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Perpetual Energy Inc. reports fourth quarter and year-end 2018 financial and operating results and credit facility extension


CALGARYMarch 27, 2019 /CNW/ – (TSX:PMT) – Perpetual Energy Inc. (“Perpetual”, the “Corporation” or the “Company”) is pleased to release its fourth quarter and year-end 2018 financial and operating results and announce the confirmation of the borrowing limit on its bank credit facility at $55 million and the extension of the maturity date to November 30, 2020. A complete copy of Perpetual’s audited consolidated financial statements, Management’s Discussion and Analysis (“MD&A”) and Annual Information Form for the year ended December 31, 2018 will be available through the Corporation’s website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.

FOURTH QUARTER AND YEAR-END 2018 FINANCIAL AND OPERATING RESULTS

The execution of our growth-oriented capital program at East Edson in 2017 set the stage for improved performance across all operating measures in 2018. However, the collapse in Western Canadian natural gas prices in early 2018 drove the Company to minimize natural-gas focused development activities until stronger pricing could be realized. Commodity price volatility was experienced in Western Canada due to restricted market access for oil, natural gas and natural gas liquids (“NGL”), driving prices lower for all commodities relative to North American benchmarks, especially during the fourth quarter. Perpetual was well positioned to participate in the stronger natural gas pricing environment driven by the early onset of winter in other parts of North America through its market diversification strategy, resulting in solid results in the fourth quarter and year ended December 31, 2018 as highlighted below:

Fourth Quarter 2018 Highlights

Capital Spending, Production and Operations

  • Exploration and development spending in the fourth quarter of 2018 was $5.6 million, consistent with capital spending guidance provided with Perpetual’s third quarter earnings release, and 71% lower than the comparative period in 2017.
    • In West Central, capital expenditures of $4.2 million were directed towards the frac and tie-in operations of one (1.0 net) Wilrich extended reach horizontal (“ERH”) natural gas well that was drilled during the first quarter of 2018. The timing of this frac was intended to align high initial production rates with higher anticipated winter natural gas prices. Additional capital was spent on the installation of field compression and a sweetening tower to restore several higher liquids ratio wells back to production in early 2019
    • Fourth quarter exploration and development spending of $1.4 million in Eastern Alberta included completion and tie-in costs for three (3.0 net) heavy oil horizontal wells which were drilled during the third quarter, along with a fourth well that was re-entered to add three additional multi-lateral legs at Mannville. Capital was also invested to finish the installation of the one-megawatt electricity generator project at the Mannville plant site which came online in early October. The project is utilizing fuel gas produced from the Mannville gas plant and converting it to electricity to be sold on the grid, effectively increasing the value of Mannville natural gas production.
  • Production averaged 9,491 boe/d in the fourth quarter, down 19% from the prior year period as 2018 natural gas focused capital spending was deferred to preserve value during the low natural gas price environment in Alberta, with investment weighted to heavy oil drilling and waterflood activities.
  • Production was comparable to the third quarter of 2018, with steady increases through the fourth quarter resulting from the tie-in and ramp up of production from the third quarter heavy oil drilling program and the consolidation of the remaining 33% working interest in a Company-operated heavy oil pool in Mannvillecompleted during the third quarter of 2018, the frac and tie-in of the East Edson natural gas well in November, and the re-start of production from the East Edson four well pad in mid-December that had been shut-in at the request of the Alberta Energy Regulator (“AER”) after the operator of record, Sequoia Resources Corp. (“Sequoia”), filed for bankruptcy in March 2018. Perpetual also opportunistically shut-in an average 450 boe/d of East Edson production during the fourth quarter to take advantage of temporary situations when natural gas could be purchased at minimal cost to satisfy pre-sold volume commitments at attractive margins, resulting in incremental realized revenue while retaining reserves for future production.

Financial Highlights

  • Natural gas prices in Alberta continued to be weak in the fourth quarter of 2018, remaining disconnected from other North American markets that experienced a significant run up in prices from the seasonal increase in demand driven by the early on-set of winter weather. Perpetual’s market diversification contract which commenced sales in November 2017, enabled the Company to sell approximately 80% of its natural gas to markets outside of Alberta, resulting in a realized natural gas price that was 2.8 times the AECO Daily Index average price for the fourth quarter. The market diversification contract generated incremental revenue over AECO Daily Index pricing of $6.8 million ($1.64/Mcf) in the fourth quarter of 2018, $19.5 million ($1.02/Mcf) in 2018, and $1.0 million ($0.19/Mcf) in the fourth quarter of 2017.
  • Perpetual’s realized oil price of $19.83/bbl was 58% lower than the fourth quarter of 2017. The decrease in realized prices was due to the substantial widening of the WCS differential to an average US$39.42/bbl from US$12.26/bbl in the fourth quarter of 2017, which far outweighed the 6% increase in WTI benchmark pricing over the same period.
  • Perpetual’s realized NGL price for the fourth quarter of 2018 was $35.73/bbl, down 34% from the fourth quarter of 2017, reflecting a decrease in all NGL component prices which were impacted by similar transportation capacity issues that caused the WCS differential to widen.
  • Net loss for the fourth quarter of 2018 was $0.3 million ($0.01/share) compared to $6.5 million($0.11/share) in the prior year quarter. The reduction in net loss is mainly due to increased unrealized gains on derivatives associated with the run-up in NYMEX futures prices in the fourth quarter, partially offset by an increased unrealized loss on the Tourmaline Oil Corp. (“TOU”) share investment compared to the prior year period.
  • Net cash flow from operating activities for the fourth quarter ended December 31, 2018, was $5.2 millioncompared to $11.0 million in the prior year period. Changes in non-cash working capital balances contributed $1.5 million of the decrease in net cash flows from operating activities compared to the prior year period.
  • Strong realized natural gas price performance significantly outweighed the impact of deteriorating oil and NGL pricing experienced during the fourth quarter, with adjusted funds flow of $8.1 million ($0.13/share) exceeding fourth quarter guidance of $5 to $7 million.

2018 Annual Highlights

Capital Spending, Production and Operations

  • Perpetual executed a $26.5 million exploration and development capital program in 2018 that was funded from adjusted funds flow. Natural gas development spending was restricted due to the weak natural gas price environment in Western Canada. Effective program execution and strong asset performance resulted in replacement of 134% of 2018 production, posting proved plus probable reserve additions of 5.2 MMboe and 2% growth year-over-year, as reported by the independent engineering firm McDaniel and Associates Consultants Ltd. (“McDaniel”).
    • Spending in West Central in 2018 was $13.7 million, and included the drilling, completion and tie-in of one (1.0 net) Wilrich ERH natural gas well, along with the frac and tie-in of two additional wells which were drilled in the fourth quarter of 2017. Additional capital expenditures consisted of maintenance activities associated with reconfiguring equipment for higher NGL recoveries.
    • Spending in Eastern Alberta in 2018 was $12.9 million, and consisted of a six well (6.0 net) horizontal drilling program, including several multi-laterals, one waterflood injector well conversion, one water disposal well conversion and associated facilities on the Company’s Mannville heavy oil properties, along with the relocation of the one-megawatt electricity generator from Panny to the Mannville plant site to convert natural gas to electricity sales.
  • Finding and development costs (“F&D”) were $5.09/boe on a proved and probable basis, including changes in future development capital. Combined with an operating netback of $13.79/boe, Perpetual achieved an attractive F&D recycle ratio of 2.7 times. Exploration and development capital spending, less proceeds on dispositions, net of acquisitions, was $15.0 million in 2018, resulting in finding, development and acquisition costs (“FD&A”) of $2.43/boe and a proved plus probable FD&A recycle ratio of 5.7 times.
  • For the year ended December 31, 2018, Perpetual spent $1.9 million on acquisitions, consolidating the remaining 33% working interest in a Company-operated Mannville heavy oil pool and adding undeveloped oil sands leases in the Panny area which are geographically and technically synergistic to the existing Panny pilot project and prospective for cold flow heavy oil in the Bluesky formation.
  • Dispositions included the sale of non-core royalty interests and exploration and evaluation properties for gross proceeds of $13.4 million and the transfer to the purchaser of $0.5 million in liabilities related to decommissioning obligations, resulting in a net gain on oil and gas properties of $0.7 million. Net proceeds on dispositions were reduced by $8.5 million in net payments associated with the retained marketing arrangements related to the sale of mature shallow gas properties in east central and northeast Alberta in the fourth quarter of 2016 (the “Shallow Gas Disposition”).
  • For the year ended December 31, 2018, Perpetual spent $2.0 million (2017 – $2.3 million) on abandonment and reclamation projects and received 21 reclamation certificates, compared to 35 in 2017. Expenditures of $1.5 million to $2.0 million are forecast in 2019, focused in Eastern Alberta under the area-based closure approach.
  • Production in 2018 averaged 10,594 boe/d, an increase of 7% over 9,876/boe in 2017. Production reached peak levels in the first quarter of 2018 and then declined through the spring and summer before increasing during the fourth quarter as drilling at East Edson was deferred pending higher natural gas prices.
    • Natural gas production increased 6% to 52.6 MMcf/d (2017 – 49.6 MMcf/d) and NGL production increased 18% to 774 bbl/d (2017 – 655 bbl/d), reflecting the drilling, completion and tie-in of one (1.0 net) Wilrich ERH natural gas well, along with the frac and tie-in of two additional wells which were drilled in the fourth quarter of 2017. During 2018, Perpetual shut-in an average 200 boe/d to take advantage of temporary situations when natural gas could be purchased at minimal cost to satisfy pre-sold volume commitments at attractive margins, resulting in realized revenue of $0.5 million($0.03/Mcf) while retaining reserves for future production.
    • Crude oil production averaged 1,050 bbl/d, an 11% increase from the prior year, due to strong waterflood performance and positive heavy oil drilling results in Mannville.
  • Perpetual’s operating netback of $53.3 million ($13.79/boe) increased 3% from $51.7 million ($14.35/boe) in 2017. The increase in the 2018 operating netback was due to the strong contribution of the market diversification contract to boost realized revenue by an incremental $1.02/Mcf, despite the 31% year-over-year decline in AECO Daily Index prices. This was partially offset by higher operating costs in Eastern Alberta related to the repair and cleanup costs from the Mannville pipeline break, combined with the impact of expanded operations.

Financial Highlights

  • Realized revenue was $89.2 million, up 5% from the prior year as a result of the 7% increase in production, offset by a 2% decrease in realized revenue per boe. Included in realized revenues for the 2018 year were $3.1 million in realized gains on derivatives comprised of $3.9 million of gains on natural gas hedges, partially offset by $0.8 million of losses on WTI and WCS differential hedges.
    • For the year ended December 31, 2018, Perpetual’s realized natural gas price was $3.05/Mcf, down 13% from $3.51/Mcf in 2017, reflecting a 31% decrease ($0.66/Mcf) in AECO Daily Index prices and higher realized gains on derivatives in 2017, which were partially offset by the full year contribution from the market diversification contract in 2018. Perpetual’s proactive market diversification strategy implemented in 2017 contributed an incremental $1.02/Mcf over the AECO Daily Index average price in 2018 (2017 $0.06/Mcf), an uplift of 68% over average AECO Daily Index prices during 2018, effectively insulating Perpetual from the 31% year-over-year decline in AECO Daily Index pricing. 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.
    • Perpetual’s realized NGL price was $52.96/bbl, up 14% from $46.60/bbl in 2017, correlating with the 27% increase in WTI prices over the comparable period. Approximately 60% of Perpetual’s NGL production is comprised of condensate which typically tracks light oil prices.
    • Average realized oil price was $40.62/bbl, down 2% from $41.62/bbl in 2017, as increased average WTI prices in 2018 were fully offset by wider WCS differentials over the same period.
  • Net loss for 2018 was $20.4 million ($0.34/share), down from $36.0 million in 2017 ($0.62/share). Net loss from operating activities was $0.7 million for 2018, an improvement of $5.0 million. The reduction was largely due to a reduced unrealized loss of $9.6 million in 2018 (2017 – $22.7 million unrealized loss) related to the change in the fair value of the TOU share investment, combined with losses incurred in 2017 to manage the natural gas floor price obligation associated with the Shallow Gas Disposition.
  • Net cash flow from operating activities was $31.5 million compared to $19.2 million in 2017. Substantially all of the increase was attributable to changes in non-cash working capital balances, reflecting lower accounts payable and accrued liability balances year-over-year as a result of the reduction in fourth quarter spending compared to the prior year period.
  • Adjusted funds flow was $30.2 million ($0.50/share), down 3% from 2017 despite the significant decrease in AECO natural gas prices.
  • At December 31, 2018, Perpetual had total net debt of $112.6 million, up $6.6 million (6%) from December 31, 2017. The increase is mainly attributable to the $9.9 million reduction in the fair value of TOU shares during 2018. As at year-end 2018, 56% of net debt outstanding was repayable in 2021 or later. Perpetual’s net debt to trailing twelve months adjusted funds flow increased slightly during 2018 to 3.7 times at December 31, 2018 (December 31, 2017 – 3.4 times).
  • On November 7, 2018, the revolving bank debt borrowing limit (“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. Perpetual had available liquidity at December 31, 2018 of $22.7 million, comprised of an unutilized Borrowing Limit against the credit facility of $8.7 million and the market value of its TOU share investment, net of the associated margin demand loan, of $14.0 million.

CREDIT FACILITY EXTENSION

On March 27, 2019, a $55 million Borrowing Limit was confirmed by the Company’s lenders and the maturity was extended to November 30, 2020. The credit facility will revolve until May 31, 2020 and may be extended for a further 364-day period subject to approval by the Company’s lenders. Perpetual is considering options to repay the $14.6 million unsecured senior notes that mature on July 23, 2019, including arranging replacement financing and the sale of a portion of its Tourmaline shares or other assets.

2019 OUTLOOK

On August 3, 2018, the Company received a Statement of Claim that was filed by PricewaterhouseCoopers Inc. LIT (“PwC”), in its capacity as trustee in bankruptcy of Sequoia, with the Alberta Court of Queen’s Bench (the “Court”), against Perpetual. The claim relates to an over two-year-old transaction when, on October 1, 2016, Perpetual closed the Shallow Gas Disposition to an arm’s length third party at fair market value at the time after an extensive and lengthy marketing, due diligence and negotiation process. This transaction was one of several completed by Sequoia. Sequoia assigned itself into bankruptcy on March 23, 2018. PwC is seeking an order from the Court to either set this transaction aside or declare it void, or damages of approximately $217 million. On August 27, 2018, Perpetual filed a Statement of Defence and Application for Summary Dismissal with the Court in response to the Statement of Claim. All allegations made by PwC have been denied and an application to the Court to dismiss all claims has been made on the basis that there is no merit to any of them. Perpetual’s Application for Summary Dismissal was heard during the fourth quarter of 2018 (the “Sequoia Litigation”). The Court’s decision is anticipated to be received in the second quarter of 2019.

Perpetual’s 2019 capital expenditure and adjusted funds flow guidance remains unchanged from guidance released with its 2018 third quarter results on November 7, 2018.

The Company’s Board of Directors has approved a total capital spending program of $21 to $25 million for 2019 to be funded from adjusted funds flow. At least 50% will be spent in Eastern Alberta, primarily targeting heavy oil development at Mannville along with abandonment and reclamation work of up to $2 million to prudently address decommissioning obligations associated with non-producing wells. The remaining 50% of expenditures will be concentrated in East Edson, developing liquids-rich natural gas reserves in the Wilrich formation if AECO forward gas prices support investment in the second half of 2019, or alternatively, will be deployed in an expanded heavy oil drilling program. The Company has minimal capital spending planned for the first half of 2019. The second half program is planned to align operations with higher anticipated commodity prices.

Forecast capital activity in Mannville for 2019 includes the drilling of 10 (10.0 net) new wells, targeting a mix of infill wells and step outs in waterflooded pools as well as multi-lateral wells in several pools in Eastern Alberta. Timing for the 2019 program is in the third quarter to take advantage of lower drilling, completion, and equipping costs generally realized in the summer in Mannville. Additionally, up to 10 shallow gas recompletions are planned to be executed in late 2019, if gas prices improve, to partially offset natural gas declines in Eastern Alberta. Decommissioning expenditures will continue to be focused in the Mannville area and are expected to provide future lease rental and property tax expense reductions while maintaining regulatory compliance. In Eastern Alberta, production is forecast to increase by 20% to 30% from 2018, to a range of 2,200 to 2,400 boe/d (61% oil) in 2019.

At East Edson, the Company has budgeted a two (2.0 net) well drilling program to come onstream during the fourth quarter of 2019, as well as capital for a strategic secondary zone recompletion program and maintenance. The two wells will be extended reach horizontal (“ERH”) wells, as the performance of the ERH wells drilled in late 2017 and early 2018 indicate improved capital efficiencies over the wells drilled with less than 2,500 meters of lateral length. If AECO forward gas prices normalize above $2.00/Mcf, drilling activities are expected to continue into 2020. Processing capacity at the Company’s 100% working interest and operated West Wolf Lake facility is 65 MMcf/d, with an additional 13 MMcf/d of working interest capacity at the non-operated Rosevear plant, plus associated liquids. The planned drilling will not have a material impact on production in 2019, as new wells are forecast to come on stream late in the year. Natural declines and capital spending deferrals to late 2019 result in lower anticipated 2019 production in East Edson with an average of 7,000 to 7,200 boe/d (10% oil and NGL). Despite reduced production in East Edson and a substantially fixed operating cost base, operating costs are forecast to remain low in 2019, at less than $3.25/boe.

The table below summarizes anticipated capital spending and drilling activities for the first and second half of 2019.

2019 Exploration and Development Forecast Capital Expenditures

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 is targeting a 2019 capital program that is funded by adjusted funds flow. Perpetual forecasts average production of 9,200 to 9,600 boe/d, with oil and NGL production growing to represent more than 20% of the production mix. This represents a reduction in average daily production in 2019 of 10% to 15% relative to 2018, but includes a 17% increase in average oil and NGL production. The Company expects to exit the year at over 11,500 boe/d (approximately 80% natural gas) as production ramps up again in the fourth quarter driven by the second half capital spending program targeting seasonal natural gas price optimization.

Cash costs of $17.00 to $18.00/boe are forecast for 2019, up approximately 13% to 16% from 2018 due to the impact of lower forecast 2019 production at East Edson on a substantially fixed operating cost base. The increase in higher netback and higher operating cost oil production in 2019 is also expected to contribute to the increase in 2019 cash costs per boe.

Perpetual has diversified its commodity and natural gas pricing point exposure (net of royalties) away from AECO as detailed below:

Market/Pricing Point

Natural gas

Estimated 2019 Exposure

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 750 bbl/d WCS differential fixed at US$25.22/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 (%)

20% – 24% oil and NGL

Commodity price assumptions reflect market price levels as follows:

2019 Commodity Price

Assumptions

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

$2.99

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

$56.56

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

($15.88)

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

$1.34

Year end 2019 net debt (net of the estimated market value of the Company’s TOU share investment of approximately $34 million), is forecast at $107 to $113 million, a marginal increase from guidance provided with Perpetual’s third quarter earnings release of $104 to $107 million. Estimated mid-range guidance for the 2019 year-end net debt to trailing twelve months adjusted funds flow ratio is forecast at approximately 4.5 times. Current guidance is based on the following assumptions:

  • Net debt at December 31, 2018 of $112.6 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 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;
  • 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; and
  • For every $0.05 increase or decrease in the Cdn$/US$ exchange rate, adjusted funds flow increases or decreases by $1.3 million.

 

Financial and Operating Highlights

Three Months ended

December 31

Year ended

 December 31

($Cdn thousands,

 except volume and per share amounts)

2018

2017

Change

2018

2017

 Change

Financial

Oil and natural gas revenue

21,510

23,810

(10%)

86,128

81,722

5%

Net loss

(331)

(6,498)

(95%)

(20,380)

(35,971)

(43%)

Per share – basic and diluted(2)

(0.01)

(0.11)

(91%)

(0.34)

(0.62)

(45%)

Cash flow from (used in) operating activities

5,163

10,953

(53%)

31,525

19,170

64%

Per share(1)(2)

0.09

0.18

(50%)

0.53

0.33

61%

Adjusted funds flow(1)

8,052

12,541

(36%)

30,155

31,093

(3%)

Per share(2)

0.13

0.21

(38%)

0.50

0.54

(7%)

Revolving bank debt

42,561

31,581

35%

42,561

31,581

35%

Senior notes, principal amount

32,490

32,490

32,490

32,490

Term loan, principal amount

45,000

45,000

45,000

45,000

TOU share margin demand loan, principal amount

14,144

18,490

(24%)

14,144

18,490

(24%)

TOU share investment

(28,132)

(37,985)

(26%)

(28,132)

(37,985)

(26%)

Net working capital deficiency(1)

6,543

16,404

(60%)

6,543

16,404

(60%)

Total net debt(1)

112,606

105,980

6%

112,606

105,980

6%

Net capital expenditures

Capital expenditures

5,617

19,047

(71%)

26,888

73,035

(63%)

Net payments (proceeds) on acquisitions and
dispositions

(1,285)

970

(232%)

(3,030)

2,422

(225%)

Net capital expenditures

4,332

20,017

(78%)

23,858

75,457

(68%)

Common shares outstanding (thousands)

End of period(3)

60,240

59,263

2%

60,240

59,263

2%

Weighted average – basic and diluted

60,448

59,338

2%

60,039

58,017

3%

Operating

Average production

Natural gas (MMcf/d)

44.9

60.8

(26%)

52.6

49.6

6%

Oil (bbl/d)

1,301

888

47%

1,050

948

11%

NGL (bbl/d)

715

738

(3%)

774

655

18%

Total (boe/d)

9,491

11,765

(19%)

10,594

9,876

7%

Average prices

Realized natural gas price ($/Mcf)

4.38

3.22

36%

3.05

3.51

(13%)

Realized oil price ($/bbl)

19.83

47.30

(58%)

40.62

41.62

(2%)

Realized NGL price ($/bbl)

35.73

54.17

(34%)

52.96

46.60

14%

Wells drilled

Natural gas – gross (net)

– (–)

3 (3.0)

1 (1.0)

15 (14.4)

Oil – gross (net)

– (–)

– (–)

6 (6.0)

4 (3.3)

Total – gross (net)

– (–)

3 (3.0)

7 (7.0)

19 (17.7)

(1)

These are non-GAAP measures. Please refer to “Non-GAAP Measures” at the end of this press release

(2)

Based on weighted average basic common shares outstanding for the period

(3)

All common shares are net of shares held in trust (2018 – 661; 2017 – 447). See “Note 16 to the Audited Consolidated Financial
Statements”



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