California CCAs Hit 3,000-Megawatt Mark for New Long-Term Clean Energy Contracts

Redondo Beach, Calif. – The California Community Choice Association (CalCCA) announced today that Community Choice Aggregators (CCAs) in the state have in one year added another 1,000 Megawatts (MW) in long-term power purchase agreements (PPAs) with new renewable energy projects, bringing the grand total of new-build contracts signed to 3,195 MW. The achievement reflects the strength of the CCA commitment to advancing clean energy, economic development and green jobs throughout California.

“CCAs are continuing to rapidly secure the clean energy resources California needs to meet ambitious decarbonization and climate change goals,” said Beth Vaughan, executive director of CalCCA. “At a time of unprecedented change in California’s energy sector, aggregators are providing stability, accountability and leadership when the state needs it most.”

In addition to securing renewable energy PPAs totaling 3,195 MW, aggregators have also signed long-term battery energy storage contracts for 239.5 MW/788 Megawatt-Hours (MWh) combined, with more than half – 149.5 MW/438 MWh – contracted for in the last year alone. Of the total, 212 MW/678 MWh, or about 86%, is co-located with solar panels that will charge batteries with sun power – energy that can be discharged at times of peak demand and to provide grid stability.

Notably, 13 CCAs – six more than last year – have now signed long-term PPAs in order to meet their renewables portfolio standard (RPS) and long-term contracting requirements under SB 350, as well as local mandates set by CCA Boards. Of the 13 CCAs, five launched just last year.

CalCCA announced the 3,000-MW milestone at the association’s Fourth Annual Meeting in Redondo Beach, where more than 450 attendees are gathered to discuss the latest developments in California’s energy market, and the key role community energy providers are playing in the state’s efforts to address climate change. Last November, CalCCA announced that CCAs had achieved a 2,000-MW milestone for long-term PPAs. In fact, aggregators have added approximately 1,000 MW in each of the last three years.

California’s CCAs have to date signed a total of 76 PPAs with new solar, wind, biogas and energy storage facilities, up from 59 contracts in November 2018 – a nearly 30% increase. The contract terms range from 10 to 25 years, or 18 years on average across all contracts.

The clean energy projects are located in 19 California counties (up from 17 in 2018), from Humboldt County in the north to Riverside County in the south, with one project located in Arizona and another in New Mexico. Several projects are already operating, while others will become operational between 2019 and 2022. A map of project locations and a list of contracts can be found here.

Several local projects have been added to the list in the last year. East Bay Community Energy, for example, signed a trio of local battery energy storage contracts to facilitate the shutdown of a fossil fuel-fired power plant in downtown Oakland. The Redwood Coast Energy Authority, meanwhile, is developing a local microgrid project at the California Redwood Coast – Humboldt County Airport. RCEA will own and operate the microgrid’s solar and energy storage systems.

Aggregators are expected to make long-term investments in more than 10,000 MW of new clean energy resources including solar, wind, geothermal and energy storage by 2030, and several CCAs are currently in the process of procuring new clean energy resources. To stay on top of CCA procurement news, sign up for CalCCA’s mailing list here.


About CalCCA: Launched in 2016, the California Community Choice Association (CalCCA) represents California’s community choice electricity providers before the state Legislature and at regulatory agencies, advocating for a level playing field and opposing policies that unfairly discriminate against CCAs and their customers. There are currently 19 operational CCA programs in California serving approximately 10 million customers.
For more information about CalCCA, visit

Bay Area Community Energy Agencies Kick Off New Program to Provide Local Resiliency

Oakland, Redwood City, Santa Clara, and Sunnyvale, Calif. – Three Bay Area Community Choice Energy agencies and one municipal utility are joining forces to ramp up efforts to help stabilize California’s electricity grid and provide reliable power. East Bay Community Energy, Peninsula Clean Energy, Silicon Valley Clean Energy, and Silicon Valley Power will announce a new program on November 5 to address the resiliency needs of our communities in the wake of multiple, on-going power shut offs and the threat of wildfires. The program will offer grid-stabilizing technology to provide power for thousands of homes and businesses in Alameda, San Mateo, and Santa Clara Counties, including those hit by recent PG&E power shutoffs.

The four public power agencies will be hosting a press event:

  • When: Tuesday, November 5 at 10 a.m. – 11 a.m.

  • What: Press event to discuss community resilience solutions enacted by a coalition of local public power providers

  • Where: Fremont Fire Station #6, 4355 Central Ave, Fremont, CA 94536 — the first fire station in the U.S. with a solar microgrid

  • Agenda: Comments from elected officials (including Fremont Mayor Lily Mei), Board members of the power agencies (including Oakland City Councilmember Dan Kalb, Portola Valley Vice Mayor Jeff Aalfs), CEOs of the power agencies, and Fremont Fire Department.

RSVP to:

Dan Lieberman | Director of Marketing

$10 Million for Emergency Backup Power During PG&E Outages Committed by Peninsula Clean Energy

REDWOOD CITY, CA – October 28, 2019 – The Peninsula Clean Energy Board of Directors voted to commit up to $10 million over three years to fund clean backup power for San Mateo County’s medically vulnerable residents and essential community services during PG&E power shutoffs.

“This investment will help provide the most vulnerable Peninsula Clean Energy customers and facilities with electricity during blackouts,” said Jan Pepper, CEO of Peninsula Clean Energy. “In just two weeks, PG&E has already turned the lights out on portions of San Mateo County three times. The planned outages by PG&E are expected to continue for years. We are acting now to develop emergency power solutions for those customers who are most at risk.

Peninsula Clean Energy purchases the electricity for 290,000 homes, businesses, and community facilities in San Mateo County while PG&E continues to maintain the grid. Nearly 60,000 Peninsula Clean Energy accounts have been affected by PG&E power shutoffs over the last several days. This includes medically vulnerable residents who rely on electricity to power lifesaving devices such as ventilators.

Peninsula Clean Energy will develop programs to support the installation of battery backup systems powered by renewable energy on eligible homes and community facilities with greatest need. These clean power options are expected to increasingly replace backup diesel generators. Diesel generators emit dangerous pollutants and greenhouse gases.

Peninsula Clean Energy’s new emergency power backup programs will begin rolling out next year. Governor Newsom’s recently announced statewide funding for emergency power backup systems is expected to supplement this effort. Peninsula Clean Energy is also collaborating with other Bay Area community choice energy agencies and the Bay Area Air Quality Management District on resiliency programs.

“Peninsula Clean Energy is committed to reducing greenhouse gas emissions throughout San Mateo County,” said Pepper. “We will offer cleaner, economical alternatives to diesel generators to protect medically sensitive customers and our community service providers. These programs are part of fulfilling the organization’s mission.”


About Peninsula Clean Energy

Peninsula Clean Energy is San Mateo County’s official electricity provider. It is a public local community choice energy agency that provides all electric customers in San Mateo County with cleaner electricity at lower rates than those charged by the local incumbent utility. Peninsula Clean Energy saves customers an estimated $18 million a year. Peninsula Clean Energy, formed in March 2016, is a joint powers authority made up of the County of San Mateo and all 20 cities and towns in the County. The agency serves approximately 290,000 accounts.

Peninsula Clean Energy Contact

Kirsten Andrews-Schwind

Peninsula Clean Energy

M: 650.260.0096

To fight climate change, California needs to plug into offshore wind

We all saw Greta Thunberg’s eyes. We saw her face. We heard her voice quivering as she urged the members of the United Nations last week to do more to fight back against the ravages of climate change.

“You have stolen my dreams and my childhood with your empty words,” the teenage Swedish activist said. “People are suffering. People are dying. Entire ecosystems are collapsing…How dare you pretend that this can be solved with just ‘business as usual’ and some technical solutions?”

As global temperatures rise, bringing with it the fury of a generation that will have to live with the consequences, we know we need to do more—we must do more—to fight this existential crisis.

Even in California, where we have already set some of the world’s most aggressive climate goals, our 100% carbon-free targets and plans for millions of electric vehicles are only part of what’s necessary to reckon with the social and moral issues we face.

If California is going to do everything it can to fight back against climate change—and serve as a model for the rest of the world—that means tapping all of the resources at our disposal.

To slow the spread of forest fires, drought, and rising sea levels, we need to accelerate every one of our clean energy strategies.

We need to tap the lithium ion in the Salton Sea and use it to power tens of millions more electric cars. We need to develop more battery storage so we can harness the sun’s power day and night—and electrify our buildings and transportation networks.

We also need to expand our horizons and find a way to harness the wind off our coast to power an electric grid that will rely more than ever on clean, renewable energy.

California already gets more than a third of its power from our state’s vast quantities of sun, wind, and geothermal energy resources. But we have even more clean energy waiting for us 25 miles off the coast. We need to go and get it.

This is the opportunity—and the challenge—bringing an international group of energy experts to San Francisco this week for a conference on how to tap the huge amounts of wind energy blowing across the Pacific Rim.

It’s also the impetus for a California Energy Commission meeting on Thursday, where state agencies will consider policies to support floating offshore wind technology.

There’s a lot to like about offshore wind—and even better, there is a lot of it.

According to the Bureau of Ocean Energy Management, a fleet of wind turbines floating (mostly out of sight) roughly 25 miles off our coastline could produce 16 gigawatts of energy—about a third of the 40-plus gigawatts used statewide during peak periods.

In addition to being 100% carbon-free, these facilities could provide energy when we need it most: Coastal winds pick up right when the sun goes down and air conditioners are firing up.

Paired with storage and other renewable sources, offshore wind is one of our best options for replacing fossil fuel peaker plants used today to keep the lights on. This means less air pollution, less oil extraction, and fewer neighborhoods suffering from dirty power facilities.

Like any new technology, there are complex issues to resolve to ensure the price is competitive, and its presence well off our shores protects the environment and our precious sea life.

But we’ve done this before in California. And we can’t let business as usual stop us from doing it again. If we want to be able to look our children and grandchildren in their faces and tell them we did everything we could, we must act now—because our most precious resource is not renewable. It is time, and we are running out of it.


Dan Jacobson is state director of Environment California, He wrote this commentary for CalMatters.


To fight climate change, California needs to plug into offshore wind, by Dan Jacobson, CalMatters, October 2, 2019.

CPX Job Announcement: Stockton/San Joaquin County Community Outreach Specialist

The Climate Center seeks a qualified individual interested in serving as a part-time “Community Outreach Specialist” to advance Community Choice Energy in the City of Stockton as part of its statewide Clean Power Exchange (CPX) program.

 The program goal is to establish a Community Choice Energy agency (CCA) to serve Stockton business and residential customers. The CPX program marries two critical issues, climate protection and social justice, and emphasizes information sharing via the CPX website. More program information can be found at:

Key activities within this position include:

  • Representing the Center and the CPX program to local elected officials and government staff 
  • Note your association with the Center/CPX on matters related to CCA 
  • Attend city council meetings and make presentations, as appropriate 
  • Write articles/blogs on a regular basis on topics related to CCA and recruit other community members to do the same 
  • Use social media to build support for Community Choice Energy 
  • Provide updates to Center staff at least weekly about relevant developments including news articles, Stockton city council agendas and/or minutes, business communications, etc. 

For the full job description and information on how to apply, please click here.

CPX Regulatory Update for October 3, 2019

Regulatory updates for October 3, 2019

Below is a numbered list of the regulatory proceedings we are tracking, followed by a summary of new developments for each of the proceedings, if any. Note that these are intended as very brief highlights of selected key actions and activities. For details on any of these proceedings, we suggest logging in to the relevant proceeding page on the CPUC’s website. An expedient way to do that is to click on the proceeding number below or visit

Brief Notes:

  • The next CPUC voting meeting is on schedule for October 10 at CPUC headquarters. See AGENDA. For the livestream, click HERE.
  • We are continuing to monitor wildfire related proceedings but will no longer be reporting on a regular basis. We will report occasionally on any significant developments.
  • We will be monitoring the OIR for SB 1339 relating to microgrids, item 11 below.

Regulatory Proceedings we are monitoring:

  1. PG&E Safety Culture Investigation 15-08-019
  2. Power Charge Indifference Adjustment (PCIA)  17-06-026
  3. Resource Adequacy (RA) 17-09-020
  4. SB 790 IOU Code of Conduct 12-02-009
  5. Integrated Resource Plans (IRP) 16-02-007
  6. Distribution Resource Plans (DRP) 14-08-013 
  7. Renewables Portfolio Standard (RPS) 18-07-003
  8. Integrated Distributed Energy Resources 4-10-003
  9. Direct Access 19-03-009
  10. NEM Successor Tariff 14-07-002
  11. SB 1339 Microgrid Rulemaking R.19-09-009

Closed proceedings that matter:

Other CPUC activities with no docket number:

~ ~ ~


  1. PG&E Safety Culture Investigation 15-08-019

New and recent developments:

  • On July 19, the Center, along with adviser Lorenzo Kristov, PhD, filed Comments pursuant to the June 18 Order seeking proposals to improve PG&E safety culture
  • Interim Decision ordering reporting of PG&E Directors’ safety qualifications by August 1 and establishing CPUC advisory panel on corporate governance.

Major Issues:

  • PG&E’s ability to maintain a safe transmission and distribution system

Key Documents:

  • Order extending statutory deadline to May 8, 2020

Background: In this case, Center for Climate Protection is a Party to the Proceeding. Read our Opening Comments HERE. The investigation originated after the San Bruno incident, and has been reinvigorated due to the 2017/18 wildfires.


  1. Power Charge Indifference Adjustment (PCIA) (Proceeding #17-06-026)

New and recent developments:

  • Sept 6 – Proposed Decision – Decision refining the method to develop and true up market price benchmarks; may be heard Oct. 10
  • Sept 3 – Administrative Law Judge’s Ruling denying in part the Motion of the Protect Our Communities Foundation for Evidentiary Hearings and modifying the proceeding schedule
  • August 1 – Proposed Decision modifying the PCIA Methodology. The deadline for comments on the APD is September 6, 2018 at 5 p.m. The deadline for consolidated reply comments on the PD and the APD is September 11, 2018 at 5 p.m.

Key Documents:

Next Steps: TBD

Background: The PCIA is a fee charged to CCAs to pay for a utility’s stranded cost of procuring electricity on behalf of customers departing in CCAs.


  1. Resource Adequacy (17-09-020)

New and recent developments:

  • 6 – Proposed Decision – This decision clarifies the requirements governing the use of energy imported into California to meet Resource Adequacy requirements, as set forth in Decision (D.) 04-10-035 and D.05-10-042.
  • On August 30, CalCCA announced a joint settlement agreement among multiple stakeholders.
  • CalCCA 8/8/19 Notice of Settlement Conference
  • 8/2/19 Comments of CalCCA on the informal workshop reports
  • Assigned Commissioner’s Ruling on July 3 seeking comment on clarification to resource adequacy import rules. Responses to questions were due by July 19, 2019. Reply comments were due by July 26, 2019.

Key Documents:

  • Track 1 Decision D.18-06-030 Adopting Local Capacity Obligations and Refinements to the RA program
  • 18-06-031 adopting flexible capacity obligations for 2019
  • Email ruling on Energy Division Effective Load Carrying Capacity Proposal
  • Proposed Decision endorsing IOUs as Central Buyer for local RA
  • Ruling on Effective Load Carrying Capacity Proposal
  • Comments on the Proposed Decision

Major Issues: CCA participation in the year-ahead RA showing, Cost allocation due to load migration, Reducing backstop procurement, Consolidating procurement using a central buyer, Updates to Effective Load Carrying Capacity modeling methods, Aligning the Commission’s RA measurement hours with CAISO’s.

Background: The RA program is designed to provide adequate electric resources to CAISO to ensure safe and reliable operation of the grid, and to provide appropriate incentives for the siting and construction of new resources needed for reliability. This proceeding has been divided into three Tracks due to the complexity of the issues involved.


  1. SB 790 IOU Code of Conduct (12-02-009) – No new developments.

Background: Original CCA law, AB 117 stipulates that IOUs must “cooperate fully” with local governments pursuing Community Choice. In the mid-to-late 2000s, San Francisco, Marin, and the San Joaquin Valley experienced egregious disinformation campaigns waged by the incumbent utility for these jurisdictions against their efforts. The obstruction was documented in a series of California Senate Select Committee on Renewable Energy hearings in 2010 chaired by Senator Mark Leno. The result of the hearings was SB 790, which created an IOU Code of Conduct that prohibits IOUs from marketing against CCAs unless they establish a separate marketing division that does not use ratepayer funds, among other provisions.


  1. Integrated Resource Planning (16-02-007)

New and recent developments:

  • 12 – Proposed Decision – In this Decision, the Commission takes a number of steps to address the potential for electricity system resource adequacy shortages beginning in 2021. The Decision includes CCAs in SCE service territory.
  • Comments on procurement track and reliability issues by CalCCA, TURN, PG&E
  • CalCCA Motion for amended ruling seeking the staff analysis identifying the “potential for near-term reliability challenges” cited in the Ruling.
  • Final Decision adopting the Reference System Plan as the Preferred System Plan.

Key Documents:

  • Order Instituting Rulemaking
  • Decision D.18-02-018 setting IRP requirements for LSEs
  • Amended Scoping Memo

Major Issues:

  • Near, medium, and long-term local reliability needs
  • Approval of a Preferred System Plan
  • How to coordinate LSE procurement to meet CA GHG goals

Next Steps:

  • Late 2019 – Proposed Decision on Procurement Track

Background: On April 25 the CPUC unanimously approved a Proposed Decision that approves or certifies 20 individual LSE IRPs. A video of the proceeding is HERE. Item 51 on the agenda. The CPUC’s action represents a major vote of confidence in the critical role CCAs are playing in California’s rapidly evolving energy system.


  1. Distribution Resource Plans (14-08-013 ) – No new updates.

August 9 – Ruling postponing capacity analysis workshop.

Background: This proceeding consolidates numerous previous proceedings and seeks to establish policies and rules for IOUs to develop Distribution Resources Plan Proposals, and to evaluate the IOUs’ infrastructure and planning to incorporate distributed energy resources (DERs) into their systems. There are three parallel and concurrent Tracks in this proceeding. Track 1 concerns methodological issues. Track 2 concerns demonstration and pilot projects. Track 3 concerns policy issues.  Decisions have been issued on all three tracks, but there are still residual issues and new issues being addressed.


  1. Renewable Portfolio Standard (18-07-003)

New or Recent Developments:

  • August 23 – Decision re IOU Effective Load Carrying Capability. Behind-the-meter Photovoltaic (PV) must be treated as a supply-side resource; annual loss of load expectation study must be conducted.
  • August 8 – Proposed Decision relaxing 2018 RPS Plan reporting for 6 new CCAs. Comment by CalCCA.
  • August 1 – Decision enforcing RPS program rules, fining Liberty Power $431,014 and Gexa $1,725,461.
  • Joint Utility comments and Joint CCA reply comments on combining IRP and RPS programs.

Major Issues:

  • Revising RPS renewable market adjusting tariff (ReMAT) and bioenergy market adjusting tariff (BioMAT).
  • Least-cost/best-fit methodology for RPS procurement
  • Cost containment for IOU RPS procurement and coordination with the IRP proceeding
  • Monitoring and review of LSE compliance.

Key Documents:

  • 12-06-038 setting RPS compliance rules.
  • OIR to further develop the RPS program.
  • 2018 RPS Annual Report to Legislature.
  • Amended Scoping Memo.
  • Proposed Decision adopting 2018 RPS procurement plans.
  • Comments on Proposed Decision by CCA Parties.

Next Steps:

  • Fourth Quarter 2019 – Decision on RPS plans
  • May 1, 2020 – Tentative consolidation of IRP/RPS filings.

Background: The RPS program implements SB 350 and SB 100 by requiring all LSEs to increase their procurement of renewable energy to 44% by 2024, 52% by 2027, 60% by 2030, and 100% by 2045.


  1. Integrated DER – No new developments.

Most recent development: ALJ Ruling directing responses to post-March 4-5, 2019 Workshop questions.

Background: Since 2007, the Commission has sought to integrate demand side energy solutions and technologies through utility program offerings. Decision (D.07-10-032) directs that utilities “integrate customer demand-side programs, such as energy efficiency, self-generation, advanced metering, and demand response, in a coherent and efficient manner.” The Commission’s IDER Action Plan published in 2016 remains in draft form.


  1. Direct Access Rulemaking (19-03-009) – No new developments.

On March 14, 2019 CPUC issued an Order Instituting Rulemaking (OIR) for proceeding R. 19-03-009 regarding implementation of Senate Bill 237 (SB 237 – Hertzberg) concerning expansion of the Direct Access (DA) program. DA is available to non-residential customers. Background: DA access was restricted after the energy crisis by SB 1X. DA access is currently capped and accessible via a lottery system, with 7,603 GWh of load on the waitlist. SB 237 increases the maximum total annual kilowatt-hours allowed under the DA program by a total of 4,000 GWh apportioned among the three IOU service territories. That increase must be implemented by June 1, 2019. SB 237 also gives CPUC until June 1, 2020 to provide the legislature with guidance on expanding DA access to all interested non-residential customers. The proceeding will have two phases to address the two mandates.


  1. NEM Successor Tariff Rulemaking R.14-07-002

Pursuant to direction in the NEM Successor Tariff Decision, the Commission will review the NEM successor tariff some time in 2019, when the proceedings related to distributed energy resources are completed and after default TOU rates are implemented. Energy Division staff will explore compensation structures for customer-sited distributed generation other than NEM, as well as consider an export compensation rate that takes into account locational and time-differentiated values. On April 26, 2019, the Energy Division distributed a Revised Solar Information Packet to service list R.14-07-002 and R.12-11-005.  The Energy Division asked for written comments about the content of the Revised Solar Information Packet and implementation approach.  The deadlines for submitting written comments has passed. If you have questions contact Kerry Fleisher at the CPUC Energy Division:

11. Microgrids – R.19-09-009

New Developments:

Major Issues:

  • Role of CCAs in microgrid development
  • Microgrid operation, value, and technical challenges.
  • Microgrid regulation and service standards.
  • How microgrids can improve the grid and further policy goals.

Key Documents:

Next Steps:

  • October 19, 2019 – Comments on the OIR.
  • November 3, 2019 – Reply comments on the OIR


Closed proceedings that matter: 

  • CCA Rulemaking03-10-003 This was the original rulemaking that occurred between 2003 and 2005 to cross the Ts and dot the Is on CCA law. Rulemaking R.03-10-003 was initiated in October 2003 to implement portions of AB 117 concerning Community Choice Aggregation. That Rulemaking is closed. One result of the proceeding was Decision 18-05-022 issued on May 31, 2018 which established reentry fees and financial security requirements applicable to CCAs as required by Public Utilities Code Section 394.25(e). The IOUs were ordered to provide a Tier 1 Advice Letter detailing their costs and to identify that in their general rate cases. CCA parties assert that the Advice Letters submitted by the utilities are overly broad and exceed the scope permitted in D.18-05-022 because they would impose liability on returning CCA customers over and above the CCA Bond amount, permit the utility to dictate whether financial instruments and arrangements were satisfactory, and require that particular agreements drafted by the utility be used to satisfy a financial security amount.


Other CCA-relevant CPUC activities with no docket number:

Customer Choice Project. No update. This is an informal activity in progress that relates directly to CCAs, the California Customer Choice Project (formerly known as the “Green Book”). The Center submitted Comments on this matter in June 2018.

AB 2514 Energy Storage Mandate. All LSEs in California are required to procure certain levels of storage under the Energy Storage Mandate in AB 2514. The CPUC oversees the implementation. Recent news is that due to CCA customers paying for IOU procurement of storage via nonbypassable charges, the obligation for CCAs to meet the mandate has been dismissed.

PG&E Bankruptcy (no docket #) (PG&E Fires Restructuring, Bankruptcy Court, CA Senate Oversight Hearings, US District Court) In addition to the above proceedings, we are also keeping a close eye on the PG&E bankruptcy, which is playing out in four arenas: the bankruptcy court, the CPUC, the CA State legislature, and the Federal Energy Regulatory Commission (FERC).

Recent Developments

  • Judge lifts the stay and RULES that litigation revolving around the 2017 Tubbs Wildfire can proceed
  • Fast-tracked legislation (AB 1054) enacted on July 11, 2019 creates $21M fund for future fires, partly at ratepayer expense
  • Settlement agreement with 18 public agencies
  • Bondholder’s $30 billion plan, $16 – $18 million for victims
  • Newsom’s $21 billion plan, renews $2.50 monthly DWR charge for 15 years
  • Ruling denying FERC jurisdiction over PPA agreements

Major Issues:

  • Chapter 11 removes restructuring authority to the Federal Bankruptcy Court.
  • PG&E’s ability to recover wildfire litigation and liability costs via rate increases.
  • The scope and role of PG&E when it emerges from bankruptcy restructuring.
  • Future role of CCAs, distributed energy resources, and distribution utility.

Key Documents:

  • Cal Fire report finding PG&E equipment involved in 12 fires during October, 2017.
  • Ruling and Scoping Memo regarding phase 2 15-08-019 Investigation Into PG&E’s Safety Culture
  • Fire Safety and Utility Infrastructure En Banc

Next Steps:

  • Sept 28 – Deadline for PG&E to propose reorganization plan


Our next CPX Regulatory Update will be published on Thursday, October 17.

Solar, and solar plus storage records *possibly/probably* set in California

Community Choice Aggregator (CCA) East Bay Community Energy (EBCE) has announced two power purchase agreements (PPA) with an average price of 2.2¢/kWh. The individual project pricing, total solar modules onsite, and expected volumes of electricity delivered on an annual basis were blacked out in the draft PPAs available to the public (236 page pdf). But we were able to get the following information on the two contracts/projects:

  • sPower Solar + Storage Project: 20-year agreement for 125 MW of solar power and 80 MW/160 MWh of battery storage in southern California, developed by Salt Lake City-based sPower
  • Edwards Solar Project: 15-year agreement for 100 MW of solar power and virtual storage in Kern County, developed by San Diego-based Terra-Gen

The project was announced by EBCE CEO Nick Chaset on Twitter:

STOP THE PRESSES – @PoweredbyEBCE has formally concluded its first major renewable energy procurement and we are pleased to announce that we have contracted for over 500 MWs of California solar at the astoundingly low average price of $22/MWh.

While the exact pricing on either of the two projects was withheld, it is probable both of these projects have set pricing records for the United States – but we must also add caveats to solar plus storage projects now that we’re seeing a greater variety of large scale projects.

In the linked to Google spreadsheet the equations can be seen that developed the below image, which suggest that the blended rate of the two projects is still greater than the current record holder 8minute Solar Energy, and Jackpot Solar’s Idaho project. However, if we consider again that the two projects “average” 2.2¢/kWh ($22/MWh) – then we ought assume that the solar only project is priced higher than the solar+storage project. And, if we lower the price of the Edwards Solar project to 2.097¢/kWh, then accounting for the escalator and discount rates, we see that it would beat out 8minute’s record – and that the average between the two projects would allow for the sPower solar+storage project to also be lower priced than 8minute’s recently signed Eland project.

Again though, these are speculative values by this pv magazine USA author, as EBCE noted the individual project data was withheld, and it was blacked out in the above draft PPAs.

As well – and this one is important – when considering the “value” of the energy storage project as compared to others, the total amount of energy storage involve in the project is very important to how much energy storage would be included. The sPower project contains 80 MW / 160 MWh – much smaller than the 300 MW / 1,200 MWh volume included in the above linked to Eland project. So while, we *possibly/probably* would see a lower sticker price, it’s a different type of project that is being delivered. And this is something we will have to consider as we write our pretty headlines going out into the future.

EBCE also released a summary of all new long-term agreements signed in 2019:

The Edwards Solar project is expected to reach financial close in June of 2022, with construction to begin by August of the same year, and to reach commercial operation by the end of 2022. Meaning the company believes they can deploy 100 MWac / of solar power in six months. sPower projects that construction will start by the last day of 2021, with the commercial operation date to be by the last day of 2022, and “full capacity deliverability status” by March 31, 2023.

The Edwards facility will be located on Edwards Air Force Base, will connect through Southern California Edison power lines via the Windhub 230 kV p-node. Terra-Gen has engaged D.H. Blattner & Sons to build the project, using the teams of the Operating Engineers Local 12, Southwest Regional Council of Carpenters, Southern California District Council of Laborers and its affiliated Laborers Local 220, IBEW Local 428, and Ironworkers Locals 416 and 433 on April 8, 2018. sPower noted in their contract that while they hadn’t yet signed the agreement for construction, it will use union labor.


Solar, and solar plus storage records *possibly/probably* set in California, by John Weaver, PV Magazine, September 30, 2019.

Unlocking Northern California’s Offshore Wind Bounty

Wind speeds off the coast of Humboldt County in Northern California are some of the strongest in the U.S. The region’s steady gusts are so powerful, in fact, that the area was one of three potential offshore wind energy development zones in California included by the federal Bureau of Ocean Energy Management in a public pitch to developers last year.

With around 140,000 residents, Humboldt County lacks one thing offshore wind developers like to see: a big demand for power. But the San Francisco Bay Area is a five-hour drive south along Highway 101.

If the wind energy zone off the shore of Humboldt County is fully developed, much of the estimated 2,100 megawatts of generating capacity would end up heading south to serve the 8 million residents of the nine-county San Francisco Bay Area. The question is how to get it there.

The existing transmission infrastructure in Humboldt County wasn’t built to export power. An undersea transmission tracking the coastline could very well be the answer.

The entity tasked with providing guidance on transmission and interconnection, as well as other critical issues such as port infrastructure, environmental concerns and economic impacts, is the Schatz Energy Research Center at Humboldt State University. Researchers at the center are conducting three studies to assess offshore wind feasibility in Humboldt Bay. Results are scheduled to be released beginning in March 2020.

Asked in an interview about the region’s limited transmission capacity, Schatz Center director Arne Jacobson said, “Saying that we are somewhat constrained is very generous. I would say we’re connected to the rest of the electrical grid by a capillary.”

Anything beyond a small pilot-scale deployment, he added, “would require some sort of upgrade to the transmission infrastructure or for a fairly significant amount of local storage.”

Piercing the “Redwood Curtain”

Part of what makes Humboldt County so appealing for residents and visitors — the region’s rugged natural beauty — makes overland electricity transmission difficult.

Bisecting the coastal plain — where the cities of Eureka and Arcata sit — and the Central Valley in the interior, are a series of north-south running, densely forested peaks of the Northern Coast Ranges. Any potential upgrades to the existing transmission network must contend with this “Redwood Curtain.”

The Schatz Center is studying three scenarios of offshore wind farm deployment: 50-megawatt pilot-scale, 150 megawatts and 2,100 megawatts, which is estimated to be the full build-out of Bureau of Ocean Energy Management’s (BOEM) designated 536 km2 “call area” in Humboldt Bay.

In September 2018, Humboldt County’s community-choice aggregator, the Redwood Coast Energy Authority, submitted an unsolicited lease application to BOEM for a 100- to 150-megawatt floating offshore wind farm to be sited in waters more than 20 miles off the coast of Eureka. RCEA’s partners include a consortium of private companies: Principle Power, EDPR Offshore North America and Aker Solutions.

In June, BOEM said it anticipates conducting a California offshore wind lease sale in 2020.

In any scenario beyond a pilot-scale project, the limited transmission capacity in what grid operators call the Humboldt pocket becomes a problem.

The primary grid link serving Eureka is a 115-kilovolt line running east-to-west along Highway 36, designed to carry around 70 megawatts of electricity. “The 115 kV line can move a certain amount of energy, but it’s rather limited,” Jacobson said.

“It wasn’t really designed to necessarily export large volumes of energy,” Jon Stallman, strategic projects manager in the grid innovation and integration unit of Pacific Gas and Electric, said at an energy planning workshop in Arcata conducted by the California Energy Commission in April 2018.

An even more constrained 60 kV transmission line runs along Highway 101 in southern Humboldt County toward the Central Valley.

“To change that system to make it larger is going to be a fairly costly event,” said Stallman.

The average load in Humboldt County is around 110 megawatts, and peak load is between 150 and 170 megawatts. So, even if wind energy development in the area was limited to the project proposed by the Redwood Coast Energy Authority — up to 150 megawatts — exporting at least some power would be necessary.

And a full build-out of Humboldt County’s 2,100-megawatt offshore wind potential would require a significant investment in transmission infrastructure.

The 115 kV line that serves Eureka connects with the larger California grid at a substation in Cottonwood, where it links to the 500 kV, north-south California-Oregon Intertie. If Humboldt Bay offshore wind farms are to export over land, PG&E’s Stallman said grid operators will have to determine if that California-Oregon transmission backbone can carry the additional load.

“We’ve got to take a look at the contracted bandwidth and figure out how we’re going to make room,” said Stallman.

Undersea cable for gigawatt-scale deployment?

No developer has yet proposed building a subsea transmission cable from a substation offshore Humboldt County to the San Francisco region, Jacobson said.

Even so, the Schatz Center is looking into the costs, as well as the technical and environmental challenges. A team in the Seattle office of the coastal engineering firm Mott MacDonald is handling the conceptual design of the undersea cable, while PG&E is tasked with estimating the transmission cost upgrades.

“The challenges would be many, but the challenges are also many with the overland routes,” Jacobson noted.

What is clear is that any offshore wind project in the region larger than pilot-scale — and certainly at full build-out — is contingent on transmission expansion.

“If you were just trying to scale it to the local load, I don’t think you would make it as large as 150 megawatts,” said Jacobson.

“On the other hand,” he went on, “from a profitability perspective, or a cost-viability perspective for investors, I don’t know that it’s that interesting to just build something for this region without leaving a pathway for scaling to something larger.”

“My sense is, and what we’ve heard from developers, is that they’re very happy to do something at [150 megawatts] as a next step in their process, but, ultimately, to become profitable, they need something at a larger scale.”

Unlike the Central Coast, California’s other promising offshore wind energy zone, Humboldt County does not face conflicts with active military uses.

“The major constraint we have that’s different from other parts of the state is the transmission one,” said Jacobson. “If there’s not a solution to the transmission issue, there really wouldn’t be a pathway forward at scale here.”


Unlocking Northern California’s Offshore Wind Bounty, by Justin Gerdes, Greentech Media, September 30, 2019.

Valley Clean Energy holds ‘solar’ workshops

Valley Clean Energy will host two public workshops in October to review upcoming enrollments for PG&E customers who have solar panels.

The workshops, which are designed to review VCE’s solar policies and answer customers’ questions, are set for 5:30 p.m. Wednesday, in the Community Chambers at Davis City Hall, 23 Russell Blvd. in Davis, and again at 5:30 p.m., Monday, Oct. 14, in the Council Chambers at Woodland City Hall, 300 First St. in Woodland.

Residents of Valley Clean Energy’s service area who had solar panels installed on their roofs or property prior to VCE’s launch in June 2018 have continued as PG&E Net Energy Metered customers. That’s about to change, as VCE begins enrolling these customers starting in January 2020.

VCE’s service area includes the cities of Woodland and Davis as well as the unincorporated area of Yolo County.

At its June meeting, the VCE board of directors voted to begin transitioning existing PG&E metered customers to VCE beginning in January. As a public power supplier operating under state rules for community choice aggregation, VCE follows the regulations regarding the automatic enrollment of customers. These NEM customers will automatically be enrolled in VCE service during their true-up month in 2020.

Enrolling on their “true-up date” allows customers to optimize the use of their energy credits at full retail value, said Mitch Sears, VCE’s interim general manager.

Metered customers will receive notices prior to enrolling with VCE, alerting them to the change. Two notices will be mailed — one during each of the two months prior to the customer’s enrollment date.

Customers who would like to enroll in VCE service prior to their annual true-up date may do so beginning in February 2020. But they should be aware of possible consequences, Sears says.

“It’s important that you know that PG&E will true-up your account prior to your enrollment in VCE, which means that any credits you have will be paid by PG&E at the wholesale level (slightly less than VCE’s rate) and your true-up date will be reset to coincide with the start of your VCE service,” Sears said.

“Before deciding to voluntarily opt into VCE service before your 2020 true-up month, be sure to review your PG&E bill to ensure that you won’t lose credits.”

Valley Clean Energy is a not-for-profit public agency formed to provide electrical generation service to customers in Woodland, Davis, and the unincorporated areas of Yolo County. Its mission is to source cost-competitive clean electricity while providing product choice, price stability, energy efficiency, greenhouse gas emission reductions and reinvestment in the communities we serve.


Valley Clean Energy holds ‘solar’ workshops,  by Woodland Daily Democrat Staff, Woodland Daily Democrat, September 28, 2019.

CalCom Energy’s $100M Fund Targets Farms for Solar-Battery Systems

In California, it’s not just vulnerable families and critical services that could use battery-backed solar systems to ride through wildfire-prevention power outages. Farms also have critical energy needs, like pumping water to crops on set schedules, or chilling them after harvest, that could face significant disruption under the state’s new wildfire prevention regime.

CalCom Energy, a long-time solar and energy services provider for California’s agricultural sector, thinks it has a solution. This week, the Fresno-based developer launched a $100 million Agriculture Energy Infrastructure Fund, aimed at combining low-cost solar power-purchase agreements with the backup power of energy storage.

The fund, developed in partnership with Symbiont Energy and Live Oak Bank, marks CalCom’s first foray into owning the systems it develops, David Williams, CalCom’s chief commercial officer, noted in Wednesday’s press release. But it’s far from CalCom’s first foray into solving the farm-specific energy challenges facing its customers in the state’s Central Valley.

Since its 2012 founding as CalCom Solar, the Fresno, Calif.-based company has developed more than 200 megawatts of clean energy projects, largely solar projects for farms and water districts. In fact, it’s one of the largest commercial solar developers in the territory of Pacific Gas & Electric, the Northern California utility now in bankruptcy reorganization under the weight of tens of billions of dollars in liabilities from deadly wildfires started by its power lines in 2017 and 2018.

Like many California solar developers, energy storage is playing an ever-increasing role in CalCom’s projects, leading it to rebrand as CalCom Energy last year. Changes to California’s net metering regime, including time-of-use (TOU) rates that reduce the value of midday energy and increase its cost in late afternoon and evening hours, have an outsize effect on commercial solar projects like CalCom’s that rely on meter aggregation for valuing their production.

CalCom also provides metering and billing analysis through its Energy Services management platform, to allow its customers to better manage how they consume electricity in relation to their solar-generated and battery-stored resources. For example, big Salinas Valley grower and shipper D’Arrigo Bros. of California, which has installed about 5.5 megawatts of solar PV through CalCom, has also added two 520-kilowatt batteries at its central cooling facility, to reduce demand charges, shift energy to different TOU periods, and provide backup power to critical loads.

But batteries have become even more critical under the much-expanded wildfire prevention “public safety power shutoff” regimes put in place by PG&E and other California utilities under state regulatory mandate this year. Agricultural customers are huge electricity users, largely to move water — pumping and treating water uses roughly one-sixth of the state’s electricity supply.

In fact, water treatment plants and other water infrastructure are among the classes of “critical services” that have been earmarked for special treatment under the California Public Utilities Commission’s latest revisions to the Self-Generation Incentive Program, which also included $100 million in incentives for disadvantaged or medically vulnerable customers who live in high-fire-threat parts of the state.

But farmers are also dependent on steady and reliable electricity to meet water-pumping schedules that are often fixed by law, or by the needs of its crops and the growing season. Solar-plus-storage projects that promise to reduce overall electric bills, as well as provide backup power, are becoming a far more attractive option than installing expensive and polluting backup generators to insure against a crop-ruining power outage.


 CalCom Energy’s $100M Fund Targets Farms for Solar-Battery Systems, by Jeff St. John, Greentech Media, September 26, 2019.