HIGHLIGHTS
- The Company achieved record annual sales volumes of 88,672 Boe/d (45% liquids) in 2022. Fourth quarter sales volumes averaged 97,370 Boe/d (45% liquids), of which 64,434 Boe/d (51% liquids) was produced in the Grande Prairie Region. (1)
- Cash from operating activities was a record $1,050 million ($7.45 per basic share) in 2022 and $307 million ($2.17 per basic share) in the fourth quarter. (2)
- Adjusted funds flow in 2022 was $1,171 million ($8.32 per basic share) and $341 million ($2.40 per basic share) in the fourth quarter, representing annual and quarterly records for the Company. (2)
- Capital expenditures in 2022, which included the pre-ordering of approximately $25 million in materials for future development, totaled $655 million versus the $640 million upper range of prior guidance.
- The Company generated record annual free cash flow in 2022 of $471 million ($3.35 per basic share) compared to prior guidance of $500 million. Fourth quarter free cash flow was $162 million ($1.14 per basic share), also a quarterly record. (2)
- Total proved (“TP”) reserves increased 31% to 445 MMBoe with an NPV10 of approximately $5.8 billion ($41.18 per basic share). Proved plus probable (“P+P”) reserves increased 15% to 759 MMBoe with an NPV10 of approximately $9.1 billion ($64.52 per basic share). (3)
- Three-year average finding and development (“F&D”) costs were $7.72/Boe for TP reserves and $4.24/Boe for P+P reserves. (4)
____________________________________ |
|
(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 and free cash flow are capital management measures used by Paramount. Cash from operating activities per basic share, adjusted funds flow per basic share and free cash flow per basic share are supplementary financial measures. Refer to the “Specified Financial Measures” section for more information on these measures. |
(3) |
All reserves are gross reserves based upon an evaluation prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) dated March 6, 2023 and effective December 31, 2022 (the “McDaniel Report”). “NPV10” refers to the net present value of future net revenue of the applicable reserves, discounted at 10 percent, as estimated in the McDaniel Report. Such value does not represent fair market value. Readers are referred to the advisories concerning “Reserves Data”. |
(4) |
F&D costs are a non-GAAP ratio. Refer to the “Specified Financial Measures” section and “Oil and Gas Measures and Definitions” in the Advisories section for more information on this measure and on the related non-GAAP financial measure of F&D capital. The three-year average F&D costs were calculated by dividing total F&D capital over the period by the aggregate reserves additions in the period. |
- Paramount continued to successfully execute its strategy of accretive acquisitions and divestitures in 2022 and early 2023. The Company more than tripled its Willesden Green Duvernay land position in two acquisitions at a total cost of $98 million and realized compelling value for its Kaybob Smoky and Kaybob South Duvernay properties and a portion of its road infrastructure in dispositions that generated aggregate proceeds of $434 million.
- Paramount continues to deliver on its free cash flow priorities:
- The Company achieved its net debt target of $300 million in October 2022 and then further reduced net debt to $161 million at year end, representing a $296 million year-over-year reduction. (1)
- Paramount more than doubled its regular monthly dividend in 2022 to $0.125 per class A common share (“Common Share”).
- In January 2023, the Company paid a special cash dividend of $1.00 per Common Share and repaid all remaining drawings under its $1.0 billion revolving credit facility. At January 31, 2023, Paramount had a cash balance of approximately $110 million.
- The carrying value of the Company’s investments in securities at December 31, 2022 was $557 million.
2022 RESERVES
- Proved developed producing (“PDP”) reserves increased 28% year-over-year to 160 MMBoe. TP reserves were up 31% to 445 MMBoe. P+P reserves increased 15% to 759 MMBoe.
- In the Grande Prairie Region, where the majority of 2022 development activity occurred, PDP reserves were up 33% year-over-year, TP reserves were up 35% and P+P reserves were up 10%.
- With the significant reserves additions in 2022, the Company’s reserves replacement ratios were 1.9x for PDP reserves, 4.0x for TP reserves and 3.7x for P+P reserves. (2)
- Compared to 2021, the NPV10 of the Company’s:
- PDP reserves increased 75% to $2.5 billion ($17.82 per basic share);
- TP reserves increased 62% to $5.8 billion ($41.18 per basic share); and
- P+P reserves increased 46% to $9.1 billion ($64.52 per basic share).
- 2022 F&D costs were: (3)
- $9.58/Boe for PDP reserves (4.5x recycle ratio);
- $14.11/Boe for TP reserves (3.0x recycle ratio); and
- $14.87/Boe for P+P reserves (2.9x recycle ratio).
- Three-year average F&D costs were: (4)
- $8.13/Boe for PDP reserves (3.4x recycle ratio);
- $7.72/Boe for TP reserves (3.5x recycle ratio); and
- $4.24/Boe for P+P reserves (6.5x recycle ratio).
_________________________________________ |
|
(1) |
Net debt is a capital management measure used by Paramount. Refer to the “Specified Financial Measures” section for more information on this measure. |
(2) |
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. |
(3) |
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 and on the related non-GAAP financial measure of F&D capital. |
(4) |
The three-year average F&D costs were calculated by dividing total F&D capital over the period by the aggregate reserves additions in the period. The associated recycle ratios were calculated by dividing the weighted average netback, a non-GAAP measure, per Boe over the period by the three-year average F&D costs. |
REVISED GUIDANCE
Paramount is reaffirming its 2023 and preliminary 2024 sales volumes guidance, as well as its five-year outlook for sales volumes. Paramount is increasing its 2023 guidance for capital expenditures by $50 million as a result of anticipated inflationary cost pressures. The Company is reaffirming its preliminary 2024 guidance and five-year outlook for capital expenditures. Capital expenditures in 2023 and 2024 are expected to be evenly split between: (i) sustaining and maintenance capital; and (ii) growth. Paramount is revising its free cash flow expectations to reflect lower natural gas prices, updated capital expenditures in 2023 and revised foreign exchange rates and other assumptions.
2023 Guidance |
|
Annual average sales volumes (Boe/d) |
100,000 to 105,000 (46% liquids) |
First half average sales volumes (Boe/d) |
96,000 to 101,000 (45% liquids) |
Second half average sales volumes (Boe/d) |
104,000 to 109,000 (47% liquids) |
Capital expenditures |
$700 to $750 million (~50% to growth) ($650 to $700 million prior guidance) |
Abandonment and reclamation expenditures |
$55 million |
Free cash flow (1) |
$375 million ($630 million prior guidance) |
The Company’s midpoint 2023 sustaining and maintenance capital program and regular monthly dividend would remain fully funded down to an average WTI price of about US$55/Bbl in 2023. The Company’s total midpoint 2023 capital program and regular monthly dividend would remain fully funded down to an average WTI price of about US$71/Bbl in 2023. (2) Paramount remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices, inflationary cost pressures and other factors.
Preliminary 2024 Guidance (3) |
|
Annual average sales volumes (Boe/d) |
110,000 to 120,000 (48% liquids) |
Capital expenditures |
$700 to $800 million (~50% to growth) |
Free cash flow (4) |
$465 million ($620 million prior guidance) |
Five-Year Outlook (5) |
|
2027 annual average sales volumes (Boe/d) |
135,000 to 145,000 |
Annual capital expenditures |
$700 to $800 million |
Midpoint cumulative free cash flow (6) |
$3.1 billion ($3.9 billion previously) |
_______________________________________ |
|
(1) |
Free cash flow is a capital management measure used by Paramount. Refer to “Advisories – Specified Financial Measures” for more information on this measure. The stated free cash flow forecast is based on the following assumptions for 2023: (i) the midpoint of stated capital expenditures and sales volumes, (ii) $55 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $55.20/Boe (US$80.00/Bbl WTI, US$3.50/MMBtu NYMEX, $3.08/GJ AECO), (v) a $US/$CAD exchange rate of $0.755, (vi) royalties of $8.30/Boe, (vii) operating costs of $11.40/Boe and (vii) transportation and processing costs of $3.55/Boe. |
(2) |
Assuming no changes to the other forecast assumptions for 2023. |
(3) |
All 2024 guidance is based on preliminary planning and current market conditions and is subject to change. |
(4) |
The stated free cash flow estimate is based on the following assumptions for 2024: (i) the midpoint of stated capital expenditures and sales volumes, (ii) $40 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $53.50/Boe (US$75.00/Bbl WTI, US$3.50/MMBtu NYMEX, $3.08/GJ AECO), (v) a $US/$CAD exchange rate of $0.755, (vi) royalties of $8.30/Boe, (vii) operating costs of $10.55/Boe and (vii) transportation and processing costs of $3.60/Boe. |
(5) |
The five-year outlook is based on preliminary planning and current market conditions and is subject to change. The five-year outlook is for the period from 2023 through to the end of 2027. |
(6) |
The stated cumulative free cash flow estimate is based on the following assumptions: (i) the stated annual capital expenditures and management assumptions as to annual sales volume growth; (ii) $55 million in abandonment and reclamation costs in 2023 and approximately $40 million annually thereafter, (iii) approximately $7 million in annual geological and geophysical expenses, (iv) 2023 realized pricing of $55.20/Boe (US$80.00/Bbl WTI, US$3.50/MMBtu NYMEX, $3.08/GJ AECO) and thereafter commodity prices of US$75.00/Bbl WTI, US$3.50/MMBtu NYMEX and $3.08/GJ AECO, (v) a $US/$CAD exchange rate of $0.755 and (vi) internal management estimates of future royalties, operating costs, transportation and processing costs and, beginning in 2027, cash taxes. |
MARCH DIVIDEND
Paramount’s Board of Directors has declared a cash dividend of $0.125 per Common Share that will be payable on March 31, 2023 to shareholders of record on March 15, 2023. The dividend will be designated as an “eligible dividend” for Canadian income tax purposes.
HEDGING
The Company’s current commodity and foreign currency exchange contracts are summarized below:
Q1 2023 |
Q2 2023 |
Q3 2023 |
Q4 2023 |
2024 |
Average Price (1) |
||
Oil |
|||||||
Condensate – Basis (Physical Sale) (Bbl/d) |
5,244 |
– |
– |
– |
– |
WTI + US$0.50/Bbl |
|
Sweet Crude Oil – Basis (Physical Sale) (Bbl/d) |
3,146 |
3,112 |
3,078 |
3,078 |
– |
WTI – US$3.73/Bbl |
|
Natural Gas |
|||||||
NYMEX Collars (MMBtu/d) |
20,000 |
– |
– |
– |
– |
US$7.50/MMBtu (Floor) |
|
US$12.13/MMBtu (Ceiling) |
|||||||
AECO Collars (GJ/d) |
20,000 |
– |
– |
– |
– |
CAD$7.25/GJ (Floor) |
|
CAD$9.60/GJ (Ceiling) |
|||||||
Chicago Index Swap (Sale) (MMBtu/d) (2) |
5,000 |
– |
– |
– |
– |
Daily – US$0.09/MMBtu |
|
AECO – Basis (Physical Sale) (MMBtu/d) |
– |
20,000 |
20,000 |
6,739 |
– |
NYMEX – US$0.94/MMBtu |
|
Dawn – Basis (Physical Sale) (MMBtu/d) |
– |
10,000 |
10,000 |
3,370 |
– |
NYMEX – US$0.19/MMBtu |
|
Foreign Currency Exchange |
|||||||
Forward Sales / Swaps (US$MM/Month) |
$60 |
– |
– |
– |
– |
1.3105 CAD$ / US$ |
|
Swaps (US$MM/Month) |
– |
$60 |
– |
– |
– |
1.3293 CAD$ / US$ |
|
Swaps (US$MM/Month) |
– |
– |
$40 |
$40 |
– |
1.3427 CAD$ / US$ |
|
Swaps (US$MM/Month) |
– |
– |
– |
– |
$20 |
1.3425 CAD$ / US$ |
|
(1) |
Average price is calculated on a volume weighted average basis. |
(2) |
“Chicago Index” refers to Chicago Index pricing. These contracts convert price exposure of Chicago monthly index to daily index. |
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, 2022 (the “Consolidated Financial Statements”) and the accompanying management’s discussion and analysis (the “MD&A”); and (ii) 2022 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 on Wednesday, May 3, 2023 at 10:30 a.m. (Calgary time) in the McMurray Room of the Calgary Petroleum Club, located at 319 – 5th Avenue S.W., Calgary Alberta.
FINANCIAL AND OPERATING RESULTS (1)
($ millions, except as noted) |
Three months ended December 31 |
Year ended December 31 |
|||||||||
2022 |
2021 |
2022 |
2021 |
||||||||
Net income |
259.9 |
101.0 |
680.6 |
236.9 |
|||||||
per share – basic ($/share) |
1.83 |
0.75 |
4.83 |
1.77 |
|||||||
per share – diluted ($/share) |
1.76 |
0.70 |
4.63 |
1.67 |
|||||||
Cash from operating activities |
306.9 |
191.8 |
1,049.6 |
482.1 |
|||||||
per share – basic ($/share) |
2.17 |
1.42 |
7.45 |
3.61 |
|||||||
per share – diluted ($/share) |
2.08 |
1.33 |
7.14 |
3.39 |
|||||||
Adjusted funds flow |
340.7 |
174.6 |
1,171.0 |
499.8 |
|||||||
per share – basic ($/share) |
2.40 |
1.29 |
8.32 |
3.74 |
|||||||
per share – diluted ($/share) |
2.31 |
1.21 |
7.97 |
3.51 |
|||||||
Free cash flow |
162.0 |
99.0 |
471.1 |
191.8 |
|||||||
per share – basic ($/share) |
1.14 |
0.73 |
3.35 |
1.44 |
|||||||
per share – diluted ($/share) |
1.10 |
0.69 |
3.20 |
1.36 |
|||||||
Total assets |
4,337.3 |
3,885.1 |
|||||||||
Investments in securities |
557.1 |
372.1 |
|||||||||
Long-term debt |
159.4 |
386.3 |
|||||||||
Net debt |
161.2 |
456.7 |
|||||||||
Common shares outstanding (millions) (2) |
142.0 |
139.2 |
|||||||||
Sales volumes (3) |
|||||||||||
Natural gas (MMcf/d) |
321.9 |
284.8 |
294.7 |
275.2 |
|||||||
Condensate and oil (Bbl/d) |
37,580 |
32,342 |
33,908 |
30,989 |
|||||||
Other NGLs (Bbl/d) |
6,143 |
5,462 |
5,650 |
5,147 |
|||||||
Total (Boe/d) |
97,370 |
85,265 |
88,672 |
82,001 |
|||||||
% liquids |
45 % |
44 % |
45 % |
44 % |
|||||||
Grande Prairie Region (Boe/d) |
64,434 |
56,035 |
58,519 |
51,869 |
|||||||
Kaybob Region (Boe/d) |
24,477 |
21,725 |
22,730 |
22,588 |
|||||||
Central Alberta & Other Region (Boe/d) |
8,459 |
7,505 |
7,423 |
7,544 |
|||||||
Total (Boe/d) |
97,370 |
85,265 |
88,672 |
82,001 |
|||||||
Netback |
$/Boe (4) |
$/Boe (4) |
$/Boe (4) |
$/Boe (4) |
|||||||
Natural gas revenue |
194.2 |
6.56 |
124.7 |
4.76 |
671.1 |
6.24 |
373.3 |
3.72 |
|||
Condensate and oil revenue |
375.1 |
108.50 |
281.1 |
94.46 |
1,448.9 |
117.07 |
926.5 |
81.91 |
|||
Other NGLs revenue |
27.3 |
48.25 |
27.4 |
54.61 |
114.2 |
55.37 |
78.6 |
41.84 |
|||
Royalty and other revenue |
1.1 |
─ |
1.3 |
─ |
18.2 |
─ |
5.2 |
─ |
|||
Petroleum and natural gas sales |
597.7 |
66.72 |
434.5 |
55.40 |
2,252.4 |
69.60 |
1,383.6 |
46.23 |
|||
Royalties |
(84.4) |
(9.43) |
(52.5) |
(6.69) |
(335.3) |
(10.36) |
(127.0) |
(4.24) |
|||
Operating expense |
(119.2) |
(13.31) |
(91.0) |
(11.61) |
(407.1) |
(12.58) |
(340.4) |
(11.37) |
|||
Transportation and NGLs processing |
(27.2) |
(3.03) |
(26.1) |
(3.33) |
(123.7) |
(3.82) |
(114.5) |
(3.83) |
|||
Sales of commodities purchased (5) |
102.7 |
11.47 |
22.1 |
2.82 |
272.0 |
8.41 |
75.5 |
2.52 |
|||
Commodities purchased (5) |
(100.4) |
(11.21) |
(22.3) |
(2.85) |
(267.0) |
(8.25) |
(76.1) |
(2.54) |
|||
Netback |
369.2 |
41.21 |
264.7 |
33.74 |
1,391.3 |
43.00 |
801.1 |
26.77 |
|||
Risk management contract settlements |
(23.0) |
(2.57) |
(72.4) |
(9.23) |
(179.0) |
(5.53) |
(218.3) |
(7.29) |
|||
Netback including risk management |
364.2 |
38.64 |
192.3 |
24.51 |
1,212.3 |
37.47 |
582.8 |
19.48 |
|||
Capital expenditures |
|||||||||||
Grande Prairie Region |
135.8 |
57.7 |
453.3 |
228.6 |
|||||||
Kaybob Region |
11.4 |
3.8 |
131.2 |
14.5 |
|||||||
Central Alberta & Other Region |
1.0 |
2.6 |
2.1 |
25.2 |
|||||||
Fox Drilling and Cavalier Energy |
12.1 |
1.0 |
27.7 |
5.0 |
|||||||
Corporate |
9.3 |
0.6 |
40.7 |
1.3 |
|||||||
Total |
169.6 |
65.7 |
655.0 |
274.6 |
|||||||
Asset retirement obligations settled |
7.0 |
7.0 |
36.1 |
25.4 |
(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 has been reclassified to conform with the current year’s presentation. |
(2) |
Common shares are presented net of shares held in trust under the Company’s restricted share unit plan: 2022: 0.8 million, 2021: 1.5 million |
(3) |
Refer 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. |
(5) |
Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual regions or properties. |
Paramount is an independent, publicly traded, liquids-rich natural gas 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 Common Shares are listed on the Toronto Stock Exchange under the symbol “POU”.
PRODUCT TYPE INFORMATION
This press release includes references to sales volumes of “natural gas”, “condensate and oil”, “NGLs”, “Other NGLs” and “liquids”. “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. “NGLs” refers to condensate and Other NGLs combined. “Other NGLs” refers to ethane, propane and butane. “Liquids” refers to condensate and oil and Other NGLs combined. 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 |
Kaybob Region |
Central Alberta and |
|||||
2022 |
2021 |
2022 |
2021 |
2022 |
2021 |
2022 |
2021 |
|
Shale gas (MMcf/d) |
232.9 |
207.9 |
166.9 |
138.8 |
38.5 |
38.6 |
27.5 |
30.5 |
Conventional natural gas (MMcf/d) |
61.8 |
67.3 |
1.3 |
2.2 |
55.0 |
58.6 |
5.5 |
6.5 |
Natural gas (MMcf/d) |
294.7 |
275.2 |
168.2 |
141.0 |
93.5 |
97.2 |
33.0 |
37.0 |
Condensate (Bbl/d) |
31,228 |
28,328 |
27,095 |
25,253 |
3,192 |
2,295 |
941 |
781 |
Other NGLs (Bbl/d) |
5,650 |
5,147 |
3,394 |
3,103 |
1,620 |
1,612 |
636 |
432 |
NGLs (Bbl/d) |
36,878 |
33,475 |
30,489 |
28,356 |
4,812 |
3,907 |
1,577 |
1,213 |
Tight oil (Bbl/d) |
480 |
487 |
– |
– |
261 |
355 |
219 |
131 |
Light and medium crude oil (Bbl/d) |
2,200 |
2,174 |
4 |
5 |
2,066 |
2,129 |
130 |
40 |
Crude oil (Bbl/d) |
2,680 |
2,661 |
4 |
5 |
2,327 |
2,484 |
349 |
171 |
Total (Boe/d) |
88,672 |
82,001 |
58,519 |
51,869 |
22,730 |
22,588 |
7,423 |
7,544 |
Q4 |
||||||||
Total |
Grande Prairie Region |
Kaybob Region |
Central Alberta and |
|||||
2022 |
2021 |
2022 |
2021 |
2022 |
2021 |
2022 |
2021 |
|
Shale gas (MMcf/d) |
260.0 |
220.4 |
188.4 |
156.5 |
41.9 |
35.6 |
29.7 |
28.2 |
Conventional natural gas (MMcf/d) |
61.9 |
64.4 |
1.5 |
2.4 |
55.0 |
56.8 |
5.4 |
5.3 |
Natural gas (MMcf/d) |
321.9 |
284.8 |
189.9 |
158.9 |
96.9 |
92.4 |
35.1 |
33.5 |
Condensate (Bbl/d) |
34,616 |
29,797 |
29,146 |
26,272 |
4,354 |
2,184 |
1,116 |
1,341 |
Other NGLs (Bbl/d) |
6,143 |
5,462 |
3,631 |
3,276 |
1,671 |
1,788 |
841 |
398 |
NGLs (Bbl/d) |
40,759 |
35,259 |
32,777 |
29,548 |
6,025 |
3,972 |
1,957 |
1,739 |
Tight oil (Bbl/d) |
629 |
497 |
– |
– |
262 |
355 |
367 |
142 |
Light and medium crude oil (Bbl/d) |
2,335 |
2,048 |
– |
6 |
2,045 |
2,000 |
290 |
42 |
Crude oil (Bbl/d) |
2,964 |
2,545 |
– |
6 |
2,307 |
2,355 |
657 |
184 |
Total (Boe/d) |
97,370 |
85,265 |
64,434 |
56,035 |
24,477 |
21,725 |
8,459 |
7,505 |
The Company forecasts that 2023 annual sales volumes will average between 100,000 Boe/d and 105,000 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 2023 sales volumes are expected to average between 96,000 Boe/d and 101,000 Boe/d (55% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 7% other NGLs). Second half 2023 sales volumes are expected to average between 104,000 Boe/d and 109,000 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). The Company’s preliminary 2024 guidance provides for annual sales volumes that will average between 110,000 Boe/d and 120,000 Boe/d (52% shale gas and conventional natural gas combined, 41% light and medium crude oil, tight oil and condensate combined and 7% 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) plus sales of commodities purchased less royalties, operating expense, transportation and NGLs processing expense and commodities purchased. Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual regions or properties. 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 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, 2022 and 2021 and for the three months ended December 31, 2022 and 2021.
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 expenditures related to Fox Drilling and Cavalier Energy and corporate capital expenditures, plus the change from the prior year in estimated future development capital included in the applicable 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, 2022, 2021 and 2020. Columns may not add due to rounding.
($ millions) |
Total Company |
|||
Proved Developed Producing |
2022 |
2021 |
2020 |
3-year Total |
Capital expenditures |
655 |
275 |
221 |
1,151 |
Fox Drilling, Cavalier Energy and corporate |
(69) |
(6) |
(2) |
(77) |
Change in estimated future development capital |
(10) |
(11) |
54 |
34 |
F&D Capital – PDP |
577 |
257 |
273 |
1,107 |
Total Proved |
2022 |
2021 |
2020 |
3-year Total |
Capital expenditures |
655 |
275 |
221 |
1,151 |
Fox Drilling, Cavalier Energy and corporate |
(69) |
(6) |
(2) |
(77) |
Change in estimated future development capital |
1,249 |
221 |
(962) |
509 |
F&D Capital – TP |
1,835 |
490 |
(743) |
1,582 |
Proved Plus Probable |
2022 |
2021 |
2020 |
3-year Total |
Capital expenditures |
655 |
275 |
221 |
1,151 |
Fox Drilling, Cavalier Energy and corporate |
(69) |
(6) |
(2) |
(77) |
Change in estimated future development capital |
1,176 |
(93) |
(1,196) |
(112) |
F&D Capital – P+P |
1,762 |
176 |
(977) |
961 |
Non-GAAP Ratios
F&D costs, recycle ratio and netback and netback including risk management contract settlements presented on a $/Boe or $/Mcf basis are non-GAAP ratios as they each have a non-GAAP financial measure as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company’s primary financial statements or other measures of financial performance calculated in accordance with IFRS.
F&D costs are calculated by dividing: (i) F&D capital (a non-GAAP financial measure) for the applicable reserves category and period; by (ii) the net changes to reserves in such reserves category from the prior period from extensions/improved recovery, technical revisions and economic factors, expressed in Boe. F&D costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects and reserve additions. Readers should refer to the information under the heading “Reserves and Other Oil and Gas Information – Reserves Reconciliation” in the Company’s annual information forms for the years ended December 31, 2022, 2021 and 2020, which are available on www.sedar.com or at www.paramountres.com, for a description of the net changes to reserves in each reserves category from the prior year. See “Advisories – Oil and Gas Definitions and Measures” below for more information about this measure.
Recycle ratio is calculated by dividing the netback (a non-GAAP financial measure) per Boe for the period by the F&D costs for the period. Recycle ratio is used by investors and management to compare the cost of adding reserves to the netback realized from production. See “Advisories – Oil and Gas Definitions and Measures” for more information about this measure.
Set out below are the applicable F&D costs and recycle ratios for 2022, 2021 and 2020.
F&D ($/Boe) |
Recycle Ratio * |
|||||
2022 |
2021 |
2020 |
2022 |
2021 |
2020 |
|
Proved Developed Producing |
$9.58 |
$6.22 |
$7.90 |
4.5x |
4.3x |
1.0x |
Total Proved |
$14.11 |
$6.72 |
na |
3.0x |
4.0x |
na |
Proved plus Probable |
$14.87 |
$2.12 |
na |
2.9x |
12.6x |
na |
Netback on a $/Boe or $/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 or $/Mcf basis is calculated by dividing netback including risk management contract settlements for the applicable period by the total production during the period in Boe or Mcf. These measures are used by investors and management to assess netback and netback including risk management contract settlements on a unit of production basis.
Capital Management Measures
Adjusted funds flow, free cash flow and net debt are capital management measures that Paramount utilizes in managing its capital structure. These measures are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities. Refer to Note 18 – Capital Structure in the Consolidated Financial Statements for: (i) a description of the composition and use of these measures, (ii) reconciliations of adjusted funds flow and free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company’s primary financial statements, for the years ended December 31, 2022 and 2021 and (iii) a calculation of net debt as at December 31, 2022 and 2021.
The following is a reconciliation of adjusted funds flow to cash from operating activities, the most directly comparable measure disclosed in the Company’s primary financial statements, for the three months ended December 31, 2022 and 2021:
Three months ended December 31 ($millions) |
2022 |
2021 |
Cash from operating activities |
306.9 |
191.8 |
Change in non-cash working capital |
48.7 |
(20.1) |
Geological and geophysical expense |
2.1 |
2.9 |
Asset retirement obligations settled |
7.0 |
7.0 |
Closure costs |
– |
– |
Provisions |
(24.0) |
– |
Settlements |
– |
(7.0) |
Transaction and reorganization costs |
– |
– |
Adjusted funds flow |
340.7 |
174.6 |
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, 2022 and 2021:
Three months ended December 31 ($ millions) |
2022 |
2021 |
Cash from operating activities |
306.9 |
191.8 |
Change in non-cash working capital |
48.7 |
(20.1) |
Geological and geophysical expense |
2.1 |
2.9 |
Asset retirement obligations settled |
7.0 |
7.0 |
Closure costs |
– |
– |
Provisions |
(24.0) |
– |
Settlements |
– |
(7.0) |
Transaction and reorganization costs |
– |
– |
Adjusted funds flow |
340.7 |
174.6 |
Capital expenditures |
(169.6) |
(65.7) |
Geological and geophysical expense |
(2.1) |
(2.9) |
Asset retirement obligation settled |
(7.0) |
(7.0) |
Free cash flow |
162.0 |
99.0 |
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, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased 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, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased on a $/Bbl, $/Mcf or $/Boe basis are calculated by dividing the revenue, petroleum and natural gas sales, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased, as applicable, over the referenced period by the aggregate applicable units of production (Bbl, Mcf or Boe) during such period.