CALGARY, Alberta, March 11, 2020 (GLOBE NEWSWIRE) -- Painted Pony Energy Ltd. (“Painted Pony” or the “Corporation”) (TSX: PONY) is pleased to announce fourth quarter and full-year 2019 financial and operating results, year-end 2019 reserves, 2020 first-half capital spending, and anticipated future reductions to transportation, processing, and general and administrative expenses ("G&A").
- Reduced bank debt at 2019 year end by 26% or $43 million to $120 million when compared to 2018 year-end bank debt of $163 million;
- Closed the sale of a 75% working interest on 11,280 gross acres (8,460 net acres) in the South Townsend block during the fourth quarter of 2019 for total cash consideration of $45 million;
- Drilling began in March 2020 on an eight-well Montney program by joint venture partner and project operator Tourmaline Oil Corp. on the 25% working interest South Townsend block;
- Amended processing and transportation agreements which, when fully implemented, are expected to save Painted Pony approximately $18 million annually;
- Delivered a 2019 Proved Developed Producing ("PDP") recycle ratio of 1.3 times, resulting in a three-year average PDP recycle ratio of 1.5 times;
- Reduced Total Proved ("1P") future development capital ("FDC") by 11% or $172 million;
- Expect to begin flowing production volumes in March 2020 through the new deep-cut facility at the AltaGas Townsend Facility (“Townsend Facility”) which is expected to add approximately 1,200 bbls/d of natural gas liquids ("NGLs"), increasing Painted Pony's liquids yields to more than 10%;
- Forecasting 2020 gross G&A to be approximately 8% or $2 million lower than 2019 gross G&A expenses;
- Increased production volumes to an estimated daily average of 315 MMcfe/d (53,000 boe/d) for the months December 2019, January 2020, and February 2020, based on actuals and field estimates; and
- Generated adjusted funds flow from operations of $18 million during the fourth quarter of 2019 bringing full-year 2019, adjusted funds flow from operations to $76 million.
Patrick Ward, President and CEO of Painted Pony, in commenting on these highlights said, “The commodity markets continue to be highly volatile with natural gas prices reaching generational lows during the summer of 2019 before AECO began rebounding in late 2019 only to see NYMEX prices fall in early 2020. Painted Pony's market diversification strategy and fixed price hedges allowed us to realize a 2019 natural gas price that exceeded the average 2019 AECO 5A daily spot price by 36%. Through the combination of capital discipline and an asset sale, we were able to reduce year-end bank debt by 26% or $43 million. We are entering 2020 with a cautious first half capital budget which forecasts investing $25 to $30 million, including drilling the first eight wells in our new joint venture with Tourmaline Oil Corp. on the South Townsend block. We are continuing to exercise caution in this difficult market which means focusing our efforts on streamlining capital spending, potential asset sales, and the ongoing pursuit of long-term contracts with large end-users of natural gas, and other cost saving initiatives. While it remains a very challenging natural gas price environment, the long-term outlook is improving as evidenced by the ongoing construction of the LNG Canada facility at Kitimat, BC, the anticipated final investment decision on the Woodfibre LNG project in 2020, and the recently announced $4 billion planned expansion to FortisBC's Tilbury LNG facility."
COST STRUCTURE IMPROVEMENTS
As part of ongoing cost reductions, Painted Pony is pleased to announce several successful initiatives which are expected to reduce annual operating and transportation expenses.
Townsend Facility Cost Structure Improvements
Effective October 1, 2019 the take-or-pay commitment at the Townsend Facility was reduced by 15 MMcf/d. The take-or-pay commitment will be reduced by an additional 16 MMcf/d on August 1, 2020 with an additional 9 MMcf/d reduction to the take-or-pay commitment on August 1, 2021, for a total reduction of take-or-pay obligation of 15% or 40 MMcf/d. In addition, Painted Pony will realize a reduced capital lease fee at the Townsend Facility, which is expected to lower the per unit cost by approximately 10%. Also, the annual fixed-cost liquids transportation expense has been reduced by approximately 40% from the Townsend Facility to the North Pine Fractionator.
Reduced Transportation Obligations
In addition to reduced facility costs, Painted Pony has permanently reduced firm transportation obligations on two major pipelines. Effective August 1, 2020, Painted Pony’s excess firm transportation obligations will be reduced by 30 MMcf/d, consisting of a reduction of 15 MMcf/d on the T-North pipeline and 15 MMcf/d on the North Montney Mainline which when combined and fully implemented, is expected to reduce Painted Pony’s annual transportation expenses by approximately $3.7 million.
Once fully implemented, cost structure improvements at the Townsend Facility combined with reduced transportation obligations on both the T-North and North Montney Mainline pipelines are expected to save Painted Pony approximately $18 million per year.
G&A Cost Reductions
Through a combination of staff attrition, reduced compensation, and various other cost cutting measures, 2019 gross G&A expenses were $1.4 million lower than 2018 gross G&A. Ongoing efficiency initiatives are expected to further reduce forecasted 2020 gross G&A expenses by an incremental $2 million below that of 2019.
2019 FINANCIAL AND OPERATING RESULTS
Net cash capital spending during 2019 totaled approximately $42 million, net of asset sale proceeds, compared to adjusted funds flow of $76 million.
Capital investment activities during 2019 included drilling 13 (13.0 net) wells, the completion of 14 (14.0 net) wells and investments into associated facilities and infrastructure. During the fourth quarter of 2019, Painted Pony completed 2 (2.0 net) wells, and executed a capital program totaling $12 million.
Painted Pony's 2019 annual average daily production was 294 MMcfe/d (48,979 boe/d), including 9% or 4,198 bbls/d of NGLs and 269 MMcf/d of natural gas compared to 347 MMcfe/d (57,879 boe/d) during 2018. Fourth quarter 2019 daily production volumes averaged 271 MMcfe/d (45,173 boe/d) compared to 315 MMcfe/d (52,453 boe/d) during the fourth quarter of 2018. Average daily production volumes during 2019 were significantly impacted by voluntary pricing-related shut-ins and pipeline restriction shut-ins. The impact of these shut-ins for the full year 2019 was 36.6 MMcfe/d (6,100 boe/d), while the impact during the fourth quarter of 2019 was 55.8 MMcfe/d (9,300 boe/d).
The low natural gas prices which plagued summer and fall 2019 and which were the cause for material production volume shut-ins improved in mid-November with natural gas prices supporting higher production volumes. December 2019 daily production volumes averaged 319 MMcfe/d (53,158 boe/d); significantly higher than the quarterly average daily production volumes of 271 MMcfe/d (45,173 boe/d) during the fourth quarter of 2019.
Adjusted Funds Flow from Operations
Adjusted funds flow from operations during the fourth quarter of 2019 was $18 million ($0.11 per basic share) with full year 2019 adjusted funds flow totaling $76 million ($0.47 per basic share).
Due to improved natural gas pricing and strong performance from our most recent wells, average daily production volumes during December 2019, January 2020, and February 2020 averaged greater than 318 MMcfe/d (53,000 boe/d), based on actuals and field estimates.
South Townsend Joint Venture
Tourmaline Oil Corp., Painted Pony's joint venture partner and operator of the project on the liquids-rich South Townsend block, began drilling an eight-well program in March 2020.
Townsend Facility Deep Cut Access
Painted Pony is expecting to access the new deep cut facility at the Townsend Facility which is expected to be commissioned and operational in late March 2020. Producing gas through the deep cut facility will increase Painted Pony's liquid yields and increase absolute NGL production by an estimated 1,200 bbls/d, increasing Painted Pony's liquids yield to greater than 10% of daily production volumes. The majority of this NGL production increase will be propane. Painted Pony's access to the AltaGas North Pine Fractionator and Ridley Island Propane Export Terminal will attract international pricing for the Corporation’s propane production volumes. These international pricing benchmarks have typically traded at a premium price to North America propane pricing.
2020 CAPITAL DEVELOPMENT PROGRAM
Painted Pony is taking a cautious approach to capital spending in 2020. The Painted Pony Board of Directors has approved first half 2020 capital spending of $25 million to $30 million. The Board of Directors and management have planned a mid-year review to determine appropriate second-half spending.
SUMMARY OF 2019 RESERVES AS PREPARED BY GLJ PETROLEUM CONSULTANTS
2019 Summary of Reserves
The Corporation retained independent qualified reserves evaluators, GLJ Petroleum Consultants Limited (“GLJ”), to evaluate and review all of the Corporation’s proved and proved plus probable reserves effective December 31, 2019, which is contained in a report dated March 11, 2020 (the “2019 Reserves Report”). The evaluation and review was conducted and prepared in accordance with standards contained in the Canadian Oil and Gas Handbook. The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and costs.
Despite lower capital investment during 2019 due to lower natural gas prices and their impact on Painted Pony's adjusted funds flow from operations, 1P and 2P reserve volumes remained relatively unchanged from year-end 2018. Strong well performance, including positive results from longer lateral wells, and improved year-over-year capital efficiencies all contributed to relatively minor changes to the 2019 reserve volumes.
Proved Developed Producing
As at December 31, 2019, Painted Pony had PDP reserves of 878 Bcfe (146 MMboe). The 2019 capital program delivered a PDP FD&A cost of $1.26 per Mcfe. NGLs made up approximately 9% of PDP reserves at December 31, 2019.
As at December 31, 2019, Painted Pony's 1P reserves were approximately 3.0 Tcfe (496 MMboe). Painted Pony realized 1P FDC cost reductions of 11% or $172 million, largely due to the impact of longer laterals on future development plans. The 1P FDC cost reductions of $172 million exceeded total 2019 capital spending of $87 million (prior to asset disposition proceeds).
Total Proved Plus Probable
As at December 31, 2019, Painted Pony's 2P reserves were approximately 6.8 Tcfe (1,134 MMboe). Painted Pony realized 2P FDC cost reductions of 4% or $133 million, largely due to the impact of longer laterals on future development plans. The 2P FDC cost reductions of $133 million exceeded total 2019 cash capital spending of $87 million (prior to asset disposition proceeds).
Tables below outline GLJ’s estimates of Painted Pony’s reserves at December 31, 2019 and December 31, 2018:
Summary of Company Working Interest Reserves (gross of royalties)
|December 31, 2019||December 31, 2018|
|Natural Gas |
|Natural Gas |
|Natural Gas |
|Proved Developed Producing||801.8||12.7||877.7||146.3||951.4|
|Proved Developed Non-Producing||36.7||0.3||38.4||6.4||8.9|
|Total Proved Plus Probable||6,326.1||79.5||6,803.1||1,133.8||6,882.5|
The tables below outline GLJ’s estimates of Painted Pony’s associated net present values of reserves at December 31, 2019:
|Net Present Values of Future Net Revenue (1)(2)|
|(Forecast Prices and Costs) ($Millions)|
|As at December 31, 2019|
|Annual Discount Rate (before income taxes)||0||%||5||%||10||%||15||%||20||%|
|Total Proved Plus Probable||11,948||5,704||3,203||2,003||1,350|
Numbers in this table may not add due to rounding.
- Estimates of future net revenue, whether discounted or not, do not represent fair market value.
- Future net revenue is after deduction of estimated costs of abandonment and reclamation of existing and future reserve wells and facilities that were evaluated by GLJ in the 2019 Reserves Report.
Reconciliation of Company Gross Reserves (Forecast Prices and Costs)
|Natural Gas |
|Total Proved Reserves|
|Opening Balance December 31, 2018||2,838.5||38.2||511.3||3,067.8|
|Extensions and Improved Recovery||0.0||0.0||0.0||0.0|
|Technical Revisions (2)||48.8||(0.2||)||7.9||47.4|
|Closing Balance December 31, 2019||2,763.6||35.7||496.3||2,978.0|
|Total Proved Plus Probable Reserves|
|Opening Balance December 31, 2018||6,383.9||83.1||1,147.1||6,882.5|
|Extensions and Improved Recovery||0.0||0.0||0.0||0.0|
|Technical Revisions (2)||93.7||(1.0||)||14.7||88.0|
|Closing Balance December 31, 2019||6,326.1||79.5||1,133.8||6,803.1|
Numbers in this table may not add due to rounding.
- Represents the Corporation’s actual production for the year ended December 31, 2019.
- Technical revisions are the result of well results and well type design, focusing development on dry gas areas and the inclusion of capital lease expenses in operating costs.
2019 FINDING, DEVELOPMENT & ACQUISITION COSTS ("FD&A") AND RECYCLE RATIOS
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 operating 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 add 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 operating netback by the 3-year weighted average finding, development and acquisition cost, both on a per unit basis.
Painted Pony generated a 2019 recycle ratio of 1.3 times on a PDP basis. This is calculated by dividing Painted Pony's 2019 operating netback (revenue less royalties, operating expenses, transportation costs, and realized hedging gains or losses) of $1.66 per Mcfe by the 2019 FD&A cost, including changes in FDC, of $1.26 per Mcfe on a PDP basis.
|Proved Developed Producing||2019||3-Year Weighted Avg.|
|Finding, Development & Acquisition Cost ($/Mcfe)||1.26||1.06|
|Finding, Development & Acquisition Cost ($/Mcfe)||nmf||0.37|
|Total Proved Plus Probable|
|Finding, Development & Acquisition Cost ($/Mcfe)||nmf||0.49|
See advisories with respect to finding, development & acquisition costs.
Note: FDC reductions exceeded capital spending in 2019, resulting in a 'not meaningful figure' (nmf)
|Future Development Costs of Reserves|
|(Forecast Prices and Costs)|
|Total Proved Undeveloped|
|As at December 31||2019||2018|
|Net Total Proved Undeveloped Wells||224||257|
|Total Proved Future Development Cost ($Millions) (undiscounted)||1,369||1,539|
|Total Proved Reserves (Bcfe)||2,978||3,068|
|Total Proved Future Development Cost ($ per Mcfe)||0.46||0.50|
|(Forecast Prices and Costs)||Proved Plus Probable Undeveloped|
|As at December 31||2019||2018|
|Net Proved Plus Probable Undeveloped Wells||558||618|
|Proved Plus Probable Future Development Cost ($Millions)||3,343||3,476|
|Total Proved Plus Probable Reserves (Bcfe)||6,803||6,883|
|Proved Plus Probable Future Development Cost ($ per Mcfe)||0.49||0.51|
Painted Pony's strategy continues to focus on the creation of long-term shareholder value through a deep inventory of drilling locations for natural gas and natural gas liquids across more than 290 net sections of Montney rights, continued focus on long-term opportunities for market diversification, and corporate-wide cost structure optimization.
Painted Pony announces the resignation of Paul Beitel as a Director of the Corporation. Mr. Beitel was a key contributor to Painted Pony since he joined the Board of Directors in May of 2017. The Board of Directors and the Corporation thank Mr. Beitel for his service to Painted Pony and wish him every success in his future endeavours.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
|Years ended |
|($ millions, except per share and shares outstanding)||2019||2018||Change|
|Natural gas and natural gas liquids revenue(1)||302.8||404.4||(25||)%|
|Cash flows from operating activities||88.6||169.0||(48||)%|
|Per share - basic(3)(8)||0.55||1.05||(48||)%|
|Per share - diluted(4)(8)||0.52||0.99||(48||)%|
|Adjusted funds flow from operations(2)||76.4||174.6||(56||)%|
|Per share - basic(3)||0.47||1.08||(56||)%|
|Per share - diluted(4)||0.45||1.03||(56||)%|
|Net income (loss) and comprehensive income (loss) - basic and diluted||(232.9||)||7.1||—||%|
|Per share - basic and diluted(3)(4)||(1.45||)||0.04||—||%|
|Cash capital expenditures (net)||42.3||154.4||(73||)%|
|Working capital (deficiency)(5)||(31.9||)||32.9||—||%|
|Convertible debentures - liability||47.5||46.1||3||%|
|Shares outstanding (millions)||161.0||161.0||—||%|
|Basic weighted-average shares (millions)||161.0||161.0||—||%|
|Fully diluted weighted-average shares (millions)||169.9||169.9||—||%|
|Daily production volumes|
|Natural gas (MMcf/d)||268.7||316.5||(15||)%|
|Natural gas liquids (bbls/d)||4,198||5,128||(18||)%|
|Realized commodity prices before financial risk management contracts|
|Natural gas ($/Mcf)||2.40||2.54||(6||)%|
|Natural gas liquids ($/bbl)||44.05||59.43||(26||)%|
|Operating netbacks ($/Mcfe)(7)||1.66||2.16||(23||)%|
|Corporate netbacks ($/Mcfe)(7)||1.12||1.71||(35||)%|
- Before royalties.
- 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”.
- Basic per share information is calculated on the basis of the weighted average number of shares outstanding in the period.
- Diluted per share information reflects the potential dilutive effect of stock options and convertible debentures.
- Working capital (deficiency) is a non-GAAP measure calculated as current assets less current liabilities. See “Non-GAAP Measures”.
- 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”.
- Operating netbacks and corporate netbacks are non-GAAP measures. Operating netbacks are 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 expenses. Corporate netbacks are calculated as operating netback less finance lease expense per unit. See “Non-GAAP Measures” and “Operating and Corporate Netbacks”.
- 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. See “Non-GAAP Measures”.
DEFINITIONS AND ADVISORIES
Currency: All amounts referred to in this press release are stated in Canadian dollars unless otherwise specified.
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. 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. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
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, 2019, which is contained in a report dated March 11, 2020 (the "2019 Reserves Report"). GLJ prepared reserves estimations and economic evaluations of the Corporation's reserves effective December 31, 2019. Reserves estimates stated herein as at December 31 of a year are extracted from the relevant evaluation.
The 2019 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, 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 2019 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.
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.
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.1
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.
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 accessing the new deep cut facility at the Townsend Facility and any increased production volumes and liquids yields resulting therefrom, expected reductions to the Corporation’s G&A expenses for the upcoming financial year, capital expenditure plans, including drilling eight wells as part of the Corporation’s joint venture with Tourmaline Oil Corp on the South Townsend Block; planned production dates, anticipated benefits arising from reducing Painted Pony’s excess firm transportation obligations, including reductions to the Corporation’s operating and transportation expenses, natural gas pricing expectations, estimates of future net revenue, and estimated average daily production volumes.
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 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 2020 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.
Non-GAAP Measures: Press releases may make reference to the terms “adjusted funds flow from operations”, “adjusted funds flow from operations per share”, "cash flow from operating activities per share", “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. 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, 2019 for further information regarding these “Non-GAAP Measures”, including reconciliations to the most directly comparable measures calculated in accordance with IFRS.
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”.
Patrick R. Ward
President and Chief Executive Officer
Stuart W. Jaggard
Chief Financial Officer
Jason W. Fleury
Director, Investor Relations