Local Balancing Is the Key to California’s Clean Energy Future. Regionalization Isn’t

California needs a sustainable and affordable energy system that can deliver an all-renewable energy supply and manage that supply cost-effectively.

Instead of creating an interstate entity that may not be aligned with California’s renewable energy goals, we should build an energy system that provides the modern grid California will actually need going into the future — one that relies on coordinated local energy, modern grid operations, and balancing authorities to efficiently use the resources in our own backyard.

Regionalization is touted as a cost-saving effort that would bring renewable energy from across half the continent to California to even out the variability in energy production from renewables. But the call for regionalization ignores the tremendous progress that is already being made in utilizing clean local energy resources — an approach that provides a trifecta of economic, environmental and resilience benefits, while avoiding the high costs in both dollars and governance associated with regionalization.

Theoretically, if the California Independent System Operator (CAISO) obtained energy from outside of the state when in-state renewable energy resources weren’t producing enough to meet California’s demand, California could meet its needs more cheaply than it would by building a lot more renewable energy plants. In principle, variability in renewable energy generation can be offset when resources are integrated over a wide enough area, because “the wind is always blowing somewhere.” However, the real question is whether regionalization is the most effective or cost-efficient approach to resolving these issues.

Regionalization would introduce new costs and risks. Relying on a continent-scale transmission grid would mean building many long transmission lines. Such continent-scale transmission is expensive and would unavoidably damage the environment it crosses.

Relying on distant energy sources increases vulnerability to disruptions across a larger grid. Operational error, extreme weather, natural disasters, and sabotage all pose greater risks with a large grid spanning the dry and fire-prone western region of North America.

In addition, without effective federal energy policy and emissions markets, regionalization could increase carbon emissions as existing renewables are dispatched from other states for California load, and coal plants in those states fill the gap. Meanwhile, investment in renewables projects in California would be suppressed, along with the associated jobs and revenues, as projects to serve California load are built out of state.

The economic risks are exacerbated by the fact that CAISO and California’s three big investor-owned utilities currently charge the same delivery fees for energy carried over hundreds of miles of expensive transmission lines as for energy delivered from down the street. This practice has already created distorted price signals that have led to inefficient markets, negatively impacted development and failed to contain the rapid rise in transmission costs. Using California ratepayer funds to subsidize energy imports and push development out of the state is not good policy.

Under some governance proposals for a regional transmission operator (RTO), California could become subject to the influence of coal state officials or utilities. California, which represents half of the population of the Western Electricity Coordinating Council area and over half of its economy, would have only a small fraction of the governance authority — placing California’s leading efforts at risk should they conflict with regional policies.

Distributed energy resources (DERs) under a local balancing authority can meet these same needs more effectively — without the downside risks that regionalization would bring.

First, the volatility and increasing complexity of the grid is happening in large measure at the distribution end of the grid, not the transmission end. Therefore, it should be managed first at the distribution level. All loads are local, and while local DERs can add complexity, they also allow loads to be locally managed and balanced, reducing volatility to the system overall.

Through a network of dedicated distribution system operators (DSOs) to manage collections of DERs at the distribution level, aggregated DERs, such as solar-plus-storage and demand response, would use complementary local technologies to balance local load and generation, providing a well-behaved load profile to the transmission grid at the transmission-distribution interface. Thus, rather than looking to an ever-larger central grid to provide control, a DSO-based energy system can manage load and generation locally to integrate complementary renewable technologies and optimize use of the resources already in place.

Second, using local power and local balancing would contain the ever-increasing costs associated with expanding transmission. In California, transmission costs have been increasing faster than inflation for decades, even as the cost of generation has fallen.

Today, delivery charges threaten to surpass the cost of generation as the major cost of energy. This trend is likely to continue as long as utilities and community-choice aggregators are incentivized to procure remote generation. If the full costs of delivery are included in energy procurement — by having transmission charges reflect the use of transmission infrastructure — DERs can often provide energy more cheaply than remote generation, leading to overall cost savings for ratepayers.

Finally, DERs deliver greater reliability, because robust local generation from multiple sources is less subject to impacts from the failures of one or two components. For example, during the recent Thomas Fire emergency in Southern California, many of the areas that maintained power did so with microgrids including solar and storage resources, as regional transmission lines failed to deliver energy.

Transitioning our grid to a fully renewable energy system will require a mix of approaches. The foundation needs to be laid first at the local level with DERs managed by DSOs to make the transmission grid manageable. Some of this is already being done by the California Public Utilities Commission and local utilities. Only if it is determined that our needs will not be met with cost-effective local and in-state resources should we consider the costly infrastructure and legal commitments required to import energy.

This approach will ensure we rely on out-of-state resources only as needed, rather than creating a new entity that looks first to ultra-remote power as a solution. This DSO-based system of grid management would not create a regional ISO, but would instead supplement the existing and successful Energy Imbalance Market to incorporate a day-ahead market that would manage energy imports and exports for mutual benefit — but without the deeper entanglements with coal states that will endanger our clean energy economy.

Ultimately, California needs an energy system that meets our clean energy goals primarily with local generation and solutions — and one that looks to distant, expensive and potentially dirty energy only as a last resort. We should certainly use the transmission system we already have to help local balancing areas support one another, but we must consider all the costs and implications of increasing our reliance on distant resources and losing control of our energy future.

 

Local Balancing Is the Key to California’s Clean Energy Future. Regionalization Isn’t, by Doug Karpa, Greentech Media, February 21, 2018.

PG&E reaches green energy goals early, but hurdles loom

PG&E has reached a state-mandated renewable energy goal three years earlier than required, the company said, but fresh challenges loom as the company’s last nuclear power plant is slated for deactivation.

The utility has reached the state-imposed 2020 renewable energy goal of producing 33 percent of its electricity from renewable energy sources, it said.

“Reducing carbon emissions, as quickly as possible, is the main objective of California’s energy policies,” said Geisha Williams, PG&E’s chief executive officer. “Creating a sustainable energy future is also the guiding vision for PG&E.”

PG&E also said it now delivers 78.8 percent of its electricity from resources that are free of greenhouse gases. Those resources, however, include the Diablo Canyon nuclear plant in central California that’s headed for decommissioning. That means the company will have to scramble to find green energy replacements for Diablo Canyon.

State regulators have approved PG&E’s proposal to shut both Diablo Canyon reactors by 2025. Described by PG&E as a source of clean energy, Diablo Canyon during 2017 provided 27.4 percent of the company’s sources of electricity.

San Francisco-based PG&E highlighted its green energy initiatives at a time when disasters have cast a shadow over the company.

Among PG&E’s woes: a fatal explosion in San Bruno that resulted in a $1.4 billion financial punishment — the largest penalty ever imposed on an American utility; PG&E’s felony conviction in federal court for actions linked to the San Bruno blast; and lethal wildfires in October that scorched the North Bay Wine Country and nearby areas, posing further potential hazards to the company’s well-being.

The next major benchmark for PG&E to meet California’s renewable energy mandates: By 2030, 50 percent of the retail electric deliveries by utilities must be derived from eligible renewable sources. PG&E believes it’s ahead of schedule to meet that benchmark.
But PG&E still needs to find new green energy sources when Diablo Canyon ceases production.

“As we prepare to replace the energy from Diablo, renewable energy sources are something we will be looking at,” said Denny Boyles, a PG&E spokesman.

 

PG&E reaches green energy goals early, but hurdles loom, by George Avalos, The Mercury News, February 20, 2018.

California regulators emphasize solar, batteries in utility planning framework

CPUC’s guidance calls for an additional 9 GW of solar and 2 GW of battery storage as the standard against which to compare utility and CCA Integrated Resource plans, and says that new fossil fuel plants must prove a need.

For decades California has been a leader in the transition to renewable energy, and the conclusion of the state’s first statewide Integrated Resource Plan (IRP) reinforces this trend, with the California Public Utilities Commission (CPUC) providing detailed guidance to the state’s utilities and community choice aggregators (CCAs) in terms of meeting state greenhouse gas reduction goals.

In a decision last week which was published yesterday, CPUC adopted a target for the electric sector to reduce its greenhouse gas emissions 50% from 2015 levels by 2030. Additionally, the agency adopted a reference system for utility and CCA plans which calls for an additional 9 GW of solar, 2 GW of battery storage, 1.1 GW of wind and 200 MW of geothermal as the optimal resource portfolio.

It is important to note that this 2 GW of battery storage is in addition to the 1,325 MW currently mandated by CPUC, however the agency notes that the need for some of this could be displaced by certain types of advanced demand response and/or pumped storage.

While setting this model portfolio of renewable energy, CPUC not only noted that the state does not need additional fossil-fuel fired plants, but essentially moves the burden of proof to the utilities. The February 8 ruling requires that any utility proposing to either contract with a new gas plant larger than 20 MW or renew a contract with an existing one for five years or more must prove that this need could not be met with another “lower- or zero-emitting resource”.

This move follows on an increasing rejection of natural gas infrastructure by California regulators in favor of clean energy alternatives, as the state continues to burn less and less gas every year in its electricity sector.

However, advocates were disappointed with the decision by CPUC to not being a process to require procurement from utilities. Vote Solar has argued that the utilities should be continuously procuring new renewable energy resources, warning that putting off procurement can lead to a boom/bust cycle.

One relevant factor here is that California continues to import a large portion of its power, a situation which could worsen once the Diablo Canyon nuclear power plant closes, which is scheduled for 2025.

“With the looming closure of California’s last nuclear power plant, the need for GHG-free energy sources can’t wait until the end of next decade to meet a 2030 target,” notes Vote Solar in a blog post.

Vote Solar says that it is looking for ways to correct the delay in implementation. The organization also notes that there is still a need to develop better modeling tools to compare distributed energy resources with utility-scale solar and wind for a more optimal mix, and Vote Solar says it will be working with CPUC to develop a common resource valuation methodology.

Finally, Vote Solar has called for more analysis of the state’s natural gas fleet, arguing that more gas plants need to close to make room for renewables and reduce electricity costs. This follows on the release of a new paper by three scientists from the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) which explores the issue of minimum requirements for conventional generation in California and Texas and how this causes curtailment of renewable energy.

 

California regulators emphasize solar, batteries in utility planning framework, by Christian Roselund, PV Magazine, February 14, 2018.

California Sets New Rules for Community Choice Aggregators

Editor’s Note: Cal-CCA’s website claims 1 million METRIC tons, not mega-tons of GHG emissions; and, CCAs have always been subject to resource adequacy requirements. The CPUC is just trying to address how the hand-off of responsibility occurs in the first year of operations of a new CCA.

News Article Repost from Greentech Media

Community-choice aggregators, or CCAs, have become a force that cannot be ignored.

In California, CCAs are cities or counties that have taken over key aspects of their own electricity and natural-gas procurement, distribution and sales from one of the state’s three big investor-owned utilities. From a slow start in 2010, the ranks of CCAs have grown to include eight operational entities with more than a dozen more being formed or expanded at present, representing 1.85 million customer accounts.

According to the advocacy group CalCCA, this growing trend can claim credit for saving tens of millions of dollars in customer energy costs, and nearly 1 million megatons of carbon emissions in renewable energy purchased, on an annual basis. These kinds of benefits have led to CCA legislation being passed in states including New York, Massachusetts, Illinois, New Jersey, New York, Ohio and Rhode Island.

But to the state’s investor-owned utilities, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, CCAs are an existential threat to their business models — a mechanism that takes away their customers, while leaving them with the burden of managing the power lines, maintenance crews, and the customer service platforms that keep the system running. How those costs are shared between CCAs and utilities has been a longstanding point of contention between the two, with the California Public Utilities Commission serving as the referee.

Last week, the CPUC adopted a resolution that will force future CCAs to take up at least one part of this common burden — resource adequacy, or the need to procure enough energy to meet the grid’s need when energy demand is peaking.

“This has been a long time coming, but it was not easy to come to a resolution,” said Elta Kolo, grid edge analyst for GTM Research. “Over the years, there has been heightened tension between CCAs, utilities and the commission.”

CCAs have been exempt from RA requirements to date, leaving utilities to include their customers as part of their load forecasts. “This scenario occurred in 2017 and will likely occur in 2018 when CCAs submitted implementation plans and began serving customers out of sequence with the RA timelines,” the CPUC wrote.

When CCAs were few and small, that wasn’t such a big problem. But the exploding number and size of CCAs over the past two years have led to a significant cost shift from CCAs to the utilities, according to the CPUC’s resolution.

There are mechanisms in place to allocate longer-term utility costs to new CCAs, under the Power Charge Indifference Adjustment (PCIA) that recovers utility costs from CCA customers, that were entered into on CCA customers’ behalf. But RA costs of less than one year aren’t captured by the PCIA, leaving remaining utility customers to foot the bill for their share of procuring RA.

“The Energy Division has confirmed this cost shift, but that data is market-sensitive and confidential,” the CPUC’s resolution noted. But according to GTM Research’s Kolo, the figures add up to “stranded costs in the tens of millions of dollars for IOU customers due to submissions of load forecasts and allocations for resource adequacy.”

To fix this gap, CPUC’s resolution requires a new or expanding CCA to submit its implementation plan no later than January 1 of the year before it intends to start serving new customers, aligning its timeline with utility RA timelines. That proposal led to an outcry from CCA advocates when it was unveiled in December, since it would constitute a de facto freeze on new developments for a year or more.

To avoid this effect, the revised resolution exempts all plans submitted or approved before December 7, 2017. That list includes the cities of San Jose, Solana Beach and Rancho Mirage, multi-city aggregations such as East Bay Community Energy and Los Angeles County Community Choice Energy, and plans by existing CCAs Marin Clean Energy and Sonoma Clean Power to expand to surrounding communities, and represents about 3,600 megawatts of load.

Five other plans, representing about 1,700 megawatts of load, will get an expedited review to meet the April 2018 load forecast deadline, the CPUC resolution noted. Those include Desert Community Energy, King City and Riverside CCAs, as well as planned expansions by Silicon Valley Clean Energy to Milpitas and Los Angeles Community Choice Energy to an additional 21 cities. Other plans that meet a March 1 deadline will also have a chance to comply with rules for serving in 2019.

These rules only apply to the 2018-2019 period. In the longer term, the CPUC plans to address the issue of CCAs and resource adequacy through other formal proceedings. “Regardless of when a CCA Implementation Plan is submitted, all prospective and expanding CCAs are still subject to the Commission’s Resource Adequacy Requirements,” it wrote.

That’s in line with the CPUC’s expectation that up to 85 percent of California’s retail load could be served by CCAs or direct access providers by 2025. That will make them a critical part of the state’s energy landscape. GTM Research has pointed to CCAs as a major new market for utility-scale solar PV over the next five years, taking up the slack from utilities that have met their near-term renewable portfolio standard targets to represent up to to 45 percent of California’s utility PV demand over the next five years.

“With California’s rapidly changing resource mix and increased penetration of renewable and distributed generation, transparency and equitable allocation of costs is crucial — especially when grid reliability is at stake,” Kolo said.

The eight operational California CCAs are Marin Clean Energy, Sonoma Clean Power, Lancaster Choice Energy, CleanPower San Francisco, Peninsula Clean Energy in San Mateo County, Apple Valley Choice Energy, Silicon Valley Clean Energy and Redwood Coast Energy Authority. Other CCAs expected to launch this year are East Bay Community Energy in Alameda County, Los Angeles Community Choice Energy and Valley Clean Energy Alliance in Yolo County and Davis.

 

California Sets New Rules for Community Choice Aggregators, by Jeff St. John, Green Tech Media, February 14, 2018.

An Unseasonably “Hot” February for California’s Clean Energy Landscape

By and large, major policy action for California’s electricity sector mimics the seasons: winter is a relatively quiet, reflective time and major policy developments start to bud in the spring. As the air heats up, so do policy debates in Sacramento, which ultimately bloom fully or die on the vine in September, when the Legislature wraps up its session.

But lately, the weather in California and electric sector policy developments seem unseasonably hot. For example, it’s currently 75 degrees outside my office in Oakland. And below are some of the things happening in the policy world that also seem particularly “hot”:

CPUC approves a 2030 clean energy blueprint.

Late last week, the California Public Utilities Commission (CPUC) approved a blueprint laying out the electricity sector investments through 2030 that will be necessary to reach greenhouse gas reduction goals consistent with the statewide requirement to reduce emissions 40% below 1990 levels by 2030.

This system-level blueprint is the first phase of what’s called the Integrated Resource Plan (IRP); the next step is for all investor-owned utilities (IOU) and community choice aggregators (CCA) to submit their individual plans, which are due in August. More information about the IRP and individual IOU and CCA progress can be found here. The publicly-owned utilities (POUs) in the state will submit their plans to the California Energy Commission (CEC) and progress can be tracked here.

UCS conducted analysis in the IRP proceeding to underscore a key blind spot in the CPUC’s own work: the fact that all of the gas generation capacity that exists today was assumed to still be around in 2030 to provide energy and grid services.

It’s well known that California has an excess of natural gas generation capacity on the grid, and it remains a significant source of global warming pollution in California. We built a lot of natural gas plants in the 90s and early 2000s, and we don’t need it all now. Our own analysis showed that a significant portion of the natural gas peaker generation capacity may not have much value to the grid in 2030. But, we also know that some gas will be important for reliability through 2030.

The question is, which plants stay and which plants go? The IRP decision underscores the need to understand the role of gas in California’s clean energy future, to make sure that the inevitable downsizing of the fleet does not jeopardize grid reliability, and benefits people that are most impacted by gas plant pollution, especially “fenceline” communities that bear the brunt of this pollution. UCS is planning some additional analysis on this issue, so stay tuned.

Big bills are being discussed in Sacramento.

Senate Bill (SB) 100, a bill that would set a bold and achievable target of getting 100% of California’s electricity from carbon-free resources by 2045 is still alive, and waiting to be taken up for a vote in the Assembly. Although there is a lot of public support for SB 100, the policy is getting hung up by potential amendments that deal with the treatment of distributed energy resources. UCS is trying to do what it can to break that logjam and in the meantime, communicate to the Assembly that we’d like to see SB 100 move forward without additional amendments.

Assembly Bill (AB) 813 is a bill that would make it possible for the California Independent System Operator (CAISO)—which operates the grid that serves about three quarters of California’s electricity needs—to expand and include other western states. Pivoting California’s energy market into one that’s west-wide is ambitious and complicated, but worth the effortExpanding the pool of resources that a grid operator has to manage the system is one of the most cost-effective ways to incorporate more wind and solar generation onto the electricity system.

Energy storage and small-scale renewables are giving natural gas a run for its money.

In early January, the CPUC issued a resolution that authorizes PG&E to hold competitive solicitations for energy storage or “preferred resources” (e.g. demand response and distributed solar) to meet local reliability requirements that have previously been met with gas power plants. This decision, combined with the CEC’s recent decision to reject NRG’s request to build a natural gas peaker plant in the Oxnard, is evidence of what will hopefully become a very significant shift away from the assumption that gas plants are the best and most cost-effective way to provide grid reliability services in the future.

These are just three examples of major clean energy advancements that have unfolded in the last six months. And, many decisions are still developing about whether the state will pass SB 100 and nearer-term plans we’ll need in order to move towards a cleaner grid. Clearly, there is more work to do. But there’s no doubt in my mind that we are making meaningful progress on these “hot topics,” and UCS will be working to make sure California continues its clean energy momentum and climate leadership to “cool down” global warming.

 

An Unseasonably “Hot” February for California’s Clean Energy Landscape, by Laura Wisland, Union of Concerned Scientists, February 12, 2018.

Equity in Hiring – The Community Choice Energy Supplier Diversity Symposium

On Friday, January 26, I attended the “CCA Supplier Diversity Symposium,” held in Richmond, California. Co-hosted by the California Community Choice Association (CalCCA) and the Greenlining Institute, the event drew over 100 attendees from throughout California including Community Choice agency (CCA) leaders, CPUC Commissioners, local government leaders, businesses, and local workforce and union representatives.

CPUC Commissioner Carla Peterman addresses the audience.

The purpose of the event was to review the commitments, initiatives, and progress made by CCAs, local governments, and the business community to support public–private partnerships with women, minority, disabled veteran, and LGBT-owned businesses in the energy sector and to share best practices for diversity in the energy workforce.

Issues addressed included:

  • How CCAs can contribute to the movement of promoting diversity – combining green energy initiatives, local control, transparency, and public engagement.
  • Best practices and resources for CCAs and suppliers to promote the use of minority businesses.
  • Challenges and successes for minority business owners and how CCAs and local governments can support them, and how non-minority-owned businesses can promote diversity.
  • Exploring how and why projects like MCE’s Solar One (see more below) are important to the State, the roles that RichmondBuild, Grid AlternativessPower, and Cenergy Power played in the MCE commitment to ensure a 50% local hire goal, their diversity initiatives and how this project may inform future deployments.
  • Presentations from individuals from the local community that were hired into the workforce for the Solar One project, discussing their personal experience, reasons for transitioning into the green workforce, current projects, and future goals.

One of the points of information that came up was the CPUC’s General Order 156, that addresses diversity in procurement in the energy sector. The program monitors supplier diversity in procurements by participating utilities and oversees a clearinghouse of women, minority, LGBT, and disabled veteran-owned business enterprises. The clearinghouse verifies the status of firms seeking certification as being owned by one of these categories.

MCE’s 10.5MW Solar One project in Richmond, CA.

The day concluded with an on-site tour of MCE’s Solar One installation, a 10.5 megawatt solar project constructed on an otherwise unusable brownfield near the Richmond waterfront. It is the largest publicly owned solar project in the Bay Area and ownership is expected to eventually transfer to MCE. For details from the day, take a look at the program.

Stay tuned to CPX E-News for interviews in the next edition with some of the local folks hired to work on the Solar One project.

 

 

 

 

 

 

Why are big utilities so afraid?

Last year, Ventura and Los Angeles counties took a huge step forward in creating energy choices when we joined with dozens of local cities to create the Clean Power Alliance of Southern California. Since, 28 jurisdictions have signed on to offer cleaner, greener and cheaper energy to communities throughout Southern California. We are not the first local California governments to embrace the promise of what is known as community choice aggregation.

By the end of 2017, there were nine such groups, and by the end of 2020, it is estimated that more than 18 million Californians will get their electricity from a CCA program. The model also has a strong track record in other forward-thinking states, including Illinois, Massachusetts, New Jersey, New York and Ohio. These programs bring more clean energy to consumers, lower utility bills and create jobs in local renewable power.

Unfortunately, big utilities are working hard to confuse the public and regulators and to make it tougher for the public to have a say over where they get their electricity. On Thursday, the California Public Utilities Commission will hear a proposal that would deliberately slow down the creation of local CCA programs.

They operate as nonprofits, allowing local governments to purchase electricity in the wholesale power market and sell it to their residents and businesses using existing transmission lines. This gives consumers an alternative to the electricity provided by big investor-owned utilities such as Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric.

Why would PG&E, SCE, and SDG&E try to stand in the way of the Clean Power Alliance of Southern California and other CCAs? The answer seems clear: After operating for decades as monopoly energy suppliers, the big utilities are simply afraid of competition.

The PUC must be alert to the big utilities’ motives and work with local governments to address the new challenges and opportunities that CCAs represent in California. We call on the commission and the utilities to be fair and forthright in their dealings with cities and counties that want to purchase cleaner energy and provide it at lower prices to residents and local businesses.

This is the future of California energy and the sooner we can make it happen, the better.

 

What are big utilities afraid of?, by Linda Parks And And Sheila Kuehl, The Sacramento Bee, February 7, 2018. 

California Gov. Brown outlines plan for 5M ZEVs by 2030

Dive Brief:

  • California Gov. Jerry Brown signed an executive order to get 5 million ZEVs on the road in California by 2030 — a significant jump from the 350,000 ZEVs currently on the state’s roads.
  • Brown’s administration also proposed a $2.5 billion plan to extend subsidies for zero-emissions vehicles (ZEV) and expand the state’s vehicle charging station network from 14,000 EV charging stations and 31 hydrogen fueling stations to 250,000 charging stations and 200 hydrogen stations. This plan still requires legislative approval.
  • In addition to the order, the governor detailed the 2018 California Climate Investments plan, which will invest $1.25 billion in cap-and-trade auction proceeds “to reduce carbon pollution and improve public health and the environment.”

Dive Insight:

These initiatives, announced during the governor’s State of State address, strengthen California’s position as a ZEV leader. The state already has one of the largest ZEV car markets in the world — thanks to a 1,300% increase in the number of ZEVs on the road over the past six years — which accounts for about 5% of all new car sales in the state.

Brown’s new proposal will require ZEVs to account for 40% of all new car sales by 2030, which is a “reasonable” goal, according to Mary Nichols, chairwoman of the California Air Resources Board. Some may consider it much more reasonable than Assemblyman Phil Ting’s proposal requiring ZEVs to account for 100% of all new cars registered in California after Jan. 1, 2040, though that proposal is still active in the California legislature.

According to a new report from think tank Next 10, Brown’s lofty ZEV goals are attainable, as long as charging infrastructure can keep pace. “Barriers such as inadequate infrastructure could slow progress, but our report shows that by 2040, ZEVs could be as ubiquitous as smartphones are today,” said Next 10 founder F. Noel Perry in a statement.

As Brown enters his final year in office, he will continue to push the state into the environmental spotlight. In September, the state will host the Global Climate Action Summit in San Francisco in an effort to “roll back the forces of carbonization” and support the Paris Agreement in the fight against climate change, despite conflicting efforts from the Trump administration.

 

California Gov. Brown outlines plan for 5M ZEVs by 2030, by Kristin Musulin, Utility Dive, January 31, 2018.

Community choice energy drives renewable growth in California

Community choice aggregation, a tool to encourage greater choice and local control, is coming into its own in California and driving significant growth in clean energy.  In other states, it’s a different story. Ben Paulos takes a look.

As communities across America seek to take climate action into their hands, they are finding that community choice aggregation can be a powerful tool – though not all towns are willing to use it, and not all willing towns have access to it.

California is at the vanguard of the community choice movement, and it is driving major growth in clean energy.

Community choice aggregation, or CCA, is a process where locals form a group to buy their own energy. It was authorized by the legislature in 2002, but was delayed by years of wrangling. Marin County was among the first to start the process of creating a CCA, but was hindered by the utility PG&E.  In 2010, PG&E spent $46 million on a ballot initiative to weaken the law, and lost.  Marin Clean Energy launched the same year.

There are currently nine active CCAs in California with another dozen in the works, but the number could rise as high as eighty, according to state officials.

Most are motivated by a desire to go green faster than state policy dictates.  Current state law requires utilities to reach 33% renewables by 2020 and 50% by 2035, but currently active CCAs already exceed those targets.  Silicon Valley Clean Energy, serving towns like Cupertino and Mountain View – home of Apple and Google – is the first to be 100% renewable.

San Diego

The biggest battle currently is in San Diego.  The city adopted a Climate Action Plan in 2015 that calls for a 50% cut of all greenhouse gas emissions by 2035, 100% renewable electricity, and various efficiency, waste management, and transportation measures.

Local activists have pushed both the City and the County to use CCA to meet the renewable energy goal, arguing that San Diego Gas & Electric (SDG&E) couldn’t be trusted with the task.

“There doesn’t exist another viable way for the city of San Diego to get to 100% other than to be in control, and community choice offers this proven model,” said Nicole Capretz with the Climate Action Campaign.

The County declined in February to launch a CCA program, but the City is still considering it.

Long a laggard on clean energy, SDG&E has changed its ways, becoming the first investor-owned utility in the state to reach the 33% landmark (five years ahead of the 2020 schedule under state law).  The utility is now at 43%, not counting the 36,000 rooftop solar systems installed by their customers, making San Diego one of the biggest solar cities in the US.  By 2021 SDG&E expects that 52% of the energy received by San Diegans will come from renewables.

In late October SDG&E filed a proposal with the City to meet San Diego’s 100% renewable energy goal. Under SDG&E’s plan, the utility would work with civic leaders to shape their renewables procurement, and let customers choose different levels of renewables, above the state-mandated level, just as CCAs do.

Capretz was not impressed.  “This is not a serious proposal, much less a viable, vetted or feasible plan,” she told the San Diego Union-Tribune. “It’s just another delay tactic to deny San Diegans choice and keep us tethered to an outdated monopoly.”

Thirteen other companies have also expressed an interest in working with the City.

One big wildcard for CCAs is the size of an exit fee that utilities are able to charge departing customers to cover the cost of past contracts. State regulators are pondering the charge now.  If it is high, it will undermine the economics of CCAs, eroding their ability to deliver more renewables at a lower cost.  While California consumers are certainly green, they are also price sensitive, and may balk at a big bill increase.  SDG&E points out that no exit fees would be necessary under their proposal to San Diego.

Meanwhile, the state legislature is considering a bill (SB 100) that would increase the RPS goal to 60% by 2030, and to 100% from renewables and zero-carbon resources by 2045.

The combination of higher exit fees and higher mandatory state renewable energy goals, plus SDG&E becoming more aggressive in pursuing renewables, could undermine the rationale for a San Diego CCA.

Other states with CCAs

California is currently the hot spot for CCA, but six other states offer it.

Illinois has been the most active, where at one time 80% of the residential load was served by over 600 CCAs.  The rapid uptake in Illinois was due to a brief window of time where CCAs could guarantee savings compared to the default utility rate.  But as the default rate fell, the savings evaporated and most CCAs shut down, sending their customers back to the utility or to choose from a competitive power supplier.

CCA is growing in Massachusetts, where 128 cities and towns have authorized it.  The largest, Boston, authorized CCA in October through a vote of the City Council.  But Mayor Walsh’s office expressed some doubts about it, saying CCA is “a very powerful tool” but “it can be a very expensive tool.”

Unlike in California, renewables are only part of the push for CCAs in Massachusetts. While many towns let consumers choose an all-green option, only a handful of towns have opted for slightly higher levels of renewables in their basic plan, due to fear of higher costs. “Five percent is the magic number,” according to the Mass Energy Consumers Alliance, an advocacy group. “It supports more renewable energy on our power grid while keeping the new aggregated supply rate competitive with what the electric utility is offering.”

States without CCAs find it tough

CCA offers an easy way for communities to take control of their energy use without the trouble of creating a municipal utility.  Under this “muni-lite” approach, a CCA does not own or operate the equipment needed to generate or deliver the power, but does choose the fuel sources and set some policies.

In states without a CCA option, communities pushing for greater local control are finding it difficult.

The poster child is Boulder, Colorado.  Frustrated by the heavy reliance on coal of their investor-owned utility, Xcel Energy, and inspired by the Kyoto Protocol, Boulder has been working to create a municipal utility since 2002.  The effort barely survived a referendum on November 7, when voters approved another $16.5 million in funding for legal and engineering fees by a margin of only 1000 votes.

Another Colorado city, Pueblo, is finding itself on a similar path. In February the city, home to a major wind turbine manufacturing plant, pledged to go 100% renewable by 2035.  But they are served by a monopoly utility, Black Hills Energy, that has repeatedly raised rates in recent years.

“We thought Black Hills was going to be a good corporate citizen of Pueblo,” Councilman Larry Atencio said at a September 25 City Council meeting. “They have not been.  They have gouged us. They have taken advantage of us. They have gone over and above being a corporate robber of the citizens of Pueblo.”

With the city’s franchise agreement with Black Hills expiring in 2020, the City Council voted unanimously to start looking into municipalization, with a $250,000 budget for research.

William McEwan, the city’s energy advisor, told the Council, “I truly believe the long-term solution for Pueblo ratepayers is a municipal utility, but its a tough, tough process.”

 

Community choice energy drives renewable growth in California, by Ben Paulos, Energy Transition, January 29, 2018.

Guide to Creating State-of-the-Art Community Choice Programs

The California Alliance for Community Energy is pleased to announce publication of this Guide as a timely and, we hope, compelling contribution to the growing Community Choice movement.

We created this guide to set forth our vision of what an optimal Community Choice program looks like and to provide pointers for how to go about creating and operating such a program. Our vision is inspired by the potential for Community Choice energy to be a powerful vehicle for delivering transformative social, economic, and political benefits.

As you may know, the Alliance has been fighting to defend Community Choice against attack from the monopoly utilities and the California Public Utilities Commission. We have also been in the trenches across the state working to create “second generation” Community Choice programs that deliver a broader set of benefits than earlier, first generation programs and are more engaged with the communities they serve.

This Guide attempts to capture this collective experience, the principles and values behind it, and what we’ve learned about building strong Community Choice programs that can serve the needs of their communities.

We invite energy advocates and practitioners, especially those with an interest in Community Choice, to check out the Guide, download it, distribute it, and let us know what you think.

 

From Al Weinrub of the California Alliance for Community Energy, January 21, 2018.