January 29, 2018

Prairie Provident Announces 2017 Year-End Reserves, 2018 Budget and Posts Updated Presentation

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Calgary, Alberta – January 29, 2018 – Prairie Provident Resources Inc. (“Prairie Provident”, “PPR” or the “Company”) is pleased to announce the results of our independent 2017 year-end reserves evaluation and to provide our 2018 budget and guidance. In 2017, Prairie Provident focused on repositioning its asset portfolio by selling non-core gas producing properties and buying oil-weighted properties in our core areas, in concert with postponing short-term development due to uncertainty in the economic environment.  Taking these steps allow Prairie Provident to high-grade its netbacks and to capture more attractive rate of returns with oil price recovery.

2018 BUDGET & GUIDANCE HIGHLIGHTS

  • Fully-funded capital budget set at $26 million (before capitalized G&A and ARO), expected to generate average full-year production between 5,200 to 5,600 boe per day. Based on this capital budget and production forecast, we anticipate achieving annual average production growth of 5% over 2017 (adjusted for divested production), while spending within forecast adjusted EBITDAX;
  • 2018 production is expected to have a liquids-weighting of 68% to 71%, compared to 65% in 2017, with high-value light/medium-oil representing approximately 95% of total forecasted liquids volumes in 2018, positioning PPR to benefit in the near and longer term should benchmark light oil prices continue to strengthen;
  • Exploration and development activities represent the majority of our 2018 budget, with approximately $25 million allocated to the drilling and completion of fifteen (14.45 net) wells, primarily in our light/medium oil-weighted Wheatland/Wayne and Princess areas of Alberta; as well as continued waterflood expansion at our Evi light oil property;
  • Drilling and completions capital is expected to be weighted to the first and third quarters of 2018, with approximately 35% and 52% of budgeted capital forecast to be invested in the first and third quarters, respectively;
  • Higher forecast liquids weighting, combined with continued cost control efforts, are expected to support stronger operating netbacks in 2018 relative to 2017;
  • Based on the capital budget outlined above and higher forecast adjusted EBITDAX due to a more heavily weighted oil program, Prairie Provident’s year-end 2018 long-term debt is expected to be approximately $58 million (net of cash collateralized for letters of credit) on a total current credit facility of approximately $70 million.

2017 RESERVES HIGHLIGHTS

  • Achieved a 10% and 13% year-over-year increase in total proved (“1P”) and proved plus probable (“2P”) reserves per share, respectively, despite the deferral of 2017 capital spending in response to a low commodity price environment, a significant proportion of capital dollars allocated to exploration and delineation drilling, and the disposition of certain non-core producing properties;
  • Increased 1P and 2P reserves by 22% and 26%, respectively, while also increasing total liquids weighting;
  • Increased the before-tax estimated net present value of future net revenue discounted at 10% (“NPV10 BT”) for 1P and 2P reserves by 31% to $208 million and by 33% to $298 million, respectively;
  • Generated 1P and 2P finding, development and acquisition costs (excluding changes in future development costs) of $13.08/boe and $9.47/boe, respectively.

RESERVES DETAIL

In 2017, Prairie Provident divested several gas-weighted properties in a focused effort to reduce our exposure to natural gas, given the significant deterioration of benchmark prices in Western Canada.  Consistent with this strategy, and in the interests of increasing our product weighting towards liquids, we acquired high-netback light oil assets in our Evi core area.  These transactions positively impacted PPR’s portfolio by increasing our forecast light oil and NGL weighting for 2018 and beyond.

Prairie Provident’s 2017 year-end reserves evaluation was conducted by Sproule Associates Limited (“Sproule”), the Company’s independent reserves evaluator, with an effective date of December 31, 2017. Sproule evaluated 100% of the Company’s reserves.  The following presentation summarizes certain information contained in Sproule’s independent reserves evaluation report as at December 31, 2017 (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”). 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, 2017, as outlined in the table below entitled “Price Forecast”.  Estimated future net revenue is stated without any provision 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, 2017 (the “AIF”), which will be filed under the Company’s profile at www.sedar.com on or before April 2, 2018.

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

Summary of Corporate Reserves(1,2,3,4,5)

The following table is a summary of the Company’s estimated reserves as at December 31, 2017, based on 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)
Proved
     Developed Producing 6,223 82 4,255 7,047 280 8,469
     Developed Non-Producing 320 8 2,107 40 24 710
     Undeveloped 4,074 5,839 125 5,172
Total Proved 10,617 90 6,362 12,926 429 14,351
Probable 4,420 219 1,667 7,406 176 6,327
Total Proved plus Probable 15,037 309 8,029 20,332 605 20,678

Notes:

  • 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, 2017 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.
  • Oil equivalent amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.   See “Other Advisories” 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, 2017, based on the Sproule Report.

Reserves Category 0% 5% 10% 15% 20%
($000s) ($000s) ($000s) ($000s) ($000s)
Proved
   Developed Producing 212,640 177,012 150,439 130,683 115,667
   Developed Non-Producing 10,609 8,742 7,290 6,180 5,322
   Undeveloped 104,631 72,286 50,097 34,750 23,884
Total Proved 327,880 258,040 207,826 171,613 144,872
Probable 182,475 125,186 90,639 68,653 53,823
Total Proved plus Probable 510,355 383,227 298,466 240,266 198,695

Notes:

  • Based on Sproule’s December 31, 2017 forecast prices and costs. The forecast of commodity prices used in the Sproule Report can be found at sproule.com.
  • 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

The following table summarizes Sproule’s commodity price forecast and foreign exchange rate and inflation rate assumptions as at December 31, 2017, as applied in the Sproule Report, for the next five years.

 Year Exchange Rate WTI @ Cushing Canadian Light Sweet 40º API Western Canada Select 20.5 API Edmonton Butane Natural gas AECO-C spot
$US/$C (US$/bbl) (C$/bbl) (C$/bbl) (C$/bbl) (C$/mmbtu)
2018 0.790 55.00 65.44 51.05 48.73 2.85
2019 0.820 65.00 74.51 59.61 55.49 3.11
2020 0.850       70.00 78.24 64.94 57.65 3.65
2021 0.850       73.00 82.45 68.43 60.12 3.80
2022 0.850       74.46 84.10 69.80 61.32 3.95

Notes:

  • Inflation is accounted for at 2.0% per year. 

Future Development Costs (“FDC”)

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

Total Total Proved
Future Development Costs ($000s)(1) Proved plus Probable
2018 26,377 37,817
2019 33,584 52,528
2020 29,132 45,982
2021 14,720 14,720
Remainder 65 181
Total FDC undiscounted 103,878 151,228
Total FDC discounted at 10% 89,348 130,164

 

Notes:

  • FDC as per Sproule Report, based on Sproule’s December 31, 2017 forecast prices and costs.

Capital Efficiencies

In 2017, PPR executed a successful drilling program which focused predominantly on oil targets. This was supplemented by key acquisitions that provided incremental organic growth opportunities.

During 2017, PPR’s 1P finding and development (“F&D”) costs(1) were $24.38/boe, while 1P finding development and acquisition (“FD&A”) costs(1) were $13.08/boe, excluding changes in estimated FDC.  The following tables provide a summary of the Company’s F&D costs and FD&A costs for 2017.

Finding & Development Costs (2017) Total Proved Total Proved plus Probable
Exploration and development capital(2)(3) ($000s) 19,015 19,015
Change in FDC ($000s)(3) (2,967) (2,031)
Total F&D costs, including changes in FDC 16,048 16,985
Total reserves additions, including revisions (mboe) 779.9 675.5
F&D costs, excluding FDC ($/boe) 24.38 28.15
F&D costs, including changes in FDC ($/boe) 20.58 25.14

 

Finding, Development & Acquisition Costs (2017) Total Proved Total Proved plus Probable
Exploration, development and acquisition capital(2)(3) ($000s) 59,464 59,464
Change in FDC ($000s) 38,648 72,129
Total FD&A costs, including changes in FDC(3) 98,111 131,592
Total reserves additions, including revisions (mboe) 4,547.5 6,280.3
FD&A costs, excluding FDC ($boe) 13.08 9.47
FD&A costs, including changes in FDC ($/boe) 21.57 20.95

Notes:

  • “F&D costs” and “FD&A costs” do not have a standardized meaning. See “Disclosure of Oil and Gas Reserves Data and Operational Information” contained in this news release.
  • Exploration and development capital excludes land expenditures and capitalized general and administrative expenses.
  • The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated FDC may not reflect the total F&D costs related to reserves additions for that year.
  • Columns may not add due to rounding. 

CAPITAL BUDGET OVERVIEW BY CORE AREA

Core Area Budget ($millions) % of Total  Activity Description
Wheatland, Wayne Area $9.0 35% ·       Drill 6.0 (6.0 net) wells

·       Budgeted DCE&T costs per well of $1.5 – $1.6 million

Princess Area $10.0 38% ·       Drill 6.0 (6.0 net) wells

·       Budgeted DCE&T costs per well of $1.5 – $1.6 million

Evi Area $6.0 23% ·       Drill 3.0 (2.45 net) Granite Wash wells

·       Waterflood expansion investment of $3.0 million

Land, Seismic and Other Opportunities $1.0 4%

 

2018 BUDGET AND GUIDANCE SUMMARY

Production guidance 5,200 – 5,600 boe/d
Liquids weighting 68 – 71%
Capital expenditures (excluding abandonment and reclamation expenditures and capitalized G&A) $26 million
Operating expense $17.00 – 18.50/boe
Operating netback $20.50 – 22.00/boe
2018 year-end long-term debt (net of cash collateralized for letters of credit) $58 million
 
Financial Assumptions
Oil (WTI) US$63.00/bbl
Oil (WCS) C$51.50/bbl
Natural gas (AECO) C$1.40/mcf
Edmonton Light/WTI differential C$6.00
USD/CAD exchange rate 0.81

UPDATED CORPORATE PRESENTATION

Prairie Provident today posted an updated corporate presentation on its website. The January 2018 corporate presentation can be accessed by following the link to www.ppr.ca

ABOUT PRAIRIE PROVIDENT

Prairie Provident is a Calgary-based company engaged in the exploration and development of oil and natural gas in Canada.  The Company’s strategy is to combine organic growth with accretive acquisitions of conventional oil prospects that bring additional development potential. The Company’s operations are primarily focused at Wheatland and Princess in Southern Alberta, where we are targeting the Lower Mannville formation; along with an early stage waterflood project at Evi in the Peace River Arch. The Company also holds a large acreage position of approximately 240,000 net acres in the Utica shale in Quebec’s Saint Lawrence lowlands.  Prairie Provident protects its income statement through an active hedging program and manages risk by allocating capital to opportunities offering maximum shareholder returns.

For further information, please contact:

Tim Granger
President & Chief Executive Officer

Tel: (403) 292-8110
Email:
tgranger@ppr.ca
Web: www.ppr.ca

Cautionary Statements

Unaudited financial information

Certain financial and operating information included in this press release for the quarter and year ended December 31, 2017, including finding and development costs and 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 and statements” set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2017 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, 2017, 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, 2017, which will be filed under the Company’s profile on SEDAR at www.sedar.com on or before April 2, 2018. The reserves data estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered or that the estimates of related 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 related 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 forward-looking information 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 and development costs”, “finding, development and acquisition costs” and “operating netbacks”, 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 assessments 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 press release, should not be relied upon for investment or other purposes.

“Finding and development costs” or “F&D costs” – The Company calculates F&D costs by dividing all capital costs for the period (except land costs and capitalized general and administrative expenses) by the change in reserves relating to discoveries, infill drilling, improved recovery, extensions and technical revisions for the same period.  F&D costs, including FDC, include all such capital costs in the period as well as the change in estimated FDC required to bring the reserves within the specified reserves category on production. 

“Finding, development and acquisition costs” or “FD&A costs” – The Company calculates FD&A costs by dividing the sum of all capital costs (except land costs and capitalized general and administrative expenses) and all acquisition costs (net of disposition proceeds) for the period 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, including FDC, include all such capital costs and all acquisition costs (net of disposition proceeds) in the period as well as the change in estimated FDC required to bring the reserves within the specified reserves category on production. 

Both F&D costs and 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 F&D and FD&A as measures of its ability to execute its capital programs (and success in doing so) and of its asset quality.

Forward-looking information

Certain information included in this news release constitutes forward-looking information within the meaning of applicable Canadian securities laws.  Statements that constitute forward-looking information 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 constitute forward-looking information.  Forward-looking information is typically, but        not always, identified by words such as “anticipate”, “believe”, “expect”, “intend”, “plan”, “budget”, “forecast”, “target”, “estimate”, “propose”, “potential”, “project”, “continue”, “may”, “will”, “should” or similar expressions suggesting future outcomes or events or statements regarding an outlook.  In particular, this news release includes forward-looking information regarding:  the estimated volumes and related future net revenue from Prairie Provident’s oil and gas reserves; budgeted capital expenditure amounts for 2018 and the timing and allocation thereof; the volume and product mix of Prairie Provident’s future oil and gas production, including expected average 2018 production volumes and liquids weighting thereof; future oil and natural gas prices; future results from operations and operating metrics, including forecast 2018 operating expenses and operating netback; the number of wells covered by the 2018 capital budget and target areas therefor; budgeted costs to drill, complete, equip and tie-in (“DCE&T”) a well at Wheatland/Wayne and Princess (as contemplated by the 2018 budget); the Company’s forecast long-term debt level at year-end 2018; and future development, exploration, acquisition and disposition activities (including drilling, completion and infrastructure plans and associated timing and costs).Forward-looking information is based on a number of material factors, expectations or assumptions of Prairie Provident, which have been used to develop such information but which may prove to be incorrect. Although Prairie Provident believes that the expectations and assumptions reflected in such forward-looking information are reasonable, undue reliance should not be placed on forward-looking information, which is inherently uncertain and depends upon the accuracy of such expectations and assumptions.  Prairie Provident can give no assurance that the forward-looking information contained herein will prove to be correct or that the expectations and assumptions upon which they are based will occur or be realized.  Actual results or events will differ, and the differences may be material and adverse to the Company.  In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: future commodity prices and costs; the timing and success of future drilling and development activities (and the extent to which the results thereof meet Management’s expectations); 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; future capital expenditure requirements and the sufficiency thereof to achieve the Company’s objectives; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Prairie Provident’s reserves volumes; certain commodity price and other cost assumptions; continued availability of external financing and cash flow to fund Prairie Provident’s current and future plans and expenditures, with financing on acceptable terms; 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; 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 information included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors, many of which are beyond the Company’s control, that may cause actual results or events to differ materially from those indicated or suggested in the forward-looking information, 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 other risks detailed from time-to-time in Prairie Provident’s public disclosure documents (including, without limitation, those risks identified in Prairie Provident’s current Annual Information Form), copies of which are available electronically under the Company’s issuer profile on the SEDAR website and on its website at www.ppr.ca.  This list is not exhaustive.

The forward-looking information contained in this news release speak only as of the date of this news release, and Prairie Provident does not assume any obligation to publicly update or revise any of the included forward-looking information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

OTHER    ADVISORIES

We have adopted the industry-standard conversion ratio of six Mcf to one bbl when converting natural gas quantities to “barrels of oil equivalent” (BOEs).  BOEs may be misleading, though, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.  Although the six-to-one conversion factor is an industry accepted norm, it is not reflective of price or market value differentials between product types.  Based on current commodity prices, the value ratio between natural gas and oil is significantly different than the 6:1 ratio based on energy equivalency.  Accordingly, a 6:1 conversion ratio may be misleading as an indication of value.

Non-IFRS Measures

The Company uses certain terms in this news release that do not have a standardized or prescribed meaning or methods of calculation under IFRS, Prairie Provident’s measurement of these terms may not be comparable with the calculation of similar terms used by other companies and therefore should not be used to make such comparisons.

“Operating netback” – This is a non-IFRS measure commonly used in the oil and gas industry. Operating netback assists management and investors to evaluate the specific operating performance at the oil and gas lease level. Operating netbacks included in this news release 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 derivative instruments.

“Adjusted EBITDAX” – The Company monitors its capital structure and liquidity based on the ratio of Debt to Adjusted EBITDAX as defined below. The ratio provides a measure of the Company’s ability to manage its debt levels under current operating conditions. “Debt” refers to the sum of the Company’s borrowings under its US$40 million senior secured revolving note facility and issue of US$16 million senior subordinated notes due October 31, 2021. “Adjusted EBITDAX” corresponds to defined terms in the Company’s senior secured revolving note agreement and means net earnings before financing charges, foreign exchange gain (loss), E&E expense, income taxes, depreciation, depletion, amortization, other noncash items of expense and non-recurring items, adjusted for major acquisitions and material dispositions assuming that such transactions had occurred on the first day of the applicable calculation period. As transaction costs are non-recurring costs, Adjusted EBITDAX has been calculated, excluding transaction costs, as a meaningful measure of continuing operating cash flows. For purposes of calculating covenants under the credit facility, Adjusted EBITDAX is determined using financial information from the most recent four consecutive fiscal quarters.