Financial Data and Key Metrics Changes - Adjusted funds flow was CAD 367 million or CAD 0.48 per basic share, with net income of CAD 152 million [8] - Free cash flow generated was CAD 3 million, with CAD 21 million returned to shareholders, including CAD 4 million in share repurchases and CAD 17 million in dividends [8] - Net debt decreased by CAD 96 million or 4% to CAD 2.3 billion, supported by a strengthening Canadian dollar [8][9] Business Line Data and Key Metrics Changes - Heavy oil production grew by 7% quarter over quarter, while production averaged 148,095 BOE per day, a 2% increase in production per share compared to the same quarter last year [6][11] - In the Pembina Duvernay, the first pad achieved average thirty-day peak production rates of 1,865 BOE per day per well, with a second pad averaging 1,264 BOE per day per well [11][12] - In the Eagle Ford, 15 wells were brought on stream, with an approximate 11% improvement in drilling and completion costs [13] Market Data and Key Metrics Changes - The commodity backdrop in Q2 was soft, with WTI averaging CAD 64 per barrel [6] - Approximately 84% of the company's production is weighted toward crude oil and liquids, indicating significant exposure to oil price fluctuations [16] Company Strategy and Development Direction - The company plans to transition to full commercialization in the Pembina Duvernay through 2026 and into 2027, targeting drilling 18 to 20 wells per year [12] - The focus remains on capital discipline, prioritizing free cash flow and reducing net debt, with a target of approximately CAD 2 billion in net debt by year-end [16] - The company is committed to rigorous capital allocation and regularly evaluates opportunities within its portfolio to maximize shareholder value [15] Management's Comments on Operating Environment and Future Outlook - Management expressed confidence in the quality of the asset portfolio and the ability to execute through volatile market conditions [15] - The company expects to generate approximately CAD 400 million of free cash flow in 2025, with the majority weighted to the second half of the year [16] - Every USD 5 per barrel change in WTI impacts annual adjusted funds flow by approximately CAD 225 million on an unhedged basis, positioning the company well for potential oil price recovery [16] Other Important Information - The company maintains substantial financial flexibility with CAD 1.1 billion in credit facility capacity, less than 25% drawn, maturing in June 2029 [9] - The average well cost in the Duvernay is CAD 12.5 million, with a target for lower costs over time [20][21] Q&A Session Summary Question: What is the average well cost in the Duvernay? - The average well cost so far this year has been CAD 12.5 million for a 12,000-foot lateral, which is approximately CAD 1,000 per completed lateral foot [20][21] Question: Should we expect a one rig program for 2026? - The company is targeting 12 to 15 wells in 2026, moving to a one rig levelized program in 2027, which will generate 18 to 20 wells per year [22][23] Question: Is the decline rate different post the refracs in Eagle Ford? - It is still early to determine decline rates, but initial rates and pressure performance are strong, indicating positive reservoir characteristics [24][25] Question: What improvements have been made in Eagle Ford? - Improvements are attributed to service cost reductions and efficiency gains, including the use of field gas instead of diesel for fracking operations [30][32] Question: Can you discuss the variability across the three wells in the Pembina Duvernay? - Performance across the wells is consistent, but there are differences due to rock and reservoir characteristics [37][39] Question: What is the expected infrastructure spending for Pembina Duvernay? - Infrastructure spending is expected to be CAD 25 million to CAD 30 million per year in the early years, with significant capacity already in place for gas processing [40][42] Question: How is the refrac program being layered in Eagle Ford? - The company intends to step up the pace of refracs, targeting 6 to 10 refracs in 2026 [43][44] Question: What is the hedging strategy going forward? - The company is targeting a CAD 60 floor for oil prices and aims to have 40% hedged by the end of the year [48][49]

Core Insights - Saturn Oil & Gas Inc. reported a significant net debt reduction of over $119 million in Q2 2025, achieving a total net debt of $694.8 million, which reflects a 15% decrease compared to Q1 2025 [2][5][6] - The company achieved record free funds flow of $93 million, supporting ongoing financial flexibility and shareholder returns [2][5][9] - Adjusted funds flow for the quarter was $109 million, representing a 23% increase compared to Q2 2024, with a per-share value of $0.56 [5][9][12] Financial Highlights - Petroleum and natural gas sales for Q2 2025 were $236.7 million, compared to $278.1 million in Q1 2025 and $208.9 million in Q2 2024 [8][37] - Cash flow from operating activities was $89.9 million, down from $165.4 million in Q1 2025 but up from $50.5 million in Q2 2024 [8][37] - Adjusted EBITDA totaled $131.7 million, a 24% increase over Q2 2024, resulting in a net debt to annualized quarterly adjusted EBITDA ratio of 1.3x [9][37] Operational Highlights - Average production for Q2 2025 was 40,417 boe/d, exceeding the high end of guidance and reflecting continued asset outperformance [5][15] - Operating costs were reported at $18.28 per boe, which was below the low end of guidance [5][10] - The company successfully repurchased $19.8 million of its Senior Notes at a discount, effectively reducing total liabilities and future interest obligations [6][11] Strategic Initiatives - The Saskatchewan government's elimination of the carbon tax is expected to yield annual operating cost savings of up to $20 million, which can be reinvested into the business [12] - The company has initiated a substantial issuer bid (SIB) to repurchase shares, with a total return to shareholders of approximately $24 million since August 2024 [9][13] - Saturn plans to continue its capital expenditures in Q3 2025, estimated between $80 million and $90 million, focusing on high-return drilling programs and production optimization initiatives [17][18]