CPX Legislative Update for October 3, 2019

Updated 10/3/19

Legislative Calendar Check: The legislature adjourned on September 13. The governor has until October 13 to sign bills. We will issue one more legislative update on October 17, and then will be on break until the legislature resumes business in January 2020. In the meantime, visit the CPX legislative page for occasional updates.

In this 2019 session we are monitored about 29 energy and/or climate-related bills, not all of which would directly impact Community Choice Energy. Below is a selection of highlighted bills with a brief summary, the Center’s position, if any, and the status of the bill.

Two-year bills that will come back in 2020:

AB 56 (Garcia) OPPOSE – This bill will empower the CPUC to order energy procurement based on real or perceived shortcomings in the Integrated Resource Plan submitted by Investor Owned Utilities, Direct Access providers, and CCAs. The bill will allow the CPUC to require procurement on any perceived deficiency that may be 10 to 12 years out in the future. This makes no sense, given that so much lead time would allow a CCA to address any potential problem. Read the Center’s updated July Letter of OppositionStatus: Two-year bill.

AB 235 (Mayes) – Now dubbed the “Catastrophic Wildfire Liability Recovery Act,” this bill will allow PG&E to issue bonds to cover 2017, 2018 wildfire liabilities that ratepayers could ultimately have to pay for, and allows the CPUC to arbitrarily set a limit on the amount a transmission & distribution utility must pay as a result of catastrophic wildfire that may have been the result of their infrastructure. It is essentially a defense of status quo corporate utility dominance.  Status: AB 235 is a two-year bill.

SB 246 (Wieckowski) – Read our Support Letter. – This bill, if enacted as written, will impose an oil and gas severance tax on the privilege of extracting oil or fossil gas from the earth or water in California upon any operator engaged in such extraction. Status: Two-year bill. It will be brought back in January 2020.

SB 350 (Hertzberg) OPPOSE – This bill would “authorize the CPUC to consider a multiyear centralized resource adequacy mechanism,” meaning, a central buyer, which would encroach on CCA statutory authority on procurement autonomy. This bill was a tandem bill with AB 56 that is also a tw0-year bill. Status: Two-year bill.

SB 386 (Caballero) – Read our Letter of Opposition. This bill would allow Turlock, Modesto, and Merced Irrigation Districts to count their large hydro assets (dams) toward their Renewable Portfolio Standard (RPS) obligations. This would significantly impact progress with new renewables. These Irrigation Districts will already be able to count their dams as carbon-free pursuant to state policy on decarbonization and mechanisms are in place to protect low-income communities from any cost burdens. Status: Two-year bill.

SB-772 (Bradford) – This bill relates to procurement of long duration bulk energy storage. Concerns center on forcing the hand of CCA procurement. Status: Two-year bill.

SB 774 (Stern) – SB 774 would require IOUs to collaborate with the State’s Office of Emergency of Services and others to identify where back-up electricity sources may provide increased electrical distribution grid resiliency and would allow the IOUs to file applications with the CPUC to invest in, and deploy, microgrids to increase resiliency. Concerns focus on too much control being placed in the hands of the IOUs over microgrid development when other LSEs and stakeholders can and should play a role. Status: Two-year bill.

Bills we opposed that were enacted:

AB 1054 (Holden, Mayes, Burke) – Enacted: This 200-page bill was fast-tracked through the legislature. In addition to encumbering ratepayers with nonbypassable charges for more than a decade just as they were set to expire, and no safeguard against rate increases, the bill includes a clause that is completely outside of any wildfire concern, and it impacts Community Choice agencies. The clause empowers the CPUC to obstruct sales of IOU assets to other load serving entities and public entities. This could hobble local governments wanting to launch their own municipal service, and/or emerging CCAs that may benefit by acquiring assets that the IOUs no longer want or need. Status: AB 1054 passed out of the legislature on July 11 and was signed by the governor. It is now being challenged in federal court by two PG&E customers on grounds that it may allow for ratepayer funds to be used to pay for cost increases due to PG&E negligence.

AB 1584 (Quirk) – In its final form this bill requires the CPUC to develop and use methodologies for allocating electrical system integration resource procurement needs to each load-serving entity based on the contribution of that LSE’ load and resource portfolio to the electrical system conditions that created the need for the procurement. It also requires the CPUC to develop and use methodologies for determining any costs resulting from a failure of a LSE to satisfy its allocation of those procurement needs. Originally this bill would have impinged on Community Choice agency statutory procurement authority. Due to amendments in August, CalCCA shifted to a neutral position. Status: On the governor’s desk.

SB 155 (Bradford) – This bill expands CPUC’s authority over CCA procurement and Integrated Resource Plans. Read the Center’s July Letter of Opposition. Due to amendments made in early July, CalCCA shifted to a neutral position. Status: On the governor’s desk.

SB-520 (Hertzberg) This bill empowers the CPUC to determine what load serving entity should serve as the provider of last resort (POLR). Currently IOUs serve as the provider of last resort in their service territories. A big problem with the bill is that it gives the IOUs veto control over the POLR application process. If another LSE (e.g., a CCA) wants to become the POLR, the incumbent IOU must agree to the application submitted to the CPUC, which is unacceptable. This bill is a step in the wrong direction. It gives the existing utilities control over whether they continue to have the exclusive right to serve as the utility and gives them control over who if anyone would take over the role of POLR. Why should the State hand over that kind of decision-making authority to the existing utilities? We are concerned that over time, this will make the utilities less accountable. We encourage firm opposition to this bill in its current form. Status: SB 520 is on the governor’s desk awaiting his signature or veto.

SB 676 (Bradford) – This bill requires the CPUC, by December 31, 2020, in an existing proceeding, to establish strategies and quantifiable metrics to maximize the use of feasible and cost-effective electric vehicle grid integration. Based on amendments made in early July, CalCCA has shifted to a neutral position. Status: On the governor’s desk.

Bills we supported that were enacted:

AB 684 (Levine) – Read our Support Letter. Rules proposed in this bill would ensure that the infrastructure necessary for EV charging in multi-family dwellings is codified through multi-family building standards. Status: On the governor’s desk.

Bills we supported that died:

AB 1046 (Ting) – Clean Vehicle Rebate Program. This bill would have required the California Air Resources Board to develop a plan to provide for the continuous funding of a program with a goal of supporting deployment of 5 million electric vehicles by December 2030. Status: AB 1046 died in the Senate Appropriations Committee on August 30.

For the complete list of bills we monitored in 2019 click HERE.  The next and final 2019 CPX legislation update will be on Thursday, October 17th.

Muni tries to tackle environmental justice with new SF green bus zones

As a Muni 47-Van Ness bus pulled into its stop at 11th and Harrison streets on a recent weekday morning, something almost imperceptible happened.

As the rumbling engine wheezed to a stop, a hush fell over the bus’ interior, and its quivering floor suddenly stopped vibrating. The vehicle was almost silent.

The bus had switched off its combustion engine and gone all-electric, temporarily eliminating its diesel emissions. The switch to battery power is automatic any time the 47-Van Ness crosses into the “green zone,” an area that stretches just under a mile from the 11th and Harrison stop heading inbound to Fisherman’s Wharf, and from Bryant and Sixth streets traveling outbound to the Caltrain depot.

The new green zones — nine in total dotting each quadrant of the city — were picked with environmental justice in mind, Muni officials told The Chronicle in an exclusive interview. The idea is to reduce emissions in neighborhoods with high concentrations of low-income households and people of color. Those communities often suffer from higher rates of air pollution — largely from vehicle emissions — which cause higher rates of respiratory illnesses.

The green zones cut through neighborhoods identified in Muni’s equity strategy, which aims to improve service in low-income areas.

Read more

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 http://www.cpuc.ca.gov/documents/

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: Kerry.Fleisher@cpuc.ca.gov

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.

SDG&E will not have to buy the Otay Mesa Energy Center for $280 million

San Diego Gas & Electric will not have to pay $280 million to take over the 608-megawatt Otay Mesa Energy Center natural gas power plant as part of a complicated and controversial agreement signed 10 years ago by the plant’s current owner, Houston-based Calpine.

Early Tuesday evening, an official at Calpine confirmed to the Union-Tribune that the company has accepted a 59-month power purchase agreement with SDG&E that will see Calpine employees continuing to operate the facility located in the foothills near Chula Vista that delivers electricity to utility customers.

The original agreement signed in 2009 is set to expire Wednesday and the 59-month deal will go into effect Thursday when the original 10-year agreement expires.

Read more

Renewable Energy Will Provide Discount To Thousands

“Poor families are going to receive hundreds and hundreds of dollars every year because of this.  If we as human beings don’t think mother nature isn’t going to bite back because what we have done, then we are living in a false reality and we need to wake up. and this project is one way to wake us up and says there is a bright beautiful future that we can have,” said former congressman Joseph Kennedy II.

Imperial Irrigation District and Citizens Energy Corporation just completed the largest low-income solar project in the country, bringing politicians from both sides of the aisle together.” 

“It’s nice to see what went on the drawing board and what we talked about in Sacramento become reality. and i think the country is going to learn a lot about what were innovating ad doing out here today,” said Senator Jeff Stone.  

There are more than 100,000 are more than 100,000 solar panels like this out here in Calipatria. It will generate 30MW of power and serve over 12,000 customers.  

”It just helps you know when each month you look at your income and you think am I going to make it this month. I just want to say thank you to everybody,” said low-income customer Pauline Price

Low income customers in Imperial and Coachella Valleys will start seeing the savings this October. 

“Anyone enrolled in IID Low Income Assistance Program will be automatically enrolled,” said Antonio Ortega.

Senator Jeff Stone said this solar project aligns with California’s steep goals on renewable energy.

“By 2045 we are suppose to be 100-percent on alternative energy. We have solar energy, wind energy, thermal energy. We set the stage for what the rest of the country is going to do,” said Stone. 


Renewable Energy Will Provide Discount To Thousands, by Sophia Miraglio, NBC Palm Springs, September 30, 2019.

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.

SLO Climate Strike pushes for policy change at county level

People from all over San Luis Obispo County gathered outside the county courthouse to take part in the second global climate strike Friday, Sept. 27.

San Luis Obispo’s strike was part of a global day of action in which over 6 million people participated in rallies across 123 countries, all participating for the cause of bringing an end to climate change. The San Luis Obispo strike included about 500 people of all ages.

“[Climate change] is the most urgent crisis of our time, and climate change is happening right now,” San Luis Obispo climate strike organizer Carmen Bouquin said. “We’re seeing it in the Central Valley, and in frontline impacted communities by climate change … and we need to stop it and halt it.”

The coalition of various environmental groups — the SLO County Youth for Environmental Action, the Sunrise Movement and the Sierra Club’s Santa Lucia chapter — among others organized the event to get the community engaged.

“Community involvement is mandatory,” San Luis Obispo Mayor Heidi Harmon said. “The climate crisis is already and will continue to impact literally every living thing on this planet, so it’s going to demand that all of us take a stand on this issue.”

Harmon said coming together as a community “doesn’t have to mean activism in the way that we’re seeing it tonight,” but does require people paying attention, getting educated and getting involved.

One instance of how community engagement influenced the community was the “Community Choice Energy” program in cities around San Luis Obispo County. The program “brings local control freedom of choice and competition into the electricity marketplace,” according to the City of San Luis Obispo website.

Currently, San Luis Obispo is one of the nation’s leading cities in going green and is hoping to reach its carbon neutrality goal by 2035. However, citizens are fighting to get Community Choice Energy at a county level.

“We hope that the county joins us in this movement and [in] telling our story in a way that more communities hear it and are inspired by it to take action, get involved and join us in our carbon neutrality goal of 2035,” Harmon said.

The coalition of environmental groups urged citizens to go to the county board of supervisors’ meeting Tuesday, Oct. 1 at 1:3o p.m. The board will be reviewing a presentation on a study of the Community Choice Energy program.

“If we get to pass it at county level, communities like mine — Garden Farms, that is just outside of Santa Margarita — would have the opportunity to get rebates on their energy bills and also carbon-free energy, which would put the money back into clean energy,” Rita Casaverde, another organizer of the event, said.

The San Luis Obispo climate strike is a prime example of how something starting off so small by “sending out one email to different organizations” can turn into something so large, according to Casaverde.

“I hope that there is a lot of inspiration to help coming from tonight,” Casaverde said. “We think that you can be inspired, you can be hopeful, and you can look at the new generations and say they’re gonna make the change, but it’s not enough.”


SLO Climate Strike pushes for policy change at county level, by Natalie Young, Mustang News, September 29, 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.

Los Angeles still has a feed-in tariff. And it’s growing.

It’s odd to be writing about an active feed-in tariff (FiT) in 2019. The policy which accelerated Germany into a 7 GW+ market annually and kick-started the global solar market had its heyday nearly a decade ago, with feed-in tariffs being introduced across Europe and Asia. This led to spectacular market growth but also dramatic crashes when the ambition of the market created exceeded these policies’ political support.

What is even more strange is to be writing about a FiT in the United States. Despite the Public Utilities Regulatory Policies act of 1978 (PURPA) serving as a model for Germany’s FiT, the U.S. market has instead been driven by the Investment Tax Credit (ITC), net metering and renewable energy mandates. The few feed-in tariffs in the United States have typically been small, regional affairs.

Among these, Los Angeles has had the largest FiT program, which was started under Mayor Eric Garcetti (D) in 2013 and which earlier this week was approved by the board of the Los Angeles Department of Water and Power (LADWP) for expansion from 150 MW to 450 MW.

Like other feed-in tariffs, LA’s FiT pays a fixed price under long-term contracts to owners of PV systems, one which is typically set at a price to incentivize building such systems. For Los Angeles these prices are generous; under the latest pricing adjustment the program will pay between 13.5 and 14.5 cents per kilowatt-hour for projects in the Los Angeles basin.

These changes now go do the City Council for final approval, and this expansion appears to be building on the momentum of a revamp of the program in 2017. However despite this progress, earlier this week LADWP reported that the program had only put 66 MW of solar in service.


Mid-sized DG

Unlike net metering, which is typically focused on residential systems, FiTs often have their greatest impact on the market for systems larger than those on residential rooftops but smaller than the large solar farms in deserts, fields and forests.

This sector, often described as the commercial and industrial market, has struggled in recent years in the United States. Wood Mackenzie reported recently that this sector had the lowest volume of installations in Q2 2019 since the third quarter of 2016, with only 426 MWdc installed, including community solar.

Los Angeles’ FiT has supported projects from 30 kW to 3 MW in capacity, but under the changes approved this week, projects up to 10 MW will be eligible. This means that if developers want to build solar on large warehouses or industrial buildings, they won’t be limited by how big they can go.

And while the price for these projects under LA’s FiT is much higher than that of larger-scale solar or wholesale market prices, these mid-sized installations also offer unique benefits. Many of these projects are located in strategic locations to meet electricity demand locally, thus reducing the need for transmission and distribution infrastructure. This means that while the price is high, so are the potential benefits and savings for utility customers.

LADWP referenced the potential savings from deferred transmission investments in its news release, and this may explain why the program is limited to projects in the Los Angeles basin, with only a small volume set aside for communities in the Owens Valley.


Solar + storage future

It’s no accident that the feed-in tariff is being revamped at this time, as it follows on the launch of the City of Los Angeles’ 2019 Sustainable pLAn, which seeks to reach 100% renewable energy by 2045.

Even with imports and exports from rest of California, it is going to take more than solar to get to the higher levels envisioned in this plan. LADWP says that in 2020 it plans to introduce an expansion of the program to support local solar + storage projects. These can help meet the city’s evening peak demand, and LADWP has mentioned that these projects can also provide voltage control support for the grid.

However, there is still a long way to go. Despite Mayor Garcetti’s controversial order to to set a schedule for decommissioning local gas plants, LADWP has a lower portion of rooftop solar per customer when compared with the state’s three big investor-owned utilities, and it’s going to take a lot of power – both during the day and at night – to meet the city’s needs with clean energy.


Los Angeles still has a feed-in tariff. And it’s growing, by Christian Roselund, PV Magazine, September 27, 2019.