FRONTERA ANNOUNCES FOURTH QUARTER AND YEAR END 2024 RESULTS, YEAR-END RESERVES AND OPERATIONAL UPDATE

Mar 10 2025 10:29 BST

Recorded Full Year 2024 Net Loss of $24.2 Million and $116.7 Million in Income from Operations

Generated Full Year 2024 Operating EBITDA of $424 Million

Delivered On All 2024 Guidance Metrics, Including Annual Production of 40,288 Boe/d, Average Q4 2024 Production of 42,406 boe/d and Average Production Cost of $9.34/boe for 2024

Recorded 151.3 Million Boe 2P Gross Reserves and 100.6 Million Boe 1P Gross Reserves

1P Reserves Replacement Ratio for 2024 of 45%

2.5 Years PDP, 6.8 Years 1P and 10.3 2P Gross Reserve Life Index

$3.4 Billion 2P Net Present Value Before Tax Discounted at 10% as at December 2024

Generated Full Year Adjusted Infrastructure EBITDA of $107 Million and $55 Million Segment Income

ODL Declared $152 Million in Dividends ($53.3 million, Net to Frontera), a 100% 2024 Payout Ratio, Payable in 2025

Returned Over $180 Million to Shareholders Since 2022

Successfully Achieved 100% of its 2024 Sustainability Goals, Including Best Ever Total Recordable Incident Rate ("TRIR") Performance

Declared Quarterly Dividend of C$0.0625 Per Share, or $3.4 Million in Aggregate, Payable on or around April 16, 2025

CALGARY, AB , March 10, 2025 /CNW/ - Frontera Energy Corporation (TSX: FEC) ("Frontera" or the "Company") today reported financial and operational results for the fourth quarter and year ended December 31, 2024, announced the results of its annual independent reserves assessment conducted by DeGolyer and MacNaughton Corp ("D&M") and provided an operational update. All financial amounts in this news release and in 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, 2024, are located in Colombia and Ecuador.

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

"2024 was another strong year for Frontera as the Company achieved all its key guidance targets while returning over $83 million to its shareholders from 2024 thru today.

The Company generated full year Operating EBITDA of $424 million, and closed the year with a strong balance sheet, including a $223 million cash position. Additionally, the Company reduced its total consolidated debt and lease liabilities by more than $30 million, including repurchasing $5 million of its 2028 Senior Unsecured Notes. Both S&P and Fitch reaffirmed Frontera's B+ and B credit rating, respectively, and stable outlook, highlighting the Company's sound credit quality, strong financial position, and industry-low leverage levels.

During the year, the Company's Infrastructure business generated $107 million of Adjusted Infrastructure EBITDA, and achieved several key milestones, including the announcement of a new LPG joint venture with Industrias Gasco and the construction of the Reficar connection, which is expected to be operational by the second quarter 2025. Importantly, Frontera's strategic review of its Infrastructure business is nearing conclusion, and the Company is analyzing various options and will communicate results in due course.

With respect to our Guyana business, the Company remains firmly of the view that its interests in, and the Petroleum Prospecting License for the Corentyne block offshore Guyana ("License") for the Corentyne block remain in place and in good standing, as the Petroleum Agreement has not been terminated. The Joint Venture is assessing all legal options available to it to assert its rights.

In January 2025, the Company repurchased an additional $30 million in common shares via another substantial issuer bid. Since 2022, the Company has returned over $180 million to its shareholders through normal course issuer bids, substantial issuer bids and dividends T he Company will continue to consider future investor initiatives throughout the year, including potential additional dividends, distributions, or bond buybacks, based on the overall results of the business, oil prices, cash flow generation and the Company's strategic goals."

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

"In 2024, we successfully executed our strategy generating positive results. Driven by successful drilling campaigns in the CPE-6 block, where we reached another record daily production level of almost 9,000 boe/d in the fourth quarter, and Sabanero which saw production increase to 2,384 boe/d in the fourth quarter, we delivered our production targets for the year. For the full year 2024, water processing volumes in SAARA averaged approximately 44,000 barrels of water per day, and during the fourth quarter, SAARA water processing volumes reached an average of 79,000 barrels of water per day. On the cost side, despite inflationary pressures, the Company achieved all its cost guidance targets, including production cost per boe, which averaged $9.34/boe due to strong cost controls.

Our strategy of value over volumes in our upstream Colombia and Ecuador business supported delivery of 100.6 million boe 1P and 151.3 million boe 2P gross reserves at year end 2024. The net present value of the Company's 2P reserves discounted at 10% before tax was $3.4 billion or $22.4/boe at December 31, 2024 and Frontera's NPV10 per boe grew by 4% year over year driven by our focus on operational efficiencies, optimization of development plans and reduced future development costs.

In our infrastructure business, ODL transported over 243,000 bbl/day while generating $274 million in full year EBITDA. Proportional to our 35% equity interest in the pipeline, we received over $60 million in capital distributions and our Adjusted Infrastructure EBITDA benefited from $96 million associated with ODL's EBITDA. Puerto Bahia generated approximately $15 million in operating EBITDA, supported by effective port operations cost controls. We look forward to commissioning and start-up of the Reficar Connection this year.

Importantly, we continue to sustainably achieve our operating objectives, achieving 100% of our 2024 sustainability goals, including restoring and preserving 769 hectares of land, achieving our best Total Recordable Incident Rate performance ever and being recognized for the fourth time as one of the world's most ethical companies by Ethisphere

Year-to-date 2025 production is approximately 40,400 barrels per day. The decrease from fourth quarter 2024 volumes is due to unexpected well failures within our Light and Medium assets occurring near the end of 2024. These issues are being addressed, and we remain confident in meeting our 2025 production guidance.

In 2025, our focus remains on executing our recently announced plan, delivering sustainable production, solid operational and financial results and enhancing investor returns."

Fourth Quarter and Full Year 2024 Operational and Financial Summary:

					Year Ended December 31
		Q4 2024	Q3 2024	Q4 2023	2024	2023

Operational Results

Heavy crude oil production ⁽¹⁾	(bbl/d)	27,740	25,312	23,002	25,329	23,359
Light and medium crude oil combined production ⁽¹⁾	(bbl/d)	12,234	12,794	13,795	12,547	14,856
Total crude oil production	(bbl/d)	39,974	38,106	36,797	37,876	38,215

Conventional natural gas production ⁽¹⁾	(mcf/d)	2,633	3,192	4,760	3,278	6,042
Natural gas liquids production⁽¹⁾	(boe/d)	1,970	1,950	1,635	1,837	1,644
Total production ⁽²⁾	(boe/d) ⁽³⁾	42,406	40,616	39,267	40,288	40,919

Inventory Balance
Colombia	(bbl)	501,778	777,158	551,715	501,778	551,715
Peru	(bbl)	480,200	480,200	480,200	480,200	480,200
Ecuador	(bbl)	47,488	58,026	44,479	47,488	44,479
Total Inventory	(bbl)	1,029,466	1,315,384	1,076,394	1,029,466	1,076,394

Brent price Reference	($/bbl)	74.01	78.71	82.85	79.86	82.17
Produced crude oil and gas sales ⁽⁴⁾	($/boe)	67.18	71.11	77.98	72.84	75.16
Purchase crude net margin ⁽⁴⁾	($/boe)	(3.22)	(3.05)	(2.22)	(2.73)	(2.23)
Oil and gas sales, net of purchases ⁽⁴⁾	($/boe)	63.96	68.06	75.76	70.11	72.93
Gain (loss) on oil price risk management contracts⁽⁵⁾⁽⁶⁾	($/boe)	0.07	(0.45)	(0.69)	(0.70)	(0.80)
Royalties ⁽⁵⁾	($/boe)	(0.88)	(0.91)	(1.79)	(1.33)	(2.98)
Net sales realized price ⁽⁴⁾	($/boe)	63.15	66.70	73.28	68.08	69.15
Production costs (excluding energy cost), net of realized FX hedge impact⁽⁴⁾	($/boe)	(7.66)	(8.88)	(9.69)	(9.34)	(8.76)
Energy costs, net of realized FX hedge impact ⁽⁴⁾	($/boe)	(5.29)	(5.11)	(5.06)	(5.11)	(4.49)
Transportation costs, net of realized FX hedge impact⁽⁴⁾	($/boe)	(11.20)	(12.12)	(11.02)	(11.39)	(11.21)
Operating netback per boe ⁽⁴⁾	($/boe)	39.00	40.59	47.51	42.24	44.69

Financial Results

Oil & gas sales, net of purchases ⁽⁷⁾	($M)	216,370	214,084	240,105	851,451	905,249
Gain (loss) on oil price risk management contracts ⁽⁶⁾	($M)	253	(1,425)	(2,198)	(8,457)	(9,903)
Royalties	($M)	(2,971)	(2,853)	(5,683)	(16,104)	(36,949)
Net sales⁽⁷⁾	($M)	213,652	209,806	232,224	826,890	858,397
Net (loss) income ⁽⁸⁾	($M)	(29,401)	16,588	92,038	(24,162)	193,497
Per share – basic	($)	(0.36)	0.20	1.08	(0.29)	2.27
Per share – diluted	($)	(0.36)	0.19	1.04	(0.29)	2.19
General and administrative	($M)	13,170	12,719	16,891	52,373	53,907
Outstanding Common Shares	Number of shares	80,793,387	84,167,856	85,151,216	80,793,387	85,151,216
Operating EBITDA ⁽⁷⁾	($M)	113,479	103,184	121,036	424,232	467,219

Average FX Exchange Rate	COP/USD	4,347.10	4,094.04	4,070.15	4,104.42	4,264.91
Cash provided by operating activities	($M)	168,691	124,610	73,432	510,032	411,794
Capital expenditures ⁽⁷⁾	($M)	85,866	82,411	82,292	317,856	442,734
Cash and cash equivalents - unrestricted	($M)	192,577	205,572	159,673	192,577	159,673
Restricted cash short and long-term ⁽⁹⁾	($M)	30,249	34,752	30,300	30,249	30,300
Total cash ⁽⁹⁾	($M)	222,826	240,324	189,973	222,826	189,973
Total debt and lease liabilities⁽⁹⁾	($M)	506,037	531,235	536,822	506,037	536,822
Consolidated total indebtedness (Excl. Unrestricted Subsidiaries) ⁽¹⁰⁾	($M)	414,481	415,387	430,170	414,481	430,170
Net Debt (Excluding Unrestricted Subsidiaries)⁽¹⁰⁾	($M)	277,298	267,043	318,092	277,298	318,092

⁽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 press 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.

⁽²⁾ Represents W.I. production before royalties. Refer to the "Further Disclosures" section on page 44 of the Company's management's discussion and analysis of the three months and year ended on December 31, 2024 ("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 is 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 278 of the MD&A.

⁽⁵⁾Supplementary financial measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 278 of the MD&A.

⁽⁶⁾ Includes the net of the put premiums paid for expired position and the positive cash settlement received from oil price contracts during the period. Please refer to the "Loss (gain) on risk management contracts" section on page 19 of the MD&A for further details.

⁽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 278 of the MD&A.

⁽⁸⁾ Net (loss) income 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 287 of the MD&A.

⁽¹⁰⁾ "Unrestricted Subsidiaries" include CGX Energy Inc. ("CGX"), listed on the TSX Venture Exchange under the trading symbol "OYL", FEC ODL Holdings Corp., including its subsidiary Frontera Pipeline Investment AG ("PIL" formerly Pipeline Investment Ltd), Frontera BIC Holding Ltd. and Frontera Bahía Holding Ltd. ("Frontera Bahia"), including 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 34 of the MD&A.

Fourth Quarter and Full Year 2024 Operational and Financial Results:

The Company recorded a net loss of $29.4 million or $0.36/share in the fourth quarter of 2024, compared with a net income of $16.6 million or $0.20/share in the prior quarter and net income of $92.0 million or $1.08/share in the fourth quarter of 2023. For the year ended December 31, 2024, the Company reported net loss of $24.2 million, compared to net income of $193.5 million for the year ended December 31, 2023. Net loss for the fourth quarter included income tax expense of $33.4 million (including $36.5 million of deferred income tax expenses), finance expenses of $21.8 million, $8.9 million related to loss on risk management contracts, and foreign exchange loss of $1.8 million, partially offset by income from operations of $14.9 million (net of a non cash impairment expense of $30.1 million) and $13.2 million from share of income from associates.
Production averaged 42,406 boe/d in the fourth quarter of 2024, up 4% compared to 40,616 boe/d in the prior quarter and 39,267 boe/d in the fourth quarter of 2023. In 2024, Frontera's production averaged 40,288 boe/d, within the Company's guidance of 40,000 - 42,000 boe/d

	Q4 2024	Q3 2024	Q4 2023	2024	2023
Heavy crude oil production (bbl/d)	27,740	25,312	23,002	25,329	23,359
Light and medium crude oil production (bbl/d)	12,234	12,794	13,795	12,547	14,856
Conventional natural gas production (mcf/d)	2,633	3,192	4,760	3,278	6,042
Natural gas liquids production(boe/d)	1,970	1,950	1,635	1,837	1,644
Total production	42,406	40,616	39,267	40,288	40,919

Heavy oil asset performance remained strong throughout the year, up 8.4% on a year-over-year basis, supported by successful drilling campaigns in both the CPE-6 and Sabanero blocks, and increased water disposal capacity in the CPE-6 block. Light and medium crude oil and conventional natural gas production decreased primarily as a result of natural declines and well failures, and the relinquishment of the Abanico production contract on October 10, 2024.

Operating EBITDA was $113.5 million in the fourth quarter of 2024 compared to $103.2 million in the prior quarter and $121.0 million in the fourth quarter of 2023. The increase in Operating EBITDA compared to the prior quarter was mainly due to lower production costs (excluding energy costs) and transportation costs, partially offset by lower Brent oil prices and higher oil price differentials during the quarter. Frontera's average Brent oil price was $79.33 in 2024, generating $424.2 million of EBITDA within the Company's guidance range of $400 - $450 million (estimated at $80/bbl Brent).
Cash provided by operating activities in the fourth quarter of 2024 was $168.7 million, compared to $124.6 million in the prior quarter and $73.4 million in the fourth quarter of 2023.
The Company reported a total cash position of $222.8 million at December 31, 2024, compared to $240.3 million at September 30, 2024 and $190.0 million at December 31, 2023. The Company generated $510.0 million of cash from operations in 2024, compared to $411.8 million in 2023. During the year, the Company primarily invested $318 million of capital expenditures, and paid $74.8 million in net debt service payments, $4 million to repurchase senior notes and $50 million in shareholder distributions.
As at December 31, 2024, the Company had a total crude oil inventory balance of 1,029,466 bbls compared to 1,315,384 bbls at September 30, 2024. As of December 31, 2024, the Company had a total inventory balance in Colombia of 501,778 barrels, including 248,985 crude oil barrels and 252,793 barrels of diluent and others. This compares to 777,158 as of September 30, 2024, and 551,715 barrels as at December 31, 2023. The decrease in inventory balance was primarily due to higher sales during the quarter.
Capital expenditures were approximately $85.9 million in the fourth quarter of 2024, compared with $82.4 million in the prior quarter and $82.3 million in the fourth quarter of 2023. During the fourth quarter, the Company drilled 2 development wells at its Sabanero block. For the full year 2024, the Company drilled a total of 68 wells (including two injector wells) at the Quifa, CPE-6, Sabanero and Perico block, and executed capital expenditures of approximately $318 million within the Company's guidance of $272 - $335 million.
The Company's net sales realized price was $63.15/boe in the fourth quarter of 2024, compared to $66.70/boe in the prior quarter and $73.28/boe in the fourth quarter of 2023. The decrease in the Company's net sales realized price quarter over quarter was mainly driven by lower Brent benchmark oil prices, weaker oil price differentials and higher cost of diluent and oil purchased, partially offset by lower royalties and realized gains from oil price risk management contracts. The Company's net sales realized price in 2024 was $68.08/boe compared to $69.15/boe in 2023.
The Company's operating netback was $39.00/boe in the fourth quarter of 2024, compared with $40.59/boe in the prior quarter and $47.51/boe in the fourth quarter of 2023. The decrease was a result of lower net sales realized prices, partially offset by a decrease in production costs (excluding energy cost) and transportation cost. The Operating netback for the year ended December 31, 2024, was $42.24/boe, compared to $44.69/boe in 2023.
Production costs (excluding energy cost), net of realized FX hedge impact, averaged $7.66/boe in the fourth quarter of 2024, compared with $8.88/boe in the prior quarter and $9.69/boe in the fourth quarter of 2023. The decrease in production costs was driven by strong cost controls, higher production and reduced well intervention activities during the quarter.
Energy costs, net of realized FX hedging impacts, averaged $5.29/boe in the fourth quarter of 2024, compared to $5.11/boe in the prior quarter and up from $5.06/boe in the fourth quarter of 2023. The increase during the quarter was related to greater heavy crude oil production levels partially offset by fixed-price contracts signed during the year 2024.
Transportation costs, net of realized FX hedging impacts, averaged $11.20/boe in the fourth quarter of 2024, compared with $12.12/boe in the prior quarter and up from $11.02/boe in the fourth quarter of 2023. The decrease in transportation costs during the quarter was the result of lower volumes transported primarily attributed to improved domestic wellhead sales.
ODL volumes transported were 235,528 bbl/d during the fourth quarter of 2024, compared to 243,997 in the third quarter of 2024, the decreased was mainly due to lower production from Llanos 34 transported through the pipeline.
Total Puerto Bahia liquids volumes were 61,990 bbl/d during the fourth quarter compared to 46,964 bbl/d the third quarter of 2024. The increase in volumes during the quarter was related to improved waterway levels improving traffic flows into the port as well as additional volumes received from Ecopetrol.
Adjusted Infrastructure EBITDA in the fourth quarter of 2024 was $27.5 million, compared to $26.2 million in the third quarter 2024.

2024 Year End Reserves Evaluation

Frontera announced the results of its annual independent reserves assessment for the year ended December 31, 2024, conducted by 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, 2024, are located in Colombia and Ecuador.

Key Highlights:

Added 2 MMboe of 2P gross reserves, for total Company 2P gross reserves of 151.3 MMboe consisting of 67% heavy crude oil, 21% light and medium crude oil, 9% conventional natural gas and 3% natural gas liquids, compared to 164.1 MMboe at December 31, 2023.
2024 year-end gross proved developed producing reserves are 36.7 MMboe and the proved developed producing reserves replacement ratio was 78%.
Delivered three-year average gross PDP, 1P and 2P Reserves Replacement Ratio of 111%, 60% and 40%, respectively.

Reserve Replacement Ratio (%)	PDP Reserves	1P Reserves	2P Reserves
2022	150 %	52 %	77 %
2023	105 %	85 %	28 %
2024	78 %	45 %	13 %
Three-year average	111 %	60 %	40 %

Delivered a 1P gross reserves life index of 6.8 years compared to 7.3 years at December 31, 2023, and a 2P reserves life index of 10.3 years compared to 11.4 years at December 31, 2023.
The NPV of the Company's 2P reserves, discounted at 10% before tax, is $3.4 billion ($22.4/2P boe) at December 31, 2024, compared to $3.5 billion ($21.6/2P boe) at December 31, 2023. The small decrease in NPV10 for the 2P reserves is primarily due to the reserves decrease, however the NPV10 per boe increased by 4% driven by operational efficiencies, optimization of development plans and reduced future development costs.
Reduced the future development cost for 2P reserves by $228 million to $1 billion at December 31, 2024, compared to $1.25 billion at December 31, 2023. The reduction is primarily due to the Company's focus on sustained production, value over volumes and optimized development plans.

2024 Year-End D&M Certified Gross Reserves Volumes ⁽¹⁾

Reserve Category	December 31, 2024 Mboe⁽²⁾	December 31, 2023 Mboe⁽²⁾	Percentage Change 2024 versus 2023
Proved Developed Producing (PDP)	36,708	39,976	(8.2) %
Proved Developed Non-Producing (PDNP)	7,610	7,864	(3.2) %
Proved Undeveloped (PUD)	56,317	60,889	(7.5) %
Total Proved (1P)	100,636	108,729	(7.4) %
Probable	50,703	55,363	(8.4) %
Total Proved Plus Probable (2P)	151,339	164,092	(7.8) %
Possible⁽³⁾	33,247	36,563	(9.1) %
Total Proved Plus Probable Plus Possible (3P)	184,587	200,654	(8.0) %

⁽⁷⁾ Gross reserves represent Frontera's W.I. before royalties

⁽⁸⁾ See "Boe Conversion" section in the "Advisories" section, at the end of this press release.

⁽⁸⁾ 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 successfully achieved 100% of its 2024 sustainability goals, marking the first milestone towards its 2028 goals.

On environmental achievements, the Company restored, protected and preserved 769 hectares of land, as well as recirculated 35.2% of its operational water and utilized 43.4% of generated waste.

Regarding the Company's social contributions, in health and safety, Frontera achieved its best Total Recordable Incident Rate ("TRIR") performance ever, with a 6% reduction compared to the previous year.

Following its fourth social investment lines, it invested approximately $4.1 million in social projects, benefiting 66,303 people near its operations, and increased local purchases from local contractors by 2% compared to last year.

As well in 2024, Frontera was ranked among the top 20 best companies to work in Colombia by Great Place to Work

On the governance front, the Company implemented an effective cybersecurity plan, maintaining a zero rate of material cybersecurity incidents. For the fourth consecutive time, Frontera during 2024 was recognized as one of the most ethical companies by Ethisphere.

Enhancing Shareholder Returns

The Company delivered on its commitment to return capital to shareholders. In total, the Company efforts have resulted in the returned of $83 million to its shareholders since 2024 including $15.1 million in dividends, $7.8 million in common shares repurchases through its normal course issuer bid ("NCIB") program, $31 million through its substantial issuer bid ("SIB") completed in October 2024 and an additional $30 million SIB completed in January 2025. Both SIB transactions achieved over 90% shareholder participation. The Company has also acquired $6 million in Senior Unsecured Notes achieving an average repurchase price of 80.15%.

Since 2022, the Company has returned over $180 million to its shareholders through normal course issuer bids, substantial issuer bids and dividends.

The Company continues to consider future investor initiatives in 2025, including potential additional dividends, distributions, or bond buybacks, based on the overall results of our businesses, oil prices, cash flow generation and the Company's strategic goals.

SIB: On September 4, 2024, the Company announced an SIB through which the Company bought back 3,375,000 shares for cancellation at a purchase price of CAD$12.00 per share for an aggregate cost of approximately $31 million. The offer expired on October 17, 2024, with a total of 77,565,602 shares validly tendered. Shareholders who tendered had approximately 4.35% of their shares purchased by the Company.

On December 16, 2024, the Company announced another SIB, through which the Company bought back 3,500,000 shares for cancellation at a purchase price of CAD$12.00 per share for an aggregate cost of approximately $30 million. The offer expired on January 24, 2025, with a total of 73,083,094 shares validly tendered. Shareholders who tendered had approximately 4.79% of their shares purchased by the Company.

NCIB: Under the Company's NCIB which commenced on November 21, 2023, and expired on November 20, 2024, Frontera was authorized to repurchase for cancellation up to 3,949,454 of its common shares. In 2024, the Company repurchased approximately 1,271,600 common shares for cancellation, or approximately 1.6% of its common shares, for $7.8 million.

Frontera also announces that the Company intends to file with the TSX a notice of intention to commence a normal course issuer bid for its Common Shares (the "NCIB"). Subject to the acceptance of the TSX, the Company would be permitted under the NCIB to purchase, for cancellation, up to that number of Common Shares equal to the greater of (a) 5% of the Company's issued and outstanding Common Shares, and (b) 10% of the Company's "public float" (as such term is defined in the TSX Company Manual), during the 12-month period following commencement of the NCIB.

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, 2025, to shareholders of record at the close of business on April 2, 2025.

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 which provides 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

Bond Buybacks: In 2024, the Company repurchased in the open market $5 million of its 2028 Unsecured Notes for cash, for a total cash consideration of $4.0 million and recognizing a gain of $1 million. As a result, the carrying value for the 2028 Unsecured Notes as of December 31, 2024, is $389.8 million.

Subsequent to the quarter, the Company repurchased an additional $1 million of its 2028 Unsecured Notes.

Strategic Alternatives Review Processes: The Company's strategic alternatives review for its Infrastructure business is reaching its final stages. Since its launch in May 2024, the Company has prepared a virtual data room, held management presentations and engaged in discussions with several interested third parties. The Company is working diligently to conclude its review process analyzing various options and will communicate its outcome when appropriate. Frontera has retained Goldman Sachs & Co. LLC as financial advisor in connection with the strategic alternatives review. There can be no guarantee that this strategic alternative review process will result in a transaction.

2025 Operational Update

Q1 2025 production to date is approximately 40,400 boe/d, mainly due to unexpected well failures within the Light and Medium assets occurring near the end of 2024. These issues are being addressed, and the Company remains confident in meeting the 2025 production guidance.

On the exploration side, The Greta Norte-1 well was drilled on January 18, 2025, and reached a total depth of 12,174 feet MD on February 5, 2025. Integration of drilling data and petrophysical interpretation identified 12.5 feet of net pay, and the well is currently in evaluation phase.

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.

Colombia & Ecuador Upstream Onshore

Colombia

During the fourth quarter of 2024, Frontera produced 40,656 boe/d from its Colombian operations (consisting of 27,740 bbl/d of heavy crude oil, 10,484 bbl/d of light and medium crude oil, 2,633 mcf/d of conventional natural gas and 1,970 boe/d of natural gas liquids).

In the fourth quarter of 2024, the Company drilled 2 development wells at the Sabanero block and completed well interventions at 9 others.

Currently, the Company has 1 drilling rigs, and 3 intervention rigs active at its Sabanero, Quifa and CPE-6 blocks in Colombia.

Quifa Block: Quifa SW and Cajua

At Quifa, fourth quarter 2024 production averaged 16,890 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company invested new and improved flow lines facilities in the block to support production for new wells and the SAARA connection.

In 2024, the Company has handled an average of approximately 1.6 million barrels of water per day in Quifa including SAARA.

CPE-6

At CPE-6, fourth quarter 2024 production averaged approximately 8,466 bbl/d of heavy crude oil, increasing 14% from 7,459 bbl/d during the third quarter of 2024. During the quarter, the Company also achieved record daily production of 8,933 bbl/d.

During the year, the Company invested in the expansion of development facilities including the expansion of water handling capacity to 360Mwpd at the CPE-6 block.

During 2024, the Company handled an average of approximately 257 thousand barrels of water per day in CPE-6.

Other Colombia Developments

At Guatiquia, production during the fourth quarter 2024 averaged 5,690 bbl/d of light and medium crude compared with 5,801 bbl/d in the third quarter of 2024.

In the Cubiro block production averaged 1,310 bbl/d of light and medium crude oil in the fourth quarter of 2024 compared with 1,447 bbl/d in the third quarter 2024.

At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,883 boe/d of light and medium crude oil in the fourth quarter of 2024 compared to 1,934 boe/d of light and medium crude oil in the third quarter of 2024.

At the Sabanero block, production averaged 2,384 boe/d of heavy oil crude production in the fourth quarter of 2024 compared to 1,075 boe/d in the third quarter of 2024. the Company drilled 2 development wells during the fourth quarter and invested in the expansion of the block facilities.

Colombia Exploration Assets

During the fourth quarter of 2024, the Company's exploration focus remained on the Lower Magdalena Valley and Llanos Basins in Colombia. At the Cachicamo Block, the Papilio-1 well was spud on December 31, 2024, reaching a total depth of 8,580 feet MD by January 8, 2025. Integration of drilling data and petrophysical interpretation identified 21.5 feet of net pay, and initial production testing started on January 18, 2025, with 100 bopd with 96% BSW, well is currently producing approximately 135 bopd with 97% BSW.

At the VIM-1 Block, ongoing discussions with authorities and communities are taking place to drill the Hidra-1 well in 2025.

At the Llanos 119 Block, preliminary results from the seismic of 80 square kilometers of 3D seismic data were below the Company's expectations. Frontera has requested the transfer of commitments in the block and subsequent relinquishment. In addition, the Company is also engaged in pre-seismic and pre-drilling activities related to social and environmental studies in the Llanos-99 and VIM-46 blocks.

Ecuador

In Ecuador, fourth quarter 2024 production averaged approximately 1,750 bbl/d of light and medium crude oil compared to 1,776 bbl/d in the prior quarter.

At the Espejo Block, the Espejo Sur-B3 well continues its long-term tests with a production of 437 bbl/d gross and a BSW of 71%. The development plan is being assessed during the first quarter of 2025.

2. Infrastructure Colombia

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. Starting in 2024, the Infrastructure Colombia Segment also includes the Company's reverse osmosis water treatment facility (SAARA) and its palm oil plantation (ProAgrollanos).

On March 5, 2025, ODL's general assembly declared $152 million in dividends ($53.3 million, net to Frontera), a 100% payout ratio, payable in 2025.

On Puerto Bahia, the connection to the Reficar refinery is expected to become operational by the second quarter 2025. With respect to the LPG import project, working groups have been assembled and detailed engineering work is taking place.

Frontera processed 78,716 barrels of water per day at is SAARA reverse osmosis water-treatment facility during the fourth quarter 2024 and peaked at 185,000 barrels of water per day in November.

The Company continues to execute on its strategic priorities supporting the long-term growth and sustainability of the businesses.

Infrastructure Colombia Segment Results

Adjusted Infrastructure EBITDA in the fourth quarter of 2024 was $27.5 million, compared with $26.2 million during the third quarter of 2024.

	Three months ended December 31		Year ended December 31
($M)	2024	2023	2024	2023
Adjusted Infrastructure Revenue⁽¹⁾	45,278	43,622	171,392	169,920
Adjusted Infrastructure Operating Cost⁽¹⁾	(13,794)	(13,221)	(50,346)	(48,379)
Adjusted Infrastructure General and Administrative⁽¹⁾	(3,952)	(3,077)	(13,823)	(11,484)
Adjusted Infrastructure EBITDA⁽¹⁾	27,532	27,324	107,223	110,057

⁽¹⁾ Non-IFRS financial measure

Segment capital expenditures for the three months ended December 31, 2024, were $26.0 million mostly related to investments at Puerto Bahia including (i) Reficar Connection Project execution, including engineering and civil works, costs related to the project's rights of way, among others (ii) tanks major maintenance, and (iii) general cargo terminal equipment and facilities; and (iv) investments in the SAARA project.

	Three months ended December 31		Year ended December 31
($M)	2024	2023	2024	2023
Revenue	13,873	10,625	48,542	49,041
Costs	(8,099)	(8,798)	(31,438)	(33,296)
General and Administrative expenses	(1,507)	(1,055)	(5,903)	(5,527)
Depletion, depreciation and amortization	(1,877)	(1,938)	(7,576)	(6,546)
Restructuring, severance and other costs	(407)	(446)	(2,060)	(1,547)
Infrastructure (loss) income from operations	1,983	(1,612)	1,565	2,125
Share of Income from associates - ODL	13,200	14,833	53,912	56,476
Infrastructure Colombia Segment Income	15,183	13,221	55,477	58,601
Infrastructure Colombia Segment cash flow from operating activities	14,788	4,243	58,034	42,579
Capital Expenditures Infrastructure Colombia segment⁽¹⁾	25,999	9,724	47,882	15,296

⁽¹⁾ Non-IFRS financial measures (equivalent to a "non-GAAP financial measures", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures'' section on page 22 of the MD&A .

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

	Three months ended December 31		Year ended December 31
(bbl/d)	2024	2023	2024	2023
At Rubiales Station	167,272	173,888	169,890	169,701
At Jagüey and Palmeras Station	68,256	78,922	73,779	73,916
Total	235,528	252,810	243,669	243,617

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

	Three months ended December 31		Year ended December 31
(bbl/d)	2024	2023	2024	2023
FEC volumes	11,626	11,971	13,513	12,863
Third party volumes	50,364	40,783	42,507	47,855
Total	61,990	52,754	56,020	60,718

The following table shows the barrels of water per day treated and irrigated in SAARA and field performance indicators for Proagrollanos:

		Three months ended December 31		Year ended December 31
		2024	2023	2024	2023
Fresh fruit bunch from palm oil (produced - sold)	(tons)	6,183	3,650	25,357	21,218

Production per hectare per year⁽¹⁾	(tons/ ha/year)	8.4	7.17	8.4	7.17
Palm oil fruit price	($/ton)	206	156	176	166

Volumes of reverse osmosis water treated	(bwpd)	78,716	71,406	44,121	56,441
Volumes of water irrigated in palm oil cultivation	(bwpd)	80,276	49,201	40,837	41,159

⁽¹⁾ Tons per hectare per year for the three months ended December 31, are calculated using the total production for the last twelve months ended December 31.

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.

The following table summarizes Frontera's hedging position as of March 10, 2025.

Term	Type of Instrument	Positions (bbl/d)	Strike Prices Put/Call
Jan 25	Put	11,000	70
Feb 25	Put	18,786	70
Mar 25	Put	16,935	70
1Q-2025	Total Average	15,467
Apr 25	Put	7,400	70
May 25	Put	10,548	70
May 25	Put Spread	6,452	70/55
Jun 25	Put	10,900	70/55
Jun 25	Put Spread	6,667	70.00
2Q-2025	Total Average	14,022

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 10, 2025, the Company had the following foreign currency derivatives contracts:

Term	Type of Instrument	Open Interest (US$ MM)	Strike Prices Put/Call	Hedging Ratio
1Q-2025	Zero Cost Collars	60	4,150/4,618	40 %
2Q-2025	Zero Cost Collars	60	4,200/4,626	40 %
3Q-2025	Zero-cost Collars	60	4,200/4,795	40 %

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, 2024, as applied in the Reserves Report. The Company's net reserves after royalties at December 31, 2024, incorporate all applicable royalties under Colombia and Ecuador fiscal legislation 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 2024.

	Oil Equivalent Gross 2P Reserves (MMboe) ⁽¹⁾⁽²⁾
December 31, 2023	164.1
Discoveries	0
Extensions & Improved Recovery	0
Technical Revisions⁽³⁾	2.1
Acquisitions	0
Dispositions⁽⁴⁾	(0.1)
Economic Factors	0
Production⁽⁵⁾	(14.7)
December 31, 2024	151.3

⁽¹⁾ See "Boe Conversion" section in the "Advisories" section, 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 technical revisions mainly in the Sabanero block, Quifa block, Cubiro, VIM-1 block and the Guatiquia block.

⁽⁴⁾ Mainly associated with the planned disposition of the Abanico Fiels and Guarimena block .

⁽⁵⁾ Production represents the Company's production for the twelve month period ended December 31, 2024, for asset 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, 2024⁽²⁾	December 31, 2023 ⁽³⁾
Total Proved (1P)	6.8 years	7.3 years
Total Proved Plus Probable (2P)	10.3 years	11.4 years
Total Proved Plus Probable Plus Possible (3P)	12.5 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 2024 production of 14.7 MMboe.

⁽³⁾ Calculated by dividing the total relevant gross reserve category by the 2023 production of 14.9 MMboe.

Net Present Value of Future Revenue Before Tax Summary - D&M Reserves Report (2024 Brent Forecast)⁽¹⁾

Reserves Category	December 31, 2023	December 31, 2024	December 31, 2024
$(000's), except per share data	NPV10 ($ 000's) ⁽²⁾	NPV10 ($ 000's)⁽³⁾	NPV10 (C$/share) ⁽⁴⁾
Proved Developed Producing (PDP)	981,636	942,785	$16.78
Proved Developed Non-Producing (PDNP)	226,047	187,260	$3.33
Proved Undeveloped	1,124,358	1,130,849	$20.13
Total Proved (1P)	2,332,041	2,260,895	$40.24
Probable	1,212,175	1,129,008	$20.09
Total Proved Plus Probable (2P)	3,544,216	3,389,903	$60.34
Possible⁽⁵⁾	862,919	718,012	$12.78
Total Proved Plus Probable Plus Possible (3P)	4,407,135	4,107,915	$73.11

⁽¹⁾ See "Advisories" at the end of this press release. The Reserves Report

⁽²⁾ Includes Future development costs ("FDC") as at December 31, 2023, of $945 million of 1P and $1,541 million for 2P

⁽³⁾ Includes FDC as at December 31, 2024, of $658 million for 1P and $1,023 million for 2P

⁽⁴⁾ Calculated by dividing the December 31, 2024 NPV10 value by 80,793,387 shares outstanding as at December 31, 2024 and a USD:CAD foreign exchange rate of 1.4380. Per share valuations do not attribute any value to the Company's material ownership in 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 Cost ("FDC") – Based on Forecast Prices and Costs

($ 000's)	Total Proved (1P)	Total Proved Plus Probable (2P)
2025	91,906	111,837
2026	146,636	228,567
2027	160,111	223,422
2028	122,965	215,839
2029	70,345	112,238
Beyond 2029	65,802	126,223
Total Undiscounted	657,766	1,023,126

About Frontera's 2024 Year-End Estimated Reserves

The Company's 2024 year-end estimated reserves were evaluated by D&M in their report dated February 6, 2025, with an effective date of December 31, 2024 (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 10, 2025. See "Advisory Note Regarding Oil and Gas Information" section in the "Advisories", at the end of this news release.

Fourth Quarter and Year End 2024 Financial Results, Year End Reserves and Operational Update Conference Call Details

A conference call for investors and analysts will be held on Monday, March 10, 2025, at 11:30 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:

RapidConnect URL:	https://emportal.ink/4k5ohlq
Participant Number (Toll Free North America):	1-888-510-2154
Participant Number (Toll Free Colombia):	+57-601-489-8375
Participant Number (International):	1-437-900-0527
Conference ID:	12268
Webcast URL:	www.fronteraenergy.ca

A replay of the conference call will be available until 11:59 p.m. Eastern Time on March 17, 2025.

Encore Toll free Dial-in Number:	1-888-660-6345
International Dial-in Number:	1-289-819-1450
Encore ID:	12268

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 22 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 statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, the Company's strategic alternatives review process for its Colombian Infrastructure business, the Company's goal of enhancing shareholder value by returning capital to shareholders, the Company's intent to consider future shareholder initiatives, the operational timing of the connection project between Puerto Bahia and Reficar, the water handling capacity at its SAARA water treatment facility, the Company's exploration and development plans and objectives, production levels, profitability, costs, future income generation capacity, cash levels (including the timing and ability to release restricted cash), regulatory approval, and the Company's hedging program and its ability to mitigate the impact of changes in oil prices) are forward-looking statements.

These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, 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. Factors that could cause actual results or events to differ materially from current expectations include, among other things: the ability of the Company to successfully conclude on a timely basis or at all its strategic review process; volatility in market prices for oil and natural gas; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; the Company's ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; political developments in the countries where the Company operates; the uncertainties involved in interpreting drilling results and other geological data; geological, technical, drilling and processing problems; timing on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility, the ability of the Company and CGX to reach an agreeement with the Government of Guyana in respect of the Corentyne block, and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 10, 2025 filed on SEDAR+ at www.sedarplus.ca.

Any forward-looking statement 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 statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.

This news release contains future oriented financial information and financial outlook information (collectively, "FOFI") (including, without limitation, statements regarding expected average production), and are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the Company's activities and results, and such information may not be appropriate for other purposes. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments, however, actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it is made, and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or otherwise, unless required by applicable laws.

Non-IFRS Financial Measures

This press 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 measures do not have standardized IFRS definitions. The Company's determination of these non-IFRS 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 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 the MD&A.

Operating EBITDA

EBITDA is a commonly used non-IFRS financial measure that adjusts net 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.

A reconciliation of Operating EBITDA to net loss (income) is as follows:

	Three months ended December 31		Year ended December 31
($M)	2024	2023	2024	2023

Net loss (income)	(29,401)	92,038	(24,162)	193,497
Finance Income	(1,852)	(2,270)	(8,386)	-9984
Finance expenses	21,810	16,865	74,205	64,185
Income tax expense	33,401	(39,007)	103,105	4,130
Depletion, depreciation and amortization	65,249	68,411	262,518	278,269
Minimum work commitment paid	—	358	—	358
Expense (recovery) of asset retirement obligation	(2,214)	(1,621)	2,335	(25,622)
Expenses of impairment	30,147	1,417	31,927	25,236
Trunkline incident costs	1,485	—	5,314	—
Post-termination obligation	705	11,160	577	18,814
Shared-based compensation	835	(745)	1,726	96
Restructuring, severance and other cost	2,096	3,744	5,312	8,548
Share of income from associates	(13,200)	(14,833)	(53,912)	(56,476)
Foreign exchange loss (gain)	1,795	(2,724)	11,041	(12,275)
Other loss, net	(6,526)	(4,554)	899	(8,936)
Unrealized loss (gain) on risk management contracts	10,035	(7,000)	13,976	(11,880)
Realized loss on risk management contract for ODL dividends received	(921)	—	(633)	—
Non-controlling interests	35	(203)	(609)	(741)
Gain on repurchased 2028 Unsecured Notes	—	—	(1,001)	—
Operating EBITDA	113,479	121,036	424,232	467,219

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
($M)	2024	2023	2024	2023

Consolidated Statements of Cash Flows
Additions to oil and gas properties, infrastructure port, and plant and equipment	93,762	70,294	328,177	241,185
Additions to exploration and evaluation assets	2,030	5,171	22,480	195,210
Total additions in Consolidated Statements of Cash Flows	95,792	75,465	350,657	436,395
Non-cash adjustments ⁽¹⁾	(8,690)	6,827	(29,084)	6,339
Cash adjustments ⁽²⁾	(1,236)	—	(3,717)	—
Total Capital Expenditures	85,866	82,292	317,856	442,734

⁽¹⁾ Related to material inventory movements, capitalized non-cash items and other adjustments

⁽²⁾ Investments related to the replacement and repairs of the affected assets in the Quifa Block due to the trunkline incident

Infrastructure Colombia Calculations

Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs 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 Costs 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 the Infrastructure Colombia Segment including ODL's general and administrative direct participation interest.

A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative is provided below.

	Three months ended December 31		Year ended December 31
($M)	2024	2023	2024	2023

Revenue Infrastructure Colombia Segment	13,873	10,625	48,542	49,041
Revenue from ODL	89,728	94,277	351,000	345,370
Direct participation interest in the ODL	35 %	35 %	35 %	35 %
Equity adjustment participation of ODL⁽¹⁾	31,405	32,997	122,850	120,879
Adjusted Infrastructure Revenues	45,278	43,622	171,392	169,920

Operating Cost Infrastructure Colombia Segment	(8,099)	(8,798)	(31,438)	(33,296)
Operating Cost from ODL	(16,270)	(12,637)	(54,020)	(43,094)
Direct participation interest in the ODL	35 %	35 %	35 %	35 %
Equity adjustment participation of ODL⁽¹⁾	(5,695)	(4,423)	(18,908)	(15,083)
Adjusted Infrastructure Operating Costs	(13,794)	(13,221)	(50,346)	(48,379)

General and administrative Infrastructure Colombia Segment	(1,507)	(1,055)	(5,903)	(5,527)
General and administrative from ODL	(6,985)	(5,776)	(22,628)	(17,019)
Direct participation interest in the ODL	35 %	35 %	35 %	35 %
Equity adjustment participation of ODL⁽¹⁾	(2,445)	(2,022)	(7,920)	(5,957)
Adjusted Infrastructure General and Administrative	(3,952)	(3,077)	(13,823)	(11,484)

⁽¹⁾ Revenues and expenses related to the ODL are accounted for using the equity method described in the Note 12 of the Interim Condensed Consolidated Financial Statements.

Adjusted Infrastructure EBITDA

The Adjusted Infrastructure EBITDA is a non-IFRS financial measure used to assist in measuring the operating results of the Infrastructure Colombia Segment business.

	Three months ended December 31		Year ended December 31
($M)	2024	2023	2024	2023
Adjusted Infrastructure Revenue⁽¹⁾	45,278	43,622	171,392	169,920
Adjusted Infrastructure Operating Cost⁽¹⁾	(13,794)	(13,221)	(50,346)	(48,379)
Adjusted Infrastructure General and Administrative⁽¹⁾	(3,952)	(3,077)	(13,823)	(11,484)
Adjusted Infrastructure EBITDA⁽¹⁾	27,532	27,324	107,223	110,057

⁽¹⁾ Non-IFRS financial measure

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 10 of the MD&A.

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 Infrastructure Colombia 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 9.

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 costs. 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
	2024	2023	2024	2023
Purchased crude oil and products sales ($M)⁽¹⁾	227,276	247,134	884,643	932,977
Purchase crude net margin ($M)	(10,906)	(7,029)	(33,192)	(27,728)
Oil and gas sales, net of purchases ($M)	216,370	240,105	851,451	905,249
Sales volumes, net of purchases - (boe)	3,383,116	3,169,346	12,144,246	12,411,825
Produced crude oil and gas sales ($/boe)	67.18	77.98	72.84	75.16
Oil and gas sales, net of purchases ($/boe)	63.96	75.76	70.11	72.93

⁽¹⁾ Excludes sales from infrastructure services as they are not part of the oil and gas segment. For further information, refer to the "Infrastructure Colombia" section on page 18.

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
	2024	2023	2024	2023
Oil and gas sales, net of purchases ($M) ⁽¹⁾	216,370	240,105	851,451	905,249
Crude oil sales volumes, net of purchases - (bbl)	3,342,067	3,118,407	11,936,680	12,042,019
Conventional natural gas sales volumes - (mcf)	234,321	289,993	1,183,171	2,107,707
Realized oil price, net of purchases ($/bbl)	64.27	76.35	70.70	74.23
Realized conventional natural gas price ($/mcf)	6.79	6.93	6.37	5.41

(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 and 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
($M)	2024	2023	2024	2023
Oil and gas sales, net of purchases ($M) ⁽¹⁾	216,370	240,105	851,451	905,249
(-) Premiums paid on oil price risk management contracts ($M)	253	(2,198)	(8,457)	(9,903)
(-) Royalties ($M)	(2,971)	(5,683)	(16,104)	(36,949)
Net Sales ($M)	213,652	232,224	826,890	858,397
Sales volumes, net of purchases (boe)	3,383,116	3,169,346	12,144,246	12,411,825
Oil and gas sales, net of purchases ($/boe)	63.96	75.76	70.11	72.93
Premiums paid on oil price risk management contracts ($/boe)⁽²⁾	0.07	(0.69)	(0.70)	(0.80)
Royalties ($/boe) ⁽²⁾	(0.88)	(1.79)	(1.33)	(2.98)
Net sales realized price ($/boe)	63.15	73.28	68.08	69.15

⁽¹⁾ Non-IFRS financial measure.

⁽²⁾ Supplementary financial measure.

Purchase crude net margin

Purchase crude net margin is a non-IFRS financial measure that is calculated using the purchased crude oil and products sales, less the cost of those volumes purchased from third parties including its transportation and refining costs. Purchase crude net margin per boe is a non-IFRS ratio that is calculated using the Purchase crude net margin, 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
	2024	2023	2024	2023
Purchased crude oil and products sales ($M)	54,469	48,324	202,752	208,069
(-) Cost of diluent and oil purchases ($M) ⁽¹⁾	(65,375)	(55,353)	(235,944)	(235,797)
Purchase crude net margin ($M)	(10,906)	(7,029)	(33,192)	(27,728)
Sales volumes, net of purchases - (boe)	3,383,116	3,169,346	12,144,246	12,411,825
Purchase crude net margin ($/boe)	(3.22)	(2.22)	(2.73)	(2.23)

⁽¹⁾ Cost of third-party volumes purchased for use and resale in the Company's oil operations, including its transportation and refining costs.

Production costs (excluding energy cost), net of realized FX hedge impact, and production cost (excluding energy 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, 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
	2024	2023	2024	2023
Production costs (excluding energy cost) ($M)	29,091	37,122	139,726	139,917
(-) Realized gain on FX hedge attributable to production costs (excluding energy cost) ($M) ⁽¹⁾	—	(2,101)	(3,358)	(9,075)
Inter-segment costs	783	—	1,370	—
Production costs (excluding energy cost), net of realized FX hedge impact ($M) ⁽²⁾	29,874	35,021	137,738	130,842
Production (boe)	3,901,352	3,612,564	14,745,408	14,935,435
Production costs (excluding energy cost), net of realized FX hedge impact ($/boe)	7.66	9.69	9.34	8.76

⁽¹⁾ See "(Loss) Gain on Risk Management Contracts" on page 14.

⁽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 describes 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 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
	2024	2023	2024	2023
Energy costs ($M)	20,647	19,005	76,631	69,924
(-) Realized gain on FX hedge attributable to energy costs ($M) ⁽¹⁾	—	(738)	(1,267)	(2,900)
Energy costs, net of realized FX hedge impact ($M) ⁽²⁾	20,647	18,267	75,364	67,024
Production (boe)	3,901,352	3,612,564	14,745,408	14,935,435
Energy costs, net of realized FX hedge impact ($/boe)	5.29	5.06	5.11	4.49

⁽¹⁾ See "(Loss) Gain on Risk Management Contracts" on page 14.

⁽²⁾ Non-IFRS financial measure.

Transportation costs, net of realized FX hedge impact, and transportation costs, 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
	2024	2023	2024	2023
Transportation costs ($M)	39,128	34,750	148,513	151,416
(-) Realized gain on FX hedge attributable to transportation costs ($M) ⁽¹⁾	—	(753)	(982)	(3,264)
Transportation costs, net of realized FX hedge impact ($M) ⁽²⁾	39,128	33,997	147,531	148,152
Net Production (boe)	3,493,148	3,084,300	12,948,348	13,210,810
Transportation costs, net of realized FX hedge impact ($/boe)	11.20	11.02	11.39	11.21

⁽¹⁾ See "(Loss) Gain on Risk Management Contracts" on page 14.

⁽²⁾ Non-IFRS financial measure.

Supplementary Financial Measures

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

Realized (loss) gain 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 (loss) gain on oil risk management contracts per boe is a supplementary financial measure that is calculated using Realized (loss) gain on risk management contracts divided by total sales volumes, net of purchases.

Royalties per boe

Royalties includes royalties and amounts paid to previous owners of certain blocks in Colombia and cash payments for PAP. Royalties per boe is a supplementary financial measure that is calculated using the royalties divided by total sales volumes, net of purchases.

NCIB weighted-average price per share

Weighted-average price per share under the 2023 NCIB is a supplementary financial measure that corresponds to the weighted-average price of common shares purchased under the 2023 NCIB during the period. It is calculated using the total amount of common shares repurchased in U.S. dollars divided by the number of common shares repurchased.

Capital Management Measures

Restricted cash short- and long-term

Restricted cash (short- and long-term) is a capital management measure, that sums 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, is comprised by 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 is comprised of the debt of the 2028 Unsecured Notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets.

Definitions:

bbl(s)	Barrel(s) of oil
bbl/d	Barrel of oil per day
boe	Refer to "Boe Conversion" disclosure above
boe/d	Barrel of oil equivalent per day
Mcf	Thousand cubic feet
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.

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SOURCE Frontera Energy Corporation

Company Announcements

FRONTERA ANNOUNCES FOURTH QUARTER AND YEAR END 2024 RESULTS, YEAR-END RESERVES AND OPERATIONAL UPDATE