PetroTal Announces Significant Increases in 2021 Year-End Oil Reserves

68% increase in 1P Reserves to 37 million barrels

53% increase in 2P Reserves to 78 million barrels

39% increase in 3P Reserves to 147 million barrels

Calgary, Alberta and Houston, Texas--(Newsfile Corp. - February 15, 2022) - PetroTal Corp. (TSXV: TAL) (AIM: PTAL) (OTCQX: PTALF) ("PetroTal" or the "Company") is pleased to announce the results of its 2021 year-end reserve evaluation by Netherland, Sewell & Associates, Inc. ("NSAI") for the Bretana oil field, operated 100% by PetroTal (the "NSAI Report"). All currency amounts are in United States dollars (unless otherwise stated) and comparisons refer to December 31, 2020.


  • Significant increases in all reserve categories:
    • Proved ("1P") reserves increasing by 68% to 37.4 million barrels. Net Present Value (before tax, discounted at 10% ("NPV-10")) is $724 million ($19.38/bbl) for 1P reserves;
    • Proved plus Probable ("2P") reserves increasing by 53% to 78 million barrels. Net Present Value (before tax, discounted at 10% ("NPV-10") is $1.39 billion ($17.82/bbl) for 2P reserves; and,
    • Proved plus Probable plus Possible ("3P") reserves increasing by 39% to 147 million barrels.
  • NPV-10 values have increased 129% for 1P and 67% for 2P, over year-end 2020, due to reserves growth and an increase in the Brent price forecast used by NSAI at year-end 2021;
  • Material progression of after tax NPV-10 per share to US$0.69/share, US$1.23/share, and US$2.00/share for 1P, 2P, and 3P categories;
  • 2021 Proved Developed Producing ("PDP") reserves increased 35% to 16.15 million barrels, representing 43% of 1P reserves, reflecting an attractive ratio of base production to low risk drilling targets;
  • Three key reserves parameters had material positive upgrades in the NSAI Report, compared to the prior year:
    • Original Oil in Place ("OOIP"): Increases of 5%, 7%, and 7% to 247, 389, and 618 million barrels, respectively, for the 1P, 2P and 3P cases;
    • Due to continued drilling success and additional subsurface data, 1P, 2P and 3P total booked well counts for 2021 are 17, 22, and 29, respectively, up materially from the 2020 well counts of 11, 15, and 20; and,
    • With additional subsurface similarities to Bretana's analogous fields now recognized, all three recovery factor percentages materially increased in 2021 to 18% (from 11%), 22% (from 15%), and 25% (from 19%) for 1P, 2P, and 3P reserve categories, respectively.
  • 2P Future Development Capital ("FDC") increased $96 million or 49% to $289 million from 2020 reflecting an additional 7 wells booked at year-end 2021 and the required associated water disposal capacity needed to accommodate higher anticipated flush and run rate production volumes;
  • 2021 Finding and Development ("F&D") cost per barrel of $6.63, $4.68 and $3.85 for 1P, 2P, and 3P reserve categories, respectively. The 1P and 2P per barrel costs were reduced 42%, and 6% from year-end 2020;
  • Attractive year-end 2021 reserves-based metrics:
    • Doubling 2021 Reserve Life Index ("RLI") for 1P and 2P reserves, to 13.8 and 28.9 years, respectively, compared to 6.4 and 14.6 years in 2020; and,
    • Robust 2021 production reserve replacement ratios of 457% and 816% for 1P and 2P reserves.
  • On a 2P per barrel basis, the NSAI Report reflected a 3.5% decrease in operating costs per barrel, which, given the inflationary pressures from higher Brent oil prices and the COVID-19 pandemic, is an important success story for PetroTal; and,
  • On a 3P basis, the 2021 NSAI production forecast shows a 16-year plateau above 10,000 barrels of oil per day ("bopd) instead of the prior 12-year plateau in NSAI's 2020 reserves report.

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented

"The Bretana field is proving itself to be a prolific investment given the significant achievements in 2021 and the 2021 year-end reserves report results. Based on the increased recovery factors and additional booked drilling locations, we have significantly extended the running room and future development potential of our asset. This should allow Bretana to generate free cash flow for a much longer period of time."

2021 Year-end Reserves Summary

The summary below sets forth PetroTal's reserves as at December 31, 2021, as presented in the reserves report prepared by NSAI, an independent qualified reserves evaluator. The figures in the following tables have been prepared in accordance with the standards contained in the most recent publication of the Canadian Oil and Gas Evaluation Handbook (the "COGEH") and the reserve definitions contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). In addition to the summary information disclosed in this announcement, more detailed information will be included in PetroTal's annual information form for the year ended December 31, 2021 (the "AIF") to be filed on SEDAR ( and posted on PetroTal's website ( in April 2022.

Six Year Crude Oil Price Forecast - NSAI Report

Year-End Forecast:2022202320242025202620276 Yr Avg
Brent (USD$/bbl) - January 1, 2021 $52.85$56.04$57.87$59.00$60.15$61.33$57.87
Brent (USD$/bbl) - January 1, 2022 $75.33$71.46$69.62$71.01$72.44$73.88$72.31


The oil price projections used by NSAI are based upon an average of December 31, 2021 and 2020 forecasts of Brent Crude futures prices prepared by three qualified reserves evaluators: GLJ Petroleum Consultants Ltd., McDaniel & Associates Consultants Ltd. and Sproule Associates Limited. The six year average for the NSAI Report reflects an average Brent price of $72.31, which as at the time of this press release, is approximately $24/bbl lower than current market Brent prices.

Year-End Crude Oil Reserves (million barrels)


Developed Producing16.212.0+35%
Total Proved37.422.3+68%
Total Proved plus Probable77.951.0+53%
Total Proved plus Probable & Possible147.1106.1+39%


Represents gross and net barrels since PetroTal has a 100% working interest and a 100% net revenue interest in these properties. Royalties are paid from sales proceeds.

Year-End Net Present Value at 10% - Before Tax ($ millions)


Developed Producing$250$135+85%
Total Proved $724$317+129%
Total Proved plus Probable $1,389$830+67%
Total Proved plus Probable & Possible $2,321$1,721+35%


Year-End Net Present Value at 10% - After Tax ($ millions)


Developed Producing$244$134+82%
Total Proved $570$271+110%
Total Proved plus Probable $1,020$621+64%
Total Proved plus Probable & Possible $1,653$1,228+35%


Forecast Revenues and Costs(1-5) ($ millions)

CATEGORYRevenueRoyaltiesOPEXFDCB-Tax Net
B-Tax Net
A-Tax Net
Total Proved $2,299$160$921$141$1,076$724$570
Total Proved plus Probable $4,865$367$1,488$289$2,722$1,389$1,020
Total Proved plus Probable & Possible $9,735$813$2,756$504$5,662$2,321$1,653


1) Royalties include the 2.5% social fund for all years.
2) FDC includes abandonment.
3) Net Revenue is defined as revenue less royalties less operating costs less FDC.
4) B-tax and A-tax refer to before and after tax.
5) Discounted values are discounted at 10%.

Year-End Reserves Value per Share - After tax

CATEGORYDec. 31, 2021Dec. 31, 2020
Reserves per share US$/shCAD$/shGBP/shUS$/shCAD$/shGBP/sh
Proved plus Probable$1.23$1.570.91$0.76$0.980.56
Proved plus Probable & Possible$2.00$2.541.48$1.50$1.931.10


Represents NPV-10 (after tax) divided by the number of common shares issued as of December 31 of each respective year and excludes other balance sheet items at the relevant date. Canadian and GBP share prices are converted at the respective year end foreign exchange conversion rates. Common share count as at December 31, 2021 totaling 828.2 million shares and as at December 31, 2020 totaling 816.2 million shares.

Reserve Life Index(1-3) ("RLI")

CATEGORYDec. 31, 2021Dec. 31, 2020
Proved13.8 years6.4 years
Proved plus Probable28.9 years14.6 years
Proved plus Probable & Possible 54.5 years30.3 years


(1) 2021 values based on 2021 year-end reserves divided by annualized Q1 2021 production of approximately 7,331 bopd.
(2) The license for Block 95 expires in 2041.
(3) 2020 values based on 2020 year-end reserves divided by annualized Q1 2020 production of approximately 9,686 bopd.

Future Development Costs

The following information sets forth development and abandonment costs deducted in the estimation of PetroTal's future net revenue attributable to the reserve categories noted below:

CATEGORY ($ million)20212020Change

Developed Producing$16 $15 +6%
Total Proved $141 $119 +19%
Total Proved plus Probable $289 $193 +49%
Total Proved plus Probable & Possible $504$297+70%


Future development costs ($/bbl)20212020Change
Proved plus Probable$4.68$4.96-6%
Proved plus Probable & Possible$3.85$3.16+22%


The future development and abandonment costs are estimates of the future capital expenditures required to convert the corresponding reserves to proved developed producing ("PDP") reserves. Future development per barrel is determined using the future development capital divided by the 1P, 2P, or 3P reserves, less cumulative PDP.

2021 Year-End Gross Reserves Reconciliation (million barrels)

ProvedProved plus ProbableProved plus Probable & Possible
December 31, 202022.351.0106.1
Technical Revisions18.230.244.2
Economic Factors0.20.00.0
December 31, 202137.477.9147.0


Qualified Person's Statement

Dewi Jones, the Company's Vice President, Exploration and Development, who has over 35 years of relevant experience in the oil industry, has approved the technical information contained in this announcement. Mr. Jones received a Bachelor of Science degree in Geology from Louisiana State University in Baton Rouge and is registered on the Texas and Louisiana Board of Professional Geoscientists.

The recovery and reserve estimates provided in this news release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. In certain of the tables set forth below, the columns may not add due to rounding.


PetroTal is a publicly traded, tri‐quoted (TSXV: TAL) (AIM: PTAL) and (OTCQX: PTALF) oil and gas development and production Company domiciled in Calgary, Alberta, focused on the development of oil assets in Peru. PetroTal's flagship asset is its 100% working interest in Bretana oil field in Peru's Block 95 where oil production was initiated in June 2018. In early 2020, PetroTal became the second largest crude oil producer in Peru and more recently the top crude oil producer. The Company's management team has significant experience in developing and exploring for oil in Peru and is led by a Board of Directors that is focused on safely and cost effectively developing the Bretana oil field. It is actively building new initiatives to champion community sensitive energy production, benefiting all stakeholders.

For further information, please see the Company's website at, the Company's filed documents at, or below:

Douglas Urch
Executive Vice President and Chief Financial Officer
T: (713) 609-9101

Manolo Zuniga
President and Chief Executive Officer
T: (713) 609-9101

PetroTal Investor Relations

Celicourt Communications
Mark Antelme / Jimmy Lea
T : 44 (0) 208 434 2643

Strand Hanson Limited (Nominated & Financial Adviser)
Ritchie Balmer / James Spinney / Robert Collins
T: 44 (0) 207 409 3494

Stifel Nicolaus Europe Limited (Joint Broker)
Callum Stewart / Simon Mensley / Ashton Clanfield
Tel: +44 (0) 20 7710 7600

Auctus Advisors LLP (Joint Broker)
Jonathan Wright
T: +44 (0) 7711 627449


FORWARD-LOOKING STATEMENTS: This press release contains certain statements that may be deemed to be forward-looking statements. Such statements relate to possible future events, including, but not limited to: PetroTal's business strategy, objectives, strength and focus; drilling, completions, workovers and other activities and the anticipated costs and results of such activities; the ability of the Company to achieve drilling success consistent with management's expectations; the ability of the Company to achieve near term production targets and operate at unrestricted levels; anticipated future production, revenue and free cash flow; drilling plans including the timing of drilling, commissioning, and startup and the impact of delays thereon; oil production levels, including production 2022; future development and growth prospects; and the timing of filing the AIF. All statements other than statements of historical fact may be forward-looking statements. In addition, statements relating to expected production, reserves, recovery, costs and valuation are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Forward-looking statements are often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "estimate", "potential", "will", "should", "continue", "may", "objective" and similar expressions. The forward-looking statements are based on certain key expectations and assumptions made by the Company, including, but not limited to, expectations and assumptions concerning the ability of existing infrastructure to deliver production and the anticipated capital expenditures associated therewith, the ability of the Ministry of Energy to effectively achieve its objectives in respect of reducing social conflict and collaborating towards continued investment in the energy sector, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices and the actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labour, royalty regimes and exchange rates, impact of inflation on costs, the application of regulatory and licensing requirements, the accuracy of PetroTal's geological interpretation of its drilling and land opportunities, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance of new wells, the Company's growth strategy, general economic conditions and availability of required equipment and services. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses; and health, safety and environmental risks), commodity price volatility, price differentials and the actual prices received for products, exchange rate fluctuations, increased operating and capital costs due to inflationary pressures, legal, political and economic instability in Peru, access to transportation routes and markets for the Company's production, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. In addition, the Company cautions that current global uncertainty with respect to the spread of the COVID-19 virus and its effect on the broader global economy may have a significant negative effect on the Company. While the precise impact of the COVID-19 virus on the Company remains unknown, rapid spread of the COVID-19 virus may continue to have a material adverse effect on global economic activity, and may continue to result in volatility and disruption to global supply chains, operations, mobility of people and the financial markets, which could affect interest rates, credit ratings, credit risk, inflation, business, financial conditions, results of operations and other factors relevant to the Company. Please refer to the risk factors identified in the Company's annual information form for the year ended December 31, 2020 and management's discussion and analysis for the three and nine months ended September 30, 2021 which are available on SEDAR at The forward-looking statements contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

OIL REFERENCES: All references to "oil" or "crude oil" production, revenue or sales in this press release mean "heavy crude oil" as defined in NI 51-101. All references to Brent indicate Intercontinental Exchange ("ICE") Brent.

RESERVES DISCLOSURE: PetroTal's Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 dated effective as at December 31, 2021, which will include further disclosure of PetroTal's oil and gas reserves and other oil and gas information in accordance with NI 51-101 and COGEH forming the basis of this press release, will be included in the AIF, which will be available on SEDAR at in April 2022. All reserves values, future net revenue and ancillary information contained in this press release are derived from the NSAI Report unless otherwise noted. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by NSAI in evaluating PetroTal's reserves will be attained and variances could be material. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. The recovery and reserve estimates of PetroTal's oil reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil reserves may be greater than or less than the estimates provided herein. 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 herein are estimates only. 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. 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 on production, and the date of resumption of production must be known with reasonable certainty. Possible 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. Certain terms used in this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 - Revised Glossary to NI 51-101, Revised Glossary to NI 51-101, Standards of Disclosure for Oil and Gas Activities ("CSA Staff Notice 51-324") and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.

DRILLING LOCATIONS: This press release discloses drilling inventory in three categories: (a) proved locations; (b) probable locations; and (c) possible locations, all of which are derived from the NSAI Report and account for drilling locations that have associated proved, probable and/or possible reserves, as applicable. There is no certainty that PetroTal will drill all booked drilling locations and if drilled there is no certainty that such locations will result in additional oil reserves or production. The drilling locations considered for future development will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the possible drilling locations have been de-risked by drilling existing wells in relative close proximity to such drilling locations, other possible drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil reserves or production.

OIL AND GAS MEASURES: This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "netback", "OOIP", "development capital", "F&D costs", "net asset value", "recycle ratio" and "reserves life index". These terms do 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. "Netback" equals total petroleum sales less quality discount, lifting costs, transportation costs and royalty payments calculated on a bbl basis. "OOIP" is equivalent to total petroleum initially-in-place ("TPIIP"). TPIIP, as defined in the COGEH, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered. "Development capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital excludes capitalized administration costs. "Finding and development costs" or "F&D costs" are calculated as the sum of field capital plus the change in future development costs for the period divided by the change in reserves that are characterized as development for the period. Finding and development costs take into account reserves revisions during the year on a per bbl basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. "Net asset value" is based on present value of future net revenues discounted at 10% before tax on reserves, net of estimated net debt at year end divided by the basic shares outstanding at year end. "Recycle ratio" is measured by dividing the netback for the applicable period by finding and development cost per bbl for the year. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. "Reserve life index" is calculated as total Company interest reserves divided by annual production. These terms have been calculated by management and do 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. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare PetroTal's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.

FOFI DISCLOSURE: This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about PetroTal's prospective results of operations, production, NPV-10, future net revenue, future development and abandonment costs, and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this press release was approved by management as of the date of this press release and was included for the purpose of providing further information about PetroTal's anticipated future business operations. PetroTal disclaims any intention or obligation to update or revise any FOFI contained in this press release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein. All FOFI contained in this press release complies with the requirements of Canadian securities legislation, including NI 51-101.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this press release.

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