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 costs³ 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 margin⁴ and a 19% profit margin⁵, resulting in a 9% return on capital employed⁶ ("ROCE") and an 11% return on equity⁸ ("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%.

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 ratio⁷ 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.

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.