Frontera Announces Third Quarter 2021 Results

THE COMPANY IS TIGHTENING AND INCREASING ITS FULL-YEAR
OPERATING EBITDA RANGE TO $360-$380 MILLION

DELIVERED NET INCOME OF $38.5 MILLION

AVERAGED 36,422 BOE/D, UP 2%,
VIM-1 PRODUCTION TO START IN NOVEMBER,
EXPECT 2021 EXIT RATE OF OVER 40,000 BOE/D

CONCILIATION AGREEMENT APPROVED RESOLVING
OUTSTANDING PIPELINE DISPUTES, PENDING FORMALITIES,

78% OF TOTAL KAWA-1 WELL FOOTAGE DRILLED

JANDAYA-1 WELL IN ECUADOR EXPECTED TO SPUD
IN DECEMBER 2021

CALGARY, AB, Nov. 3, 2021 /CNW/ - Frontera Energy Corporation (TSX: FEC) ("Frontera" or the "Company") today reported financial and operational results for the third quarter ended September 30, 2021. All financial amounts in this news release are in United States dollars, unless otherwise stated.

Third Quarter Operational and Financial Results:

• The Company is tightening and increasing its full-year operating EBITDA to $360-$380 million, compared to its prior $325-$375 million guidance range. Operating EBITDA was $72.6 million in the third quarter compared with $84.8 million in the prior quarter and $52.1 million in the third quarter of 2020. The decrease in operating EBITDA quarter over quarter was primarily a result of one less cargo sold during the third quarter (which was sold early in the fourth quarter) and the corresponding increase in inventory. This was partially offset by a decrease in realized loss on risk management contracts and a $7.2 million reversal of prior period cash royalties provision. Frontera expects to sell six cargoes in the fourth quarter of 2021.
  
  
• The Company saw positive momentum in production growth throughout and subsequent to the quarter as progress was made to address water-handling and community challenges. Frontera reaffirms its year end exit rate of over 40,000 boe/d. Production averaged 36,422 boe/d, up 2% compared to 35,682 boe/d in the prior quarter and 43,202 boe/d in the third quarter of 2020. Frontera's daily production on November 2, 2021 was approximately 38,400 boe/d and the Company's year-to-date average to November 2, 2021 was approximately 37,600 boe/d. See the table below for product type and prior quarter production information.
  
  

	Q3 2021	Q2 2021	Q3 2020
Heavy crude oil production (bbl/d)	18,168	17,241	21,997
Light and medium crude oil production (bbl/d)	17,371	17,535	19,820
Conventional natural gas production (mcf/d)	5,033	5,164	7,895
Total production (boe/d)	36,422	35,682	43,202

• At September 30, 2021, the Company had a total inventory balance of 1,423,321 bbls compared to 969,028 bbls at June 30, 2021. The increase in inventory balance in the third quarter is a result of one less cargo sold during the third quarter compared to the previous quarter and no sales in Perú.
  
  
• The Company reported a total cash position of $419.5 million at September 30, 2021 compared to $486.6 million at June 30, 2021. Cash utilization during the third quarter included $63.4 million for the pre-payment related to the prior quarter refinancing of the Company's U.S.$350 million 9.7% senior unsecured notes due 2023 with the lower cost U.S.$400 million 7.875% senior unsecured notes due 2028. The Company's restricted cash position was $100.7 million at September 30, 2021 compared to $128.3 million in the second quarter of 2021, a release of approximately $27.6 million. Year to date, the Company has released approximately $68.3 million of restricted cash
  
  
• Cash provided by operating activities was $79.1 million, compared with $87.4 million in the prior quarter and $35.9 million in the third quarter of 2020.
  
  
• Under the Company's current Normal Course Issuer Bid ("NCIB") which commenced on March 17, 2021, the Company repurchased for cancelation 1,078,600 common shares during the quarter at a cost of approximately $6.1 million. Year to date to November 2, the Company repurchased approximately 3.12 million common shares for cancelation for approximately $17 million.
  
  
• Capital expenditures were $103.2 million in the third quarter of 2021, compared with $61.2 million in the prior quarter and $2.9 million in the third quarter of 2020. Year to date to September 30, 2021, the Company executed $178.8 million in total capital spending. The increase in capital expenditures in the third quarter compared to the prior quarter was primarily due to increased operational activity as the Company drilled 15 development wells and increased exploration activity in Guyana and Colombia. 
  
  
• The Company recorded net income of $38.5 million ($0.40/share) compared with a net loss of $25.6 million ($0.26/share) in the prior quarter and a net loss of $90.5 million ($0.93/share) in the third quarter of 2020. The net income in the current quarter was mainly due to $40 million of income from operations during the quarter.
  
  
• The Company's operating netback was $37.79/boe, up 15.2% compared with $32.80/boe in the prior quarter and $17.84/boe in the third quarter of 2020 due to higher net sales realized price and a reduction in production and transportation costs during the third quarter. The majority of the Company's hedge ceilings from the second quarter have now rolled off, providing upside exposure to Brent pricing. 
  
  
• The Company's net sales realized price was $59.47/boe in the third quarter, up 7%, or $3.80/boe, compared to $55.67/boe in the prior quarter and $36.63/boe in the third quarter of 2020. The increase was primarily driven by the increase in the benchmark oil price and lower losses on risk management contracts, partially offset by higher royalties as a result of a reversal of a previously recorded provision during the second quarter of 2021 and wider differentials during the third quarter of 2021. Beginning in the second quarter of 2021, the Company moved from using a third-party diluent service to buying its own diluent at the corresponding fields (mainly Quifa), using it for blending to meet pipeline specifications and other services, and then selling the blended oil at the sales point. The dollar difference between the cost of the purchases versus sales is approximately equivalent to how the Company accounted for the diluent costs in the past, or lower, considering the Company's ability to secure better prices than a third-party diluent service. The decrease in diluent costs since the second quarter reflects decreased usage of the diluent service as the Company adopts this more efficient approach.
  
  
• Production costs averaged $11.44/boe, down 2.4% compared with $11.72/boe in the prior quarter and $8.55/boe in the third quarter of 2020.
  
  
• Transportation costs averaged $10.24/boe, down 8.2% compared with $11.15/boe in the prior quarter and $10.24/boe in the third quarter of 2020.
  
  
• The Company recorded a realized loss on risk management contracts of $6.6 million in the third quarter of 2021 compared to a realized loss of $24.8 million in the second quarter of 2021 and a loss of $6.2 million in the third quarter of 2020. The realized loss on risk management contracts was primarily due to cash settlement on 3-ways and Put Spreads contracts paid during the quarter at an average price of $62.85/bbl. The Company's fourth quarter hedges do not materially cap upside price potential. See the Hedging Update section below for more information.
  
  
• Frontera continues to advance its ESG Strategy and expects to achieve its 2021 ESG goals. The Company has planted 110 hectares of biological corridors to preserve biodiversity and ecosystems, and has purchased carbon credits to offset 40% of the Company's emissions. See below for more information.

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

"Frontera continues to make significant progress on its key strategic priorities. The Company is tightening and increasing its full year operating EBITDA range to $360-$380 million.

The Company saw positive production growth momentum throughout and subsequent to the end of the quarter. Frontera also reaffirms its year end exit rate of over 40,000 boe/d.

Frontera and majority-owned subsidiary and co-venturer CGX, spud the Kawa-1 well in the Corentyne block, offshore Guyana. As of November 1, 2021, close to 78% of the planned footage has been drilled and the three main geological targets remain to be drilled. The Joint Venture continues to progress towards its total depth target in one of the most exciting exploration wells of 2021 and a potentially transformational catalyst for Frontera and CGX.

Subsequent to the quarter, the conciliation agreement between Frontera, CENIT and Bicentenario was approved, pending formalities, fully resolving all outstanding transportation disputes in Colombia and removing the Company's largest contingent liability and opening the door for other strategic opportunities."

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

"The Company delivered solid financial and operating results in the third quarter including delivering net income of $38.5 million. Compared to the second quarter, Frontera's production increased 2%, operating netback increased 15.2% and net sales realized price increased 7%. The majority of the Company's hedge ceilings from the second quarter have now rolled off, providing upside exposure to Brent pricing. Transportation costs also decreased 8.2% and production costs decreased 2.4% quarter over quarter. Frontera also repurchased 1,078,600 common shares for cancelation at an approximate cost of $6.1 million. 

The Company drilled 15 wells and completed 27 workovers and well services during the third quarter. At Quifa, the Company drilled a new injector well which increased water handling capacity and production. At CPE-6, we grew production to approximately 5,000 bbl/d. At the La Belleza discovery, the Joint Venture expects early gross production of approximately 2,400 boe/d to commence in November 2021. In Ecuador, environmental licensing is complete and road construction is underway in advance of spudding the Jandaya-1 exploration well in the Perico block in early December 2021.

Subsequent to the quarter, Frontera sold its interests in Maurel and Prom Colombia, reducing work commitments by $17.2 million, streamlining its portfolio and focusing on its core assets. "Frontera also acquired approximately 45 million CGX common shares in connection with their rights offering, increasing Frontera's ownership in CGX to 76.98% on a non-diluted basis."

Executive Updates

Effective October 1, 2021, Victor Vega became Vice-President, Field Development, Reservoir Management, and Exploration, replacing Duncan Nightingale. Mr. Vega has more than 30-years industry experience with Amoco, BP, Talisman and Shell in various technical and managerial positions and will lead Frontera's Exploration, Reserves and Technical Support, Reservoir Development functions.

Third Quarter 2021 Operational and Financial Summary:

		Q3 2021		Q2 2021		Q3 2020
Operational Results
Heavy crude oil production	(bbl/d)	18,168		17,241		21,997
Light and medium crude oil production	(bbl/d)	17,371		17,535		19,820
Total crude oil production ^(1)	(bbl/d)	35,539		34,776		41,817
Conventional natural gas production	(mcf/d)	5,033		5,164		7,895
Total production ^(2)(3)	(boe/d) ^(4)	36,422		35,682		43,202
Inventory Balance
Colombia	(bbl)	943,121		488,828		708,103
Peru	(bbl)	480,200		480,200		1,000,058
Total Inventory	(bbl	1,423,321		969,028		1,708,161
Oil & gas sales, net of purchases^(5)	($/boe)	67.13		64.54		40.18
Realized (loss) gain on risk management contracts	($/boe)	(2.68)		(8.00)		(1.70)
Royalties	($/boe)	(4.83)		(0.53)		(0.23)
Diluent costs	($/boe)	(0.15)		(0.34)		(1.62)
Net sales realized price ^(6)	($/boe)	59.47		55.67		36.63
Production costs^(7)(9)	($/boe)	(11.44)		(11.72)		(8.55)
Transportation costs^(8)(9)	($/boe)	(10.24)		(11.15)		(10.24)
Operating netback ^(10)	($/boe)	37.79		32.80		17.84
Financial Results
Oil and Gas Sales, net of purchases	($M)	164,731		200,581		147,832
Realized (loss) gain on risk management contracts	($M)	(6,570)		(24,877)		(6,246)
Royalties	($M)	(11,848)		(1,640)		(861)
Diluent costs	($M)	(366)		(1,056)		(5,954)
Net sales^(10)	($M)	145,947		173,008		134,771
Net income (loss)^(11)	($M)	38,531		(25,648)		(90,473)
Per share – basic	($)	0.40		(0.26)		(0.93)
Per share – diluted	($)	0.39		(0.26)		(0.93)
General and administrative	($M)	12,656		14,132		10,539
Operating EBITDA ^(10)	($M)	72,646		84,771		52,113
Cash provided by operating activities	($M)	79,114		87,391		35,929
Capital expenditures ^(12)	($M)	103,220		61,214		2,905
Cash and cash equivalents - unrestricted	($M)	318,791		358,325		259,980
Restricted cash short and long-term	($M)	100,692		128,283		161,318
Total cash, including restricted cash	($M)	419,483		486,608		421,298
Total debt and lease liabilities	($M)	563,173		565,238		557,182
Consolidated total indebtedness (Excl. Unrestricted Subsidiaries) ^(13)	($M)	401,148		468,424		352,058
Net Debt (Excluding Unrestricted Subsidiaries)^(13)	($M)	130,680		138,701		113,054

1. Reference to crude oil or natural gas production in the above table and elsewhere in the Company's management
discussion & analysis for the three and nine months ended September 30, 2021 (the "MD&A") refer to the light and medium crude oil and heavy crude oil and conventional natural gas, respectively, product types in National Instrument 51-101- Standards of Disclosure for Oil and Gas Activities.

2. Represents working interest production before royalties and total volumes produced from service contracts. Refer to the "Further Disclosures" section on page 25 of the MD&A.

3. Conventional Natural gas liquids have not been presented separately because production for such type was immaterial to the Company.

4. Boe has been expressed using the 5.7 to 1 Colombian Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy.

5. "Oil & Gas sales, net of purchases" is a non-IFRS measure and includes crude oil and natural gas sales, net of the cost of volumes purchased from third-party. For further detail refer to the "Non-IFRS Measures" section on page 16 of the MD&A.

6. Per boe is calculated using sales volumes from development and producing ("D&P") assets. Volumes purchased from third parties are excluded.

7. Per boe is calculated using production.

8. Per boe is calculated using net production after royalties.

9. Prior period figures are different compared with those previously reported as a result of a reclassification from production cost to transportation cost and diluent cost by approximately ($0.40/boe), $0.30/boe and $0.10/boe per quarter, respectively. The reclassification was related to certain logistic and refining processes fees of own crude oil previously recorded as production cost.

10. Refer to the "Non-IFRS Measures" section on page 16 of the MD&A. This section also includes a description and details for all per boe metrics included in operating netback.

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

12. Capital expenditures include costs, net of income from exploration and evaluation ("E&E") assets.

13. Refer to the "Non-IFRS Measures" section on page 16 of the MD&A. ("Unrestricted Subsidiaries") include CGX Energy Inc.("CGX"), ODL JV Ltd., and Frontera Bahía Holding Ltd including its subsidiary Sociedad Portuaria Puerto Bahía S.A. ("Puerto Bahia").

Operational Update

Guyana

On August 22, 2021, Frontera and majority-owned subsidiary and co-venturer CGX commenced drilling operations on the Kawa-1 exploration well and CGX exercised its option to drill a second well with Maersk Drilling Holdings Singapore Pte ("Maersk") through the use of the Maersk Discoverer rig. Operations at Kawa-1 have proceeded on schedule and comprehensive planning by the Joint Venture has resulted in effective contingency planning and a final well plan and design that has allowed the well to progress without a major individual setback to date. Four of five planned casing strings have been landed and cemented in place with two contingency casing strings still available for use if required. As of November 1, 2021, close to 78% of the planned footage has been drilled and the three main prospective targets of the Kawa-1 well remain to be drilled, cased and evaluated with current expectations on reaching total depth consistent with the previous public disclosure of December 2021.

The Kawa-1 well will test the easternmost channel/lobe complex on the northern section of the Corentyne block. The primary target at Kawa is a Santonian age channel/fan, with secondary targets in the Campanian and deeper Santonian. The primary target has the best and brightest amplitudes in the Santonian, and most definitive trap definition.

Frontera and majority-owned subsidiary and co-venturer CGX hold over 1.4 million gross acres in the Guyana-Suriname basin. Additional drill-ready prospects have been identified in the North Corentyne area and several exploration leads are being matured. CGX continues to advance its development of its Berbice deep water harbor project to support the rapidly expanding local oil and gas industry including its own activities.

Colombia

Production averaged 36,422 boe/d, up 2% compared to 35,682 boe/d in the prior quarter and 43,202 boe/d in the third quarter of 2020. Higher production quarter over quarter was a result of production growth in the CPE-6 and Quifa blocks resulting from water handling improvements during the third quarter.

Currently, the Company has three drilling rigs and six workover rigs active at its Quifa, Coralillo and Abanico operations. In the third quarter of 2021, the Company drilled 15 wells and completed 27 workovers and well services. Year to date, the Company has drilled 28 wells and completed workovers/well services and other activities at 86 others.

At Quifa, current production is approximately 16,300 bbl/d (including both Quifa and Cajua). Frontera drilled one new injector well and converted one inactive well into an injector well, which the Company expects will contribute to increased production volumes from the Block through year-end as water disposal volumes increase. Year to date, Frontera has drilled 13 development wells at Quifa and the Company expects to drill an additional 10 development wells in the fourth quarter.

At CPE-6, current production is approximately 5,000 bbl/d due to continued drilling and construction of additional water-handling facilities.

At Guatiquia, the Company successfully completed the Coralillo-4 and Coralillo-5 wells in the Coralillo field, which are producing over 720 bbl/d. A third well in Coralillo (Coralillo-9) is currently being completed.

On the VIM-1 Block (Frontera 50% W.I., Parex 50% W.I. and operator) the Planadas-1 exploration well has been drilled to a measured depth of ~13,700 feet in Cretaceous aged crystalline basement. The well was drilled 6.3 kilometers west of the La Belleza-1 discovery well targeting the limestones and sandstones of the CDO Formation as well as the fractured basement section. The well was positioned 1,425 feet (true vertical depth) down dip of the La Belleza-1 well and 1,140 feet above the regional structural closure in order to test the possibility of a continuous hydrocarbon column existing across the large Apure High on the VIM-1 block. Gas shows were encountered during drilling and a detailed logging program is now underway to identify zones for potential testing.

At the La Belleza discovery on VIM-1, the Joint Venture expects early gross production of ~2,400 boe/d (consisting of 1,400 bbls/d of light crude oil per day and 6 mmcf/d of conventional natural gas) to commence in November 2021.           

Ecuador

In Ecuador, environmental licensing is complete and road construction is underway in advance of spudding the Jandaya-1 exploration well in the Perico block (Frontera 50% W.I. and operator, GeoPark 50% W.I.) in early December 2021. In the Espejo block (Frontera 50% W.I., GeoPark 50% W.I. and operator) 3D seismic acquisition of 60 sq km is expected to start in the fourth quarter.

Peru

Remediation work in Block 192 and the Z-1 block continues as the Company pursues its exit from Peru. At the end of the third quarter, Frontera's oil inventory in Peru was 480,200 bbls. The Company expects to sell the remaining oil inventory in Peru in 2022.

Administrative Tribunal of Cundinamarca Approves Conciliation Agreement Between Frontera, CENIT and Bicentenario, Pending Formalities

On November 1, 2021, Frontera, announced that the official webpage of the Colombian judicial branch reported that the Administrative Tribunal of Cundinamarca had approved the conciliation agreement ("Conciliation Agreement") between Frontera, Cenit Transporte y Logística de Hidrocarburos S.A.S. ("CENIT") and Oleoducto Bicentenario de Colombia S.A.S. ("Bicentenario"). Formalities are required in order for the mentioned decision to be in full force and effect. Consequently, the parties agreed to extend the deadline until November 30, 2021, to allow for the formalities to be completed.

The approval of the "Conciliation Agreement" by the Administrative Tribunal of Cundinamarca fully resolves all outstanding disputes between the parties related to the Bicentenario Pipeline and the Caño Limón – Coveñas Pipeline and terminates all pending arbitration proceedings related to such disputes.

Frontera and Etablissement Maurel & Prom S.A. Complete Share Transfer

On October 22, 2021, Frontera signed and closed a Sale and Settlement Agreement, transferring to Etablissement Maurel & Prom ("EMP") 49.999% of all issued and outstanding shares of the Maurel & Prom Colombia B.V. ("M&P"), an entity that holds 100% interests in the COR-15 and Muisca exploration licenses. As a result, Frontera committed to fund $1.6 million in Muisca cash calls. In addition, Frontera will provide M&P up to $6.0 million to be disbursed in 2022 in relation to outstanding commitments at COR-15, subject to certain conditions. Following the transaction, EMP and Frontera settled all mutual obligations, removing an estimated $17.2 million in Frontera minimum work commitments subsequent to September 30, 2021, and providing certain indemnities to M&P. With the closing of this transaction, Frontera terminated a revolving loan agreement, which required the Company to support 100% of any future development costs in the COR-15 license. Completion of this transaction supports Frontera's ongoing efforts to streamline its portfolio, reduce exposure to liabilities and exploration commitments and focus on its core assets.

Update on Credit Lines

The Company has various uncommitted bilateral letters of credit lines. As of September 30, 2021, the Company had increased its uncollateralized credit lines to $78.8 million. Subsequent to the quarter, the Company increased its uncollateralized credit lines to $90.3 million.

Update on the Company's Restricted Cash Position

As of September 30, 2021, Frontera's restricted cash position was $100.7 million compared to $128.3 million in the second quarter of 2021. Year to date, the Company has released approximately $68.3 million of restricted cash. The decrease in restricted cash is primarily due to the release of $22.3 abandonment funds that were replaced with letters of credit, $13.9 million of closed legal processes, and $31.6 million released due to the reduction in cash collateral requirements of exploration commitments and the new agreement with Citibank regarding cash collateral of letters of credit and foreign exchange fluctuations. The Company anticipates releasing additional restricted cash in the fourth quarter of 2021 as the Company continues to optimize its credit lines.

Update on the Normal Course Issuer Bid

During the third quarter of 2021, the Company repurchased for cancelation, 1,078,600 common shares at an approximate cost of $6.1 million. Year to date to November 2, the Company has repurchased approximately 3.12 million common shares for cancelation for approximately $17 million with an additional 2,076,612 common shares available for repurchase under the NCIB. Under its NCIB, Frontera may purchase up to 5,197,612 common shares during the twelve-month period commencing March 17, 2021 and ending March 16, 2022, representing approximately 10% of the Company's "public float", calculated in accordance with the rules of the Toronto Stock Exchange as of March 11, 2021.

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 using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside. This diversification of instruments allows the Company to take a more dynamic approach to the management of its hedging portfolio. In 2021, the Company executed a risk management strategy using a variety of derivatives instruments, including 3 - ways, puts and put spreads primarily to protect against downward oil price movements. The following table summarizes Frontera's hedging position for the fourth quarter of 2021 and first quarter of 2022.

Term	Instrument	Notional Amount/ Volume (bbl/d)	Strike Prices Put/ Call; Call Spreads
October	3-Ways	1,935	37/47/62.9
	Put Spread	13,484	40/50
	Put	7,742	60
November	3-Ways	2,000	37/47/62.9
	Put Spread	13,933	40/50
	Put	7,233	60
December	3-Ways	1,935	37/47/62.9
	Put Spread	13,484	40/50
	Put	7,645	60
Total 4Q 2021		23,130
January	Zero Cost Collars	1,774	60/102
	Put	16,129	60
February	Put	16,250	60
March	Put	14,194	60
Total 1Q 2022		16,111

Update on Frontera's ESG Strategy

Frontera continues to advance its ESG Strategy and expects to achieve its 2021 ESG goals. In the environmental focus area, the Company has planted 110 hectares of biological corridors to preserve biodiversity and ecosystems, and has purchased carbon credits to offset 40% of the Company's emissions. In the social focus area, the Company is strengthening its local suppliers program, developing a training program aimed at improving competitiveness and increasing local purchasing. In the governance focus area, the Company is integrating ESG-related risks within its existing risk management framework to improve measuring, monitoring and reporting.

Third Quarter 2021 Conference Call Details

A conference call for investors and analysts will be held on Thursday, November 4, 2021 at 10:30 a.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Alejandro Piñeros, 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): 1-866-269-4260
Participant Number (Toll Free Colombia): 01-800-518-3328
Participant Number (International): 1-647-792-1240
Conference ID: 9932507
Webcast Audio: www.fronteraenergy.ca

A replay of the conference call will be available until 11:59 p.m. Eastern Time on November 11, 2021.

Encore Toll free Dial-in Number: 1-647-436-0148
International Dial-in Number: 1-888-203-1112
Encore ID: 9932507

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 39 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 e-mail 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 statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, the Company's exploration and development plans and objectives, including with respect to its joint venture with CGX)),including its drilling plans and the timing thereof, estimates and/or assumptions in respect of the Company's capital expenditure program (including Company's guidance), production levels, costs, future income generation capacity, cash levels (including the timing and ability to release restricted cash), regulatory approval, and the Company's hedging program and its ability to mitigate the impact of changes in oil prices) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: volatility in market prices for oil and natural gas (including as a result of a sustained low oil price environment due to the COVID-19 pandemic and the procedures imposed by governments in response thereto and the actions of OPEC and non-OPEC countries); the duration and spread of the COVID-19 pandemic and its severity, the success of the Company's program to manage COVID-19; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; the Company's ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; political developments in the countries where the Company operates; the uncertainties involved in interpreting drilling results and other geological data; geological, technical, drilling and processing problems; timing on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 3, 2021 filed on SEDAR at www.sedar.com. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.

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

Non-IFRS Financial Measures

This news release contains financial terms that are not considered in the International Financial Reporting Standards ("IFRS"): Operating EBITDA, Operating Netback, Net Sales, Oil & gas sales, net of purchases, Consolidated Total Indebtedness and Net Debt. These financial measures, together with measures prepared in accordance with IFRS, provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. The Company's determination of these non-IFRS measures may differ from other reporting issuers, and therefore are unlikely to be comparable to similar measures presented by other companies. Further, these non-IFRS measures should not be considered in isolation or as a substitute for measures of performance or cash flows prepared in accordance with IFRS. These financial measures are included because management uses this information to analyze operating performance and liquidity. Prior period figures are different compared with those previously reported as a result of the change in the treatment of purchased volumes and cost of purchases according to the new operating netback approach. Refer to the "Non-IFRS Measures" section on page 13 of the MD&A for further details.

Operating EBITDA

Management believes that EBITDA is a common measure used to assess profitability before the impact of different financing methods, income taxes, depreciation and impairment of capital assets and amortization of intangible assets.

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 represents the operating results of the Company's primary business, excluding the items noted above, restructuring, severance and other costs, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, costs under terminated pipeline contracts, and share-based compensation) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company.

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

			Three Months Ended
($M)	September 30, 2021		June 30, 2021		September 30, 2020
Net income (loss)	38,531		(25,648)		(90,473)
Finance Income	(817)		(6,167)		(2,019)
Finance expenses	12,720		11,728		12,655
Income tax (recovery) expense	(13,992)		37,869		2,805
Depletion, depreciation and amortization	33,480		40,455		60,960
Impairment and Others	3,846		(1,111)		480
Cost under terminated pipeline contracts	—		—		8,391
Shared-based compensation	962		3,142		246
Restructuring, severance and other cost	954		1,535		1,047
Share of income from associates	(8,691)		(9,805)		(15,193)
Foreign exchange loss	5,846		48		12,450
Other loss, net	570		3,182		38,626
Unrealized gain (loss) on risk management contracts	(4,068)		(7,453)		351
Non-controlling interests	3,305		3,373		(2,169)
Loss on extinguishment of debt	—		29,112		—
Reclassification of currency translation adjustments	—		—		2,956
Operating EBITDA	72,646		84,771		52,113

Netbacks

Management believes that Netback is a useful measure to assess the net profit after all the 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. Operating Netback represents realized price per barrel plus realized gain or loss on financial derivatives, less production costs, transportation costs, royalties, and diluent costs, and shows how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of trading activities and Midstream segment from its per barrel metrics. Refer to the "Operating Netback" section on page 7 of the MD&A.

Net Sales

Net sales are a non-IFRS subtotal 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 of diluent cost 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 exclude sales from port services, as it is not considered part of the oil & gas segment, and sales and purchases of oil and gas for trading as the gross margins from these activities are not considered significant or material to the Company's operations.  Refer to the reconciliation in the "Sales" section on page 8 of the MD&A.

Consolidated Total Indebtedness and Net Debt

Consolidated total indebtedness and net debt are used by the Company to monitor its capital structure, financial leverage, and as a measure of overall financial strength. Consolidated total indebtedness is defined as long-term debt, plus liabilities for leases and net position of risk management contracts, excluding Unrestricted Subsidiaries. This metric is consistent with the definition under the Company's Unsecured Notes (as defined in the MD&A) for the calculation of certain conditions and covenants. Net debt is defined as consolidated total indebtedness less cash and cash equivalents.  Both measures are exclusive of non-recourse subsidiary debt (2025 Puerto Bahia Debt) and cash attributable to the Unrestricted Subsidiaries.

Please see the MD&A for additional information about these financial measures.

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
bbl/d	Barrels of oil per day
Bcf	Billion cubic feet
boe	Refer to "Boe Conversion" disclosure above
boe/d	Barrel of oil equivalent per day
Mcf	Thousand cubic feet
MMbbl	Million barrels of oil
MMboe	Million barrels of oil equivalent
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

Brent Anderson, Director, Investor Relations, [phone], [email protected], www.fronteraenergy.ca

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