November 8, 2018
CALGARY, Nov. 8, 2018 /CNW/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release its third quarter 2018 financial and operating results, and provide capital spending guidance for 2019. A complete copy of Perpetual's unaudited condensed interim consolidated financial statements and related Management Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2018 can be obtained through the Company's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.
THIRD QUARTER 2018 HIGHLIGHTS
Production and Operations
2018 capital spending and production guidance
Perpetual anticipates 2018 exploration and development capital expenditures of approximately $25 to $26 million ($4 to $5 million for the fourth quarter), reducing the upper end of its previous guidance of $25 to $30 million provided in its second quarter financial and operating results press release dated August 2, 2018 (the "Q3 Guidance"). The Mannville heavy oil drilling program for the second half of 2018 has been reduced from the Q3 Guidance of 4.3 – 8.3 net wells to 3.0 net wells, plus one re-entry (1.0 net). The expansion to the drilling program was deferred to allow more time to monitor performance from the first quad lateral re-entry and due to the alternative use of funds to acquire a partner's interest in one of the Company's operated Mannville heavy oil pools. Furthermore, the Company expects that heavy oil differentials will narrow in the second half of 2019, improving economics for the heavy oil drills.
At East Edson, one horizontal well drilled in the first quarter of 2018 will be completed and tied-in during the fourth quarter. Additionally, the installation of field compression and a sweetening tower is targeting to restore several higher liquids ratio wells back to production. The timing of the capital activity is designed to align high initial production rates with higher anticipated winter natural gas prices. Decommissioning expenditures are anticipated to be $0.5 to $1.0 million for the remainder of 2018, consistent with Q3 Guidance. Capital spending during the remainder of 2018 will be funded from adjusted funds flow.
Production for 2018 is expected to be 10,250 boe/d to 10,750 boe/d, down slightly from Q3 Guidance, as the re-start of production from the 700 boe/d four well pad at Edson is not forecast to commence until early 2019, and extremely low AECO gas prices in October and early November have caused the Company's voluntary production shut-in strategy to be implemented on a number of occasions.
For the October 2018 through March 2019 period, Perpetual has fixed the price on 15,000 GJ/d at $1.41/GJ AECO with the remainder of its production sold at daily index prices at the Chicago, Dawn, Empress, Malin and Michcon markets through its 40,000 MMBtu/d market diversification contract. If AECO prices temporarily weaken, Perpetual's fixed price AECO position provides the ability to shut-in production and purchase gas to deliver against pre-sold commitments while preserving reserves and future deliverability capability. Perpetual has costless collar and fixed price WTI oil sales arrangements in place to sell 750 bbl/d at an average ceiling price of US$60.71/bbl for the remainder of 2018. Additionally, Perpetual has fixed the US$/Cdn$ exchange rate on approximately 53% of its US$ denominated sales at a rate of $1.30 for the remainder of 2018.
Cash costs of $15.00 to $15.50/boe are now anticipated for 2018, up slightly from Q3 Guidance, due to the produced water spill remediation costs incurred in the third quarter.
Adjusted funds flow for 2018 is anticipated to be in the $27 to $29 million range ($5 to $7 million for the remainder of 2018), consistent with Q3 Guidance. On a per share basis, adjusted funds flow for 2018 is anticipated to be $0.44 to $0.48 per share.
Guidance assumptions are as follows:
Exploration and development expenditures ($ millions)
$25 - $26
$25 – 30
2018 cash costs ($/boe)
$15.00 - $15.50
$14.00 - $15.00
2018 average daily production (boe/d)
10,250 - 10,750
10,500 - 11,000
2018 average production mix (%)
17% oil and NGL
16% oil and NGL
Commodity price assumptions reflect market price levels as follows:
2018 average NYMEX natural gas price (US$/MMBtu)
2018 average West Texas Intermediate ("WTI") oil price (US$/bbl)
2018 average Western Canadian Select ("WCS") differential (US$/bbl)
2018 average exchange rate (US$1.00 = Cdn$)
Year end 2018 net debt (net of the estimated market value of the Company's TOU share investment of approximately $35 million) is forecast at $104 - $107 million, up from Q3 Guidance of $98 - $103 million, due to a decrease in the market value of the Company's TOU share investment since the second quarter. Current guidance is based on the following assumptions:
On November 7, 2018, the revolving bank debt borrowing limit was reduced from $60 million to $55 million by the Company's lenders with the next borrowing limit redetermination scheduled on or prior to May 31, 2019. The term of the revolving bank debt has not been extended and will mature on May 31, 2019.
2019 capital spending and production guidance
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. 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 of 2019 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 open hole multi-lateral wells following up on the success of the 2018 program. Timing for the 2019 program is in the third quarter of 2019 to take advantage of lower drilling, completion, and equipping costs generally realized in the summer in Mannville, as well as the anticipation that heavy oil price differentials will improve through 2019. 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 grow from a range of 1,800 to 1,900 boe/d (54% oil) in 2018 to 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 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, in order to ramp up production to again match processing and transportation capacity. 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 NGLs). Despite reduced production in East Edson, and a substantially fixed operating cost base, operating costs are forecast to remain in the top quartile 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
(1) Excludes budgeted abandonment and reclamation spending of $1.5 to $2.0 million in 2019.
Perpetual expects the 2019 capital program will be 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 approximately 22% of the production mix. The Company expects to exit the year at over 11,500 boe/d (80% natural gas) as production ramps up again driven by the second half capital spending program targeting seasonal natural gas price optimization. This represents a reduction in average daily production in 2019 of approximately 11% relative to 2018, but includes a 16% increase in oil and NGL production.
Cash costs of $17.00 to $18.00/boe are forecast for 2019, up approximately 13% to 16% from 2018 guidance due to the impact of 11% lower forecast 2019 production on a substantially fixed operating cost base. Increased oil production in 2019 that is higher cost than compared to natural gas cash costs, 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)
(1) Net of royalties.
(2) 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 ceiling price of US$72.40/bbl, along with a 500 bbl/d WCS differential fixed at US$26.83/bbl.
Guidance assumptions are as follows:
Exploration and development expenditures ($ millions)
$21 - $25
2019 cash costs ($/boe)
$17.00 - $18.00
2019 average daily production (boe/d)
9,200 - 9,600
2019 average production mix (%)
22% oil and NGL
Commodity price assumptions reflect market price levels as follows:
2019 average NYMEX natural gas price (US$/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 $35 million), is forecast at $103 to $108 million, with an estimated net debt to trailing twelve months adjusted funds flow ratio of approximately 4.3 times. Current guidance is based on the following assumptions:
The following sensitivities can be applied to estimate changes to projected 2019 cash flow from operating activities and adjusted funds flow, assuming no change in differentials to Perpetual's market pricing points:
Financial and Operating Highlights
Three months ended
Nine months ended
except volume and per share amounts)
Oil and natural gas revenue
Per share – basic and diluted(2)
Cash flow from operating activities
Adjusted funds flow(1)
Revolving bank debt
Senior notes, at principal amount
Term loan, at principal amount
TOU share margin demand loan, at principal amount
TOU share investment
Net working capital deficiency(1)
Total net debt(1)
Net capital expenditures
Net payments (proceeds) on acquisitions and dispositions
Net capital expenditures
Common shares outstanding (thousands)(3)
End of period
Weighted average – basic and diluted
Natural gas (MMcf/d)
Realized natural gas price ($/Mcf)
Realized oil price ($/bbl)
Realized NGL price ($/bbl)
Natural gas – gross (net)
Oil – gross (net)
Total – gross (net)
(1) These are non-GAAP measures. Please refer to "Non-GAAP Measures" below.
(2) Based on weighted average common shares outstanding for the period.
(3) All common shares are presented net of shares held in trust.
Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual operates a diversified asset portfolio, including liquids-rich natural gas assets in the deep basin of west central Alberta, heavy oil and shallow natural gas in eastern Alberta, with longer term opportunities through undeveloped oil sands leases in northern Alberta. Additional information on Perpetual can be accessed at www.sedar.com or from the Corporation's website at www.perpetualenergyinc.com.
The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.
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; drilling, completion and development activities; infrastructure expansion and construction; 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, 2017 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). In addition, defence costs of legal claims can be substantial, even with respect to claims that have no merit and due to the inherent uncertainty of the litigation process, the resolution of the legal proceeding to which the Company has become subject could have a material effect on the Company's financial position and results of operations. 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.
This news release contains the terms "adjusted funds flow", "adjusted funds flow per share", "adjusted funds flow per boe", "annualized adjusted funds flow", "cash costs", "net working capital deficiency (surplus)", "net debt", "net bank debt", "operating netback" and "realized revenue" 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.
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.
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 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 our operating areas. Expenditures on decommissioning obligations are managed through our 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. 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 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 earnings 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 a period.
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, G&A and cash interest expense and income. Cash costs per boe is calculated by dividing cash costs by total production sold in a period.
Net debt and net bank debt: Net bank debt is measured as current and long-term bank indebtedness 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 bank debt and net debt are used by management to analyze borrowing capacity.
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.
Operating netback: Perpetual considers operating netback 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 costs 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.
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 is used by management to calculate the Corporation's net realized commodity prices, taking into account monthly settlements of foreign exchange contracts, financial crude oil and natural gas forward sales, collars and basis differentials. These contracts are put in place to protect Perpetual's adjusted funds flow from potential volatility in commodity prices, and as such, any related realized gains or losses are considered part of the Corporation's realized price.
Perpetual's aggregate proved and probable reserves are reported in barrels of oil equivalent (boe). Boe may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas of 6 Mcf: 1 boe has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
The following abbreviations used in this news release have the meanings set forth below:
barrels of oil equivalent
thousand cubic feet
million cubic feet
million British Thermal Units
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 Officer; W. Mark Schweitzer, Vice President Finance and Chief Financial Officer