Market Overview

Paramount Resources Ltd. Reports Third Quarter 2018 Results

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CALGARY, Nov. 8, 2018 /CNW/ -

OIL AND GAS OPERATIONS

  • Sales volumes averaged 80,471 Boe/d in the third quarter of 2018, including 29,831 Bbl/d or 37 percent liquids. Production was impacted by scheduled turnarounds at a third-party facility in Karr and Paramount's 8-9 facility in Kaybob, as well as the Resthaven/Jayar sale. In addition, an extended commissioning period for the Kaybob Smoky 6-16 plant expansion delayed the start-up of 4 (4.0 net) new Duvernay wells until early-November.

  • The Karr 1-2 pad was brought on production in the third quarter. Four of the 5 (5.0 net) new Montney wells have produced for at least 30 days, averaging 1,809 Boe/d of peak 30-day wellhead production per well, with an average condensate to gas ratio (ʺCGRʺ) of 258 Bbl/MMcf. (1)

  • At Karr, the Company has largely completed liquids debottlenecking projects at its 6-18 compression and dehydration facility and new trucking facilities, increasing raw liquids handling capacity to approximately 15,000 Bbl/d. Sales volumes at Karr averaged approximately 26,000 Boe/d for the seven-day period ended November 4, 2018.

  • At Wapiti, completion operations were accelerated to take advantage of cost saving opportunities and all 11 (11.0 net) wells on the 9-3 pad have been fracked. These wells will be produced through a new third-party processing facility, which is scheduled to be commissioned in mid-2019.

  • At South Duvernay, 5 (2.5 net) new wells brought on production in the third quarter at the 7-22 pad averaged 1,453 Boe/d of gross peak 30-day production per well, with an average CGR of 199 Bbl/MMcf.(1)

  • The 5-29 Duvernay well (1.0 net) at Willesden Green was brought on production in the third quarter, averaging 944 Boe/d of peak 30-day wellhead production, 86 percent oil. (1)

  • Annual capital spending for 2018 remains on track at approximately $600 million, excluding land and property acquisitions.

  • Paramount has further diversified its natural gas sales arrangements, bringing the total to approximately 122,000 GJ/d of sales priced at Dawn, US Midwest and Malin markets. The Company continues to evaluate opportunities to access additional North American natural gas markets.

  • Annual sales volumes in 2018 are expected to average between 85,000 Boe/d and 86,000 Boe/d, reflecting lower anticipated fourth quarter sales volumes due to lower production in the Kaybob region, dry gas shut-ins, pipeline outages in northeast British Columbia and weather issues in west central Alberta.

____________________________________

(1)

Production measured at the wellhead. Depending on the property, natural gas sales volumes are between five and fifteen percent lower and liquids sales volumes are between 10 and 30 percent lower due to shrinkage. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.

 

CORPORATE

  • Adjusted funds flow was $58.2 million ($88.3 million before hedging settlements) or $0.44 per share for the third quarter of 2018, and $218.4 million ($285.5 million before hedging settlements) or $1.65 per share for the nine months ended September 30, 2018.

  • Capital expenditures for the nine months ended September 30, 2018 totalled $452.7 million.

  • Paramount realized $181.7 million of cash proceeds from dispositions in the nine months ended September 30, 2018. Paramount continues to pursue non-core property dispositions with a focus on maximizing value.

  • The Company has purchased for cancellation 4.1 million of a maximum 7.5 million common shares under its normal course issuer bid program, at a total cost of $65.8 million.

REVIEW OF OPERATIONS

Paramount's sales volumes averaged 80,471 Boe/d in the third quarter of 2018, including 29,831 Bbl/d or 37 percent liquids. Production was impacted by scheduled turnarounds at a third-party facility in Karr and Paramount's 8-9 natural gas processing facility in Kaybob (the ʺ8-9 Plantʺ), which in total impacted sales volumes by approximately 5,000 Boe/d, as well as the sale of approximately 5,000 Boe/d of production at Resthaven/Jayar in early-July. In addition, an extended commissioning period for the Kaybob Smoky 6-16 processing plant expansion (the ʺ6-16 Plantʺ) delayed the start-up of new Duvernay wells from August to early-November.

Fourth quarter 2018 sales volumes are expected to be lower than previously forecast primarily as a result of lower production in the Kaybob Region. Montney Oil production levels are lower due to bringing on new production later than planned, reducing the number of wells drilled in 2018 in order to redeploy capital to fund additional well completions at Wapiti and increased water handling requirements for certain wells. At Smoky Duvernay, new production was delayed until early-November as a result of unanticipated issues identified while commissioning the 6-16 Plant. At South Duvernay, production levels are being impacted by start-up issues related to new production equipment and unscheduled third-party facility outages.

The Company continues to monitor its natural gas properties and is shutting-in wells on a temporary basis when market prices fall below economic thresholds. In September, Paramount permanently shut-in all production related to the Hawkeye area in the Central Alberta and Other region, which averaged approximately 1.79 MMcfe/d of dry gas (approximately 300 Boe/d) for the nine months ended September 30, 2018.

Paramount's netback was $112.2 million in the third quarter of 2018. As a result of lower sales volumes, operating costs averaged $12.25 per Boe in the third quarter. Operating costs averaged $11.77 per Boe for the nine months ended September 30, 2018.

Exploration and development capital was $131.0 million in the third quarter of 2018 and $434.4 million for the nine months ended September 30, 2018. Year-to-date exploration and development spending included $124.8 million related to growth projects at Wapiti and Karr that will add material liquids-rich production and cash flow in 2019. The Company completed an extensive maintenance program in the third quarter in the Kaybob and Central Alberta and Other regions, including processing facility turnarounds, compressor overhauls and equipment upgrades. Where possible, this work was scheduled to align with facility outages.

GRANDE PRAIRIE REGION

Grande Prairie Region sales volumes averaged 21,446 Boe/d in the third quarter of 2018, primarily liquids-rich production from the Karr development. The impact of the scheduled turnaround at a third-party facility that processes Karr natural gas production was as expected. Exploration and development capital totaled $80.6 million in the third quarter and $228.4 million for the nine months ended September 30, 2018. Development activities in the third quarter focused on starting up the five wells on the 1-2 Karr pad and drilling and completion operations at the 9-3 Wapiti pad.

Karr

Cash flows at Karr benefit from a liquids-rich product mix, which generates higher per-unit revenues, and low per-unit operating costs, resulting in top-tier per unit netbacks. Third quarter sales volumes and netbacks at Karr are summarized below:


Q3 2018

Q3 2017

% Change

Sales volumes




Natural gas (MMcf/d)

57.2

48.7

17

Condensate and oil (Bbl/d)

9,942

9,329

7

Other NGLs (Bbl/d)

1,082

625

73

Total (Boe/d)

20,563

18,074

14

% liquids

54%

55%






Netback

($ millions)

($/Boe)

($ millions)

($/Boe)

% Change in
$ millions

Petroleum and natural gas sales

89.6

47.35

57.3

34.47

56

Royalties

(9.5)

(5.01)

(1.5)

(0.90)

533

Operating expense

(15.9)

(8.38)

(13.6)

(8.17)

17

Transportation and NGLs processing

(6.5)

(3.41)

(5.8)

(3.52)

12


57.7

30.55

36.4

21.88

59

 

Production at Karr has resumed following the two-week third-party facility turnaround in September. The Company has largely completed liquids debottlenecking projects at the 6-18 compression and dehydration facility (the ʺ6-18 Facilityʺ) and new trucking facilities, increasing raw liquids handling capacity. Sales volumes at Karr averaged approximately 26,000 Boe/d for the seven-day period ended November 4, 2018.  

Royalty rates for the Karr development increased in the third quarter of 2018 compared to the same period in 2017 as a number of wells from the 2016/2017 Montney drilling program fully utilized their new well royalty incentives. New wells at Karr will continue to benefit from a five percent initial royalty rate up to the maximum incentive.

Initial results from the five Montney wells on the 1-2 Karr pad have been in line with expectations. The 1-2 Karr pad includes the Company's first high intensity completion of a Lower Montney horizontal well. This well continues to meet expectations and is performing in line with adjacent Middle Montney wells. No well locations have been recognized in the Lower Montney for Paramount's Karr development to date.

The following table summarizes the performance of the 2016/2017 and 2018 Karr wells that have produced for at least 30 days:





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)


2016/2017 Wells








Average - 27 wells

1,971

1,186

252

12,128

6,646

202

354

2018 Wells








00/04-25-065-05W6/0

1,598

975

261

108

63

233

78

02/04-25-065-05W6/0

1,703

951

211

92

50

198

59

00/01-26-065-05W6/0

1,878

1,180

282

110

69

280

64

00/02-26-065-05W6/0

2,058

1,286

278

106

66

275

55



(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 five 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.

(2)

Cumulative is the aggregate production measured at the wellhead to October 31, 2018. Natural gas sales volumes are approximately five 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 wellhead liquids volumes by wellhead natural gas volumes.

 

Wapiti

In August 2018, six of the eleven wells on the Wapiti 9-3 pad were completed. To take advantage of economies of scale and reduced completion fluid handling costs due to warmer weather, the Company accelerated completions for the remaining five wells on the 9-3 pad to October 2018. The completion program for these wells set new pacesetters on several metrics and was completed without any operational or safety issues. The fracks employed a plug and perf design in a zipper fracturing operation, with pumping downtime being minimized between stages by utilizing a surface manifold. This, along with other advances in well designs and program execution, contributed to an average of 14 stages pumped per day (an increase from 11 previously), with a day record of 23 stages pumped (compared to 16 previously), both of which are new records for Paramount. A transfer of new technology from the Karr field has also reduced the duration of mill-out operations with the adoption of dissolvable plugs.

The Company has also commenced drilling operations for 12 (12.0 net) new Montney wells on the 5-3 pad at Wapiti. Wells from the 9-3 pad and the 5-3 pad will be produced through a new 150 MMcf/d third-party processing facility, which the operator plans to commission in mid-2019.

KAYBOB REGION

Kaybob Region sales volumes averaged 37,454 Boe/d in the third quarter of 2018, including 11,632 Bbl/d of liquids. The production impact of the scheduled turnaround at Paramount's 8-9 Plant in Kaybob was larger than expected. Exploration and development capital in the Kaybob Region was $33.6 million in the third quarter of 2018 and $172.5 million for the nine months ended September 30, 2018. 

Kaybob Smoky Duvernay

The 4 (4.0 net) wells on the 10-35 Smoky pad began flowing through permanent facilities in early-November. The 6-16 Plant at Smoky was expanded from 6 MMcf/d to 12 MMcf/d by making use of existing equipment moved to Kaybob from Zama in northern Alberta. This redeployment of existing equipment reduced capital costs and enabled the plant expansion to be fast tracked from 2019, but also resulted in an unanticipated two-month extension of the commissioning and startup period as plant components underwent additional inspections and refurbishment.

Initial results have confirmed the high liquids yield nature of the Smoky Duvernay reservoir. The Company plans to evaluate the performance of these wells for the remainder of 2018 and develop a full field development strategy for the Company's Duvernay lands in this area. 

Kaybob South Duvernay

The Company's 2018 capital program at the Kaybob South Duvernay development includes two multi-well pads. 5 (2.5 net) wells on the 7-22 South Duvernay pad were brought on production in the third quarter. These wells averaged 1,453 Boe/d of gross peak 30-day production per well, with an average CGR of 199 Bbl/MMcf.(1) Drilling operations for 5 (2.5 net) wells on the 2-28 pad commenced in September. These wells are scheduled to be completed and brought on production in mid-2019.  

Paramount is utilizing fiber optic technology to monitor production data from controlled tests in perforation clusters, fluid viscosity, pump rate, fracture sequencing and landing zones on two of the wells on the 7-22 pad. The system was installed prior to fracking the wells and has remained intact for production testing. The information gathered in these tests is being incorporated in future well completions.

Kaybob Montney Oil

Third quarter 2018 sales volumes at the Kaybob Montney Oil property were 7,052 Boe/d, approximately 57 percent liquids. Production levels in the third quarter were significantly impacted by the turnaround at the 8-9 Plant. Montney Oil production is lower than planned due to bringing on new production later than scheduled, reducing the number of wells drilled in 2018 and increased water handling requirements for certain wells. To date, 8 (8.0 net) new wells have been completed and brought on production. Drilling operations for 3 (3.0 net) additional wells were completed in the third quarter and these wells are expected to be on-stream by the end of the year. Two (2.0 net) additional wells are being drilled on the property in the fourth quarter of 2018.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 21,571 Boe/d in the third quarter of 2018.  Exploration and development capital in the Central Alberta and Other Region totaled $16.8 million in the third quarter.  

Development activities in the Central and Other Region are focused at Willesden Green, where the 5-29 Duvernay oil well was completed and brought on production in the third quarter. Pressure test results from the 5-29 well confirm that an over-pressure, high oil deliverability reservoir is present on the majority of the Company's Willesden Green Duvernay acreage. The 5-29 well averaged 944 Boe/d of peak 30-day wellhead production, 86 percent oil.(2)

Over the course of the past year, the Company has expanded its Duvernay land position in the East Shale Basin. Total working interest lands more than doubled to approximately 50,000 acres. Paramount also owns over 10,000 acres of Fee Title lands in the area.

In September, Paramount permanently shut-in all production related to the Hawkeye area, which averaged approximately 1.79 MMcfe/d of dry gas (approximately 300 Boe/d) for the nine months ended September 30, 2018.

_____________________________________

(1)

Production measured at the wellhead. Natural gas sales volumes are approximately nine percent lower and liquids sales volumes are approximately 30 percent lower due to shrinkage. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.

(2)

Production measured at the wellhead. Natural gas sales volumes are approximately 15 percent lower and liquids sales volumes are approximately 20 percent lower due to shrinkage. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.

 

OPERATING AND FINANCIAL RESULTS (1)

($ millions, except as noted)


Three months ended September 30

Nine months ended September 30


2018

2017

2018

2017

Sales volumes (Boe/d)





Grande Prairie

21,446

22,819

25,750

17,985

Kaybob

37,454

13,892

39,592

4,820

Central Alberta and Other

21,571

12,312

21,087

5,166

Total

80,471

49,023

86,429

27,971

% liquids

37%

40%

36%

44%










Netback


$/Boe (3)


$/Boe (3)


$/Boe (3)


$/Boe (3)

Natural gas revenue

53.9

1.93

30.9

1.89

187.9

2.09

62.9

2.44

Condensate and oil revenue

168.0

79.83

74.2

54.30

495.6

75.59

152.2

56.90

Other NGLs revenue (2)

20.6

32.16

9.8

23.05

62.3

30.43

15.2

22.59

Royalty and sulphur revenue

6.0

1.6

12.2

2.3

Petroleum and natural gas sales

248.5

33.57

116.5

25.84

758.0

32.13

232.6

30.46

Royalties

(22.8)

(3.08)

(5.0)

(1.11)

(61.2)

(2.59)

(7.8)

(1.03)

Operating expense

(90.7)

(12.25)

(47.8)

(10.59)

(277.8)

(11.77)

(79.8)

(10.45)

Transportation and NGLs processing (4)

(22.8)

(3.08)

(12.3)

(2.74)

(68.8)

(2.92)

(26.6)

(3.49)

Netback

112.2

15.16

51.4

11.40

350.2

14.85

118.4

15.49










Exploration and development capital (5)





Grande Prairie

80.6

88.0

228.4

330.3

Kaybob

33.6

9.5

172.5

9.5

Central Alberta and Other

16.8

22.5

33.5

37.4

Total

131.0

120.0

434.4

377.2






Net income (loss)

(23.4)

223.5

(239.1)

289.5

per share – diluted ($/share)

(0.18)

1.97

(1.80)

2.65






Adjusted funds flow

58.2

45.3

218.4

108.6

per share – diluted ($/share)

0.44

0.40

1.65

0.99






Total assets



4,912.0

5,020.9






Net debt



797.3

564.3






Common shares outstanding (thousands)



130,994

134,835








(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 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 third 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/PRL_Q3_2018_Results.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 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:

  • expected average sales volumes and forecast annual capital expenditures for 2018;
  • the projected start-up date of the third-party processing facility at Wapiti;
  • the expectation that fourth quarter 2018 sales volumes will be lower than previously forecast;
  • expected material additions to production and cash flow in 2019 from spending related to growth projects at Wapiti and Karr; and
  • planned exploration, development and production activities, included the expected timing of bringing new wells on production.

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;
  • 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, including third-party facilities).

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.  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, 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, 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 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 "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 nine months ended September 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 nine months ended September 30, 2018 for the calculation thereof.  "Net debt" 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 nine months ended September 30, 2018 for the calculation of Net debt. "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 nine months ended September 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

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/d

Gigajoules per day

Bbl/d

Barrels per day


Mcf

Thousands of cubic feet

MBbl

Thousands of barrels


MMcf

Millions of cubic feet

NGLs

Natural gas liquids


MMcf/d

Millions of cubic feet per day

Condensate

Pentane and heavier hydrocarbons

AECO

AECO-C reference price




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 press release 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 nine months ended September 30, 2018, the value ratio between crude oil and natural gas was approximately 55:1. 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.

Wellhead CGRs disclosed in this document were calculated for each well by dividing total raw liquids volumes produced by total raw natural gas volumes produced. Raw volumes as measured at the wellhead.

SOURCE Paramount Resources Ltd.

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