investors

Painted Pony Announces Record Adjusted Funds Flow, 19% Increase in Proved Developed Producing Reserves Delivering a 3.1 Times Recycle Ratio, 2018 Year-End Financial and Operating Results

03/06/2019

CALGARY, March 6, 2019 /CNW/ - Painted Pony Energy Ltd. ("Painted Pony" or the "Corporation") (TSX: PONY) is pleased to announce year-end 2018 financial and operating results and reserves as of December 31, 2018.

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

HIGHLIGHTS

Financial

  • Achieved record annual adjusted funds flow for Painted Pony of $175 million ($1.08 per share) in 2018 compared to $109 million ($0.78 per share) during 2017, an increase of 38% per share;
  • Increased adjusted funds flow during the fourth quarter of 2018 by 65% to $59 million ($0.36 per share) compared to $36 million ($0.22 per share) during the fourth quarter of 2017;
  • Reduced 2018 year-end net debt by 10% or $37 million when compared to the third quarter of 2018; and
  • Increased fourth quarter 2018 net income and comprehensive income by 70% to $63 million ($0.39 per share) compared to $37 million ($0.23 per share) during the fourth quarter of 2017.

Reserves

  • Increased Proved Developed Producing ("PDP") reserves by over 19% to 951 Bcfe at year-end 2018, from 797 Bcfe at year-end 2017;
  • Recorded a 31% increase in PDP natural gas liquids ("NGL") to 14 MMbbls at the end of 2018 compared to the end of 2017;
  • Increased PDP net present value at the end of 2018 by 23% to $1.1 billion ($6.94 per share) at a 10% discount rate and using pricing from independent qualified reserves evaluators, GLJ Petroleum Consultants Ltd. ("GLJ") as compared to the end of 2017;
  • Generated a finding, development and acquisition ("FD&A") PDP recycle ratio of 3.1 times, using an FD&A cost of $0.55 per Mcfe, and a corporate netback of $1.71 per Mcfe;
  • Replaced 222% of 2018 production volumes through PDP reserve additions of 282 Bcfe; and
  • Reduced Total Proved ("1P") and Total Proved Plus Probable ("2P") future development capital ("FDC") by 17% or $308 million and 16% or $657 million, respectively; and
  • Increased 1P NGLs to 38 MMbbls (23% annual increase) and increased 2P NGLs to 83 MMbbls (14% annual increase) compared to year-end 2017.

Production

  • Increased average daily production volumes during 2018 by 35% to 347 MMcfe/d (57,879 boe/d) compared to 2017, which was at the upper-end of production guidance of 339 MMcfe/d (56,500 boe/d) to 348 MMcfe/d (58,000 boe/d); and
  • NGL annual average daily production volumes increased by 43% to 5,128 bbls/d during 2018 compared to 3,587 bbls/d during 2017.

Patrick Ward, President and CEO of Painted Pony, in commenting on these highlights said, "Despite the ongoing low natural gas prices in western Canada, Painted Pony generated free cash flow during 2018 allowing us to reduce net debt in Q4 2018 by $37 million compared to Q3 2018 while delivering annual average daily production volume growth of 35%.  Painted Pony's market diversification strategy allowed us to realize natural gas prices that exceeded the average AECO 5A daily spot price during 2018 by 69%. Our focus on growing PDP reserves in 2018 yielded positive results with year-end PDP reserves up 19% compared to year-end 2017, including PDP natural gas liquids reserves growth of more than 30%. Our 2P FDC fell by 16% or $657 million due to fewer undeveloped locations.  There is an increased 1P average recovery of 2.0 Bcfe per well, driving stronger capital efficiencies and lowering the per Mcfe cost of future reserve additions. Our track record of low-cost reserve additions continued with a 2018 PDP FD&A cost of $0.55 per Mcfe that generated an industry leading PDP recycle ratio of 3.1 times."

SUMMARY OF 2018 RESERVES AS PREPARED BY GLJ PETROLEUM CONSULTANTS

2018 Summary of Reserves
GLJ prepared an evaluation of Painted Pony's properties effective December 31, 2018, which is contained in a report dated March 5, 2019.

Proved Developed Producing (PDP)
During 2018, Painted Pony increased PDP reserves by 19% to 951 Bcfe (159 MMboe) at an FD&A cost of $0.55 per Mcfe.  NGLs made up approximately 9% of PDP reserves at December 31, 2018. Painted Pony's PDP reserve additions replaced 222% of 2018 average daily production volumes.

Total Proved (1P)
As at December 31, 2018, Painted Pony's 1P reserves were maintained at approximately 3.1 Tcfe (511 MMboe), which included a 23% increase in NGLs to 38 MMbbls compared to 2017 year-end NGLs of 31 MMbbls.  Painted Pony realized 1P FDC cost reductions of 17% or $308 million from a reduced number of wells. Recoverable reserves per proved undeveloped location increased by an average of 2.0 Bcfe per well. FDC cost reductions exceeded total 2018 capital spending of $154 million.

Total Proved Plus Probable (2P)
As at December 31, 2018, Painted Pony maintained 2P reserves at approximately 6.9 Tcfe (1,147 MMboe), which included a 14% increase in NGLs to 83 MMbbls compared to 2017 year-end NGLs of 73 MMbbls. Painted Pony realized 2P FDC cost reductions of 16% or $657 million from a reduced number of wells. Recoverable reserves per proved plus probable undeveloped location increased by an average of 1.3 Bcfe per well. FDC cost reductions of $657 million exceeded total 2018 capital spending of $154 million.

2018 FINDING, DEVELOPMENT & ACQUISITION COSTS
In 2018, the Corporation generated a PDP FD&A recycle ratio of 3.1 times, as illustrated below. The corporate netback of $1.71 per Mcfe, which has been adjusted to include the cost of the finance lease expense related to the Townsend Facility, is divided by the FD&A costs of $0.55 per Mcfe on a PDP basis.

Operating and Corporate Netbacks 

($/Mcfe)

2018

Revenue

3.19

Realized Gain on Risk Management Contracts

0.30

Revenue including Realized Gain on Risk Management Contracts

3.49

Royalties

(0.05)

Operating Expenses

(0.57)

Transportation Expenses

(0.71)

Operating Netbark

2.16

Finance Lease Expense (Townsend Facility)

(0.45)

Corporate Netback

1.71


Note: See Non-GAAP disclosure in Advisory section

 

The tables below outline GLJ's estimates of Painted Pony's reserves at December 31, 2018 and December 31, 2017:

Summary of Company Working Interest Reserves (gross of royalties)





December 31, 2018

December 31, 2017


Natural Gas
(Bcf)


NGLs
(MMbbls)


Natural Gas
Equivalent
(Bcfe)


Oil
Equivalent
(MMboe)


Natural Gas Equivalent
 (Bcfe)

Proved Developed Producing

869.1


13.7


951.4


158.6


796.6

Proved Developed Non-Producing

7.8


0.2


8.9


1.5


14.8

Proved Undeveloped

1,961.7


24.3


2,107.5


351.2


2,298.9

Total Proved

2,838.5


38.2


3,067.8


511.3


3,110.2

Total Probable

3,545.4


44.9


3,814.8


635.8


3,782.8

Total Proved Plus Probable

6,383.9


83.1


6,882.5


1,147.1


6,893.0

See the advisories with respect to resource definitions.


Numbers in this table may not add due to rounding.

 

The tables below outline GLJ's estimates of Painted Pony's associated net present values of reserves at December 31, 2018:

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

(Forecast Prices and Costs) ($Millions)


As at December 31, 2018

Annual Discount Rate

0%


5%


10%


15%

BEFORE INCOME TAXES








Proved








Developed Producing

1,983


$

1,430


$

1,116


$

920

Developed Non-Producing

20


$

13


$

10


$

7

Undeveloped

3,570


$

2,007


$

1,219


$

776

Total Proved

5,574


$

3,450


$

2,344


$

1,704

Probable

7,997


$

3,476


$

1,784


$

1,017

Total Proved Plus Probable

13,570


$

6,926


$

4,128


$

2,721


Numbers in this table may not add due to rounding.


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 reserve wells that were evaluated by GLJ in the 2018 Reserves Evaluation and does not include costs of abandonment and reclamation of facilities and pipelines.

 

Reconciliation of Company Gross Reserves

(Forecast Prices and Costs)










Natural Gas








   (Shale Gas)
(Bcf)


NGLs

(MMbbl)


 Total
(MMboe)


Total
(Bcfe)

Total Proved Reserves








Opening Balance December 31, 2017

2,924.2


31.0


518.4


3,110.2

Discoveries




Extensions and Improved Recovery




Technical Revisions (2)

29.7


9.1


14.0


84.2

Economic Factors

0.2




0.2

Dispositions




Acquisitions




Production (1)

(115.5)


(1.9)


(21.1)


(126.8)

Closing Balance December 31, 2018

2,838.5


38.2


511.3


3,067.8

Total Proved Plus Probable Reserves







Opening Balance December 31, 2017

6,454.9


73.0


1,148.8


6,893.0

Discoveries




Extensions and Improved Recovery




Technical Revisions (2)

44.2


12.0


19.3


116.1

Economic Factors

0.2




0.2

Dispositions




Acquisitions




Production (1)

(115.5)


(1.9)


(21.1)


(126.8)

Closing Balance December 31, 2018

6,383.9


83.1


1,147.1


6,882.5


Numbers in this table may not add due to rounding.


(1) Represents the Corporation's actual production for the year ended December 31, 2018.


(2) Technical revisions are the result of improved performance in well results, natural gas liquids yields, and type curves.

 

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




Proved Developed Producing

2018

3-Year Weighted Avg.

Finding, Development & Acquisition Cost ($/Mcfe)

0.55

0.95

Recycle Ratio

3.1x

1.7x

Total Proved



Finding, Development & Acquisition Cost ($/Mcfe)

n/a

0.58

Recycle Ratio

nmf*

2.8x

Total Proved Plus Probable



Finding, Development & Acquisition Cost ($/Mcfe)

n/a

0.43

Recycle Ratio

nmf*

3.7x


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

*Reduction in FDC exceeds capital spending in 2018, resulting in a 'not meaningful figure' (nmf)

 

Future Development Costs of Undeveloped Reserves

(Forecast Prices and Costs)



Total Proved Undeveloped

As at December 31

2018


2017

Net Total Proved Undeveloped Wells

257


368

Total Proved Future Development Capital ($Millions) (undiscounted)

1,539


1,847

Total Proved Reserves (Bcfe)

3,068


3,110

Total Proved Future Development Capital ($ per Mcfe)

0.50


0.59



(Forecast Prices and Costs)



Proved Plus Probable Undeveloped

As at December 31

2018


2017

Net Proved Plus Probable Undeveloped Wells

618


759

Proved Plus Probable Future Development Capital ($Millions)

3,476


4,133

Total Proved Plus Probable Reserves (Bcfe)

6,883


6,893

Proved Plus Probable Future Development Capital ($ per Mcfe)

0.51


0.60

 

2018 FINANCIAL AND OPERATING RESULTS

Capital Expenditures
Capital spending during 2018 totaled approximately $154 million compared to adjusted funds flow for 2018 of $175 million. This capital spending profile is consistent with Painted Pony's 2018 capital spending strategy of delivering annual average daily production volume growth through capital investments which did not exceed 2018 adjusted funds flow.

Activities included the drilling of 22 (22.0 net) wells, the completion of 28 (28.0 net) and investments into associated facilities and infrastructure.

During the fourth quarter of 2018, Painted Pony drilled 1 (1.0 net) and completed 5 (5.0 net) wells, and executed a capital program of $19 million, which included spending approximately $17 million on drilling and completions, $1 million on facilities and equipment and $1 million on capitalized G&A.

Production
Painted Pony's 2018 annual average daily production increased by 35% to 347 MMcfe/d (57,879 boe/d), including 9% or 5,128 bbls/d of NGLs, over 2017 annual average daily production volumes of 257 MMcfe/d (42,882 boe/d), including 8% or 3,587 bbls/d of NGLs.

During the fourth quarter of 2018 temporary production volume shut-ins totaling approximately 32 MMcfe/d (5,300 boe/d) occurred. The majority of these shut-ins were due to third-party interruptions and voluntary shut-ins due to price weakness created by these third-party restrictions and outages.

NGL production for the fourth quarter of 2018 was affected by approximately 9% compared to the fourth quarter of 2017 due to issues at the Townsend Facility. Painted Pony is working with the facility operator to ensure the issues are resolved.

During the fourth quarter of 2018 Painted Pony maintained average daily production volumes of 315 MMcfe/d (52,453 boe/d) compared to fourth quarter 2017 production volumes of 315 MMcfe/d (52,544 boe/d).

Adjusted Funds Flow from Operations
Adjusted funds flow from operations increased to $175 million during 2018, compared to 2017 adjusted funds flow from operations of $109 million.  The increase in adjusted funds flow from operations is the result of a 35% increase in production volumes, a 12% increase in realized prices including risk management contracts, offset by a 20% increase in costs per Mcfe.

Painted Pony's fourth quarter 2018 adjusted funds flow from operations increased 65% to $59 million, compared to adjusted funds flow from operations of $36 million during the fourth quarter of 2017.

The increase in adjusted funds flow in 2018 was positively influenced by Painted Pony's diversified marketing strategy which captured strong pricing at both the Dawn hub in southern Ontario and the Sumas sales hub in southern BC during the fourth quarter of 2018.

2019 CAPITAL PROGRAM

Painted Pony remains well-positioned to deliver a 2019 capital program based on expected adjusted funds flow delivering between 3% and 7% lower forecasted annual average daily production volumes of between 324  MMcfe/d (54,000 boe/d) and 336 MMcfe/d (56,000 boe/d) compared to 2018 annual average daily production volumes of 347 MMcfe/d (57,879 boe/d).

At the time of Painted Pony's December 17, 2018 press release detailing the 2019 capital program, the forward strip price for spot AECO daily 5A natural gas averaged approximately $1.75 per Mcf for the months of January and February 2019.  Actual forward strip price for spot AECO daily 5A natural gas averaged approximately $2.57 per Mcf during January and February 2019, an increase of 47% over the December 2018 forward strip price.

Painted Pony's strategy continues to focus on the creation of long-term shareholder value through the deep inventory of drilling locations for natural gas and natural gas liquids across more than 300 net sections of Montney rights, continued focus on long-term opportunities for market diversification, and corporate-wide cost structure optimization.

FINANCIAL AND OPERATIONAL HIGHLIGHTS




Years ended December 31,

($ millions, except per share and shares outstanding)

2018


2017


Change

Financial






Petroleum and natural gas revenue(1)

404.4


249.2


62%

Cash flows from operating activities

169.0


106.9


58%

Per share - basic (3)(8)

1.05


0.76


38%

Per share - diluted (4)(8)

0.99


0.74


34%

Adjusted funds flow from operations(2)

174.6


109.2


60%

Per share - basic (3)

1.08


0.78


38%

Per share - diluted(4)

1.03


0.76


36%

Net income and comprehensive income

7.1


122.4


(94)%

Per share - basic (3)

0.04


0.87


(95)%

Net income and comprehensive income - diluted

7.1


123.2


(94)%

Per share - diluted(4)

0.04


0.85


(95)%

Capital expenditures

154.4


302.6


(49)%

Working capital (5)

32.9


33.0


—%

Bank debt

163.1


149.2


9%

Senior notes

143.1


141.6


1%

Convertible debentures - liability

46.1


44.9


3%

Net debt (6)

348.5


363.9


(4)%

Total assets

2,055.4


2,031.6


1%

Shares outstanding (millions)

161.0


161.0


—%

Basic weighted-average shares (millions)

161.0


140.7


14%

Fully diluted weighted-average shares (millions)

169.9


144.1


18%

Operational






Daily production volumes






Natural gas (MMcf/d)

316.5


235.8


34%

Natural gas liquids (bbls/d)

5,128


3,587


43%

Total (MMcfe/d)

347.3


257.3


35%

Total (boe/d)

57,879


42,882


35%

Realized commodity prices before financial risk






management contracts






Natural gas ($/Mcf)

2.54


2.13


19%

Natural gas liquids ($/bbl)

59.43


50.53


18%

Total ($/Mcfe)

3.19


2.65


20%

Operating netbacks ($/Mcfe)(7)

2.16


2.01


7%

Corporate netbacks ($/Mcfe)(7)

1.71


1.54


11%

(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 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, 2018.

(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, 2018.

(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, 2018.

(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. Corporate netback is calculated as operating netback less finance lease expense per unit. See "Non-GAAP Measures" and "Operating and Corporate Netbacks" in Management Discussion and Analysis for the year ended December 31, 2018.

(8)

Cash flows from operating activities per share - basic and diluted are non-GAAP measures calculated by dividing cash flows from operating activities by the weighted average of basic or diluted shares outstanding in the period.

 

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.

  • "Total 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 total 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 total 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, 2018, which is contained in a report dated March 5, 2019 (the "2018 Reserves Report"). GLJ prepared reserves estimations and economic evaluations of the Corporation's reserves effective December 31, 2018. Reserves estimates stated herein as at December 31 of a year are extracted from the relevant evaluation.

The 2018 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, 2018, which is filed on SEDAR on March 6, 2019.

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 2018 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 total 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 2018 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, the expected adjusted funds flow, the forecasted annual average daily production volumes, and the 2019 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 2019 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", "cash flow from operations per share", "adjusted funds flow from operations per Mcfe", "working capital deficiency", "net debt", "operating netbacks" and "corporate netback", 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 and decommissioning expenditures. "Adjusted funds flow from operations per share" and "cash 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.  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 "corporate netback" 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. Corporate netback is calculated on a per unit basis as operating netback per unit less finance lease expense per unit.  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 financial results of the Corporation for the year ended December 31, 2018.

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.

Emergency Phone: 1-888-775-0440

PAINTED PONY ENERGY LTD.

1200, 520 3 Avenue SW Calgary, Alberta T2P 0R3 P: 403 475-0440 F: 403 238-1487 TF: 1-866-975-0440 E: info@paintedpony.ca

24-HOUR EMERGENCY CONTACT

Call 1-888-775-0440 to report concerns regarding any of Painted Pony’s field operations. This is for EMERGENCIES ONLY and does not connect to Painted Pony’s head office.

PAINTED PONY ENERGY LTD.

1200, 520 3 Avenue SW Calgary, Alberta T2P 0R3 P: 403 475-0440 F: 403 238-1487 TF: 1-866-975-0440 E: info@paintedpony.ca