FRONTERA ANNOUNCES 2021 YEAR END RESERVES

2021 2P RESERVES OF 167 MILLION BOE
WITH NET PRESENT VALUE BEFORE TAX OF $3.0 BILLION

REPLACED 157% NET 1P AND 105% NET 2P RESERVES

ADDED 13.1 MMBOE NET 2P RESERVES

INCREASED NET 2P NATURAL GAS AND ASSOCIATED NATURAL GAS LIQUIDS
RESERVES BY 105% TO 19.1 MMBOE,
FURTHER DIVERSIFYING FRONTERA'S FUTURE PRODUCTION MIX

EXTENDED NET 1P RESERVES LIFE INDEX TO 8.7 YEARS AND 2P TO 13.3 YEARS

CALGARY, AB, Feb. 16, 2022 /CNW/ - Frontera Energy Corporation (TSX: FEC) ("Frontera" or the "Company") today announced the results of its annual independent reserves assessment conducted by DeGolyer and MacNaughton ("D&M"). All dollar amounts in this news release and the Company's financial disclosures are in United States dollars, unless otherwise noted. All of the Company's booked reserves for the year ended December 31, 2021 are located in Colombia and Ecuador.

Orlando Cabrales, Chief Executive Officer, commented:

"Frontera delivered solid reserves results in 2021. The Company replaced 157% of net 1P reserves and 105% of net 2P reserves, and extended our net 1P reserves life index to 8.7 years and our net 2P reserves life index to 13.3 years. We also increased net 2P natural gas and associated natural gas liquids reserves by 105% to 19.1 MMboe, further diversifying Frontera's future production mix. The net present value (10% discount) on December 31, 2021 of the Company's 2P reserves increased by 61% to $3.036 billion before tax and $2.248 billion after tax due in part to higher Brent prices year over year and greater operational and development cost stability."

2021 Reserves Report Highlights:

For the year ended December 31, 2021, Frontera:

• Added 13.1 MMboe of 2P net reserves, slightly increasing the Company's 2P net reserves to 167.0 MMboe, compared to 166.4 MMboe at December 31, 2020. The Company's 167 MMboe of net 2P reserves consist of 62% heavy crude oil, 27% light and medium crude oil and 7% conventional natural gas and 4% natural gas liquids.
  
  
• Achieved a 1P net Reserves Replacement Ratio of 157% and a net 2P Reserve Replacement Ratio of 105%.
  
  
• Extended 1P reserves life index to 8.7 years compared to 6.4 years at December 31, 2020.
  
  
• Extended 2P reserves life index to 13.3 years compared to 10.3 years at December 31, 2020.
  
  
• Added 7.8 MMboe of 3P net reserves, for a total of 217.1 MMboe at December 31, 2021, slightly lower compared to 221.8 MMboe at December 31, 2020.
  
  
• Achieved a three-year average finding and development ("F&D") cost of $8.50/boe on a 2P basis ($3.38/boe in 2020) with upstream reserves-based capital expenditures of $187 million ($101 million in 2020), not including changes in future development costs ("FDC"). 1P F&D cost three-year average was $9.80/boe in 2021 compared to $7.38/boe in 2020.
  
  
• Increased 2P reserves on a gross working interest basis before royalties by 2% to 178.2 MMboe compared to 174.0 MMboe at December 31, 2020. Delivered 3P reserves on a gross working interest basis before royalties of 229.8 MMboe compared to 230.4 MMboe at December 31, 2020.
  
  
• The Net Present Value ("NPV") for the net 2P reserves, discounted at 10% before tax, is $3.036 billion at December 31, 2021, compared to $1.888 billion at December 31, 2020. The increase in NPV for the 2P reserves is primarily due to higher commodity prices at December 31, 2020 and improved development and operational cost stability. See the Net Present Value After Tax summary table below for more information.

About The Reserves Evaluation

For the year ended December 31, 2021, the Company's reserves were evaluated by D&M, in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) ("COGEH") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and are based on the Company's 2021 year-end estimated reserves as evaluated by D&M in their report dated February 9, 2022, with an effective date of December 31, 2021 (the "Reserves Report").  D&M is an independent qualified reserves evaluator as defined in NI 51-101.

Additional reserves information as required under NI 51-101 will be included in the Company's statement of reserves data and other oil and gas information on Form 51-101F1, which is expected to be filed on SEDAR on March 2, 2022. See "Advisory Note Regarding Oil and Gas Information" section in the "Advisories", at the end of this news release.

Reserves data related to the El Dificil, Rio Meta and Entrerrios assets acquired by Frontera upon its acquisition of 100% of the common shares of Petroleos Sud Americanos S.A. ("PetroSud") on December 30, 2021, have been included in the Reserves Report. The Reserves Report also includes results from the Company's Jandaya-1 exploration well in the Perico block, in Ecuador (Frontera 50% W.I., operator). Numbers in tables may not add due to rounding differences.

2021 Year-End D&M Certified Gross Reserves Volumes⁽¹⁾

Reserves Category	December 31, 2021 MBoe ^(2)	December 31, 2020 MBoe ^(2)	Percentage Change 2021 versus 2020
Proved Developed Producing (PDP)	31,778	27,301	16%
Proved Developed Not Producing (PDNP)	10,461	10,015	4%
Proved Undeveloped (PUD)	76,045	70,685	8%
Total Proved (1P)	118,284	108,001	10%
Probable	59,957	66,017	(9)%
Total Proved Plus Probable (2P)	178,241	174,018	2%
Possible ^(3)	51,559	56,378	(9)%
Total Proved Plus Probable Plus Possible (3P)	229,799	230,396	0%

⁽¹⁾ Gross reserves represent Frontera's W.I. before royalties.

⁽²⁾ See "Boe Conversion" section in the "Advisories", at the end of this press release.

⁽³⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

2021 Year-End D&M Certified Net Reserves Volumes⁽¹⁾

Reserves Category	December 31, 2021 Mboe ^(2)	December 31, 2020 Mboe ^(2)	Percentage Change 2021 versus 2020
Proved Developed Producing (PDP)	29,640	25,955	14%
Proved Developed Not Producing (PDNP)	9,483	9,395	1%
Proved Undeveloped (PUD)	70,224	66,845	5%
Total Proved (1P)	109,346	102,195	7%
Probable	57,670	64,203	(10)%
Total Proved Plus Probable (2P)	167,016	166,399	0%
Possible ^(3)	50,055	55,420	(10)%
Total Proved Plus Probable Plus Possible (3P)	217,071	221,818	(2)%

⁽¹⁾ Net reserves represent Frontera's W.I. after royalties.

⁽²⁾ See "Boe Conversion" section in the "Advisories", at the end of this press release.

⁽³⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

The following tables provide a summary of the Company's oil and natural gas reserves based on forecast prices and costs effective December 31, 2021, as applied in the Reserves Report. The Company's net reserves after royalties at December 31, 2021, incorporate all applicable royalties under Colombia and Ecuador fiscal legislations based on forecast pricing and production rates evaluated in the Reserves Report, including any additional participation interest related to the price of oil applicable to certain Colombian and Ecuadorian blocks, as at year-end 2021.

2021 Year-End D&M Certified Reserves Volumes by Product Type and Country⁽⁶⁾

Reserves at December 31, 2021 (MMboe) ^(1)(5)
Country	Field	Proved (1P)		Probable		Proved plus Probable (2P)		Hydrocarbon Type
		Gross	Net	Gross	Net	Gross	Net
Colombia	Quifa SW field	48.3	42.2	6.0	5.2	54.3	47.3	Heavy crude oil
	Other heavy oil blocks^(2)	35.1	33.8	22.1	21.7	57.1	55.4	Heavy crude oil
	Light/medium oil blocks^(3)	25.8	24.5	20.1	19.3	46.0	43.8	Light and medium crude oil
	Natural gas blocks^(4)	6.5	6.5	5.8	5.8	12.4	12.4	Conventional natural gas
	Natural gas blocks^(4)	1.6	1.6	5.1	5.1	6.7	6.7	Natural gas liquids
	Sub-Total	117.4	108.6	59.1	57.0	176.5	165.6	Oil and natural gas
Ecuador	Perico block	0.9	0.8	0.8	0.7	1.8	1.4	Light and medium crude oil
	Total Dec. 31, 2021	118.3	109.3	60.0	57.7	178.2	167.0	Oil and natural gas
	Total Dec. 31, 2020	108.0	102.2	66.0	64.2	174.0	166.4
	Difference	10.3	7.2	(6.1)	(6.5)	4.2	0.6
	2021 Production	13.7	12.5	Total Reserves Incorporated		17.9	13.1

⁽¹⁾ See "Boe Conversion" section in the "Advisories", at the end of this press release.

⁽²⁾ Includes Cajua and Jaspe fields in Quifa Block and Sabanero and CPE-6 blocks.

⁽³⁾ Includes Cubiro, Cravoviejo, Canaguaro, Guatiquia, Casimena, Corcel, Neiva, Cachicamo and other producing blocks.

⁽⁴⁾ Includes VIM-1, El Difícil and La Creciente Blocks.

⁽⁵⁾ Gross refers to Frontera's W.I. before royalties. Net refers to Frontera's W.I. after royalties.

⁽⁶⁾ All of the Company's booked reserves are located in Colombia and Ecuador.

2021 2P Reserves Reconciliation

	Oil Equivalent Gross 2P Reserves (MMboe)^(1)(2)	Oil Equivalent Net 2P Reserves (MMboe)^(1)(2)
December 31, 2020	174.0	166.4
Net Additions ^(3)	5.6	5.0
Economic and Technical Revisions	6.1	2.1
Acquisitions/Dispositions	6.1	6.1
Production ^(4)	13.7	12.5
December 31, 2021	178.2	167.0

⁽¹⁾ See "Boe Conversion" section in the "Advisories", at the end of this press release.

⁽²⁾ Gross refers to Frontera's W.I. before royalties. Net refers to Frontera's W.I. after royalties.

⁽³⁾ Includes discovery of Jandaya field (Perico Block in Ecuador), extensions and improved recoveries (including improved recoveries of Coralillo and Copa fields (Guatiquia and Cubiro blocks in Colombia).

⁽⁴⁾ Production represents the production for the twelve-month period ended December 31, 2021 for assets with associated reserves. Production associated with exploration and evaluation assets are included in production volumes for financial reporting purposes.

Five Year Crude Oil Price Forecast - D&M Reserves Reports ⁽¹⁾

(US$/bbl)	2022	2023	2024	2025	2026
Brent Oil Price Forecast 2020	52.85	56.04	57.87	59.00	60.15
Brent Oil Price Forecast 2021	75.33	71.46	69.62	71.01	72.44

⁽¹⁾ The Reserves Report and the December 31, 2020 reserves report used the average Brent projected price of three major international independent auditors: GLJ Petroleum Consultants, McDaniel and Associates Consultants and Sproule Consultants. The 2020 price forecast reflects prices used in the Company's December 31, 2020 reserves report and the 2021 price forecast reflects prices used in the Reserves Report.

Reserve Life Index ("RLI")⁽¹⁾

(US$/bbl)	December 31, 2020^(2)	December 31, 2021^(3)
Total Proved (1P)	6.4 years	8.7 years
Total Proved Plus Probable (2P)	10.3 years	13.3 years
Total Proved Plus Probable Plus Possible (3P)	13.8 years	17.3 years

⁽¹⁾ RLI does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

⁽²⁾ Calculated by dividing the total relevant net reserves category by the 2020 production of 16.1 MMboe.

⁽³⁾ Calculated by dividing the total relevant net reserves category by the 2021 production of 12.5 MMboe.

Net Present Value Before Tax Summary - D&M Reserves Report (2021 Brent Forecast)⁽¹⁾

Reserves Category	December 31, 2020	December 31, 2021	December 31, 2021
$ (000's), except per share data	NPV10 ($ 000's)^(2)	NPV10 ($ 000's)^(3)	NPV10 (C$/share)^(4)
Proved Developed Producing (PDP)	367,237	773,686	10.11
Proved Developed Not Producing (PDNP)	153,073	235,503	3.08
Proved Undeveloped	549,355	1,100,986	14.34
Total Proved (1P)	1,114,666	2,110,176	27.56
Probable	773,015	926,177	12.10
Total Proved Plus Probable (2P)	1,887,681	3,036,353	39.66
Possible ^(5)	669,312	894,668	11.69
Total Proved Plus Probable Plus Possible (3P)	2,556,993	3,931,021	51.34

⁽¹⁾ See "Advisories" at the end of this press release. The Reserves Report used the average Brent projected price of three major international independent auditors: GLJ Petroleum Consultants, McDaniel and Associates Consultants and Sproule Consultants. The January 1, 2021 price forecast is included in the December 31, 2020 reserves report.

⁽²⁾ Includes FDC as at December 31, 2020, of $808 million for 1P and $1,309 million for 2P.

⁽³⁾ Includes FDC as at December 31, 2021, of $792 million for 1P and $1,269 million for 2P.

⁽⁴⁾ Calculated by dividing the December 31, 2021 NPV10 value by 94,695,694 shares outstanding as at December 31, 2021 and a USD:CAD foreign exchange rate of 1.26:1. Per share valuations do not consider any value attributed to the Company's material ownership in midstream and infrastructure assets as well as any equity value for its ownership in CGX Energy Inc. (TSXV:OYL).

⁽⁵⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Net Present Value After Tax Summary - D&M Reserves Report (2021 Brent Forecast)⁽¹⁾⁽²⁾

Reserves Category	December 31, 2020	December 31, 2021	December 31, 2021
$ (000's), except per share data	NPV10 ($ 000's)^(3)	NPV10 ($ 000's)^(4)	NPV10 (C$/share)^(5)
Proved Developed Producing (PDP)	344,170	608,715	7.95
Proved Developed Not Producing (PDNP)	143,415	187,470	2.45
Proved Undeveloped	556,317	862,350	11.26
Total Proved (1P)	1,043,903	1,658,535	21.66
Probable	522,958	589,523	7.70
Total Proved Plus Probable (2P)	1,566,860	2,248,058	29.36
Possible ^(6)	451,961	570,597	7.45
Total Proved Plus Probable Plus Possible (3P)	2,018,822	2,818,655	36.82

⁽¹⁾ See "Advisories" at the end of this press release. The Reserves Report used the average Brent projected price of three major international independent auditors: GLJ Petroleum Consultants, McDaniel and Associates Consultants and Sproule Consultants. The full January 1, 2022 price forecast will be included in the Reserves Report.

⁽²⁾ The tax calculations used in the preparation of the Reserves Report are done at the field level in accordance with standard practice, and do not reflect the actual tax position at the corporate level which may be significantly different.

⁽³⁾ Includes FDC as at December 31, 2020 of $808 million for 1P and $1,309 million for 2P.

⁽⁴⁾ Includes FDC as at December 31, 2021, of $792 million for 1P and $1,269 million for 2P.

⁽⁵⁾ Calculated by dividing the December 31, 2021 NPV10 value by 94,695,694 shares outstanding as at December 31, 2021 and a USD:CAD foreign exchange rate of 1.26:1. Per share valuations do not consider any value attributed to the Company's material ownership in midstream and infrastructure assets as well as any equity value for its ownership in CGX Energy Inc. (TSXV:OYL).

⁽⁶⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Calculation of Three-Year Reserve Metrics - Net

	Proved (1P)	Proved Plus Probable (2P)
Capital Expenditures ($ 000's)^(1)	577,113	577,113
Reserve Additions (000's boe)^(2)	58,915	68,149
F&D Costs ($/boe)^(3)	9.8	8.5

⁽¹⁾ Calculated using actual capital expenditures for the period from January 1, 2019 to December 31, 2021.

⁽²⁾ Net reserves additions of the Company in 2019 and 2021 and additions in Colombia in 2020.

⁽³⁾ The aggregate of the exploration and development costs incurred, generally will not reflect total F&D costs related to reserves additions for the period. F&D costs are calculated as capital expenditures divided by reserve additions for F&D Costs ($/boe). The measure "F&D costs" does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

Future Development Costs (FDC) - Based on Forecast Prices and Costs

Colombia ($ 000's)	Total Proved (1P)	Total Proved Plus Probable (2P)
2022	114,792	155,971
2023	116,702	191,306
2024	145,831	227,512
2025	98,499	144,668
2026	133,924	154,527
Beyond 2026	182,271	394,791
Total undiscounted	792,020	1,268,774

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 34 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 Information

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 statement of reserves data and other oil and gas information on Form 51-101F1, which is expected to be filed on SEDAR on March 2, 2022, information relating to reserves and resources, including reserves and resources estimates, reserve life index, reserve replacement ratio, price forecasts and future development costs. All information other than historical fact is forward-looking information.

Forward-looking information reflects the current expectations, assumptions and beliefs of the Company based on information currently available to it and considers the Company's experience and its perception of historical trends, including expectations and assumptions relating to commodity prices and interest and foreign exchange rates; the current and potential adverse impacts of the COVID-19 pandemic, including the status of the pandemic and future waves and any associated policies around current business restrictions; reserves and resources estimates; the performance of assets and equipment; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour, services and infrastructure; and the development and execution of projects. 

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 of the Company 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. 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; 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. The Company's annual information form dated March 3, 2021, its annual management's discussion and analysis for the year ended December 31, 2020, and other documents it files from time to time with securities regulatory authorities describe the risks, uncertainties, material assumptions and other factors that could influence actual results and such factors are incorporated herein by reference. Copies of these documents are available without charge by referring to the company's profile on SEDAR at www.sedar.com. All forward-looking information speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking information, whether as a result of new information, future events or results or otherwise.

Non-Standardized Measures

This news release includes non-standardized measures. Readers are cautioned that these measures, such as reserve life index, reserves replacement ratio, NPV per share and F&D costs, should not be construed as alternative measures of financial performance. Such measures have been included to provide readers with additional means to evaluate the Company's performance but these non-standardized measures are not reliable indicators of the Company's future performance and therefore must not be relied upon unduly. The Company's method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Readers are cautioned that the information provided or derived by these measures should not be relied upon for investment purposes.

Advisory Note Regarding Oil and Gas Information

The reserves information contained in this press release has been prepared in accordance with NI 51-101 but only presents a portion of the disclosure required thereunder. Complete reserves disclosure required in accordance with NI 51-101 will be available on SEDAR at www.sedar.com on or around March 2, 2022.  Actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this news release. There is no assurance that forecast prices and costs assumed in the Reserves Report, and presented in this news release, will be attained and variances from such forecast prices and costs could be material. The estimated future net revenue from the production of the disclosed oil and natural gas reserves in this news release does not represent the fair market value of these reserves.

The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.

The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The tax calculations used in the preparation of the Reserves Report are done at the field level in accordance with standard practice, and do not reflect the actual tax position at the corporate level which may be significantly different.

Boe Conversion

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. In addition, as the value ratio between oil and natural gas based on current market values is significantly different from the energy equivalency of 5.7:1, utilizing a conversion of 5.7:1 may be misleading as an indication of value.

Definitions:

1P	Proved reserves
2P	Proved plus probable reserves
3P	Proved plus probable plus Possible reserves
bbl(s)	Barrel(s) of oil
boe	Refer to "Boe Conversion" disclosure above
boe/d	Barrel of oil equivalent per day
Gross Production	Refers to means working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company
Mboe	Thousand barrels of oil equivalent
MMboe	Million barrels of oil equivalent
Mcf	Thousand cubic feet
Net Production	Refers to working interest (operating or non-operating) share after deduction of royalty obligations, plus the Company's royalty interests in production or reserves
W.I.	Working interest

• "Proved Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been in production, and the date of resumption of production must be known with reasonable certainty.
• "Proved Developed Non-Producing Reserves" are those reserves that either have not been on production or have previously been on production but are shut-in and the date of resumption of production is unknown.
• "Proved Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
• "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
• "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
• "Possible" reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
• "Reserves Life Index" (RLI) is calculated as the net reserves in the referenced category divided by the net production of the last year. It is a measure of how long the booked reserves will last if the production rate is maintained and no additional reserves are added.
• "Reserves Replacement Ratio" is calculated as the net reserves added in the referenced category divided by the net production of the last year. It is a measure of the capacity to replace the production.
• "F&D costs" are calculated as capital expenditures divided by reserve additions for F&D Costs ($/boe). This measure does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

SOURCE Frontera Energy Corporation

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