Focus: Market transformation will end dominance of electrical utilities, regulators predict

California is poised for a swift transformation of its electricity landscape — and that could bring tumult if preparations aren’t made soon to maintain quality and avoid reliability problems like rolling blackouts, the state’s leading energy regulator is warning.

After decades of dominance by investor-owned utilities, electricity markets in the state are becoming more competitive. Ratepayers today have a growing number of choices for powering their lights, laptops and electric cars — from installing rooftop solar panels and consumer-scale batteries to joining increasingly popular government-run electricity programs known as community choice aggregation, or CCA.

Currently, investor-owned utilities such as San Diego Gas & Electric, Southern California Edison and Pacific Gas & Electric together buy and sell more than 75 percent of the state’s electricity. Their collective share could plunge to 10 percent within the next five years, with CCA programs causing most of the change, according to the state’s most aggressive forecast. More conservative estimates still show major shifts away from the utilities.

“Innovation is actually starting this process of hollowing out the investor-owned utilities,” Michael Picker, president of the California Public Utilities Commission, said during a public meeting last month. “The confluence of these disruptive business models … (is) to some extent dramatic.”

SDG&E, SCE and PG&E agree that the state’s electricity markets are undergoing adjustments, but declined to weigh in on specific forecasts.

“As California’s energy landscape continues to rapidly change, all market participants must take immediate steps to help keep energy affordable and (environmentally) clean for all customers,” said Ari Vanrenen, spokeswoman for Pacific Gas & Electric.

In recent years, traditional utilities, CCA backers and others advocating an end to electricity generated from coal or natural gas have been locked in an expanding struggle for customers. Generally speaking, the state’s push for ever-greater use of solar, wind, geothermal and other renewable energy sources is upending the electricity market.

Traditional utility companies have met — or exceeded, in the case of SDG&E — the Legislature’s minimum thresholds for boosting green energy in their portfolios.

Environmentalists and other backers of CCA programs want a quicker and more emphatic pursuit of what they see as the end goal: Using 100 percent renewable power and eventually producing much, if not all, of that zero-emissions energy within each geographic market’s territory. That would mean, for instance, having a community install solar arrays on virtually every rooftop and harness wave energy from the nearby coastline.

For decade after decade, the typical system has involved a utility purchasing electricity generated farther away and then transmitting it across long, large power lines into customers’ homes and businesses.

Under the CCA model, a utility continues to operate and maintain the poles and wires needed to deliver energy, but elected officials for a city, county or consortium of municipal governments control the buying and selling of that power for their jurisdiction. With no shareholders and an emphasis on fighting climate change, community choice programs in California have been investing their revenues in renewable-energy projects in or around their service territory.

Since the state’s first CCA was launched in Marin County in 2010, community choice has grown to account for 5 percent of the electricity bought and sold in California. By 2020, the utilities commission said the state should be prepared for CCA to control 67 percent of the total electric load if the agency’s forecasting proves correct.

There are eight community choice programs in the state, such as Redwood Coast Energy Authority, CleanPowerSF and Lancaster Choice Energy. That number is expected to roughly double by the end of next year, with San Jose and Los Angeles County gearing up to create what would be the state’s two largest CCAs.

In San Diego County, 15 of the region’s 18 cities are in various stages of looking at community choice, with Solana Beach being the furthest along. The city of San Diego could decide by early next year on whether to proceed toward a CCA, while the county of San Diego has put off the idea for now.

Under the utilities commission’s most dramatic predictions, investor-owned utilities would make up just 10 percent of the market by 2020. Rooftop solar would comprise 10 percent, up from 6 percent today. The remaining 13 percent would be direct-access sales, an arrangement where nonresidential customers buy directly from a specific power generator instead of from a traditional utility.

Commission officials said the shift away from utility companies could play out more slowly. Still, they urged lawmakers and regulators to prepare for a transformation, especially to ensure that CCAs and other new entities are properly regulated so they don’t fall short when demand for electricity spikes.

“The transition could be messy,” said Edward Randolph, energy division director for the commission. “The point is to make sure that we have enough electricity under contract during a peak day in the summertime, so you don’t have rolling blackouts or the wholesale price of electricity goes higher and gets passed on to ratepayers.”

Regulators said they have begun such measures, but stressed that revising the oversight process could take years and might require legislative action to expand the commission’s authority over CCAs.

When the idea of community choice emerged in California, the state’s three largest utilities used their dollars to oppose it. After bitter battle between Marin County and Pacific Gas & Electric over creation of the state’s inaugural CCA, the Legislature decided in 2011 to bar investor-owned utilities from using ratepayer money to speak out on community choice.

Those companies must apply with the utilities commission to create a separate lobbying division that’s funded entirely by shareholders. In the case of SDG&E, the commission last year permitted establishment of a lobbying arm — Sempra Services Corporation — that’s housed under the utility’s parent company.

Last week, Frank Urtasun of Sempra Services Corp. said consideration of CCA programs should be postponed until regulators give more clarity on some key issues.

“Two of the most critical elements of a feasibility analysis are the costs and benefits. Unfortunately, there is tremendous uncertainty about both of these components right now,” he said.

California’s major utilities largely make profits from building infrastructure like transmission lines, while energy procurement and sales are largely pass-through costs. When a CCA is formed, a utility company continues to issue bills to that program’s customers — but breaks out transmission expenses collected by the utility versus generation charges paid to the CCA.

SDG&E, SCE and PG&E have said CCAs wouldn’t dramatically impact their bottom line as long as they’re made whole for long-term energy contracts they have signed on behalf of customers who later chose a community choice program.

The state charges CCA customers a fee to address this concern.

Both the utility companies and CCA leaders have criticized the formula for determining this fee, which is called the Power Charge Indifference Adjustment, or PCIA.

Community choice groups said the process of determining the PICA amount isn’t transparent because free-market rules restrict them from understanding the pricing data that utilities submit to state regulators.

Utilities said they’re not receiving full compensation for expensive, long-term purchases of green power that they’ve made to fulfill the state’s renewable-energy requirements. The cost of solar power has come down significantly in recent years, benefiting community choice programs that have sprung up during this pricing drop.

“Revamping (the commission’s) policies to deal with this emerging situation is going to be a huge job,” said Dan Farber, co-director of the Center for Law, Energy and the Environment at UC Berkeley. “Because some customers will still need or desire the utilities for power, and everyone will be using their distribution systems, it has to be managed in a way that’s fair to them. …”

A revision of the PICA formula is expected within the next 18 months. Over time, regulators said, the issue could become much less of a concern as the utilities’ long-term contracts expire.

Focus: Market Transformation Will End Dominance of Electrical Utilities, Regulators Predict, by Joshua Emerson Smith, The San Diego Union-Tribune, July 16, 2017.

Picking Solar Winners and Losers at Intersolar North America

The ample rains that ended California’s historic drought this year may have dampened the state’s residential solar industry, but the weather can’t claim as much credit as net metering changes.

That’s right — when it comes to solar’s success, it’s still all about policy, as illustrated by a panel on the North America solar market at this week’s Intersolar.

With 35% fewer installs in Q1 year over year, is California residential solar a loser? And who were the winners in 2016 – 2017?

Policy trumps — well, just about everything else

Stress about the slowdown of the residential sector has moved beyond industry insiders to the pages of the New York Times, which cited saturation of the California market as one cause. That’s too bad, because the negative press is itself a cause for the slowdown, according to Kelly Knutsen, Senior Policy Advisor at CALSEIA. Bad lead gen tactics haven’t helped either.

Still, the biggest culprit, not surprisingly, is policy. We can blame the weather, but Knutsen’s chart on the San Diego area — which had about the same rainfall this year as last year — shows what happened when Net Metering 2.0 kicked in there in the middle of its sunniest season:

Image courtesy of Kelly Knutsen

What’s often as harmful as bad policy is policy uncertainty. A looming uncertainty is the “national proliferation” of net metering and retail rate reforms, said Galen Barbose, a research scientist at the Lawrence Berkeley National Laboratory. That includes time of use (TOU) rates, which may be shifted in a way that would slow solar adoption.

Fixed charges can also have devastating effects on the rooftop solar market. While some utilities have proposed charges as high as $50 a month, that’s unlikely to happen, said Barbose — which is good, because it could reduce nationwide residential solar growth by 90%. Even more modest increases of about $10 could reduce the sector’s long-term growth by 15% nationwide.

Demand charges represent a serious threat for residential solar, said Barbose, since residential customers don’t have the ability to moderate those charges. When Salt River Project rolled out demand charges in 2015, that led to an abrupt dropoff in residential solar:

Image courtesy of Galen Barbose

And then there’s Suniva — speaking of uncertainty. Elizabeth Sluder, a partner at Morrison Foerster, noted that while uncertainty about the case isn’t freezing investment, it’s already slowing down solar development, something that’s been corroborated by more than one solar company.

What’s working in solar

Not surprisingly, policy is also a leading character in solar’s success stories. Sarah Wright, Executive Director of Utah Clean Energy, showed how strong policies moved Utah from an F to a double A in the Freeing the Grid assessment, and helped the state more than double its rooftop solar in the last few years.

Community Choice Aggregation (CCA) shows early signs of becoming a big success story in California, facilitated by a 2002 law that enabled the programs in the state. Already, 1 million California residents are part of a CCA, and CCAs now being considered would cover another 15 million — that’s about 40% of the state’s population. By some estimates, in 5 years, 60% of California investor-owned utility (IOU) customers will be part of a CCA. That means that a large percentage of California solar customers wouldn’t be subject to utilities’ rates and regulations, and it could open up more solar markets through programs like community solar and feed-in tariffs.

Image courtesy of Kelly Knutsen

Storage could also be a major bright spot — again, if we have the policies to support it. Storage is key to solar’s future success, and as Aram Shumavon, founder and CEO of Kevala, pointed out, storage can help balance local and system needs with customer needs.

According to Knutsen, nearly 1 GW of utility-scale storage will be installed in California by 2018, with another 130 MW behind the meter. He wasn’t the only one at Intersolar to declare that storage today is where PV was in 2007 — and we know what happened there.

Too soon to declare victory?

Andrew Beebe of Obvious Ventures believes “we should all be declaring victory right now.”

He conceded that we’re about to enter into “a whole new world of annoyance,” which includes, of course, the Suniva case. But he insisted that the planet is winning, small businesses are winning, and we’re on an “inexorable move toward 100% renewable.”

A nice note to end on, but as inevitable as clean energy seems to those of us in the industry, they don’t call it the “solarcoaster” for nothing. And most would consider the trade case more than an “annoyance.”

Just a day after a rousing social media push at Intersolar to support SB 700, which aimed to be a “California Solar Initiative for storage,” the bill was halted in the state Assembly. That underscores both the volatility of the policy landscape and the need to keep fighting to move clean energy forward

Picking Solar Winners and Losers at Intersolar North America, by Rosana Francescato, PV Solar Report, July 14, 2017.

Utilities Are Buying up Distributed Energy Companies. Should Community Energy Agencies Take a Lesson?

The following article by Jeff St. John of Greentech Media demonstrates the burgeoning competition for electricity customers as utility monopolies lose their stronghold. Will Community Choice Energy agencies take a lesson and avoid losing their own customers? Considering their community focus, are Community Choice agencies developing sufficient opportunities and incentives for local solar to support the solar stakeholders in their service territories? Comments encouraged at the bottom.

The case for utilities to bundle their energy businesses—before they’re cannibalized

The utility industry has already been undergoing significant change over the past 25 years, with the rise of independent grid operators, competitive energy markets and the split of vertically-integrated business models.

But the rise of distributed energy is creating more turmoil for the utility industry than even these epochal changes. And because these changes are being driven by fundamental advances in technology, they’re happening at a pace and scale that’s increasingly outside the utility’s control.

These underlying trends — or “megatrends,” if you will — have created a world in which utilities are increasingly moving into unfamiliar markets and business models, according to experts at Greentech Media’s Grid Edge World Forum 2017 conference in San Jose.

“There are two no-regret decisions for utilities — renewable energy and anything that gets them closer to customers,” said Andrew Bennett, senior vice president and “Internet of Things Evangelist” for Schneider Electric North America, during a Wednesday panel session. “Look at all the acquisitions that are taking place on the commercial side of utilities, both European and in the U.S. over the last year.”

Large-scale renewables have long been a part of many utilities’ portfolios, but this trend has been accelerating over the past few years. Notable examples include Duke Energy Renewables, the utility giant’s new business founded in 2007 and expanded through the acquisition of California solar installer REC Solar and energy management company Phoenix Energy Technologies. Other utility moves into commercial solar include NextEra’s acquisition of Smart Energy Capital and Edison International’s purchase of SoCore.

Utilities are also getting closer to customers. Some of the biggest U.S. examples include Southern Company’s $431 million purchase of PowerSecure and its 1.5-gigawatt fleet of backup power systems, and Edison International’s creation of its energy services business through the acquisition of a roster of energy service providers and renewable power developers.

European utilities have been following suit. France’s EDF formed its distributed electricity and storage business unit earlier this year, building on its 2016 acquisition of groSolar. French utility Engie bought U.S. energy services provider Ecova and OpTerra Energy Services, as well as behind-the-meter battery startup Green Charge Networks. And Italian utility Enel’s U.S. subsidiary has joined the fray with its purchase of behind-the-meter energy storage project developer Demand Energy, and most recently, demand response market leader EnerNOC.

All of these acquisitions share several common characteristics, Bennett said. First, they’re bringing utilities opportunities in territories outside their core regulated services territories. After all, “you’re not going to self-cannibalize your steady income,” he said.

Second, they’re aimed at capturing the growing share of large commercial and industrial customers that are looking for more control of their energy usage. “They’re going to take those high-end customers, because the customers want it.”

These two trends are mutually reinforcing, he noted. The defection of C&I customers from traditional utility relationships is already happening, “and at a scale that’s pretty large,” said Bennett, pointing to high-profile examples like MGM’s Nevada casinos paying $87 million to drop service from utility NV Energy and take up with retail power provider Tenaska.

It doesn’t take too many of these losses to have a significant impact on a utility, he noted. “You don’t need to lose 10 percent of your customers. You just have to lose a few percentage points of your top customers that are subsidizing major portions of your grid costs.”

Regulatory efforts are underway to enable distributed energy to play a role in utility operations, as with California’s DRP proceeding and New York’s REV initiative, as well as to play a role in energy markets run by transmission system operators such as California ISO or PJM.

But “regulator-driven change hasn’t been particularly successful” in this industry, noted Michael Carlson, president of Siemens Digital Grid, noted, citing the experience of California’s abortive deregulation in the late 1990s and early 2000s.

Regulatory changes can also take too long to keep pace with changes being wrought by technology, noted Todd Glass, a partner with law firm Wilson Sonsini Goodrich & Rosati.

Still, despite the rise of contenders like Tesla and SolarCity, the utilities’ deep pockets and central role as energy provider for the majority of the country could put them in position to offer the complete package of products and services that many customers are looking for, said Glass.

“I don’t know who the ultimate competitors or providers of services will be in the future,” he said. “You’re going to have larger companies offering bundled services.”

Smaller companies that can’t pull together this complete suite are “going to be acquired, largely, I think — or evolve into much bigger companies.”

Utilities Are Buying up Distributed Energy Companies. Should Community Energy Agencies Take a Lesson?, by Woody Hastings, Center for Climate Protection, July 12, 2017.

There’s Energy behind State Bill to Promote Solar Power Storage: Guest commentary

Here in another California heat wave, we are reminded that communities need new strategies to be resilient as we face erratic shifts in our climate.

By harnessing our state’s abundant sunshine, so we can tap into it even when the sun isn’t out or during a prolonged outage, energy-storage technology can boost community preparedness efforts.

Many of your neighbors — and perhaps your family — have economically installed rooftop solar panels thanks to state subsidies and tax rebates that encourage it. But home storage of the electricity generated remains highly expensive, on the order of $30,000.

That’s why it’s so important to for the state Legislature to pass a bill that would encourage storage in the same way we’ve successfully encouraged solar panels.

Energy storage is a key innovation that can enable our march toward 100 percent renewable energy. Through energy storage, California can absorb the solar power we already produce during the day and use it at times when the state otherwise turns to dirty fossil fuels to meet our electricity needs. Energy storage also allows our residents, businesses, and schools to take control of their electricity bills and ensure they are using clean, locally produced renewable energy.

Energy storage can involve a number of technologies, such as lithium ion batteries or flow batteries, or thermal energy storage used to store energy from a generation source, such as a solar PV system, for use at a later time.

Energy storage technologies give customers and utilities the ability to control the flow of electrons in an efficient manner, effectively solving the problem of the intermittency of renewable energy and allowing for an ever-greater reliance on renewables. When the sun is shining, a solar energy system can recharge an on-site storage device. Then, when the sun goes down, the storage device can be used to meet evening and night-time electricity demand.

With the right incentives and controls, storage devices can be highly flexible and dynamic, storing and/or discharging electrons to the grid. In this way, storage technologies are among the most important and effective tools for grid operators to increase use of renewable energy and build a more resilient and reliable system.

We must ensure all Californians, especially families living in underserved areas, benefit from our clean energy revolution. If an incentive existed to encourage installation of energy storage, low-income renters could save more money at home with solar energy. Locally, properties like Mosaic Gardens in Whittier, which already has solar panels installed, could benefit from such incentives.

Adding energy storage at affordable housing developments that already have solar power will do more than just boost electricity bill savings for residents; it will also diminish reliance on the electricity grid, reducing the need for fossil fuel plants that are disproportionately located in disadvantaged communities.

Solar energy already employs more than 100,000 Californians, and pairing it with energy storage helps both industries flourish. As energy storage is inherently local, it will create good local jobs and promote economic opportunity in our communities.

With Los Angeles County set to launch its own power agency to offer renewable energy directly to customers, energy storage would help this effort deliver more savings and more jobs.

The bill moving through the Legislature, Senate Bill 700 by Sen. Scott Wiener, D-San Francisco, would slash the price of energy storage through a tiered rebate program to help this technology go mainstream, just as solar power itself has. If approved, the law would promote energy storage with a focus on disadvantaged neighborhoods and affordable-housing communities.

By reserving at least 30 percent of funding for low-income and underserved Californians, SB700 would keep energy costs stable and predictable for families that are most vulnerable to price spikes. The bill also contains local workforce training and hiring components so that the proliferation of energy storage can create economic development throughout the state.

SB700 offers a technology-neutral solution to increase the amount of storage to solve for the grid issues California faces and unlock the solution to getting more renewables across the state. We cannot afford to wait as we increase our commitment to renewable energy. Energy storage technology is ready to efficiently absorb the renewable energy we already produce and allow for the expansion of clean, local solar power.

As California takes the national and global stage on our climate change leadership, SB700 wwould ensure all Californians reap the benefits of clean energy.

When the next epic heat wave comes, we need to be ready.

There’s Energy behind State Bill to Promote Solar Power Storage: Guest commentary, by Jim Jenal, Stephanie Wang, and Dan Jacobson, Pasadena Star-News, July 6, 2017.

California Bill Aims to Help Befuddled Cities, Towns Permit Energy Storage Quickly

With hundreds of small-scale energy storage applications expected in response to California’s Self-Generation Incentive Program, a new bill aims to help confused cities, towns and counties permit energy storage systems efficiently.

permit energy storageSponsored by the California Energy Storage Alliance, AB 546 would create a handbook of best practices for permitting energy storage systems and establish limits on what communities can charge for permits, said Alex Morris, director of policy and regulatory affairs for CESA. The handbook is designed as a model other states may use.

California regulators recently doubled incentives for the Self-Generation Incentive Program, giving the lion’s share to energy storage funding. They ruled that the state’s investor-owned utilities must collect $83 million annually between 2017 and 2019 for the SGIP program. That’s double what was collected in 2008. The incentive program includes a carve-out for residential customers.

“We’re expecting hundreds of permit requests,” said Morris. “They will start coming through the SGIP program. The program has been on hold for a long period of time. Now it’s opening in rolling steps. It has a residential carve out. We’re expecting to see a number of small systems.”

Local governments unfamiliar with how to permit energy storage

While all these applications are good news for the storage industry, local governments aren’t familiar with energy storage and could hold up the permitting, he said.

“The purpose here is to give cities and counties helpful tools. The vast majority of projects are small behind-the-meter projects that have to connect with the utility and go through the permitting process,” said Morris. The best practices permitting handbook would be helpful to government agencies that don’t have the funding to learn how to permit energy storage systems.

The bill also requires that the government agencies state clearly the cost of permitting. They’re required to charge only the price of permitting, and not inflate the price to make money, he said.

“In some cases, one city or county has a low-cost fee, and another city or county has a high price, setting an artificially high permitting price,” he said.

Putting a price on ability to ramp quickly

Meanwhile, the California Energy Storage Alliance has its eye on work by California regulators to put a price on the ability of resources to be flexible and ramp up quickly, he said. Last week, the California Public Utilities Commission passed resource adequacy rules that relate to this issue.

“Every year they have to make resource adequacy targets. Originally they were going to look at updating or revisiting how they approach the system’s flexible capacity needs,” said Morris. The PUC discussed establishing what’s called a “durable flexible product,” a standard product that producers can participate in. CESA had hoped the PUC would focus more on establishing a product that would include prices that compensate storage providers for their ability to ramp up quickly, Morris said.

“The portfolio we use to run the grid is evolving,” said Morris. “You need a set of resources that you can have standing by to absorb extra solar and run the gauntlet of providing grid services, take directions from the California ISO, and provide four hours of energy at a time to meet peaking needs. Storage is very well positioned to provide a lot of those services.”

“The portfolio we use to run the grid is evolving. You need a set of resources that you can have standing by to absorb extra solar…”

Right now, some are concerned the state is relying too much on natural gas in ways that work against its ambitious emissions-reduction targets, he noted. Natural gas power plants are kept idling, waiting for solar production to drop off, so that they can respond.

“You have to keep them around just for this momentary ramping need, and you have to burn fuel, and you end up with the emissions effects of natural gas,” said Morris.

“There’s a lot of money in it…”

While natural gas is expected to play an important role for California for a long time, there’s room for storage to compete against natural gas, especially if storage providers are compensated for their ability to ramp up quickly and provide flexibility, he said.

At this time, older gas plants that are slow to ramp up, new gas plants, and storage all qualify as “flexible,” and receive the same payments, even though they provide different levels of flexibility.

A storage device that can ramp 300 MW in a few minutes counts the same as the other resources, he noted.

“This is an ongoing and important regulation,” said Morris. “It’s one of the most important issues. There’s a lot of money in it, and it’s all about running the grid reliably.”

California Bill Aims to Help Befuddled Cities, Towns Permit Energy Storage Quickly, by Lisa Cohn, Microgrid Knowledge, July 7, 2017.

What Do You Get When You Sign up for a 100% Green Electricity Plan?

For the first time, residents and businesses up and down the state can buy electricity plans touted as “100 percent green” in their quest to fight climate change or simply be more environmentally friendly.

They can enroll in these programs through California’s three major investor-owned utilities — San Diego Gas & Electric, Southern California Edison and Pacific Gas & Electric — or through the growing number of cities and counties that offer alternative power programs called community choice aggregation, or CCA.

Does this mean all the electricity flowing into those customers’ homes and offices is created with renewable energy? No.

When residents pay a roughly $5 to $10 premium on top of the average monthly bill to get a 100 percent green plan, the provider buys a corresponding amount of renewable energy on their behalf. Almost all of that green power comes from existing inventory, which is mixed with electricity generated from fossil fuels, and the situation isn’t expected to undergo a transformation until far more people enroll in 100 percent plans. Whether that explosion in demand takes years or decades to realize remains to be seen.

PUC Will Consider Changing Energy Exit Fee

The California Public Utilities Commission has decided to review the mechanism by which Pacific Gas and Electric Co. and other investor-owned utilities are compensated when customers switch to community choice aggregators, such as Marin Clean Energy.

The utilities and the community choice aggregators agree that the current mechanism for compensation is flawed. They are at odds, however, over how it should be changed or what should replace it.

MCE, formerly known as Marin Clean Energy, and other aggregators must pay the utilities a “power charge indifference adjustment (PCIA),” a fee to compensate them for the energy they purchased to serve the departing customers. The fee was imposed by the California Public Utilities Commission to ensure that customers remaining with the utilities would not end up footing the entire cost.

In April, the utilities requested that the exit fee be replaced with another compensating mechanism.

“By all accounts, the current methodology for allocating costs and benefits among these customer groups is fundamentally broken,” the utilities wrote in their application.

The application went on to state: “The current approach forecasts costs based on administratively-determined estimates of hypothetical future market prices, with no true-up for actual costs. Because this complex process is not and cannot be based on actual, current market prices, it results in cost shifts between customer groups.”


Last month, the CPUC declined the utilities’ request saying it was premature, but the commission has said it will consider the proposal in a more thorough review of the exit fee.

“The growth of community choice aggregation requires the CPUC to closely analyze cost sharing between customers who stay with a utility and customers who leave for a community choice aggregator,” said Commissioner Carla Peterman in a statement. “This proceeding will holistically examine cost sharing issues by taking into account the concerns raised by a wide range of organizations interested in this topic.”

MCE has about 255,000 customers. It serves Marin County and all of its municipalities; Napa County and its municipalities; as well as the municipalities of Walnut Creek, Richmond, Lafayette, Benicia, El Cerrito and San Pablo. On July 20, MCE’s board will decide whether to add Contra Costa County and eight municipalities in that county, which could add an additional 230,000 customers.

Regarding the CPUC review of the exit fee, Dawn Weisz, MCE’s executive officer, said, “We see this as a very positive development. We’ve been urging the commission to address the deficiencies in the PCIA since 2012. We’re very pleased that the commission will now be looking at the issue in a comprehensive way.”


In January 2016, the CPUC approved PG&E’s request for a steep increase in the exit fee, despite objections by MCE. The increase nearly doubled the exit fee and made PG&E’s overall rates at the time lower than MCE’s. Today, MCE’s rates are slightly lower than PG&E’s. Fifty-five percent of MCE’s “light green” electricity product comes from renewable sources while 30 percent of PG&E’s electricity comes from renewable sources. A typical MCE household pays nearly $13 a month in exit fees.

The exit fee is calculated annually and adopted at the beginning of each year based on a forecast of the projected costs of energy for the next year. It is based on the difference between the price paid by the investor-owned utility for the energy and the average market prices. All energy customers pay the fee regardless of whether they buy their electricity from a utility or a community choice aggregator, such as MCE.

“The problem is there is no transparency into the calculation and the contracts that the investor-owned utilities have in their portfolios,” Weisz said. “It’s a very black box methodology when you can’t see the contracts that our customers are having to pay for.

“We think that when the power is sold off into the market it needs to be sold at the highest value possible not dumped in the spot market, which is what we’re seeing,” Weisz said. “These excess energy volumes are being undervalued when they’re sold off in the market and that means that customers are having to pay more to cover the above-market cost of that power.”


Weisz said the new methodology that the utilities are seeking approval for would allow them to continue selling excess energy for less than it is worth. She said the methodology would also allow the utilities to transfer excess energy contracts to community choice aggregators without allowing for price negotiation. And it would permit them to transfer renewable energy certificates (RECs) to aggregators.

Weisz said that while the utilities purchase these RECs bundled with the renewable-source electricity they represent, the transfer would automatically convert them into unbundled RECs.

“By law, the energy has to be delivered at the same time that the clean attribute is delivered and to the same party,” Weisz said.

An “unbundled, renewable energy certificate” is a credit that, when purchased, allows the buyer to legally claim ownership of 1 megawatt hour of renewable electricity. It has been “unbundled” from the actual renewable electricity that was generated.

MCE has been criticized in the past for using too many “unbundled” RECs to meet its targets for renewable energy use. Critics of unbundled RECs say they are often priced too low to finance the energy generation they represent. Over the last two years, MCE has curtailed its use of these RECs; currently they account for only about 3 percent of MCE’s renewable electricity.

PG&E spokeswoman Deanna Contreras declined to respond to any of the issues raised by MCE.

“We look forward to working collaboratively with all parties through this process to ensure that all customers are treated fairly and equally,” Contreras said. “Everyone agrees that the current formula is broken and out-of-date, and that’s why it’s critically important to address these inequities in a timely fashion.”

PUC Will Consider Changing Energy Exit Fee, by Richard Halstead, Marin Independent Journal, July 7, 2017.

New, Bigger Incentives for Electric Cars Could Be Ahead in California

California could be poised to set up more generous rebates and incentives for electric vehicle buyers — and not just affluent drivers cruising in Teslas.

Assemblyman Phil Ting, D-San Francisco, is pushing a proposal to establish a $3 billion fund to support the spread of electric vehicles with bigger rebates, more programs for low-income buyers and the deployment of more charging stations. It would also deliver discounts at dealerships, eliminating the need for consumers to file for tax rebates.

Ting said the proposal would give the electric vehicle market an aggressive push and help California hit its ambitious environmental goals.

“We’ve been able to dispel the notion that you can’t clean the environment and grow the economy,” he said. “The next wave is electric vehicles.”

The proposal, AB1184, is a huge leap in funding from current programs, which have given $420 million to low- and zero-emission vehicle owners since 2010. Funds are expected to be diverted from existing sources, with details set by the California Air Resources Board.

The program would provide a boost to Gov. Jerry Brown’s goal of having 1.5 million clean cars on California roads by 2025. Only about 300,000 electric vehicles have been sold in the state. Zero emission vehicles accounted for less than 2 percent of the 2 million new cars sold in California last year.

Supporters believe the measure, called the California Electric Vehicle Initiative, will fuel the market for electric vehicles, much like state incentives did for the rooftop solar industry a decade ago. Incentives would fade out as electric vehicle costs decline.

The bill drew some opposition from Republican lawmakers in the Assembly, and now faces Senate hearings.

If the proposal is approved, supporters expect the new rebate program to roll out late next year.

The new program would give electric vehicle makers a dependable market to grow their business, said Steve Chadima, senior vice president at Advanced Energy Economy, a clean energy business association co-sponsoring the bill.

The market for electric vehicles is “coming along,” said Chadima. “It’s just not coming along quickly enough.”

California has several electric vehicle startups, including Palo Alto-based Tesla.

The air resources board would determine the size of a rebate based on equalizing the cost of an EV and a comparable gas-powered car. For example, a new, $40,000 electric vehicle might have the same features as a $25,000 gas-powered car. The EV buyer would receive a $7,500 federal rebate, and the state would kick in an additional $7,500 to even out the bottom line.

Two new electric vehicles that deliver over 200 miles of range on a single charge — the Chevy Bolt and the forthcoming Tesla Model 3 — carry sticker prices around $35,000.

Ting said the market for affordable, long-range electric vehicles is just developing.

The proposal also continues an existing program that dedicates $500 million annually to promote low or zero-emission vehicles in poor communities.The funds provide incentives to switch transit vehicles from diesel to electric or hybrid, and also help low and moderate income Californians purchase used, low emission cars.

The proposal is essentially an expansion of a state program that now hands out rebates of between $1,500 and $5,000 to buyers of electric vehicles and hybrids.  Rebates for plug-in hybrids may decrease under the new bill.

The Clean Vehicle Rebate Project has issued 115,000 rebates worth $295 million to buyers of battery-powered vehicle since 2010. Critics say the program favors wealthier Californians who can afford new cars.

Lawmakers adjusted the rebate program in March 2016, curbing allowances for wealthy buyers and offering higher rebates for low and moderate income purchasers.

A study last year by two UC Berkeley-trained researchers of nearly 100,000 rebates found that more than 80 percent of the checks went to Californians reporting an income greater than $100,000. The money went primarily into communities with few black and Latino residents.

New, Bigger Incentives for Electric Cars Could Be Ahead in California, by Louis Hansen, The Mercury News, June 28, 2017.

New Report Examines Consequences of Private Utility Over-Purchasing of Power for Customers as Community Choice Grows

A new report by the Center for Climate Protection examines the over procurement of power by private utilities in the context of the growth of Community Choice Energy in California. The report is authored by energy policy analyst June Brashares and Tyler Bonson, a graduate of Sonoma State’s Energy Management and Design and in Economics.

The rise of Community Choice

In the last three years, the rise of Community Choice Energy in California has been dramatic. The first Community Choice Agency (CCA), MCE Clean Energy, launched in 2010, and was the only one for four years until Sonoma Clean Powerlaunched in 2014, followed soon after by Lancaster Choice Energy in 2015. By mid-2015 a critical mass of information-sharing and proof-of-concept had spread throughout California and by late 2016 nearly half the counties in the state and over 300 cities were either operational or at some stage of evaluation of Community Choice. The Center for Climate Protection keeps track of the growth with a dynamic interactive map, updated weekly, that includes Community Choice Energy status information about every city and county in the state at the Clean Power Exchange. The report takes it from there and projects the magnitude of the growth between now and 2020 in terms of megawatt-hours of load departing to Community Choice.

The exit fee challenge to Community Choice

In late 2015 a nearly 100% increase in a previously obscure fee on Community Choice Energy bills in PG&E service territory upset many customers and concerned advocates for Community Choice Energy. The fee, known as the Power Charge Indifference Adjustment, or “PCIA,” is a fee meant to cover the costs of previous power purchases made on behalf of customers who have now exited their private utility and become Community Choice customers. It is often called an “exit fee.” This spike in fees raised the question: at what point do the utilities cease to purchase power on behalf of customers in an area that is evaluating Community Choice Energy? It matters because all customers, big utility or Community Choice, must pay for this power. In fact, the issue of over-procurement of power by private utilities has gotten a lot of media attention recently, and this is one of the main questions explored in the paper.

Over-purchasing power

According to LA Times reporter Ivan Penn, who has covered the issue since February 2017: “California has a big — and growing — glut of power, an investigation by the Los Angeles Times has found. The state’s power plants are on track to be able to produce at least 21% more electricity than it needs by 2020, based on official estimates. And that doesn’t even count the soaring production of electricity by rooftop solar panels that has added to the surplus.” (Californians are paying billions for power they don’t need, LA Times, Ivan Penn and Ryan Menezes, Feb 5, 2017)

The new report has several key findings relating to both the exit fees and private utility procurement of power. They include:

  1. The methodology by which the exit fee is currently calculated does not accurately or fairly accomplish its intent. The result has been volatile increases in exit fees that undercut Community Choice agencies. The exit fee’s volatility, complexity, and lack of transparency put Community Choice customers at risk of unexpected, confusing, and potentially unfair cost increases.
  2. Private utility load forecasts and the corresponding procurement decisions have underestimated the number of customers leaving private utilities for a Community Choice option, resulting in more over-procurement of power by private utilities.

The paper offers a series of recommendations including:

  1. Initiating a transparent proceeding at the California Public Utility Commission dedicated to reforming the structure and nature of exit fees.
  2. Adjusting load forecast procedures to ensure that power procurement plans fairly and correctly include Community Choice growth projections.
  3. Allowing appropriate Community Choice agency staff to review confidential protected energy data subject to a Non-Disclosure Agreement, enabling Community Choice agencies to verify private utility calculations for exit fees.
  4. Establishing incentives for private utilities to reduce quantity and associated costs of current and future procurement contracts to minimize avoidable costs to Community Choice customers as well as their own customers.

To download the entire report and appendices, click the following links: Community Choice Aggregation Expansion in California and its Relation to Investor Owned Utility Procurement with underpinning CCA/IOU Load Data Spreadsheet, prepared for the Center for Climate Protection by June Brashares and Tyler Bonson

If you would like to make a comment about exit fees to the California Public Utilities Commission, you can call, write, or email the CPUC Public Advisor at:

Telephone:  1-866-849-8390
Postal Address:
Public Advisor’s Office – CPUC
505 Van Ness Ave
San Francisco, CA 94102

For further information visit the Public Advisor’s website at:
And the main CPUC contact webpage at:

Stop, Collaborate and Listen: California Stakeholders Want to Open Electric System Communications

An unprecedented collaboration between California’s grid operator, its investor-owned utilities, and third-party distributed resource providers could streamline electric system communications in preparation for higher distributed energy resource penetration.

The groundbreaking work maps out plans to interconnect the bulk transmission system to distributed energy resources(DERs) through utility-operated distribution systems, achieving a new level of communication between the transmission system operator, the distribution system operator, and the DER provider.

 Technology advances and customer demand are transforming the electric power, according to a newly-released report from the California Independent System Operator (CAISO), Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E).

DERs are beginning to reach significant penetration levels on the emerging “decentralized system,” and are on their way to becoming key resources, the paper noted. A working group led by think tank More Than Smart (MTS), which included the IOUs, CAISO, and DER providers, released the paper at the end of the first year of a multi-year effort.

The group’s objective is to resolve operational challenges preventing transmission operators and distribution operators from working with private sector developers to meet consumer demand for DER, said MTS President Tony Brunello.

Jeffrey Nelson, SCE Director of FERC Rates and Market Integration, said that DER demand is driving a “transformation in the way we operate the grid.” The utility, Nelson said, wants to be involved “in shaping that transformation.”

It has never been necessary before for transmission and distribution operators to coordinate, added Lorenzo Kristov, a market and infrastructure policy principal for CAISO. But as DERs proliferate, efficient dispatch of those resources in wholesale power markets will require communication between DER providers, distribution operators and the transmission operators.

Power sector experts agree proactive information exchanges will be necessary on tomorrow’s grid. This working group, which is endorsed by all three stakeholder groups, is the leading effort to build that coordination framework, Krisotov said.

What’s happening at the transmission-distribution interface

The transmission and distribution systems are interconnected, but are distinct and have “different structures, characteristics, functions and operating principles,” the MTS white paper noted. Because of that, crafting communications to bridge the different systems and DER providers is key to handling higher DER penetration.

The transmission system delivers central-station generated electricity to utility-operated distribution systems via transmission-distribution substation “interfaces.”

Transmission operators have “little to no visibility” into the distribution system, the white paper noted. But with only central station generation flowing one way through transmission -distribution interfaces, there has been no need for visibility.

DERs are defined as resources connected to the distribution side of the transmission-distribution interface, according to the paper. In California, across the U.S., and around the world, policies and incentives are driving down the cost of DERs and spurring customer demand, MTS reports. In California, DERs make up 10% of peak demand, and some forecasts predict an installed capacity doubling before 2030.

Private providers see new value propositions in delivering aggregated DERs to wholesale markets while also serving retail customers, MTS reported. CAISO and the California Public Utilities Commission (CPUC) are working to lower barriers.

But growth introduces new operational complexities because of the lack of visibility of transmission operators into distribution system-interconnected DER described by the white paper.

“This lack of visibility may result in the ISO issuing dispatch instructions to DERs that the [resources] are unable to comply with due to distribution system constraints,” MTS reports. It may also create operational complications for [distributed operators], making streamlined coordination and communication at the transmission-distribution interface “even more important.”

The paper evaluates two timeframes: a near-term outlook to 2018 and a mid-term outlook into the early 2020s.  In the near term, a relatively low DER penetration will make aggregated DERs only a small factor in the wholesale market.

Towards the mid-term, wholesale markets are likely to see “much higher volumes and diversity of DERs and DER aggregations.”

The paper considers three DER use cases in those timeframes: In one, DERs provide services only to the wholesale market. In another, those resources provide services to the distributed operators or end-use customers but not to the wholesale market. In the third, DERs provide wholesale market and end-use customer services, as well as services for distributed operators.

As these scenarios move from the near term to the mid-term, increased coordination and communication across the transmission-distribution interface will become critical.

DER providers have to be informed of current distribution system changes that will affect their operation,” Kristov said. And the transmission operator’s’ dispatch instructions to DER “need to be communicated to the distribution operators.”

The paper recommends steps to achieve the needed coordination and communication.

For 2017,CAISO and the distribution operators, supported by DER providers, should “initiate, pilot, and test” ways to move beyond manual procedures, the paper proposes. To allow providers to modify market bids when necessary, “[Distributed operators] should pilot processes to communicate advisory information on current system conditions to DER providers.”

CAISO needs to develop ways to provide day-ahead DER dispatch schedules to the distribution operators so they can anticipate potential “reliability or performance problems,”  MTS adds. This type of communication could be incorporated into DER Management Systems (DERMS).

DER providers need to be able to communicate constraints on their resources to CAISO, MTS reports, which could be modified market bids or outage notifications.

Finally, the distribution operator and the DER provider should have a formal “integration agreement” for aggregated DERs, similar to an  interconnection agreement while delineating responsibilities in the event of disruptions.

For the mid-term scenario, the paper recommends exploring new utility business models that call for today’s utilities to act as distribution system platform operators (DSOs).

Participants should also “develop and pilot” methods of forecasting DER “activity and impacts at T-D interfaces,” MTS recommends. And stakeholders need to expand understanding of how high DER penetrations may impact distribution system safety and reliability and identify ways to mitigate threats.

Matthew Tisdale, the executive director of MTS,said overall, the DER transformation remains too hazy  prescribe more precise solutions. But the working group allows CAISO and distributed operators to work proactively on more precise planning with DER providers who are “disrupting the way the grid has been run.”

Why the utilities are in

Some utility officials agree the foremost objective of participating in the workshop was to ensure the utility transformation protects distribution system safety and reliability.

“A lot more can happen on a distributed system,” said Mark Esguerra, PG&E’s director of integrated grid planning, said. “Being able to provide advisory information on events to providers will be key to them knowing if their market participation will be impacted.”

The current low penetrations of DERs can be served manually with existing tools, but future penetrations will likely require a “a website or server that DER providers log into,” Esguerra expected. “It will certainly require utility investment in software capabilities and automation.”

PG&E also anticipates the need for pilot programs to test software capabilities, he added.

Esquerra sees two takeaways in the MTS work so far. One is that the distributed operators “don’t have the same level of visibility, control, and situational awareness on DER that CAISO has on transmission-connected generation.”

The other is that the transmission operator, the distributed operator, and DER providers “all stand to benefit” from improved communication and coordination across the T-D interface.

SCE’s Nelson said it is noteworthy that the paper acknowledged the complexity of developing greater coordination between the three system participants. “A much more sophisticated coordination than what is in place needs to be envisioned.”

Each of the three participants has part of the system information needed “to know if market transactions are feasible,” Nelson said. “But none has enough information.”

He endorsed the paper’s near term and mid-term scenarios. “It offers no specific remedies but reports that monitoring, visibility, and control of the distribution system needs to be synchronized with the complexity it has to deal with.”

The MTS working group is “about getting out ahead of the coming transformation,” Nelson added. “If that does not happen, the electric power sector will not be ready to provide customers with the choice they are demanding and to use DER to help meet the state’s goals.”

SDG&E’s director of electric transmission and distribution engineering Will Speer said that even beyond specific takeaways, “the best thing that happened was us sitting around the table and discussing what the future will look like.”

They did not engage in controversial questions about rate design or the costs and benefits of DER, he added. They focused “purely on operational issues.”

A framework on which to build coordination and communication is not urgently needed at present but “we need to establish a process,” Speer said. “A DERMS or some other kind of platform or control system will eventually be necessary but we are not there yet.”

To determine the exact hardware or software infrastructure needed to streamline coordination and communication, “there has to be a bigger DER sample size,” Speer said.

Once such an infrastructure is built, “we will be able to operate in a high DER future with the resources participating in wholesale markets,” Speer said. “That would reduce cost for all our customers.”

Modernizing the system will  include a DERMS-like platform that provides automated monitoring and control systems, Speer agreed. That will provide distributed operators with the kind of distribution system visibility CAISO has at the bulk system level. It will also give DER providers the system status signals they need and keep the distribution operators in the loop.

The providers’ perspective

On the third-party side, Advanced Microgrid Solutions (AMS) and Green Charge Networks described the communications proposed by the paper as a “connective tissue” to allow cost-effective management of the grid.

It’s crucial because “visibility and control don’t talk to each other and can’t be managed without communication,” said AMS CEO Susan Kennedy, also an MTS board member.

Solutions for communications at the T-D interface “are the key technical and regulatory issues in distribution system operations and will be the foundation for integrating DER,” Kennedy said.

Michael Grabstein, AMS’ working group representative and grid sercices project manager, said the paper’s communications proposals are essential to the limited-scale DER aggregation now being done by AMS. “To provide a capacity resource for the ISO, we have to ensure the [distribution operator] does not constrain us.”

AMS’ vice president of markets and policy Manal Yamout said AMS’s newest project will deliver a 90 MWh fleet of resources to SCE. “Without communications, that could cause havoc on the distribution grid instead of displacing the need for transmission and distribution upgrades and providing services to the customer.”

The paper’s communications proposals will make aggregated DER, and especially distributed energy storage, dispatchable grid resources, Yamount added. “The key to storage economics is enabling multiple uses of a single asset and that can only happen if everyone who wants to use that asset always knows what’s going on in real time.”

GCN’s vice president of policy Walker Wright said working group participation is crucial for DER providers. “Regulatory intelligence and business development go hand in hand,” he said. “Providers need to be at the table to hear the perspectives of utilities, regulators, and other stakeholders as they build a framework for new DER markets.”

While the working group strives to develop cooperation on the complicated interactions between the three interdependent parties interacting at the transmission-distribution interface, Wright noted ultimately all parties want the same outcome.

“Utilities and DER developers want the same thing, which is to satisfy their customers,” he said. “Consumer demand is the force building the grid of the future and it is important to go back to the kitchen table and ask the question high level regulatory conversations can miss:  What is driving consumers?”

Stop, Collaborate and Listen: California Stakeholders Want to Open Electric System Communications, by Herman K. Trabish, UtilityDive, June 22, 2017.