Paramount Resources Ltd. Announces Record 2022 Annual Results
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 |
(3) |
All reserves are gross reserves based upon an evaluation prepared by |
(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. |
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|
-
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 inOctober 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. AtJanuary 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 |
(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. |
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REVISED GUIDANCE
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 |
( |
Abandonment and reclamation expenditures |
|
Free cash flow ( 1) |
|
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
Preliminary 2024 Guidance (3 ) |
|
Annual average sales volumes (Boe/d) |
110,000 to 120,000 (48% liquids) |
Capital expenditures |
|
Free cash flow (4 ) |
|
Five-Year Outlook (5 ) |
|
2027 annual average sales volumes (Boe/d) |
135,000 to 145,000 |
Annual capital expenditures |
|
Midpoint cumulative free cash flow (6 ) |
|
_______________________________________ |
|
(1) |
Free cash flow is a capital management measure used by |
(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) |
(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) |
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MARCH DIVIDEND
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 + |
Sweet Crude Oil – Basis (Physical Sale) (Bbl/d) |
|
3,146 |
3,112 |
3,078 |
3,078 |
– |
WTI – |
Natural Gas |
|
|
|
|
|
|
|
NYMEX Collars (MMBtu/d) |
|
20,000 |
– |
– |
– |
– |
|
|
|
|
|
|
|
|
|
AECO Collars (GJ/d) |
|
20,000 |
– |
– |
– |
– |
|
|
|
|
|
|
|
|
|
Chicago Index Swap (Sale) (MMBtu/d) (2) |
|
5,000 |
– |
– |
– |
– |
Daily – |
AECO – Basis (Physical Sale) (MMBtu/d) |
|
– |
20,000 |
20,000 |
6,739 |
– |
NYMEX – |
Dawn – Basis (Physical Sale) (MMBtu/d) |
|
– |
10,000 |
10,000 |
3,370 |
– |
NYMEX – |
Foreign Currency Exchange |
|
|
|
|
|
|
|
Forward Sales / Swaps (US$MM/Month) |
|
|
– |
– |
– |
– |
|
Swaps (US$MM/Month) |
|
– |
|
– |
– |
– |
|
Swaps (US$MM/Month) |
|
– |
– |
|
|
– |
|
Swaps (US$MM/Month) |
|
– |
– |
– |
– |
|
|
|
|
|
|
|
|
|
|
(1) |
Average price is calculated on a volume weighted average basis. |
(2) |
"Chicago Index" refers to Chicago Index pricing. These contracts convert price exposure of |
COMPLETE ANNUAL RESULTS
ANNUAL GENERAL MEETING
FINANCIAL AND OPERATING RESULTS (1)
($ millions, except as noted) |
|
Three months ended |
Year ended |
||||||||
|
|
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 % |
|||||
|
|
64,434 |
|
56,035 |
58,519 |
51,869 |
|||||
|
|
24,477 |
|
21,725 |
22,730 |
22,588 |
|||||
|
|
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 |
|
|
|
|
|
|
|||||
|
|
135.8 |
|
57.7 |
453.3 |
228.6 |
|||||
|
|
11.4 |
|
3.8 |
131.2 |
14.5 |
|||||
|
|
1.0 |
|
2.6 |
2.1 |
25.2 |
|||||
|
|
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 |
(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. |
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 |
Region |
Kaybob Region |
|
||||
|
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 |
Region |
Kaybob Region |
|
||||
|
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
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
($ millions) |
|
|||
Proved Developed Producing |
2022 |
2021 |
2020 |
3-year Total |
Capital expenditures |
655 |
275 |
221 |
1,151 |
|
(69) |
(6) |
(2) |
(77) |
Change in estimated future development capital |
(10) |
(11) |
54 |
34 |
|
577 |
257 |
273 |
1,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
2022 |
2021 |
2020 |
3-year Total |
Capital expenditures |
655 |
275 |
221 |
1,151 |
|
(69) |
(6) |
(2) |
(77) |
Change in estimated future development capital |
1,249 |
221 |
(962) |
509 |
|
1,835 |
490 |
(743) |
1,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Plus Probable |
2022 |
2021 |
2020 |
3-year Total |
Capital expenditures |
655 |
275 |
221 |
1,151 |
|
(69) |
(6) |
(2) |
(77) |
Change in estimated future development capital |
1,176 |
(93) |
(1,196) |
(112) |
|
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 $/Mcf basis are non-GAAP ratios as they each have a non-GAAP financial measure as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.
F&D costs are calculated by dividing: (i) F&D capital (a non-GAAP financial measure) for the applicable reserves category and period; by (ii) the net changes to reserves in such reserves category from the prior period from extensions/improved recovery, technical revisions and economic factors, expressed in Boe. F&D costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects and reserve additions. Readers should refer to the information under the heading "Reserves and Other Oil and Gas Information – Reserves Reconciliation" in the Company's annual information forms for the years ended
Recycle ratio is calculated by dividing the netback (a non-GAAP financial measure) per Boe for the period by the F&D costs for the period. Recycle ratio is used by investors and management to compare the cost of adding reserves to the netback realized from production. See "Advisories – Oil and Gas Definitions and Measures" for more information about this measure.
Set out below are the applicable F&D costs and recycle ratios for 2022, 2021 and 2020.
|
F&D ($/Boe) |
Recycle Ratio * |
||||
|
2022 |
2021 |
2020 |
2022 |
2021 |
2020 |
Proved Developed Producing |
|
|
|
4.5x |
4.3x |
1.0x |
Total Proved |
|
|
na |
3.0x |
4.0x |
na |
Proved plus Probable |
|
|
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
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
Three months ended |
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
Three months ended |
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.
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:
- forecast sales volumes for 2023 and certain periods therein;
- planned capital expenditures in 2023;
- planned abandonment and reclamation expenditures in 2023;
- forecast free cash flow in 2023;
- preliminary 2024 sales volumes, capital expenditure and free cash flow guidance;
- the Company's five-year outlook for 2027 average annual sales volumes, capital expenditures and cumulative free cash flow;
- the expectation that capital expenditures in 2023 and 2024 will be evenly split between sustaining and maintenance capital and growth; 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 Russian invasion of the
Ukraine ; - royalty rates, taxes and capital, operating, general & administrative and other costs;
- foreign currency exchange rates, interest rates and the rate and impacts of inflation;
- general business, economic and market conditions;
- the performance of wells and facilities;
- the availability to
Paramount of the required capital to fund 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 expected and acceptable costs to carry out its activities; - the ability of
Paramount to secure adequate processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities; - the ability of
Paramount to market its production successfully; - the ability of
Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, product 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, the construction, commissioning and start-up of new and expanded facilities, including third-party facilities, and facility turnarounds and maintenance).
Although
- fluctuations in commodity prices;
- changes in capital spending plans and planned exploration and development activities;
- the potential for changes to preliminary 2024 sales volumes, capital expenditure and free cash flow guidance prior to finalization;
- the potential for changes to the Company's five-year outlook for 2027 average annual sales volumes, capital expenditures 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 production, future revenue, free cash flow, reserve additions, product yields (including condensate to natural gas ratios), resource recoveries, royalty rates, taxes and costs and expenses;
- the ability to secure adequate 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 expected and acceptable costs, including the potential effects of inflation and supply chain disruptions;
- 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 to fund, or to otherwise finance, planned exploration, development and operational activities and meet current and future commitments and obligations (including 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 Indigenous 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 by the Company 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 section titled "Risk Factors" in
Certain forward-looking information in this press release, including forecast free cash flow in 2023 and future periods, may also constitute a "financial outlook" within the meaning of applicable securities laws. A financial outlook involves statements about
Reserves Data
Reserves data set forth in this press release is based upon an evaluation of the Company's reserves prepared by
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", "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
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 in the applicable category from technical revisions, economic factors and extensions/improved recovery, 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.
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
SOURCE