Addendum to Community Solar Pilot Program NOFA

The California Department of Community Services and Development (CSD) has issued an Addendum to the Notice of Funding Availability (NOFA) for the Community Solar Pilot Program (2018 – NOFA – 62). The Addendum was issued in response to questions and comments received during the NOFA’s questions and answer period. The updated NOFA, Addendum Table, related documents, and Questions and Answers on the NOFA have been posted at

The deadline for proposals in response to the Pilot Program’s NOFA is October 2, 2018. Also posted on CSD’s website is a webinar link to the recording of the recent technical assistance webinar, “Best Practices in Solar Development and Oversight.” Interested parties may register to view this webinar recording at: Please note that the presentation ended early due to the expiration of the reservation time.

Stakeholders may also be interested in a recent webinar presented by the Clean Energy States Alliance (CESA), “Community Solar Program Design and Implementation for Low-and Moderate-Income Customers.” Slides and a recording of this webinar are available at:

CSD’s Community Solar Pilot Program is part of the Low-Income Weatherization Program, a California Climate Investments program funded from the State of California’s Cap-and-Trade auction proceeds through the Greenhouse Gas Reduction Fund.


About CSD
Under the umbrella of the California Health and Human Services Agency, CSD’s mission is to reduce poverty for Californians by leading the development and coordination of effective and innovative programs. For more information about CSD visit

California customer choice at a crossroads: Regulators to weigh 3 key issues next week

California regulators are poised to decide soon between two proposals on how to calculate the exit fee charged to customers moving away from California’s investor-owned utilities (IOUs) to new electricity providers. The result could determine the near-term viability of California’s budding customer choice movement.

Regulators face three big questions on how to calculate the Power Charge Indifference Adjustment (PCIA), a small per-kWh amount added to the bill of a departing customer that compensates the utility for investments made in anticipation of serving that customer.

The first question is whether the PCIA should include the cost of high-priced utility-owned generation the IOUs might long ago have sold off. The second question is whether it should include the cost of somewhat newer but still high-priced utility-owned generation added to IOU portfolios largely for reliability purposes. And, finally, regulators must decide how, if at all, to limit the size of changes in the value of the PCIA.

The answers could make the PCIA too high for new customer choice-inspired load serving entities (LSEs), including Community Choice Aggregators (CCAs) and direct access providers, to fulfill commitments to deliver cleaner energy at a lower cost. Or it could put the state’s IOUs at financial risk.

Two alternatives in phase one

One approach to updating the PCIA calculation can be found in an Aug. 1 proposed decision by California Public Utilities Commission (CPUC) Administrative Law Judge Stephen C. Roscow; another approach in an Aug.14 alternate proposed decision by CPUC Commissioner Carla Peterman.

Both found that the CPUC’s current PCIA methodology cannot prevent cost shifts between customers. But that’s where the similarities end. On Sept. 27, the commission is poised to vote on what the new PCIA calculation should be.

But while the decision will be important to the continued expansion of the customer choice movement, it is just one phase in the process of updating how the PCIA is calculated and even bigger challenges lie ahead.

A second phase will take on bigger questions like how utilities can cost-effectively eliminate the older utility-owned generation from their portfolios and how the PCIA calculation can appropriately value elements of LSE power portfolios that deliver other system services or meet California policy goals.

The rise of customer choice

California’s 2002 Assembly Bill 117 established CCAs to give residential and small business customers a non-utility option for buying electricity. Direct access was shut down after the 2000-2001 California energy crisis, but 2009’s Senate Bill 695 re-established it.

There were nine CCAs in operation in 2017 and eight are expected to launch by the end of 2018, according to a July paper from California think tank Next 10. The just-passed Senate Bill 237 increased the cap on direct access from 13% of IOU load to 15.4%, further expanding customer choice.

IOUs served 70% of California’s load in 2017, but will fall to 57% in 2020, Next 10 forecasts. By the mid-2020s, over 80% of the state’s retail electricity load will be served by CCAs, direct access or distributed generation, according to a 2017 white paper from the CPUC.

CCAs and direct access providers have thrived by committing to deliver more renewables and lower bills to customers than IOUs. But if the PCIA is too high, new load serving entities may not be able to fulfill those commitments. Choice advocates say the present PCIA calculation inputsresult in a charge that unfairly imposes costs on their customers. IOUs say it unfairly imposes costs on their customers.

Proposed vs. alternate proposed decision

The PCIA, now in the range of $0.01/kWh to $0.04/kWh, is intended to “equalize cost sharing” between customers who leave their IOUs for new load serving entities, called “departing load,” and those who stay with their IOUs, called “bundled load,” Roscow wrote in his Aug.1 proposed decision.

California’s IOUs have made enormous investments in generating infrastructure over decades to serve anticipated customer load. Some investments met the traditional “least cost, best fit” standard. Others had higher than market costs but were necessary to meet state mandates. Most of that generation capacity can today be obtained at significantly lower prices but remains in IOU portfolios.

Judge Roscow made decisions about many factors used in the calculation of the PCIA. Commissioner Peterman’s Aug. 14 alternate proposed decision reversed three important ones.

Roscow’s proposed decision excluded imposing a price in the PCIA for legacy pre-2002 utility-owned generation and excluded imposing a price for post-2002 utility-owned generation and storage that is over ten years old. Peterman found they should be included. Third, the proposed decision established a PCIA collar, or limit on any increase, of $0.005/kWh per year, with an upper cap starting at $0.022/kWh in 2019. Peterman’s alternate proposed decision collar is 25% of the PCIA and is not implemented until 2020.

The current Pacific Gas and Electric (PG&E) PCIA is $0.027/kWh and it is forecast to go up to $0.029/kWh in 2019, Nick Chaset, CEO for the East Bay Community Energy (EBCE) CCA, told Utility Dive. Under Peterman’s alternate proposed decision it will be about $0.036/kWh, driven largely by the utility-owned generation. Under Roscow’s proposed decision, it will be $0.022/kWh because of the cap.

The Southern California Edison (SCE) PCIA is currently $0.017/kWh, VP Colin Cushnie told Utility Dive, “If the CPUC votes to accept Commissioner Peterman’s alternative, SCE’s PCIA rate will be between $0.02/kWh and $0.03/kW in 2019, depending on other assumptions, but if the commission accepts the proposed decision, SCE’s PCIA would be close to or less than $0.02/kWh.”

“But it’s not the prices that matter,” Cushnie said. “If departing customers pay less than their equitable share, remaining customers have to pay more, and that’s not good public policy or consistent with the law.”

How the commission votes on the three major factors will determine the size of the PCIA and could impact CCAs ability to meet the Next 10 and other forecasts for significant growth.

Factor 1: Legacy utility-owned generation

The Peterman’s decision allows costs for legacy utility-owned generation procured before the 2002 CCA law was passed to be part of the PCIA price. It includes nuclear, natural gas and large hydropower resources procured largely at prices higher than current market prices. The Roscow decision’s PCIA is lower because it does not include legacy utility-owned generation.

In the alternate proposed decision, Commissioner Peterman cited arguments made about legacy utility-owned generation by the California Community Choice Association (CalCCA). She also cited arguments made jointly by SCE, PG&E and San Diego Gas and Electric (SDG&E).

CalCCA argued that lawmakers intentionally excluded legacy utility-owned generation in AB 117 and “no statute passed since that time has imposed legacy utility-owned generation costs on CCAs or any other departing load customer class.”

Citing “Expressio unius est exclusio alterius — the expression of one thing implies the exclusion of others,” CalCCA argued utility-owned generation should not be included in the calculation of the PCIA, Peterman reported.

“There is very clear evidence that AB 117 excluded utility-owned generation from the PCIA calculation to push the utilities to begin changing their resource portfolios,” Chaset said.

CalCCA also argued the above-market cost of legacy utility-owned generation has increased their customers’ bills.  Their filing reports it contributed “$545 million in uneconomic costs to PG&E’s 2018 PCIA.”

The state’s three largest IOUs reframed CalCCA’s argument, suggesting that AB 117 could have explicitly excluded legacy utility-owned generation costs, Peterman wrote. SCE, PG&E and SDG&E also argued that the basis of both AB 117 and 2015’s Senate Bill 350, which “clarified” AB 117, “is the absolute prohibition on cost-shifting between customers.”

SB 350 increased the IOUs’ renewables obligations at the same time the customer choice movement gained momentum, Cushnie said. “The bill made it clear procurements by the IOUs for bundled customers should not result in higher costs for either departing or remaining customers. That is customer indifference.”

CalCCA’s statutory arguments were “unconvincing” and the legal arguments from the utilities, especially those about the superseding importance of SB 350, were noteworthy, Peterman wrote.

“Exclusion of those costs [for utility-owned generation from the PCIA] while they are above-market amounts to an invitation to shift costs to bundled customers that were incurred to serve CCA customers who later departed,” she concluded.

Factor 2: Post-2002 utility-owned generation

Peterman’s alternate proposed decision concluded the PCIA should include costs for utility-owned generation and storage that was procured after the 2002 law was passed but is over ten years old. Roscow’s proposed decision produces a lower PCIA by excluding it.

That utility-owned generation, largely natural gas generation, is an important factor in the PCIA price now because it supports system reliability.

“The CCA argument against including post-2002 utility-owned generation is even stronger than the one against legacy utility-owned generation because it’s supported by law, by 16 years of precedent and by state policy,” Chaset said. “The commission has continuously excluded it from the PCIA calculation for CCAs, so the alternate proposed decision’s interpretation sets a new precedent and makes all previous rulings on it wrong.”

The precedent was set because the only significant departing load between 2002 and 2010 was the capped departure of direct access customers, which the CPUC wanted to protect, Cushnie said. “As CCAs grew, the commission made it clear utilities could petition for a reconsideration of the ten-year limitation if circumstances warranted it.”

With current forecasts that as much as 85% of IOU load could be gone by the early 2020s, “circumstances have clearly changed,” he said. “It’s not feasible to have the remaining 15% of customers pay for utility-owned generation that provides much of the system’s essential reliability services.”

On the precedent question, Peterman concluded the IOUs cannot now be expected to have known the current wave of departing load would strand most of their supply portfolio.

More importantly, she added, CalCCA’s argument of “alleged portfolio mismanagement of post-2002 utility-owned generation would simply place the burden of cost recovery solely on bundled customers.” There is “no justification to continue a ten-year limit” on including costs for post-2002 utility-owned generation or energy storage resources in the PCIA calculation, she concluded.

Factor 3: Collars and caps

The alternate proposed decision leaves the current PCIA in place for 2019 and establishes a collar limiting the change in the PCIA value starting in 2020. It caps the annual change at 25%. Roscow’s proposed decision sets the 2019 value at no more than $0.022/kWh, limiting the near-term increase, and establishes a collar of $0.005/kWh/year, which would slow the rise of the PCIA more.

“The cap and the collar are important,” Chaset said. “It gives me certainty and allows me to plan.”

Peterman’s 25% cap is close to the $0.005/kW increase in Roscow’s proposed decision initially but starts at the much higher current PCIA of $0.029/kWh for PG&E, he said. That means the 2019 PCIA is uncertain and could be too high for CCAs to meet their commitments to customers. It also allows greater growth over time.

“If there’s going to be a collar and a cap, we’d prefer the one in the [alternate proposed decision],” Cushnie said. But that works against customer indifference because a true-up against actual market values could find money due to bundled customers from departed customers. That could give “customers opportunities to avoid costs and creates inequities among different customer classes,” he added.

Stakeholder testimony convinced Peterman a cap and collar, with regulatory oversight, could work against cost shifts, prevent PCIA volatility and increase transparency. This “supports adoption of a PCIA collar,” she decided.

What the gavel will decide

Stakeholders expect a final ruling on how the PCIA should be calculated from the commission any day and a commission vote on it at the September 27 CPUC meeting. The big questions are what phase one will decide, what will be left for phase two, and how both will impact customer choice viability.

Both the proposed decision and the alternate proposed decision report a “general consensus” for “quick but incremental action in the short-term” on the calculation of the PCIA and “portfolio optimization” in the second phase, Chaset said. Portfolio optimization would include ways the IOUs can sell off the controversial utility-owned generation or share it most cost-effectively with other LSEs.

Reforming the calculation of the PCIA is a multistep process, and the proposed and alternate proposed decisions are just the first steps, he added. Calculations of the resource adequacy value, the greenhouse gas emissions-free generation adder and other PCIA factors are not sufficiently handled by either. “The phase one ruling should leave the more difficult challenges to phase two,” Chaset said.

Cushnie partially agreed. “The key issue is equity among all customers and protecting customer difference,” he said. “If that issue is resolved, phase two will be limited to providing guidance to the utilities on how to manage or unwind their portfolios over time.”

That is Peterman’s objective. “The task before us here is an equitable division of the portfolio costs incurred to serve customers who have since departed,” she wrote. “Portfolio optimization will be taken up in the second phase.”


California customer choice at a crossroads: Regulators to weigh 3 key issues next week, by Herman K. Trabish, Utility Dive, September 18, 2018.

Solar With Batteries Cheaper Than Gas in Parts of U.S. Southwest

Natural gas-fired power plants will be facing more price competition from solar farms in some parts of the U.S. as falling battery costs make it possible to deliver electricity produced from sunshine even after dark.

Solar projects that incorporate storage are becoming cheaper to build per megawatt-hour in parts of the U.S. Southwest than new gas-fired generation, according to a report Monday by Bloomberg NEF.

That positions solar to replace a significant portion of the 7 gigawatts of coal-fired power that’s expected to retire in the region over the next decade, said Hugh Bromley, a New York-based analyst at BNEF. And that trend will likely be repeated elsewhere.

“This won’t be contained to the Southwest,” Bromley said in an interview Monday. “This is spreading and will continue to spread.

Utilities that buy electricity from solar farms typically still rely on gas-fired generators in the evenings. But the increasing affordability of batteries — thanks in part to a federal incentive — is making solar compelling, even after sundown.

For example, a 100-megawatt solar farm that goes into service in Arizona in 2021, coupled with a 25-megawatt storage system with four hours of capacity, will be able to provide power for $36 a megawatt-hour, according to BNEF. That’s well below the $47 price from a new combined-cycle gas plant, according to the report.

“In the long-term, this is a threat to gas suppliers whose demand from utilities will be in decline,” Bromley said.


Solar With Batteries Cheaper Than Gas in Parts of U.S. Southwest, by Brian Eckhouse, Bloomberg, September 17, 2018.

120 Elected Officials Urge CPUC to Issue Fair and Equitable PCIA Decision

Elected officials representing a diverse range of communities throughout the state are urging the California Public Utilities Commission to “put people over profits” and issue a fair and equitable decision on the Power Charge Indifference Adjustment. The PCIA is an “exit fee” charged by the state’s investor-owned utilities (IOUs) to community choice aggregation (CCA) and other departing load customers to compensate for electricity bought in the past at prices that are now above-market.

In an open letter published in The San Francisco Chronicle on September 13 to coincide with the Global Climate Action Summit, ten dozen mayors, city councilmembers and county supervisors call on CPUC Commissioners to consider the many ways local governments are contributing to clean energy advancement and climate change action in California.

San Francisco Chronicle Advertisement

“Our cities and counties are among the more than 160 communities across California that have chosen to participate in CCA programs to meet climate action goals, provide residents and businesses with more energy options, ensure local transparency and accountability, and drive new in-state economic development,” the letter notes. “CCAs are reliably serving more than 8 million customers with clean, affordable electricity, and can continue to thrive with a fair cost allocation decision.”

Public, transparent CCA programs born in cities and counties across the state face uncertainty as the CPUC considers changes to the PCIA. CCAs oppose an “alternate proposal” that is currently before the Commission as it would roll back clean energy efforts by communities, hit low-income customers the hardest, and reward big corporate utilities for mismanaging their energy portfolios.

The alternate “would significantly and unfairly increase exit fees charged by big corporate utilities and threaten current and future community choice energy programs — the very programs that are helping the state exceed its emissions-reduction targets,” the letter said.

The letter is signed by more than 25 mayors of California cities both large and small — from Oxnard to Oakland, Rancho Mirage to Rocklin —  as well as scores of city and county councilmembers and supervisors.

The Commission is expected to consider PCIA reform proposals on September 27.


The California Community Choice Association supports the development and long-term sustainability of locally-run Community Choice Aggregation (CCA) electricity providers in California. CalCCA is the authoritative, unified voice of local CCAs, offering expertise on local energy issues while promoting fair competition, consumer choice, and cost allocation and recognizing the social and economic benefits of localized energy authorities. There are currently 19 operational CCA programs in California.

For more information about CalCCA, visit


FOR IMMEDIATE RELEASE: September 14, 2018
Press Contact: Leora Broydo Vestel
(415) 999-4757 |

How Community Choice Aggregation Fits In to California’s Clean Energy Future

[Editor’s note: Please see guest blogger Robert Freehling’s commentary in response to some of the elements of this blog]

This month, California enacted one of the most ambitious clean energy goals in the country: getting 100 percent of its electricity from carbon-free sources by 2045.

California’s community-choice aggregation (CCA) providers say they’re ready to hit that milestone — and on an accelerated schedule.

In a Tuesday forum in San Francisco, CCA advocates laid out how these city- and county-based entities, which have grown to include millions of customers formerly served by the state’s investor-owned utilities, are pushing ahead of the renewable energy and carbon reduction goals set out in California’s just-passed SB 100.

They also highlighted how several policies under review by state regulators could stymie the growth of CCAs, including rules that govern how investor-owned utilities are compensated for customers taken over by CCAs, and how the two parties share responsibility for procuring the energy resources needed to keep the grid stable.

“We’ve had an explosion of CCAs in the past couple of years,” said Beth Vaughan, executive director of the California Community Choice Association. CalCCA’s 19 members now account for nearly 2.6 million customer accounts, up from about 1.85 million accounts at the end of 2017.

Most of the action has been in Northern California. These include several of the oldest CCAs in the state — Marin Clean Energy with 470,000 customer accounts and Sonoma Clean Power with 223,000. There are also more recently launched CCAs, such as Monterey Bay Community Power with 307,000 customer accounts, Peninsula Clean Energy with 291,000, Silicon Valley Clean Energy with 275,000, and East Bay Community Energy with 550,000.

Taken together, these CCAs add up to 2.1 million customer accounts out of utility Pacific Gas & Electric’s 5.4 million electricity customer accounts and 4.3 million natural gas customer accounts. While Southern California hasn’t seen as many CCAs formed to date, Southern California Edison and San Diego Gas & Electric are both looking at large-scale CCAs being formed in their service territories, as well as dozens of cities interested in following the lead of Lancaster, California’s Lancaster Choice Energy.

And the pace of CCA formation is accelerating. Dawn Weisz, CEO of Marin Clean Energy, explained that she arrived late to Tuesday’s forum because she had just come from a meeting that cemented Solano County as MCE’s newest member.

While CCAs remain a small percentage of the state’s utility customers, the California Public Utilities Commission estimates that up to 85 percent of the state’s retail load could be served by CCAs, as well as by direct access providers, by 2025. These trends are seen as an existential threat for California’s investor-owned utilities. According to state Senator Scott Wiener (D-San Francisco), the utility fight against the CCA model is continuing.

“Every year, there are probably three or four different efforts, sometimes with a fresh bill, sometimes with a quiet amendment inserted into another bill, other times trying to push something through at the last moment,” that are meant “to try [to] blow up CCAs,” Wiener said at Tuesday’s forum.

The most recent example he cited was language inserted into one of this legislative session’s controversial utility wildfire bills “that would completely undermine CCAs,” he said. “Some of us had to…hound people for weeks on end before the language was taken out.”

Utilities have long protested that the rules of CCA formation leave them with too high a share of the costs of serving those customers. While CCAs take over the job of procuring energy for their customers, which allows them to exceed utility renewables mandates and increase the roster of clean energy projects being built in the state, utilities remain responsible for all other aspects of keeping the power flowing, including the costs of maintaining transmission and distribution grids and managing customer billing.

But in the context of this week’s Global Climate Action Summit in San Francisco, CCA advocates say they’re fulfilling the promise that led legislators to create them in the first place — giving customers an avenue to support even more aggressive clean energy targets than the state has set.

How CCAs are hitting their clean energy targets 

Most of California’s CCAs have been formed with the express aim of increasing their share of renewables faster than the investor-owned utilities they’re part of, Vaughan said. To date, they’ve contracted for more than 1,300 megawatts of renewable energy.

CCAs also provided the first 100 percent clean energy options for customers in the state — a move that prompted utilities like PG&E to follow suit, Wiener said.

At the same time, CCAs have been able to deliver their customers lower rates than their utility counterparts for both their standard renewable-rich plans and their 100-percent-clean offerings. That’s largely because CCAs have been able to procure their renewables much more cheaply over the past several years, compared to utilities that have been procuring solar and wind power under state mandate for more than a decade, back when wind and solar were much more expensive.

According to a 2017 report from UCLA’s Luskin Center for Innovation, this underlying market reality has allowed CCAs to offer a much larger share of renewable energy than their affiliated utilities, up to 25 percent more in some cases. Looking at a 12-month period before its publication last year, the report estimated that these efforts have helped reduce carbon emissions by about 590,000 metric tons, which under the state’s cap-and-trade regime translates to $7.5 million in annual savings for electricity ratepayers.

“Through our analysis, we found that continued development of CCAs may enable California to surpass its 2020 renewable energy targets by up to four percentage points,” the Luskin Center report said. This analysis was based on the performance of the five oldest CCAs, however, and doesn’t account for the new ones that have been created or proposed since then.

Tuesday’s event brought out several CCAs to tout their accomplishments on this front. Marin Clean Energy, founded in 2008, now has $1.8 billion in committed contracts for a total of 924 megawatts of resources, said Heather Shepard, MCE public affairs director. As of this year, 80 percent of that generation is greenhouse-gas-free. By 2025, MCE plans to bring that figure up to 100 percent, with 80 percent of it in the form of renewable energy — a target that would put MCE far ahead of investor-owned utilities in meeting the state’s new SB 100 goals.

This includes a fair share of wind and solar projects outside its service area, but MCE has also deployed just under 20 megawatts in local projects, said David Potovsky, MCE’s power supply contracts manager. Its feed-in tariff program, launched in 2012 for projects smaller than 1 megawattis now fully subscribed for first 15 megawatts, and is adding another 15 megawatts, he noted.

CleanPowerSF, the CCA launched by San Francisco Public Utility District in 2016, now has about 80,000 customers, including some showcase clients like Salesforce, which is buying 100 percent renewable energy for its Salesforce Tower and two other office buildings. In June, CleanPowerSF signed long-term contracts for 100 megawatts of solar and 47 megawatts of wind, said San Francisco Public Utilities Commission assistant manager Barbara Hale.

And San Mateo County-based CCA Peninsula Clean Energy, which began serving its first customers in late 2016, inked its first 200-megawatt solar contract last year, and has since signed up big commercial customers for its 100 percent clean energy offering, including Facebook’s Menlo Park, Calif. headquarters, communications director Kirsten Andrews-Schwind noted.

The continued growth of CCAs is of concern to the CPUC, which published a report this year that questions whether CCA growth could undermine the state’s broader clean energy and carbon reduction goals.

But MCE CEO Dawn Weisz asserts that “what the [CPUC’s report] got wrong is, there is no crisis” resulting from CCA expansion. “If anything, we’re creating a more diverse marketplace. And adding local accountability and transparence really adds a lot of strength.”

How key policy decisions could support or undermine CCA clean energy plans 

Despite their record to date, CCAs have had some challenges that utilities don’t face in procuring large-scale renewables, such as their relative lack of financial reserves and creditworthiness to ink long-term contracts. And as the Luskin Center report noted, “whether CCAs can remain cost-competitive with their incumbent IOUs depends on several policy decisions that could occur in the near future.”

The first big issue is over the Power Charge Indifference Adjustment, or PCIA — the “exit fee” that CCAs pay utilities when they take over their customers, Weisz said. The goal of the PCIA is “to make investor-owned utilities whole,” or “indifferent” as to whether or not the customer stays with them or joins the CCA, she said (hence the term “indifference adjustment”).

The CPUC has been working on the PCIA issue for more than a year. Last month, it issued a proposed decision that, while far from perfect from both the utility and the CCA perspective, does take important steps toward “fair cost allocation,” Weisz said. These include measures to stop charging CCAs for utility-owned generation built before 2002, as well as to limit post-2002 generation costs to a 10-year cost recovery period. These factors will take a significant chunk of legacy utility costs out of the equation.

CalCCA believes these changes will help reduce today’s cost shifts from utility “bundled” to CCA “departing load “customers, which it calculates as up to $492 million annually for PG&E and up to $25 million annually for Southern California Edison in 2018. But utilities complain that these changes will unfairly burden them with legacy generation costs that should be shared by their former customers, and could potentially lead to CCAs disrupting the state’s energy markets.

Now, the CPUC is also considering an alternative PCIA plan that would increase, not decrease, those charges by retaining legacy generation costs, as well as imposing additional burdens on CCAs, according to CalCCA’s analysis. The CPUC is expected to make a final decision later this month.

“The real crux of the issue is that we want to make sure that what’s going into that fee are the unavoidable costs to utilities,” Weisz said. “There’s a lot of stuff in that fee that could have been avoided.”

The second big issue before CCAs is resource adequacy, or RA — California’s term for the capacity resources that all load-serving entities, including CCAs, have to procure to ensure grid reliability during times of peak demand. Under current CPUC regulations, CCAs have covered the cost of their host utilities procuring resource adequacy through the PCIA charge. It’s a method that made sense when CCAs were few and small, but which becomes increasingly difficult to manage under their current growth rates.

In February, the CPUC adopted a resolution that would force CCAs to contract for some portion of their share of RA requirements in the current year. CCAs protested, saying it could undermine their low-cost renewables goals by forcing them to buy short-term contracts for resources such as natural gas peaker plants that can meet the state’s needs.

“CCA compliance in resource adequacy requirements has been good. But it is challenging, because the market is tightening, and products can be difficult to procure,” SFPUC’s Barbara Hale said at Tuesday’s event.

Beyond that, CCAs want to see changes in how the PCIA calculates RA costs, Weisz said. “Right now, resource adequacy is being valued in this PCIA in very short-term increments — one year, two years,” she said. CCAs are pushing for a methodology that allows for the RA value of their long-term contracts to be calculated as well.

The long-term role of CCAs in California’s energy future

Weisz conceded that “the lion’s share of resource adequacy services are natural gas” power plants, increasing their share of fossil fuel-fired power.

At the same time, CCAs are moving alongside California’s investor-owned utilities to find cleaner ways to manage resource adequacy, including distributed energy resources such as energy efficiency, demand response, energy storage and EV charging, she said.

MCE has a pilot project attempting to shift loads at customers’ homes and businesses from peak afternoon and evening hours to earlier in the day when solar power is plentiful, she said. It’s also employing EV charging incentives that encourage workplace charging during peak solar generation hours, rather than later in the day. CalCCA’s Vaughan noted that all of its group’s members are working on EV charging infrastructure plans aimed at accomplishing similar load-shifting and -shaping goals.

As CCAs grow their share of the California energy market, their role in maintaining and creating new resources for grid stability will increase. This could well lead to more regulations to incorporate them into state energy policy. CPUC President Michael Picker has laid out some ideas on this front, including creating a statewide integrated procurement process to rationalize what could become an increasingly fragmented market for renewables project development.

And in the longer run, CCAs that have relied on short-term procurements because of their lack of creditworthiness for longer-term power-purchase agreement contracts will have to grow to a scale that can support their share of the state’s long-range needs. Under SB 350, by 2021 at least 65 percent of a CCA’s renewable portfolio will have to come from contracts of 10 years or more — a rule that “could impact the cost-competitiveness of some CCAs due to their lack of credit history,” the Luskin Center report noted.

Getting to a 100 percent clean energy portfolio by 2045 is likely to bring additional challenges.


How Community Choice Aggregation Fits In to California’s Clean Energy Future, by Jeff St. John, Greentech Media, September 12, 2018.

Developers see value in California offshore wind development

Now that offshore wind energy has taken a strong position in New England’s future power planning, due in part to unexpectedly competitive prices, developers are looking toward new markets.

State mandates and contractual commitments promise to make offshore wind a key part of the East Coast power mix by the mid-2020s. But offshore wind is not limited to the east. A Sept. 17 meeting of a federal-state Energy Task Force could clear federal permitting obstacles, bring thousands of California coastal wind MWs into the market, and pioneer floating turbine technology.

Regulators are saying little ahead of the meeting but the Trump administration sees wind energy as “affordable and reliable,” Department of Energy (DOE) Office of Energy Efficiency and Renewable Energy (EERE) Chief of Staff Alex Fitzsimmons told Utility Dive. And because of its high capacity factors, offshore wind “has the potential to contribute to reliability,” he added. “It is a critical resource for the future.”

First, however, developers will need the rights to build. That remains in doubt until at least Sept. 17. If they get those rights, a three-step plan may allow California to bring prices down enough to begin harvesting wind, just when it will be needed the most.

The meeting

The September meeting has taken on greater significance since the Aug. 29 passage of California’s Senate Bill 100, which targets 100% renewables for the state by 2045.

But California is only at 30% renewables now, despite being the national leader in utility-scale solar and distributed solar capacities and fourth in the nation in wind capacity. Offshore wind could be the needed boost.

California’s highest peak summer load projection for 2018 was just under 52 GW, according to its grid operator. The state’s gross offshore wind resource capacity is 1,698 GW, and six small areas outside existing “use exclusions” have a technical offshore wind resource capacity of 112 GW, according to a 2017 presentation to the Task Force by National Renewable Energy Laboratory (NREL) Research Scientist, Walt Musial.

Whatever portion of that potential policymakers and stakeholders agree can be harvested would certainly help the state reach its renewables target.

At the Task Force meeting, representatives of the Department of Interior, the Bureau of Ocean Energy Management (BOEM), the California Energy Commission (CEC) and industry and environmental stakeholders will confront the use exclusions.

Task Force meetings began in 2016 to identify areas in federal waters off California’s coast that can be permitted for wind energy. At this one, BOEM looks forward to a “robust discussion” about “the next step of our offshore wind leasing process: issuance of a Call for Information and Nomination,” spokesperson John Romero emailed Utility Dive.

The “Call” is the formal initiation of the process that would lead to development off the California coast. At the meeting, BOEM and the CEC will present “data and technical information” about the hypothetical timing and logistics of issuing a Call. Romero did not confirm the Call would be officially initiated, however.

Coastal traffic prevents development of major California load centers like San Francisco, Los Angeles and San Diego. Developers want leases for the central coast off San Luis Obispo County and for the northern coast off Humboldt County, where the wind resource is rich, and populations are relatively dispersed.

The big question is whether the U.S. Navy, the Task Force’s dominant stakeholder, will allow development in those central coast areas where it oversees vital air, surface and submarine training operations.

The potential and the obstacle

Given capacity factors, the 112 GW technical potential could deliver 392 TWh of electricity per year to the grid operator, or about 1.5 times California’s usage, Musial reported.

A 16 GW California offshore wind development would add 6,000 long‐term jobs, a $39.7 billion GDP boost during construction and a $7.9 billion annual GDP increase for the projects’ 25 years of operations, according to a 2016 NREL study. A 10 GW development would mean 3,000 long‐term jobs, a $16.2 billion GDP impact during construction and a $3.5 billion annual GDP increase of 25 years.

However, “potential is dependent on the level of policy support, technology attributes, the value of other market factors, and the prevailing electricity prices,” Musial told the Task Force. Developers have plans to refine technologies and bring costs down to market-competitive levels, but they are waiting for policy support.

BOEM will make the final decision, but the most influential stakeholder is the Navy, Trident Winds CEO Alla Weinstein told Utility Dive. “But East Coast developers have shown we can find middle ground solutions to manage conflicts,” she added.

The Navy’s concerns “are legitimate,” Magellan Wind CEO Jim Lanard said. Developers would need to commit to protecting critical Navy training and testing operations to get access to the “300 square miles [they] want within the Navy’s 36,000 square mile footprint.”

The value of the central coast’s wind resource is increased by its extensive transmission infrastructure, Lanard said. “That transmission now serves natural gas and nuclear power plants scheduled to be shuttered over the next five years, just as the proposed (offshore wind) capacity begins coming online.”

The northern California coast actually has stronger winds, Lanard said. But it lacks the transmission necessary to transfer generation from large projects to the state’s load centers.

If the Navy signs off, an official process will begin that could deliver offshore wind-generated electricity to the California grid by the mid-2020s. Developers and policymakers are now working on technologies and approaches to make that happen.

The north coast resource is stronger but the central coast is adjacent to transmission.   Credit: From the BOEM California page

The new technology

There are 25.46 GW of capacity across 13 states in the U.S. offshore wind project pipeline, according to DOE’s most recent Offshore Wind Market Technologies Update. California’s pipeline consists entirely of Trident Wind’s proposed 765 MW Morro Bay floating wind project.

About 60% of the U.S. offshore resource is in waters deeper than 197 feet, but 96% of California’s resource is in deep waters that make floating foundations, a technology in the prototype-pilot stages, the only option, according to Musial.

DOE sees “potential for advancements using the experience and expertise of America’s domestic oil and natural gas industry at developing offshore resources,” Fitzsimmons said. “DOE can help drive that innovation.”

Statoil-Equinor’s floating technology is being proven in the Hywind pilot off Scotland and Principle Power’s technology is scheduled for a proof-of-concept pilot off Portugal next year, Trident’s Weinstein said. “If we were selecting now, those two technologies are at the head of the pack.”

Magellan Wind is readying a prototype of its TetraSpa floating platform, Lanard said, which could dramatically lower floating wind costs through the use of better quality but cheaper steel and by allowing the turbine to be mounted on the foundation’s platform at dockside.


Developer-announced global floating offshore wind pipeline   Credit: From the DOE 2018 OSW Market report

The three-step plan

California can follow a three-step plan to fully access its offshore wind resource without interfering with the needs of the Navy or other stakeholders, Lanard said.

It would start with a small-scale project off the north coast, using a research lease. “Going through a state or federal agency would streamline the permitting process,” Lanard said. “But the transmission capacity off the north coast is no more than a 140 MW.”

That is enough for “one or two 50 MW projects, which would be the first U.S. floating wind installations,” he said.

Redwood City Energy Authority, a Humboldt County customer choice energy provider, has moved in this direction. It signed a Memorandum of Understanding with Principle Power in October 2017 “to explore opportunities for offshore wind development.” Jointly, they have begun development and await a north coast lease auction.

“If BOEM then allows commercial leases off the central and north coasts, limited north coast development could move ahead while the auctions take place,” Lanard said. “Commercial-scale projects can’t be built off the north coast without more transmission, but a major driver of a transmission build would be proving the efficacy of commercial-scale development off the central coast.”

Step two would begin with three leases for each region, with no developer holding more than one lease in the region, Lanard said. “The Navy could allow 1 GW to 2 GW in the first central coast leases as first mover projects.”

The third step could be driven by California’s 100% renewables by 2045 and transportation electrification goals because demand for renewable energy would spike, Lanard said. “If we prove the technology off the central coast, the state might see a need to support a transmission solution to access the much greater north coast wind resource.”

At that point, developers would be selling power into California markets. That means competing with low cost utility-scale solar generation but Weinstein and Lanard said they will be able to compete.

What will it cost?

DOE’s 2015 WindVision roadmap targeted a 40% reduction in the average levelized cost by 2030, from $50/MWh to $30/MWh, DOE’s Fitzsimmons said. For offshore wind, the goal was also to reduce the 2015 average levelized cost 40% by 2030, from $150/MWh to $90/MWh.

But long-term contracts filed with Massachusetts regulators in April turned that goal on its head. The contract price for the 400 MW Vineyard Wind project was $65/MWh. It beat the long-term forecast in the University of Delaware 2016 Special Initiative on Offshore Wind study, which forecast a decade-long 2,000 MW build in Massachusetts would drive the price to $108/MWh by 2030.

Lanard, Weinstein, and Stephanie McClellan, director of the University of Delaware Special Initiative and lead author of the report, agreed the Vineyard Wind price’s significance does not apply widely. It was an LCOE and included an investment tax credit unlikely to be available when California’s projects commence construction, Weinstein said.

“But this is a genie-out-of-the-bottle moment. We’re not going to go back to 2016’s $244/MWh price for Block Island or even 2017’s $132/MWh Maryland price,” McClellan said.

The mid-2020s California price could be at or below what McClellan’s paper predicted for 2030. That research did not anticipate there would be the confidence in the market that has been created by the over 10 GW committed, contracted or in development in the New England region.

“Now we’re in a moment that’s just shocking, she said. “I don’t think anybody would have expected we’d be able to get contract prices this lowthis quickly.”

Lanard and Weinstein agreed on three critical points. They are unlikely to deliver $65/MWh bids in California, they must be able to compete against very low, solar-driven California market prices, and they will be able to compete.

California regulators will recognize offshore wind’s ability to provide power when the sun does not, and value that capacity at a price that will allow it help meet California renewable energy goals, Lanard said.

“The Vineyard price without tax incentives is around the California hourly market price that we will need to meet or beat when we go into service,” Weinstein agreed. “Solar has the best price when the sun is shining, but what happens when the sun goes down? That is when the market price is highest and the California coastal winds are strongest.”


Developers see value in California offshore wind development, by Herman K. Trabish, Utility Dive, September 10, 2018.

Community Choice Aggregation Puts Communities in Control of Their Electricity

Keep your eyes and ears open for Community Choice Aggregation, already a major player for consumer energy choice in California and spreading rapidly. In the post below, 2018 UCS Schneider Fellow Rebecca Behrens explains how CCAs work, where CCAs are forming, and what you should be on the look-out for as more communities get involved.

It’s late summer, which means ice cream season is coming to an end. A coworker and I have made it a habit of exploring the (many) ice cream shops around our office each week, and for something as simple as ice cream, it’s amazing how many choices we have. I can choose what ice cream I want based on price, proximity, flavor, or even the company’s business practices.

This got me thinking: if I have so many choices for something as simple as ice cream, what about bigger choices in my life—like where my electricity comes from? Like most of the US, I’m served by one utility. If I don’t like the way they’re sourcing electricity or setting rates, I have limited options.

But that story has been changing, in part due to the growth in Community Choice Aggregation (“CCA”). CCAs offer an alternative to traditional utilities and are designed to give communities a voice in where their electricity comes from. In California, many CCAs are striving to provide their customers with more renewable energy at lower costs than traditional utilities. Let’s break down the what, when, where, how and why of this new body.

What are CCAs?

Community Choice Aggregation allows local governments to purchase electricity on behalf of their residents, aggregating the electricity needs of everyone in the community to increase purchasing power.

The investor-owned utility (“utility” or “IOU”) that used to supply and deliver electricity is still there, but it plays a different role. Now, the utility is just in charge of delivering the electricity through its transmission and distribution lines (the utility still owns and maintains the “poles and wires”) and billing customers. This partnership distinguishes a CCA from a municipally-owned utility, which takes over both electricity procurement and electricity delivery (aka the poles and wires).

When and where have CCAs formed?

So far, CCAs are allowed in seven states: Massachusetts, Rhode Island, New Jersey, New York, Ohio, Illinois and California. Within a state, the decision to form a CCA is up to the community and local government. California has seen the most recent growth in CCAs, so I’ll be using it as an example here, but know that CCA formation and growth looks a bit different in each state.

Most of the seven states that allow Community Choice Aggregation passed bills legalizing CCAs in the early 2000s: California passed AB 117 in 2002. However, it wasn’t until years later, in 2010, that the first CCA in California launched in Marin County.

Since 2010, the number of CCAs in California has grown significantly. In 2016, there were five CCAs serving 915,000 customers. In 2017, there were nine CCAs. By the end of 2018, there will be 20 CCAs, serving over 2.5 million customers. And more local governments are considering the option.

The regions CCAs serve in California as of September 2018. Because CCAs are growing quickly in California, this map changes quickly, too. (Source: Cal-CCA)

Even if no more CCAs launch after 2018, CCAs are expected to serve 16% of the electrical load in California in 2020. But, it’s highly likely more CCAs will launch in the coming years, which could put this number at over 50% in 2020.

How do CCAs work?

In California, once the local government votes to form a CCA, a nonprofit agency is formed to carry out its duties. The agency goes through a rigorous planning process and once the CCA is ready to launch, they line up the customers.

And who are those customers? Anybody who wants to be. CCAs are “opt-out” in California, and in most other states, meaning that the default is for customers to be automatically served by the CCA. Customers have 60 days to opt-out for free and are notified about the change four times before this deadline. After 60 days, customers can opt-out for a fee to account for the power the CCA had bought in advance for them.

And that’s it! Customers are now served by the CCA. In California, if customers were receiving discounts because of particular circumstances, they will automatically continue receiving those discounts. This includes California Alternative Rates for Energy (“CARE”), Family Electric Rate Assistance Program (“FERA”) and Medical Baseline customers. Customers with rooftop solar systems who are on a net energy metering program are automatically enrolled to continue.

In terms of electricity service, as a CCA customer, nothing else changes. Your lights stay on, your TV still works, and your freezer stays cold.

The biggest difference is that the existence of CCAs allow customers to have more of a choice in the type of electricity they receive. Not only can customers choose between being served by the utility or the CCA, but if customers are unhappy with the electricity options or rates offered by their CCA, they can provide feedback to the CCA at its board meetings, which allow for public participation in California.

CCA communities can also benefit from the reinvestment of CCA profits, given that CCAs are nonprofits. CCAs can offer additional programs beyond what the utility offers. These could look like free energy efficiency audits, rebates for electric car charging stations, incentives for low-income customers to install solar, or really any program that helps customers better manage their electricity usage.

In some cases, customers could lose access to programs run by their utility by joining a CCA, although in California, most utility programming is still available to CCA customers. In any case, it’s smart to reach out to your local CCA and ask if you’ll still be eligible for programs you rely on.

Why do CCAs matter?

In California, every CCA (so far) has chosen to provide customers with more renewable energy than the competing utility and has done so at lower rates. However, how much new renewable energy CCAs are contributing to the grid varies a lot from community to community.

The devil is in the details here: A CCA that uses mostly short-term contracts to buy renewable energy or renewable energy credits (“RECs”) is likely buying from projects that already exist. Electricity purchases from existing renewable energy projects do not increase the supply of clean electricity on the grid, and customers that used to consume electricity from those renewable projects may now be consuming electricity from a dirtier source. This is called resource shuffling. On the other hand, a CCA that uses long-term contracts is helping new renewable projects develop, which means that more clean power is being added to the grid.

If you live in an area served by a CCA, it’s up to you to make sure your CCA is sourcing electricity in a way you support and providing programming you can use. Here are some questions you can ask to see how well a CCA is doing:

  1. Is the CCA providing more renewable energy than the competing utility, and are they sourcing their renewable energy from long-term contracts for energy and RECs? By buying “bundled” renewable energy through long-term contracts, CCAs can more directly support the development of additional renewable energy projects and add more clean electricity to the grid.
  2. Is the CCA making use of local resources and supporting the local community? Having a sustainable workforce policy and hiring locally and from unions can help bring the broader benefits of renewable energy to a community.
  3. Is the CCA leveraging grants and their revenue to provide programs designed to help customers reduce or better control their energy use? More renewable energy is just one piece of the puzzle; we need a host of solutions for a clean energy transition. Programs that invest in electric vehicle infrastructure and energy efficiency are equally important.
  4. Is the CCA proactively reaching out to its community? Programming needs to be accessible, useful and reach all members of the community—especially those that historically have not received the full benefits of energy programming and renewable energy.

CCAs have the potential to empower (and quite literally power) communities. But it’s up to residents to hold their CCAs accountable and ask them to provide equitable and fair climate solutions. By staying engaged and informed, you can make sure your CCA is providing your community with the best options.

CCAs are a growing movement in California but they aren’t the only way consumers are making choices about their electricity. While not every utility or state offers choices in electricity sourcing, it is worth seeing if yours does. You may even be surprised on what your options are: home in Vermont, through my utility I can choose to buy Cow Power! What sets CCAs apart from other choices is their ability to localize decision making and let communities invest in what is best for themselves, which has made them a powerful new player at the table.


Community Choice Aggregation Puts Communities in Control of Their Electricity, Laura Wisland, Union of Concerned Scientist, September 10, 2018.

The Future of CCAs Is Being Hashed Out in a Flood of Private Meetings

Over the last month, regulators from the California Public Utilities Commission have had a deluge of private meetings with utility company officials and officials representing government-run power agencies known as community choice aggregators, or CCAs.

These “ex parte” meetings are legal but have been the subject of controversy. A widely panned deal to leave ratepayers on the hook for problems with the nuclear power plant at San Onofre was hashed out, in part, during an undisclosed ex parte meeting in Poland.

Typically, the meetings are not so much like something out of a James Bond movie. Instead, according to regulatory filings that disclose some of what happened, they are meetings between people with business before the commission and aides to the five CPUC commissioners.

The meetings generally last about a half hour, in person or by phone. The parties lobbying the CPUC staffers typically leave behind a short handout or PowerPoint presentation. Afterward, participants file a document that talks about what was discussed and a copy of any written material used during the meeting.

The current case is contentious because it could decide the fate of the CCA movement.

In early August, state utility regulators unveiled a draft plan for dealing with power companies’ stranded costs as an increasing number of Californians switch to buying power from CCAs.

Existing power companies – San Diego Gas & Electric, Southern California Edison and Pacific Gas & Electric – already built power plants or signed long-term contracts to buy power on the assumption that their existing monopolies would never end. Now, though, millions of California customers are leaving for CCAs. For years, companies have been able to charge departing customers an “exit fee” to recoup those stranded costs, but nobody has been able to agree on whether the fee is too high or too low. If it’s too high, few governments would be able to provide cheaper power, destroying the community choice movement. Too low, and customers stuck in places without any choices will be paying too much.

The number of private meetings in this exit fee proceeding is unprecedented, said Matthew Freedman, a staff attorney for The Utility Reform Network.

“The CCAs have been doing everything possible to engage in private conversations to persuade CPUC Commissioners and staff to adopt a methodology that minimizes the responsibility of CCA customers for stranded costs,” he said in an email. “I don’t recall any recent proceeding that generated this volume of ex parte contacts.”

Beth Vaughan, the head of a community choice trade group, said nothing unusual was afoot – the reason CCAs are appearing in these private meetings so frequently is simply because there are a lot of them.

“There are now 19 operational CCAs in California, with 10 launched in 2018 alone, so it’s a big group,” she said in a statement. “The commission designated each operational CCA as a party to the [exit fee] proceeding and consequently they have an obligation to actively contribute and ex partes are one avenue. Under the rules, each party is allocated equal time.”

Ironically, one of the main reasons CCAs argue they are better than existing power companies is that they are locally governed, while the CPUC, which meets in San Francisco, has to clear most major power company decisions. In this instance, the CCAs remain at the mercy of the CPUC.

Power companies have also arranged meetings, too: For example, on Aug. 3, just two days after the proposed decision was released – and it became clear that things might not be going the power companies’ way – the state’s three major utilities had arranged meetings with four of the five commissioners.

Read full article here.

Environment Report: The Future of CCAs Is Being Hashed Out in a Flood of Private Meetings, by Ry Rivard, Voice of San Diego, September 10, 2018.

To reduce wildfires, Edison seeks $582 million from ratepayers for improvements

In a sweeping effort to reduce the wildfire risk from electric power lines, Southern California Edison said Monday that it wants to spend $582 million for a series of improvements to its grid that likely would mean higher bills for ratepayers.

The utility giant’s actions underscore power companies’ growing concerns over their fire liability. In the last few years, the state has experienced its largest and most destructive blazes on record.

Another huge California utility, Pacific Gas & Electric, faces up to $15 billion in losses from last year’s wine country fires, which destroyed more than 8,000 homes and killed more than 40 people. Residents have blamed downed power lines for the fires, though officials have not completed their investigation of the causes.

Many of California’s most destructive fires have been fueled by powerful winds, which in some cases have caused power lines to snap off and spark blazes. Utility companies are on the hook for hundreds of millions of dollars in losses, and officials have warned that the losses will grow if the agencies can’t find ways to reduce the risks.

“We’ve seen with fires in recent years we’re basically upping our estimate of what the risk exposure is. When we’re assessing the risk versus the benefit, it’s leaning more toward the side of spending money,” UC Berkeley electrical engineering professor Alexandra von Meier said.

Edison is asking the state for permission to spend the $582 million on improvements, including strengthening poles and using better technology to determine when winds put the power grid at risk.

Over the next two years, an estimated 600 miles of exposed power lines would be replaced with insulated ones that would not spark if they came in contact with a fallen branch or a Mylar balloon.

Officials said ratepayers would see their bills increase between 81 cents and $1.20 a month, but far less than if Edison is found liable for a catastrophic fire like those that hit Sonoma, Napa, Lake and Mendocino counties last October. Edison is estimated to face up to $4 billion in losses from the Thomas fire, which hit Ventura and Santa Barbara counties in December, and the Montecito mudslide that occurred a month later.

PG&E’s potential losses from the October blazes were so vast that the utility said it faced possible bankruptcy if it did not get some relief from the state. Those concerns prompted the state Legislature last month to approve a bill that would allow PG&E to borrow money for its 2017 wildfire costs while using funds collected from ratepayers to pay back the loan.

PG&E lobbied lawmakers heavily for help, warning that Wall Street investors could downgrade the company’s credit rating without relief from the Legislature. The bill was controversial, with some calling it a bailout for a utility that should have been better prepared to deal with the wildfire danger.

Wildfire liability has been a growing problem for California’s utilities. San Diego Gas & Electric has spent more than a decade seeking permission to pass along to ratepayers $379 million in costs from the deadly 2007 fires in San Diego County, which destroyed hundreds of homes. SDG&E spent $2.4 billion to resolve more than 2,000 lawsuits related to those fires, but the utility insists the blazes were ignited by factors beyond its control — including extreme Santa Ana winds and a tree limb that fell onto an SDG&E line due to high winds.

The upgrades Edison is proposing would reduce those risks, said Bill Chiu, the director of Edison’s Grid Resiliency and Wildfire Safety program.

“In the state of the ‘new normal,’ there’s this tremendous urgency to act quickly. Eight of the 20 most destructive fires in California happened since 2015,” Chiu said. “Even though wildfires start for many reasons, utility power lines is almost 10%. We feel it’s necessary we do our part.”

Along with insulated wiring, Edison will change out more than 15,000 current limiting fuses to new ones that stay cooler and respond faster during interruptions. New remote-controlled automatic reclosers that prevent lines from reenergizing during an interruption will also be installed.

High-definition cameras that can monitor remote parts of the grid are being added, as are 850 weather stations that will provide on-the-ground data for utility operators.

All of those upgrades are the kind of infrastructure investment that the utilities — and through them, consumers — should come to expect in the future, von Meier said.

San Diego Gas and Electric is planning to spend $3 million this year on wildfire safety, in addition to the $1 billion it has spent on the issue since 2007. The utility’s fire prevention plan outlines a broad overhaul of the system that includes putting power lines underground and replacing wooden power poles with concrete ones.

PG&E officials said the utility has spent more than $2 billion on vegetation management and infrastructure maintenance since 2013.

Exposed lines and falling power poles contributed to the deadly fires that swept across Northern California in October 2017, according to the California Department of Forestry and Fire Protection.

PG&E equipment was found to have played a role in more than half of the fires that broke out between Oct. 8 and 9, including branches falling into lines power lines for the Nuns, Atlas and Redwood fires, which killed 18 people. A cause has yet to be determined for the Cascade and Tubbs fires, which killed four and 22, respectively.

Almost all of those fires broke out in the middle of the night or early-morning hours amid high heat and gale-force winds that sent flames running across mountain slopes and between hillside canyons like a blowtorch.

In a perfect world, the kind of equipment Edison and other utilities are looking to add would be enough to stave off that kind of disaster. While they’ll certainly help, von Meier said, ultimately it’s playing the odds.

“It’s like getting to zero auto accidents on the freeway. You’d like to get there, but short of insulating every single mile of conductor and having new protection systems everywhere, it’s just not realistic,” she said. “In the long run, the best investment that the electric utilities and we all can make to prevent wildfire damage is investing in climate change mitigation. In the long run that’s what’s really targeting the cause of a lot of these fires.”

Another tactic power companies are increasingly employing is shutting down power in high-risk areas when winds get too strong. SDG&E has done this, to mixed reviews from residents.

Von Meier said she has homes in Edison and PG&E territory. She has received notices from both informing her that the power might be turned off during heavy winds.

“I’d much rather the utility shut it off preemptively than risk a fire or having a fire exacerbated,” she said.

To prevent wildfires, Edison seeks $582 million from ratepayers for a sweeping grid overhaul, by Joseph Serna, The Los Angeles Times, September 10, 2018.

CCA 101: How does Community Choice Aggregation work? What you need to know

The name may sound clunky, but Community Choice Aggregation, or CCA, is one of the hottest energy topics in California and may upend the long-time relationship between utilities and customers.

But while the growth of CCAs has led to heated debates across the state within the energy and political spheres, many local utility customers are either unclear or unaware of the subject — even as the City of San Diego slowly deliberates whether to hop on the CCA bandwagon to help it meet its Climate Action Plan that calls for 100 percent of the city’s electricity coming from renewable sources by 2035.

It’s a complicated story but an important one because adopting a CCA affects what consumers pay, what kinds of energy sources a community purchases and who makes those acquisitions.

It also tests the relative levels of trust and mistrust ratepayers have in their local power companies and local governments while raising questions about making decisions affecting an energy sector with a history of volatility, in a state where dramatic transformations are already underway.

Here’s an overview.

What are they?

Community Choice Aggregation allows any city, county or combination thereof to form an entity to take over the responsibility for purchasing power for their community.

How are they different?

About 75 percent of electricity supply in California comes from three investor-owned utilities — Pacific Gas & Electric in Northern California, Southern California Edison in the Los Angeles metropolitan area and San Diego Gas & Electric, which covers San Diego County and a small portion of Orange County.

As the name suggests, investor-owned utilities are owned by shareholders, and these private electricity and natural gas providers are overseen by the California Public Utilities Commission, or CPUC.

They are different from publicly-owned utilities, which are not regulated by the CPUC, such as Los Angeles Department of Water and Powerthe largest municipal utility in the country.

Under the traditional model, investor-owned utilities:

1) Purchase sources of electricity (natural gas, solar, wind, etc.) to meet the energy needs of their customers and make sure the electric grid runs smoothly.

2) Maintain the transmission and distribution lines (poles, wires, etc.) needed to deliver the electricity.

3) Handle billing and customer service issues.

How do CCAs work?

Should a CCA be established, one big thing changes and two big things remain the same.

The utility still maintains the transmission and customer service responsibilities, but the purchasing of power is done by municipal governments.

Since elected officials often don’t have expertise in energy markets, many CCAs hire third-parties with experience in energy markets to perform all sorts of complex scheduling and marketing transactions. They are paid by the CCAs, using rates charged to their customers.

CCAs typically offer customers three different energy programs — a default program, a program for solar and a more expensive program advertising use of 100 percent renewable sources.

Who joins?

Once elected officials vote to form a CCA, all the electric customers in their jurisdiction are automatically signed up. Customers can remain with the investor-owned utility if they want to, but it’s up to them to contact the CCA and go through the opt-out process.

Opting out is free, provided it is done within the first few billing cycles (usually within 60 days). After that, a small fee may be charged, although some CCAs don’t impose opt-out fees.

Who does the billing?

The utility still does. A consolidated monthly statement will include a line-item for the CCA so customers would not receive two separate bills. The customer pays the entire bill and the utility then pays the CCA its share.

Are the number of CCAs growing?

Yes. There were fewer than 10 CCAs in the state last year but there are now 18, with a 19thexpected to come online by September.

The state’s first CCA was formed in Marin County in May 2010 with 8,000 customers, many of whom wanted community choice in order to tap more green sources of power. Called MCE (short for Marin Clean Energy), it has grown dramatically and now serves 470,000 customers in four counties.

Solana Beach became the first community in San Diego County to establish a CCA, which went online June 1.

What kind of effect have CCAs had so far?

CCAs across the state have offered electricity from renewable sources ranging from 37 percent to 100 percent, with a statewide average of 52 percent, according to the Luskin Center for Innovation at UCLA.

By comparison, SDG&E delivered about 45 percent renewable resources to customers last year, exceeding state mandates.

Rapid CCA growth is expected to continue. In 2010, investor-owned utilities had 78 percent of the statewide market share but it dropped to 70 percent last year and the Luskin Center report predicts it falling to 57 percent within two years.

PG&E mentioned erosion of its customer base due to CCAs as one of the reasons for shutting down the Diablo Canyon nuclear power plant.

What about San Diego?

The City of San Diego is considering whether to create a CCA to reach the goal of the city’s Climate Action Plan that mandates 100 percent of the city’s electric needs coming from renewable energy sources by 2035.

SDG&E is putting together a counter proposal that promises to get the city to 100 percent renewables by 2035.

The city council is expected to make a decision by the end of this year.

Why do some communities adopt CCAs?

Some want more clean sources in their energy portfolios. Others want more local control, working on the premise that community choice can deliver lower rates for customers than utilities. Boosters of CCAs say community choice delivers on both fronts.

MCE, for example, said its default program costs 2 to 5 percent less than Pacific Gas & Electric, the investor-owned utility in its area.

But slightly lower bills represent only part of their attraction for fans of CCAs.

Under the traditional utility model, energy decisions “aren’t made in our backyard,” said Nicole Capretz, executive director of the San Diego-based Climate Action Campaign and one of the architects of the city’s Climate Action Plan. “They’re made in San Francisco (home of the CPUC) and Sacramento (home of the Legislature).”

CCAs tend to be “much smaller and more nimble” than investor-owned utilities “and they’re not paying for these exorbitant salaries and they don’t have bonuses and shares of stocks” to concern themselves with, Capretz said.

Who makes the calls?

Leaving the final say on energy procurement to elected officials is a concern, said Tony Manolatos, spokesman for the Clear the Air Coalition.

“A lot of people don’t believe the city should be in the energy business — it’s very volatile,” Manolatos said. “The city would be better off focusing on core services like police, fire, parks, fixing our roads, helping solve the homeless problem … Not on launching a billion-dollar energy program.”

The Clear The Air Coalition includes representatives of the San Diego Regional Chamber of Commerce, the San Diego County Taxpayers Association, two faith groups, the Downtown San Diego Partnership and lobbyists for Sempra Energy — the parent company of San Diego Gas & Electric.

Under state law, a utility cannot use ratepayer dollars to lobby about CCAs but utilities can set up marketing divisions for that purpose, provided that shareholders, not ratepayers, fund them. SDG&E’s parent company, Sempra, did just that in 2016.

City officials making energy decisions is “like any other public agency accountability,” Capretz said. “You want to make sure they hire the right people who are experts in the field … Yes, ultimately the elected officials make the final decisions, but all the leg work and ground work is done by the professional staff.”

In Marin County, MCE has a staff of 60 but officials say that represents less than 3 percent of its budget.

How big is too big?

Another concern centers on the size of a proposed CCA in the City of San Diego — about 1.3 million customers. That’s well over twice the size of the largest CCA operating in the state (East Bay Community Energy, based in Alameda County, with 550,000 customer accounts).

If a City of San Diego CCA went belly up, critics worry ratepayers would be on the hook for financial liability.

But Capretz said a recently formed CCA in Los Angeles County, the Clean Power Alliance, “is going to be way bigger than us.”

The Clean Power Alliance expects to grow its current customer base of 36,000 to just under 1.04 million by the end of May 2019. By then, its CEO said from an energy load perspective, the L.A. County CCA would be the fifth-largest load serving entity in the state, trailing only Southern California Edison, PG&E, Los Angeles Department of Water and Power and SDG&E.

“L.A. County is just starting implementation and like them, we would do the same thing,” Capretz said. “You do it in phases, you get your sea legs, set up best practices and move on.”

What about cities outside San Diego but still in the county?

Since a City of San Diego CCA — at least in its initial iteration — would not include other cities and communities in the county, Haney Hong, CEO of the San Diego County Taxpayers Association, worries that cities like Imperial Beach or Chula Vista could be exposed to higher costs.

SDG&E in recent years signed power purchase agreements with energy providers under long-term contracts for renewables. But the price of renewable energy is lower today. That means a CCA can procure green energy sources at a lower price. That’s good news for customers in a proposed City of San Diego CCA but Hong sees a potential problem for communities in the county not in the CCA.

“If things are not properly accounted, then you have one taxpayer benefiting over another,” Hong said. “I remind folks we’re the San Diego County Taxpayers Association. We’re not just looking at San Diego city taxpayers; we’re also looking at National City taxpayers and Imperial Beach taxpayers.”

Capretz said such cost-shifting concerns can be addressed by properly accounting for the exit fees CCAs pay utilities each month.

What exit fees?

Among the acronyms thrown around, there’s another inelegant set of initials to keep in mind — PCIA, which stands for Power Charge Indifference Adjustment.

Once a CCA is created, the state’s Public Utilities Commission requires the community choice customers pay an exit fee, the PCIA.

Why? Because of those long-term power contracts utilities signed to secure energy for their customers. The utilities commission mandates that customers going to a CCA do not burden the remaining utility customers with costs paid to procure those energy purchases and investments.

Power companies have also built infrastructure, such as natural gas and solar power plants, all with CPUC approval. The utilities procured many of the clean energy sources in order to meet the state’s aggressive climate goals via the Renewable Portfolio Standard.

The exit fee is applied to each kilowatt-hour of electricity consumed by the customer and it shows up as a separate charge on every monthly bill.

The size of the fee is critical. Utilities want to make sure it compensates them for the generation they have procured while CCAs want to ensure the exit fee doesn’t raise their customers’ bills too high.

The utilities commission determines the fee, which involves a complicated formula. The exit fee is different in each of the service territories of the state’s three investor-owned utilities because each power company has a different mix of resources. In very general terms, the exit fee runs about 2.5 cents per kilowatt-hour for SDG&E residential rates.

Last month, an administrative law judge for the CPUC proposed a new exit fee the utilities did not like.

CPUC commissioner Carla Peterman responded with an alternate proposal that is more favorable to the remaining customers of power companies. As one would expect, the CCAs don’t like Peterman’s proposal. The Clear The Air Coalition liked the alternate decision better but didn’t like the fact that both proposals include caps from one year to the next, saying they would create “uncertainty, risk and debt.”

The full five-members of the commission are scheduled to make a decision on a new exit fee on Sept. 13 but CPUC watchers say they would not be surprised if a vote is delayed, given the details and debate.

“If I were a community considering a CCA, I would want to know the resolution of the PCIA debate before committing to provide service to local residents,” said Matthew Freedman, staff attorney at The Utility Reform Network .

Are CCAs really cleaner?

One of the raps on CCAs centers on what is called “resource shuffling” — that the power being purchased from existing resources really doesn’t result in more sources of clean energy but simply moves them around to appear to reduce greenhouse gas emissions.

Earlier this year, Voice of San Diego reported that Marin County’s MCE and another CCA in Sonoma purchased power from a utility in Washington state that operates two hydropower facilities, a clean source of power.

But the Washington utility increased its own amount of coal and natural gas, indicating it may have replaced the hydropower it sold off to MCE and Sonoma with dirtier energy sources.

Dawn Weisz, MCE’s chief executive officer, said her company has no control over decisions a seller makes regarding its own power supply.

“Any load-serving entity, including SDG&E or PG&E, that buys green power to their load doesn’t have control over what the seller chooses to do for their own procurement purposes.”

Another criticism? That CCAs are just purchasing power from existing sources and not creating new generation, or putting “steel in the ground.”

CCAs push back on that and say as the community choice movement grows, so will the number of their energy projects.

Earlier this year, MCE unveiled a 60-acre, 10.5-megawatt solar farm in Richmond.

“We have under contract more than 900-megawatts of new California based renewables,” Weisz said. “We ventured into long-term power supply agreements for wind, solar, geothermal, biomass in California, and that’s not resource shuffling. That’s building new power supply.”

Relatively few CCAs have entered into long-term supply commitments for substantial volumes of new clean energy infrastructure but community choice advocates say that will change as CCAs mature.

What do regulators think?

CCAs are part of a much larger change in the way customers in California receive their energy — whether from community choice, rooftop solar panels or private groups called Direct Access providers who re-sell electricity.

The changes are coming so fast it makes regulators nervous.

CPUC president Michael Picker sees similarities to the bad old days of the California Energy Crisis in 2000 and 2001 when failed deregulatory measures resulted in rolling blackouts across the state.

“If we don’t have a better plan than we currently have, then I worry we could end up in the same pickle,” said Picker, who also voiced his concerns in an extensive CPUC report released last month on the evolving electricity market. “If you’re a smaller provider, you don’t always get what you need.”

CPUC rules have been established making sure entities have purchased sufficient capacity, or resource adequacy.

“I find that not all CCAs are created equal,” Picker said, with some better run than others. “I’m not trying to judge them; I just know that there’s potential for failure there and we have to think that through and take steps.”

Some critics worry if there are big shifts in the market, CCAs in their development stages won’t have amassed the capital needed to withstand a financial shock.

CCAs have bristled at any comparisons to the energy crisis. The trade group representing community choice, CalCCA, challenged the CPUC report, saying in comments filed in Junethat safeguards are in effect to prevent a replay of what happened 18 years ago.

“The deregulated market was a free-for-all and this is completely different,” Capretz said. “Community choice programs are part of the long-term resource planning processes. They have to have resource adequacy. They have to prove that they have enough power for everybody … It’s not like the lights are going out.”

Going forward

All eyes are on the upcoming decision by the CPUC on the exit fee/PCIA.

San Diego’s city council is not expected to make a decision until that’s resolved.

A feasibility study released last year predicted a CCA has the potential to deliver cheaper rates over time than SDG&E’s current service, while providing as much as 50 percent renewable energy by 2023 and 80 percent by 2027.

SDG&E’s counter proposal to get to 100 percent renewables by 2035 has so far produced a rough outline for a “tariff” program that would charge ratepayers the cost of delivering more clean sources of energy over time.

Some council members have expressed frustration more specifics have not been sketched out.


CCA 101: How does Community Choice Aggregation work? What you need to know, by Rob Nikolewski, The San Diego Union-Tribune, September 9, 2018.