This is not how things were supposed to go.
When the world shut down for a pandemic two years ago and carbon emissions plummeted, environmentalists saw an opportunity to leap forward on climate goals by rallying around renewables and leaving oil and gas in the ground.
But Russia’s invasion of Ukraine brought a cold shot of reality to the Energy Transition timeline and raised an urgent new question with big implications for U.S. midstream markets: Just how much and how fast can U.S. natural gas free Europe from its reliance on Russian energy?
The answer will depend in large part on America’s ability to expand natural gas production and LNG exports, and government has already taken some early steps to loosen restrictions around the latter. But the breadth and pace of response will also be determined by the pipeline capacity available to transport natural gas from producing basins to the growing number of LNG liquefaction and export facilities along the U.S. Gulf Coast.
“This crisis has demonstrated the continued dependance of the world on fossil fuels, especially natural gas, and the inability to develop a satisfactory substitute in the short to intermediate term,” Kinder Morgan Executive Chairman Richard Kinder said during a quarterly call with investors in April.
“I anticipate that all of our present LNG export facilities will be running at capacity for the foreseeable future and the contracts necessary to support the construction of new facilities in the next few years will be more attainable than they’ve been in the past,” said Kinder, whose company moves about 50% of all natural gas to U.S. LNG export terminals.
LNG Surge
The surge of LNG expansion activity continued in March and April after the Ukraine invasion, as President Joe Biden promised the United States would deliver at least 15 Bcm in additional LNG to Europe this year than previously planned, with more to come in future years.
Prior to the February invasion, Refinitiv data showed natural gas supplies to U.S. LNG export plants had reached a record 13.3 Bcf/d. Venture Global, which started producing LNG at its Calcasieu Pass LNG plant in Louisiana in January, loaded LNG on its first commissioning vessel in February. Around the same time, Cheniere reported that its six liquefaction trains at its Sabine Pass plant were already operating near full capacity after their startup in November.
New Fortress Energy in March filed for federal approval of a new export project in federal waters off the Louisiana coast, which would be able to export about 2.8 million tonnes per annum (mpta) of LNG, or almost 400,000 Mcf/d of gas, using its “Fast LNG” technology.
Also in March, Cheniere announced that it contracted with Bechtel Energy for development of its 1.49 mtpa Corpus Christi Stage III Project, while Tellurian Inc. said it will begin construction of Phase 1 of its Driftwood LNG terminal, an export facility near Lake Charles, Louisiana. Phase 1 of the 27.6 mtpa Driftwood project would include two LNG plants with an export capacity of up to 11 mpta.
Basin Roulette
When demand for natural gas grew in pre-pandemic years, the Appalachian Basin offered virtually an on-demand tap for incremental production increases, with growth rates of roughly 3-4 Bcf/d per year. Not anymore. There’s still plenty of gas in the ground, but Appalachia’s prolific Marcellus Shale is located across state lines from Gulf Coast export facilities and permitting issues have effectively bottlenecked the region.
That leaves two major basins to meet most of the surging demand – the Permian Basin of West Texas and New Mexico and the Haynesville Basin of Northeast Texas and northern Louisiana, which both have the ability to deliver natural gas to LNG facilities on the U.S. Gulf Coast via intrastate pipelines, potentially streamlining permitting and construction.
Market dynamics vary significantly between the two regions, although their differences are less meaningful when both crude oil and natural gas prices are high.
Activity in the crude oil-dominant Permian Basin is driven by oil prices, with high rates of associated gas that must be piped, flared or stored as oil is produced. The Permian has dramatically expanded its crude oil takeaway capacity and added natural gas egress, as well, but gas pipelines are filling rapidly with higher demand and pricing.
As a predominantly dry gas basin, activity in the Haynesville shale has historically been limited by low natural gas prices, but its fortunes have reversed with higher prices and ever-increasing demand forecasts tied to nearby LNG plants.
“All things point to the Gulf Coast, and the Haynesville is optimally positioned geographically to benefit from this trend,” Eugene Kim, research director for Americas Gas Research at Wood McKenzie told P&GJ. “There are more low-cost well locations in the Northeast, but it’s very difficult to build the infrastructure to move it to market.
If production growth shifts from Appalachia to the Haynesville, as predicted, that means that the ramp-up will probably be slower and pricier. The accelerated response to global demand is extending to other some other U.S. regions, as well, but with lesser impact on midstream markets.
Some of the heaviest drilling activity over the past year has occurred within the Anadarko Basin, and some mature areas such as the natural gas liquids-rich Barnett Shale of North Texas are also regaining attention. But part of the attractiveness of such regions is largely due to their existing, underutilized infrastructure.
Haynesville Rising
At depths of 10,500 feet to 13,500 feet, wells in the Haynesville are deeper than in other plays, and drilling costs tend to be higher. By comparison, wells in the Marcellus in the Appalachian Basin are shallower – between 4,000 feet and 8,500 feet.
Haynesville natural gas production had declined steadily from mid-2012 until 2016 due to its relatively higher production cost but reached record highs in late 2021 and remained relatively strong in early 2022 on expanded pipeline takeaway capacity and higher demand.
Production reached 12.5 Bcf/d in November of 2021 and has been averaging about 12 Bcf/d since, accounting for about 13% of all U.S. dry gas production, according to the U.S. Energy Information Administration (EIA).
That growth was made possible by expanding pipeline takeaway capacity, including Midcoast Energy’s CJ Express pipeline, which entered into service in April 2021, and Enterprise Products Partners’ Gillis Lateral pipeline. The related expansion of Enterprise’s Acadian Haynesville Extension also entered service in December 2021.
Those three projects added 1.3 Bcf/d of takeaway capacity from the Haynesville area, raising its total estimated takeaway capacity to 15.9 Bcf/d, according to PointLogic. That figure suggests excess takeaway capacity out of the Haynesville is at or below 900,000 Mcf/d, or about 7% of total capacity.
In response, Energy Transfer has started construction of the 1.65 Bcf/d Gulf Run pipeline to move gas from the Louisiana Haynesville to the Gulf Coast. That project, which Energy Transfer gained via its acquisition of Enable Midstream in December 2021, is backed by a 20-year agreement with the $10 billion Golden Pass LNG export plant now under construction in Texas by QatarEnergy (70%) and Exxon Mobil (30%).
Energy Transfer has said it expects to complete Gulf Run by the end of 2022, and Co-CEO Marshall McCrea told analysts earlier this year that the Dallas-based company was making progress toward potential FID for its own LNG export project at Lake Charles in Louisiana.
As pipeline operators look toward intrastate pipelines as the fastest path to expansion, two distinct corridors are developing for egress from the Haynesville, with pipelines from the Louisiana side aimed at LNG facilities on the Louisiana coast and proposed projects from the Texas Haynesville targeting Texas LNG exports, along with increasing Permian volumes.
Williams has said it is considering a pipeline project that would connect the north Louisiana Haynesville with its Transco line to the south, while Kinder Morgan said it is evaluating a project to link the Texas Haynesville with LNG export points on the Texas side of the border.
Permian Expansion
There is no shortage of crude oil takeaway capacity from the Permian Basin after a multi-year expansion left the top U.S. oil play over-piped even before the COVID-19 crisis crushed global demand. The need for additional natural gas pipeline capacity from the Permian, however, is becoming more acute by the day.
The European crisis has placed a premium on speed as producers look for projects that can economically add the most capacity fastest. Earlier projections were for natural gas egress from the Permian Basin to become constrained by year-end 2023, but that now appears more likely to occur around the end of 2022, operators say.
The accelerated demand trend helped generate fresh competition for Kinder Morgan’s proposed greenfield Permian Pass project, which had come back into play after being postponed when demand plunged in 2020. Competing projects sought to differentiate themselves on time to market.
In early February, MPLX said on a conference call that it was seriously considering a 500,000 Mcf/d expansion of the Whistler Pipeline, a joint venture of MPLX, WhiteWater Midstream, WTG and Stonepeak. Whistler just began full commercial service last July with 2 Bcf/d of incremental natural gas transport capacity to Texas Gulf Coast markets.
“As we continue to extend up into the Midland Basin, we’ve essentially tapped out some of the existing capacity, and we’ll be looking to grow that capacity on Whistler overall,” said Timothy Aydt, chief commercial officer at MPLX. The project could come online in late 2023, he said.
Less than two weeks later, Energy Transfer announced that it, too, is looking to build the next natural gas pipeline out of the Permian, indicating that it could add 1.5-2 Bcf/d of transport capacity faster than Permian Pass by connecting a shorter, 260-mile pipe to an existing system that delivers gas to the Gulf Coast from Cushing, Oklahoma.
While not abandoning its Permian Pass project, Kinder Morgan has since proposed a faster-paced approach to add 1.2 Bcf/d of additional takeaway capacity via compression expansions on its Permian Highway and Gulf Coast Express systems.
“Compression expansions are low-risk from a siting and permitting perspective, and they are very capital efficient, though they do come with a higher fuel rate for the customer,” CEO Steve Kean said during an April investor call. “Most importantly in today’s environment, compression expansions allow for speed to market.”
Once it has contracts and makes a final investment decision (FID), Kean said, the company believes it can get to in-service within about 18 months.
“We believe the market will need that capacity in that timeframe and see one or both of these expansions as the near-term solution, pushing out our potential greenfield third pipeline (Permian Pass) further in time.
Broader Response
U.S. midstream markets were already rebounding before Russia’s invasion of Ukraine and the unprecedented NATO sanctions that followed, but with cautious and uneven impacts across the sector.
Service providers and equipment manufacturers who rely on pipeline construction activity for income have been slow to bounce back. Many are reporting that they’ve seen a growing number of tire-kickers in recent months, but that has not yet translated into significant sales growth. Some have been leaning into international markets.
Large pipeline operators, on the other hand, have been generating cash at or near record levels in recent quarters while limiting their capital spending and rewarding shareholders with stock buybacks and dividend increases.
Although project purse strings show some signs of loosening, operators are primarily looking at optimization or expansion projects, favoring brownfield additions over greenfield construction.
“All four of the projects that we have in the FERC queue right now are brownfield projects,” said Scott Hallam, senior vice president, Transmission and Gulf of Mexico at Williams, noting that its 820,000-dekatherm Regional Energy Access in Pennsylvania and New Jersey and every other project to be filed near-term are entirely within existing rights of way.
“What we really think about is how to leverage our footprint to minimize our environmental impact and continue expanding our capacity to meet downstream customer demand,” Hallam added. “So, I’d say it’s going to be a big percentage of what we see moving forward.”
