Has California built its last natural gas plant?
Two pending decisions from state regulators will decide how California moves toward a clean(er) energy future.
Two pending decisions from California utility regulators will show whether the state is committed to its renewable energy goals or bound to natural gas for years to come.
The most notable decision is the future of NRG Energy’s proposed 262 MW Puente natural gas project. Earlier this year, a committee of the California Energy Commission came out against building the plant, resulting in NRG suspending its application while reviewing the facility’s future prospects.
On another front, Pacific Gas and Electric’s (PG&E) decision to shutter its 2,200 MW Diablo Canyon nuclear facility by 2024 or 2025 leaves a gaping hole in capacity that needs to be filled. The utility proposed a $1.3 billion energy efficiency investment as part of a 2016 agreement with renewable energy advocates over shuttering the plant.
But an administrative law judge with the California Public Utilities Commission (CPUC) deferred approval of that investment, saying it should be addressed in the state’s new comprehensive planning.
Natural gas appears to be the easy answer to fill the state’s capacity goals, but a recent investigation by the Los Angeles Times left many questioning whether the state is overbuilding that resource. California ISO agreed earlier this year to examine alternatives to Puente after pressure from lawmakers. Clean energy and green groups are also urging regulators and lawmakers to pivot to solar, efficiency and storage as a more cost-effective way to meet power needs and reduce emissions.
As these debates play out, California is reaching an inflection point over the future of its energy landscape and how these decisions play out will decide how the state will move forward to cut emissions and invest in more renewable energy.
What to do with Puente
Directed by the CPUC, Southern California Edison is reviewing alternative options to “address the unique needs” at the location where the Puente gas plant would have been built. The utility plans to submit a request to the Commission in order to launch a Request For Proposals by early 2018, according to SCE spokesperson Robert Villegas.
The RFP will focus on meeting local reliability needs the Puente project was designed to serve and will “prioritize preferred resources and energy storage,” Villegas said.
This aligns with the utility’s recently-released white paper that seeks to slash carbon emissions even further than the state mandate, while aggressively decarbonizing the electric and transportation sectors.
CAISO is also examining alternatives to the plant — which could range in costs anywhere between $309 million to more than $1 billion. But some stakeholders say a new planning process is to blame for hurting the development of natural gas generation.
Jan Smutny-Jones, CEO of the generator trade group Independent Energy Producers Association (IEPA), told Utility Dive the Puente decision shows the challenge California faces. Puente was “squeezed out of existence” by a new planning process, which is too “granular” and “complicated,” he said.
The decision “sends the wrong signal to investors,” he added. The new uncertainty facing natural gas generators could drive plant closures and a downward spiral in the sector.
The recommendations supporting DER alternatives from CAISO and CEC were pivotal to the decision, but raise jurisdictional, technical feasibility, and cost issues, Smutny-Jones said.
The jurisdictional concern is with the use of customer-generated electricity to charge batteries that would then be sold into CAISO's markets. The Federal Energy Regulatory Commission (FERC) considers net energy metering a state-jurisdictional matter,” Smutny-Jones said. “But electricity for resale is subject to FERC jurisdiction and that is an unlitigated potential conflict.”
Using DER at scale to meet system needs also challenges present technical capabilities, he said. “It will require a smart distribution system and smart inverters at the customer level,” he said. “It will require redesigning and reconfiguring the distribution system.”
That could become very expensive because meeting system needs is not only about having generation for average system conditions, he warned. It also requires meeting rare contingency conditions.
“Batteries are good at frequency regulation, but they are tuperware,” Smutny-Jones said. “Once discharged, they must be recharged to have any value. For long duration capacity needs, overbuilding will be necessary.”
Smutny-Jones blames the reversal of the Puente decision on the CAISO Board of Governors. “In the Puente proceeding, you could see that Governor Dave Olsen has very strong anti-gas beliefs.”
Dave Olsen emailed Utility Dive that he is not “anti-gas” but “pro-California GHG policy, which requires, among other things, phasing out the use of natural gas.”
Olsen said California’s reliance on natural gas-generated electricity in the future hinges on several unknowns, including how fast battery storage costs fall and how quickly and widely demand response (DR) and EE programs reduce the need for generation, he said. Innovation must also resolve “short-circuit current” and “weak grid” issues.
But California’s least efficient natural gas turbines “are the opposite of what we need” and are already scheduled to be retired by 2024-2025, Olsen said.
Those retirements will boost the use of rising penetrations of “renewables, demand resources and efficiency,” he said. That is why the CPUC “should be very, very careful” about approving new natural gas facility proposals. “We have a large and relatively modern fleet of combined cycle gas turbine (CCGT) units now, which may be able to take us past 2030.”
Olsen said it is also crucial to protect the financial viability of existing CCGTs. Over-supply in CAISO’s “very competitive” wholesale market and a rising abundance of zero-marginal-cost renewable capacity leaves many natural gas suppliers unable to “stay afloat” economically, he said. “We have to develop an orderly phase-down plan.”
He acknowledged the likely need for new natural gas peakers because of plant retirements and transmission-constrained load pocket needs. They must be small, modular, state-of-the-art turbines capable of meeting system needs with minimal emissions, Olsen said.
But if public pressure keeps decision makers focused on meeting the state’s goals, California can see “a substantial reduction in net natural gas generation capacity over the next several years,” he said.
The Diablo dilemma
The ALJ’s proposed decision to move PG&E’s procurement issues to the IRP proceeding represents “a missed opportunity for creativity and innovation,” said V. John White, executive director of the Center for Energy Efficiency and Renewable Technology (CEERT). “It ignores the agreement made between stakeholders and PG&E and invites more reliance on natural gas.”
By declining to support procurement of renewables or EE, “Picker and the PUC staff substituted their biases and concerns for the hard work of a broad coalition of parties and stakeholders,” he added.
CPUC President Michael Picker said political realities make any new procurement in California in the near term unlikely, despite concerns stakeholders may have about the IRP proceeding. “The real issue is that we were too successful here, and the market has flattened,” he told Utility Dive.
Aside from that, the final decision for Diablo canyon will be by the state’s renewables and greenhouse gas emissions reduction commitments. The ALJ moved procurement to the Integrated Resource Planning (IRP) proceeding partly because the Diablo Canyon proceeding did not make clear “what, if any, replacement procurement will be needed in 2024 to 2025,” he said
A new CPUC report tracking compliance with the RPS showed PG&E got 32.9% of its power from renewables in 2016; SCE got 28.2%; and San Diego Gas and Electric (SDG&E) got 43.2%.
Regulatory Assistance Project (RAP) senior advisor Mike Hogan, who spent much of his career in the natural gas industry, agreed with Picker's point. “California is wallowing in generation capacity,” he told Utility Dive. “Maybe they have already built their last large CCGTs. It's hard to imagine any need for that in the foreseeable future.”
He agreed with CAISO’s Olsen that local grid support issues could require additional “small, flexible, distributed peaking generation to complement renewables.” But that could come from combinations of DERs, he added.
Hogan also agreed with Olsen that an orderly retirement of California’s older natural gas generators is needed. Whether California can move from natural gas peakers to DER will depend on the expansion of demand response and the growth in price-responsive demand.
“Customers having access to robust time-varying pricing and being able to program various devices to respond to real time system conditions is dirt cheap,” he said. “The more you have, the less you need new gas-fired power plants.”
Instead, utilities are eyeing other cleaner resources to meet power needs.
Utilities and providers talk ‘dirt cheap’ alternatives
SCE’s Villegas said utilities require “a portfolio of products” to meet reliability needs cost effectively.
"Peaker plants will likely continue to provide important flexible capacity, energy, and ancillary service products,” he added. But as demand response evolves to play a greater role, the utility’s ability to manage the system to “maximize the value of resources outside traditional utility generation plants will be key.”
However, some utilities take a difference stance on the need for more natural gas generation.
Spokesperson Helen Gao said in an email that SDG&E “is committed to growing our demand response programs to the greatest extent possible.” But current steep demand ramps make natural gas peaker plants “necessary to ensure reliability,” she added. “DR is unlikely to solve the peak demand issue on its own” and reliability is best met by "a diverse portfolio of resources.”
Dave Margolius, Market Operations Manager for battery-based DR provider Green Charge Networks, noted demand response “needs to be extremely reliable to be economically competitive.” To deliver sufficient MW, or GW, he wrote in an email, it must be automated. “
If DR isn't considered reliable enough in a contingency event, gas-fired plants will still be required.”
Battery-based demand response is “a limited resource” with “finite MWh,” added Margolious.
Advanced Microgrid Systems (AMS) is one of the few other prominent DER-based demand response providers. Spokesperson Carly Sorrentino said policymakers need to provide similar incentives for non-wires reliability solutions (NWS) as are provided to generators. An example are the UK’s performance-based incentives, she added.
“Obligations” for utilities and system operators to evaluate NWS have also driven demand response in markets, Sorrentino said. For example, SCE’s 2014 RFO to provide local capacity requirement lost to the San Onofre shuttering is prime example. Because the CPUC compelled the utility to consider storage, AMS was able to win one of the first utility contracts awarded to battery-based demand response.
Mona Tierney-Lloyd, senior director of Western Regulatory Affairs for demand response provider EnerNOC, said California is bound to a 150-year-old “fossil-fuel generator-centric model.” Despite its strong policy support for demand response, energy efficiency, and renewables, the state “has been hesitant to build DR into planning and operations,” she said in an email.
FERC has issued orders to support demand response and other wholesale markets have adopted it at scale, but CAISO dispatches only a “subset of 20-minute-response resources,” she added. And integration of demand response into CPUC planning is still at the pilot stage.
Undercounting DR in planning leads to the procurement of other reliability resources, often natural gas generation, to fill the gap, Tierney-Lloyd said. Those long-term assets displace the need for new demand response, worsening the resource's disadvantage and increasing the need for natural gas.
The Puente decision “may be a signal that cycle is coming to an end,” she said. “It is time to plan a future grid and prepare for reliability in a distributed world, where demand response is one of many available technologies."