Lawsuit filed to stop California’s new wildfire liability law

Just one week after Gov. Gavin Newsom signed into law a sweeping piece of legislation designed to change the way California’s utilities pay for damages resulting from wildfires ignited by their own equipment, a lawsuit was filed in federal court Friday looking to stop it in its tracks.

San Diego attorneys Michael Aguirre and Maria Severson filed the complaint on behalf of Northern California resident Gene Nelson, arguing Assembly Bill 1054 should be declared invalid on multiple grounds, including that its provisions violate the U.S..and California’s constitutions.

More specifically, the lawsuit characterizes AB 1054 as a “bailout” of the state’s big three investor-owned utilities that “as a practical matter, it is now nearly impossible for utility customers to prevent (a utility) from passing uninsured wildfire liabilities onto them.” The complaint asks the U.S. District Court in Northern California to issue an injunction to keep the state from implementing the new law.

The suit names the heads of a host of California agencies and the five voting members of the California Public Utilities Commission as defendants.

Read more

California’s new Public Utilities Commission president must lead us to a gas-free future

Everywhere you turn in California, clean energy technologies are winning out over gas.

From Oxnard to Los Angeles and Glendale, to the Inland Empire and Bay Area, proposed and existing gas-fired plants are being scrapped in favor of cleaner options.

Clean energy is winning because it’s a safer and more affordable option.

This is critical for the communities who have been forced to live with gas plants in their backyard—often low-income communities of color who have disproportionately shouldered the pollution burdens of our state’s dependence on fossil fuels. For them, the shift to cleaner energy sources comes not a moment too soon.

As solar and wind costs plunge, energy storage technology such as batteries and large scale, pumped water, compressed air, and thermal energy storage are proving they can cost-effectively reduce our reliance on gas to meet local capacity and reliability needs.

Battery storage projects are now slated to replace gas-fired plants in Moorpark, Oakland and San Jose, to provide reliable energy when the sun is down and the wind isn’t blowing.

But getting to 100% clean and affordable energy is about more than closing gas plants.

It’s about enabling an entire suite of clean resources, from distributed generation, to local solar power that recharges energy storage systems, to demand response, time-of-use rates, and targeted energy efficiency to work together to balance the energy grid.

This is the hard work facing Marybel Batjer, Gov. Gavin Newsom’s newly appointed president of the California Public Utilities Commission.

Bringing these zero-emission resources on to the grid requires innovation, new ways of thinking and a strong dose of political will.

The Public Utilities Commission has shown a commitment to prioritizing communities bearing the highest pollution and socioeconomic burdens in the state.

In the California Environmental Justice Alliance’s annual agency scorecard assessing how California regulators have honored the principles of environmental justice in 2018, the Public Utilities Commission scored a B+.

Now, we must ensure that these communities gain access to the clean energy technologies they have been promised.

This is where we need visionary leadership from Batjer, because when we scratch beneath the surface, we find the Public Utilities Commission is in danger of moving in the opposite direction.

The commission must redesign its processes to allow clean energy technology to compete with gas, by being bundled together and strategically dispatched, so that they can provide the same services under the same contract terms as gas plants.

They must reform and update accounting rules to enable cost effective, zero carbon resources to compete to provide grid reliability services. The technology is available and cost effective, but is left out because of outdated requirements.

Instead, the commission is preparing to award multi-year contracts to gas plants and is failing to prepare and expand California’s portfolio of clean resources to meet our “resource adequacy” requirement.

Despite the direction of the Legislature to adopt a plan to acquire new large-scale storage projects, the Public Utilities Commission has stalled. Even more alarming, the commission is allowing Southern California Gas Company to pull more gas from the dangerous Aliso Canyon storage facility, instead of looking for strategies to honor Gov. Newsom’s promise to close the facility that poisoned thousands of people.

This business-as-usual thinking is a luxury we simply do not have.

We’re encouraged by Gov. Newsom’s appointment of Marybel Batjer. By appointing a leader who is not afraid of blazing new trails, Gov. Newsom is exhibiting his own bold leadership. As Batjer takes the reins, we look forward to seeing her exercise her expertise to seize the incredible opportunity before her.

Under her watch, the agency must prepare California to move beyond gas. Achieving that goal will require much greater integration within the agency, and dedicated coordination with other agencies and power providers.

Creating an equitable, safe and secure phase-out of gas in coming decades will be no small feat. That transition must be undertaken with a commitment to protecting working families, improving energy affordability, and avoiding saddling Californians with increasingly expensive gas energy.

Ms. Batjer has demonstrated she is not afraid of taking courageous action and shaking things up. This is exactly what the Public Utilities Commission needs.

The Public Utilities Commission’s power to help California’s communities thrive is undeniable. With Batjer exhibiting people-centered leadership that combines technical expertise and innovation, she can play a major role in leading California into a healthy and prosperous 100 percent clean energy future.

Gladys Limón is executive director of the California Environmental Justice Alliance, glimon@caleja.org. V. John White is the executive director of the Center for Energy Efficient and Renewable Technologies, vjw@ceert.org. They wrote this commentary for CalMatters.

 

California’s new Public Utilities Commission president must lead us to a gas-free future, by Gladys Limón and V. John White, Cal Matters, July 18, 2019.

How batteries can reduce CCAs GHG emissions

In our previous TerraBlog post, How CCAs can model and deploy DERs, we shared the process and results for modeling battery storage systems for CCA customers with existing solar systems under the NEM tariff. Part of this process included studying the impact of batteries on greenhouse gas (GHG) emissions of a CCA. In this blog post we will share how we modeled and assessed this impact.

Calculating the GHG emissions can get complicated as the electricity supply mix varies depending on the time of the day, geographical location and the demand on the grid.

One approach to calculating GHG emissions from electricity purchases is to use a constant value associated with electricity purchases from unspecified sources provided by the California Air Resources Board. The constant value, also referred to as the grid GHG content value, represents the emissions associated with power purchases outside a CCA’s contracted emission free sources. For the analysis, we used the GHG content for PG&E territory of 0.435 tCO2/MWh.

Another approach to calculating GHG emissions is to use the proposed Clean Net Short (CNS) method suggested by the California Public Utilities Commission. The CNS method utilizes standard reference tables with multipliers for every hour of a month to account for the grid GHG content. The reference tables provide an estimate of the grid GHG content for any location in the state of California. The CNS method is different from the current method because the tables display data using the 288-hourly format. The 288 hourly format is derived from the product of typical 24-hourly values in any given day for each month of the year. For example, the average grid GHG content on any day at 2pm in the month of January is estimated to be 0.2 tCO2/MWh per the following reference table for the year 2022.

TerraVerde has utilized both methods within the BEO software to compare the emissions impact of batteries for CCAs. It was found that using the current method, the GHG emissions increase after modeling the battery storage systems. Addition of a battery storage system to a building increases the electricity usage of the building due to the round-trip losses in the battery storage systems. A typical battery system has a round-trip efficiency of 86% which means 14% of electricity is lost during a charging and discharging cycle. Thus, when using the current GHG emissions accounting method, there is an increase in GHG emissions as only the annual electricity usage is taken into account. However, when we include the time of electricity usage, using the CNS method, the GHG emissions are reduced as a result of pairing the battery storage systems with existing solar systems. The GHG emissions reductions is achieved as a result of charging the batteries using surplus solar electricity generated during the day when the grid GHG content is low and discharging the batteries in the evening when the grid GHG content is high.

As seen from the results of the BEO software, batteries for CCA customers with existing solar systems can provide both economic and GHG reduction benefits. In our next post we will share the potential impacts of batteries to Resource Adequacy costs for CCAs.

Scroll down to the foot page to sign up for future TerraBlog posts!

 

How batteries can reduce CCAs GHG emissions, by Ashley Hale, TerraVerde, July 18, 2019.

Sunrun Wins Another Capacity Contract for Aggregated Home Storage

A network of residential energy systems will help Oakland, California wean itself off fossil-fueled peakers.

East Bay Community Energy, which buys power for Alameda County in Northern California, approved a contract Wednesday night to pay Sunrun for 500 kilowatts of capacity from residential solar-plus-storage.

The 10-year contract, which goes into effect in 2022, marks a second contracted win for Sunrun’s theory of using aggregated residential energy assets for grid services. The company won its first virtual power plant contract in February to supply ISO New England with 20 megawatts by 2022.

San Francisco-based Sunrun is the leading installer of U.S. residential solar systems.

“This kind of deal is a critical catalyst for this transition to customers as the prosumer, investing in energy to serve their own needs and also to serve the grid,” said EBCE CEO Nick Chaset.

As a community-choice aggregator (CCA), EBCE buys power for county residents with a mission to make the fuel mix cleaner while maintaining affordable prices.

The organization has to meet state obligations for resource adequacy on behalf of its customers, and that’s where the clean energy goal gets tricky: The market’s answer for capacity tends to be gas-burning peaker plants. If EBCE wants to ensure grid reliability and commit to high levels of carbon-free power, it needs to bring something new to the table.

It did just that with the Oakland Clean Energy Initiative, a collaborative effort to replace a jet-fuel-burning peaker in Oakland’s Jack London Square. The group contracted with Vistra last month for a 20-megawatt battery, the largest standalone battery to be built for a CCA.

Whereas the 20-megawatt battery will literally replace the peaker turbines, the Sunrun deal will provide 2 megawatt-hours of energy storage (500 kilowatts with 4-hour duration) scattered throughout the service territory, but with an emphasis on West Oakland.

“The project is not as closely linked to this specific peaker; it’s more broadly adding it to our portfolio of resources that are going to help us avoid general peakers,” Chaset said. “We’re paying you to perform and that performance will help relieve us of the obligation to buy peaker plants.”

As a general rule, residential batteries cost more than utility-scale batteries due to economies of scale. In this case, however, EBCE is not buying any equipment outright; it is contracting for capacity with developers that draw other revenue streams from the assets.

Chaset declined to disclose the price of the decentralized contract, but said “there was no major premium” compared to the larger batteries.

“This was very competitive on a price perspective with the bigger front-of-the-meter batteries that we’re procuring,” Chaset said.

The contract stipulates that Sunrun will pay prevailing wages to install the equipment on low-income single-family and multifamily homes within Alameda County.

Audrey Lee, Sunrun’s vice president for energy services, noted that the community-oriented nature of CCAs makes a natural fit with Sunrun’s “people-powered” grid philosophy. Instead of filling the capacity need entirely with utility assets hooked up to the grid, EBCE elected to meet some of its obligation in a way that gives community members access to more clean power and resilience.

“We hope it’s something we can replicate across California,” Lee said. “The growth of the CCAs in California has been enormous.”

Across the state, 19 CCAs now buy power for more than 4 million customers, according to industry group CalCCA. The traditional investor-owned utilities maintain the poles and wires that deliver that power.

Now that the model contract has been figured out, Chaset said he could see behind-the-meter capacity scaling to multimegawatt levels, and that multiple CCAs could join forces for regional distributed energy programs.

The new capacity revenue will allow Sunrun to add batteries alongside solar, giving the residential buildings access to backup power for critical circuits.

The contract also raises the possibility that Sunrun could enlist some of its thousands of existing solar and storage customers in a similar crowdsourced capacity program. That would be technically possible, Lee said.

“Our BrightBox systems today in California are programmed to do time-of-use load-shifting as well as backup power,” she said. “If they were enrolled with a capacity contract, those batteries can be easily reprogrammed to discharge to provide that capacity.”

At the end of 2018, Sunrun had installed roughly 5,000 BrightBox systems nationally, with California as the dominant market.

The new arrangement builds on Sunrun’s commitment to supply 100 megawatts of solar power to low-income housing, said Lee. In moving toward that goal, announced last fall, Sunrun draws on funds from California’s Solar on Multifamily Affordable Housing program and works with building owners to deliver solar at no cost to tenants.

 

Sunrun Wins Another Capacity Contract for Aggregated Home Storage, by Julian Spector, Greentech Media, July 18, 2019.

California replacing 200 polluting diesel school buses with all-electric buses

The California Energy Commission has awarded nearly $70 million to state schools to replace more than 200 diesel school buses with new, all-electric school buses.

The commission approved the funding this week. A total of $89.8 million has now been earmarked for new electric buses at schools in 26 California counties, as the commission’s School Bus Replacement Program works toward this goal.

A study published in Economics of Education Review last month showed diesel retrofits had positive results on both respiratory health and test scores. Eliminating emissions from these buses completely will do even more to protect children from dangerous emissions while cutting air pollution.

The new buses will eliminate nearly 57,000 pounds of nitrogen oxides, and nearly 550 pounds of fine particulate matter (PM2.5) emissions annually. Calfornia Energy Commissioner Patty Monahan said,

“School buses are by far the safest way for kids to get to school. But diesel-powered buses are not safe for kids’ developing lungs, which are particularly vulnerable to harmful air pollution. Making the transition to electric school buses that don’t emit pollution provides children and their communities with cleaner air and numerous public health benefits.”

The exact number of buses going to California school districts is unclear — the energy commission only says “more than 200.” If the entirety of the $70 million went to just 200 buses, that’d be $350,000 per bus.

But while the exact cost of each bus is unknown, the commission does estimate that “schools will save nearly $120,000 in fuel and maintenance costs per bus over 20 years.” Some estimates have noted that electric school buses tend to cost about $120,000 more than diesel buses — if that’s the case here, the price will be equal in the end, with added health benefits.

Funding for the electric buses is supplied by the voter-approved California Clean Energy Jobs Act, and the commission’s Clean Transportation Program will provide the charging infrastructure to support the buses.

Today, the commission awarded The Lion Electric Co. with a contract to provide electric buses. Lion has already deployed more than 200 electric school buses in North America, with California getting the bulk of those buses thus far.

Electrek’s Take

School buses are a perfect opportunity to go electric. In addition to the health benefits for school children and others, school buses generally run short, set routes at the same times every day, so charging should never be an issue.

Upfront funding seems to be the biggest challenge to getting more electric school buses, as costs balance out over time when considering fuel and maintenance savings. We’d love to see more investments in these types of initiatives, and more kids taking electric buses to schools every day. It’s such an obvious fit.

 

California replacing 200 polluting diesel school buses with all-electric buses, by Phil Dzikiy, Electrek, July 17, 2019.

CPX Regulatory Update – July 11, 2019

Regulatory updates for Thursday, July 11, 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 visit http://www.cpuc.ca.gov/documents/

Notes:

  • A CPUC voting meeting is on schedule for today, July 11. Agenda is HERE. To log in to the livestream, click HERE.
  • In June CPUC President Picker announced that he will be departing the CPUC once a replacement is found – no update.
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. Wildfire Cost Recovery 19-01-006
  6. Utility Wildfire Mitigation Plans (SB 901) 18-10-007
  7. New: Penalties for 2017 Wildfires 19-06-015
  8. PG&E Bankruptcy (no formal docket #)
  9. Integrated Resource Plans (IRP) 16-02-007
  10. Distribution Resource Plans (DRP) 14-08-013 
  11. Renewables Portfolio Standard (RPS) 18-07-003
  12. Integrated Distributed Energy Resources 4-10-003
  13. Direct Access 19-03-009
  14. NEM Successor Tariff 14-07-002
Closed proceedings that matter:
  1. CCA Rulemaking; Bond and Re-Entry Fees – 03-10-003 and 18-05-022
Other non-adjudicatory activities:
  • Customer Choice Project
  • AB 2514 Implementation (Energy Storage)

 

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

New Developments:

  • Order establishing process for parties to comment on proposals to improve PG&E safety Key proposals presented in the Order:
    • Separating PG&E into separate gas and electric utilities or selling the gas assets;
    • Establishing periodic review of PG&E’s Certificate of Convenience and Necessity (CPCN);
    • Modification or elimination of PG&E Corp.’s holding company structure;
    • Linking PG&E’s rate of return or return on equity to safety performance metrics.
  • Motion to Amend June 18, 2019 Assigned Commissioner and ALJ’S Ruling to align it with the scope of the Proceeding
  • The Public Advocate’s Office filed a Motion to Amend the scope of the Order.
    • Minimum safety and performance prerequisites.
    • Alternatives to PG&E.
  • 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 role in achieving CA’s GHG goals; PG&E’s operational integrity; PG&E’s role in its service territory; Costs passed on to ratepayers.

Key Documents:

  • Order extending statutory deadline to May 8, 2020

Next Steps:

  • July 16 – Respond to Public Advocate’s Office Motion
  • July 19 – Opening comments on the Order
  • August 1 – PG&E to report on Board’s safety qualifications
  • August 2 – Reply comments on the Order
  • May 8, 2020 – Deadline to conclude proceeding

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 (Proceeding #R.17-06-026)

New Developments:

  • Ex Parte between SDG&E and Comm. Picker.
  • Group 1 (benchmark and true-up) Final Report workshop 1 and workshop 2.
  • Group 2 (prepayment) workshop 2 workshop 1.
  • Group 3 (portfolio optimization/auction) First Progress Report, workshop 1.

Key Documents:

  • Order Instituting Rulemaking.
  • Scoping Memo.
  • Decision 18-10-019 modifying the PCIA.
  • Joint Petition for Modification of Track 1 Decision D.18-07-009.
  • Applications for re-hearing of Decision 18-10-019 by POC, CLECA and DACC, CalCCA, Shell, and PCE/MCE/SCP
  • Phase 2 Scoping Memo.

Working Groups and co-chairs for Phase 2:

  1. Benchmark true-up and related issues – PG&E, CalCCA.
  2. Prepayment − SDG&E, AreM/DACC.
  3. Portfolio Optimization & Cost Reduction – SCE, CalCCA.
    1. Voluntary allocation and auction proposal – Commercial Energy.

Next Steps (Tentative):

  • July 25 – Group 3 second workshop
  • July 26 – Group 2 second update
  • September – Proposed decision on Group 1 issues 1 – 7
  • September 26 – Group 3 second update
  • October 2019 – Commission vote on Group 1 issues 1 – 7
  • November 2019 – Resolution of Group 1 issues
  • December 9 – Group 2 Final Report

Background:

The PCIA is a fee charged to pay for a utility’s stranded cost of procuring electricity on behalf of customers departing for in CCAs or as Direct Access customers. On October 11, 2018 the CPUC voted to accept the Alternate Proposed Decision that significantly increased the PCIA.

  1. Resource Adequacy (17-09-020)

New Developments:

  • On June 27 the Proposed Decision adopting local and flexible capacity obligations 2020-2022 was passed;
    • Comments by CalCCA, SDG&E regarding load migration;
  • May 22 workshop by Shell; Summary prepared by Shell
  • CAISO Local Capacity Study
  • Comments on Workshop and Track 3 proposals by CalCCA, PG&E, CAISO.
  • RA Workshops Outline.

Also See:

  • June 14 comments of the California Community Choice Association on Track 3 Proposed Decision.
  • Opening comments of MCE Clean Energy and Sonoma Clean Power on the Track 3 Proposed Decision

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.

Next Steps: TBD

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. Wildfire Cost Recovery (19-01-006)

New Developments

  • Proposed Decision finding PG&E ineligible for Stress Test
    • PG&E Comments rejecting the Proposed Decision
    • TURN’s Comments requesting ratepayer reimbursement
  • Report from CA Commission on Catastrophic Wildfire Cost and Recovery
  • Staff Proposal for “Stress Test” methodology; Stress Test Workshop slides.
  • Comments on the staff report by PG&E, TURN, City and County of San Francisco. City and County of San Francisco
  • June 18 – Wildfire recovery costs estimated at $50B – Sac Bee

June 27 – Voting on Proposed Decision. PASSED.

Special note:

There is currently bill relevant to this proceeding making its way through the legislative process. AB 235 introduced by Chad Mayes (Dist. 42, Yucca Valley, R). The bill authorizes the CPUC, when determining recovery by an electrical corporation for costs and expenses arising from a catastrophic wildfire occurring on or after January 1, 2019, to consider the electrical corporation’s financial status and determine the maximum amount the corporation can pay without harming ratepayers or materially impacting the electrical corporation’s ability to provide adequate and safe service. The bill is now on the Senate Energy Committee with no hearing date scheduled.

Major Issues:

  • How much a utility can be required to pay out of pocket?
  • What are the costs that a utility can legitimately pass on to ratepayers?
  • What will be used as a cost recovery calculation methodology?

Key Documents:

  • Comments by Mendocino/Napa/Sonoma Counties, PG&E, San Francisco City Attorney.
  • Order Instituting Rulemaking.
  • SB 901 (Dodd)
  • Scoping Memo.

Next Steps: TBD

Background: The CPUC’s R.19-01-006 is a proceeding to implement Public Utilities Code Section 451.2 regarding criteria and methodology for wildfire cost recovery pursuant to Senate Bill 901 (2018). Major questions include:

  1. Utility Wildfire Mitigation Plans (SB 901) 18-10-007

Updates:

  • IOU wildfire mitigation plans were approved at the May 30 CPUC voting meeting.
  • Assigned Commissioner and Administrative Law Judge’s June 14 Ruling launching Phase 2 of the Wildfire Mitigation Plan proceeding.

Background: Senate Bill 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities’ plans to prevent, combat, and respond to wildfires affecting their service territories. Through a proceeding it opened on Oct. 25, 2018 (R.18-10-007), the CPUC will review the initial plans, and develop and refine the content of and process for review and implementation of wildfire mitigation plans to be filed in future years.

  1. NEW: Penalties for 2017 Wildfires (I.19-06-015)

This is a newly opened Investigation that we will monitor

Issue: Possible PG&E violation of Public Utilities Code.

Key Documents:

  • Order Instituting Investigation
    • Commission’s Safety and Enforcement Division finding PG&E violated Commission General Orders and Resolution E-4148 and failed to follow industry best practices.

Next Steps:

  • July 29 – Responses to OII
  • August 5 – PG&E report in response to questions in OII
  1. 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).

New Developments

  • CA Legislature fast-tracking legislation (AB 1054) to address IOU viability – on the Assembly Floor today
  • 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
  • PG&E Motion for Protective Order
  • 2,500 acre fire on Tuesday July 25 caused by downed PG&E line. No injuries.
  • $105 million immediate assistance for wildfire victims
  • Commission approves PG&E’s Wildfire Mitigation Plan.
  • PG&E Quarterly Earnings Report reveals SEC investigation. Statement by PG&E.
  • PG&E hires former TVA CEO Bill Johnson.
  • PG&E will propose increasing its Board to 15 directors at the Annual Shareholders

Meeting.

  • US District Court Probation Order suspending dividends until PG&E complies with vegetation management and wildfire mitigation plan.

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

New Developments:

  • June 20 – Assigned commissioner and Administrative Law Judge’s RULING initiating procurement track and seeking comment on potential reliability issues. Comments are due no later than July 15, 2019. Reply comments are due no later than July 25, 2019.
  • 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. o SEA Analysis of the Final Decision
    • SEA Analysis of the Proposed Decision.
  • Comments on the PD by SDG&E, CalCCA, CAISO, Calpine, SEA .
  • Reply comments by SDG&E, CalCCA, CAISO, Calpine.

Key Documents:

  • Order Instituting Rulemaking
  • Decision D.18-02-018 setting IRP requirements for LSEs
  • Amended Scoping Memo
  • Ruling on production cost modeling approach and schedule for preferred system plan development
  • Ruling seeking comment on policy issues and options related to reliability
  • Ruling seeking comments on inputs and assumptions for development of the 2019-2020 Reference System Plan

Major Issues:

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

Next Steps:

  • July 15 – Party Comments on the Procurement Track.
  • July 25 – Reply Comments.
  • July 29 – Comments on procurement track (tentative).
  • Late 2019 – Proposed Decision on Procurement Track.
  • August 16, 2019 – LSEs to provide informal IRP resource contract and development status reports. Can be submitted confidentially.

Background: On April 25 the CPUC unanimously approved a Proposed Decision that approves or certifies 20 individual LSE IRPs. Grants exemptions to 9 LSEs. Requires another 19 LSEs to refile their individual IRPs as Tier 2 advice letters, with additional information about the criteria pollutants associated with serving their load. It also adopts a Preferred System Portfolio to use as the basis for future planning and to transfer to the CAISO for use in its Transmission Planning Process (TPP) as the reliability base case and policy-driven base case. Lastly, it requires LSEs serving load in the territory of PG&E to include in their next IRPs a section addressing retirement of Diablo Canyon. The decision primarily relies on Community Choice agencies to procure the new clean energy resources the State needs over the next decade to achieve California’s renewable energy and GHG emissions reduction targets attributable to the State’s electricity sector. 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 update.

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 (R.18-07-003)

New Developments:

  • July 2 Proposed Decision implementing SB100
    • 44% for 2021-2024 by December 31, 2024; 52% for 2025-2027 by December 31, 2027; 60% for 2028-2030 by December 31, 2030
    • Progress assessed using “straightline” method in D.11-12-020
    • No Comments against the PD
  • Schedule of Review for 2019 RPS Plans.
    • Updated Schedule
    • July 21, 2019–IOUs, ESPs, and CCA RPS procurement plans deadline

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
  • Co-ordination 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.
  • 19-02-007 accepting draft 2018 RPS plans filed by LSEs.
  • Comments on SB 100 implementation from CCAs and PG&E.
  • Reply comments from Joint CCAs and Joint Utilities.

Next Steps:

  • July 19 – Comments on plans and coordination with IRP proceeding.
  • August 2 – Deadline for Motion to request evidentiary hearings.
  • August 2 – Reply comments on RPS plans.
  • August 23 – Updates to RPS procurement plans.

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. Recent ALJ Rulingdirecting 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 (SB 237) – 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: Kerry.Fleisher@cpuc.ca.gov

 

Closed proceedings that matter: 

  1. CCA Bond Requirements and Re-entry Fees – No new developments. Background: Rulemaking R.03-10-003 was initiated in October 2003 to implement portions of AB 117concerning Community Choice Aggregation. That Rulemaking is closed. One result of the proceeding was Decision 18-05-022issued 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.
  1. CCA Rulemaking03-10-003This was the original rulemaking that occurred between 2003 and 2005 to cross the Ts and dot the Is on CCA law.

Other regulatory matters:

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. Lastly, 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.

 

 

Clean Power Alliance Signs Three New Renewable Energy Power Purchase Agreements

Los Angeles, CA–Clean Power Alliance (CPA) signed three new competitively priced long-term power purchase agreements, including two new solar projects and one existing small hydroelectric project. The projects were approved by CPA’s Board of Directors at their June 28th board meeting.

All of the projects are located in Southern California in areas with low environmental impacts and specifically designated for renewable energy development. The projects will enable CPA to meet its customers’ renewable energy demand, lower costs, and comply with state renewable energy mandates. The two new solar facilities will create approximately 500 jobs, contracting well-paid and skilled workers to deliver on CPA’s mission to invest in a green energy workforce.

“These contracts demonstrate that Clean Power Alliance’s environmental commitments are translating into high impact investments and competitive pricing for our customers, while combatting climate change,” said Diana Mahmud, Board Chair of Clean Power Alliance and South Pasadena City Councilmember.

The first project contracts 233 megawatts from the Arlington Solar project in Riverside County, which will be owned and operated by a subsidiary of NextEra Energy Resources, LLC. That project will come on-line in two phases, with the first 100 MWAC delivered December 2021 and the next 133 MWAC delivered December 2022. It has an expected output of 718,220 MWh/year and a 15-year long contract.

The second project contracts 40 megawatts from Clearway Energy Group’s Rosamond Solar project in Kern County, beginning in March 2021. It has an expected output of 114,780 MWh/year and a 15-year long contract.

The last project contracts all of Isabella Partners’ existing 12 megawatt Isabella small hydroelectric project in Kern County, beginning in December 2020. It has an expected output of approximately 48,000 MWh/year and a 10-year long contract.

The projects resulted from CPA’s 2018 Clean Energy Request for Offers (RFO) and complement a long-term contract for the Terra-Gen owned Voyager wind project, executed in late 2018. CPA is negotiating additional long-term contracts from its 2018 Clean Energy RFO and will launch another Clean Energy RFO this coming fall.

CPA’s newly signed contracts follow a trend of Community Choice Aggregation (CCA) programs across the state exercising their buying power and driving new renewable energy development. Collectively to date, California’s CCAs have signed long-term renewable energy contracts for over 2000 megawatts.

“Our customers and the local governments who comprise Clean Power Alliance have overwhelmingly chosen competitively priced renewable energy options. These contracts will allow us to give our customers what they want while meeting California’s ambitious renewable energy goals ten years early,” said Natasha Keefer, Director of Power Planning and Procurement, Clean Power Alliance.

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Clean Power Alliance believes in a clean energy future that is local, where communities are empowered, and customers are given a choice about the source of their energy. As of June 2019, Clean Power Alliance serves over one million customer accounts and has the most customers on 100% renewable energy rate plans than any other electricity company in the country. Visit www.cleanpoweralliance.org or call Clean Power Alliance at 888-585-3788 for more information.

Sonoma Clean Power Seeks Participants for its Lead Locally Program: Energy-Saving Upgrades Available to Eligible Homes and Businesses in Sonoma and Mendocino Counties

(SANTA ROSA, CA) – Sonoma Clean Power (SCP), the public electricity provider for Sonoma and Mendocino Counties, is currently recruiting participants for a study on energy-saving technology in which homes and businesses will receive free energy-efficient equipment.

The study is part of SCP’s Lead Locally program which is funded through a grant from the California Energy Commission, along with additional support from SCP. The program aims to develop strategies to double energy efficiency in existing buildings and measure the results of the prospective technologies, prior to launching future customer programs.

“SCP wants to bring the right technologies to our community that can move us toward a cleaner energy future. Before we launch any potential rebate or incentive programs, we want to know what our community thinks,” said Chad Asay, the Programs Manager for Lead Locally.

“That’s why the Lead Locally program is asking for residents and businesses in SCP’s service territory to help evaluate these energy-saving technologies now, so that we can develop the right programs to help meet our community’s energy efficiency goals,” added Asay.

SCP is looking for approximately 35 homes and 18 businesses to receive upgrades. All the equipment studied under the Lead Locally program will be provided to the participants for free, along with any permit fees, leaving only the installation costs to be covered by the homeowner or business owner.

For residential customers, home upgrades include cooling and ventilation, air draft sealing, induction cooktops, and water heating. For businesses, upgrades include daylighting and insulation materials, as well as commercial-scale induction cooktops and dishmachines.

Participant feedback will be used to identify the best practices for installers, guide future energy-saving programs locally and state-wide, and most importantly, confirm that these technologies work well for the Sonoma County and Mendocino County communities.

Based on the results of the study, SCP plans to offer future rebates and incentives to its customers to improve the efficiency of buildings in its service territory and significantly reduce local emissions.

Additionally, SCP is opening an Advanced Energy Center in 2020 where customers will be able to learn about, test and purchase these energy-saving technologies for their home or business.

Participation requests can be submitted by visiting the Lead Locally program page on SCP’s website. Applications will be used to screen for a building’s eligibility and will be processed on a first-come, first-served basis. Participants must be willing to complete quarterly satisfaction surveys and allow energy usage monitoring for 12 to 18 months.

About Sonoma Clean Power

Sonoma Clean Power is proud to serve the Counties of Sonoma and Mendocino as a self-funded, public electricity provider. SCP’s services are practical, affordable and inclusive, empowering everyone to be part of the transition toward a clean energy future. To learn more, visit sonomacleanpower.org or call 1 (855) 202-2139.

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With Calif. cap-and-trade funds, a city plagued by pollution plans swift transformation

A tool that helped direct $66.5 million to Fresno could provide a template for other states seeking to counteract the effects of pollution in vulnerable communities.

As proponents of the Green New Deal seek to create jobs and protect vulnerable communities while fighting climate change, California has had a statewide program to accomplish those goals since 2013.

And Fresno is the latest city on the verge of accomplishing something big as a result. A new community college satellite campus, a food hub, parks and pathways, affordable homes, electric car charging stations and a slew of electric bikes are among the 24 projects expected to transform the city’s landscape by 2024.

The state of California has strict guidelines designed to achieve sharp reductions in greenhouse gas emissions by mid-century; to achieve these goals, the California Air Resources Board extracts fees from companies for the pollution that they produce. Each year, the state allocates millions of dollars in these cap-and-trade funds for climate mitigation projects, with 25% of the money going toward disadvantaged and low-income neighborhoods.

The transportation and the renewable energy sector receive the bulk of the money. But just as important to many communities and to city officials are projects meant to improve living conditions for California’s nearly 40 million inhabitants.

One of the most notable milestones in the state’s carbon-cutting programs was the award of $66.5 million to Fresno, under the rubric of the Transformative Climate Communities program (TCC). At the heart of the effort is a data analysis tool that could provide a template for other states.

Fresno, with about 530,000 residents, is California’s fifth-largest city. And like many major metropolitan areas, the population consists of a broad mix of people. The community of Watts in Los Angeles and the city of Ontario in San Bernardino County were each awarded $35 million in TCC funds, respectively.

“This is the state of California’s way of coming alongside communities faced with environmental, economic and equity challenges to assist them in leapfrogging into a state of development that is sustainable,” said H. Spees, director of strategic initiatives for Fresno’s mayor’s office.

Launched in 2016, the TCC program recognizes that California’s poor, often marginalized communities have borne the brunt of discriminatory practices that placed minority groups in the path of polluting industries and adjacent to traffic corridors.

“To say that we have some of the worst air quality would be an understatement — we have some of the worst air quality in the nation,” said Grecia Elenes, a long-term resident of Fresno and a senior policy advocate for the nonprofit Leadership Counsel for Justice and Accountability.

While the bulk of the state’s cap-and-trade funds go to projects that can lower a city’s carbon footprint, like solar panels for low-income households, TCC differs in that it takes a triple-bottom-line approach to community investments to “provide local economic, environmental and health benefits” for cities like Fresno.

Fresno has had a long history of redlining and white flight. Beginning in the 1870s, the city’s minority and white residents had segregated along racial lines, and the legacy of those discriminatory practices had resonated across generations. Decades of neglect — due to a lack of community investment by banks and successive city administrations — had gutted parts of the city.

“It still astonishes me, the divide between north and south Fresno,” Elenes said.

Rather than depend on the testimony of historians and activists to prioritize which communities should receive TCC funds, decision-makers can take an evidence-based approach.

In 2013, state officials created an interactive database called CalEnviroScreen. At its core, CalEnviroScreen is a data visualization tool that compiles socio-economic data to reveal the hidden effects of pollution on vulnerable communities.

“CalEnviroScreen was designed as an environmental justice tool, but grew out of a need to measure multiple sources of pollution,” said Sam Delson, deputy director of legislative affairs for CalEPA.

California’s 1,800 ZIP codes were tabulated and color-coded according to 18 (now 20) socio-economic and environmental indicators, such as traffic density, air quality, education and unemployment. ZIP codes in the light green range suffered little in terms of poverty and environmental degradation. On the other hand, blue is an indicator that both poverty and pollution are prevalent. A deep shade of blue engulfs many of Fresno neighborhoods.

Over the past four years, the map has become even more detailed, incorporating 8,306 census tracts statewide. As of 2018, five of Fresno’s census tracks ranked in the 99th percentile, among the worst in the state.

The maps generated by CalEnviroScreen confirmed what community advocates like Elenes had suspected but found difficult to prove in the abstract — that high rates of poverty and pollution are linked in Fresno.

Upon final approval by state officials, the funds for TCC projects are expected to start to flow by years’ end. The first goal is to build a conduit between downtown Fresno, Chinatown and southwest Fresno. Spees anticipates it will start with a trickle and end with a flood of construction. Fresno has five years to complete about two dozen housing and infrastructure projects designed to ease traffic congestion and revitalize the downtown corridor.

The TCC grant also requires the city to match the grant by 50%, a number that Fresno has more than doubled through public and private partnerships.

“Fresno has two futures,” Spees said. The default, he said, is that Fresno does nothing with an apocalyptic future of poverty and despair. Or, he added, city officials and stakeholders can build sustainable communities based on a diversified economy: “the TCC is a down payment on our future.”

 

With Calif. cap-and-trade funds, a city plagued by pollution plans swift transformation, by Enrique Gili, Energy News Network, July 8, 2019.

How CCAs can model and deploy DERs

Many CCAs are expanding their electricity procurement plans to include deployment of distributed energy resources (DERs) like on-site solar, battery storage, electric vehicle supply equipment, etc. as a means to reduce their procurement costs and provide additional value to their customers. TerraVerde has partnered with CCP and CCAs to advance the deployment of DERs. Read more about this effort below:

With the rapid emergence of community choice energy agencies (CCAs) throughout the state, California schools, municipalities and other public agencies are well positioned to take advantage of the new choice in how their electricity is supplied. For most public agencies, transitioning to a CCA from their incumbent utility provider will result in electricity cost savings.

Many CCAs are expanding their electricity procurement plans to include deployment of distributed energy resources (DERs) like on-site solar, battery storage, electric vehicle supply equipment, etc. as a means to reduce their procurement costs and provide additional value to their customers. TerraVerde has partnered with CCAs to advance the deployment of DERs. In 2017, a California Energy Commission grant under the Local Government Challenge was awarded to MCE Clean Energy, TerraVerde, Center for Climate Protection and other partners to develop a software and a program, titled Building Efficiency Optimization (BEO) for CCA program and procurement managers to identify scalable and replicable programs for deploying DERs that optimize building electricity use and reduce greenhouse gas emissions on a community scale. In doing so, the program is designed to broaden the deployment of energy efficiency, electric vehicle charging infrastructure, solar and batteries deployment to facilitate local renewable energy integration and to increase benefits that are passed onto customers.

The BEO software is designed to perform multi variable analysis that can be framed in the following omni question format by the user:

“What is the Benefit or Cost to promote a Quantity of DERs to Customer Segment in a CCA’s Territory/Location over the span of Time Frame?”

Where the inputs are:

• A Quantity of DERs
• A Customer Segment of a CCA’s total customer base
• A CCA’s Territory/Location in California
• A Time Frame in the past or future
• A Benefit or Cost selection

And the output is:

• A Benefit or Cost calculation using an output function (ex. impact to GHG emissions, impact to CCA procurement cost, revenues collected from customers or payments avoided to customers, etc.).

For our first analysis using the software, we worked with two CCAs to address the cost of servicing solar NEM customers with net surplus generation. These are CCA customers with existing solar under the NEM tariff that produce more electricity than is used by their buildings (homes, schools, businesses, etc.). As a result of excess solar generation, these customers generate excess electricity bill credits which are required to be paid out by the CCAs through an annual true-up.

We studied the benefits of pairing battery storage devices to be used for load shaping while providing back-up power to the host customers. The load shaping strategy relied on charging the batteries with excess solar generation and discharging the batteries between 4 to 9 pm. The battery charge and discharge cycles can be selected as desired by each CCA to minimize electricity procurement beyond already contracted power when wholesale costs are high.

As a first step, we collected and ingested the 15 minute and hourly interval import and export data from all the customers in the study. We then grouped the customers by specific rate schedule and class to identify the top opportunity groups where a CCA can achieve the most benefit per deployed battery storage. In this case, customers under the A-6 rate schedule were selected since just 90 customers provide 10.3% of all net electricity exports. The software then was used to perform a load clustering activity to identify the specific customers within the A-6 group of customers that had a consistent evening peak profile suitable for load flattening using the batteries. As shown in the presentation included below delivered at the 2019 Business of Local Energy Symposium conference CCA Cutting Edge Projects, the results of the simulations support the thesis that batteries could be used to provide economic benefits to CCAs by reducing the excess generation credit payments, reducing procurement of electricity during the specified 4 to 9 pm period, while still providing back up to the customers. Additionally, the greenhouse gas (GHG) emissions impact were studied using two methodologies. We will cover the GHG impact analysis in the next TerraBlog post!

 

How CCAs can model and deploy DERs, by Ali Chehrehsaz, TerraVerde Energy, July 8, 2019.