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Perpetual Energy Inc. Releases Third Quarter 2018 Financial and Operating Results and Provides 2019 Guidance

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

  • During the third quarter, operations were focused on growing the Company's heavy oil production in the Mannville area of Eastern Alberta. Capital expenditures included the drilling of three (3.0 net) new heavy oil horizontal wells, along with a fourth well that was re-entered to add three additional laterals. Two of the wells were tied-in to production at the end of the third quarter, and the remaining two came online during the first week of October. The new drills are performing as forecast. The Company also re-purposed an inventoried generator and installed it at Mannville to improve the value of shallow gas sales by selling power to the grid. In addition, Perpetual acquired the remaining 33% working interest in a Mannville heavy oil pool, adding approximately 65 boe/d of production, for $1.3 million.

  • Perpetual's proactive market diversification strategy implemented in 2017 provided a 98% uplift over average AECO Daily Index prices during the third quarter of 2018 (Q3 2017 – nil). 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.

  • 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 Resources Corp. ("Sequoia"), with the Alberta Court of Queen's Bench (the "Court"), against Perpetual. The claim relates to an almost two-year-old transaction when, on October 1, 2016, Perpetual closed the disposition of shallow gas assets (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 award 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 and that they constitute an abuse of process. Perpetual's Application for Summary Dismissal is scheduled to be heard on November 8, 2018 with the Court's decision expected by the end of December. Management expects that the Company is more likely than not to be successful in defending against the claim such that no damages will be awarded against it, and therefore, no amounts have been accrued as a liability in these financial statements. The full text of the Statement of Defence and Application for Summary Dismissal as well as other related documents filed with the Court have been posted to the Company's website at http://www.perpetualenergyinc.com. Further information can be obtained by reviewing the public court documents that pertain to the action number 1801-10960, as filed with the Court, Calgary Judicial Centre.

  • Cash flow from operating activities in the third quarter of 2018 was $6.7 million ($0.11/share) up 16% compared to cash flow from operating activities in the prior year period of $5.8 million ($0.10/share).

  • Adjusted funds flow in the third quarter of 2018 was $5.2 million ($0.09/share), down 37% from the prior year period of $8.2 million ($0.14/share) due to decreased production and higher cash costs largely related to the remediation of the produced water pipeline break at Mannville and the Sequoia litigation, despite higher realized revenue per boe. Adjusted funds flow was $5.86/boe in the third quarter of 2018, down 32% from the prior year period of $8.63/boe and 28% lower than the second quarter of 2018 ($8.12/boe).

Production and Operations

  • Perpetual's exploration and development spending in the third quarter of 2018 was $4.3 million, 83% lower than $25.4 million spent in the comparative period of 2017. The three (3.0 net) third quarter 2018 drills at Mannville were development wells targeting higher pressure areas of existing pools under waterflood, and production results to date are consistent with expectations. The fourth well was a re-entry to add three additional legs to an existing horizontal well to evaluate the application of multi-lateral drilling technology for the large resource in place in tighter Mannville oil pools. Initial results are positive, and the Company will continue to monitor performance.

  • Third quarter capital spending also included the installation of a one-megawatt electricity generator at the Mannville plant site. The project will utilize fuel gas produced from the Mannville gas plant and convert it to electricity which will be sold on the grid, effectively increasing the value of Mannville gas production. The generator was sourced from internal inventory, minimizing the net cost of the project. The power project came online in the first week of October.

  • Spending at the East Edson property in West Central Alberta represented just 4% of total exploration and development expenditures in the third 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 nine months ended September 30, 2018 included the drilling of one (1.0 net) Wilrich extended reach horizontal ("ERH") natural gas well and the frac and tie-in of two wells drilled in the fourth quarter of 2017. The 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.

  • Third quarter production averaged 9,569 boe/d, down 7% from 10,330 boe/d in the comparative period of 2017. The decrease was driven by approximately 700 boe/d of production that was shut-in at East Edson throughout the second and third quarters at the request of the Alberta Energy Regulator after the operator of record, 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 by Sequoia following the Shallow Gas Disposition. Production was shut-in, pending the completion of the bankruptcy trustee's review of Sequoia's assets and operations. Perpetual anticipates that production from these wells will resume by early 2019. Compared to the second quarter of 2018, production was down 10%. The decrease was driven by natural declines in East Edson resulting from limited capital investment during 2018 in response to low AECO natural gas prices.

  • Perpetual's petroleum and natural gas ("P&NG") revenue, before derivatives, for the three months ended September 30, 2018 of $20.5 million increased 2% from the third quarter of 2017 despite a 7% decrease in average daily production. Third quarter P&NG revenue was comparable to the second quarter of 2018, despite the 10% decline in average daily production.

  • Natural gas revenue, before derivatives, of $11.3 million in the third quarter of 2018 comprised 55% (Q3 2017 – 66%) of total P&NG revenue while natural gas production was 81% (Q3 2017 – 84%) of total production. Perpetual's 40,000 MMBtu market diversification contract contributed $5.0 million to revenue ($1.17/Mcf) over the AECO Daily Index price in the quarter. Natural gas revenue decreased 14% from $13.2 million in the third quarter of 2017, reflecting the impact of the 9% decrease in natural gas production volumes driven by natural declines following limited capital investment in East Edson during the second and third quarters of 2018.

  • Oil revenue of $5.4 million represented 26% (Q3 2017 – 21%) of total P&NG revenue while oil production was 11% (Q3 2017 – 9%) of total production. Oil revenue was 29% higher than the same period in 2017 due to the 13% increase in realized oil prices combined with the 4% increase in crude oil production. The improved WCS average prices are a function of a higher WTI US$ benchmark price and stronger US dollar, which more than offset the wider WCS differential compared to the prior year period. Oil revenue was 7% higher than the second quarter of 2018, due to the 5% increase in crude oil production.

  • NGL revenue for the third quarter of 2018 of $3.8 million represented 19% (Q3 2017 – 13%) of total P&NG revenue while NGL production was just 8% (Q3 2017 – 7%) of total Company production. NGL revenue increased by 43% over the prior year period while NGL production remained flat despite declining natural gas production, reflecting higher condensate yields and a 43% increase in NGL prices compared to the prior year period. NGL revenue was 16% lower than the second quarter of 2018, due to the 9% decline in NGL production combined with an 8% decrease in realized NGL pricing.

  • Royalty expenses for the third quarter of 2018 were $2.7 million, consistent with the comparable period of 2017 and the second quarter of 2018. The combined average royalty rate on P&NG revenue remained consistent with the prior year period at approximately 13%. For the nine months ended September 30, 2018, sharply lower Alberta Gas Reference prices (43% decline) and AECO Daily Index prices (35% decline) used to calculate crown and freehold natural gas royalties respectively, contributed to most of the decrease in royalty expense from $9.3 million to $8.3 million, despite the 20% increase in natural gas production over the same period.

  • Total production and operating expenses were up 72% on a unit-of-production basis to $6.02/boe for the third quarter of 2018, compared to $3.50/boe for the comparable period of 2017. The increase was driven by remediation costs of $0.8 million ($0.91/boe) incurred from the Mannville produced water spill and the absence of a $0.9 million ($0.95/boe) non-recurring adjustment in the prior year period associated with third party processing facilities that were sold as part of the Shallow Gas Disposition. Remediation work related to the pipeline break at Mannville was completed in early October. Production and operating expenses increased 23% from $4.3 million in Q2 2018, with the cost per boe increasing 35% due to the impact of increased costs on declining production volumes.

  • Transportation costs in the third quarter of 2018 were $1.6 million, up 19% from the prior year period due to the increase in firm natural gas transportation commitments at East Edson to 78 MMcf/d that commenced in December 2017. Transportation costs averaged $1.71/boe at West Central compared to $2.22/boe for production from Eastern Alberta. On a unit-of-production basis, transportation costs were $1.81/boe in the third quarter, up 29% from the prior year period due to the impact of fixed firm capacity transportation costs against lower production.

  • Perpetual's operating netback of $11.0 million ($12.49/boe) in the third quarter of 2018 decreased 18% from $13.4 million ($14.12/boe) in the comparative period of 2017. This decrease was due to the 7% decrease in production caused by natural declines at East Edson, combined with a 12% decrease in operating netback per boe. The lower operating netback per boe in the third quarter of 2018 reflected a 7% increase in realized revenue per boe due to improved crude oil and NGL pricing. Higher realized selling prices were more than offset by the associated increase in royalties as well as higher operating costs. Compared to the second quarter of 2018, Perpetual's operating netback decreased 10% from $13.85/boe due primarily to the increased production and operating expenses resulting from the Mannville produced water spill.

Financial Highlights

  • During the third quarter of 2018, cash general and administrative ("G&A") expense was $3.8 million, a slight decrease from the prior year period of $3.9 million. Cash G&A expense increased by $0.3 million over the second quarter of 2018, due primarily to Sequoia litigation defence costs. The Company expects the majority of future defence costs will be covered by insurance. Compared to the prior year period, third quarter 2018 overhead recoveries decreased by 60% due to reduced capital spending, combined with a reduction in expenditures on decommissioning obligations. On a unit-of-production basis, total G&A expense of $3.86/boe for the three months ended September 30, 2018 was up 29% from the prior year period due to the impact of decreasing production.

  • Total cash interest expense and income of $2.2 million for the three months ended September 30, 2018 was 10% higher than the prior year period (Q3 2017 – $2.0 million) due to increased debt levels, partially offset by dividend income of $0.2 million ($0.10 per TOU share) received from the TOU share investment during the third quarter of 2018 (Q3 2017 – nil). Total cash interest expense for the third quarter of 2018 was consistent with the previous quarter but increased on a unit-of-production basis from $2.22/boe to $2.51/boe due to the impact of decreasing production.

  • Net loss for the third quarter of 2018 was $12.3 million ($0.20/share), compared to a net loss of $8.1 million ($0.14/share) in the comparative period of 2017. The increase in net loss from the prior year period was due primarily to a $7.2 million ($0.12/share) write-down of exploration and evaluation ("E&E") assets during the third quarter of 2018.

  • At September 30, 2018, Perpetual had total net debt of $105.4 million, down $0.6 million from December 31, 2017, as net cash flow from operations and net proceeds from non-core asset sales exceeded capital expenditures and acquisitions during the year-to-date period. The net working capital deficiency of $7.5 million at September 30, 2018 decreased by $8.9 million from December 31, 2017, due to reduced capital expenditures during the third quarter of 2018 compared to the fourth quarter of 2017, resulting in lower payables at September 30, 2018 compared to December 31, 2017. The decrease in the net working capital deficiency was funded by a corresponding increase in revolving bank debt. Compared to June 30, 2018, net debt increased 5% from $100.2 million, reflecting the final settlement of the gas marketing contract related to the Shallow Gas Disposition.

  • As at September 30, 2018, 60% of net debt outstanding was repayable in 2021 or later. Perpetual's net debt to trailing twelve months adjusted funds flow improved during the nine months ended September 30, 2018 to 3.0 times at September 30, 2018 (December 31, 2017 – 3.4 times).

OUTLOOK

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:


Q4 Guidance

Q3 Guidance

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:


Q4 Guidance

Q3 Guidance

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

$2.97

$2.85

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

$67.11

$65.24

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

($25.68)

($23.62)

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

$1.29

$1.30

 

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:

  • Net debt at September 30, 2018 of $105.4 million
  • Adjusted funds flow for the remainder of 2018 of $5 to $7 million
  • Capital spending for the remainder of 2018 of $4 to $5 million
  • Decommissioning expenditures for the remainder of 2018 of $0.5 to $1.0 million

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


H1 2019

($ millions)

# of wells

(gross/net)

H2 2019

($ millions)

# of wells

(gross/net)

West Central liquids-rich gas

0

0/0.0

12

2/2.0

Eastern Alberta

0

0/0.0

11

10/10.0

Total(1)

0

0/0.0

23

12/12.0

(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:

Market/Pricing Point


Estimated 2019 Exposure

Natural gas


     AECO(1)

     AECO - fixed price

2%

     Empress

7%

     Dawn

15%

     Michcon

10%

     Chicago

24%

     Malin

21%

Total natural gas

79%

Natural gas liquids - Condensate(1)

4%

Natural gas liquids - Other(1)

2%

Crude oil(1)(2)

15%

Total

100%

(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:


2019 Guidance

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 Guidance

2019 average NYMEX natural gas price (US$/MMBtu)

$2.89

2019 average West Texas Intermediate ("WTI") oil price (US$/bbl)

$69.81

2019 average Western Canadian Select ("WCS") differential (US$/bbl)

($29.16)

2019 average exchange rate (US$1.00 = Cdn$)

$1.30

 

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:

  • Net debt at December 31, 2018 of $104 to $107 million
  • Adjusted funds flow for 2019 of $22 to $27 million ($0.36/share to $0.44/share)
  • Capital spending for 2019 of $21 to $25 million
  • Decommissioning expenditures for 2019 of $1.5 to $2.0 million

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:

  • For every US$0.25/MMBtu increase or decrease in the Calendar 2019 NYMEX Daily Index price, adjusted funds flow increases or decreases by $4.8 million;
  • For every US$2.50/bbl increase or decrease in the Calendar 2019 WTI light oil price, adjusted funds flow increases or decreases by $1.4 million;
  • For every 2.5 MMcf/d increase or decrease in average natural gas production, adjusted funds flow increases or decreases by $1.4 million; and
  • For every 250 bbl/d increase or decrease in average crude oil and NGL production, adjusted funds flow increases or decreases by $4.2 million.

Financial and Operating Highlights

 

Three months ended

September 30

Nine months ended

 September 30

(Cdn$ thousands,

 except volume and per share amounts)

2018

2017

Change

2018

2017

 Change

Financial







Oil and natural gas revenue

20,504

20,026

2%

64,618

57,912

12%

Net loss

(12,259)

(8,082)

(52%)

(20,049)

(29,473)

32%

Per share – basic and diluted(2)

(0.20)

(0.14)

(43%)

(0.33)

(0.51)

35%

Cash flow from operating activities

6,729

5,778

16%

26,362

8,217

221%

Per share(2)

0.11

0.10

10%

0.44

0.14

214%

Adjusted funds flow(1)

5,155

8,199

(37%)

22,103

18,574

19%

Per share(2)

0.09

0.14

(36%)

0.37

0.32

16%

Revolving bank debt

42,431

29,262

45%

42,431

29,262

45%

Senior notes, at principal amount

32,490

32,490

32,490

32,490

Term loan, at principal amount

45,000

35,000

29%

45,000

35,000

29%

TOU share margin demand loan, at principal amount

15,681

18,740

(16%)

15,681

18,740

(16%)

TOU share investment

(37,675)

(42,304)

(11%)

(37,675)

(42,304)

(11%)

Net working capital deficiency(1)

7,484

19,556

(62%)

7,484

19,556

(62%)

Total net debt(1)

105,411

92,744

14%

105,411

92,744

14%

Net capital expenditures







Capital expenditures

4,343

25,392

(83%)

21,271

53,988

(61%)

Net payments (proceeds) on acquisitions and dispositions

4,341

680

538%

(1,745)

1,452

(220%)

Net capital expenditures

8,684

26,072

(67%)

19,526

55,440

(65%)

Common shares outstanding (thousands)(3)







End of period

60,524

59,316

2%

60,524

59,316

2%

Weighted average – basic and diluted

60,468

59,152

2%

59,900

57,572

4%

Operating







Average production







Natural gas (MMcf/d) 

46.9

51.8

(9%)

55.2

45.9

20%

Oil (bbl/d)

1,022

978

4%

965

968

NGL (bbl/d)

730

733

794

627

27%

Total (boe/d)

9,569

10,330

(7%)

10,965

9,240

19%

Average prices







Realized natural gas price ($/Mcf)

2.83

2.99

(5%)

2.69

3.65

(26%)

Realized oil price ($/bbl)

48.57

43.01

13%

50.06

39.86

26%

Realized NGL price ($/bbl)

56.02

39.06

43%

58.19

43.59

33%

Wells drilled







Natural gas – gross (net)

5 (4.4)


1 (1.0)

12 (11.4)


Oil – gross (net)

3 (3.0)


6 (6.0)

4 (3.3)


Total – gross (net)

3 (3.0)

5 (4.4)


7 (7.0)

16 (14.7)


(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). 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.

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", "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.

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.

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: info@perpetualenergyinc.com; Susan L. Riddell Rose; President and Chief Executive Officer; W. Mark Schweitzer, Vice President Finance and Chief Financial Officer