February 3, 2020

Prairie Provident Announces Year-End 2019 Reserves

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Calgary, Alberta – February 3, 2020 – Prairie Provident Resources Inc. (“Prairie Provident”, “PPR” or the “Company”) is pleased to announce the results of our independent 2019 year-end reserves evaluation conducted by Sproule Associates Limited (“Sproule”) with an effective date of December 31, 2019 (the “Sproule Report”).


  • Significant proved plus probable (“2P”) and total proved (“1P”) reserves were added through exploration and development activities in 2019, totaling 4.3 MMboe and 1.7 MMboe, respectively.
  • Operating cost reductions at Michichi and improved well performance at Princess resulted in positive technical revisions of 0.5 MMboe for 2P, 1.7 MMboe for 1P and 1.7 MMboe for proved developed producing (“PDP”) reserves. PPR’s continued transition to our Evi waterflood resulted in 1.5 MMboe of 2P and 1.2 MMboe of 1P improved recovery in 2019, but also led to negative technical revisions of 1.2 MMboe for 2P and 0.9 MMboe for 1P due to the removal of undeveloped locations, which offset some of the positive technical revisions realized at Michichi and Princess.
  • Replaced 163% and 113% of 2019 production with reserves additions and technical revisions, on a 2P and 1P basis, respectively.
  • Reserves totaled 34.5 MMboe, 21.7 MMboe and 10.0 MMboe for 2P, 1P and PDP, respectively. Reserves additions were offset by the impact of Sproule’s lower price deck forecasts, which resulted in reserves reductions of 0.4 MMboe, 0.9 MMboe and 0.8 MMboe for 2P, 1P and PDP, respectively.  Excluding the impact of lower pricing, PPR recorded year-over-year growth of 4% and 1% on a 2P and 1P basis, respectively, on a modest $10.6 million exploration and development program.
  • Finding, development and acquisition (“FD&A”)(1) costs were $12.48/boe, $1.29/boe and $6.16/boe for 2P, 1P and PDP, respectively, including change in future development costs and technical revisions, resulting in estimated FD&A recycle ratios(1) of 1.5, 14.4 and 3.0 times, respectively, using an estimated 2019 operating netback of $18.58/boe(1)(2).
  • 2019 net present values of future net revenue before tax discounted at 10% (“NPV10 BT”) for 2P, 1P and PDP reserves totaled $437.7 million, $257.4 million and $135.4 million, respectively, including asset retirement obligation (“ARO”) deductions of $29.1 million, $28.2 million and $26.8 million, respectively. Based on Sproule’s application of new guidance added to the Canadian Oil and Gas Evaluation Handbook (“COGEH”) in late 2019, PPR’s NPV10 BT includes a larger component of ARO in the reserves.  Approximately 79% of PPR’s estimated ARO is now included in the 2019 reserves evaluation compared to only 26% in 2018.  Excluding the inclusion of this larger component of ARO and the impact from Sproule’s lower price forecast, PPR’s NPV10 BT in 2019 would have been higher than in 2018.
  • Net asset value (“NAV”)(1)(2) per share is $1.92, $0.87 and $0.16 on a 2P, 1P and PDP basis, respectively.
  • With a reserve life index(1) of 15.6 years, 9.8 years and 4.5 years on a 2P, 1P and PDP basis, PPR is well positioned for long-term sustainability and to continue the measured development of its oil and liquids-weighted asset base.


  • Finding, Development & Acquisition Costs”, “Recycle Ratios”, “Operating Netback”, “Net Asset Value” and “Reserve Life Index” do not have standardized meanings. See “Cautionary Statements” below. See also “Capital Efficiencies” and “Net Asset Value” below.
  • All 2019 financial information is unaudited. See advisories.



PPR executed a successful 2019 capital development program which added approximately 4.3 MMboe and 1.7 MMboe of incremental 2P and 1P reserves from an exploration and development program that was just over $10 million, and achieved robust recycle ratios due to attractive FD&A costs and netbacks.  Significant declines in Sproule’s price forecasts negatively impacted the Company’s overall reserves and NPV10.  Before the effects of lower forecast pricing, PPR replaced 163% and 113% of 2019 production on a 2P and 1P basis.

PPR delivered strong operational performance in 2019, successfully, safely and responsibly adding reserves through our capital program.  At Evi, PPR has transitioned its development plan from infill drilling to waterflood.  As a result, an incremental 1.5 MMboe and 1.2 MMboe of 2P and 1P undeveloped reserves (98% liquids), respectively, have been assigned to future waterflood expansions. PPR’s continued transition to waterflood at Evi also led to the removal of infill locations in the waterflood areas, resulting in 1.2 MMboe and 0.9 MMboe of negative technical revisions on a 2P and 1P basis, respectively.  The transition also reduced 1P future capital by $5.3 million, which high-graded the development economics.

At Michichi, meaningful reserves were added as a result of improved operational efficiencies and lower overall operating costs. Improved well economics resulted in the addition of 1.7 MMboe of 2P undeveloped reserves and added positive technical revisions of 1.7 MMboe and 1.6 MMboe of 2P and 1P reserves, respectively.

In our Princess area, we extended 1.0 MMboe and 0.4 MMboe of 2P and 1P undeveloped reserves relating to Glauconite and Ellerslie development.  In addition, over 0.4 MMboe of 2P and 0.6 MMboe of 1P positive technical revisions were realized from improved well performance.

Commencing in 2019, Sproule has reflected a larger proportion of the Company’s estimated ARO within our reserves, which resulted in a decrease in value relative to 2018. This change was made based on new guidelines added to the COGEH in late 2019, which recommends as a best practice the inclusion of all abandonment, decommissioning and reclamation (“ADR”) costs associated with active assets in the reserve report. This includes costs for both active and inactive wells, including ADR costs for producing wells, suspended wells, service wells, gathering systems, facilities, and surface land development for all active assets. At year-end 2019, Sproule’s evaluation of our NPV10 BT for ARO related to our 2P, 1P and PDP reserves was $29.1 million, $28.2 million, and $26.8 million, respectively, an increase of $14.3 million, $12.4 million, and $13 million compared to the corresponding ARO measures at the end of 2018, respectively.

We expect to release PPR’s Q4 and full-year 2019 financial and operating results after market on March 25, 2020.  We appreciate the ongoing support from our shareholders and your continued confidence in PPR’s strategic direction.


Reserves Summary Highlights

The following presentation summarizes certain information contained in the Sproule Report, which was prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”).  Sproule evaluated 100% of the Company’s reserves.  The Sproule Report is based on forecast prices and costs and applies Sproule’s forecast escalated commodity price deck and foreign exchange rate and inflation rate assumptions as at December 31, 2019, as outlined in the table below entitled “Price Forecast”.  Estimated future net revenue is stated without any provisions for interest costs, other debt service charges or general and administrative expenses, and after the deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future development costs.

Additional information regarding the Company’s reserves data and other oil and gas information will be included in the Company’s Annual Information Form for the year ended December 31, 2019 (the “AIF”), which will be filed under the Company’s issuer profile on SEDAR at www.sedar.com on or before March 30, 2020.

See also the “Cautionary Statements” below for further explanations and discussions.


Summary of Corporate Reserves(1)(2)(5)

The following table is a summary of the Company’s estimated reserves as at December 31, 2019, as evaluated in the Sproule Report.

 Reserves Category Light and Medium Oil Heavy Oil Conventional Natural Gas(3) (other than Solution Gas) Conventional Natural Gas (Solution Gas) Natural Gas Liquids Barrels of Oil Equivalent(4)
(Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mboe)
     Developed Producing 6,065 403 9,063 10,381 329 10,038
     Developed Non-producing 137 253 4 183
     Undeveloped 7,910 459 16,905 316 11,502
Total Proved 14,112 862 9,063 27,540 648 21,723
Probable 8,003 748 2,448 19,214 383 12,744
Total Proved plus Probable 22,115 1,610 11,511 46,754 1,031 34,467


  • Reserves are presented on a “company gross” basis, which is defined as Prairie Provident’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company.
  • Based on Sproule’s December 31, 2019 forecast prices and costs. The forecast of commodity prices used in the Sproule Report can be found at sproule.com. See also “Price Forecast” below.
  • Including both non-associated gas and associated gas but excluding solution gas (gas dissolved in crude oil).
  • Oil equivalent amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.   See “Cautionary Statements – Barrels of oil equivalent” below.
  • Columns may not add due to rounding of individual items.


Net Present Values of Future Net Revenue Before Income Taxes Discounted at (%/year) (1)(2)(3)(4)(5)

The following table is a summary of the estimated net present values of future net revenue (before income taxes) associated with Prairie Provident’s reserves as at December 31, 2019, discounted at the indicated percentage rates per year, as evaluated in the Sproule Report.

Reserves Category 0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$)
   Developed Producing 22.6 129.8 135.4 127.2 117.4
   Developed Non-Producing 4.8 3.9 3.2 2.7 2.4
   Undeveloped 249.1 170.5 118.8 83.7 59.2
Total Proved 276.5 304.2 257.4 213.6 179.0
Probable 342.8 241.3 180.3 140.5 112.9
Total Proved plus Probable 619.3 545.5 437.7 354.1 291.9


  • Based on Sproule’s December 31, 2019 forecast prices and costs. The forecast of commodity prices used in the Sproule Report can be found at sproule.com. See also “Price Forecast” below.
  • Estimated future net revenues are stated without any provision for interest costs, other debt service charges or general and administrative expenses, and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future development costs.
  • Estimated future net revenue, whether discounted or not, does not represent fair market value.
  • Net present values of future net revenue after income taxes are estimated to approximate the before income tax values based on the estimated future revenues, available tax pools and future deductible expenses.
  • Columns may not add due to rounding of individual items.


Price Forecast(1)

The following table summarizes Sproule’s commodity price forecast and foreign exchange rate and inflation rate assumptions as at December 31, 2019, as applied in the Sproule Report, for the next five years.

 Year Exchange Rate WTI @ Cushing Canadian Light Sweet 40º API Western Canada Select 20.5º API Edmonton Butane Natural gas AECO-C spot
$US/$C (US$/bbl) (C$/bbl) (C$/bbl) (C$/bbl) (C$/MMbtu)
2020 0.76 61.00 73.84 59.81 37.72 2.04
2021 0.77 65.00 78.51 63.98 43.90 2.27
2022 0.80 67.00 78.73 63.77 47.74 2.81
2023 0.80 68.34 80.30 65.04 48.69 2.89
2024 0.80 69.71 81.91 66.34 49.67 2.98


  • Inflation is accounted for at 2.0% per year.


Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs(2)(3)

FACTORS Proved Probable Proved plus
December 31, 2018 22,360 11,504 33,863
Acquisitions 0 0 0
Dispositions 0 0 0
Drilling (Extensions and Improved Recovery(1)) 1,724 2,554 4,278
Discoveries 0 0 0
Technical Revisions 781 (1,443) (662)
Pricing (Economic Factors) (930) 129 (802)
Production (2,212) 0 (2,212)
December 31, 2019 21,723 12,744 34,467


  • Reserves additions under Infill Drilling, Improved Recovery and Extensions are combined and reported as “Extensions and Improved Recovery”.
  • Columns may not add due to rounding.
  • Company Gross Reserves exclude royalty volumes.


Future Development Costs (“FDC”)

The following table provides a summary of the estimated FDC required to bring Prairie Provident’s 1P and 2P undeveloped and non-producing reserves to production, as reflected in the Sproule Report, which costs have been deducted in Sproule’s estimation of future net revenue associated with such reserves.

Total Total Proved
Future Development Costs (MM$)(1) Proved plus Probable
2020 46.7 64.1
2021 73.4 104.7
2022 32.0 68.2
2023 36.9 66.5
Remainder 0.1 0.1
 Total FDC undiscounted 189.1 303.6
Total FDC discounted at 10% 160.0 253.4


  • FDC as per Sproule Report, based on Sproule’s December 31, 2019 forecast prices and costs.


Capital Efficiencies(2)(4)

The following table sets out our calculation of FD&A costs.  See also “Cautionary Statements – Finding, Development and Acquisition costs” below.

Finding, Development and Acquisition Costs (2019) Proved Developed Producing Total Proved Total Proved plus Probable
Exploration and development capital(1) (MM$) 10.3 10.3 10.3
Change in FDC(2) (MM$) 0 (7.1) 34.8
Total FD&A costs, including change in FDC (MM$) 10.3 3.2 45.1
Total reserves additions, including technical revisions (Mboe) 1,675 2,505 3,616
FD&A costs, including change in FDC ($/boe) 6.16 1.29 12.48


  • Exploration and development capital (unaudited) related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities.
  • FDC as per Sproule Report, based on Sproule’s December 31, 2019 forecast prices and costs.
  • Columns may not add due to rounding.


Net Asset Value

The following table sets out a calculation of NAV based on the estimated before-tax estimated net present value of future net revenue (discounted at 10%) (“NPV10 BT”) associated with our PDP, 1P and 2P reserves, as evaluated in the Sproule Report, our estimated long-term debt, and the number of PPR common shares outstanding, all as of December 31, 2019.  See also “Cautionary Statements – Net Asset Value” below.

NPV10 BT (MM$) 135.4 257.4 437.7
Estimated long-term debt, less cash collateralized letters of credit (unaudited) (MM$) (108.7) (108.7) (108.7)
Net Asset Value (MM$) 26.7 148.7 329.0
Basic shares outstanding (MM) 171.4 171.4 171.4
Estimated NAV/share ($) 0.16 0.87 1.92



Prairie Provident is a Calgary-based company engaged in the exploration and development of oil and natural gas properties in Alberta. The Company’s strategy is to grow organically in combination with accretive acquisitions of conventional oil prospects, which can be efficiently developed. Prairie Provident’s operations are primarily focused at the Michichi and Princess areas in Southern Alberta targeting the Banff, the Ellerslie and the Lithic Glauconite formations, along with an established and proven waterflood project at our Evi area in the Peace River Arch. Prairie Provident protects its balance sheet through an active hedging program and manages risk by allocating capital to opportunities offering maximum shareholder returns.


For further information, please contact:

Prairie Provident Resources Inc.
Tim Granger
President and Chief Executive Officer
Tel: (403) 292-8110
Email: tgranger@ppr.ca


Cautionary Statements


Unaudited financial information

Certain financial and operating information included in this news release for the quarter and year ended December 31, 2019, including finding, development and acquisition costs, are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed under “Forward-looking information” set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2019 and changes could be material.

Disclosure of Oil and Gas Reserves Data and Operational Information

Prairie Provident’s Statement of Reserves Data and Other Oil and Gas Information for the year ended December 31, 2019, providing additional information regarding our reserves data and oil and gas activities in accordance with NI 51-101, will be contained in our Annual Information Form for the year ended December 31, 2019, which will be filed under the Company’s issuer profile on SEDAR at www.sedar.com on or before March 30, 2020. The reserves data estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered or that the related estimates of future net revenues will be realized. There can be no assurance that the forecast prices and cost assumptions applied by Sproule in evaluating the Company’s reserves will be attained, and variances between actual and forecast prices and costs could be material.  Actual reserves may be greater than or less than the estimated volumes provided herein, and it should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves.  Estimates in respect of individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.  The Company’s belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading “Forward-looking information”.

This news release discloses certain metrics commonly used in the oil and natural gas industry – namely “”finding, development and acquisition costs”,  “net asset value” and “reserve life index” – that do not have standardized meanings or methods of calculation under applicable laws, International Financial Reporting Standards, the COGE Handbook or other applicable professional standards.  Accordingly, such measures, as determined by the Company, may not be comparable to similarly defined or labelled measures presented by other companies, and therefore should not be used to make such comparisons. These metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, but should not be relied upon for comparative purposes.  Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Prairie Provident’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 news release, should not be relied upon for investment or other purposes.

Finding, Development and Acquisition costs (“FD&A costs”)

The Company calculates FD&A costs by dividing the sum of exploration and development capital and all acquisition costs (net of disposition proceeds) for the period, plus the change in estimated FDC required to bring the reserves within the specified reserves category on production, by the change in reserves relating to discoveries, infill drilling, improved recovery, extensions and technical revisions inclusive of changes due to acquisitions and dispositions for the same period. FD&A costs have been presented in this news release because acquisitions and dispositions can have a significant impact on Prairie Provident’s ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of its cost structure. Management uses FD&A as measure of its ability to execute its capital programs (and success in doing so) and of its asset quality. 

Operating Netback

Operating netback is a non-IFRS measure commonly used in the oil and gas industry. This measurement assists management and investors to evaluate the specific operating performance at the oil and gas lease level.  Operating netbacks included in this release are based on 2019 (unaudited) realized operating netback before any hedging gains/losses, and were determined by taking (oil and gas revenues less royalties less operating costs) divided by gross working interest production. Operating netback, including realized commodity (loss) and gain, adjusts the operating netback for only realized gains and losses on derivatives.

Recycle Ratio

Recycle ratio is defined as operating netback per boe divided by FD&A costs on a per boe basis.  PPR’s operating netback in 2019, used in the above calculations, averaged $18.58 per boe (unaudited). 

Net Asset Value (“NAV”)

The Company calculates NAV by subtracting its long-term debt balance from the net present values of estimated future net revenues (before income taxes and discounted at 10% per year) associated with its reserves, as evaluated in the Sproule Report.  Management uses NAV as a measure of the Company’s oil and gas asset value attributable to its shareholders. 

Reserve Life Index (“RLI”)

The Company calculates RLI based on the amount for the relevant reserves category prepared by Sproule, divided by 2019 annual production.


Forward-looking information

This news release contains certain statements (“forward-looking statements”) that forward-looking information within the meaning of applicable securities laws.  Forward-looking statements relate to future performance, events or circumstances, and are based upon internal assumptions, plans, intentions, expectations and beliefs.  All statements other than statements of current or historical fact are forward-looking statements.  Forward-looking statements are typically, but not always, identified by words such as “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plan”, “intend”, “budget”, “potential”, “target” and similar words or expressions suggesting future outcomes or events or statements regarding an outlook.

In particular, but without limiting the foregoing, this news release contains forward-looking statements pertaining to: estimated volumes of Prairie Provident’s oil and gas reserves and their categorization; estimated net present values of future net revenue associated with evaluated reserves; future growth; potential opportunity for expanded drilling; Evi-area development through waterflood expansion; the volume and product mix of Prairie Provident’s oil and gas production; future oil and natural gas prices; future results from operations and operating metrics, potential for lower costs and efficiencies going forward; future development, exploration, acquisition and disposition activities (including drilling, completion and infrastructure plans and associated timing and costs); and related production expectations.

Forward-looking statements are based on a number of material factors, expectations or assumptions of Prairie Provident which have been used to develop such but which may prove to be incorrect. Although Prairie Provident believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements because Prairie Provident can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that Prairie Provident will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities consistent with past operations; the quality of the reservoirs in which Prairie Provident operates and continued performance from existing wells; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Prairie Provident’s reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Prairie Provident’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Prairie Provident operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Prairie Provident to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Prairie Provident has an interest in to operate the field in a safe, efficient and effective manner; the ability of Prairie Provident to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Prairie Provident to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Prairie Provident operates; and the ability of Prairie Provident to successfully market its oil and natural gas products.

The forward-looking statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statement, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking statements including, without limitation: changes in commodity prices; changes in the demand for or supply of Prairie Provident’s products, the early stage of development of some of the evaluated areas and zones; the potential for variation in the quality of the lithic gluconate  formation; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Prairie Provident or by third party operators of Prairie Provident’s properties, increased debt levels or debt service requirements; inaccurate estimation of Prairie Provident’s oil and gas reserve volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Prairie Provident’s public disclosure documents, (including, without limitation, those risks identified in this news release and Prairie Provident’s Annual Information Form).

The forward-looking statements contained in this news release speak only as of the date of this news release, and Prairie Provident assumes no obligation to publicly update or revise them to reflect new events or circumstances, or otherwise, except as may be required pursuant to applicable laws. All forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

Barrels of oil equivalent

The oil and gas industry commonly expresses production volumes and reserves on a “barrel of oil equivalent” basis (“boe”) whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants.  A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead nor at the plant gate, which is where Prairie Provident sells its production volumes.  Boes may therefore be a misleading measure, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency ratio of 6:1, utilizing a 6:1 conversion ratio may be misleading as an indication of value.