Paramount Resources Ltd. press release

Paramount Resources Ltd. Announces First Quarter 2022 Results, Upwardly Revised Guidance, Increased Dividend and Complementary Asset Acquisition

2022-05-04

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

Canada NewsWire

CALGARY, AB , May 4, 2022 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce strong first quarter 2022 financial and operating results, the acceleration of development activities at Karr supporting increased production in 2023 and beyond and a highly complementary $40 million Duvernay acquisition in its Willesden Green core area. Paramount is also pleased to announce that it is increasing its regular monthly dividend from $0.08 per class A common share ("Common Share") to $0.10 per Common Share beginning May 2022 .

HIGHLIGHTS

First quarter 2022 sales volumes averaged 82,137 Boe/d (45% liquids), in-line with expectations. (1) 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 at March 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 at March 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 at Zama . In late April, the Company acquired Duvernay lands and production directly offsetting its existing 61,000 net acre position in the Willesden Green area of Alberta for approximately $40 million in cash prior to adjustments. The acquisition is accretive on all key metrics and more than doubles Paramount'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 to May 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.

| _ | | | (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

Paramount's Board of Directors has approved a 25% increase in the Company's regular monthly dividend from $0.08 to $0.10 per Common Share. The first increased dividend will be payable on May 31, 2022 to shareholders of record on May 16 , 2022. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

UPDATED 2022 GUIDANCE AND PRELIMINARY 2023 BUDGET

The Company's planned 2022 capital expenditures have been upwardly revised by $20 million to a range of between $520 million and $560 million . The additional capital expenditures will be used to accelerate the drilling of a five-well pad at Karr from 2023 into late 2022 to facilitate further production growth in 2023. Paramount 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 Company continues to budget $33 million of abandonment and reclamation expenditures in 2022, net of approximately $8 million in funding under the ASRP.

Paramount is reaffirming its 2022 annual average sales volume guidance of between 91,000 Boe/d and 95,000 Boe/d (46% liquids).

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 $590 million to approximately $710 million to reflect higher commodity price assumptions and its updated capital expenditure plan. (1)

| | | | (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) $33 million in net abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $72.55/Boe (US$97.07/Bbl WTI, US$6.34/MMBtu NYMEX, $5.34/GJ AECO), (v) a $US/$CDN exchange rate of $0.793, (vi) royalties of $12.40/Boe, (vii) operating costs of $11.30/Boe and (viii) transportation and processing costs of $4.10/Boe. | | | |

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 US$50.00 /Bbl over the last three quarters of 2022. (1)

Paramount's anticipated 2023 capital expenditure budget, based on preliminary planning and current market conditions, has been upwardly revised by $60 million at the midpoint to a range of between $540 million and $580 million . The additional capital expenditures will largely be focused on accelerating development activities at Karr to grow production by approximately 4,000 Boe/d in 2023 to a range of 45,000 Boe/d to 49,000 Boe/d and set the stage for a new production plateau range of 50,000 Boe/d to 54,000 Boe/d in 2024.

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.

Paramount is updating its estimate of 2023 free cash flow that would be expected from such a capital program from approximately $580 million to approximately $820 million to reflect higher production and commodity price assumptions. (2)

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. Paramount now anticipates cumulative free cash flow through to the end of 2026 of approximately $4.1 billion , up from $3.3 billion . The Company now anticipates annual capital expenditures of approximately $550 million (up from $500 million ) and a compound annual production growth rate of approximately 7% (up from 5%) through the period. (3)

DELIVERING ON FREE CASH FLOW PRIORITIES

Paramount's free cash flow priorities are: (i) the achievement of its net debt target of about $300 million and the maintenance of conservative leverage levels thereafter, (ii) shareholder returns and (iii) incremental growth. Paramount has and will continue to deliver on these 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 in July 2021 of $0.02 per share and increasing it three times to $0.10 per share beginning in May 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) $40 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $63.80/Boe (US$87.88/Bbl WTI, US$5.04/MMBtu NYMEX, $4.48/GJ AECO), (v) a $US/$CDN exchange rate of $0.794, (vi) royalties of $12.05/Boe, (vii) operating costs of $10.60/Boe and (vii) transportation and processing costs of $3.80/Boe. | | (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 $40 million in average annual abandonment and reclamation costs, (iii) approximately $7 million in annual geological and geophysical expenses, (iv) strip commodity prices and foreign exchange rates as at April 21, 2022, and (v) internal management estimates of future royalties, operating costs, transportation and processing costs and, in 2026, cash taxes. | | (4) | Assuming 2022 adjusted funds flow in excess of $1 billion. | | | |

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Grande Prairie Region sales volumes and netbacks are summarized below:

| | 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 $ millions (%) _ | | 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 $10.6 million in respect of a contingent business interruption insurance claim. Refer to Note 12 in the unaudited Interim Condensed Consolidated Financial Statements as at and for the three months ended March 31, 2022. | | NM means not meaningful. | | | | |

KARR AREA

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 $ millions (%) _ | | 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. | | | | |

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 $6.9 million per well. Average gross peak 30-day production per well was 1,395 Boe/d (3.6 MMcf/d of shale gas and 802 Bbl/d of NGLs) with an average CGR of 225 Bbl/MMcf. (1) The Company continues to strive for improved efficiencies in its development activities to mitigate inflationary pressures on DCET costs without compromising completion effectiveness or health, safety and environmental performance. The 16-17 pad, as well as the Wapiti 9-22 pad, are the Company's first two pads to have been equipped with instrument air to operate all pneumatically driven controllers. Paramount plans to equip new pads with instrument air where possible to minimize methane emissions from its operations.

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. Paramount plans to bring onstream additional gas lift compression in the year to support liquids production and continue to build out infrastructure to debottleneck future production.

| _ | | | (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. | | | |

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 $ millions (%) _ | | 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 $10.6 million in respect of a contingent business interruption insurance claim. Refer to Note 12 in the unaudited Interim Condensed Consolidated Financial Statements as at and for the three months ended March 31, 2022. | | NM means not meaningful. | | | | |

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 March 31, 2022 includes $10.6 million in respect of the Company's business interruption claim arising from outages at the Wapiti Plant in 2020 and 2021.

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.

| _ | | | (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. | | | |

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.