Painted Pony announces 4.6 Tcfe of Proved Plus Probable reserves, 2.0 Tcfe of Proved Reserves and 2015 Operating and Financial Results

CALGARY, March 2, 2016 /CNW/ - Painted Pony Petroleum Ltd. ("Painted Pony" or the "Corporation") (TSX: PPY) continues to deliver industry leading finding and development costs ("F&D") while building substantial reserves and value for shareholders. The Corporation is a BC Montney natural gas producer with production expected to rapidly increase to a 2016 exit rate in excess of 240.0 MMcfe/d (40,000 Boe/d). This production increase is made possible through the commissioning of the AltaGas Townsend Facility (the "Facility"), which will provide the necessary processing capacity for Painted Pony to accelerate the realization of significant value from its reserves, during the second half of 2016. 

Highlights:

  • Increasing Proved ("1P") reserves by 175% to 2.0 Tcfe (337 MMboe) at December 31, 2015;
  • Increasing Proved Plus Probable ("2P") reserves by 57% to 4.6 Tcfe (768 MMboe) at December 31, 2015;
  • Adding 2P reserves in 2015 at an F&D cost of $0.16/Mcfe ( $0.98/boe);
  • Generating an F&D recycle ratio of 7.5 times for 2P reserves and 1.5 times for 1P reserves based on a 2015 corporate netback of $1.23/Mcfe ($7.38/Boe);
  • Increasing to $2.9 billion and $1.4 billion the estimated 2P and 1P, respectively, net present values at December 31, 2015 discounted at 10% ("NPV10");
  • Reducing cash operating costs (royalties, operating expenses and transportation costs) by 32% to $1.36/Mcfe in 2015 from $2.00/Mcfe in 2014;
  • Generating net earnings of $2.6 million during the fourth quarter of 2015 compared to a net loss of $3.4 million in the fourth quarter of 2014;
  • Increasing average 2P undeveloped reserve booking per well to 8.8 Bcfe, an approximate 25% increase over 2014.

Patrick Ward, President and CEO of Painted Pony, in commenting on these highlights said, "Decreasing FDC per Mcfe, improved well production performance, and decreasing costs will continue to drive Painted Pony's ability to grow economically in a low price environment, with a fully funded capital program."

OPERATIONS

Townsend Facility Update

The Townsend Facility is a 198 MMcf per day natural gas processing facility being constructed by AltaGas and is located approximately 100 kilometers northwest of Fort St. John. Painted Pony has reserved all of the firm capacity of the Facility under a take-or-pay agreement. AltaGas confirms that construction of the Facility is approximately 75% complete. AltaGas has indicated the Facility is on track to be in service by mid-2016, which is earlier than budgeted by the Corporation.

Current Operations

To date in 2016, Painted Pony has drilled a total of 7 (7.0 net) new wells and completed 4 (4.0 net) new wells. Prior to spring break-up, a further 6 (6.0 net) wells are expected to be drilled and an additional 10 (10.0 net) wells are expected to be completed and production tested. The Corporation currently has 3 active drilling rigs and intends to drill a total of 30 (29.0 net) wells and complete a total of 26 (26.0 net) wells in 2016. The majority of this activity is focused on developing the production volumes to supply the AltaGas Townsend Facility, which is expected to commence operations in the second half of 2016.

SUMMARY OF 2015 RESERVES AS PREPARED BY GLJ PETROLEUM CONSULTANTS

Over the past five years, Painted Pony's Blair-Townsend Montney property has emerged as a world-class natural gas asset. Painted Pony has 217 net sections of Montney rights covering the Blair-Townsend area. The Montney reservoir at Blair-Townsend contains over 300 meters (1,000 feet) of highly over-pressured, gas-saturated pay on high working interest land. These features, combined with Painted Pony's successful drilling and completion program, have resulted in significant reserves growth while continuing to de-risk the resource. For the third consecutive year, technology driven well-performance improvements during 2015 drove positive technical revisions which accounted for 50% of total 2P reserve additions and 52% of total 1P reserve additions, all without requiring an increase in FDC.

2015 Summary of Reserves

Effective December 31, 2015, Painted Pony increased 2P reserves by 57% to 4.6 Tcfe (768 MMboe) and increased 1P reserves by 175% to 2.0 Tcfe (337 MMboe). As a result, 2P reserves per share increased to 46.1 Mcfe/share (7.7 Boe/share) at year end 2015 from 29.5 Mcfe/share (4.9 Boe/share) at year end 2014. The estimated net present value of 2P reserves at December 31, 2015 discounted at 10% ("NPV10") increased by 12% to $2.9 billion over year end 2014 despite significantly lower commodity price assumptions.

The Corporation's 2P reserve additions replaced 2015 average daily production of 15,604 boe/d by more than 5,000%. The Corporation has a reserve life index ("RLI") of 140 years on a 2P basis and 61 years on a 1P basis, based on fourth quarter 2015 annualized production of 15,043 boe/d.  Continued improvements in well productivity from the application of advanced drilling and completion technologies led to positive 2P technical revisions of 864 Bcfe (144 MMboe).

The following tables outline GLJ's estimates of Painted Pony's reserves and associated net present values at December 31, 2015 and December 31, 2014:

Summary of Company Gross Reserves

(Forecast Prices and Costs)


 

 

Reserves Category

As at December 31, 2015

As at December 31, 2014

Natural Gas(1)

(Bcf)

NGLs

(MMbbl)

Oil Equivalent
(MMboe)

Gas Equivalent

(Bcfe)

Gas Equivalent

(Bcfe)

Proved







Developed Producing

219

4

40

240

192


Developed Non-Producing

4

0

1

4

2


Undeveloped

1,607

28

296

1,775

542

Total Proved

1,830

32

337

2,020

736

Probable

2,323

44

431

2,588

2,195

Total Proved Plus Probable

4,152

76

768

4,608

2,931

(1)

See advisories re: product type

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

(Forecast Prices and Costs) ($Millions)


                                                                    As at December 31, 2015

Annual Discount Rate

0%

5%

10%

15%

20%

BEFORE INCOME TAXES






Proved







Developed Producing

602

421

323

263

223


Developed Non-Producing

3

2

2

1

1


Undeveloped

3,372

1,837

1,068

637

374

Total Proved

3,977

2,261

1,392

901

598

Probable

7,135

3,015

1,547

900

568

Total Proved Plus Probable

11,112

5,276

2,939

1,801

1,166

(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 2015 Reserves Evaluation and does not include costs of abandonment and reclamation of facilities

(3)

Numbers in this table are subject to rounding

Reconciliation of Company Gross Reserves 

(Forecast Prices and Costs)







Natural Gas(1)

NGLs

Total

Total



(Bcf)

(MMbbl)

(MMboe)

(Bcfe)

Proved Developed Producing Reserves






Opening Balance December 31, 2014

171

3

32

192



Discoveries

-

-

-

-



Extensions and Improved Recovery

49

1

9

53



Technical Revisions

32

-

5

30



Economic Factors

-

-

-

-



Dispositions

-

-

-

-



Production

(32)

-

(6)

(34)


Closing Balance December 31, 2015

219

4

40

240

Proved Reserves






Opening Balance December 31, 2014

662

12

123

736



Discoveries

-

-

-

-



Extensions and Improved Recovery

556

15

107

644



Technical Revisions

644

5

112

674



Economic Factors

-

-

-

-



Dispositions

-

-

-

-



Production

(32)

-

(6)

(34)


Closing Balance December 31, 2015

1,830

32

337

2,020

Proved Plus Probable Reserves






Opening Balance December 31, 2014

2,636

49

488

2,931



Discoveries

-

-

-

-



Extensions and Improved Recovery

727

21

142

850



Technical Revisions

823

7

144

864



Economic Factors

(2)

-

-

(2)



Dispositions

-

-

-

-



Production

(32)

-

(6)

(34)


Closing Balance December 31, 2015

4,152

76

768

4,608

(1)

Includes non-associated gas; See advisories re: product type.

(2)

Numbers in this table are subject to rounding

2015 FINDING AND DEVELOPMENT COSTS AND RECYCLE RATIOS

The Corporation generated recycle ratios of 7.5 times on a 2P basis, 1.5 times on a 1P basis and 0.9 times on a PDP basis. This is calculated by dividing Painted Pony's average corporate netback (revenue less royalties, operating expenses, transportation costs, and realized hedging gains) of $1.23/Mcfe by the F&D costs, including changes in FDC, of $0.16 per Mcfe on a 2P basis, $0.84/Mcfe on a 1P basis and $1.38/Mcfe on a PDP basis. 

The following table highlights Painted Pony's capital program efficiency.

Capital Efficiencies (1)

(Forecast Prices and Costs )


Proved Developed Producing

2015

2014

2013

3-Year Weighted Avg.


FD&A ($/Mcfe)

$1.38

$1.56

$2.77

$1.76



Recycle Ratio

0.9x

2.0x

1.1x

1.3x


F&D ($/Mcfe)

$1.38

$2.26

$2.77

$2.08



Recycle Ratio

0.9x

1.4x

1.1x

1.1x

Proved






FD&A ($/Mcfe)

$0.84

$1.16

$1.95

$0.98



Recycle Ratio

1.5x

2.7x

1.6x

2.4x


F&D ($/Mcfe)

$0.84

$1.35

$1.95

$1.03



Recycle Ratio

1.5x

2.3x

1.6x

2.3x

Proved Plus Probable






FD&A ($/Mcfe)

$0.16

$0.70

$1.60

$0.60



Recycle Ratio

7.5x

4.5x

2.0x

3.9x


F&D ($/Mcfe)

$0.16

$0.76

$1.60

$0.62



Recycle Ratio

7.5x

4.1x

2.0x

3.8x

(1)

See advisories with respect to finding and development costs.


Future Development Costs

Painted Pony's 2P FDC increased 5.5% from $3.038 billion at year end 2014 to $3.204 billion at year end 2015 while FDC/Mcfe of undeveloped reserves decreased 34% from $1.13/Mcfe in 2014 to $0.75/Mcfe in 2015. The application of advanced drilling and completion technologies has resulted in improved well productivities and recovery factors, leading to average 2P undeveloped reserve booking per well of 8.8 Bcfe, an increase of 25% over 2014 undeveloped reserves per well of approximately 6.6 Bcfe.  These improvements resulted in a 57% increase in total 2P undeveloped reserves.  

Future Development Costs of Undeveloped Reserves

(Forecast Prices and Costs)

2P Undeveloped

As at December 31

2015

2014

Net 2P Undeveloped Wells

544

434

2P FDC ($Millions, undiscounted)

3,205

3,038

Reserves (Bcfe)

4,301

2,684

2P FDC per Mcfe

$0.75

$1.13




(Forecast Prices and Costs)



1P Undeveloped

As at December 31

2015

2014

Net 1P Undeveloped Wells

287

101

1P FDC ($Millions, undiscounted)

1,677

687

Reserves (Bcfe)

1,775

542

1P FDC per Mcfe

$0.94

$1.27

TRANSPORTATION, HEDGING AND PRICING

In order to protect cash flow, capital investment and production profiles, Painted Pony sells natural gas using a combination of financial hedges and firm physical delivery transactions, supported by firm transportation contracts.  Painted Pony has been successful in diversifying sales contracts to AECO, Station 2, and Sumas through a combination of these strategies.

Firm Transportation Capacity

As previously released on August 12, 2015, the Corporation has signed a definitive agreement with Spectra Energy for an incremental 220 MMcf/d of firm capacity for a total of 266 MMcf/d on the T-North pipeline system beginning in November 2016. This contract provides long-term natural gas transportation for Painted Pony's growing British Columbia production base with connections to both Station 2 and Sunset Creek.  The Sunset Creek sales point gives Painted Pony the opportunity for direct access to AECO pricing. In support of this, Painted Pony signed an agreement with TransCanada Corporation ("TransCanada") in January 2016 to participate in the Towerbirch Expansion Project that will provide the Corporation with 130 MMcf/d of firm transportation service.  This allows Painted Pony to divert approximately 50% of capacity on Spectra's T-North directly into AECO and eliminates the price differential between AECO and Station 2 on those associated volumes.  This will diversify Painted Pony's direct sales point access into a more liquid natural gas sales hub.  The Corporation anticipates completion of the Towerbirch Expansion Project as early as November 2017.  Painted Pony has arranged firm transportation for Facility start-up in September 2016.

Hedging

Painted Pony hedges certain production volumes to provide balance sheet and capital spending protection.  Currently the Corporation has hedging contracts extending into 2019.  For 2016 and 2017, Painted Pony has the following financial hedges in place:


Natural Gas Financial Contracts

Reference point

Volume (MMcf/d)

 Term 

Weighted Average
Price ($/Mcf)

Options

Traded

CDN$ AECO

66.4

January – March 2016

3.02

Swaps

CDN$ AECO

66.4

April – September 2016

3.03

Swaps

CDN$ AECO

85.3

October 2016 – March 2017

3.03

Swaps

CDN$ AECO

61.6

April – June 2017

3.04

Swaps

CDN$ AECO

54.0

July – December 2017

3.10

Swaps

CDN$ STATION 2

37.9

October 2016 – December 2016

1.87

Swaps

CDN$ STATION 2

42.7

January 2017 – December 2017

1.86

Swaps






Note: GJ converted to Mcf at 1.055



Pricing and Contracts

Painted Pony has executed several physical delivery contracts which further diversify the Corporation's access to sales hubs and position it for the potential early commissioning of the Facility.

Between April 2016 and November 2016, Painted Pony has 66.4 MMcf/d of firm, physical contracts in place.  From November 2016 to March 2017 Painted Pony has 76.8 MMcf/d of firm, physical contracts in place, including existing renewable contracts.  These contracts have a variety of terms and price points which include AECO and Sumas index-based contracts and fixed differentials. 

2015 FINANCIAL AND OPERATING RESULTS
Capital Expenditures

Capital expenditures for 2015 of $106.7 million included $78.7 million on drilling and completions activity. During 2015, the Corporation drilled 15 (15.0 net) wells targeting Montney natural gas, the majority of which were pre-drilled wells to supply the Facility.  Expenditures on facilities and equipment during the year totaled $22.1 million and included wellsite facilities costs, pipeline construction costs and spending on compression and dehydration facilities.  During the fourth quarter of 2015, Painted Pony's capital expenditures were $14.6 million.

As previously announced, throughout 2015 Painted Pony realized operational efficiencies and cost reductions that have allowed the Corporation to reduce the planned 2016 capital program from $287 million to $197 million, while still preserving the forecasted production profile.

Production

Annual average daily production volumes increased 18% compared to the year ended December 31, 2014 which continues to reflect strong organic production growth.  Fourth quarter 2015 average daily production volumes increased 10% to 90.3 MMcfe/d (15,043 boe/d) compared to the fourth quarter of 2014 when average daily production volumes totaled 82.0 MMcfe/d (13,665 boe/d).

Current production is over 100.0 MMcfe/d (16,700 boe/d) based on field estimates and Painted Pony expects to average approximately 138.0 MMcfe/d (23,000 boe/d) in 2016, an increase of 47% over 2015 average daily production volumes. Exit volumes for 2016 are estimated to be approximately 240.0 MMcfe/d or 40,000 boe/d, a 166% increase over fourth quarter 2015 average daily production. 

Funds Flow from Operations

During the year ended December 31, 2015, Painted Pony generated funds flow from operations of $31.3 million, compared to $88.9 million during the year ended December 31, 2014. The Corporation generated funds flow from operations of $3.4 million during the fourth quarter of 2015, compared to $12.6 million during the fourth quarter of 2014.

Net Income (Loss)

During the fourth quarter of 2015, net income was $2.6 million due to realized and unrealized hedging gains as compared to a net loss of $3.4 million in the fourth quarter of 2014. For the year ended December 31, 2015, the Corporation had a net loss of $5.2 million, compared to $15.6 million for the year ended December 31, 2014.

Cash Operating Costs and Netbacks

Painted Pony improved its cash operating costs (royalties, operating expenses and transportation costs) on a per Mcfe basis in 2015 to $1.36/ Mcfe, a 32% reduction from $2.00/Mcfe in 2014.

Royalties in 2015 were $0.06/Mcfe, or 2.5% of total revenue, representing a 76% decrease from $0.25/Mcfe in 2014. Royalties decreased significantly in 2015 primarily due to the sale of Painted Pony's Saskatchewan crude oil assets effective July 30, 2014. For 2016, the Corporation anticipates overall royalty rates to remain at or below 3% of total revenues.

Operating expenses in 2015 decreased by $0.33/Mcfe or 26% to $0.94/Mcfe from $1.27/Mcfe in 2014. Per unit operating expenses for both the fourth quarter and full year 2015 have improved significantly due to the exceptional efforts of Painted Pony's field and production operations staff.  Tremendous cost and efficiency improvements continue to be made with respect to all aspects of field operations.  Painted Pony anticipates these per unit cost reductions to continue as production grows and efficiencies improve.

Transportation costs in 2015 decreased 25% to $0.36/Mcfe from $0.48/Mcfe in 2014 as the Corporation successfully negotiated access to alternate delivery points with improved economics for trucking of natural gas liquids.

Field operating netbacks decreased as a result of significantly lower realized commodity prices, offset by lower per unit royalties, operating expenses and transportation costs. Field operating netbacks in 2015 were $1.03/Mcfe, or 43% of total revenue per Mcfe of $2.39/Mcfe.

Corporate netbacks, including realized hedging gains of $0.20 per Mcfe, in 2015 were $1.23 per Mcfe or 52% of total revenue per Mcfe.

General and Administrative Costs

General and administrative ("G&A") expenses in 2015 decreased 14% to $0.32/Mcfe compared to $0.37/Mcfe in 2014. In February 2015, in order to reduce G&A expenses, the Corporation's senior staff and directors accepted reductions in salaries and fees, which continue to be in effect in 2016.

Painted Pony anticipates 2016 full year G&A expenses will be less than $0.25/Mcfe due to significantly increased production.


FINANCIAL HIGHLIGHTS


Year ended December 31,


2015

2014

 

Change

Financial ($ millions, except per share and shares outstanding)




Petroleum and natural gas revenue(1)

81.6

160.5

(49%)

Funds flow from operations(2)

31.3

88.9

(65%)


Per share – basic(3) and diluted(4)

0.31

0.97

(68%)

Net loss

(5.2)

(15.6)

(67%)


Per share – basic(3) and diluted(4)

(0.05)

(0.17)

(71%)

Capital expenditures

106.7

270.5

(61%)

Working capital (deficiency)(5)

(4.6)

2.8

N/A

Bank debt

63.6

-

N/A

Total assets

781.6

737.8

6%

Shares outstanding (millions)

100.0

99.5

1%

Basic weighted-average shares (millions)

99.8

91.2

9%

Fully diluted weighted-average shares (millions)

99.8

92.1

8%

 

Operational




Daily production volumes





Natural gas (MMcf/d)

88.7

70.6

26%


Natural gas liquids (bbls/d)

826

923

(11%)


Crude oil (bbls/d)

-

503

N/A


Total (boe/d)

15,604

13,192

18%


Total (MMcfe/d)

93.6

79.2

18%

Realized prices




Natural gas ($/Mcf)

2.10

4.48

(53%)


Natural gas liquids ($/bbl)

44.30

75.39

(41%)


Crude oil ($/bbl)

-

102.34

N/A


Total ($/Mcfe)

2.39

5.56

(57%)

Field operating netbacks ($/Mcfe)(6)

1.03

3.56

(71%)

Corporate netbacks ($/Mcfe)(6)

1.23

3.45

(64%)




1.

Before royalties.

2.

Funds flow from operations and 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, deferred share unit expense and decommissioning expenditures.  Funds flow from operations per share is calculated by dividing funds flow from operations by the weighted average number of basic or diluted shares outstanding in the period. See "Non-GAAP Measures". 

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.

5.

Working capital (deficiency) is a non-GAAP measure calculated as current assets less current liabilities. See "Non-GAAP Measures".

6.

Field operating netbacks is a non-GAAP measure calculated on a per unit basis as natural gas, crude oil and natural gas liquids revenues less royalties, operating and transportation costs. Corporate netbacks in a non-GAAP measure calculated by adjusting field operating netbacks for realized gains or losses on financial instruments. See "Non-GAAP Measures" and "Field Operating Netbacks and Corporate Netbacks".

DEFINITIONS AND ADVISORIES

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, 2015, which is contained in a report dated March 2, 2016 (the "2015 Reserves Report"). GLJ prepared reserves estimations and economic evaluations of the Corporation's reserves effective December 31, 2014. GLJ and Sproule Associates Limited ("Sproule") prepared reserves estimations and economic evaluations of the Corporation's reserves effective December 31, 2013. Reserves estimates stated herein as at December 31 of a year are extracted from the relevant evaluation.

The 2015 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, 2015, which will be filed on SEDAR on or before March 31, 2016.

Currency:  All amounts referred to in this press release are stated in Canadian dollars unless otherwise specified.

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 time 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. 

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, 2016 price forecast is available on its website at gljpc.com. At the time of the 2015 Reserves Evaluation the Corporation's 2016 capital expenditure budget was $197 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. 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 each of the years 2015, 2014 and 2013 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 2P reserves, by the additions to either proved reserves or 2P 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.

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 2015 future development costs excludes capital associated with the capital leases belonging to the AltaGas Townsend plants and Blair-Townsend interconnect pipeline. The Proved capital associated with the capital leases is $257 million (undiscounted). Proved plus probable capital associated with the capital leases is $648 million (undiscounted).

Reserves Replacement:  Reserves replacement is calculated by dividing proved developed producing reserves, proved reserves or proved plus probable reserves additions, as applicable, before production by total production in the applicable period.  Reserves replacement may be used as a measure of a company's sustainability and its ability to replace its reserves. 

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. 

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, 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.

Non-GAAP Financial Measures: This press release contains the terms, "working capital (deficiency)", "field operating netbacks", and "corporate netbacks" which do not have any standardized meanings prescribed by generally accepted accounting principles ("GAAP") and therefore may not be comparable with the calculation of similar measures for other entities. Management calculates working capital deficiency as current assets less current liabilities and uses this ratio to analyze operating performance and leverage. Field operating netbacks are calculated on a per unit basis as crude oil, natural gas and natural gas liquids revenues less royalties, operating costs and transportation costs. Corporate netbacks are calculated by adjusting field operating netbacks for realized gains or losses on financial instruments.

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. Information relating to reserves is forward looking as it involves the implied assessment, based on certain estimates and assumptions, that the reserves exist in quantitates predicted or estimated and that the reserves can be profitably produced in the future.  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; expected results from the Corporation's assets and results of operations; price forecasts; future development capital; decline rates; operating cost reductions will reduce costs over the long-term; credit facilities will be maintained a current levels; the 2016 capital program will be executed; the AltaGas Townsend Facility will be constructed in the time frame anticipated; contracted firm transportation will become available;

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 2016 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 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 cautions that reliance on such information may not be appropriate for other purposes. 

ABBREVIATIONS

Natural Gas


Natural Gas Liquids

Mcf

thousand cubic feet

bbls

barrels

Mcf/d

thousand cubic feet per day

bbls/d

barrels per day

MMcf/d

million cubic feet per day

 

 

NGLs

natural gas liquids

Bcf

  Billion cubic feet

Mcfe

thousand cubic feet equivalent

Bcfe

  Billion cubic feet equivalent

Mcfe/d

thousand cubic feet equivalent per day

Tcfe

  Trillion cubic feet per day



boe

barrels of oil equivalent



boe/d

barrels of oil equivalent per day



ABOUT PAINTED PONY
Painted Pony is a publicly-traded natural gas Corporation 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 Toronto Stock Exchange under the symbol "PPY".

SOURCE Painted Pony Petroleum Ltd.

For further information: Patrick R. Ward, President and CEO, (403) 475-0440; John H. Van de Pol, Senior Vice President and CFO, (403) 475-0440; Jason Fleury, Director, Investor Relations, (403) 475-0440

RELATED LINKS
www.paintedpony.ca

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