BTE

Overall Strategic Direction

• The company’s core strategy is to grow production 6% to 8% annually, leverage existing heavy oil expertise, commercialize Duvernay development, reduce operating costs, and return capital to shareholders, with a long-term target of 15% annual total shareholder return at a mid-cycle WTI price of $70 per barrel.
• Two new directors (Derek Evans and Deanna Zumwalt) were appointed to strengthen the board with deep resource development and energy finance expertise aligned with the company’s strategy.

Heavy Oil Operations

• Average Q2 2026 total production hit 71,243 BOE per day, exceeding the high end of prior guidance and representing 11% year-over-year production growth.
• Activity at Peace River has resumed after spring breakup, with second half 2026 development on track. Four rigs are active across the heavy oil portfolio, with a fifth rig scheduled to start operations in Moranville in August 2026.
• Two initial waterflood pilots at Peavine are now active on injection, testing producer-to-injector conversion repressurization and new development pressure maintenance. Two additional waterflood patterns at Peavine and a Rex formation test in Moranville are scheduled to begin injection by Q4 2026.
• The 21-square-mile seismic program at Uticama is complete, and initial interpretations confirm the presence of the Kisco Mounds. Up to two exploration test wells are planned for early 2027, with a projected cost of approximately $2.5 million per well.

Duvernay Operations

• The first pad on the Gilby southern Duvernay acreage came online in June 2026. One well was completed at half lateral length after a stuck bottom hole assembly, but still delivered an IP30 of 866 BOE per day. These results strengthen confidence in the southern Duvernay development opportunity.
• The second Duvernay pad at north Pembina has been drilled, with completion operations underway and production on track to start in September 2026.
• The 2026 Duvernay program is on track, with 17 wells drilled, 13 expected online in 2026, and the remaining 4-well pad scheduled for completion and production in early 2027.

Capital Return and Balance Sheet

• Baytex repurchased 22 million shares for $136 million (average price of $6.27 per share) in Q2 2026, and declared a quarterly dividend of $0.25 per share payable October 1, 2026.
• Since the December 2025 sale of its Eagleford business, the company has repurchased 69 million shares (approximately 9% of outstanding shares) for $378 million, and has renewed its normal course issuer bid (NCIB) through July 1, 2027, allowing repurchase of up to 70.9 million shares. The company expects to complete $650 million in total share repurchases using Eagleford disposition proceeds.
• All pre-existing WTI hedges from before the U.S. asset sale rolled off at the end of Q2, and the company has no remaining WTI hedges in place. Given its strong net cash balance sheet, management does not anticipate entering new WTI hedges going forward.

• Full year 2026 production guidance was raised to 71,000 BOE per day, an increase of 1,000 BOE per day from the midpoint of prior guidance, with a targeted exit production rate of 72,000 BOE per day. The full year 2026 capital expenditure program is maintained at $625 million, with no changes from prior guidance.
• The Gemini Thermal project remains beyond the 3-year outlook, with management continuing technical and commercial work targeting a final investment decision (FID) in the second half of 2027.
• Full commercial Duvernay development is targeted for 2027, following the completion of 2026 appraisal activity.

Baytex Energy reports two core operating segments: Heavy Oil and Duvernay. No separate segment financial revenue breakdown was provided in the call. Consolidated Q2 2026 financial results are as follows: adjusted funds flow of $254 million (35 cents per share); net income of $175 million (24 cents per share), bringing year-to-date 2026 net income to $108 million (15 cents per share); free cash flow of $128 million (18 cents per share), up from $2 million in Q1 2026; operating net back of $55.33 per BOE, up from $35.36 per BOE in Q1 2026; total capital expenditure for the quarter was $122 million; the company exited Q2 with net cash of $566 million. Heavy oil delivered strong outperformance: 6 new Peavine wells achieved average IP30 rates of 478 barrels per day per well, outperforming internal expectations; 7 Manville wells were brought online at Lloydminster, with the company’s multilateral and circulation expertise delivering consistent results. The Duvernay segment delivered strong initial results from the first pad of the Gilby southern acreage: 3 of 4 wells achieved average IP30 rates of 1,630 BOE per day per well with 88% liquids, marking one of the company’s strongest length-normalized Duvernay results to date.

• The commercial viability of new waterflood pilots and Duvernay southern acreage development remains uncertain, as initial well results require more time to evaluate long-term production decline and recoverable reserves.
• The Gemini Thermal project faces uncertainty around subsurface characterization, updated capital cost estimates for small-scale modular SAGD facilities, and evolving regulatory frameworks for energy development in Alberta.
• Unhedged WTI price exposure: with no active hedges in place, the company’s adjusted funds flow is fully exposed to commodity price volatility; a $5 per barrel change in WTI impacts annualized adjusted funds flow by approximately $125 million.

Q: How opportunistic will management be with the $650 million remaining share repurchase program relative to share price, and has a substantial issuer bid (SIB) for accelerated buybacks been ruled out? / A: Management plans to maintain a steady daily repurchase pace of ~$2.5 million per day through the back half of 2026, relying on natural dollar-cost averaging inherent to fixed daily purchases, which automatically increases buys at lower prices and reduces buys at higher prices. Management has ruled out an SIB and will complete the program via the existing NCIB structure, which is tax-efficient and avoids the need to time the market.

Q: Do the strong initial Gilby Duvernay well results change development plans or imply upside to existing inventory assumptions? / A: The initial results confirm management’s pre-drill expectations for the quality of the southern Duvernay acreage, and included minor tweaks to completion design (higher proppant tonnage, adjusted cluster and perf designs) to test far-field reservoir drainage. It is too early to claim upside to inventory assumptions, as management needs more time to evaluate long-term production curve trends; there are no changes to the current 2026-2027 development plan.

Q: What cost improvements and completion innovations is management pursuing as Duvernay development moves toward commercial scale? / A: Baytex has driven consistent total drilling and completion cost (DCE) improvements, from $1,150 per foot in 2024 to a 2026 budget of $1,000 per foot, with a target of $900 per foot. Current innovation efforts include cluster/perf design tweaks to improve proppant placement efficiency, trials of on-site wellbore gas to power frac equipment, mud system processing improvements to reduce drilling costs, and water infrastructure expansion to reduce logistics costs for completion operations.

Q: What work remains to complete before a final investment decision on the Gemini Thermal project in H2 2027? / A: Three core workstreams are ongoing: further refinement of subsurface characterization and reservoir deliverability models; updating capital cost estimates to incorporate technological advancements in small-scale modular SAGD facilities developed over the past decade; and finalizing alignment with the evolving Alberta regulatory framework for new energy development. The project team has been expanded with three new full-time members to advance these workstreams.