Karina Montoya was among the many Oxnard, Calif., residents who protested NRG Energy Inc.'s now-canceled gas-fired Puente power project at the site of its retired Mandalay Generating Station. California still faces major challenges to rid its grid of gas. |
This is the final installment of a five-part series exploring oversupply in the power sector and the factors driving a glut of natural gas-fired power plants.
On the northwestern edge of Greater Los Angeles, the gated communities of Malibu give way to the modest, largely Latino city of Oxnard, its pristine beaches marred by three natural gas-fired power plants plus a toxic Superfund site left by a scrap metal recycling operation.
This is where environmental activists, renewable energy advocates, city and state politicians, and finally energy regulators drew a line in the sand, forcing New Jersey-based power generation giant NRG Energy Inc. and Edison International utility Southern California Edison Co. in 2018 to abandon plans for yet another natural gas facility on California's South Coast. Instead, based on a reevaluation of the least expensive options, the utility plans to bolster the area's electric reliability with battery storage and new transmission.
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In the process, Oxnard and the broader L.A. region, the second-largest urban area in the United States, have emerged as the epicenter of California's clean-energy transition. As laid out in the landmark legislation former Gov. Jerry Brown signed as one of his final official acts, known as the 100% Clean Energy Act of 2018, California must boost its renewable energy purchases to 60% of retail electric sales by 2030, almost twice as much as in 2018, en route to total decarbonization by 2045.
But that does not necessarily mean phasing out all natural gas generation, the state's single largest source of power. The law's zero-carbon requirement does not apply to generation outside of retail sales, according to California energy agencies' disputed interpretation of the law, leaving what Southern California Edison sees as a small but "crucial" role for gas well into the future. To prevent extreme reliability or cost impacts, the law gives regulators the freedom to keep some gas plants on the grid, possibly setting up decades of wrangling over California's dream of ubiquitous carbon-free electricity.
"Don't strand us with the remnants of a soon-to-be-stranded industry," said Carmen Ramirez, a member of the Oxnard City Council, which unanimously objected to NRG's now-cancelled, roughly $300 million Puente Power Project at the site of its gas-fired Mandalay Generating Station, which shuttered in 2018. "Now, I realize there's a transition," Ramirez added, speaking from Oxnard City Hall, "but California has to be a leader for the world, and we are, so let's not leave anybody behind."
California clearly leads in shifting to renewable resources from fossil fuels to generate electricity, already besting its 2020 target of supplying 33% of the state's retail power with renewables by hitting an estimated 34% in 2018. Renewables on the state's primary power grid, operated by the California ISO, briefly neared 80% one afternoon in April 2019.
Such renewables-rich days, however, expose a growing paradox: When the sun sets and millions of solar panels power down, natural gas has become more critical than ever to cover peaking power demand. As a result, even as the Golden State embarks on its quest to purge carbon from the world's fifth-largest economy, it remains uncertain how the state and communities like Oxnard can turn off the natural gas generation that, for now, remains essential to keeping California's lights on.
As renewable energy installations surged in California over the past decade, a wave of new gas plants accompanied them, justified by reliability concerns. But the state has consistently overshot its needs. Reserve capacity, including imports, shot up to between 30% and 40% over peak demand from 2009 to 2018, according to information supplied in response to a California Public Utilities Commission records request, dwarfing the state's target reserve margin of 15%.
Yet, those excesses could soon swing to shortfalls because of shrinking imports and the planned retirement of a host of aging ocean-water-cooled gas plants in the next few years, along with the scheduled shutdown of the 2,240-MW Diablo Canyon nuclear facility, the state's largest power plant and source of carbon-free electricity.
S&P Global Market Intelligence forecasts the California ISO's reserve margin could fall to 15% by 2021, while the grid operator in August warned of a 4,700 MW capacity deficit in 2022.
On Nov. 7, the CPUC recommended that the State Water Resources Control Board extend the lives of nine retiring gas units at four facilities in Southern California by one to three years, including the 1,516-MW Ormond Beach Generating Station in Oxnard. Regulators also required electricity suppliers to procure 3,300 MW, excluding new fossil fuel-only capacity but allowing gas-battery hybrids and additions at existing gas facilities to compete with standalone batteries, solar-plus-storage plants and other resources.
The hurdles to getting off gas highlight the early elusiveness of the "exit strategy and phase-out timeline" the ISO board of governors called for two years ago. State officials embracing decarbonization are concerned.
"We need a plan. Otherwise we are just going to do it by the seat of our pants," said state Sen. Bob Wieckowski, whose bill to create a phase-out plan for natural-gas generation failed in the final hours of the 2018 legislative session after intense lobbying from fossil-fuel interests. "I get the industry doesn't like the element that we get together a plan of what a phase-out would look like … but the phase-out's going to occur anyway."
'We still need gas'
Accounting for over half of in-state capacity in 2018, natural gas remains the largest generating resource and source of greenhouse gas emissions on California's grid. Natural gas's share of the generation mix, including imported power, rose 2% last year, according to California ISO data, at least temporarily reversing its downward trend. Regulators fear that pulling the plug too early — before batteries and other peak power alternatives have proven capable on the massive scale required for a zero-carbon grid — could result in an emergency reminiscent of the 2000-2001 energy crisis, with its widespread blackouts and sharp price hikes.
"If we are not careful, we can drift into another energy crisis," former CPUC President Michael Picker warned in a 2018 report on the state's shifting energy landscape.
"We still need gas for renewables integration," CPUC member Clifford Rechtschaffen said in an interview. "We can't jeopardize reliability even though we know where we want to go in terms of long-term decarbonization."
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Underlying this discussion is the fact that California, with its abundant sunshine and aggressive clean energy policies, often has renewables in excess of what it can consume — until it does not have enough.
Midday solar-fueled surpluses are increasingly triggering cutbacks of available wind and solar energy, known as curtailments, and forcing generators to pay distributors to take electricity off their systems — a phenomenon known as "negative pricing." The state offloaded 37% more renewables through the first five months of 2019 than in all of 2018, setting records for idled renewable electricity, according to an S&P Global Market Intelligence analysis of California ISO data. The 630,864 MWh of cuts through May are more than many large solar plants generate in an entire year.
Later in the day, when the sun sets on the Pacific Ocean, California's more than 20,000 MW of utility-scale and distributed solar capacity disappears and other resources must take up the slack.
Despite progress on battery storage, flexible gas generation and hydroelectricity remain the go-to options when solar production fades. On Jan. 1, the grid operator hit a new high for resources required to ramp up within a three-hour period to offset lost solar generation, at 15,639 MW. Gas and hydro provided the lion's share, while batteries pitched in only 76 MW, grid operator data shows.
Larger energy storage volumes are coming, but not fast enough to keep pace with an expanding evening ramp that could exceed 20,000 MW by 2022, the ISO said in a May report. That raises the question of when, or if, it will be possible to shut down the hundreds of gas plants that continue to serve California's grid.
The grid operator sees batteries as part of a suite of tools to reduce California's oversupply and facilitate the grid's transition. But cost remains a concern. A 100% carbon-free grid in California would require "a massive amount of battery storage" and be "prohibitively costly" at more than $100 billion, Moody's estimated in a client note after Jerry Brown signed the Clean Energy Act.
'Living on a thread'
The legacy of the energy crisis nearly two decades ago, and the power shortages it brought on, helped produce the state's oversupplies of both gas and solar.
Past public utilities commissions led by Michael Peevey, a former utility executive who headed the CPUC from 2003 to 2015, resolved to avoid another energy crisis at almost any cost.
"Some degree of redundancy and over-reserve is not a bad thing," Rechtschaffen said. "We don't want to be way over-procured and way over-reserved, but better to be above [the reserve margin] than below it. We had a real energy crisis. It was a positive thing to avoid being vulnerable."
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But this can be an expensive justification, said David Olsen, whom Gov. Gavin Newsom in 2019 reappointed as chair of the California ISO's governing board.
"To hedge their bets they approved new gas-fired power plants at a time when we were adding renewables every year pursuant to the [state's renewable portfolio standard]," Olsen said. Regulators did so "even though it was clear that new gas generation would take our reserve margin beyond 25%, at considerable additional cost to California customers."
Many of those investments, especially facilities without long-term contracts, are struggling economically as renewables proliferate, reducing the hours the gas-fired power plants are used.
A 2017 report from the ISO said that nearly a quarter of the state's gas-fired fleet — almost 10,000 MW — is at risk of early retirement. The study came after La Paloma Generating Co. LLC, operator of a gigawatt-sized merchant gas plant in McKittrick, Calif., filed for Chapter 11 bankruptcy protection in 2016, blaming the state's "inhospitable" and "oversupplied" market.
"A number of these power plants are living on a thread," said Jan Smutny-Jones, CEO of the Independent Energy Producers Association, a long-time Sacramento-based lobbyist and former chair of the California ISO's governing board. "What keeps me up at night is you have too many plants operating under adverse financial conditions and at some point in time they all start making rational economic decisions and going, like, 'We're out of here.'"
Heeding such concerns, California has begun reforming how it procures resources and provides reliability, though the model remains in flux amid a sweeping transformation of the state's retail power sector.
In recent years, investor-owned utilities have ceded roughly 10 million customers to fast-multiplying local government-run community choice aggregators, or CCAs. The CPUC expects aggregators to seize 23% of utilities' customer base in 2019, based on electric demand, nearly quadrupling from 2017.
Most of those defections have occurred in the territory of Pacific Gas and Electric Co. — the state's largest utility, which is in Chapter 11 bankruptcy protection with its parent PG&E Corp. — and Southern California Edison. San Diego and a handful of nearby cities in September voted to form a CCA in Sempra Energy subsidiary San Diego Gas & Electric Co.'s service territory in 2021.
As CCAs spread, California regulators have expressed concern over grid reliability.
"We are pushing back on that," said Ramirez, the Oxnard city official who also chairs the energy planning and resources committee of the Clean Power Alliance, a CCA serving around 3 million customers in Southern California.
After a failed 2019 legislative attempt to create a state-run central buyer of capacity, which CCAs called a CPUC "power grab," the California Community Choice Association in August reached consensus with NRG Energy, Calpine Corp., Shell Energy North America (US) LP and other market participants on a similar proposal that they say better preserves "self-procurement autonomy."
Another potential reform, suggested by Olsen, is for the CPUC to encourage investor-owned utilities and CCAs to procure renewable energy through contracts that go beyond energy-only agreements.
"With less and less gas on the system, clean resources will soon have to provide a much larger percentage of essential reliability services," Olsen said. "We don't get any grid services from wind, solar or geothermal. That has to change."
Other side of the bridge
As its Spanish meaning implies, NRG once envisioned its now-canceled Puente power plant in Oxnard — a state-of-the-art, highly efficient peaker — as a "bridge" to a cleaner generation fleet. Instead, it became one of at least 16 proposed gas projects, representing more than $10 billion in planned investments, that developers have ditched since 2014.
"I don't have any good indication that California wants any more gas plants," acknowledged Chris Moser, executive vice president of operations at NRG Energy. "After Puente, I don't see any reason for that not to be the case."
Still, several new gas plants with long-term contacts have recently come online, and more are under construction.
NRG completed the 530-MW Carlsbad Energy Center, outside of San Diego, in December 2018. Also proceeding are W Power LLC's 98-MW Stanton Energy Reliability Center in Orange County, with 20 MW of energy storage, and two major AES Corp. combined-cycle gas projects combining for 1,284 MW as part of its $2.3 billion Southland repowering initiative.
With agreements that expire just ahead of California's 2045 deadline to complete the decarbonization of its grid, one of those facilities could be the state's last gas plant standing. However, they all will have plenty of gas left in the tank when that date arrives, whether California needs it or not, creating potentially stranded assets for the owners.
"We are very well aware of what the market risks are," said Ken Zagzebski, president of AES' U.S. strategic business unit.
Though it is the largest owner of gas plants operating and under construction in California, the Virginia-based company is also involved in major solar and storage projects. Fluence Energy LLC, a partnership with Siemens AG, is building a 100-MW battery system alongside AES' nearly 700-MW gas-fired Alamitos Repowering project in Long Beach.
AES is supportive of California's push for a carbon-free grid, but Zagzebski is skeptical about the time frame. "You don't place that big of a bet without a backup plan," he said. AES will have plenty of backup on offer.
Ramirez is hopeful that California will not need gas as midcentury nears. "Let's put our money where our mouth is," she said. A few miles from Oxnard City Hall is the shuttered Mandalay plant, and next door to Mandalay is Southern California Edison's McGrath Peaker Plant (Oxnard Peaker Plant), completed in 2012. A short distance down the beach is GenOn Holdings Inc.'s Ormond plant.
California's energy past, present and future are very visible in Oxnard, and Ramirez believes that the city's struggle to rid its shores of obsolete power plants holds valuable lessons for the entire state. "It's costly. It can be painful. We will need leadership at all levels."