FORM 51-101F1 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION Year Ended December 31, 2016 March 2, 2017
TABLE OF CONTENTS DATE OF STATEMENT AND RELEVANT DATES... 1 DISCLOSURE OF RESERVES DATA... 1 Report of Independent Qualified Reserves Evaluator... 1 Reserves Data... 2 Breakdown of Reserves... 2 Net Present Value of Future Net Revenue... 2 Elements of Future Net Revenue... 3 Future Net Revenue by Product Type... 4 PRICING ASSUMPTIONS... 4 Forecast Prices Used in Estimates... 4 Actual Weighted Average Prices... 5 RECONCILIATION OF CHANGES IN RESERVES... 6 ADDITIONAL INFORMATION RELATING TO RESERVES DATA... 7 Undeveloped Reserves... 7 Significant Factors or Uncertainties Affecting Reserves Data... 8 Future Development Costs... 8 OTHER OIL AND GAS INFORMATION... 9 Oil and Gas Properties and Wells... 9 Producing and Non-Producing Wells... 9 Properties with No Attributed Reserves... 9 Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves...10 Forward Contracts...10 Tax Horizon...11 Costs Incurred...11 Exploration and Development Activities...11 Production Estimates...12 Production History...12 ADVISORIES... 12 DEFINITIONS... 15 ABBREVIATIONS, CONVERSIONS AND CONVENTIONS... 17 Abbreviations...17 Conversions...18 Convention...18 Schedule A Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor....A-1 Schedule B Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure...B-1 i
DATE OF STATEMENT AND RELEVANT DATES This Form 51-101F1 Statement of Reserves Data and Other Oil and Gas Information (the Statement of Reserves ) of Painted Pony Petroleum Ltd. (the Corporation ) is dated March 2, 2017. The effective date of the information provided in the Statement of Reserves is December 31, 2016 unless otherwise indicated. The date of preparation of this Statement of Reserves is March 2, 2017. DISCLOSURE OF RESERVES DATA Report of Independent Qualified Reserves Evaluator GLJ Petroleum Consultants Ltd. ( GLJ ), independent qualified reserves evaluators of Calgary, Alberta, prepared an independent evaluation of the Corporation s oil and natural gas properties effective December 31, 2016, which is contained in a report dated February 27, 2017 (the 2016 Reserves Report ). GLJ previously prepared a report dated March 2, 2016, with an effective date of December 31, 2015, (the 2015 Reserves Report ). Reserves estimates stated herein as at December 31 of a year are extracted from the relevant evaluation. GLJ confirmed to the Reserves Committee of the Corporation s Board of Directors that the 2016 Reserves Report and the 2015 Reserves Report were prepared in accordance with the Canadian Oil & Gas Evaluation Handbook (the COGE Handbook ) and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ( NI 51-101 ). In the course of the evaluation of the Corporation s reserves as at the year ended December 31, 2016, GLJ obtained basic information from the Corporation, which included land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts, financial data and future operating plans. Other engineering, geological or economic data required to conduct the evaluation and upon which the 2016 Reserves Report is based, were obtained from public records, other operators and from GLJ s non-confidential files. GLJ advised that the accuracy of any reserves and production estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While GLJ believes the reserves and production estimates presented in the 2016 Reserves Report are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Revenue projections in the 2016 Reserves Report are based in part on forecasts of market prices, currency exchange rates, inflation, market demand and governmental policy, which are subject to many uncertainties and may, in future, differ materially from the forecasts utilized in the 2016 Reserves Report. Present values of revenues documented in the 2016 Reserves Report do not necessarily represent the fair market value of the reserves evaluated in the 2016 Reserves Report. The 2016 Reserves Report was conducted on the basis of the GLJ January 1, 2017 price forecast, which is available on its website at gljpc.com. Prior reserves evaluations were conducted on the basis of the price forecast in effect at the time of the relevant evaluation. At the time of the 2016 Reserves Report the Corporation s 2017 capital expenditure budget was $319 million. Forecast expenditures in future years may vary from actual expenditures. 1 paintedpony.ca
Reserves Data The tables contained in this Statement of Reserves summarize information provided by GLJ contained in the 2016 Reserves Report. Due to rounding, numbers in tables may not add. Breakdown of Reserves All of the Corporation s reserves are in Canada and specifically, in northeast British Columbia. The following table summarizes GLJ s estimates of the Corporation s reserves as at December 31, 2016, using Forecast Prices and Costs. Summary of Reserves (Forecast Prices & Costs) Reserves Category Gross (MMcf) Shale Gas Natural Gas Liquids Oil Equivalent Net (MMcf) Gross (Mbbl) Net (Mbbl) Gross (Mboe) Net (Mboe) Proved Developed Producing 443,611.8 377,997.1 6,791.1 5,990.9 80,726.4 68,990.4 Developed Non-producing 4,392.6 3,944.4 23.4 20.5 755.5 677.9 Undeveloped 1,976,775.7 1,736,398.3 31,175.8 27,580.5 360,638.4 316,980.2 Total Proved 2,424,780.0 2,118,339.7 37,990.3 33,591.9 442,120.3 386,648.6 Probable 2,091,951.7 1,732,244.7 32,607.0 27,367.6 381,265.6 316,075.1 Total Proved Plus Probable 4,516,731.8 3,850,584.4 70,597.3 60,959.5 823,385.9 702,723.9 Net Present Value of Future Net Revenue The following table sets out the net present value of the future net revenue associated with GLJ s estimates of the Corporation s reserves as at December 31, 2016, using Forecast Prices and Costs, before and after deducting future income tax expense, and calculated at various discount rates. The following table also sets out such information on a unit value basis using a discount rate of 10% and calculated before deducting future income tax expenses. Net Present Values of Future Net Revenue Before and After Income Taxes (1)(2) (Forecast Prices and Costs) (M$) Discounted At Unit Value (3) Annual Discount Rate 0% 5% 10% 15% 20% 10% Discount ($/boe) ($/Mcfe) Before Income Taxes Proved Developed Producing 1,233,063 890,507 705,315 591,775 515,483 10.22 1.70 Developed Non- Producing 5,330 3,852 2,902 2,257 1,798 4.28 0.71 Undeveloped 4,430,486 2,552,755 1,587,054 1,033,835 689,961 5.01 0.83 Total Proved 5,668,880 3,447,114 2,295,271 1,627,867 1,207,242 5.94 0.99 Probable 6,242,382 2,767,235 1,480,519 899,469 596,081 4.68 0.78 Total Proved Plus Probable 11,911,262 6,214,350 3,775,790 2,527,336 1,803,323 5.37 0.90 After Income Taxes Proved Developed Producing 1,152,452 853,473 686,873 581,985 510,011 9.96 1.66 Developed Non- Producing 3,922 3,002 2,370 1,914 1,573 3.50 0.58 Undeveloped 3,262,840 1,847,532 1,114,842 695,005 434,964 3.52 0.59 2 paintedpony.ca
Discounted At Unit Value (3) Annual Discount Rate 0% 5% 10% 15% 20% 10% Discount ($/boe) ($/Mcfe) Total Proved 4,419,213 2,704,007 1,804,085 1,278,904 946,548 4.67 0.78 Probable 4,606,923 2,025,216 1,067,953 638,662 417,038 3.38 0.56 Total Proved Plus Probable 9,026,136 4,729,223 2,872,038 1,917,566 1,363,586 4.09 0.68 (1) Estimates of future net revenue, whether discounted or not, do not represent fair market value. (2) Future net revenue is estimated after deduction of the estimated costs of abandonment of existing and future wells evaluated by GLJ in the 2016 Reserves Report and does not include well abandonment costs for wells to which reserves have not been attributed or the abandonment and reclamation costs of facilities and pipelines. (3) Calculated using net present value, before income taxes, discounted at 10%, divided by the Corporation s net reserves. Elements of Future Net Revenue The following table sets out the various elements of the Corporation s future net revenue associated with GLJ s estimate of the Corporation s reserves as at December 31, 2016, using Forecast Prices and Costs and calculated without discount. Total Future Net Revenue (1)(2) (Forecast Prices & Costs) (MM$) (Undiscounted) Reserves Category Sales Revenue Royalties Operating Costs (3) Development Costs (4) Abandonment and Reclamation Costs Future Net Revenue Before Income Taxes Income Taxes Future Net Revenue After Income Taxes Proved 13,415.7 1,604.2 4,207.9 1,825.3 109.3 5,668.9 1,249.7 4,419.2 Proved Plus Probable 27,619.5 3,830.3 8,763.8 2,916.7 197.4 11,911.3 2,885.2 9,026.1 (1) Estimates of future net revenue, whether discounted or not, do not represent fair market value. (2) Future net revenue is estimated after deduction of the estimated costs of abandonment of existing and future wells evaluated by GLJ in the 2016 Reserves Report and does not include well abandonment costs for wells to which reserves have not been attributed or the abandonment and reclamation costs of facilities and pipelines. (3) Operating costs represents the sum of operating costs (proved: MM$4,168.5; proved plus probable: MM$8,657.0) and the costs of the Capital Leases (proved: MM$39.4; proved plus probable: MM$106.7). (4) Development costs represents the total development capital less capital associated with the Capital Leases (proved: MM$1,864.7; proved plus probable: MM$3,023.5). The 2015 Reserves Report incorporated the Capital Lease treatment of the AltaGas Townsend Facilities. In the 2016 Reserves Report the AltaGas Townsend Facilities have been treated as finance leases in the Corporation s consolidated financial statements. Upon commencement of commercial operations, the Corporation recorded the assets, representing the total construction cost of the AltaGas Townsend Facilities, with corresponding obligations on the statement of financial position. Over the course of the Capital Leases, there will be capital fees paid to AltaGas, which, from an accounting perspective, will be split between finance costs and the amortization of the obligation. 3 paintedpony.ca
Future Net Revenue by Product Type The following table sets out the net present value of future net revenue before deducting future income expenses as at December 31, 2016, estimated by using Forecast Prices and Costs and calculated using a discount rate of 10%. Net Present Value of Future Net Revenue (1)(2)(3) (Forecast Prices & Costs) (Before Income Tax) (10% Discount Rate) Reserves Category Product Type Future Net Revenue Unit Value (MM$) ($/boe) Proved Shale Gas 2,295.3 5.94 Proved Plus Probable Shale Gas 3,775.8 5.37 (1) Estimates of future net revenue, whether discounted or not, do not represent fair market value. (2) Future net revenue is estimated after deduction of the estimated costs of abandonment of existing and future wells evaluated by GLJ in the 2016 Reserves Report and does not include well abandonment costs for wells to which reserves have not been attributed, abandonment and reclamation costs of facilities and pipelines. (3) Future net revenue associated with the product type Natural Gas Liquids are included in the future net revenue of the product type Shale Gas. Forecast Prices Used in Estimates PRICING ASSUMPTIONS The following table sets out the pricing assumptions used by GLJ in preparing the 2016 Reserves Report. GLJ prepared its January 1, 2017 price and market forecast after a comprehensive review of information from sources including government agencies, industry publications, Canadian oil refiners and natural gas marketers. While GLJ considered these forecasts reasonable at the time, users of forecasts should understand the inherently high uncertainty in forecasting any commodity or market. Summary of Pricing and Inflation Rate Assumptions (Forecast Prices & Costs) Shale Gas Natural Gas Liquids Forecast Year Edmonton AECO Natural Gas Price Spec Ethane Edmonton Propane Edmonton Butane C5+ Stream Quality Inflation Rate Exchange Rate ($Cdn/MMBtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) (%/Yr) ($US/$Cdn) 2017 3.46 11.15 28.43 49.92 72.11 2.0 0.750 2018 3.10 9.92 26.74 54.19 74.79 2.0 0.775 2019 3.27 10.52 26.25 56.25 78.75 2.0 0.800 2020 3.49 11.27 26.73 57.27 79.80 2.0 0.825 2021 3.67 11.87 27.59 59.12 82.37 2.0 0.850 2022 3.86 12.54 28.82 61.76 86.06 2.0 0.850 2023 4.05 13.20 30.06 64.41 89.32 2.0 0.850 2024 4.16 13.56 31.29 67.06 92.99 2.0 0.850 2025 4.24 13.83 32.53 69.71 97.59 2.0 0.850 2026 4.32 14.13 33.46 71.71 99.91 2.0 0.850 Thereafter +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 0.850 4 paintedpony.ca
Actual Weighted Average Prices In 2016, the Corporation received a weighted average price of $2.04 per Mcf for natural gas; and $43.49 per bbl for natural gas liquids, each of which is before transportation, marketing fees, royalties and hedging. 5 paintedpony.ca
RECONCILIATION OF CHANGES IN RESERVES The following table sets forth a reconciliation of GLJ s estimate of the Corporation s gross reserves as at December 31, 2016, to GLJ s estimates of the Corporation s gross reserves as at December 31, 2015, using the price forecasts in effect at the time of the relevant evaluation. Reconciliation of Corporate Gross Reserves by Product Type (Forecast Prices and Costs) Shale Gas Natural Gas Liquids Oil Equivalent Reserves Category and Factors (MMcf) (Mbbl) (Mboe) Proved Opening Balance December 31, 2015 1,829,583 31,709 336,639 Discoveries 0 0 0 Extensions and Improved Recovery (1) 533,792 9,850 98,815 Technical Revisions (2) 110,945 (3,529) 14,962 Acquisition 141,581 3,024 26,621 Dispositions (143,585) (1,864) (25,794) Economic Factors (3) 0 (630) (630) Production (4) (47,537) (570) (8,493) Closing Balance December 31, 2016 2,424,780 37,990 442,120 Probable Opening Balance December 31, 2015 2,322,760 44,284 431,410 Discoveries 0 0 0 Extensions and Improved Recovery (1) (228,191) (7,840) (45,872) Technical Revisions (2) (58,532) (4,204) (13,960) Acquisition 183,028 1,595 32,100 Dispositions (127,114) (1,549) (22,735) Economic Factors (3) 0 322 322 Production (4) 0 0 0 Closing Balance December 31, 2016 2,091,952 32,607 381,266 Proved Plus Probable Opening Balance December 31, 2015 4,152,343 75,992 768,049 Discoveries 0 0 0 Extensions and Improved Recovery (1) 305,601 2,010 52,943 Technical Revisions (2) 52,413 (7,733) 1,002 Acquisition 324,609 4,619 58,721 Dispositions (270,699) (3,413) (48,529) Economic Factors (3) 0 (308) (308) Production (4) (47,537) (570) (8,493) Closing Balance December 31, 2016 4,516,732 70,597 823,386 (1) The changes comprising Extensions and Improved Recovery were the result of expanded areas being attributed to proved and to proved plus probable reserves. Reserves moved out of probable are the result of change of category from probable to proved. (2) The positive Technical Revisions in the gas volumes are the result of better performance in the wells productivity. The negative Technical Revisions in the NGL volumes are the result of lower performance in the NGL yields. Reserves moved out of probable are the result of change of category from probable to proved. (3) The changes attributed to Economic Factors result from GLJ s price forecasts used in the 2016 Reserves Report being lower than GLJ s price forecasts used in the 2015 Reserves Report. (4) Represents the Corporation s actual production for the year ended December 31, 2016. 6 paintedpony.ca
Undeveloped Reserves ADDITIONAL INFORMATION RELATING TO RESERVES DATA The following table sets forth the volume of the proved undeveloped reserves and the probable undeveloped reserves, by product type, that were first attributed in each of the most recent three financial years, in aggregate. Undeveloped Reserves Year of First Attribution Proved Undeveloped Reserves Shale Gas (MMcf) Natural Gas Liquids (Mbbl) Probable Undeveloped Reserves Shale Gas (MMcf) Natural Gas Liquids (Mbbl) 2016 741,813 14,470 365,298 4,886 2015 1,084,759 20,279 509,470 16,232 2014 170,002 4,053 542,350 14,937 The Corporation has a large inventory of development opportunities and its capital spending activities are prioritized to optimize development plans, achieve strategic goals and maximize shareholder value. GLJ attributed proved undeveloped reserves to each future horizontal well location that is proximal to an existing well, to which GLJ has attributed proved developed reserves, via a singlewell step-out. In areas where existing wells with proved developed reserves demonstrate sufficient proved delineation of the resource, as determined by GLJ, additional infill horizontal well locations are assigned proved undeveloped reserves. GLJ has estimated these proved undeveloped reserves using forecast production rates that are based on a statistical analysis of production rates of existing wells operated by the Corporation or others in the regional area. GLJ attributed probable undeveloped reserves to each future horizontal well location that is proximal to an existing well, to which GLJ has attributed proved plus probable developed reserves, via a double-well step-out. In areas where existing wells with proved plus probable developed reserves demonstrate sufficient probable delineation of the resource, as determined by GLJ, additional infill horizontal well locations are assigned probable undeveloped reserves. GLJ has estimated these probable undeveloped reserves using forecast production rates that are based on a statistical analysis of production rates of existing wells operated by the Corporation or others in the regional area. The Corporation s development of its proved undeveloped and probable undeveloped reserves is limited primarily by capital, facility and infrastructure constraints. The Corporation plans to develop all of the proved undeveloped reserves within the next five years and all of the probable undeveloped reserves within the next ten years. Approximately 37% of the future development costs for proved reserves and 5% of the future development costs for probable reserves are scheduled to be incurred within the next two years. The Corporation s plans for the development of its proved undeveloped reserves and its probable undeveloped reserves and the timing of such development may change based on changes in geological, geophysical and engineering data and commodity prices and upon the characteristics of other potential investments that become available to the Corporation. 7 paintedpony.ca
Significant Factors or Uncertainties Affecting Reserves Data There are a number of important economic factors and significant uncertainties inherent in estimating the quantities of reserves and resources, including many factors beyond the control of the Corporation. In general, estimates of economically recoverable 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, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. For these reasons, estimates of the economically recoverable 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 expected therefrom, prepared by different engineers or by the same engineer at different times, may vary substantially. The actual production, revenues, taxes and development and operating expenditures of the Corporation with respect to these reserves will vary from such estimates, and such variances could be material. See also the Corporation s Annual Information Form under the heading Risk Factors. Estimates with respect to proved plus probable reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. Consistent with the securities disclosure legislation and policies of Canada, the Corporation has used forecast prices and costs in calculating reserve quantities. Actual future net cash flows will also be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. The reserve estimates contained herein are based on GLJ s production forecasts, prices and economic conditions at the time of preparation of the 2016 Reserves Report. The factors and assumptions that affect these reserve estimates include, among other things: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulations; and (viii) other government levies imposed over the life of the reserves. Future Development Costs The following tables sets out GLJ s estimates of the Corporation s future development costs of the proved reserves and the proved plus probable reserves. Future Development Costs (1) (Forecast Prices & Costs) (M$) Year Proved Reserves Proved Plus Probable Reserves 2017 328,885.3 376,493.8 2018 353,793.4 356,642.2 2019 467,859.3 467,859.3 2020 418,479.2 418,479.2 2021 254,715.0 304,950.7 Thereafter 1,584.6 992,265.5 Total (undiscounted) 1,825,316.7 2,916,690.7 (1) GLJ s estimate of future development costs excludes the Capital Leases. 8 paintedpony.ca
The Corporation expects that the funds required for future development costs will be obtained from the combination of internally-generated cash flow, credit facilities, and other available financing sources. There can be no guarantee that funds will be available or that the Corporation will allocate funding to develop all of the reserves attributed in the 2016 Reserves Report. Failure to develop these reserves would have a negative impact on future cash flow of the Corporation. Interest and other costs of external funding are not included in the future development costs of the reserves or in the future net revenue estimates and could reduce reserves and future net revenue to varying degrees depending upon the funding source utilized. The Corporation does not anticipate that interest or other funding costs would make development of any property uneconomic. Oil and Gas Properties and Wells OTHER OIL AND GAS INFORMATION The Corporation s important properties, plants and facilities are described in its Annual Information Form, into which this Statement of Reserves is incorporated by reference. Producing and Non-Producing Wells The following table sets out the Corporation s producing and non-producing natural gas wells as at December 31, 2016. Producing and Non-Producing Wells Natural Gas Wells Producing Non-Producing Location Gross Net Gross Net British Columbia 108.0 93.7 84.0 61.9 Properties with No Attributed Reserves The following table sets forth the Corporation s properties with no attributed reserves as at December 31, 2016. Properties with No Attributed Reserves (1) Unproved Properties Location Gross Acres Net Acres British Columbia 222,223 168,393 Alberta 24,423 24,423 Total 246,646 192,816 (1) Determined by Seaton-Jordan & Associates, an independent third party land evaluation specialist, effective December 31, 2016. The Corporation has no work commitments for 2017 on unproved properties. In the normal course of business, the Corporation submits continuation applications to the British Columbia Ministry of Natural Gas Development on expiring lands. The Corporation has 32,927 net acres which are scheduled to expire in 2017. Of these, 31,507 net acres are expected to be continued. 9 paintedpony.ca
Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves There are several economic factors and significant uncertainties that affect the anticipated development of the Corporation s properties with no attributed reserves. The Corporation will be required to make substantial capital expenditures in order to prove, exploit, develop and produce oil and natural gas from these properties in the future. If the Corporation s cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, that the terms will be acceptable to the Corporation. Failure to obtain such financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain opportunities and reduce its development. The inability of the Corporation to access sufficient capital for its exploration and development purposes could have a material adverse effect on the Corporation s ability to execute its business strategy to develop its prospects. See also the Corporation s Annual Information Form under the heading Risk Factors. The significant economic factors that affect the Corporation s development of its lands to which no reserves have been attributed are future commodity prices of natural gas and natural gas liquids (and the Corporation s outlook relating to such prices) and the future costs of drilling, completing, tying in and operating wells. The significant uncertainties that affect the Corporation s development of its lands are the future drilling and completion results the Corporation achieves in its development activities; drilling and completion results achieved by others on lands in proximity to the Corporation s lands; and future changes to applicable regulatory or royalty regimes that affect timing or economics of proposed development activities. All of these uncertainties have the potential to delay the development of such lands. Forward Contracts The Corporation enters into physical commodity contracts in the normal course of business. These contracts are not derivatives and are treated as executory contracts, which are recognized at cost at the time of transaction. As at December 31, 2016, the Corporation held the derivative commodity contracts summarized in the following table. Natural Gas Financial Contracts Financial AECO Natural Gas Contracts Reference Volume (GJ/d) Term Weighted Average Price ($/GJ) Options Traded CDN$ AECO 90,000 Q1 2017 2.87 Swaps CDN$ AECO 75,000 Q2 2017 2.85 Swaps CDN$ AECO 90,000 Q3 2017 2.86 Swaps CDN$ AECO 145,000 Q4 2017 2.89 Swaps CDN$ AECO 71,000 Q1 2018 2.93 Swaps CDN$ AECO 71,000 Q2 2018 2.85 Swaps CDN$ AECO 50,000 Q3 2018 2.81 Swaps CDN$ AECO 24,000 Q4 2018 2.72 Swaps CDN$ AECO 18,000 Q1 2019 2.64 Swaps CDN$ AECO 18,000 Q2 2019 2.64 Swaps CDN$ AECO 25,000 Q4 2017 Q4 2019 2.88 Call Options 10 paintedpony.ca
Financial Station 2 Natural Gas Contracts Reference Volume (GJ/d) Term Weighted Average Price ($/GJ) Options Traded CDN$ Station 2 75,000 Q1 2017 1.82 Swaps CDN$ Station 2 90,000 Q2 2017 1.90 Swaps CDN$ Station 2 100,000 Q3 2017 1.93 Swaps CDN$ Station 2 120,000 Q4 2017 2.07 Swaps CDN$ Station 2 105,000 Q1 2018 2.04 Swaps CDN$ Station 2 42,000 Q2 2018 2.38 Swaps CDN$ Station 2 37,000 Q3 2018 2.36 Swaps CDN$ Station 2 37,000 Q4 2018 2.36 Swaps CDN$ Station 2 37,000 Q1 2019 2.36 Swaps CDN$ Station 2 37,000 Q2 2019 2.36 Swaps CDN$ Station 2 25,000 Q3 2019 2.37 Swaps CDN$ Station 2 10,000 Q4 2019 2.45 Swaps Financial WTI Crude Oil Contracts Volume Weighted Average Options Reference (bbl/d) Term Price ($/bbl) Traded CDN$ WTI 500 Q1 2017 Q4 2017 70.05 Swaps CDN$ WTI 500 Q1 2018 Q4 2019 70.20 Swaps Tax Horizon The Corporation was not required to pay any cash income taxes for the year ended December 31, 2016. Actual taxes payable in the future will become a function of commodity prices, production volumes and capital expenditures combined with active tax planning. Based on after-tax economic forecasts for total proved reserves as prepared by GLJ, income taxes may become payable by the Corporation beginning in 2019. The Corporation has tax pools of $927 million, and management forecasts that the Corporation will not be taxable for at least the next four years. Costs Incurred The following table sets forth the property acquisition costs and the exploration costs and development costs for the year ended December 31, 2016. 2016 Acquisition, Exploration and Development Costs (M$) Property Acquisition Costs Exploration Costs Development Costs Proved Properties Unproved Properties ($386) - - $203,928 Exploration and Development Activities The following table sets forth a summary of the Corporation s exploration and development drilling activities for the year ended December 31, 2016. 2016 Exploration and Development Activities Exploratory Wells Development Wells Total Gross Net Gross Net Gross Net Natural Gas Wells - - 36 36.0 36 36.0 Total - - 36 36.0 36 36.0 11 paintedpony.ca
During 2017, the Corporation intends to drill 61 (61.0 net) and complete 61 (61.0 net) Montney natural gas development wells. There are no plans to drill exploration wells during 2017. Production Estimates The following table sets forth GLJ s forecast volumes of the Corporation s production from gross proved reserves and gross probable reserves as estimated in the 2016 Reserves Report. 2017 Production Estimates Reserves Category Shale Gas (Mmcf/d) Natural Gas Liquids (bbl/d) Oil Equivalent (boe/d) Gross Proved 234.2 3,954.0 42,987.3 Gross Probable 254.2 4,454.8 46,821.5 Production History The following table sets forth, by product type, the Corporation s share of average daily production, quarterly and for the year ended December 31, 2016. 2016 Quarterly Production History March 31, 2016 Three Months Ended June 30, 2016 Sept 30, 2016 Dec 31, 2016 Year Ended Dec 31, 2016 Shale Gas Production Volume (Mcf/d) (1) 94,494 93,828 129,316 201,111 129,881 Price 1.60 0.94 1.97 2.78 2.04 Royalties 0.05 0.01 0.04 0.05 0.04 Costs (2) 1.18 1.02 0.85 0.97 0.99 Netbacks (3) 0.37 (0.09) 1.08 1.76 1.01 Natural Gas Liquids Production Volume (bbl/d) (1) 852 996 1,189 3,177 1,557 Price 36.26 41.73 41.67 46.62 43.49 Royalties 0.91 1.11 1.15 1.25 1.16 Costs (2) 7.11 6.15 5.12 5.83 5.94 Netbacks (3) 28.24 34.47 35.40 39.54 36.39 (1) Production volume reflects the Corporation s share of average daily production volumes, before the deduction of royalties. (2) Costs include transportation costs and production operating costs. (3) Netbacks is a non-gaap measure calculated on a per unit basis as natural gas revenues or natural gas liquids revenues less royalties, operating costs and transportation costs. ADVISORIES Boe Conversions: Barrel of oil equivalent ( boe ) amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 Mcf) of natural gas to one barrel of oil (1 bbl). Boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 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. Mcfe Conversions: Thousands of cubic feet of gas equivalent ( Mcfe ) amounts have been calculated by using the conversion ratio of one barrel of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas. Mcfe amounts may be misleading, particularly if used in isolation. 12 paintedpony.ca
A conversion ratio of 1 bbl to 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Product Type: NI 51-101 requires a reporting issuer to disclose its reserves in accordance with the product types contained in NI 51-101, which product type includes conventional natural gas, shale rock and natural gas liquids. Shale gas as defined in NI 51-101 means natural gas: (i) contained in dense organic-rich rocks, including low-permeability shales, siltstones and carbonates, in which the natural gas is primarily adsorbed on the kerogen or clay minerals; and (ii) usually requires the use of hydraulic fracturing to achieve economic production rates. Shale gas is the NI 51-101 product type that most closely matches the natural gas from the Corporation s properties. Company Gross Reserves: Unless otherwise stated, references to reserves are to the Corporation s gross reserves, defined as the Corporation s working interest (operated or nonoperated) share before deduction of royalties and without including any royalty interests of the Corporation. Currency: All amounts are stated in Canadian dollars unless otherwise specified. Forecast Prices and Costs: Reserves estimates stated herein are calculated using the forecast price and cost assumptions by the reserves evaluator which were in effect at the time of the applicable reserves evaluation. The complete GLJ January 1, 2017 price forecast is available on its website at gljpc.com. At the time of the 2016 Reserves Report the Corporation s 2017 capital expenditure budget was $319 million. Forecast expenditures in future years may vary from actual expenditures. Estimated Future Net Revenue: Future net revenue is estimated after deduction of the estimated costs of abandonment of existing and future wells evaluated by GLJ in the 2016 Reserves Report and does not include well abandonment costs for wells to which reserves have not been attributed, or to abandonment and reclamation costs of facilities and pipelines. Estimates of future net revenue, whether discounted or not, do not represent fair market value. Future Development Costs: With respect to future development costs, there can be no guarantee that in the future, funds will be available or that the Corporation will allocate funds to develop all of the attributed reserves. Failure to develop these reserves would have a negative impact on future production and cash flow estimated by GLJ. Year-end 2016 future development costs excluded capital costs associated with the Capital Leases of the AltaGas Townsend Phase 2 Facilities. In 2016, the proved capital costs associated with the Capital Leases was $39 million (undiscounted). In 2016, proved plus probable capital costs associated with the Capital Leases was $107 million (undiscounted). Non-GAAP Financial Measures: This Statement of Reserves contains the term netbacks, which does not have a standardized meaning prescribed by Canadian generally accepted accounting principles ( GAAP ) and therefore may not be comparable with the calculation of similar measures for other entities. Netbacks are calculated on a per unit basis as natural gas revenues or natural gas liquids revenues less royalties, operating costs and transportation costs. Netbacks are used as a useful supplemental measure of a Corporation s profitability relative to commodity prices. Rounding: Numbers in tables may not add due to rounding. 13 paintedpony.ca
Forward-Looking Information: This Statement of Reserves contains certain forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to future events or future performance and is based upon the Corporation s current internal expectations, estimates, projections, assumptions and beliefs. All information other than historical fact is forward-looking information. Words such as plan, expect, intend, believe, anticipate, estimate, may, will, potential, proposed and other similar words that indicate events or conditions may occur are intended to identify forward-looking information. In particular, this Statement of Reserves contains forward looking information relating to: estimates of recoverable reserves volumes and the future net revenues associated with those reserves; the Corporation s development plans for its reserves, the anticipated costs in relation thereto, and the sources of funding for such costs; the anticipated expiry of the Corporation s rights to explore, develop and exploit its properties; the expected timing of the Corporation s tax obligations; production estimates; and the intention to drill and complete wells during 2017. Actual results could vary from forward-looking information; readers should not put undue reliance on forward looking information. Forward-looking information is based on assumptions including but not limited to future commodity prices, currency exchange rates, drilling success, production rates future capital expenditures and the availability of labor and services. With respect to estimates of reserves, a key assumption is that the data used by GLJ in their independent reserves evaluation is valid. With respect to future wells, a key assumption is the validity of geological and technical interpretations performed by the Corporation s technical staff, which indicate that commercially economic volumes can be recovered from the Corporation s lands. Estimates as to average annual production assume that no material unexpected outages occur in the infrastructure the Corporation relies upon to produce its wells, that existing wells continue to meet production expectations and that future wells scheduled to come on production in 2017 meet timing and production rate expectations. Undue reliance should not be placed on forward-looking information, as there can be no assurance that the plans, intentions or expectations on which they are based will occur. Although the Corporation s management believes that the expectations in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Forward-looking information necessarily involves both known and unknown risks associated with oil and gas exploration, production, transportation and marketing. There are risks associated with the uncertainty of geological and technical data, imprecision of reserve estimates, operational risks, risks associated with drilling and completions, environmental risks, risks of the change in government regulation of the oil and gas industry, risks associated with competition from others for scarce resources and risks associated with general economic conditions affecting the Corporation s ability to access sufficient capital. Additional information on these and other risk factors that could affect operational or financial results are included in the Corporation s most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities. Forward-looking information is based on estimates and opinions of management at the time the information is presented. The Corporation is not under any duty to, nor will it, update the forwardlooking information after the date of this Statement of Reserves to revise such information to actual results or to changes in the Corporation s plans or expectations, except as required by applicable securities laws. Any financial outlook contained herein, as such term is defined by applicable securities laws, is provided for the purpose of providing information about management s current expectations and 14 paintedpony.ca
plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. DEFINITIONS In this Statement of Reserves, the capitalized terms set forth below have the following meanings. Certain terms used but not defined herein, have the same meanings as set out in NI 51-101 and CSA Staff Notice 51-324, as applicable. 2015 Reserves Report means the independent evaluation dated March 2, 2016, prepared by GLJ, evaluating the Corporation s natural gas reserves as at December 31, 2015. 2016 Reserves Report means the independent evaluation dated February 27, 2017, prepared by GLJ, evaluating the Corporation s natural gas reserves as at December 31, 2016. AltaGas means AltaGas Ltd. Annual Information Form means the Corporation s annual information form dated March 2, 2017 for the year ended December 31, 2016. AltaGas Townsend Phase 2 Facilities means two facilities owned and operated by AltaGas in the Townsend area, each with a design capacity 99 MMcf/d, which are anticipated to be fully contracted by the Corporation. AltaGas Townsend Facilities means three facilities owned and operated by AltaGas, in particular: (1) the initial Townsend facility with design capacity of up to 198 MMcf/d; (2) a future second Townsend area facility, also with a design capacity of up to 198 MMcf/d; and (3) a pipeline interconnect from the Corporation s Blair area, transporting natural gas to the Townsend area. Capital Leases means, for the purpose of the 2016 Reserves Report, the capital lease costs representing the amortization of the capital lease obligations associated with the AltaGas Townsend Phase 2 Facilities, which for the purpose of the 2016 Reserves Report were scheduled separately; and for the purpose of the 2015 Reserves Report, the capital lease costs representing the amortization of the capital lease obligations associated with the AltaGas Townsend Facilities, which for the purpose of the 2015 Reserves Report were scheduled separately. COGE Handbook means the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary chapter), as amended from time to time. Corporation or Painted Pony means Painted Pony Petroleum Ltd. CSA Staff Notice 51-324 means the Canadian Securities Administrators Staff Notice 51-324 Glossary to NI 51-101. Forecast Prices and Costs means future prices and costs that are generally accepted as being a reasonable outlook of the future. GAAP means Canadian generally accepted accounting principles. GLJ means GLJ Petroleum Consultants Ltd., independent qualified reserves evaluators of Calgary, Alberta. 15 paintedpony.ca
Gross means: (a) (b) (c) in relation to the Corporation s interest in production or reserves, the Corporation s working interest (operated or non-operated) share before deduction of royalty obligations and without including any royalty interests of the Corporation; in relation to wells, the total number of wells in which the Corporation has an interest; and in relation to properties, the total area in which the Corporation has an interest. Montney means the Montney formation, a stratigraphic zone in the Western Canadian Sedimentary Basin. Net means: (a) (b) (c) in relation to the Corporation s interest in production or reserves, the Corporation s working interest (operating or non-operating) share after deduction of royalty obligations, plus the Corporation s royalty interests in such production or reserves; in relation to wells, the number of wells obtained by aggregating the Corporation s working interest in each of the Corporation s gross wells; and in relation to properties, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation. NI 51-101 means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Reserves means estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. (a) Reserves are classified according to the degree of certainty associated with the estimates: (i) (ii) (iii) 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; and Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. 16 paintedpony.ca
(b) Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories: (i) (ii) Developed Reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing; and 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 classification (proved, probable, possible) to which they are assigned. working interest means a percentage of ownership in an oil and gas property, obligating the owner to share in the costs of exploration, development and operations and granting the owner the right to share in production revenues after royalties are paid. Abbreviations ABBREVIATIONS, CONVERSIONS AND CONVENTIONS The abbreviations set forth below have the following meanings: Oil and Natural Gas Liquids bbls bbls/d Mbbls MMbbls boe boe/d Mboe MMboe NGLs LNG barrels barrels per day thousand barrels million barrels barrels of oil equivalent barrels of oil equivalent per day thousand barrels of oil equivalent million barrels of oil equivalent natural gas liquids liquefied natural gas Natural Gas Mcf Mcfe Mcfe/d MMcf MMcfe MMcfe/d Bcf Tcf Mcf/d MMcf/d m 3 GJ thousand cubic feet thousand cubic feet equivalent thousand cubic feet equivalent per day million cubic feet million cubic feet equivalent million cubic feet equivalent per day billion cubic feet trillion cubic feet thousand cubic feet per day million cubic feet per day cubic metres gigajoule Other AECO WTI M$ MM$ benchmark natural gas price determined at the AECO C hub in southeast Alberta West Texas Intermediate crude oil, a benchmark oil price determined at Cushing, Oklahoma thousands of dollars millions of dollars 17 paintedpony.ca
Conversions The following table sets forth certain Standard Imperial Units and International System of Units conversions. Convention From To Multiply By Mcf Mcf cubic metres bbls acres sections sections cubic metres GJ cubic feet cubic metres hectares acres hectares 28.174 1.055 35.494 0.159 0.405 640 256 Unless otherwise indicated, references herein to $ or dollars are to Canadian dollars. 18 paintedpony.ca
SCHEDULE "A" A-1
A-2
SCHEDULE "B" FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE Management of Painted Pony Petroleum Ltd. (the Corporation ) is responsible for the preparation and disclosure of information with respect to the Corporation s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2016, estimated using forecast prices and costs. An independent qualified reserves evaluator has evaluated the Corporation s reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report. The Reserves Committee of the Board of Directors of the Corporation has: (a) reviewed the Corporation s procedures for providing information to the independent qualified reserves evaluator; (b) (c) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and reviewed the reserves data with management and the independent qualified reserves auditor. The Reserves Committee of the Board of Directors has reviewed the Corporation s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved: (a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; (b) (c) the filing of Form 51-101F2, which is the report of the independent qualified reserves evaluator on the reserves data; and the content and filing of this report. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery. DATE: March 2, 2017 signed Patrick R. Ward Patrick R. Ward President, Chief Executive Officer and Director signed Glenn R. Carley Glenn R. Carley Director and Chairman of the Board signed L. Barry McNamara L. Barry McNamara Vice President, Corporate Development and Marketing signed Lynn Kis Lynn Kis Director and Chair of the Reserves Committee B-1