Frontera Announces Fourth Quarter and Year End 2022 Results

Recorded Net Income of $197.8 Million in Q4'22 and $286.6 Million for FY'22

Delivered Full Year Operating EBITDA of $641.9 Million, Up 70%
On Frontera's $98/Bbl Weighted Average Brent Price

Delivered 41,382 Boe/d 2022 Average Daily Production, Up 9%

Generated $54.3 Million of Midstream Segment Income,
From Standalone and Growing Midstream Business

Wei-1 Well Currently Ahead of Schedule and At 15,400 Feet

Repurchased 9.6 Million Common Shares Or 20% of the Public Float,
Returned More Than $91.4 Million To Shareholders in 2022 Via SIB and NCIB

Achieved 102% of 2022 ESG Goals, Offset 52% Of Emissions Through Carbon Credits,
Preserved And Restored 1,747 Hectares of Key Connectivity Corridors In Casanare And Meta, Colombia

The Company Reiterates 2023 Production Guidance Of 40,000-43,000 Boe/d,
 Increased Water-Handling Capacity at Quifa and CPE-6 Key Milestones on Path to 50,000 Boe/d Future

CALGARY, AB, Mar. 1, 2023 /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, 2022. All financial amounts in this news release are in United States dollars, unless otherwise stated.

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

"2022 was a strong financial and operational year for Frontera. The Company delivered average daily production of 41,382 boe/d, a 9% increase compared to its 2021 production average and in-line with its increased and tightened 2022 production guidance. The Company increased full year operating EBITDA by 70% to $641.9 million, within the Company's $90-$100/bbl 2022 guidance range. The Company finished the year with a total cash position of approximately $313 million including restricted cash of $23 million.

Frontera remains committed to enhancing shareholder returns. In 2022, the Company returned over $91 million to shareholders through its NCIB and SIB programs. Since 2018, Frontera has returned more than $300 million to shareholders through dividends and share buybacks while maintaining strong credit metrics. In addition, since 2017, the Company has resolved more than $2.6 billion in contingent liabilities and commitments, permanently eliminating legacy issues.

The Company is focused on unlocking shareholder value from its upstream Colombia and Ecuador business, its standalone and growing midstream business and its potentially transformational offshore exploration program in Guyana.

In 2022, Frontera advanced the Company's exciting development and lower-risk exploration portfolio in Colombia and Ecuador and started investments in additional water-handling facilities at Quifa and CPE-6 in support of the Company's 50,000 boe/d production target.

Also in 2022, Frontera strengthened its midstream portfolio with the acquisition of the remaining 40% interest in Pipeline Investment Limited. Frontera now owns 35% of the ODL pipeline, which generated over $215 million in EBITDA in 2022. Since 2019, the Company has increased its interest in Puerto Bahia by approximately 60% to 99.8%. Frontera's interest in the ODL pipeline and in Puerto Bahia creates a unique standalone midstream business which provides shareholders with significant upside potential.

In Guyana, the Joint Venture discovered light oil and condensate at the Kawa-1 well, offshore Guyana and has successfully drilled the first prospective geologic horizons in the Upper Maastrichtian at the Wei-1 well, the Joint Venture's second exploration well in the Corentyne block, several days ahead of schedule.

Frontera's assets strong operating performance and sound balance sheet has positioned the Company to deliver its 2023 objectives and to continue generating value for shareholders by unlocking the sum of its parts." 

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

"I am pleased with Frontera's 2022 operating and financial results. We delivered record production at CPE-6, which contributed to 2% quarter over quarter production growth to 41,806 boe/d and 9% year over year growth to 41,382 boe/d. The Company increased water-handling capacity at Quifa to approximately 1,550,000 bwpd at year end and we plan to grow to 2,000,000 bwpd by mid-2024 as the SAARA water treatment facility comes on-line and at CPE-6 where the Company expects to increase oil and water-handling capacity to 240,000 bwpd in 2023 and 480,000 bwpd in 2025, building the foundation to grow production to 50,000 boe/d.

The Company safely and responsibly executed $314 million in capital spending in support of its Colombia and Ecuador upstream onshore business and $104 million on its exciting Guyana offshore exploration program. I am also pleased with the Company's continued efforts to manage its cost structure. While production costs were higher year over year due to increased energy tariffs, maintenance, internal transportation costs and well services, Frontera's transportation costs and G&A were in-line with 2021. The Company also increased its operating netback by 60% to $59.78/boe, increased its net sales realized price by 40% to $82.59/boe, reduced its restricted cash position by approximately $40 million and increased its uncollateralized credit lines to $118.4 million.

In our Midstream segment, we revamped Puerto Bahia's leadership, adding expertise in the container business to drive incremental opportunities in the dry cargo terminal. For the year ended 2022, revenues from third-party liquids and general cargo through Puerto Bahia increased 41% to approximately $40 million, compared to 2021. Over 80% of Puerto Bahia's EBITDA is now generated from third parties. For 2022, the midstream business generated approximately $47 million in segment cash flow from operations.

Frontera achieved 102% of its 2022 ESG Goals, offset 52% of emissions, preserved and restored 1,747 hectares of key connectivity corridors in Casanare and Meta, Colombia and recycled 15% of its operating water and 17% of its solid waste. The Company invested approximately $4.31 million on education, inclusive economic development, and quality of life initiatives, benefiting 73,101 people through 218 social projects in Ecuador, Peru and Colombia.

Importantly, I'm pleased to confirm the Company's 2023 production guidance of 40,000-43,000 boe/d."

Fourth Quarter 2022 Operational and Financial Summary

					Year Ended December 31
		Q4 2022	Q3 2022	Q4 2021	2022	2021
Operational Results
Heavy crude oil production ^(1)	(bbl/d)	22,144	20,945	20,912	21,441	19,326
Light and medium crude oil production ^(1)	(bbl/d)	17,073	17,428	16,300	17,274	17,218
Total crude oil production	(bbl/d)	39,217	38,373	37,212	38,715	36,544
Conventional natural gas production ^(1)	(mcf/d)	9,097	9,969	4,663	9,741	5,022
Natural gas liquids ^(1)	(boe/d)	993	911	575	958	393
Total production ^(2)	(boe/d) ^(3)	41,806	41,033	38,605	41,382	37,818
Inventory Balance
Colombia	(bbl)	683,416	590,984	326,861	683,416	326,861
Peru	(bbl)	480,200	480,200	480,200	480,200	480,200
Ecuador	(bbl)	75,164	66,729	–	75,164	–
Total Inventory	(bbl)	1,238,780	1,137,913	807,061	1,238,780	807,061
Oil and gas sales, net of purchases^(4)	($/boe)	82.90	90.53	75.12	91.73	66.54
Realized (loss) on risk management contracts^(5)	($/boe)	(1.32)	(1.30)	(1.87)	(1.22)	(4.01)
Royalties^(5)	($/boe)	(6.04)	(7.23)	(3.62)	(7.83)	(2.66)
Dilution costs^(5)	($/boe)	(0.07)	(0.07)	(0.10)	(0.09)	(0.72)
Net sales realized price ^(4)	($/boe)	75.47	81.93	69.53	82.59	59.15
Production costs^(5)	($/boe)	(11.85)	(11.45)	(12.71)	(12.35)	(11.46)
Transportation costs^(5)	($/boe)	(10.57)	(10.70)	(9.02)	(10.46)	(10.43)
Operating netback per boe ^(4)	($/boe)	53.05	59.78	47.80	59.78	37.26
Financial Results
Oil and gas sales, net of purchases ^(6)	($M)	261,785	305,338	269,525	1,109,602	815,793
Realized (loss) on risk management contracts	($M)	(4,182)	(4,393)	(6,692)	(14,733)	(49,119)
Royalties	($M)	(19,076)	(24,371)	(12,974)	(94,709)	(32,572)
Dilution costs	($M)	(235)	(223)	(368)	(1,132)	(8,773)
Net sales^(6)	($M)	238,292	276,351	249,491	999,028	725,329
Net income (loss) ^(7)	($M)	197,796	(26,893)	629,376	286,615	628,133
Per share – basic	($)	2.29	(0.30)	6.60	3.16	6.50
Per share – diluted	($)	2.25	(0.30)	6.40	3.08	6.29
General and administrative	($M)	12,761	12,549	12,144	55,063	52,134
Outstanding Common Shares	Number of Shares	85,592,075	86,575,175	94,695,694	85,592,075	94,695,694
Operating EBITDA ^(6)	($M)	144,994	173,207	148,645	641,877	378,179
Cash provided by operating activities	($M)	138,312	120,804	113,482	620,479	327,380
Capital expenditures ^(6)	($M)	134,165	76,018	135,458	417,563	314,257
Cash and cash equivalents - unrestricted	($M)	289,845	253,550	257,504	289,845	257,504
Restricted cash short and long-term ^(8)	($M)	23,202	55,552	63,321	23,202	63,321
Total cash ^(8)	($M)	313,047	309,102	320,825	313,047	320,825
Total debt and lease liabilities ^(8)	($M)	511,552	533,077	560,135	511,552	560,135
Consolidated total indebtedness (Excl. Unrestricted Subsidiaries) ^(9)	($M)	407,808	412,926	416,883	407,808	416,883
Net Debt (Excluding Unrestricted Subsidiaries)^(9)	($M)	178,534	205,625	207,578	178,534	207,578

	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 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. See "Advisories - Oil and Gas Information Advisories".
	3. Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy. See "Advisories - Oil and Gas Information Advisories".
	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"). See "Advisories - Non-IFRS and Other Financial Measures''.
	5. Supplementary financial measure (as defined in NI 52-112). See "Advisories - Non-IFRS and Other Financial Measures''.
	6. Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). See "Advisories - Non-IFRS and Other Financial Measures''.
	7. Net income (loss) attributable to equity holders of the Company.
	8. Capital management measure (as defined in NI 52-112). See "Advisories - Non-IFRS and Other Financial Measures''.
	9. "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., Frontera BIC Holding Ltd., and Frontera Bahía Holding Ltd., including its subsidiary Sociedad Portuaria Puerto Bahía S.A. ("Puerto Bahia"). Refer to the "Liquidity and Capital Resources" section on page 29 of the MD&A (as defined below).

Fourth Quarter and Full Year Operational and Financial Results:

• The Company recorded net income of $197.8 million or $2.29/share in the fourth quarter of 2022, compared with a net loss of $26.9 million or $0.30/share in the prior quarter and net income of $629.4 million or $6.60/share in the fourth quarter of 2021. The Company's fourth quarter net income included operating income of $296.8 million (including a non-cash reversal of impairment of $229.8 million), partially offset by $68.6 million of income tax expense, foreign exchange loss of $28.2 million and finance expense of $14.2 million. This compared to net income of $629.4 million in the fourth quarter of 2021, which included operating income of $697.1 million (including a non-cash reversal of impairment of $586.7 million) and $36.1 million income tax recovery, partially offset by $103.6 million related to currency translation adjustments ("CTA") as a result of the disposal of the Company's 43.03% interest in Bicentenario.
  
  
• For the year ended December 31, 2022, the Company reported net income of $286.6 million, which included operating income of $643.4 million (including a non-cash reversal of impairment of $229.8 million), partially offset by income tax expense of $249.3 million, foreign exchange losses of $76.4 million (primarily related to our midstream business) and finance expense of $53.0 million. This compared to net income of $628.1 million for the year ended December 31, 2021, which included $854.2 million of operating income (including a non-cash reversal of impairment of $586.7 million), partially offset by $103.6 million related to the CTA as a result of the disposal of the Company's 43.03% interest in Bicentenario, $41.9 million loss on risk management contracts, $51.8 million in finance expense, and $29.1 million debt extinguishment costs.
• Production averaged 41,806 boe/d as increased water-handling capacity contributed to higher oil production, up approximately 2% compared to 41,033 boe/d in the prior quarter and 38,605 boe/d in the fourth quarter of 2021. In 2022, Frontera averaged 41,382 boe/d, in-line with the Company's increased and tightened 2022 guidance of 41,000-43,000 boe/d and up 9.4% compared with 37,818 boe/d in 2021. See the table above for production by product type for the prior quarter, fourth quarter of 2021, and year ended 2022 and 2021. 
  
  
• Operating EBITDA was $145.0 million in the fourth quarter of 2022 compared with $173.2 million in the prior quarter and $148.6 million in the fourth quarter of 2021. The decrease in operating EBITDA quarter over quarter was primarily a result of lower commodity prices, lower volumes sold in the fourth quarter and higher energy input costs. Frontera's weighted average Brent price was $98/bbl in 2022, generating $641.9 million of EBITDA, up 70% compared to $378.2 million in 2021 and within the $90-$100/bbl 2022 guidance range.
  
  
• Cash provided by operating activities in the fourth quarter of 2022 was $138.3 million, compared with $120.8 million in the prior quarter and $113.5 million in the fourth quarter of 2021. The increase in cash provided by operating activities quarter over quarter was primarily due to positive variations in working capital offset by lower Brent benchmark oil prices.
  
  
• The Company reported a total cash position of $313.0 million at December 31, 2022 relatively flat compared to $309.1 million at September 30, 2022 and $320.8 million at December 31, 2021. During the quarter, the Company invested $42.4 million in debt service and interest, $14.9 million payment as result of the non-controlling interest acquisition and $7.8 million to repurchase shares. The Company generated $620.5 million of cash from operations in 2022, compared to $327.4 million in 2021. During the year, the Company primarily invested $417.6 million in capital expenditures, $93.9 million in debt service payments, $91.4 million in share buybacks and $36 million to increase its indirect interest in the ODL pipeline to 35%.
  
  
• The Company's restricted cash position was $23.2 million at December 31, 2022 compared to $55.6 million in the third quarter of 2022, a decrease of approximately $32.4 million. The decrease in restricted cash quarter over quarter is primarily due to restricted cash being released from (i) the Puerto Bahía Debt Service Reserve Account ("DSRA") used for Debt Service payment on December 15, 2022, for $24.7 million, (ii) replacement of abandonment funds with letters of credit of $7.9 million and (iii) foreign exchange fluctuations. In total, the Company released approximately $40.1 million of restricted cash during 2022.
  
  
• The Company has various uncommitted bilateral credit lines. As of December 31, 2022, the Company had increased its uncollateralized credit lines to $118.4 million, an increase of $28.7 million compared to December 31, 2021.
  
  
• As at December 31, 2022, the Company had a total inventory balance of 1,238,780 bbls compared to 1,137,913 bbls at September 30, 2022.
  
  
• Capital expenditures were approximately $134.2 million in the fourth quarter of 2022, compared with $76.0 million in the prior quarter and $135.5 million in the fourth quarter of 2021. The Company executed approximately $417.6 million in total capital spending in 2022, below its updated 2022 capital guidance of $435-495 million and compared to $314.3 million in 2021. The increase in capital expenditures quarter-over-quarter and year-over-year was primarily due to increased development drilling at Quifa, CPE-6 and Cubiro blocks, development facilities spending at Quifa, CPE-6 and Guatiquia blocks, exploration spending in Colombia and Ecuador and spending in advance of spudding the Wei-1 well offshore Guyana.
  
  
• The Company's net sales realized price was $75.47/boe in the fourth quarter of 2022, compared to $81.93/boe in the prior quarter and $69.53/boe in the fourth quarter of 2021. 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 resulting from decreases in Brent benchmark oil prices. The Company's net sales realized price in 2022 was $82.59/boe, up 40% compared to $59.15/boe in 2021. The increase year-over-year was mainly a result of higher Brent benchmark oil prices, lower losses on risk management contracts, reduction in dilution costs, and improved differentials during 2022, partially offset by higher cash royalties.
  
  
• The Company's operating netback was $53.05/boe in the fourth quarter of 2022, compared with $59.78/boe in the prior quarter and $47.80/boe in the fourth quarter of 2021. The decrease in operating netback quarter-over-quarter was primarily due to lower net sales realized price as a result of lower average Brent benchmark oil prices. The Company's operating netback for the year ended December 31, 2022, was $59.78/boe, up 60% compared to $37.26/boe in 2021. The increase in operating netback year-over-year was primarily due to higher net sales realized price partially offset by higher production costs as explained below.
  
  
• Production costs averaged $11.85/boe in the fourth quarter of 2022, up slightly compared with $11.45/boe in the prior quarter and $12.71/boe in the fourth quarter of 2021. Frontera's production costs averaged $12.35/boe in 2022, higher than the Company's 2022 guidance range of $11.00-$12.00/boe. The increase in production costs quarter-over-quarter and year-over-year was primarily due to increased energy tariffs, maintenance, internal transportation costs and well services.
  
  
• Transportation costs averaged $10.57/boe in the fourth quarter of 2022, down slightly compared with $10.70/boe in the prior quarter and up from $9.02/boe in the fourth quarter of 2021 mainly due to additional volumes transported in Ecuador during the fourth quarter of 2022 and the one-time prepaid services in Colombia recorded as lower transportation costs during the fourth quarter of 2021 after the implementation of the conciliation agreement between Frontera, Cenit Transporte y Logistica de Hidrocarburos S.A.S. and Oleoducto Bicentenario de Colombia S.A.S. ("Bicentenario"). Frontera's transportation costs averaged $10.46/boe in 2022, within the Company's 2022 guidance range of $10.00-$11.00/boe and essentially flat when compared to $10.43/boe in 2021.
  
  
• The Company recorded realized losses on risk management contracts of approximately $4.2 million in the fourth quarter of 2022 compared to a realized loss of approximately $4.4 million in the third quarter of 2022 and a loss of $6.7 million in the fourth quarter of 2021. The realized loss on risk management contracts quarter-over-quarter resulted from cash paid for premiums related to put options settled during the period. The Company recorded a realized loss on risk management contracts of $14.7 million in 2022 compared with $49.1 million in 2021. In 2022, the Company hedged 40% of its production at $70/bbl floors with full price upside exposure.
  
  
• The Company's Midstream segment reported income from operations for the three months and year ended December 31, 2022, of $14.9 million and $54.3 million respectively, compared with $19.4 million and $77.8 million in the same periods of 2021 which included Frontera Colombia's liquids terminal take or pay which expired in December 2021. For the year ended 2022, revenues from third party liquids and general cargo through Puerto Bahia was $39.6 million, up 41% compared to $28.1 million in 2021. Today, over 80% of Puerto Bahia's EBITDA is generated from third parties. For the year ended 2022, ODL generated $215.1 million of EBITDA and $120.1 million of net income, which represented 11% and 11% year over year growth, respectively. Frontera, through its wholly-owned subsidiary Pipeline Investments Limited, has a 35% equity interest in ODL. For additional information regarding the Company's Midstream segment please refer to the Company's MD&A. 
  
  
• On December 2, 2022, Fitch Ratings affirmed Frontera's Long-Term Foreign and Local Currency Issuer Default Ratings (IDRs) at 'B'. In addition, Fitch affirmed Frontera's senior unsecured notes at 'B'/'RR4'. The Rating Outlook is Stable. On September 22, 2022, S&P Global Ratings upgraded its outlook for Frontera from 'stable' to 'positive' and affirmed its B+ issuer credit and issue-level ratings.
  
  
• In 2022, Frontera achieved 102% of its ESG goals for the year compared with 98% in 2021. The Company offset 52% of its emissions through carbon credits in 2022 compared with 41% in 2021, restored and reforested 1,747 hectares of key connectivity corridors in Casanare and Meta Departments, Colombia, compared with 765 hectares in 2021 and recycled 15% of its operating water and 17% of its solid waste. See below for more information.

Enhancing Shareholder Returns

Since 2018, Frontera has returned more than $300 million to shareholders through dividends and share buybacks while maintaining a strong balance sheet. In 2022, the Company repurchased approximately 9.6 million Common Shares for cancellation, or 20% of the public float, returning more than $91.4 million to shareholders through its Normal Course Issuer Bid ("NCIB") and a Substantial Issuer Bid ("SIB").

NCIB:

• Under the Company's current NCIB which commenced on March 17, 2022, and will expire on March 16, 2023, Frontera is authorized to repurchase for cancellation up to 4,787,976 of the Company's common shares ("Common Shares"). During the fourth quarter of 2022, the Company repurchased for cancellation 983,100 Common Shares during the fourth quarter of 2022 at a cost of approximately $7.8 million. As of March 1, 2023, the Company has repurchased approximately 4.3 million Common Shares for cancellation for approximately $40.9 million with approximately 0.5 million additional Common Shares remaining available for repurchase under the NCIB.

SIB:

• On June 24, 2022, the Company launched a SIB, pursuant to which the Company offered to purchase from shareholders for cancellation up to C$65.0 million of its outstanding Common Shares. On August 11, 2022, the Company announced that, in accordance with the terms and conditions of the SIB, the Company took up for cancellation 5,416,666 Common Shares at a price of C$12.00 per Common Share, for a total cost of $51.2 million (funded by cash, representing an aggregate purchase price of C$65.0 million plus transaction costs). The Common Shares taken up for cancellation under the SIB represented approximately 5.84% of the total number of the Company's issued and outstanding Common Shares as of August 8, 2022.

Frontera remains committed to enhancing shareholder returns. As part of its 2023 plan, the Company strives to unlock shareholder value from its upstream Colombia and Ecuador business, its standalone and growing midstream business and its potentially transformational offshore exploration program in Guyana.

Continuing Progress On Frontera's ESG Strategy - Building A Sustainable Future

Over the last three years, Frontera has established a strong sustainability model at the centre of its business through its ESG strategy - "Building a Sustainable Future".

In 2022, Frontera achieved 102% of its ESG goals for the year compared with 98% in 2021. The Company offset 52% of our emissions through carbon credits, restored and reforested 1,747 hectares of key connectivity corridors in Casanare and Meta Departments, Colombia, compared with 765 hectares in 2021, and recycled 15% of its operating water and 17% of its solid waste. Frontera was awarded the Friendly Biz certification for its sexual discrimination and harassment-free environment, and received the Great Place-to-Work certification as one of the best companies to work for in Colombia. The Company invested approximately $4.3 million on education, inclusive economic development and quality of life initiatives, benefiting 73,101 people through 218 social projects in Ecuador, Peru and Colombia. In 2022, Frontera was recognized for the second consecutive year as one of the World's Most Ethical Companies by Ethisphere Institute.

Frontera employees achieved a best-ever Company total recordable injury rate of 0.82 in 2022. Frontera's operations in Colombia received recertification of its integrated management system under ISO 9001, ISO 14001, ISO 45001 and ISO 39001 standards. In Ecuador, the Company is the first operator in the country to receive certification of its integrated management system under ISO 9001, ISO 14001 and ISO 45001 standards.

Operational Update

Guyana

Frontera and CGX, joint venture partners (the "Joint Venture") in the Petroleum Prospecting License for the Corentyne block offshore Guyana (the "License"), commenced drilling operations on the Wei-1 well on January 20, 2023 and is currently at 15,400 feet (4,694 metres) measured depth. There have been no lost time, safety or environmental incidents since starting operations. Drilling operations have gone as planned and the first prospective geologic horizons in the Upper Maastrichtian have been successfully drilled, several days ahead of schedule. Geophysical logs are currently being obtained in the open hole section within which hydrocarbon shows were encountered. When drilling operations resume, deeper prospective horizons in the Lower Maastrichtian, Campanian and Santonian sections will be targeted.

The Wei-1 well is located approximately 14 kilometres northwest of the Joint Venture's previous Kawa-1 light oil and condensate discovery and is being drilled in water depth of approximately 1,912 feet (583 metres) to an anticipated total depth of 20,500 feet (6,248 metres). The Wei-1 well is targeting Maastrichtian, Campanian and Santonian aged stacked sands within channel and fan complexes in the northern section of the Corentyne block. The well is expected to take approximately 4-5 months from well spud to reach total depth.

Subsequent to the quarter, the Government of Guyana approved an Appraisal Plan for the northern section of the Corentyne block which commenced with the Wei-1 well. Following completion of Wei-1 drilling operations and upon detailed analysis of the results, the Joint Venture may consider future wells per its appraisal program to evaluate possible development feasibility in the Kawa-1 discovery area and throughout the northern section of the Corentyne block. Any future drilling is contingent on positive results at Wei-1 and the Joint Venture has no further drilling obligations beyond the Wei-1 well.

Demerara Block Relinquishment Complete

On February 27, 2023 the Joint Venture completed the process of relinquishing the Demerara block through a mutual termination agreement with the Government of Guyana.

Colombia

During the quarter, Frontera produced 40,560 boe/d from its Colombian operations (consisting of 22,144 bbl/d of heavy crude oil, 15,827 bbl/d of light and medium crude oil, 9,097 mcf/d of conventional natural gas and 993 boe/d of natural gas liquids). Importantly, the Company further diversified its production mix in 2022, increasing its conventional natural gas production to 9,741 mcf/d, up 94% compared to 5,022 in 2021. The Company also grew its natural gas liquids production to 958 boe/d in 2022, up 144% from 393 boe/d in 2021.

In the fourth quarter of 2022, the Company drilled 17 development wells at Quifa, Cajua, CPE-6 and Cubiro blocks and one injector well at Quifa. This compares to 14 development wells in the prior quarter. In 2022, the Company drilled 67 development wells, compared to 42 in 2021.

Currently, the Company has five drilling rigs, and three workover rigs active at its Quifa, CPE-6, Cubiro and Corcel/Guatiquia and VIM-22 blocks in Colombia.

At Quifa, fourth quarter production averaged approximately 16,470 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company drilled 15 wells on the block in the fourth quarter of 2022, including 14 development wells and 1 injector well. The Company brought the Battery 4 central processing facility on-line in October 2022, increasing water disposal capacity by 100,000 barrels of water per day (bwpd) and in November, increased pumping capacity at the Centro de Manejo de Agua water treatment facility by 50,000 bwpd. Combined, these two operational achievements increased Frontera's water handling capacity to approximately 1,550,000 bwpd. Initiation of Frontera's reverse osmosis water treatment facility (SAARA previously Agrocascada)  in 2023 is expected to further increase water disposal capacity and support production growth at Quifa. Frontera expects to increase water disposal capacity to up to 2,000,000 bwpd by mid-2024.

CPE-6

At CPE-6, fourth quarter production averaged approximately 5,214 bbl/d of heavy crude oil, increasing from 4,850 bbl/d at year end 2021. The Company drilled the Hamaca Norte-1 step out well in November to a total depth of 3,800 feet (1,158 metres) to the north of Frontera's existing production areas, penetrating 17.7 feet (5.4 metres) of net hydrocarbon pay in C7 - Basal Sands (Carbonara Formation). The well was completed in December and an initial seven-day production test produced an average of 50 bbls/d of 10.5 degree API heavy crude oil with a 53% water cut and confirmed the continuation of the Hamaca field to the north. No pressure build-up was performed.

The Company also drilled the Hamaca-117D (Hamaca Sur) well in November to a total depth of 3,721 feet (1,134 metres), penetrating 50 feet (15.2 metres) net hydrocarbon pay in the U Basal Sands Carbonera Formation. The drilling objective of the Hamaca Sur well was to acquire information on the geology to the southwest of Frontera's existing HAM-65 producer well cluster for efficient future development of the area. During a two-week initial production test, the well produced approximately 42 bbl/d with a 96% BSW. The well was completed as a horizontal well (Hamaca-117D-STH). No pressure build-up was performed.

The Hamaca Norte and Sur wells are the first of several delineation wells that are expected to define additional growth opportunities adjacent to the Company's existing and expanding CPE-6 facilities. The Company is currently defining its multi-year development plan including increasing oil and water-handling capacity to 480,000 bwpd in 2025.

Guatiquia

At Guatiquia, fourth quarter production averaged approximately 7,941 bbl/d of light and medium crude oil.

VIM-1

At VIM-1 block (Frontera 50% W.I., non operator), fourth quarter production averaged approximately 1,370 bbl/d of light and medium crude oil. In the fourth quarter of 2022, the La Belleza-2 well was drilled approximately 2.5 kilometres east of the La Belleza-1 well to a total depth of 14,166 feet and encountered 2,000 feet of porous limestone in the Cienaga de Oro ("CDO") formation. The well was drilled as a horizontal well and completed for natural flow production. Over an 8-day initial production testing period, the well produced a total of 15,610 barrels of condensate and 62 mcf of conventional natural gas, representing an average test rate of 1,993 barrels of condensate per day and 8 mcfd of gas (3,326 boepd). Due to liquid storage limitations, the true capability of the well could only be tested over a one-hour period where the well produced 7,530 barrels of condensate and 38.5 mcfd of gas (13,953 boepd). Bottom hole pressure recorders indicated a producing drawdown of 4% during the average flow period and a maximum drawdown of 10% at the highest rate tested during the one-hour period. A total of 817 barrels of formation water and water of condensation was produced during the test for an average water-cut of 5%, consistent with the long-term trends at the La Belleza-1 well. The well is now in production.

VIM-22

Subsequent to the quarter, the Company began civil works on the VIM-22 block in advance of drilling the Chimi-1, Winner-1 and Tubara Sur-1 wells in 2023. The Company spud the Chimi-1 well on February 16, 2023.

VIM-46

Subsequent to the quarter, the Company began pre-seismic and pre-drilling activities.

La Creciente

At the La Creciente block, the Magari-1D exploratory well was spudded in the fourth quarter of 2022 and reached total depth in early January 2023. Gassy water was found in the CDO formation but the well was unsuccessful in producing commercial quantities of hydrocarbons. The well was subsequently plugged and abandoned.

Ecuador

In Ecuador, fourth quarter gross production averaged approximately 2,492 bbl/d of light & medium crude oil. Frontera's share of production in Ecuador for the three months ended December 31, 2022, was 1,246 bbl/d of medium crude oil compared to 1,204 bbl/d in the prior quarter. At the Perico block (Frontera 50% W.I. and operator), current production is 1,178 bbl/d.

At the Espejo block (Frontera 50% W.I. and non-operator), the Pashuri-1 well was drilled to a total depth of 10,907 feet (3,324 metres) in October 2022. Preliminary logging information indicated the presence of hydrocarbons in the M1 and U Sandstones in the Napo formation. The well has been in an extended production test since December 2, 2022, with a current rate of approximately 350 bbl/d of 19.8 degree API with 12% water cut in the U Sandstone from the Napo formation with no significant pressure decline.

During the fourth quarter of 2022, Frontera recorded a $4.5 million partial impairment of the Pashuri-1 well due to initial lower than expected recoverable resources from the well. The Company is currently analyzing its long-term options for this well.

The operator drilled the Caracara-1 exploration well in November 2022, reaching a total depth of 10,090 feet (3,075 metres). Preliminary logging information indicated the presence of hydrocarbons in the M1 and U Sandstones. Initial production tests after six days of testing showed traces of heavy and viscous oil in M1 Sandstone from Napo formation with no significant pressure declines. Further analyses are being carried out to define next steps.

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. Consistent with this strategy, the Company entered into new put hedges totaling 2,160,000 bbls to protect a portion of the Company's production through May 2023. The following table summarizes Frontera's 2023 hedging position as of March 1, 2023.

Term	Type of Instrument	Open Positions (bbl/d)	Strike Prices Put/ Call
January	Put	14,839	80
February	Put	14,286	70
March	Put	14,194	70
1Q-2023	Total Average	14,444
April	Put	14,333	70
May	Put	13,871	70
2Q-2023	Total Average	9,451

Fourth Quarter 2022 Conference Call Details

A conference call for investors and analysts will be held on Thursday, March 2, 2023, at 1 p.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, René 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):	1-888-664-6383
Participant Number (Toll Free Colombia):	01-800-518-4036
Participant Number (International):	1-416-764-8650
Conference ID:	34443426
Webcast Audio:	www.fronteraenergy.ca

A replay of the conference call will be available until 11:59 p.m. Eastern Time on March 9, 2023.

Encore Toll free Dial-in Number:	1-888-390-0541
International Dial-in Number:	1-416-764-8677
Encore ID:	443426

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 31 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.

If you would like to receive news releases via email as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.

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 return and its efforts to unlock shareholder value as part of its 2023 plan; statements relating to the Company's guidance and objectives for 2023; statements regarding the Company's path to a 50,000 boe/d future; expectations regarding the initiation and expected impacts of the Company's reverse osmosis water treatment facility (SAARA previously Agrocascada) in 2023 and increased water handling capacity at Quifa in 2023 and 2024; expectations regarding increased oil and water handling capacity at CPE-6 in 2023 and 2025; anticipated exploration, development and drilling activities and seismic acquisition, including expectations regarding drilling of the Wei-1 well on the Corentyne block, including project evolution, drilling objectives, timelines and target zones, statements regarding the impact of the Wei-1 exploration well results on the development plans for the Corentyne block, statements relating to anticipated well results and additional analysis being conducted on well data, and expectations with respect to additional growth opportunities adjacent to the Company's existing and expanding CPE-6 facilities; statements regarding the Company's multi-year development plan; expectations with respect to the Company's hedging strategy; and activities and expectations regarding the Company's ESG strategy. 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 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 CPE-6 and Quifa in the time frames indicated; the availability and cost of labour, 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 1, 2023, its annual management's discussion and analysis for the year ended December 31, 2022, 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.sedar.com. 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 measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and depletion, depreciation and amortization expense.

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 and 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.

A reconciliation of net income to operating EBITDA is as follows:

	Three Months Ended December 31		Year Ended December 31
($M)	2022	2021	2022	2021
Net income	197,796	629,376	286,615	628,133
Finance Income	(2,323)	(30)	(5,505)	(5,362)
Finance expenses	14,239	11,768	52,991	51,822
Income tax expense (recovery)	68,599	(36,118)	249,275	1,039
Depletion, depreciation, and amortization	49,198	20,121	195,419	126,692
Impairment (reversal) expense and others	(207,895)	(562,520)	(206,736)	(565,523)
Cost under terminated pipeline contracts	-	(4,386)	-	(4,386)
Post-termination obligation	5,229	322	12,299	4,980
Shared-based compensation non cash portion	3,213	2,973	7,777	6,695
Restructuring, severance, and other costs	2,624	1,746	4,463	4,616
Share of income from associates	(12,135)	(9,751)	(42,043)	(38,033)
Foreign exchange loss	28,230	11,128	76,413	35,510
Other loss (income)	5,381	(14,788)	10,800	(1,435)
Unrealized gain on risk management contracts	(6,600)	(4,530)	(4,310)	(7,213)
Non-controlling interests	(562)	(265)	4,420	7,933
Loss on extinguishment of debt	-	-	-	29,112
Reclassification of currency translation adjustments	-	103,599	-	103,599
Operating EBITDA	144,994	148,645	641,877	378,179

Capital Expenditures

Capital expenditures is a non-IFRS financial measure that reflects the cash and non cash items used by a company to invest in capital assets. This financial measure considers oil and gas properties, plant and equipment, infrastructure, exploration, and evaluation assets.

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 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. Refer to the reconciliation in the "Operating Netback" section on page 12 of the MD&A. Refer to the "Operating Netback and Oil and Gas Sales, Net of Purchases" section on pages 26 and 27 of the MD&A for 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 ratio that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining cost, divided by the total sales volumes from D&P assets, net of purchases. Refer to the reconciliation in the "Operating Netback and Oil and Gas Sales, Net of Purchases'' section on pages 26 and 27 of the MD&A.

Net Sales

Net sales is a non-IFRS financial measure that adjusts revenue to include realized gains and losses from risk management contracts while removing the cost of dilution activities. 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 risk management activities. The deduction for dilution costs and cost of purchases is helpful to understand the Company's sales performance based on the net realized proceeds from production net of dilution, 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 & gas segment.  Refer to the reconciliation in the "Sales" section on page 27 of the MD&A.

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 risk management contracts less royalties and dilution costs). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. Refer to the "Net sales realized price" section on page 27 of the MD&A for a reconciliation of this calculation.

Production Cost Per Boe, Transportation Cost Per Boe, Royalties Per Boe and Dilution Costs Per Boe

Production costs mainly include lifting costs, activities developed in the blocks, and processes to put the crude oil and gas in sales condition. Production cost per boe is a supplementary financial measure that is calculated using production cost divided by production (before royalties). Refer to the "Production cost per boe" section on page 28 of the MD&A for a reconciliation of this calculation. Transportation costs include all commercial and logistics costs associated with the sale of produced crude oil and gas such as trucking, pipeline and refining processing fees. Transportation cost per boe is a supplementary financial measure that is calculated using transportation cost divided by net production after royalties. Refer to the "Transportation cost per boe" section on page 28 of the MD&A for a reconciliation of this calculation. Royalties include 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. Dilution costs include all costs associated with the dilution services. Dilution costs per boe is a supplementary financial measure that is calculated using the dilution costs divided by total sales volumes, net of purchases.

Realized (loss) gain on risk management contracts per boe

Realized (loss) gain on risk management contracts includes the gain or loss during the period, as a result of the Company's exposure in derivative contracts. Realized (loss) gain on 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.

Working Capital

Working capital is a capital management measure to describe the liquidity position and ability to meet its short-term liabilities. Working Capital is defined as current assets less current liabilities.

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.

Oil and Gas Information Advisories

Reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons. Disclosure of well-flow test results included in this press release are not necessarily indicative of long-term performance or of ultimate recovery. Where a pressure transient analysis or well-test interpretation has not yet been carried out, as indicated above, the data should be considered preliminary until such analysis or interpretation has been done.

This news release includes the terms "net hydrocarbon pay" and "hydrocarbon shows". Such terms should not be interpreted to mean there is any level of certainty in regard to any volume of oil, natural gas or condensates that may be present therein, or that any such volumes may be produced profitably, in commercial quantities, or at all.

The term "boe" is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy.

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

SOURCE Frontera Energy Corporation

please contact Brent Anderson, Director, Investor Relations, at 1 403 705 8827, [email protected], www.fronteraenergy.ca