With distributed generation steadily rising and creeping into new states, electricity regulators in each region of the U.S. are dealing with change very differently.
Regulatory officials from California, Texas, Minnesota and Arizona discussed how they’re addressing some of the most pressing issues in their service territories this week at the National Town Meeting on Demand Response and Smart Grid in Washington, D.C.
California is the national leader in the deployment of solar PV, plug-in electric vehicles, grid-scale energy storage and home automation technologies. Today, about 20 percent of the state’s electricity comes from renewable energy, putting California on track to meet its 33 percent renewable energy target by 2020.
But while the Golden State continues to come up with new ways to promote and integrate advanced energy technologies, the focus will shift from renewables in the coming years, said Michael Picker, president of the California Public Utilities Commission.
“We’re moving away from a technology-based discussion to [a discussion of] grid values -- what does the grid need, what do customers need?” he said. “And we will probably move away from a focus on renewables per se as a series of technologies, to a series of metrics on reducing greenhouse gas emissions.”
“There’s always the challenge that we could continue to increase our penetration of renewables, but actually start to create reliability issues,” he said. “Or we start to go the direction the Germans did, where they started to have a lot of peak-demand backup generation.”
Picker added that this shift away from individual technologies toward holistic grid solutions will reinforce a convergence between traditional electric utilities, the transportation industry, the natural gas industry and all types of distributed energy resources (DERs).
Not everyone is going to like this trend. Last week, the CPUC voted to approve a 500-megawatt gas plant for San Diego Gas & Electric in Carlsbad, Calif. Picker said the approval was needed to replace the retiring Encina Power gas peaker plant and San Onofre nuclear plant in Southern California. Many stakeholders argued strongly that the aging power plants should have been replaced by renewable energy, efficiency measures, demand response and energy storage.
“As someone who’s sited and permitted 18 gigawatts of renewable energy, and spent a lot of time working on facilitating solar and storage, I don’t really like voting for natural gas,” said Picker in an interview. “But we’re still at a point where the grid requires it, especially at this weak spot in the grid.”
"The argument that we're abandoning our clean energy goals, I just don't see it," he added. "I think we're just making the pragmatic decisions you've got to make when you're still in mid-stride."
The reality is that California can do a lot with energy efficiency, solar and storage, but the state still needs reactive power, said Picker. The state’s electricity system needs to be able to deal with voltage collapse, fast-ramping to accommodate renewables and the ability to come back quickly from a cold start.
“For all of those reliability issues, we’re probably going to have to have one more [gas plant],” said the commissioner.
The energy sector in Texas looks drastically different than California's.
Texas has seen very little activity on distributed energy resources (DERs) to date, said Donna Nelson, chairman of the Texas PUC. That’s because Texas has some of the lowest electricity rates in the country. It’s also because retailers don’t have a guaranteed a rate of return in Texas’ deregulated market, so the state has never implemented net metering or a feed-in tariff to encourage the adoption of distributed energy resources. Proposals to add incentives have been repeatedly shot down.
Texas also doesn’t have a capacity market, and so it does not offer any special payments to electricity providers or demand response participants at times of peak demand. ERCOT, Texas’ regional grid operator, does offer demand response through its Emergency Response Service, but the program requirements make it a last-resort option mostly limited to commercial and industrial customers, according to a Brattle Group report.
ERCOT is currently considering changes to its ancillary services market that would increase compensation to faster-responding resources, such as demand response and batteries. Retailers are also leveraging wide penetration of AMI to offer demand response products to residential customers. But while the market is progressing, demand response providers shouldn’t expect any special treatment from the PUC, according to Commissioner Nelson.
“Our ultimate goal is to put in place a market, which started with nodal, where any customers -- industrial customers or retailers on behalf of residential customers -- can bid into the market,” she said.
“It is my belief that if we made a decision not to move forward with a capacity market, we shouldn’t put in place a bunch of small products that are capacity payments beyond what we already have to entice further DR,” she added. “DR in Texas needs to learn to play in the same field as generation does, and that is where they bid in to the market.”
Also in the name of preserving competition, Nelson said Texas is likely to push back against the Obama administration’s Clean Power Plan.
“You can expect to see Texas fighting it,” she said. “It would fundamentally change the way the competitive market in ERCOT works.”
Minnesota couldn’t be more different than Texas. Minnesota’s utilities are all fully integrated, there is very little AMI infrastructure, the state has a net metering program and is seeing steadily increasing amounts of distributed solar.
To cope with increasing amounts of customer-generated solar power on the grid, Minnesota recently became the first state to approve a “value-of-solar” tariff. Utilities could use this tariff to compensate solar customers instead of net metering at the applicable retail rate.
“The value-of-solar tariff is really the way of the future,” said Nancy Lange, Minnesota PUC commissioner.
But she admitted that utilities don’t like that the tariff factors in avoided environmental costs from solar energy. So far, no utility has chosen to use the value of solar tariff as a compensation method. Lange said she hasn’t spoken enough to utilities to find out exactly why.
“I haven’t given up on it as a tool,” she said. “Pricing things at the applicable retail rate is really a proxy for what something is worth. If you can take something apart and say this thing is worth this much in avoided generation, or avoided environmental [damage], or it costs this much to connect it and back up -- that...is going to start replacing the proxy values we’re using right now.”
Lange said she is eager to get more insight on all new technologies coming onto the distribution grid, not just solar. As a result, she said she plans to open a grid modernization proceeding at the PUC in order to address disruption in a more proactive way.
DERs have the ability to help customers manage their load and reduce their electricity bills. But if DERs don’t add value in this way, then there’s no reason to deploy them, she said.
“We need to understand the current system better and what it needs to maximize customer and system value,” said Lange. “Just because something is distributed doesn’t necessarily make it inherently good.”
In Arizona, the second-largest solar market in the U.S. after California, there is a heated debate playing out over the true value of solar that is far from being resolved. Rather than offer an alternative to the state’s net metering policy, the Arizona Corporation Commission (ACC) is considering changes to net metering on a utility-by-utility basis.
Earlier this year, Salt River Project -- a utility that is not regulated by the ACC -- passed policy changes that amount to a fee of roughly $50 per month on new solar customers in SRP territory. “The feedback we have is that that’s basically stopped...rooftop solar [installations] in the Salt River Project area,” said ACC Commissioner Bob Burns.
The SRP decision prompted other utilities and co-ops regulated by the ACC to propose changes to their net metering policies, he said. The ACC is currently reviewing plans from the three main investor-owned utilities -- Arizona Public Service, Tucson Electric Power and UniSource Energy Services -- all of which are seeking to increase monthly fees on rooftop solar customers.
To allow for more proactive planning going forward, Burns said he’s pushing to change Arizona’s integrated resource planning process. Arizona’s regulated utilities currently determine their own future energy needs, and then bring proposals for meeting that need to the ACC.
“My suggestion is we need to have an independent evaluate the need -- we could do that through an RFP process possibly,” he said. “Then, once the need is determined, we need to go through an RFP process to figure out how to fulfill that need, putting the Commission in a leading position instead of following.”
Bonus: New York
Many regulators in the U.S. are looking to New York’s Reforming the Energy Vision proceeding for possible ways to cope with the changes in the electricity system.
“A key part of what we want to do is create robust competitive markets around customers, because it is around that competition that innovation will come to the market,” said Richard Kauffman, chairman of energy and finance for New York state.
As part of this process, utilities will have to transform into distributed service platform providers responsible for managing assets at the grid edge. Third-parties will also have to change, and learn to think about the system as a whole, he said.
Regulators will have to change, too. Policymakers are more comfortable being at the center of decision-making, rather than working in an open market, said Kauffman.
Policymakers also like issuing grants because they can show ratepayers where each dollar went, he continued. It’s much harder for them to justify using ratepayer funds to be “an enabler of the market," he said. Playing that role "isn't going to get a photo op for the local official."