Frontera Announces Third Quarter 2022 Results

Generated EBITDA of $173.2 Million

Delivered Production of 41,033 Boe/d, Up 12.7% From Q3'21,

Delivered Another Record Quarterly Average Production at CPE-6 of 5,070 boe/d
Achieved a Total Recordable Incident Rate of 1.01,
Best Safety Performance in Frontera History

Revised Wei-1 Well Spud Window to Between December 2022 to Late January 2023

Invested Over $100 Million in Shareholder Value Generating Initiatives

Including $86.6 million in Share Buybacks YTD and Acquisition of Additional Interest in ODL Pipeline

Outlook Upgraded By S&P Global Ratings From 'Stable' to 'Positive',
B+ Issuer Credit and Issue-Level Ratings Affirmed

CALGARY, AB, Nov. 1, 2022 /CNW/ - Frontera Energy Corporation (TSX: FEC) ("Frontera"' or the "Company") released financial and operational results for the third quarter ended September 30, 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:

"Frontera's third quarter results underscore the Company's continued focus on cash flow generation, operational excellence and unlocking value for shareholders. Year to date, the Company continues to deliver on its guidance with over 41,200 barrels per day in production - representing about 10% year-over-year growth, generating close to $500 million in EBITDA and a strong focus on cost control, including a 9.5% decrease in quarter over quarter production costs. Additionally, the Company continues to deliver on its shareholder value initiatives. Year to date, the Company has invested over $100 million, including $87 million in share buybacks through its SIB and NCIB programs, while retiring more than 8.5 million shares. Further, with the Company's purchase of IFC's interest in ODL, Frontera has strengthened its midstream cash flows and created a self-sustained and growing midstream business. As a result of its continued focus on performance and value, during the quarter S&P Global Ratings upgraded its outlook for Frontera from 'stable' to 'positive' and affirmed the Company's B+ issuer credit and issue-level ratings. The Company, through its joint venture with CGX, looks forward to building on the light oil and condensate discovery at Kawa-1 with the spudding of the Wei-1 well, offshore Guyana in between December 2022 and late January 2023, subject to rig release by the third-party operator."

Orlando Cabrales, Chief Executive Officer, Frontera, commented:

"Frontera delivered solid operational and financial results during the third quarter. The Company generated EBITDA of $173.2 million and almost $500 million of EBITDA year to date to the end of the third quarter. Frontera also produced 41,033 boe/d in the third quarter, averaging 41,238 boe/d year to date to the end of the third quarter. We remain on track to deliver our 2022 production guidance of 41,000-43,000 boe/d as production ramps up in the fourth quarter due to additional water disposal capacity in Quifa via the new Battery 4 facility (which came on-line in October) and increased pumping capacity at the CMA water treatment facility in November, as development drilling grows record production at CPE-6 and as liquids recovery increases at VIM-1.

We're delivering on our production and EBITDA targets so far this year while controlling our operating costs, despite industry-wide inflationary pressures and we anticipate achieving our production and transportation cost guidance for the year. I'm proud to say that we are delivering these results while achieving a total recordable injury rate of 1.01 - the best safety performance in the Company's history - and a credit to everyone at Frontera.

In the fourth quarter, we expect to continue generating strong free cash flow from our oil-weighted production and efficient operations, advance our significant development and high-impact exploration growth prospects in Colombia, Ecuador and Guyana while maintaining a strong balance sheet, healthy leverage levels and returning value to shareholders through our NCIB."

Third Quarter 2022 Operational and Financial Summary

					Nine Months ended September 30
		Q3 2022	Q2 2022	Q3 2021	2022	2021
Operational Results
Heavy crude oil production (1)	(bbl/d)	20,945	21,455	18,168	21,203	18,791
Light and medium crude oil production (1)	(bbl/d)	17,428	17,348	17,160	17,342	17,528
Total crude oil production	(bbl/d)	38,373	38,803	35,328	38,545	36,319
Conventional natural gas production (1)	(mcf/d)	9,969	10,374	5,033	9,958	5,141
Natural gas liquids (1)	(boe/d)	911	963	211	946	331
Total production (2)	(boe/d) (3)	41,033	41,586	36,422	41,238	37,552
Total inventory balance	(bbl)	1,137,913	1,423,695	1,423,321	1,137,913	1,423,321
Oil and gas sales, net of purchases (4)	($/boe)	90.53	103.34	67.13	94.84	63.00
Realized loss on risk management contracts (5)	($/boe)	(1.30)	(1.15)	(2.68)	(1.18)	(4.89)
Royalties (5)	($/boe)	(7.23)	(10.57)	(4.83)	(8.46)	(2.26)
Dilution costs (5)	($/boe)	(0.07)	(0.12)	(0.15)	(0.10)	(0.97)
Net sales realized price (4)	($/boe)	81.93	91.50	59.47	85.10	54.88
Production costs (5)	($/boe)	(11.45)	(12.65)	(11.44)	(12.52)	(11.03)
Transportation costs (5)	($/boe)	(10.70)	(10.84)	(10.24)	(10.42)	(10.91)
Operating netback (4)	($/boe)	59.78	68.01	37.79	62.16	32.94
Financial Results
Oil & gas sales, net of purchases (6)	($M)	305,338	312,910	164,731	847,817	546,268
Realized loss on risk management contracts	($M)	(4,393)	(3,476)	(6,570)	(10,551)	(42,427)
Royalties	($M)	(24,371)	(32,018)	(11,848)	(75,633)	(19,598)
Dilution costs	($M)	(223)	(376)	(366)	(897)	(8,405)
Net sales (6)	($M)	276,351	277,040	145,947	760,736	475,838
Net income (loss) (7)	($M)	(26,893)	13,484	38,531	88,819	(1,243)
Per share – basic	($)	(0.30)	0.14	0.40	0.96	(0.01)
Per share – diluted	($)	(0.30)	0.14	0.39	0.94	(0.01)
General and administrative	($M)	12,549	15,097	12,656	42,302	39,990
Operating EBITDA (6)	($M)	173,207	190,678	77,304	496,883	229,534
Cash provided by operating activities	($M)	120,804	246,615	79,114	482,167	213,898
Capital expenditures (6)	($M)	76,018	93,835	103,220	283,398	178,799
Cash and cash equivalents – unrestricted	($M)	253,550	295,098	318,791	253,550	318,791
Restricted cash short and long-term (8)	($M)	55,552	57,975	100,692	55,552	100,692
Total cash (8)	($M)	309,102	353,073	419,483	309,102	419,483
Total debt and lease liabilities (8)	($M)	533,077	535,454	563,173	533,077	563,173
Consolidated total indebtedness (excluding Unrestricted Subsidiaries) (9)	($M)	412,926	409,694	401,148	412,926	401,148
Net debt (excluding Unrestricted Subsidiaries) (9)	($M)	205,625	168,512	130,680	205,625	130,680

1. References to heavy crude oil, light and medium crude oil combined, natural gas liquids, or conventional natural gas production in the above table and elsewhere in this MD&A refer to the heavy crude oil, light and medium crude oil combined, natural gas liquids, and conventional natural gas, respectively, product types as defined in National Instrument ("NI") 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 30 of the MD&A.

3. Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy. Refer to the "Further Disclosures - Boe Conversion" section on page 30 of the MD&A.

4. Non-IFRS ratio (equivalent to a "non-GAAP ratio", as defined in NI 52-112 - Non-GAAP and Other Financial Measures Disclosure "NI 52-112" ). Refer to the "Non-IFRS and Other Financial Measures'' section on page 18 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 18 of the MD&A.

6. 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 18 of the MD&A.

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

8. Capital management measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures'' section on page 18 of the MD&A.

9. "Unrestricted Subsidiaries" include CGX Energy Inc.("CGX") listed on the TSX Venture Exchange under the trading symbol "OYL", Frontera ODL Holding Corp. ("Frontera ODL") , including its subsidiary Pipeline Investment Ltd. ("PIL"), Frontera BIC Holding Ltd., and Frontera Bahía Holding Ltd. ("Frontera Bahía"), including its subsidiary Sociedad Portuaria Puerto Bahía S.A. ("Puerto Bahia"). Refer to the "Liquidity and Capital Resources" section on page 22 of the MD&A.

Third Quarter Operational and Financial Results:

• Production averaged 41,033 boe/d, compared to 41,586 boe/d in the prior quarter and 36,422 boe/d in the third quarter of 2021. The slight decrease in production quarter over quarter was mainly due to a delay in the initiation of new Battery 4 water disposal facilities at the Quifa block (which came on-line in October 2022), operational challenges in some of the Company's natural gas and light and medium crude oil fields, partially offset by record quarterly CPE-6 production of 5,070 boe/d due to positive development drilling, successful Jandaya-1 well stimulation and the reactivation of the Sabanero block on July 1, 2022. The Company's year-to-date average production to September 30, 2022 was 41,238 boe/d. The Company remains on track to deliver its tightened 2022 production guidance of 41,000-43,000 boe/d. See the table above for production by product type for the third quarter of 2022, the prior quarter and third quarter of 2021.
  
  
• Operating EBITDA was $173.2 million in the third quarter of 2022 compared with $190.7 million in the prior quarter and $77.3 million in the third quarter of 2021. The decrease in operating EBITDA quarter over quarter was primarily a result of a decrease in the benchmark oil price compared to the previous quarter, partially offset by lower differentials, lower royalties and inventory drawdowns which resulted in one more cargo sold during the third quarter.
  
  
• Cash provided by operating activities was $120.8 million in the third quarter of 2022, compared with $246.6 million in the prior quarter and $79.1 million in the third quarter of 2021. The decrease in cash provided by operating activities quarter over quarter was primarily due to the variance in working capital resulting from the timing of cargo sales and payments received, a decrease in the benchmark oil price compared to the previous quarter partially offset by inventory volumes sold in the third quarter.
  
  
• The Company's total cash position at September 30, 2022, was $309.1 million compared to $353.1 million at June 30, 2022. During the quarter, the Company invested $61.1 million in exploration, production and development facilities in Colombia and Ecuador, returned $57.9 million in capital to shareholders through the its SIB and NCIB share repurchases, paid $21.2 million as part of the acquisition of the 40.07% direct interest in PIL, spent $11.8 million in Guyana in support of pre Wei-1 well drilling activities and $9.3 million on debt service obligations, leases and foreign exchange impacts to cash and cash equivalents.
  
  
• The Company's restricted cash position was $55.6 million as at September 30, 2022, compared to $58.0 million as at June 30, 2022. The Company anticipates releasing additional restricted cash in the fourth quarter of 2022 as the Company continues to optimize its credit lines.
  
  
• The Company has various uncommitted bilateral credit lines. Subsequent to the quarter, the Company increased its uncollateralized credit lines to $113 million, compared to $107.8 million at June 30, 2022.
  
  
• As at September 30, 2022, the Company had a total inventory balance of 1,137,913 bbls, compared to 1,423,695 bbls as at June 30, 2022.
  
  
• Capital expenditures were $76.0 million in the third quarter of 2022, compared with $93.8 million in the prior quarter and $103.2 million in the third quarter of 2021. Capital expenditures during the quarter included $44.1 million on development drilling at Quifa, CPE-6 and VIM-1, $9.9 million on development facilities at CPE-6 and Quifa and reactivation of the Sabanero block, $7 million on exploration drilling at the Espejo block and $9.5 million mainly related to pre-Wei-1 exploration well activities in Guyana.
  
  
• The Company recorded a net loss of $26.9 million or $0.30/share in the third quarter of 2022, compared with net income of $13.5 million or $0.14/share in the prior quarter and net income of $38.5 million or $0.40/share in the third quarter of 2021. The Company's third quarter net loss included $93.8 million in deferred income tax expenses resulting from the devaluation of the COP during the quarter and the utilization of deferred tax assets to offset higher profits in 2022, $38.7 million in foreign exchange losses and $13.9 million in finance expenses partially offset by $118.2 million in operating income.
  
  
• The Company's net sales realized price was $81.93/boe in the third quarter of 2022, compared to $91.50/boe in the prior quarter and $59.47/boe in the third quarter of 2021. The decrease in net sales realized price quarter over quarter was driven by a decrease in the benchmark oil price partially offset by better differentials and lower royalties.
  
  
• The Company's operating netback was $59.78/boe, compared with $68.01/boe in the prior quarter and $37.79/boe in the third quarter of 2021. The decrease in operating netback quarter over quarter was primarily due to lower net sales realized price, partially offset by decreased production costs mainly due to lower well services and energy costs, as well as a decreased transportation costs.
  
  
• Production costs averaged $11.45/boe in the third quarter of 2022, compared with $12.65/boe in the prior quarter and $11.44/boe in the third quarter of 2021. The decrease in production costs quarter over quarter was mainly due to lower well services and energy costs, and lower internal field transport. The Company remains on track to deliver 2022 production cost guidance of $11-$12/boe.
  
  
• Transportation costs averaged $10.70/boe in the third quarter of 2022, compared with $10.84/boe in the prior quarter and $10.24/boe in the third quarter of 2021. The decrease in transportation costs quarter over quarter was mainly due to the positive impact of foreign exchange fluctuations in COP-denominated costs partially offset by a contractual increase in regulated pipeline tariffs in Colombia. The Company remains on track to deliver 2022 transportation cost guidance of $10-$11/boe.
  
  
• The Company recorded a realized loss on risk management contracts of $4.4 million in the third quarter of 2022 compared with a realized loss of $3.5 million in the prior quarter and a loss of $6.6 million in the third quarter of 2021. The realized loss on risk management contracts resulted from cash paid for put options settled during the period. Frontera did not enter into any new hedges during the third quarter. Frontera has hedged 40% of its 2022 production at $70/bbl floors with full price upside exposure. Subsequent to the quarter, the Company entered into new put hedges totaling 230,000 bbls to protect a portion of the Company's January 2023 production at a $80/bbl strike price. See the Hedging Update section below for more information
  
  
• 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.

Frontera 2022 Environmental, Social and Governance (ESG) Highlights

The Company continues to deliver on its ESG goals. Through September 2022, Frontera achieved a Total Recordable Incident Rate (TRIR) of 1.01, the best safety performance in Company history and below its 2022 TRIR objective of 1.40. Frontera has also neutralized 52% of its 2022 Colombian emissions through the purchase of carbon credits and has protected 458 hectares of important biodiverse ecosystems.

The Company is focused on bridging diversity, inclusion and gender equity gaps and is advancing training of community women in its oil and gas technical programme - Crece con Frontera. To date, Frontera has invested US$2.3 million in 105 social projects, benefiting more than 21,000 people in Colombia, Ecuador and Peru. The Company purchased $32.3 million from local suppliers and will accomplish its goal of purchasing $41 million locally in 2022.

In October 2022, Frontera was recognized by the Society of Petroleum Engineers Win Awards for its commitment to sustainability. The awards highlight leading corporate and individual practices in the hydrocarbons sector. Frontera was recognized in the 'Equity, Diversity and Inclusion' and 'Sustainability' categories and two Frontera women were also recognized in the 'Leadership' category.

Update on Key Shareholder Value Initiatives

Frontera is committed to generating and returning value to shareholders. During the quarter, the Company completed two key initiatives: (i) a substantial issuer bid ("SIB") and (ii) the PIL acquisition, totaling $71 million. Year to date, Frontera's total investments for shareholder value initiatives, including its normal course issuer bid ("NCIB"), exceed $100 million.

Share Buybacks

In August 2022, the Company completed its C$65 million (equivalent to USD$50 million) SIB taking up for cancellation at a price of C$12.00 per share approximately 5.42 million of its common shares or approximately 5.84% of the total number of Frontera's issued and outstanding common shares as of August 8, 2022. As at September 30, 2022, Frontera had 86,575,175 common shares outstanding.

Through the Company's current NCIB, the Company has repurchased 3,183,600 common shares for cancellation for approximately $32.5 million as of November 1, 2022. Frontera may purchase up to 4,787,976 common shares, representing approximately 10% of the Company's public float through its current NCIB.

Midstream Business

In September 2022, the Company acquired the remaining 40.07% interest it did not already own in Pipeline Investment Ltd. ("PIL") for an aggregate cash consideration of approximately $47.4 million, including $21 million immediately following the closing of the transaction. The transaction represents an important milestone for the Company as it increases Frontera's direct interest in the ODL pipeline to 35%, strengthens Frontera's midstream cash flows, and creates a self-sustaining and growing midstream business.

The ODL pipeline is a 260-kilometre, 24-inch pipeline with throughput capacity of 300,000 bbl/d at 18° API that transports Frontera's heavy crude oil from the Quifa SW and Cajua fields and part of the CPE-6 field, as well as other third-party production from the Llanos basin, including from Ecopetrol, Hocol, Geopark and Parex, and connects the OCENSA pipeline at Cusiana and Monterrey to the export terminal in Coveñas. Ecopetrol's Cenit Transporte y Logística de Hidrocarburos S.A.S. owns the remaining 65% of ODL. For further information related to the PIL acquisition, please refer to page 5 of the Company's Interim Financial Statements in the "Statements of Changes in Equity'' section.

Guyana

Wei-1 Well Spud Window Revised

Due to unforeseen challenges to the exploration activities of a third-party operator, the release of the NobleCorp Discoverer drilling unit to CGX has been delayed. This situation is beyond the reasonable control of the Joint Venture. Frontera and CGX have communicated the revised spud window for the Wei-1 well to the Government of Guyana; expected to now be between December 2022 and late January 2023, subject to rig release by the third-party operator.

Final preparations are complete in advance of spudding the Wei-1 well on the Corentyne block, and follows the discovery of light oil and condensate at the Kawa-1 well earlier this year. The Wei-1 well will be located approximately 14 kilometres northwest of the Kawa-1 exploration well in the Corentyne block, approximately 200 kilometres offshore from Georgetown, Guyana and will be drilled in water depth of approximately 1,912 feet (583 metres) to an anticipated total depth of 20,500 feet (6,248 metres). Wei-1 will target Maastrichtian, Campanian and Santonian aged stacked channels in a western channel complex in the northern section of the Corentyne block.

Demerara Block Relinquishment

On September 20, 2022, the Government of Guyana provided CGX a surrender deed to formalize relinquishment of the Demerara block. Subsequent to September 30, 2022, the Joint Venture signed the surrender of the Demerara PPL. The Joint Venture's relinquishment of the block allows the people of Guyana to benefit from exploration activities under the stewardship of interested parties. As of October 31, 2022, the Deed of Surrender was in the process of being finalized.

Update on the Joint Operating Agreement Amendment

On July 22, 2022, CGX and Frontera announced that the companies had entered into an agreement to amend the Joint Operating Agreement originally signed between CGX and a subsidiary of Frontera on January 30, 2019, as amended (the "JOA Amendment"), effectively farming into the Corentyne block and securing funding for the Wei-1 well, subject to satisfaction of certain conditions precedent. On October 3, 2022, CGX and Frontera announced that the parties had agreed to (i) extend the maturity date of the previously announced US$19 million convertible loan to CGX dated May 28, 2021, as amended (the "Loan Agreement") to November 30, 2022; and (ii) amend the JOA Amendment to extend the outside date by which the conditions precedent to such agreement must be fulfilled to November 30, 2022, as the Joint Venture continues to await the satisfaction of all conditions precedent. Once all conditions precedent have been satisfied, as a result of the JOA Amendment, CGX will hold a 32.00% participating interest and Frontera will hold a 68.00% participating interest in the Corentyne block.

Colombia

During the quarter, Frontera produced 39,829 boe/d from its Colombian operations (consisting of 20,945 bbl/d of heavy crude oil, 16,224 bbl/d of light and medium crude oil, 9,969 mmcf/d of conventional natural gas and 911 bbl/d of natural gas liquids). The Company currently has 5 drilling rigs and 3 workover rigs active at its drilling and well workover operations in Colombia. In the third quarter of 2022, the Company drilled 16 development wells and completed 18 workovers and well services. Through the third quarter 2022, the Company has drilled 50 development wells and completed 78 workovers and well services in Colombia.

At Quifa, year to date to September 30, 2022 production averaged approximately 16,150 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company drilled 10 development wells at Quifa in the third quarter of 2022. Subsequent to the quarter, the Company brought its new Battery 4 water disposal facility on-line in October which is expected to increase the Company's water disposal capacity. The Company expects to add additional water disposal capacity in November.

At Guatiquia, year to date to September 30, 2022 production averaged approximately 8,949 bbl/d of light and medium crude oil.

At the CPE-6 block in the Llanos Basin, year to date to September 30, 2022 production averaged approximately 4,916 bbl/d of heavy crude oil. During the quarter, the Company drilled 5 successful development wells and delivered record quarterly production of 5,070 boe/d in the third quarter and record monthly production of 5,220 boe/d in October. The Company is undertaking civil works in the northern exploratory area of the CPE-6 block in advance of spudding the Hamaca Norte-1 exploration well. Frontera plans to drill the Hamaca-107D appraisal well in the southern portion of the block in November 2022.

At the VIM-1 block (Frontera 50% W.I., and non-operator) in the Lower Magdalena Valley, year to date to September 30, 2022 production averaged approximately 1,250 boe/d, including approximately 2,980 mmcf/d of conventional natural gas and approximately 727 bbl/d of light crude oil. During the quarter, the La Belleza-2 horizontal development well was drilled to its total depth with encouraging results. The well is expected to be completed in the fourth quarter of 2022. Once the horizontal well is completed, La Belleza-1 well will be used for gas reinjection. The operator intends to grow long-term liquids recovery by reinjecting gas for enhanced oil recovery. The operator estimates that there is potential to double the liquids recovery factor.

At the El Dificil block, the Company drilled two development wells during the quarter which are currently suspended due to operational issues which are expected to be resolved by the first quarter of 2023. Frontera is currently defining near-field opportunities in the Ciénaga de Oro and Porquero formations.

At the VIM-22 block, pre-drilling activities including civil works will begin in the fourth quarter in advance spudding the Chimi-1 exploration well in January.

At VIM-46, Llanos 99, and Llanos 119 blocks, pre-seismic activities related to social and environmental impact studies continue.

Ecuador

In Ecuador, current gross production is approximately 2,600 bbl/d of medium crude oil. Frontera's share of production in Ecuador for the three months ended September 30, 2022 was 1,204 bbl/d of medium crude oil compared to 610 bbl/d in the prior quarter. The increase in production quarter over quarter was due to stimulation operations in the Jandaya-1 well and the stabilization of the Yin-1 well. Operations remain under long-term test as the Company prepares an environmental impact assessment in order to obtain a production environmental license. Additional appraisal activities will be conducted in the near future to confirm size and mid- to long-term production levels. The Company has drilled three out of four wells required as part of its work commitment on the Perico block. Additional prospects on the Perico block have been identified and are being analyzed for future drilling.

At the Perico block, Frontera is evaluating subsequent exploratory & development activities in the block. An update of the exploration potential was finalized, a full field development plan for Jandaya is ongoing, and an information acquisition plan was defined for Tui.

At the Espejo block (Frontera 50% W.I. and non-operator), the operator spud the first exploration well on the block, Pashuri-1, in September and reached total depth in October 2022. Preliminary logging information and other relevant data indicated the presence of hydrocarbons in the M1 and Lower U sandstones in the Napo formation. Testing activities are expected to start in November 2022. Based on the preliminary success at Pashuri-1, the operator anticipates spudding the Caracara-1 well in the fourth quarter. 

Hedging Update

As part of its risk management strategy, the Company 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 the estimated production to protect the revenue generation and cash position of the Company while maximizing upside.  In 2022, Frontera is only using put options, which allow the Company to capture the full upside price benefit while offering efficient downside hedging. Subsequent to the quarter, the Company entered into new put hedges totaling 230,000 bbls to protect a portion of the Company's January 2023 production at a $80/bbl strike price. The following table summarizes Frontera's hedging position as of November 1, 2022.

Term	Type of Instrument	Open Positions (bbl/d)	Strike Prices Put/ Call
October	Put	15,484	70
November	Put	15,333	70
December	Put	15,161	70
4Q-2022	Total Average	15,326
January	Put	7,419	80
1Q-2023	Total Average	2,556

Third Quarter 2022 Conference Call Details

A conference call for investors and analysts will be held on November 2, 2022, at 10:00 a.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):	1-888-644-6383
Participant Number (Toll Free Colombia):	01-800-818-4036
Participant Number (International):	1-416-764-8650
Conference ID:	21477734
Webcast Audio:	www.fronteraenergy.ca

A replay of the conference call will be available until 11:59 p.m. Eastern Time on November 9, 2022.

Encore Toll free Dial-in Number:	1-888-390-0541
International Dial-in Number:	1-416-764-8677
Encore ID:	477734

Frontera to Host Investor Open House on November 15, 2022

On November 15, 2022 from 9:30 a.m. to 5:00 p.m. Col time, Frontera will host an Investor Open House for analysts, investors, shareholders and bondholders at its office at Calle 110 N° 9 – 25 Piso 16, Bogotá, Colombia. Members of Frontera's executive team will provide in-depth presentations and answer questions on Frontera's strategy and key initiatives, operations and production, Colombia and Ecuador exploration, development and reserves, transportation and marketing, midstream business, Guyana exploration, sustainability efforts and finance initiatives. The event will be webcast for those who cannot attend in person. Those wishing to participate via the webcast should pre-register using the following link: https://app.webinar.net/r/nLzjZz46qB1 

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 32 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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Corporate Presentation and Q3'22 Earnings Presentation

See Frontera's Corporate and Q3'22 Earnings Presentations at: https://www.fronteraenergy.ca/reports-presentations/

Social Media

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Advisories

Cautionary Note Concerning Forward-Looking Statements

This news release contains forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to activities, events or developments that the Company believes, expects or anticipates will or may occur in the future. Forward-looking information in this news release includes, without limitation, statements relating to the Company's expectations regarding the Company's operational and financial progress throughout the rest of the year, including updates to the Company's previously issued guidance; expectations regarding the Company's NCIB; expectations with respect to releasing additional restricted cash in the fourth quarter of 2022 as the Company optimizes its credit lines; expectations regarding the relinquishment of the Demerara block to the Government of Guyana pursuant to a mutual termination agreement and Deed of Surrender, which remains to be finalized; expectations regarding the JOA Amendment, including with respect to outstanding conditions precedent; anticipated exploration, development and drilling activities, including, without limitation, expectations regarding timing and impact of new water disposal facilities at the Quifa block, expectations regarding the anticipated timing for spudding the Wei-1 well in the Corentyne block, and the status of the Corentyne License, expectations regarding anticipated timing for spudding the Hamaca Norte-1 well in the CPE-6 block, expectations with respect to increased long-term liquids recovery at the VIM-1 block following the completion of the La Belleza-2 horizontal well, expectations regarding additional near-field exploration opportunities on the El Dificil block, expectations regarding pre-seismic and pre-drilling activities at the VIM-46 block, expectations regarding additional appraisal activities in Ecuador, including the anticipated timing for spudding the Caracara-1 well on the Espejo block in Ecuador; expectations with respect to the Company's hedging strategy; and expectations regarding the Company's commitment to ESG and its progress toward its 2022 ESG goals. 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 potential impacts of the COVID-19 pandemic, actions of the Organization of Petroleum Exporting Countries, 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; the anticipated timing for release of the NobleCorp Discoverer by a third-party operator; the performance of assets and equipment; the availability and cost of labour, services and infrastructure; the development and execution of exploration and development projects; the receipt of any required regulatory approvals and outcome of discussions with governmental authorities; and the success of the Company's hedging strategy.

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 2, 2022, its annual management's discussion and analysis for the year ended December 31, 2021, 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.

Certain information included in this news release may constitute future oriented financial information and financial outlook information (collectively, "FOFI") within the meaning of applicable Canadian securities laws. The FOFI has been prepared by management to provide an outlook of the Company's activities and results and may not be appropriate for other purposes. Management believes that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments; however, actual results of the Company's operations and the resulting financial outcome may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it was made, and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or otherwise, unless required by applicable laws.

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 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 this news release.

Operating EBITDA
EBITDA is a commonly used non-IFRS financial 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 previous quarter, 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 (loss) to operating EBITDA is as follows:

	Three months ended September 30		Nine months ended September 30
($M)	2022	2021	2022	2021
Net income (loss)	(26,893)	38,531	88,355	(1,243)
Finance income	(1,699)	(817)	(3,182)	(5,332)
Finance expenses	13,896	12,720	38,752	40,054
Income tax expense (recovery)	102,362	(13,992)	180,676	37,157
Depletion, depreciation and amortization	57,927	33,480	146,221	106,571
Impairment, recovery of asset retirement obligation and minimum work commitment paid	969	3,846	1,158	(3,003)
Post-termination obligation	—	4,658	7,070	4,658
Share-based compensation non cash portion	59	962	5,927	3,722
Restructuring, severance and other costs	453	954	1,839	2,870
Share of income from associates	(11,166)	(8,691)	(29,908)	(28,282)
Foreign exchange loss (gain)	38,745	5,846	48,183	24,382
Other (income) loss, net	(5,662)	570	5,419	13,353
Unrealized gain (loss) on risk management contracts	1,637	(4,068)	2,290	(2,683)
Non-controlling interests	2,579	3,305	5,446	8,198
Loss on extinguishment of debt	—	—	—	29,112
Operating EBITDA	173,207	77,304	498,246	229,534

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.

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, including 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 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 its own 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 and gas segment. Refer to the reconciliation in the "Sales" section on page 8 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 midstream segment from the per barrel metrics. Refer to the reconciliation in the "Operating Netback" section on page 7 of the MD&A.

Refer to the "Operating Netback and Oil and Gas Sales, Net of Purchases" section on page 19 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 per boe, 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 page 19 of the MD&A.

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.

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 20 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 21 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 21 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.

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
bbls/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

SOURCE Frontera Energy Corporation

Brent Anderson, Director, Investor Relations, 403-705-8827, [email protected], www.fronteraenergy.ca