Paramount Resources Ltd. Reports First Quarter 2018 Results

CALGARY, May 9, 2018 /CNW/ -

OIL AND GAS OPERATIONS

  • Paramount's sales volumes averaged 92,203 Boe/d in the first quarter of 2018 compared to 16,163 Boe/d in the first quarter of 2017. Third-party outages, due to unscheduled downtime and extremely cold weather conditions, impacted production by approximately 6,000 Boe/d in the quarter.

  • Montney wells at Karr are maintaining higher condensate rates for longer periods after initial start-up. To maximize cash flows, the Company is prioritizing condensate production and fully utilizing liquids handling capacity, which resulted in natural gas production at Karr being curtailed by approximately 2,400 Boe/d in the first quarter of 2018.

  • Liquids sales volumes increased to 33,689 Bbl/d in the first quarter of 2018 compared to 7,603 Bbl/d in the first quarter of 2017. Liquids revenue was $183.9 million, 68 percent of total revenue.

  • Adjusted funds flow was $97.6 million in the first quarter of 2018 compared to $28.0 million in the first quarter of 2017.

  • In the Grande Prairie Region, activities focused on Paramount's Montney developments, with drilling operations carried out at two five-well pads at Karr and an eleven-well pad at Wapiti.

  • In the Kaybob Region, development activities focused on drilling operations for a four-well Smoky Duvernay pad, a five-well South Duvernay pad and six Montney Oil wells drilled on two pads.

  • In the Central Alberta and Other Region, a new Duvernay well was drilled at Willesden Green.

  • Exploration and development capital for the first quarter of 2018 totaled $131.6 million, primarily related to drilling and completion programs and facilities projects in the Grande Prairie and Kaybob Regions.

  • First quarter 2018 capital spending included $42.1 million related to 2019 projects at Wapiti and Karr. The Wapiti growth play will add material production and cash flows in mid-2019.

  • As a result of liquids handling constraints at Karr, delays in the anticipated startup of new Kaybob wells, the deferral of new production at the non-operated Birch property and unplanned third-party outages in the first quarter, the Company expects sales volumes to average approximately 92,500 Boe/d (37 percent liquids) in 2018.

  • Sales volumes are anticipated to be three to five percent lower in the second and third quarters of 2018 compared to the first quarter, primarily due to processing facility outages. Sales volumes will increase in the fourth quarter as facility constraints are alleviated and new wells are brought on production.
  • The Company's 2018 capital budget remains unchanged at $600 million.

CORPORATE

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

  • In December 2017, Paramount implemented a normal course issuer bid. To date, the Company has purchased and cancelled 1,454,100 common shares under the program at a total cost of $27.4 million.

  • The Company has commenced a disposition process for its fee simple and royalty lands in southern Alberta and expects the disposition to be completed in the third quarter of 2018. The Company continues to pursue other non-core dispositions.

REVIEW OF OPERATIONS

Paramount's sales volumes averaged 92,203 Boe/d in the first quarter of 2018 compared to 16,163 Boe/d in the first quarter of 2017, with liquids volumes increasing to 33,689 Bbl/d compared to 7,603 Bbl/d in the same period in 2017. Production in the quarter was impacted by liquids production management at Karr and production disruptions due to third-party outages resulting from unscheduled downtime and extremely cold weather conditions.

Paramount's netback was $134.5 million in the first quarter of 2018, over four times the first quarter 2017 netback of $31.7 million. Adjusted funds flow was $97.6 million compared to $28.0 million in the same quarter in 2017.

The Company's cost structure is comparable to other liquids-focused producers in western Canada. As a liquids-focused producer, Paramount's operating costs include liquids handling expenses that are not applicable to dry natural gas production. Operating costs were $11.12 per Boe in the first quarter due to maintenance work and lower sales volumes. 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 for the first quarter of 2018 totaled $131.6 million, primarily related to the 2018 drilling and completion programs and facilities projects in the Grande Prairie and Kaybob Regions. Approximately $42.1 million or 32 percent of first quarter capital spending was related to projects at Wapiti and Karr that will add new production in 2019.

GRANDE PRAIRIE REGION

Sales volumes in the Grande Prairie Region in the first quarter of 2018 averaged 28,398 Boe/d, 51 percent of which were liquids. In addition to a 2,400 Boe/d curtailment of natural gas volumes at Karr to maximize condensate production, unplanned third-party facility and pipeline outages reduced Grande Prairie Region sales volumes by approximately 2,000 Boe/d in the first quarter.

Exploration and development capital in the Grande Prairie Region was $74.3 million in the first quarter of 2018. Development activities focused on drilling operations at two five-well pads at Karr (the 1-2 and 4-24 pads) and an eleven-well pad at Wapiti (the 9-3 pad). First quarter capital expenditures include approximately $11 million of additional costs as a result of difficulties encountered with a well completion at Karr.

Karr

Condensate to gas ratios, and wellhead condensate rates, from Montney wells at Karr continue to exceed expectations. New wells are maintaining higher condensate rates for longer periods after initial start-up, which resulted in higher than expected per-well condensate production in the first quarter of 2018. To maximize cash flows, the Company is prioritizing condensate production at the Company's 6-18 dehydration and compression facility (the ʺ6-18 Facilityʺ), fully utilizing liquids handling capacity and managing natural gas production by applying a low drawdown (choke management) to the wellhead. This resulted in the curtailment of approximately 2,400 Boe/d of natural gas production in the first quarter of 2018.

Wells from the 2016/2017 capital program are being produced at restricted rates and in some cases shut-in as the Company pursues a number of liquids handling debottlenecking initiatives. Production volumes from the existing production base and the new 1-2 pad, which is scheduled to be brought on production in the third quarter, are expected to continue to fully utilize Karr area liquids handling capacity for the remainder of the year. As a result, the Company is deferring the completion and startup of the five wells on the new 4-24 pad until 2019.

Paramount is adding liquids handling expansion projects to the 2018 Karr capital program to debottleneck liquids processes at the 6-18 Facility and add incremental liquids gathering capacity. This will allow additional liquids volumes to be delivered to the downstream third-party facility (the ʺSimonette Facilityʺ) that processes Company production volumes. The Company is also installing additional liquids loading equipment at the 6-18 Facility and at pad sites upstream to increase trucking capacity. These projects are expected to be completed by the end of 2018 at a cost of approximately $10 million.

The Company has also added a water disposal well and related facilities to the 2018 Karr capital program, at a cost of approximately $9 million. This project will provide operating cost savings by reducing water trucking and disposal costs.

The expansion of the 6-18 Facility from 80 MMcf/d to 100 MMcf/d is proceeding on schedule. The compression and dehydration equipment for the expansion has been installed and the expansion will be tied in and commissioned as the liquids handling debottlenecking projects are completed and the incremental natural gas capacity is required. This incremental natural gas capacity, together with the Company's liquids handling enhancements, will enable the Company to further increase overall production in 2019.

Production at Karr was shut-in for approximately three days at the beginning of May 2018 for the tie-in of a condensate stabilizer expansion at the Simonette Facility.   

To support growth at Karr, the Company has sanctioned the construction of a Company-owned processing facility to be built alongside the current 6-18 dehydration and compression facility. The project will add 50 MMcf/d of natural gas processing capacity and 30,000 Bbl/d of condensate stabilization capacity. This new processing facility is scheduled to be commissioned in the second half of 2020.

Sales volumes and netbacks at Karr are summarized as follows:

Karr



Q1 2018

Q1 2017

Change %

Sales volumes






Natural gas (MMcf/d)


63.1

23.9

164


Condensate and oil (Bbl/d)


11,399

5,231

118


Other NGLs (Bbl/d)


1,192

428

179


Total (Boe/d)


23,105

9,642

140


% liquids


54%

59%


Netback


$/Boe

($ millions)

$/Boe

($ millions)

Change %

($ millions)


Petroleum and natural gas sales


43.97

91.4

44.19

38.3

139


Royalties


(1.27)

(2.6)

(1.45)

(1.3)

100


Operating expense


(8.19)

(17.0)

(8.55)

(7.4)

130


Transportation and NGLs processing


(4.17)

(8.7)

(4.44)

(3.8)

129



30.34

63.1

29.75

25.8

145

 

Karr area production currently represents approximately 25 percent of Paramount's production. The Company's cash flows benefit from the liquids-rich product mix at Karr, which generates higher per-unit revenues. Per-unit operating costs at Karr are also lower due to production being focused at multi-well pads, which are more efficient to produce. As Paramount continues to grow production at Karr and bring on its new Montney development at Wapiti, these liquids-focused areas will contribute a higher proportion of the Company's sales volumes and cash flows.   

The table below summarizes the performance from 27 Montney wells from the Company's 2016/2017 development program:

Well


Peak 30-Day
Total (1)

Peak 30-Day
Condensate (1)

Peak 30-Day
Condensate

Days on
Production

Cumulative
Production (2)



(Boe/d)

(Bbl/d)

(%)


(MBoe)

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


2,555

1,815

71%

443

565

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


2,847

2,176

76%

413

658

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


2,637

1,795

68%

400

493

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


2,163

1,401

65%

330

508

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


2,127

1,263

59%

310

532

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


2,221

1,533

69%

290

336

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


1,955

946

48%

267

307

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


1,820

900

49%

268

377

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


1,345

694

52%

267

267

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


2,053

1,414

69%

265

381

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


1,845

942

51%

264

425

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


2,627

1,341

51%

248

476

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


1,356

710

52%

243

277

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


2,143

994

46%

257

371

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


1,918

805

42%

255

347

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


1,771

1,042

59%

235

270

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


2,230

1,350

61%

203

346

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


1,860

1,176

63%

180

286

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


1,715

1,060

62%

177

227

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


1,921

1,235

64%

133

226

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


1,796

1,218

68%

130

213

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


1,913

1,146

60%

127

205

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


1,507

890

59%

123

159

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


1,818

1,013

56%

116

197

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


1,610

1,007

63%

78

115

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


1,838

1,076

59%

77

123

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


1,521

1,044

69%

49

66

Average


1,963

1,185

60%

228


(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 due to facility and gathering system constraints.

(2)

Cumulative production for an individual well measured at the wellhead to April 30, 2018. Excludes days when the well did not produce. Natural gas sales volumes are approximately 10 percent lower and stabilized condensate sales volumes are approximately 15 percent lower due to shrinkage.

 

Wapiti

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

Drilling operations for the 2018 capital program commenced in January with 11 (11.0 net) of the planned 23 (23.0 net) Montney wells spud. These 11 wells are located on the 9-3 pad and are being drilled with two Fox Drilling rigs working simultaneously. The 9-3 pad is scheduled to be completed and brought on production through a new 150 MMcf/d third-party processing facility, which the operator plans to commission in mid-2019. These new Wapiti Montney wells are similar in design to the recent Karr development wells and are expected to have similar production profiles.

KAYBOB REGION

Sales volumes in the Kaybob Region in the first quarter of 2018 averaged 41,843 Boe/d, including 12,650 Bbl/d of liquids. Production disruptions as a result of unplanned third-party pipeline and facility outages and freeze offs due to extremely cold weather conditions reduced first quarter sales volumes by approximately 3,500 Boe/d. Exploration and development capital in the Kaybob Region was $50.0 million in the first quarter of 2018.

In April 2018, approximately 4,000 Boe/d of Kaybob area production was shut-in as a result of a scheduled four-week turnaround at a third-party facility that processes the Company's production. The downstream facility is expected to be back in service in mid-May and the Company will restart affected wells.

Kaybob Smoky Duvernay

The Company is drilling a four (4.0 net) well pad at Kaybob Smoky Duvernay in 2018. The first well on the pad was spud in late November 2017 and all four wells were rig released by the end of April 2018. Wells on this pad are scheduled to be completed in the summer and brought on production through the Paramount operated Kaybob Smoky natural gas plant. The expansion of the Kaybob Smoky plant is in progress with start-up anticipated in the third quarter of 2018. 

Kaybob South Duvernay

The Company's 2018 capital plan at the Kaybob South Duvernay development includes 11 (5.6 net) wells on two multi-well pads. Five of the wells are scheduled to be completed in 2018, with the remaining wells to be completed in 2019. The first five-well pad was spud in November 2017, with all five wells being rig released in the first quarter of 2018. This pad is scheduled to be brought on production in the third quarter of 2018, through a third-party operated natural gas plant.

Kaybob Montney Oil

First quarter 2018 sales volumes at the Kaybob Montney Oil property were 8,965 Boe/d, approximately 62 percent liquids. Six wells in the Company's 2018 capital program have been completed and brought on production to date. Drilling and completion activities are continuing and additional wells from the program will be brought on production throughout the year.

The total cost to drill, complete and tie-in certain Kaybob Montney Oil wells has increased compared to the original budget. As a consequence, the Company has removed four wells from the 21-well 2018 capital program. 

CENTRAL ALBERTA AND OTHER REGION

Sales volumes in the Central Alberta and Other Region in the first quarter of 2018 averaged 21,962 Boe/d. Third-party outages and cold weather reduced sales volumes in the Region by approximately 500 Boe/d. The operator of the Birch property in northeast British Columbia has delayed the startup of new production until 2019, which is expected to impact Paramount's 2018 average sales volumes by approximately 1,100 Boe/d. 

Total capital expenditures in the Central Alberta and Other Region were $7.3 million in the first quarter of 2018. Development activities focused on a Duvernay well at Willesden Green. The well was rig released in April 2018 and is scheduled to be completed and brought on production in the third quarter.  

As the Company achieved its land tenure objective with the initial well in the program, Paramount has removed a second well planned for Willesden Green in 2018. The Company is reallocating capital to optimization projects that are expected to recover incremental reserves from existing wells.  

The Company has commenced a disposition process for its fee simple and royalty lands in southern Alberta and expects the disposition to be completed in the third quarter of 2018. There is minimal production associated with these lands. The Company continues to pursue other non-core dispositions.

OUTLOOK

As a result of: (i) prioritizing condensate production and delays in starting up new production at Karr due to liquids handling constraints, (ii) delays in the anticipated startup of new Kaybob wells, (iii) the deferral of approximately 1,100 Boe/d of new production at the non-operated Birch property and (iv) approximately 6,000 Boe/d (1,500 Boe/d annualized) of unplanned third-party outages in the first quarter, the Company expects sales volumes to average approximately 92,500 Boe/d (37 percent liquids) in 2018.

Paramount's sales volumes are anticipated to be three to five percent lower in the second and third quarters of 2018 compared to the first quarter of 2018. The Company's production in the second quarter is being impacted by third-party outages at Kaybob and Karr. In the third quarter, a scheduled turnaround will also impact production at Karr, and the Company is completing a turnaround at its 8-9 natural gas processing facility in Kaybob, which will curtail production and delay the startup of new Duvernay wells.  Sales volumes will increase in the fourth quarter as facility constraints are alleviated and new wells from the 2018 capital program are brought on production.

The Company continues to monitor natural gas prices and may shut-in properties on a short-term basis through the summer months.  

As a result of a large proportion of the Company's operating costs being fixed, the revision to forecast sales volumes is expected to result in average operating costs of approximately $11.00 per Boe in 2018. 

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

OPERATING AND FINANCIAL RESULTS (1)






($ millions, except as noted)







Q1 2018

Q1 2017

% Change

Sales volumes (Boe/d)







Grande Prairie


28,398


14,408

97


Kaybob


41,843


218

NM


Central Alberta and Other


21,962


1,537

NM

Total


92,203


16,163

470

Netback

$/Boe (3)


$/Boe (3)


% Change
$/Boe


Natural gas revenue

2.59

81.9

3.55

16.4

(27)


Condensate and oil revenue

70.10

160.2

61.75

35.3

14


Other NGLs revenue (2)

31.68

23.7

23.69

2.7

34


Royalty and sulphur revenue

4.0

0.3

Petroleum and natural gas sales

32.51

269.8

37.61

54.7

(14)


Royalties

(1.93)

(16.0)

(1.39)

(2.0)

39


Operating expense

(11.12)

(92.3)

(10.22)

(14.9)

9


Transportation and NGLs processing (4)

(3.26)

(27.0)

(4.22)

(6.1)

(23)

Netback

16.20

134.5

21.78

31.7

(26)







Exploration and development capital (5)







Grande Prairie


74.3


131.5

(43)


Kaybob


50.0


100


Central Alberta and Other


7.3


14.3

(49)

Total


131.6


145.8

(10)







Net income (loss)


(81.1)


20.7

     NM


per share – diluted ($/share)


(0.61)


0.19








Adjusted funds flow


97.6


28.0

249


per share – diluted ($/share)


0.73


0.26








Total assets


4,978.0


2,010.3

148







Net debt (cash)


705.7


(442.6)

     NM







Common shares outstanding (thousands)


133,662


106,142

26







(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 include 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 incurred by the Company.

(5)

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

NM

Not meaningful

 

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 first 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/paramount0509.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;
  • forecast capital expenditures and operating costs;
  • exploration, development, and associated operational plans and strategies;
  • projected timelines for, and the estimated costs of, constructing and starting up new and expanded processing facilities; 
  • the projected availability of third party processing facilities; 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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 three months ended March 31, 2018, the value ratio between crude oil and natural gas was approximately 40:1. 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" includes ethane, propane and butane.

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; www.paramountres.com, Phone: (403) 290-3600

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