Editor's Note: This article is part of a series on the key issues driving the utility sector today. All stories in this series can be found here.
California is often at the forefront of national energy trends. In 2013, it was the first state to put an energy storage mandate in place. This May it became the first state to require that all new homes come equipped with solar panels.
The state is also a place where gas-fired generation is struggling, getting pushed out of the market by low-cost wind, solar and hydro power. Renewable penetration in California is high because of the state's aggressive environmental policies, but as more states turn toward fossil fuel alternatives, could gas-fired generation's fate in California echo throughout the country?
"The short answer is 'yes,'" Art Holland, vice president with Pace Global Energy Services, a Siemens business, told Utility Dive. "The only question ... is how long will it take, and that is a huge uncertainty."
"There is at least one scenario in which the last combined-cycle gas turbine could be built in the next seven to 10 years."
Art Holland
Vice president, Pace Global Energy Services
In the short to intermediate term, Holland says there could even be an increased reliance on gas-fired generation as coal and nuclear power plants continue to retire. But as more renewable and distributed generation enter the market, there is a good chance the role of gas could shift from baseload to quasi-baseload.
"There is at least one scenario in which the last combined-cycle gas turbine could be built in the next seven to 10 years," Holland said, especially if energy efficiency and demand response continue to erode demand and renewable generation continues to grow.
"You are already seeing that in the West. You can't build a combined-cycle plant in California, and that trend could roll out for the rest of the country."
Gas-fired generation is already facing challenges in Texas where wind power can often set the clearing price in the wholesale power market. Further east, the concept that gas-fired generation could be a bridge to a renewable future has more credence because renewable penetration is not as high, but the lessons from California are still instructive.
California: Where gas goes to die
The challenges California's gas-fired generators are facing was highlighted in Pacific Gas & Electric's recent proposal to the state's Public Utilities Commission (CPUC) to replace three gas-fired plants with 569 MW/2,270 MWh of energy storage.
Calpine, the owner of those plants, has said they cannot operate economically in California's wholesale market and has asked for and won reliability must run (RMR) contracts from the California ISO.
In March, NRG Energy lost the battle to keep three gas-fired plants in Southern California running. NRG, like Calpine, cited the economic challenges its plants face.
The striking thing about those gas plants is that many of them, like Calpine's Metcalf plant in San Jose, are not particularly old but are of recent vintage, state of the art gas-fired combined cycle plants. If these plants can't compete in the market, their ilk could become obsolete, which is what's happening to nuclear and coal in California and elsewhere.
"Generally, most gas plants in California are having difficulty, especially combined-cycle plants," which are designed to run as baseload plants, that is, on a continual or nearly continual basis, Steven Kelly, director of policy at the Independent Energy Producers Association (IEPA), told Utility Dive.
At first glance, it may appear that renewables are winning the generation battle in California. They are outcompeting gas plants in the wholesale market. But a closer look reveals a more complicated picture.
California's wholesale energy prices are low because an abundance of no-fuel cost renewable generation in the power market keeps the clearing price low. But renewable generation resources don't bid directly into the California ISO's day-ahead energy market. They sign long term offtake contracts with utilities, which then schedule that output into the ISO, presumably at prices low enough to ensure the resources are dispatched. The actual price the renewable resources are paid is stipulated in the confidential contracts with utilities.
In addition to energy market sales, thermal resources, like gas, coal and nuclear can also sign bilateral Resource Adequacy (RA) contracts, which serve as the basis for California's capacity market, but are only a year in length, as opposed to renewable contracts, which can extend up to 20 years.
Generators in the RA market are getting enough money for one year, but then get "stuck with relatively significant O&M costs without a mechanism to recover those costs" because RA contracts are not designed to cover longer terms costs, Kelly said. "Those units get stranded" and are faced with having to retire unless they can secure an RMR contract with CAISO.
"In the near term, capacity from natural gas power plants is still needed to undergird our electric system, and some entities are having trouble procuring it via the market."
Liane Randolph
California PUC Commissioner
One potential exception is the slew of once-through-cooling (OTC) plants that will be forced to either retrofit or close to comply with new regulations. The PUC is offering 10 year contracts to some of those plants.
The prospect of a large portion of California's gas-fired generation fleet being forced into retirement has raised alarms. The fact that some utilities are having trouble meeting their RA obligations while generators like NRG are closing plants because they cannot earn sufficient revenues in the market points to a problem, PUC Commissioner Liane Randolph wrote in an opinion article for Utility Dive last June.
"In the near term, capacity from natural gas power plants is still needed to undergird our electric system, and some entities are having trouble procuring it via the market," she wrote. "If the market-driven Resource Adequacy process is not delivering sufficient returns to provide incentives for critical resources … to continue operating, then it is our job to redesign the market — or develop administrative alternatives," she said.
In June, the commission took steps to address the problem by extending the term of the obligation for local RA needs from one, to three to five years.
Local RA obligations are one of three forms of RA obligations. The others are flexible and system obligations. IEPA has filed with the CPUC seeking extensions on all three RA obligations.
Whether or not that happens, "there will be bridging," Kelly said, referring to the concept of gas-fired generation providing a "bridge" to a renewable future. "But we don't know how long it will take," he said. "You can't just eliminate all the flexible capacity needed to support intermittent resources. If you do, the state will go broke buying storage."
While gas is facing challenges in California, what applies in the Golden state does not always hold true in other states, at least not right away. In many markets, gas-fired generation has overtaken coal-fired generation as the dominant generation source, and its role is only expected to grow. But even in places like gas-rich Texas, it's facing headwinds.
The limits of California dreaming
In terms of energy markets, there couldn't be a starker contrast to California than Texas.
The Electric Reliability Council of Texas (ERCOT), which operates the wholesale power market for most of the state, does not have a capacity market. It is unique in the U.S. in that it is an energy-only market. Energy prices rise and fall based on supply and demand. There is a cap, but it is set very high, at $9,000/MWh.
The theory is that high prices will attract sufficient new generation to provide enough capacity to keep the lights on. Other states have been reluctant to put that much faith in the market and have implemented capacity markets. So far, the Texas model has worked, although thermal generators occasionally lobby for the state to create a capacity market.
In an April report, ERCOT said it would have enough generation to meet an expected record summer demand, met by a variety of resources. Unlike California, Texas still has several coal and nuclear plants, as well as gas and the highest concentration of wind power in the nation.
"The question becomes how much reliance on wind is sustainable in the short term."
Brian McIntosh
Product director for market analytics, Genscape
Sometimes wind dominates the ERCOT market, but gas-fired generation and coal still play an important role in Texas. In 2017, gas-fired generation supplied nearly 39% of ERCOT's power, compared with 32% from coal and nearly 17.5% from wind. In terms of capacity, natural gas generation comprises 53% of the mix and wind 22%.
ERCOT's interconnection queue, however, "is heavily focused on wind, and that's going to be tricky for them," Brian McIntosh, product director for market analytics at Genscape, an energy sector research and analytics company, told Utility Dive.
"The question becomes how much reliance on wind is sustainable in the short term," McIntosh said. Right now, Texas has a lot of gas-fired generation available, as well as a "decent" amount of coal-fired generation. "I wouldn't be surprised if those coal plants stick around," McIntosh said, as they could remain profitable if prices rise.
The market has already responded to the potential summer squeeze, McIntosh noted. The prospect of a hot summer caused forward power prices to trade at historic highs that drew at least one mothballed plant out of retirement.
That is not to say it is smooth sailing for ERCOT gas-fired generation. In May 2017, Panda Power declared bankruptcy for its Temple gas plant in Central Texas. After years of struggling, the owner conceded that the plant could not earn enough in the market to service its debt obligations. The plant exited bankruptcy in April.
The Temple bankruptcy illustrates one of the quirks of the ERCOT market, McIntosh said. "If you don't have high prices in July and August, it is hard to get by on energy costs." When the plant was financed, the expectation was that prices would be high, but as more wind came on to the system and natural gas prices continued to drop, Temple was suddenly out of the money.
The plant runs almost like a baseload unit, McIntosh said. "It does well in the summer and most other months, but the assumptions a few years ago were significantly higher," he said. That is not as big an issue in the PJM Interconnection market, he said, because PJM has a capacity market.
PJM: Gas for the long run
There are marked differences between the power markets in PJM, California and Texas, but PJM is the only one with a capacity market.
PJM not only has a capacity market, it is also a showcase for the effects low cost natural gas can have on power markets. Much of PJM sits on Marcellus and Utica shale formations that yield low cost gas from hydraulic fracturing, which has lured developers into PJM to tap into those supplies hoping to undercut competitors with the lowest cost bids.
Developers continue to bid new projects into PJM's capacity market despite the fact that the RTO has a reserve margin at 15.8%, far higher than its mandated minimum. In its most recent capacity auction, PJM procured enough capacity for a 21.5% reserve margin.
"Gas-fired combined-cycle generation comprises about 50% of PJM's interconnection queue. I can't imagine that it goes away any time soon."
Christina Simeone
Director of policy and external affairs, Kleinman Center for Energy Policy
Low cost gas generation is not only setting the market price in PJM. Developers keep proposing new gas plants in hopes that they will be able to beat existing generation on costs. Analysts estimate there are about 15 GW of combined-cycle capacity under construction in PJM with another 22 GW of new gas capacity in development.
"Gas-fired combined-cycle generation comprises about 50% of PJM's interconnection queue. I can't imagine that it goes away any time soon," Christina Simeone, director of policy and external affairs at the Kleinman Center for Energy Policy, told Utility Dive.
In PJM's most recent capacity auction, about 1,100 MW of new generation cleared the market, but those results could have been skewed because a court challenge to proposed rule changes resulted in older rules prevailing. How much new generation shows up in the next auction is also up in the air because PJM's market rules are in upheaval following recent regulatory maneuvers.
In mid-August, PJM asked the Federal Energy Regulatory Commission (FERC) for approval to delay its May 2019 capacity auction as a result of an earlier FERC action. In June, FERC denied approval of market reforms PJM proposed to address the presence of state-supported resources like nuclear power and renewable energy, which PJM calls out-of-market solutions that distort market results.
That landscape became even more uncertain in late August when the Trump administration proposed its Affordable Clean Energy plan designed to both address climate change and support coal-fired generation.
The plan is almost certain to attract court challenges and elicit protests from groups claiming that it would distort the operation of competitive markets. And while the plan could enable some coal plants to run or perform upgrades more cheaply than under previous regulations, the rule will not alter the underlying economics pushing coal out of the market — low cost natural gas. The plan "might prolong the life of some coal units for a short while, but it would be unlikely to have any significant change in long-term economics of coal plants," Metin Celebi, a principal at The Brattle Group, told Utility Dive via email.
In fact, if the news coming out of the Permian Basin in Texas is any indication, coal could have an even tougher time competing with gas-fired generation. The recent rise in oil prices has spurred an increase in production in the basin and with it an increase in the production of associated gas, resulting in natural gas prices at the Waha Hub falling to a substantial discount to Henry Hub prices. And, of course, cheap natural gas lowers operating costs for gas-fired generators and can spur the development of even more gas plants.
The wind threat
For gas-fired generation, however, the threat is not from coal plants, but from wind power. While not able to make a blanket statement about the economics of wind power, "if you look at the costs and where wind is today, wind is very competitive, even without the [production tax credit] subsidy," Genscape's McIntosh said.
"As long as gas prices remain pretty low, gas-fired generation fits the market pretty well."
Dale Probasco
Managing director, Navigant
Wind might force some gas-fired generation into retirement in some markets, but the real question, McIntosh said, is "Will the cost of energy storage drop to a level that allows wind to push out gas? Wind alone or solar alone won't be able to do it."
The implication, McIntosh said, is that in a market like California, gas-fired generation will probably be a "short bridge, but further east in PJM and New England and parts of New York, it could be quite a bit longer.
The key, at least in the near to mid-term, to gas-fired generation's survival, is likely going to come down to costs. "As long as gas prices remain pretty low, gas-fired generation fits the market pretty well," Dale Probasco, managing director at Navigant, told Utility Dive. As more renewables enter the system, they only increase the need for reliable flexibility. "Gas can meet that easier than coal or nuclear power."
The bridge will happen gradually over time as more and more storage is rolled out, Probasco said. Unless there is a significant breakthrough in storage, its growth will be incremental, he said.
The question, Probasco said, "Is how do you make that transition in a way that maintains system reliability and a way that doesn't lay costs on those people who can least afford it?"
