GeoPark Reports Fourth Quarter and Full-Year 2021 Results

2021 Operational Delivery & Cash Generation Funded Debt Reduction & Higher Shareholder Returns

2022 Work Program Delivering Results and Accelerating Profitable Growth

BOGOTA, Colombia--(BUSINESS WIRE)--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 (“Fourth Quarter” or “4Q2021”) and for the year ended December 31, 2021 (“Full-year” or “FY2021”). A conference call to discuss 4Q2021 financial results will be held on March 10, 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 December 31, 2021, available on the Company’s website.

FOURTH QUARTER AND FULL-YEAR 2021 HIGHLIGHTS

Consistent Operational Delivery

• Quarterly oil and gas production of 37,928 boepd / Full-year oil and gas production of 37,602 boepd (or 35,466 boepd pro forma, excluding production from Argentina blocks, divested January 31, 2022¹)
• Full-year consolidated gross operated production of 62,270 boepd
• CPO-5 block (GeoPark non-operated, 30% WI) annual gross production up 55% vs 2020 to 12,407 bopd
• 32 gross wells drilled in 2021 (29 operated with a success rate of 96%)
• 350+ sq km of 3D seismic acquisition during 2021 in the Llanos and Putumayo basins in Colombia

Improved Capital and Cost Efficiency

• Capital expenditures of $43.9 million / Full-year capital expenditures of $129.3 million
• 2021 Adjusted EBITDA to capital expenditures ratio of 2.3x (3.2x excluding cash hedge losses)
• Full-year G&G and G&A costs reduced by 16% to $54.7 million (31% lower vs 2019)

Growing Cash Generation and Profits

• Revenue up 90% to $202.4 million / Full-year Revenue up 75% to $688.5 million
• Adjusted EBITDA up 56% to $87.1 million / Full-year Adjusted EBITDA up 38% to $300.8 million
• Net Profit of $36.9 million / Full-year Net Profit of $61.1 million

Less Debt and Stronger Balance Sheet

• Cash in hand of $100.6 million
• $105 million in debt paid down in 2021
• Net leverage of 1.9x (2.7x in December 2020)

Bigger Shareholder Returns

• Direct returns to shareholders during 4Q2021 totaled $8.9 million² (up 36% vs 3Q2021)
• Discretionary share buyback program in place for up to 10% of shares outstanding until November 2022
• Doubling quarterly cash dividend to $5.0 million ($0.082 per share) payable on March 31, 2022

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^1	GeoPark no longer reports production from Argentina since closing the transaction on January 31, 2022.
^2	$6.4 million in share buybacks plus $2.5 million in quarterly dividends.

40-48 Well Drilling Program Underway and Delivering Results

• Self-funded 2022 capital expenditures program of $160-180 million to drill 40-48 gross wells
• In Ecuador in the Perico block (GeoPark non-operated, 50% WI): First discovery with the Jandaya 1 well now producing gross 870 boepd (770 light oil and 0.6 mmcfpd of gas) with a 1.7% water cut
• In Colombia in the CPO-5 block: Indico 4 development well drilled and now producing gross 4,200 bopd of light oil with less than 0.2% water cut. Currently drilling the Indico 5 development well to be followed by high-impact exploration drilling campaign beginning by the end of 1Q2022
• In Colombia in the Llanos 34 block (GeoPark operated, 45% WI): 7 new gross development wells drilled in the Tigana, Jacana and Tigui oil fields

2022 Production and Cash Generation

• Targeted 2022 production increase of 5-10% to 35,500-37,500 boepd - does not include production from Argentina³ and Brazil⁴ and any potential production from 15-20 exploration wells being drilled
• At $80-85/bbl Brent, the work program generates $210-240 million free cash flow, a 25-30% yield
• At $95-100/bbl Brent, the work program generates $260-280 million free cash flow, a 31-33% yield
• Free cash flow will be used to: (i) fund additional capital opportunities within the portfolio, (ii) partially or fully repay the 2024 Notes ($170 million principal remaining), as well as (iii) increasing shareholder returns (through dividends and buybacks) and other corporate purposes

James F. Park, Chief Executive Officer of GeoPark, said: “Thanks again to the incredible GeoPark team for delivering a successful 2021 and for continuing to make us a more-prepared and stronger Company – regardless of a world in constant change. Beginning as always with consistent on-the-ground operational performance and thoroughly working across all our Company to get better in every way, the year ended robustly with more cash generation, lower structure costs, smaller carbon footprint, more bottom-line profits, less debt, and more shareholder returns – including increased dividends. And 2022, building on this big momentum, is already off and running. Supported by our core low cost producing assets, we have 10 rigs working as part of a big 40-48 well drilling program – and with positive results coming in – including from an ambitious exploration drilling program focused on low-risk, quick tie-in opportunities in proven high potential basins. And, of course, there is a powerful wind at our back now with high oil prices and strong demand for the energy we are finding and producing.”

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^3	GeoPark no longer reports production from Argentina since closing the transaction on January 31, 2022.
^4	Please refer to section “Manati Gas Field Divestment Process Update in Brazil” included in this release.

PORTFOLIO MANAGEMENT UPDATE

Completion of the Argentina Divestment Process

In November 2021, GeoPark accepted an offer from Oilstone Energía S.A. to purchase GeoPark's 100% WI in the Aguada Baguales, El Porvenir and Puesto Touquet blocks for a total consideration of $16 million. Closing of the transaction occurred on January 31, 2022 and GeoPark no longer reports production from these blocks since that date.

Manati Gas Field Divestment Process Update in Brazil

In November 2020 GeoPark signed an agreement to sell its 10% non-operated WI in the Manati gas field to Gas Bridge S.A. for a total consideration of R$144.4 million ($~28 million at an exchange rate of R$5.1 per dollar), including a fixed payment of R$124.4 million plus an earn-out of R$20.0 million, subject to obtaining certain regulatory approvals. The transaction is subject to several conditions that should be met before March 31, 2022 and that have not been met as of the date of this release.

SPEED / ESG+ ACHIEVEMENTS AND RECOGNITIONS

Electrification and Solar Photovoltaic Plant Update

The electrification of the Llanos 34 block is proceeding and is 51% complete. This connection will improve overall operational reliability and reduce carbon emissions and energy generation costs, and is expected to be fully operational in 2H2022. In addition, the solar photovoltaic plant in the Llanos 34 block is now 80% complete, and will be fully operational in 1H2022.

Bloomberg Gender Equality-Index Inclusion

In January 2022 GeoPark was added to the Bloomberg Gender-Equality Index, including companies with best-in-class gender-related practices and policies.

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Key Indicators	4Q2021	3Q2021	4Q2020	FY2021	FY2020
Oil production^a (bopd)	33,205	32,844	33,238	32,474	34,860
Gas production (mcfpd)	28,338	30,090	36,390	30,768	31,992
Average net production (boepd)	37,928	37,859	39,304	37,602	40,192
Brent oil price ($ per bbl)	79.0	73.2	46.0	70.7	43.2
Combined realized price ($ per boe)	59.3	53.9	31.7	52.2	28.4
⁻ Oil ($ per bbl)	65.9	60.3	35.5	58.4	31.2
⁻ Gas ($ per mcf)	4.0	4.2	3.0	4.0	3.0
Sale of crude oil ($ million)	192.9	163.5	97.5	647.6	359.6
Sale of gas ($ million)	9.5	10.5	9.2	40.9	34.1
Revenue ($ million)	202.4	174.0	106.7	688.5	393.7
Commodity risk management contracts^b ($ million)	(2.5)	(11.7)	(17.5)	(109.2)	8.1
Production & operating costs^c ($ million)	(67.6)	(49.2)	(34.9)	(212.8)	(125.1)
G&G, G&A^d ($ million)	(11.6)	(13.8)	(20.7)	(54.7)	(65.3)
Selling expenses ($ million)	(3.4)	(1.8)	(1.0)	(8.8)	(5.8)
Adjusted EBITDA ($ million)	87.1	86.8	56.0	300.8	217.5
Adjusted EBITDA ($ per boe)	25.5	26.9	16.6	22.8	15.7
Operating Netback ($ per boe)	29.0	30.8	22.2	26.7	19.9
Net Profit (loss) ($ million)	36.9	37.0	(119.2)	61.1	(233.0)
Capital expenditures ($ million)	43.9	30.6	26.1	129.3	75.3
Amerisur acquisition^e ($ million)	-	-	-	-	272.3
Cash and cash equivalents ($ million)	100.6	76.8	201.9	100.6	201.9
Short-term financial debt ($ million)	17.9	18.1	17.7	17.9	17.7
Long-term financial debt ($ million)	656.2	656.8	766.9	656.2	766.9
Net debt ($ million)	573.5	598.1	582.7	573.5	582.7

a)	Includes royalties paid in kind in Colombia for approximately 1,119, 1,213 and 986 bopd in 4Q2021, 3Q2021 and 4Q2020, 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, $1.7 million and $2.3 million in 4Q2021, 3Q2021 and 4Q2020, 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 4Q2021 was 37,928 boepd. Compared to 4Q2020, oil and gas production decreased by 4%, resulting from lower production in Chile, Brazil, and Argentina, partially offset by a slight production increase in Colombia.

Oil represented 88% and 85% of total reported production in 4Q2021 and 4Q2020, respectively.

For further details, please refer to the 4Q2021 Operational Update published on January 19, 2022.

Reference and Realized Oil Prices: Brent crude oil prices averaged $79.0 per bbl during 4Q2021, and the consolidated realized oil sales price averaged $65.9 per bbl in 4Q2021.

The tables below provide a breakdown of reference and net realized oil prices in Colombia, Chile and Argentina in 4Q2021 and 4Q2020:

4Q2021 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina
Brent oil price (*)	79.0	80.5	79.0
Local marker differential	(4.8)	-	-
Commercial, transportation discounts & Other	(8.1)	(8.0)	(19.8)
Realized oil price	66.1	72.5	59.2
Weight on oil sales mix	95%	1%	4%

4Q2020 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina
Brent oil price (*)	46.0	45.6	46.0
Local marker differential	(2.3)	-	-
Commercial, transportation discounts & Other	(8.4)	(7.8)	(5.0)
Realized oil price	35.3	37.8	41.0
Weight on oil sales mix	95%	1%	4%
(*) Brent oil price may differ in each country as sales are priced with different Brent reference prices.

Revenue: Consolidated revenue increased by 90% to $202.4 million in 4Q2021, compared to $106.7 million in 4Q2020, reflecting higher oil and gas prices and to a lesser extent a 2% increase in oil and gas deliveries.

Sales of crude oil: Consolidated oil revenue increased by 98% to $192.9 million in 4Q2021, driven by a 87% increase in realized oil prices and to a lesser extent 6% higher oil deliveries. Oil revenue was 95% of total revenue in 4Q2021 and 91% in 4Q2020.

(In millions of $)	4Q2021	4Q2020
Colombia	184.0	91.6
Chile	2.3	1.3
Argentina	6.4	4.4
Brazil	0.2	0.2
Oil Revenue	192.9	97.5

• Colombia: 4Q2021 oil revenue increased by 101% to $184.0 million, reflecting higher realized oil prices and higher oil deliveries. Realized prices increased by 87% to $66.1 per bbl due to higher Brent oil prices while oil deliveries increased by 6% to 31,277 bopd. Earn-out payments increased to $6.0 million in 4Q2021, compared to $3.6 million in 4Q2020 in line with higher oil prices.
• Chile: 4Q2021 oil revenue increased by 69% to $2.3 million, reflecting higher realized prices that were partially offset by lower oil deliveries. Realized prices increased by 92% to $72.5 per bbl due to higher Brent oil prices while oil deliveries decreased by 12% to 339 bopd.
• Argentina: 4Q2021 oil revenue increased by 45% to $6.4 million, due to 44% higher realized oil prices of $59.2 per bbl. Oil deliveries remained flat at 1,175 bopd.

Sales of gas: Consolidated gas revenue increased by 3% to $9.5 million in 4Q2021 compared to $9.2 million in 4Q2020 reflecting 35% higher gas prices, partially offset by 24% lower gas deliveries. Gas revenue was 5% and 9% of total revenue in 4Q2021 and 4Q2020, respectively.

(In millions of $)	4Q2021	4Q2020
Chile	3.5	3.5
Brazil	4.5	4.5
Argentina	1.0	0.6
Colombia	0.5	0.6
Gas Revenue	9.5	9.2

• Chile: 4Q2021 gas revenue remained flat at $3.5 million, reflecting lower gas deliveries that were offset by higher gas prices. Gas deliveries fell by 38% to 10,254 mcfpd (1,709 boepd). Gas prices were 61% higher, at $3.7 per mcf ($22.0 per boe) in 4Q2021.
• Brazil: 4Q2021 gas revenue remained flat at $4.5 million, due to higher gas prices that were offset by lower gas deliveries. Gas prices increased by 20% to $5.0 per mcf ($29.9 per boe). Gas deliveries decreased by 16% from the Manati gas field (GeoPark non-operated, 10% WI) to 9,881 mcfpd (1,647 boepd).
• Argentina: 4Q2021 gas revenue increased by 49% to $1.0 million, resulting from higher gas prices and higher gas deliveries. Gas prices increased by 47% to $2.4 per mcf ($14.4 per boe) while deliveries increased by 2% to 4,327 mcfpd (721 boepd).

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to a $2.5 million loss in 4Q2021, compared to a $17.5 million loss in 4Q2020.

The table below provides a breakdown of realized and unrealized commodity risk management contracts in 4Q2021 and 4Q2020:

(In millions of $)	4Q2021	4Q2020
Realized (loss) gain	(31.0)	5.3
Unrealized gain (loss)	28.5	(22.8)
Commodity risk management contracts	(2.5)	(17.5)

The realized portion of the commodity risk management contracts registered a loss of $31.0 million in 4Q2021 compared to a $5.3 million gain in 4Q2020. Realized losses recorded in 4Q2021 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 $28.5 million gain in 4Q2021, compared to a $22.8 million loss in 4Q2020. Unrealized gains during 4Q2021 resulted from the reclassification of unrealized to realized losses during 4Q2021 plus unrealized losses accrued in 4Q2021 due to the increase in the forward Brent oil price curve at December 31, 2021 compared to September 30, 2021.

Please refer to the “Commodity Risk Oil Management Contracts” section below for a description of hedges in place as of the date of this release.

Production and Operating Costs⁵: Consolidated production and operating costs increased to $67.6 million from $34.9 million, mainly resulting from a $26.2 million increase in cash royalties due to higher oil and gas prices, and to a lesser extent, due to increased operating costs.

The table below provides a breakdown of production and operating costs in 4Q2021 and 4Q2020:

(In millions of $)	4Q2021	4Q2020
Cash royalties	(37.7)	(11.6)
Share-based payments	(0.1)	(0.4)
Operating costs	(29.8)	(22.9)
Production and operating costs	(67.6)	(34.9)

Consolidated royalties increased to $37.7 million in 4Q2021 compared to $11.6 million in 4Q2020, in line with higher oil and gas prices.

Consolidated operating costs increased to $29.8 million in 4Q2021 compared to $22.9 million in 4Q2020.

The breakdown of operating costs is as follows:

• Colombia: Operating costs per boe amounted to $7.7 in 4Q2021, compared to $6.5 in 4Q2020. Total operating costs increased to $21.4 million in 4Q2021 from $16.4 million in 4Q2020 due to higher deliveries (deliveries in Colombia increased by 6%) and higher operating costs per boe resulting from inventories reduction in the Platanillo block, with higher costs per boe than the Llanos 34 or CPO-5 blocks, combined with higher maintenance costs.
• Chile: Operating costs per boe amounted to $14.9 in 4Q2021, compared to $8.9 in 4Q2020. Total operating costs increased to $2.8 million in 4Q2021 from $2.6 million in 4Q2020, in line with higher operating costs per boe, partially offset by lower oil and gas deliveries (deliveries in Chile decreased by 35%).
• Brazil: Operating costs per boe amounted to $7.4 in 4Q2021 compared to $7.6 in 4Q2020. Total operating costs decreased to $0.8 million in 4Q2021 from $0.9 million in 4Q2020, due to lower operating costs per boe and reflecting lower gas deliveries in the Manati field (deliveries in Brazil decreased by 16%).
• Argentina: Operating costs per boe amounted to $27.8 in 4Q2021 compared to $18.5 in 4Q2020. Total operating costs increased to $4.8 million in 4Q2021 from $3.1 million in 4Q2020, due to higher operating costs per boe and higher oil and gas deliveries.

Lower operating costs per boe in 4Q2020 in Chile and Argentina mainly resulted from reduced or suspended well intervention and maintenance activities resulting from the lower oil price environment in 2020.

Selling Expenses: Consolidated selling expenses increased to $3.4 million in 4Q2021, compared to $0.9 million in 4Q2020.

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

Administrative Expenses: Consolidated G&A decreased to $11.0 million in 4Q2021 compared to $16.0 million in 4Q2020 due to lower staff costs and higher allocation to joint operations.

Geological & Geophysical Expenses: Consolidated G&G expenses decreased to $0.6 million in 4Q2021 compared to $4.8 million in 4Q2020 due to lower staff costs.

Adjusted EBITDA: Consolidated Adjusted EBITDA⁶ increased by 56% to $87.1 million, or $25.5 per boe, in 4Q2021 compared to $56.0 million, or $16.6 per boe, in 4Q2020.

(In millions of $)	4Q2021	4Q2020
Colombia	90.1	60.5
Chile	1.8	0.3
Brazil	2.9	2.2
Argentina	(2.8)	(1.7)
Corporate, Ecuador and Other	(4.9)	(5.3)
Adjusted EBITDA	87.1	56.0

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 4Q2021 and 4Q2020, on a per country and per boe basis:

Adjusted EBITDA/boe	Colombia		Chile		Brazil		Argentina		Total
	4Q21	4Q20	4Q21	4Q20	4Q21	4Q20	4Q21	4Q20	4Q21	4Q20
Production (boepd)	32,002	31,858	2,162	3,133	1,822	2,167	1,942	2,146	37,928	39,304
Inventories, RIK^a& Other	(512)	(2,329)	(114)	11	(150)	(187)	(46)	(266)	(822)	(2,771)
Sales volume (boepd)	31,490	29,529	2,048	3,144	1,672	1,980	1,896	1,880	37,106	36,533
% Oil	99.3%	99.3%	17%	12%	2%	1%	62%	62%	88%	85%
($ per boe)
Realized oil price	66.1	35.3	72.5	37.8	79.5	43.2	59.2	41.0	65.9	35.5
Realized gas price^b	26.7	31.3	22.0	13.7	29.9	24.9	14.4	9.8	24.0	17.7
Earn-out	(2.1)	(1.3)	-	-	-	-	-	-	(2.0)	(1.1)
Combined Price	63.7	33.9	30.3	16.6	30.6	25.2	42.2	29.3	59.3	31.7
Realized commodity risk management contracts	(10.7)	2.0	-	-	-	-	-	-	(9.1)	1.6
Operating costs	(7.7)	(6.5)	(14.9)	(8.9)	(7.4)	(7.6)	(27.8)	(18.5)	(9.1)	(7.4)
Royalties in cash	(12.5)	(3.8)	(1.2)	(0.6)	(2.2)	(2.0)	(5.8)	(4.5)	(11.1)	(3.4)
Selling & other expenses	(1.0)	(0.2)	(0.4)	(0.3)	(0.0)	-	(2.5)	(1.2)	(1.0)	(0.3)
Operating Netback/boe	31.8	25.4	13.9	6.9	21.0	15.6	6.0	5.2	29.0	22.2
G&A, G&G & other									(3.5)	(5.6)
Adjusted EBITDA/boe									25.5	16.6

a)	Includes royalties paid in kind in Colombia for approximately 1,119 and 986 bopd in 4Q2021 and 4Q2020, respectively. No royalties were paid in kind in other countries.
b)	Conversion rate of $mcf/$boe=1/6.

Depreciation: Consolidated depreciation charges decreased by 23% to $22.2 million in 4Q2021 compared to $28.8 million in 4Q2020, in line with lower depreciation costs per boe, partially offset by a 2% increase in oil and gas volumes delivered.

Write-off of unsuccessful exploration efforts: The consolidated write-off of unsuccessful exploration efforts was zero in 4Q2021 compared to $48.9 million in 4Q2020.

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^6	See “Reconciliation of Adjusted EBITDA to Profit (Loss) Before Income Tax and Adjusted EBITDA per boe” included in this press release.

Impairment of non-financial assets: The consolidated impairment charges amounted to a $17.6 million loss in 4Q2021 compared to a $35.4 million loss in 4Q2020. Impairment charges in 4Q2021 refer to costs incurred in previous years in the Fell block in Chile, resulting from lower oil and gas reserves in the 2021 year-end reserves certification. An impairment loss is recognized for the amount by which an asset’s carrying amount exceeds its recoverable amount.

Other Income (Expenses): Other operating expenses showed a $8.0 million loss in 4Q2021, compared to a $2.7 million loss in 4Q2020.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses decreased to $13.1 million in 4Q2021 compared to $16.4 million in 4Q2020, mainly resulting from the strategic deleveraging process executed in April 2021 that resulted in significant gross debt reduction with extended maturities and lower cost of debt.

Foreign Exchange: Net foreign exchange charges amounted to a $0.4 million loss in 4Q2021 compared to a $6.3 million loss in 4Q2020.

Income Tax: Income taxes totaled $19.1 million in 4Q2021 compared to $13.4 million in 4Q2020, mainly resulting from the effect of higher taxable profits before tax recorded in 4Q2021 compared to 4Q2020.

Net Profit: Gain of $36.9 million in 4Q2021 compared to a $119.2 million loss recorded in 4Q2020.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $100.6 million as of December 31, 2021, compared to $201.9 million as of December 31, 2020.

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

(In millions of $)	FY2021
Cash flows from operating activities	216.8
Cash flows used in investing activities	(126.6)
Cash flows used in financing activities	(190.4)
Net decrease in cash & cash equivalents	(100.2)

Cash flows from operating activities are shown net of cash taxes paid of $65.3 million.

Cash flows used in investing activities included capital expenditures incurred by the Company as part of its 2021 work program, partially offset by proceeds from the disposal of assets of $2.7 million.

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

Financial Debt: Total financial debt net of issuance cost was $674.1 million, including the remainder of the 2024 Notes, the 2027 Notes and other bank loans totaling $2.3 million. Short-term financial debt was $17.9 million as of December 31, 2021.

(In millions of $)	Dec 31, 2021	Dec 31, 2020
2024 Notes	171.9	428.7
2027 Notes	499.9	352.1
Other bank loans	2.3	3.7
Financial debt	674.1	784.6

For further details, please refer to Note 27 of GeoPark’s consolidated financial statements as of December 31, 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
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
3Q2021	674.9	76.8	598.1	2.2x	5.8x
4Q2021	674.1	100.6	573.5	1.9x	6.7x

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 27 of GeoPark’s consolidated financial statements as of December 31, 2021, 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
1Q2022	Zero cost collar	Brent	14,500	49.1	74.8
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	3,000	67.5	102.1

For further details, please refer to Note 8 of GeoPark’s consolidated financial statements for the period ended December 31, 2021, available on the Company’s website.

SELECTED INFORMATION BY BUSINESS SEGMENT (UNAUDITED)
Colombia (In millions of $)	4Q2021	4Q2020
Sale of crude oil	184.0	91.6
Sale of gas	0.5	0.6
Revenue	184.5	92.2
Production and operating costs^a	(57.6)	(26.9)
Adjusted EBITDA	90.1	60.5
Capital expenditure	38.5	25.5

Chile (In millions of $)	4Q2021	4Q2020
Sale of crude oil	2.3	1.3
Sale of gas	3.5	3.5
Revenue	5.7	4.8
Production and operating costs^a	(3.0)	(2.8)
Adjusted EBITDA	1.8	0.3
Capital expenditure	0.7	0.4

Brazil (In millions of $)	4Q2021	4Q2020
Sale of crude oil	0.2	0.1
Sale of gas	4.5	4.5
Revenue	4.7	4.6
Production and operating costs^a	(1.1)	(1.2)
Adjusted EBITDA	2.9	2.2
Capital expenditure	0.0	0.1

Argentina (In millions of $)	4Q2021	4Q2020
Sale of crude oil	6.4	4.4
Sale of gas	1.0	0.6
Revenue	7.4	5.1
Production and operating costs^a	(5.8)	(3.9)
Adjusted EBITDA	(2.8)	(1.7)
Capital expenditure	0.0	0.0

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

CONSOLIDATED STATEMENT OF INCOME (QUARTERLY INFORMATION UNAUDITED)
(In millions of $)	4Q2021	4Q2020	FY2021	FY2020
REVENUE
Sale of crude oil	192.9	97.5	647.6	359.6
Sale of gas	9.5	9.2	40.9	34.1
TOTAL REVENUE	202.4	106.7	688.5	393.7
Commodity risk management contracts	(2.5)	(17.5)	(109.2)	8.1
Production and operating costs	(67.6)	(34.9)	(212.8)	(125.1)
Geological and geophysical expenses (G&G)	(0.6)	(4.8)	(7.9)	(14.9)
Administrative expenses (G&A)	(11.0)	(16.0)	(46.8)	(50.3)
Selling expenses	(3.4)	(0.9)	(8.8)	(5.8)
Depreciation	(22.2)	(28.8)	(89.0)	(118.1)
Write-off of unsuccessful exploration efforts	-	(48.9)	(12.3)	(52.7)
Impairment loss on non-financial assets	(17.6)	(35.4)	(4.3)	(133.9)
Other operating	(8.0)	(2.7)	(11.7)	(11.7)
OPERATING PROFIT (LOSS)	69.4	(83.1)	185.8	(110.7)
Financial costs, net	(13.1)	(16.4)	(62.5)	(61.4)
Foreign exchange gain (loss)	(0.4)	(6.3)	5.0	(13.0)
PROFIT (LOSS) BEFORE INCOME TAX	56.0	(105.8)	128.4	(185.1)
Income tax	(19.1)	(13.4)	(67.3)	(47.9)
PROFIT (LOSS) FOR THE PERIOD	36.9	(119.2)	61.1	(233.0)

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION (QUARTERLY INFORMATION UNAUDITED)
(In millions of $)	Dec '21	Dec '20
Non-Current Assets
Property, plant and equipment	614.0	614.7
Other non-current assets	49.2	54.0
Total Non-Current Assets	663.2	668.7
Current Assets
Inventories	10.9	13.3
Trade receivables	70.5	46.9
Other current assets	50.6	29.5
Cash at bank and in hand	100.6	201.9
Total Current Assets	232.6	291.6
Total Assets	895.7	960.3
Equity
Equity attributable to owners of GeoPark	-61.9	-109.2
Total Equity	-61.9	-109.2
Non-Current Liabilities
Borrowings	656.2	766.9
Other non-current liabilities	97.8	105.9
Total Non-Current Liabilities	754.0	872.8
Current Liabilities
Borrowings	17.9	17.7
Other current liabilities	185.7	179.0
Total Current Liabilities	203.7	196.7
Total Liabilities	957.7	1,069.5
Total Liabilities and Equity	895.7	960.3

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOW (QUARTERLY INFORMATION UNAUDITED)
(In millions of $)	4Q2021	4Q2020	FY2021	FY2020
Cash flow from operating activities	88.0	77.1	216.8	168.7
Cash flow used in investing activities	(42.3)	(26.0)	(126.6)	(347.6)
Cash flow (used in) from financing activities	(21.5)	(13.1)	(190.4)	271.1

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX
FY2021 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other^(a)	Total
Adjusted EBITDA	294.8	7.6	12.6	2.1	(16.3)	300.8
Depreciation	(61.3)	(14.3)	(4.1)	(9.1)	(0.2)	(89.0)
Unrealized commodity risk management contracts	0.5	-	-	-	-	0.5
Write-off of unsuccessful exploration efforts & impairment	(7.8)	(22.1)	-	13.3	-	(16.6)
Share based payment	(0.8)	(0.1)	-	-	(5.7)	(6.6)
Lease Accounting - IFRS 16	4.3	0.8	1.6	0.6	0.2	7.5
Others	(0.7)	(1.1)	(0.6)	(7.5)	(0.9)	(10.8)
OPERATING PROFIT (LOSS)	229.0	(29.2)	9.5	(0.6)	(22.9)	185.8
Financial costs, net						(62.5)
Foreign exchange charges, net						5.1
PROFIT BEFORE INCOME TAX						128.4
FY2020 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other^(a)	Total
Adjusted EBITDA	218.5	8.1	4.8	1.2	(15.1)	217.5
Depreciation	(63.7)	(33.6)	(3.7)	(16.6)	(0.5)	(118.1)
Unrealized commodity risk management contracts	(13.0)	0.0	0.0	0.0	0.0	(13.0)
Write-off of unsuccessful exploration efforts & impairment	(2.0)	(132.1)	(2.3)	(16.2)	(34.0)	(186.5)
Share based payment	(0.7)	(0.2)	(0.1)	(0.3)	(7.1)	(8.4)
Lease Accounting - IFRS 16	5.8	0.1	2.2	0.9	0.4	9.4
Others	(0.2)	(1.0)	0.3	(1.6)	(9.2)	(11.7)
OPERATING PROFIT (LOSS)	144.8	(158.6)	1.2	(32.6)	(65.5)	(110.7)
Financial costs, net						(61.4)
Foreign exchange charges, net						(13.0)
LOSS BEFORE INCOME TAX						(185.1)

(a)	Includes Peru, Ecuador and Corporate.

2022 FREE CASH FLOW CALCULATION AND SENSITIVITIES TO DIFFERENT BRENT OIL PRICES

The table below provides sensitivities to different Brent oil prices using the 2022 base work program:

2022 Free Cash Flow^7	$65-70 per bbl	$80-85 per bbl	$95-100 per bbl
(in millions of $)
Operating Netback	420-470	510-550	560-580
Adjusted EBITDA	370-430	460-500	510-530
Cash Taxes	(40-45)	(40-45)	(40-45)
Capital Expenditures	(160-180)	(160-180)	(160-180)
Mandatory Debt Service Payments^8	(38-42)	(38-42)	(38-42)
Free Cash Flow	110-150	210-240	260-280
Free Cash Flow Yield (in %)	11-18%	25-30%	31-33%

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.

Free cash flow yield is calculated as free cash flow divided by GeoPark’s average market capitalization from January 3 to February 28, 2022.

____________

^7	Brent oil price assumptions refer to March-December 2022 and consider a $3-4 Vasconia/Brent differential. Free cash flow excludes changes in working capital.
^8	Excluding potential and voluntary prepayments on existing financial debt.

CONFERENCE CALL INFORMATION

Reporting Date for 4Q2021 Results Release

GeoPark management will host a conference call on March 10, 2022 at 10:00 am (Eastern Standard Time) to discuss the 4Q2021 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/3575585/D8C22C704081598319ACA0C7BF36387F

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

United States Participants: 844-200-6205
International Participants: [phone]
Passcode: 376830

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
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
Mm^3/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 the Manati gas field divestment, emission reduction goals, expected or future production, production growth and operating and financial performance, operating netback, future opportunities, our dividend or other distributions and capital expenditures plan. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

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

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

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

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

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

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

Adjusted EBITDA: The Company defines Adjusted EBITDA as profit for the period before net finance costs, income tax, depreciation, amortization and certain non-cash items such as impairments and write-offs of unsuccessful exploration and evaluation assets, accrual of stock options stock awards, unrealized results on commodity risk management contracts and other non-recurring events. Adjusted EBITDA is not a measure of profit or cash flow as determined by IFRS. The Company excludes the items listed above from profit for the period in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, profit for the period or cash flow from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.

Operating Netback per boe: Operating netback per boe should not be considered as an alternative to, or more meaningful than, profit for the period or cash flow from operating activities as determined in accordance with IFRS or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from operating netback per boe are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of operating netback per boe. The Company’s calculation of operating netback per boe may not be comparable to other similarly titled measures of other companies. For a reconciliation of operating netback per boe to the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.

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