March 27, 2019
CALGARY, March 27, 2019 /CNW/ - (TSX:PMT) – Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release its fourth quarter and year-end 2018 financial and operating results and announce the confirmation of the borrowing limit on its bank credit facility at $55 million and the extension of the maturity date to November 30, 2020. A complete copy of Perpetual's audited consolidated financial statements, Management's Discussion and Analysis ("MD&A") and Annual Information Form for the year ended December 31, 2018 will be available through the Corporation's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.
FOURTH QUARTER AND YEAR-END 2018 FINANCIAL AND OPERATING RESULTS
The execution of our growth-oriented capital program at East Edson in 2017 set the stage for improved performance across all operating measures in 2018. However, the collapse in Western Canadian natural gas prices in early 2018 drove the Company to minimize natural-gas focused development activities until stronger pricing could be realized. Commodity price volatility was experienced in Western Canada due to restricted market access for oil, natural gas and natural gas liquids ("NGL"), driving prices lower for all commodities relative to North American benchmarks, especially during the fourth quarter. Perpetual was well positioned to participate in the stronger natural gas pricing environment driven by the early onset of winter in other parts of North America through its market diversification strategy, resulting in solid results in the fourth quarter and year ended December 31, 2018 as highlighted below:
Fourth Quarter 2018 Highlights
Capital Spending, Production and Operations
2018 Annual Highlights
Capital Spending, Production and Operations
CREDIT FACILITY EXTENSION
On March 27, 2019, a $55 million Borrowing Limit was confirmed by the Company's lenders and the maturity was extended to November 30, 2020. The credit facility will revolve until May 31, 2020 and may be extended for a further 364-day period subject to approval by the Company's lenders. Perpetual is considering options to repay the $14.6 million unsecured senior notes that mature on July 23, 2019, including arranging replacement financing and the sale of a portion of its Tourmaline shares or other assets.
On August 3, 2018, the Company received a Statement of Claim that was filed by PricewaterhouseCoopers Inc. LIT ("PwC"), in its capacity as trustee in bankruptcy of Sequoia, with the Alberta Court of Queen's Bench (the "Court"), against Perpetual. The claim relates to an over two-year-old transaction when, on October 1, 2016, Perpetual closed the Shallow Gas Disposition to an arm's length third party at fair market value at the time after an extensive and lengthy marketing, due diligence and negotiation process. This transaction was one of several completed by Sequoia. Sequoia assigned itself into bankruptcy on March 23, 2018. PwC is seeking an order from the Court to either set this transaction aside or declare it void, or damages of approximately $217 million. On August 27, 2018, Perpetual filed a Statement of Defence and Application for Summary Dismissal with the Court in response to the Statement of Claim. All allegations made by PwC have been denied and an application to the Court to dismiss all claims has been made on the basis that there is no merit to any of them. Perpetual's Application for Summary Dismissal was heard during the fourth quarter of 2018 (the "Sequoia Litigation"). The Court's decision is anticipated to be received in the second quarter of 2019.
Perpetual's 2019 capital expenditure and adjusted funds flow guidance remains unchanged from guidance released with its 2018 third quarter results on November 7, 2018.
The Company's Board of Directors has approved a total capital spending program of $21 to $25 million for 2019 to be funded from adjusted funds flow. At least 50% will be spent in Eastern Alberta, primarily targeting heavy oil development at Mannville along with abandonment and reclamation work of up to $2 million to prudently address decommissioning obligations associated with non-producing wells. The remaining 50% of expenditures will be concentrated in East Edson, developing liquids-rich natural gas reserves in the Wilrich formation if AECO forward gas prices support investment in the second half of 2019, or alternatively, will be deployed in an expanded heavy oil drilling program. The Company has minimal capital spending planned for the first half of 2019. The second half program is planned to align operations with higher anticipated commodity prices.
Forecast capital activity in Mannville for 2019 includes the drilling of 10 (10.0 net) new wells, targeting a mix of infill wells and step outs in waterflooded pools as well as multi-lateral wells in several pools in Eastern Alberta. Timing for the 2019 program is in the third quarter to take advantage of lower drilling, completion, and equipping costs generally realized in the summer in Mannville. Additionally, up to 10 shallow gas recompletions are planned to be executed in late 2019, if gas prices improve, to partially offset natural gas declines in Eastern Alberta. Decommissioning expenditures will continue to be focused in the Mannville area and are expected to provide future lease rental and property tax expense reductions while maintaining regulatory compliance. In Eastern Alberta, production is forecast to increase by 20% to 30% from 2018, to a range of 2,200 to 2,400 boe/d (61% oil) in 2019.
At East Edson, the Company has budgeted a two (2.0 net) well drilling program to come onstream during the fourth quarter of 2019, as well as capital for a strategic secondary zone recompletion program and maintenance. The two wells will be extended reach horizontal ("ERH") wells, as the performance of the ERH wells drilled in late 2017 and early 2018 indicate improved capital efficiencies over the wells drilled with less than 2,500 meters of lateral length. If AECO forward gas prices normalize above $2.00/Mcf, drilling activities are expected to continue into 2020. Processing capacity at the Company's 100% working interest and operated West Wolf Lake facility is 65 MMcf/d, with an additional 13 MMcf/d of working interest capacity at the non-operated Rosevear plant, plus associated liquids. The planned drilling will not have a material impact on production in 2019, as new wells are forecast to come on stream late in the year. Natural declines and capital spending deferrals to late 2019 result in lower anticipated 2019 production in East Edson with an average of 7,000 to 7,200 boe/d (10% oil and NGL). Despite reduced production in East Edson and a substantially fixed operating cost base, operating costs are forecast to remain low in 2019, at less than $3.25/boe.
The table below summarizes anticipated capital spending and drilling activities for the first and second half of 2019.
2019 Exploration and Development Forecast Capital Expenditures
# of wells
# of wells
West Central liquids-rich gas
Excludes budgeted abandonment and reclamation spending of $1.5 to $2.0 million in 2019
Perpetual is targeting a 2019 capital program that is funded by adjusted funds flow. Perpetual forecasts average production of 9,200 to 9,600 boe/d, with oil and NGL production growing to represent more than 20% of the production mix. This represents a reduction in average daily production in 2019 of 10% to 15% relative to 2018, but includes a 17% increase in average oil and NGL production. The Company expects to exit the year at over 11,500 boe/d (approximately 80% natural gas) as production ramps up again in the fourth quarter driven by the second half capital spending program targeting seasonal natural gas price optimization.
Cash costs of $17.00 to $18.00/boe are forecast for 2019, up approximately 13% to 16% from 2018 due to the impact of lower forecast 2019 production at East Edson on a substantially fixed operating cost base. The increase in higher netback and higher operating cost oil production in 2019 is also expected to contribute to the increase in 2019 cash costs per boe.
Perpetual has diversified its commodity and natural gas pricing point exposure (net of royalties) away from AECO as detailed below:
Estimated 2019 Exposure
AECO - fixed price
Total natural gas
Natural gas liquids - Condensate(1)
Natural gas liquids - Other(1)
Net of royalties
For the 2019 calendar year, Perpetual has a costless collar on 500 bbl/d protecting a WTI floor price of US$60.00/bbl with a
Guidance assumptions are as follows:
Exploration and development expenditures ($ millions)
$21 - $25
2019 cash costs ($/boe)
$17.00 - $18.00
2019 average daily production (boe/d)
9,200 – 9,600
2019 average production mix (%)
20% - 24% oil and NGL
Commodity price assumptions reflect market price levels as follows:
2019 Commodity Price
2019 average NYMEX natural gas price (US$/MMBtu)
2019 average West Texas Intermediate ("WTI") oil price (US$/bbl)
2019 average Western Canadian Select ("WCS") differential (US$/bbl)
2019 average exchange rate (US$1.00 = Cdn$)
Year end 2019 net debt (net of the estimated market value of the Company's TOU share investment of approximately $34 million), is forecast at $107 to $113 million, a marginal increase from guidance provided with Perpetual's third quarter earnings release of $104 to $107 million. Estimated mid-range guidance for the 2019 year-end net debt to trailing twelve months adjusted funds flow ratio is forecast at approximately 4.5 times. Current guidance is based on the following assumptions:
The following sensitivities can be applied to estimate changes to projected 2019 cash flow from operating activities and adjusted funds flow, assuming no change in differentials to Perpetual's market pricing points:
Financial and Operating Highlights
Three Months ended
except volume and per share amounts)
Oil and natural gas revenue
Per share – basic and diluted(2)
Cash flow from (used in) operating activities
Adjusted funds flow(1)
Revolving bank debt
Senior notes, principal amount
Term loan, principal amount
TOU share margin demand loan, principal amount
TOU share investment
Net working capital deficiency(1)
Total net debt(1)
Net capital expenditures
Net payments (proceeds) on acquisitions and
Net capital expenditures
Common shares outstanding (thousands)
End of period(3)
Weighted average – basic and diluted
Natural gas (MMcf/d)
Realized natural gas price ($/Mcf)
Realized oil price ($/bbl)
Realized NGL price ($/bbl)
Natural gas – gross (net)
Oil – gross (net)
Total – gross (net)
These are non-GAAP measures. Please refer to "Non-GAAP Measures" at the end of this press release
Based on weighted average basic common shares outstanding for the period
All common shares are net of shares held in trust (2018 – 661; 2017 – 447). See "Note 16 to the Audited Consolidated Financial
Oil and Gas Advisories
The reserves estimates contained in this news release represent gross reserves as at December 31, 2018 as estimated by McDaniel and Associates Consultants Ltd. ("McDaniel") and are defined under National Instrument 51-101 as interest before deduction of royalties and without including any of royalty interests. The recovery and reserves estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein.
To provide a single unit-of-production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe), using the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.
This news release contains metrics commonly used in the oil and natural gas industry, such as "finding and development" costs or "F&D" costs, "F&D recycle ratio", "finding, development and acquisition" costs or "FD&A" costs and "FD&A recycle ratio". These oil and gas metrics have been prepared by management and do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this news release to provide readers with additional measures to evaluate Perpetual's performance, however, such measures are not reliable indicators of Perpetual's future performance and future performance may not compare to Perpetual's performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders and investors with measures to compare Perpetual's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.
F&D costs are calculated on a per boe basis by dividing the aggregate of the change in future development capital ("FDC") from the prior year for the particular reserve category and the costs incurred on development and exploration activities in the year by the change in reserves from the prior year for the reserve category. FD&A costs are calculated on a per boe basis by dividing the aggregate of the change in FDC from the prior year for the particular reserve category and the costs incurred on development and exploration activities and property acquisitions (net of dispositions) in the year by the change in reserves from the year for the reserve category. Both F&D costs and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the F&D costs incurred in the financial year and changes during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year. F&D costs both including and excluding acquisitions and dispositions have been presented in this news release because acquisitions and dispositions can have a significant impact on ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure.
F&D recycle ratio and FD&A recycle ratio is calculated by dividing the operating netback for the period by the F&D costs per boe or FD&A costs per boe for the particular reserve category.
Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking information or statements under applicable securities laws. The forward looking information includes, without limitation, anticipated amounts and allocation of capital spending; statements pertaining to adjusted funds flow levels, statements regarding estimated production and timing thereof; statements pertaining to type curves being exceeded, forecast average production; completions and development activities; infrastructure expansion and construction; estimated FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves; prospective oil and natural gas liquids production capability; projected realized natural gas prices and adjusted funds flow; estimated decommissioning obligations; commodity prices and foreign exchange rates; and commodity price management. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this news release, which assumptions are based on management's analysis of historical trends, experience, current conditions and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this news release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's Annual Information Form and MD&A for the year ended December 31, 2018 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com) and at Perpetual's website (www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released, and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.
Also included in this news release are estimates of Perpetual's 2019 adjusted funds flow, which is based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Perpetual on March 27, 2019 and is included to provide readers with an understanding of Perpetual's anticipated adjusted funds flow and sensitivities based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
This news release contains the terms "adjusted funds flow", "adjusted funds flow per share", "adjusted funds flow per boe", "available liquidity", "cash costs", "net working capital deficiency (surplus)", "net debt", "net bank debt", "net debt to adjusted funds flow ratio", "operating netback", "realized revenue" and "enterprise value" which do not have standardized meanings prescribed by GAAP. Management believes that in addition to net income (loss) and net cash flows from operating activities as defined by GAAP, these terms are useful supplemental measures to evaluate operating performance. Users are cautioned however that these measures should not be construed as an alternative to net income (loss) or net cash flows from operating activities determined in accordance with GAAP as an indication of Perpetual's performance and may not be comparable with the calculation of similar measurements by other entities.
Adjusted funds flow: Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess the ability of the Company to generate the funds necessary to finance capital expenditures, expenditures on decommissioning obligations and meet its financial obligations. Adjusted funds flow is calculated based on cash flows from (used in) operating activities, excluding changes in non-cash working capital and expenditures on decommissioning obligations since Perpetual believes the timing of collection, payment or incurrence of these items is variable. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of the Company's operating areas. Expenditures on decommissioning obligations are managed through the capital budgeting process which considers available adjusted funds flow. The Company has also deducted the change in gas over bitumen royalty financing from adjusted funds flow, in order to present these payments net of gas over bitumen royalty credits received. These payments are indexed to gas over bitumen royalty credits and are recorded as a reduction to the Corporation's gas over bitumen royalty financing obligation in accordance with IFRS. Additionally, the Company has excluded payments of restructuring costs associated with the disposition of the shallow gas assets on October 1, 2016 (the "Shallow Gas Disposition"), which management considers to not be related to cash flow from operating activities. Restructuring costs include employee downsizing costs and surplus office lease obligations. Commencing in the first quarter of 2018, the Company no longer excludes 'exploration and evaluation – geological and geophysical costs' from the calculation of adjusted funds flow as these costs are no longer significant to the Company's business. The calculation of adjusted funds flow for comparative periods has been adjusted to give effect to this change.
Adjusted funds flow per share is calculated using the same weighted average number of shares outstanding used in calculating income (loss) per share. Adjusted funds flow is not intended to represent net cash flows from (used in) operating activities calculated in accordance with IFRS.
Adjusted funds flow per boe is calculated as adjusted funds flow divided by total production sold in the period.
Available Liquidity: Available Liquidity is defined as Perpetual's Credit Facility Borrowing Limit, plus Tourmaline Oil Corp. ("TOU") share investment, less borrowings and letters of credit issued under the Credit Facility and TOU share margin demand loan. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioning obligations and meet financial obligations.
Cash costs: Management believes that cash costs assist management and investors in assessing Perpetual's efficiency and overall cost structure. Cash costs are comprised of royalties, production and operating, transportation, general and administrative and cash interest expense and income. Cash costs per boe is calculated by dividing cash costs by total production sold in the period.
Realized revenue: Realized revenue is the sum of realized natural gas revenue, realized oil revenue and realized NGL revenue which includes realized gains (losses) on financial natural gas, crude oil and foreign exchange contracts but excludes any realized gains (losses) resulting from contracts related to the Shallow Gas Disposition. Realized revenue, including foreign exchange and market diversification contracts, is used by management to calculate the Corporation's net realized commodity prices, taking into account monthly settlements on financial crude oil and natural gas forward sales, collars, basis differentials, and forward foreign exchange sales. These contracts are put in place to protect Perpetual's adjusted funds flow from potential volatility in commodity prices and foreign exchange rates, and as such, any related realized gains or losses are considered part of the Corporation's realized price.
Operating netback: Perpetual considers operating netback to be an important performance measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated by deducting royalties, operating costs, and transportation from realized revenue. Operating netback is also calculated on a per boe basis using production sold for the period. Operating netback on a per boe basis can vary significantly for each of the Company's operating areas.
Net working capital deficiency (surplus): Net working capital deficiency (surplus) includes total current assets and current liabilities excluding short-term derivative assets and liabilities related to the Corporation's risk management activities, current portion of gas over bitumen royalty financing, TOU share investment, TOU share margin demand loan, revolving bank debt, senior notes, and current portion of provisions.
Net bank debt, net debt and net debt to adjusted funds flow ratio: Net bank debt is measured as current and long-term revolving bank debt including net working capital deficiency (surplus). Net debt includes the carrying value of net bank debt, the principal amount of the term loan, the principal amount of the TOU share margin demand loan and the principal amount of senior notes, reduced for the mark-to-market value of the TOU share investment. Net debt, net bank debt and net debt to adjusted funds flow ratios are used by management to assess the Corporation's overall debt position and borrowing capacity. Net debt to adjusted funds flow ratios are calculated on a trailing 12-month basis.
Enterprise value: Enterprise value is equal to net debt plus the market value of issued equity and is used by management to analyze leverage. Enterprise value is not intended to represent the total funds from equity and debt received by the Corporation upon issuance.
For additional reader advisories in regards to non-GAAP financial measures, including Perpetual's method of calculation and reconciliation of these terms to their corresponding GAAP measures, see the section entitled "Non-GAAP Measures" within the Company's MD&A filed on SEDAR.
SOURCE Perpetual Energy Inc.
For further information: Perpetual Energy Inc., Suite 3200, 605 - 5 Avenue SW Calgary, Alberta, Canada T2P 3H5, Telephone: 403 269-4400, Fax: 403 269-4444, Email: email@example.com; Susan L. Riddell Rose, President and Chief Executive Office; W. Mark Schweitzer, Vice President Finance and Chief Financial Officer