HIGHLIGHTS
- Third quarter sales volumes averaged 98,644 Boe/d (45% liquids), a quarterly record. (1)
Grande Prairie Region sales volumes averaged a record 74,381 Boe/d (50% liquids) despite approximately 5,400 Boe/d in unplanned outages and curtailments associated with third-party midstream facilities.Kaybob Region sales volumes increased to 17,027 Boe/d (32% liquids) due to the recovery from theAlberta wildfires. The Company successfully completed the planned turnaround at its Kaybob 8-9 natural gas processing plant in September, which shut-in the majority ofKaybob Region production for approximately three weeks.Central Alberta andOther Region sales volumes averaged 7,236 Boe/d (30% liquids).
Paramount has expanded its coreMontney land position in theGrande Prairie Region through the addition of 10 net sections of new land at Karr and Wapiti. The Company has also disclosed the location of a further 10 net sections at Wapiti that were previously held confidentially. The Company maintains an active exploration program and is pleased with the progress made to date in capturing additional resource.- Cash from operating activities was
$208 million ($1.45 per basic share) in the third quarter. Adjusted funds flow was$234 million ($1.64 per basic share). (2) - Free cash flow was
$19 million ($0.13 per basic share) in the third quarter. (2)
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(1) | In this press release, "liquids" refers to NGLs (including condensate) and oil combined, "natural gas" refers to shale gas and conventional natural gas combined, "condensate and oil" refers to condensate, light and medium crude oil, tight oil and heavy crude 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, tight oil and heavy crude 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 |
- Third quarter capital expenditures totaled
$199 million . Key activities included:Grande Prairie Region (Montney ) - nine (9.0 net) wells drilled, five (5.0 net) wells completed and eight (8.0 net) wells brought on production;Kaybob Region (Duvernay ) - two (2.0 net) wells drilled and three (3.0 net) wells brought on production; andCentral Alberta andOther Region (Duvernay ) - three (3.0 net) wells drilled in Willesden Green and advancement of the liquids handling expansion atParamount's Leafland natural gas processing plant.
- Initial results at two of the Company's most recent pads brought on production, the Karr 7-33S five-well
Montney pad and the Kaybob North 4-13S three-wellDuvernay pad, have been exceptional, significantly exceeding type curve. - Asset retirement obligations settled in the third quarter totaled
$14 million . Activities in the quarter included the abandonment of seven wells and reclamation of seven well sites. - At
September 30, 2023 , net debt was$44 million andParamount's $1.0 billion revolving credit facility was undrawn. (1) - The carrying value of the Company's investments in securities at
September 30, 2023 was$578 million . - Subsequent to
September 30, 2023 , the Company monetized certain WTI liquids hedges that were outstanding at quarter end for cash consideration of approximately$13 million , which will be included in fourth quarter 2023 adjusted funds flow.Paramount also hedged 10,000 Bbl/d of 2024 liquids sales volumes at an average WTI price ofCAD$109.50 /Bbl.
UPDATED 2023 GUIDANCE
Third quarter sales volumes were in-line with expectations.
Third quarter capital expenditures were also in-line with expectations.
The Company is updating its forecast of 2023 free cash flow to approximately
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(1) | Net (cash) debt is a capital management measure used by |
(2) | Free cash flow is a capital management measure used by |
2024 BUDGET AND GUIDANCE
The Company remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices and other factors.
The 2024 capital budget at midpoint is broken down as follows:
$415 million (~50%) to sustaining capital and maintenance activities;$45 million (~5%) to growth capital associated with production benefits in 2024; and$400 million (~45%) to growth capital associated with production benefits largely in 2025 and beyond, including approximately$150 million related to the construction of the Company's new processing facility in Willesden Green.
The breakdown by region at midpoint is as follows:
Grande Prairie Region −$425 million ;Kaybob Region −$185 million ; andCentral Alberta andOther Region −$250 million .
The breakdown by category at midpoint is as follows:
- Drilling, completion, equipping and tie-ins −
$575 million ; - Facilities and gathering −
$280 million ; and - Corporate and other −
$5 million .
The majority of the facilities and gathering capital budgeted for 2024 relates to the first phase of the Company's new processing facility in Willesden Green. This first phase will provide an estimated 50 MMcf/d of raw gas and 10,000 Bbl/d of raw liquids handling capacity upon completion to support
The Company has budgeted
Average sales volumes in 2024 are expected to be between 108,000 Boe/d and 116,000 Boe/d (47% liquids), 3,000 Boe/d lower at midpoint compared to the previous preliminary guidance primarily due to (i) an increase in planned downtime by the third-party operator of the Wapiti Plant, (ii) a reduction in
First half 2024 average sales volumes are expected to be between 101,000 Boe/d and 111,000 Boe/d (46% liquids), with second quarter sales volumes being impacted by a 21 day planned turnaround at the Wapiti Plant. Second half 2024 average sales volumes are expected to be between 115,000 Boe/d and 121,000 Boe/d (47% liquids).
Preliminary 2024 Guidance | 2024 Budget | |
Annual average sales volumes (Boe/d) | 110,000 to 120,000 (48% liquids) | 108,000 to 116,000 (47% liquids) |
First half average sales volumes (Boe/d) | —
| 101,000 to 111,000 (46% liquids) |
Second half average sales volumes (Boe/d) | —
| 115,000 to 121,000 (47% liquids) |
Capital expenditures | ||
Abandonment and reclamation expenditures | No change | |
Free cash flow (1) |
The Company's midpoint 2024 sustaining and maintenance capital program and regular monthly dividend would remain fully funded down to an average WTI price in 2024 of about
FIVE-YEAR OUTLOOK
NOVEMBER DIVIDEND
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(1) | Free cash flow is a capital management measure used by |
(2) | Assuming no changes to the other forecast assumptions for 2024. |
(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 midpoint annual capital expenditures; (ii) compound annual production growth in the stated range; (iii) approximately |
(4) | Based on 144.3 million outstanding Common Shares as at |
REVIEW OF OPERATIONS
Sales volumes and netbacks in the
Q3 2023 |
Q2 2023 |
% Change | |||
Sales Volumes | |||||
Natural gas (MMcf/d) | 223.2 | 196.4 | 14 | ||
Condensate and oil (Bbl/d) | 32,365 | 30,205 | 7 | ||
Other NGLs (Bbl/d) | 4,815 | 4,012 | 20 | ||
Total (Boe/d) | 74,381 | 66,950 | 11 | ||
% liquids | 50 % | 51 % | |||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) | Change in $ |
Natural gas revenue (2) | 55.6 | 2.71 | 43.3 | 2.42 | 28 |
Condensate and oil revenue | 308.7 | 103.68 | 260.5 | 94.76 | 19 |
Other NGLs revenue | 15.4 | 34.70 | 11.7 | 31.99 | 32 |
Royalty income and other revenue | – | – | 0.3 | – | NM |
Petroleum and natural gas sales | 379.7 | 55.48 | 315.8 | 51.83 | 20 |
Royalties | (64.7) | (9.45) | (39.3) | (6.45) | 65 |
Operating expense | (72.7) | (10.62) | (70.7) | (11.61) | 3 |
Transportation and NGLs processing | (25.6) | (3.75) | (27.2) | (4.47) | (6) |
216.7 | 31.66 | 178.6 | 29.30 | 21 |
(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) | Per unit natural gas revenue presented as $/Mcf. | |||||
NM means not meaningful |
Sales volumes in the
Development activities in the
At Karr, all five (5.0 net) wells on the 7-33S pad were brought on production late in the third quarter. Production results from these wells to date have significantly exceeded expectations, averaging gross 30-day peak production per well of 2,554 Boe/d (4.8 MMcf/d of shale gas and 1,749 Bbl/d of NGLs) with an average CGR of 362 Bbl/MMcf. (1)
_________________________________ | |
(1) | Production measured at the wellhead. Natural gas sales volumes were lower by approximately 10% and liquids sales volumes were lower by approximately 7% 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. |
At Wapiti, all three (3.0 net) wells on the 1-27 pad were brought on production in the third quarter. Production results from these wells are in-line with expectations, averaging gross 30-day peak production per well of 1,187 Boe/d (2.7 MMcf/d of shale gas and 730 Bbl/d of NGLs) with an average CGR of 266 Bbl/MMcf. (1) More recently,
In 2024, the Company plans to drill 41 (41.0 net) wells and bring on production 36 (36.0 net) wells in the
The third-party operator of the Wapiti Plant has notified
KAYBOB REGION
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(1) | Production measured at the wellhead. Natural gas sales volumes were lower by approximately 9% and liquids sales volumes were 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. |
Production from the three well 4-13S pad has been very strong, averaging gross 30-day peak production per well of 1,601 Boe/d (1.2 MMcf/d of shale gas and 1,403 Bbl/d of NGLs) with an average CGR of 1,177 Bbl/MMcf.(1) These results are among the best ever recorded for
Development activities in the third quarter included the drilling of two wells on the Kaybob North Duvernay six (6.0 net) well 15-7N pad. Drilling of the remaining four wells is ongoing, with completion operations and tie-ins to commence in the fourth quarter of 2023. The Company continues to apply past learnings from the drilling of long reach lateral wells and has once again set a new company record with one of the wells on the 15-7N pad reaching approximately 8,100 meters of total measured depth with a lateral length of approximately 4,800 meters. All six wells are anticipated to be brought onstream in the first quarter of 2024.
The drilling of the four (4.0 net)
In 2024, the Company plans to grow annual average sales volumes in the
Construction of the Company's previously announced second natural gas processing facility at Willesden Green is set to commence in 2024, with start-up expected in the fourth quarter of 2025. The first phase of this new facility will provide an estimated 50 MMcf/d of raw gas and 10,000 Bbl/d of raw liquids handling capacity to support the Willesden Green Duvernay development. It is anticipated that the new facility will ultimately be capable of handling approximately 150 MMcf/d of raw gas and 30,000 Bbl/d of raw liquids, and be constructed in three phases of approximately 50 MMcf/d of raw gas handling and 10,000 Bbl/d of raw liquids handling each.
_________________________________________ | |
(1) | Production measured at the wellhead. Natural gas sales volumes were lower by approximately 16% and liquids sales volumes were lower by approximately 13% 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. |
HEDGING
The Company's commodity and foreign exchange contracts are summarized below:
Instruments | Aggregate | Average | Remaining term | |||
Oil | ||||||
NYMEX WTI Swaps (Sale) | 10,000 Bbl/d | |||||
Sweet Crude Oil – Basis | 3,078 Bbl/d | WTI – | ||||
Natural Gas | ||||||
AECO – Basis (Physical Sale) | 50,000 MMBtu/d | NYMEX – | ||||
Dawn – Basis (Physical Sale) | 25,000 MMBtu/d | NYMEX – | ||||
Foreign Currency Exchange | ||||||
Swaps (sale) | $40MM/Month | |||||
Swaps (sale) | $30MM/Month |
(1) | Average price is calculated using a weighted average of notional volumes and prices. "NYMEX" refers to NYMEX pricing at Henry Hub. |
(2) | Sweet crude oil located at the Peace Pipeline at |
ABOUT
A summary of historical financial and operating results is also available on
Financial and operating results (1)
($ millions, except as noted) | Q3 2023 | Q2 2023 | Q3 2022 | |||
Net income | 87.2 | 74.2 | 221.9 | |||
per share – basic ($/share) | 0.61 | 0.52 | 1.57 | |||
per share – diluted ($/share) | 0.59 | 0.50 | 1.51 | |||
Cash from operating activities | 207.6 | 172.2 | 248.9 | |||
per share – basic ($/share) | 1.45 | 1.20 | 1.76 | |||
per share – diluted ($/share) | 1.40 | 1.16 | 1.69 | |||
Adjusted funds flow | 234.2 | 178.7 | 334.3 | |||
per share – basic ($/share) | 1.64 | 1.25 | 2.37 | |||
per share – diluted ($/share) | 1.58 | 1.21 | 2.27 | |||
Free cash flow | 18.5 | 30.5 | 137.5 | |||
per share – basic ($/share) | 0.13 | 0.21 | 0.97 | |||
per share – diluted ($/share) | 0.12 | 0.21 | 0.93 | |||
Total assets | 4,305.1 | 4,106.6 | 4,261.3 | |||
Investments in securities | 577.5 | 489.9 | 451.3 | |||
Long-term debt | – | – | 306.3 | |||
Net (cash) debt | 44.4 | 2.3 | 347.0 | |||
Common shares outstanding (millions) (2) | 143.4 | 143.1 | 141.2 | |||
Sales volumes (3) | ||||||
Natural gas (MMcf/d) | 323.1 | 290.2 | 315.9 | |||
Condensate and oil (Bbl/d) | 38,161 | 34,230 | 38,804 | |||
Other NGLs (Bbl/d) | 6,627 | 5,648 | 6,144 | |||
Total (Boe/d) | 98,644 | 88,243 | 97,601 | |||
% liquids | 45 % | 45 % | 46 % | |||
74,381 | 66,950 | 65,981 | ||||
17,027 | 13,238 | 24,021 | ||||
7,236 | 8,055 | 7,599 | ||||
Total (Boe/d) | 98,644 | 88,243 | 97,601 | |||
Netback | ($/Boe) (4) | ($/Boe) (4) | ($/Boe) (4) | |||
Natural gas revenue | 79.3 | 2.67 | 64.1 | 2.43 | 185.7 | 6.39 |
Condensate and oil revenue | 362.9 | 103.36 | 294.1 | 94.42 | 401.8 | 112.56 |
Other NGLs revenue | 20.5 | 33.64 | 15.9 | 30.86 | 28.9 | 51.20 |
Royalty income and other revenue | 1.1 | – | 0.3 | – | 2.5 | ─ |
Petroleum and natural gas sales | 463.8 | 51.11 | 374.4 | 46.63 | 618.9 | 68.92 |
Royalties | (75.2) | (8.28) | (41.2) | (5.12) | (89.4) | (9.96) |
Operating expense | (113.9) | (12.55) | (104.6) | (13.03) | (110.0) | (12.25) |
Transportation and NGLs processing | (31.2) | (3.44) | (33.6) | (4.19) | (34.4) | (3.83) |
Sales of commodities purchased (5) | 42.1 | 4.64 | 47.7 | 5.94 | 77.9 | 8.67 |
Commodities purchased (5) | (39.2) | (4.32) | (49.3) | (6.15) | (76.4) | (8.51) |
Netback | 246.4 | 27.16 | 193.4 | 24.08 | 386.6 | 43.04 |
Risk management contract settlements | 0.2 | 0.02 | (2.7) | (0.33) | (44.4) | (4.94) |
Netback including risk management contract | 246.6 | 27.18 | 190.7 | 23.75 | 342.2 | 38.10 |
Capital expenditures | ||||||
117.6 | 66.0 | 133.5 | ||||
41.4 | 45.5 | 30.8 | ||||
35.5 | 17.1 | 0.2 | ||||
4.9 | 7.6 | 10.8 | ||||
Corporate | (0.5) | 4.0 | 9.0 | |||
Total | 198.9 | 140.2 | 184.3 | |||
Asset retirement obligations settled | 14.0 | 5.9 | 10.2 |
(1) | Adjusted funds flow, free cash flow and net (cash) 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: Q3 2023: 0.4 million, Q2 2023: 0.4 million, Q3 2022: 0.8 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 shale gas and conventional natural gas combined. "Condensate and oil" refers to condensate, light and medium crude oil, tight oil and heavy crude 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, light and medium crude oil, tight oil and heavy crude oil. Numbers may not add due to rounding.
| ||||||||||||||||||
Q3 2023 | Q2 2023 | Q3 2022 | ||||||||||||||||
Shale gas (MMcf/d) | 276.7 | 246.0 | 253.8 | |||||||||||||||
Conventional natural gas (MMcf/d) | 46.4 | 44.2 | 62.1 | |||||||||||||||
Natural gas (MMcf/d) | 323.1 | 290.2 | 315.9 | |||||||||||||||
Condensate (Bbl/d) | 35,984 | 32,341 | 35,747 | |||||||||||||||
Other NGLs (Bbl/d) | 6,627 | 5,648 | 6,144 | |||||||||||||||
NGLs (Bbl/d) | 42,611 | 37,989 | 41,891 | |||||||||||||||
Light and medium crude oil (Bbl/d) | 1,154 | 942 | 2,608 | |||||||||||||||
Tight oil (Bbl/d) | 627 | 538 | 449 | |||||||||||||||
Heavy crude oil (Bbl/d) | 396 | 409 | – | |||||||||||||||
Crude oil (Bbl/d) | 2,177 | 1,889 | 3,057 | |||||||||||||||
Total (Boe/d) | 98,644 | 88,243 | 97,601 | |||||||||||||||
| ||||||||||||||||||
Q3 2023 | Q2 2023 | Q3 2022 | Q3 2023 | Q2 2023 | Q3 2022 | Q3 2023 | Q2 2023 | Q3 2022 | ||||||||||
Shale gas (MMcf/d) | 222.8 | 196.1 | 188.2 | 28.0 | 21.7 | 38.5 | 25.9 | 28.2 | 27.1 | |||||||||
Conventional natural gas (MMcf/d) | 0.4 | 0.3 | 1.4 | 41.7 | 38.4 | 54.8 | 4.3 | 5.5 | 5.9 | |||||||||
Natural gas (MMcf/d) | 223.2 | 196.4 | 189.6 | 69.7 | 60.1 | 93.3 | 30.2 | 33.7 | 33.0 | |||||||||
Condensate (Bbl/d) | 32,145 | 30,046 | 30,610 | 2,981 | 1,301 | 4,157 | 858 | 994 | 980 | |||||||||
Other NGLs (Bbl/d) | 4,815 | 4,012 | 3,758 | 1,188 | 891 | 1,666 | 624 | 745 | 720 | |||||||||
NGLs (Bbl/d) | 36,960 | 34,058 | 34,368 | 4,169 | 2,192 | 5,823 | 1,482 | 1,739 | 1,700 | |||||||||
Light and medium crude oil (Bbl/d) | – | – | 5 | 1,131 | 914 | 2,434 | 23 | 28 | 169 | |||||||||
Tight oil (Bbl/d) | 220 | 159 | – | 104 | 115 | 208 | 303 | 264 | 241 | |||||||||
Heavy crude oil (Bbl/d) | – | – | – | – | – | – | 396 | 409 | – | |||||||||
Crude oil (Bbl/d) | 220 | 159 | 5 | 1,235 | 1,029 | 2,642 | 722 | 701 | 410 | |||||||||
Total (Boe/d) | 74,381 | 66,950 | 65,981 | 17,027 | 13,238 | 24,021 | 7,236 | 8,055 | 7,599 |
The Company forecasts that 2023 annual sales volumes will average between 95,000 Boe/d and 98,000 Boe/d (54% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs). Fourth quarter 2023 sales volumes are expected to average between 100,000 Boe/d and 103,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs).
The Company forecasts that 2024 annual sales volumes will average between 108,000 Boe/d and 116,000 Boe/d (53% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% Other NGLs). First half 2024 sales volumes are expected to average between 101,000 Boe/d and 111,000 Boe/d (54% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs). Second half 2024 sales volumes are expected to average between 115,000 Boe/d and 121,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil 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. Sales of commodities purchased and commodities purchased are treated as Corporate items and not are 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 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 (cash) 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) petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf 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.
Petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expense, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf basis are calculated by dividing the petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expense, sales of commodities purchased or commodities purchased, as applicable, over the referenced period by the aggregate units (Boe or Mcf) produced during such period.
ADVISORIES
Forward-looking Information
Certain statements in this press release constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "schedule", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward-looking information in this press release includes, but is not limited to:
- planned capital expenditures in 2023 and 2024 and the allocation thereof;
- forecast sales volumes for 2023 and 2024 and certain periods therein;
- planned abandonment and reclamation expenditures in 2023 and 2024;
- forecast free cash flow in 2023 and 2024;
- the anticipated capacity and timing of startup of the planned new facility at Willesden Green;
- the Company's five-year outlook for capital expenditures, cumulative free cash flow and sales volumes;
- the statement that
Paramount does not forecast cash tax in its five-year outlook until 2027; - planned exploration, development and production activities, including the expected timing of drilling, completing and bringing new wells on production and the expected timing of completion of planned facilities and infrastructure;
- planned outages and downtime of facilities;
- expected
Grande Prairie sales volumes in 2024; - expected Kaybob North Duvernay sales volumes growth;
- the expectation that
Kaybob Region sales volumes will exceed 20,000 Boe/d in 2024; - the Company's plans to grow production in the
Central Alberta andOther Region to over 10,000 Boe/d in 2024; and - the potential payment of future dividends.
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 international conflicts, including 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, including approvals required for the expansion and construction of facilities at Willesden Green;
- 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 facilities at Willesden Green, 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 the Company's five-year outlook for capital expenditures, cumulative free cash flow and sales volumes;
- 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 that may result in changes to the planned expansion and construction of facilities at Willesden Green, including the potential for changes to facility design or the timelines for construction prior to finalization or the failure to obtain required governmental and regulatory approvals;
- 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.
With respect to the statement that
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 2024 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 | ||||
WTI | West Texas Intermediate | MMcf | Millions of cubic feet | ||||
MMcf/d | Millions of cubic feet per day | ||||||
Oil Equivalent | AECO | AECO-C reference price | |||||
Boe | Barrels of oil equivalent | ||||||
MBoe | Thousands of barrels of oil equivalent | ||||||
MMBoe | Millions of barrels of oil equivalent | ||||||
Boe/d | Barrels of oil equivalent per day | ||||||
This press release contains disclosures expressed as "Boe", "$/Boe" 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 nine 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.
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
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