FRONTERA ANNOUNCES THIRD QUARTER 2023 RESULTS

Recorded Net Income of $32.6 Million

Generated Strong Operating EBITDA of $137.8 Million, Up 18% compared to Q2 2023

Delivered Steady Average Daily Production of 40,802 Bbl/d,

Including Record CPE-6 Quarterly Average Production of 5,803 Bbl/d, Up 13% versus Q2 2023

Completed Successful Exploration and Appraisal Activities and Produced 1 Millionth Barrel from the Perico Block, Ecuador

Generated Quarterly Adjusted Midstream EBITDA of $29.9 Million and Segment Income of $17.3 Million From Standalone and Growing Midstream Business

Discovered 342 Feet (104 meters) of Total Net Pay, Confirming the Significant Potential of the Corentyne Block

Achieved Best Ever Total Recordable Incident Rate (TRIR) of 0.49,

Preserved 1,367 Hectares in the Serranía de Manacacías Park, Entrerríos

Intends to Launch a NCIB To Permit Purchases Up to 10% Of the Outstanding Float Over the Next Year

CALGARY, AB, Nov. 9, 2023 /PRNewswire/ – Frontera Energy Corporation (TSX: FEC) (“Frontera” or the “Company“) today reported financial and operational results for the third quarter ended September 30, 2023. 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 three core businesses continue to deliver solid performance.

Frontera delivered strong operational and financial results from its upstream onshore business and capital spending returned to normal levels following the completion of Wei-1 operations. As a result, the Company increased its total cash position, including restricted cash, to $221 million as of September 30.

Income from the Company’s standalone and growing Colombia Midstream business increased 13% during the quarter and pre-construction activities have begun on the important pipeline connection between Frontera’s Puerto Bahia liquids terminal and the Cartagena Refinery.

In parallel with the third-party laboratory confirmation of our significant light oil and sweet medium crude discovery at Wei-1, the Joint Venture, with support from Houlihan Lokey, is reviewing strategic options for its potentially transformational Guyana exploration business, the Corentyne block, including a potential farm down, as it progresses its efforts to maximize value from its investments in Guyana.

Importantly, during the quarter, the Company continued to drive costs out of its business, reducing its G&A by 4%. Building on this positive momentum and to better position the Company for sustained long-term success, subsequent to the quarter, Frontera’s board of directors approved a restructuring plan that will improve organizational and operational efficiencies, reduce costs and better align the Company’s workforce with current business needs, top strategic priorities, and key growth opportunities.

Frontera also plans to launch a NCIB to permit purchases of up to 10% of its outstanding float.

I am excited about the strong performance from Frontera’s three core businesses and the tangible steps the Company is taking to surface value for shareholders.”

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

“I am pleased with Frontera’s third quarter operational and financial results. We increased our operating EBITDA by 18% and our operating netback by 19% quarter over quarter, driven in part by a 16% increase in our net sales realized price.

Year-to-date, our production has averaged 41,477 boe/d. In the third quarter, we increased our heavy oil production by 15% due in part to increased water-handling at SAARA and increased natural gas liquids production by 100% compared to the same quarter last year. At CPE-6, we also delivered record quarterly average production of 5,803 bbl/d, up 13% quarter/quarter through development drilling, new flow lines, and expanded facilities. Recently, CPE-6 achieved record daily production of 6,435 bbl/d.

We achieved record safety results for the nine-months ended September 30, as our employees delivered the lowest recordable incident rate (TRIR) in Company history. Additionally, the Company recycled 41.4% of all water used in our operations, offset 33% of our 2023 Colombian emissions, and preserved 1,367 hectares in the Serranía de Manacacías Park, in Entrerríos as we continue to responsibly meet our corporate and ESG objectives.

Finally, during the quarter, third-party laboratory analysis confirmed the presence of medium sweet crude oil in high-quality Maastrichtian cored reservoir at the Wei-1 well on the Corentyne block, offshore Guyana, confirming the significant potential of this block.”

Third Quarter 2023 Operational and Financial Summary:

		Q3 2023	Q2 2023	Q3 2022

Operational Results

Heavy crude oil production ⁽¹⁾	(bbl/d)	24,097	24,051	20,945
Light and medium crude oil production ⁽¹⁾	(bbl/d)	13,964	15,188	17,428
Total crude oil production	(bbl/d)	38,061	39,239	38,373

Conventional natural gas production	(mcf/d)	5,250	5,626	9,969
Natural gas liquids production ⁽¹⁾	(boe/d)	1,820	1,823	911
Total production ⁽²⁾	(boe/d) ⁽³⁾	40,802	42,049	41,033

Inventory Balance
Colombia	(bbl)	812,797	881,758	590,984
Peru	(bbl)	480,200	480,200	480,200
Ecuador	(bbl)	37,421	72,550	66,729
Total inventory balance	(bbl)	1,330,418	1,434,508	1,137,913

Brent price reference	($/bbl)	85.92	77.73	97.70
Oil & gas sales, net of purchases ⁽⁴⁾⁽⁵⁾	($/boe)	78.48	67.91	90.40
Premiums paid on oil price risk management contracts ⁽⁶⁾	($/boe)	(0.59)	(0.80)	(1.30)
Royalties ⁽⁶⁾	($/boe)	(3.76)	(3.02)	(7.23)
Net sales realized price ⁽⁴⁾⁽⁵⁾	($/boe)	74.13	64.09	81.87
Production costs, net of realized FX hedge impact ⁽⁴⁾⁽⁵⁾	($/boe)	(13.86)	(12.39)	(11.20)
Transportation costs, net of realized FX hedge impact ⁽⁴⁾⁽⁵⁾	($/boe)	(11.73)	(10.89)	(10.70)
Operating netback per boe ⁽⁴⁾	($/boe)	48.54	40.81	59.97

Financial Results

Oil and Gas Sales, net of purchases ⁽⁷⁾	($M)	254,805	221,218	304,899
Premiums paid on oil price on risk management contracts	($M)	(1,930)	(2,600)	(4,393)
Royalties	($M)	(12,216)	(9,837)	(24,371)
Net sales ⁽⁷⁾	($M)	240,659	208,781	276,135
Net income (loss) ⁽⁸⁾	($M)	32,582	80,207	(26,893)
Per share – basic	($)	0.38	0.94	(0.30)
Per share – diluted	($)	0.37	0.92	(0.30)
General and administrative	($M)	11,925	12,422	12,549
Outstanding Common Shares	Number of Shares	85,431,716	85,188,573	86,575,175
Operating EBITDA ⁽⁷⁾	($M)	137,800	116,461	173,207
Cash provided by operating activities	($M)	153,957	183,560	120,804
Capital expenditures ⁽⁷⁾	($M)	74,130	154,860	76,018
Cash and cash equivalents – unrestricted	($M)	189,190	180,294	253,550
Restricted cash short and long-term ⁽⁹⁾	($M)	32,048	33,485	55,552
Total cash ⁽⁹⁾	($M)	221,238	213,779	309,102
Total debt and lease liabilities ⁽⁹⁾	($M)	525,517	532,273	533,077
Consolidated total indebtedness (Excl. Unrestricted Subsidiaries) ⁽¹⁰⁾	($M)	409,853	415,395	412,926
Net Debt (Excluding Unrestricted Subsidiaries) ⁽¹⁰⁾	($M)	271,508	286,675	205,625

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

2. Represents W.I. production before royalties. Refer to the “Further Disclosures” section of the Company’s management’s discussion and analysis for the three months ended September 30, 2023 (the “Interim MD&A”), which will be filed on the Company’s profile on SEDAR+ at www.sedarplus.ca.

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 “Oil and Gas Information Advisories” section.

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

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

6. Supplementary financial measure (as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section.

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

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

9. Capital management measure (as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section.

10. “Unrestricted Subsidiaries” as of September 30, 2023, include CGX Energy Inc. (“CGX”), listed on the TSX Venture Exchange under the trading symbol “OYL”, Frontera ODL Holding Corp., including its subsidiary Pipeline Investment Ltd. (“PIL”), Frontera BIC Holding Ltd., and Frontera Bahía Holding Ltd., including its subsidiary Sociedad Portuaria Puerto Bahia S.A (“Puerto Bahia”). On April 11, 2023, Frontera Energy Guyana Holding Ltd. And Frontera Energy Guyana Corp. were designated as unrestricted subsidiaries. Refer to the “Liquidity and Capital Resources” section on page 26 of the Interim MD&A.

Third Quarter Operational and Financial Results:

The Company recorded net income of $32.6 million ($0.38/share) in the third quarter of 2023, compared with net income of $80.2 million ($0.94/share) in the prior quarter and a net loss of $26.9 million (($0.30))/per share) in the third quarter of 2022. The Net income in the third quarter included operating income of $65.0 million, share of income from associates of $13.7 million, a foreign exchange gain of $4.3 million and finance income of $1.9 million, partially offset by finance expenses of $16.4 million, other expenses of $1.2 million and income tax expenses of $15.3 million.
Production averaged 40,802 boe/d (consisting of 24,097 bbl/d of heavy crude oil, 13,964 bbl/d of light and medium crude oil, 5,250 mcf/d of conventional natural gas and 1,820 boe/d of natural gas liquids) in the third quarter of 2023, down 3% compared to 42,049 boe/d in the prior quarter and 41,033 boe/d in the third quarter of 2022. The decrease in production quarter-over-quarter was mainly the result of lower light and medium crude oil production in Colombia, driven in part by the relinquishment of the Neiva and Orito blocks (which produced approximately 587 boe/d net to Frontera) to Ecopetrol following the completion of the block’s production contract at the end of the second quarter of 2023, The decrease was partially offset by higher heavy oil crude production driven by another record quarterly CPE-6 production of 5,803 bbl/d due to positive development drilling and the reactivation of the Sabanero block on July 1, 2022, and the successful Jandaya-1 well stimulation in Ecuador.
Operating EBITDA was $137.8 million in the third quarter of 2023, up 18% compared with $116.5 million in the prior quarter and $173.2 million in the third quarter of 2022. The increase in operating EBITDA quarter-over-quarter was primarily a result of higher Brent oil prices and improved differentials during the quarter, partially offset by higher production and transportation costs.
As of September 30, 2023, the Company had a total inventory balance in Colombia of 812,797 barrels, including 624,535 crude oil barrels and 188,262 barrels of diluent and others. This compared to 881,758 as of June 30, 2023, and 590,984 barrels as at June 30, 2022. The decrease in inventory balance was primarily due to inventory drawn for export sales. Inventory balances in the third quarter related to Ecuador and Peru were 37,421 barrels and 480,200 barrels, respectively.
Capital expenditures were $74.1 million in the third quarter of 2023, down 52% compared with $154.9 million in the prior quarter as expenditures related to drilling operations at Wei-1 wrapped up and $76.0 million in the third quarter of 2022. During the third quarter, the Company drilled 14 development wells at its Quifa, Cajua and CPE-6 blocks as well as one exploration well, Perico Centro-1 (formerly Jandiayacu-1) on the Perico block in Ecuador. For the nine months ended September 30, 2023, the Company has executed $360.4 million in total capital spending, including $156.8 million in total capital spending related to the Wei-1 well.
Cash provided by operating activities in the third quarter of 2023 was $154.0 million, compared with $183.6 million in the prior quarter and $120.8 million in the third quarter of 2022. Cash generation from operating activities remained strong due to stronger quarter over quarter Brent oil prices and $64.2 million in income tax and VAT recoveries.
The Company reported a total cash position of $221.2 million as of September 30, 2023, up 3% compared to $213.8 million as of June 30, 2023, and $309.1 million as of September 30, 2022. Subsequent to the quarter, the Company also borrowed $18 million under a new Bancolombia working capital loan facility and immediately repaid in full the outstanding balance of $12 million under the Citibank working capital loan.
The Company’s net sales realized price was $74.13/boe in the third quarter of 2023, up 16%, or $10.04/boe, compared to $64.09/boe in the prior quarter and $81.87/boe in the third quarter of 2022 primarily driven by the increase in the benchmark oil price and narrower differentials during the third quarter of 2023.
Frontera’s operating netback was $48.54/boe in the third quarter of 2023, up 19% compared with $40.81/boe in the prior quarter and $59.97/boe in the third quarter of 2022 due to higher net sales realized price partially offset by higher production and transportation costs during the third quarter.
Production costs, net of realized FX hedge impact, averaged $13.86/boe in the third quarter of 2023, up 12% compared with $12.39/boe in the prior quarter and $11.20/boe in the third quarter of 2022. The increase in production cost on a per barrel basis in the third quarter compared to the prior quarter is the result of higher energy costs, technical assistance and fuel consumption partially offset by lower well services costs.
Transportation costs, net of realized FX hedge impact, averaged $11.73/boe in the third quarter of 2023, up 8% compared with $10.89/boe in the prior quarter and $10.70/boe in the third quarter of 2022. The increase in transportation cost quarter-over-quarter was mainly due to the annual increase in transportation tariffs and exchange rate impacts.
In the Company’s Colombia Midstream business, total Oleoducto de los Llanos Orientales S.A. (“ODL“) volumes pumped were 251,988 bbl/d during the third quarter of 2023, up 17% versus the third quarter of 2022.
Puerto Bahia liquid volumes were 53,586 bbl/d during the third quarter down 11% compared to the third quarter of 2022, driven mainly by lower imported crude volumes. Puerto Bahia liquid revenues were $7.8 million during the third quarter, up 1% compared to the third quarter of 2022, mainly due to higher tariffs.
Adjusted Midstream EBITDA in the third quarter of 2023 was $29.9 million, compared with $31.1 million in the prior quarter and $17.6 million in the third quarter of 2022.
In the Company’s exciting Guyana Exploration business, confirmed the discovery of 342 feet (104 meters) feet of total net pay discovered to date on North Corentyne. Results further demonstrate the potential for a standalone shallow oil resource development across the Corentyne block.
Total costs associated for the Wei-1 well are now estimated to be within $185-190 million following the successful implementation of several initiatives. It is anticipated that Frontera’s actual direct and indirect WI will vary between 72.1% and 72.4%, and 93.3% and 93.4%, respectively. Final WI calculations will be determined in December 2023 after close out of the Wei-1 well.
From a shareholder initiatives standpoint, Frontera intends to implement a normal course issuer bid (“NCIB”) to permit purchase up to 10% of its public float over the next year subject to approval of the Toronto Stock Exchange (TSX).

Frontera’s ESG Strategy

The Company continues to deliver on its ESG goals. In the nine months ended September 2023, Frontera achieved a Total Recordable Incident Rate (TRIR) of 0.49, the best safety performance in Company history and below its 2023 TRIR objective of 0.74. During the third quarter Frontera, protected and preserved 1,367 hectares of land in the Serranía de Manacacías Park, Entrerríos. When combined with reforestation plantings and sustainable use projects, the Company has exceeded its goal of 1,000 hectares and totaling 5,994 hectares preserved.

As of September 30, 2023, the Company has recycled 41.4% of water used in its operation and has offset 33% of its 2023 Colombian emissions through the purchase of carbon credits. Additionally, the Company continues to focus on bridging diversity, inclusion, and gender equity gaps. During the quarter, Frontera hired six locally trained community women as well operators through its oil and gas technical program called – Crece con Frontera.

As of September 2023, Frontera has invested $2.1 million in 161 social projects, benefiting more than 33,000 people in Colombia, Ecuador and Peru. The Company purchased $50.9 million from local suppliers and will accomplish its goal of purchasing $55 million locally in 2023.

Frontera’s Three Core Businesses

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

Colombia and Ecuador Upstream Onshore

Colombia

Production from the Company’s Colombian operations in the third quarter averaged 40,150 boe/d (consisting of 24,097 bbl/d of heavy crude oil, 13,312 bbl/d of light and medium crude oil combined, 5,250 mcf/d of conventional natural gas and 1,820 boe/d of natural gas liquids), down 3% compared to 41,436 boe/d in the prior quarter, and up 1% compared to 39,829 boe/d in the third quarter of 2022. The decrease in production quarter-over-quarter was mainly the result of lower light and medium crude oil production in Colombia, driven in part by the relinquishment of the Neiva and Orito blocks (which produced approximately 587 boe/d, net to Frontera) to Ecopetrol following the completion of the block’s production contract at the end of the second quarter of 2023, partially offset higher heavy oil crude production driven by another record quarterly CPE-6 production of 5,803 bbl/d due to positive development drilling and the reactivation of the Sabanero block on July 1, 2022.

In the third quarter of 2023, the Company drilled 14 development wells, one injector well and completed well services at 21 others.

Year to date, the Company has drilled 50 development wells and 2 injector wells and completed workover services at 61 others. Currently, the Company has 3 drilling rigs, and 3 workover rigs active at its Quifa and CPE-6 blocks in Colombia.

Quifa Block: Quifa SW and Cajua

At Quifa, the Company drilled 9 development wells in the third quarter 2023. Production averaged 17,836 bbl/d of heavy crude oil in the third quarter compared to 18,408 bbl/d in the second quarter of 2023. Year to date, Frontera has drilled 33 development wells at Quifa. Additionally, the Company invested in new flow lines in the Quifa block to connect with the SAARA project.

The Company’s current water handling capacity in Quifa is approximately 1.6 million bwpd.

During the third quarter, Frontera continued with its recommissioning efforts supporting SAARA, its reverse osmosis water treatment facility with an estimated 1 million bwpd nameplate capacity. As of October 2023, the plant had processed 16.3 million barrels of water as part of its recommissioning program, providing irrigation source water to the Company’s nearby ProAgrollanos palm oil plantation. The Company is actively engaged in discussions with Ecopetrol to permanently bring the SAARA facility online under terms mutually acceptable to both parties.

CPE-6

At CPE-6, production averaged approximately 5,803 bbl/d of heavy crude oil in the third quarter, compared to 5,116 bbl/d in the second quarter of 2023. Subsequent to the quarter, the Company achieved record daily production at CPE-6 of 6,435 bbl/d. During the quarter the Company drilled 5 development wells and one injector well, invested in new flow lines, and the expanded and improved of development facilities, which the Company anticipates will double water-handling capacity to 240,000 bbls/day in the block by the end of 2023.

Other Colombia Developments

At Guatiquia, production during the quarter averaged 6,763 bbl/d of light and medium crude compared with 7,239 bbl/d in the second quarter of 2023.

On the Cubiro Block production averaged 1,729 bbl/d of light and medium crude oil in the third quarter of 2023 compared with 1,915 bbl/d in the second quarter 2023.

At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,660 bbl/d of light and medium crude oil in the third quarter of 2023 compared to approximately 1,711 bbl/d of light and medium crude oil in the second quarter of 2023.

Colombia Exploration Assets

The Company’s Colombian exploration focus remains on the Lower Magdalena Valley and Llanos Basins. In the third quarter, the Company continued to process 163 square kilometers of 3D seismic data from the Llanos-99 block. In addition, the final PSTM volume was completed in October. The Company is progressing pre-seismic and pre-drilling activities related to social and environmental studies in the Llanos-119, LLA-99, CPE-6, and VIM-46 blocks.

Ecuador

Frontera’s share of production in Ecuador for the three months ended September 30, 2023, was 652 bbl/d of medium crude oil compared to 613 bbl/d in the prior quarter.

On the Perico block (Frontera 50% W.I. and operator), the Company drilled the Perico Centro-1 (formerly Jandiayacu-1) well during the quarter, Petrophysical interpretation identified 19.5 feet of net pay in the Lower U sand, 7.5 feet in the Upper Hollin and 7.5 feet in the Main Hollin, with oil found in three intervals and initial tests delivering average production of approximately 800 bbl/d, of 28-degree API medium crude oil with 1% BSW. Clean-up activities are underway. The Company believes that the Upper Hollin presents additional exploration or production opportunity. With the completion of drilling activities at the Perico Centro-1 well, the Company has satisfied its four-well exploration commitment on the block.

The Company also spudded and completed the Yin-2 appraisal well in the third quarter, discovering 48 feet of net pay in the Lower U sand and 24 feet of net pay in the Hollin main formation, with initial production rates of approximately 1,200 bbl/d of 30.5-degree API crude oil.

In addition, the Perico Norte A4 well was spudded on October 8, 2023, reached a total depth of 11,433 feet (3,485 meters) and was completed on November 4, 2023, with initial production rates of approximately 1,200 bbl/d of 29.4 degree API crude oil with 5% BSW.

The Company continues to conduct long-term testing at the Jandaya-1, Tui-1 and Yin-1 exploration wells, as it prepares environmental impact assessments in advance of obtaining production environmental licenses.

2. Midstream Colombia

Frontera has investments in certain significant infrastructure and midstream assets, including storage, port and other facilities in Colombia as well as the Company’s investments in certain pipelines which comprise its standalone and growing Colombia Midstream business (“Midstream Colombia Segment“). Frontera’s Midstream Colombia Segment principally includes the Company’s 35% equity interest in the ODL pipeline through Frontera’s wholly owned subsidiary, PIL and the Company’s 99.97% interest in Puerto Bahia.

Midstream Colombia Segment Results

The Company’s Midstream Colombia Segment income was $17.3 million for the three months ended September 30, 2023, up 13% compared with $15.2 million in the third quarter of 2022. For the three months ended September 30, 2023, the Puerto Bahia liquids terminal revenues was $7.8 million compared with $7.7 million in the same period of 2022. The liquids terminal revenues during the third quarter of 2023, represented 60% of Puerto Bahia’s revenues, this increase can be attributed to higher revenues per barrel during 2023.

On the general cargo business, revenue increased 20% in the third quarter of 2023 compared to the same period in 2022, primarily driven by $1.2 million of additional revenues from the shorebase operation.

For the third quarter, ODL generated $39.2 million of net income. ODL total volumes pumped were 251,988 bbl/d during the third quarter, up 17% compared to the third quarter of 2022, driven by stronger crude oil volumes from [the Cano Sur block]. ODL results are recorded through the equity method in the Company’s Interim Financial Statements as “Share of Income from associates”.

Cash provided by operating activities of the Midstream Colombia Segment for three months ended September 30, 2023, was $19.2 million, up 33% compared to $14.4 million in the same period of 2022. The increase was mainly due to fluctuations in non-cash working capital.

	Three months ended September 30		Nine months ended September 30
($M)	2023	2022	2023	2022
Revenue	13,083	12,103	37,309	34,674
Liquids port facility	7,838	7,727	24,491	22,420
FEC liquids port facility	2,093	1,777	5,660	5,165
Third party liquids port facility	5,745	5,950	18,831	17,255
General Cargo	5,245	4,376	12,818	12,254
Cost	(6,419)	(5,400)	(17,269)	(15,691)
General administrative expenses	(1,400)	(1,246)	(4,197)	(3,999)
Depletion, depreciation, and amortization	(1,441)	(1,345)	(3,992)	(4,384)
Restructuring, severance, and other costs	(298)	(57)	(1,101)	(1,113)
Puerto Bahia income from operations	3,525	4,055	10,750	9,487
Share of Income from associates ODL	13,726	11,166	41,643	29,908
Segment income	17,251	15,221	52,393	39,395
Segment cash flow from operating activities	19,168	14,364	46,877	46,368

	Three months ended September 30		Nine months ended September 30
($M)	2023	2022	2023	2022
Adjusted Midstream Revenue ⁽¹⁾	43,774	26,621	125,191	75,228
Adjusted Midstream Operating Cost ⁽¹⁾	(10,881)	(7,107)	(27,929)	(20,770)
Adjusted Midstream General and Administrative ⁽¹⁾	(3,015)	(1,926)	(8,132)	(6,123)
Adjusted Midstream EBITDA ⁽¹⁾	29,878	17,588	89,130	48,335

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

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

	Three months ended September 30		Nine months ended September 30
(bbl/d)	2023	2022	2023	2022
At Rubiales Station	179,310	140,958	168,290	136,942
At Jagüey and Palmeras Station	72,678	75,158	72,229	72,816
Total	251,988	216,166	240,519	209,758

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

	Three months ended September 30		Nine months ended September 30
(bbl/d)	2023	2022	2023	2022
FEC volumes	13,789	16,052	13,163	13,197
Third party volumes	39,797	44,285	50,238	47,777
Total	53,586	60,337	63,401	60,974

Puerto Bahia and Reficar Connection Update

Preconstruction activities are underway for Puerto Bahia’s 6.8-kilometre, 18-inch bi-directional hydrocarbon flowline. Once in service, the connection shall enable the continuous transport of crude oil and other hydrocarbons between Puerto Bahía’s port facility and the Cartagena Refinery.

Since the announcement in August 2023, the connection project has already achieved notable milestones in various key areas including technical, environmental and social matters, financing and procurement.

3. Guyana Exploration

As announced on November 9, 2023, Frontera and its Joint Venture (the “Joint Venture“) partner, CGX, discovered of a total of 114 feet (35 meters) of net pay at the Wei-1 well and a total net pay of 342 feet (104 meters) discovered to date on the Corentyne block, approximately 200 kilometers offshore from Georgetown, Guyana.

The Joint Venture believes that the rock quality discovered in the Maastrichtian horizon in the Wei-1 well is analogous to that reported in the Liza Discovery on Stabroek block. Results further demonstrate the potential for a standalone shallow oil resource development across the Corentyne block.

The Joint Venture also announced that Houlihan Lokey, a leading global investment bank and capital markets expert, is supporting its active pursuit of strategic options, for the Corentyne block, including a potential farm down, as it seeks to develop this potentially transformational oil investment in one of the most attractive oil and gas destinations in the world today, Guyana. There can be no guarantee that the review of strategic options will result in a transaction.

For further details, see the joint news release by Frontera and CGX dated November 9, 2023

Shareholder Initiatives

Frontera also announces that the Company intends to file with the TSX a notice of intention to commence a normal course issuer bid for its Common Shares (the “NCIB”). If accepted by the TSX, the Company would be permitted under the NCIB to purchase, during a 12-month period, up to 3,872,358 Common Shares, representing approximately 10% of the Company’s “public float” (as calculated in accordance with TSX rules). The NCIB will be made in accordance with the rules of the TSX through the facilities of the TSX or alternative trading systems, if eligible. Frontera believes that, from time to time, the market price of its Common Shares may not fully reflect the underlying value of its business and future prospects and financial position. In such circumstances, Frontera may purchase for cancellation outstanding Common Shares, thereby benefitting all shareholders by increasing the underlying value of the remaining Common Shares. The Company remains committed to returning capital to shareholders and continues to consider future shareholder value enhancement initiatives.

Under its normal course issuer bid that expired on March 16, 2023, Frontera was authorized to repurchase for cancellation 4,787,976 Common Shares and Frontera purchased for cancellation 4,270,100 Common Shares between March 17, 2022, and March 16, 2023, at a volume weighted average price of C$9.04 per share. Purchases were made on the open market.

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 NAR 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, allowing the Company to take a more dynamic approach to the management of its hedging portfolio. Consistent with this strategy, the Company entered new put hedges during the quarter totaling 1,508,000 bbls to protect a portion of the Company’s production through January 2024. The following table summarizes Frontera’s hedging position as of November 8, 2023.

Term	Type of Instrument	Open Positions (bbl/d)	Strike Prices Put/Call
Oct 23	Put	1,903	70
Oct 23	Put	11,387	80
Nov 23	Put	1,967	70
Nov 23	Put	12,167	80
Dec 23	Put	13,667	80
4Q-2023	Total Average	13,696
Jan 24	Put	8,000	80

The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of November 8, 2023, the Company had entered new positions of foreign currency derivatives contracts as follows:

Term	Type of Instrument	Open Interest (US$ MM)	Strike Prices Put/ Call	Hedging Ratio
4Q-2023	Zero-cost Collars	60	4,320 / 4,914.49	40 %
1Q-2024	Zero-cost Collars	60	4,125 / 4,763.25	40 %
2Q-2024	Zero-cost Collars	60	4,125 / 4,763.25	40 %

Third Quarter 2023 Conference Call Details

A conference call for investors and analysts will be held on Thursday, Nov 10, 2023, at 10:00 a.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Rene Burgos, Chief Financial Officer, and other members of the senior management team.

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

Rapid Connect URL:	https://emportal.ink/3ZXizbO
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:	52702838
Webcast Audio:	www.fronteraenergy.ca

A replay of the conference call will be available until 11:59 p.m. Eastern Time on November 17, 2023.

Encore Toll free Dial-in Number:	1-888-390-0541
International Dial-in Number:	1-416-764-8677
Encore ID:	702838

About Frontera:

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

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 aligning its Upstream, Midstream and Guyana core businesses to achieve its financial, operating and strategic goals; expectations regarding the results of our restructuring plan; statements relating to the Company’s guidance and objectives for 2023; statements regarding the Company’s ESG targets and the impact thereof; statements regarding the Company’s water handling capacity and anticipated growth in production, including expectations regarding expected impacts of the Company’s reverse osmosis water treatment facility (SAARA – previously Agrocascada); anticipated exploration, development and drilling activities and seismic acquisition; statements regarding the construction of the Company’s connection project; expectations regarding the completion of the Wei-1 well exploration drilling activities on the Corentyne block and the opportunities of the Corentyne block; expectations with respect to the NCIB and regulatory approval thereof and expectations with respect to the Company’s hedging 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 Israel-Palestine conflict, and the expected impact of measures that the Company has taken and continues to take in response to these events; expectations regarding the Company’s ability to manage its liquidity and capital structure and generate sufficient cash to support operations, capital expenditures and financial commitments; the performance of assets and equipment; the Company’s ability to achieve the increased oil and water handling capacity at Quifa in the time frames indicated; the availability and cost of labor, services and infrastructure; the execution of exploration and development projects; the receipt of any required regulatory approvals and outcome of discussions with governmental authorities; the success of the Company’s hedging strategy; and the impact and success of the Company’s ESG strategies.

Although the Company believes that the assumptions inherent in the forward-looking information are reasonable, forward-looking information is not a guarantee of future performance and accordingly undue reliance should not be placed on such information. Forward-looking information is subject to a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to the Company. The actual results may differ materially from those expressed or implied by the forward-looking information, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. The Company’s annual information form dated March 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.sedarplus.ca. All forward-looking information speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking information, whether as a result of new information, future events, or results or otherwise.

Non-IFRS Financial and Other Measures

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

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

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

Operating EBITDA

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

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

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

	Three Months Ended September 30
($M)	2023	2022

Net income (loss) ⁽¹⁾	32,582	(26,893)
Finance Income	(1,941)	(1,699)
Finance expenses	16,411	13,896
Income tax expense	33,012	102,362
Depletion, depreciation, and amortization	61,756	57,927
Expense of impairment, (recovery) of asset retirement obligation and others	5,822	969
Post-termination obligation	1,377	—
Shared-based compensation non-cash portion	305	59
Restructuring, severance, and other costs	1,407	453
Share of income from associates	(13,726)	(11,166)
Foreign exchange (income) loss	(4,305)	38,745
Other loss	1,207	(5,662)
Unrealized loss (gain) on risk management contracts	4,002	1,637
Non-controlling interests	(109)	2,579
Operating EBITDA	137,800	173,207

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

Capital Expenditures

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

	Three months ended September 30
($M)	2023	2022
Statements of Cash Flows
Additions to Oil and Gas properties, infrastructure port and plant and equipment	61,745	59,261
Additions to exploration and evaluation assets	12,169	16,511
Total additions to Statements of Cash Flows	73,914	75,772
Non-cash Adjustments ⁽¹⁾	216	246
Total Capital Expenditures	74,130	76,018

Capital Expenditures attributable to Midstream Colombia Segment	2,341
Capital Expenditures attributable to other segments different to Midstream	71,789	76,018
Total Capital Expenditures	74,130	76,018

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

Midstream Colombia Calculations

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

	Three months ended September 30
($M)⁽¹⁾	2023	2022
Revenue Midstream Colombia Segment	13,083	12,103
Revenue from ODL	87,689	69,214
Direct participating interest in the ODL	35 %	21 %
Equity adjustment participation of ODL⁽¹⁾	30,691	14,518
Adjusted Midstream Revenues	43,774	26,621

Operating Cost Midstream Colombia Segment	(6,419)	(5,400)
Operating Cost from ODL	(12,749)	(8,138)
Direct participating interest in the ODL	35 %	21 %
Equity adjustment participation of ODL⁽¹⁾	(4,462)	(1,707)
Adjusted Midstream Operating Cost	(10,881)	(7,107)

General and Administrative Midstream Colombia Segment	(1,400)	(1,246)
General and administrative from ODL	(4,615)	(3,244)
Direct participating interest in the ODL	35 %	21 %
Equity adjustment participation of ODL⁽¹⁾	(1,615)	(680)
Adjusted Midstream General and Administrative	(3,015)	(1,926)

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

Operating Netback and Oil and Gas Sales, Net of Purchases

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

	Q3 2023		Q3 2022
	$M	($/boe)	$M	($/boe)
Net sales realized price ⁽¹⁾	240,659	74.13	276,135	81.87
Production costs, net of realized FX hedge impact ^(1)(2)(3)	(52,015)	(13.86)	(42,263)	(11.20)
Transportation costs, net of realized FX hedge impact ^(1)(2)(4)	(39,422)	(11.73)	(34,746)	(10.70)
Operating Netback ^{(1) (2)}	149,222	48.54	199,126	59.97
		(boe/d)		(boe/d)
Sales volumes, net of purchases ⁽⁵⁾		35,289		36,660
Production ⁽⁶⁾		40,802		41,033
Net production ⁽⁷⁾		36,517		35,312

⁽¹⁾ Non-IFRS ratio. Refer to the “Non-IFRS and Other Financial Measures” section on page 21.

⁽²⁾ Non-IFRS financial measure. Refer to the “Non-IFRS and Other Financial Measures” section on page 21.

⁽³⁾ Includes $2.9 million, $6.2 million and $Nil of realized FX hedge gain attributable to production costs for the third quarter of 2023, second quarter of 2023, and the third quarter of 2022, respectively. See “Gain (Loss) on Risk Management Contracts” on page 13.

⁽⁴⁾ Includes $0.7 million, $1.8 million and $Nil of realized FX hedge gain attributable to transportation costs for the third quarter of 2023, second quarter of 2023, and the third quarter of 2022, respectively. See “Gain (Loss) on Risk Management Contracts” on page 13.

⁽⁵⁾ Sales volumes, net of purchases, exclude sales of third-party volumes.

⁽⁶⁾ Refer to the “Production” section on page 6.

⁽⁷⁾ Refer to the “Further Disclosures” section on page 36.

Oil and gas sales, net of purchases, is a non-IFRS financial measure that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining cost. Oil and gas sales, net of purchases per boe, is a non-IFRS ratio that is calculated using oil and gas sales, net of purchases divided by the total sales volumes, net of purchases.

A reconciliation of this calculation is provided below:

	Three months ended September 30
	2023	2022
Produced crude oil and gas sales ($M) ⁽¹⁾	260,828	309,898
Purchased crude oil and products sales ($M)	48,532	58,479
(-) Cost of purchases ($M) ⁽²⁾	(54,555)	(63,478)
Oil and gas sales, net of purchases ($M)	254,805	304,899
Sales volumes, net of purchases – (boe)	3,246,588	3,372,753
Oil and gas sales, net of purchases ($/boe)	78.48	90.40

⁽¹⁾ Excludes sales from port services as they are not part of the oil and gas segment. For further information, refer to the “Midstream Colombia” section in the Interim MD&A.

⁽²⁾ Cost of third-party volumes purchased for use and resale in the Company’s oil operations, including its transportation and refining costs.

Net Sales

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

	Three months ended September 30
($M)	2023	2022
Oil and gas sales, net of purchases ⁽¹⁾	254,805	304,899
Premiums paid on oil price risk management contracts ⁽²⁾	(1,930)	(4,393)
Royalties	(12,216)	(24,371)
Net sales ⁽¹⁾	240,659	276,135
Net sales realized price ($/boe) ⁽³⁾	74.13	81.87

⁽¹⁾ Non-IFRS financial measure. Refer to the “Non-IFRS and Other Financial Measures” section on page 21 of the Interim MD&A.

⁽²⁾ Includes put premiums paid for the position expired during the period.

⁽³⁾ Non-IFRS ratio. Refer to the “Non-IFRS and Other Financial Measures” section on page 21 of the Intermim MD&A.

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

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

	Three months ended September 30
	2023	2022
Oil and gas sales, net of purchases ($M) ⁽¹⁾	254,805	304,899
(-) Premiums paid on oil price risk management contracts ($M)	(1,930)	(4,393)
(-) Royalties ($M)⁽²⁾	(12,216)	(24,371)
Net sales ($M)	240.66	276.14
Sales volumes, net of purchases – (boe)	3,246,588	3,372,753
Oil and gas sales, net of purchases ($/boe)	78.48	90.4
Premiums paid on oil price risk management contracts ⁽²⁾	(0.59)	(1.30)
Royalties ($/boe) ⁽²⁾	(3.76)	(7.23)
Net sales realized price ($/boe)	74.13	81.87

⁽¹⁾ Non-IFRS financial measure

⁽²⁾Supplementary financial measure

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

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

	Three months ended September 30
	2023	2022
Production costs ($M)	54,942	42,263
(-) Realized gain on FX hedge attributable to production cost ($M)⁽¹⁾	(2,927)	0
Production costs, net of realized FX hedge impact ($M) ⁽²⁾	52,015	42,263
Production (boe)	3,753,784	3,775,067
Production costs ($/boe)	13.86	11.20

(1) See “Gain (Loss) on Risk Management Contracts” on page 13 of the MD&A

(2) Non-IFRS financial measure

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

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

	Three months ended September 30
	2023	2022
Transportation costs ($M)	40,166	34,746
(-) Realized gain on hedge attributable to transportation costs ($M)⁽¹⁾	(744)	0
Transportation costs, net of realized FX hedge impact ($M) ⁽²⁾	39,422	34,746
Net Production (boe)	3,359,564	3,248,796
Transportation costs ($/boe)	11.73	10.70

(1) See “Gain (Loss) on Risk Management Contracts” on page 13 of the MD&A

(2) Non-IFRS financial measure

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

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

Restricted cash short and long-term

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

Total cash

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

Total debt and lease liabilities

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

Oil and Gas Information Advisories

Certain disclosures in this news release constitute “anticipated results” for the purposes of NI 51-101 because the disclosure in question may, in the opinion of a reasonable person, indicate the potential value or quantities of resources in respect of Frontera’s or the Joint Venture’s resources or a portion of its resources. Without limitation, the anticipated results disclosed in this news release include “net pay” (and variations thereof) attributable to the resources of Frontera or the Joint Venture. Such estimates have been prepared by Frontera or the Joint Venture, as applicable and have not been prepared or reviewed by an independent qualified reserves evaluator or auditor. Such terms should not be interpreted to mean there is any level of certainty in regard to the hydrocarbons present, or that hydrocarbons may be produced profitably, in commercial quantities, or at all. Anticipated results are subject to certain risks and uncertainties, including those described herein and various geological, technical, operational, engineering, commercial, and technical risks. In addition, the geotechnical analysis and engineering to be conducted in respect of such resources is not complete. Such risks and uncertainties may cause the anticipated results disclosed herein to be inaccurate. Actual results may vary, perhaps materially.

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
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

Analogous Information:

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

SOURCE Frontera Energy Corporation

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