Peyto Exploration & Development Corp. press release
Peyto Reports Strong Third Quarter Results and Preliminary 2025 Capital Program
TSX - Toronto Stock Exchange · Natural Gas · Natural Gas Liquids · Oil · Canada
CALGARY, Alberta, Nov. 12, 2024 (GLOBE NEWSWIRE) -- Peyto Exploration & Development Corp. ("Peyto" or the "Company") is pleased to report its operating and financial results for the third quarter of 2024 and a preliminary capital plan for 2025.
Highlights:
Delivered $154.3 million in funds from operations 1 , 2 ("FFO"), or $0.78/diluted share, generated earnings of $51.0 million, or $0.26/diluted share, and returned $64.7 million of dividends to shareholders. Production volumes averaged 120,031 boe/d (638.4 MMcf/d of natural gas, 13,626 bbls/d of NGLs), a 23% increase year over year, mainly due to the Repsol Canada Energy Partnership acquisition that closed in the fourth quarter of 2023 (the "Repsol Acquisition" or "Repsol Assets"). The 2024 drilling program on the Repsol Assets continued to deliver strong well results in the quarter including sustained increases to average well productivity of approximately 40% above Peyto's recent annual drilling programs. Production from the Repsol Assets has doubled from 23,000 to 46,000 Boe/d since the acquisition. The Company's disciplined hedging and diversification program protected third quarter revenues from the continued decline in AECO natural gas prices. Peyto's realized natural gas price for the quarter of $2.95/Mcf (or $2.57/GJ) was nearly 4 times the average AECO daily price of $0.65/GJ. The Company exited the quarter with a strong hedge position, which currently protects approximately 436 MMcf/d, 455 MMcf/d and 273 MMcf/d of gas production for the fourth quarter of 2024, calendar 2025, and calendar 2026, respectively, at an average gas price near $4/Mcf. The securing of future revenues supports the sustainability of the Company's capital program, dividends, and continued strengthening of the balance sheet. Currently Peyto’s fixed revenue for 2025 is approximately $790 million. Quarterly cash costs 3 totaled $1.44/Mcfe, including royalties of $0.18/Mcfe, operating costs of $0.54/Mcfe, transportation of $0.31/Mcfe, G&A of $0.03/Mcfe and interest expense of $0.38/Mcfe. Peyto's operating costs increased 4% from the second quarter of 2024 due to curtailed production volumes in the quarter and turnaround expenses but are on target to achieve a 10% reduction in the fourth quarter of 2024 from $0.55/Mcfe in the first quarter of 2024. Peyto continues to have the lowest cash costs of producers in the Canadian oil and natural gas industry. Total capital expenditures were $125.9 million in the quarter. Peyto drilled 21 wells (21.0 net), completed 19 wells (18.8 net), and brought 21 wells (19.3 net) on production. Facilities and pipeline projects totaled $26.1 million in the quarter, which included $7.5 million of turnaround costs, and multiple plant and gathering system optimization projects. Peyto delivered a 64% operating margin 4 and a 19% profit margin 5 , resulting in a 9% return on capital employed 6 ("ROCE") and an 11% return on equity 8 ("ROE"), on a trailing 12-month basis. The Company has set preliminary plans to spend $450 to $500 million in capital for 2025 and expects to add between 43,000 to 48,000 Boe/d of new production from the development program to offset base production decline estimated between 26–28%.
Third Quarter 2024 in Review
Peyto maintained a steady drilling and completion program through the third quarter but managed its production levels in response to weak natural gas prices by curtailing new production and shutting in base production at times when prices were weakest. While this resulted in a total payout ratio 7 greater than 100%, Peyto believes running a consistent program is an important factor that drives lower costs and improved capital efficiencies. Early in the quarter, the Company shut down the sour gas processing and Sulphur recovery units at the Edson Gas Plant ("EGP") which is expected to yield lower plant operating costs and increased reliability. Peyto also successfully completed a major turnaround at the EGP on the remaining sweet gas processing facilities to improve the life of this strategic asset. During the quarter, Peyto realized a natural gas price of $2.57/GJ, nearly 4 times the AECO daily average benchmark price of $0.65/GJ. Peyto's operating costs of $0.54/Mcfe were slightly higher in the third quarter due to the curtailment of production and non-capitalized costs associated with the EGP turnaround. The Company remains committed to its goal of reducing operating costs by 10% from first quarter levels by the end of 2024. Peyto’s disciplined hedging strategy, natural gas market diversification and low cash costs combined to deliver FFO of $154.3 million and earnings of $51.0 million in the quarter.
| | Three Months Ended Sep 30 | % | Nine Months Ended Sep 30 | % | | | | | | | | | | | 2024 | 2023 | Change | 2024 | 2023 | Change | | | | | | | | Operations | | | | | | | | | | | | | | Production | | | | | | | | | | | | | | Natural gas (Mcf/d) | 638,433 | | 520,504 | | 23 | % | 642,791 | | 530,418 | | 21 | % | | NGLs (bbl/d) | 13,626 | | 11,231 | | 21 | % | 15,309 | | 11,471 | | 33 | % | | Thousand cubic feet equivalent (Mcfe/d @ 1:6) | 720,186 | | 587,888 | | 23 | % | 734,643 | | 599,245 | | 23 | % | | Barrels of oil equivalent (boe/d @ 6:1) | 120,031 | | 97,981 | | 23 | % | 122,441 | | 99,874 | | 23 | % | | Production per million common shares (boe/d) | 612 | | 558 | | 10 | % | 627 | | 570 | | 10 | % | | Product prices | | | | | | | | | | | | | | Realized natural gas price – after hedging and diversification ($/Mcf) | 2.95 | | 3.33 | | -11 | % | 3.29 | | 3.46 | | -5 | % | | Realized NGL price – after hedging ($/bbl) | 69.61 | | 70.25 | | -1 | % | 66.11 | | 73.02 | | -9 | % | | Net Sales Price ($/Mcfe) | 3.93 | | 4.29 | | -8 | % | 4.25 | | 4.46 | | -5 | % | | Royalties ($/Mcfe) | 0.18 | | 0.29 | | -38 | % | 0.23 | | 0.33 | | -30 | % | | Operating expenses ($/Mcfe) | 0.54 | | 0.44 | | 23 | % | 0.54 | | 0.47 | | 15 | % | | Transportation ($/Mcfe) | 0.31 | | 0.29 | | 7 | % | 0.30 | | 0.27 | | 11 | % | | Field netback ( 1) ($/Mcfe) | 2.96 | | 3.29 | | -10 | % | 3.22 | | 3.42 | | -6 | % | | General & administrative expenses ($/Mcfe) | 0.03 | | 0.04 | | -25 | % | 0.05 | | 0.04 | | 25 | % | | Interest expense ($/Mcfe) | 0.38 | | 0.28 | | 36 | % | 0.37 | | 0.24 | | 54 | % | | Financial ($000, except per share) | | | | | | | | | | | | | | Natural gas and NGL sales including realized hedging gains (losses) ( 2) | 260,608 | | 231,938 | | 12 | % | 856,982 | | 729,679 | | 17 | % | | Funds from operations ( 1) | 154,343 | | 147,980 | | 4 | % | 513,802 | | 470,152 | | 9 | % | | Funds from operations per share - basic ( 1) | 0.79 | | 0.84 | | -6 | % | 2.63 | | 2.69 | | -2 | % | | Funds from operations per share - diluted ( 1) | 0.78 | | 0.84 | | -7 | % | 2.62 | | 2.66 | | -2 | % | | Total dividends | 64,707 | | 59,802 | | 8 | % | 193,229 | | 175,195 | | 10 | % | | Total dividends per share | 0.33 | | 0.33 | | 0 | % | 0.99 | | 0.99 | | 0 | % | | Earnings | 51,029 | | 57,444 | | -11 | % | 202,341 | | 204,840 | | -1 | % | | Earnings per share – basic | 0.26 | | 0.33 | | -21 | % | 1.04 | | 1.17 | | -11 | % | | Earnings per share – diluted | 0.26 | | 0.33 | | -21 | % | 1.03 | | 1.16 | | -11 | % | | Total capital expenditures ( 1) | 125,869 | | 93,579 | | 35 | % | 340,082 | | 297,701 | | 14 | % | | Decommissioning expenditures | 2,013 | | 1,026 | | 96 | % | 6,610 | | 1,026 | | 544 | % | | Total payout ratio ( 1) | 125 % | | 104% | | 20 | % | 105 % | | 101% | | 4 | % | | Weighted average common shares outstanding - basic | 196,077,193 | | 175,573,752 | | 12 | % | 195,183,132 | | 175,085,253 | | 11 | % | | Weighted average common shares outstanding - diluted | 197,051,764 | | 176,732,946 | | 11 | % | 196,395,465 | | 176,589,394 | | 11 | % | | | | | | | | | | | | | | | | Net debt ( 1) | | | | 1,362,947 | | 877,011 | | 55 | % | | | | | Shareholders' equity | | | | 2,735,586 | | 2,290,511 | | 19 | % | | | | | Total assets | | | | 5,589,573 | | 4,325,691 | | 29 | % | | | | | (1) This is a Non-GAAP financial measure or ratio. See "non-GAAP and Other Financial Measures" in this news release and in the Q3 2024 MD&A (2) Excludes revenue from sale of third-party volumes | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital Expenditures
Peyto drilled 21 wells (21.0 net), completed 19 wells (18.8 net) and brought 21 wells (19.3 net) on production for total drilling, completion, equipping and tie-in costs of $99.9 million in the quarter. Facilities and pipeline projects totaled $26.1 million in the quarter, which included $7.5 million for the second and final phase of the Edson Gas Plant turnaround, and several pipeline and plant debottlenecking projects across Peyto’s core areas. Peyto's drilling program featured 13 Notikewin (62%), 3 Wilrich (14%), 3 Dunvegan (14%) and 2 Falher (10%) wells including 10 wells (48%) drilled on the acquired Repsol lands. The results of the overall drilling program in 2024 show an average 25% sustained production improvement over recent past years. The improvement of productivity outcomes is partially attributable to the continued successful drilling program on the acquired Repsol lands which exhibit an average 40% increase over average legacy results. Production from the Repsol Assets has doubled from an initial 23,000 to 46,000 boe/d, the result of an active drilling program, despite the shut-in of approximately 2,000 net boe/d of low value Ethane recovery in the second quarter and the recent shut-in of 1,500 net boe/d of uneconomic sour gas production processed at the EGP. The Company’s focus on the more prolific Notikewin formation in the quarter led to a 10% reduction in overall well lengths. This lowered total average drilling costs per well by 3% but increased the average per meter costs by 8%. The better reservoir quality of the Notikewin allows for reduced stimulation requirements, lowering average well completion costs by 11% and average unit costs per horizontal meter by 6%. Drilling and completion cost history is summarized in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2023 Q1 | | 2023 Q2 | | 2023 Q3 | | 2023 Q4 | | 2024 Q1 | | 2024 Q2 | | 2024 Q3 ( 1 ) | | Gross Hz Spuds | | 135 | | 70 | | 61 | | 64 | | 95 | | 95 | | 72 | | 19 | | 15 | | 19 | | 19 | | 18 | | 20 | | 21 | | Measured Depth (m) | | 4,229 | | 4,020 | | 3,848 | | 4,247 | | 4,453 | | 4,611 | | 4,891 | | 5,198 | | 4,768 | | 4,728 | | 4,868 | | 5,220 | | 5,364 | | 4,804 | | Drilling ($MM/well) | | $1.90 | | $1.71 | | $1.62 | | $1.68 | | $1.89 | | $2.56 | | $2.85 | | $3.05 | | $2.74 | | $2.64 | | $2.94 | | $3.05 | | $2.89 | | $ 2.81 | | $ per meter | | $450 | | $425 | | $420 | | $396 | | $424 | | $555 | | $582 | | $587 | | $574 | | $559 | | $603 | | $585 | | $539 | | $ 585 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Completion ($MM/well) | | $1.00 | | $1.13 | | $1.01 (2) | | $0.94 | | $1.00 | | $1.35 | | $1.54 | | $1.73 | | $1.64 | | $1.38 | | $1.48 | | $1.80 | | $1.75 | | $ 1.56 | | Hz Length (m) | | 1,241 | | 1,348 | | 1,484 | | 1,682 | | 1,612 | | 1,661 | | 1,969 | | 1,947 | | 2,140 | | 1,853 | | 1,949 | | 2,223 | | 2,350 | | 2,224 | | $ per Hz Length (m) | | $803 | | $751 | | $679 | | $560 | | $620 | | $813 | | $781 | | $888 | | $776 | | $743 | | $759 | | $809 | | $744 | | $ 703 | | $ ‘000 per Stage | | $81 | | $51 | | $38 | | $36 | | $37 | | $47 | | $52 | | $59 | | $50 | | $46 | | $53 | | $55 | | $49 | | $ 48 | | (1) Based on field estimates and may be subject to minor adjustments going forward. (2) Peyto’s Montney well is excluded from drilling and completion cost comparison. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
In addition to the capital program, Peyto incurred $2.0 million on decommissioning expenditures in the quarter as part of the Company's responsible 2024 asset retirement plan, bringing the total to $6.6 million for the year to date. The Company also divested non-core land in Saskatchewan, which was acquired in the Repsol acquisition, for $1.0 million.
Commodity Prices and Realizations
In the third quarter, Peyto realized a natural gas price after hedging and diversification of $2.95/Mcf, or $2.57/GJ, 3.95 times higher than the average AECO daily benchmark of $0.65/GJ. Peyto’s natural gas hedging activity resulted in a realized gain of $1.31/Mcf ($76.8 million) in the quarter, due to the low-price environment at AECO and Henry Hub.
Condensate and pentanes averaged $101.18/bbl in the quarter, up 1% year over year, while Canadian dollar WTI ("WTI CAD") decreased 7% to $102.45/bbl over the same period. The Q3 2024 condensate and pentanes price included an adjustment for component balancing on shipped volumes in 2024, which increased the realized price in the quarter by approximately $4.50/bbl. Butane, and propane volumes were sold in combination at an average price of $28.73/bbl, or 28% of WTI CAD, down 12% from $32.47/bbl in Q3 2023. Peyto's combined realized NGL price in the quarter was $69.60/bbl before hedging, and $69.61/bbl including a hedging gain of $0.01/bbl.
Netbacks
The Company’s realized natural gas and NGL sales yielded a combined revenue stream of $2.77/Mcfe before hedging gains of $1.16/Mcfe, resulting in a quarterly net sales price of $3.93/Mcfe. Peyto's net sales price was 8% lower than the $4.29/Mcfe realized in Q3 2023 due to the continued decline in natural gas prices, partially offset by increased realized hedging gains. Cash costs totaled $1.44/Mcfe in the quarter, 4% lower than the $1.50/Mcfe in Q2 2024 due to lower royalties and G&A, which offset higher operating, transportation and interest costs. Operating and transportation costs increased to $0.54/Mcfe and $0.31/Mcfe in the quarter, respectively, from $0.52/Mcfe and $0.30/Mcfe in the second quarter of 2024, mainly due to Peyto curtailing production volumes in response to low natural gas prices. Peyto's cash netback (net sales price including other income, third-party sales net of purchases, realized gain on foreign exchange, less total cash costs), in a quarter with extremely weak natural gas prices, was $2.55/Mcfe resulting in a strong 64% operating margin. Historical cash costs and operating margins are shown in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | 2022 | 2023 | 2024 | | | | | | | | | | | | | | | | | | | | | | | | | | | | ($/Mcfe) | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 | | | Revenue (1) | 3.70 | | 2.92 | | 3.33 | | 4.42 | | 5.25 | | 5.48 | | 5.01 | | 5.74 | | 5.10 | | 4.07 | | 4.32 | | 4.83 | | 4.92 | | 3.97 | | 3.99 | | | Royalties | 0.29 | | 0.26 | | 0.36 | | 0.53 | | 0.60 | | 0.95 | | 0.70 | | 0.72 | | 0.53 | | 0.18 | | 0.29 | | 0.30 | | 0.24 | | 0.26 | | 0.18 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Op Costs | 0.36 | | 0.35 | | 0.35 | | 0.32 | | 0.41 | | 0.39 | | 0.38 | | 0.41 | | 0.50 | | 0.47 | | 0.44 | | 0.55 | | 0.55 | | 0.52 | | 0.54 | | | Transportation | 0.17 | | 0.22 | | 0.23 | | 0.23 | | 0.28 | | 0.27 | | 0.26 | | 0.22 | | 0.24 | | 0.29 | | 0.29 | | 0.26 | | 0.30 | | 0.30 | | 0.31 | | | G&A | 0.04 | | 0.05 | | 0.02 | | 0.02 | | 0.03 | | 0.02 | | 0.02 | | 0.02 | | 0.03 | | 0.05 | | 0.04 | | 0.06 | | 0.06 | | 0.06 | | 0.03 | | | Interest | 0.38 | | 0.33 | | 0.26 | | 0.22 | | 0.21 | | 0.20 | | 0.21 | | 0.21 | | 0.22 | | 0.22 | | 0.28 | | 0.40 | | 0.36 | | 0.36 | | 0.38 | | | Cash cost pre-royalty | 0.95 | | 0.95 | | 0.86 | | 0.79 | | 0.93 | | 0.88 | | 0.87 | | 0.86 | | 0.99 | | 1.03 | | 1.05 | | 1.27 | | 1.27 | | 1.24 | | 1.26 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Cash Costs 8 | 1.24 | | 1.21 | | 1.22 | | 1.32 | | 1.53 | | 1.83 | | 1.57 | | 1.58 | | 1.52 | | 1.21 | | 1.34 | | 1.57 | | 1.51 | | 1.50 | | 1.44 | | | Cash Netback 9 | 2.46 | | 1.71 | | 2.11 | | 3.10 | | 3.72 | | 3.65 | | 3.44 | | 4.16 | | 3.58 | | 2.86 | | 2.98 | | 3.26 | | 3.41 | | 2.47 | | 2.55 | | | Operating Margin | 67% | | 59% | | 63% | | 70% | | 71% | | 67% | | 69% | | 72% | | 71% | | 70% | | 69% | | 67% | | 69% | | 62% | | 64 % | | | (1) Revenue includes other income, net third party sales and realized gains on foreign exchange. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Depletion, depreciation, and amortization charges of $1.40/Mcfe, along with provisions for current tax, deferred tax and stock-based compensation payments resulted in earnings of $0.77/Mcfe, or a 19% profit margin. Dividends to shareholders totaled $0.98/Mcfe.
Hedging and Marketing
The Company has been active in hedging future production with financial and physical fixed price contracts to protect a portion of its future revenue from commodity price and foreign exchange volatility. The following table summarizes Peyto's hedge position for the fourth quarter of 2024, calendar 2025, and calendar 2026.
| | | | | | | Q4 2024 | 2025 | 2026 | | Natural Gas | | | | | Volume (MMcf/d) | 436 | 455 | 273 | | Average Fixed Price ($/Mcf) | 4.09 | 4.14 | 3.99 | | WTI Swaps | | | | | Volume (bbls/d) | 4,350 | 2,466 | 197 | | Average Fixed Price ($/bbl) | 101.11 | 97.91 | 92.59 | | WTI Collars | | | | | Volume (bbls/d) | 750 | 623 | 123 | | Put–Call ($/bbl) | 90.00–103.05 | 88.75–103.34 | 85.00–100.00 | | Propane | | | | | Volume (bbls/d) | 500 | 123 | - | | Average Fixed Price (US$/bbl) | 33.86 | 33.86 | - | | USD FX Contracts | | | | | Amount sold (USD 000s) | 62,000 | 245,000 | 116,000 | | Rate (CAD/USD) | 1.3421 | 1.3509 | 1.355 | | | | | |
In the third quarter, Peyto commenced its 15-year, 60,000 GJ/day gas supply agreement with the Cascade Power Plant and added 50,000 GJ/day of firm transportation service on the TC Energy mainline from Empress to Union Parkway Belt ("Parkway") in Ontario. This additional service uses a portion of Peyto’s existing Empress service and provides market exposure to a strong demand region. The service commenced on November 1, 2024 and has a 10 year term. The additional cost to access the Parkway market is approximately $1.00/GJ.
The Company's fixed price contracts combined with its diversification to the Cascade power plant and other premium market hubs in North America allow for revenue security and support Peyto's capital expenditure program, continued shareholder returns through dividends and debt reduction. Details of Peyto’s ongoing marketing and diversification efforts are available on Peyto’s website at https://www.peyto.com/Marketing.aspx .
Activity Update
Since the start of the fourth quarter, Peyto has continued with an active drilling program across all core areas with 9 wells (9.0 net) drilled, 8 wells (8.0 net) completed, and 12 wells (12.0 net) brought on production. The Company believes a steady capital program is a key factor in running efficient operations and reducing costs rather than starting and stopping activity during low commodity periods. Peyto reached a new monthly milestone of 130,000 boe/d for the month of October and continues to have minimal exposure to the AECO market with increased volumes diversified to other markets. The Company will continue, if prices weaken, to manage production and avoid exposure to low natural gas prices by restricting new well rates or delaying onstream timing.
In October, Peyto completed a second well in a newly discovered Falher channel that has recently been mapped across the Company’s legacy land position. The results to date from these wells have been excellent and the team has identified at least another 20 locations on Peyto lands. The discovery of this exciting new trend in the heart of an established development area serves as a reminder of the value of the stacked potential found in the Deep Basin and across Peyto’s lands.
Private Placement Issuance of Senior Secured Notes
Peyto is pleased to announce that it issued $75 million of senior secured notes on October 17, 2024. The notes have a coupon rate of 5.638% and mature on October 17, 2034. The notes were issued by way of a private placement pursuant to a note purchase agreement and rank equally with Peyto's obligations under its credit facilities and existing note purchase and private shelf agreement. Interest will be paid semi-annually in arrears. Proceeds from the notes have been used to repay the $65 million, 4.26% notes that were due May 1, 2025.