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Paramount Resources Ltd. reports second quarter 2020 results


HIGHLIGHTS

  • Sales volumes averaged 68,839 Boe/d (39 percent liquids) in the second quarter of 2020 compared to 70,022 Boe/d (38 percent liquids) in the first quarter.
    • At Wapiti, second quarter sales volumes increased 107 percent to 14,940 Boe/d (64 percent liquids) compared to the first quarter as run time at the third-party processing facility improved.
    • At Karr, the five wells on the 12-18 pad were flowed through test facilities partway through the quarter and were brought on production through permanent facilities in early July. Average gross peak 30-day production per well was 1,593 Boe/d, including 1,216 Bbl/d of wellhead liquids, with an average wellhead CGR of 538 Bbl/MMcf. (1)
    • Average sales volumes in the quarter were impacted by shut-ins and curtailments.
  • Second quarter operating costs were $62.6 million ($9.99/Boe), a reduction of about 30 percent quarter-over-quarter. Approximately 30 to 50 percent of this reduction is attributable to sustainable improvements in the Company’s cost structure.
  • Paramount’s netback was $21.7 million in the second quarter of 2020 compared to $44.5 million in the first quarter of 2020, reflecting the impact of substantially lower commodity prices which were only partially offset by cost improvements. (2)
  • Adjusted funds flow was $19.0 million or $0.14 per share.(2) Cash from operating activities was ($14.2) million in the second quarter of 2020, largely because of changes in working capital.
  • Second quarter capital spending totaled $41.4 million, primarily related to drilling and completion activities at Karr and drilling operations at Wapiti.
  • The Company has realized significant cost savings in its capital program through its continuing focus on well design, increased efficiencies and lower vendor rates, while not compromising on completion effectiveness:
    • All-in lease construction, drilling, completion, equip and tie-in (collectively, “DCET”) costs for the five-well (three Middle Montney and two Lower Montney) Karr 12-18 pad averaged $8.8 million per well, $0.7 million lower than prior estimates. This represents a 27 percent reduction compared with average DCET costs for all Karr wells in 2018 and 2019.
    • Drilling operations were concluded in the second quarter on the five-well (three Upper Montney and two Middle Montney) Karr 5-16 West pad. Average drilling costs of $2.7 million per well were in line with recent pacesetters at Karr.
    • Completion activities at the five-well (all Middle Montney) Karr 2-1 pad have recently been concluded and preliminary lease construction, drilling and completion costs are coming in at a pacesetting estimate of $7.0 million per well.
    • At Wapiti, drilling operations were completed on the five-well (two Middle Montney and three Lower Montney) 5-3 West pad, with estimated costs averaging $3.1 million per well.
  • The expansion of the third-party Karr 6-18 facility was completed in July. The additional raw gas and liquids processing capacity adds flexibility to the Company’s Karr operations, including minimizing the impact of future disruptions at other accessible third-party processing facilities.
  • Paramount has received approval for up to $8 million of funding under the Alberta Site Rehabilitation Program and applied for funding under similar programs in BC and Saskatchewan. The majority of activities to be funded under the Alberta Site Rehabilitation Program are expected to occur in 2021.
  • The Company advanced its project to replace 200 high-bleed controllers with low-bleed units at well sites in the Grande Prairie area in 2020, with 164 low-bleed units installed to date. The project is anticipated to eliminate approximately 8,600 tonnes of greenhouse gas (“GHG”) emissions annually. In addition, reduced trucking of produced water following the start-up of two new water disposal wells at Karr is expected to eliminate approximately 13,500 tonnes per year of GHG emissions (the equivalent of removing approximately 2,900 passenger cars from use) while also reducing operating costs.

________________________

(1)

Production measured at the wellhead. Natural gas sales volumes are lower by approximately 10 percent and wellhead liquids sales volumes are lower by approximately 12 percent due to shrinkage, under normalized operations. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGRs are calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section.

(2)

“Netback” and “Adjusted funds flow” are Non-GAAP measures. See “Non-GAAP Measures” in the Advisories section.

CORPORATE

  • Paramount is on track to achieve its previously announced 2020 cost reduction targets of $25 million in operating costs and $15 million in general and administrative expenses.
  • The Company is maintaining its 2020 capital guidance of $165 million and allocating the significant capital savings it is realizing to advance certain projects that had previously been planned for 2021.  Paramount continues to evaluate the merits of accelerating additional projects as market conditions evolve.
  • Approximately 4,300 Boe/d of production currently remains shut-in and Paramount continues to review opportunities to bring volumes back online as conditions improve.
  • Sales volumes are anticipated to average between 65,000 Boe/d and 70,000 Boe/d in the second half of 2020.
  • Reflective of the macro economic environment and significant reduction in commodity prices, in June 2020 Paramount’s senior secured revolving bank credit facility was amended to provide a period of financial covenant relief to and including June 30, 2021 and to amend the size of the facility to $1.0 billion. Long-term debt at June 30, 2020 was $754.9 million.
  • In July 2020 the Company’s unsecured demand revolving letter of credit facility was increased from $40 million to $70 million.
  • The Company has entered into additional 2020 natural gas and liquids hedges to mitigate volatility and protect cash flows. See “Hedging” below for a summary of the Company’s current hedge position.
  • Paramount continues to respond to the COVID-19 pandemic. At the beginning of June, Paramount implemented a plan to safely transition its Calgary head office employees from remote work back to the office.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Grande Prairie Region sales volumes and netbacks are summarized below:

Q2 2020

Q1 2020

% Change

Sales volumes

Natural gas (MMcf/d)

78.3

74.6

5

Condensate and oil (Bbl/d)

16,309

14,097

16

Other NGLs (Bbl/d)

1,680

1,680

Total (Boe/d)

31,039

28,214

10

% liquids

58%

56%

Netback

($ millions)

($/Boe)

 ($ millions)

($/Boe)

% Change in
$millions

Petroleum and natural gas sales

60.3

21.34

91.7

35.71

(34)

  Royalties (1)

0.3

0.12

(6.2)

(2.42)

NM

  Operating expense

(38.8)

(13.73)

(42.4)

(16.53)

(8)

  Transportation and NGLs processing

(12.9)

(4.58)

(10.3)

(4.03)

25

8.9

3.15

32.8

12.73

(73)

(1)  Second quarter royalties were impacted by lower prices and adjustments related to prior year gas cost allowance.

NM  Not meaningful

 

 

 

Karr

Karr sales volumes and netbacks are summarized below:

Q2 2020

Q1 2020

% Change

Sales volumes

Natural gas (MMcf/d)

46.1

59.4

(22)

Condensate and oil (Bbl/d)

7,501

9,691

(23)

Other NGLs (Bbl/d)

829

1,290

(36)

Total (Boe/d)

16,009

20,885

(23)

% liquids

52%

53%

Netback

($ millions)

($/Boe)

 ($ millions)

($/Boe)

% Change in $
millions

Petroleum and natural gas sales

29.4

20.20

64.2

33.76

(54)

Royalties (1)

1.3

0.87

(5.0)

(2.62)

NM

Operating expense

(22.4)

(15.39)

(30.8)

(16.19)

(27)

Transportation and NGLs processing

(7.2)

(4.91)

(6.7)

(3.54)

7

1.1

0.77

21.7

11.41

(95)

(1)  Second quarter royalties were impacted by lower prices and adjustments related to prior year gas cost allowance.

NM  Not meaningful

Second quarter sales volumes at Karr averaged 16,009 Boe/d compared to 20,885 Boe/d in the first quarter.  Sales volumes were impacted by a seven-day planned outage (including ramp-down and ramp-up periods) at the third-party Karr 6-18 facility related to the completion of expansion activities and the temporary shut-in of certain offsetting wells due to completion activities at the 12-18 and 2-1 pads, as well as by natural declines.

In addition to previously installed gas lift and related compression at pads near the southwest terminus of Paramount’s gathering system, work is ongoing to mitigate current and future potential back-out issues in the Karr gathering system as new production continues to be brought online.  This includes additional booster compression that is scheduled to be brought into service midway through the third quarter to mitigate production currently backed-out.

Substantial operating cost savings have been realized with the addition of the Company’s two new water disposal wells that were brought into service near the end of the first quarter.  These wells have accommodated the disposal of substantially all produced water from Karr area wells and resulted in approximately $4 million in operating costs savings compared to the previous quarter from the elimination of trucking and third-party disposal fees. These wells are expected to meet Karr area development needs for the foreseeable future.

Final DCET costs for the 12-18 pad came in at a pacesetting $8.8 million average per well, $0.7 million per well lower than previously estimated.  This represents a 27 percent reduction compared with average DCET costs for all Karr wells in 2018 and 2019.  The wells (three Middle Montney and two Lower Montney) flowed through testers partway through the quarter and began producing through permanent facilities in early July.  Average gross peak 30-day production per well was 1,593 Boe/d, including 1,216 Bbl/d of wellhead liquids, with an average wellhead CGR of 538 Bbl/MMcf. (1)

Paramount completed the drilling of five wells (three Upper Montney and two Middle Montney) on the 5-16 West pad during the second quarter.  Average drilling costs of $2.7 million per well are in line with the pacesetting results at the 2-1 pad drilled in the fourth quarter of 2019.  The successful negotiation of lower vendor rates and the continuous improvement from prior drilling operations helped achieve this result.  Paramount plans to complete, tie-in, and bring on production all five wells on the 5-16 West pad in 2021.

Completion activities at the five-well Middle Montney Karr 2-1 pad have recently been concluded and preliminary lease construction, drilling and completion costs are coming in at a pacesetting estimate of $7.0 million per well.  Paramount continues to aggressively pursue capital cost savings without compromising on completion effectiveness. The Company plans to tie-in and bring on production the wells on the 2-1 pad in the third quarter.

The Karr 6-18 third-party processing facility expansion has been completed and commercial operations commenced in July 2020.  The facility now has 150 MMcf/d of total raw gas handling capacity, including 70 MMcf/d of sour raw gas processing, and 30,000 Bbl/d of raw hydrocarbon liquids handling capacity.  The additional gas and liquids processing capacity will allow the Company to grow future production as well as minimize the impact of future disruptions at the other accessible third-party processing facilities.

_________________________

(1)

Production measured at the wellhead. Natural gas sales volumes are lower by approximately 10 percent and wellhead liquids sales volumes are lower by approximately 12 percent due to shrinkage, under normalized operations. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGRs are calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section.

The following table summarizes the performance of the wells on the 12-18, 1-19, and 4-24 pads, as well as the five wells drilled in 2018 and the 27 wells drilled in the 2016/2017 capital program at Karr:

Peak 30-Day (1)

Cumulative (2)

Total

Wellhead

Liquids

CGR (3)

Total

Wellhead
Liquids

CGR (3)

Days on
Production

(Boe/d)

(Bbl/d)

(Bbl/MMcf)

(MBoe)

(MBbl)

(Bbl/MMcf)

12-18 Pad

00/09-17-065-05W6/2

1,304

1,056

710

43

35

694

36

00/16-17-065-05W6/0

1,644

1,262

550

56

43

540

36

02/09-17-065-05W6/0

1,757

1,350

553

60

46

542

36

02/16-17-065-05W6/0

1,692

1,181

385

58

40

378

36

03/09-17-065-05W6/0

1,567

1,232

614

55

42

571

36

Avg. per well

1,593

1,216

538

54

41

520

36

01-19 Pad

03/13-29-065-05W6/0

1,704

1,209

407

279

187

340

229

03/14-29-065-05W6/0

1,357

1,067

611

167

124

479

206

04/13-29-065-05W6/0

1,566

1,170

493

229

162

406

223

Avg. per well

1,542

1,149

486

225

158

390

219

04-24 Pad

00/01-11-065-06W6/0

1,878

1,271

349

351

211

250

315

00/02-12-065-06W6/0

1,836

1,308

413

284

194

360

320

00/03-12-065-06W6/0

2,307

1,583

365

460

293

291

333

00/04-12-065-06W6/0

2,097

1,329

289

468

279

245

326

02/03-12-065-06W6/0

2,029

1,308

302

406

251

270

327

Avg. per well

2,029

1,360

338

394

246

276

324

2018 Wells

5 wells (Avg. per well)

1,877

1,121

247

629

327

180

624

2016/2017 Wells

27 wells (Avg. per well)

1,969

1,171

245

738

368

166

860

(1)

Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Natural gas sales volumes are approximately 10 percent lower and wellhead liquids sales volumes are approximately 12 percent lower due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes shown are 30-day peak rates over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. See ʺOil and Gas Measures and Definitionsʺ in the Advisories.

(2)

Cumulative is the aggregate production measured at the wellhead to July 31, 2020. Natural gas sales volumes are approximately 10 percent lower and wellhead liquids sales volumes are approximately 12 percent lower due to shrinkage. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.

(3)

CGRs calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes.

Wapiti

Wapiti sales volumes and netbacks are summarized below:

Q2 2020

Q1 2020

% Change

Sales volumes

Natural gas (MMcf/d)

31.9

14.8

116

Condensate and oil (Bbl/d)

8,786

4,364

101

Other NGLs (Bbl/d)

841

386

118

Total (Boe/d)

14,940

7,209

107

% liquids

64%

66%

Netback

($ millions)

($/Boe)

 ($ millions)

($/Boe)

% Change in $
millions

Petroleum and natural gas sales

30.7

22.61

27.2

41.53

13

Royalties

(1.0)

(0.70)

(1.2)

(1.85)

(17)

Operating expense

(15.9)

(11.69)

(11.2)

(17.11)

42

Transportation and NGLs processing

(5.8)

(4.24)

(3.6)

(5.46)

61

8.0

5.98

11.2

17.11

(29)

Second quarter sales volumes at Wapiti averaged 14,940 Boe/d (64 percent liquids) compared to 7,209 Boe/d (66 percent liquids) in the first quarter.  Run time at the third-party operated processing facility was significantly improved compared with previous quarters.

All 12 wells on the 5-3 East pad are now flowing through permanent production facilities as additional third-party effluent gathering system capacity came online during the second quarter.

Paramount completed the drilling of five wells (two Middle Montney and three Lower Montney) on the 5-3 West pad at an average cost of $3.1 million per well in the second quarter.  Plans to complete and bring on production these wells and drill the remaining six wells on the eight-well 6-4 pad have been deferred.  A tenure well drilled and completed in 2015 is planned to be brought on production in the third quarter.

The following table summarizes the performance of wells on the 5-3 East and 9-3 pads:

Peak 30-Day (1)

Cumulative (2)

Total

Wellhead

Liquids

CGR (3)

Total

Wellhead
Liquids

CGR (3)

Days on
Production

(Boe/d)

(Bbl/d)

(Bbl/MMcf)

(MBoe)

(MBbl)

(Bbl/MMcf)

5-3 East Pad

03/11-27-067-06W6/0

2,226

1,412

289

240

143

246

209

04/06-15-068-06W6/0

1,736

1,187

360

168

112

336

172

02/09-28-067-06W6/0

1,776

1,110

278

142

88

271

118

02/11-27-067-06W6/0

2,076

1,344

306

224

139

274

203

00/12-27-067-06W6/0

1,393

928

333

131

81

270

141

02/12-27-067-06W6/0

1,998

1,326

329

182

110

253

144

00/09-28-067-06W6/0

1,701

1,155

353

168

104

271

130

03/06-15-068-06W6/0

1,465

1,036

403

159

111

382

161

00/05-15-068-06W6/0

1,480

1,066

429

133

94

407

142

02/05-15-068-06W6/0

1,663

1,170

396

149

103

375

131

00/08-16-068-06W6/0

1,516

1,055

381

145

98

351

127

02/08-16-068-06W6/0

1,845

1,348

452

119

84

403

77

Avg. per well

1,740

1,178

350

163

106

305

146

9-3 Pad

00/11-27-067-06W6/0

1,360

880

306

228

143

279

310

03/08-15-068-06W6/0

962

689

421

162

119

452

279

04/09-27-067-06W6/0

1,536

1,102

423

348

219

284

394

03/09-27-067-06W6/0

1,268

794

279

316

198

277

395

02/06-15-068-06W6/0

1,511

1,088

429

219

152

379

263

02/09-27-067-06W6/0

1,094

769

395

281

179

293

375

03/07-15-068-06W6/0

1,042

787

516

216

145

338

361

02/10-27-067-06W6/0

1,137

779

362

273

174

292

356

03/10-27-067-06W6/0

1,111

749

345

276

167

256

376

02/08-15-068-06W6/0

969

693

419

193

133

365

332

02/07-15-068-06W6/0

1,192

815

360

210

143

357

318

Avg. per well

1,198

831

378

247

161

311

342

(1)

Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Natural gas sales volumes are approximately 11 percent lower and wellhead liquids sales volumes are approximately 3 percent lower due to shrinkage under normalized operations. Excludes days when the wells did not produce. The production rates and volumes shown are 30-day peak rates over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. See ʺOil and Gas Measures and Definitionsʺ in the Advisories.

(2)

Cumulative is the aggregate production measured at the wellhead to July 31, 2020. Natural gas sales volumes are approximately 11 percent lower and wellhead liquids sales volumes are approximately 3 percent lower due to shrinkage under normalized operating conditions. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.

(3)

CGRs calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes.

KAYBOB REGION

Kaybob Region sales volumes averaged 29,561 Boe/d (26 percent liquids) in the second quarter compared to 32,700 Boe/d (29 percent liquids) in the first quarter.  This decrease was mainly attributable to natural declines and shut-ins during the second quarter.

Paramount holds material positions in Duvernay and Montney Oil resource plays in the Kaybob Region that will compete for capital in the medium term.  The Company continues to actively evaluate longer-term full field development plans for these plays.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 8,239 Boe/d (12 percent liquids) in the second quarter compared to 9,108 Boe/d (14 percent liquids) in the first quarter.  Sales at Birch were impacted by planned and unplanned plant outages in the second quarter.

Paramount holds a material, contiguous Duvernay position at Willesden Green and continues to actively evaluate longer-term full field development plans of the asset.

GREENHOUSE GAS REDUCTION INITIATIVE

As part of Paramount’s continued commitment to responsible energy development, the Company has been participating in GHG emission reduction programs and investing in new equipment to reduce GHG emissions from its operations.

The Company is continuing upgrades at various sites to replace its remaining high-bleed controllers with modern low-bleed units. A total of 200 low-bleed units are expected to be installed in the Grand Prairie Region in 2020, with 164 installed to date.  These new units are expected to eliminate approximately 8,600 tonnes of GHG emissions per year and generate approximately $0.5 million in GHG credits under current regulations through 2022.

Reduced trucking of produced water with the start-up of two new water disposal wells at Karr is expected to eliminate approximately 13,500 tonnes per year of GHG emissions (the equivalent of removing approximately 2,900 passenger cars from use) while also reducing operating costs.

HEDGING

The tables below set out the Company’s hedge position:

Oil

Volume

Price

Remaining term

NYMEX WTI Swaps (Sale)

4,000 Bbl/d

CDN$80.11/Bbl

July 2020 – December 2020

NYMEX WTI Swaps (Sale)

6,000 Bbl/d

US$41.75/Bbl

August 2020 

NYMEX WTI Swaps (Sale)

16,000 Bbl/d

US$42.23/Bbl

September 2020

NYMEX WTI Swaps (Sale)

6,000 Bbl/d

US$43.03/Bbl

October 2020

NYMEX WTI Swaps (Sale)

4,000 Bbl/d

US$43.73/Bbl

November 2020

NYMEX WTI Swaps (Sale)

4,000 Bbl/d

US$43.99/Bbl

December 2020

Gas

Volume

Price

Remaining term

Ventura Swaps (Sale) (1)

  20,000 MMBtu/d

US$1.69/MMBtu

August 2020 – October 2020

Chicago Swaps (Sale) (1)

20,000 MMBtu/d

US$1.71/MMBtu

August 2020 – October 2020

NYMEX Swaps (Sale)

20,000 MMBtu/d

US$2.17/MMBtu

September 2020

NYMEX Swaps (Sale)

10,000 MMBtu/d

US$2.93/MMBtu

November 2020 – March 2021

NYMEX Swaps (Sale)

40,000 MMBtu/d

US$2.68/MMBtu

January 2021 – December 2021

Dawn fixed-price physical

54,956 MMBtu/d

US$1.60/MMBtu

August 2020

Dawn fixed-price physical

45,000 MMBtu/d

US$1.56/MMBtu

September 2020

AECO fixed-price physical

90,000 GJ/d

CDN$1.66/GJ

July 2020 – October 2020

AECO fixed-price physical

35,000 GJ/d

CDN$1.80/GJ

August 2020

AECO fixed-price physical

25,000 GJ/d

CDN$1.85/GJ

September 2020

AECO fixed-price physical

10,000 GJ/d

CDN$2.65/GJ

November 2020 – March 2021

AECO fixed-price physical

20,000 GJ/d

CDN$2.50/GJ

January 2021 – December 2021

(1)

These hedges swap physical sales of Alberta natural gas production from Chicago and Ventura index pricing to fixed prices.

ABOUT PARAMOUNT

Paramount is an independent, publicly traded, liquids-focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas reserves and resources, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company’s principal properties are located in Alberta and British Columbia. Paramount’s Class A common shares are listed on the Toronto Stock Exchange under the symbol “POU”.

Paramount’s second quarter 2020 results, including Management’s Discussion and Analysis and the Company’s Consolidated Financial Statements can be obtained at https://mma.prnewswire.com/media/1224861/Paramount_Resources_Ltd.pdf

This information will also be made available through Paramount’s website at www.paramountres.com and on SEDAR at www.sedar.com.

FINANCIAL AND OPERATING RESULTS (1)

($ millions, except as noted)

Q2 2020

Q1 2020

Net loss

(75.7)

(235.1)

per share – basic and diluted ($/share)

(0.57)

(1.76)

Cash from (used in) operating activities

(14.2)

30.5

per share – basic and diluted ($/share)

(0.11)

0.23

Adjusted funds flow

19.0

33.5

per share – basic and diluted ($/share)

0.14

0.25

Total assets

3,066.4

3,009.5

Long-term debt

754.9

651.5

Net debt

810.7

771.9

Common shares outstanding (thousands)(2)

133,784

133,346

Sales volumes

Natural gas (MMcf/d) 

253.2

261.5

Condensate and oil (Bbl/d)

22,823

21,898

Other NGLs (Bbl/d) (3)

3,817

4,539

Total (Boe/d)

68,839

70,022

  % liquids

39%

38%

Grande Prairie Region (Boe/d)

31,039

28,214

Kaybob Region (Boe/d)

29,561

32,700

Central Alberta and Other Region (Boe/d)

8,239

9,108

Total (Boe/d)

68,839

70,022

Netback

$/Boe (4)

$/Boe (4)

  Natural gas revenue

44.7

1.94

53.6

2.25

  Condensate and oil revenue

60.3

29.05

111.4

55.92

  Other NGLs revenue (3)

4.3

12.28

4.4

10.75

  Royalty and sulphur revenue

3.9

2.7

Petroleum and natural gas sales

113.2

18.07

172.1

27.01

  Royalties

(3.6)

(0.57)

(11.7)

(1.84)

  Operating expense

(62.6)

(9.99)

(92.3)

(14.49)

  Transportation and NGLs processing (5)

(25.3)

(4.04)

(23.6)

(3.70)

Netback

21.7

3.47

44.5

6.98

Commodity contract settlements

12.9

2.05

7.0

1.10

Netback including commodity contract settlements

34.6

5.52

51.5

8.08

Total Capital Expenditures

Grande Prairie Region

36.7

49.8

Kaybob Region

1.8

10.1

Central Alberta and Other Region

0.8

2.8

Corporate

1.5

1.1

Land and property acquisitions

0.6

Total capital expenditures

41.4

63.8

Asset retirement obligation settlements

4.0

30.3

(1)

Readers are referred to the advisories concerning Non-GAAP Measures and Oil and Gas Measures and Definitions in the Advisories section of this document. This table contains the following Non-GAAP measures: Adjusted Funds Flow, Net Debt, Netback, and Total Capital Expenditures.

(2)

Common shares are presented net of shares held in trust under the Company’s restricted share unit plan (000’s of common shares): Q2 2020: 414 and Q1 2020: 852.

(3)

Other NGLs means ethane, propane and butane.

(4)

Natural gas revenue presented as $/Mcf.

(5)

Includes downstream transportation costs and NGLs fractionation costs.



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