Top

Paramount Resources Ltd. Class A

TSX Exchange | Aug 6, 2020, 5:55 PM EDT | Real-time price

POU $ 2.16 RT
CHANGE
0.08 (3.8462%)
VOLUME
547,442
Day Low: 2.06
Day High: 2.20
 Back
Paramount Resources Ltd. Reports First Quarter 2020 Results

Canada NewsWire

CALGARY, May 13, 2020 /CNW/ -

Paramount Resources Ltd. Reports First Quarter 2020 Results (CNW Group/Paramount Resources Ltd.)

HIGHLIGHTS

  • Sales volumes averaged 70,022 Boe/d (38 percent liquids) in the first quarter of 2020.(1)

  • Production in the first quarter of 2020 was impacted by three separate outages (two unscheduled, one scheduled) at a third-party processing facility in the Wapiti area. This amounted to approximately one full month of downtime or the equivalent of approximately 4,300 Boe/d of high netback production for the quarter. Severe cold weather in January also impacted production in both the Grande Prairie and Kaybob Regions. Production in the Central and Other Region was approximately 6,200 Boe/d lower in the first quarter as a result of the sale of certain assets in the fourth quarter of 2019.

  • Paramount's netback was $44.5 million in the first quarter of 2020 compared to $114.9 million in the fourth quarter of 2019 mainly due to lower commodity prices and production. (2)

  • Cash from operating activities was $30.5 million in the first quarter of 2020. Adjusted funds flow was $33.5 million or $0.25 per share.(2)

  • At Karr, drilling operations were concluded in the first quarter on the remaining wells from the five-well 12-18 pad first spud in the fourth quarter of 2019. An additional five-well pad at 5-16 was spud part way through the first quarter. Completion operations on the 12-18 pad are now finished, with total lease construction, drilling, completion, equip and tie-in (collectively, "DCET") costs estimated at a pacesetting $9.5 million per well. This compares with historic type well DCET costs of $12.3 million per well in Karr.

  • Two new water disposal wells were brought into service towards the end of the first quarter of 2020 at Karr. These wells will reduce operating costs associated with water trucking and disposal and are expected to meet Karr area development needs for the foreseeable future.

  • At Wapiti, drilling operations commenced on the five-well 5-3 West pad and two wells on the eight-well 6-4 pad were drilled in the first quarter of 2020. In response to current market conditions, Paramount elected to defer the drilling of the remaining six wells on the 6-4 pad.

  • Abandonment and reclamation projects at Hawkeye and Zama under the area-based closure ("ABC") program continued in the first quarter of 2020, with the Company abandoning 224 wells between the two properties, including all remaining operated wells in the Hawkeye area. An additional 24 wells were abandoned in other areas for a total of 248 well abandonments in the first quarter of 2020 at a total cost of $30.3 million. Paramount's abandonment and reclamation activities for the year are budgeted at $33 million and are now largely complete.

  • First quarter capital spending totaled $63.8 million, primarily related to drilling activities at Karr and Wapiti. Capital expenditures were lower than expected as a result of both lower costs and improved efficiencies.

_______________



(1)

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 has implemented a corporate pandemic response plan aimed at ensuring the health and safety of its staff and contractors and the people they come in contact with. Under the plan, Paramount staff are working remotely other than in situations where physical workplace attendance is essential. Paramount has taken action to ensure its field operations are being conducted in compliance with public health requirements and guidelines, including by providing additional personal protective equipment and restricting access to its work sites to critical personnel.

  • The Company has moved aggressively to further reduce its cost structure in response to the recent significant decline in liquids prices:

    • Paramount has revised its 2020 capital guidance to $165 million. This revised guidance reflects expected cost reductions at planned activity levels generally unchanged from the low end of previous capital guidance of $185 million.

    • Measures to reduce operating costs, including securing lower contractor and supplier rates, are expected to result in total savings of approximately $25 million over the final three quarters of 2020.

    • Workforce reductions, a 20 percent reduction in the salary of the Chief Executive Officer and in the cash compensation of the Board of Directors, a 10 percent reduction in the salaries of all other staff and the suspension or elimination of a number of benefits and incentive compensation programs are expected, when combined with previous initiatives, to reduce 2020 general and administrative costs by approximately $15 million.

    • Paramount has temporarily shut-in approximately 6,600 Boe/d of production at various properties and will adjust shut-in levels as required to maximize the economics of its production base.

  • The Company has also entered into incremental 2020 and 2021 natural gas hedges and near-term liquids hedges to mitigate volatility and protect cash flows. See below under "Hedging".

  • Given the significant ongoing uncertainty in market conditions and the unknown extent and duration of shut-ins, Paramount is withdrawing its 2020 sales volume guidance.

  • Long-term debt as at March 31, 2020 was $651.5 million. Paramount was in compliance with the financial covenants contained in its senior secured revolving bank credit facility (the "Paramount Facility") as at March 31, 2020. These covenants are described under the heading "Liquidity and Capital Resources" in the Company's Management's Discussion & Analysis for the quarter. The current adverse pricing conditions for liquids that have arisen in connection with the COVID-19 pandemic have resulted in a risk of non-compliance with these financial covenants in future periods. In response to this risk, Paramount has initiated negotiations for financial covenant relief and these negotiations are ongoing. Paramount anticipates that any agreement for financial covenant relief will include a reduction in the size of the Paramount Facility, among other changes.

  • The impact of the COVID-19 pandemic on forecast liquids and natural gas prices has caused the Company to record impairments to petroleum and natural gas assets totaling $191.8 million and a $130.0 million charge to derecognize a portion of the Company's deferred tax asset.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Karr

Karr sales volumes and netbacks are summarized below:


Q1 2020

Q4 2019

% Change

Sales volumes




Natural gas (MMcf/d)

59.4

69.1

(14)

Condensate and oil (Bbl/d)

9,691

11,816

(18)

Other NGLs (Bbl/d)

1,290

1,614

(20)

Total (Boe/d)

20,885

24,943

(16)

% liquids

53%

54%


Netback

($ millions)

($/Boe)

 ($ millions)

($/Boe)

% Change in $
 millions

Petroleum and natural gas sales

64.2

33.76

92.5

40.32

(31)

Royalties

(5.0)

(2.62)

(6.8)

(2.98)

(26)

Operating expense

(30.8)

(16.19)

(30.5)

(13.29)

1

Transportation and NGLs processing

(6.7)

(3.54)

(6.9)

(3.00)

(3)


21.7

11.41

48.3

21.05

(55)

First quarter 2020 sales volumes at Karr averaged 20,885 Boe/d compared to 24,943 Boe/d in the fourth quarter of 2019. First quarter sales volumes were impacted by severe cold weather and the back-out of production from certain legacy wells due to high pressures from the 4-24 and 1-19 pads. 

The Company has installed gas lift and related compression at pads near the southwest terminus of Paramount's gathering system. This work was done to mitigate the impact from newer higher-pressure wells upstream. 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. The bulk of these efforts are scheduled to be completed in third quarter of 2020.

Paramount brought into service two additional water disposal wells towards the end of the first quarter of 2020. These new wells are anticipated to reduce operating costs in the second quarter of 2020 and beyond by reducing the need to truck and dispose of water at third-party facilities.  Trucking is expected to be reduced even further upon the start-up of the third-party Karr 6-18 expansion in the second half of 2020 as additional high-pressure pumps will facilitate increased transportation of water to the disposal wells. The Company estimates that with the addition of these wells and related infrastructure, water disposal capacity is now sufficient to meet development needs for the foreseeable future. 

Drilling operations on 5 (5.0 net) wells on the 12-18 pad that commenced in the fourth quarter of 2019 were completed in the first quarter of 2020. New drill bit technology and improved directional drilling performance resulted in an 18 percent decrease in per meter costs on an Upper Montney well relative to equivalent wells on prior pads. Likewise, the Company saw improved efficiencies in its completion operations with a 25 percent increase in peak fracking stages per day at the 12-18 pad.  Paramount continues to incorporate cost savings through design changes that maintain performance without compromising on completion effectiveness.   

The streamlining of pad facility design combined with improved execution and strategic alliances with key vendors has proven effective in reducing equipping and tie-in costs. The Company anticipates savings of approximately 10 percent on upcoming pads with the potential for further reductions based on recent discussions with its key vendors. In aggregate, Paramount estimates that the all-in DCET cost on the 12-18 pad will average approximately $9.5 million per well; a new pacesetter cost for the Company. This compares with historic type well DCET costs of $12.3 million per well in Karr. 

The Company plans to complete and bring on production all 10 (10.0 net) wells from the 2-1 pad, drilled in the fourth quarter of 2019, and the 12-18 pad over the remainder of the year in conjunction with the completion of the third-party Karr 6-18 processing facility expansion, expected in the second half of 2020. Paramount commenced the drilling of 5 (5.0 net) Montney wells on the 5-16 pad in the first quarter of 2020 with current plans to complete and bring the wells on production in 2021.

Production in the second and third quarters of 2020 will be impacted by the temporary shut-in of certain offsetting wells due to completion activities at both the 12-18 and 2-1 pads. As these wells resume production and wells on the 12-18 and 2-1 pads are brought onstream, production at Karr is expected to increase through the second half of the year. A scheduled one-week outage in May at the third-party operated Karr 6-18 facility, in relation to expansion activities, is currently underway and will also impact second quarter volumes.

The following table summarizes the performance of the wells on the 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)


01-19 Pad








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

1,704

1,209

407

205

138

343

141

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

1,357

1,067

611

120

91

518

122

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

1,566

1,170

493

161

117

450

136

Avg. per well

1,542

1,149

486

162

115

412

133

04-24 Pad








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

1,878

1,271

349

268

165

265

201

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

1,836

1,308

413

222

152

362

202

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

2,307

1,583

365

356

230

307

216

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

2,097

1,329

289

358

216

253

209

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

2,029

1,308

302

318

199

278

209

Avg. per well

2,029

1,360

338

304

192

286

207

2018 Wells








5 wells (Avg. per well)

1,877

1,121

247

587

308

184

536

2016/2017 Wells








27 wells
(Avg. per well)

1,969

1,171

245

707

356

169

776

(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 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 March 31, 2020. Natural gas sales volumes are approximately 10 percent lower and 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

First quarter sales volumes at Wapiti averaged 7,209 Boe/d (66 percent liquids) compared to 11,498 Boe/d (66 percent liquids) in the fourth quarter of 2019. Production in the first quarter of 2020 was impacted by three outages at the third-party processing facility consisting of an unplanned outage in January of approximately 12 days (1,500 Boe/d), a planned outage in early March of approximately 7 days (1,100 Boe/d) and an unplanned outage in the second half of March of approximately 11 days (1,700 Boe/d). During the outages, both Paramount and the third-party operator capitalized on the downtime by conducting optimization and maintenance work that would have otherwise required future near-term outages. While it is expected that these activities will improve the reliability and efficiency of the processing facility and associated infrastructure, Paramount continues to assume a lower uptime factor until consistent reliability is exhibited.

The Company commenced drilling operations on 5 (5.0 net) wells at the 5-3 West pad and completed the drilling of 2 (2.0 net) new Montney wells at the 6-4 pad in the first quarter of 2020. Plans to complete and bring onstream wells on the 5-3 West pad, drill the remaining 6 (6.0 net) wells on the 6-4 pad, and complete and bring onstream all 8 wells, have been deferred. A tenure well drilled and completed in 2015 is planned to be brought on production later in 2020.

Paramount continues to maximize production from wells on the 12-well 5-3 East pad drilled in 2019 as third-party infrastructure capacity allows. The wells on the 5-3 East pad are seeing improved performance relative to wells on the 9-3 pad as a result of changes to well equipping configuration and more efficient fluid handling. To date, seven wells on the 5-3 East pad have flowed through permanent facilities with all having produced through test facilities.

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

147

93

286

92

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

1,736

1,187

360

80

55

366

58

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

1,776

1,110

278

95

61

291

67

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

2,076

1,344

306

130

84

303

86

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

-

-

-

36

24

348

25

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

-

-

-

55

36

328

27

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

-

-

-

41

28

369

22

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

1,465

1,036

403

68

49

423

52

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

1,481

1,066

428

46

34

443

32

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

-

-

-

41

29

399

23

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

-

-

-

31

22

395

20

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

-

-

-

21

16

494

10

Avg. per well

1,793

1,193

331

66

44

340

43

9-3 Pad








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

1,360

880

306

174

111

294

195

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

962

689

421

142

104

459

227

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

1,536

1,102

423

276

175

288

281

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

1,268

794

279

255

162

289

279

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

1,511

1,088

429

157

113

424

150

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

1,094

769

395

218

142

314

259

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

1,042

787

516

167

115

369

249

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

1,137

779

362

207

135

312

242

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

1,111

749

345

210

129

266

259

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

969

693

419

154

105

353

229

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

1,192

815

360

154

107

379

207

Avg. per well

1,198

831

378

192

127

325

234

(1)

Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Under standard process flowing conditions at contracted rates, the natural gas sales volumes are approximately 11 percent lower and liquids sales volumes are approximately 3 percent lower due to process 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 March 31, 2020. Under standard process flowing conditions at contracted rates, the natural gas sales volumes are approximately 11 percent lower and liquids sales volumes are approximately 3 percent lower due to process 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.

KAYBOB REGION

Kaybob Region sales volumes averaged 32,700 Boe/d (29 percent liquids) in the first quarter of 2020 compared to 33,167 Boe/d (31 percent liquids) in the fourth quarter of 2019. The annual decline rate on base well production in the Region is expected to be 15 percent over 2020 and is expected to largely flatten to 11 percent by 2022.

In the first quarter of 2020 the Company drilled 1 (1.0 net) Montney oil well at Ante Creek for Crown land retention purposes. A second land retention well that was planned to be drilled in 2020 prior to the Government of Alberta's announcement extending land expiries by one year will be deferred in reliance on this extension. The Company will benefit from this extension in a number of other areas.

The Company's crude oil terminal adjacent to the Kaybob North 8-9 gas plant continues to ramp-up operations smoothly with the capacity to handle growing Paramount and third-party volumes. Along with significant crude storage capability at this facility, Paramount is well positioned to take advantage of recent and anticipated price volatility in the crude and condensate markets in order to enhance Kaybob Region netbacks.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 9,108 Boe/d (14 percent liquids) in the first quarter of 2020 compared to 15,455 Boe/d (26 percent liquids) in the fourth quarter of 2019. Sales volumes in the fourth quarter of 2019, when adjusted to exclude production from assets sold in December 2019, averaged approximately 9,200 Boe/d.

The Company continued its ABC abandonment and reclamation projects at Hawkeye and Zama in 2020. In the first quarter of 2020, Paramount abandoned 224 wells in these areas (out of total of 248 abandoned by the Company in the quarter), including all remaining operated Hawkeye wells. In doing so, the Company realized an approximate 7 percent decrease in per-well abandonment costs compared to the fourth quarter of 2019. 

GREENHOUSE GAS REDUCTION INITIATIVE

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

The Company is continuing upgrades to replace its remaining high-bleed controllers at various sites with modern low-bleed units. 196 low-bleed units are expected to be installed in the Grande Prairie Region in the second quarter of 2020. 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.

HEDGING

The Company's current commodity hedge position is summarized below:

Oil

Volume

Price

Remaining term

Oil – NYMEX WTI Swaps (Sale)

4,000 Bbl/d

CDN$80.11/Bbl

      April 2020 – December 2020

Oil – NYMEX WTI Swaps (Sale)

6,000 Bbl/d

CDN$38.78/Bbl

                                    May 2020 

Oil – NYMEX WTI Swaps (Sale)

6,000 Bbl/d

CDN$40.15/Bbl

                                   June 2020

 

Gas

Volume

Price

Remaining term

NYMEX Swaps (Sale)

10,000 MMBtu/d

US$2.93/MMBtu

   November 2020 - March 2021

NYMEX Swaps (Sale)

20,000 MMBtu/d

US$2.75/MMBtu

January 2021 - December 2021

Physical

80,000 GJ/d

$1.61/GJ

April 2020 - October 2020

Physical

10,000 GJ/d

$2.11/GJ

May 2020 - October 2020

Physical

10,000 GJ/d

$2.65/GJ

November 2020 - March 2021

Physical

20,000 GJ/d

$2.50/GJ

January 2021 - December 2021

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 first 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/1167577/Paramount_Resources_Ltd_ReportsQ12020.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)


Q1 2020

Q4 2019

Net loss

(235.1)

(31.1)

per share – basic and diluted ($/share)

(1.76)

(0.24)

Cash from operating activities

30.5

70.5

per share – basic and diluted ($/share)

0.23

0.54

Adjusted funds flow

33.5

93.5

per share – basic and diluted ($/share)

0.25

0.71

Total assets

3,009.5

3,531.3

Long-term debt

651.5

632.3

Net debt

771.9

703.5

Common shares outstanding (thousands)(2)

133,346

133,337

Sales volumes



Natural gas (MMcf/d) 

261.5

299.0

Condensate and oil (Bbl/d)

21,898

28,516

Other NGLs (Bbl/d) (3)

4,539

7,064

Total (Boe/d)

70,022

85,411

% liquids

38%

42%

Grande Prairie Region (Boe/d)

28,214

36,789

Kaybob Region (Boe/d)

32,700

33,167

Central Alberta and Other Region (Boe/d)

9,108

15,455

Total (Boe/d)

70,022

85,411

Netback


$/Boe (4)


$/Boe (4)

Natural gas revenue

53.6

2.25

75.1

2.73

Condensate and oil revenue

111.4

55.92

175.0

66.70

Other NGLs revenue (3)

4.4

10.75

8.5

13.03

Royalty and sulphur revenue

2.7

1.3

Petroleum and natural gas sales

172.1

27.01

259.9

33.08

Royalties

(11.7)

(1.84)

(17.2)

(2.19)

Operating expense

(92.3)

(14.49)

(105.0)

(13.36)

Transportation and NGLs processing (5)

(23.6)

(3.70)

(22.8)

(2.90)

Netback

44.5

6.98

114.9

14.63

Commodity contract settlements

7.0

1.10

4.7

0.60

Netback including commodity contract settlements

51.5

8.08

119.6

15.23

Total Capital Expenditures



Grande Prairie Region

49.8

60.7

Kaybob Region

10.1

9.5

Central Alberta and Other Region

2.8

0.6

Corporate

1.1

Land and property acquisitions

1.4

Total

63.8

72.2

Asset retirement obligations settlements

30.3

18.0

(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): 2020: 852.4; 2019: 859.7

(3)

Other NGLs means ethane, propane and butane.

(4)

Natural gas revenue presented as $/Mcf.

(5)

Includes downstream transportation costs and NGLs fractionation costs.

ADVISORIES

Forward-looking Information

Certain statements in this press release constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "schedule", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward-looking information in this press release includes, but is not limited to:

  • an expected reduction in operating costs from two additional water disposal wells at Karr and the expectation that the wells will meet Karr development needs for the foreseeable future;
  • planned capital expenditures for 2020;
  • planned abandonment and reclamation expenditures for 2020;
  • planned exploration, development and production activities;
  • expected reductions in costs and expenditures;
  • the expectation that negotiations for financial covenant relief under the Paramount Facility will be successful and the terms thereof;
  • estimated and anticipated DCET costs;
  • the expected completion of the 6-18 facility expansion and the timing thereof;
  • an expected increase in production at Karr through the second-half of the year;
  • an expected improvement in the reliability and efficiency of the third-party Wapiti processing facility and associated infrastructure;
  • expected decline rates at Kaybob; and
  • expected GHG reductions associated with controller upgrades and expected GHG credits.

Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this press release:

  • future natural gas and liquids prices and the potential impact of the COVID-19 pandemic thereon;
  • the likely impact of the COVID-19 pandemic on operations;
  • the likely result of negotiations for financial covenant relief under the Paramount Facility;
  • the ability to realize expected cost savings;
  • the ability to successfully implement measures to reduce costs and expenses;
  • royalty rates, taxes and capital, operating, general & administrative and other costs;
  • foreign currency exchange rates and interest rates;
  • general business, economic and market conditions;
  • the ability of Paramount to obtain the required capital to finance its exploration, development and other operations and meet its commitments and financial obligations;
  • the ability of Paramount to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out its activities;
  • the ability of Paramount to secure adequate product processing, transportation, fractionation, and storage capacity on acceptable terms and the capacity and reliability of facilities;
  • the ability of Paramount to market its natural gas and liquids successfully to current and new customers;
  • the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, liquids yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations;
  • the timely receipt of required governmental and regulatory approvals;
  • the application of regulatory requirements respecting abandonment and reclamation; and
  • anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins, the construction, commissioning and start-up of new and expanded facilities, including third-party facilities and facility turnarounds and maintenance).

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct. In addition, although Paramount expects that negotiations for financial covenant relief under the Paramount Facility will be successful, there is no assurance that an agreement will be reached on acceptable terms. Forward-looking information is based on expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward-looking information. The material risks and uncertainties include, but are not limited to:

  • those risks set out in the Management's Discussion and Analysis for the three months ended March 31, 2020 ("MD&A") under "Risk Factors";
  • fluctuations in natural gas and liquids prices, including in relation to the impact of the COVID-19 pandemic;
  • the risk that negotiations for financial covenant relief under the Paramount Facility will not be successful and the risks set out under "Risk Factors - Credit Facility and Indebtedness" in Paramount's annual information form;
  • changes in capital spending plans and planned exploration and development activities;
  • changes in foreign currency exchange rates and interest rates;
  • the uncertainty of estimates and projections relating to future revenue, production, reserve additions, liquids yields (including condensate to natural gas ratios), resource recoveries, royalty rates, taxes and costs and expenses;
  • the ability to secure adequate product processing, transportation, fractionation, and storage capacity on acceptable terms;
  • operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts;
  • the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost;
  • potential disruptions, delays or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities);
  • processing, pipeline, and fractionation infrastructure outages, disruptions and constraints;
  • risks and uncertainties involving the geology of oil and gas deposits;
  • the uncertainty of reserves estimates;
  • general business, economic and market conditions;
  • the ability to generate sufficient cash flow from operations and obtain financing to fund planned exploration, development and operational activities and meet current and future commitments and obligations (including product processing, transportation, fractionation and similar commitments and obligations);
  • changes in, or in the interpretation of, laws, regulations or policies (including environmental laws);
  • the ability to obtain required governmental or regulatory approvals in a timely manner, and to obtain and maintain leases and licenses;
  • the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;
  • the timing and cost of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination;
  • uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders;
  • the outcome of existing and potential lawsuits, regulatory actions, audits and assessments; and
  • other risks and uncertainties described elsewhere in this document and in Paramount's other filings with Canadian securities authorities.

The foregoing list of risks is not exhaustive. For more information relating to risks, see the sections titled "Risk Factors" in Paramount's annual information form for the year ended December 31, 2019, and in the MD&A which are available on SEDAR at www.sedar.com. The forward-looking information contained in this press release is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Non-GAAP Measures

In this press release, "Adjusted funds flow", "Netback", "Net Debt" and "Total Capital Expenditure", together the "Non-GAAP measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards.

"Adjusted funds flow" refers to cash from operating activities before net changes in operating non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements, provision and other, dispute settlements, closure costs and transaction and reorganization costs.  Adjusted funds flow is used to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations, including the settlement of asset retirement obligations. Asset retirement obligation settlements are excluded from the calculation of adjusted funds flow because such expenditures are not directly linked to the revenue generating activities of the Company. Paramount manages the timing of expenditures related to asset retirement obligation settlements in accordance with regulatory requirements and its overall approach to managing its asset retirement obligations and, as a result, amounts incurred may vary from period to period. Adjusted funds flow is not intended to represent cash from operating activities, net loss or any other GAAP measure and should not be construed as being an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS. The following is a reconciliation of adjusted funds flow to the nearest GAAP measure for the three months ended March 31, 2020 and December 31, 2019:

Three months ended

Mar 31, 2020

(MM$)

Dec. 31, 2019

(MM$)

Cash from operating activities

30.5

70.4

Change in non-cash working capital

(34.3)

(7.9)

Geological and geophysical expenses

2.6

3.5

Asset retirement obligations settled

30.3

18.0

Provision and other

4.4

-

Closure costs

-

4.7

Dispute settlements

-

2.5

Transaction and reorganization costs

-

2.3

Adjusted funds flow

33.5

93.5

"Netback" equals petroleum and natural gas sales less royalties, operating costs and transportation and NGLs processing costs.  Netback is commonly used by management and investors to compare the results of the Company's oil and gas operations between periods. Refer to the table under the heading "Financial and Operating Results" for the calculation thereof.

"Net Debt" is a measure of the Company's overall debt position after adjusting for certain working capital and other amounts and is used by management to assess the Company's overall leverage position. Refer to the Liquidity and Capital Resources section of the Company's MD&A for the calculation of Net Debt.

"Total capital expenditures" refers to the Company's property, plant and equipment and exploration expenditures. Refer to the Property, Plant and Equipment and Exploration Expenditures section of the Company's MD&A for the calculation thereof.

Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers.

Oil and Gas Measures and Definitions

The term "liquids" includes oil, condensate and Other NGLs (ethane, propane and butane).  NGLs consist of condensate and Other NGLs.

Abbreviations

Liquids


Natural Gas

Bbl

Barrels


GJ

Gigajoules

Bbl/d

Barrels per day


GJ/d

Gigajoules per day

MBbl

Thousands of barrels


Mcf

Thousands of cubic feet

NGLs

Natural gas liquids


MMcf

Millions of cubic feet

Condensate

Pentane and heavier hydrocarbons

MMcf/d

Millions of cubic feet per day




AECO

AECO-C reference price

Oil Equivalent


WTI

West Texas Intermediate

Boe

Barrels of oil equivalent




MBoe

Thousands of barrels of oil equivalent




MMBoe

Millions of barrels of oil equivalent




Boe/d

Barrels of oil equivalent per day




This press release contains disclosures expressed as "Boe", "$/Boe", "MBoe","MMBoe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the three months ended March 31, 2020, the value ratio between crude oil and natural gas was approximately 26:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.

This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes. This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses this oil and gas metric for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measure is not a reliable indicator of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.

Additional information respecting the Company's oil and gas properties and operations, including a breakdown of 2019 annual and quarterly production volumes by product type, is provided in the Company's annual information form for the year ended December 31, 2019 which is available on SEDAR at www.sedar.com.

SOURCE Paramount Resources Ltd.

Cision View original content to download multimedia: http://www.newswire.ca/en/releases/archive/May2020/13/c8570.html

Paramount Resources Ltd., J.H.T. (Jim) Riddell, President and Chief Executive Officer and Chairman, Rodrigo (Rod) Sousa, Executive Vice President, Corporate Development and Planning, www.paramountres.com, Phone: (403) 290-3600Copyright CNW Group 2020

Copyright © QuoteMedia. Data delayed 15 minutes unless otherwise indicated. View delay times for all exchanges. Market Data powered by QuoteMedia. See the QuoteMedia Terms of Use.