As battery costs decline, researchers say localized portfolios of clean energy could challenge gas plant investments.
The U.S. power mix is rapidly changing, but utilities still want the same thing — a resource mix that delivers the most reliable and safe electricity to customers at the lowest price.
Despite pronouncements from the White House, that preferred mix is no longer a portfolio based largely on coal and nuclear energy. Both those resources have seen their market share undercut by cheaper natural gas in recent years, pushing many of the oldest and least efficient plants offline.
Natural gas may fall victim to a similar situation within the typical two-decade utility planning horizon, according to new research.
“The Economics of Clean Energy Portfolios,” released by the nonprofit Rocky Mountain Institute (RMI) last month, shows that emerging mixes of renewable energy, storage, and other distributed energy resources (DERs) may soon be more cost effective than natural gas plants in most regions.
“For decades, utility planners have used the portfolio approach to power system planning and for their integrated resource planning (IRP),” RMI Electricity Practice Principal Mark Dyson, the paper’s lead author, told Utility Dive. “This paper demonstrates that, because of technology and cost advances, portfolios of renewables, batteries, demand response and energy efficiency can replace fossil fuel assets.”
The paper has already attracted attention in clean energy circles.
“RMI’s modeling shows the portfolio can replace natural gas plants and save ratepayers money,” said Lon Huber, a vice president at Strategen Consulting, who helps states craft clean energy policy in regulatory proceedings.
The problem, RMI warns, is that developers engaged in a “rush to gas” have already planned $110 billion in gas plant investments by 2025. That trend could lock in $1 trillion in costs to the U.S. power sector by 2030 if it continues, analysts warn, and make it more difficult for renewables and batteries to get a foothold in the market.
The gas rush will likely continue, analysts say, if regulators and lawmakers do not provide new incentives and market rules to encourage battery storage and demand management, which will provide crucial flexibility in emerging clean energy portfolios.
Progress on that front is uneven, but some utilities are beginning to see the value in clean energy portfolios and are changing investment plans as a result.
The portfolio approach
More than half of the U.S. thermal generation capacity is over 30 years old and will reach retirement age by 2030, RMI reports. More efficient, lower-cost turbines and historic lows in natural gas prices have created the “rush to gas” to replace the retiring capacity.
Utility and system planners and independent power producers (IPPs) have announced more than $110 billion in natural gas generation investments through 2025, the report adds. If the rush continues through 2030, the investment could reach over $500 billion for plants and $480 billion in fuel costs — and lock in billions of tons of CO2 emissions.
But the levelized costs of renewables, distributed energy resources (DER) and battery storage “have fallen precipitously” RMI notes. Combined into “clean energy portfolios,” these resources can “provide the same services as power plants, often at net cost savings.”
To quantify this, RMI compared the costs of four currently proposed natural gas plants with “optimized, region-specific clean energy portfolios.” Two of the plants were CCGTs, “planned for high capacity-factor operation,” and two were combustion turbine (CT) power plants, “planned for peak-hour operation.”
Actual projects, though unidentified, were used to make the modeling credible, Dyson said. The two “peakers” were in Texas and the Mid-Atlantic region, and the two CCGTs were in Florida and on the West Coast.
The technology choices and geographic distribution of the plants were intentional, as were specific operational challenges modeled, RMI Electricity Practice Associate and paper co-author Alex Engel told Utility Dive. Florida’s poor wind resource, for instance, made optimizing a portfolio there more challenging, and the Mid-Atlantic portfolio required meeting a winter peak.
In each case, RMI assessed regional resources and used an optimization tool to determine a cost effective clean energy portfolio, Dyson said.
RMI’s cost modeling compared the plants with replacement portfolios that would provide the same services at the time of the plants’ early 2020s in-service dates.
The net cost of the clean energy portfolio was 6% less than the proposed California CCGT, 47% less than the proposed Texas CT, and 60% less than the proposed Mid-Atlantic CT, RMI found. It was 6% more expensive than the proposed Florida CCGT until projected “cost reductions in distributed solar and/or a $7.50/ton price on CO2 emissions” were factored in.
“All four cases show that an optimized clean energy portfolio is more cost-effective and lower in risk than the proposed gas plant,” RMI reported.
But financial modeling is not the same as a real world transition to clean energy portfolios, analysts stressed. Attention to the financial risk factor will be critical.
The stranded cost risk
The financial risk of stranded assets is not news, RMI reports. “The same technological innovations and price declines in renewable energy that have already contributed to early coal-plant retirement are now threatening to strand investments in natural gas.”
The modeling solved for least cost net present value at the plants’ in-service dates, Dyson said. “But renewables and storage are getting cheaper and the price of natural gas will probably either stay the same or go up.”
If the price of natural gas remains at its current level, in the $3 per million British thermal units (mmBTU) range, “a [clean energy] portfolio would replace a new combined cycle plant and be cheaper by 2040,” Dyson said.
“With $5 gas, that happens in 2026.”
According to the report, $112 billion in planned natural gas generation investments and $32 billion in pipeline commitments are “already at risk of becoming stranded assets.” There are also $93 billion in proposed IPP investments at risk and “ratepayers face $19 billion of locked-in costs,” RMI reports.
“In both regulated and restructured electricity markets, there is a significant opportunity to redirect capital from uneconomic, risky investment,” RMI reports. It can be directed “toward clean energy portfolio resources, at a net cost savings.”
Regulators should compare the clean energy portfolio approach “before allowing recovery of costs in rates” for new natural gas generation,” RMI says.
“Natural gas investments today could become stranded assets in 10 years. For now, the answer is shorter contracts, all-source procurements, demand-side measures and smarter rate designs.”
Lon Huber – Vice President, Strategen Consulting
Even with the rush to gas, elements of the clean energy portfolio will be deployed, driving market prices down, Dyson said. “That will make billion-dollar investments in new gas plants a risky bet.”
The risk is particularly big because RMI used “conservative modeling,” Dyson said. It only matched single assets, and did not consider the financial costs of risk, fuel price volatility, carbon price volatility, or costs for the transmission and distribution systems.
Finally, it did not assume changes in market rules or products. Of the planned natural gas investment, 83% is for regional markets with rules and products designed only for thermal plants, RMI reports. The real opportunity will come with new market rules and products that enable and compensate the portfolio approach, Dyson said.
Two utilities look at portfolios
A clean energy portfolio approach, using conventional utility IRP planning tools but expanding it to include other resources, can “minimize risk to investors and enable net cost savings,” according to RMI. The approach represents “a $350 billion market opportunity for renewables and DERs through 2030.”
RMI’s modeling “proves the concept at the foundation of Arizona’s Energy Modernization Plan,” Strategen’s Huber said. That plan is aimed at preventing the kind of stranded investments made in decades past by Arizona Public Service (APS), the state’s dominant electricity provider, in coal and nuclear power.
“The same thing could happen to APS investments in natural gas plants,” he said.
For utilities in some markets, the value proposition in RMI’s portfolio approach may not be there, Huber said. “But natural gas investments today could become stranded assets in 10 years. For now, the answer is shorter contracts, all-source procurements, demand-side measures and smarter rate designs.”
APS is working toward that approach, Director of Resource Management Jeff Burke said. Industry expectations were high after APS contracted, in February, for a breakthrough solar-plus-storage project specifically designed to meet peak demand. The 65 MW solar plus 50 MW battery storage project, scheduled to come online in 2021, will serve a purpose now met almost exclusively by natural gas CTs.
A controversial April request for proposals (RFP) from March, however, would all but guarantee that the utility site at least some new gas generation.
“The intention of the natural gas is to allow integrating renewables,” Burke told Utility Dive. “We would likely sign merchant plants owned by IPPs to shorter term, six-year and seven-year contracts that will allow us to move to renewables when those short term contracts expire.”
“Our real world experience with the DER portfolio is limited, but we think the RMI report’s premise is sound. DERs are cost-competitive, can be located in transmission constrained areas where siting a power plant is difficult, and can be scaled up as the need grows.”
Colin Cushnie – Vice President for Energy Procurement, Southern California Edison
Some clean energy advocates say the RFP, for 400 MW to 800 MW of peaking capacity, violates an Arizona Corporation Commission-imposed moratorium on building new natural gas generation. APS says it does not. And, Burke said, the RFP requests up to 100 MW of energy storage, up to 100 MW of renewables plus storage, and up to 100 MW of distributed generation.
“That means 300 MW of a 400 MW procurement could be clean energy,” he said. “This is a measured approach to protect reliability while allowing us to use these technologies. As they mature, and costs go down, more storage will show up in our plans.”
Southern California Edison anticipates a similar cost curve. The utility’s 2015 plan to replace its retiring San Onofre nuclear plant was a step toward the clean portfolio approach, Vice President for Energy Procurement Colin Cushnie told Utility Dive.
“We contracted for a substantial amount of carbon free distributed resources to serve the transmission-constrained Los Angeles Basin,” he said. “That preferred resources pilot (PRP) is the direction we are headed in. We are now doing the same thing for the Moorpark local capacity area to replace the proposed Puente project.”
Private sector providers for SCE’s first local capacity requirement procurement are now completing deployment, Cushnie said. “Our real world experience with the DER portfolio is limited, but we think the RMI report’s premise is sound. DERs are cost-competitive, can be located in transmission constrained areas where siting a power plant is difficult, and can be scaled up as the need grows.”
Testing of the PRP process will be complete by the end of the summer, said SCE Head of Integrated Innovation and Modernization Sergio Islas.
“There is a lot of work at SCE and across the country on proof of concept portfolio projects,” Islas told Utility Dive. “But the scale of this PRP to meet demand with a portfolio of DER very similar to what RMI proposes is unprecedented.”