Microgrid Knowledge, Aug 2018
Quickly growing community choice aggregations (CCA) are expected to play a significant role in drawing 85 percent of customers away from California’s investor-owned utilities by 2025, according to a new report.
The community aggregation report was one of three on grid disruption released by Next 10, an organization with a goal of improving California’s future. The other two reports focused on electric vehicles (EV) and distributed energy resources (DER). All three studies attempt to uncover ways to improve the grid and reduce greenhouse gas emissions, said Noel Perry, founder of Next 10.
Community choice aggregations are energy buying coops formed by cities or counties.
“The IOUs forecasted that by 2025, 85 percent will leave their systems,” said Kelly Trumball, a co-author of the community aggregation report, “The Growth of Community Choice Aggregation: Impacts to California’s Grid,” and staff researcher and assistant project manager with UCLA’s Luskin Center for Innovation. “We expect the vast majority to go to CCAs, but also to direct access, energy efficiency and behind the meter folks generating and consuming themselves.”
Another report, “The Growth of Distributed Energy: Implications for California,” found the state to be home to 90 percent of the small-scale energy storage in the US and half of all US large-scale storage. In addition, as of 2017, 36 microgrids operated in California, with an additional 80 under construction or planned. Together, these microgrids will provide over 650 MW of peak capacity to the grid, “less than one percent of the total in-state generation capacity, but an important resource to help manage grid reliability,” the report said.
The growth in community choice aggregations reflect customer desire for more choice and control, according to JR DeShazo, director, UCLA’s Luskin Center for Innovation and a co-author of the CCA report.
“There has been grassroots interest across the state. It’s coming from localities that want the opportunity to procure their own energy. They are local communities that want local control and are unhappy with the historical arrangement of being part of the large service territories of Southern California Edison and Pacific Gas & Electric,” he said.
In California community choice aggregations are forming to meet environmental and climate-change goals. In other parts of the country, such as New York, communities hope to gain access to less expensive energy.
Eight new community choice aggregations launched in California this year, bringing the total to 18, and about 20 are expected to be in place by the end of the year, said Trumball.
“There’s been almost exponential growth in CCAs in California,” she said.
To date, one community choice aggregation, Redwood Coast Energy Authority (RCEA) plans a microgrid, but Trumball said she expects more will follow its lead.
RCEA is located in a rural area in Humboldt County more than 100 miles from transmission, said the report. It is focusing on local energy production and is pursuing the microgrid, supported by funding from the California Energy Commission. RCEA will own and operate the multi-customer microgrid, which will include 2 MW PV and 2 MW storage.
Community choice aggregations in the state have begun investing in local energy programs, including EV rebate and demand response programs. They pay up to three times more than IOUs for renewable energy – generally rooftop solar — through net metering programs, she said.
Under most utility net metering programs, the meter runs backward when the generator produces power.
What’s more, community choice aggregations in Sonoma and Marin County have feed-in-tariff programs for compensating renewable energy generators, said Trumbull. These are generally seen as a better alternative than net metering because they are generally long-term contracts at set prices. They also allow energy to be generated and sold independently of consumption, while net metering is tied to consumption.
The growth in California community choice aggregations has also boosted the ratio of renewable energy per California customer, said DeShazo. That’s because there are fewer utility customers, which increases the ratio. Under California’s renewable portfolio standard (RPS) requirements, the utility must purchase long-term contracts for hundreds of megawatts of renewable energy, he said. When the utilities lose customers to community choice aggregations, the ratio of renewable energy per customer increases. This affects how much renewable energy the utilities must purchase to meet RPS requirements.
“What’s so stunning about that is, within 18 months, by 2020, the IOUs will have met their 2030 goals for renewable energy in the state,” he said.
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Those who leave utilities for community choice aggregations are offered energy that has a higher amount of renewable energy, according to a press release from Next 10. Community choice aggregations offer customers electricity that’s made up of 37 to 100 percent renewable energy, and an average of 52 percent. Utilities, on the other hand, offer renewable energy content between 32 percent and 44 percent, but estimate a renewable content of more than 50 percent by 2020.
A second report about EVs, “Electric Vehicles and the California Grid,” found that the expected 3.9 million EVs will increase the state’s annual load by about 15,500 GWh, or 5 percent of the total load. It also said that in 2017, the state’s EVs accounted for only about 0.01 percent of total distribution system upgrade costs.
In addition, the report noted that smart charging could provide “significant benefits.” An analysis found that smart charging of 2.5 million EVs could avoid 50 percent of incremental power system operating costs and cut renewable energy curtailment by 27 percent annually, compared to charging the same number of vehicles without smart charging.
Next 10 commissioned these reports in an effort to better understand how to reduce greenhouse gas emissions, said Perry.
“Looking at California’s emissions, there are two areas that are challenging: transportation and the grid,” he said. “Unfortunately, our emissions numbers have been going up over the past few years. If we’re going to hit our numbers in terms of climate policy goals, we need to make sure the grid is working correctly.”
Exit fee: Deciding the fate of California’s utilities and customer choice movement: The future of California’s biggest utilities may depend on how much customers have to pay to leave them.
EDITOR’S NOTE: This story has been updated to include a recently filed Alternate Proposed Decision by Commissioner Carla Peterman.
Promised more renewables and lower utility bills, customers in California are flocking to newly-emerging Community Choice Aggregation (CCA) programs and Direct Access (DA) providers.
But the transition — and the savings — are not that simple. Someone has to pay for the power that investor-owned utilities (IOUs) procured to serve the customers moving to new load serving entities (LSEs).
The California Public Utilities Commission (CPUC) is determining how ratepayers should compensate utilities for procured generation if they move to customer choice organizations. The latest development came on Aug. 2, when the CPUC issued a proposed decision that would redefine the charge CCAs and DAs have to pay when customers migrate to them from traditional investor-owned utilities. And the old-school power companies are not pleased.
The CPUC’s decision fails to assure “customer fairness in the division of the costs of long-term renewables contracts,” Southern California Edison (SCE) Vice President Colin Cushnie told Utility Dive via email.
As customer migration to new LSEs accelerated over the last two years, procurement of new renewables has virtually halted until a charge for the transitioning customers is determined.
The ‘hundred years war’ over choice
State law requires departing customers to pay IOUs a cost for moving to new LSEs. That cost, known as the Power Charge Indifference Adjustment (PCIA), promises to be intensely disputed between choice advocates and the IOUs.
The PCIA is intended to “equalize cost sharing” between customers who leave their IOUs for new LSEs, called “departing load,” and those that stay with their IOUs, called “bundled load,” California Public Utilities Commission (CPUC) administrative law judge Stephen C. Roscow wrote on issuing the proposed decision. Direct Access porviders must similarly maintain fairness to all customers, he added.
If the PCIA is too high, the new LSEs are not certain they can fulfill promises of lower customer bills.
“The decision goes a long way to resolving our uncertainty,” said Nick Chaset, CEO of the alternative provider East Bay Community Energy (EBCE). “We don’t know what the present PCIA will be year to year, which makes it extremely hard to plan.”
But the IOUs say a lower PCIA would not compensate them fairly for generation procured in the expectation it would be needed to serve customers who now are moving to new LSEs.
SCE’s Cushnie said the decision does not “preserve the value of current utility portfolios” or “ensure that departing load does not disrupt California’s energy markets.”
The IOUs want a PCIA that includes the cost of utility-owned generation (UOG). The alternative providers reject this idea because new renewable generation is more cost-effective.
“The CCAs are going one way and the IOUs are going the other,” former CPUC Commissioner Mike Florio told Utility Dive. Florio, who co-authored a June 2018 GridWorks white paper on CCAs, said the “tweak” in the PCIA formula “was the straightforward thing to do without taking a side in the hundred years war.”
The customer choice groups and the IOUs say the proposed decision needs improvements.
On Tuesday, CPUC Commissioner Carla Peterman, who is in charge of the PCIA proceeding, filed an Alternate Proposed Decision (AD). The AD differs from ALJ Roscow’s PD in four fundamental ways, according to her.
The most important are that it found legacy UOG should be included in the PCIA calculation and there should be no limit on when that legacy UOG was added to the IOUs’ portfolios. The AD also alters the proposed cap and collar on the PCIA and proposed adders in the calculation of charge in ways that could allow the PCIA to reach a higher value.
California regulators’ final ruling could decide their financial viability as customers are increasingly migrating away from IOUs, as shown in the figure below.
Balancing competing interests
New LSEs look to the current PCIA calculation as a burden that is likely to worsen.
The current charge would shift $492 million from Pacific Gas and Electric (PG&E) customers and $25 million from SCE customers to the CCAs’ 2018 customers, according to the California Community Choice Association(CalCCA). “That will increase as more customers switch to CCA.”
PG&E argues it allowed CCA customers to pay only about 65% of what they should have paid in 2017. The result was “about $180 million in costs being imposed on remaining utility customers, an amount that could grow to $500 million by the early 2020s.”
If the cost of an IOU’s portfolio, including UOG, is above market value, it shifts more of it to departing customers through the PCIA. If the PCIA is below market value, it shifts the cost burden of the IOU’s portfolio to their remaining customers.
The objective of the PCIA proceeding is to address “widespread concerns” that the current PCIA’s “existing cost allocation and recovery mechanism is not preventing cost shifting,” the proposed decision’s author, Roscow, wrote. That would violate the laws empowering CCAs and DAs that require customer fairness, he added.
On behalf of the CPUC, Roscow found that UOG purchased before AB 117, the 2002 law establishing CCAs, should not be included in the PCIA calculation. The law included a specific list of costs “for which departing CCA load would be responsible, and pre-2002 legacy UOG is not on that list,” Roscow wrote.
The legislature and the CPUC “expected that the utilities would work diligently to reduce or eliminate future liabilities,” he added. Simply because they did not do this yet “is not a reason to impose these costs on CCAs.”
“The law is clear,” EBCE’s Chaset said. “There can be no cost shift, because CCA customers cannot shift a responsibility they do not have.”
But “clearly those assets were built for all customers,” former CPUC commissioner Florio said. “It was a strange reading of the statue.”
Both Florio and SCE’s Cushnie said the CPUC regulatory judge failed to consider history subsequent to AB 117. “SCE’s first CCA didn’t start until 2015,” he said. SCE’s UOG was “approved by the Commission for the benefit of all customers.”
The CPUC regulatory judge also failed to recognize that a significant portion of UOG “is in critical local reliability areas and provides local reliability services for the benefit of all customers,” Cushnie added.
The best way to protect all customers is “to allocate all benefits and net costs of the existing utility portfolios to all customers, regardless of their load serving entity,” Cushnie said.
Attorney Matthew Freedman, representing customer advocacy group The Utility Reform Network (TURN), agreed with Cushnie and Florio. The cost of the UOG should be shared by all customers because “the governor and this Commission were leaning hard on the utilities to bring as many new generating resources online as possible.”
Calculating the PCIA
The CPUC’s decision imposes several new mechanisms. One is a “rate collar with a floor and a cap that will limit the change of the PCIA from one year to the next” and protect against “the potential for volatility” in energy prices. “The cap will provide a degree of stability and predictability.”
The initial EBCE analysis shows the proposed decision will set the PCIA “at or near its current level,” Chaset said. “But the cap and the collar are important.”
As EBCE computes it, the PCIA was about $0.026/kWh, but is capped for 2019 at $0.022/kWh, Chaset said. Because of the collar, the maximum increase of the charge for 2020 would be $0.005/kWh. That means that the 2020 PCIA cannot be higher for EBCE than $0.027/kWh, and the 2021 charge cannot be higher than $0.032/kWh, he said.
“This will not hinder our ability to operate,” Chaset said. “But the most important part is it gives me certainty and allows me to plan.”
The cap seems inconsistent with laws protecting against cost shifts, Cushnie said. It will also “be subject to customer gaming unless applied on a customer-specific basis — which is also highly impractical.”
Another mechanism is an annual “true-up” to correct inaccuracies from forecasts with actual market data. “The true-up will ensure that bundled and departing load customers pay equally for PCIA-eligible resources,” the CPUC’s Roscow wrote.
The true-up is one of the most important provisions of the proposed decision, TURN’s Freedman said. It will “reconcile actual resource costs, recorded generation volumes, and realized market revenues” and ensure that net costs are tied to actual market revenues and not “theoretical long-term planning values.”
SCE’s Cushnie and CalCCA Executive Director Beth Vaughan also want the decision’s true-up mechanism to reflect actual market results. This appears to be a sign of potential common ground in “the hundred years war.”
“Until now, a blindfolded baby could beat the utilities’ prices, but the gap between what CCAs can buy for and what the IOUs are paying is likely to close.” Mike Florio Former CPUC Commissioner
Can California wait?
CCA growth is accelerating, according to a new paper from California think tank Next 10. There were nine CCAs in operation in 2017 and eight are expected to launch in 2018. Their impact in the longer term “depends on their energy procurement strategies and their local investments.”
IOUs served 70% of California’s load in 2017, but will fall to 57% in 2020, Next 10 forecasts. Passage of SB 237 would add to the likelihood of the CPUC forecast that IOUs could lose as much as 85% of their current load by the mid-2020s.
Filings by the CCAs in the CPUC’s integrated resource planning proceeding are “a mixed bag,” Union of Concerned Scientists senior energy analyst Laura Wisland told Utility Dive. The aggregated CCA portfolio contains a lot of large hydro and out of state wind, and “what grows over time is mostly solar,” she said. “That does not address the state’s need for resource diversity or relieve its solar over-generation.”
But, she added, “we should be doing everything possible to accelerate their ability to invest in California’s clean energy future.”
CCA offerings range from 37% to 100% renewables, but they are new entities with unestablished creditworthiness, limited balance sheets, and uncertain customer loads, Next 10 points out. The think tank reported great potential in renewables growth from the CCA trend, as shown in the figure below.
However, CCA’s have relied largely on “short-term and out-of-state” contracts for existing renewables.
That “is not adding a lot of value,” V. John White, Executive Director of California’s Center for Energy Efficiency and Renewable Technologies, told Utility Dive. “They are well motivated, but it is not clear they will be able to procure what is needed to help meet California’s clean energy and climate goals.”
Wisland and White agreed a central procurement authority might help CCAs overcome their limitations.
However, it takes two years to three years for a CCA to establish the balance sheet and credit it needs, Next 10 paper lead author Julien Gattaciecca of the UCLA Luskin Center for Innovation told Utility Dive. “The debate about CCA procurement should not look at the past, it should look to the future.”
CalCCA’s Vaughan and EBCE’s Chaset said a key driver for CCA procurement would be to accept CalCCA proposals to auction older vintage, above-market IOU renewables contracts and securitize UOG.
The auction could move viable long-term renewables contracts into CCA portfolios at more affordable prices, Vaughan said. Securitization would help IOUs optimize their portfolios, which would minimize the burden of the proposed decision’s finding on pre-2002 UOG.
“Our initial assessments suggest securitization would save bundled customers more than any potential costs of exempting CCA customers from paying for pre-2002 assets,” Chaset said.
The proposed decision calls for “a second phase” of the PCIA proceeding to take on “a comprehensive solution” to optimizing utility portfolios.” It will include “a ‘working group’ process to enable parties to further develop a number of proposals,” the CPUC’s Roscow wrote.
A CPUC final ruling is expected September 13. The working group process would follow.
It is unlikely the commission will change the regulatory judge’s basic approach, Florio said before Peterman filed her AD. Florio had foreshadowed that the CPUC might offer “a different conclusion” on the pre-2002 UOG.
A central buyer might streamline procurement, but the newer CCAs, led by those that preceded them, seem to already be moving faster, he added. “Clearly there is a lost opportunity because this a good time to be a renewables buyer. But waiting for the CCAs “may be the only choice now.”
And the shift away from the IOUs may not be as big as the CPUC foresees, he added. The proposed decision could put the PCIA at a level that will discourage some CCA efforts to beat utility prices.
“Until now, a blindfolded baby could beat the utilities’ prices, but the gap between what CCAs can buy for and what the IOUs are paying is likely to close,” Florio said.
As second wave of state storage targets builds, utilities propose new projects
Experts are watching Arizona, Nevada and Colorado for new policies that will help develop the industry.
Energy storage has been taking root across the country, but coastal states, such as California, Massachusetts and Oregon, have taken the lead in implementing related policies. That could change as states such as Colorado and Nevada move closer to potentially ambitious policies to support energy storage.
Rising renewable penetration combined with falling costs for lithium-ion batteries is driving many states to explore policies that encourage energy storage.
New Jersey became the most recent state to adopt an energy storage target when Democratic Gov. Phil Murphy in May signed a bill that establishes a 2,000 MW by 2030 target. And in New York, the Public Service Commission is in the process of setting an energy storage target that some observers say could end up as high as 3,000 MW by 2030.
But Arizona could be the next state to adopt an energy storage goal, if Commissioner Andy Tobin has his way.
“Energy storage is high on my list,” Tobin told Utility Dive.
The man with the plan
The Energy Modernization Plan that Tobin released in January includes a recommended target for 3,000 MW of energy storage deployed by 2030. The plan would have the state be powered by 80% clean energy by 2050, from 15% by 2025, and directs the investor owned utilities to build 60 MW of biomass plants for service by 2022.
The Arizona Corporation Commission (ACC) “could be voting on the plan by January or February,” Tobin said.
“We thought we had enough votes” to put it on the docket, Tobin said at the commission last month. Instead, the ACC decided to do a study on the financial impact of the plan. That study, being prepared by the state’s Residential Utility Consumer Office, should be ready in about two weeks.
Tobin wants to see the adoption of his plan ahead of the next fire season, as the biomass plant component could burn fuel from Arizona’s forests and lessen the devastation of forest fires.
Tobin is optimistic, noting that some commissioners are already on board.
The state’s investor-owned utilities have responded to the proposed energy plan with proposals for energy storage projects, according to Tobin. Tucson Electric Power is considering participating in the 2,000 MW Big Chino Valley Pumped Storage Hydroelectric project proposed by ITC Grid Development. And Arizona Public Service has proposed a solar-plus-storage project that includes a 50 MW, 135 MWh battery to serve a 65 MW solar farm.
In addition to the progress in Arizona and New York, Timothy Fox, vice president at ClearView Energy Partners, is also tracking developments in Nevada where a regulatory proceeding is underway to create a storage target pursuant to S.B. 204, enacted last spring.
GTM Research also recently began tracking Nevada and Colorado for energy storage policies.
“There are some large utility projects going on” in Nevada, Brett Simon, senior energy storage analyst at GTM Research, told Utility Dive. The state’s constant shifts on net metering policies for solar power are driving interest in residential storage that can be used to time shift solar power generation from mid-day to the evening, he said.
NextEra Energy has proposed a 500 MW solar-plus storage project in Nevada outside of Pahrump. A joint venture of Australia’s Quinbrook Infrastructure Partners and Arevia Power of California has also proposed the Gemini Solar Project near Las Vegas that would eventually be capable of generating up to 690 MW and include some battery storage.
In Colorado, Simon noted that the state legislature passed SB 18-009, which establishes the right of consumers to install energy storage devices on their property as a means of enhancing grid reliability and reducing the need for additional generating plants. Another bill, HB 18-1207, directs the state’s Public Utilities Commission to include energy storage in utilities’ long-term planning processes.
“Colorado is clearly on a path legislatively for energy storage,” Simon said. “I wouldn’t rule out targets entirely, but they are not going to happen right now. The state is about where Massachusetts was two years ago, but will probably move faster than Massachusetts.”
“When a state sets an RPS, the objective is clear. With a storage mandate, it is less clear.” Scott Baker Senior business solutions manager, PJM
Last June, after years of study and preparation, Massachusetts set a targetof 200 MWh of storage by 2020. Even after approval of its energy storage target, Massachusetts had further to go to truly open a market for energy storage in the state.
Stakeholders recently reached a compromise on issues involving the ownership of capacity rights for energy storage facilities in the state. Developers had argued that if utilities had been able to retain those rights, it would have put a damper of the development of energy storage in the state.
The wholesale connection
Access to capacity markets could prove to be a key to the development of energy storage, regardless of state policies. That is particularly true in the 13 states that participate in the PJM Interconnection’s wholesale power market.
“When a state sets an RPS, the objective is clear. With a storage mandate, it is less clear,” Scott Baker, senior business solutions manager at PJM, told Utility Dive. “What is the mandate trying to accomplish? It is not a bad thing, it just has to be sorted out.”
It is important to understand the value the state is getting at the retail level and at the wholesale level, Baker said. And one of the key questions, he said, is how to ensure that a facility is not being paid twice for the same output or service.
For example, if a storage facility was eligible for net metering and a state was paying for energy, that resource should not be eligible to participate in PJM’s energy market, Baker said. That is similar to the issues that arose in Massachusetts. In the past, solar power has not had a direct revenue stream for capacity. Its capacity value was more comparable to a demand side management asset that could reduce load by reducing the need for power at critical times.
But energy storage has the potential to change that equation, particularly when it is combined with solar power. While the advantages of combining storage with solar to help stretch out solar output may seem obvious, the combination presents problems for competitive wholesale power markets that were set up before energy storage became a more viable option.
When storage is used to hybridize a generation resource, whether it is a solar facility or a gas-fired generator, it presents a problem for RTOs. It does not fit neatly into their rules. “Is it one unit or two different units?” asked Baker.
“In PJM, and most markets, it is treated as two different units,” Baker said. That is because market rules call for generators to bid cost-based offers into the market and the cost basis of the generating portion and the storage portion of the facility are very different. “It is not an unsolvable problem,” Baker said, but it is one that will have to be dealt with as more states adopt energy storage targets.
An offer utilities can’t refuse: The low cost of utility-scale solar
Despite some policy uncertainty, large solar projects are now “competitive with coal and gas.” Herman K. Trabish Aug. 9, 2018
New numbers show the “beautiful friendship” between utilities and solar is growing and bringing the U.S. power system’s transition to higher renewables penetrations along.
“Utilities of all kinds and in many places are accelerating from zero to 100 on solar in response to record-low prices,” Smart Electric Power Alliance (SEPA) research manager and paper lead author Daisy Chung told Utility Dive.
Contrary to the word from Washington, D.C., utility-scale renewables are not “badly behaved coal plants” that threaten grid reliability and national security, Seb Henbest, lead author of the Bloomberg New Energy Finance New Energy Outlook, wrote July 25. “By 2050, we’re painting a picture of an electricity system utterly reshaped around cheap wind, solar and batteries.”
Investors say “phenomenally abundant” renewables could support a trillion-dollar U.S. market by 2030 and solar will play a key part, according to an April American Council on Renewable Energy survey.
Utilities are seeing the opportunity and responding, according to the 2018 Utility Solar Market Snapshot released in July by the SEPA.
Utilities step up to the sun
Utilities have long played a central role in U.S. wind growth, which has tripled since 2007 to reach almost 89 GW of cumulative installed capacity. In the same time period, utilities added 42 GW of solar to the grid, including 7.4 GW in 2017, SEPA reports.
“Utilities of all kinds and in many places are accelerating from zero to 100 on solar in response to record low prices.” Daisy Chung Research Manager, SEPA
Solar prices have been slower to reach competitive levels than wind prices, but the SEPA report shows utilities responding to the new low prices quickly, Chung said.
Out of the 7.4 GW total, investor-owned utilities added 5,825 MW of new solar capacity in 2017 and “remain the driving force of new solar installations across the country,” SEPA reports. In the Southeast, where solar growth has historically been slowest, “several large utilities have propelled rapid solar deployment.”
Southern Company and its four subsidiaries are “bullish on solar,” VP for Energy Policy Bruce Edelston told Utility Dive. They added a cumulative 375 MW for four Southeastern states in 2017 and have a pipeline that will likely deliver around 200 MW annually for the foreseeable future, he said.
“The price has come down substantially in the past couple of years and is now competitive with coal and gas,” he said. “We would not be buying so much now if it was not the cheapest option.”
One of the country’s strongest advocates for distributed solar agreed. “Recent bids in utility solicitations show how cost-effective utility-scale solar is,” John Farrell, director of the Energy Democracy Initiative at the Institute for Local Self Reliance (ILSR), told Utility Dive.
Public power utilities, which added 1,210 MW of solar last year, are also “gaining industry recognition,” SEPA reports. In small jurisdictions, low prices are making solar a factor, Chung said. The Navajo Tribal Utility Authority added 27.3 MW of solar in 2017, a 913 watts of solar per customer rate that made it seventh in SEPA’s watts per customer ranking, which was created to highlight smaller utilities’ efforts.
The development was done with Arizona public power utility Salt River Project, Chung added. They also signed an agreement targeting 500 MW more on Navajo land.
Early in 2018, Guam approved a contract for 120 MW of new solar, SEPA reports. The contract’s size and its option to add energy storage are noteworthy for such a small territory. But what made it remarkable was that Guam only added 26 MW in 2017 and only had 42 MW total at the end of the year. “Few utilities have grown so fast,” Chung said.
Electric cooperatives, which added 240 MW of solar in 2017, are also pioneering two of the solar world’s fastest growing innovations:community solar and using solar-plus-storage to meet peak demand.
Pickwick Electric Cooperative added 24 MW for its generation and transmission (G&T) provider, the Tennessee Valley Authority, and G&T East Kentucky Power Cooperative added 8.5 MW for its member cooperatives. Both additions serve community solar programs and helped community solar double its installed capacity in 2017 to become the fastest growing solar sector.
Kauai Island Utility Cooperative (KIUC) deployed its first solar-plus-storage system in 2017. The combined 13 MW solar array and 13 MW-52 MWh battery storage system have allowed KIUC to reduce fossil generation use at peak from over 65 MW to below 60 MW, KIUC data provided to Utility Dive shows. And the project’s $0.145/kWh PPA is significantly below KIUC’s cost for fossil generation.
The project was the first to demonstrate that solar-plus-storage can compete with natural gas peaker plants, Navigant Director Lon Huber told Utility Dive.
Colorado’s United Power Cooperative has gone a step farther. It will combine its 24 MW of utility-supply solar with a 4 MW-16 MWh battery to provide community battery energy storage, SEPA reports.
Resilience to changing policy
There were 148 state policy actions related to solar between April 1 and June 30, according to the Q2 2018 solar policy update from the North Carolina Clean Energy Technology Center. One state-level policy and two federal policies overshadow all these debates.
As many as 116 of the 148 state-level policy actions are directly or indirectly related to the question of net energy metering (NEM). At least 59 address the question of using an alternative to the NEM retail electricity rate compensation for solar owners’ generation exported to the grid.
SEPA asked over 170 utilities about their compensation offerings. The retail rate is used by 57% and a below-retail fixed compensation is used by 13%. Only 7% compensate based on variables like where the generation is delivered to the grid or what time of day it is delivered. A combination of compensations is used by 4%.
Of the 18% of surveyed utilities that use “other” compensation approaches, about 60% value customer-exported generation “based on avoided cost, wholesale price, or marginal costs,” SEPA reports. NEM is “no longer a super-majority strategy,” the report concludes.
Of the two federal policies, the paper resolves a misconception about which is most significant, SEPA’s Chung said.
The solar market expanded year-over-year continuously from 2007 until 2016, but after adding 6.1 GW in 2015 and 9.4 GW in 2016, it dropped to 7.4 GW in 2017. However, the 2016 spike was an “outlier,” SEPA reports. That makes 2017 “less like a downturn and more like a continuation of steady growth, as well as evidence of market resilience.”
The atypical 2016 spike was caused by uncertainty associated with an anticipated “sunsetting of the 30% federal investment tax credit (ITC)” which did not happen, SEPA reports. Further uncertainty was created in 2017 by the anticipated and then imposed federal import tariffs on solar cells and panels.
But the import tariffs have only added about 10% to the installed cost of utility-scale solar, SEPA reports. It was offset by falling installed costs of solar and by the 2017 federal corporate tax reduction, Regulatory Assistance Project (RAP) senior advisor and economist Jim Lazar told Utility Dive.
“The ITC affects 30% of project cost,” Chung said. “From our financial model, we cannot generate a situation where the new imported panel pricing caused by the tariffs goes above that.” Because the ITC is the more important policy, “the overall trend of growth in solar has not stopped.”
The tariffs and federal tax policies “produce headwinds for solar,” Vlahoplus emailed Utility Dive. But “the overall outlook remains positive.”
Solar continues to face a range of other policy debates. But they tend to be local issues, like demand charges in Massachusetts and legalizing leasing in Florida, which are not hampering broad national growth. Community solar advocates continue to add markets, but that is happening one or two states at a time.
Two new markets
The Pacific and Mountain regions accounted for 41.7% of new U.S. solar capacity in 2017, SEPA reports. But utilities in the Southeast accounted for 21.4% of 2017’s total. The Southeast is just opening up, now that prices have become appealing,” Chung said.
Duke Energy Progress in North Carolina deployed 355 MW of solar in 2017 and moved to third place among all utilities for total new capacity. Southern Company’s 375 MW of new solar capacity were spread across its four subsidiaries — Alabama Power, Gulf Power in Florida, Georgia Power and Mississippi Power.
“It is a win for the transition to clean energy if utilities are investing in clean, cost effective, large solar systems, as long as it does not undermine their customers’ ownership of solar.” John Farrell Director of Energy Democracy Initiative, Institute for Local Self Reliance
Southern Company subsidiaries will continue to grow solar “fairly rapidly,” Edelston said. “Other than the Vogtle nuclear plant being built by Georgia Power, we are adding no new generation except solar, at least until we need new capacity, which is not likely for another decade or so.”
The other new market opportunity is in small and medium-sized commercial-industrial businesses (SMBs), Chung said. SMBs are “a sliver” of the non-manufacturing commercial sector, but have many of the same ambitions as the larger corporate buyers who procured about 2.78 GW of renewables in 2017, SEPA reports. “Utilities have yet to fully address this market,” It adds.
A recent survey of SMBs found “about two-thirds, or 65%, indicated interest in renewable energy,” SEPA reports. For 56%, on-site solar was the strongest preference, and among their planned “next steps” was “reaching out to utilities.”
There are not a lot of offerings to meet that demand and SMBs “seem inclined to take whatever their utilities offer,” Chung said.
Urban utilities will continue to build utility-scale solar “to serve the part of their load that will not be able to serve itself with solar,” RAP’s Lazar said. “That is probably one-third to one-half of an urban utility’s total load,” he said. But SMBs could offer utilities a major new opportunity.
For those waiting for a utility offering, the utility could lease their rooftops, Lazar said. Instead of building utility-scale solar where there is available land, the utility could build and own solar where there is no cost of transmission, he said. The power and all its system benefits go to the utility and the roof owners earn the rent.”
The future of utilities and solar
The SEPA report reviews a range of future innovations that utilities and solar can share, including solar-plus-storage, advanced inverters and microgrids.
SEPA does not make predictions, Chung said. But it is becoming clear that 2017 trends are continuing into this year. “They include policy and market uncertainty, growth in smaller markets with slowed growth in mature markets, and announcements of record low prices.”
ScottMadden’s Vlahoplus said the cost declines will continue to expand the utility-solar partnership. Solar eventually will become “part of a ‘normal’ generation portfolio” and an “accepted option for utilities,” he said.
NRECA’s Roepke said solar is “the first wave” of customer choice in a future where utilities coordinate and optimize a “range” of services and resources. The utility will continue to deliver “reliable, safe and affordable electricity” from both large-scale and distributed generation, she said.
ILSR’s Farrell agreed. Despite his strong advocacy for distributed solar, he said, “it is a win for the transition to clean energy if utilities are investing in clean, cost effective, large solar systems, as long as it does not undermine their customers’ ownership of solar.”
But utilities should be concerned about one thing, he said. “Buyers of distributed solar are making individual decisions that are adding a lot of power to the grid. It is not the result of utility planning, but of millions of individual market-driven decisions. It can have awesome system benefits, but utilities need to think about how to make it work for their bottom lines.”