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Painted Pony Announces 6.9 Tcfe of Proved Plus Probable Reserves, Record Annual Production and Adjusted Funds Flow from Operations, and 2017 Year-End Financial and Operating Results

Canada NewsWire

CALGARY, March 7, 2018 /CNW/ - Painted Pony Energy Ltd. ("Painted Pony" or the "Corporation") (TSX: PONY) is pleased to announce that Proved Plus Probable reserves as at December 31, 2017 were 6.9 Tcfe representing year-over-year growth of 40%, record annual average daily production of 257 MMcfe/d (42,882 boe/d) complimented by a 93% increase in adjusted funds flow from operations to a Corporation record of $108 million, and 2017 year-end financial and operational results. 

Painted Pony Energy Ltd. (CNW Group/Painted Pony Energy Ltd.)

2017 Reserve Highlights:

  • Increased Proved Developed Producing reserves by 64% to 797 Bcfe at year-end 2017 from 484 Bcfe at year-end 2016;

  • Increased Proved Developed Producing net present value by 28% or $200 million to $905 million ($5.62 per share) compared to December 31, 2016 at a 10% discount rate using pricing from independent qualified reserves evaluators, GLJ Petroleum Consultants Ltd. ("GLJ");

  • Generated a finding, development and acquisition ("FD&A") Proved Developed Producing recycle ratio of 1.1 times, while finding and development ("F&D") Proved Developed Producing costs produced a recycle ratio of 1.6 times;

  • Replaced 432% of 2017 production volumes through Proved Developed Producing reserve additions of 313 Bcfe, including 10 MMbbls of natural gas liquids ("NGL");

  • Increased Total Proved reserves by 17% to 3.1 Tcfe, including 31 MMbbls of natural gas liquids, at year-end 2017 compared to 2.7 Tcfe at year end 2016;

  • Generated an FD&A Total Proved recycle ratio of 1.6 times, inclusive of changes in future development capital ("FDC");

  • Increased Proved Plus Probable reserves by 40% to 6.9 Tcfe, including 73 MMbbls of natural gas liquids, at year-end 2017 from 4.9 Tcfe at year end 2016; and

  • Generated an FD&A Proved Plus Probable recycle ratio of 1.9 times, inclusive of FDC.

2017 Fourth Quarter and Full Year Financial Highlights

  • Achieved record annual adjusted funds flow from operations for Painted Pony of $108 million ($0.76 per share) in 2017 compared to $56 million ($0.56 per share) during 2016, an increase of 93% (36% per share);

  • Increased adjusted funds flow from operations during the fourth quarter of 2017 by 33% to $35 million compared to $27 million during the fourth quarter of 2016; and

  • Underspent fourth quarter capital by $11 million or 15%, spending $62 million compared to capital spending guidance of $74 million as released on November 8, 2017.

2017 Fourth Quarter and Full-Year Production Highlights

  • Increased fourth quarter 2017 average daily production volumes by 43% to 315 MMcfe/d (52,544 boe/d), which includes the impact of approximately 48 MMcfe/d (8,000 boe/d) of voluntary pricing-related production shut-ins, compared to 2016 average daily production volumes of 220 Mcfe/d (36,695 boe/d);

  • Averaged annual daily production volumes of 257 MMcfe/d (42,882 boe/d) during 2017, an 85% increase over 2016 annual average daily production of 139 MMcfe/d (23,204 boe/d); and

  • NGL annual average daily production volumes increased by 130% to 3,587 bbls/d during 2017 compared to 1,557 bbls/d during 2016.

Patrick Ward, President and CEO of Painted Pony, in commenting on these highlights said, "Despite a very challenging commodity price environment, 2017 operations lifted Painted Pony to almost 7 Tcfe of Proved Plus Probable reserves with a net present value of $3.3 billion or $20.43 per share at a 10% discount rate using our independent reserve evaluator's pricing. We are particularly pleased with the 64% growth in our Proved Developed Producing reserves. Painted Pony achieved some notable records for the Corporation in 2017.  Annual average daily production at over 257 MMcfe/d or 42,882 boe/d and adjusted funds flow from operations of $108 million are both records for Painted Pony and significant milestones for the Corporation of which we are very proud."

SUMMARY OF 2017 RESERVES AS PREPAR ED BY GLJ PETROLEUM CONSULTANTS
2017 Summary of Reserves
GLJ, independent qualified reserves evaluators, prepared an evaluation of Painted Pony's properties effective December 31, 2017, which is contained in a report dated March 6, 2018.  

Proved Developed Producing
During 2017, Painted Pony increased Proved Developed Producing reserves by 64% to 797 Bcfe (133 MMboe) at an FD&A cost of $1.40 per Mcfe.  The Corporation's Proved Developed Producing reserve additions replaced 2017 average daily production by 4.3 times.

Total Proved
During 2017, Painted Pony increased Total Proved reserves by 17% to 3.1 Tcfe (518 MMboe) at an FD&A cost of $0.96 per Mcfe. The Corporation's Total Proved reserve additions replaced 2017 average daily production by 5.9 times.

Proved Plus Probable
During 2017, Painted Pony increased Proved Plus Probable reserves by 40% to 6.9 Tcfe (1,149 MMboe) at an FD&A cost of $0.82 per Mcfe. The Corporation's Proved Plus Probable reserve additions replaced 2017 average daily production by 21.8 times.

2017 FINDING, DEVELOPMENT & ACQUISITION COSTS AND RECYCLE RATIOS
In 2017, the Corporation generated an FD&A Total Proved recycle ratio, inclusive of FDC, of 1.6 times. This is calculated as per the table below.  The operating netback of $1.54 /Mcfe, which has been adjusted to include the cost of the finance lease expense related to the AltaGas Ltd. facility at Townsend ("AltaGas Townsend Facility"), is divided by the FD&A costs, including changes in FDC, of $0.96/Mcfe on a Total Proved basis.

($/Mcfe)

2017

Revenue

2.65

Realized Gain on Risk Management Contracts

0.47

Revenue including Realized Gain on Risk Management Contracts

3.12


Royalties

(0.05)


Operating Expenses

(0.64)


Transportation Costs

(0.42)

Operating Netback

2.01


Finance Lease Expense for AltaGas Townsend Facility

(0.47)

Operating Netback including Finance Lease Expense

1.54

Note: See Non-GAAP disclosure in Advisory section


 

The following tables outline GLJ's estimates of Painted Pony's reserves at December 31, 2017 and December 31, 2016:

Summary of Company Working Interest Reserves
(Numbers in this table may not add due to rounding)  





December 31, 2017

December 31, 2016


Natural Gas
(Bcf)

NGLs
(MMbbls)

Natural Gas
Equivalent
(Bcfe)

Oil
Equivalent
(MMboe)

Natural Gas
Equivalent
(Bcfe)

Proved Developed Producing

733.7

10.5

796.6

132.8

484.4

Proved Developed Non-Producing

14.7

-

14.7

2.5

4.5

Proved Undeveloped

2,175.7

20.5

2,298.9

383.1

2,163.8

Total Proved

2,924.2

31.0

3,110.2

518.4

2,652.7

Total Probable

3,530.8

42.0

3,782.8

630.5

2,287.6

Total Proved Plus Probable

6,454.9

73.0

6,893.0

1,148.8

4,940.3

See the advisories with respect to resource definitions.

 

The following tables outline GLJ's estimates of Painted Pony's associated net present values of reserves at December 31, 2017:

Net Present Values of Future Net Revenue (1)(2)

(Forecast Prices and Costs; Numbers in this table may not add due to rounding) ($Millions)


As at December 31, 2017

Annual Discount Rate

0%

5%

10%

15%

BEFORE INCOME TAXES





Proved






Developed Producing

1,587.1

1,154.8

905.4

747.8


Developed Non-Producing

15.9

11.7

9.1

7.3


Undeveloped

2,418.7

1,318.3

725.0

382.8

Total Proved

4,021.7

2,484.7

1,639.5

1,138.0

Probable

6,953.0

3,187.6

1,650.1

932.7

Total Proved Plus Probable

10,974.7

5,672.3

3,289.6

2,070.7

1.

Estimates of future net revenue, whether discounted or not, do not represent fair market value.

2.

Future net revenue is after deduction of estimated costs of abandonment and reclamation of existing and future wells that were evaluated by GLJ in the 2017 Reserves Evaluation and does not include costs of abandonment and reclamation of facilities.

 

Reconciliation of Company Gross Reserves

(Forecast Prices and Costs; Numbers in this table may not add due to rounding)


Natural Gas
(Shale Gas)

NGLs

Total

Total


(Bcf)

(MMbbl)

(MMboe)

(Bcfe)

Proved Developed Producing Reserves





Opening Balance December 31, 2016

443.6

6.8

80.7

484.4

Discoveries

-

-

-

-

Extensions and Improved Recovery (1)

286.9

5.3

53.1

318.7

Technical Revisions

3.3

(0.4)

0.2

1.2

Economic Factors (2)

(6.6)

(0.1)

(1.2)

(7.1)

Dispositions

-

-

-

-

Acquisitions (3)

92.5

0.1

15.6

93.6

Production (4)

(86.1)

(1.3)

(15.7)

(93.9)

Closing Balance December 31, 2017

733.7

10.5

132.8

796.6

Proved Reserves





Opening Balance December 31, 2016

2,424.8

38.0

442.1

2,652.7

Discoveries

-

-

-

-

Extensions and Improved Recovery (1)

75.1

0.9

13.5

80.8

Technical Revisions

(77.9)

(6.6)

(19.6)

(117.4)

Economic Factors (2)

(31.3)

(0.3)

(5.5)

(33.2)

Dispositions

-

-

-

-

Acquisitions (3)

619.6

0.3

103.5

621.2

Production (4)

(86.1)

(1.3)

(15.7)

(93.9)

Closing Balance December 31, 2017

2,924.2

31.0

518.4

3,110.2

Proved Plus Probable Reserves





Opening Balance December 31, 2016

4,516.7

70.6

823.4

4,940.3

Discoveries

-

-

-

-

Extensions and Improved Recovery (1)

66.7

0.3

11.5

68.8

Technical Revisions

126.1

(6.7)

14.3

85.8

Economic Factors (2)

(55.1)

(0.5)

(9.7)

(58.0)

Dispositions

-

-

-

-

Acquisitions (3)

1,886.5

10.6

325.0

1,950.1

Production (4)

(86.1)

(1.3)

(15.7)

(93.9)

Closing Balance December 31, 2017

6,454.9

73.0

1,148.8

6,893.0

(1)

The changes comprising "Extensions and Improved Recovery" were the result of expanded areas being attributed to Proved and to Proved Plus Probable reserves.

(2)

The changes attributed to "Economic Factors" result from GLJ's price forecasts used in the 2017 Reserves Report being lower than GLJ's price forecasts used in the 2016 Reserves Report.

(3)

Represents the reserves acquired pursuant to the acquisition of UGR Blair Creek Ltd.

(4)

Represents the Corporation's actual production for the year ended December 31, 2017.


 

Painted Pony uses the measure of recycle ratios as a measure of the Corporation's ability to grow reserves profitably and invest capital efficiently. The recycle ratio is calculated by dividing the annual corporate operating netback by the annual finding, development and acquisition cost, both on a per unit basis.  The higher the recycle ratio, the more efficient the Corporation has been in deploying capital to grow reserves.  The Corporation also uses the 3-year weighted average recycle ratio, which smooths out yearly fluctuations by dividing the 3-year weighted average operating netback by the 3-year weighted average finding, development and acquisition cost, both on a per unit basis. The following table highlights Painted Pony's capital program  efficiency and the resulting recycle ratios.

Capital Efficiencies (1)

(Forecast Prices and Costs)



Proved Developed Producing

2017

3-Year Weighted Avg.


Finding, Development & Acquisition Cost ($/Mcfe)

$1.40

$1.14



Recycle Ratio                                                 

1.1x

1.3x

Proved




Finding, Development & Acquisition Cost ($/Mcfe)

$0.96

$0.79



Recycle Ratio

1.6x

1.8x

Proved Plus Probable




Finding, Development & Acquisition Cost ($/Mcfe)

$0.82

$0.45



Recycle Ratio

1.9x

3.2x

(1)

See advisories with respect to finding, development & acquisition costs.

 

Future Development Costs of Undeveloped Reserves

(Forecast Prices and Costs)


Total Proved Undeveloped

As at December 31

2017

2016

Net Total Proved Undeveloped Wells

368

339

Total Proved Future Development Capital ($Millions)

1,847

1,825

Reserves (Bcfe)

3,110

2,164

Total Proved Future Development Capital per Mcfe

$0.59

$0.84




(Forecast Prices and Costs)


Proved Plus Probable Undeveloped

As at December 31

2017

2016

Net Proved Plus Probable Undeveloped Wells

759

548

Proved Plus Probable Future Development Capital ($Millions)

4,133

2,917

Reserves (Bcfe)

6,893

4,317

Proved Plus Probable Future Development Capital per Mcfe

$0.60

$0.68

 

2017 FINANCIAL AND OPERATING RESULTS
Capital Expenditures
Painted Pony invested a total of $303 million during 2017 into the Corporation's Montney assets.  Activities included the drilling of 52 (52.0 net) wells, the completion of 51 (51.0 net) and minor investments into associated facilities and infrastructure.

During the fourth quarter of 2017, Painted Pony drilled 7 (7.0 net) and completed 15 (15.0 net) wells, and executed a capital program of $62 million, which was lower than planned spending of $74 million per Painted Pony's guidance.

Production
The Corporation's 2017 annual average daily production increased by 85% to 257 MMcfe/d (42,882 boe/d) over 2016 annual average daily production volumes of 139 MMcfe/d (23,204 boe/d).  Painted Pony increased fourth quarter 2017 production volumes by 43% to 315 MMcfe/d (52,544 boe/d) compared to fourth quarter 2016 production volumes of 220 MMcfe/d (36,695 boe/d). 

The production volume increase during 2017 was driven by production additions from successful new drills in the Blair Creek, Townsend and Daiber areas, the commissioning of the AltaGas Townsend Facility expansion in the third quarter of 2016, and the acquisition of UGR Blair Creek Ltd.

Painted Pony's increase in liquids production volumes by 130% to 3,587 bbls/d in 2017 compared to 1,557 bbls/d in 2016 reflects the impact of a full year of liquids-rich processing capacity of the Townsend Facility that came on-line during the third quarter of 2016. Production volumes during the fourth quarter of 2017 were impacted by approximately 48 MMcfe/d (8,000 boe/d) of voluntary pricing-related production shut-ins.

Adjusted Funds Flow from Operations
Adjusted funds flow from operations increased to $108 million during 2017, compared to adjusted funds flow from operations of $56 million in the year ended December 31, 2016.  The increase in adjusted funds flow from operations is the result of an 85% increase in production volumes, a 24% increase in per unit realized gains on risk management contracts, and an 11% increase in realized commodity prices, offset by a 7% increase in costs per unit.

Painted Pony's adjusted funds flow from operations increased to $35 million during the fourth quarter of 2017, an increase of 33%, compared to adjusted funds flow from operations of $27 million during the fourth quarter of 2016.

The increase in adjusted funds flow from operations was largely the result of a 43% fourth quarter over fourth quarter increase in average daily production volumes including a 44% increase in liquids production to 4,575 bbls/d during the fourth quarter of 2017 from 3,177 bbls/d during the fourth quarter of 2016.

2018 CAPITAL PROGRAM
The 2018 capital budget strategy is to deliver a capital program that approximately matches internally generated adjusted funds flow from operations. Painted Pony closely monitors commodity prices and the impact forward strip prices may have on near-term adjusted funds flow from operations to ensure forecasted levels of capital spending align with the Corporation's stated 2018 capital spending strategy.  

CFO Appointment
Mr. Stuart Jaggard, Vice President, Finance, is appointed Chief Financial Officer of the Corporation on March 7, 2018. Mr. Jaggard joined Painted Pony as Vice President and Controller in October 2014. He has over 30 years of experience in the oil and gas industry, obtaining his Chartered Accountant designation in 1985. He held various senior finance positions within the oil and gas industry prior to joining Painted Pony. Mr. Jaggard worked in the audit practice of KPMG LLP from 1982 to 1995.

Mr. Jaggard completed his Bachelor of Commerce degree at the University of Calgary in 1982. He is a member of CPA Canada and CPA Alberta.

FINANCIAL AND OPERATIONAL HIGHLIGHTS




Years ended December 31,

($ millions, except per share and shares outstanding)

2017

2016

Change

Financial




Petroleum and natural gas revenue(1)

249.2

121.6

105%

Cash flow from operating activities

106.9

44.7

139%


Per share - basic(3)

0.76

0.45

69%


Per share - diluted(4)

0.74

0.45

64%

Adjusted funds flow from operations(2)

107.5

55.6

93%


Per share - basic(3)

0.76

0.56

36%


Per share - diluted(4)

0.75

0.56

34%

Net income (loss) and comprehensive income (loss)

122.4

(51.9)


Per share - basic(3)

0.87

(0.52)


Per share - diluted(4)

0.85

(0.52)

Capital expenditures

302.6

204.4

48%

Working capital (deficiency) (5)

33.0

(73.6)

Bank debt

149.2

200.8

(26)%

Senior notes

141.6

Convertible debentures - liability

44.9

Net debt (6)

363.9

228.5

59%

Total assets

2,031.6

1,337.0

52%

Shares outstanding (millions)

161.0

100.2

61%

Basic weighted-average shares (millions)

140.7

100.1

41%

Fully diluted weighted-average shares (millions)

144.1

100.1

44%

Operational




Daily production volumes





Natural gas (MMcf/d)

235.8

129.9

82%


Natural gas liquids (bbls/d)

3,587

1,557

130%


Total (MMcfe/d)

257.3

139.2

85%


Total (boe/d)

42,882

23,204

85%

Realized commodity prices





Natural gas ($/Mcf)

2.13

2.04

4%


Natural gas liquids ($/bbl)

50.53

43.49

16%


Total ($/Mcfe)

2.65

2.39

11%

Operating netbacks ($/Mcfe)(7)

2.01

1.73

16%

(1)

Before royalties.

(2)

Adjusted funds flow from operations and adjusted funds flow from operations per share (basic and diluted) are non-GAAP measures used to represent cash flow from operating activities before the effects of changes in non-cash working capital, share unit expense and decommissioning expenditures.  Adjusted funds flow from operations per share is calculated by dividing adjusted funds flow from operations by the weighted average number of basic or diluted shares outstanding in the period. See "Non-GAAP Measures"  in Management Discussion and Analysis for the year ended December 31, 2017.

(3)

Basic per share information is calculated on the basis of the weighted average number of shares outstanding in the period.

(4)

Diluted per share information reflects the potential dilutive effect of stock options and convertible debentures.

(5)

Working capital deficiency is a non-GAAP measure calculated as current assets less current liabilities. See "Non-GAAP Measures" in Management Discussion and Analysis for the year ended December 31, 2017.

(6)

Net debt is a non-GAAP measure calculated as bank debt, senior notes, liability portion of convertible debentures, and working capital deficiency, adjusted for the net current portion of fair value of risk management contracts and current portion of finance lease obligation. See "Non-GAAP Measures" in Management Discussion and Analysis for the year ended December 31, 2017.

(7)

Operating netbacks is a non-GAAP measure calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or losses on risk management, less royalties, operating expenses and transportation costs. See "Non-GAAP Measures" and "Operating Netbacks" in Management Discussion and Analysis for the year ended December 31, 2017.

 

DEFINITIONS AND ADVISORIES
Reserves Categories:  Reserves are 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 (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.  Reserves are classified according to the degree of certainty associated with the estimates.

  • "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. Proved reserves should have at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

  • "Probable reserves" 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. Probable reserves should have at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

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.

Mcfe, Bcfe and Tcfe Conversions: Thousands of cubic feet of gas equivalent ("Mcfe"), billions of cubic feet of gas equivalent ("Bcfe") and trillions of cubic feet of gas equivalent ("Tcfe") 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, Bcfe and Tcfe amounts may be misleading, particularly if used in isolation. 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.

Independent Reserves Evaluation

GLJ Petroleum Consultants ("GLJ"), independent qualified reserves evaluators of Calgary, Alberta, prepared a reserves estimation and economic evaluation of the Corporation's oil and natural gas properties effective December 31, 2017, which is contained in a report dated March 6, 2018 (the "2017 Reserves Report"). GLJ prepared reserves estimations and economic evaluations of the Corporation's reserves effective December 31, 2017. Reserves estimates stated herein as at December 31 of a year are extracted from the relevant evaluation.

The 2017 Reserves Report and the prior reserves evaluation were prepared in accordance with the standards contained in the Canadian Oil & Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), which were in effect at the time of the evaluation.

The reserves data provided in this press release contains only excerpts of the disclosure required under NI 51-101. All of the required information will be contained in the Corporation's Annual Information Form for the year ended December 31, 2017, which is filed on SEDAR on March 7, 2018.

Finding and Development Costs: With respect to disclosure of finding and development ("F&D") costs and finding, development and acquisition costs ("FD&A") costs disclosed in this press release:

  • F&D costs both including and excluding acquisitions and dispositions have been presented in this press release. While NI 51-101 requires the calculation of F&D costs to eliminate the effects of acquisitions and dispositions, FD&A costs have also been presented because acquisitions and dispositions can have a significant impact on the Corporation's ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Corporation's cost structure.

  • F&D costs for 2017 are calculated by dividing the total of the exploration costs, development costs and the change during the most recent financial year in estimated future development capital relating to either proved reserves or probable reserves, by the additions to either proved reserves or probable reserves during the most recent financial year.

  • The aggregate of the exploration and development costs incurred in the most recent financial year and any change during that year in estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year.

Recycle Ratios:  Recycle ratios are calculated by dividing the average operating netback per boe of Mcfe, or funds flow netback per boe or Mcfe, by F&D costs and FD&A costs, as applicable.  Recycle ratios may be used as a measure of a company's profitability. 

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 types include 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-rick rocks, including low-permeability shales, siltstones and carbonites, in which the natural gas is primarily absorbed 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.

Currency: All amounts referred to in this press release 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 2017 Reserves Evaluation the Corporation's 2018 capital expenditure budget was $185 million. Forecast expenditures in future years may vary from actual expenditures.

Company Gross Reserves: In this press release, unless otherwise stated, references to "reserves" are to the Corporation's gross reserves, defined as the Corporation's working interest (operated or non- operated) share before deduction of royalties and without including any royalty interests of the Corporation.

Rounding:  Numbers in tables may not add due to rounding.

Estimated Future Net Revenues: Estimated future net revenues are stated before deducting income taxes and future estimated site restoration costs and are reduced for estimated future abandonment costs and estimated capital for future development associated with the reserves. The undiscounted and discounted net present values disclosed do not represent the fair market value of the reserves.

Reserves for Portion of Properties: With respect to the disclosure of reserves contained herein relating to portions of the Corporation's properties, the estimates of reserves and future net revenue for 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.

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. 

Forward-Looking Information: This press release 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 press release contains forward looking information relating to estimates of recoverable reserves volumes and the future net revenues associated with those reserves; future development costs, forecasts of future price and costs, and the 2018 capital program.

Forward-looking information is based on certain expectations and assumptions including but not limited to future commodity prices, currency exchange rates interest rates, royalty rates and tax rates; the state of the economy and the exploration and production business; the economic and political environment in which the Corporation operates; the regulatory framework; anticipate timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned operations; operating, transportation, marketing and general and administrative costs; drilling success, production rates, future capital expenditures and the availability of labor and services. 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 and exit 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 the remainder of 2018 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. As a consequence, actual results may differ materially from those anticipated.

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, 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 update the forward-looking information after the date of this press release 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 in this press release, as such term is defined by applicable securities laws, is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes

Non-GAAP Measures: This press release makes reference to the terms "adjusted funds flow from operations", "adjusted funds flow from operations per share", "adjusted funds flow from operations per Mcfe", "working capital deficiency", "net debt" and "operating netbacks", which do not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures presented by other issuers.

Management uses "adjusted funds flow from operations" to analyze operating performance and considers adjusted funds flow from operations to be a key measure as it demonstrates the Corporation's ability to generate the cash necessary to fund future capital investment and to repay debt. Adjusted funds flow from operations denotes cash flow from operating activities before the effects of changes in non-cash working capital, share unit expense and decommissioning expenditures. "Adjusted funds flow from operations per share" is calculated using the basic and diluted weighted average number of shares for the period. "Adjusted funds flow from operations per Mcfe" is calculated using the average production volumes for the period.  For the year ended December 31, 2017, adjusted funds flow from operations, adjusted funds flow from operations per share and adjusted funds flow from operations per Mcfe are presented net of UGR acquisition costs. These terms should not be considered alternatives to, or more meaningful than, cash flows from operating activities as determined in accordance with IFRS as an indicator of the Corporation's performance.

Management uses "working capital deficiency" and "net debt" as useful supplemental measures of the liquidity of the Corporation. Working capital deficiency is calculated as current assets less current liabilities. Net debt is calculated as bank debt, senior notes, liability portion of convertible debentures, and working capital deficiency, adjusted for the net current portion of fair value of risk management contracts and current portion of finance lease obligation. These terms should not be considered alternatives to, or more meaningful than, current and long-term debt as determined in accordance with IFRS.

"Operating netback" and "operating netback including finance lease expense" are used as a supplemental measure of the Corporation's profitability relative to commodity prices. Operating netback is calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or losses on risk management contracts, less royalties, operating expenses and transportation costs. Operating netback including finance lease expense is calculated on a per unit basis as operating netback per unit less finance lease expense for AltaGas Townsend Facility.  These terms should not be considered alternatives to, or more meaningful than net income (loss) and comprehensive income (loss) as determined in accordance with IRFS.

Management of the Corporation believes these measures are useful supplemental measures of the net position of current assets and current liabilities of the Corporation and the profitability relative to commodity prices. Readers are cautioned, however, that these measures should not be construed as alternatives to other terms such as current and long-term debt or comprehensive income determined in accordance with IFRS as measures of performance. The Corporation's method of calculating these non-GAAP measures may differ from other companies, and accordingly, may not be comparable to similar measures used by other entities.  Please see the "Non-GAAP Measures" section of the Corporation's management's discussion and analysis of the consolidated financial results of the Corporation for the year ended December 31, 2017.

ABOUT PAINTED PONY
Painted Pony is a publicly-traded natural gas company based in Western Canada.  The Corporation is primarily focused on the development of natural gas and natural gas liquids from the Montney formation in northeast British Columbia.  Painted Pony's common shares trade on the TSX under the symbol "PONY".

SOURCE Painted Pony Energy Ltd.

View original content with multimedia: http://www.newswire.ca/en/releases/archive/March2018/07/c7327.html

Patrick R. Ward, President and Chief Executive Officer; Stuart Jaggard, Vice President, Finance; Jason W. Fleury, Director, Investor Relations, (403) 776-3261; (403) 475-0440, 1-877-975-0440 toll free, [email protected], www.paintedpony.caCopyright CNW Group 2018


Source: Canada Newswire (March 7, 2018 - 6:02 PM EST)

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