August 2, 2018 - 8:10 PM EDT
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Perpetual Energy Inc. Releases Second Quarter 2018 Financial and Operating Results

Canada NewsWire

CALGARY, Aug. 2, 2018 /CNW/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release its second quarter 2018 financial and operating results. A complete copy of Perpetual's unaudited condensed interim consolidated financial statements and related Management Discussion and Analysis ("MD&A") for the three and six months ended June 30, 2018 can be obtained through the Company's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.

SECOND QUARTER 2018 HIGHLIGHTS

  • Cash flow from operating activities in the second quarter of 2018 was $8.4 million ($0.14/share), up 79% compared to cash flow from operating activities in the prior year period of $4.7 million ($0.08/share).

  • Adjusted funds flow in the second quarter of 2018 was $7.8 million ($0.13/share), up 47% over the prior year period of $5.3 million ($0.09/share) due to increased production and lower cash costs, partially offset by lower realized revenue per boe driven by lower commodity prices. Adjusted funds flow was $8.12/boe in the second quarter of 2018, up 30% over the prior year period, and up slightly from $7.94/boe in the first quarter of 2018.

  • Production averaged 10,620 boe/d in the second quarter of 2018, up 15% from the comparable period in 2017 driven by the successful Wilrich development program at East Edson executed throughout 2017 and into the first quarter of 2018. With the precipitous drop in the forward market for natural gas prices in Western Canada in early 2018, the East Edson drilling program was paused to preserve value, leading to natural declines in the production base during the second quarter of 2018 as compared to the first quarter.

  • Perpetual's market diversification contract contributed $5.1 million to natural gas revenue during the quarter and increased Perpetual's average realized natural gas price by $1.06/Mcf over the AECO Daily Index price. The 40,000 MMBtu/d market diversification contract is priced based on daily index prices at five pricing hubs outside of Alberta that generally track North American NYMEX prices and is effectively mitigating the impact of low and volatile natural gas prices at the Alberta AECO hub.

  • Cash costs were $14.19/boe in the second quarter of 2018, down 18% compared to the prior year period due to diligent cost management combined with the impact of increased production at East Edson on a substantially fixed cost base.

  • Exploration and development spending in the second quarter of 2018 was seasonally low, totaling $1.7 million, of which 82% was incurred at Mannville to complete and tie-in wells drilled during the first quarter of 2018 and acquire certain crown lands in Eastern Alberta.

  • Non-core asset dispositions during the second quarter included the sale of royalty interests and undeveloped land for gross proceeds of $12.1 million, contributing to the 13% reduction in net debt quarter over quarter.

  • At June 30, 2018, Perpetual had total net debt of $100.2 million, down $14.9 million (13%) from March 31, 2018, as cash flow from operations exceeded capital expenditures and combined with proceeds from non-core asset sales and an increase in market value of the Tourmaline Oil Corp. ("TOU") share investment.

Production and Operations

  • For the six months ended June 30, 2018, spending in Eastern Alberta consisted of a three well (3.0 net) multi-lateral horizontal drilling program, one waterflood injector well conversion, one water disposal well conversion and associated facilities in the Company's Mannville heavy oil property. The disposal facility is working as intended, and is contributing to operating cost improvements. Pressure response is apparent from the injector conversion completed in December of 2017, further validating the success of the Mannville waterfloods. For the balance of 2018, drilling plans in Eastern Alberta include the drilling of five to nine (4.3 – 8.3 net) wells targeting banked waterflood oil, pool extensions, and follow up multi-lateral drilling in early stage pool development, along with several heavy oil reactivations.

  • Spending at the East Edson property in West Central Alberta represented 18% of total exploration and development expenditures in the second quarter of 2018, and consisted primarily of maintenance activities associated with reconfiguring equipment for higher Natural Gas Liquids ("NGL") recoveries. East Edson capital activity for the six months ended June 30, 2018 included the drilling of one (1.0 net) Wilrich extended reach horizontal ("ERH") well and the frac and tie-in of two wells drilled in the fourth quarter of 2017. The one well drilled during the first quarter is expected to be frac'd and tied-in to production during the fourth quarter of 2018 to align high initial production rates with higher anticipated winter natural gas prices.

  • Second quarter production averaged 10,620 boe/d, up 15% from 9,223 boe/d in the comparative period of 2017, reflecting a 23% increase in natural gas and associated NGL production at East Edson. Compared to the first quarter of 2018, production was down 2,122 boe/d of which 1,050 boe/d was temporarily shut-in. The remainder of the drop related to natural declines stemming from the suspension of development at East Edson. Shut-ins and natural declines were offset somewhat by a 10% increase in heavy oil production at Mannville from the first quarter of 2018 to 943 bbl/d, as production from heavy oil wells drilled during the first quarter ramped up.

  • Perpetual voluntarily shut-in an average 350 boe/d of East Edson production during the quarter to take advantage of short-term situations when natural gas could be purchased at minimal cost to satisfy pre-sold volume commitments at attractive margins, resulting in an increase in realized revenue of $0.04/Mcf while retaining reserves for future production. Additionally, approximately 700 boe/d of production was shut-in at East Edson at the request of the Alberta Energy Regulator after the operator of record, Sequoia Resources Corp. ("Sequoia"), filed for bankruptcy. The four well pad at East Edson is 100% owned by Perpetual, but Sequoia was designated operator to facilitate the recovery of Perpetual's gas over bitumen royalty credit amounts held through Sequoia following the disposition of the shallow gas assets on October 1, 2016 (the "Shallow Gas Disposition"). Production remains shut-in pending the completion of the bankruptcy trustee's review of Sequoia's assets and operations. We anticipate production will be restarted later in the fourth quarter of 2018 after the bankruptcy trustee's review has been completed.

  • Perpetual's petroleum and natural gas ("P&NG") revenue, before derivatives, for the three months ended June 30, 2018 of $20.8 million increased 5% from the second quarter of 2017 due to a 15% increase in average daily production, partially offset by lower natural gas prices. Compared to the first quarter of 2018, P&NG revenue declined by 11% due to the impact of lower natural gas production at East Edson.

  • Natural gas revenue, before derivatives, of $11.3 million in the second quarter of 2018 comprised 54% (Q2 2017 – 64%) of total P&NG revenue while natural gas production was 83% (Q2 2017 – 81%) of total production. Natural gas revenue decreased 11% from $12.7 million in the second quarter of 2017, reflecting the impact of the 58% decrease in AECO Daily Index natural gas prices which more than offset the 18% increase in production volumes.

  • Oil revenue of $5.1 million represented 24% (Q2 2017 – 22%) of total P&NG revenue while oil production was 9% (Q2 2017 – 11%) of total production. Oil revenue was 16% higher than the same period in 2017 due to the 26% increase in Western Canadian Select ("WCS") average prices which more than offset the 7% decline in crude oil production. The improving WCS average prices are a function of a higher WTI US$ benchmark price which more than offsets the wider WCS differential and stronger Canadian dollar compared to the prior year period. Compared to the first quarter of 2018, oil revenue was 45% higher, due to the 8% increase in crude oil production and 10% increase in Perpetual's realized oil price per barrel.

  • NGL revenue for the second quarter of 2018 of $4.5 million represented 22% (Q2 2017 – 14%) of total P&NG revenue while NGL production was just 8% (Q2 2017 – 7%) of total Company production. NGL revenue increased by 66% over the prior year period as production increased by 21%, reflecting increased natural gas production at East Edson and higher NGL recoveries related to process optimization work, combined with a 37% increase in NGL prices compared to the prior year period. NGL revenue was consistent with the first quarter of 2018, as the 5% decline in production was offset by a corresponding 5% increase in realized NGL pricing.

  • Royalty expenses for the quarter ended June 30, 2018 were $2.6 million, 28% lower than the comparable period of 2017, as higher revenue in the current quarter was offset by a decrease in the combined average royalty rate on P&NG revenue from 18.3% in the prior year period to 12.4% in the second quarter of 2018. Sharply lower Alberta gas reference prices and AECO Daily Index prices used to calculate crown and freehold natural gas royalties respectively, contributed to most of the decrease in royalty expense. Royalty expenses also declined by 15% from the first quarter of 2018 for the same reasons mentioned above, with the cost per boe largely unchanged.

  • Total production and operating expenses of $4.3 million were down 19% on a unit-of-production basis to $4.45/boe for the second quarter of 2018, compared to $5.52/boe for the comparable period of 2017. On an absolute dollar basis, production and operating costs were down by $0.3 million, despite the 15% increase in production. Increased production at East Edson combined with a low variable cost structure, drove West Central operating costs down to $2.25/boe in the second quarter of 2018 (Q2 2017 – $3.29/boe). Production and operating expenses declined 10% from $4.8 million in Q1 2018, with the cost per boe increasing 7% due to the impact of largely fixed costs on declining production volumes.

  • Transportation costs in the second quarter of 2018 were $1.5 million, up 26% from the prior year period due to the increase in firm transportation commitments at East Edson that commenced in December 2017. Transportation costs averaged $1.50/boe at West Central compared to $2.07/boe for production from Eastern Alberta. On a unit-of-production basis, transportation costs were $1.60/boe in the second quarter (Q1 2017 - $1.26/boe), up 10% from the prior year period due to the nature of fixed firm capacity costs relative to lower production.

  • Perpetual's operating netback of $13.4 million ($13.85/boe) in the second quarter of 2018 increased 28% from $10.4 million ($12.42/boe) in the comparative period of 2017. This increase was due to the 15% increase in production, combined with a 12% increase in operating netback per boe. Compared to the prior quarter, Perpetual's operating netback increased 8% from $12.87/boe due to increased realized revenue per boe stemming from the Company's realized gains on derivatives and contributions from the natural gas market diversification contract.

Financial Highlights

  • During the second quarter of 2018, cash general and administrative ("G&A") expense was $3.5 million, a modest decrease from the prior year period of $3.6 million. Compared to the prior year period, overhead recoveries decreased by 16% as a result of reduced capital spending, offset partially by the increase in expenditures on decommissioning obligations. On a unit-of-production basis, total G&A expense of $3.24/boe for the three months and $3.05/boe for the six months ended June 30, 2018, was down 13% and 23% respectively from the prior year periods due to increasing production. Compared to the first quarter of 2018, total G&A expense decreased by 5% on an absolute dollar basis, as savings on cash G&A were partially offset by lower overhead recoveries resulting from seasonally reduced capital expenditures.

  • Total cash interest expense of $2.1 million for the three months ended June 30, 2018 was 11% higher than the prior year period (Q2 2017 – $1.9 million) due to increased debt levels partially offset by dividend income of $0.2 million ($0.09 per TOU share) received from the TOU share investment. Total cash interest expense was consistent with the first quarter of 2018 at $2.1 million, but increased on a unit-of-production basis from $1.84/boe to $2.22/boe due to declining quarter-over-quarter production.

  • Net loss for the second quarter of 2018 was $1.3 million ($0.02/share), compared to a net loss of $7.2 million ($0.12/share) in the comparative 2017 period. The improvement from the prior year period reflected stronger operational and capital performance including a 15% increase in production, 18% reduction in cash costs per boe and a 4% reduction in depletion expense per boe, partially offset by a 5% decrease in realized revenue per boe related to lower natural gas prices.

  • At June 30, 2018, Perpetual had total net debt of $100.2 million, down $5.8 million from December 31, 2017 and $14.9 million from March 31, 2018 as net cash flow from operations, net proceeds from non-core asset sales completed in the second quarter, and the increased market value of the TOU share investment exceeded capital expenditures during the second quarter and on a year-to-date basis. 

  • As at June 30, 2018, 63% of net debt outstanding was repayable in 2021 or later. Perpetual's net debt to trailing twelve months adjusted funds flow improved slightly during the six months ended June 30, 2018 to 2.7 times at June 30, 2018 (December 31, 2017 – 3.4 times).

2018 OUTLOOK

Perpetual has increased its 2018 capital expenditure guidance from a range of $21 to $25 million provided in a press release dated May 8, 2018 ("Previous Guidance") to $25 to $30 million ($8 to $13 million for the remainder of 2018) and increased its planned Mannville heavy oil drilling in the second half of 2018 to five to nine wells (4.3 - 8.3 net) from two wells (1.3 net) previously. At East Edson, one horizontal well drilled in the first quarter will be completed and tied-in during the fourth quarter of 2018 to align high initial production rates with higher anticipated winter natural gas prices. Additional development drilling is ready to activate if AECO forward prices normalize above $2.00/Mcf. Additionally, decommissioning expenditures are anticipated to be $1.0 to $1.5 million for the remainder of 2018, consistent with Previous Guidance. Capital spending during the remainder of 2018 will be funded through adjusted funds flow.

Production for 2018 is expected to be 10,500 boe/d to 11,000 boe/d, consistent with Previous Guidance. East Edson production that has been shut-in due to the Sequoia bankruptcy proceedings, is anticipated to be restarted during the fourth quarter after the bankruptcy trustee's review has been completed. For the April through October period, Perpetual has fixed the price on 20,000 GJ/d at $1.74/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 oil sales arrangements in place to sell 750 bbl/d at an average US$60.71/bbl for the remainder of 2018. Additionally, Perpetual has fixed the US$/Cdn$ exchange rate on approximately 65% of its US$ denominated sales at a rate of $1.301 for the remainder of 2018.

Cash costs of $14.00 to $15.00/boe are anticipated for 2018, consistent with Previous Guidance.

Adjusted funds flow for 2018 is anticipated to be in the $26 to $30 million range, up slightly from Previous Guidance of $25 to $28 million due to improved performance in the second quarter.

Guidance assumptions are as follows:


Current
Guidance

Prior Guidance

Exploration and development expenditures ($ millions)

$25 - 30

$21 - 25

2018 cash costs ($/boe)

$14.00 - $15.00

$14.00 - $15.00

2018 average daily production (boe/d)

10,500 - 11,000

10,500 - 11,000

2018 average production mix (%)

16% oil and NGL

15% oil and NGL

 

Commodity price assumptions reflect market price levels as follows:


Current Guidance

Prior Guidance

2018 average NYMEX natural gas price (US$/MMBtu)

$2.85

$2.86

2018 average NYMEX to AECO basis differential (US$/MMBtu)

($1.68)

($1.73)

2018 average West Texas Intermediate ("WTI") oil price (US$/bbl)

$65.24

$65.55

2018 average Western Canadian Select ("WCS") differential (US$/bbl)

($23.62)

($22.30)

2018 average exchange rate (US$1.00 = Cdn$)

$1.298

$1.277

 

Year end 2018 net debt (net of the current market value of the Company's TOU share investment of approximately $40 million) is forecast at $98 - 103 million, down from Previous Guidance of $105 - $110 million, due to net proceeds received from non-core asset dispositions during the second quarter and an increase in the current market value of TOU shares, offset by modestly higher capital spending. Current guidance is based on the following assumptions:


  • Net debt at June 30, 2018 of $100.2 million
  • Adjusted funds flow for the remainder of 2018 of $11 to $15 million
  • Capital spending for the remainder of 2018 of $8 to $13 million
  • Decommissioning expenditures for the remainder of 2018 of $1.0 to $1.5 million
  • Shallow Gas Disposition – fixed marketing obligation payment of $3.1 million in the third quarter of 2018

Financial and Operating Highlights

 

Three months ended

June 30

Six months ended

 June 30

(Cdn$ thousands,

 except volume and per share amounts)

2018

2017

Change

2018

2017

 Change

Financial







Oil and natural gas revenue

20,774

19,728

5%

44,114

37,886

16%

Net loss

(1,325)

(7,219)

(82%)

(7,790)

(21,391)

(64%)


Per share – basic and diluted(2)                             

(0.02)

(0.12)

(83%)

(0.13)

(0.38)

(66%)

Cash flow from operating activities

8,435

4,728

78%

19,633

2,439

705%


Per share(2)                                

0.14

0.08

75%

0.33

0.04

725%

Adjusted funds flow(1)

7,847

5,265

49%

16,948

10,375

63%


Per share(2)

0.13

0.09

44%

0.28

0.18

56%

Revolving bank debt

42,752

4,404

871%

42,752

4,404

871%

Senior notes, at principal amount

32,490

33,490

(3%)

32,490

33,490

(3%)

Term loan, at principal amount

45,000

35,000

29%

45,000

35,000

29%

TOU share margin loans, at principal amount

15,714

35,543

(56%)

15,714

35,543

(56%)

TOU share investment

(38,917)

(46,489)

(16%)

(38,917)

(46,489)

(16%)

Net working capital deficiency(1)

3,123

6,389

(51%)

3,123

6,389

(51%)

Total net debt(1)

100,162

68,337

47%

100,162

68,337

47%

Net capital expenditures








Capital expenditures

2,031

4,006

(49%)

16,928

28,596

(41%)


Net payments (proceeds) on acquisitions and
dispositions

(7,012)

609

(1,251%)

(6,086)

772

(888%)

Net capital expenditures

(4,981)

4,615

(208%)

10,842

29,368

(63%)

Common shares outstanding (thousands)(3)







End of period

60,369

59,035

2%

60,369

59,035

2%

Weighted average – basic and diluted

59,876

59,045

1%

59,612

56,769

5%

Operating







Average production








Natural gas (MMcf/d)                    

53.1

45.1

18%

59.4

42.9

38%


Oil (bbl/d)

971

1,049

(7%)

936

962

(3%)


NGL (bbl/d)

806

665

21%

827

573

44%


Total (boe/d)

10,620

9,223

15%

11,675

8,686

34%

Average prices








Realized natural gas price ($/Mcf)

2.62

3.18

(18%)

2.64

4.05

(35%)


Realized oil price ($/bbl)

53.26

43.91

21%

50.89

38.24

33%


Realized NGL price ($/bbl)

60.77

44.28

37%

59.16

46.54

27%

Wells drilled








Natural gas – gross (net)

1 (1.0)

1 (1.0)


1 (1.0)

7 (7.0)



Oil – gross (net)

3 (3.0)


3 (3.0)

4 (3.3)


Total – gross (net)

4 (4.0)

1 (1.0)


4 (4.0)

11 (10.3)


 

(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.

 

About Perpetual

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.

Forward-Looking Information

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). 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.

Non-GAAP Measures

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 and 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, (six months ended June 30, 2018 – nil; and six months ended June 30, 2017$0.02 million recovery) 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, general and administrative 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 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 loan 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.

BOE Equivalents

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:

bbls        

 barrels

boe          

 barrels of oil equivalent

Mcf            

 thousand cubic feet

MMcf          

 million cubic feet

MMBtu         

 million British Thermal Units

GJ                 

 gigajoules

 

SOURCE Perpetual Energy Inc.

View original content: http://www.newswire.ca/en/releases/archive/August2018/02/c2072.html

Perpetual Energy Inc., Suite 3200, 605 - 5 Avenue SW Calgary, Alberta, Canada T2P 3H5, Telephone: 403 269-4400, Fax: 403 269-4444, Email: [email protected]; Susan L. Riddell Rose, President and Chief Executive Officer; W. Mark Schweitzer, Vice President Finance and Chief Financial OfficerCopyright CNW Group 2018


Source: Canada Newswire (August 2, 2018 - 8:10 PM EDT)

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