Paramount Resources Ltd. Announces Third Quarter 2024 Results

2024-11-07

TSX - Toronto Stock Exchange · Natural Gas · Oil · Natural Gas Liquids · Ethane · Canada

Canada NewsWire

CALGARY, AB , Nov. 7, 2024 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its third quarter 2024 financial and operating results.

HIGHLIGHTS

Third quarter sales volumes averaged 94,892 Boe/d (48% liquids). (1) Grande Prairie Region sales volumes averaged 67,635 Boe/d (50% liquids). The planned turnaround at the Wapiti natural gas processing plant (the "Wapiti Plant") and related full Wapiti production outage commenced in mid-September, five days earlier than expected. Prior to the turnaround, Wapiti sales volumes reached over 35,000 Boe/d as two new Montney pads were brought on production. Kaybob Region sales volumes averaged 20,894 Boe/d (41% liquids). Central Alberta and Other Region sales volumes averaged 6,363 Boe/d (53% liquids). 5,600 Boe/d of dry natural gas production was shut-in for the quarter due to low natural gas prices.

Cash from operating activities was $206 million ( $1.40 per basic share) in the third quarter. Adjusted funds flow was $201 million ( $1.37 per basic share). Free cash flow was ($26) million ( ($0.18) per basic share). (2) Third quarter capital expenditures totaled $217 million . Significant activities included: Grande Prairie Region ( Montney ) – eight (8.0 net) wells drilled, nineteen (19.0 net) wells brought on production and the successful completion of the new compressor node at Wapiti that was brought onstream in the third quarter, which will support development of the western portion of the field; Kaybob Region ( Duvernay ) – three (3.0 net) wells drilled; and

| _ | | | (1) | In this press release, "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, "Other NGLs" refers to ethane, propane and butane and "liquids" refers to condensate and oil and Other NGLs combined. 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 Paramount. Cash from operating activities per basic share, adjusted funds flow per basic share and free cash flow per basic share are supplementary financial measures. Refer to the "Specified Financial Measures" section for more information on these measures. |

Central Alberta and Other Region ( Duvernay ) – three (3.0 net) wells brought on production and the ongoing construction of the Company's second operated natural gas processing plant at Willesden Green (the "Alhambra Plant").

Paramount has recently spud the first of two horizontal appraisal wells at its Sinclair property, where the Company has approximately 107,000 net acres prospective for high-rate gas production from the Montney formation. Asset retirement obligations settled in the third quarter totaled $7 million . The carrying value of the Company's investments in securities at September 30, 2024 was $482 million . (1) At September 30, 2024 , net debt was $129 million . (2)

UPDATED 2024 GUIDANCE

Third quarter sales volumes averaged 94,892 Boe/d (48% liquids), below prior guidance of between 96,000 Boe/d to 104,000 Boe/d (49% liquids). In addition to the impact from the early start of the Wapiti Plant turnaround, the Company's third quarter sales volumes were affected by numerous curtailments due to high ambient temperatures throughout the summer, unplanned outages at several minor infrastructure sites and the continuing shut-in of dry natural gas production.

Paramount is updating its fourth quarter 2024 sales volumes guidance to a range of 102,000 Boe/d to 109,000 Boe/d (49% liquids). The Company has deferred bringing approximately 4,200 Boe/d of dry natural gas production onstream in the fourth quarter. In addition, fourth quarter sales volumes were impacted by approximately 5,000 Boe/d due to the Wapiti Plant turnaround extending for the equivalent of 6 full days longer than expected in October as well as other disruptions in the month. Annual sales volumes would average 100,000 Boe/d at the upper end of the forecast range of fourth quarter 2024 sales volumes.

With the Wapiti Plant turnaround complete and subsequent disruptions resolved, Grande Prairie Region sales volumes have averaged over 80,000 Boe/d and total Company sales volumes have averaged over 110,000 Boe/d since late-October.

The Company is reaffirming its 2024 guidance for capital expenditures and abandonment and reclamation expenditures.

Paramount is updating its forecast of 2024 free cash flow from $100 million to $10 million to reflect results from the first three quarters, revised fourth quarter forecast production and a lower forecast WTI price of US$70 /Bbl (previously US$80 /Bbl).

| _ | | | (1) | Investments in publicly traded securities are carried at their September 30, 2024 closing trading price. | | (2) | Net (cash) debt is a capital management measure used by Paramount. This capital management measure has been expressed as net debt in this instance for simplicity as the amount referenced is a positive number. Refer to the "Specified Financial Measures" section for more information on this measure. | | (3) | Free cash flow is a capital management measure used by Paramount. Refer to the "Specified Financial Measures" section for more information on this measure. The stated free cash flow forecast is based on the following assumptions for 2024: (i) the midpoint of stated capital expenditures, (ii) the midpoint of fourth quarter sales volumes, (iii) $40 million in abandonment and reclamation costs, (iv) $10 million in geological and geophysical expenses, (v) realized pricing of $48.50/Boe, (vi) a $US/$CAD exchange rate of $0.735, (vii) royalties of $6.25/Boe, (viii) operating costs of $13.30/Boe and (ix) transportation and NGLs processing costs of $3.50/Boe. The stated amounts have been adjusted to incorporate actual results for the first three quarters of 2024. |

NOVEMBER DIVIDEND

Paramount's Board of Directors has declared a cash dividend of $0.15 per class A common share that will be payable on November 29 , 2024 to shareholders of record on November 15 , 2024. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Sales volumes and netbacks in the Grande Prairie Region are summarized below:

| | Q3 2024 | Q2 2024 | % Change | | | | Sales Volumes | | | | | | | Natural gas (MMcf/d) | 203.2 | 187.3 | 8 | | | | Condensate and oil (Bbl/d) | 29,047 | 28,083 | 3 | | | | Other NGLs (Bbl/d) | 4,723 | 4,179 | 13 | | | | Total (Boe/d) | 67,635 | 63,480 | 7 | | | | % liquids | 50 % | 51 % | | | | | Netback (1) | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | _Change in $ millions (%) _ | | Natural gas revenue (2) | 25.9 | 1.38 | 28.5 | 1.67 | (9) | | Condensate and oil revenue | 257.4 | 96.33 | 264.9 | 103.63 | (3) | | Other NGLs revenue | 16.1 | 37.09 | 12.8 | 33.77 | 26 | | Petroleum and natural gas sales | 299.4 | 48.12 | 306.2 | 53.01 | (2) | | Royalties | (39.9) | (6.40) | (56.9) | (9.86) | (30) | | Operating expense | (83.4) | (13.41) | (82.6) | (14.29) | 1 | | Transportation and NGLs processing | (24.8) | (3.99) | (21.9) | (3.80) | 13 | | | 151.3 | 24.32 | 144.8 | 25.06 | 4 |

| (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. |

Third quarter 2024 sales volumes in the Grande Prairie Region averaged 67,635 Boe/d (50% liquids) compared to 63,480 Boe/d (51% liquids) in the second quarter. Sales volumes were higher quarter-over-quarter as a result of new well production from 19 (19.0 net) new Montney wells that were brought onstream. The scheduled turnaround of the Wapiti Plant, which began five days earlier than expected, resulted in the shutdown of production from the Wapiti field for the equivalent of 15 full days in the third quarter, impacting average third quarter sales volumes by approximately 5,400 Boe/d. Unplanned maintenance at another third-party processing facility and high ambient temperatures also reduced sales volumes in the quarter. Paramount's aggressive well optimization program initiated in March 2024 is now substantially complete.

The Wapiti Plant turnaround continued into October. In total, the Wapiti Plant turnaround resulted in the shutdown of production from the Wapiti field for the equivalent of 32 full days, 11 more than originally expected.

Initial production from a new 4 (4.0 net) well Montney pad that was brought onstream at Karr in the quarter is in line with expectations, averaging gross 30-day peak production per well of 1,347 Boe/d (2.4 MMcf/d of shale gas and 953 Bbl/d of NGLs) with an average CGR of 403 Bbl/MMcf. (1)

Initial production results from a new 7 (7.0 net) well Montney pad that was brought onstream in the western portion of the Wapiti field in the quarter are encouraging despite the wells being heavily choked to manage temporary facilities constraints. The wells averaged gross 30-day peak production per well of 1,120 Boe/d (4.8 MMcf/d of shale gas and 314 Bbl/d of NGLs) with an average CGR of 65 Bbl/MMcf. (2)

Third quarter development activities in the Grande Prairie Region included the drilling of 8 (8.0 net) Montney wells, the completion of 16 (16.0 net) Montney wells and the bringing onstream of 19 (19.0 net) Montney wells. The Company also brought a new compressor node onstream to service the western portion of the Wapiti field.

Paramount plans to drill a total of seven (7.0 net) Montney wells and bring on production a total of eight (8.0 net) Montney wells in the Grande Prairie Region in the fourth quarter of 2024.

The Company has spud the first of two appraisal wells to be drilled in 2024 at Sinclair. Paramount will use the flow test and other data obtained from these wells to continue to advance its development plans for the property, which have included the securing of downstream transportation capacity that would enable the first phase of Sinclair production to commence as early as the fourth quarter of 2027. The Sinclair property is prospective for high-rate gas production from the Montney formation.

KAYBOB REGION

Kaybob Region sales volumes averaged 20,894 Boe/d (41% liquids) in the third quarter of 2024 compared to 23,946 Boe/d (41% liquids) in the second quarter. Sales volumes were lower quarter-over-quarter as a result of natural declines and the previously disclosed shut-in of dry gas production that occurred in mid-June. New well production from 5 (5.0 net) new Duvernay wells that came onstream in May partially offset the decreases.

Development activities in the third quarter included the drilling of three (3.0 net) Duvernay wells at Kaybob North. Paramount plans to drill an additional two (2.0 net) Duvernay wells and bring on production six (6.0 net) Duvernay wells at Kaybob North in the fourth quarter of 2024.

| _ | | | (1) | 30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well 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. Natural gas sales volumes were lower by approximately 11% and liquids sales volumes were lower by approximately 8% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone. | | (2) | 30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well 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. Natural gas sales volumes were lower by approximately 10% and liquids sales volumes were lower by approximately 2% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone. |

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 6,363 Boe/d (53% liquids) in the third quarter of 2024 compared to 8,183 Boe/d (49% liquids) in the second quarter. Third quarter sales volumes were lower quarter-over-quarter as a result of natural declines, a planned outage at the Company's Leafland facility and the shut-in of certain wells to allow for completion activities on offsetting wells.

Initial production from the three new Duvernay wells that were brought onstream in the quarter is in line with expectations, averaging gross 30-day peak production per well of 1,254 Boe/d (2.3 MMcf/d of shale gas and 865 Bbl/d of NGLs) with an average CGR of 371 Bbl/MMcf. (1)

In addition to the completion and tie-in of the three new Duvernay wells, development activities in the third quarter of 2024 included the ongoing construction of the Alhambra Plant at Willesden Green. The Alhambra Plant will add approximately 18,000 Boe/d of raw handling capacity (comprised of 50 MMcf/d or raw gas handling and 10,000 Bbl/d of raw liquids handling).

The Company has initiated its drilling program that will provide production to the first phase of the Alhambra Plant. Paramount plans to drill five (5.0 net) wells in the fourth quarter of 2024 and complete and tie-in those wells in advance of the planned fourth quarter 2025 start-up of the Alhambra Plant.

HEDGING

The Company's current commodity and foreign exchange contracts are summarized below:

| | | Q4 2024 | 2025 | | Average Price (1) | | | Oil | | | | | | | | NYMEX WTI Swaps (Sale) (Bbl/d) | | 5,000 | 5,000 | | C$105.00/Bbl | | | | | | | | | | | Natural gas | | | | | | | | AECO – Basis (Physical Sale) (MMBtu/d) | | 13,478 | – | | NYMEX less US$0.93/MMBtu (2) | | | Malin / Citygate Basis Swap (Sale) (MMBtu/d) | | 10,000 | 10,000 | | Citygate less US$1.03/MMBtu (3) | | | | | | | | | | | Foreign Currency Exchange | | | | | | | | Swaps (Sale) (US$ million / month) | | $30 | – | | 1.3462 C$ / US$ | |

| (1) | Average price is calculated using a weighted average of notional volumes and prices. | | (2) | "NYMEX" means NYMEX pricing at Henry Hub. The contract has a notional volume of 40,000 MMBtu/d for the final period of the term, October 2024. | | (3) | "Malin" refers to Pacific Gas & Electric at Malin and "Citygate" refers to Pacific Gas & Electric Citygate. The remaining term of this contract is October 2024 to October 2027. |

| | | | (1) | 30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well 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. Natural gas sales volumes were lower by approximately 13% and liquids sales volumes were lower by approximately 7% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone. |

ABOUT PARAMOUNT

Paramount is an independent, publicly traded, liquids-rich natural gas focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company's principal properties are located in Alberta and British Columbia. Paramount's Common Shares are listed on the Toronto Stock Exchange under the symbol "POU".

Paramount's third quarter 2024 results, including Management's Discussion and Analysis and the Company's Interim Consolidated Financial Statements, can be obtained on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports .

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

FINANCIAL AND OPERATING RESULTS (1)

| ($ millions, except as noted) | Q3 2024 | Q2 2024 | Q3 2023 | | | | | Net income | 95.8 | 84.5 | 87.2 | | | | | per share – basic ($/share) | 0.65 | 0.58 | 0.61 | | | | | per share – diluted ($/share) | 0.64 | 0.57 | 0.59 | | | | | Cash from operating activities | 205.7 | 220.5 | 207.6 | | | | | per share – basic ($/share) | 1.40 | 1.51 | 1.45 | | | | | per share – diluted ($/share) | 1.38 | 1.47 | 1.40 | | | | | Adjusted funds flow | 200.7 | 266.2 | 234.2 | | | | | per share – basic ($/share) | 1.37 | 1.82 | 1.64 | | | | | per share – diluted ($/share) | 1.34 | 1.78 | 1.58 | | | | | Free cash flow | (26.3) | 20.3 | 18.5 | | | | | per share – basic ($/share) | (0.18) | 0.14 | 0.13 | | | | | per share – diluted ($/share) | (0.18) | 0.14 | 0.12 | | | | | Total assets | 4,544.1 | 4,589.2 | 4,305.1 | | | | | Investments in securities | 482.2 | 579.5 | 577.5 | | | | | Long-term debt | 44.0 | – | – | | | | | Net (cash) debt | 128.8 | 29.3 | 44.4 | | | | | Common shares outstanding _(millions) _(2) | 146.5 | 146.7 | 143.4 | | | | | Sales volumes (3) | | | | | | | | Natural gas (MMcf/d) | 294.5 | 296.8 | 323.1 | | | | | Condensate and oil (Bbl/d) | 38,770 | 39,206 | 38,161 | | | | | Other NGLs (Bbl/d) | 7,045 | 6,928 | 6,627 | | | | | Total (Boe/d) | 94,892 | 95,609 | 98,644 | | | | | % liquids | 48 % | 48 % | 45 % | | | | | Grande Prairie Region (Boe/d) | 67,635 | 63,480 | 74,381 | | | | | Kaybob Region (Boe/d) | 20,894 | 23,946 | 17,027 | | | | | Central Alberta & Other Region (Boe/d) | 6,363 | 8,183 | 7,236 | | | | | Total (Boe/d) | 94,892 | 95,609 | 98,644 | | | | | Netback | | ($/Boe) (4) | | ($/Boe) (4) | | ($/Boe) (4) | | Natural gas revenue | 37.2 | 1.37 | 45.6 | 1.69 | 79.3 | 2.67 | | Condensate and oil revenue | 342.9 | 96.15 | 367.7 | 103.07 | 362.9 | 103.36 | | Other NGLs revenue | 23.5 | 36.25 | 20.8 | 33.07 | 20.5 | 33.64 | | Royalty income and other revenue (5) | 1.2 | – | 9.5 | – | 1.1 | – | | Petroleum and natural gas sales | 404.8 | 46.37 | 443.6 | 50.99 | 463.8 | 51.11 | | Royalties | (46.4) | (5.31) | (66.1) | (7.60) | (75.2) | (8.28) | | Operating expense | (116.3) | (13.33) | (115.7) | (13.29) | (113.9) | (12.55) | | Transportation and NGLs processing | (34.2) | (3.92) | (31.3) | (3.60) | (31.2) | (3.44) | | Sales of commodities purchased (6) | 79.6 | 9.11 | 84.4 | 9.70 | 42.1 | 4.64 | | Commodities purchased (6) | (78.5) | (9.00) | (82.4) | (9.47) | (39.2) | (4.32) | | Netback | 209.0 | 23.92 | 232.5 | 26.73 | 246.4 | 27.16 | | Risk management contract settlements | 2.0 | 0.23 | 36.4 | 4.18 | 0.2 | 0.02 | | Netback including risk management contract settlements | 211.0 | 24.15 | 268.9 | 30.91 | 246.6 | 27.18 | | Capital expenditures | | | | | | | | Grande Prairie Region | 84.6 | 154.8 | 117.6 | | | | | Kaybob Region | 56.5 | 40.9 | 41.4 | | | | | Central Alberta & Other Region | 73.0 | 45.9 | 35.5 | | | | | Fox Drilling and Cavalier Energy | 2.7 | 0.7 | 4.9 | | | | | Corporate (7) | (0.1) | (1.5) | (0.5) | | | | | Total | 216.7 | 240.8 | 198.9 | | | | | Asset retirement obligations settled | 7.4 | 2.3 | 14.0 | | | |