Paramount Resources Ltd. Announces First Quarter 2022 Results, Upwardly Revised Guidance, Increased Dividend and Complementary Asset Acquisition
HIGHLIGHTS
- First quarter 2022 sales volumes averaged 82,137 Boe/d (45% liquids), in-line with expectations.(1)
- Sales volumes at Karr averaged 38,611 Boe/d (51% liquids).
- Sales volumes at Wapiti averaged 16,126 Boe/d (59% liquids).
- Cash from operating activities was
$175 million ($1.25 per basic share) in the first quarter. Adjusted funds flow was$238 million ($1.70 per basic share). Free cash flow was$103 million ($0.74 per basic share).(2) - First quarter capital expenditures totaled
$117 million and were predominantly focused on drilling and completion activities at Karr and Wapiti as well as in the Kaybob region. -
Paramount realized cash proceeds of approximately$51 million from the sale of a portion of its investments in securities in the first quarter. - Net debt was reduced by approximately
$96 million quarter-over-quarter to$361 million atMarch 31, 2022 , including drawings under the Company's credit facility of$305 million . Net debt does not account for the$479 million carrying value of the Company's investments in securities as atMarch 31, 2022 . (3) -
Paramount now expects to achieve its net debt target of about$300 million by mid-year, earlier than previously forecast, even after accounting for the$40 million Willesden Green acquisition. - Abandonment and reclamation expenditures in the first quarter totaled
$15 million , net of$5 million in funding under the Alberta Site Rehabilitation Program ("ASRP"). A total of 63 wells were abandoned in the quarter, including 36 under the Company's ongoing area-based closure program atZama . - In late April, the Company acquired
Duvernay lands and production directly offsetting its existing 61,000 net acre position in the Willesden Green area ofAlberta for approximately$40 million in cash prior to adjustments. The acquisition is accretive on all key metrics and more than doublesParamount's land position and internally estimated drilling locations in the area, setting the stage for more efficient future development and potential infrastructure synergies. Current production from the acquisition is approximately 1,300 Boe/d (49% liquids). - In May,
Paramount increased the capacity of its bank credit facility to$1.0 billion and extended the maturity date toMay 3, 2026 . The capacity of the credit facility can be further increased by up to$250 million pursuant to an accordion feature, subject to incremental lender commitments.
_______________________________________________ |
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(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. 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) |
Net debt is a capital management measure used by Paramount. Refer to the "Specified Financial Measures" section for more information on this measure. |
INCREASED DIVIDEND
UPDATED 2022 GUIDANCE AND PRELIMINARY 2023 BUDGET
The Company's planned 2022 capital expenditures have been upwardly revised by
- First half 2022 sales volumes are expected to average between 81,000 Boe/d and 85,000 Boe/d (44% liquids).
- Second half 2022 sales volumes are expected to average between 101,000 Boe/d and 105,000 Boe/d (47% liquids).
The Company is increasing its forecast of 2022 free cash flow from approximately
________________________ |
|
(1) |
The stated free cash flow forecast is based on the following assumptions for 2022: (i) the midpoint of forecast capital spending and production, (ii) |
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The Company's 2022 capital program, targeted net debt reduction and regular monthly dividend would remain fully funded down to an average WTI price of about
The Company expects that a capital program in this range will result in 2023 average sales volumes of 105,000 Boe/d to 110,000 Boe/d (47% liquids), 6,500 Boe/d higher than previous estimates and a 15% increase at midpoint from forecast average 2022 sales volumes.
UPDATED FIVE-YEAR OUTLOOK
The Company is updating its previously provided five-year outlook to reflect revised capital and production expectations and recent commodity prices.
DELIVERING ON FREE CASH FLOW PRIORITIES
- The Company expects to achieve its net debt target of about
$300 million by mid-year 2022. At this level, year-end 2022 net debt to adjusted funds flow would be less than 0.3x.(4) -
Paramount has increased shareholder returns by implementing a regular monthly dividend inJuly 2021 of$0.02 per share and increasing it three times to$0.10 per share beginning inMay 2022 . The Company retains the flexibility to make repurchases of shares under its normal course issuer bid. - The Company has allocated incremental capital to its highest risk-adjusted rate of return organic growth opportunities and to accretive acquisitions, adding to the significant free cash flow and production growth described in the five-year outlook.
_________________________ |
|
(1) |
Assuming no changes to the other free cash flow forecast assumptions for 2022. |
(2) |
The revised free cash flow estimate is based on the following assumptions for 2023: (i) the midpoint of stated capital spending and production, (ii) |
(3) |
The five-year outlook is based on preliminary planning and current market conditions and is subject to change. The stated anticipated cumulative free cash flow is based on the following assumptions: (i) the stated annual capital expenditures and compound annual production growth; (ii) approximately |
(4) |
Assuming 2022 adjusted funds flow in excess of |
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REVIEW OF OPERATIONS
|
Q1 2022 |
Q4 2021 |
% Change |
||
Sales volumes |
|
|
|
||
Natural gas (MMcf/d) |
152.5 |
158.9 |
(4) |
||
Condensate and oil (Bbl/d) |
26,048 |
26,278 |
(1) |
||
Other NGLs (Bbl/d) |
3,267 |
3,276 |
- |
||
Total (Boe/d) |
54,737 |
56,035 |
(2) |
||
% liquids |
54% |
53% |
|
||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
72.1 |
5.25 |
71.5 |
4.89 |
1 |
Condensate and oil revenue |
277.1 |
118.21 |
230.5 |
95.37 |
20 |
Other NGLs revenue |
18.1 |
61.47 |
16.6 |
54.97 |
9 |
Royalty and other revenue (3) |
10.7 |
- |
- |
- |
NM |
Petroleum and natural gas sales |
378.0 |
76.74 |
318.6 |
61.81 |
19 |
Royalties |
(61.4) |
(12.46) |
(39.8) |
(7.74) |
54 |
Operating expense |
(53.7) |
(10.89) |
(54.9) |
(10.64) |
(2) |
Transportation and NGLs processing |
(23.2) |
(4.73) |
(19.0) |
(3.68) |
22 |
|
239.7 |
48.66 |
204.9 |
39.75 |
17 |
(1) |
"Netback" is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the "Specified Financial Measures" section for more information on these measures. |
(2) |
Natural gas revenue presented as $/Mcf. |
(3) |
In the first quarter of 2022, royalty and other revenue includes |
NM means not meaningful. |
|
|
Karr sales volumes and netbacks are summarized below:
|
Q1 2022 |
Q4 2021 |
% Change |
||
Sales volumes |
|
|
|
||
Natural gas (MMcf/d) |
113.3 |
124.0 |
(9) |
||
Condensate and oil (Bbl/d) |
17,246 |
18,521 |
(7) |
||
Other NGLs (Bbl/d) |
2,475 |
2,449 |
1 |
||
Total (Boe/d) |
38,611 |
41,629 |
(7) |
||
% liquids |
51% |
50% |
|
||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
53.1 |
5.21 |
55.2 |
4.84 |
(4) |
Condensate and oil revenue |
182.4 |
117.56 |
161.3 |
94.67 |
13 |
Other NGLs revenue |
14.4 |
64.60 |
13.1 |
58.20 |
10 |
Royalty and other revenue |
0.1 |
- |
- |
- |
NM |
Petroleum and natural gas sales |
250.0 |
71.95 |
229.6 |
59.96 |
9 |
Royalties |
(54.0) |
(15.52) |
(35.7) |
(9.32) |
51 |
Operating expense |
(35.2) |
(10.14) |
(36.0) |
(9.38) |
(2) |
Transportation and NGLs processing |
(16.1) |
(4.65) |
(14.0) |
(3.68) |
15 |
|
144.7 |
41.64 |
143.9 |
37.58 |
1 |
(1) |
"Netback" is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the "Specified Financial Measures" section for more information on these measures. |
(2) |
Natural gas revenue presented as $/Mcf. |
NM means not meaningful. |
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|
First quarter 2022 sales volumes at Karr averaged 38,611 Boe/d (51% liquids) compared to 41,629 Boe/d (50% liquids) in the fourth quarter of 2021. Sales volumes were lower primarily due to natural declines. Several short, unplanned curtailments at third-party operated facilities in the first quarter, all of which have now been resolved, also contributed to the reduction.
The first seven wells at the 16-17 pad came on production ahead of schedule and under budget with preliminary drilling, completion, equipping and tie-in ("DCET") costs averaging
Second quarter activities at Karr include completing the drilling of the remaining five wells at the 16-17 pad. These wells are expected to be brought onstream in the third quarter. Second quarter sales volumes are expected to be impacted by a 16-day full field outage for scheduled turnaround activities at third-party midstream facilities.
In the second half of 2022, the Company plans to drill, complete, tie-in and bring on production the four-well 1-2 North pad and commence drilling the five-well 4-2 South pad. In addition, the Company is accelerating the drilling of the five-well 4-2 North pad into the fourth quarter.
_________________________ |
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(1) |
Production measured at the wellhead. Natural gas sales volumes are lower by approximately 6% and liquids sales volumes are lower by approximately 6% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See "Oil and Gas Measures and Definitions" in the Advisories section. |
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WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
|
Q1 2022 |
Q4 2021 |
% Change |
||
Sales volumes |
|
|
|
||
Natural gas (MMcf/d) |
39.2 |
34.9 |
12 |
||
Condensate and oil (Bbl/d) |
8,802 |
7,757 |
13 |
||
Other NGLs (Bbl/d) |
792 |
827 |
(4) |
||
Total (Boe/d) |
16,126 |
14,406 |
12 |
||
% liquids |
59% |
60% |
|
||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
19.0 |
5.39 |
16.3 |
5.07 |
17 |
Condensate and oil revenue |
94.7 |
119.49 |
69.2 |
97.03 |
37 |
Other NGLs revenue |
3.7 |
51.67 |
3.5 |
45.43 |
6 |
Royalty and other revenue (3) |
10.6 |
- |
- |
- |
NM |
Petroleum and natural gas sales |
128.0 |
88.20 |
89.0 |
67.15 |
44 |
Royalties |
(7.4) |
(5.13) |
(4.1) |
(3.18) |
80 |
Operating expense |
(18.5) |
(12.69) |
(18.9) |
(14.26) |
(2) |
Transportation and NGLs processing |
(7.1) |
(4.92) |
(5.0) |
(3.69) |
42 |
|
95.0 |
65.46 |
61.0 |
46.02 |
56 |
(1) |
"Netback" is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the "Specified Financial Measures" section for more information on these measures. |
(2) |
Natural gas revenue presented as $/Mcf. |
(3) |
In the first quarter of 2022, royalty and other revenue includes |
NM means not meaningful. |
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First quarter 2022 sales volumes at Wapiti averaged 16,126 Boe/d (59% liquids) compared to 14,406 Boe/d (60% liquids) in the fourth quarter of 2021 as a result of new production from the seven-well 9-22 pad that came onstream between late in the fourth quarter of 2021 and the first quarter of 2022. The increase in sales volumes was achieved despite three unplanned outages at the Wapiti Plant that resulted in approximately three weeks of downtime and approximately 5,100 Boe/d of lost production in the quarter.
Royalty and other revenue for the three months ended
Despite operational challenges associated with outages at the Wapiti Plant, initial results from the seven-well 9-22 pad have been encouraging, averaging gross peak 30-day production per well of 1,503 Boe/d (4.0 MMcf/d of shale gas and 840 Bbl/d of NGLs) with an average CGR of 211 Bbl/MMcf.(1)
Drilling operations at the eight-well 8-22 pad that commenced in late 2021 are now complete. The pad is the Company's first where all wells have been configured as monobores. This delivers a cost advantage compared to conventional multiple casing wells due to lower steel requirements and higher pumping efficiencies.
_________________________ |
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(1) |
Production measured at the wellhead. Natural gas sales volumes are lower by approximately 12% and liquids sales volumes are lower by approximately 2% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See "Oil and Gas Measures and Definitions" in the Advisories section. |
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Second quarter sales volumes are anticipated to increase as all eight wells on the 8-22 pad are brought onstream. Additional second quarter activities include the drilling of eight wells at the 6-32 pad, which is forecast to be brought on production in the third quarter, and the commencement of drilling operations at the eight well 16-15 pad, which is forecast to be brought on production in early 2023. The Company also plans to commence the drilling of the eight well 8-15 pad later in the year.
KAYBOB REGION
Development commenced at the Company's two
In addition to the activities at Kaybob Smoky and Kaybob North,
The recently completed acquisition at Willesden Green adds over 90,000 net acres (after deducting near-term expiries) to
_________________________ |
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(1) |
See also "Oil and Gas Measures and Definitions" in the Advisories section for additional information respecting internally estimated drilling locations. |
HEDGING
|
Type (1) |
|
Q2 2022 |
Q3 2022 |
Q4 2022 |
Q1 2023 |
Average Price (2) |
Oil – WTI Swaps (Sale) (Bbl/d) |
Financial |
|
3,500 |
3,500 |
3,500 |
– |
|
Oil – WTI Swaps (Sale) (Bbl/d) |
Financial |
|
3,500 |
3,500 |
3,500 |
– |
|
Oil – WTI Collars (Bbl/d) |
Financial |
|
7,000 |
7,000 |
7,000 |
– |
|
|
|
|
|
|
|
|
|
Sweet Crude Oil – Basis (Sale) (Bbl/d) |
Physical |
|
5,186 |
– |
– |
– |
WTI - |
|
|
|
|
|
|
|
|
Gas – NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
|
30,000 |
– |
– |
– |
|
Gas – NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
|
– |
30,000 |
– |
– |
|
Gas – NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
|
– |
– |
3,370 |
– |
|
Gas – AECO fixed price (GJ/d) |
Physical |
|
80,000 |
80,000 |
26,957 |
– |
|
Gas – Dawn fixed price (MMBtu/d) |
Physical |
|
20,000 |
20,000 |
6,739 |
– |
|
|
|
|
|
|
|
|
|
Fx – CDN/USD Forwards (US$MM/Month) |
Forwards |
|
|
|
|
|
|
Fx – CDN/USD Collars (US$MM/Month) |
Financial |
|
|
|
|
– |
|
|
|
|
|
|
|
|
|
Fx – CDN/USD Swaps (US$MM/Month) |
Financial |
|
|
|
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(1) |
Financial, refers to financial commodity and foreign currency exchange contracts. Physical, refers to fixed-priced and basis physical contracts. Forwards, refers to foreign currency exchange forwards contracts. |
(2) |
Average price is calculated using a weighted average of notional volumes and prices. |
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ANNUAL GENERAL MEETING
ABOUT
A summary of historical financial and operating results is also available on
FINANCIAL AND OPERATING RESULTS (1) |
||||||||
($ millions, except as noted) |
Q1 2022 |
Q4 2021
|
Q1 2021 |
|||||
Net income (loss) |
16.6 |
101.0 |
(82.5) |
|||||
per share – basic ($/share) |
0.12 |
0.75 |
(0.62) |
|||||
per share – diluted ($/share) |
0.11 |
0.70 |
(0.62) |
|||||
Cash from operating activities |
174.9 |
191.8 |
81.3 |
|||||
per share – basic ($/share) |
1.25 |
1.42 |
0.61 |
|||||
per share – diluted ($/share) |
1.20 |
1.33 |
0.61 |
|||||
Adjusted funds flow |
237.8 |
174.6 |
90.9 |
|||||
per share – basic ($/share) |
1.70 |
1.29 |
0.69 |
|||||
per share – diluted ($/share) |
1.63 |
1.21 |
0.69 |
|||||
Free cash flow |
103.4 |
99.0 |
21.6 |
|||||
per share – basic ($/share) |
0.74 |
0.73 |
0.16 |
|||||
per share – diluted ($/share) |
0.71 |
0.69 |
0.16 |
|||||
Total assets |
4,095.5 |
3,885.1 |
3,583.1 |
|||||
Long-term debt |
302.6 |
386.3 |
712.7 |
|||||
Net debt |
361.2 |
456.7 |
761.7 |
|||||
Common shares outstanding (millions) (2) |
140.0 |
139.2 |
132.8 |
|||||
|
|
|
|
|||||
Sales volumes (3) |
|
|
|
|||||
Natural gas (MMcf/d) |
272.9 |
284.8 |
273.1 |
|||||
Condensate and oil (Bbl/d) |
31,375 |
32,342 |
29,854 |
|||||
Other NGLs (Bbl/d) |
5,276 |
5,462 |
5,170 |
|||||
Total (Boe/d) |
82,137 |
85,265 |
80,540 |
|||||
% liquids |
45% |
44% |
43% |
|||||
Grande Prairie Region (Boe/d) |
54,737 |
56,035 |
47,385 |
|||||
Kaybob Region (Boe/d) |
20,726 |
21,725 |
24,938 |
|||||
Central Alberta & Other Region (Boe/d) |
6,674 |
7,505 |
8,217 |
|||||
Total (Boe/d) |
82,137 |
85,265 |
80,540 |
|||||
|
|
|
|
|
|
|
|
|
Netback |
|
$/Boe (4) |
|
$/Boe (4) |
|
$/Boe (4) |
|
|
Natural gas revenue |
127.1 |
5.18 |
124.7 |
4.76 |
77.3 |
3.14 |
|
|
Condensate and oil revenue |
331.9 |
117.53 |
281.1 |
94.46 |
185.9 |
69.20 |
|
|
Other NGLs revenue |
29.3 |
61.64 |
27.4 |
54.61 |
15.0 |
32.29 |
|
|
Royalty and other revenue |
11.3 |
─ |
1.3 |
─ |
1.9 |
─ |
|
|
Petroleum and natural gas sales |
499.6 |
67.59 |
434.5 |
55.40 |
280.1 |
38.64 |
|
|
Royalties |
(76.2) |
(10.31) |
(52.5) |
(6.69) |
(18.6) |
(2.57) |
|
|
Operating expense |
(89.2) |
(12.07) |
(91.0) |
(11.61) |
(84.3) |
(11.63) |
|
|
Transportation and NGLs processing |
(31.3) |
(4.24) |
(26.1) |
(3.33) |
(27.9) |
(3.84) |
|
|
Sales of commodities purchased (5) |
48.8 |
6.59 |
22.1 |
2.82 |
8.6 |
1.18 |
|
|
Commodities purchased (5) |
(49.1) |
(6.64) |
(22.3) |
(2.85) |
(8.8) |
(1.21) |
|
|
Netback |
302.6 |
40.92 |
264.7 |
33.74 |
149.1 |
20.57 |
|
|
Risk management contract settlements |
(49.7) |
(6.72) |
(72.4) |
(9.23) |
(32.7) |
(4.51) |
|
|
Netback including risk management contract |
252.9 |
34.20 |
192.3 |
24.51 |
116.4 |
16.06 |
|
|
|
|
|
|
|||||
Capital expenditures |
|
|
|
|||||
Grande Prairie Region |
76.8 |
57.7 |
51.3 |
|||||
Kaybob Region |
31.1 |
3.8 |
5.0 |
|||||
Central Alberta & Other Region |
0.1 |
2.6 |
1.2 |
|||||
Corporate |
9.0 |
1.6 |
1.8 |
|||||
Total |
117.0 |
65.7 |
59.3 |
|||||
|
|
|
|
|||||
Asset retirement obligations settlements |
14.8 |
7.0 |
8.4 |
(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: Q1 2022: 1.5 million; Q4 2021: 1.5 million; Q1 2021: 1.9 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 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.
|
Total |
|
Kaybob Region |
||||||
|
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
Shale gas (MMcf/d) |
213.1 |
220.4 |
197.8 |
151.4 |
156.5 |
120.6 |
35.7 |
35.6 |
42.1 |
Conventional natural gas (MMcf/d) |
59.8 |
64.4 |
75.3 |
1.1 |
2.4 |
2.0 |
53.6 |
56.8 |
65.8 |
Natural gas (MMcf/d) |
272.9 |
284.8 |
273.1 |
152.5 |
158.9 |
122.6 |
89.3 |
92.4 |
107.9 |
Condensate (Bbl/d) |
29,098 |
29,797 |
27,017 |
26,042 |
26,272 |
23,974 |
2,130 |
2,184 |
2,611 |
Other NGLs (Bbl/d) |
5,276 |
5,462 |
5,170 |
3,267 |
3,276 |
2,984 |
1,558 |
1,788 |
1,677 |
NGLs (Bbl/d) |
34,374 |
35,259 |
32,187 |
29,309 |
29,548 |
26,958 |
3,688 |
3,972 |
4,288 |
Tight oil (Bbl/d) |
403 |
497 |
479 |
- |
- |
- |
322 |
355 |
342 |
Light and medium crude oil (Bbl/d) |
1,874 |
2,048 |
2,358 |
6 |
6 |
- |
1,832 |
2,000 |
2,321 |
Crude oil (Bbl/d) |
2,277 |
2,545 |
2,837 |
6 |
6 |
- |
2,154 |
2,355 |
2,663 |
Total (Boe/d) |
82,137 |
85,265 |
80,540 |
54,737 |
56,035 |
47,385 |
20,726 |
21,725 |
24,938 |
|
|||||||||
|
Central and |
Karr |
Wapiti |
||||||
|
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
Shale gas (MMcf/d) |
26.0 |
28.2 |
35.1 |
112.8 |
122.5 |
89.1 |
38.6 |
34.0 |
31.5 |
Conventional natural gas (MMcf/d) |
5.1 |
5.3 |
7.5 |
0.5 |
1.5 |
1.1 |
0.6 |
0.9 |
0.9 |
Natural gas (MMcf/d) |
31.1 |
33.5 |
42.6 |
113.3 |
124.0 |
90.2 |
39.2 |
34.9 |
32.4 |
Condensate (Bbl/d) |
926 |
1,341 |
433 |
17,246 |
18,521 |
16,095 |
8,796 |
7,751 |
7,879 |
Other NGLs (Bbl/d) |
451 |
398 |
509 |
2,475 |
2,449 |
2,108 |
792 |
827 |
876 |
NGLs (Bbl/d) |
1,377 |
1,739 |
942 |
19,721 |
20,970 |
18,203 |
9,588 |
8,578 |
8,755 |
Tight oil (Bbl/d) |
81 |
142 |
136 |
- |
- |
- |
- |
- |
- |
Light and medium crude oil (Bbl/d) |
36 |
42 |
37 |
- |
- |
- |
6 |
6 |
- |
Crude oil (Bbl/d) |
117 |
184 |
173 |
- |
- |
- |
6 |
6 |
- |
Total (Boe/d) |
6,674 |
7,505 |
8,217 |
38,611 |
41,629 |
33,230 |
16,126 |
14,406 |
14,155 |
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 and netback including risk management contract settlements 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. 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 three months ended
Non-GAAP Ratios
Netback and netback including risk management contract settlements presented on a $/Boe basis are non-GAAP ratios as they each have a non-GAAP financial measure (netback and netback including risk management contract settlements, respectively) 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.
Netback on a $/Boe basis is calculated by dividing netback for the applicable period by the total production during the period in Boe. Netback including risk management contract settlements on a $/Boe basis is calculated by dividing netback including risk management contract settlements for the applicable period by the total production during the period in Boe. 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
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 expense, 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 expense, sales of commodities purchased or 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:
- the expectation that the Company will achieve its net debt target of about
$300 million mid-year 2022 and potential net debt to adjusted funds flow at year-end; - planned abandonment and reclamation expenditures and activities in 2022 and 2023;
- planned capital expenditures in 2022;
- forecast sales volumes for 2022 and certain periods therein;
- forecast free cash flow in 2022;
- preliminary anticipated capital expenditures in 2023 and the resulting expected 2023 average sales volumes and free cash flow;
- expected production growth at Karr in 2023 and the potential range of plateau production at Karr in 2024;
- 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;
- the expectation that second quarter sales volumes at Karr will be impacted by a 16-day full field outage for scheduled turnaround activities at third-party midstream facilities;
- expected increases in sales volumes at Wapiti in the second quarter of 2022;
- internally estimated drilling locations and potential plateau production volumes at Willesden Green and the time period over which plateau production volumes may be maintained; and
- the payment of future dividends under the Company's monthly dividend program.
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
- 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, 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 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
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
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 three months ended
This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes. This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses 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.
This press release contains information respecting
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