FRONTERA ANNOUNCES FOURTH QUARTER AND YEAR END 2023 RESULTS

Recorded Full Year Net Income of $193.5 Million, Including $92.0 Million in Q4’23

Delivered Full Year Average Daily Production of 40,919 Boe/d

Generated Full Year Operating EBITDA of $467.2 Million

Generated Full Year Adjusted Infrastructure EBITDA of $119.8 Million and Segment Income of $69.3 Million

Declared Quarterly Dividend of C$0.0625 Per Share, Or $3.9 Million in Aggregate, Payable on or around April 16, 2024

Recorded 164.1 Million Boe 2P Gross Reserves and 108.7 Million 1P Gross Reserves

$3.5 Billion 2P Net Present Value Before Tax Discounted At 10% As At December 31, 2023

7.3 Year 1P and 11.0 Year 2P Gross Reserves Life Index

514-628 Mmboe PMean Unrisked Gross Prospective Resources Estimated in Maastrichtian Horizons in the Northern Portion of the Corentyne Block

Commissioned First Solar Farm, Offset 50% of Emissions Through Carbon Credits, and Preserved and Restored 1,681 New Hectares in Casanare and Meta, Colombia

CALGARY, AB, March 7, 2024 /PRNewswire/ – Frontera Energy Corporation (TSX: FEC) (“Frontera” or the “Company”) today reported financial and operational results for the fourth quarter and year ended December 31, 2023, and announced the results of its annual independent reserves assessment conducted by DeGolyer and MacNaughton Corp (“D&M”). All financial amounts in this news release and the Company’s financial disclosures are in United States dollars, unless otherwise stated. All of the Company’s booked reserves for the year ended December 31, 2023, are located in Colombia and Ecuador.

Gabriel de Alba, Chairman of the Board of Directors, commented:

“During 2023, Frontera continued to take concrete steps to deliver significant value to shareholders. The Company delivered EBITDA of $467MM, at the higher end of guidance for 2023, closing the year with a strong balance sheet including $190 million cash position, and having a fully funded plan for 2024.

Our significant Infrastructure business generated Adjusted Infrastructure EBITDA of approximately $120 million and keeps building momentum following the announcement of the connection agreement between Refineria de Cartagena S.A.S (“Reficar”) and Puerto Bahia’s liquids terminal. On its Guyana exploration business, Frontera, and its JV partner CGX Energy Inc. (“CGX”) with support from Houlihan Lokey, is pursuing a review of strategic options, including a farm down of its interest in Offshore Guyana, following the announcement of a second discovery in the Corentyne block. Lastly, the Company during the 4^th quarter of 2023 renewed its normal course issuer bid (“NCIB”) program and repurchased approximately 741,700 Common Shares for cancellation, returning $5.9 million to shareholders in 2023.

Frontera recently announced the initiation of a new quarterly dividend and remains committed to enhancing shareholder returns. The Company will continue to consider future shareholder value enhancement initiatives in 2024 and beyond, including potential additional dividends, distributions, or bond buybacks, based on the overall results of our businesses and strategic goals.”

Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented:

“Frontera successfully achieved its strategic, capital and production targets across the Company’s three core businesses in 2023:

Through our Colombia and Ecuador Upstream onshore business, we delivered average daily production of 40,919 boe/d, with an increase to our heavy crude oil production of 9% year over year, while maintaining our production costs, transportation costs and capital expenditures within guidance.

Our commitment to sustained production and value over volumes continues to be supported by our upstream Colombia and Ecuador reserves which closed the year with 108.7 million and 164.1 million boe in 1P and 2P gross reserves, respectively. Achieved a three-year average gross Reserves Replacement Ratio of 79% for 2P Reserves and 104% for 1P reserves, while maintaining a Reserve Life index of 7.3 Years for 1P reserves and 11.0 Years for 2P reserves, and a significant 2P net present value of $3.5 billion before tax discounted at 10%.

In our standalone and growing infrastructure business, we generated full year Adjusted Infrastructure EBITDA of approximately $120 million. ODL transported over 243,000 bbl/day, generated $285 million in full year EBITDA and distributed over $135 million to its shareholders. Proportional to its 35% interest, the Company received $47 million in capital distributions and Frontera’s Adjusted Infrastructure EBITDA benefited from $100 million associated with ODL’s EBITDA. Puerto Bahia generated approximately $20 million in operating EBITDA, reached a connection agreement, started pre-construction activities with Reficar, and successfully refinanced its existing legacy project finance debt with room to grow.

In our potentially transformational Guyana exploration business, as announced in the December 11th, 2023 news release, we successfully completed the second well of our two-well program, where we believe that approximately 514-628 mmboe PMean unrisked gross prospective resources are present in multiple Maastrichtian horizons in the northern portion of the Corentyne block.

Frontera is committed to sustainability and achieved 108% of its 2023 ESG goals. We started the operation of our first solar farm named “Ikotia” in December which we expect will reduce CPE-6 power consumption from the grid and offset 50% of the block’s scope 1 emissions.

As we turn now to 2024, we remain focused on executing our recently announced 2024 plan and continuing to deliver sustainable value-focused production, strong operational and financial results, and driving shareholder returns.”

Fourth Quarter and Full Year 2023 Operational and Financial Summary

					Year ended December 31
		Q4 2023	Q3 2023	Q4 2022	2023	2022
Operational Results
Heavy crude oil production ⁽¹⁾	(bbl/d)	23,002	24,097	22,144	23,359	21,441
Light and medium crude oil combined production ⁽¹⁾	(bbl/d)	13,795	13,964	17,073	14,856	17,274
Total crude oil production	(bbl/d)	36,797	38,061	39,217	38,215	38,715
Conventional natural gas production ⁽¹⁾	(mcf/d)	4,760	5,250	9,097	6,042	9,741
Natural gas liquids production ⁽¹⁾	(boe/d)	1,635	1,820	993	1,644	958
Total production ⁽²⁾	(boe/d) ⁽³⁾	39,267	40,802	41,806	40,919	41,382
Total inventory balance	(bbl)	1,076,394	1,330,418	1,238,780	1,076,394	1,238,780
Brent price reference	($/bbl)	82.85	85.92	88.63	82.17	99.04
Oil and gas sales, net of purchases ^{(4) (5)}	($/boe)	75.76	78.48	82.60	72.93	91.39
Premiums paid on oil price risk management contracts ⁽⁶⁾	($/boe)	(0.69)	(0.59)	(1.32)	(0.80)	(1.22)
Royalties ⁽⁶⁾	($/boe)	(1.79)	(3.76)	(6.04)	(2.98)	(7.83)
Net sales realized price ^{(4) (5)}	($/boe)	73.28	74.13	75.24	69.15	82.34
Production costs (excluding energy cost), net of realized FX hedge impact ⁽⁴⁾⁽⁵⁾	($/boe)	(9.69)	(8.82)	(8.48)	(8.76)	(8.79)
Energy costs, net of realized FX hedge impact ⁽⁴⁾⁽⁵⁾	($/boe)	(5.06)	(5.04)	(3.08)	(4.49)	(3.35)
Transportation costs, net of realized FX hedge impact ⁽⁴⁾⁽⁵⁾	($/boe)	(11.02)	(11.73)	(10.55)	(11.21)	(10.44)
Operating netback per boe ⁽⁴⁾⁽⁵⁾	($/boe)	47.51	48.54	53.13	44.69	59.76
Financial Results
Oil & gas sales, net of purchases ⁽⁷⁾	($M)	240,105	254,805	260,824	905,249	1,105,503
Premiums paid on oil price risk management contracts	($M)	(2,198)	(1,930)	(4,182)	(9,903)	(14,733)
Royalties	($M)	(5,683)	(12,216)	(19,076)	(36,949)	(94,709)
Net sales ⁽⁷⁾	($M)	232,224	240,659	237,566	858,397	996,061
Net income ⁽⁸⁾	($M)	92,038	32,582	197,796	193,497	286,615
Per share – basic	($)	1.08	0.38	2.29	2.27	3.16
Per share – diluted	($)	1.04	0.37	2.25	2.19	3.08
General and administrative	($M)	16,891	11,925	12,761	53,907	55,063
Outstanding Common Shares	Number of Shares	85,151,216	85,431,716	85,592,075	85,151,216	85,592,075
Operating EBITDA ⁽⁷⁾	($M)	121,036	137,800	144,994	467,219	641,877
Cash provided by operating activities	($M)	73,432	153,957	138,312	411,794	620,479
Capital expenditures ⁽⁷⁾	($M)	82,292	74,130	134,165	442,734	417,563
Cash and cash equivalents – unrestricted	($M)	159,673	189,190	289,845	159,673	289,845
Restricted cash short and long-term ⁽⁹⁾	($M)	30,300	32,048	23,202	30,300	23,202
Total cash ⁽⁹⁾	($M)	189,973	221,238	313,047	189,973	313,047
Total debt and lease liabilities ⁽⁹⁾	($M)	536,822	525,517	511,552	536,822	511,552
Consolidated total indebtedness (excluding Unrestricted Subsidiaries) ⁽¹⁰⁾	($M)	430,170	409,853	407,808	430,170	407,808
Net debt (excluding Unrestricted Subsidiaries) ⁽¹⁰⁾	($M)	318,092	271,508	178,534	318,092	178,534

⁽¹⁾ References to heavy crude oil, light and medium crude oil combined, conventional natural gas and natural gas liquids in the above table and elsewhere in this news release refer to the heavy crude oil, light crude oil and medium crude oil combined, conventional natural gas and natural gas liquids, respectively, product types as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“).

⁽²⁾ Represents W.I. production before royalties. Refer to the “Further Disclosures” section on page 44 of the Company’s MD&A for the fiscal year ended December 31, 2023 (the “MD&A).

⁽³⁾ Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy. Refer to the “Further Disclosures – Boe Conversion” section on page 44 of the MD&A.

⁽⁴⁾ Non-IFRS ratio (equivalent to a “non-GAAP ratio”, as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure (“NI 52-112” ). Refer to the “Non-IFRS and Other Financial Measures” section on page 27 of the MD&A.

⁽⁵⁾ 2022 prior period figures are different compared with those previously reported as a result of the exclusion of Promotora Agricola de los Llanos S.A. (“ProAgrollanos“) revenues and, production and transportation costs.

⁽⁶⁾ Supplementary financial measure (as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section on page 27 of the MD&A.

⁽⁷⁾ Non-IFRS financial measure (equivalent to a “non-GAAP financial measure”, as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section on page 27 of the MD&A.

⁽⁸⁾ Net income (loss) attributable to equity holders of the Company.

⁽⁹⁾ Capital management measure (as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section on page 27 of the MD&A.

⁽¹⁰⁾ “Unrestricted Subsidiaries” include CGX Energy Inc.(“CGX“), listed on the TSX Venture Exchange under the trading symbol “OYL”, Frontera ODL Holding Corp., including its subsidiary Pipeline Investment Ltd. (“PIL“), Frontera BIC Holding Ltd. and Frontera Bahía Holding Ltd. (“Frontera Bahia“), including its subsidiary Sociedad Portuaria Puerto Bahia S.A (“Puerto Bahia“). On April 11, 2023, Frontera Energy Guyana Holding Ltd. and Frontera Energy Guyana Corp. were designated as unrestricted subsidiaries. Refer to the “Liquidity and Capital Resources” section on page 33 of the MD&A.

Fourth Quarter and Full Year Operational and Financial Results:

The Company recorded net income of $92.0 million or $1.04/share in the fourth quarter of 2023, compared with net income of $32.6 million or $0.37/share in the prior quarter and net income of $197.8 million or $2.25/share in the fourth quarter of 2022. For the year ended December 31, 2023, the Company reported net income of $193.5 million, compared to net income of $286.6 million for the year ended December 31, 2022.
Production averaged 39,267 boe/d in the fourth quarter 2023 (consisting of 23,002 bbl/d of heavy crude oil, 13,795 bbl/d of light and medium crude oil combined, 4,760 mcf/d of conventional natural gas and 1,635 boe/d of natural gas liquids) compared to 40,802 boe/d in the prior quarter and 41,806 boe/d in the fourth quarter of 2022, lower production during the quarter was a result of lower planned drilling and workover activity in the fourth quarter, natural decline, and unplanned maintenance on an injector well in Quifa. In 2023, Frontera’s production averaged 40,919 boe/d (consisting of 23,359 bbl/d of heavy crude oil, 14,856 bbl/d of light and medium crude oil combined, 6,042 mcf/d of conventional natural gas and 1,644 boe/d of natural gas liquids), within the Company’s 2023 guidance of 40,000-43,000 boe/d.
Operating EBITDA was $121.0 million in the fourth quarter of 2023 compared with $137.8 million in the prior quarter and $145.0 million in the fourth quarter of 2022. The decrease in operating EBITDA quarter over quarter was primarily a result of lower commodity prices and lower volumes sold in the fourth quarter. Frontera’s weighted average Brent price was $81.88/bbl in 2023, generating $467.2 million of EBITDA.
Cash provided by operating activities in the fourth quarter of 2023 was $73.4 million, compared with $154.0 million in the prior quarter and $138.3 million in the fourth quarter of 2022. The decrease quarter over quarter was primarily due to changes in working capital mainly related to income taxes withheld, lower commodity prices and volumes sold.
The Company reported a total cash position of $190.0 million at December 31, 2023, compared to $221.2 million at September 30, 2023 and $313.0 million at December 31, 2022. The Company generated $411.8 million of cash from operations in 2023, compared to $620.5 million in 2022. During the year, the Company primarily invested $442.7 million in capital expenditures, including $153.7 million related to the Wei-1, $12.7 million related to the acquisition of the IFC interest on ODL, $56.9 million in net debt service payments and $5.9 million in share buyback.
As at December 31, 2023, the Company had a total crude oil inventory balance of 1,076,394 bbls compared to 1,330,418 bbls at September 30, 2023. As of December 31, 2023, the Company had a total inventory balance in Colombia of 551,715 barrels, including 322,639 crude oil barrels and 229,076 barrels of diluent and others. This compared to 812,797 as of September 30, 2023, and 683,416 barrels as at December 31, 2022. The decrease in inventory balance was primarily due to inventory drawn for export sales. Inventory balances in the fourth quarter related to Ecuador and Peru were 44,479 barrels and 480,200 barrels, respectively.
Capital expenditures were approximately $82.3 million in the fourth quarter of 2023, compared with $74.1 million in the prior quarter and $134.2 million in the fourth quarter of 2022. During the fourth quarter, the Company drilled 14 development wells at its Quifa SW, Cajua and CPE-6 blocks as well as one exploration well, Perico Norte-A4 on the Perico block in Ecuador. For the full year 2023, the Company executed approximately $442.7 million in total capital spending, including $157.3 million in total capital spending related to the Wei-1 well, within its 2023 capital guidance of $420-475 million and compared to $417.6 million in 2022.
The Company’s net sales realized price was $73.28/boe in the fourth quarter of 2023, compared to $74.13/boe in the prior quarter and $75.24/boe in the fourth quarter of 2022. The decrease in net sales realized price quarter-over-quarter was primarily driven by the decrease in Brent benchmark oil price compared with the previous quarter, partially offset by lower royalties. The Company’s net sales realized price in 2023 was $69.15/boe, compared to $82.34/boe in 2022.
The Company’s operating netback was $47.51/boe in the fourth quarter of 2023, compared with $48.54/boe in the prior quarter and $53.13/boe in the fourth quarter of 2022. The decrease in operating netback quarter-over-quarter was primarily due to a lower net sales realized price and, higher production costs, resulting from higher well services activity costs and higher energy costs. The Company’s operating netback for the year ended December 31, 2023, was $44.69/boe, compared to $59.76/boe in 2022.
Production costs (excluding energy cost), net of realized FX hedge impact, averaged $9.69/boe in the fourth quarter of 2023, compared with $8.82/boe in the prior quarter and $8.48/boe in the fourth quarter of 2022. The increase quarter over quarter was due to higher technical assistance and maintenance costs, partially offset by lower cost associated to well services activities. Frontera’s total production costs, including energy cost, net of realized FX hedge impact, averaged $13.25/boe in 2023, within the Company’s 2023 guidance range of $12.50–$13.50/boe.
Transportation costs averaged $11.02/boe in the fourth quarter of 2023, compared with $11.73/boe in the prior quarter and up from $10.55/boe in the fourth quarter of 2022. The decrease during the quarter was mainly due to an increase in local sales volumes to the thermal market. Frontera’s transportation costs averaged $11.21/boe in 2023, within the Company’s 2023 guidance range of $10.50–$11.50/boe.
Total ODL volumes transported were 252,810 bbl/d during the fourth quarter of 2023, up 13% versus the fourth quarter of 2022. Total volumes transported through ODL for 2023 were 243,617 and received capital distributions of $47 million during the year.
Puerto Bahia liquids volumes were 52,754 bbl/d during the fourth quarter down 21% compared to the third quarter of 2022, driven mainly by lower imported crude volumes, and 60,718 bbl/d for the full year 2023 compared to 62,422 bbl/d in 2022. Puerto Bahia liquids revenues were $7.6 million during the fourth quarter, up 12% compared to the fourth quarter of 2022, mainly due to higher tariffs. For the full year 2023, Puerto Bahia liquids revenues were $32.1 million compared to $29.6 million in 2022, mainly due to higher tariffs.
Adjusted Infrastructure EBITDA in the fourth quarter of 2023 was $30.7 million, compared with $26.6 million in the fourth quarter of 2022, and $119.8 million for the full year 2023.
In the Company’s exciting Guyana Exploration business, the discovery of 228 feet of net pay in Kawa-1 and 114 feet of net pay in Wei-1, on North Corentyne was confirmed. Results further demonstrate the potential for a standalone shallow oil resource development across the Corentyne block.
Total costs associated for the Wei-1 well are now estimated to be $189 million following the successful implementation of several cost saving initiatives. Frontera’s direct and indirect WI in the Corentyne block is estimated at up to 72.52% and 93.42%, respectively.
During the fourth quarter of 2023, the Company repurchased for cancellation 280,500 Common Shares at a cost of approximately $1.7 million.

2023 Year End Reserves Evaluation

Frontera announced the results of its annual independent reserves assessment for the year ended December 31, 2023, conducted by DeGolyer and MacNaughton Corp (“D&M”) in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) (the “COGE Handbook“), National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“) and CSA Staff Notice 51-324, and are based on the Reserves Report (as defined below). All of the Company’s booked reserves for the year ended December 31, 2023, are located in Colombia and Ecuador.

Key Highlights:

Added 4.2 MMboe of 2P gross reserves, for total Company 2P gross reserves of 164.1 MMboe consisting of 64% heavy crude oil, 24% light and medium crude oil, 8% conventional natural gas and 4% natural gas liquids, compared to 174.8 MMboe at December 31, 2022.
2023 year-end gross proved developed producing reserves increased by 2% to 40.0 MMboe and the proved developed producing reserves replacement ratio was 105%.
Delivered three-year average gross PDP, 1P and 2P Reserves Replacement Ratio of 129%, 104% and 79%, respectively.

Reserves Replacement Ratio (%)	PDP Reserves	1P Reserves	2P Reserves
2021	133 %	175 %	131 %
2022	150 %	52 %	77 %
2023	105 %	85 %	28 %
Three-year average	129 %	104 %	79 %

Delivered a 1P gross reserves life index of 7.3 years compared to 7.4 years at December 31, 2022, and a 2P reserves life index of 11.0 years compared to 11.6 years at December 31, 2022.
The NPV of the Company’s 2P reserves, discounted at 10% before tax, is $3.5 billion ($21.60/2P boe) at December 31, 2023, compared to $3.7 billion ($21.24/2P boe) at December 31, 2022. The decrease in NPV10 for the 2P reserves is primarily due to a decrease in the forecast oil price used to calculate the NPV10, however the NPV10 per boe increased by 2% driven by operational efficiencies and reduced future development costs.
Reduced the future development cost for 2P reserves by $300 million to $1.2 billion at December 31, 2023, compared to $1.5 billion at December 31, 2022. The reduction is primarily due to the Company’s focus on sustained production, value over volumes and an optimized development plan.

2023 Year-End D&M Certified Gross Reserves Volumes⁽¹⁾

Reserves Category	December 31, 2023 Mboe⁽²⁾	December 31, 2022 MBoe ⁽²⁾	Percentage Change 2023 versus 2022
Proved Developed Producing (PDP)	39,976	39,287	2 %
Proved Developed Non-Producing (PDNP)	7,864	9,951	(21 %)
Proved Undeveloped (PUD	60,889	61,774	(1 %)
Total Proved (1P)	108,729	111,013	(2 %)
Probable	55,363	63,752	(13 %)
Total Proved Plus Probable (2P)	164,092	174,765	(6 %)
Possible ⁽³⁾	36,563	43,770	(16 %)
Total Proved Plus Probable Plus Possible (3P)	200,654	218,535	(8 %)

	⁽¹⁾ Gross reserves represent Frontera’s W.I. before royalties.
	⁽²⁾ See “Boe Conversion” section in the “Advisories”, at the end of this press release.
	⁽³⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Frontera’s Sustainability Strategy

Frontera achieved 108% of its 2023 Sustainability Goals, started the operation of its first solar farm (Ikotia) in December that will reduce almost 8,000 TCO2e from the power generation in CPE6 in 2024 and offset 50% of its scope 1 emissions. The Company also completed 5,737 cumulative hectares preserved and restored in key connectivity corridors in Casanare and Meta (Colombia) and recycled 45% of its operating water and 12% of its solid waste. Frontera handed over 1,000 hectares to the National Parks Association in Colombia, which contributed to the declaration of the Serranía de Manacacías as a National Park in Meta, a major environmental milestone for the country.

The Company invested approximately $5.5 million in education, including economic development, and quality of life initiatives, benefiting 94,875 people through 256 social projects in Colombia, Ecuador and Guyana. Frontera purchased $73.3 million worth of goods and services from local suppliers in nearby operation areas. In 2023 Frontera was included in the Bloomberg Gender-Equality Index (“GEI”) and was recognized for the fourth consecutive year as one the most ethical companies in the world by the Ethisphere Institute.

Enhancing Shareholder Returns

Since 2018, Frontera has returned more than $306 million to shareholders through dividends and share buybacks while maintaining a strong balance sheet.

NCIB: Under the Company’s current NCIB which commenced on November 21, 2023, Frontera is authorized to repurchase for cancellation up to 3,949,454 of the Company’s common shares (“Common Shares”). As of March 7, 2024, the Company has repurchased approximately 624,600 Common Shares for cancellation for approximately $3.7 million.

Dividend: Pursuant to Frontera’s dividend policy, Frontera’s Board of Directors has declared a dividend of C$0.0625 per Common Share to be paid on or around April 16, 2024, to shareholders of record at the close of business on April 2, 2024. This dividend payment to shareholders is designated as an “eligible dividend” for purposes of the Income Tax Act (Canada). This dividend is eligible for the Company’s Dividend Reinvestment Plan to provide shareholders of Frontera who are resident in Canada with the option to have the cash dividends declared on their Common Shares reinvested automatically back into additional Common Shares, without the payment of brokerage commissions or services charges.

Frontera’s Three Core Businesses

Frontera’s three core businesses include: (1) its Colombia and Ecuador Upstream Onshore business, (2) its standalone and growing Colombian Infrastructure business, and (3) its potentially transformational Guyana Exploration business offshore Guyana.

1. Colombia and Ecuador Upstream Onshore

Colombia

During the fourth quarter of 2023, Frontera produced 37,814 boe/d from its Colombian operations (consisting of 23,002 bbl/d of heavy crude oil, 12,342 bbl/d of light and medium crude oil, 4,760 mcf/d of conventional natural gas and 1,635 boe/d of natural gas liquids).

In the fourth quarter of 2023, the Company drilled 13 development wells at its Quifa and CPE-6 blocks well services at 11 others.

For the year ended December 31, 2023, Frontera drilled 65 development wells (including two injector wells) at its Quifa, CPE-6, Cajua and Cubiro blocks and completed well interventions at 73 others. The Company reduced its cost per well in 2023, due to drilling campaign efficiencies and well types.

Currently, the Company has 4 drilling rigs active at its Quifa and CPE-6 blocks in Colombia.

Quifa Block: Quifa SW and Cajua

At Quifa, fourth quarter 2023 production averaged approximately 16,452 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company drilled 8 wells on the block in the fourth quarter of 2023. The Company also invested in new flow lines in the Quifa block to integrate the SAARA project. The Company’s current water handling capacity in Quifa is approximately 1.5 million bwpd.

During the fourth quarter 2023, Frontera continued with its recommissioning efforts supporting SAARA, its reverse osmosis water treatment facility. As of year-end 2023, the plant had processed 20.6 million barrels of water as part of its recommissioning program, providing irrigation source water to the Company’s nearby ProAgrollanos palm oil plantation. In 2024, Frontera successfully completed the pilot phase of the SAARA project with Ecopetrol. The Company intends to invest in the commissioning of the first phase of the project, the stabilization phase, to reach a minimum of 250,000 barrels of water per day available for the Quifa block, subject to final JV approval.

CPE-6

At CPE-6, fourth quarter 2023 production averaged approximately 6,162 bbl/d of heavy crude oil, increasing 18% from 5,214 bbl/d at year end 2022. The Company drilled 5 development wells. Additionally, the Company invested in new flow lines and in the expansion and improvement of the development facilities in CPE-6 block, which doubled the water-handling capacity from 120,000 to 240,000 bwpd.

Other Colombia Developments

At Guatiquia, production during the fourth quarter 2023 averaged 6,206 bbl/d of light and medium crude compared with 6,763 bbl/d in the third quarter of 2023.

In the Cubiro Block production averaged 1,535 bbl/d of light and medium crude oil in the fourth quarter of 2023 compared with 1,729 bbl/d in the third quarter 2023.

At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,775 boe/d of light and medium crude oil in the fourth quarter of 2023 compared to approximately 1,798 boe/d of light and medium crude oil in the third quarter of 2023.

Colombia Exploration Assets

The Company’s exploration focus remains on the Lower Magdalena Valley and Llanos Basins in Colombia. During the fourth quarter of 2023, the Company processed 163 square kilometers of 3D seismic, from the Llanos 99 block, confirming one of the exploratory opportunities previously identified by a 2D survey (LLA99 West), and identified multiple smaller traps to the NE of the 3D survey.

Additionally, during the year 2023, the Company received approval from the Agencia Nacional de Hidrocarburos (“ANH”) to terminate by mutual agreement the CR-1 and COR-24 contracts, which reduced exploratory commitments by $11.1 million.

Ecuador

In Ecuador, fourth quarter 2023 gross production averaged approximately 1,453 bbl/d of light & medium crude oil. Frontera’s share of production in Ecuador for the three months ended December 31, 2023, was 1,453 bbl/d of medium crude oil compared to 652 bbl/d in the prior quarter.

In the Perico Block, (Frontera 50% W.I. and operator), the Company spudded the Perico Norte-4 well on October 8, 2023, and reached a total depth of 11,433 ft MD on October 23, 2023. Petrophysical interpretation identified 49 ft of net pay in the lower U Sand. The well produced 1,000 bbl/d of 29.4 API, medium crude oil with 0.3% BSW.

The Perico Centro-1 well (formerly Jandiayacu-1) was spud on August 22, 2023, reaching total depth of 11,198 ft MD on September 11, 2023, and finding oil in three intervals The well was completed, and an initial test produced average production of 800 bbl/d of 28 API medium crude oil with 1% BSW.

The Perico Norte A-3 (formerly Yin-2) appraisal well was drilled in July, discovering 48 feet of net pay in the Lower U sand and 24 feet net pay in the Hollin main formation.

Frontera is currently conducting long-term testing and preparing the environmental impact assessments in order to obtain a production environmental license at the Perico Norte-1 (formerly Jandaya-1), Perico Sur B-1 (formerly Tui-1) and Perico Norte A-2 (formerly Yin-1) exploration wells. The Company has completed the four wells required as part of its exploration commitment on the Perico block.

At the Espejo block (Frontera 50% W.I. and non-operator), the Company expects to drill two exploration wells, targeting the Lower U Ss and M1 Ss.

In 2024, Frontera anticipates investing $35 – $45 million on various exploration activities in its core upstream Colombia and Ecuador business including drilling the high impact Hydra-1 well in the VIM-1 block and two wells in the Espejo block. Highlights of the Company’s key exploratory activities include:

VIM-1 block (Frontera 50% non-operator): the Company anticipates spudding the high-impact Hydra-1 exploration well mid-2024. The Hydra-1 well will be drilling using new seismic processing technology and will target gas and condensate.
Espejo Block (Frontera 50% non-operated): the Company will drill two exploratory wells which target plays successfully tested in nearby areas.
LLA119 block (Frontera 100%): the Company plans to complete 80 sqkm of 3D seismic data, complete pre-drilling activities and commence civil works.
LLA99 and VIM46 block (Frontera 100%): the Company intends to complete pre-seismic and pre-drilling activities ahead of 3D seismic acquisition.

2. Infrastructure Colombia (formerly “Midstream Colombia”)

Frontera has investments in certain significant infrastructure and midstream assets seeking to capture stable and long-term revenue streams, including storage, port, and other facilities in Colombia as well as the Company’s investments in certain pipelines which comprise its standalone and growing Colombia Infrastructure business. Frontera’s Infrastructure Colombia Segment includes the Company’s 35% equity interest in the ODL pipeline through Frontera’s wholly owned subsidiary, PIL and the Company’s 99.97% interest in Puerto Bahia.

Infrastructure Colombia Segment Results

The Company’s Infrastructure Colombia Segment income increased by $2.0 million and $15.0 million for the three months and year ended December 31, 2023, respectively, compared with the same periods of 2022, mainly due to the increase in share of income from associates ODL which increased by $2.7 million and $14.4 million, respectively, driven by stronger crude oil volumes from the Cano Sur and Rubiales blocks. For the three months ended December 31, 2023, Puerto Bahia revenues decreased $1.3 million, compared with the same period of 2022, mainly due to lower volumes sold of general cargo. For the year ended December 31, 2023, Puerto Bahia revenues increased $1.4 million compared with the same period of 2022. The increase was primarily due to the higher liquids terminal revenues by $2.5 million, and a decrease by $1.2 million in general cargo terminal revenues due to lower volumes of cargo handled.

Cash provided by operating activities of the Infrastructure Colombia Segment for three months ended December 31, 2023, was $7.6 million, compared to $12.8 million, in the same period of 2022. The decrease was mainly due to the absence of dividends during the fourth quarter of 2023, while there was a dividend payment during the fourth quarter of 2022. For the year ended December 31, 2023, cash provided by operating activities of the Infrastructure Colombia Segment was $54.5 million, compared to $46.9 million, in the same period of 2022, mainly due to fluctuations in working capital.

	Three months ended December 31		Year ended December 31
($M)	2023	2022	2023	2022
Revenue	10,954	12,209	48,263	46,883
Liquids port facility	7,591	6,750	32,082	29,550
FEC liquids port facility	1,719	2,096	7,379	7,261
Third party liquids port facility	5,872	4,654	24,703	22,289
General Cargo	3,363	5,459	16,181	17,333
Cost	(5,864)	(5,685)	(23,133)	(21,376)
General administrative expenses	(951)	(1,376)	(5,148)	(5,375)
Depletion, depreciation, and amortization	(1,570)	(1,233)	(5,562)	(5,617)
Restructuring, severance, and other costs	(446)	(1,116)	(1,547)	(2,229)
Puerto Bahia income from operations	2,123	2,799	12,873	12,286
Share of Income from associates ODL	14,833	12,135	56,476	42,043
Segment income	16,956	14,934	69,349	54,329
Segment cash flow from operating activities	7,639	12,796	54,516	46,898

	Three months ended December 31		Year ended December 31
($M)	2023	2022	2023	2022
Adjusted Infrastructure Revenue ⁽¹⁾	43,951	38,355	169,142	113,583
Adjusted Infrastructure Operating Cost ⁽¹⁾	(10,287)	(8,950)	(38,216)	(29,720)
Adjusted Infrastructure General and Administrative ⁽¹⁾	(2,973)	(2,847)	(11,105)	(8,970)
Adjusted Infrastructure EBITDA ⁽¹⁾	30,691	26,558	119,821	74,893

(1)

Non-IFRS financial measure (equivalent to a “non-GAAP financial measure”, as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures”.

The following table shows the volumes pumped per injection point in ODL:

	Three months ended December 31		Year ended December 31
(bbl/d)	2023	2022	2023	2022
At Rubiales Station	173,888	150,634	169,701	140,393
At Jagüey and Palmeras Station	78,922	72,221	73,916	72,666
Total	252,810	222,855	243,617	213,059

The following table shows throughput for the liquids port facility at Puerto Bahia:

	Three months ended December 31		Year ended December 31
(bbl/d)	2023	2022	2023	2022
FEC volumes	11,971	13,575	12,863	13,292
Third party volumes	40,783	53,142	47,855	49,130
Total	52,754	66,717	60,718	62,422

Puerto Bahia and Reficar Connection Update

Frontera anticipates breaking ground on the connection construction during the first quarter of 2024 and connection start-up by the end of 2024. Frontera has secured an additional $30 million in committed funding, subject to certain conditions precedent, in connection with this project from its existing group of lenders led by Macquarie Group.

3. Guyana Exploration

As disclosed in the December 11th, 2023 news release, the Company announced that its Joint Venture with CGX had discovered approximately 514 to 628 mmboe PMean unrisked gross prospective resources in the Corentyne block, offshore Guyana. The Joint Venture believes that the rock quality discovered in the Maastrichtian horizon in the Wei-1 well is analogous to that reported in the Liza Discovery on Stabroek block. The Joint Venture believes that they have discovered sufficient resources to underpin a potential standalone commercial oil development in the Maastrichtian horizons with additional potential upside in the deeper Campanian and Santonian horizons.

On November 9, 2023, Frontera announced that with the support from Houlihan Lokey, it is actively pursuing a possible farm down of its interests in the Corentyne block in Guyana, where a data room has been opened and management presentations are underway. There can be no guarantee that the strategic review processes will result in a transaction.

Hedging Update

As part of its risk management strategy, Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company’s strategy aims to protect 40-60% of its estimated net after royalties’ production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, thereby allowing the Company to take a more dynamic approach to the management of its hedging portfolio. Consistent with this strategy, the Company entered new put hedges totaling 2,574,826 bbls to protect a portion of the Company’s production through June 2024. The following table summarizes Frontera’s 2024 hedging position as of March 7, 2024.

Term	Type of Instrument	Open Positions (bbl/d)	Strike Prices Put/Call
Jan 24	Put	13,823	80.00
Feb 24	Put	13,601	72.00
Mar 24	Put	13,497	72.00
1Q-2024	Total Average	13,641	74.76
Apr 24	Put	14,711	72.00
May 24	Put	14,586	72.00
Jun 24	Put	14,667	72.00
2Q-2024	Total Average	14,653	72.00

The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of March 7, 2024, the Company had entered new positions of foreign currency derivatives contracts as follows:

Term	Type of Instrument	Open Interest (US$ MM)	Strike Prices Put/ Call	Hedging Ratio
1Q-2024	Zero-cost Collars	60	4,125 / 4,763	40 %
2Q-2024	Zero-cost Collars	60	4,125 / 4,763	40 %
Oct, 2024	Forward	17	4,386

Additional Reserves Results Details

The following tables provide a summary of the Company’s oil and natural gas reserves based on forecast prices and costs effective December 31, 2023, as applied in the Reserves Report. The Company’s net reserves after royalties at December 31, 2023, incorporate all applicable royalties under Colombia and Ecuador fiscal legislations based on forecast pricing and production rates evaluated in the Reserves Report, including any additional participation interest related to the price of oil applicable to certain Colombian and Ecuadorian blocks, as at year-end 2023.

2023 2P Reserves Reconciliation

	Oil Equivalent Gross 2P Reserves (MMboe) ⁽¹⁾⁽²⁾
December 31, 2022	174.8
Discoveries⁽³⁾	4.6
Extensions & Improved Recovery	0.0
Technical Revisions⁽⁴⁾	2.4
Acquisitions	0.0
Dispositions⁽⁵⁾	(0.1)
Economic Factors⁽⁶⁾	(2.7)
Production⁽⁷⁾	(14.9)
December 31, 2023	164.1


	⁽¹⁾ See “Boe Conversion” section in the “Advisories”, at the end of this press release.
	⁽²⁾ Gross refers to Frontera’s W.I. before royalties. Net refers to Frontera’s W.I. after royalties.
	⁽³⁾ Includes U reservoir in Perico fields and Perico Centro discovery in the Perico block in Ecuador.
	⁽⁴⁾ Includes technical revisions mainly in the Hamaca field (in the CPE-6 block) and Copa trend fields (Cubiro block)
	⁽⁵⁾ Adjustments in Arauco field returned to ANH and Dina Terciarios (Neiva field) for contract end.
	⁽⁶⁾ Evaluation prices impact in the economic limit/reserves of several fields, mainly Jaspe field in the Quifa block
	⁽⁷⁾ Production represents the Company’s production for the twelve-month period ended December 31, 2023, for assets with associated reserves. Production associated with exploration and evaluation assets are included in production volumes for financial reporting purposes.

Gross Reserve Life Index (“RLI”)⁽¹⁾

(US$/bbl)	December 31, 2022⁽²⁾	December 31, 2023⁽³⁾
Total Proved (1P)	7.4 years	7.3 years
Total Proved Plus Probable (2P)	11.6 years	11.0 years
Total Proved Plus Probable Plus Possible (3P)	14.5 years	13.5 years


	⁽¹⁾ RLI does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
	⁽²⁾ Calculated by dividing the total relevant gross reserves category by the 2022 production of 15.1 MMboe.
	⁽³⁾ Calculated by dividing the total relevant gross reserves category by the 2023 production of 14.9 MMboe.

Net Present Value of Future Net Revenue Before Tax Summary – D&M Reserves Report (2023 Brent Forecast)⁽¹⁾

Reserves Category	December 31, 2022	December 31, 2023	December 31, 2023
$ (000’s), except per share data	NPV10 ($ 000’s)⁽²⁾	NPV10 ($ 000’s)⁽³⁾	NPV10 (C$/share)⁽⁴⁾
Proved Developed Producing (PDP)	1,118,382	981,636	15.27
Proved Developed Non-Producing (PDNP)	288,281	226,047	3.52
Proved Undeveloped	1,029,911	1,124,358	17.49
Total Proved (1P)	2,436,575	2,332,041	36.27
Probable	1,277,388	1,212,175	18.85
Total Proved Plus Probable (2P)	3,713,962	3,544,216	55.13
Possible ⁽⁵⁾	1,064,195	862,919	13.42
Total Proved Plus Probable Plus Possible (3P)	4,778,157	4,407,135	68.55


	⁽¹⁾ See “Advisories” at the end of this press release. The Reserves Report used the average Brent projected price of three major international independent auditors: GLJ, McDaniel and Sproule. The full December 31, 2023 price forecast will be included in the Reserves Report. The December 31, 2022 price forecast is included in the 2022 Reserves Report.
	⁽²⁾ Includes future development costs (“FDC“) as at December 31, 2023, of $945 million for 1P and $1,541 million for 2P.
	⁽³⁾ Includes FDC as at December 31, 2023, of $837 million for 1P and $1,252 million for 2P.
	⁽⁴⁾ Calculated by dividing the December 31, 2023 NPV10 value by 85,151,216 shares outstanding as at December 31, 2023 and a USD:CAD foreign exchange rate of 1.3245. Per share valuations do not attribute any value to the Company’s material ownership in midstream and infrastructure assets as well as any equity value for its ownership in CGX Energy Inc. (TSXV:OYL) (“CGX“).
	⁽⁵⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Future Development Costs (FDC) – Based on Forecast Prices and Costs⁽¹⁾

($ 000’s)	Total Proved (1P)	Total Proved Plus Probable (2P)
2024	138,997	160,116
2025	193,534	268,669
2026	162,586	230,232
2027	141,061	187,939
2028	136,062	223,370
Beyond 2027	40,193	142,760
Total undiscounted	812,432	1,213,087

⁽¹⁾ Does not include $24.8 million in FDC from Ecuador 1P and $38.6 million in FDC from Ecuador 2P.

About Frontera’s 2023 Year-End Estimated Reserves

The Company’s 2023 year-end estimated reserves were evaluated by D&M in their report dated March 7, 2024, with an effective date of December 31, 2023 (the “Reserves Report“), in accordance with the definitions, standards and procedures contained in the COGE Handbook, NI 51-101 and CSA Staff Notice 51-324. D&M is an independent qualified reserves evaluator as defined in NI 51-101.

Additional reserves information as required under NI 51-101 will be included in the Company’s statement of reserves data and other oil and gas information on Form 51-101F1, which is expected to be filed on SEDAR on March 7, 2024. See “Advisory Note Regarding Oil and Gas Information” section in the “Advisories“, at the end of this news release.

Fourth Quarter and Year-end 2023 Conference Call Details

A conference call for investors and analysts will be held on Friday, March 8, 2024, at 10:00 a.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Rene Burgos, Chief Financial Officer, and other members of the senior management team.

Analysts and investors are invited to participate using the following dial-in numbers:

Participant Number (Toll Free North America):	1-888-644-6383
Participant Number (Toll Free Colombia):	01-800-518-4036
Participant Number (International):	1-416-764-8650
Conference ID:	01718743
Webcast Audio:	www.fronteraenergy.ca

A replay of the conference call will be available until 11:59 p.m. Eastern Time on March 15, 2024.

Encore Toll free Dial-in Number:	1-888-390-0541
International Dial-in Number:	1-416-764-8677
Encore ID:	718743

About Frontera:

Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 27 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally, and ethically responsible manner.

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Advisories:

Cautionary Note Concerning Forward-Looking Statements

This news release contains forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to activities, events, or developments that the Company believes, expects, or anticipates will or may occur in the future. Forward-looking information in this news release includes, without limitation, statements regarding the Company’s continued commitment to enhancing shareholder returns and its efforts to unlock shareholder value; statements regarding the payment of dividends, statements regarding expected reductions in grid power consumption and offset emissions stemming from the Company’s solar farm; statements regarding the Company’s intended investment in the SAARA project, including expectations regarding the results of such investment; anticipated exploration, activities in the Company’s core upstream Colombia and Ecuador business; expectations regarding drilling exploration wells at the Espejo block; pursuit of a review of strategic options by the Company and its JV partner CGX with support from Houlihan Lokey, with respect to the Corentyne block, including a farm down of its interest in Offshore Guyana expectation; expectation with respect to the NCIB; and expectations with respect to the Company’s hedging strategy; and statements regarding the Company’s investor call. All information other than historical fact is forward-looking information.

Forward-looking information reflects the current expectations, assumptions and beliefs of the Company based on information currently available to it and considers the Company’s experience and its perception of historical trends, including expectations and assumptions relating to commodity prices and interest and foreign exchange rates; the current and expected impacts of the COVID-19 pandemic, actions of the Organization of Petroleum Exporting Countries (“OPEC+“) and the impact of the Russia–Ukraine conflict and the Israel-Palestine conflict, and the expected impact of measures that the Company has taken and continues to take in response to these events; expectations regarding the Company’s ability to manage its liquidity and capital structure and generate sufficient cash to support operations, capital expenditures and financial commitments; the performance of assets and equipment; the Company’s ability to achieve the increased oil and water handling capacity at Quifa; the availability and cost of labor, services and infrastructure; the execution of exploration and development projects; the receipt of any required regulatory approvals and outcome of discussions with governmental authorities; the success of the Company’s hedging strategy; and the impact and success of the Company’s ESG strategies.

Although the Company believes that the assumptions inherent in the forward-looking information are reasonable, forward-looking information is not a guarantee of future performance and accordingly undue reliance should not be placed on such information. Forward-looking information is subject to a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to the Company. The actual results may differ materially from those expressed or implied by the forward-looking information, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. The Company’s annual information form dated March 7, 2024, its annual management’s discussion and analysis for the year ended December 31, 2023, and other documents it files from time to time with securities regulatory authorities describe the risks, uncertainties, material assumptions and other factors that could influence actual results and such factors are incorporated herein by reference. Copies of these documents are available without charge by referring to the company’s profile on SEDAR+ at www.sedarplus.ca. All forward-looking information speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking information, whether as a result of new information, future events, or results or otherwise.

Non-IFRS Financial and Other Measures

This news release contains various “non-IFRS financial measures” (equivalent to “non-GAAP financial measures”, as such term is defined in NI 52-112), “non-IFRS ratios” (equivalent to “non-GAAP ratios”, as such term is defined in NI 52-112), “supplementary financial measures” (as such term is defined in NI 52-112), and “capital management measures” (as such term is defined in NI 52-112), which are described in further detail below. Such financial measures do not have standardized IFRS definitions. The Company’s determination of these financial measures may differ from other reporting issuers, and they are therefore unlikely to be comparable to similar measures presented by other companies. Furthermore, these financial measures should not be considered in isolation or as a substitute for measures of performance or cash flows as prepared in accordance with IFRS. These financial measures do not replace or supersede any standardized measure under IFRS. Other companies in our industry may calculate these financial measures differently than we do, limiting their usefulness as comparative measures.

The Company discloses these financial measures, together with measures prepared in accordance with IFRS, because management believes they provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. These financial measures highlight trends in the Company’s core business that may not otherwise be apparent when relying solely on IFRS financial measures. Further, management also uses non-IFRS measures to exclude the impact of certain expenses and income that management does not believe reflect the Company’s underlying operating performance. The Company’s management also uses non-IFRS measures in order to facilitate operating performance comparisons from period to period and to prepare annual operating budgets and as a measure of the Company’s ability to finance its ongoing operations and obligations.

Set forth below is a description of the non-IFRS financial measures, non-IFRS ratios, supplementary financial measures and capital management measures used in this news release.

Operating EBITDA

EBITDA is a commonly used non-IFRS financial measure that adjusts net (loss) income as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and DD&A. Operating EBITDA is a non-IFRS financial measure that represents the operating results of the Company’s primary business, excluding the following items: restructuring, severance and other costs, post-termination obligation, payments of minimum work commitments and, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, and share-based compensation) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company.

Since the three and six months ended June 30, 2022, the Company changed the composition of its Operating EBITDA calculation to exclude certain unusual or non-recurring items as post-termination obligations and payments of minimum work commitments, which could distort future projections as they are not considered part of the Company’s normal course of operations.

The following table provides a reconciliation of net income to Operating EBITDA:

	Three months ended December 31		Year ended December 31
($M)	2023	2022	2023	2022
Net income ⁽¹⁾	92,038	197,796	193,497	286,615

Finance income	(2,270)	(2,323)	(9,984)	(5,505)
Finance expenses	16,865	14,239	64,185	52,991
Income tax (recovery) expense	(39,007)	68,599	4,130	249,275
Depletion, depreciation and amortization	68,411	49,198	278,269	195,419
Minimum work commitment paid	358	—	358	919
Expense (recovery) of asset retirement obligation	(1,621)	3,235	(25,622)	(1,823)
Expenses (recovery) of impairment	1,417	(211,130)	25,236	(205,833)
Post-termination obligation	11,160	5,229	18,814	12,299
Share-based compensation	(745)	3,213	96	7,777
Restructuring, severance and other costs	3,744	2,624	8,548	4,463
Share of income from associates	(14,833)	(12,135)	(56,476)	(42,043)
Foreign exchange loss (income)	(2,724)	28,230	(12,275)	76,413
Other (income) loss	(4,554)	5,381	(8,936)	10,800
Unrealized gain on risk management contracts	(7,000)	(6,600)	(11,880)	(4,310)
Non-controlling interests	(203)	(562)	(741)	4,420
Operating EBITDA	121,036	144,994	467,219	641,877

⁽¹⁾ Refers to net income attributable to equity holders of the Company.

Capital Expenditures

Capital expenditures is a non-IFRS financial measure that reflects the cash and non-cash items used by the Company to invest in capital assets. This financial measure considers oil and gas properties, plant and equipment, infrastructure, exploration and evaluation assets expenditures which are items reconciled to the Company’s Statements of Cash Flows for the period.

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Consolidated Statements of Cash Flows
Additions to oil and gas properties, infrastructure port, and plant and equipment	70,294	85,074	241,185	261,144
Additions to exploration and evaluation assets	5,171	46,281	195,210	154,516
Total additions in Consolidated Statements of Cash Flows	75,465	131,355	436,395	415,660
Non-cash adjustments ⁽¹⁾	6,827	2,810	6,339	1,903
Total Capital Expenditures	82,292	134,165	442,734	417,563

Capital Expenditures attributable to Infrastructure Colombia Segment	7,867	718	11,407	2,573
Capital Expenditures attributable to other segments different to Infrastructure Colombia Segment	74,425	133,447	431,327	414,990
Total Capital Expenditure	82,292	134,165	442,734	417,563

⁽¹⁾ Related to material inventory movements, capitalized non-cash items and other adjustments. In addition, CPE-6 solar plant project is included as part of the Capital Expenditures, according to Guidance 2023. In the Consolidated Statements of Cash Flows is considered as non-cash adjustment.

Infrastructure Colombia Calculations

Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Cost and Adjusted Infrastructure General and Administrative, is a non-IFRS financial measure, and each is used to evaluate the performance of the Infrastructure Colombia Segment operations. Adjusted Infrastructure Revenue includes revenues of the Infrastructure Colombia Segment including ODL’s revenue direct participation interest. Adjusted Infrastructure Operating Cost includes costs of the Infrastructure Colombia Segment including ODL’s cost direct participation interest. Adjusted Infrastructure General and Administrative includes general and administrative costs of Infrastructure Colombia Segment including ODL’s general and administrative direct participation interest. A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Cost and Adjusted Infrastructure General and Administrative is provided below.

	Three months ended December 31		Year ended December 31
($M) ⁽¹⁾	2023	2022	2023	2022
Revenue Infrastructure Colombia Segment	10,954	12,209	48,263	46,883
Revenue from ODL	94,277	74,702	345,370	268,040
Direct participation interest in the ODL ⁽¹⁾	35.00 %	35.00 %	35.00 %	35.00 %
Equity adjustment participation of ODL ⁽²⁾	32,997	26,146	120,879	66,700
Adjusted Infrastructure Revenues	43,951	38,355	169,142	113,583

Operating cost Infrastructure Colombia Segment	(5,864)	(5,685)	(23,133)	(21,376)
Operating Cost from ODL	(12,637)	(9,329)	(43,094)	(33,541)
Direct participation interest in the ODL ⁽¹⁾	35.00 %	35.00 %	35.00 %	35.00 %
Equity adjustment participation of ODL ⁽²⁾	(4,423)	(3,265)	(15,083)	(8,344)
Adjusted Infrastructure Operating Costs	(10,287)	(8,950)	(38,216)	(29,720)

General and administrative Infrastructure Colombia Segment	(951)	(1,376)	(5,148)	(5,375)
General and administrative from ODL	(5,776)	(4,204)	(17,019)	(14,329)
Direct participation interest in the ODL ⁽¹⁾	35.00 %	35.00 %	35.00 %	35.00 %
Equity adjustment participation of ODL ⁽²⁾	(2,022)	(1,471)	(5,957)	(3,595)
Adjusted Infrastructure General and Administrative	(2,973)	(2,847)	(11,105)	(8,970)

	⁽¹⁾ On September 15, 2022, the Company acquired the remaining 40.07% interest it did not already own of PIL, increasing its ownership interest to 100%, and have a direct participation in ODL by 35%
	⁽²⁾ Revenues and expenses related to the ODL are accounted for using the equity method described in the Note 15 of the 2023 Annual Consolidated Financial Statements.

Operating Netback and Oil and Gas Sales, Net of Purchases

Operating netback is a non-IFRS financial measure and operating netback per boe is a non-IFRS ratio. Operating netback per boe is used to assess the net margin of the Company’s production after subtracting all costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel and is an indicator of how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of any trading activities and results from its midstream segment from the per barrel metrics and adds the effects attributable to transportation and operating costs of any realized gain or loss on foreign exchange risk management contracts. Refer to the reconciliation in the “Operating Netback” section on page 13 of the MD&A.

The following is a description of each component of the Company’s operating netback and how it is calculated. Oil and gas sales, net of purchases, is a non-IFRS financial measure that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining cost. Oil and gas sales, net of purchases per boe, is a non-IFRS ratio that is calculated using oil and gas sales, net of purchases divided by the total sales volumes, net of purchases.

A reconciliation of this calculation is provided below:

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Produced crude oil and gas sales ($M) ⁽¹⁾	247,134	262,430	932,977	1,121,344
Purchased crude oil and products sales ($M)	48,324	63,375	208,069	201,534
(-) Cost of purchases ($M) ⁽²⁾	(55,353)	(64,981)	(235,797)	(217,375)
Oil and gas sales, net of purchases ($M)	240,105	260,824	905,249	1,105,503
Sales volumes, net of purchases – (boe)	3,169,346	3,157,716	12,411,825	12,096,465
Oil and gas sales, net of purchases ($/boe)	75.76	82.60	72.93	91.39

	⁽¹⁾ Excludes sales from port services as they are not part of the oil and gas segment. For further information, refer to the “Infrastructure Colombia” section on page 24 of the MD&A.
	⁽²⁾ Cost of third-party volumes purchased for use and resale in the Company’s oil operations, including its transportation and refining costs.

Net Sales

Net sales is a non-IFRS financial measure that adjusts revenue to include realized gains and losses from oil risk management contracts while removing the cost of any volumes purchased from third parties. This is a useful indicator for management, as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these oil risk management activities. The deduction of cost of purchases is helpful to understand the Company’s sales performance based on the net realized proceeds from its own production, the cost of which is partially recovered when the blended product is sold. Net sales also exclude sales from port services, as it is not considered part of the oil and gas segment. Refer to the reconciliation in the “Sales” section on page 14 of the MD&A.

Non-IFRS Ratios

Realized oil price, net of purchases, and realized gas price per boe

Realized oil price, net of purchases, and realized gas price per boe are both non-IFRS ratios. Realized oil price, net of purchases, per boe is calculated using oil sales net of purchases, divided by total sales volumes, net of purchases. Realized gas price is calculated using sales from gas production divided by the conventional natural gas sales volumes.

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Produced crude oil sales ($M)	245,123	258,365	921,573	1,104,808
Purchased crude oil and products sales ($M)	48,324	63,375	208,069	201,534
(-) Cost of purchases ($M)	(55,353)	(64,981)	(235,797)	(217,375)
Conventional natural gas sales ($M)	2,011	4,065	11,404	16,536
Oil and gas sales, net of purchases ($M) ⁽¹⁾	240,105	260,824	905,249	1,105,503
Sales volumes, net of purchases – (bbl)	3,118,407	3,003,102	12,042,019	11,456,143
Conventional natural gas sales volumes – (mcf)	289,993	881,402	2,107,707	3,655,102
Realized oil price, net of purchases ($/bbl)	76.35	85.50	74.23	95.06
Realized conventional natural gas price ($/mcf)	6.93	4.61	5.41	4.52

⁽¹⁾ Non-IFRS financial measure.

Net sales realized price

Net sales realized price is a non-IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below:

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Oil and gas sales, net of purchases ($M) ⁽¹⁾	240,105	260,824	905,249	1,105,503
(-) Premiums paid on oil price risk management contracts ($M)	(2,198)	(4,182)	(9,903)	(14,733)
(-) Royalties ($M)	(5,683)	(19,076)	(36,949)	(94,709)
Net sales ($M)	232,224	237,566	858,397	996,061
Sales volumes, net of purchases – (boe)	3,169,346	3,157,716	12,411,825	12,096,465
Oil and gas sales, net of purchases ($/boe)	75.76	82.60	72.93	91.39
Premiums paid on oil price risk management contracts ⁽²⁾	(0.69)	(1.32)	(0.80)	(1.22)
Royalties ($/boe) ⁽²⁾	(1.79)	(6.04)	(2.98)	(7.83)
Net sales realized price ($/boe)	73.28	75.24	69.15	82.34

	⁽¹⁾ Non-IFRS financial measure.
	⁽²⁾ Supplementary financial measure.

Production cost (excluding energy cost), net of realized FX hedge impact and production cost, net of realized FX hedge impact per boe

Production costs (excluding energy cost), net of realized FX hedge impact is a non-IFRS financial measure that mainly includes lifting costs, activities developed in the blocks, and processes to put the crude oil and gas in sales condition and the realized gain or loss on foreign exchange risk management contracts attributable to production costs. Production cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using production cost (excluding energy cost), net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Production costs (excluding energy cost) ($M)	37,122	32,628	139,917	132,758
(-)Realized gain on FX hedge attributable to production costs (excluding energy cost)($M)⁽¹⁾	(2,101)	—	(9,075)	—
Production costs (excluding energy cost), net of realized FX hedge impact ($M) ⁽²⁾	35,021	32,628	130,842	132,758
Production (boe)	3,612,564	3,846,152	14,935,435	15,104,430
Production costs (excluding energy cost), net of realized FX hedge impact ($/boe)	9.69	8.48	8.76	8.79

	⁽¹⁾ See “Gain (Loss) on Risk Management Contracts” on page 18 of the MD&A.
	⁽²⁾ Non-IFRS financial measure.

Energy costs, net of realized FX hedge impact, and production cost, net of realized FX hedge impact per boe

Energy costs, net of realized FX hedge impact is a non-IFRS financial measure that described the electricity consumption and the costs of localized energy generation and the realized gain or loss on foreign exchange risk management contracts attributable to energy costs. Energy cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using e cost, net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Energy costs ($M)	19,005	11,837	69,294	50,644
(-) Realized gain on FX hedge attributable to production costs ($M) ⁽¹⁾	(738)	—	(2,900)	—
Energy costs, net of realized FX hedge impact ($M) ⁽²⁾	18,267	11,837	67,024	50,644
Production (boe)	3,612,564	3,846,152	14,935,435	15,104,430
Energy costs, net of realized FX hedge impact ($/boe)	5.06	3.08	4.49	3.35

	⁽¹⁾ See “Gain (Loss) on Risk Management Contracts” on page 18 of the MD&A.
	⁽²⁾ Non-IFRS financial measure.

Transportation cost, net of realized FX hedge impact and transportation cost, net of realized FX hedge impact per boe

Transportation costs, net of realized FX hedge impact is a non-IFRS financial measure that includes all commercial and logistics costs associated with the sale of produced crude oil and gas such as trucking and pipeline and the realized gain or loss on foreign exchange risk management contracts attributable to transportation costs. Transportation cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using transportation cost, net of realized FX hedge impact divided by net production after royalties. A reconciliation of this calculation is provided below:

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Transportation costs ($M)	34,750	35,660	151,416	137,554
(-) Realized gain on FX hedge attributable to transportation costs ($M) ⁽¹⁾	(753)	—	(3,264)	—
Transportation costs, net of realized FX hedge impact ($M) ⁽²⁾	33,997	35,660	148,152	137,554
Net production (boe)	3,084,338	3,380,908	13,210,810	13,175,770
Transportation costs, net of realized FX hedge impact ($/boe)	11.02	10.55	11.21	10.44

	⁽¹⁾ See “Gain (Loss) on Risk Management Contracts” on page 18 of the MD&A.
	⁽²⁾ Non-IFRS financial measure.

Realized gain (loss) on oil risk management contracts per boe.

Realized gain (loss) on oil risk management contracts includes the gain or loss during the period, as a result of the Company’s exposure in derivative contracts of crude oil. Realized gain (loss) on oil risk management contracts per boe is a supplementary financial measure that is calculated using Realized gain (loss) on risk management contracts divided by total sales volumes, net of purchases.

Restricted cash short and long-term

Restricted cash (short and long term) is a capital management measure, that sum the short-term portion and long-term portion of the cash that the Company has in term deposits that have been escrowed to cover future commitments and future abandonment obligations or insurance collateral for certain contingencies and other matters that are not available for immediate disbursement.

Total cash

Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available and consists of the cash and cash equivalents and the restricted cash short and long-term.

Total debt and lease liabilities

Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company, and comprises the debt of unsecured notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets.

Non-Standardized Measures

This news release includes non-standardized measures, including reserves life index and reserves replacement ratio. Reserves life index is calculated as the gross reserves in the referenced category divided by the net production of the last year. It is a measure of how long the booked reserves will last if the production rate is maintained and no additional reserves are added. Reserves replacement ratio is calculated as the net reserves added in the referenced category divided by the net production of the last year. It is a measure of the capacity to replace the production. These measures should not be construed as alternative measures of financial performance. Such measures have been included to provide readers with additional means to evaluate the Company’s performance but these non-standardized measures are not reliable indicators of the Company’s future performance and therefore must not be relied upon unduly. The Company’s method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Readers are cautioned that the information provided or derived by these measures should not be relied upon for investment purposes.

Advisory Note Regarding Oil and Gas Information

The reserves information contained in this press release has been prepared in accordance with NI 51-101, but only presents a portion of the disclosure required thereunder. Complete reserves disclosure required in accordance with NI 51-101 will be available on SEDAR at www.sedar.com on or around March 7, 2024. Actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this news release. There is no assurance that forecast prices and costs assumed in the Reserves Report, and presented in this news release, will be attained and variances from such forecast prices and costs could be material. The estimated future net revenue from the production of the disclosed oil and natural gas reserves in this news release does not represent the fair market value of these reserves.

The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.

The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The tax calculations used in the preparation of the Reserves Report are done at the field level in accordance with standard practice, and do not reflect the actual tax position at the corporate level which may be significantly different.

Prospective Resources

Prospective resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially prospective from undiscovered accumulations by application of future development projects. Prospective resources are not, and should not be confused with, reserves or contingent resources.

The prospective resource estimates were made based on separate reviews by two independent, third-party qualified reserves evaluators, effective as of October 30, 2023, and November 30, 2023, respectively. Such estimates have been prepared in compliance with NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. All estimates of prospective resources presented herein are on an un-risked basis, meaning that they have not been adjusted for risk based on the chance or discovery or the chance of development, and all volumes are presented on a gross basis, meaning the Joint Venture’s aggregate working interest before adjustment for royalties. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Estimates of resources always involve uncertainty, and the degree of uncertainty can vary widely between accumulations/projects and over the life of a project. Readers are cautioned that the prospective resource potential disclosed in this news release are not necessarily indicative of ultimate recovery.

The resource estimates presented above are subject to certain risks and uncertainties, including those associated with the drilling and completion of future wells, limited available geological and geophysical data and uncertainties regarding the actual production characteristics of the reservoirs, all of which have been assumed for the preparation of the resource estimates. In addition, significant positive and negative factors related to the prospective resource estimate include the high exploration success rate of, and frequency of development projects by, operators in the Guyana-Suriname Basin, a lack of infrastructure and transportation in the Corentyne area and the capital expenditures and financing required to conduct additional appraisal activities and/or develop resources at an acceptable cost.

Definitions:

bbl(s)	Barrel(s) of oil
bbl/d	Barrels of oil per day
boe	Refer to “Boe Conversion” disclosure above
boe/d	Barrel of oil equivalent per day
Mcf	Thousand cubic feet
W.I.	Working Interest
Net Production	Net production represents the Company’s working interest volumes, net of royalties and internal consumption

“Proved Developed Producing Reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been in production, and the date of resumption of production must be known with reasonable certainty.
“Proved Developed Non-Producing Reserves” are those reserves that either have not been on production or have previously been on production but are shut-in and the date of resumption of production is unknown.
“Proved Undeveloped Reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production.They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
“Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
“Possible” reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Analogous Information:

Certain information in this presentation may constitute “analogous information” as defined in NI 51-101. Such information includes reservoir information retrieved from the continuous disclosure record of certain industry participants from www.sedarplus.ca or other publicly available sources. The Joint Venture believes the information is relevant as it may help to define the reservoir characteristics of certain lands in which the Joint Venture holds an interest. The Joint Venture is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor and is unable to confirm that the analogous information was prepared in accordance with NI 51-101. Such information is not an estimate of the resources attributable to lands held by the Joint Venture and there is no certainty that the resources data and commercial viability for the lands held by the Joint Venture will be similar to the information presented herein. The reader is cautioned that the data relied upon by the Joint Venture may be in error and/or may not be analogous to such lands held by the Joint Venture

For further information, please contact Investor Relations, at 1 403 705 8827, [email protected], www.fronteraenergy.ca

SOURCE Frontera Energy Corporation

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