Paramount Resources Ltd. press release

Paramount Resources Ltd. Announces Third Quarter 2021 Results, Updated 2021 Guidance, 2022 Capital Budget and Guidance and Increased Dividend

2021-11-04

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

Canada NewsWire

CALGARY, AB, Nov. 4, 2021 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce strong third quarter 2021 financial and operating results, upwardly revised 2021 guidance and its approved 2022 capital expenditure budget that is forecast to generate approximately $455 million in free cash flow in 2022 on production of between 90,000 Boe/d and 94,000 Boe/d (46 percent liquids). (1)(2) The Company is also pleased to announce a tripling of its regular monthly dividend from $0.02 to $0.06 per class A common share ("Common Share") effective November 2021 .

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Q3 2021 HIGHLIGHTS

Sales volumes averaged 82,150 Boe/d (45 percent liquids) in the third quarter of 2021. Cash from operating activities was $97.0 million in the third quarter. Adjusted funds flow was $148.4 million or $1.12 per basic share. (4) Free cash flow was $72.6 million . Third quarter capital spending totaled $68.9 million and was focused on drilling and completion activities at Karr, Wapiti and the Willesden Green Duvernay. Per unit operating costs continue to decrease and averaged $11.02 /Boe in the third quarter of 2021, down from $11.23 /Boe in the second quarter and $11.63 /Boe in the first quarter. Karr operating costs averaged $9.03 /Boe in the third quarter of 2021. Abandonment and reclamation expenditures in the third quarter totaled $6.9 million , net of $0.9 million in funding under the Alberta Site Rehabilitation Program ("ASRP"). The Company implemented a regular monthly dividend in July and repurchased 197,500 Common Shares under its normal course issuer bid ("NCIB") in the third quarter at an average price of $13.66 per share. Paramount closed the sale of its non-operated Birch asset for proceeds of approximately $85 million . The carrying value of the Company's investments in securities at September 30, 2021 was approximately $300 million , approximately $75 million higher on a quarter over quarter basis.

| _ | | | (1) | "Free cash flow" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section. See the "2022 Budget and Guidance" section for a description of the assumptions upon which the free cash flow forecast is based. | | (2) | 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 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, tight oil and light and medium crude oil. See also "Oil and Gas Measures and Definitions" in the Advisories section. | | (3) | Production measured at the wellhead. Natural gas sales volumes are lower by approximately 4% and liquids sales volumes are lower by approximately 9% 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. | | (4) | "Adjusted funds flow" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section. |

UPDATED 2021 GUIDANCE

Paramount expects fourth quarter sales volumes to range between 85,000 Boe/d and 86,500 Boe/d (45 percent liquids). As a result, full year 2021 sales volumes are expected to average approximately 82,000 Boe/d (44 percent liquids), achieving the high end of the previous guidance range of 80,000 Boe/d to 82,000 Boe/d, 1,000 Boe/d higher than the mid-point. The Company has added approximately $15 million of capital expenditures in the second half of 2021, which include additional activities at Wapiti to accelerate the achievement of targeted plateau production of 30,000 Boe/d into 2023 and further debottlenecking initiatives at Karr. Full year 2021 capital spending is now expected to be between $285 and $295 million . Paramount is forecasting 2021 free cash flow of approximately $215 million , an increase of $30 million from previous guidance. The increase reflects year-to-date actual results, updated sales volumes guidance and revised commodity price and other assumptions for the fourth quarter of 2021. (1) Year-end net debt to adjusted funds flow is forecast to be approximately 0.8x, below the Company's previously targeted range of 1.0x to 2.0x. (2)

| _ | | | (1) | The stated forecast is based on the following assumptions for 2021: (i) the midpoint of forecast capital spending and production, (ii) $25 million in net abandonment and reclamation costs, (iii) realized pricing of $47.55/Boe (US$67.63/Bbl WTI, US$3.94/MMBtu NYMEX, $3.59/GJ AECO), (iv) royalties of $4.60/Boe, (v) operating costs of $11.15/Boe and (vi) transportation and processing costs of $4.00/Boe. | | (2) | "Net debt" and "Net debt to adjusted funds flow" are Non-GAAP financial measures. See "Non-GAAP Financial Measures" in the Advisories section. The forecast of year end net debt to adjusted funds flow assumes the payment of a regular monthly dividend of $0.06 per Common Share commencing in November 2021 and the conversion of the Company's $35 million of convertible debentures into Common Shares in the fourth quarter of 2021. |

2022 BUDGET AND GUIDANCE

The Company's 2022 capital budget is expected to range between $500 million and $540 million , excluding land acquisitions and abandonment and reclamation activities, an increase of $165 million at midpoint from preliminary guidance. The budget includes the acceleration of approximately $70 million in activities at Wapiti, $60 million to advance a number of high return opportunities in the Kaybob and Central Alberta & Other Regions and additional growth capital that will primarily benefit 2023 production. 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.

Annual average sales volumes in 2022 are now expected to be between 90,000 Boe/d and 94,000 Boe/d (46 percent liquids), an increase of 6,000 Boe/d from previous preliminary guidance.

First half 2022 sales volumes are expected to average between 81,000 Boe/d and 85,000 Boe/d (44 percent liquids) after accounting for a planned 16-day full field outage at Karr for turnaround activities at third-party midstream facilities. Second half 2022 sales volumes are expected to average between 99,000 Boe/d and 103,000 Boe/d (47 percent liquids) as numerous wells are brought onstream related to capital activities initiated earlier in 2022.

Paramount is forecasting approximately $455 million of free cash flow in 2022, $135 million higher than the Company's prior preliminary guidance. (1)

The 2022 capital budget is broken down as follows at midpoint:

$290 million of sustaining capital and maintenance activities; $160 million of growth capital associated with production benefits in 2022; and $70 million of growth capital associated with production benefits largely in 2023.

The breakdown by region is as follows at midpoint:

Grande Prairie − $365 million ; Kaybob − $130 million ; Central Alberta & Other − $10 million ; and Corporate − $15 million

The Company has budgeted approximately $41 million for abandonment and reclamation activities in 2022. Approximately $8 million is to be funded directly through the ASRP, resulting in approximately $33 million net to Paramount. The majority of these funds will be directed to the Zama area.

| | | | (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) realized pricing of $53.70/Boe (US$74.44/Bbl WTI, US$4.35/MMBtu NYMEX, $3.95/GJ AECO), (iv) royalties of $6.65/Boe, (v) operating costs of $11.00/Boe and (vi) transportation and processing costs of $3.85/Boe. |

FREE CASH FLOW PRIORITIES

Paramount's free cash flow priorities continue to be (i) the achievement of targeted leverage levels, (ii) shareholder returns and (iii) incremental growth.

With strong 2021 performance and commodity prices, the Company expects year-end 2021 net debt to adjusted funds flow will be approximately 0.8x, below the previously targeted range of 1.0x to 2.0x. The Company is reducing its targeted long-term leverage level to approximately $300 million in net debt. This target is expected to be achieved in the third quarter of 2022, implying a net debt to trailing 12-month adjusted funds flow ratio of less than 0.5x at the end of that quarter. (1) Paramount implemented a regular monthly dividend of $0.02 per share in July 2021 and is tripling its monthly dividend beginning in November 2021 to $0.06 per share, implying a 10 percent payout ratio for 2022 and a 3.5 percent current dividend yield. (2) Remaining 2022 free cash flow will be available to:

Paramount has hedged approximately 23 percent of its 2022 midpoint forecast production to provide greater free cash flow certainty. With these hedges, the Company's 2022 capital program, targeted net debt reduction and $0.06 per share regular monthly dividend would remain fully funded down to an annual average WTI price in 2022 of approximately US$52.50 /Bbl with no changes to the Company's natural gas pricing assumptions.

PRELIMINARY 2023 GUIDANCE

Based on preliminary planning and current market conditions, Paramount anticipates 2023 capital spending, excluding land acquisitions and abandonment and reclamation activities, to range between $475 million and $525 million , broken down as follows at midpoint:

$330 million of sustaining capital and maintenance activities; and $170 million of growth capital.

The breakdown by region is as follows at midpoint:

Grande Prairie − $295 million ; Kaybob − $170 million ; Central Alberta & Other − $25 million ; and Corporate − $10 million .

| | | | (1) | The forecasted timing of achieving the targeted net debt level and net debt to adjusted funds flow assumes the payment of a regular monthly dividend of $0.06 per Common Share commencing in November 2021 and the conversion of the Company's $35 million of convertible debentures into Common Shares in the fourth quarter of 2021. | | (2) | Payout ratio is calculated as total annual dividends assuming a $0.06 per Common Share regular monthly dividend divided by forecast 2022 midpoint adjusted funds flow. |

A capital program in this range would be expected to result in 2023 annual average sales volumes of between 97,500 Boe/d and 102,500 Boe/d (48 percent liquids) and free cash flow of approximately $450 million . (1)

FIVE-YEAR OUTLOOK

To highlight Paramount's free cash flow and production growth potential, the Company is providing an initial five-year outlook through to the end of 2026. At current strip prices and subject to change as conditions evolve, the Company anticipates:

annual capital spending, excluding land acquisitions and abandonment and reclamation activities, of approximately $500 million ; a compound annual production growth rate of approximately 5 percent; and cumulative free cash flow of over $2.7 billion . (2)

Paramount had total tax pools of approximately $4.7 billion as of September 30, 2021 , including approximately $3.5 billion of immediately deductible non-capital loss and SR&ED pools. At current strip prices, the Company does not expect to pay Canadian income taxes within the next five years.

INCREASED DIVIDEND

Paramount's Board of Directors has approved an increase in the Company's regular monthly dividend from $0.02 to $0.06 per Common Share. The first increased dividend will be payable on November 30, 2021 to shareholders of record on November 15 , 2021. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

REDEMPTION OF CONVERTIBLE DEBENTURES

The Company has delivered notices to redeem all $35 million of its 7.5% senior unsecured convertible debentures, effective December 3, 2021 . It is expected that all holders will exercise their right to convert their debentures into Common Shares prior to the redemption date, resulting in approximately 5.3 million Common Shares being issued.

| _ | | | (1) | The free cash flow estimate is based on the following assumptions for 2023: (i) the midpoint of expected capital spending and production, (ii) $40 million in abandonment and reclamation costs, (iii) realized pricing of $48.55/Boe (US$67.39/Bbl WTI, US$3.56/MMBtu NYMEX, $3.28/GJ AECO), (iv) royalties of $5.95/Boe, (v) operating costs of $10.50/Boe and (vi) transportation and processing costs of $3.70/Boe. | | (2) | 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) strip commodity prices and foreign exchange rates as at October 22, 2021, and (iv) internal management estimates of future royalties, operating costs and transportation and processing costs. |

HEDGING

The Company's current hedging position is summarized below.

| | Type (1) | Q4 2021 | Q1 2022 | Q2 2022 | Q3 2022 | Q4 2022 | Average Price (2) | | Oil – WTI Swaps (Sale) (Bbl/d) | Financial | 10,000 | – | – | – | – | US$45.82/Bbl | | Oil – WTI Swaps (Sale) (Bbl/d) | Financial | – | 3,500 | 3,500 | 3,500 | 3,500 | US$75.79/Bbl | | Oil – WTI Swaps (Sale) (Bbl/d) | Financial | 6,000 | – | – | – | – | CDN$88.45/Bbl | | Oil – WTI Swaps (Sale) (Bbl/d) | Financial | – | 9,500 | – | – | – | CDN$87.90/Bbl | | Oil – WTI Swaps (Sale) (Bbl/d) | Financial | – | – | 3,500 | 3,500 | 3,500 | CDN$91.38/Bbl | | Oil – WTI Costless Collars (Bbl/d) | Financial | – | 7,000 | 7,000 | 7,000 | 7,000 | CDN$82.50/Bbl (Floor) | | | | | | | | | CDN$100.47/Bbl (Ceiling) | | Condensate – Basis (Sale) (Bbl/d) | Physical | 855 | 2,098 | – | – | – | WTI + US$3.13/Bbl | | Gas – NYMEX Swaps (Sale) (MMbtu/d) | Financial | 110,000 | – | – | – | – | US$3.37/MMbtu | | Gas – NYMEX Swaps (Sale) (MMbtu/d) | Financial | – | 40,000 | – | – | – | US$4.15/MMbtu | | Gas – AECO fixed price (GJ/d) | Physical | 116,848 | – | – | – | – | CDN$3.16/GJ | | Gas – AECO fixed price (GJ/d) | Physical | – | 40,000 | – | – | – | CDN$4.06/GJ | | Gas – AECO fixed price (GJ/d) | Physical | – | – | 30,000 | 30,000 | 10,109 | CDN$3.54/GJ |

| (1) Financial, refers to financial commodity contracts. Physical, refers to fixed-priced and basis physical contracts.

(2) Average price is calculated using a weighted average of notional volumes and prices. |

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Grande Prairie Region sales volumes and netbacks are summarized below: (1)

| | Q3 2021 | Q2 2021 | % Change | | | | Sales volumes | | | | | | | Natural gas (MMcf/d) | 148.0 | 134.3 | 10 | | | | Condensate and oil (Bbl/d) | 26,648 | 24,090 | 11 | | | | Other NGLs (Bbl/d) | 3,274 | 2,874 | 14 | | | | Total (Boe/d) | 54,586 | 49,345 | 11 | | | | % liquids | 55% | 55% | | | | | Netback | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | _% Change in $ millions _ | | Petroleum and natural gas sales | 275.8 | 54.92 | 217.7 | 48.47 | 27 | | Royalties | (20.5) | (4.08) | (15.3) | (3.40) | 34 | | Operating expense | (52.6) | (10.47) | (48.8) | (10.88) | 8 | | Transportation and NGLs processing | (22.5) | (4.48) | (21.4) | (4.76) | 5 | | | 180.2 | 35.89 | 132.2 | 29.43 | 36 | | | | | | | |

| | | | (1) | "Netback" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section. |

KARR AREA

Karr sales volumes and netbacks are summarized below:

| | Q3 2021 | Q2 2021 | % Change | | | | Sales volumes | | | | | | | Natural gas (MMcf/d) | 114.4 | 107.6 | 6 | | | | Condensate and oil (Bbl/d) | 18,328 | 18,458 | (1) | | | | Other NGLs (Bbl/d) | 2,477 | 2,281 | 9 | | | | Total (Boe/d) | 39,878 | 38,679 | 3 | | | | % liquids | 52% | 54% | | | | | Netback | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | _% Change in $ millions _ | | Petroleum and natural gas sales | 195.3 | 53.23 | 168.0 | 47.72 | 16 | | Royalties | (17.1) | (4.66) | (13.1) | (3.72) | 31 | | Operating expense | (33.1) | (9.03) | (33.1) | (9.40) | - | | Transportation and NGLs processing | (15.7) | (4.27) | (16.0) | (4.52) | (2) | | | 129.4 | 35.27 | 105.8 | 30.08 | 22 |

Third quarter sales volumes at Karr averaged 39,878 Boe/d (52 percent liquids) compared to 38,679 Boe/d (54 percent liquids) in the second quarter. Plateau production of approximately 40,000 Boe/d that was first achieved in March has been sustained through efficient and reliable operations, continued strong performance from the six-well 3-10 pad that first produced in February and new well production from the five-well 7-18 pad that came onstream in late-July. The Company continues to seek efficiencies in its operations while maintaining its focus on safety, asset integrity, reliability and environmental performance.

The 7-18 pad has outperformed internal type well projections, averaging gross peak 30-day production per well of 2,137 Boe/d (6.4 MMcf/d of shale gas and 1,076 Bbl/d of NGLs) with an average CGR of 169 Bbl/MMcf. (1) The Company projects that this pad will achieve payout approximately five months after coming onstream.

While remaining sharply focused on maintaining well performance, Paramount continues to realize lower than historical DCET costs despite experiencing certain inflationary pressures. Preliminary DCET costs at the five-well Karr 5-16 East pad that was brought on production in late-October 2021 averaged $6.3 million per well, approximately 15 percent lower than average DCET costs of the 5-16 West pad that was brought onstream in the fourth quarter of 2020. Drilling operations are ongoing at the twelve-well 16-17 pad and the Company expects that seven of the twelve wells will be drilled by year-end. The 16-17 pad was initially planned as a ten well pad, but two additional wells were added prior to the commencement of drilling.

Karr unit operating costs trended lower in the third quarter as a result of higher production volumes and the Company's continued focus on capturing efficiencies and streamlining operations. Paramount achieved operating costs at Karr of $9.03 /Boe in the third quarter of 2021, lower than targeted operating costs of $10.00 /Boe at plateau production of approximately 40,000 Boe/d. The Company also achieved a record netback of $35.27 /Boe at Karr in the third quarter.

In 2022, Paramount plans to maintain plateau production at Karr of 40,000 Boe/d by drilling 14 Montney wells and bringing onstream 16 wells, consistent with the Company's expectation that a total of 12 to 16 new wells per year are needed to maintain plateau production. The twelve-well 16-17 pad is currently being drilled and will be brought on production in two phases, with the first seven wells scheduled to come onstream in the second quarter of 2022 and the remaining five wells to come onstream in the second half of the year. Drilling of the four-well 1-2 North pad is scheduled to commence in the second quarter and the Company plans to bring all four wells onstream in late-2022. The Company also plans to bring onstream additional gas lift compression in the year to support liquids production as well as build out certain 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. |