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Mixed signals from regulators, crumbling infrastructure create Calif. gas morass


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Mixed signals from regulators, crumbling infrastructure create Calif. gas morass

California needs lots of natural gas — and the infrastructure to deliver it — but perhaps only to 2045.

That mixed message was one of the dominant themes at a Los Angeles natural gas industry conference in which multiple speakers mused on of the opportunity for the home-heating and power-generation fuel in the state, and also of challenges that range from delivery constraints to regulatory opposition.

As Rachel Peterson, chief of staff to California Public Utilities Commission member Liane Randolph told the gathering, changes to insure electric grid reliability in the state "will in all likelihood lead to multi-year contracts with natural gas-fired power plants." Moments later, she warned: "I think that under some futures there would not be a role for natural gas power plants in say, 2045-2050."

California aims to get all of its power from zero-emitting sources within three decades, although that goal is highly dependent on advances in technology, particularly in power storage. Along the way it will drop nuclear plants that provide a large portion of the state's baseload electricity supply and limit imports of power from neighboring jurisdictions to zero-emission sources. In its plan to rely on natural-gas generators, regulators must grapple with gas storage and infrastructure issues along with luring operators to the state.

PG&E Corp.'s San Bruno pipeline explosion in 2010 and Southern California Gas Co.'s Aliso Canyon storage leak in 2015 sent state utilities to regulators for rate increases to improve the safety of infrastructure in their local distribution companies. And the limits on Aliso Canyon's storage operations created unforeseen stress on California's aging intrastate transmission infrastructure as the utilities, and SoCalGas in particular, have been forced to rely more heavily on imports, Laird Dyer, an independent energy analyst, told the LDC Gas Forums Rockies and West conference Oct. 9.

"They couldn't pull anything out of storage so they needed to import higher quantities of gas at times on their import lines. So that's import stress. In Sept. 2017 that stress culminated in the pipeline explosion on Line 235 and [Line] 4000," said Dyer, who has testified as an expert witness on gas issues at the CPUC. "They're still offline and there's no indicated date when they will be returned to service."

SoCalGas, which is owned by Sempra Energy, has said it could have Line 235 back in service by mid-April, 2019. The 2017 explosion also forced the shutdown of adjacent and much-larger Line 4000. While that line was restarted, it has been operating at about 270 MMcf/d compared with its full capacity of 700 MMcf. Those constrictions, along with closures forced by loss of right of way and other outages mean the utility has "lost roughly a third of their import capacity [and is] operating at 2.4 Bcf/d." Aliso Canyon, which had provided a backstop during both summer and winter peaks, is now restricted to a capacity of 34 Bcf from its pre-leak capacity of about 86 Bcf, dropping SoCaGas's storage capacity to about 87 Bcf from 137 Bcf. "Your vulnerability right now is for more outages," Dyer said. "We don't know … what SoCalGas will have as import capacity."

'It's probably going to require infrastructure'

Import capacity and service area storage are vital to meeting demand from natural gas-fired generators, Kinder Morgan Inc. Vice President Will Brown told the conference. Where midstream operators once set service goals of steady supply while filling storage to meet demand, backstop power generation is needed quickly and at any time renewables may not be available. The Houston-based pipeline giant is responding by exploring hourly service and "in-market" gas storage to meet the sudden spikes, Brown said.

"It becomes increasingly important for natural gas-fired generation to follow this load as renewable firming to insure that grid resilience for reliability," he said. "Maybe instead of having a rateable product, we also offer three-hour, eight-hour, 16-hour [products]. There might be a different product in the market and we would be happy to work with our customers on that. With that being said, it's probably going to require infrastructure. But we stand ready to work with our customers to build infrastructure to meet the needs of that load."

Biogas use increasing

Biogas, methane produced from garbage dumps and human or animal waste, is gaining traction as another option in the California market, particularly for use as a transportation fuel, according to John Armstrong, vice president of global environmental products at BP PLC. The fuel is considered emissions-neutral, leading to a limited but growing market of producers and buyers hungry for environmental credits, Armstrong said. "Once you generate the environmental currency, there is demand for it from those obligated parties," he said. "That is a method by which they meet their compliance obligation."

Depending on credits assigned to biogas that are determined by its source, the fuel can ultimately fetch between $8/MMBtu and $52/MMBtu. Recouping production costs makes it necessary for plant owners to have long-term contracts for their output, which results in a tight market. "There is no biogas sitting on the sidelines today," he said. "If a project has been built, then that project is encumbered."

Pipeline operators are slowly warming up to the idea of having biogas on their systems, although reaching that point has required extensive testing and, in the case of California, overturning a law. "There are still utilities out there that are reluctant to accept biogas into the system until they get a feel for what is happening around the U.S. … You're seeing more openness to allowing biogas to be injected into their systems," Armstrong said.

Electricity storage, either through battery banks or other devices, could forestall the need for new gas-fired plants, although participants at the conference generally agreed that a viable, dispatchable energy source has not yet emerged even as the cost of renewables, particularly solar, has decreased. "The cost of solar is dropping, but in terms of adding in solar-plus-battery, that doesn't work unless the cost of implementation and battery size is half what it is today," S&P Global Platts Managing Director Teri Viswanath said.

The CPUC's Peterson said the commission's stance on gas-fired power is it is a "pragmatic and affordable" way to insure grid reliability. "Right now, there is no viable, affordable replacement for the narrow service that natural gas-fired plants play today," she said. "But over time, with advances in other technologies such as energy storage, such as distributed energy resources that can respond to local conditions, perhaps we'll start to see the moments in time when there can be a credible alternative to that role."

S&P Global Platts and S&P Global Market Intelligence are owned by S&P Global Inc.