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Paramount Resources Ltd. Reports 2021 Annual Results and Increased Dividend and 2022 Guidance

·40 min read

CALGARY, AB, March 2, 2022 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to report 2021 annual results that include record adjusted funds flow, continuing capital discipline, increased reserves with strong finding and development costs and recycle ratios and a 47% year-over-year reduction in net debt. Paramount is also pleased to announce that it is increasing its regular monthly dividend from $0.06 per share to $0.08 per share beginning March 2022 and forecasting higher 2022 production and free cash flow.

HIGHLIGHTS

  • Annual sales volumes averaged 82,001 Boe/d (44% liquids) in 2021, in line with guidance. Fourth quarter 2021 sales volumes averaged 85,265 Boe/d (44% liquids).(1)

  • Cash from operating activities was $482.1 million in 2021 and $191.8 million in the fourth quarter. Adjusted funds flow in 2021 was $499.8 million ($3.74 per basic share) and $174.6 million ($1.29 per basic share) in the fourth quarter, representing annual and quarterly records for the Company.(2)

  • 2021 capital expenditures totaled $274.6 million and were predominantly focused on drilling and completion activities at Karr, Wapiti and the Willesden Green Duvernay. Capital expenditures were $15.4 million less than the midpoint of previous guidance, reflecting strong execution and a continued focus on cost control.

  • In 2021, the Company achieved proved plus probable ("P+P") reserves additions of 82.8 MMBoe, P+P finding and development ("F&D") costs of $2.12/Boe and a P+P recycle ratio of 12.6x. Total proved ("TP") reserves additions in 2021 were 72.9 MMBoe, with TP F&D costs of $6.72/Boe and TP recycle ratio of 4.0x.(3)

__________

(1)

In this press release, "liquids" refers to NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane. See the Product Type Information section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, light and medium crude oil and tight oil. See also "Oil and Gas Measures and Definitions" in the Advisories section.

(2)

Adjusted funds flow is a capital management measure used by Paramount. Adjusted funds flow per share is a supplementary financial measure. Refer to the "Specified Financial Measures" section for more information on these measures.

(3)

Readers are referred to the advisories concerning "Reserves Data". Reserves evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") as of December 31, 2021 in accordance with National Instrument 51-101 definitions, standards and procedures. Reserves are gross reserves representing working interest before royalties. F&D costs and recycle ratio are non-GAAP ratios. Refer to the "Specified Financial Measures" section and "Oil and Gas Measures and Definitions" in the Advisories section for more information on these measures.

  • Operating costs averaged $11.37/Boe in 2021, 4% lower than 2020. Karr operating costs averaged $9.57/Boe in 2021.(1)

  • Abandonment and reclamation expenditures totaled $25.4 million in 2021, net of $9.7 million funded under the Alberta Site Rehabilitation Program ("ASRP").

  • Free cash flow was $191.8 million ($1.44 per basic share) in 2021 and $99.0 million ($0.73 per basic share) in the fourth quarter.(2)

  • The Company reduced net debt by $397.4 million year-over-year to $456.7 million at December 31, 2021.(3)

  • Net debt does not account for the $372.1 million carrying value of the Company's investments in securities as at December 31, 2021.

  • The Company implemented a regular monthly dividend of $0.02 per Common Share in July 2021 and tripled it to $0.06 per Common Share in November 2021. The Company is increasing its monthly dividend to $0.08 per Common Share beginning in March 2022.

  • In the first quarter of 2022, the Company completed a highly complementary asset acquisition in the Grande Prairie Region for $24.4 million (the "Grande Prairie Acquisition"), which is expected to contribute approximately 1,000 Boe/d to annual 2022 sales volumes.

RESERVES

  • Paramount's P+P reserves increased 5% to 662 MMBoe in 2021 compared to 632 MMBoe in 2020. TP and proved developed producing ("PDP") reserves increased 9% and 4%, respectively.

  • The Company's reserves replacement ratio was 1.4x for PDP reserves.(4)

__________

(1)

Operating costs on a $/Boe basis is a supplementary financial measure. Refer to the "Specified Financial Measures" section for more information on this measure.

(2)

Free cash flow is a capital management measure used by Paramount. Free cash flow per share is a supplementary financial measure. Refer to the "Specified Financial Measures" section for more information on these measures.

(3)

Net debt and net debt to adjusted funds flow are capital management measures used by Paramount. Refer to the "Specified Financial Measures" section for more information on these measures.

(4)

See "Oil and Gas Measures and Definitions" in the Advisories section of this document for a description of the calculation and use of reserves replacement ratio.

  • Paramount achieved strong F&D costs and recycle ratios in 2021 due to lower drilling, completion, equipping and tie-in costs across its major resource plays and higher netbacks.(1)


F&D ($/Boe)

Recycle Ratio *


Total

Grande Prairie

Total

Grande Prairie

Proved Developed Producing

6.22

6.53

4.3

5.1

Total Proved

6.72

1.99

4.0

16.8

Proved plus Probable

2.12

0.59

12.6

56.2

  • Estimated future net revenue at December 31, 2021, discounted at 10% before tax, totaled $1.4 billion for PDP reserves, $3.6 billion for TP reserves and $6.2 billion for P+P reserves.(2)

2022 GUIDANCE

The Company's planned 2022 capital expenditures remain unchanged at a range of between $500 million and $540 million, with anticipated efficiency gains offsetting certain inflationary pressures. The 2022 capital budget is focused on development and debottlenecking operations at Karr to grow production to 43,000 to 47,000 Boe/d in the second half of 2022, development activities at Wapiti to achieve targeted plateau production of 30,000 Boe/d in 2023 and development activities at Kaybob to advance the Duvernay plays at Kaybob Smoky and Kaybob North. Paramount remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices and other factors.

The Company is increasing its 2022 annual production guidance to average between 91,000 Boe/d and 95,000 Boe/d (46% liquids) to reflect the impact of the Grande Prairie Acquisition. Although production in early 2022 at Wapiti was affected by two unplanned outages totaling 18 days at the third-party operated Wapiti natural gas processing facility, well outperformance is anticipated to offset this unplanned downtime.

  • First half 2022 sales volumes are still expected to average between 81,000 Boe/d and 85,000 Boe/d (44% liquids), taking into account a planned 16-day full field outage at Karr during the second quarter for turnaround activities at third-party midstream facilities.

  • Second half 2022 sales volumes are now expected to average between 101,000 Boe/d and 105,000 Boe/d (47% liquids) as numerous new wells from the Company's capital program are brought onstream.

Paramount is increasing its forecast of 2022 free cash flow from approximately $455 million to approximately $590 million to reflect higher commodity price assumptions and higher forecast production.(3)

__________

(1)

Netback is a non-GAAP financial measure. Refer to the "Specified Financial Measures" section for more information on this measure.

(2)

Net present values of future net revenue were determined using forecast prices and costs and do not represent fair market value.

(3)

The stated free cash flow forecast is based on the following assumptions for 2022: (i) the midpoint of forecast capital spending and production, (ii) $33 million in net abandonment and reclamation costs, (iii) $7 million in geological and geophysical expense, (iv) realized pricing of $61.95/Boe (US$86.30/Bbl WTI, US$4.74/MMBtu NYMEX, $4.25/GJ AECO), (v) royalties of $9.45/Boe, (vi) operating costs of $11.15/Boe, (vii) transportation and processing costs of $3.75/Boe and (viii) a $US/$Cdn exchange rate of $0.788.

As previously disclosed, the Company's free cash flow priorities are (i) the achievement of targeted leverage levels, (ii) shareholder returns and (iii) incremental growth.

  • The Company expects to achieve its net debt target of about $300 million in the third quarter of 2022 based on its 2022 free cash flow forecast.

  • Remaining 2022 free cash flow will be available to:

The Company continues to budget approximately $41 million for abandonment and reclamation activities in 2022. Approximately $8 million is to be funded directly through the ASRP, resulting in approximately $33 million net to Paramount. The majority of these funds will be directed to the Zama area.

PRELIMINARY 2023 BUDGET

Paramount's anticipated 2023 capital expenditure budget, based on preliminary planning and current market conditions, remains unchanged at a range of between $475 million and $525 million.

Paramount expects that a capital program in this range will result in 2023 average sales volumes of between 98,500 Boe/d and 103,500 Boe/d (48% liquids), 1,000 Boe/d higher than previously estimated.

Paramount is updating its estimate of 2023 free cash flow that would be expected from such a capital program from approximately $450 million to approximately $580 million to reflect higher commodity price assumptions and higher estimated production.(1)

FIVE-YEAR OUTLOOK

Paramount is updating its previously provided five-year outlook to reflect recent commodity prices. The Company now anticipates cumulative free cash flow through to the end of 2026 of over $3.3 billion, up from $2.7 billion. The Company continues to anticipate annual capital expenditures of approximately $500 million and a compound annual production growth rate of approximately 5 percent through the period. (2)

INCREASED DIVIDEND

Paramount's Board of Directors has approved an increase in the Company's regular monthly dividend from $0.06 to $0.08 per Common Share. The first increased dividend will be payable on March 31, 2022 to shareholders of record on March 15, 2022. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

__________

(1)

The stated free cash flow estimate is based on the following assumptions for 2023: (i) the midpoint of stated capital spending and production, (ii) $40 million in net abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $54.60/Boe (US$76.96/Bbl WTI, US$3.84/MMBtu NYMEX, $3.39/GJ AECO), (v) royalties of $8.55/Boe, (vi) operating costs of $10.65/Boe, (vii) transportation and processing costs of $3.65/Boe and (viii) a $US/$Cdn exchange rate of $0.787.

(2)

The five-year outlook is based on preliminary planning and current market conditions and is subject to change as conditions evolve. The stated anticipated cumulative free cash flow is based on the following assumptions: (i) the stated annual capital expenditures and compound annual production growth; (ii) approximately $40 million in average annual abandonment and reclamation costs, (iii) approximately $7 million in annual geological and geophysical expenses, (iv) strip commodity prices and foreign exchange rates as at February 16, 2022, and (v) internal management estimates of future royalties, operating costs and transportation and processing costs.

HEDGING

Paramount has hedged approximately 33% of its 2022 forecast production to provide greater free cash flow certainty. The Company's current 2022 hedging position is summarized below:


Type (1)


Q1 2022

Q2 2022

Q3 2022

Q4 2022

Average Price (2)

Oil – WTI Swaps (Sale) (Bbl/d)

Financial


3,500

3,500

3,500

3,500

US$75.79/Bbl

Oil – WTI Swaps (Sale) (Bbl/d)

Financial


9,500

CDN$87.90/Bbl

Oil – WTI Swaps (Sale) (Bbl/d)

Financial


3,500

3,500

3,500

CDN$91.38/Bbl

Oil – WTI Collars (Bbl/d)

Financial


7,000

7,000

7,000

7,000

CDN$82.50/Bbl (Floor)








CDN$100.47/Bbl (Ceiling)

Condensate – Basis (Sale) (Bbl/d)

Physical


2,098

WTI + US$3.13/Bbl

Sweet Crude Oil – Basis (Sale) (Bbl/d)

Physical


5,186

WTI - US$2.15/Bbl

Gas – NYMEX Swaps (Sale) (MMBtu/d)

Financial


40,000

US$4.15/MMBtu

Gas – NYMEX Swaps (Sale) (MMBtu/d)

Financial


30,000

US$4.62/MMBtu

Gas – NYMEX Swaps (Sale) (MMBtu/d)

Financial


30,000

US$4.67/MMBtu

Gas – NYMEX Swaps (Sale) (MMBtu/d)

Financial


3,370

US$4.91/MMBtu

Gas – AECO fixed price (GJ/d)

Physical


40,000

CDN$4.06/GJ

Gas – AECO fixed price (GJ/d)

Physical


80,000

80,000

26,957

CDN$3.78/GJ

Gas – Dawn fixed price (MMBtu/d)

Physical


20,000

20,000

6,739

US$4.03/MMBtu

Fx – CDN/USD Swaps (US$MM/Month)

Financial


$5

$5

$5

$5

1.27 C$ / US$

Fx – CDN/USD Collars (US$MM/Month)

Financial


$5

$5

$5

$3.3

1.25 C$ / US$ (Floor)








1.30 C$ / US$ (Ceiling)


(1) Financial, refers to financial commodity contracts. Physical, refers to fixed-priced and basis physical contracts.
(2) Average price is calculated using a weighted average of notional volumes and prIces.

COMPLETE ANNUAL RESULTS

Paramount's: (i) complete annual results, including a review of operations, the Company's audited consolidated financial statements as at and for the year ended December 31, 2021 (the "Consolidated Financial Statements") and the accompanying management's discussion and analysis (the "MD&A") and (ii) 2021 annual information form, which contains additional important information concerning the Company's reserves, properties and operations, can be obtained on SEDAR at www.sedar.com or on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.

A summary of historical financial and operating results is also available on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.

ANNUAL GENERAL MEETING

Paramount will hold its annual general meeting of shareholders in a virtual-only format on Wednesday, May 4, 2022 at 10:30 a.m. (Calgary time).

FINANCIAL AND OPERATING RESULTS (1)




($ millions, except as noted)

Three months ended December 31

Year ended December 31


2021


2020

2021

2020

Net income (loss)

101.0


311.5


236.9

(22.7)­

per share – basic ($/share)

0.75


2.35


1.77

(0.17)

per share – diluted ($/share)

0.70


2.35


1.67

(0.17)

Cash from operating activities

191.8


53.2


482.1

80.9

per share – basic ($/share)

1.42


0.40


3.61

0.61

per share – diluted ($/share)

1.33


0.40


3.39

0.61

Adjusted funds flow

174.6


67.9


499.8

150.0

per share – basic ($/share)

1.29


0.51


3.74

1.12

per share – diluted ($/share)

1.21


0.51


3.51

1.12

Free cash flow

99.0


0.6


191.8

(113.7)

per share – basic ($/share)

0.73


0.01


1.44

(0.85)

per share – diluted ($/share)

0.69


0.01


1.36

(0.85)

Total assets





3,885.1

3,497.0

Long-term debt





386.3

813.5

Net debt





456.7

854.1

Common shares outstanding (millions) (2)





139.2

132.3








Sales volumes (3)






Natural gas (MMcf/d)

284.8


256.3

275.2

248.7

Condensate and oil (Bbl/d)

32,342


25,752

30,989

22,565

Other NGLs (Bbl/d)

5,462


4,987

5,147

4,325

Total (Boe/d)

85,265


73,460

82,001

68,340

% liquids

44%


42%

44%

39%

Grande Prairie Region (Boe/d)

56,035


37,782

51,869

31,076

Kaybob Region (Boe/d)

21,725


27,056

22,588

28,685

Central Alberta & Other Region (Boe/d)

7,505


8,622

7,544

8,579

Total (Boe/d)

85,265


73,460

82,001

68,340











Netback


$/Boe (4)


$/Boe (4)



$/Boe (4)


$/Boe (4)

Natural gas revenue

124.7

4.76

66.7

2.83


373.3

3.72

204.9

2.25

Condensate and oil revenue

281.1

94.46

123.3

52.03


926.5

81.91

383.8

46.47

Other NGLs revenue

27.4

54.61

9.5

20.61


78.6

41.84

24.7

15.63

Royalty and other revenue

1.1

2.5


4.6

12.6

Petroleum and natural gas sales

434.3

55.37

202.0

29.89


1,383.0

46.21

626.0

25.03

Royalties

(52.5)

(6.69)

(11.7)

(1.73)


(127.0)

(4.24)

(31.3)

(1.25)

Operating expense

(91.0)

(11.61)

(79.8)

(11.80)


(340.4)

(11.37)

(297.1)

(11.88)

Transportation and NGLs processing

(26.1)

(3.33)

(24.6)

(3.63)


(114.5)

(3.83)

(101.3)

(4.05)

Netback

264.7

33.74

85.9

12.73


801.1

26.77

196.3

7.85

Risk management contract settlements

(72.4)

(9.23)

7.9

1.18


(218.3)

(7.29)

37.6

1.50

Netback including risk management contract settlements

192.3

24.51

93.8

13.91


582.8

19.48

233.9

9.35







Capital expenditures






Grande Prairie Region

57.7


64.3

228.6

196.9

Kaybob Region

3.8


1.8

14.5

16.4

Central Alberta & Other Region

2.6


0.8

25.3

4.6

Corporate

1.6


(1.8)

6.2

2.3

Total

65.7


65.1

274.6

220.2







Asset retirement obligations settlements

7.0


0.1

25.4

35.0

(1)

"Adjusted funds flow", "free cash flow" and "net debt" are capital management measures used by Paramount. "Netback" and "netback including risk management contract settlements" are non-GAAP financial measures. Netback and Netback including risk management contract settlements presented on a $/Boe or $/Mcf basis are non-GAAP ratios. Each measure, other than net income, that is presented on a per share, $/Mcf or $/Boe basis is a supplementary financial measure. Refer to the "Specified Financial Measures" section for more information on these measures. Prior period free cash flow results have been reclassified to conform with the current years' presentation.

(2)

Common shares are presented net of shares held in trust under the Company's restricted share unit plan: 2021: 1.5 million; 2020: 1.9 million; 2019: 0.9 million.

(3)

Other NGLs means ethane, propane and butane. Readers are referred to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by specific product type.

(4)

Natural gas revenue presented as $/Mcf.

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, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company's principal properties are located in Alberta and British Columbia. Paramount's Class A common shares are listed on the Toronto Stock Exchange under the symbol "POU".

PRODUCT TYPE INFORMATION

This press release refers to sales volumes of "liquids", "natural gas", "condensate and oil" and "other NGLs". "Liquids" means NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane. Below is a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. Numbers may not add due to rounding.


Annual


Total

Grande Prairie
Region

Kabob

Region

Central Alberta and
Other Region


2021

2020

2021

2020

2021

2020

2021

2020

Shale gas (MMcf/d)

207.9

156.7

138.8

77.2

38.6

43.8

30.5

35.7

Conventional natural gas (MMcf/d)

67.3

92.0

2.2

1.4

58.6

82.1

6.5

8.5

Natural gas (MMcf/d)

275.2

248.7

141.0

78.6

97.2

125.9

37.0

44.2

Condensate (Bbl/d)

28,328

19,334

25,253

15,991

2,295

2,885

781

458

Other NGLs (Bbl/d)

5,147

4,325

3,103

1,964

1,612

1,812

432

549

NGLs (Bbl/d)

33,475

23,659

28,356

17,955

3,907

4,697

1,213

1,007

Tight oil (Bbl/d)

487

462

355

301

131

161

Light and Medium crude oil (Bbl/d)

2,174

2,768

5

14

2,129

2,709

40

46

Crude oil (Bbl/d)

2,661

3,230

5

14

2,484

3,010

171

207

Total (Boe/d)

82,001

68,340

51,869

31,076

22,588

28,685

7,544

8,579


Annual


Karr

Wapiti


2021

2020

2021

2020

Shale gas (MMcf/d)

107.9

55.6

31.0

21.5

Conventional natural gas (MMcf/d)

1.3

0.7

0.6

0.4

Natural gas (MMcf/d)

109.2

56.3

31.6

21.9

NGLs (Bbl/d)

20,188

11,389

8,159

6,550

Total (Boe/d)

38,381

20,777

13,432

10,207


Q4


Total

Grande Prairie
Region

Kabob
Region

Central Alberta and
Other Region


2021

2020

2021

2020

2021

2020

2021

2020

Shale gas (MMcf/d)

220.4

170.7

156.5

92.7

35.6

41.9

28.2

36.1

Conventional natural gas (MMcf/d)

64.4

85.6

2.4

1.6

56.8

76.3

5.3

7.7

Natural gas (MMcf/d)

284.8

256.3

158.9

94.3

92.4

118.2

33.5

43.8

Condensate (Bbl/d)

29,797

22,782

26,272

19,635

2,184

2,631

1,341

515

Other NGLs (Bbl/d)

5,462

4,987

3,276

2,429

1,788

1,953

398

605

NGLs (Bbl/d)

35,259

27,769

29,548

22,064

3,972

4,584

1,739

1,120

Tight oil (Bbl/d)

497

437

355

299

142

138

Light and Medium crude oil (Bbl/d)

2,048

2,533

6

2,000

2,480

42

54

Crude oil (Bbl/d)

2,545

2,970

6

2,355

2,779

184

192

Total (Boe/d)

85,265

73,460

56,035

37,782

21,725

27,056

7,505

8,622


Q4


Karr

Wapiti


2021

2020

2021

2020

Shale gas (MMcf/d)

122.5

69.6

34.1

22.8

Conventional natural gas (MMcf/d)

1.5

0.9

0.6

0.5

Natural gas (MMcf/d)

124.0

70.5

34.7

23.3

NGLs (Bbl/d)

20,970

15,165

8,568

6,875

Total (Boe/d)

41,629

26,914

14,350

10,764

Fourth quarter 2021 sales volumes at Karr averaged 41,629 Boe/d (122.5 MMcf/d of shale gas, 1.5 MMcf/d of conventional natural gas and 20,970 Bbl/d of NGLs), compared to 39,878 Boe/d (113.0 MMcf/d of shale gas, 1.4 MMcf/d of conventional natural gas and 20,805 Bbl/d of NGLs) in the third quarter of 2021. Fourth quarter 2021 sales volumes at Wapiti averaged 14,350 Boe/d (34.1 MMcf/d of shale gas, 0.6 MMcf/d of conventional natural gas and 8,568 Bbl/d of NGLs), compared to 14,651 Boe/d (32.7 MMcf/d of shale gas, 0.6 MMcf/d of conventional natural gas and 9,100 Bbl/d of NGLs) in the third quarter of 2021.

The Company forecasts that 2022 sales volumes will average between 91,000 Boe/d and 95,000 Boe/d (54% shale gas and conventional natural gas combined, 40% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). First half 2022 sales volumes are expected to average between 81,000 Boe/d and 85,000 Boe/d (56% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second half 2022 sales volumes are expected to average between 101,000 Boe/d and 105,000 Boe/d (53% shale gas and conventional natural gas combined, 41% light and medium crude oil, tight oil and condensate combined and 6% other NGLs).

SPECIFIED FINANCIAL MEASURES

Non-GAAP Financial Measures

Netback, netback including risk management contract settlements and F&D capital are non-GAAP financial measures. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.

Netback equals petroleum and natural gas sales (the most directly comparable measure disclosed in the Company's primary financial statements) less royalties, operating expense and transportation and NGLs processing expense. Netback is used by investors and management to compare the performance of the Company's producing assets between periods.

Netback including risk management contract settlements equals netback after including (or deducting) risk management contract settlements received (paid). Netback including risk management contract settlements is used by investors and management to assess the performance of the Company's producing assets after incorporating management's risk management strategies.

Refer to the table under the heading "Financial and Operating Results" in this press release for the calculation of netback and netback including risk management contract settlements for the years ended December 31, 2021 and 2020 and for the three months ended December 31, 2021 and 2020.

F&D capital is a measure used in determining F&D costs and is comprised of capital expenditures (the most directly comparable measure disclosed in the Company's primary financial statements) for the year excluding corporate expenditures plus the change from the prior year in estimated future development capital included in the reserves evaluation prepared by McDaniel. F&D capital is used by management and investors, in calculating F&D costs, to represent the amount of capital invested in oil and gas exploration and development projects to generate reserves additions.

Set out below is the calculation of F&D capital for the years ended December 31, 2021 and 2020. Prior period results have been restated to conform with the current years' presentation to reflect the inclusion of changes in estimated future development capital in the calculation of F&D capital.

($ millions)

Grande Prairie Region (1)

Total Company (1)

Proved Developed Producing

2021

2020

2021

2020

Capital expenditures

229

197

275

221

Corporate expenditures

(6)

(2)

Change in estimated future development capital

(22)

(4)

(11)

54

F&D Capital

207

193

257

273






Total Proved

2021

2020

2021

2020

Capital expenditures

229

197

275

221

Corporate expenditures

(6)

(2)

Change in estimated future development capital

(182)

(736)

221

(962)

F&D Capital

47

(539)

490

(743)






Proved Plus Probable

2021

2020

2021

2020

Capital expenditures

229

197

275

221

Corporate expenditures

(6)

(2)

Change in estimated future development capital

(197)

(1,106)

(93)

(1,196)

F&D Capital

31

(909)

176

(977)






(1) Columns may not add due to rounding.

Non-GAAP Ratios

F&D costs, recycle ratio, netback and netback including risk management contract settlements presented on a $/Boe of $/Mcf basis are non-GAAP ratios as they each have a non-GAAP financial measure as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.

F&D costs are calculated by dividing: (i) F&D capital (a non-GAAP financial measure) for the applicable reserves category; by (ii) the net changes to reserves in such reserves category from the prior year from extensions/improved recovery, technical revisions and economic factors. F&D 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. Readers should refer to the information under the heading "Reserves and Other Oil and Gas Information – Reserves Reconciliation" in the Company's annual information form for the year ended December 31, 2021, which is available on www.sedar.com or at www.paramountres.com, for a description of the net changes to reserves in each reserves category from the prior year. See "Advisories – Oil and Gas Definitions and Measures" for more information about this measure.

Recycle ratio is calculated by dividing the netback (a non-GAAP financial measure) per Boe for the year by the F&D costs for the year. Recycle ratio is used by investors and management to compare the cost of adding reserves to the netback realized from production. See "Advisories – Oil and Gas Definitions and Measures" for more information about this measure.

Set out below, for comparative purposes to the 2021 information included in this press release, are the applicable F&D costs and recycle ratios for 2020. Prior period results have been restated to conform with the current years' presentation to reflect the inclusion of changes in estimated future development capital in the calculation of F&D capital.


F&D ($/Boe)

Recycle Ratio *


Total

Grande Prairie

Total

Grande Prairie

Proved Developed Producing

$7.90

$8.79

1.0x

1.3x

Total Proved

na

na

na

na

Proved plus Probable

na

na

na

na

Netback on a $/Boe of $/Mcf basis is calculated by dividing netback (a non-GAAP financial measure) for the applicable period by the total production during the period in Boe or Mcf. Netback including risk management contract settlements on a $/Boe of $/Mcf basis is calculated by dividing netback including risk management contract settlements for the applicable period by the total production during the period in Boe or Mcf. These measures are used by investors and management to assess netback and netback including risk management contract settlements on a unit of production basis.

Capital Management Measures

Adjusted funds flow, free cash flow, net debt and net debt to adjusted funds flow are capital management measures that Paramount utilizes in managing its capital structure. These measures are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities. Refer to Note 18 – Capital Structure in the Consolidated Financial Statements for: (i) a description of the composition and use of these measures, (ii) reconciliations of adjusted funds flow and free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the years ended December 31, 2021 and 2020 and (iii) a calculation of net debt as at December 31, 2021 and 2020.

The following is a reconciliation of adjusted funds flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three months ended December 31, 2021 and 2020:

Three months ended December 31

2021

2020

Cash from operating activities

191.8

53.2

Change in non-cash working capital

(20.1)

12.5

Geological and geophysical expense

2.9

2.1

Asset retirement obligations settled

7.0

0.1

Closure costs

Provisions

Settlements

(7.0)

Transaction and reorganization costs

Adjusted funds flow

174.6

67.9

The following is a reconciliation of free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three months ended December 31, 2021 and 2020:

Three months ended December 31

2021

2020

Cash from operating activities

191.8

53.2

Change in non-cash working capital

(20.1)

12.5

Geological and geophysical expense

2.9

2.1

Asset retirement obligations settled

7.0

0.1

Closure costs

Provisions

Settlements

(7.0)

Transaction and reorganization costs

Adjusted funds flow

174.6

67.9

Capital expenditures

(65.7)

(65.1)

Geological and geophysical expense

(2.9)

(2.1)

Asset retirement obligation settled

(7.0)

(0.1)

Free cash flow

99.0

0.6

For comparative purposes to the 2021 information included in this press release, net debt to adjusted funds flow as at December 31, 2020 was 5.7x.

Supplementary Financial Measures

This press release contains supplementary financial measures expressed as: (i) cash from operating activities, adjusted funds flow and free cash flow on a per share – basic and per share – diluted basis and (ii) revenue, petroleum and natural gas sales, royalties, operating expenses and transportation and NGLs processing expenses on a $/Bbl, $/Mcf or $/Boe basis.

Cash from operating activities, adjusted funds flow and free cash flow on a per share – basic basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average basic shares outstanding during the period determined under IFRS. Cash from operating activities, adjusted funds flow and free cash flow on a per share – diluted basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average diluted shares outstanding during the period determined under IFRS.

Revenue, petroleum and natural gas sales, royalties, operating expenses and transportation and NGLs processing expenses on a $/Bbl, $/Mcf or $/Boe basis are calculated by dividing the revenue, petroleum and natural gas sales, royalties, operating expenses or transportation and NGLs processing expenses, as applicable, over the referenced period by the aggregate applicable units of production (Bbl, Mcf or Boe) during such period.

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:

  • planned capital expenditures in 2022;

  • forecast sales volumes for 2022 and certain periods therein;

  • the expectation that well outperformance in 2022 will offset the impact of the unplanned outages at the third-party operated Wapiti natural gas processing facility;

  • forecast free cash flow in 2022;

  • the Company's priorities and expectations respecting the allocation of free cash flow;

  • the expectation that the Company will achieve its net debt target of about $300 million in the third quarter of 2022;

  • the expectation that plateau production will be reached at Wapiti in 2023;

  • planned abandonment and reclamation expenditures and activities in 2022;

  • preliminary anticipated capital expenditures in 2023 and the resulting expected 2023 average sales volumes and free cash flow;

  • the Company's five-year outlook for capital spending, annual production growth rate and cumulative free cash flow;

  • planned exploration, development and production activities, including the expected timing of drilling, completing and bringing new wells on production; and

  • the payment of future dividends under the Company's monthly dividend program.

Statements relating to reserves are also deemed to be forward looking information, 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.

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 commodity prices;

  • the impact of the COVID-19 pandemic on the Company;

  • the ability to realize expected cost savings;

  • royalty rates, taxes and capital, operating, general & administrative and other costs;

  • foreign currency exchange rates, interest rates and the rate of inflation;

  • general business, economic and market conditions;

  • the performance of wells and facilities;

  • 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, materials, services and personnel in a timely manner and at an acceptable cost to carry out its activities;

  • the ability of Paramount to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities;

  • the ability of Paramount to market its natural gas and liquids successfully to current and new customers;

  • the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, liquids yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations;

  • the timely receipt of required governmental and regulatory approvals;

  • the receipt of benefits under government programs;

  • the application of regulatory requirements respecting abandonment and reclamation; and

  • anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins, the construction, commissioning and start-up of new and expanded facilities, including third-party facilities, and facility turnarounds and maintenance).

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct. 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 commodity prices;

  • changes in capital spending plans and planned exploration and development activities;

  • the potential for changes to preliminary anticipated 2023 capital expenditures prior to finalization and changes to the resulting expected 2023 average sales volumes and free cash flow;

  • the potential for changes to the Company's five-year outlook for capital spending, annual production growth rate and cumulative free cash flow;

  • changes in foreign currency exchange rates, interest rates and the rate of inflation;

  • the uncertainty of estimates and projections relating to future revenue, free cash flow, production, reserve additions, product yields (including condensate to natural gas ratios), resource recoveries, royalty rates, taxes and costs and expenses;

  • the ability to secure adequate product processing, transportation, fractionation, and storage capacity on acceptable terms;

  • operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts;

  • the ability to obtain equipment, materials, services and personnel in a timely manner and at an acceptable cost;

  • potential disruptions, delays or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities);

  • processing, pipeline, and fractionation infrastructure outages, disruptions and constraints;

  • risks and uncertainties involving the geology of oil and gas deposits;

  • the uncertainty of reserves estimates;

  • general business, economic and market conditions;

  • the ability to generate sufficient cash from operating activities and obtain financing to fund planned exploration, development and operational activities and meet current and future commitments and obligations (including product processing, transportation, fractionation and similar commitments and obligations);

  • changes in, or in the interpretation of, laws, regulations or policies (including environmental laws);

  • the ability to obtain required governmental or regulatory approvals in a timely manner, and to obtain and maintain leases and licenses;

  • the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;

  • uncertainties as to 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, insurance claims, 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.

There are risks that may result in the Company changing, suspending or discontinuing its monthly dividend program, including changes to free cash flow, operating results, capital requirements, financial position, market conditions or corporate strategy and the need to comply with requirements under debt agreements and applicable laws respecting the declaration and payment of dividends. There are no assurances as to the continuing declaration and payment of future dividends under the Company's monthly dividend program or the amount or timing of any such dividends.

The foregoing list of risks is not exhaustive. For more information relating to risks, see the sections titled "Risk Factors" in Paramount's annual information form for the year ended December 31, 2021, 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.

Certain forward-looking information in this press release, including forecast free cash flow in 2022 and future periods, may also constitute a "financial outlook" within the meaning of applicable securities laws. A financial outlook involves statements about Paramount's prospective financial performance or position and is based on and subject to the assumptions and risk factors described above in respect of forward-looking information generally as well as any other specific assumptions and risk factors in relation to such financial outlook noted in this press release. Such assumptions are based on management's assessment of the relevant information currently available and any financial outlook included in this press release is provided for the purpose of helping readers understand Paramount's current expectations and plans for the future. Readers are cautioned that reliance on any financial outlook may not be appropriate for other purposes or in other circumstances and that the risk factors described above or other factors may cause actual results to differ materially from any financial outlook.

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 1, 2022 and effective December 31, 2021 (the "McDaniel Report"). The price forecast used in the McDaniel Report is an average of the January 1, 2022 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2021 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, 2021, which is available on SEDAR at www.sedar.com, for a complete description of the McDaniel Report (including reserves by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil) and the material assumptions, limitations and risk factors pertaining thereto.

Oil and Gas Measures and Definitions

Liquids


Natural Gas

Bbl

Barrels


GJ

Gigajoules

Bbl/d

Barrels per day


GJ/d

Gigajoules per day

MBbl

Thousands of barrels


MMBtu

Millions of British Thermal Units

NGLs

Natural gas liquids


MMBtu/d

Millions of British Thermal Units per day

Condensate

Pentane and heavier hydrocarbons


Mcf

Thousands of cubic feet




MMcf

Millions of cubic feet

Oil Equivalent


MMcf/d

Millions of cubic feet per day

Boe

Barrels of oil equivalent


AECO

AECO-C reference price

MBoe

Thousands of barrels of oil equivalent


WTI

West Texas Intermediate

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, 2021, the value ratio between crude oil and natural gas was approximately 24:1. 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 F&D costs, recycle ratio and reserves replacement ratio. 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.

Refer to the "Specified Financial Measures" section of this press release for a description of the calculation and use of F&D costs and recycle ratio. Reserves replacement ratio is calculated by dividing: (i) the net changes in reserves from the prior year from extensions/improved recovery, 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 exploration and development.

Additional information respecting the Company's oil and gas properties and operations is provided in the Company's annual information form for the year ended December 31, 2021 which is available on SEDAR at www.sedar.com.

SOURCE Paramount Resources Ltd.

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