Growing Production and Free Cash Flow Funds Deleveraging & Accelerated 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 September 30, 2022 ("Third Quarter" or "3Q2022"). A conference call to discuss 3Q2022 financial results and the 2023 work program and shareholder return framework will be held on November 10, 2022 at 10:00 am (Eastern Daylight Time).

All figures are expressed in US Dollars and growth comparisons refer to the same period of the prior year, except when specified. Definitions and terms used herein are provided in the Glossary at the end of this document. This release does not contain all of the Company's financial information and should be read in conjunction with GeoPark's consolidated financial statements and the notes to those statements for the period ended September 30, 2022, available on the Company's website.

THIRD QUARTER 2022 HIGHLIGHTS

Accelerating Production Growth

Consolidated oil and gas production up 8% to 38,396 boepd¹
13 rigs operating in November 2022 (compared to 8 rigs in November 2021)
On track to reach 2022 full-year guidance of 38,500-40,500 boepd

Growing Revenue, Adjusted EBITDA & Cash Flow Driving Record Net Profit

Revenue up 48% to $258.2 million
Adjusted EBITDA up 63% to $141.3 million (including $13.8 million of realized cash hedge losses)
Operating Profit up 79% to $145.4 million
Cash flow from operations up 183% to $141.1 million
Record Net Profit of $73.4 million (or $1.24 earnings per share)
2022 full-year capital expenditures program of $200-220 million, generating free cash of $250-280 million² assuming $90-100 per bbl Brent³, equivalent to a 33-37% free cash flow yield⁴
Capital expenditures of $43.4 million
Every dollar invested in capital expenditures yielded 3.2x in Adjusted EBITDA

Returning More Value To Shareholders

Quarterly Dividend of $0.127 per share, or $7.5 million, payable on December 7, 2022
Equivalent to an annualized dividend of approximately $30 million (or $0.508 per share), a 4% dividend yield⁵
Completed share buyback program after acquiring 2.2 million shares (or over 3% of total shares outstanding) for $29.3 million since November 2021
Renewed discretionary share buyback program for up to 10% of shares outstanding until December 2023

Deleveraging and Balance Sheet Strengthening

Fully redeemed the remaining $67.1 million principal of the 2024 Notes in September 2022
Reduced gross debt by $170 million since January 1, 2022, or $275 million since April 2021
Net leverage of 0.8x
Cash in hand of $93.0 million

2023 Work Program: Strong Cash Generation with Increased Shareholder Returns

2023 production guidance of 39,500-41,500 boepd (assuming no production from the exploration drilling program)
Self-funded 2023 capital expenditures program of $200-220 million to drill 50-55 gross wells
At $80-90 per bbl Brent, GeoPark expects to generate an Adjusted EBITDA of $510-580 million and targeting to return approximately 40-50% of free cash flows after taxes⁶to shareholders

Recent Events And Upcoming Catalysts

Indico 6 development well, completed in October 2022 is currently producing 4,100 bopd (on a restricted 32/64 inch choke), of 35 degrees API with 0.1% water cut
Drilling 15-18 gross wells in 4Q2022, targeting development, appraisal, and exploration projects in the Llanos and Putumayo basins in Colombia and in the Oriente basin in Ecuador
Exploration drilling includes 3-4 wells in new blocks in the Llanos basin, 1 well in the Putumayo basin and 1 well in the Oriente basin in Ecuador

Andrés Ocampo, Chief Executive Officer of GeoPark, said: "The third quarter financial results reflect the hard work of GeoPark's most important asset, our people. Once again, in 2022, that hard work has paid off with a busy drilling schedule that produced record financial results from the top line to the bottom line. We have just completed our 2023 capital allocation process and anticipate another active year drilling between 50-55 wells across our portfolio. This will translate into significant free cash flow in 2023 to self-fund our high-impact exploration and development program and increase shareholder returns while maintaining a strong balance sheet, reducing emissions and strengthening the ties to our neighbors."

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Key Indicators	3Q2022	2Q2022	3Q2021	9M2022	9M2021
Oil production^a (bopd)	34,875	35,238	32,844	34,886	32,228
Gas production (mcfpd)	21,126	22,212	30,090	22,799	31,587
Average net production (boepd)	38,396	38,940	37,859	38,686	37,492
Brent oil price ($ per bbl)	98.2	111.5	73.2	101.9	67.7
Combined realized price ($ per boe)	77.5	90.0	53.9	81.2	49.7
- Oil ($ per bbl)	85.9	98.7	60.3	89.7	55.7
- Gas ($ per mcf)	4.5	5.1	4.2	4.8	4.0
Sale of crude oil ($ million)	248.7	296.4	163.5	784.1	454.6
Sale of purchased crude oil ($ million)	1.0	5.4	-	6.3	-
Sale of gas ($ million)	8.6	9.4	10.5	28.2	31.5
Revenue ($ million)	258.2	311.2	174.0	818.6	486.2
Commodity risk management contracts^b ($ million)	23.0	(15.5)	(11.7)	(70.7)	(106.7)
Production & operating costs^c ($ million)	(87.1)	(115.1)	(49.2)	(282.8)	(145.2)
G&G, G&A^d ($ million)	(16.7)	(13.8)	(13.9)	(43.2)	(43.0)
Selling expenses ($ million)	(2.0)	(1.2)	(1.8)	(5.2)	(5.3)
Adjusted EBITDA ($ million)	141.3	144.8	86.8	408.7	213.7
Adjusted EBITDA ($ per boe)	42.4	41.9	26.9	40.6	21.9
Operating Netback ($ per boe)	46.4	45.4	30.8	44.3	25.9
Net Profit (loss) ($ million)	73.4	67.9	37.0	172.2	24.2
Capital expenditures ($ million)	43.4	32.4	30.6	115.2	85.4
Cash and cash equivalents ($ million)	93.0	122.5	76.8	93.0	76.8
Short-term financial debt ($ million)	6.8	15.3	18.1	6.8	18.1
Long-term financial debt ($ million)	484.3	570.0	656.8	484.3	656.8
Net debt ($ million)	398.1	462.9	598.1	398.1	598.1

a)		Includes royalties paid in kind in Colombia for approximately 911, 1,273, and 1,213 bopd in 3Q2022, 2Q2022 and 3Q2021, 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 and economic rights paid in cash, share based payments and purchased crude oil.
d)		G&A and G&G expenses include non-cash, share-based payments for $3.9, $2.0 million and $1.7 million in 3Q2022, 2Q2022 and 3Q2021, respectively. These expenses are excluded from the Adjusted EBITDA calculation.

RECENT BLOCKADES IN THE LLANOS BASIN IN COLOMBIA

In mid-October 2022, localized blockades in the Llanos basin partially affected production and operations in the Llanos 34 block (GeoPark operated, 45% WI), that is expected to reduce net production by approximately 230 bopd in 4Q2022. Blockades have been lifted as of the date of this release and production and operations have been normalized.

Production: Oil and gas production in 3Q2022 was 38,396 boepd. Adjusting for divestments in Argentina (completed on January 31, 2022), consolidated oil and gas production increased by 8% compared to 3Q2021, due to higher production in Colombia, Chile and Ecuador, partially offset by lower production in Brazil. Oil represented 91% and 87% of total reported production in 3Q2022 and 3Q2021, respectively.

Compared to 2Q2022, oil and gas production was 1% lower, mainly due to temporary local blockades in Colombia that reduced 3Q2022 production by approximately 1,100-1,200 boepd, and to a lesser extent, lower gas production in Brazil.

For further details, please refer to the 3Q2022 Operational Update published on October 20, 2022.

Reference and Realized Oil Prices: Brent crude oil prices averaged $98.2 per bbl during 3Q2022, and the consolidated realized oil sales price averaged $85.9 per bbl in 3Q2022.

A breakdown of reference and net realized oil prices in relevant countries in 3Q2022 and 3Q2021 is shown in the tables below:

3Q2022 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina⁷	Ecuador
Brent oil price (*)	98.2	98.2	-	98.2
Local marker differential	(3.8)	-	-	-
Commercial, transportation discounts & Other	(8.7)	(4.8)	-	(5.2)
Realized oil price	85.7	93.4	-	93.0
Weight on oil sales mix	98%	1%	-	1%

3Q2021 - Realized Oil Prices ($ per bbl)	Colombia	Chile	Argentina	Ecuador
Brent oil price (*)	73.2	73.2	73.2	-
Local marker differential	(4.1)	-	-	-
Commercial, transportation discounts & Other	(8.8)	(9.2)	(16.1)	-
Realized oil price	60.3	64.0	57.1	-
Weight on oil sales mix	96%	1%	3%	-

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

Revenue: Consolidated revenue increased by 48% to $258.2 million in 3Q2022, compared to $174.0 million in 3Q2021, reflecting higher oil and gas prices and higher deliveries.

Sales of crude oil: Consolidated oil revenue increased by 52% to $248.7 million in 3Q2022, driven by a 42% increase in realized oil prices and 6% higher oil deliveries. Oil revenue was 96% of total revenue in 3Q2022 and 94% in 3Q2021.

(In millions of $)	3Q2022	3Q2021
Colombia	243.6	156.1
Chile	3.0	1.5
Argentina	-	5.7
Brazil	0.2	0.2
Ecuador	1.9	-
Oil Revenue	248.7	163.5

Colombia: 3Q2022 oil revenue increased by 56% to $243.6 million, reflecting higher realized oil prices and higher oil deliveries. Realized prices increased by 42% to $85.7 per bbl due to higher Brent oil prices while oil deliveries increased by 10% to 32,071 bopd. Earn-out payments increased to $9.3 million in 3Q2022, compared to $6.0 million in 3Q2021 in line with higher oil prices.
Chile: 3Q2022 oil revenue increased by 96% to $3.0 million, reflecting higher realized prices and higher oil deliveries. Realized prices increased by 46% to $93.4 per bbl due to higher Brent oil prices while oil deliveries increased by 34% to 345 bopd.
Ecuador: 3Q2022 oil revenue totaled $1.9 million, reflecting a realized oil price of $93.0 with deliveries of 227 bopd. Deliveries recorded in Ecuador are net of the Government's production share.

Sales of purchased crude oil: 3Q2022 sales of purchased crude oil totaled $1.0 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).

Sales of gas: Consolidated gas revenue decreased by 18% to $8.6 million in 3Q2022 compared to $10.5 million in 3Q2021 reflecting 24% lower gas deliveries, partially offset by 9% higher gas prices. Gas revenue was 3% and 6% of total revenue in 3Q2022 and 3Q2021, respectively.

(In millions of $)	3Q2022	3Q2021
Chile	4.2	4.1
Brazil	4.3	4.6
Argentina	-	1.3
Colombia	0.1	0.5
Gas Revenue	8.6	10.5

Chile: 3Q2022 gas revenue increased by 3% to $4.2 million, reflecting higher gas prices, partially offset by lower gas deliveries. Gas prices were 5% higher, at $3.9 per mcf ($23.1 per boe) in 3Q2022. Gas deliveries fell by 2% to 11,753 mcfpd (1,959 boepd).
Brazil: 3Q2022 gas revenue decreased by 7% to $4.3 million, due to lower gas deliveries, partially offset by higher gas prices. Gas deliveries decreased by 11% from the Manati gas field to 8,630 mcfpd (1,438 boepd). Gas prices increased by 5% to $5.4 per mcf ($32.5 per boe) in 3Q2022.

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to a $23.0 million gain in 3Q2022, compared to a $11.7 million loss in 3Q2021.

The table below provides a breakdown of realized and unrealized commodity risk management contracts in 3Q2022 and 3Q2021:

(In millions of $)	3Q2022	3Q2021
Realized loss	(13.8)	(22.4)
Unrealized loss	36.8	10.6
Commodity risk management contracts	23.0	(11.7)

The realized portion registered a loss of $13.8 million in 3Q2022 compared to a $22.4 million loss in 3Q2021. Realized losses in 3Q2022 reflected hedges with average ceiling prices below actual Brent oil prices during the quarter.

The unrealized portion registered a gain of $36.8 million in 3Q2022, compared to a $10.6 million gain in 3Q2021. Unrealized gains in 3Q2022 mainly resulted from reclassifications to realized losses, combined with movements in the forward Brent oil price curve at September 30, 2022, compared to June 30, 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 Costs⁸: Consolidated production and operating costs increased to $87.1 million from $49.2 million, mainly resulting from a $31.6 million increase in royalties and economic rights, due to higher oil and gas prices.

The table below provides a breakdown of production and operating costs in 3Q2022 and 3Q2021:

(In millions of $)	3Q2022	3Q2021
Royalties	(15.5)	(10.9)
Economic rights	(47.0)	(20.0)
Operating costs	(23.6)	(18.2)
Purchased crude oil	(0.7)	-
Share-based payments	(0.3)	(0.1)
Production and operating costs	(87.1)	(49.2)

Consolidated royalties amounted to $15.5 million in 3Q2022 compared to $10.9 million in 3Q2021, in line with higher oil prices.

Consolidated economic rights (including high price participation, x-factor and other economic rights paid to the Government) amounted to $47.0 million in 3Q2022 compared to $20.0 million in 3Q2021, in line with higher oil prices.

Consolidated operating costs increased to $23.6 million in 3Q2022 compared to $18.2 million in 3Q2021, mainly resulting from higher deliveries and higher operating costs per boe in Colombia, Chile and Brazil, and the addition of operating costs coming from Ecuador, partially offset by the divestment of the Aguada Baguales, Puesto Touquet and El Porvenir blocks in Argentina (completed in January 2022).

The breakdown of operating costs is as follows:

Colombia: Total operating costs increased to $19.4 million in 3Q2022 from $11.9 million in 3Q2021, mainly due to due to higher operating costs per boe resulting from increased activity levels and higher deliveries (deliveries in Colombia increased by 9%). However, compared to 2Q2022, total operating costs decreased by 9%.
Chile: Total operating costs increased to $2.6 million in 3Q2022 from $2.2 million in 3Q2021, in line with higher operating costs per boe and higher oil and gas deliveries (deliveries in Chile increased by 2%).
Brazil: Total operating costs remained flat at $0.8 million in 3Q2022 compared to $0.8 million in 3Q2021, due to lower gas deliveries in the Manati field (deliveries in Brazil decreased by 11%), offset by higher operating costs per boe.
Ecuador: Total operating costs were $0.6 million in 3Q2022.
Argentina: The divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks was completed in January 2022. The comparative period, 3Q2021, included $3.3 million in operating costs.

Consolidated purchased crude oil charges amounted to $0.7 million in 3Q2022, 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 increased to $2.0 million in 3Q2022 compared to $1.8 million in 3Q2021.

Geological & Geophysical Expenses: Consolidated G&G expenses increased to $2.3 million in 3Q2022 compared to $2.1 million in 3Q2021.

Administrative Expenses: Consolidated G&A increased to $14.3 million in 3Q2022 compared to $11.8 million in 3Q2021.

Adjusted EBITDA: Consolidated Adjusted EBITDA⁹ increased by 63% to $141.3 million, or $42.4 per boe, in 3Q2022 compared to $86.8 million, or $26.9 per boe, in 3Q2021.

(In millions of $)	3Q2022	3Q2021
Colombia	139.1	83.1
Chile	3.6	2.7
Brazil	2.5	2.9
Argentina	(1.6)	2.2
Ecuador	0.7	(0.4)
Corporate	(3.0)	(3.7)
Adjusted EBITDA	141.3	86.8

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 3Q2022 and 3Q2021, on a per boe basis:

Adjusted EBITDA/boe	Colombia		Chile		Brazil		Ecuador		Total^d
	3Q22	3Q21	3Q22	3Q21	3Q22	3Q21	3Q22	3Q21	3Q22	3Q21
Production (boepd)	33,338	31,565	2,425	2,354	1,439	1,791	1,194	-	38,396	37,859
Inventories, RIK^a& Other	(1,212)	(2,102)	(121)	(91)	19	(147)	(967)	-	(2,175)	(2,746)
Sales volume (boepd)	32,126	29,463	2,304	2,263	1,458	1,644	227	-	36,221	35,113
% Oil	99.8%	99.3%	15%	11%	1%	1%	100%	-	90%	87%
($ per boe)
Realized oil price	85.7	60.3	93.4	64.0	100.1	71.2	93.0	-	85.9	60.3
Realized gas price^c	27.1	27.0	23.1	22.0	32.5	31.1	-	-	27.1	25.0
Earn-out	(3.2)	(2.2)	-	-	-	-	-	-	(2.8)	(1.9)
Combined Price	82.5	57.8	33.7	26.8	33.4	31.6	93.0	-	77.5	53.8
Realized commodity risk management contracts	(4.7)	(8.2)	-	-	-	-	-	-	(4.2)	(6.9)
Operating costs^e	(6.7)	(5.3)	(12.4)	(10.6)	(8.7)	(7.6)	(30.7)	-	(7.3)	(6.5)
Royalties & economic rights	(21.0)	(10.5)	(1.3)	(0.9)	(2.6)	(2.7)	0.0	-	(18.8)	(9.3)
Purchased crude oil^b	-	-	-	-	-	-	-	-	(0.3)	-
Selling & other expenses	(0.5)	(0.1)	(0.4)	(0.4)	(0.0)	(0.0)	(19.6)	-	(0.6)	(0.2)
Operating Netback/boe	49.6	33.6	19.6	14.8	22.1	21.4	42.7	-	46.4	30.8
G&A, G&G & other									(4.0)	(4.0)
Adjusted EBITDA/boe									42.4	26.9

a)		RIK (Royalties in kind). Includes royalties paid in kind in Colombia for approximately 911 bopd and 1,213 bopd in 3Q2022 and 3Q2021, 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 decreased by 9% to $21.4 million in 3Q2022 compared to $23.6 million in 3Q2021, mainly resulting from the divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina, with higher depreciation costs per boe.

Write-off of unsuccessful exploration efforts: The consolidated write-off of unsuccessful exploration efforts amounted to $5.9 million in 3Q2022 compared to $4.2 million in 3Q2021. Amounts recorded in 3Q2022 correspond to exploration costs incurred in previous years in the Tacacho and Terecay blocks (Putumayo basin in Colombia) and an exploratory well drilled in the CPO-5 Block (Llanos basin in Colombia).

Other Income (Expenses): Other operating expenses showed a $2.6 million loss in 3Q2022, compared to a $1.6 million loss in 3Q2021.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses remained flat at $13.3 million in 3Q2022 and 3Q2021, mainly resulting from borrowing cancellation costs of $2.1 million recorded in 3Q2022 associated with gross debt reductions during the quarter, offset by lower interest costs resulting from a sustained deleveraging process that started in April 2021 and continued in 2022.

Foreign Exchange: Net foreign exchange gains amounted to $11.5 million in 3Q2022 compared to $1.0 million in 3Q2021. Gains recorded in 3Q2022 mainly resulted from the devaluation of the Colombian peso and its effect on liabilities in local currency.

Income Tax: Income taxes totaled $70.2 million in 3Q2022 compared to $31.9 million in 3Q2021, mainly resulting from higher profits before income taxes and the effect of fluctuations of the Colombian peso over deferred income taxes.

Net Profit: Profit increased by 98% to a $73.4 million gain in 3Q2022 compared to a $37.0 million gain in 3Q2021.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $93.0 million as of September 30, 2022, compared to $100.6 million as of December 31, 2021.

This net decrease is explained by the following:

(In millions of $)			9M2022
Cash flows from operating activities			354.1
Cash flows used in investing activities			(100.1)
Cash flows used in financing activities			(262.4)
Currency Translation			0.8
Net decrease in cash & cash equivalents			(7.6)

Cash flows used in investing activities included $115.2 million in capital expenditures incurred by the Company as part of its 2022 work program, partially offset by proceeds from the disposal of assets that amounted to $15.1 million.

Cash flows used in financing activities mainly included $180.4 million related to repurchases and redemptions of the 2024 Notes (including borrowing cancellation costs and other costs paid), $36.5 million related to interest payments, $23.1 million related to executing the Company's share buyback program and $17.0 million related to dividend payments.

Financial Debt: Total financial debt net of issuance cost was $491.1 million, including the 2027 Notes and other bank loans for $1.2 million. Short-term financial debt was $6.8 million as of September 30, 2022.

(In millions of $)	September 30, 2022	December 31, 2021
2024 Notes	-	171.9
2027 Notes	489.9	499.9
Other bank loans	1.2	2.3
Financial debt	491.1	674.1

During 9M2022, the Company significantly reduced its gross debt through repurchases and the redemption of its 2024 Notes.

For further details, please refer to Note 12 of GeoPark's consolidated financial statements as of September 30, 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
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
3Q2022	491.1	93.0	398.1	0.8x	12.7x

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

Covenants in the 2027 Notes: The 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 September 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
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	8,500	69.1	113.1
3Q2023	Zero cost collar	Brent	2,000	70.0	101.1

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

SELECTED INFORMATION BY BUSINESS SEGMENT


Colombia (In millions of $)	3Q2022	3Q2021
Sale of crude oil	243.6	156.1
Sale of gas	0.1	0.5
Revenue	243.7	156.7
Production and operating costs^a	(81.6)	(41.2)
Adjusted EBITDA	139.1	83.1
Capital expenditure	36.7	30.4

Chile (In millions of $)	3Q2022	3Q2021
Sale of crude oil	3.0	1.5
Sale of gas	4.2	4.1
Revenue	7.1	5.6
Production and operating costs^a	(2.9)	(2.4)
Adjusted EBITDA	3.6	2.7
Capital expenditure	0.2	0.1

Brazil (In millions of $)	3Q2022	3Q2021
Sale of crude oil	0.2	0.2
Sale of gas	4.3	4.6
Revenue	4.5	4.8
Production and operating costs^a	(1.2)	(1.2)
Adjusted EBITDA	2.5	2.9
Capital expenditure	0.0	0.0

Ecuador (In millions of $)	3Q2022	3Q2021
Sale of crude oil	1.9	-
Sale of gas	0.0	-
Revenue	1.9	-
Production and operating costs^a	(0.6)	-
Adjusted EBITDA	0.7	(0.4)
Capital expenditure	6.4	0.2

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

CONSOLIDATED STATEMENT OF INCOME (QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	3Q2022	3Q2021	9M2022	9M2021
REVENUE
Sale of crude oil	248.7	163.5	784.1	454.6
Sale of purchased crude oil	1.0	-	6.3	-
Sale of gas	8.6	10.5	28.2	31.5
TOTAL REVENUE	258.2	174.0	818.6	486.2
Commodity risk management contracts	23.0	(11.7)	(70.7)	(106.7)
Production and operating costs	(87.1)	(49.2)	(282.8)	(145.2)
Geological and geophysical expenses (G&G)	(2.3)	(2.1)	(8.0)	(7.2)
Administrative expenses (G&A)	(14.3)	(11.8)	(35.1)	(35.8)
Selling expenses	(2.0)	(1.8)	(5.2)	(5.3)
Depreciation	(21.4)	(23.6)	(66.2)	(66.8)
Write-off of unsuccessful exploration efforts	(5.9)	(4.2)	(5.9)	(12.3)
Impairment loss on non-financial assets	-	13.3	-	13.3
Other	(2.6)	(1.6)	2.7	(3.7)
OPERATING PROFIT	145.4	81.3	347.4	116.4

Financial costs, net	(13.3)	(13.3)	(44.0)	(49.4)
Foreign exchange gain	11.5	1.0	12.0	5.4
PROFIT BEFORE INCOME TAX	143.6	68.9	315.4	72.4

Income tax	(70.2)	(31.9)	(143.1)	(48.2)
PROFIT FOR THE PERIOD	73.4	37.0	172.2	24.2

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION (QUARTERLY INFORMATION UNAUDITED)

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

Non-Current Assets
Property, plant and equipment	658.6	614.0
Other non-current assets	55.6	49.2
Total Non-Current Assets	714.2	663.2

Current Assets
Inventories	12.5	10.9
Trade receivables	59.0	70.5
Other current assets	24.0	50.6
Cash at bank and in hand	93.0	100.6
Total Current Assets	188.5	232.6

Total Assets	902.7	895.7

Total Equity	82.5	(61.9)

Non-Current Liabilities
Borrowings	484.3	656.2
Other non-current liabilities	131.1	97.8
Total Non-Current Liabilities	615.4	754.0

Current Liabilities
Borrowings	6.8	17.9
Other current liabilities	197.9	185.7
Total Current Liabilities	204.8	203.7
Total Liabilities	820.1	957.7
Total Liabilities and Equity	902.7	895.7

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOW (QUARTERLY INFORMATION UNAUDITED)

(In millions of $)	3Q2022	3Q2021	9M2022	9M2021

Cash flow from operating activities	141.1	49.9	354.1	128.8
Cash flow used in investing activities	(42.6)	(30.7)	(100.1)	(84.3)
Cash flow used in financing activities	(127.5)	(27.1)	(262.4)	(169.0)

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT BEFORE INCOME TAX

9M2022 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other^(a)	Total
Adjusted EBITDA	401.1	9.1	10.0	(5.4)	(6.0)	408.7
Depreciation	(52.8)	(10.9)	(2.2)	(0.2)	(0.0)	(66.2)
Unrealized commodity risk management contracts	10.3	-	-	-	-	10.3
Write-off of unsuccessful exploration efforts	(5.9)	-	-	-	-	(5.9)
Share based payment	(1.2)	(0.2)	(0.0)	(0.2)	(5.9)	(7.6)
Lease Accounting - IFRS 16	3.4	0.8	1.1	0.1	0.0	5.4
Others	1.6	0.5	0.4	5.1	(4.9)	2.7
OPERATING PROFIT (LOSS)	356.4	(0.7)	9.2	(0.7)	(16.8)	347.4
Financial costs, net						(44.0)
Foreign exchange charges, net						12.0
PROFIT BEFORE INCOME TAX						315.4

9M2021 (In millions of $)	Colombia	Chile	Brazil	Argentina	Other^(a)	Total
Adjusted EBITDA	204.7	5.8	9.7	4.9	(11.4)	213.7
Depreciation	(44.1)	(10.7)	(3.1)	(8.8)	(0.2)	(66.8)
Unrealized commodity risk management contracts	(28.0)	0.0	0.0	0.0	0.0	(28.0)
Write-off of unsuccessful exploration efforts & impairment	(7.8)	(4.4)	0.0	13.3	0.0	1.0
Share based payment	(0.6)	(0.1)	0.0	(0.1)	(4.9)	(5.7)
Lease Accounting - IFRS 16	3.1	0.5	1.2	0.6	0.2	5.6
Others	(0.8)	(0.1)	(0.2)	(1.6)	(0.8)	(3.4)
OPERATING PROFIT (LOSS)	126.5	(9.0)	7.7	8.2	(17.1)	116.4
Financial costs, net						(49.4)
Foreign exchange charges, net						5.4
PROFIT BEFORE INCOME TAX						72.4

(a)

Includes Ecuador and Corporate.

The Company is unable to present a quantitative reconciliation of the 2023 Adjusted EBITDA which is a forward-looking non-GAAP measure, because the Company cannot reliably predict certain of its components. Since free cash flow is calculated based on Adjusted EBITDA, for similar reasons, the Company does not provide a quantitative reconciliation of the 2023 free cash flow.

CONFERENCE CALL INFORMATION

Reporting Date, Conference Call & Webcast for 3Q2022 financial results, and 2023 Work Program and Shareholder Return Framework

In conjunction with the 3Q2022 results press release, GeoPark management will host a conference call on November 10, 2022, at 10:00 am (Eastern Daylight Time) to discuss the 3Q2022 financial results, and the work program and shareholder return framework for 2023.

To listen to the call, participants can access the webcast located in the Invest with Us section of the Company's website at www.geo-park.com, or by clicking below:

https://events.q4inc.com/attendee/960192027

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: 648171

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 Invest with Us 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

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 Invest with Us 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, including Adjusted EBITDA, expected free cash flow and shareholder returns, dividends and buybacks forecasts, timing, method and amount of share repurchases, operating netback, future opportunities, our deleveraging process, our dividend or other distributions, capital return yield, and our 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, and operating netback per boe may not be comparable to other similarly titled measures of other companies.

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

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

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

¹		Percentages are calculated adjusting for divestments in Argentina in 3Q2021.
²		Free cash flow is used here as Adjusted EBITDA less capital expenditures, mandatory interest payments and cash taxes.
³		Brent oil price assumption corresponds to October to December 2022.
⁴		Calculated using GeoPark's average market capitalization from July 1 to October 31, 2022.
⁵		Annualized and calculated using GeoPark's market capitalization from July 1 to October 31, 2022.
⁶		Free cash flow is used here as Adjusted EBITDA less capital expenditures, mandatory interest payments and cash taxes. 2023 cash taxes include GeoPark's preliminary estimates of the full impact of the new tax reform in Colombia, irrespective of the timing of its cash impact, expected in 2023 or early 2024. The Company is unable to present a quantitative reconciliation of the 2023 Adjusted EBITDA which is a forward-looking non-GAAP measure, because the Company cannot reliably predict certain of the necessary components, such as write-off of unsuccessful exploration efforts or impairment loss on non-financial assets, etc. Since free cash flow is calculated based on Adjusted EBITDA, for similar reasons, the Company does not provide a quantitative reconciliation of the 2023 free cash flow forecast.
⁷		The divestment of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina was completed on January 31, 2022.
⁸		Operating costs per boe represents the figures used in Adjusted EBITDA calculation with certain adjustments to the reported figures.
⁹		See "Reconciliation of Adjusted EBITDA to Profit Before Income Tax" included in this press release.

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