An old fossil-fuel burning power plant in Oakland’s Jack London Square area is one step closer to being replaced with cleaner energy sources.
The board of East Bay Community Energy, an Alameda County agency that buys green power for local residents, on Wednesday approved a contract with the plant’s owner for an 80-megawatt-hour battery installation that will pave the way for the closure of the plant, whose equipment is about 40 years old.
While the Martin Luther King Jr. Way plant is used only a few times annually when demand in the area is especially high, local officials have wanted to shut it down for years.
State grid managers last year approved a plan to swap the facility out with cleaner energy, including storage. The East Bay energy agency and Pacific Gas and Electric Co., which still controls the power lines in the area, subsequently sought proposals to wind down the plant.
Once the batteries are operational, they will work by drawing electricity from the grid when demand is low and then discharging it when needed.
Approval of the contract does not alone allow the plant to retire, but it will bring officials “significantly closer” to that goal, said Nick Chaset, chief executive officer of East Bay Community Energy.
With the East Bay agency contract approved, the plant’s owner, Vistra Energy, can get more approvals required to wind down the old facility, Chaset said. For example, the California Independent System Operator still needs to verify that the plant’s capacity is being adequately replaced.
The agency is also eyeing some other smaller projects as part of the broader power plant closure effort, dubbed the Oakland Clean Energy Initiative.
“This is probably the single biggest energy storage piece that needs to be put in place,” Chaset said.
The agency did not specify the cost of its 10-year storage contract with Vistra.
Vistra, based in Texas, acquired the Oakland plant in 2018 as part of its merger with the facility’s prior owner, Dynegy.
Vistra is “proud to have the opportunity to provide Oakland residents with renewable power while supporting the community’s clean energy transition,” CEO Curt Morgan said in a statement.
Oakland City Councilman Dan Kalb, who also serves as vice chair of East Bay Community Energy, said the eventual retirement of the fossil fuel plant will also reap environmental and health benefits for people who live in the area.
“If we can never have to turn that plant on ever again, that’s a lot of emissions that will not be going into the nearby community,” Kalb said. “West Oakland already bears a large part of the brunt in terms of poor air quality in the East Bay.”
“It’s particularly acute in that community because you’re also at the port, so you already have a lot of diesel combustion going on,” he said. “This is sort of a magnifier, especially on really hot summer days. Taking that out will deliver some meaningful local air quality benefits.”
East Bay Community Energy said the battery storage project is expected to start operating commercially in 2022.
PG&E said it has “received multiple, competitive bids” through a request for offers it initiated as part of the Oakland Clean Energy Initiative. The company “hasn’t made any final decisions at this time,” a spokesman said in an email.
The Community Innovation Grant is East Bay Community Energy’s first grant program, funding projects that benefit local, Alameda County communities while inspiring innovation
Oakland, CA (April 18, 2019) – East Bay Community Energy (EBCE) is Alameda County’s local community choice energy program and currently provides electricity services to over half a million customers across the county. EBCE is launching a new grant initiative and invites community-based non-profit organizations to apply for its Community Innovation Grant. The grant program is one of the early action items in EBCE’s Local Development Business Plan, which is a comprehensive framework to deliver benefits within Alameda County.
Proposed projects must align with EBCE’s mission to deliver social, environmental, and financial benefits to residents of Alameda County. Applicants can request up to $40,000 for an energy-related project. Specifically, EBCE is looking for proposals that will deliver local benefits to targeted communities in areas such as job creation, workforce development, economic empowerment, and climate and social resilience, as well as projects that advance innovation and collaboration. Programs such as community-shared solar, energy conservation retrofits, workforce development efforts engaging disadvantaged and/or displaced workers, and energy-related projects directly impacting disadvantaged communities in Alameda County can directly benefit from EBCE’s grant. In addition, these programs will bring direct benefits to program participants.
“We are excited to launch EBCE’s very first Community Innovation Grant outlined in EBCE’s Local Development Business Plan. Investing in our local communities while supporting innovative, energy-related projects that benefit our County is a priority for our organization,” said Nick Chaset, CEO of EBCE.
An online application is available Thursday, April 18, 2019. Applications are due on Friday, May 10, 2019. EBCE staff will host a webinar on April 25, 2019. To attend our webinar, please RSVP here. More information on the Community Innovation Grant program can be found at ebce.org/communitygrants.
EBCE is the local electricity provider created by the votes of 11 City Councils and the County of Alameda Board of Supervisors to provide low cost, cleaner power to our community. Launching to residential customers in November 2018, EBCE joined 19 other Community Choice Energy programs operating across California.
Gaps in resource procurement by California’s proliferating load serving entities (LSEs) could prevent the state from achieving its nation-leading renewable energy and climate goals.
The state’s massive renewable resource portfolio has gaps in it that threaten the reliable delivery of electricity, according to a March 18 proposed decision in the California Public Utilities Commission (CPUC) integrated resource planning docket. The docket was designed to address reliability in planning by assuring that variable resources are adequately balanced by resources that are available when needed.
That will require balancing “existing and new resources” with “baseload and intermittent resources” made up of “renewable, storage, and conventional fossil-fueled resources,” Fitch wrote. In the LSEs’ filings, “there is inconsistent, and in some cases, nonexistent, recognition of these realities.”
Participants in the planning process were concerned that California was going off course, until agreement began to emerge that Assembly Bill (AB) 56’s “backstop procurement entity” points toward a solution to the gaps in procurement. The bill got a big boost when an April 12 report from Governor Gavin Newsom’s specially-appointed “Strike Force” endorsed the backstop concept as a way to make procurement more efficient.
IOUs have not been procuring new generation because their customers are departing to community choice aggregators (CCAs) and electricity service providers (ESPs). But many LSEs are new and still getting financial and organizational foundations in place for procuring generation, many stakeholders, including CCA spokespeople, told Utility Dive.
When procurement was largely shared by Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E), each managed reliability in its territory. With procurement now disaggregated among many locally-focused LSEs, and levels of low-cost wind and solar rising, the system’s needs are evolving.
Firm resources like geothermal, biogas, pumped hydro and types of storage are needed to replace natural gas generation by 2030, studies from California agencies and research groups have reported. But those technologies are not yet cost-competitive, and CPUC analyses show they are not being procured by the new, cost-minded LSEs, which insist on making independent procurement decisions.
Fitch’s proposed decision opens a “procurement track” to study new reliability solutions. With PG&E in bankruptcy and all three IOUs facing another potentially catastrophic wildfire season, the legislative solution offered in AB 56 may be a faster track to reliability, spokespeople for IOUs, CCAs, ESPs and power providers told Utility Dive.
California’s procurement controversy
Disaggregation of generation procurement has led to controversy over whether the procurement process itself can be improved.
There are now 19 CCA programs serving over 10 million former customers of investor-owned utilities. Ten of them emerged in 2018. The CPUC expects CCAs to serve over 80% of IOUs’ current customers by the mid-2020s. There are 21 CPUC-registered ESPs now serving commercial-industrial (C&I) customers. Senate Bill 237, passed last August, increased ESPs’ allowed share of IOU C&I load to 15.4%.
Because of the rapid emergence of these LSEs, IOUs did not procure new renewables in 2016, 2017 or 2018, but have adequate contracted capacity to meet most of their 2030 RPS obligations, according to the CPUC’s November 2018 RPS report. CCAs and ESPs, though, “have an immediate RPS procurement need of approximately 6,900 GWh beginning in 2020.”
Administrative Law Judge Fitch agreed. “The individual resource choices by the LSEs collectively did not result in a diverse and balanced portfolio of resources needed to ensure a sufficiently reliable or environmentally beneficial statewide electricity resource portfolio,” she concluded.
“The pieces did not add up to the whole we were trying to plan for to meet the state’s 2030 GHG reduction targets,” Center for Energy Efficiency and Renewable Technologies (CEERT) Grid Policy Director Liz Anthony Gill told Utility Dive. For near-term planning, Fitch’s proposed decision ordered the use of an “optimized” resource portfolio developed early in the IRP process before LSEs submitted their plans, with procurements and costs allocated by the CPUC.
A centralized procurement process
The new IRP “procurement track” will study ways higher capital cost, zero emissions resources, like geothermal, offshore wind or pumped hydro storage, can be acquired to benefit the system, she added. “One possible solution is a central procurement entity.”
Data on CCA procurements shows a need for a solution to meet California’s 2030 renewables goals, Matt Freedman, senior staff attorney for ratepayer advocacy group The Utility Reform Network (TURN) told Utility Dive in an email. There are new long-term renewable energy contracts from only a small number of CCAs and many new CCAs “have yet to announce contracts for new resources,” he found. CEERT’s Anthony Gill agreed.
But CCAs are optimistic they can comply with any renewable requirements.
CCAs are governed by “local elected officials on our governing boards, but we are subject to CPUC jurisdiction and required to submit plans under the IRP,” EBCE Senior Director of Public Policy and Deputy General Counsel Melissa Brandt told Utility Dive. “There was a two-to-three-year procurement lull during the transition from IOUs, but we are on track to meet state mandates.”
Other stakeholders in the IRP process endorse LSEs’ right to procure independently, but are concerned about the gaps in procurement identified in ALJ Fitch’s proposed decision that were once filled by IOUs.
IOU “operational resources and balance sheets” have been used to meet state mandates, and LSEs have “the same obligation,” SDG&E VP for Energy Supply Kendall Helm told the Senate Energy Committee March 19. But gaps due to “decentralized decision making” could be filled by “a state Special Purpose Entity (or central buyer).”
CCAs can support a central buyer if it is limited to “residual central procurement” so that “LSEs would do their own procurement and the entity would fill the remaining gaps,” Brandt said.
California Assembly member Eduardo Garcia‘s AB 56 proposes that kind of entity. “It is ‘backstop’ procurement,” Garcia told Utility Dive. It would not impede individual LSEs, but “would be a tool in the regulatory agencies’ tool box to ensure California meets its renewables and climate goals without threatening system reliability or increasing ratepayers’ bills.”
AB 56’s California Alternative Energy and Advanced Transportation Financing Authority (CAEATFA) would be “a backstop procurement entity,” said TURN’s Freedman. TURN is a Garcia bill stakeholder sponsor.
“The public, non-profit corporation would be governed by a publicly-appointed board and procure for all retail electricity customers,” he said. “But only if the CPUC or the California Energy Commission (CEC) identified procurement needs and allocated it that responsibility.”
The Garcia bill backstop entity “is unique to California,” Freedman added. But similar procurement approaches are working in Illinois and New Yorkand by the state-regulated Efficiency Vermont.
“All procurement would be reviewed and approved by the CPUC or CEC, both in advance of and after it is identified,” Freedman said. “Some people suggest it could go rogue, do whatever it wants, and send the bill to the state, but the Garcia bill expressly prevents that.”
With agency approval, CAEATFA could do five types of procurement. It could procure to meet state mandates or a Resource Adequacy program need for local reliability. Third, it could fill gaps left by LSE IRP plans. Fourth, it would allow LSEs to pool resources for RPS procurements. Finally, it could manage abrogated IOU generation contracts, such as from a bankruptcy.
Another advantage of the Garcia bill entity would be its ability to leverage state funds, incentives and public financing mechanisms to minimize LSE costs, which would lower customer rates, Freedman said. CAEATFA would also relieve IOUs of backstopping reliability and allow refocusing on “their distribution and transmission assets and their customer facing services.”
Critically, the entity would protect the autonomy of CCAs and ESPs to procure independently in the absence of a reliability need identified through a public regulatory proceeding, he stressed.
This type of “backstop procurement entity” may be a solution for meeting system needs that CCAs, IOUs, generators and other stakeholders can all endorse.
“Our understanding is that the proposal in the Garcia bill is intended to be for a residual central procurement entity,” Brandt said. “We are going to work with Assemblyman Garcia’s office to clarify that.”
But SCE and others have doubts about the viability of such a backstop.
The existing mechanisms for backstop procurement have been effective, and if ESPs and CCAs allow commission oversight of their planning, “central procurement can be small,” SCE’s Cushnie told the Energy Committee. But if “city councils and county supervisor boards” continue to direct their planning, “there will be large gaps” and a “central buyer will have to do lots of procurement.”
California’s power system “needs to be centrally planned,” he insisted. “We can’t be fighting one another on that.”
“But some LSEs may leave procurement entirely to the backstop entity,” he said. “There has to be a balance between giving the backstop authority to fill gaps and leaving all procurement to it. We have some concerns that Garcia may give the backstop entity too much authority.”
The new LSEs are not procuring renewables “in the magnitude and volume the IOUs once did, and procurement changes could destabilize California’s power market,” American Wind Energy Association California Caucus Director Danielle Mills said. “We are looking for principles that will stabilize it.”
If AB 56’s entity “could manage existing IOU contracts in a bankruptcy, and keep procurement going, that would be valuable,” she told Utility Dive. “But there is only value if the entity simplifies procurement.”
The IRP proceeding has led to a lot of learning about planning, “and it is messy, and it needs to evolve, but it is too soon to rush to the conclusion that the process is broken,” EBCE’s Brandt said. “Central procurement is one solution. CCAs have proposed others.”
The CPUC could “just order more or different procurements if LSE plans do not meet state goals,” she said. “That is simpler. There is no need for a new state agency if the CPUC can order an LSE to obtain a certain amount of a resource at a specific location to comply with its IRP obligation.”
The Garcia bill is “jumping the gun” because the IRP proceeding has not concluded central procurement, even using a residual model, “is the only way to close gaps in LSE procurements,” Brandt said. It may be acceptable to CCAs if it does not “limit our ability to procure and it addresses only the unmet need.” But, first, the CPUC “must clearly establish a need and give LSEs an opportunity to procure.”
The Garcia proposal “will expand a discussion that has been going on in California for years about some kind of backstop procurement entity” to head off any reliability crisis caused by disaggregated procurement, TURN’s Freedman said. “There is no crisis now, but we need to get ahead of this dynamic and evolving market with a plan that is robust and adaptable because making policy in a crisis almost guarantees a bad result.”
With increased uncertainty from so many factors, “letting the market work could mean more of the same gaps in procurement,” Garcia told Utility Dive. New resources and technologies and new threats from wildfires and utility instabilities call for “a hands-on approach.”
After wildfires caused power outages in California, the tinder box state is considering more microgrids in a proceeding before state regulators.
“Wildfires are now to California what Sandy was to New York,” said Rick Bolton, CEO of Compass Energy Platform, referencing the 2012 superstorm that spurred a government push for microgrids after eight million people in the Northeast lost power, some for weeks.
During wildfire season in California, power outages come about both accidentally and intentionally. Sometimes lines and equipment get destroyed in the flames; other times they appear to cause the fires. And in still other cases, utilities shut off power to avoid danger when conditions become ominous. The fire may be many miles away from the customers who lose power.
In the proceeding before the Calfornia Public Utilities Commission (R.18-10-007), several parties recommend microgrids as a way to keep electricity flowing locally when fires — or the threat of them — lead to service loss.
Pacific Gas & Electric (PG&E), which serves a 70,000 square-mile swath of the state, contemplates microgrids as part of resilience zones, areas with grocery stores, gas stations and other critical services. The microgrids would keep the zones energized when the grid is down.
Small businesses need microgrids too
One example is Angwin, a town in Napa County, where the utility is working with Pacific Union College to incorporate its cogeneration plant into the zone. During dangerous conditions, the utility hopes to safely energize a fire station, gas station, apartment building and a plaza.
Small Business Utility Advocates (SBUA) called for all utilities to follow PG&E’s lead and include microgrids as part of their now required fire mitigation plans.
The group wants small businesses included in microgrid service. Power outages jeopardize “health and safety” and sometimes local businesses are the only suppliers of goods and services in the area, argued the SBUA in a recent filing.
“At a minimum, these programs should reach out to hard-to-reach commercial customers,” the small business group said.
Communities take action
Community choice aggregations also are looking to develop microgrids in fire planning. Also known as municipal aggregations, CCAs are run by local governments that procure power on behalf of their citizens and businesses, while continuing to use the local utilities transmission and distribution lines.
Utilities tend to rely on diesel-fed mobile generators for emergency service. But CCAs are demonstrating that “low- or no-carbon alternatives to mobile generation sources, such as microgrids and associated storage, are just as reliable, feasible, and cost-effective in many circumstances, and also provide a long-term solution,” said a joint filing by solar energy company Sunrun and Peninsula Clean Energy Authority (PCE), a CCA in San Mateo County.
Microgrids represent a relatively new concept that requires adapting existing frameworks. Because of that, projects must involve careful coordination between the developer, utility and the developer’s energy consultant to ensure a successful outcome. Download the new white paper from Velioa that explores how to navigate local utility requirements for microgrids.
The aggregation has funded a pilot project to install small solar and storage projects at local faith organizations to support resilience locations within neighborhoods. In addition PCE is working in partnership with another CCA, East Bay Community Energy in Alameda County, to identify resilience locations in each of their territories. That project is funded by the Bay Area Air Quality Management District.
Another CCA, Redwood Coast Energy Authority in Humboldt County, is developing a microgrid to improve resilience with less diesel-fired back-up generation.
PCE expects last year’s passage of SB 1339 to spur more microgrids by making clear that “customer development of microgrids is a legislative priority.” The new law requires state regulators to consider a tariff or other mechanism to support microgrid development.
But the next wildfire season is just a couple of months a way. While the state is one of the most active in the US for microgrid development, it still has a long way to go before there are enough microgrids to provide serious coverage during outages. Even PG&E’s resilience zones are still in the pilot stage. So the fear is that Calfornia communities will find themselves after the fact again saying, if only…
The California Public Utilities Commission has approved two sweeping programs in recent years to spur community solar construction in the state, but the market has yet to gain real traction. Solar developers are now scrambling to organize projects as these programs advance and new opportunities crop up.
“There is not a community solar market yet, but we’re about to experiment with it in a real way,” said CPUC Commissioner Martha Guzman Aceves, in an interview with GTM.
California is a leader in U.S. solar development, but the state has deployed few community solar projects so far, with a little more than 100 megawattsof mostly one-off projects built to date. Community solar has not found fast footing in the state. Today, there are still virtually no up-and-running community solar projects within California’s investor-owned utility territories, which make up the majority of the state.
That’s a problem, as millions of people across California rent their homes or are otherwise unable to install rooftop solar. Community solar provides an access point for these people.
“There are a lot of obstacles to get on the roof to install solar when you don’t own it,” Guzman Aceves said. “At the most basic level, our plan gets to a significant population in California that would never have access. This is a really good thing, in that regard.”
The first program, adopted by the CPUC in January of 2015, is dubbed the Enhanced Community Renewables program. Under that policy, which was created by Senate Bill 43, developers market community solar directly to customers as an electricity product. Customers can buy a share of a local solar project directly from the developer and then receive credit for avoided generation costs from the utility. The program is one slice of the state’s 600-megawatt Green Tariff Shared Renewables portfolio, but there is no specific carve-out for community solar.
At present, just over 7 megawatts’ worth of projects are under construction or seeking approval through the Enhanced Community Renewables program:
In Sheep Creek near Victorville located in Southern California, developer Jaton is working on a 3-megawatt solar farm in Southern California Edison’s territory territory. Jaton formed in 2016 and seeks to take advantage of the state’s community solar programs.
In Campo, a town along the Mexico border, ForeFront Power is developing a 2.4-megawatt project with San Diego Gas & Electric.
In Fresno County in Northern California, ForeFront is working with Pacific Gas & Electric (PG&E) on a 1.656-megawatt project.
While the going is rough, ForeFront is emerging as a key developer in California’s fledgling community solar programs. In 2018, PG&E put out a call for community solar proposals, and ForeFront submitted 11 projects that exceed 37 megawatts of power, all of which have the potential to come online in the future. In a public letter dated February 4, 2019, the utility noted that ForeFront’s projects were “selected for award and continued participation.”
One issue with the Enhanced Community Renewables program is that the solar comes at a premium, rather than offering customers savings, because these projects don’t qualify for net metering credits. PG&E started offering community solar at a premium in 2015, and it’s taken years to see any real action.
Disadvantaged communities solar tariff
Last June, the CPUC approved a second program, the Community Solar Green Tariff, that opened a pipeline for another 41 megawatts of community solar. The tariff stems from a provision of the 2013 bill AB 327 — sometimes called the “rate reform bill” — that requires growth of the solar industry in what the state calls “disadvantaged communities.”
The program creates a 20 percent bill reduction for people who live in areas with lots of air pollution and poverty and who want to participate in community solar. The projects must be located within a 5-mile area of their home. Solar developers and utilities operate with traditional power-purchase agreements.
In Southern California, SCE is well positioned to take advantage of the new tariff. Nearly half of the neighborhoods that qualify for this new program are within its territory, according to the utility.
“We found that our existing solar penetration is in this area already,” said Jessica Lim, SCE’s principal manager of product management, customer products and services. “That is where most of the solar projects are coming, from and customers can benefit from the savings in that area.”
SCE estimates that it can service 5,200 customers with the 18 megawatts allotted to the utility under the program.
The Enhanced Community Renewables program and the Community Solar Green Tariff program aren’t the only pathways to deploying solar in the Golden State.
Last year, SCE proposed a suite of community oriented solar programs to address some of the other programs’ pitfalls. Customers with Sacramento Municipal Utility District can already participate in a separate community solar program. Local organizations that procure power for residents, the community-choice aggregators (CCAs), are also developing their own initiatives.
Guzman Aceves said the CCAs aren’t burdened by the same regulatory restrictions as utilities. “The CCAs can do something quicker, theoretically, and that’s a good thing,” she said. “They have a lot more flexibility.”
When it comes to the Community Solar Green Tariff, however, CCAs could create a pain point.
SCE’s territory in particular includes many “disadvantaged communities” that qualify for the program, but a lot of these communities overlap with CCA territory, which could create problems if the local groups pursue their own community solar programs. PG&E has less overlap between its qualifying neighborhoods and the CCA service area within its territory, which means that it might be in a position to move more quickly, according to Guzman Aceves.
“One message I have for the CCAs and the utility is to make sure to work together on these types of projects,” Guzman Aceves said. “Do not make it be another five years of pointing fingers at each other, but [rather] see this as an opportunity for collaboration.”
Regulators are currently reviewing proposals under the Community Solar Green Tariff, which is expected to come online in the second quarter of 2019.
Proposal backers believe that building solar within polluted neighborhoods will reduce air pollution, but some developers complained that the program’s constraints are too tight and might limit growth.
Brandon Smithwood, policy director for the Coalition for Community Solar, said: “You’re asking developers to find a place where you have enough customers and where you can interconnect to the distribution grid. There are only so many places on the grid that you can practically plug into. And then this adds the requirement that all of your customers have to be in a small geographic area around the projects.”
He added that the CPUC’s new community solar contracts are a good sign, but they don’t guarantee that anything will be built.
“Whether these programs can work at all is still an open question,” Smithwood said. “Then, I think it’s clear that they’re not scalable. You have very complicated programs that don’t really fit in with the megatrends of the state.”
Instead, Smithwood argues that community solar can be used as a way to expand and experiment with successor programs to net metering. “That’s a way to create a community solar program that’s not these individual programs that have a ton of really complex requirements and restrictions,” he said.
Guzman Aceves expressed concern about introducing a net energy metering (NEM) structure for community solar because of what she called a rise in predatory actions by electricity service providers.
“There is a gaming that can occur with NEM that can’t occur with a fixed tariff,” she said. “It’s not all developers that use that approach, but it is happening with the NEM structure, particularly in low-income communities, monolingual and elderly households, and that’s a real big problem.”
SCE’s suite of community programs
Last September, SCE asked regulators to approve a slate of community-oriented clean energy options. At the time, it acknowledged that the current program for community solar wasn’t working very well.
It crafted an alternative set of programs. Altogether, SCE’s proposal generates 181 megawatts’ worth of new projects, with a 45-megawatt carve-out for low-income participants. The utility estimates the suite of programs could serve more than 82,000 customers.
With one initiative, SCE could aggregate customers for community solar projects itself, rather than solicit a developer or a community-based organization to do that work through contracts.
“Today, with our current program, we don’t really have a direct role in the formation of a community solar project,” Lim said. “We facilitate a solicitation process for the market. With this new program, assuming it is approved, SCE will be right in the middle. We’ll be the connector with customers and with communities.”
“Community solar is an important part of our clean energy future,” Lim said. “For us, it’s still in its infancy. We just want to grow this program and try to be innovative in how we approach this by emphasizing disadvantaged communities.”
CPUC officials are currently reviewing the proposal, and approval is not guaranteed. In a memo, officials questioned whether SCE could end its existing program without violatingregulations.
CCAs and community solar
East Bay Community Energy, an Alameda County-based CCA, is developing a program that the group’s top executive Nick Chaset calls “a version of community solar more tailored to local governments.”
The idea is to pair city loads with renewable generation. If the program can scale, it will be be accessible to all of the group’s customers.
Chaset said that unlike the CPUC programs, there would be no third-party project owner. Instead, the city would contract for the project directly through the CCA.
Customer demand would be the only cap on the program’s growth. Projects could be built locally or located farther away.
“What differentiates this concept from a standard 100 percent renewable energy product is temporal commitment,” Chaset said. “Municipalities commit for a longer period of time, and that’s what gets the project built in the first place.”
“We are a community-owned provider,” he said. “In some ways all our solar is community solar.”
Energy and equity
Grid Alternatives, one of the largest nonprofit solar installers in the U.S., is also moving into community solar in Southern California.
It is working with SCE, the Greenlining Institute, and other policy and advocacy organizations on a pilot initiative called the Clean Energy Access Working Group. The goal is to create community solar projects that are designed, led and owned by local groups.
While still in development, one potential site is in Compton on land owned by Ujima Housing Corporation, a nonprofit group, according to SCE.
Michael Kadish, Grid Alternative’s executive director for the Los Angeles area, said it’s important for community solar projects to provide customers with real financial savings, and the group is exploring additional community solar options. “We’re accustomed to saving people 80 percent on their energy bill,” he said. “That’s the level of benefit we’re looking to provide.”
The group recently hosted a conference on the subject in Los Angeles. The meeting explored successful models from across the country and pathways to improve programs in California.
“Community solar is interesting and holds potential for us, if you understand our mission,” Kadish said. “We care about bringing the benefits of renewable energy to underserved communities where most people are actually renters.”
Community solar holds potential for a lot of stakeholders in California. The challenge has been and will continue to be finding ways to harness that opportunity.
As community-choice aggregation (CCA) ramps up around the state of California, a myth has taken hold that CCAs are not signing contracts for new energy supply. But new data shows that CCAs have actually been busy contracting for over 2,000 megawatts of new renewable energy — with more to come.
Investor-owned utilities, meanwhile, have gone on hiatus, not even looking at new renewables for the past three years.
“These programs produce very little new renewable energy, instead buying from existing sources, including out-of-state wind and solar farms,” Jerry Sanders, former mayor of San Diego and head of the San Diego Regional Chamber of Commerce, said of community choice initiatives.
A related myth is that CCAs are unable to sign long-term contracts because they don’t have a credit rating. Only MCE Clean Energy, after all, has a rating, which it got from Moody’s last May.
So what is really going on? As customers departed in droves for CCAs throughout 2017 and 2018, investor-owned utilities (IOUs) have been left with an excess of the renewable energy they need to comply with the state renewable portfolio standard. As a result, IOUs did not conduct annual RPS solicitations in 2016 or 2017, nor did they plan to undertake solicitations in 2018, according to the California Public Utilities Commission’s RPS annual report, released in November.
The report also says that the nine CCAs in service in 2017 had an average RPS position of 49 percent, well ahead of RPS schedules. But load served by CCAs is rapidly increasing, with 10 new CCAs starting up in 2018. “As the RPS requirements increase and more CCAs fully come online,” the CPUC report says, “there will be a near-term renewable procurement need.”
In total, the CPUC says CCAs will need to procure “approximately 6,900 [gigawatt-hours] beginning in 2020,” plus more to meet the 60 percent RPS target by 2030.
And CCAs are busy doing exactly that.
Two gigawatts and counting
Our state trade association, CalCCA, recently released data showing that six CCAs have so far signed long-term contracts for over 2,000 megawatts of new renewables. Of the 56 contracts they tallied, 38 are for 20 years or longer. Only three are for less than 10 years.
CCAs passed the 2-gigawatt milestone in October when Monterey Bay Community Power and Silicon Valley Clean Energy jointly approved contracts for 278 megawatts of solar, coupled with 340 megawatt-hours of battery storage for two separate projects to be built in Kern and Kings Counties. That is the largest solar-plus-storage procurement to date in California. That same month, Peninsula Clean Energy broke ground on a 200-megawatt solar project supported with a 25-year contract.
Altogether, CCAs signed up for about 1,000 megawatts of new renewables under long-term contracts in 2017. And more contracts are on the way.
So far, every CCA in California plans to procure more renewables than is required under the RPS, and far ahead of schedule. Most are being driven by their member communities. Ten communities in the Clean Power Alliance, for example, recently voted to go 100 percent renewable as soon as CPA starts operations this year.
CCAs that are just getting started are proving ready to solicit long-term contracts right out of the gate. To get ready for our residential launch last November, East Bay Community Energy, the CCA I lead, issued a solicitation last June for California-based renewable energy from new projects, with at least 20 megawatts from local projects. We got a very robust response to the RFP from many suppliers and are in the process of negotiating 15- to 20-year agreements for about 600-700 megawatts‘ worth of new contracts.
How can we and other CCAs sign contracts without a credit rating? The workaround is simple; it’s called a “lockbox.”
CCA revenues are put in a bank account, with instructions that the bank use the funds to pay for PPAs first. Only after the PPAs are paid can the CCA withdraw funds for other purposes. This easy fix has made counterparties comfortable enough to sign billions of dollars’ worth of contracts so far.
Contracts big and small
The contracts signed to date support 1,360 megawatts of new solar, 741 megawatts of new wind, and 12 megawatts of new biogas. Interestingly, all but one of the projects are in California, belying the related myth that CCAs are supporting “out of state” power suppliers.
Timeline of Operation Dates for CCA-Supported New Renewables
MCE Clean Energy, the oldest CCA, has signed the most contracts, at just over 900 megawatts. MCE’s diverse portfolio includes 36 contracts ranging from three to 25 years in length, and from 60 kilowatts to 160 megawatts. Over 400 megawatts of its new renewables capacity came online last year. MCE got a favorable review and rating from Moody’s Investors Service in May, the first CCA to to be rated.
Signed Contracts for Wind, Solar and Biogas
Monterey Bay Community Power and Silicon Valley Clean Energy have teamed up on their procurement efforts, signing contracts for three big wind and solar projects — coupled with batteries — that will come online in 2021. The average length for those contracts is 16 years. Monterey Bay is in its first year of operations, initially beginning to serve residential customers on July 1, 2018, while Silicon Valley went live in April 2017.
One of the smallest CCAs, Lancaster Clean Energy, has set “a lofty goal of becoming the nation’s first net-zero city.” Lancaster, a desert town of 160,000, was the first city in America to require all new homes to have solar; it has also converted all city buses to electric. Lancaster Clean Energy took a step toward its net-zero goal by signing a 20-year contract for a 10-megawatt solar farm just outside of town, enough to power 1,800 homes.
CCA Renewable Energy Contract Duration
While 2,000 megawatts is an impressive start, more needs to be — and will be — procured. Gov. Jerry Brown signed SB 100 into law in September, committing the entire state to at least 60 percent renewable electricity and 100 percent zero-carbon power by 2045. CCAs will be on the front lines of achieving that goal as quickly, reliably and affordably as possible.
A broad coalition of community energy choice groups from across Northern California called last week for a sweeping restructuring of Pacific Gas & Electric, in the wake of the utility’s unfolding bankruptcy. The groups argue that the state’s largest utility should get out of the retail energy business altogether, and instead focus on the distribution and transmission of power.
The California Community Choice Association (CalCCA) and community-choice aggregators (CCAs) pressed their case in a new filing with the California Public Utilities Commission. They claim that CCAs should take over the role from the utility in generating and procuring electricity for communities, and that PG&E should transform into a “wires-only” company.
The association argues that the ownership and maintenance of the power grid and the natural-gas system is the utility’s core business from a shareholder perspective. “That’s where they derive the vast majority of their revenues and profits,” said Nick Chaset, a CalCCA board member.
“This restructuring is important as it allows for PG&E to be focused on the safety and reliability of that infrastructure,” Chaset said. “The reality is today that PG&E spends a considerable amount of time and resources on the provision of energy supply. I think that in light of all the challenges that they have had and continue to have dealing with the safe operations of their system, the time is right now for them to focus on those critical tasks.”
PG&E is saddled with debt, and its liability from sparking wildfires could soar into the billions of dollars. The utility recently filed for bankruptcy protection, which has sparked a major debate over PG&E’s future.
As a decoupled utility, PG&E’s profits are separated from the amount of energy it sells, and it makes most of its money through a regulated rate of return on capital investments, such as building infrastructure projects and software for its customers. That means the utility shouldn’t be entirely averse to becoming a poles-and-wires company.
Other utilities in California are exploring this option. The San Diego Gas & Electric is leading the charge for utilities wanting to transform into transmission and distribution businesses. Recognizing that CCA programs are taking root in Southern California, SDG&E is searching for a pathway out of power generation.
PG&E has indicated that it is also open to the idea, but with reservations.
PG&E makes its case
Removing PG&E from the power generation business will likely require passing state legislation, but the California Public Utilities Commission could move the process forward by making it easier for CCAs to form and to operate. Community-choice agencies already serve more than 2.4 million of the 5.4 million customers in PG&E’s service territory, with more growth by the CCAs planned in 2019.
A spokesperson for the utility wouldn’t comment on the prospect of becoming a wires-only entity. Instead, the representative referred to a separate brief PG&E filed with state regulators, in which the utility said it “supports consideration” of providing only transmission and distribution services, but warned that the municipalities and CCAs taking over its generation services must prove that they can effectively manage the task.
“Given that generation services carry unique risks, the potential benefit of a wires-only company would be that, by reducing the total number of risks managed by PG&E, it could lead to better management of the remaining risks,” PG&E wrote. “The Commission would need confidence that the entity or entities assuming operations would manage risk as well or better, or overall public safety risk would not improve.”
In its comments, PG&E suggests it is better prepared to handle the risks associated with generating power, noting that the wires-only proposal would “pose several challenges and take considerable time to implement.” One challenge is that PG&E would no longer have an obligation to be the energy supplier of last resort, and would no longer be responsible for procuring power for customers should their new provider exit the market for any reason. This aspect alone prompts a lot of questions.
Additionally, the utility said that “there are no direct, public safety risks” associated with its operations for procuring and generating energy.
For their part, the aggregators cast themselves as vehicles for the speedy development of technological innovation and climate policy, and they say they are in better position to quickly act on this issues than PG&E. They also say that they are better equipped to meet the specific demands of communities and should be given the opportunity to aggressively pursue local control of retail power generation.
CalCCA criticized PG&E for what the group calls a “dismal safety record over the past 20 years.”
“Clearly, the status quo for providing electric utility service in Northern California is no longer tenable in light of PG&E’s deplorable safety record. As PG&E moves into yet another bankruptcy, the Joint CCAs strongly endorse movement toward more alternatives for safe, reliable, and cost-effective electric power supply to Californians through locally controlled public agencies.”
Chaset, who is also CEO of East Bay Community Energy, agrees that PG&E’s retail and generation businesses do not pose any risks to the public.
“That’s exactly the point that we’re making,” he said. “There are considerable resources that PG&E as an organization is expending on things like operating and procuring energy, or operating solar plants, and that work does not contribute to their overall operating operational safety. Our view is that they should be focused first and foremost on the safe operations of their grid.”
“Having a retail generation business does not contribute to that,” added Chaset.
“The core choice”
Community-choice aggregators already service 46 percent of the retail electric customer load in PG&E’s territory. The recently filed comments represent a push for greater control over the power business and its financing across the state. The documents were signed by the East Bay Community Energy, Peninsula Clean Energy Authority, Pioneer Community Energy, Silicon Valley Clean Energy, Sonoma Clean Power, Valley Clean Energy Alliance, and the City of San Jose.
The groups are also asking for local control over a wide range of energy programs from demand response, to energy efficiency measures, to electric vehicle initiatives. Power generation aside, it would be a big lift for the aggregators to assume control of the teams of people that manage these programs and interact with customers and the software that allow them to operate.
If the groups take over the power generation business from PG&E, it could undercut a key argument for community-choice aggregation. CCAs have long argued that the programs bring healthy competition to the power utilities, which otherwise operate as regulated monopolies.
But Chaset said that community choice isn’t only about competition; it’s about local control over energy decision-making.
“The core choice remains,” he said. “And that core choice is the one the community makes every month at the board meeting, where a group of local elected officials meet to decide on key operational questions. ‘How much renewable energy do you want to procure? What kind of local investments do you want to make? What should the rates be?’ And that will remain.”
Seventy miles north of downtown Los Angeles, where the Mojave Desert gives way to the San Joaquin Valley, three newly built wind turbines stand atop a ridge overlooking State Route 58. Strong gusts emerge from the mountain pass below, making this an especially windy spot in one of the windiest parts of California.
A few new turbines aren’t normally a big deal in the Golden State, which has been building wind farms for decades.
But these particular machines are at the heart of a revolution in California’s energy industry, which for millions of people, homes and businesses could mean an end to buying power from monopoly utilities such as Southern California Edison.
The three wind turbines at the top of the ridge — and three others nearby — recently started generating electricity for Clean Power Alliance, a government-run energy provider that is replacing Edison as the power source for more than 1 million homes and businesses across the Southland. Twenty-nine cities have joined Clean Power Alliance, as have unincorporated areas in Los Angeles and Ventura counties.
Residents of those areas will start receiving electricity from Clean Power Alliance in February. Edison will still distribute power over the poles and wires of the electric grid, and the Rosemead utility will send out the bills. But the alliance will buy and sell power, set rates and decide what incentives to provide customers for reducing their consumption or going solar.
Clean Power Alliance launched for a small group of customers last year, rolling out electric service to city governments and 30,000 businesses in parts of Los Angeles County. But next month will serve as the alliance’s grand opening. By the end of February, it will be California’s fifth-largest power provider, after Edison, Pacific Gas & Electric, San Diego Gas & Electric and the Los Angeles Department of Water and Power.
That fact is especially striking given Clean Power Alliance’s start-up-like working conditions. The alliance has 13 employees and is based in a WeWork shared-office space in downtown Los Angeles, with living-room-style lounges and Instagram-worthy neon lights.
“We’re not a bunch of people who were running some other public-sector something or other. We’re bringing a business savvy to this that is really important for our size and our ambition,” said Ted Bardacke, Clean Power Alliance’s executive director and a former infrastructure director for Los Angeles Mayor Eric Garcetti.
Clean Power Alliance customers can choose among three electricity rate plans: one with a 36% renewable energy mix that’s slightly cheaper than Edison’s base rate, one with 50% renewables that’s on par with Edison and one with 100% renewables that’s more expensive than Edison. They can also opt out of Clean Power Alliance service and return to Edison at any time.
Local governments across the state have been forming these so-called community choice aggregators, or CCAs, to reduce rates and increase the use of climate-friendly energy sources such as wind and solar.
The CCA push started in the Bay Area a decade ago and more recently spread to Southern California, where efforts are also underway to establish community choice programs in San Diego, Riverside County and other areas.
Community choice providers are different from municipal utilities such as the DWP or Burbank Water and Power. Unlike municipal utilities, they’re not responsible for owning or operating the electric grid. Their role is to buy and sell the electrons that flow through power lines controlled by investor-owned utilities such as Edison.
Advocates say CCAs are an improvement on investor-owned utilities because they shift control from private monopolies to local governments, giving communities the ability to set their own rates, buy as much clean energy as they want and find creative ways to encourage clean energy technologies including rooftop solar, electric cars and microgrids.
There are now 19 community choice programs operating in California, 14 of which have launched in the last two years, according to the Center for Climate Protection, a nonprofit advocacy group.
What does community choice mean for clean energy?
Although CCAs are an increasingly popular option, the rapid expansion of community choice has caused some renewable energy developers to worry about potential unintended consequences.
California has tripled its use of renewable energy in the last 15 years, in large part by requiring utilities to replace fossil fuels with solar, wind and other renewable power sources. Most of the work has been done by Edison, PG&E and SDG&E, which serve about two-thirds of electricity demand statewide.
In 2017, Edison’s power supply was 32% renewable, PG&E’s was 33% and SDG&E’s was 44%, according to the California Public Utilities Commission.
The rise of community choice — and the loss of customers for the monopoly utilities — has fundamentally changed that model. State officials estimate that Edison, PG&E and SDG&E could lose 85% of their energy sales by the mid-2020s. With far fewer customers, they won’t need nearly as much clean electricity to meet the state’s upcoming targets of 60% renewable energy by 2030 and 100% climate-friendly energy by 2045.
Edison already has enough projects under contract or in development to meet the 2030 mandate, said Colin Cushnie, the company’s vice president of energy procurement and management. And with uncertainty over how many Edison customers will ultimately depart for CCAs, it’s not clear if or when the utility will sign more renewable energy contracts, which typically have a life span of 20 to 30 years.
“Since we’re meeting our statutory requirement,” Cushnie said, “we’re taking a hiatus at this point in time.”
Community choice providers are required to meet the state’s renewable energy targets too, and they’ve been picking up some of the slack as the monopoly utilities sign fewer contracts. Overall, CCAs have signed long-term deals for more than 2,000 megawatts of new renewable energy capacity, mostly solar and wind farms.
Clean Power Alliance’s six new wind turbines in Kern County are a small example.
“A lot of new steel has gone into the ground thanks to the CCAs,” said Don Vawter, director of origination and development for Terra-Gen, a New York-based energy developer that built the turbines for Clean Power Alliance.
But some renewable energy developers aren’t sure the CCAs can meet the state’s goals over the next few years. They say the newly formed entities don’t have credit ratings or much of a financial history, which can make it difficult to persuade lenders to fund construction of solar and wind farms.
The vast majority of the long-term clean energy contracts signed by CCAs so far have been inked by Marin Clean Energy and Sonoma Clean Power, the two community choice programs that have been around the longest.
“All the new ones that are being stood up today are struggling to figure out how they can obtain creditworthy status and contract for power,” said Bill Miller, an executive at Anschutz Corp., which has been working to build a huge wind farm in Wyoming and sell the electricity in California. “They can do some near-term, short-term contracts … but to enter into long-term, reliable contracts is very difficult for them.”
Short-term contracts to buy clean electricity from existing projects can help CCAs meet their renewable energy goals for a few years. But in the long run, the state’s next climate change target — reducing carbon emissions 40% below 1990 levels by 2030 — will require huge amounts of new renewable energy capacity to be built.
The Large-Scale Solar Assn., a Sacramento-based trade group, estimated in September that CCAs needed to strike deals for an additional 5,000 megawatts of clean power by 2021 to meet the state’s long-term contracting requirements.
“There’s market uncertainty in terms of who’s going to buy, when are they going to buy,” said Rick Umoff, California director of state affairs for the Solar Energy Industries Assn., a national trade group. “It’s unclear if the CCAs are even equipped to buy the energy they need to meet the [renewable energy] targets.”
‘You have to figure out a way to get comfortable’
Community choice advocates say those concerns are overblown and don’t reflect the views of most renewable energy developers. They say the CCAs have met or exceeded the state’s clean energy targets so far and will continue to do so.
Nick Chaset, chief executive of East Bay Community Energy in Alameda County and a former chief of staff to California Public Utilities Commission President Michael J. Picker, noted that several of the country’s biggest clean energy developers, including NextEra and EDF, have done deals with CCAs. He said community choice programs have shown banks that customers will pay their bills and are unlikely to opt out of CCA service and return to the investor-owned utilities.
Chaset suggested that renewable energy trade groups skeptical of community choice were behind the times and haven’t caught up with the reality that their members are figuring out how to work with CCAs.
“They’re used to a certain system,” Chaset said, “and they’re struggling with the fact that the system is changing.”
It’s no longer just well-established CCAs that are signing long-term contracts. Silicon Valley Clean Energy and Monterey Bay Community Power, which launched in 2017 and 2018, respectively, have entered into three long-term contracts together, including deals with the developers Recurrent Energy and EDF for solar farms paired with battery storage.
The CCAs say those projects are the largest solar-plus-storage facilities ever contracted in California. Silicon Valley and Monterey Bay also signed a contract with Pattern Energy for 200 megawatts of wind power from New Mexico.
There are other examples of CCAs banding together to buy energy. Several CCAs have joined the Lancaster-based California Choice Energy Authority, which has negotiated contracts on behalf of its members.
Clean Power Alliance was able to get its first six wind turbines built because they’re part of a larger wind farm development, with more established buyers committed to buying most of the energy. But now the CCA is evaluating long-term contract offers from more than 50 developers, including proposals for solar, wind and battery storage.
The alliance might not have gotten so many offers a few years ago. But banks and energy companies are coming around on the CCAs, said Matt Langer, Clean Power Alliance’s chief operating officer and a former Edison employee.
“The developers have recognized that if you want to be developing renewable energy in California and the West, then who’s buying? It’s the CCAs,” Langer said. “So you have to figure out a way to get comfortable.”