Paramount Resources Ltd. Reports Second Quarter 2018 Results

CALGARY, Aug. 8, 2018 /CNW/ -

OIL AND GAS OPERATIONS

  • Paramount's sales volumes averaged 86,741 Boe/d in the second quarter of 2018. Liquids sales volumes averaged 31,057 Bbl/d and constituted 77 percent of total revenue.

  • The Karr development averaged 54 percent liquids for the quarter and generated 55 percent of Paramount's total netback.

  • The Company is on target to complete liquids handling projects that will increase Karr area raw liquids handling capacity to approximately 15,000 Bbl/d by the end of 2018.

  • Paramount executed its first high-intensity well completion in the Lower Montney zone at Karr and the well was flow tested in July. Preliminary results from this well are encouraging and the Company is in the process of quantifying the number of Lower Montney locations on its Karr lands (none currently recognized).

  • At Wapiti, 11 Montney wells were drilled on the 9-3 pad between January and July 2018. These wells are similar in design to the recent Karr Montney wells and are expected to have similar liquids-rich production profiles. Six of these wells are scheduled to be completed in the fourth quarter.

  • In the Kaybob Region, well completions were carried out at the 7-22 five-well South Duvernay pad and the 10-35 four-well Smoky Duvernay pad. These wells are currently being flow tested through temporary facilities.

  • In the Central Alberta and Other Region, the 5-29 Duvernay well at Willesden Green was completed and flow tested in July. Test data from this well confirms that an over-pressure, high oil deliverability reservoir is present on the majority of the Company's Willesden Green Duvernay acreage.

  • Exploration and development capital was $171.8 million in the second quarter and $303.4 million for the six months ended June 30, 2018.

  • In July 2018, Paramount sold its oil and gas properties at Resthaven/Jayar in the Grande Prairie Region for $340 million. The Company expects to recognize a gain of approximately $53 million in respect of the disposition in the third quarter.

  • Paramount expects 2018 average annual sales volumes to range between 88,000 Boe/d and 92,000 Boe/d (approximately 37 percent liquids).

  • The Company's 2018 capital budget is unchanged at $600 million. Approximately one-third of the 2018 capital program is being directed to growth projects at Wapiti and Karr that will add material liquids-rich production and cash flow in 2019.

CORPORATE

  • Adjusted funds flow was $62.6 million ($87.4 million before hedging settlements) for the second quarter and $160.3 million ($197.4 million before hedging settlements) for the six months ended June 30, 2018.

  • With the closing of the Resthaven/Jayar property sale, Paramount has exceeded its 2018 disposition target. Consistent with its long-term strategy, Paramount continues to opportunistically pursue non-core property dispositions with a focus on maximizing value.

  • Paramount has purchased and cancelled 3.2 million common shares under its normal course issuer bid program at a total cost of $53.8 million to July 31, 2018.

  • In April 2018, the Company redeemed all $300 million principal amount of its 7.25% senior unsecured notes. The redemption was funded from Paramount's expanded $1.2 billion bank credit facility.

REVIEW OF OPERATIONS

Sales volumes averaged 86,741 Boe/d in the second quarter of 2018 compared to 18,367 Boe/d in the second quarter of 2017. Liquids volumes increased to 31,057 Bbl/d compared to 9,532 Bbl/d in the same period in 2017. Second quarter production was impacted by approximately 4,300 Boe/d as a result of scheduled and unscheduled third-party facility outages.

Paramount's netback was $103.6 million in the second quarter of 2018, nearly three times the Company's second quarter 2017 netback. Second quarter 2018 adjusted funds flow was $62.6 million compared to $35.2 million in the same period in 2017.

Operating costs averaged $12.01 per Boe in the second quarter of 2018 and $11.56 per Boe for the six months ended June 30, 2018. As a large proportion of Paramount's operating costs are fixed, operating costs per Boe are expected to decrease in the second half of 2018 as sales volumes increase and further benefits are realized from operational efficiencies. The Company is continuing to streamline its field operations, including consolidating field offices, optimizing field staff and contract operators and rationalizing software and service contracts.

Exploration and development capital was $171.8 million for the second quarter of 2018 and $303.4 million for the first half of 2018. First half exploration and development spending included $72.7 million related to growth projects at Wapiti and Karr that will add material liquids-rich production and cash flow in 2019.  

2018 WELL COMPLETION PROGRAM

In the second quarter of 2018, completion operations were carried out on three multi-well pads at Kaybob and Karr and a Duvernay well was completed at Willesden Green. Paramount successfully completed 5 (2.5 net) wells on the 7-22 Kaybob South Duvernay pad and 5 (5.0 net) wells on the 1-2 Karr Montney pad. Both pads set new pacesetters on several metrics and were completed without any operational or safety issues. The completions employed a plug and perf design with a zipper fracturing operation. Pumping downtime was minimized between stages by utilizing a surface manifold on both pads. This, along with other improvements, contributed to an average of 11.4 and 10.9 fracks completed per day, with a daily maximum of 15 and 16 fracks, for the 7-22 Kaybob pad and the 1-2 Karr pad, respectively. Reductions in the duration of the mill-out portion of the completions were also achieved, as Paramount successfully tested a variety of composite and dissolvable plugs.

Paramount also continued to refine completion designs with controlled tests in perforation clusters, fluid viscosity, pump rate, fracture sequencing and landing zones. The 7-22 Kaybob pad included permanent fiber optic installations on two of its wells, which remain intact for future production tests. The fiber optic system was utilized in real time to assess the distribution of fluid and sand for specific perforations designs. The analysis from the 7-22 Kaybob pad fiber optic system was immediately incorporated in well completion designs for the 4 (4.0 net) wells on the 10-35 Kaybob Smoky Duvernay pad and the 5-29 Duvernay well at Willesden Green.

GRANDE PRAIRIE REGION

Sales volumes in the Grande Prairie Region in the second quarter of 2018 averaged 27,483 Boe/d, primarily comprised of liquids-rich production from the Karr development. Exploration and development capital totaled $73.5 million in the second quarter and $147.8 million for the six months ended June 30, 2018. Development activities in the second quarter focused on finishing drilling operations at the 5 (5.0 net) well 4-24 Karr pad and completing the five wells on the 1-2 Karr pad. Drilling operations also continued at the 11 (11.0 net) well 9-3 Wapiti pad.

In July 2018, Paramount sold its oil and gas properties at Resthaven/Jayar for $340 million to Strath Resources Ltd. (ʺStrathʺ). Total consideration included $170 million cash, 85 million common shares of Strath and 8.5 million warrants to acquire Strath common shares. Sales volumes for the properties in 2018 prior to the sale averaged approximately 5,000 Boe/d, on a restricted basis.

Karr

The Karr development generated 55 percent of Paramount's total netback in the second quarter. Cash flows at Karr benefit from a liquids-rich product mix, which generates higher per-unit revenues, and lower per-unit operating costs.

Sales volumes at Karr in the second quarter of 2018 were impacted by approximately 1,800 Boe/d as a result of planned and unplanned outages at a third-party processing facility. Second quarter sales volumes and netbacks at Karr are summarized as follows:


Q2 2018

Q2 2017

% Change

Sales volumes





Natural gas (MMcf/d)

58.6

29.4

99


Condensate and oil (Bbl/d)

10,308

7,147

44


Other NGLs (Bbl/d)

1,195

410

191


Total (Boe/d)

21,269

12,452

71


% liquids

54%

61%






Netback

$/Boe

($ millions)

$/Boe

($ millions)

% Change in
$ millions


Petroleum and natural gas sales

44.51

86.1

42.04

47.6

81


Royalties

(3.33)

(6.4)

(0.58)

(0.7)

814


Operating expense

(9.14)

(17.7)

(9.51)

(10.8)

64


Transportation and NGLs processing

(2.72)

(5.3)

(5.09)

(5.7)

(7)


29.32

56.7

26.86

30.4

87

 

New wells are maintaining higher condensate rates for longer periods after initial start-up resulting in higher than expected per-well condensate production. To maximize cash flows, Paramount is prioritizing condensate production at its Karr 6-18 compression and dehydration facility (the ʺ6-18 Facilityʺ), fully utilizing liquids handling capacity and managing natural gas production by restricting flow rates. The Company is on target to complete debottlenecking projects at the 6-18 Facility and new trucking facilities that will increase Karr area raw liquids handling capacity to approximately 15,000 Bbl/d by the end of 2018.

Following the completion of an expansion to condensate stabilization capacity at a third-party facility in May 2018, the majority of liquids volumes at Karr are now being delivered into pipelines, which provide cost savings. The Company is continuing to truck a portion of liquids production in excess of available pipeline and stabilization capacity to maximize cash flows.

The Company executed its first high intensity well completion on a new Lower Montney horizontal well to test the deliverability of the zone. This well was flow tested in line in July 2018 and is currently shut-in for tubing installation. In the five days prior to being shut-in, the well averaged 1,776 Boe/d of test production at the wellhead on a restricted basis, with a 62 percent condensate ratio(1). Preliminary results from this well are encouraging, and Paramount is in the process of quantifying the number of Lower Montney locations on its Karr lands. No locations have been recognized in the Lower Montney for Paramount's Karr development to date.

Test results from the five Montney wells on the 1-2 Karr pad to date have been in line with expectations. These wells will be brought on full production in the third quarter following the installation of permanent production facilities.

The expansion of natural gas capacity at the 6-18 Facility from 80 MMcf/d to 100 MMcf/d is substantially complete. The expansion will be tied-in and commissioned as the liquids handling projects are completed and the incremental capacity is required.

To support growth at Karr, Paramount has sanctioned the construction of a Company-owned and operated natural gas processing facility to be built alongside the current 6-18 Facility. The project will add 50 MMcf/d of natural gas processing capacity and 30,000 Bbl/d of condensate stabilization capacity. The Company is currently placing long-lead time equipment orders to meet the project timeline for start-up in the second half of 2020.

Paramount's production base at Karr includes 27 (27.0 net) horizontal Montney wells from the Company's 2016/2017 capital program (the ʺ2016/2017 Karr Wellsʺ). These 27 wells were part of the Company's initial drilling and completion program employing new well designs with longer lateral sections and high intensity fracks. The following table summarizes the performance of the 2016/2017 Karr Wells:

Well

Peak 30-
Day

Total (1)

Peak 30-Day

Condensate (1)

Peak 30-
Day
Condensate

Days on
Production

Cumulative
Production (2)

Cumulative
Condensate
P
roduction (2)

Cumulative
Condensate
Production


(Boe/d)

      (Bbl/d)

(%)


(MBoe)

(MBbl)

(%)









00/04-07-065-05W6/00

2,555

1,815

71%

526

618

435

70%

02/04-07-065-05W6/00

2,847

2,176

76%

497

738

558

76%

02/01-12-065-06W6/00

2,637

1,795

68%

470

540

354

66%

00/09-32-065-04W6/00

2,163

1,401

65%

412

600

335

56%

00/16-32-065-04W6/00

2,127

1,263

59%

394

652

340

52%

00/01-12-065-06W6/00

2,221

1,533

69%

311

355

244

69%

00/03-22-066-05W6/00

1,955

946

48%

284

322

141

44%

00/04-06-066-04W6/00

1,820

900

49%

350

467

192

41%

02/16-24-066-05W6/00

1,345

694

52%

341

346

149

43%

02/04-06-066-04W6/00

2,053

1,414

69%

347

469

209

45%

00/03-06-066-04W6/00

1,845

942

51%

345

536

227

42%

00/15-14-065-06W6/00

2,627

1,341

51%

248

477

239

50%

00/16-24-066-05W6/00

1,356

710

52%

296

326

148

45%

00/04-34-065-05W6/00

2,143

994

46%

341

420

191

46%

00/01-33-065-05W6/00

1,918

805

42%

333

405

176

43%

02/09-32-065-04W6/00

1,771

1,042

59%

292

330

175

53%

02/16-14-065-06W6/00

2,230

1,350

61%

280

436

264

60%

00/08-32-065-04W6/00

1,860

1,176

63%

204

319

195

61%

00/13-14-065-06W6/00

1,715

1,060

62%

243

271

156

57%

02/15-14-065-06W6/00

1,921

1,235

64%

185

284

171

60%

02/14-14-065-06W6/00

1,796

1,218

68%

199

310

181

58%

02/02-25-065-05W6/02

1,913

1,146

60%

208

317

179

57%

03/01-25-065-05W6/00

1,507

890

59%

203

255

148

58%

02/03-25-065-05W6/00

1,818

1,013

56%

137

223

132

59%

00/03-25-065-05W6/00

1,610

1,007

63%

126

173

108

63%

00/02-25-065-05W6/00

1,838

1,076

59%

116

177

104

58%

00/14-14-065-06W6/00

1,521

1,044

69%

96

122

80

66%

Average

1,963

1,185

60%

288



56%

(1)

Peak 30 Day is the highest daily average production rate over a 30-day consecutive period for an individual well, measured at the wellhead. Natural gas sales volumes are approximately 10 percent lower and stabilized condensate sales volumes are approximately 15 percent lower due to shrinkage. Excludes days when the well 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. Certain of the wells were produced at restricted rates from time-to-time due to facility and gathering system constraints.

(2)

Cumulative production for an individual well measured at the wellhead to July 29, 2018. Natural gas sales volumes are approximately 10 percent lower and stabilized condensate sales volumes are approximately 15 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.

 

Royalty rates for the Karr development increased in the second quarter of 2018 compared to the same period in 2017 primarily as a result of fully utilizing new well royalty allowances for a portion of the 2016/2017 Karr Wells. New wells from the Company's 2018 development program will continue to benefit from a five percent initial royalty rate up to the maximum allowance.

Wapiti

Sales volumes at Wapiti for the second quarter of 2018 averaged approximately 500 Boe/d. Paramount is currently producing legacy Montney wells at Wapiti through an existing third-party processing facility.

Drilling operations for the 2018 capital program commenced at the 9-3 Wapiti pad in January, with all 11 wells being drilled by the end of July. These wells are targeting the Middle and Lower Montney formations at varied well spacings to collect additional reservoir performance data for future development. In the fourth quarter of 2018, six of these wells are scheduled to be completed and drilling operations are scheduled to commence on a new 12-well Wapiti pad. These Wapiti Montney wells are similar in design to the recent Karr development wells and are expected to have similar liquids-rich production profiles. These new Wapiti Montney wells will be produced through a new 150 MMcf/d third-party processing facility, which the operator plans to commission in mid-2019.

Paramount has received regulatory approval for a water disposal well at Wapiti to support its development. Injection and fall-off tests were conducted to assess the well's disposal capacity over the 200 meter completed interval. Step rate test results exceeded 7,500 cubic meters per day without reaching maximum injection pressure and the long-term injection capacity of the well was confirmed by reservoir analysis.  This disposal well will reduce trucking and water disposal fees, resulting in lower completion and operating costs for the Company's Wapiti development.

KAYBOB REGION

Kaybob Region sales volumes averaged 39,527 Boe/d in the second quarter of 2018, including 12,024 Bbl/d of liquids. A portion of Kaybob area production was shut-in due to the scheduled turnaround of a third-party processing facility, which reduced second quarter sales volumes by approximately 1,800 Boe/d. The outage was slightly longer than anticipated. Exploration and development capital in the Kaybob Region was $87.7 million in the second quarter of 2018 and $138.9 million for the six months ended June 30, 2018.

Kaybob Smoky Duvernay

Completion operations on the 10-35 Smoky pad were completed in June and all four wells are currently flowing on clean-up at restricted rates. Initial test results are confirming the high liquids yield nature of the area. The Company plans to evaluate the performance of these wells for the remainder of 2018 and resume drilling and completion activities at Kaybob Smoky Duvernay in 2019. Wells on this pad will be produced through the Paramount operated 6-16 Kaybob Smoky natural gas plant (the ʺ6-16 Plantʺ). An expansion of the 6-16 Plant to increase throughput capacity to 12 MMcf/d of liquids-rich natural gas is expected to be operational by the end of August 2018.

Kaybob South Duvernay

The Company's 2018 capital program at the Kaybob South Duvernay development includes two multi-well pads. The 7-22 South Duvernay pad was completed and all 5 (2.5 net) wells are currently flowing on clean up at restricted rates through temporary facilities awaiting the installation of permanent production equipment. Over their initial 31 days on production, these wells averaged a restricted 1,251 Boe/d of gross production per well, including 56 percent condensate volumes, with an average condensate to gas ratio of 216 Bbl/MMcf.(2) Drilling operations for 5 (2.5 net) wells on a new South Duvernay pad are scheduled to commence by the end of the third quarter.

Kaybob Montney Oil

Second quarter 2018 sales volumes at the Kaybob Montney Oil property were 9,640 Boe/d, approximately 60 percent liquids. To date, eight (8.0 net) wells in the Company's 17-well Kaybob Montney Oil capital program for 2018 have been completed and brought on production. These new wells are currently producing at restricted rates pending the installation of additional liquids handling infrastructure later in the third quarter. Drilling operations will commence later in August for the remaining 9 (9.0 net) wells in the 2018 program.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 19,731 Boe/d in the second quarter of 2018. Third-party outages as a result of scheduled facility turnarounds impacted second quarter sales volumes in the Region by approximately 700 Boe/d. Exploration and development capital spending in the Central Alberta and Other Region totaled $10.6 million in the second quarter of 2018.

Development activities in the Central and Other Region are focused on the 5-29 Duvernay oil well at Willesden Green. This well was completed in July and is being flow tested. Pressure test results from the 5-29 well indicate high over-pressure in the reservoir. The pressure data has confirmed that an over-pressure, high oil deliverability reservoir is present on the majority of the Company's Willesden Green Duvernay acreage.

OUTLOOK

Paramount expects 2018 average annual sales volumes to range between 88,000 Boe/d and 92,000 Boe/d (approximately 37 percent liquids). Production in the third quarter will be impacted by scheduled turnarounds at Paramount's operated 8-9 facility in Kaybob and a third-party facility in Karr, as well as the Resthaven/Jayar sale. The impact of these events will be largely offset by bringing onstream the new pads at Karr and Kaybob, the Duvernay well at Willesden Green and several other wells throughout the third quarter. Sales volumes are expected to increase in the fourth quarter.

The Company's 2018 capital budget remains unchanged at $600 million including exploration, optimization and maintenance programs, excluding land acquisitions, divestitures and abandonment and reclamation activities.

OPERATING AND FINANCIAL RESULTS (1)

($ millions, except as noted)


Three months ended June 30

Six months ended June 30


2018

2017

2018

2017

Sales volumes (Boe/d)






Grande Prairie

27,483

16,658

27,938

15,529


Kaybob

39,527

199

40,678

209


Central Alberta and Other

19,731

1,510

20,841

1,533

Total

86,741

18,367

89,457

17,271


% liquids

36%

52%

36%

50%

Netback

$/Boe (3)


$/Boe (3)


$/Boe (3)


$/Boe (3)



Natural gas revenue

1.71

52.1

3.24

15.6

2.16

134.0

3.39

32.0


Condensate and oil revenue

77.25

167.4

57.95

42.8

73.58

327.6

59.61

78.1


Other NGLs revenue (2)

27.35

18.0

20.09

2.6

29.65

41.7

21.77

5.3


Royalty and sulphur revenue

2.2

0.3

6.2

0.6

Petroleum and natural gas sales

30.37

239.7

36.69

61.3

31.47

509.5

37.12

116.0


Royalties

(2.84)

(22.4)

(0.46)

(0.8)

(2.37)

(38.4)

(0.90)

(2.8)


Operating expense

(12.01)

(94.8)

(10.29)

(17.2)

(11.56)

(187.1)

(10.25)

(32.1)


Transportation and NGLs processing (4)

(2.40)

(18.9)

(4.89)

(8.2)

(2.84)

(46.0)

(4.58)

(14.3)

Netback

13.12

103.6

21.05

35.1

14.70

238.0

21.39

66.8










Exploration and development capital (5)






Grande Prairie

73.5

110.6

147.8

242.1


Kaybob

87.7

138.9


Central Alberta and Other

10.6

0.6

16.7

14.9

Total

171.8

111.2

303.4

257.0






Net income (loss)

(134.6)

45.3

(215.6)

66.1


per share – diluted ($/share)

(1.01)

0.42

(1.62)

0.62






Adjusted funds flow

62.6

35.2

160.3

63.2


per share – diluted ($/share)

0.47

0.33

1.20

0.59






Total assets



5,044.7

2,051.8






Net debt (cash)



853.8

(565.6)






Common shares outstanding (thousands)



132,759

106,200






(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.

(2)

Other NGLs means ethane, propane and butane.

(3)

Natural gas revenue shown per Mcf.

(4)

Includes Downstream natural gas, NGLs and oil transportation costs and NGLs fractionation costs.

(5)

Excludes land and property acquisitions and spending related to corporate assets.

 

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 resources, including long-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 2018 results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements can be obtained at: http://files.newswire.ca/1509/ParamountQ2-2018.pdf

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

Advisories

Forward-looking Information

Certain statements in this document 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 document includes, but is not limited to:

  • projected production, sales volumes and cash flows and the timing thereof and the projected liquids component of such production and sales volumes;
  • forecast capital expenditures and operating costs;
  • estimated gain in respect of the Resthaven/Jayar property disposition;
  • exploration, development, and associated operational plans and strategies;
  • projected timelines for constructing and starting up new and expanded processing facilities and the processing capacity of such facilities upon completion;
  • the projected availability of third party processing facilities;
  • non-core property dispositions; and
  • general business strategies and objectives.

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 document:

  • future natural gas and liquids prices;
  • 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, de-ethanization, fractionation, and storage capacity on acceptable terms;
  • 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; and
  • anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins and the construction, commissioning and start-up of new and expanded facilities).

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable, undue reliance should not be placed on them as Paramount can give no assurance that such expectations will prove to be correct. 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:

  • fluctuations in natural gas and liquids prices;
  • 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, de-ethanization, fractionation, and storage capacity on acceptable terms;
  • operational risks in exploring for, developing and producing, natural gas and liquids;
  • 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, de-ethanization, 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, de-ethanization, 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 section titled "RISK FACTORS" in Paramount's current annual information form. The forward-looking information contained in this document 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 document "Adjusted funds flow", "Netback", "Net debt (cash)" and "Exploration and development capital", collectively 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 and transaction and reorganization costs. Adjusted funds flow is commonly used in the oil and gas industry to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations. Refer to the Consolidated Results section of the Company's Management's Discussion and Analysis for the three and six months ended June 30, 2018 for the calculation thereof. 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 Operating Results section of the Company's Management's Discussion and Analysis for the three and six months ended June 30, 2018 for the calculation thereof. Net debt (cash) is a measure of the Company's overall debt position after adjusting for certain working capital 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 Management's Discussion and Analysis for the three and six months ended June 30, 2018 for the calculation of Net debt (cash). Exploration and development capital consists of the Company's spending on wells, infrastructure projects, other property, plant and equipment and exploration and evaluation assets and excludes spending related to land and property acquisitions and corporate assets. The Exploration and development capital measure provides management and investors with information regarding the Company's capital spending on wells and infrastructure projects separate from land and property acquisition activity and corporate expenditures. Refer to the Property, Plant and Equipment and Exploration Expenditures section of the Company's Management's Discussion and Analysis for the three and six months ended June 30, 2018 for the calculations 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

Abbreviations

Liquids


Natural Gas

Bbl

Barrels


Mcf/d

Thousands of cubic feet

Bbl/d

Barrels per day


MMcf/d

Millions of cubic feet per day

MBbl

Thousands of barrels


Bcf

Billions of cubic feet

NGLs

Natural gas liquids


AECO

AECO-C reference price

Condensate

Pentane and heavier hydrocarbons


NYMEX

New York Mercantile Exchange






Oil Equivalent




Boe

Barrels of oil equivalent




MBoe

Thousands of barrels of oil equivalent




Boe/d

Barrels of oil equivalent per day




 

This document contains disclosures expressed as "Boe", "$/Boe", "MBoe" 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. 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 six months ended June 30, 2018, the value ratio between crude oil and natural gas was approximately 53:1. 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. The term "liquids" is used to represent oil, condensate and Other NGLs. NGLs consist of condensate and Other NGLs. The term "Other NGLs" means ethane, propane and butane.

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(1) Production measured at the wellhead. Natural gas sales volumes are approximately 10 percent lower and stabilized condensate sales volumes are approximately 15 percent lower due to shrinkage. The production rates and volumes 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.
(2) Production measured at the wellhead. Natural gas sales volumes are approximately 10 percent lower and stabilized condensate sales volumes are approximately 15 percent lower due to shrinkage. The production rates and volumes 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.

SOURCE Paramount Resources Ltd.

For further information: Paramount Resources Ltd., J.H.T. (Jim) Riddell, President and Chief Executive Officer, B.K. (Bernie) Lee, Executive Vice President, Finance and Chief Financial Officer; Rodrigo Sousa, Vice President, Corporate Development, www.paramountres.com, Phone: (403) 290-3600

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