Antero Resources

Iran-backed Houthi rebels have taken control of the Bab al-Mandeb strait, according to several news reports. Also, last week, drone attacks damaged the critical East-West pipeline, forcing Saudi Arabia to shut it down.

Why it matters: The Bab al-Mandeb Strait is another critical Middle Eastern maritime chokepoint, aside from the Strait of Hormuz, while the East-West pipeline is a critical artery that crosses Saudi Arabia and connects it to the Red Sea. Saudi Arabia used both as a workaround to the current crisis. Before the war, roughly 4%-7% of global liquids moved through Bab el-Mandeb, though EIA estimates have shown that figure rose during the second quarter. Houthi control of this strait disrupts one of the world's major suppliers and heightens the risk of escalation. While we previously flagged that recovery was quicker than expected following the now-failed earlier Memorandum of Understanding between the US and Iran, we now believe something akin to our prior bear case scenario is more likely and that the disruption of flows will persist into 2027.

The bottom line: We aren't changing our $65 per barrel Brent midcycle oil price estimate, as stated in real terms, but we're far more concerned about near-term supply disruptions than we were previously. While Saudi Arabia can keep loading crude, it must rely on a thin storage cushion. How quickly flows normalize will depend on how fast Saudi Arabia can restore the pipeline. We've read that the country could partly restore the pipeline through one of its two lines, even as full repairs could take multiple weeks. But even so, Houthi control of the Red Sea will still hurt flows. We continue to model oil price futures in our next two-year assumptions as we have no edge over markets here. Long-term, however, we see greater opportunity in the gas supply chain in names such as Expand, Antero, and Baker Hughes, particularly as cheap Permian supply hurts gas companies.

We raise our fair value estimate to $52 per share from $42 after incorporating the most recent earnings release and increasing our assumed Henry Hub midcycle natural gas price to $3.70/mcf from $3.30/mcf. Growing demand for natural gas in the US, particularly from LNG exports and power consumption, drove the increase to our outlook. We expect US natural gas demand to grow from 107 bcf/d to 148 bcf/d by 2035, which will require higher-cost marginal supply.

We assume oil (West Texas Intermediate) prices in 2026 and 2027 will average $81 and $72 per barrel, respectively. In the same periods, natural gas (Henry Hub) prices are expected to average $3.10 and $3.49 per thousand cubic feet. Terminal prices are defined by our long-term midcycle price estimates (currently $65/bbl Brent, $60/bbl WTI, and $3.70/mcf natural gas).

Our fair value estimate corresponds to enterprise value/EBITDA multiples of 6.7 and 6.4 times for 2026 and 2027, respectively. Our production forecast for 2026 is 4,187 million cubic feet of gas equivalent per day. That drives our 2026 EBITDA forecast to $2.8 billion; we expect free cash flow of $1.7 billion in the same period. Our 2027 estimates for production and EBITDA are 4,539 mmcfe/d and $3.0 billion, respectively, buoyed by the HG Energy acquisition.

We don't believe Antero Resources has an economic moat. Breakeven pricing for natural gas is incredibly low for oil-focused companies. Oil producers enjoy low gas breakeven pricing because gas is a byproduct of production for them, called associated gas. It carries very little economic value to them, and they often must sell it at negative pricing within the basin to avoid regulatory flaring charges. So, this dynamic gives us low confidence in Antero or any Appalachian producer achieving a durable competitive advantage.

Hydrocarbons like oil, natural gas liquids, and natural gas are commodities, so they don’t exhibit pricing power, switching costs, or other moat sources that depend on differentiation or cornering a market niche. Antero primarily focuses on extracting natural gas and NGLs. It is the largest gas-focused producer of NGLs in the US, materially ahead of its next competitor.

For context, 1 barrel of oil equivalent is equal to 6 million British thermal units of natural gas, so if natural gas trades at $3.30/mmBtu at the Henry Hub benchmark and crude oil trades at $60/barrel West Texas Intermediate, oil is still 3 times more valuable than gas. E&Ps tethered to natural gas can overcome this disparity with superior unit economics, long-lived reserves, and narrow price differentials to leading benchmarks like Henry Hub.

Comparing gas-weighted companies with oil-weighted companies would be misguided. The macroeconomic drivers for the two commodities are mostly decoupled. Natural gas is a regional market dictated by local weather patterns, domestic storage inventories, and LNG export capacity, whereas oil is driven by global supply and demand. The severe seasonality of gas pricing forces gas-weighted producers to maintain aggressive hedging books, with some carrying books with greater than 50% of yearly volumes hedged. These hedges allow the firm to have a clearer view on their production programs throughout the year, leading to more stable cash flows. Importantly, as oil production grows in the US, so does natural gas production in the form of associated gas, which undercuts the economics of gas-focused producers.

While we believe Antero has an attractive portfolio of Marcellus assets that carry a heavier NGL mix than the typical gas player, NGLs are about in the middle of natural gas and oil pricing on a boe basis. Most of these NGLs go out of the Marcus Hook port in Pennsylvania, while 75% of its gas heads south to the Gulf Coast. Gulf Coast pricing, though more attractive than in-basin, is associated with a high transportation price tag.

The cost-of-service contract differences and transportation distance show up in this company’s gathering, processing, and market transportation costs. GPMT costs represent the entire cost of the physical supply chain to move molecules from the well to the market. These costs are typically lower for streams of dry gas (gas without NGLs in the mix) than wet gas, which includes the added steps of fractionation and, in many cases, cryogenic cooling. Antero Resources contracts almost exclusively with its Antero Midstream counterpart for gathering and processing services. AR owns 29% of AM’s common units outstanding. AM’s only material client is AR, so a portion of the GPMT fees that AR pays are effectively rebated. In periods of growth, the relationship between the two entities can be advantageous. They have been known to negotiate to lower GPMT costs if AR can grow production. Still, in business-as-usual markets, the costs for GPMT paid to the midstream can be a disadvantage in comparison to other Appalachian gas producers.

The contracts struck with third parties for long-haul transportation are typically take-or-pay, meaning the producer pays the pipeline operator regardless of utilization. Agreements for interstate pipelines are rate-regulated on a cost-of-service basis and generally last more than a decade, sometimes more than 20 years.

Antero also sits squarely near the median of inventory life in its peer group, with almost 25 years of proved and probable reserves. A longer inventory life typically reduces exploration uncertainty and mitigates the need for risky acquisitions. Currently, we don’t model any M&A activity for Antero in our base case, though with a shorter inventory life than leading peers, it's reasonable to assume Antero will pursue M&A past our explicit forecast period, leading to less confidence in its ability to generate excess returns. In its public company history, Antero has only pursued roughly 3.2 billion in inorganic growth, not including asset sales.

Like other gas E&Ps, Antero’s moat rating depends on what we assume is a midcycle price for natural gas, which we peg at $3.30 per thousand cubic feet to assess Antero’s prospects. We would need to see Antero significantly lower its cost structure before awarding a narrow moat rating. Antero is committed to many long-haul pipeline projects, which ensures it will have out-of-basin pricing for its production. We believe it is overcommitted to these agreements, contributing to an elevated cost structure. Contracts for long-haul transport begin rolling off in 2032 through 2035, so we do not see this structure improving materially within our forecast horizon.

Given the robust fundamentals for natural gas demand over the coming decade (data centers, power, LNG exports, petrochemicals, heating), we see Antero as a marginal-cost US natural gas producer, only earning its cost of capital over the long run.

Antero's long-haul transport contracts give it priority access to LNG export markets, enabling it to benefit from soaring overseas demand for US natural gas.

The firm's liquids-rich drilling inventory will enable it to outperform peers if NGL prices remain constructive, as we expect.

Antero's partial ownership of its midstream counterpart gives it favorable bargaining power, leveraging fully integrated power and water supply deals with data centers in the region.

Antero's margins are weakened by above-average unit costs, driven by less favorable contract structures on transportation.

Takeaway constraints in Appalachia do not affect Antero's realized prices, but they do limit how fast the company can expand its output.

The acquisition and integration of HG Energy may fail to deliver the required synergies and distract management.