U.S. natural gas prices will fall further, to $2.25/MMBtu, starting in 2021 as demand from Mexico and LNG export terminals levels off at the same time gas associated with Permian Basin shale oil wells crashes into gas coming from Appalachia, a team of commodity and equity analysts at Sanford C. Bernstein & Co. LLC predicted in a series of March 27 notes.
Winners in this low-price environment will be LNG exporters, such as Cheniere Energy Inc.; independent power plant operators; and petrochemical manufacturers. Losers will be gas-focused producers in the Haynesville and Marcellus Shales who are burdened with take-or-pay pipeline contracts, Bernstein said.
"Gas levered names, particularly those with significant debt loads, are likely to struggle as gas prices compress cash margins," Bernstein analyst Bob Brackett said. He downgraded Appalahcian gas drillers Chesapeake Energy Corp. to "underperform" and Range Resources Corp. to "market perform."
Bernstein's full prediction is for $2.75/MMBtu prices the rest of the year year, falling to $2.50/MMBtu in 2019 and 2020, then $2.25/MMBtu in 2021 and not recovering until 2025. The prediction is a sharp break from price forecasts by the U.S. Energy Information Administration, which has Henry Hub prices averaging $3.06/MMBtu in 2018 and rising to $3.66/MMBtu in 2021 and $4.07/MMBtu in 2025.
U.S. demand is being dictated by exports via overseas LNG or to Mexico, which flatten after 2020, Bernstein analyst Jean Ann Salisbury said in a separate note March 27. At the same time, 25 Bcf/d of "free" gas associated with Permian Basin shale oil wells comes on the market and competes with 30 Bcf/d of Marcellus and Utica Shale gas. Appalachian producers will be forced to produce gas at less than a nominal $2.50/MMBtu break-even price because they will need to fill the pipeline build-out that is happening now, Salisbury said.
"Associated gas growth continues to grow, unperturbed by gas price," Salisbury said. "This leaves almost no room for non-associated gas — we have the Marcellus/Utica plateauing at 30 Bcf/d and not even filling the 36 Bcf/d of total demand plus capacity that it will have by 2019."
In another note, Salisbury said she expects "healthy gas demand growth in the US, driven primarily by the startups of LNG liquefaction, ethane crackers, and Mexico power plants," through to 2020. "In our view, this wave of new demand growth ends abruptly in 2020. ... [I]t will be 2025-plus that we see the next wave."
Permian gas will cover all the minimal U.S. net demand growth during the hiatus, Salisbury said, leaving little room for gas from other basins. "This is bad for [Williams Cos. Inc.], which is effectively a play on gas volume" in the U.S. outside the Permian, Salisbury said. "Williams does have some demand-driven growth on [Transcontinental Gas Pipe Line Co. LLC]," but 50% of its EBITDA is related to gathering and processing services in other shale plays. "When we adjust for this in post 2020 growth it brings us to a market perform rating" for Williams, Salisbury said.
"The second way this could impact Williams, is through counterparty risk," Salisbury added. With natural gas prices in the low-$2/MMBtu range, Williams' biggest customer, Chesapeake, "will struggle to stay solvent," Salisbury said, putting pressure on Williams to renegotiate lower rates.
Upstream analyst Brackett was more sanguine about the pressures on Chesapeake, though he thinks Chesapeake needs average gas prices to be $3.25/MMBtu or more. "Chesapeake has a large asset base and has shown its ability to manage through a commodity price downturn through asset sales and debt exchanges," Bernstein said. "This debt management story does not allow for much of an equity bull case to be made but it does make a bankruptcy case more remote."
Cabot, Range and Southwestern are trading at values that reflect a $2.50/MMBtu environment and will perform in parallel with U.S. gas prices, Brackett said, noting that at $3/MMBtu, all three drillers have "significant upside." At a $2.25/MMBtu strip: "significant downside."