Antero Resources Corporation (AR) Earnings

Management highlights

- **Strategic Shift and Structural Margin Improvements** • Management is transitioning the business from a producer-push market model (needing to transport product out of the basin to find demand) to a demand-pull model, driven by surging regional natural gas demand from new power and data center projects. This structural shift is expected to reduce cash flow volatility and permanently improve margins. • The company targets a 25% reduction in cash operating costs to $2 per Mcfe by the end of 2028, for a total of $300 million in annual margin improvement. This breaks down to: $90 million from expiring legacy financial transactions (overriding royalty interest and VPP), $105 million from optimizing natural gas firm transportation and increasing dry gas development, and $105 million from optimizing liquids firm transportation contracts. - **Dry Gas Drilling and Acquisition Updates** • After 12 years focusing on liquids development, Antero spud and completed its first dry gas pad in core Appalachian Marcellus acreage. Modern drilling and completion techniques delivered a 67% improvement in estimated ultimate recovery (EUR) to over 2 Bcf per thousand feet, and a 28% reduction in cost per foot to $900. Results exceeded internal expectations. Antero holds over 1,000 undeveloped dry gas locations, which management calls the largest undrilled Tier 1 dry gas position in the U.S. • The company closed $315 million in bolt-on acquisitions in its core West Virginia Marcellus footprint, adding 125 million cubic feet equivalent per day of immediate production and 15 new net drilling locations at a valuation of 4x EBITDA with a 20%+ free cash flow yield. - **NGL and Natural Gas Market Fundamentals** • U.S. LPG exports have hit record highs, driven by Middle East supply disruptions that increased global demand for U.S. product. U.S. propane exports averaged 2.03 million barrels per day in Q2 2026, with new weekly records set in May and July 2026, while normal butane exports hit a new monthly record in April 2026. China's LPG imports from the U.S. have rebounded from a 10% market share low to 51% in Q2 2026, and Chinese PDH petrochemical demand for LPG has increased 40% from April to July 2026 and is forecast to return to all-time highs. Additional LPG export terminal capacity coming online through 2027 will support further export growth, and Antero, as the second-largest U.S. NGL producer and unhedged on NGLs, is positioned to benefit from rising prices and demand. • Total U.S. natural gas demand is forecast to grow 42 Bcf per day by 2030, with 19 Bcf per day from domestic power and data center projects and 23 Bcf per day from LNG and Mexico exports. Antero's Appalachian Basin alone has over 9 Bcf per day of publicly announced regional demand from power projects (plus another 3 Bcf per day of unannounced projects), 6 Bcf per day of which are already FID or under construction. Antero's existing long-haul firm transportation portfolio gives it unique optionality to access an additional 7 Bcf per day of planned demand across the Midwest and South, allowing management to be highly selective and only participate in risk-adjusted accretive projects that compete with existing high-margin out-of-basin sales opportunities.

Guidance

- Total capital expenditure for 2026 is guided at $1.2 billion total, consisting of $1 billion for maintenance CapEx and $0.2 billion for growth CapEx. Current 2026 spending is tracking slightly above $1 billion, with full deployment of growth CapEx dependent on Henry Hub natural gas prices holding above $3 per MMBtu. - Cash operating costs are on track to reach the $2 per Mcfe end-of-2028 target, with approximately half of the targeted cost reduction already achieved as of Q2 2026. The $0.70 per Mcfe total cash cost reduction is partially offset by an expected $0.35 per Mcfe reduction in price realizations from increased in-basin sales, resulting in a net $0.35 per Mcfe margin improvement. - The $300 million annual margin improvement target by 2028 is conservative; management expects total margin improvements could reach $600-$700 million annually when extending the timeline past 2028. - The 50-50 natural gas sales split between out-of-basin long-haul and in-basin local sales is expected to be achieved gradually over a 5-year period.

Segment performance

Antero Resources operates two core product segments: natural gas and natural gas liquids (NGLs/liquids). In Q2 2026, overall adjusted EBITDA increased 57% year-over-year to a level that generated $220 million of free cash flow. Total company production hit a record 4.1 Bcfe per day, a 21% year-over-year increase, with an expected 2026 exit rate of 4.5 Bcfe per day (36% production growth since the start of 2025). Currently, the natural gas sales mix is approximately 2/3 out-of-basin (via long-haul firm transportation to the LNG fairway) and 1/3 in-basin/local sales, while 1/3 of total overall production is liquids and 2/3 is natural gas. The company targets a balanced 50-50 split of natural gas between long-haul out-of-basin and local in-basin sales over the next 5 years. NGLs (C3+) realized a record average price of $44.26 per barrel in Q2 2026, up $6.41 per barrel year-over-year, the highest quarterly price since 2022.

Risks & headwinds

- Geopolitical uncertainty around energy product transit through critical chokepoints like the Strait of Hormuz has created elevated VLGC freight rates, which creates short-term headwinds for U.S. LPG exports. Longer-term new vessel builds are expected to relieve this pressure by 2027-2028. - Proposed in-basin power and demand projects carry counterparty credit and execution risk. Antero requires credit assurance (such as letters of credit) for new in-basin contracts and only participates in projects with sufficient credit quality and execution certainty. - Deployment of 2026-2027 growth CapEx for dry gas drilling is dependent on natural gas prices holding above $3 per MMBtu. A sustained drop in natural gas prices would lead to delayed well completions and slower growth. - In-basin natural gas pricing realization may be lower than current forecasts, though the net impact on margins is still positive due to offsetting cost reductions.

Analyst Q&A

• Q: The analyst asks what criteria would make Antero more aggressive in signing long-term sales agreements for natural gas with new regional in-basin projects, and why a recent large local project did not attract Antero participation. /

  A: Management explains that Antero’s legacy long-term firm transport contracts are expiring, allowing the company to select the highest margin sales option from competing out-of-basin and in-basin opportunities. All new in-basin projects must match the returns available from existing out-of-basin sales on a risk-adjusted basis, meeting thresholds for price, timing, and execution certainty. The recent local project failed to meet these return hurdles, so Antero declined to participate.

• Q: With the stock trading in the mid-$30s and strong free cash flow potential ahead, has management elevated the priority of share repurchases for free cash flow allocation? /

  A: Management confirms share repurchases are now a higher priority at current valuation levels. In Q2 2026, Antero unexpectedly accelerated repurchases, buying 1.1 million shares for $38 million when the share price became attractive. Management notes that despite production up 21%, cash costs down 11%, liquids prices up significantly, and adjusted EBITDA up 57% year-over-year, the share price is unchanged from last year, making repurchases very attractive at current levels.

• Q: How is the 2026 CapEx outlook tracking for Antero's current 4-rig program, and when will additional growth CapEx be deployed? /

  A: The rig count will decline from 4 to 3 in the next month as one rig completes its current project. Total 2026 CapEx is tracking slightly above the $1 billion maintenance CapEx level, but has not yet reached the full $1.2 billion annual budget. Most remaining growth CapEx is for completion work scheduled for Q4 2026, and full deployment will depend on whether Henry Hub natural gas prices hold above $3. Management will make a final decision on deployment when the quarter approaches.

• Q: How should the market understand the offset between lower cash costs and lower price realizations in the cost optimization plan, and what does this imply for Antero's view on natural gas prices? /

  A: The offset does not reflect a bearish macro view. The dynamic comes from the shift to in-basin sales: buyers take on the cost of transportation when purchasing in-basin, so they pay a lower point-of-sale price, but Antero saves the full cost of transporting product out of the basin. The net result is a $0.35 per Mcfe net margin improvement after the offset, which management views as very attractive. This shift is a result of new demand-pull dynamics, where buyers are now actively seeking in-basin volumes, rather than an expression of market views.