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Paramount Resources Ltd. Reports 2018 Annual Results and Provides 2019 Guidance

CALGARY , March 7, 2019 /CNW/ -

Paramount Resources Ltd. Reports 2018 Annual Results and Provides 2019 Guidance (CNW Group/Paramount Resources Ltd.)

OIL AND GAS OPERATIONS


  • Annual sales volumes averaged 85,941 Boe/d (37 percent liquids) in 2018, an increase of 91 percent compared to average sales volumes of 44,970 Boe/d (40 percent liquids) in 2017. Fourth quarter 2018 sales volumes averaged 84,495 Boe/d (38 percent liquids).

  • Adjusted funds flow in 2018 was $263.9 million or $2.00 per share. Liquids revenue was $682.6 million or 71 percent of total revenue.

  • Capital spending in 2018, excluding land acquisitions, totalled $569.0 million compared to Paramount's capital guidance of $600 million . Fourth quarter spending totalled $126.3 million . Cash proceeds from non-core asset sales in 2018 totalled $182.4 million .

  • At Karr, 5 (5.0 net) new Montney wells on the 1-2 pad were brought on production in the third quarter of 2018. These wells averaged 1,869 Boe/d of peak 30-day wellhead production per well, with an average condensate to gas ratio (ʺCGRʺ) of 264 Bbl/MMcf.(1)

  • Facilities enhancements and trucking facility expansions were completed at Karr, increasing raw liquids handling capacity to approximately 15,000 Bbl/d. Fourth quarter sales volumes at Karr averaged 26,282 Boe/d (53 percent liquids).

  • At Wapiti, 11 (11.0 net) wells on the 9-3 pad have been drilled and completed, and are awaiting the start-up of a new third-party processing facility, scheduled to be onstream in mid-2019.

  • Paramount's natural gas diversification strategy includes approximately 122,000 GJ/d of sales under long-term contracts priced at the Dawn, US Midwest and Malin markets. The Company's average realized natural gas sales price for the fourth quarter of 2018 was $2.73 /Mcf compared to average AECO prices of $1.64 /GJ.

  • Paramount has 14,000 Bbl/d of liquids hedged for fiscal 2019 at an average price of C$77.05 /Bbl.

  • In the fourth quarter of 2018, Paramount expanded its covenant-based revolving bank credit facility from $1.2 billion to $1.5 billion and extended the maturity date to November 2022 . At December 31, 2018 , $815.0 million was drawn on the facility.

  • Paramount shut-in the dry-gas Hawkeye field in central Alberta and has decided to cease production operations in the Zama field in northern Alberta . Total sales volumes for these fields averaged approximately 1,500 Boe/d. Paramount is moving forward with area-based closure programs for both of these fields.

_______________________________



(1)

Production 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. 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.

 

2019 GUIDANCE

  • Paramount is focused on maintaining capital discipline and is prioritizing lower-risk, liquids-rich Montney resource plays that generate immediate cash flows. Discretionary spending on longer-term projects is being limited in order to preserve financial flexibility and balance sheet strength.

  • Paramount's 2019 annual sales volumes are expected to average between 81,000 Boe/d and 85,000 Boe/d.

  • The Company's base capital budget for 2019 is $350 million , excluding land acquisitions and abandonment and reclamation activities. The 2019 program is largely focused on growing Montney production at Wapiti and Karr, increasing liquids sales and per-unit netbacks.

  • Capital expenditures required in 2019 to advance the further expansion of the Karr 6-18 facility for a 2020 startup are estimated at $145 million and are not included in the $350 million base capital budget. Spending on the expansion is heavily weighted to the second half of the year, providing the Company flexibility to evaluate funding alternatives.

  • The Company's 2019 capital plan remains flexible and may be adjusted depending on commodity prices and other factors.

  • The Company has budgeted $32 million for abandonment and reclamation activities in 2019, including those at Hawkeye and Zama .


RESERVES

  • Paramount's proved plus probable reserves (ʺP+Pʺ) increased seven percent to 634 MMBoe in 2018 compared to 594 MMBoe in 2017. Proved reserves increased four percent to 391 MMBoe in 2018 compared to 376 MMBoe in 2017.

  • The Company's reserves replacement ratio was 2.5 times for P+P reserves and 1.7 times for proved reserves.

  • Total developed reserves (P+P) were 178 MMBoe in 2018, with estimated future net revenue of $1.2 billion (discounted at 10 percent, before tax).

  • P+P reserves for the Karr and Wapiti Montney plays in the Grande Prairie Region increased 29 percent to 356 MMBoe in 2018 compared to 277 MMBoe in 2017.

  • P+P finding, development and acquisition costs for the Grande Prairie region were $10.61 per Boe in 2018.

  • Estimated future net revenue at December 31, 2018 totalled $2.1 billion for proved reserves and $4.1 billion for P+P reserves (discounted at 10 percent, before tax).


CORPORATE

  • In early 2019, the Company entered into interest rate swaps to fix interest rates on a portion of its debt; $250 million notional amount for four years and an additional $250 million notional amount for seven years.

  • The Company purchased a total of 4.2 million common shares for cancellation under its 2018 normal course issuer bid program at a total cost of $66.4 million . In January 2019 , Paramount implemented a normal course issuer bid program under which the Company may purchase up to 7.1 million common shares for cancellation.  


OPERATING AND FINANCIAL RESULTS (1)

($ millions, except as noted)


Three months ended December 31

Twelve months ended December 31


2018

2017

2018

2017

Sales volumes (Boe/d)





Grande Prairie

26,976

31,791

26,059

21,480

Kaybob

37,262

41,531

39,004

14,073

Central Alberta and Other

20,257

22,090

20,878

9,417

Total

84,495

95,412

85,941

44,970

% liquids

38%

37%

37%

40%

Netback


    $/Boe (3)






     $/Boe (3)

       $/Boe (3)

      $/Boe (3)

Natural gas revenue

79.2

2.73

69.9

2.11

267.1

2.25

132.8

2.26

Condensate and oil revenue

104.3

45.54

161.2

66.65

599.9

67.81

313.4

61.52

Other NGLs revenue (2)

20.4

31.39

25.4

30.15

82.7

30.67

40.5

26.80

Royalty and sulphur revenue

3.5

2.4

15.8

4.7

Petroleum and natural gas sales

207.4

26.68

258.9

29.49

965.5

30.78

491.4

29.94

Royalties

(8.0)

(1.03)

(16.8)

(1.92)

(69.2)

(2.21)

(24.6)

(1.50)

Operating expense

(103.2)

(13.28)

(86.1)

(9.81)

(381.0)

(12.15)

(165.9)

(10.11)

Transportation and NGLs processing (4)

(24.2)

(3.11)

(24.3)

(2.77)

(93.0)

(2.96)

(51.0)

(3.11)

Netback

72.0

9.26

131.7

14.99

422.3

13.46

249.9

15.22










Exploration and development capital (5)





Grande Prairie

72.0

97.0

301.6

369.6

Kaybob

35.6

39.3

215.7

106.5

Central Alberta and Other

16.3

14.1

40.9

51.5

Total

123.9

150.4

558.2

527.6






Net income (loss) (6)

(170.5)

(103.2)

(367.2)

336.9

per share – diluted ($/share)

(1.31)

(0.76)

(2.78)

2.91






Adjusted funds flow

45.5

110.1

263.9

218.7

per share – diluted ($/share)

0.35

0.82

2.00

1.89






Total assets (6)



4,118.1

4,480.6






Net debt



896.0

636.2






Common shares outstanding (thousands)



130,899

135,059







(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.

(6)

Net income (loss) for the three and twelve months ended December 31, 2017 and total assets as at December 31, 2017 have been restated, refer to the Company's consolidated financial statements.

 

RESERVES (1)(2)


Proved

Proved plus Probable


2018

2017

% Change

2018

2017

% Change

Natural gas (Bcf)

1,366.6

1,398.7

(2)

2,169.2

2,171.3

NGLs (MBbl) (3) 

146,791

119,134

23

238,325

196,883

21

Crude oil (MBbl)

16,130

23,570

(32)

34,550

34,714

 Total (MBoe)

390,688

375,824

4

634,403

593,473

7








Future Net Revenue NPV10 ($ millions)

2,136

2,464

(13)

4,134

4,353

(5)


(1)

Readers are referred to the advisories concerning Oil and Gas Measures and Definitions in the Advisories section of this document.

(2)

Reserves evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") as of December 31, 2018 and December 31, 2017 in accordance with National Instrument 51-101 definitions, standards and procedures. Reserves are gross reserves representing working interest before royalties. Net present values of future net revenue were determined using forecast prices and costs and do not represent fair market value.

(3)

Includes ethane, propane, butane and condensate.


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 2018 annual results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements can be obtained at: http://files.newswire.ca/1509/PRLQ4.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:

  • the timing of the projected start-up of the new third-party processing facility at Wapiti;
  • expected average sales volumes for 2019, including for the first half 2019 and the fourth quarter of 2019;
  • an expected increase in production in the second half of 2019;
  • planned capital expenditures for 2019;
  • estimated capital expenditures required in 2019 for the expansion of the 6-18 facility at Karr;
  • planned abandonment and reclamation expenditures for 2019; and
  • planned exploration, development and production activities, including the anticipated ramp up of production at Wapiti.


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;
  • the application of regulatory requirements respecting abandonment and reclamation; and
  • anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins and the construction, commissioning and start-up of new and expanded facilities, including third-party facilities).


Statements relating to reserves are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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 annual information form for the year ended December 31, 2018 , which is available on SEDAR at www.sedar.com.  The forward-looking information contained in this press release is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Non-GAAP Measures

In this press release, "Adjusted funds flow", "Netback", "Net debt" and "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 year ended December 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 year ended December 31, 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 year ended December 31, 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 and Advisories sections of the Company's Management's Discussion and Analysis for the year ended December 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.

Reserves Data

Reserves data set forth in this press release is based upon an evaluation of the Company's reserves prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") dated March 6, 2019 and effective December 31, 2018 (the "McDaniel Report").  The price forecast used in the McDaniel Report is an average of the January 1, 2019 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2018 price forecast of Sproule Associates Ltd.  The estimates of reserves contained in the McDaniel Report and referenced in this press release are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual reserves may be greater than or less than the estimates contained in the McDaniel Report and referenced in this press release.  There is no assurance that the forecast prices and costs assumptions used in the McDaniel Report will be attained, and variances could be material.  Estimated future net revenue does not represent fair market value.  The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. Readers should refer to the Company's annual information form for the year ended December 31, 2018 , which is available on SEDAR at www.sedar.com, for a complete description of the McDaniel Report and the material assumptions, limitations and risk factors pertaining thereto.

Oil and Gas Measures and Definitions

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

Abbreviations

Liquids


Natural Gas

Bbl

Barrels


GJ

Gigajoules

Bbl/d

Barrels per day


GJ/d

Gigajoules per day

MBbl

Thousands of barrels


Mcf

Thousands of cubic feet

NGLs

Natural gas liquids


MMcf

Millions of cubic feet

Condensate

Pentane and heavier hydrocarbons

MMcf/d

Millions of cubic feet per day




AECO

AECO-C reference price

Oil Equivalent


NYMEX

New York Mercantile Exchange

Boe

Barrels of oil equivalent




MBoe

Thousands of barrels of oil equivalent

MMBoe

Millions of barrels of oil equivalent

Boe/d

Barrels of oil equivalent per day

 

This press release contains disclosures expressed as "Boe", "$/Boe", "MBoe","MMBoe" and "Boe/d".  Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe.  Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the year ended December 31, 2018 , the value ratio between crude oil and natural gas was approximately 47:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.

This press release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this press release. The metrics are "CGR", "reserves replacement ratio" and "finding and development costs". These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.

"CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes.  

"Reserves replacement ratio" is calculated by dividing: (i) the aggregate changes in reserves from the prior year from extensions and discoveries, technical revisions and economic factors, by (ii) the aggregate production during the year.  Reserves replacement ratio is a measure commonly used by management and investors to assess the rate at which reserves depleted by production are being replaced by reserves added through operations.

"Finding, development and acquisition costs" for the Grande Prairie Region were calculated by dividing: (i) the sum of the total exploration and development capital expenditures for the year, inclusive of the net acquisition costs and disposition proceeds, and net changes in estimated future development costs from the prior year (excluding changes in estimated future development costs resulting from the inclusion of maintenance capital not associated with reserves additions due to 2018 amendments to the COGE Handbook), by (ii) the net changes to reserves from the prior year before production, inclusive of changes due to acquisitions and dispositions. Finding, development and acquisition costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects and reserve additions associated with such projects.

SOURCE Paramount Resources Ltd.


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