Sun is setting on shale gas-driven pipeline building boom

As the energy transition gathers pace, mounting political and financial barriers to new natural gas pipeline infrastructure threaten to end the midstream industry's years-long spending and building boom.

Environmental, social and governance-oriented investors are pressuring companies that own and operate interstate gas transmission assets to decarbonize, just as many of their utility customers pledge to reach net-zero carbon emissions targets by 2050 to comply with state mandates.

ADDITIONAL COVERAGE: Natural Gas in Transition

While some pipelines may eventually be involved in transporting cleaner fuels, they will primarily deliver gas for decades to come, experts say. At the same time, pipelines facing difficulty renewing shipper contracts could become stranded assets, they warn.

Some supply-push pipelines built during the height of the shale boom are particularly vulnerable to falling out of use, according to S&P Global Ratings analyst Michael Grande.

"The contracts all came on in the 2010 timeframe," Grande said in a recent interview. "Down the road in 2019, 2020, contracts tended to roll off and be renewed at lower rates because the basins compressed so much, and there is just lower revenue."

One of these pipelines is Kinder Morgan's Ruby Pipeline, which connects Opal, Wyoming, and Malin, Oregon. Since the start of 2020, flows on the 1.5 million-Dt/d pipeline have not exceeded an average 1 million Dt/d, data from S&P Global Platts Analytics shows. Meanwhile, a firm transportation agreement with Anadarko Energy Services comprising nearly 17% of Ruby's reserved capacity is scheduled to expire in July, according to S&P Global Market Intelligence contract data.

In April, S&P Global Ratings downgraded the pipeline's issuer credit rating to CCC from B-, while Moody's in March downgraded the company to Caa1 from B1, with both agencies citing re-contracting concerns. "Lower renewal rates will result in weaker cash flows and credit metrics," Ratings wrote in an earlier downgrade.

Steel in the ground

North America's pipeline buildout isn't necessarily over yet — companies could add 33 Bcf/d of capacity from 2020 to 2025, according to a study funded by the INGAA Foundation, the research arm of the trade group representing the natural gas pipeline industry — but the hurdles to new construction are getting higher. Federal regulators are increasingly considering climate as a factor in pipeline permitting, and state-level barriers and environmental opposition have driven multiple project cancellations.

With midstream firms becoming more reluctant to lay new long-haul pipelines, operators with ample long-term, take-or-pay capacity see their infrastructure at a competitive advantage.

"The value of the pipe we have in the ground is increasing," said Al Monaco, Enbridge's president and CEO, said during a March panel at CERAWeek by IHS Markit. "You simply can't replicate this pipe in the ground, and it's going to be generating cash flow for a very long time."

For interstate gas pipelines that have guaranteed longevity, replacing 10% to 15% of those volumes with hydrogen and blending the two fuels for transportation is something management teams are considering. Existing gas pipelines are compatible with hydrogen blending at low volumes and low pressures, according to Platts Analytics. Lower pressure steel pipes are seen as the most likely to be converted in the early days of hydrogen blending.

Heavyweights Kinder Morgan, Enbridge and Williams have all expressed interest in exploring blending opportunities. Enbridge is already working on pilot projects involving gas distribution, where hydrogen blending is less problematic due to low-pressure gas flows. Hydrogen is most likely to compromise steel pipelines that operate at high pressure, making injection into certain interstate transmission lines more challenging.

Midstream and end-use infrastructure will be another major challenge for blending, according to Platts Analytics. Compressor stations, meters, natural gas turbines, furnaces, water heaters and gas burners will all need to be recalibrated or retrofitted to accommodate the higher burn speed and lower calorific content of hydrogen.

According to analysts at Sanford C. Bernstein & Co., the best gas transmission pipeline candidates for green-, or renewable-hydrogen, blending include Tallgrass Energy's Rockies Express Pipeline and TC Energy's ANR Pipeline, both of which are near potential supply sources.

"It appears to be more cost-effective if produced where the renewable generation is available if there is existing pipeline," the firm told clients Feb. 5. "Then ideally you would want the existing gas pipeline to go from a wind/solar nexus to a demand center. These analyses suggest the best locations for pipelines to exist are starting in Middle America and the American Southwest, and going to urban demand centers (California, the Gulf Coast, Midwest)."

Still, according to Platts Analytics, it could be difficult to convert entire pipelines to accommodate hydrogen-blended gas, since many of the distribution segments contain polymer-based materials that can cause leaking and pooling of combustible gas.

Financial and regulatory hurdles

Turning hydrogen blending into a reality would require significant financial investment.

For steel and iron-based pipelines, which can experience hydrogen embrittlement under high pressure, spray-in liners and doped steel can mitigate integrity concerns, according to Platts Analytics.

For newer pipelines, interior coatings could be a viable, cost-effective retrofit solution that would allow for transmission of hydrogen-blended gas, according to experts. For older pipelines, such as Panhandle Eastern Pipe Line, for instance, the cost of a retrofit could be prohibitively high. Per data released by the US Pipeline and Hazardous Materials Safety Administration in 2019, only 11% of the Energy Transfer-operated Panhandle Eastern gathering and transmission mileage was installed after 1970 – raising questions about how much additional upgrading might be needed to retrofit the pipeline for blending.

The system is also likely to continue flowing gas in coming decades given that customer Rover Pipeline, with purchased volumes that account for at least 20% of Panhandle Eastern's contracted capacity, only began full commercial service in 2018 – backed by its own long-term shipper agreements. Re-contracted capacity is not a central concern, according to S&P Global Ratings, which rates Panhandle Eastern's investment grade issuer-level credit at BBB-.

Energy Transfer has yet to join other large pipeline companies in pledging to evaluate hydrogen transportation opportunities. Earlier this year, though, the midstream operator moved to keep pace with the energy transition by announcing the launch of a new group within its partnership to develop alternative energy projects aimed at reducing its environmental footprint.

"We kind of scratch our heads around hydrogen," President and Chief Commercial Officer Marshall McCrea said in 2020.

Another potential issue for hydrogen blending is the problem it poses for federal regulation of pipeline rates, according to FiscalNote Markets Managing Director Katie Bays.

"It will require additional legislation because [the Federal Energy Regulatory Commission] does not currently have jurisdiction over anything related to hydrogen," Bays said in an interview. "To the extent that the commission wants to try, they probably could expand the scope of their authority in the Natural Gas Act to be inclusive of some policy related to hydrogen, but it would be extremely limited."

With hydrogen infrastructure lying outside of FERC's interstate gas transportation mandate, Bays added, "it's a very incomplete regulatory chain."

IHS Markit is subject to a merger with S&P Global pending regulatory and other customary approvals.