production: Oil and gas production in 1Q2022 was 38,626 boepd, a 1% increase compared to 1Q2021. Adjusting for recent divestments in Argentina, consolidated oil and gas production increased by 6% compared to 1Q2021, due to higher production in Colombia and to a lesser extent, recent exploration successes in Ecuador, partially offset by lower production in Chile and Brazil.

Oil represented 89% and 86% of total reported production in 1Q2022 and 1Q2021, respectively.

For further details, please refer to the 1Q2022 Operational Update published on April 11, 2022.

Reference and Realized Oil Prices: Brent crude oil prices averaged $96.9 per bbl during 1Q2022, and the consolidated realized oil sales price averaged $84.3 per bbl in 1Q2022.

A breakdown of reference and net realized oil prices in Colombia, Chile and Argentina in 1Q2022 and 1Q2021 is shown in the tables below:

1Q2022 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina
Brent oil price (*)	96.9	103.7	96.9
Local marker differential	(3.7)	-	-
Commercial, transportation discounts & Other	(8.8)	(7.8)	(40.2)
Realized oil price	84.4	95.9	56.7
Weight on oil sales mix	98%	1%	1%

1Q2021 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina
Brent oil price (*)	61.1	60.5	61.1
Local marker differential	(2.9)	-	-
Commercial, transportation discounts & Other	(8.5)	(8.6)	(10.5)
Realized oil price	49.7	51.9	50.6
Weight on oil sales mix	95%	1%	4%

(*) Corresponds to ICE Brent for Colombia and Argentina. Corresponds to Dated Brent for Chile

Revenue: Consolidated revenue increased by 70% to $249.2 million in 1Q2022, compared to $146.6 million in 1Q2021, reflecting higher oil and gas prices.

Sales of crude oil: Consolidated oil revenue increased by 74% to $239.0 million in 1Q2022, driven by a 69% increase in realized oil prices and to a lesser extent 3% higher oil deliveries. Oil revenue was 96% of total revenue in 1Q2022 and 94% in 1Q2021.

(In millions of $)	1Q2022	1Q2021
Colombia	234.0	130.1
Chile	3.1	1.4
Argentina	1.7	5.8
Brazil	0.2	0.1
Oil Revenue	239.0	137.3

• Colombia: 1Q2022 oil revenue increased by 80% to $234.0 million, reflecting higher realized oil prices and higher oil deliveries. Realized prices increased by 70% to $84.4 per bbl due to higher Brent oil prices while oil deliveries increased by 6% to 31,903 bopd. Earn-out payments increased to $8.4 million in 1Q2022, compared to $4.5 million in 1Q2021 in line with higher oil prices.
• Chile: 1Q2022 oil revenue increased by 129% to $3.1 million, reflecting higher realized prices and higher oil deliveries. Realized prices increased by 85% to $95.9 per bbl due to higher Brent oil prices while oil deliveries increased by 24% to 362 bopd.
• Argentina: 1Q2022 oil revenue decreased by 71% to $1.7 million from $5.8 million in 1Q2021, reflecting revenue only until divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks that occurred on January 31, 2022.

Sales of gas: Consolidated gas revenue increased by 9% to $10.2 million in 1Q2022 compared to $9.3 million in 1Q2021 reflecting 34% higher gas prices, partially offset by 18% lower gas deliveries. Gas revenue was 4% and 6% of total revenue in 1Q2022 and 1Q2021, respectively.

(In millions of $)	1Q2022	1Q2021
Chile	3.6	3.2
Brazil	5.7	4.7
Argentina	0.3	0.8
Colombia	0.5	0.5
Gas Revenue	10.2	9.3

• Chile: 1Q2022 gas revenue increased by 12% to $3.6 million, reflecting higher gas prices, partially offset by lower gas deliveries. Gas prices were 30% higher, at $3.7 per mcf ($22.3 per boe) in 1Q2022. Gas deliveries fell by 14% to 10,775 mcfpd (1,796 boepd).
• Brazil: 1Q2022 gas revenue increased by 22% to $5.7 million, due to higher gas prices that were partially offset by lower gas deliveries. Gas prices increased by 33% to $6.5 per mcf ($39.0 per boe). Gas deliveries decreased by 8% from the Manati gas field to 9,823 mcfpd (1,637 boepd).
• Argentina: 1Q2022 gas revenue decreased by 65% to $0.3 million from $0.8 million in 1Q2021, reflecting revenue only until divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks that occurred on January 31, 2022.

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to a $78.1 million loss in 1Q2022, compared to a $47.3 million loss in 1Q2021.

The table below provides a breakdown of realized and unrealized commodity risk management contracts in 1Q2022 and 1Q2021:

(In millions of $)	1Q2022	1Q2021
Realized loss	(30.5)	(20.6)
Unrealized loss	(47.6)	(26.7)
Commodity risk management contracts	(78.1)	(47.3)

The realized portion registered a loss of $30.5 million in 1Q2022 compared to a $20.6 million loss in 1Q2021. Realized losses in 1Q2022 reflected hedges with average ceiling prices below actual Brent oil prices during the quarter.

The unrealized portion registered a loss of $47.6 million in 1Q2022, compared to a $26.7 million loss in 1Q2021. Unrealized losses in 1Q2022 mainly resulted from the increase in the forward Brent oil price curve at March 31, 2022 compared to December 31, 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 Costs¹¹: Consolidated production and operating costs increased to $80.6 million from $42.9 million, mainly resulting from a $38.2 million increase in royalties in cash, due to higher oil and gas prices, partially offset by lower operating costs.

The table below provides a breakdown of production and operating costs in 1Q2022 and 1Q2021:

(In millions of $)	1Q2022	1Q2021
Operating costs	22.5	23.1
Royalties in cash	58.0	19.8
Share-based payments	0.1	0.0
Production and operating costs	80.6	42.9

Consolidated operating costs decreased to $22.5 million in 1Q2022 compared to $23.1 million in 1Q2021.

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¹¹ Operating costs per boe represents the figures used in Adjusted EBITDA calculation with certain adjustments to the reported figures.

The breakdown of operating costs is as follows:

• Colombia: Operating costs per boe amounted to $5.9 in 1Q2022, compared to $6.9 in 1Q2021. Total operating costs decreased to $16.2 million in 1Q2022 from $17.4 million in 1Q2021 due to lower operating costs per boe, partially offset by higher deliveries (deliveries in Colombia increased by 6%).
• Chile: Operating costs per boe amounted to $18.9 in 1Q2022, compared to $9.2 in 1Q2021. Total operating costs increased to $3.7 million in 1Q2022 from $2.0 million in 1Q2021, in line with higher operating costs per boe due to higher maintenance costs, partially offset by lower oil and gas deliveries (deliveries in Chile decreased by 9%).
• Brazil: Operating costs per boe amounted to $10.6 in 1Q2022 compared to $6.0 in 1Q2021. Total operating costs increased to $1.2 million in 1Q2022 from $0.5 million in 1Q2021, due to higher operating costs per boe, partially offset by lower gas deliveries in the Manati field (deliveries in Brazil decreased by 8%).
• Argentina: Operating costs per boe amounted to $24.1 in 1Q2022 compared to $18.8 in 1Q2021. Total operating costs decreased to $1.3 million in 1Q2022 from $3.2 million in 1Q2021, reflecting costs until divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks that was completed on January 31, 2022.

Selling Expenses: Consolidated selling expenses increased to $2.0 million in 1Q2022, compared to $1.7 million in 1Q2021.

Geological & Geophysical Expenses: Consolidated G&G expenses decreased to $2.7 million in 1Q2022 compared to $3.1 million in 1Q2021.

Administrative Expenses: Consolidated G&A decreased to $9.9 million in 1Q2022 compared to $11.3 million in 1Q2021 due to lower staff costs, share based payments and higher allocation to joint operations due to higher level of activity.

Adjusted EBITDA: Consolidated Adjusted EBITDA¹² increased by 84% to $122.6 million, or $37.3 per boe, in 1Q2022 compared to $66.5 million, or $20.3 per boe, in 1Q2021.

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¹² See “Reconciliation of Adjusted EBITDA to Profit (Loss) Before Income Tax and Adjusted EBITDA per boe” included in this press release.

(In millions of $)	1Q2022	1Q2021
Colombia	121.8	64.3
Chile	2.1	1.7
Brazil	3.6	3.2
Argentina	(1.7)	1.1
Corporate, Ecuador and Other	(3.2)	(3.8)
Adjusted EBITDA	122.6	66.5

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 1Q2022 and 1Q2021, on a per country and per boe basis:

Adjusted EBITDA/boe	Colombia					Chile				Brazil					Argentina				Total
	1Q22		1Q21			1Q22		1Q21		1Q22		1Q21			1Q22		1Q21		1Q22		1Q21
Production (boepd)	33,738		31,455			2,279		2,491		1,815		1,984			604		2,201		38,626		38,131
Inventories, RIKa & Other	(1,635)		(1,151)			(121)		(117)		(153)		(170)			1		(232)		(2,098)		(1,670)
Sales volume (boepd)	32,103		30,304			2,158		2,374		1,662		1,814			605		1,969		36,528		36,461
% Oil	99.4%		99.3%			17%		12%		1%		1%			54%		64%		89%		87%
($ per boe)
Realized oil price	84.4		49.7			95.9		51.9		104.5		58.4			56.7		50.6		84.3		49.8
Realized gas priceb	28.8		25.8			22.3		17.1		39.0		29.3			11.9		13.4		28.8		21.5
Earn-out	(2.9)		(1.7)			-		-		-		-			-		-		(2.9)		(1.6)
Combined Price	81.2		47.9			34.6		21.4		39.9		29.7			36.0		37.3		75.8		44.7
Realized commodity risk management contracts	(10.6)		(7.6)			-		-		-		-			-		-		(9.3)		(6.3)
Operating costs	(5.9)		(6.9)			(18.9)		(9.2)		(10.6)		(6.0)			(24.1)		(18.8)		(7.2)		(7.6)
Royalties in cash	(19.7)		(6.7)			(1.4)		(0.8)		(3.2)		(2.4)			(5.0)		(5.6)		(17.7)		(6.0)
Selling & other expenses	(0.6)		(0.5)			(0.4)		(0.4)		-		-			(1.9)		(1.4)		(0.6)		(0.5)
Operating Netback/boe	44.3		26.2			13.9		11.0		26.2		21.4			5.0		11.5		41.0		24.2
G&A, G&G & other																			(3.7)		(3.9)
Adjusted EBITDA/boe																			37.3		20.3

	a)		RIK (Royalties in kind). Includes royalties paid in kind in Colombia for approximately 1,115 bopd and 1,101 bopd in 1Q2022 and 1Q2021, respectively. No royalties were paid in kind in Chile, Brazil or Argentina.
	b)		Conversion rate of $mcf/$boe=1/6.

Depreciation: Consolidated depreciation charges decreased by 4% to $21.6 million in 1Q2022 compared to $22.6 million in 1Q2021, in line with lower depreciation costs per boe.

Other Income (Expenses): Other operating expenses showed a $4.5 million gain in 1Q2022, compared to a $1.8 million loss in 1Q2021. Gains recognized in 1Q2022 are mainly related to the sale of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina that was closed in January 2022.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses decreased to $15.1 million in 1Q2022 compared to $15.5 million in 1Q2021, mainly resulting from the strategic deleveraging process executed in April 2021 that resulted in significant gross debt reduction, extended maturities and lower cost of debt, partially offset by $0.8 million borrowing cancellation in 1Q2022. Borrowing cancellation costs relate to repurchases of the 2024 Notes during 1Q2022 for $23.1 million in open market transactions, reflecting the difference between the carrying amount of debt repurchased and the consideration paid.

Foreign Exchange: Net foreign exchange charges amounted to a $6.6 million loss in 1Q2022 compared to a $2.7 million gain in 1Q2021.

Income Tax: Income taxes totaled $5.9 million in 1Q2022 compared to $13.4 million in 1Q2021, mainly resulting from the effect of fluctuations of local currencies over deferred income taxes, partially offset by higher profits before income taxes.

Net Profit: Gain of $31.0 million in 1Q2022 compared to a $10.3 million loss recorded in 1Q2021.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $114.1 million as of March 31, 2022, compared to $100.6 million as of December 31, 2021.

This net increase is explained by the following:

(In millions of $)	1Q2022
Cash flows from operating activities	89.7
Cash flows used in investing activities	(25.0)
Cash flows used in financing activities	(52.9)
Currency Translation	1.7
Net increase in cash & cash equivalents	13.5

Cash flows used in investing activities included $39.4 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 included $23.1 million related to repurchases of the 2024 Notes that were acquired in open market transactions at prices below the call option.

Financial Debt: Total financial debt net of issuance cost was $642.5 million, including the remainder of the 2024 Notes, the 2027 Notes and other bank loans totaling $2.7 million. Short-term financial debt was $8.7 million as of March 31, 2022.

(In millions of $)	March 31, 2022	Dec 31, 2021
2024 Notes	146.2	171.9
2027 Notes	493.6	499.9
Other bank loans	2.7	2.3
Financial debt	642.5	674.1

During 1Q2022 the Company repurchased $23.1 million of the 2024 Notes in open market transactions at prices below the call option, reducing gross debt and providing financial cost savings. After the balance sheet date, the Company continued repurchasing 2024 Notes for an additional $9.8 million.

On the date hereof, GeoPark sent a notice of redemption to holders of the 2024 Notes to redeem $45 million aggregate principal amount of the 2024 Notes, which is expected to be completed in May 26, 2022.

For further details, please refer to Note 12 of GeoPark’s consolidated financial statements as of March 31, 2022, 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
1Q2021	773.0	187.6	585.4		2.8x		4.1x
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

a)

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 March 31, 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
2Q2022	Zero cost collar	Brent	12,500	53.4	79.4
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	7,500	65.0	105.0
2Q2023	Zero cost collar	Brent	4,500	68.3	108.8

For further details, please refer to Note 4 of GeoPark’s consolidated financial statements for the period ended March 31, 2022, available on the Company’s website.

SELECTED INFORMATION BY BUSINESS SEGMENT

(UNAUDITED)

Colombia (In millions of $)		1Q2022	1Q2021
Sale of crude oil		234.0	130.1
Sale of gas		0.5	0.5
Revenue		234.5	130.6
Production and operating costsa		(73.4)	(35.7)
Adjusted EBITDA		121.8	64.3
Capital expenditure		28.4	18.3

Chile (In millions of $)	1Q2022	1Q2021
Sale of crude oil	3.1	1.4
Sale of gas	3.6	3.2
Revenue	6.7	4.6
Production and operating costsa	(4.0)	(2.1)
Adjusted EBITDA	2.1	1.7
Capital expenditure	2.9	2.0

Brazil (In millions of $)	1Q2022	1Q2021
Sale of crude oil	0.3	0.1
Sale of gas	5.7	4.7
Revenue	6.0	4.9
Production and operating costsa	(1.7)	(0.9)
Adjusted EBITDA	3.6	3.2
Capital expenditure	0.0	0.0

Argentina (In millions of $)	1Q202213	1Q2021
Sale of crude oil	1.7	5.8
Sale of gas	0.3	0.8
Revenue	2.0	6.6
Production and operating costsa	(1.6)	(4.2)
Adjusted EBITDA	(1.7)	1.1
Capital expenditure	0.0	0.0

(a)

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

_________________
¹³ 1Q2022 figures include revenue, costs, Adjusted EBITDA and capital expenditure until divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks that was completed on January 31, 2022.

CONSOLIDATED STATEMENT OF INCOME

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	1Q2022	1Q2021
REVENUE
Sale of crude oil	239.0	137.3
Sale of gas	10.2	9.3
TOTAL REVENUE	249.2	146.6
Commodity risk management contracts	(78.1)	(47.3)
Production and operating costs	(80.6)	(42.9)
Geological and geophysical expenses (G&G)	(2.7)	(3.1)
Administrative expenses (G&A)	(9.9)	(11.3)
Selling expenses	(2.0)	(1.7)
Depreciation	(21.6)	(22.6)
Write-off of unsuccessful exploration efforts	-	-
Impairment loss on non-financial assets	-	-
Other operating	4.5	(1.8)
OPERATING PROFIT	58.6	15.9
Financial costs, net	(15.1)	(15.5)
Foreign exchange gain (loss)	(6.6)	2.7
PROFIT BEFORE INCOME TAX	36.9	3.1
Income tax	(5.9)	(13.4)
PROFIT (LOSS) FOR THE PERIOD	31.0	(10.3)

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	Mar '22	Dec '21
Non-Current Assets
Property, plant and equipment	632.1	614.0
Other non-current assets	49.1	49.2
Total Non-Current Assets	681.2	663.2
Current Assets
Inventories	11.1	10.9
Trade receivables	109.4	70.5
Other current assets	18.1	50.6
Cash at bank and in hand	114.1	100.6
Total Current Assets	252.7	232.6
Total Assets	933.9	895.7
Equity
Equity attributable to owners of GeoPark	(36.2)	(61.9)
Total Equity	(36.2)	(61.9)
Non-Current Liabilities
Borrowings	633.9	656.2
Other non-current liabilities	79.2	97.8
Total Non-Current Liabilities	713.1	754.0
Current Liabilities
Borrowings	8.7	17.9
Other current liabilities	248.4	185.7
Total Current Liabilities	257.0	203.7
Total Liabilities	970.1	957.7
Total Liabilities and Equity	933.9	895.7

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOW

(QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	1Q2022	1Q2021
Cash flow from operating activities	89.7	36.4
Cash flow (used in) investing activities	(25.0)	(20.3)
Cash flow (used in) from financing activities	(52.9)	(29.7)

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX

1Q2022 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other(a)	Total
Adjusted EBITDA	121.8	2.1	3.6	(1.7)	(3.2)	122.6
Depreciation	(17.4)	(3.3)	(0.8)	(0.1)	(0.0)	(21.6)
Unrealized commodity risk management contracts	(47.6)	-	-	-	-	(47.6)
Write-off of unsuccessful exploration efforts & impairment	-	-	-	-	-	-
Share based payment	(0.2)	(0.0)	(0.0)	0.2	(1.0)	(1.0)
Lease Accounting - IFRS 16	1.0	0.4	0.4	0.0	0.0	1.8
Others	0.7	(0.0)	(0.1)	4.0	(0.0)	4.5
OPERATING PROFIT (LOSS)	58.3	(0.9)	3.1	2.4	(4.2)	58.6
Financial costs, net						(15.1)
Foreign exchange charges, net						(6.6)
PROFIT BEFORE INCOME TAX						36.9
1Q2021 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other(a)	Total
Adjusted EBITDA	64.3	1.7	3.2	1.1	(3.8)	66.5
Depreciation	(14.8)	(3.3)	(1.0)	(3.3)	(0.1)	(22.6)
Unrealized commodity risk management contracts	(26.7)	-	-	-	-	(26.7)
Write-off of unsuccessful exploration efforts & impairment	-	-	-	-	-	-
Share based payment	(0.2)	-	-	-	(1.8)	(2.1)
Lease Accounting - IFRS 16	1.5	0.1	0.5	0.2	0.1	2.5
Others	(0.9)	(0.1)	(0.2)	0.2	(0.9)	(1.8)
OPERATING PROFIT (LOSS)	23.2	(1.6)	2.5	(1.8)	(6.5)	15.9
Financial costs, net						(15.5)
Foreign exchange charges, net						2.7
PROFIT BEFORE INCOME TAX						3.1

(a)

Includes Ecuador and Corporate.

CONFERENCE CALL INFORMATION

Reporting Date for 1Q2022 Results Release

GeoPark management will host a conference call on May 12, 2022 at 10:00 am (Eastern Standard Time) to discuss the 1Q2022 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/3738306/B98B6DEBD18BAB89024E05E5E5412500

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

United States Participants: 844-200-6205

International Participants: [phone]

Passcode: 970790

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
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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