AGENDA
ORANGE COUNTY POWER AUTHORITY
MEETING OF THE LEGISLATIVE AND REGULATORY COMMITTEE
Thursday, March 6, 2025
3:30 p.m.
This meeting will proceed as an in-person meeting at 15310 Barranca Parkway, Suite 250, Irvine, CA 92618. In addition, as a convenience to the public, the Orange County Power Authority is also providing an option for members of the public to remotely view and participate in the meeting.
Further details are below. Please note that, in the event of a technical issue causing a disruption in the remote participation option, the meeting may continue unless otherwise required by law.
Note: Any member of the public may provide comments to the Committee on agenda items only by requesting to speak during Item 4. When providing comments to the Committee, it is requested that you provide your name and city of residence for the record. Commenters are requested to address their comments to the Committee as a whole through the Chair. Comments may be provided in the following manner:
To provide comments during the meeting, in-person attendees, please fill out the public speaker slip and provide it to the clerk at the beginning of the meeting. Before Item 4, the Chair or Clerk will ask members of the public to join the queue to provide public comment. The queue will remain open for a reasonable amount of time to allow members of the public sufficient time to request to speak and inform the Committee of the number of speakers. After such time, the queue will be closed and the members of the public who have joined the queue to speak will be recognized at the appropriate time may speak. To join the queue on Zoom video conference by computer or mobile phone, use the “Raise Hand” feature. If joining the meeting using the Zoom dial-in number, you can raise your hand and join the queue by pressing *9. Members of the public will not be shown on video but will be able to speak when called upon.
Comments shall generally be limited to three minutes when speaking, provided that the Chair may equally reduce each speaker’s time to accommodate a large number of speakers or a large number of agenda items. If you have anything that you wish to be distributed to the Committee, please provide it via [email protected], who will distribute the information to the Members.
The public may participate using the following remote options:
ZOOM WEBINAR
Please click the link below to join the webinar:
Launch Meeting - Zoom
Dial-in: 1-669-900-6833
Webinar ID: 812 9441 5984
1. CALL TO ORDER
2. PLEDGE OF ALLEGIANCE
3. ROLL CALL
4. PUBLIC COMMENTS ON AGENDA ITEMS
Opportunity for members of the public to address the Committee on any items on the agenda.
5. PUBLIC COMMENTS ON NON-AGENDA ITEMS
Opportunity for members of the public to address the Committee on any items not on the agenda but within the jurisdiction of the Committee.
6. COMMITTEE MEMBER ANNOUNCEMENTS
Committee Members may briefly provide information to other members of the Committee and the public, ask questions of staff, or report on conferences, events, or activities related to Authority business. There is to be no discussion or action taken on comments made by Committee Members unless authorized by law.
7. CONSENT CALENDAR
All items listed under the Consent Calendar are considered to be routine and may be enacted by one motion. Prior to the motion to consider any action by the Legislative and Regulatory Committee, any public comments on any of the Consent Items will be heard.
There will be no separate action unless members of the Legislative and Regulatory Committee request specific items be removed from the Consent Calendar.
1. MINUTES FOR THE LEGISLATIVE AND REGULATORY COMMITTEE MEETING OF NOVEMBER 13, 2024
Recommended Action:
Approve as submitted.
8. REGULAR CALENDAR
The following items call for discussion or action by the Committee. The Committee may discuss and/or take action on any item listed below if the Committee is so inclined.
1. ADOPT 2025 CALENDAR
Recommended Action:
Adopt 2025 Calendar.
2. AFFORDABILITY - LEGISLATIVE AND REGULATORY UPDATE
Recommended Action:
Receive and file.
3. INTRODUCED LEGISLATION POSITION RECOMMENDATIONS
Recommended Action:
Recommend the Orange County Power Authority Board of Directors take positions on legislation as recommended by Staff.
9. ADJOURNMENT
Compliance with the Americans with Disabilities Act
OCPA meetings comply with the protections and prohibitions of the Americans with Disabilities Act. Individuals with a disability who require a modification or accommodation, including auxiliary aids or services, in order to participate in the public meeting may contact 949-263-2612. Requests for disability-related modifications or accommodations require different lead times and should be provided at least 72-hours in advance of the public meeting.
Availability of Documents
Copies of the agenda and agenda packet are available at www.ocpower.org. Late-arriving documents related to a Committee meeting item which are distributed to a majority of the Committee prior to or during the Committee meeting are available for public review as required by law. Public records, including agenda-related documents, can be requested electronically at [email protected] or by mail to 15642 Sand Canyon Avenue, P.O. Box 54283, Irvine, CA 92619-4283. The documents may also be posted at the above website.
Such public records are also available for inspection, by appointment, at 15310 Barranca Parkway, Suite 250, Irvine, CA 92618. Please contact [email protected] to arrange an appointment.
MINUTES
SPECIAL MEETING
LEGISLATIVE AND REGULATORY COMMITTEE
ORANGE COUNTY POWER AUTHORITY
Wednesday, November 13, 2024
OCPA Legislative & Regulatory Special Meeting of November 13, 2024 Page 1
1. CALL TO ORDER
Chair Jung called to order the Special Meeting of the Legislative and Regulatory Committee at 12:00 p.m. on Wednesday, November 13, 2024.
2. PLEDGE OF ALLEGIANCE
Chair Jung led the Pledge of Allegiance.
3. ROLL CALL
Present: Chair Fred Jung City of Fullerton
Director Kathleen Treseder City of Irvine
4. PUBLIC COMMENTS ON AGENDA ITEMS ONLY
None
5. COMMITTEE MEMBER ANNOUNCEMENTS
None
6. CONSENT CALENDAR
Moved by Director Treseder and seconded by Chair Jung to approve the September 5, 2024, Minutes.
The motion carried unanimously by the following vote:
Ayes: Chair Jung, Director Treseder
Noes: None
Absent: None
1. MINUTES FOR THE LEGISLATIVE AND REGULATORY COMMITTEE MEETING OF SEPTEMBER 5, 2024
Action Taken:
Approved as submitted.
OCPA Legislative & Regulatory Special Meeting of November 13, 2024 Page 2
7. REGULAR CALENDAR
1. WEST-WIDE GOVERNANCE PATHWAYS INITIATIVE UPDATE
Regulatory and Legislative Manager, Steven Halligan, provided a summary of the presentation on this item.
Action Taken:
Received and filed.
2. LEGISLATIVE AND REGULATORY POLICY PLATFORM
Regulatory and Legislative Manager, Steven Halligan, provided a summary of the presentation on this item.
Action Taken:
Reviewed and Provided Feedback.
8. ADJOURNMENT
There being no further business to come before the Committee, Chair Jung adjourned the meeting at 12:37 p.m.
Submitted by:
Pat Jacquez-Nares, Board Authority Secretary
ORANGE COUNTY POWER AUTHORITY
Staff Report – Item 8.1
-------------------------------------------------------------------------------------------------------------------- To: Orange County Power Authority Legislative and Regulatory Committee From: Steven Halligan, Regulatory and Legislative Manager Approved By: Joe Mosca, Chief Executive Officer
Subject: ADOPT 2025 CALENDAR
Date: March 6, 2025
--------------------------------------------------------------------------------------------------------------------
RECOMMENDED ACTION
Adopt 2025 Calendar.
BACKGROUND
After an extensive review of holidays, and meeting dates and times of member agencies, staff recommend Legislative and Regulatory Committee meetings be held at 3:30 p.m. on the dates below. These dates were chosen to reduce any conflicts with other meetings and holidays.
Thursday, June 5, 2025
Thursday, September 4, 2025
Thursday, December 4, 2025
FISCAL IMPACT
None
ATTACHMENTS
None
ORANGE COUNTY POWER AUTHORITY
Staff Report – Item 8.2
-------------------------------------------------------------------------------------------------------------------- To: Orange County Power Authority Legislative and Regulatory Committee From: Steven Halligan, Regulatory and Legislative Manager Approved By: Joe Mosca, Chief Executive Officer
Subject: AFFORDABILITY - LEGISLATIVE AND REGULATORY UPDATE Date: March 6, 2025
--------------------------------------------------------------------------------------------------------------------
RECOMMENDED ACTION
Receive and file.
BACKGROUND
Staff will provide an update on legislative and regulatory affairs with a focus on affordability measures. Below is a summary of the items that will be covered during the meeting including Executive Order N-5-24 and the corresponding responses, affordability measures introduced in the state legislator, a regulatory update, and a federal update.
ANALYSIS AND DISCUSSION
Executive Order N-5-24
On October 30, 2024, Governor Newsom signed Executive Order (EO) N-5-24 (Attachment 1).
EO N-5-24 directed several agencies to file reports related to lowering the cost of energy bills paid across the state. The order directed California Energy Commission (CEC) to examine all electric ratepayer-funded programs it oversees or administers and to identify any programs, and any other regulations that may be unduly adding to rates. The order also directed the California Public Utilites Commission (CPUC) to examine the benefits and costs to electric ratepayers of programs it oversees. These reports were due to the Governor by January 1, 2025. Lastly, the order requested the CPUC and the California Air Resources Board to consult with each other on options to maximize the effectives of California’s Climate Credit.
On February 18, 2025, the CPUC released their response (Attachment 2) to EO N-5-24. The report highlights seven areas to address increased rates. Those include 1) All energy-related mandates should be assessed for overall cost-effectiveness with the goal of achieving the lowest possible rates for all customers of each utility. 2) Supplement essential wildfire mitigation programs and extreme weather-related catastrophic event response costs with other sources of funding. 3) Identify cost-reduction measures by integrating wildfire mitigation strategies into the existing General Rate Case process. 4) Equitable rate structures: Refine the elements of Net Energy Metering so that all customers share wildfire mitigation, public purpose programs and system costs. 5) Redistribute the Climate Credit to customers most impacted by increasing electricity costs. 6) Fund today’s and future cost-shifting programs from non-ratepayer sources. 7) Ensure that programs benefitting all electric customers are supported by all customers, including customers of publicly-owned utilities.
The CEC response (Attachment 3) was made public in mid-February and examined all electric investor-owned utility (IOU) ratepayer-supported programs that it oversees and administers. The report focused on four areas, 1) Energy Efficiency programs such as Statewide Codes & Standards Program, 2) California Schools Healthy Air, Plumbing, and Efficiency (CalSHAPE) program, 3) Solar Equipment Lists, and 4) Electric Program Investment Charge (EPIC).
Legislative Affordability Measures
SB 330 – Electrical transmission infrastructure: financing Senate Bill 330 (SB), introduced by Senator Padilla, on February 12, 2025, would authorize the Governor to establish one or more pilot projects to develop, finance, or operate electrical transmission infrastructure that meet the specified criteria, including, among other things, that the transmission line is identified by the Independent System Operator in its transmission planning process as necessary to support clean energy generation to meet the state’s clean energy goals.
In October 2024, Berkeley Law Center for Law, Energy, & the Environment released a report titled Improving Transmission Financing California (Attachment 4). The report was commissioned by the Clean Air Task Force and Net-Zer California who issued an executive summary of the CLEE report titled “Wired for Savings” (Attachment 5). The CLEE report found that some form of public-private partnership could provide significant benefits to deploying lower-cost transmission, due to cost-savings potential and the ability to leverage existing institutions and structures. According to the report a business-as-usual approach to transmission development could—over 40 years—cost ratepayers $100 billion, more than twice the cost of alternative approaches. The difference is due primarily to the higher cost financing used by investor-owned utilities, and what other studies have found to be a lack of sufficient competition in procuring new transmission lines. The use of public sector financing and accompanying institutional changes could reduce costs to ratepayers by as much as 57%—or nearly $60 billion—over the 40-year period. This is equivalent to savings of $1.5 billion per year.
SB 540 – Independent System Operator: independent regional organization SB 540, introduced by Senator Becker, on February 20, 2025, would authorize the California Independent System Operator (CAISO) to use energy markets governed by an independent regional organization. A factsheet is attached (Attachment 6). Studies have shown that allowing the CAISO to tap into a wider market of electricity resources would provide significant benefits to Californians including cost savings, enhanced grid reliability, and reduced air pollution. One such study prepared by Brattle for the California Energy Commission, titled Preliminary Day-Ahead market Impacts Study is attached (Attachment 7).
CalCCA Electricity Affordability
Ahead of the CalCCA Advocacy Day in January 2025, OCPA staff assisted in the drafting of an Electricity Affordability Explainer to be utilized when meeting with state legislators. The explainer focuses on three main areas, 1) Leveraging the Greenhouse Gas Reduction Fund (GGRF) to Support Affordability, 2) Reducing ratepayer Costs by Reducing Artificial Resource Adequacy Demand, and 3) Increased Accountability and Transparency. A copy of the Explainer is attached (Attachment 8). Regarding the GGRF, staff advocated for the its use in two ways, one focused on short term bill savings and one on long term bill savings. For the short-term bill savings, the GGRF could be used to boost the California Climate Credit. The use of $650 million in GGRF funding would increase the Climate Credit by approximately $60 per household. For longer-term savings, money from the GGRF could be used to finance policy-driven transmission projects that are approved by CAISO in their Transmission Plan. Another cost-saving measure would be to allow LSEs to trade hourly RA load obligations. It is estimated that this ability would save California ratepayers over $180 million annually. This ability is also being pursued in the regulatory space and is discussed in greater detail below. Lastly, there are several areas where the legislator could increase Accountability and Transparency over the Investor-Owned Utility rates that have the potential to lower customer bills. These include doing an Affordability Analysis for each major policy change the CPUC proposes, audits of IOU Balancing Accounts, enhanced oversight of IOU rate of return, and adequately funding the CPUC and Public Advocates Office.
Regulatory Update
Power Charge Indifference Adjustment Proceeding
On February 11, 2025 the CPUC issued an Order Instituting Rulemaking (OIR) to initiate a new proceeding related to the Power Charge Indifference Adjustment (PCIA). The proceeding will consist of two tracks. The first track will be an expedited track focused on potential modifications to the Market Price Benchmark (MPB). Track two may consider several issues including a review of the revisions to the MPB, consideration of ERRA-specific implementation guidance for RA program changes, changes to Bundled Procurement Plan directions, and consideration of improved PCIA and ERRA mechanisms to reduce rate volatility. The CPUC has identified four objectives of the proceeding:
• Consider and identify reasonable improvements to existing ERRA and PCIA rules, mechanisms, and processes to ensure best practices in utility forecasting and other procurement plan activities;
• Identify ways to mitigate and respond to rate volatility, whether resulting from market conditions or ratemaking constructs;
• Best ensure indifference among bundled and departed customers; • Provide policy guidance to ensure that individual utility forecast ratemaking proceedings function as efficiently and consistently as possible.
Resource Adequacy Slice of Day Obligation Transactability On February 12, 2025 CalCCA, presented at the Resource Adequacy (RA) Track 3 Proposal Workshop a proposal on allowing load serving entities (LSE) to transact RA products in the same units denominated in setting RA requirements; in other words, if RA requirements are set on an hourly basis, some or all products should be transactable on an hourly basis. Allowing this transactability will promote affordability by reducing artificial RA scarcity and thus lowering RA prices, and it will minimize over procurement by allowing LSEs to capture diversity. CalCCA estimated that avoiding purchases of RA through trade can reduce direct RA costs by $180 million per year with $62 million seen by CCAs. They also estimated that an indirect benefit of lowering RA costs by approximately $77 million per year.
Federal Update
While OCPA’s routine operations are not federally funded, there are activities that may occur at the Federal level that may impact the energy market that OCPA participates in, potential grants that OCPA may apply to, and tax incentives that our customers and suppliers may take advantage of. One action the federal government has taken is to issue Executive Orders. Staff have attached a summary of the orders (Attachment 9). The impact of these orders is still being researched.
On January 6, 2025, Aurora Energy Research released a study titled “Impact of reform to clean energy tax credits on investment, jobs, and customer bills” (Attachment 10). In the study they found that the removal of tax credits for wind, solar, and battery deployment would increase residential electricity bills by 10% on average in California. This increase in electricity bills is in addition to slowing the growth of renewables in California and the west and a decrease in jobs.
FISCAL IMPACT
None
ATTACHMENTS
1. Executive Order N-5-24
2. CPUC Response to Executive Order N-5-24
3. CEC Response to Executive Order N-5-24
4. Improving Transmission Financing in California – Berkley Law
5. Wire for Savings – Clean Air Task Force and Net-Zero California
6. SB 540 Fact Sheet
7. Preliminary Day-Ahead Market Impacts Study – California Energy Commission
8. CalCCA Affordability Explainer
9. Federal Executive Orders
10. Impact of reform to clean energy tax credits, jobs, and consumer bills – Aurora Energy Research
EXECUTIVE DEPARTMENT
STATE OF CALIFORNIA
EXECUTIVE ORDER N-5-24
WHEREAS California has responded forcefully to the climate crisis with ambitious plans for a clean energy future-one in which the State will achieve carbon neutrality economywide by 2045, and run on 90% clean electricity by 2035 and 100% clean electricity by 2045; and
WHEREAS clean energy will power more of the daily lives of Californians as we move closer to those goals, from our cars and trucks and trains, to our homes and buildings, to our industrial sector; and
WHEREAS it is essential that electric service remains affordable, reliable, and safe for all Californians during our clean energy transition; and WHEREAS California's over four decades of work to advance appliance and building energy efficiency standards has kept electric bills lower on average in California than many other states, but Californians have seen their electric bills rise in recent years, outpacing the rate of inflation; and WHEREAS Californians' electric rate increases have been driven largely by the cost of some programs added over time, such as the subsidy provided through the legacy Net Energy Metering program for rooftop solar photovoltaic systems; and
WHEREAS electric rate increases have also been driven by historic investments that are critical to reduce wildfire risk and improve the safety and reliability of the electric grid, particularly in the wake of catastrophic wildfires that devastated communities throughout California in recent years and have been exacerbated by the increasing impacts of climate change; and WHEREAS in 2023, I released the Building the Electricity Grid of the Future:
California's Clean Energy Transition Plan to provide a roadmap for keeping electric costs affordable, while effectively managing our energy supply through this transition; and
WHEREAS California regulatory agencies have taken important actions within their authority to advance the cost-effective procurement and deployment of clean energy resources while pursuing opportunities to limit and stabilize costs to Californians, including actions by the California Public Utilities Commission to adjust the Net Energy Metering program subsidies to reflect the growth of the rooftop solar photovoltaic market and the value these systems provide to all customers, and through improved oversight and the imposition of cost controls on private utility expenses; and WHEREAS the critical work of upgrading and expanding the aging electric transmission and distribution infrastructure that makes up our electric grid to meet future demand is well underway - investments that will ultimately increase the base of electricity customers and help address rising electricity rates while growing the State's economy; and
WHEREAS the upcoming legislative session provides a critical opportunity to take decisive action to rein in those costs by ensuring that private electric utilities and State programs alike are prioritizing the most efficient and effective opportunities to meet energy demand with clean energy resources, informed by the analyses required and requested under this Order; and WHEREAS the California Climate Credit, a bill credit funded by California's Cap-and-Trade Program, has helped offset hundreds of dollars of electric and natural gas costs on individual ratepayer bills, totaling over $12 billion since 2014.
NOW, THEREFORE, I, GAVIN NEWSOM, Governor of the State of California, in accordance with the authority vested in me by the State Constitution and statutes of the State of California, do hereby issue the following Order to become effective immediately:
IT IS HEREBY ORDERED THAT:
1. The California Energy Commission is directed to examine all electric ratepayer-funded programs it oversees or administers and to identify any programs, and any other regulations that may be unduly adding to rates, for which the electricity system benefits may not be justified by the costs they impose on electric ratepayers, or whose funding might more appropriately come from a source other than ratepayers. The commission shall report to me by January 1, 2025, the results of its analysis and its recommendations for statutory and/or regulatory changes, including the modification or elimination of any Underperforming or underutilized programs and whether any ratepayer funds in any programs remain unused and can be considered for possible return to ratepayers.
2. The California Public Utilities Commission is requested to examine the benefits and costs to electric ratepayers of programs it oversees and rules and orders it has promulgated pursuant to statutory mandates that may be unduly adding to electric rates, or whose funding might more appropriately come from a source other than ratepayers. The commission is requested to report to me by January 1, 2025, the results of its analysis and its recommendations for modifying or repealing any statute that would reduce costs to electric ratepayers without compromising public health and safety, electric grid reliability, or the achievement of the State's 2045 clean electricity goal and the State's 2045 economywide carbon neutrality goal.
3. The California Public Utilities Commission is requested to take immediate action under existing authorities to modify or sunset any underperforming or underutilized programs or orders whose costs exceed the value and benefits to electric ratepayers. The commission is requested to return any unused funds collected from ratepayers for underperforming programs and utility investments in the form of a bill credit, if it identifies such funds.
4. The California Air Resources Board is directed, and the California Public Utilities Commission is requested, to consult with each other on options to maximize the effectiveness of California's Climate Credit-which returned an average of $71 to electric ratepayers on their utility bills this fall. Options to improve the credit, particularly for low-income Californians, should be reported to me by January 1, 2025.
5. The Office of Energy Infrastructure Safety is directed, and the California Public Utilities Commission is requested, to consult with each other on adjustments to utility wildfire safety oversight processes, procedures, and practices that would yield administrative efficiencies and focus utility investments and activities on cost-effective wildfire mitigation measures that reduce wildfire ignition risk while managing costs to electric ratepayers. Proposals for legislative or regulatory changes should be reported to me by January 1, 2025.
6. The California Public Utilities Commission is requested to pursue, and direct the regulated utilities to pursue, all federal funding opportunities that can help reduce and avoid electric service costs that would otherwise flow into electric ratepayer bills.
IT IS FURTHER ORDERED that, as soon as hereafter possible, this Order be filed in the Office of the Secretary of State and that widespread publicity and notice be given of this Order.
This Order is not intended to, and does not, create any rights or benefits, substantive or procedural, enforceable at law or in equity, against the State of California, its agencies, departments, entities, officers, employees, or any other person.
IN WITNESS WHEREOF I have
hereunto set my hand and caused
the Great Seal of the State of
California to be affixed this 30th day
of October 2024.
f1,,,' , ____________ _
GAVIN NEWSOM
Governor of California
ATTEST:
SHIRLEY WEBER, PH.D.
Secretary of State
CPUC Response to
Executive Order N-5-24
February 18, 2025
Thanks to:
Jenny Au, Simon Baker, Aaron Bloom, Adam Banasiak, Dan Buch, Adam Buchholz, Dan Bout, Tory Francisco, Justin Galle, Brooke-Sydney Harbour, Jenneille Hsu, Coby Jacob, Ankit Jain, Forest Kaser, Kapil Kulkarni, Cheryl Lee, Regina Momblanco, Candace Morey, April Mulqueen, Rachel Peterson, Erica Petrofsky, Bridget Sieren-Smith, Jean Spencer, Jeorge Tagnipes, Leuwam Tesfai, Chris Westling, Nick Zanjani
Contents
PREFACE .................................................................................................... 1 INTRODUCTION: CLEAN ENERGY SUCCESS IS THREATENED BY RATE IMPACTS 3 California’s Climate Goals in the Energy Sector: A Success Made Possible by Utility Ratepayers........................................................................................................... 3 Today’s Electricity Rates Trajectory..................................................................... 6 What is Cost Effectiveness, and How Does it Affect Rates? ............................... 8 SECTION 1 - RESPONSE TO EXECUTIVE ORDER REQUEST TO REVIEW PROGRAMS .............................................................................................. 14 SECTION 2 – RESPONSE TO EXECUTIVE ORDER REQUEST TO CONSIDER WAYS TO IMPROVE THE EFFECTIVENESS OF THE CALIFORNIA CLIMATE CREDIT ...... 19 SECTION 3 - RESPONSE TO EXECUTIVE ORDER REQUEST TO RECOMMEND WAYS TO REDUCE WILDFIRE MITIGATION COSTS......................................... 22 SECTION 4 – RESPONSE TO EXECUTIVE ORDER REQUEST TO PURSUE FEDERAL FUNDING OPPORTUNITIES .......................................................................... 27 APPENDIX ................................................................................................. 28 CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 1
Preface
The California Public Utilities Commission (CPUC) appreciates the opportunity to respond to Governor Newsom’s Executive Order N-5-24. The Governor’s Executive Order sets forth an imperative to mitigate the rising costs of electricity service in California. The CPUC shares this sense of urgency and resolve. In the CPUC’s annual SB 695 Report, the CPUC provides an analysis of rates and forecasts of rate trends, and for several years has taken actions within the CPUC’s authority to mitigate rising costs for ratepayers.
Executive Order N-5-24 requests the CPUC to:
• Examine the benefits and costs to electric ratepayers of programs it oversees and rules and orders it has promulgated pursuant to statutory mandates that may be unduly adding to electric rates, or whose funding might more appropriately come from a source other than ratepayers.
Report to Governor Newsom by January 1, 2025, the results of its analysis and its recommendations for modifying or repealing any statute that would reduce costs to electric ratepayers without compromising public health and safety, electric grid reliability, or the achievement of the State's 2045 clean electricity goal and the State's 2045 economywide carbon neutrality goal.
• Take immediate action under existing authorities to modify or sunset any underperforming or underutilized programs or orders whose costs exceed the value and benefits to electric ratepayers. The commission is requested to return any unused funds collected from ratepayers for underperforming programs and utility investments in the form of a bill credit, if it identifies such funds.
• Consult with California Air Resources Board on options to maximize the effectiveness of California's Climate Credit-which returned an average of $71 to electric ratepayers on their utility bills this fall.
Options to improve the credit, particularly for low-income Californians, should be reported to me by January 1, 2025.
• Consult with the Office of Energy Infrastructure Safety on adjustments to utility wildfire safety oversight processes, procedures, and practices that would yield administrative efficiencies and focus utility investments and activities on cost-effective wildfire mitigation measures that reduce wildfire ignition risk while managing costs to electric ratepayers.
Proposals for legislative or regulatory changes should be reported to me by January 1, 2025.
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 2
• Pursue, and direct the regulated utilities to pursue, all federal funding opportunities that can help reduce and avoid electric service costs that would otherwise flow into electric ratepayer bills.
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 3
Introduction: Affordability and
Clean Energy Success Is
Threatened by Rate Impacts
California’s Climate Goals in the Energy Sector: A Success Made Possible by Utility Ratepayers
California’s climate goals have clean energy as a centerpiece. From 2002 when the state adopted its first Renewables Portfolio Standard (RPS) requirement, utility ratepayers have funded major clean energy achievements. The vision for economywide carbon neutrality is now set forth in the California Air Resources Board’s Climate Change Scoping Plan, and the electricity sector is on track to achieve greenhouse gas emissions reductions to achieve the ambitious goal of carbon neutrality by 2045.
The California Constitution and the Public Utilities Code spell out how utility customers have funded this success. The Legislature directs the CPUC, who in turn directs the retail electricity providers (load serving entities) to purchase utility-scale least-cost, best fit clean electricity resources on behalf of their customers. This structure has resulted in cost-competitive clean energy achievements that lead the world.
All new procurement today is emissions-free. What’s more, prices for solar, wind, and battery storage that are shared among customers on our interconnected bulk system are decreasing every year.
This is the ratepayer funded clean energy success story of California.
At the same time, California’s transportation, buildings and industrial sectors are transitioning away from fossil fuel-supplied energy sources. Electricity is already playing a larger role in powering the economy and addressing the climate crisis demands further expansion of electrification.
However, as the Governor’s Executive Order recognizes, electricity ratepayers are now experiencing rising bills due to a number of factors, including the impacts of climate change, and many Californians are struggling to bear the burden of increased costs.
In this report, the CPUC responds to the Executive Order by putting the costs of these programs in context with the total scale of IOU revenue requirements, describes the mechanisms by which these costs are created and shared between customers, and identifies ways that the Legislature and the CPUC can work to improve affordability.
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 4
Conclusions in This Report: Options Exist to Save Ratepayers Money Going Forward
Inequitable rate structures and the need for unprecedented climate impact related investments have created a perfect storm driving electricity rate increases. In addition to creating financial hardship, continued rate inflation will put stress on meeting the states climate goals. Electrifying the transportation, building and industrial sectors are critical decarbonization strategies that become increasingly difficult with every increase in electricity rates.
Three areas present opportunities to control costs and reduce electricity bills: first, identifying opportunities to control the growth in utility spending. Second, identifying any opportunities for cost sharing. Third, implementing equitable rates to recover approved costs for wildfire mitigation, public purpose programs and the fixed costs of the grid.
The CPUC’s SB 695 report has identified the biggest drivers of rate increases: the growth in spending to address wildfire mitigation and the cost shift that results from legacy Net Energy Metering programs. Secondarily, energization and energy transition related investments in transmission and distribution infrastructure are also putting upward pressure on rates.
This report concludes with strategies that address these costs to save ratepayers money going forward:
1. All energy-related mandates should be assessed for overall cost-effectiveness with the goal of achieving the lowest possible rates for all customers of each utility.
2. Supplement essential wildfire mitigation programs and extreme weather-related catastrophic event response costs with other sources of funding.
3. Identify cost-reduction measures by integrating wildfire mitigation strategies into the existing General Rate Case process.
4. Equitable rate structures: Refine the elements of Net Energy Metering so that all customers share wildfire mitigation, public purpose programs and system costs.
5. Redistribute the Climate Credit to customers most impacted by increasing electricity costs.
6. Fund today’s and future cost-shifting programs from non-ratepayer sources.
7. Ensure that programs benefitting all electric customers are supported by all customers, including customers of publicly-owned utilities.
This report also describes ways in which programs add to overall costs and explains the ratepayer impact of how new programs create and distribute new costs and benefits.
Ratepayer-Funded Programs Have Delivered Benefits in
California and Across the United States
California’s pioneering investments in clean energy technology have had impacts around the world.
Customers of investor-owned utilities are funding programs and tariffs that bring many benefits:
electricity bills have been the vehicle to fund the incubation and commercialization of technologies, CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 5
including photovoltaic solar and battery storage, as well as the means to integrate renewable energy through programs such as time of use rates enabled by investments in advanced metering infrastructure.
Historically, California’s programs have supported every stage of technological development:
• Innovation, through programs like the Electric Program Investment Charge program (EPIC),
• Pilots, like a new program harnessing vehicle-to-grid technology to turn Oakland United School District’s newly electrified school bus fleet into a virtual power plant, and • Deployment at scale, such as competitively bid generation projects through the Renewables Portfolio Standard.
These investments continue today through innovation with next-generation smart meters, microgrid technology, smart homes, generation that is increasingly disaggregated, and mechanisms to procure new renewable generation technologies like offshore wind.
As we move through the Innovation, Pilot, and Deployment process, we need to constantly evaluate whether the programs are succeeding on their own terms and whether their benefits outweigh their costs. In addition, the CPUC needs to be constantly evaluating the opportunity costs of the decisions to fund one approach over another. This is especially true of well-established areas like energy efficiency.
For some of these investments, all utility customers are sharing the incremental cost of programs that provide higher-cost individual benefits to a select group of customers or to private industry.
Socializing investments can provide substantial benefits, such as helping certain small companies enter the renewable energy industry, providing energy efficiency or distributed energy resources to a group of low-income households, or improving plumbing and ventilation in public schools. These programs can bring important benefits and can avoid certain other costs. However, unless there is a non-utility source of funding, the costs of these investments are divided among all customers, and bill savings for one customer necessarily increases costs for everyone else.
The Nature of Electricity Necessitates Infrastructure Sized to Meet Highest Potential Demand
Unlike commodities such as water, natural gas or gasoline, electricity does not persist if it is not used or stored after it is generated.
Considerable efforts are being made to put excess grid energy to work: batteries use electricity for charging, pumped storage facilities use electricity to move water to generate electricity later, time of use rates encourage customers to shift their energy use to daytime when solar energy is plentiful, and electric vehicles and buildings are a growing source of demand.
Electricity generators are generally compensated through contractual commitments to purchase energy or tariffs, and some are further compensated for the guarantee that they will be ready to serve CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
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demand whenever needed. Likewise, the grid is built to efficiently share electricity generation but must also be sized to meet the highest potential demand. Accordingly, using less energy does not always result in cost savings. While guaranteed load reduction measures are increasingly valuable at times of high usage, at other times, more load can mean lower rates.
One key to future cost reduction is increased electricity consumption from buildings and transportation electrification and other new loads, combined with flexible load measures that are targeted, predictable and controllable for system needs. This can bring relief to all customers: when existing infrastructure is used more efficiently and the same fixed costs are spread across a greater volume of electricity provided, customers’ total energy costs can be reduced, and climate change action can be achieved at least cost.
Today’s Electricity Rates Trajectory
As the CPUC has detailed in its annual rates report,1 today’s rate increases are not driven by prices of contracts for new renewable energy generation.
Broadly, ratepayer bills are rising because of: wildfire risk reduction surrounding utility infrastructure, inequitable rate structures, programs that require energy procurement that is not needed or is not competitively priced, and programs that provide bill reductions or discounts to one group of ratepayers, thus leaving other customers with a larger share of overall costs.
In 2024, ratepayers of the three largest electric utilities paid a collective $54 billion in rates for the cost of utility services and investments.
2 While the CPUC looks for every opportunity to distribute costs fairly, collecting revenue through rates is inherently regressive: low-income Californians pay a higher share of their income for utility bills than higher-income Californians. 3 Distributing Costs and Benefits Fairly Is Key to Affordability The electric system is large and dynamic, and numerous programs distribute the costs and benefits of it differently – and so distributing costs and benefits fairly is essential to affordability.
In a variety of policy decisions, the CPUC seeks to distribute costs progressively and aid California families who most need help reducing their utility bills. The CPUC also seeks to measure programs using cost-effectiveness tools that are continuously vetted by stakeholders. However, rising costs 1 See the 2024 SB 695 Report or the 2024 Padilla report. 2 This includes a $12 billion proxy estimate for CCA generation costs, and subtracts the impact of the climate credit. 3 Severin Borenstein, Meredith Fowlie, and James Sallee “Paying for Electricity in California: How Residential Rate Design Impacts Equity and Electrification” (September 2022). Paying for Electricity in California.
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for the system and operations as well as requirements and programs beyond core utility services are causing electricity rates to increase significantly in recent years.
Many of these programs have benefits as well. The question presented by Executive Order N-5-24 is whether costs can be reduced and whether costs and benefits are being distributed in ways most fair to all customers, and in ways that enable California to achieve its clean energy and electrification goals.
The CPUC Has Taken Actions to Mitigate Rising Rates
As the CPUC has recognized in its annual SB 695 reports, 4 electricity rates for customers of
California’s electric IOUs have been projected to increase faster than inflation. As the economic regulator of the state’s IOUs, the CPUC limits approvals to necessary costs and identifies cost saving measures wherever they can be found.
The CPUC’s adopted monthly flat rate of $24.15 for those who can pay and $12 per month for low-income customers reflects a positive shift toward more equitable ratemaking practices and movement away from regressive cost collection. The flat rate requires all customers to pay the same amount for a portion of utility costs that do not vary with volume of usage and gives low-income households a discount. It is a more progressive method to allocate costs than per-unit charges. More CPUC actions designed to decrease bills for ratepayers as a whole with a focus on equity are described in the appendix.
The Impact of Legacy Contracts
After California legislation required its IOUs to divest generation assets, long-term clean energy contracts have been essential to meeting reliability needs while supporting emerging clean energy technologies. Such contracts, however, can also lead to long-term costs for ratepayers, particularly when they create ongoing financial commitments like contractual obligations or tariffs that extend benefits to electricity generators over time.
One example of an ongoing cost is legacy renewable energy contracts signed more than a decade ago. Load serving entities are required to procure sufficient energy to serve their customers long before it is needed, which is essential for reliability and for hedging against market volatility. Legacy contracts thus deliver benefits, and also impact ratepayers: in 2024, ratepayers paid an estimated $1.2 billion more than they would pay today for RPS contracts signed between the years 2000 and 2016.5
4 See the 2024 SB 695 Report.
5 This estimate includes all RPS contracts signed between 2000 and 2016. This includes Qualifying Facility Standard Offer, ReMAT, BioMAT, and BioRAM. BioMat and BioRAM incurred an estimated $25 million in above-market costs, and ReMAT cost ratepayers approximately $5.4 million.
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The CPUC has required utilities to renegotiate lower, market-competitive prices for these contracts when they are up for renewal, but above-market contracts persist.
These legacy contracts, together with other legacy costs, also have the unintended effect of creating a cost-savings value stream for any customer who can independently procure or self-generate electricity and thus off-set higher volumetric charges for energy, while still using the grid. In doing so, these customers avoid legacy and other fixed costs, and necessarily shift costs to other customers.
Many Investor-Owned Utility Programs are Mandated by State Laws
As stated in this report, most electricity programs could be funded through non-ratepayer funds.
This would shift costs away from customers.
The Legislature can also take statutory action to repeal or significantly revise mandated electricity programs that result in ratepayer costs that are higher than necessary for safe, reliable, clean electricity.
What is Cost Effectiveness, and How Does it Affect Rates? When a utility program has costs, rates rise, since those costs are paid on ratepayer bills. Some programs also reduce costs that are borne by ratepayers, but unless these reductions fully offset the costs, ratepayers will experience a rate increase. This section explains why.
Every Utility Program Carries Operational and/or Fixed Costs In California, as in nearly every state, Investor-Owned Utilities (IOUs) collect operational costs on a “cost of service” model: IOUs are permitted to collect all the costs of providing electricity service to customers. The IOUs’ operations are a straight pass-through of costs. Utilities do not earn a profit on these costs.
When IOUs invest in infrastructure – substations, transmission, distribution lines, metering infrastructure, and more – they earn a return on these investments, known as their “authorized rate of return,” or profit. The capital invested by the utility plus a rate of return are paid back over time by all customers.
Each year, the total amount of a utility’s operational costs and an amortized portion of capital investments is divided up among all customers of the utility and allocated for collection largely according to the amount of electricity used. An electrical bill may also include electricity generation costs charged by a non-utility load serving entity such as a Community Choice Aggregator or an Electric Service Provider.
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Together, operational and capital costs include every single utility program. Again, under the structure of the Legislature, the CPUC, and the utilities, every program that the Legislature directs the CPUC to implement via the utilities is either an operational cost, a capital cost, or both, and is paid for by ratepayers. Figure 1 summarizes the 2024 revenue requirement for the three large electric IOUs.
Figure 1. The combined 2024 electric revenue requirement for PG&E, SCE, and SDG&E, after subtracting the California Climate Credit. This estimate uses IOU generation costs as a proxy for Community Choice Aggregator generation costs. The majority of these costs must be paid to the utilities, regardless of electric sales. 2025’s revenue requirement is projected to be approximately 5- 9% higher than 2024’s.
The Capital Costs of the System Are Long-Term Investments That Support Numerous Goals
Capital costs include the physical infrastructure needed to deliver electricity to customers. Much of the recent increase in distribution and transmission costs are upgrades to improve system safety and reliability. This system must be built to meet peak system demand, and costs are not reduced if the 0 10
20 30
40 50
60 Revenue Requirement ($ Billions)
Breakout of ~$54B 2024 Electric Revenue
Requirement
Other
Public Purpose Programs
Transmission
Distribution
Generation
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CALIFORNIA PUBLIC UTILITIES COMMISSION 10
system is used less at certain times of the day on certain days of the year. Long-term investments in the system make the system stronger, more resilient and better able to facilitate electrification of end uses, but they are also sunk costs that must be repaid, and therefore limit California’s options to reduce rates.
Under the Current Cost Allocation Structure, Some Customers Pay Less Operational and Fixed Costs While the Majority of Customers Pay More
Under the current cost allocation structure, some advantaged customers pay less than their share of operational and capital costs while disadvantaged customers pay more than their share of both, especially because more advantaged customers have benefitted from the NEM subsidies paid by all other customers. This is partially caused by a policy that eliminates the connection between the revenue an electric utility collects and the amount of energy they sell.
Observers often believe that utilities are seeking to sell more electricity to customers. This is an inaccurate viewpoint. Utilities are indifferent to how much electricity they sell to customers, because of an important energy policy that California adopted in the 1990s that breaks apart electricity sales from utility budgets. Numerous states have followed California’s pathbreaking approach, and it has been foundational to the success of programs like energy efficiency and net energy metering. This “decoupled” approach means that if a utility sells more or less electricity in one year, any revenue over-collection or shortfall will either be returned to customers (in the case of over-collection) or collected (in the case of shortfall) the next year. Utilities’ revenues are not linked to the amount of electricity they sell, so they have no incentive to sell more or less electricity to any group of customers or to ratepayers as a whole.
Because most operational and capital costs are fixed in advance and allocated on an annual basis, any program that provides rate relief for one customer group results in a shift of operational and fixed costs to another. The second group gets a rate increase, while the first group gets a rate or bill decrease. Figure 2 demonstrates the shifting of such costs from participants in such a program to non-participants. Electricity costs for the customers who don’t receive the exemption can rise dramatically – an effect we are seeing today.
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Figure 2. Animation showing the impact on customers who are not participating (blue) in a program, such as NEM 1 and 2, that allows other customers (grey) to reduce their contributions to direct costs. As fewer customers contribute to direct costs, the rest of customers pay higher rates to compensate. This figure is illustrative and does not reflect exact costs of any particular program. To view the animation, open this document in the desktop version Adobe, click on the graphic and “trust” the document.
This happens for a few reasons:
• In the short term, the cost of the entire physical electric system doesn’t drop when less electricity is sold. As a result, allowing some customers to not pay for their share of fixed costs moves their share onto everyone else. Some programs may reduce costs in the long term, but only if they directly address the drivers of fixed costs. • Numerous programs mandated by the Legislature require customers to pay for expensive electricity that would not be able to compete in market-based requests for offers. When utilities, CCAs, or Energy Service Providers are required to compensate generators for expensive electricity, such as for exports from rooftop solar under the Net Energy Metering Tariff, the customers who purchase less electricity overall are purchasing less of the expensive commodity, too. And in turn, the remaining customers who cannot reduce their electricity purchases are paying for a greater share of the more expensive electricity.
In general, the customers who are purchasing less electricity are those who own their homes and can afford to buy or lease rooftop solar panels and in-home battery storage. On that basis, we know that advantaged customers are paying less fixed and operational costs while disadvantaged customers are paying more.
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Net Energy Metering
Net Energy Metering (NEM) program costs are one of the largest contributors to rising electricity rates for customers that do not have rooftop solar. According to the Public Advocates Office, the NEM program’s and the Net Billing Tariff’s (NBT) combined $8.5 billion cost shift constitutes 21- 27% of the average non-participating customer’s bill.
The NEM 1.0 and NEM 2.0 programs increase electricity bills in two ways: (1) customers pay for the generation that is exported to the grid from another customer’s NEM system at a higher rate than other available generation, and (2) customers pay for the part of bill savings experienced by NEM customers because the program allows rooftop customers to bypass their share of direct costs to maintain the electric grid, which other customers without rooftop solar end up paying (see figure 2, above).
IOU customers without rooftop solar are paying NEM customers for the generation they send to the electric grid at a rate that exceeds the cost of generation otherwise available from the grid. NEM
1.0 and NEM 2.0 customers are compensated for electricity exported to the grid at the retail volumetric rate, which exceeds the marginal cost of avoided wholesale generation purchased for that customer. IOU customers without rooftop solar pay this increased cost to NEM customers for 20 years after their grid interconnection dates.
Distributed energy resources, including batteries, electric vehicles, and heat pumps, are a part of California’s overall electricity future, and new policies are helping to send improved price signals to these resources so that they can best support electric grid needs. From April 2023 on, new rooftop solar customers—will receive compensation through the new Net Billing Tariff (NBT), which provides compensation that is more aligned with the value of the generation the systems provide to other customers. It also includes more generous subsidies for systems with battery storage compared to rooftop solar. This cost increase, however, is not fully mitigated by the new Net Billing Tariff (NBT): NEM 2 customers who switch to the NBT can create a cost shift that is 76-82% as high as their cost shift under NEM 2.
Cost Effectiveness Approaches
Cost effectiveness is a heavily contested concept. Two approaches have the most direct relevance to rates:6 the Ratepayer Impact Measure, which identifies the extent to which savings for one customer shifts costs to another, and the Total Resource Cost test, which measures financial costs and benefits to all ratepayers and the utility. Both tests measure exclusively monetary costs, and do not 6 There are two additional tests described in the CPUC’s Standard Practice Manual: the Participant Cost Test, which measures whether a program is financially beneficial to participants, and the Program Administrator Test, which measures costs and benefits to the utility or entity administering the program. The Societal Cost Test measures costs and benefits to society and was recently adopted to use on an informational basis by the CPUC in D.24-07-015.
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include non-monetary benefits and costs such as the societal cost of carbon and health or safety benefits.
Generally, when a program’s financial benefits to ratepayers outweigh its costs, it will have a Total Resource Cost effectiveness score over 1.0 and it will lower total system costs relative to other resources. Conversely, a score below 1 indicates that a program will raise total system costs relative to the alternative. A score below 1.0 on the Ratepayer Impact Measure indicates that the program raises rates by creating more costs for non-participating customer than it saves for the grid as a whole.
In the time available to prepare this report, the CPUC has not carried out a comprehensive cost effectiveness review of all programs under its purview. In many cases, the statute directing the CPUC to establish the program does not require that the program be cost effective. When the CPUC examines cost effectiveness of an electricity program, it is typically conducted within CPUC proceedings, during which dozens of stakeholders litigate the analysis and results.
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Section 1 - Response to Executive Order
Request to Review Programs
Figure 3 shows the contribution to rates of programs funded through electric IOU revenues. Note that this figure conflates the cost shifting (indicated by textured wedges) visualized in Figure 2 with direct costs like the expense of purchasing energy from biomass incinerators in the BioMAT and NEM 1, 2, and NBT
(Not C-E)
ESA (Not C-E)
Programs without C-E
Scores
CARE/FERA (No Score)
Demand Response
Energy Efficiency
Wildfire Mitigation
All Remaining
Revenue Requirement
(Transmission,
Distribution,
Generation, O&M, etc)
Above-Market Costs of
Legacy IOU RPS Contracts
Uncollectibles
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BioRAM programs. The chart is best understood to show the potential impacts on IOU electric revenue collections (and therefore system average rates) if programs were funded outside of electric rates. Eliminating programs whose primary rate impact is through cost shifting would affect which customers pay certain costs, but would have virtually no direct impact on average bills. For example, repealing and eliminating California Alternate Rates for Energy (CARE) would dramatically increase costs for the most vulnerable ratepayers and lower costs for wealthier ratepayers, commercial customers, and industrial customers. 7 It would not impact average bills
because savings for one group translate directly into costs for another.
Because each customer class (residential, commercial, industrial) contributes different amounts to each program and cost shift, class-specific impacts would vary from the amount shown in the pie chart. For example, Net Energy Metering and the Net Billing Tariff primarily shift costs within the residential class: funding the cost shift from an outside source would create significantly greater than
15.6% savings for non-participating residential customers.
A full list of programs with their approximate annual costs can be found in the Appendix.
What All of This Means: Opportunities to Cut Rates Today and For the Future
There are opportunities to cut rates today, which will promote affordability. Finding ways to save ratepayers money is essential. The CPUC’s analysis shows the following:
1. For context, in 2024 electric ratepayers will pay approximately $54 billion in rates to the three large IOUs and to community choice aggregators. In 2025, revenue requirements are projected to increase an estimated 5-9%.
8 2. From 2019 to 2024, the IOUs collected approximately $24 billion in wildfire mitigation and insurance premium costs.9
3. While the vast majority of industrial, commercial, and residential customers do not have solar panels, the California Public Advocates Office estimates that they will pay approximately $8.5 billion in 2024 for the 15% of customers who do, under the NEM 1, 7 Approximately three quarters of the CARE subsidy is paid for by non-residential customers. If there were no CARE program, average rates within the residential class would rise: CARE customers would pay approximately $1.9 billion more, while non-CARE residential customers would only save approximately $500 million. 8 This estimate uses IOU generation costs as a proxy for CCA generation costs, and subtracts the impact of the California Climate Credit. The overall increase in revenue requirement depends on the result of pending proceedings. 9 Approximately $18 billion was placed into revenue requirements through 2023. See 2024 SB 695 Report, p. 53. At the time of this report’s drafting, 2024 costs were estimated to be approximately $6 Billion.
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NEM 2, and NBT tariff programs. The Public Advocates office estimates that this cost shift represents 21-27% of residential bills.10
4. The flagship low-income discount programs, California Alternate Rates for Energy (CARE) and Family Electric Rates for Energy (FERA) shift approximately $1.75 Billion to non-participating customers. Nearly three quarters of these costs are paid by non-residential customers.
5. The remaining electricity programs that the CPUC orders the IOUs to carry out based on mandates from the Legislature total approximately $2 to $2.5 billion per year. Half of this amount is spent on programs demonstrated to be cost-effective. The remaining half is spent on programs that have benefits and costs, but have not been reviewed for cost-effectiveness.
Based on the above facts, the following are potential principles for consideration. These require statutory changes, budget from another source, or other methods of implementation:
1. Fund the NEM and NBT Cost Shift From Non-Ratepayer Sources: Achieve a rate drop in 2025 of approximately 15.6% systemwide11 by funding $8.5 billion for NEM 1, NEM 2, and NBT customers from non-ratepayer sources. Sustain the rate drop through a commitment to steadily increase the allocation as the number of NBT customers, and the associated cost shift, grows.12
2. Reduce the NEM and NBT Cost Shift: the cost shift created by NEM 1, 2, and the NBT could be reduced by:
a. Shorten legacy periods: almost all NEM 1 and 2 customers have more than 10 years before they will be defaulted onto the NBT. Nearly half have 15 or more years of this legacy period remaining. By reducing the legacy period from 20 years, NEM 1 and 2 customers could be defaulted onto the Net Billing Tariff sooner. This would save non-participants billions of dollars.
b. Tie compensation for excess generation from solar systems to rates in effect when NEM customers interconnected: Because NEM customers receive retail rates for any excess electricity that passes through their meter, the amount paid by non-NEM customers for this excess energy is increasing over time as rates rise.
Tying compensation for excess generation to the rates in effect when a NEM or NBT customer signed up for the tariff would mitigate the increase in cost shifts. c. Establish a Grid Benefits Charge for NEM and NBT customers: Solar customers use the grid to import and export energy, but a large portion of their 10 Per the Public Advocates Office. 240822 Public Advocates Office 2024 NEM Cost Shift Fact Sheet. 11 Per the Public Advocates Office, the NEM 1, 2, and NBT cost shift totals $8.5 billion in 2024. 240822 Public Advocates Office 2024 NEM Cost Shift Fact Sheet.
12 While the NBT is an improvement over NEM 1 and 2, it does not eliminate the cost shift. NEM 1 and 2 customers have a 20-year legacy period, and the majority connected within the last 5 years. If volumetric electric rates continue to increase, the cost shift from these customers will continue to grow.
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existing share of system costs is necessarily moved to other customers’ bills when their systems are installed. A monthly charge for NEM and NBT customers would help to reduce the amount that shifts from NEM customer bills to non-NEM customer bills.
d. Tying legacy periods to the customer, not the system: currently, the 20-year legacy period before which NEM 1 and 2 customers are defaulted onto the NBT is linked to the installed system, not the customer. Systems could be converted to the NBT when the home changes ownership or at the end of the legacy period, whichever is sooner, rather than only when the system reaches the end of its legacy period.
3. Use Stable Non-Ratepayer Funds to Increase the CARE and FERA Discount:
Because fixed costs are high and will remain so for the foreseeable future, a stable source of non-ratepayer funding can be used for a larger direct subsidy to low-income Californians on their electricity bills.
4. Fund Other Programs From a Non-Ratepayer Source: Achieve a rate drop of up to approximately 2.3% starting in 2027 through statutory changes in 2025 that fund programs without cost-effectiveness scores from non-ratepayer sources. These programs also provide benefits - repealing them entirely would produce ongoing savings significantly lower than
2.3%, by also eliminating any benefits they provide.
5. Fund Any Future Cost-Shifting Programs from Non-Ratepayer Sources: Future programs that give exemptions to certain customer groups should be allocated funding from non-ratepayer sources so that other customer groups do not pay for them.
6. Use Existing Review Processes of Utility Spending: The existing General Rate Case (GRC) process is often the best way to ensure that all costs are reasonable and cost-effective, particularly in wildfire-related areas. New programmatic mandates should be evaluated through the GRC instead of standalone applications, such as those to collect costs tracked in memorandum accounts.
7. If a Program Benefits all Electric Customers, All Electric Customers Should Contribute: Any program funded by electric ratepayers for the benefit of all of California should be paid for by all electric customers, including the customers of publicly owned utilities.
8. Prioritize the Needs of Ratepayers: All energy-related mandates should be assessed for overall cost-effectiveness with the goal of achieving lowest possible rates for all customers of each utility. In addition, statutes ordering the CPUC to prioritize a specific industry’s needs, the needs of a specific customer group, or other needs beyond the delivery of safe, reliable and clean energy13 over the needs of all ratepayers are likely to increase costs. 13 For example, SB 1090 requires ratepayers to reimburse $85 million in lost local government tax revenue due to the closure of Diablo Canyon Nuclear Plant and pay $128 million in employee retention funding beyond what the CPUC approved. These priorities contribute to increases in PG&E customer bills.
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Actions to Be Taken Under the CPUC’s Authority
The following are examples of actions the CPUC could take to reduce ratepayer costs:
1. Open an Energy Efficiency Rulemaking: The CPUC plans to open a new rulemaking on energy efficiency in 2025. It will include a focus on cost effectiveness.
2. Move toward incorporating a greater share of ratepayer costs into General Rate Cases for holistic review and decision-making.
3. Evaluate new programs for cost-effectiveness where appropriate. Identify statutory barriers to implementing cost effectiveness tests on mandated programs.
4. Improve risk-informed spending by continuing efforts in the Risk-Based Decisionmaking Framework proceeding, directing the utilities to provide better and more consistent information about how they incorporate risk into their GRC funding requests.
5. Consider reprioritizing transportation electrification spending by focusing on critical grid investments and pausing $1 billion in new ratepayer charges previously authorized in the Transportation Electrification Framework decision.
6. Approve lower-cost wildfire risk mitigation methods where appropriate.
7. Identify programs meeting the following criteria:
a. Programs that require ratepayers to purchase energy from specific generation types that are not competitive with alternative RPS-eligible resources.14 Removal of costs from rates may require legislative action.
b. Programs that are underutilitized and could return funds to ratepayers.
8. Continually improve the efficiency of the CPUC’s administrative processes. 14 Above-market mandated procurement can occur through tariffs or non-competitively bid contracts.
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Section 2 – Response to Executive
Order Request to Consider Ways
to Improve the Effectiveness of
the California Climate Credit
The California Climate Credit is a twice-per-year bill credit automatically provided to all residential and certain qualifying small businesses. Qualifying energy intensive trade-exposed (“EITE”) industrial customers also receive the California Industry Assistance credit. The funds originate from the California Cap-and-Trade Program, which requires power plants, fuel providers, and large industrial facilities that emit greenhouse gases to turn in for compliance carbon pollution allowances equal to their greenhouse gas emissions.
The credit is designed to help utility customers during the transition to a low-carbon future by sharing proceeds from the sale of allowances with customers. In 2025, the residential climate credit will total $1.39 billion (an average of $120 per customer), with another $117 million for small businesses and $104 million for EITE industrial customers.
As noted in this report, the burden of high rates does not affect all customers evenly. Pursuant to Executive Order N-5-24, this section explores several potential approaches to maximize the effectiveness of these funds.
The minimal administrative cost is a particular strength of the identified approaches.
Allocating the Climate Credit to Specific Customer Groups Currently, every residential customer receives a credit on their bill twice per year as their share of the proceeds from California’s cap and trade program. In 2025, more than 11.6 million customer accounts will receive an average of $120.
The Climate Credit presents a significant equity opportunity for California. The Climate Credit could be reallocated to customers who need it the most: first, to all customers who receive the CARE benefit, and second, all customers without rooftop solar who are paying for those who have it.
The potential bill credits under three possible alternative approaches are outlined in the table below:
allocating the climate credit exclusively to CARE customer accounts, and allocating it to all non- CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
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NEM 1.0, 2.0, and Net Billing Tariff accounts, and allocating it to non-NEM/NBT CARE and FERA customers, along with non-NEM/NBT customers in the hottest climate zones.
Additionally, funding from other sources could be added to the climate credit, increasing the customer benefits shown below.
Allocation
Total Residential
Climate Credit,
2025
Estimated Total
Benefiting
Accounts
Resulting Bill
Credit
All Customer
Accounts (status
quo)
$1.39 Billion 11.6 million $120
CARE and FERA
Customer
Accounts only
$1.39 Billion 3.1 million $454
Non-NEM 1.0,
2.0, or NBT
Customer
Accounts
$1.39 Billion 9.9 million $142
Non-NEM/NBT
CARE, FERA,
and Customers in
Hottest Climate
Zones
$44515
15 “Reallocating the Residential California Climate Credit to Low-Income Customers.” Dollar value may not be directly comparable to others in this table because the workpaper may have used different assumptions.
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Volumetric Distribution of Climate Credit
Currently, the Climate Credit is given twice per year in a lump sum. It could be allocated on the basis of usage, reducing the volumetric rate for electricity. While this would not reduce total annual bills, it could potentially make electrification more appealing to ratepayers. It would also reduce month-to-month bill volatility, easing ups and downs of utility bills for many Californians. Any change from a non-volumetric to volumetric return of the climate credit must be reflected in the Cap-and-Trade Regulation.
Rate Reduction if $1.4B
Residential Credit were Allocated
Volumetrically
$0.023/kWh
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Section 3 - Response to Executive
Order Request to Recommend
Ways to Reduce Wildfire
Mitigation Costs
This section is the joint response of the Office of Energy Infrastructure Safety and the CPUC in accordance with Paragraph 5 of Executive Oder N-5-24.
Background
Wildfire represents the single most significant financial and safety risk for California’s investor-owned electrical utilities. California is experiencing compounding impacts of climate change, as wildfires become larger, more intense, and harder to contain than ever before. Because wildfire represents such a considerable risk, utilities are required to prepare Wildfire Mitigation Plans (WMPs) describing their strategies for reducing wildfire risk for review and approval by the Office of Energy Infrastructure Safety (Energy Safety). As noted above, between 2019 and 2024, IOUs collected approximately $24 billion from ratepayers to pay for wildfire mitigation costs and insurance premiums.
16 The WMPs have dramatically improved the way electrical utilities in California understand and reduce the risk of utility-caused wildfire. However, the cost of implementing these plans has resulted in associated wildfire mitigation-related rate pressures.
Wildfire Risk Mitigation Will Continue to Contribute to Electricity Rate Increases
Ignition risk associated with electric lines can be reduced through a variety of approaches including vegetation management, grid hardening, replacing uninsulated lines with covered conductors, and undergrounding.
• Undergrounding: moving above-ground lines beneath the surface. 16 Approximately $18 billion was collected through 2023. See 2024 SB 695 Report, p. 53. At the time of this report’s drafting, 2024 costs were estimated to be approximately $6 Billion.
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• Covered Conductor: replacing wires with heavily insulated alternatives that are far less likely to spark than traditional wires.
• Other Grid Hardening and Grid Design: can include replacing wooden poles with fire-resistant materials, replacement or strengthening of infrastructure, segmentation of lines to allow isolation of faults, or adding sensors to cut power when electric faults are detected. • Vegetation Management: Removing and trimming trees and other vegetation around electrical lines and equipment to reduce the risk of vegetation coming into contact with power lines and reducing the amount of dry vegetation close to electrical equipment.
While each approach reduces wildfire risk to varying degrees, undergrounding raises rates the most and takes the longest to implement. Although undergrounding costs are hard to estimate and vary dramatically because of many factors, including topography, estimates show that undergrounding every IOU distribution line in high fire threat areas could cost an estimated $92-224 billion.
Undergrounding transmission would be significantly more costly. In contrast, installing covered conductor would cost approximately one-fourth as much.
17 Of the four approaches, undergrounding is in certain locations the most effective option, and is therefore an essential tool in utility efforts to reduce wildfire risk. SB 884 facilitates longer-term utility infrastructure undergrounding investments, but does not provide a source of funding for this work other than increases in customer bills.
No matter the approach, the costs associated with hardening the electric grid to reduce the risk of utility-ignited wildfires are borne by ratepayers through increases in electricity rates. The most effective way to reduce the electricity bill impact is to fund these investments from a source other than ratepayers.
Consolidating and Streamlining Utility Funding Requests Will Provide Some Relief
These rate pressures may be reduced through increased transparency and improved coordination of cost approval processes, electric underground infrastructure construction, and fuel treatment efforts.
Currently, electrical utilities request wildfire mitigation funding through multiple mechanisms at the CPUC, including GRCs, memorandum accounts for the recovery of WMP costs, and, prospectively, additional applications for large electrical undergrounding plans. The multiple streams of funding for 17 Depending on the IOU, undergrounding distribution lines costs $2.3-$5.6 million per mile, while transmission undergrounding is significantly more expensive: the Tehachapi Renewable Transmission Project cost $139 million (in 2025 dollars) per mile to underground. Covered conductor costs $770,000 - $1.35 million per mile. There are approximately 40,000 miles of above-ground IOU distribution lines in California’s High Fire Threat Districts. Per-mile costs are drawn from recent IOU filings and CPUC decisions. This calculation is highly uncertain.
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wildfire mitigation decrease transparency, complicate oversight, and reduce accountability, leading to increased rates.
The CPUC’s GRC process is the most transparent available process and requires the highest levels of cost justification. The GRC allows parties to the proceeding to scrutinize proposed spending forecasts and present evidence in support of lower or higher amounts than those proposed by the electrical utilities. Based on the evidence presented, the CPUC ultimately prospectively approves a fixed amount of funding utilities may recover from ratepayers each year of the four-year GRC cycle.
In the case of costs required to implement WMPs, the CPUC is required to allow the utilities to track and record additional costs, above approved GRC forecasts, and seek cost recovery from ratepayers for these expenditures.
Solutions Requiring Legislation
Integrating Wildfire Mitigation Plans into Utility General Rate Cases
The implementation measures included in Wildfire Mitigation Plans (WMPs) are not currently subject to the coordinated cost review and evaluation that other utility programs and investments receive. This may unnecessarily drive costs up and decrease transparency of wildfire-related spending. Applications to recover many of these costs are often filed after the work is completed and involve lengthy, contentious proceedings to evaluate potential overlap with GRC approvals and after-the-fact reasonableness of expenditures. The time delay increases debt carrying costs that must be paid by ratepayers.
The Public Utilities Code could be amended to require utilities to integrate WMP costs into the normal planning and budgeting process (their GRC) instead of treating it as a stand-alone activity.
While the CPUC could still authorize utilities to track and recover WMP implementation costs that exceed GRC-authorized amounts, utilities would need to include their entire forecasted amounts in GRC applications. This modification would reduce ratepayer costs by allowing CPUC review of planned expenditures before work is completed and help ensure that utilities choose the most cost-effective mitigations.
The aim of the alignment would be to increase administrative efficiency by reducing the rate at which utilities prepare comprehensive wildfire mitigation plans from once every three years to once every four years. While the WMP process to date has successfully driven electrical utilities to rapidly improve how they understand and address wildfire risk, utilities have matured to the point where they can be expected to incorporate their wildfire mitigation planning into the GRC process.
Synchronizing WMP planning with planning for other spending, along with additional procedural changes, would improve clarity and reduce redundancy in the Energy Safety and CPUC review processes. The elimination of more than a dozen CPUC resolutions ratifying WMPs every year CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 25
would lead to significant reductions in planning, preparation, review, and litigation expenses for the CPUC, Energy Safety, and utilities.
Finally, this proposal would improve utilities’ certainty as to what wildfire mitigation activities must be completed as well as the associated approved budgets thereby avoiding complex factual determinations around the reasonableness of utility incremental spending over GRC approvals.
These changes would largely mirror those proposed in SB 1003 (Dodd, as amended August 28) during the 2023-2024 legislative session. Energy Safety would continue to review and approve or deny WMPs while the revenue approval remains with the CPUC.
This alignment would build on lessons learned from the past five years and prepare California for the next phase of utility wildfire risk reduction. It would also preserve successful features of the current oversight model:
o The reforms keep the focus on mitigating utility wildfire risk. Energy Safety will continue to set requirements and evaluate the quality of WMPs.
o Every year, Energy Safety would assess utility implementation of WMPs and provide feedback to utilities and CPUC.
o Every year, utilities would continue to apply for certification from Energy Safety based on enumerated statutory criteria rooted in proactive investments in safety. By meeting these criteria, the utilities demonstrate their commitment to safety culture, safety based executive compensation, transparent reporting, and continued maturity in their planning efforts. In return, they can be entitled to a presumption of reasonable action in a proceeding before the CPUC to recover costs in the event of a utility related wildfire. o The CPUC would evaluate and approve wildfire spending costs with attention to cost effectiveness.
o The CPUC would still have authority penalize utilities who do not implement their WMPs.
Reducing the Construction Costs of Burying Electric Utilities When undergrounding their facilities, electrical utilities do not consistently receive information on the location of other utilities’ underground infrastructure until two days before excavation begins. Therefore, contractors installing electric infrastructure are often required to make costly changes during construction to account for previously unknown existing underground facilities, driving up the cost of constructing new underground facilities.
These challenges could be addressed by legislation authorizing Energy Safety’s Underground Safety Board to determine how utilities must provide buried facility records to electrical and other utilities during the project planning and design phases. This would be accomplished through processes used by existing 811 underground service alert notification centers. Energy Safety’s Underground Safety CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 26
Board would need the authority to develop regulations requiring contractors who submit a significant number of 811 tickets to provide advance notice to utility operators in the affected area.
This advance notice, which could be integrated into the 811 design process, would enable utility operators to more effectively plan for large-scale projects. This process could also be used to facilitate early Tribal notification of pending excavation activities.
Solutions Actionable on Existing Authority
Energy Safety: Better Fuels Treatment Coordination Between Electrical Utilities and Large Landowners
Electrical utilities generally plan wildfire mitigation activities independently of the extensive coordinated wildfire mitigation work occurring throughout the state. WMP initiatives activities can be costly to plan and implement as stand-alone small-scale projects and are often too limited in scale to protect electric companies' assets from wildland fires. Energy Safety could leverage its existing participation in various wildfire mitigation boards and task forces, along with its relationships with the electrical utilities, to facilitate broader coordination and integrated wildfire mitigation projects between public and private partners.
Coordination of fuel management treatment design, permitting, and environmental review work produces savings for land managers and electrical utilities. Stewardship agreements could allow multiple entities to hire a single contractor to conduct the forest fuel reduction treatments across a broader geographical area.
As an example, the 6,400-acre Liberty Utilities Resilience Corridors Project—coordinated with the U. S. Forest Service— enabled fuel reduction treatment along utility corridors and allowed the Forest Service and Liberty Utilities to share in the costs. Energy Safety can work with existing partners such as the Office of the State Fire Marshal and the California and the Wildfire and Forest Resilience Task Force to identify and facilitate similar projects.
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CALIFORNIA PUBLIC UTILITIES COMMISSION 27
Section 4 – Response to Executive
Order Request to Pursue Federal
Funding Opportunities
In April 2024, the Commission adopted Resolution E-5254. The Resolution formalized support for IOU pursuit of federal funding opportunities, allowed for the establishment of a memorandum account to track spending on applications and other federal funding costs, and established a process for utilities to seek cost recovery for any required ratepayer cost shares for successful grant applications. Utilities are directed to apply for cost recovery through the existing general rate case (GRC) or application process to ensure that all projects face a sufficient level of scrutiny and opportunity for public engagement.
The utilities have also received multiple letters from CPUC President Alice Reynolds directing them to pursue all available funding opportunities, highlighting upcoming deadlines, and ordering the IOUs to report on their efforts to apply for funding.
These efforts have led to significant successes, including a $15 billion low-interest loan from the Department of Energy. Additional funding is summarized in table A-3 of this report’s appendix.
The CPUC will continue to strongly support and encourage the IOUs to secure any and all available non-ratepayer funding.
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Appendix
18 See D.23-01-005 issued in PG&E’s 2023 General Rate Case (A.21-06-021) and D.23-05-013 issued in SCE’s 2021 General Rate Case (A.19-08-013). 19 AB 1054 excludes the first $5 billion of the large IOUs’ Wildfire Mitigation Plan (WMP) capital spending from earning a return on equity. (AB 1054, Section 18). This limits rate increases directly by eliminating the investor return portion of the return on rate base of $5 billion in WMP capital spending. See Chapter IV, Wildfire-Related Costs section for each IOU’s total equity rate base exclusion amount.
20 See Chapter IV, Wildfire-Related Costs section for specific Financing Order Application and Decision numbers. 21 Under PG&E's bankruptcy plan and SB 901, the CPUC also authorized $7.5 billion in securitization (SB 901, Section 32).
22 See D.22-12-056 in proceeding R. 20-08-020.
CPUC Actions Taken to Reduce Costs
Wildfire Self-Insurance Produces Ratepayer Savings
• Cost of commercial market wildfire insurance has escalated in recent years. • The CPUC approved proposals for PG&E and SCE to implement wildfire self-insurance, estimated to have resulted in a $467 million ratepayer savings impact in 2023.18 Similar savings are anticipated for future years.
Equity Rate Base Exclusion and Optional Securitization Limit Rate Increases • As directed by AB 1054, the annual revenue requirements approved by the CPUC preclude the IOUs from recovering a Return on Equity on $5 billion in wildfire mitigation capital costs. 19 • These equity rate base exclusions are forecasted to save ratepayers as much as $2 billion over the lifetime of the assets.
• AB 1054 also allows for securitization of wildfire mitigation capital spending. Securitization benefits ratepayers by allowing the securitized bonds to obtain a lower interest rate than would otherwise be available to finance WMP capital expenditures.20 As of July 2024, the CPUC has authorized $10.9 billion in securitization bonds under AB 1054 and SB 901.21
Net Billing Tariff (NBT) Limits Cost Increases
• The CPUC reduced electricity bills for IOU customers by reducing the amount customers pay to other IOU customers who install solar or solar-plus-storage systems in the future.22 • While Net Energy Metering (NEM) 1.0 and 2.0 programs decrease electricity bills for customers participating in the programs, they increase electricity bills for all other customers. The NBT decision does not change the ongoing increased costs that non-participating customers pay for participants to remain on the NEM 1.0 and NEM 2.0 tariffs. It also does not eliminate future CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 29
23 Comparing a NEM 2 solar-only customer to an NBT solar and storage customer. 24 See D.23-11-068 in proceeding R.20-08-020.
25 The TPR Process was established in Resolution E-5252. cost shifts: the NBT reduces the per-customer cost shift by an estimated 18-24% relative to NEM 2.23
Virtual Net Billing Tariff (VNBT) and NBT Aggregation Subtariff Limit Cost Increases • The CPUC reduced electricity bills for IOU customers by reducing the amount customers pay to other IOU customers who install solar or solar-plus-storage systems using the VNBT and NBT Aggregation programs compared to previous Virtual Net Energy Metering (VNEM) and Net Energy Metering Aggregation (NEMA) programs.24
• While VNEM and NEMA programs decrease electricity bills for customers participating in the programs, they increase electricity bills for all other customers. The decision does not change the ongoing cost shift created by customers remaining on the NEM 1.0 and NEM 2.0 tariffs. It also does not eliminate future bill increases that occur when other customers install rooftop solar and solar-plus-storage systems using the new tariffs.
Self-Generation Incentive Program Transitioned to Non-Ratepayer Funding Source • Pursuant to AB 209, the CPUC allocated $280 million from the Greenhouse Gas Reduction Fund to the Self-Generation Incentive Program (SGIP) Residential Solar and Storage Equity budget.
• This allowed the program to continue to support resiliency in low-income and environmental and social justice communities without drawing on ratepayer funds.
Intervention In Federal Transmission Owner Rate Cases Saves Ratepayers Money • The CPUC continuously advocates in Transmission Owner rate cases at FERC on behalf of ratepayers.
• Ratepayer savings are ongoing and estimated to be $5 billion since 2018, or $700 million per year.
Transmission Project Review (TPR) Process Increases Transparency of Costs • CPUC designed the TPR Process to provide cost transparency of IOUs' transmission projects before Federal Energy Regulatory Commission whose costs exceed $1 million.25 • While not always quantifiable, savings from previous FERC-derived processes between 2020 and 2023 resulted in quantified long-term savings to ratepayers of between $500 million and $1 billion. • As the TPR Process is more robust than those earlier processes, the affordability benefits to ratepayers are expected to be at least as great.
Implementation of FERC Order Saves Ratepayers Money
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CALIFORNIA PUBLIC UTILITIES COMMISSION 30
26 See D.23-06-008 in proceeding R.17-05-010.
• AB 209 reaffirms and clarifies that IOU participation in the CAISO is ordered by the CPUC and not voluntary. This clarification confirms that the IOUs cannot collect additional costs from ratepayers as an incentive to participate in an ISO.
• The Federal Energy Regulatory Commission (FERC) ruled in December 2023 that AB 209 is clear that incentives are not appropriate if an action is already mandatory. This adder will not be allowed in future rate cases and has an estimated cost savings of $86 million in 2024. •
The GRC Process is Transparent and Publicly Vetted
• The CPUC’s GRC proceedings require a transparent process for analyzing proposed utility costs and high levels of cost justification.
• In GRC proceedings, the CPUC requires evidence of forecasted costs and uses procedures for parties to litigate these forecasts in a public proceeding. This process enables the commission to identify necessary and cost-effective expenditures and typically leads to approvals that are lower than utility cost recovery requests.
Revision of Electric Rule 20 Prevents Ratepayers From Funding Inequitable Investments • The Rule 20A program subsidized the undergrounding of power lines for aesthetic purposes in localized areas and benefits few ratepayers at the expense of the many ratepayers. • The CPUC discontinued and is phasing down the Rule 20A Program by 2033 to prevent ratepayers from funding inactive and inequitable infrastructure investments.26 • The action is estimated to save $74 million annually through 2033.
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Table A-2. Program list.
Bill or
Statute
Mandating
Program, if
Any
Ratepayer
Funding ($
Millions, unless
otherwise
noted)
%
Reduction
in Average
Rates if
Funded by
Non-Ratepayer
Funds
One-Time
Savings if
Discontinued
Cost Effective?
Blank Cells
Mean No
Evaluation Has
Been Conducted
NEM 1 and 2
PU Code
Sections 2827
and 2827.1
$8.25 Billion in
Cost Shifts21 15.2% No
CARE and FERA PU Code
Section 739.1
$1.75 Billion
(1/3rd from
residential
customers)
3.2%
Energy Efficiency
PU Code
454.55,
454.56
$810 1.5%
Yes, with non-cost-effective
components
Demand
Response
PU Code
Sections
454.5(b)(9)(C)
(i), 380,
400(c), 769
$486 0.9%
Yes, with pilots
excluded from
cost-effectiveness
requirements
Uncollectibles/Arr
earage
Management
Program (AMP)
$483 million in
2025, $204
million from
AMP
0.9%
CalSHAPE (AB
841)
PU Code
Sections
1610-1618,
1620-1627,
1630-1633
$331 0.60%
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Net Billing Tariff
PU Code
Sections 2827
and 2827.1
$250 million in
cost shifts27 0.4% No
Energy Savings
Assistance (ESA)
PU Code
Section 382
~$140-200
million 0.3% No
Transportation
Electrification
Rebate Program
$200 0.40%
EPIC $185 0.3%
BioMAT/BioRA
M
PU Code
Section
399.20
$150 0.3%
SOMAH PU Code
Section 2870) $100 0.2% $517
VNEM
Approximately
$26 million in
202228
0.04% No
RES-BCT PU Code
Section 2830
~$30-50
million in cost
shifting
0.05%
DAC-GT/CSGT
PU Code
Section
2827.1
$24 0.04%
SB 1090 – Diablo
Canyon
Settlement
Agreement
PU Code
712.7
$9.48 million
in 2024, $213
million total,
27 Per the Public Advocates Office. 240822 Public Advocates Office 2024 NEM Cost Shift Fact Sheet. 28 Decision 23-11-068, page 22.
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Microgrid
Incentive Program
PU Code
8370, 8371
Low millions
in 2024, up to
$200 million
over 3-6 years
RISE $0 in 2024, $50
million total $50
AB 841
(Transportation
Electrification)
PU Code
Sections
740.12,
740.18,
740.19, and
740.20.
Unknown –
shifts costs to
non-participating
customers
Fuel Cell Net
Energy Metering
(NEM-FC)
PU Code
Section
2827.10
Low millions
in cost shifting
from 120 MW
of capacity –
NEM 2
Lookback
Study found
small cost shift
from
commercial
customers
NEM-A PU Code
2827, 2827.1
Low millions
in cost shifting
Solar Equipment
List
PU Code
Section 2851 $1.28 0.01%
Clean Energy
Financing $0 0% $270.5
SGIP PU Code
379.6
$0
Unquantified
cost shifting
Unquanti
fied ~$129 million
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TECH
PU Code
sections 922,
748.6
$0 0%
Community
Renewable Energy
Program (CREP)
PU Code
sections 769.3
and 913.15
$0 0%
AB 2109 –
Industrial
Surcharge
Exemption
PU Code
Sections 371
and 451.7
Unknown –
Shifts costs to
non-participating
customers
Unknown
Table A-3. Summary of federal funding secured by IOUs.
Applicant Project Award Amount Description
PG&E, SCE, CEC,
CPUC, CAISO, UC
Berkeley
CHARGE-2T
(California Harnessing A
dvanced Reliable Grid E
nhancing Technologies
for Transmission)
Press Release
DOE Factsheet
$600M Federal Share /
$901M Ratepayer Share
Reconductor 100+ miles
of transmission lines to
increase transmission
capacity to support
renewables integration.
Also supports
interconnection reform.
PG&E, Redwood
Coast Energy
Authority, Schatz
Energy Research
Center at Cal Poly
Humboldt
Tribal Energy Resilience
and Sovereignty
(TERAS) Project
DOE Fact Sheet
$88M Federal / $89M
Ratepayer
Implement nested
microgrids serving
Hoopa Valley, Yurok,
Karuk, and Blue Lake
Rancheria tribal lands to
drastically reduce outage
times.
Liberty Utilities Project Leapfrog
DOE Factsheet
$13M Federal Share /
$13M Ratepayer Share
Upgrade the distribution
system for real-time
information gathering,
greater manipulability,
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CALIFORNIA PUBLIC UTILITIES COMMISSION 35
and faster outage
management
CPUC, CEC, CA
Infrastructure and
Economic
Development Bank,
CA Labor & Workforce
Development Agency
Solar for All
EPA Solar for All
website
$249.8M Deliver residential solar
for low-income and
disadvantaged
communities across the
state.
PG&E Maintaining &
Enhancing
Hydroelectricity Section
247
DOE Award List
$34.5M for 39 different
projects
Maintain and improve
existing hydropower
facilities.
PG&E Project Polaris
DOE Press Release
$15 billion loan Expand hydropower
generation and battery
storage, upgrade
transmission capacity
through reconductoring
and grid enhancing
technologies, and enable
virtual power plants
January 1, 2025
California Energy Commission Response to Executive Order N-5-24 Overview
The California Energy Commission (CEC), as the state’s energy policy and planning agency, is responsible for advancing state energy policy, investing in energy innovation, overseeing energy infrastructure, and preparing for energy emergencies. The CEC is also responsible for advancing energy efficiency and developing renewable energy and has done so in part through longstanding building and appliance efficiency programs, as well as more recent, nation-leading energy research, renewable energy, and load flexibility programs. These programs support California’s energy and environmental policies, including the transition to entirely clean energy sources by 2045.
The CEC administers dozens of programs funded by a variety of revenue sources. Outside of the recent one-time state and federal funds dedicated to expediting the state’s transition to clean energy, most CEC programs are funded by dedicated revenue sources from special funds. One example is the Clean Transportation Program (CTP), which invests up to $100 million annually, leveraging public and private investments to accelerate the development of zero-emission and near-zero-emission technologies and reduce petroleum dependence. The CTP receives revenue from vehicle registration, vehicle identification plates, and smog abatement fees. Another example is fees paid by power plant developers to support the CEC’s power plant licensing and compliance activities.
The main fund supporting CEC’s operational activities is the Energy Resources Programs Account (ERPA).
The revenues in ERPA are linked to the sale of metered electricity, and ERPA revenues support activities at the CEC such as building and appliance standards that have helped California consistently rank as a leading state in energy efficiency – including the #1 ranking in the latest assessment of the American Council for an Energy-Efficient Economy (ACEEE).
1 Since their inception in the late 1970s, these
standards have significantly reduced energy consumption and ratepayer bills.
The clean energy programs of the CEC are critical to helping the state rise to meet the energy and climate challenges of today and tomorrow, from grid decarbonization to reliability and affordability. The state has made great strides in decarbonizing the California grid. From January to September 2024, for example, the grid reached 100 percent clean energy for a portion of the day in two out of every three days. The grid’s struggles with reliability seemed insurmountable only a couple years ago when extreme weather events, more limited flexible resources, and market dynamics, among other influences, led to outages that disrupted lives and the economy.
2 In contrast, this past summer was the hottest in modern history, and ratepayers experienced no outages from supply shortfalls and zero flex alerts. These 1 ACEEE State Energy Efficiency Scorecard. https://www.aceee.org/state-policy/scorecard 2 CAISO, CPUC, CEC (2021) Root Cause Analysis: Mid-August 2020 Extreme Heat Wave. https://www.caiso.com/Documents/Final-Root-Cause-Analysis-Mid-August-2020-Extreme-Heat-Wave.pdf 2 outcomes reflect tremendous progress. And, while the challenges related to affordability are substantial and impactful, particularly to the state’s low-income and disadvantaged communities and tribes, they too are solvable.
The CEC’s electric ratepayer-funded programs seed the innovations, deploy the resources and infrastructure, and enable the statewide action needed to mitigate electricity affordability challenges while continuing to decarbonize, modernize, and strengthen the grid. The value of these programs is tangible in the deep efficiencies unlocked through codes, standards, and technology innovation.
Moreover, the load growth facilitated through the continued electrification of California’s economy could help to stabilize rates and potentially counteract the higher fixed costs on utility bills, depending on rate design and other factors. Ratepayer-supported programs and initiatives advance energy technologies across the economy – including electric vehicles, heavy-duty fleets, and transit; residential, commercial, and industrial heat pumps for space and water heating and highly efficient appliances; advanced renewable energy generation; and integrated controls and battery and thermal storage that enable the state to shape and shift its demand. In this way and more, the CEC programs are integral to a just, clean energy future.
In response to Executive Order N-5-24,
3 the CEC examined all electric investor-owned utility (IOU) ratepayer-supported programs that it oversees and administers, and reports the following:
● Energy Efficiency: California’s efficiency programs are highly cost-effective to ratepayers and have long been key to achieving affordable bills and meeting the state’s energy and environmental goals. The Statewide Codes & Standards Program is funded by electric and gas ratepayers at $56.7 million per year as of 2024, whereas efficiency standards for buildings and appliances are saving billions annually, have saved Californians over $200 billion since inception in the late 1970s, and are set to reach $300 billion in total cumulative economic value to the state by 2030. The CEC recommends retaining the ratepayer supported programs that directly contribute to these foundational efforts, in particular the California Public Utilities Commission (CPUC)-overseen and IOU-managed Statewide Codes & Standards Program. However, the Legislature should consider if the costs of this foundational program should be borne more broadly by electric and gas ratepayers across all of California, given the statewide customer benefits these programs provide.
● California Schools Healthy Air, Plumbing, and Efficiency (CalSHAPE) Program: The CalSHAPE program was authorized in 2020 as a COVID-19 urgency measure to re-open schools and improve indoor air quality. Since program implementation, other non-ratepayer funding sources have become available, including the $10 billion Proposition 2 of 2024 and local bond measures.
Given the availability of non-ratepayer funding, the Governor and Legislature may consider refunding $196.1 million of unencumbered CalSHAPE funds to electric and gas IOU ratepayers before December 31, 2026.
● Solar Equipment Lists: The CEC’s Solar Equipment Lists (SELs) provide a standardized, streamlined and cost-effective process for equipment identification that is relied upon by equipment manufacturers, IOUs, publicly-owned utilities (POU), providers of permitting platforms, local governments, certain CPUC and CEC programs, the National Renewable Energy Laboratory (NREL) and other entities across the country. In Spring 2023, the CEC released a public request for information (RFI) to better assess the use cases and benefits of its SELs.
California electric utilities’ responses to the RFI indicated that by leveraging SELs for interconnection application review, the utilities achieve tremendous cost savings, due to 3 Executive Order N-5-24 (2024). https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf 3 reduced review times and labor hours, exceeding the cost to administer the SELs program by several factors. Information from the SELs is utilized in software platforms that assist local governments in streamlining the permitting processes for distributed energy resources (DER).
Without information from the SELs, challenges to interconnection and permitting of DERs would increase, potentially slowing down deployment significantly and adversely impacting the growth of the DER industry. However, the IOUs maintain their own SELs list as required by CPUC’s Rule
21. Therefore, the CEC recommends identifying an alternate funding source.
Information is also provided on the CPUC-overseen and CEC-administered Electric Program Investment Charge (EPIC).
Energy Efficiency
Program Background and Objectives
Since 1978, building and appliance energy efficiency standards have saved Californians over $200 billion and served as a foundational, highly cost-effective strategy for meeting the state’s climate action goals. Appliance standards are estimated to save over 40,000 GWh of annual electricity demand while delivering sizeable reductions in water use and fossil gas consumption. The term “energy” as used below encompasses direct electricity and fossil fuel consumption, embodied energy in the delivery and treatment of potable water, and indirect avoided fuel consumption by power plants due to lowering peak demands. If the state were to credit just the electricity savings at the wholesale price, as opposed to the retail value, energy efficiency from appliance standards alone would be worth $2 billion annually to ratepayers, which is more than the entire annual CPUC budget for energy efficiency and entire annual CEC staff budget combined.
The building code adopted by the CEC in 2024 is estimated to provide California with 30-year benefits of at least $4.8 billion4
— or over 20 times the roughly $200 million cost of the entire 3-year Statewide Codes & Standards budget, including Energy Commission expenditures, appliance standards, and other energy efficiency standards activities. These highly impactful building and appliance energy efficiency standards are enabled by the electric IOU ratepayer-supported Statewide Codes & Standards Program, which is implemented by the IOUs and delivers critical analytical support for standards development.
The Los Angeles Department of Water & Power (LADWP) and the Sacramento Municipal Utility District (SMUD) have also historically contributed to the program. The Statewide Codes & Standards Program is funded at $56.7 million per year as of 2024.
5 Research and Development (R&D) in energy efficiency and incentive programs for energy efficient technologies ultimately result in new, cost-effective energy efficiency technologies and practices that can be adopted into the state’s mandatory building energy code, resulting in significant cost savings to ratepayers in the form of reduced energy bills. In other words, California’s national and global leadership in building and appliance energy standards is made possible by ratepayer-funded initiatives on both the code adoption side – in particular the Statewide Codes & Standards Program – and on the research and product development side, such as EPIC.
4 CEC (2024) Form 399 for the Proposed Changes to the 2025 Building Energy Efficiency Standards. https://efiling.energy.ca.gov/GetDocument.aspx?tn=255315-5&DocumentContentId=90999 5 CEDARS California Energy Data and Reporting System. https://cedars.cpuc.ca.gov/filings/list/ 4 Program Impact
Energy efficiency has been key to affordable customer electric and gas bills. While California has long had above-average electricity rates, until recent years, Californians still enjoyed some of the lowest bills in the country thanks to their low energy usage. Program expenditures for CEC’s building and appliance standards programs have not substantially increased in recent years and are not responsible for the recent increase in energy bills.
California’s energy efficiency programs are working. The residential electricity consumption between 2009 and 2019 increased by only 2 percent despite the population growing by 7 percent (which would be expected to cause a matching 7 percent growth in energy demand, all else being equal) as well as a major increase in consumer electronics and air conditioner saturation. 6 Codes and standards rely on a complex pipeline of market transformation efforts. New energy efficient technologies and techniques are studied and developed in the state’s R&D programs such as EPIC. At the next stage of market transformation are voluntary programs that include inducements, marketing, and labeling that drive the new technology to a larger market share. Only once the technology is developed, proven, and has reasonable customer acceptance will it typically be considered for a code or standard, which is further supported by “above code” programs operated by IOUs, community choice aggregators (CCA), and other private groups. Therefore, the significant energy and financial savings achieved through the codes and standards programs depend on – and should be partially attributed to – an ecosystem of R&D programs and energy efficiency inducement programs.
As an example, consider the process of essentially eliminating incandescent bulbs from residential households. R&D funding was spent on developing compact fluorescent and light emitting diode (LED) lighting, measuring their characteristics and their acceptance by consumers. Based on resulting products, labels and inducements were provided to drive the initial scale in the market. Finally, appliance standards required that only efficient, quality bulbs be allowed for sale in the state.
Appliance Efficiency Program
Appliance standards set by the CEC, first adopted in the late 1970s, have transformed the national appliance market and many have since been adopted as national standards. California standards become de facto national standards, and in most cases literally become national standards; the federal legislation instituting the U.S. Department of Energy’s (DOE) national program was a direct response to California’s standards and a concern from manufacturers that other states would follow California’s lead and create a patchwork of requirements. California’s standards became the starting point for DOE’s consideration and adoption of national standards,
7 a pattern that has repeated for the majority of
federal standards now applicable nationwide. This is further supported by “above code” programs operated by IOUs, CCAs and other private groups. California developed the first efficiency standards for all major electricity and gas appliances in the home — refrigerators, air conditioners, furnaces, water heaters, etc. The impacts of early actions continue to be observed in the market. Appliance standards that became effective after 2015 are still accelerating in their energy and financial savings impact given that it takes an average of 10 years for full market turnover of a given appliance. This includes standards for the following:
6 See the Residential Appliance Saturation Surveys conducted for 2003, 2009 and 2019. https://www.energy.ca.gov/data-reports/surveys/2019-residential-appliance-saturation-study 7 See Public Resources Code § 25402. 5 Appliance
Annual
avoided
GWh
(2024)8
2024 cost savings
(wholesale - $50/MWh)
2024 cost savings
(retail - $0.31/kWh)
Battery Chargers 5,290 $ 264.5 M $ 1,640 M
Lighting 2,331 $ 116.6 M $ 722.6 M
Computers 1,932 $ 96.6 M $ 598.9 M
Televisions 1,391 $ 69.6 M $ 431.2 M
Computer Monitors 347 $ 17.4 M $ 107.6 M
Portable Electric
Spas 35 $ 1.8 M $ 10.9 M
Combined, these recent standards are responsible for 11,000 GWh of the 40,000 GWh annual total savings attributable to the Appliance Efficiency Program, with the remainder occurring from standards adopted over 10 years ago (for which full stock turnover has effectively taken place). Battery chargers are the largest single contributor to this total, contributing 5,290 GWh in 2024, and these standards are growing rapidly in impact as more products come to use rechargeable battery technology. In fact, CEC staff anticipates a doubling of their impact by 2030.
The Appliance Efficiency Program also reduces gas and water used in equipment, with similarly impressive results. CEC staff estimate annual savings of 127 billion gallons of water resulting from standards adopted in 2015, another 152 billion gallons of annual savings from standards adopted in 2019, and project another 76 billion gallons in annual savings through standards planned for 2025 (after full stock turnover). Additionally, staff estimate annual savings of 1.9 billion therms in direct provision of gas by utilities.
Building Energy Efficiency Standards
The CEC updates the statewide Building Energy Efficiency Standards every three years to improve the energy efficiency of California’s buildings, reduce operational costs, lower greenhouse gas emissions, and enhance the resilience of buildings to extreme weather linked to climate change. Recently, the CEC adopted the 2025 code updates, applicable to newly constructed residential and commercial buildings, renovations, and certain other existing buildings, which will advance California’s economic, clean energy, climate, and public health goals. This new code is expected to save Californians $4.8 billion in energy costs over its lifetime of 30 years, make homes and buildings more climate-resilient, and reduce 8 Figures projected to 2024 consistent with published reports, as follows: for lighting, reports published in dockets 16-AAER-04, 15-AAER-06, 17-AAER-07 and 19-AAER-04; for battery chargers, 11-AAER-2 and 18-AAER-02; for computers, computer monitors and televisions, 14-AAER-02 and 16-AAER-02; for portable electric spas, 12-AAER-02G, 15-AAER-02, 18-AAER-01, 18-AAER-02, and 20-AAER-04. All documents available at:
https://www.energy.ca.gov/proceedings/dockets/california-energy-commission-dockets 6 greenhouse gas emissions by about 4 million metric tons—equivalent to the annual energy consumption of over half a million homes.
9 Finding
The CEC found California’s efficiency programs are highly cost-effective to ratepayers and have long been key to achieving affordable bills and meeting the state’s energy and environmental goals. The Statewide Codes & Standards Program is funded by electric and gas ratepayers at $56.7 million per year as of 2024, whereas efficiency standards for buildings and appliances are saving billions annually, have saved Californians over $200 billion since inception in the late 1970s, and are set to reach $300 billion in total cumulative economic value to the state by 2030. The CEC recommends retaining the ratepayer supported programs that directly contribute to these foundational efforts, in particular the CPUC-overseen and IOU-managed Statewide Codes & Standards Program. However, the Legislature should consider if the costs of this foundational program should be borne more broadly by electric and gas ratepayers across all of California, given the statewide customer benefits these programs provide.
Without these programs, California’s energy efficiency standards for buildings and appliances would be significantly diminished. For instance, 25 highly technical reports were developed to demonstrate the cost-effectiveness and technical feasibility of the updates adopted in the 2025 Building Energy Efficiency Standards; the Statewide Codes & Standards Program prepared and published 19 of these reports.
Without the substantial contributions of the Statewide Codes & Standards Program — which includes the three major investor-owned utilities (IOUs), along with support from the LADWP and the SMUD — the statewide impact of the 2025 code updates would have been greatly reduced. This program serves as a cornerstone for advancing energy efficiency standards across the state.
California Schools Healthy Air, Plumbing, and Efficiency (CalSHAPE) Program
Program Background and Objectives
The California Schools Healthy Air, Plumbing, and Efficiency (CalSHAPE) Program was established by Assembly Bill 841 in September 2020 as an urgent energy efficiency measure during the COVID-19 pandemic to help schools improve air quality and reduce energy use while meeting current classroom ventilation requirements, and to assist local educational agencies (LEA) in making much needed upgrades to school infrastructure. Pursuant to Public Utilities Code (PUC) Section 1615(e)(1), the CEC must return all unspent CalSHAPE Program funds to the electric and gas IOU ratepayers by December 1, 2026. The CEC set an encumbrance deadline of October 31, 2024, for new grant agreements to ensure funds are reverted by this date.
CalSHAPE includes two grant programs: the Ventilation Program and the Plumbing Program. The Ventilation Program provides funding for LEAs to assess, maintain, repair, and replace ventilation systems in schools. As required by PUC Section 1631, the Plumbing Program provides funding for LEAs and state agencies to replace aging and water-inefficient plumbing fixtures and appliances with water-conserving plumbing fixtures and appliances. The CalSHAPE Program also creates work opportunities for a skilled and trained workforce and prioritized awards to schools in underserved communities, consistent with the goals of the program.
9 Estimated utilizing U.S. Environmental Protection Agency Greenhouse Gas Equivalencies Calculator. https://www.epa.gov/energy/greenhouse-gas-equivalencies-calculator-calculations-and-references#houseenergy 7 The CalSHAPE Program is funded by all electric and gas IOU ratepayers with funding collected in calendar years 2021, 2022, and 2023. Public Utilities Code (PUC) Section 1615 (a)(1)(A) required each IOU to allocate a portion of their energy efficiency budgets plus any unspent and uncommitted energy efficiency funds carried over from the previous calendar year to the CalSHAPE Program. This resulted in additional funding being collected from all electric and gas IOU ratepayers. The IOUs transferred $993 million between 2021 and 2023. PUC Section 1616 required 75 percent of the program funding be directed to the Ventilation Program and 25 percent to the Plumbing Program. No additional funding is being collected by the IOUs for the CalSHAPE Program, and the program must return any unused funds to all electric and gas ratepayers by December 1, 2026.
PUC Section 1617 automatically deems these programs cost-effective without ex-post evaluation of the expended funding and specifies that the programs shall not be considered by the CPUC when calculating the overall cost-effectiveness of the IOUs’ energy efficiency portfolios. This is uncommon. Standard best practice would be for energy efficiency programs that encourage the deployment of complex energy efficiency projects with varying degrees of energy and costs savings to be evaluated to measure their efficacy and determine the value of these ratepayer-funded investments. The Legislature should consider requiring that these types of programs undergo a robust cost-effectiveness evaluation to ensure the benefits delivered are sufficient to merit the ratepayer contributions that make these programs possible.
The CalSHAPE Program was also allocated $20 million from the Greenhouse Gas Reduction Fund in the Budget Act of 2022, which includes $19 million for grants and $1 million for program administration. The Budget Act of 2022 (Section 2 3360-001-3228 and 3360-101-3228) states that funds shall be used only for HVAC system replacement in the Ventilation Program, as described in PUC Division 1, Part 1, Chapter
8.7 (commencing with Section 1600).
The CalSHAPE Program accepted applications from fall 2021 through summer 2024. As of November 1, 2024, the CalSHAPE Program encumbered $786.8 million, or 78 percent, of the total funding. PUC Section 1615 (d) states that the CEC can use up to $5 million per year for program administration, and since the program runs for six years (January 2021 to December 2026), the CEC has reserved $30 million for administration costs. The CEC has expended $7.5 million on administration through Fiscal Year (FY) 2023-2024 and expects to expend an additional $5 million in FY 2024-2025. The CalSHAPE Program currently has $196.1 million in remaining (unencumbered) funds, which, per statute, will be returned to all electric and gas IOU ratepayers with any additional unspent funds by December 1, 2026.
Program Funding and Impact
For the Ventilation Program, $654 million of $741 million in available funding has been encumbered, and the remaining or unallocated balance is $87 million. Encumbered funding has enabled 625 LEAs to assess, maintain, repair, and replace HVAC systems at 4,676 schools, with 32,035 MTCO2e in forecasted greenhouse gas emission reductions.
For the Plumbing Program, $131.9 million of $241 million in available funding has been encumbered and the remaining or unallocated balance is $109.1 million. Encumbered funding has enabled 228 LEAs to replace aging and water inefficient plumbing fixtures and appliances at 1,489 schools, with an estimated
2.5 billion gallons in water savings with the replacement of 58,974 plumbing fixtures and appliances.
Regarding the program administration, $7.5 million of $30 million in allocated administrative costs have been expended. Administrative tasks include program oversight, application and report review, issuing of checks, technical contract implementation, and completion of program status reports. CEC estimates in order to effectively complete the program, administrative funds would be needed for a minimum of 2 years after final project completion, which is estimated to be December 1, 2028. 8 CEC Oversight and Quality Control
The Ventilation Program has detailed project requirements, outlined in PUC Section 1620-1627, which include the use of qualified technicians and a skilled and trained workforce to assess and maintain HVAC systems, make minor adjustments and repairs as needed, and produce an HVAC Assessment Report. The HVAC Assessment Report includes information on the condition of the HVAC systems and the filtration and ventilation provided to each classroom as found during the assessment. The CEC has a robust compliance process for Ventilation Program projects, which includes conducting field audits and performing a thorough review of the HVAC Assessment Reports. This oversight is needed to provide quality control of the projects and ensure that grant funds are being used appropriately. However, the detailed oversight may result in some LEAs having to resubmit the HVAC Assessment Report or require the contractor to redo portions of the project if issues are found and may extend the lifetime of the projects.
Finding
The CalSHAPE program was authorized in 2020 as a COVID-19 urgency measure to re-open schools and improve indoor air quality. Since program implementation, other non-ratepayer funding sources have become available, including the $10 billion Proposition 2 of 2024 and local bond measures. Given the availability of non-ratepayer funding, the Governor and Legislature may consider refunding $196.1 million of unencumbered CalSHAPE funds to electric and gas IOU ratepayers before December 31, 2026.
California Solar Equipment Lists (SELs) Program
Program Background and Objectives
Senate Bill 1 (2006) directed the CEC to establish criteria and standards for solar incentive programs under the California Solar Initiative (CSI). In response, the CEC established the Solar Equipment Lists (SELs), which set rating standards for equipment components and systems to assure reasonable performance and facilitate safe and reliable interconnection with California’s electricity grid and distribution systems. Over time, while the CSI programs sunset, the broader industry came to rely on the SELs as a primary source for determining equipment compliance with standards required for local government permitting and grid interconnection of DERs across the state. The SELs include thousands of unique equipment models, including solar modules, meters, smart inverters, batteries, energy storage systems, and power control systems that have been validated as meeting national standards. The SELs facilitate substantial improvements in processing of DER interconnection application requests and local government permitting of DERs.
Program Funding and Impact
The Solar Equipment List is currently funded with approximately $1.3 million annually. The CEC continuously receives requests from equipment manufacturers to have the manufacturer’s products added to the relevant SEL. The CEC updates the SELs three times each month. In 2024, approximately 8,000 unique models of equipment were validated to meet all requirements and were added to the SELs.
Finding
The CEC’s SELs provide a standardized, streamlined and cost-effective process for equipment identification that is relied upon by the equipment manufacturers, IOUs, POUs, providers of permitting 9 platforms, local governments, certain CPUC and CEC programs, NREL and other entities across the country. In Spring 2023, the CEC released a public RFI to better assess the use cases and benefits of its SELs. California electric utilities’ responses to the RFI indicated that by leveraging SELs for interconnection application review, the utilities achieve tremendous cost savings, due to reduced review times and labor hours, exceeding the cost to administer the SELs program by several factors.
Information from the SELs is utilized in software platforms that assist local governments in streamlining the permitting processes for DERs. Without information from the SELs, challenges to interconnection and permitting of DERs would increase, potentially slowing down deployment significantly and adversely impacting the growth of the DER industry. However, the IOUs maintain their own SELs list as required by CPUC’s Rule 21. Therefore, the CEC recommends identifying an alternate funding source.
Electric Program Investment Charge (EPIC)
Program Background and Objectives
In 2011, the CPUC established the Electric Program Investment Charge (EPIC), a ratepayer funded research, development, and deployment program, and authorized the CEC as one of four administrators alongside California’s three largest IOUs, whose ratepayers fund the program – Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric, and Southern California Edison (SCE). The CEC administers 80 percent of the program’s total funds, investing in clean energy technologies and approaches to help benefit California IOU ratepayers. All demonstration projects are sited in electric IOU service territories because they are funded by electric IOU ratepayers. The CEC funds projects in all three investment areas of the EPIC program: applied research and development, technology demonstration and deployment, and market facilitation.
The EPIC program is the leading state energy research and development program in the United States.
The intent of EPIC is to deliver a range of important benefits to IOU ratepayers including improving energy affordability, incubating lower-cost energy technologies, and reducing the disproportionate burdens of climate change and energy-related emissions on disadvantaged and low-income communities.
Program Funding
EPIC is funded by a ratepayer surcharge on bills of customers of the state’s electric IOUs, providing approximately $148 million per year for the CEC’s implementation of EPIC – equivalent to approximately 1 cent per person per day. With that contribution, EPIC has provided a stable, sustained source of public investment in energy innovation – critical to supporting the pipeline of technology development from early stages through commercialization and deployment in the state. EPIC endeavors to drive innovation and advances science and technology in energy efficiency, load flexibility, renewable energy and advanced clean generation, transportation, grid transmission and distribution, and energy-related environmental protection, among other areas important to California’s electricity system and ratepayers.
In August 2020, the CPUC renewed EPIC program funding for an additional 10 years, through December 31, 2030.10 All grant funding under the current 2021-2025 EPIC Investment Plan (EPIC 4) is either encumbered or designated for use according to CPUC Decision 22-06-004,11 Decision 21-07-006,12 and 10 CPUC Decision 20-08-042 (2020). 346225760.PDF 11 CPUC Decision 22-06-004 (2022). 482684526.PDF 12 CPUC Decision 21-07-006 (2021). 394265545.PDF 10 related decisions,13 and will be used accordingly. Future funding under the 2026-2030 EPIC Investment Plan (EPIC 5) will be designated for use according to the upcoming CPUC decision under the EPIC Proceeding (anticipated in 2025) and deployed accordingly.
Program Impact Assessment
The CEC integrates the assessment of benefits into each stage of the funding life cycle. Each R&D topic included in the investment plan includes a summary of potential impacts and expected outcomes if successful, as well as high-level metrics and performance indicators. These impacts and metrics are refined through competitive solicitations and assessed through scoring criteria on impacts and benefits for ratepayers. During project implementation, CEC staff collects data via recipient questionnaires to measure and verify performance. The final report for each project documents technical performance, outreach, technology transfer, and lessons learned. After project completion, CEC staff continues to collect data to assess ratepayer benefits, including through annual surveys and online resources, including Pitchbook and Google Scholar. Because the full impact of clean energy innovations can take several decades, the CEC assesses both achieved and projected benefits. 13 CPUC EPIC decisions available at: Energy Research Development and Deployment WATER
LAND USE
OCEANS
CLIMATE
& ENERGY
OCTOBER 2024
Policy Report IMPROVING TRANSMISSION
FINANCING in California
Alternative Models and Policy Strategies to Increase
Affordability
About The Center for Law, Energy
& the Environment
The Center for Law, Energy & the Environment (CLEE) channels the expertise and creativity of the Berkeley Law community into pragmatic policy solutions to environmental and energy challenges. CLEE works with government, business, and the nonprofit sector to help solve urgent problems requiring innovative, often interdisciplinary approaches. Drawing on the combined expertise of faculty, staff, and students across the University of California, Berkeley, CLEE strives to translate empirical findings into smart public policy solutions to better environmental and energy governance systems.
DESIGN
Template design and layout:
Jordan Rosenblum
Document design and layout:
Odd Moxie
Image credits:
Adobe Stock
OCTOBER 2024 | POLICY REPORT
IMPROVING TRANSMISSION
FINANCING IN CALIFORNIA
Alternative Models and Policy Strategies to Increase Affordability
AUTHORS
Ken Alex
D I R EC TO R , P R OJ EC T C LI M AT E
C E N T E R FO R L AW, E N E R G Y &
THE ENVIRONMENT
Ethan Elkind
DIRECTOR, CLIMATE PROGRAM
C E N T E R FO R L AW, E N E R G Y &
THE ENVIRONMENT
Grayson Peters
GRADUATE STUDENT RESEARCHER (FORMER)
C E N T E R FO R L AW, E N E R G Y &
THE ENVIRONMENT
The report authors wish to thank Net-Zero California and Clean Air Task Force for their support for this work.
Table of Contents
I. THE NEED FOR AFFORDABLE TRANSMISSION FINANCING 7
Overview: Status Quo Financing in California 7
Novel Financing Strategies for California 8
Key Findings and Implementation Considerations 8
Recommendations 11
Conclusion: 12
References 14
II. APPENDIX I: APPROACHES TO TRANSMISSION FINANCING 16 California Needs More Transmission Capacity 17
Public Financing Could Help Meet California’s Transmission Needs Affordably 17 Transmission Overview: A Lengthy, Expensive, and Compartmentalized Process 18 Transmission Finance Overview 21
Models for State Transmission Finance Reform 26
Other Options for Public Support 37
Conclusion 41
References 42
III. APPENDIX II: PUBLIC SECTOR FINANCING OF ELECTRICITY TRANSMISSION LINES IN CALIFORNIA 55
5 Center For Law, Energy & the Environment
i. The Need for Affordable
Transmission Financing
California will need a significant build-out of new high-voltage transmission lines to meet state goals for renewable energy deployment and a decarbonized grid by 2045, which requires a quadrupling of its current in-state solar and wind capacity. Transmission will be needed to deliver offshore wind power from the North and Central Coast, large-scale solar from the Central Valley, and geothermal from the Salton Sea, among other regions.
But if this new infrastructure is paid for solely through electricity rates, it could increase those rates significantly and potentially undermine the economy-wide transition to clean energy. Rates have already increased roughly 50% over the past three years for investor-owned utility customers in the state, placing political and economic pressure on state leaders to build these lines with as little burden on ratepayers as possible.1 In response, UC Berkeley Law’s Center for Law, Energy and the Environment (CLEE) presents in this summary policy report a variety of strategies available to policymakers for financing new high-voltage power transmission in California, with the dual goals of 1) reducing costs to ratepayers and 2) accelerating transmission development. With sup-port from Net-Zero California (NZC) and Clean Air Task Force (CATF), CLEE developed these strategies based on a literature review, legal research, multiple interviews, and a convening of transmission experts and stakeholders from government, industry and nonprofit organizations, along with examples of alternative approaches used in other states. In addition, a separate financial analysis by DH Infrastructure and EE-Analysis (see Appendix 2) quantified the potential ratepayer savings of public transmission financing and development models compared to a business-as-usual investor-owned utility scenario, which further informed this report. A more detailed memo, including selected financing options and their specific challenges, can be found in Appendix 1 on page 16.
OVERVIEW: STATUS QUO FINANCING IN CALIFORNIA
Transmission financing strategies employed in California currently include:
7 Center For Law, Energy & the Environment
• Investor-owned utility financed and ratepayer funded: When investor-owned utilities (IOUs) build transmission lines, they pass the cost to consumers through Transmission Access Charges on ratepayers’ electricity bills. In California, these utilities include Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E), which recover the costs, along with a guaranteed rate of return, from ratepayers.2 • Private developer funding: Some transmission projects are funded en-tirely by private sources, such as when energy project developers finance the transmission they need in conjunction with their projects. These private transmission line owners then receive revenue through the same California Independent System Operator (CAISO) Transmission Access Charge that utilities use.
NOVEL FINANCING STRATEGIES FOR CALIFORNIA
As this report details below, the state could expand or adopt innovative transmission financing strategies to reduce costs, such as:
• Public co-development: Public-private partnerships (PPP, or “P3” as used in this report) arrangements, in which both public entities and private de-velopers participate, can be structured in different ways, including:
o A lease-type P3, in which a government-owned holding company or special purpose vehicle provides financing for the transmission asset but hires a private company to operate the assets. o A concession-type P3, in which a government-owned asset is designed, built, operated and financed by a private company over the life of the asset, and then ultimately returned to government at the end of the concession agreement.
• Public ownership: Some states have established public agencies that can finance and own transmission lines, including through bonding and other financing authority. These agencies can also participate in public-private partnerships.
As DH Infrastructure details (see Appendix 2), the use of these types of public sector financing, along with targeted institutional changes, can reduce the cost of California’s needed transmission build-out by tens of billions of dollars over the next two decades.
KEY FINDINGS AND IMPLEMENTATION CONSIDERATIONS
CLEE convened expert participants to help identify which of these novel financing strategies would be most feasible for California to adopt. Participants included rep-resentatives from the California Public Utilities Commission (PUC), the California In-dependent System Operator, California Natural Resources Agency, non-governmental organizations (NGOs), ratepayer advocacy, the state legislature, and clean energy in-dustry groups, among others. 8 Improving T ransmission F inanc ing in Cal ifornia
The convening discussion, and follow-up research and outreach, yielded a number of key findings:
1. Some form of public-private partnership could provide significant benefits to deploying lower-cost transmission, due to cost-savings potential and the ability to leverage existing institutions and struc-tures. Exactly which form such a partnership should take is not certain without more detailed evaluation. As noted above, a number of possibilities and considerations exist, and the form of P3 may depend on the particular transmission line, developers, and other project-specific circumstances. How-ever, the basic components of public investment would remain consistent, such as bonding authority and a general P3 structure. Variation may exist in terms of which entity issues the bonds and which sub-elements of a P3 structure meet the needs of the projects and the State.
2. An example of P3-type financing is the “Citizens-Morongo Model,” named after the two companies involved, Citizens Energy (a non-profit that shares proceeds with communities) and Morongo Transmission (owned by the Morongo Band of Mission Indians). These groups partnered with utilities SDG&E and SCE to build transmission. The utilities agreed to sell a 30-year leasehold interest to Citizens-Morongo, making Citizens-Morongo a partic-ipating owner of transmission assets that the utilities continue to operate.
The Federal Energy Regulatory Commission (FERC) approved the ability of Citizens-Morongo to finance with 100% debt rather than a combination of debt and equity, given that these entities do not otherwise have easy access to equity. The Federal Energy Regulatory Commission also approved a fixed, 30-year transmission rate, and Citizens-Morongo’s ability to share proceeds with the community helps engender crucial local stakeholder sup-port. Expanding this Citizens-Morongo option to apply more broadly across California will require better understanding of any possible tradeoffs, cost savings, limitations, risks, and streamlining benefits.
3. Policymakers may endow an existing entity with transmission fi-nancing and related P3 authorities, rather than create a new entity.
Currently, California has multiple entities with at least some role in trans-mission, including the California Independent System Operator, California Public Utilities Commission, California Energy Commission (CEC), California Infrastructure and Economic Development Bank (IBank), and Department of Water Resources. Creating a wholly new public entity, or endowing an existing agency, in California to finance and oversee transmission would entail administrative and procedural changes, which may be more significant for a new public entity.
Any change in the status quo for transmission financing in California will face a num-ber of implementation challenges. Notably, the following considerations are relevant regardless of the structure or entity that holds authority over transmission financing and oversight:
• Impact on investor-owned utilities. Under the current system, as noted, these utilities receive a guaranteed rate of return on investment from trans-mission construction. This return represents a key source of their revenue. 9 Center For Law, Energy & the Environment
If a different approach to financing precludes or reduces that rate of return, policymakers will need to evaluate the impact on the financial viability of the investor-owned utilities.
• Public-private partnership concerns in the California Legislature.
Legislators may have concerns about authorizing public-private partnership approaches, in part due to a perception that they require the government to assume private-sector risk while lacking private-sector expertise. However, legislators widely recognize the need to reduce both the cost of transmission and the implementation time. Public-private partnerships could potentially offer some relief for both, and these partnerships already exist in many forms. • Lack of clarity on which public entity would lead. If a public or gov-ernmental entity is to have a significant role in transmission financing, pol-icymakers will need to determine whether to create a new entity or if they should provide additional authority to an existing agency or department. In either case, legislators will need to determine the extent of the authorization and responsibilities.
• Relationship of any new state authority to existing authority. Agency review and control over transmission siting and related issues is complex and time-consuming, with significant roles for the California Independent System Operator, California Public Utilities Commission, California Energy Commission, and other entities. The role of a new governmental entity, or an existing entity with additional authority, will need to be integrated into the current framework in a manner ensuring clear authority, while not ex-acerbating current financial and governance challenges. • Asset ownership. If the state is a key part of financing transmission, it will need to determine if it should own some part of the asset. Ownership could be determined through negotiation at various energy agencies, or directly among interested parties, for each transmission line or through legislation, which can also serve to limit public liability for any operational risks. • Liability ownership. With ownership, the issue of liability becomes central, particularly given the role of transmission lines in catastrophic wildfires.
Liability could be determined through negotiation or legislation, or a com-bination of the two. Liability can also be determined differently for specific harms, such as liability for fire versus for injuries from downed power lines. • Inverse condemnation. If a governmental entity has an ownership interest in transmission lines and some form of liability for harm from the lines, policymakers could consider reforms to limit the scope or applicability of inverse condemnation claims for damage to property caused by fires resulting from the lines, as the IOUs currently face.
• Possible opposition from organized labor. Public utility unions are often closely tied to the IOUs, and different models of transmission ownership or financing could make the IOUs’ financial position, and associated union jobs and pay, more uncertain. Legislative leaders would need to conduct ongoing 10 Improving T ransmission F inanc ing in Cal ifornia
engagement and discussion with these unions to ensure their participation and recognition in new models.
• Availability of engineers. Most engineers are employed by private devel-opers. Public entities could face challenges hiring engineers with the req-uisite experience and expertise, which may be a factor in the role of any government entity in overseeing transmission lines and systems. • Eminent domain authority. Eminent domain authority is essential for build-ing new transmission lines, so which entities have that authority, particularly in the P3 context, is a crucial element in determining agency authority and responsibility.
RECOMMENDATIONS
Based on the convening discussion and CLEE research, this report offers the following potential solutions to the identified challenges:
1. Focus on demonstrating alternative financing arrangements for four to six key transmission regions and lines in the California Independent System Operator’s 20-year transmission outlook that most stakeholders agree are essential. Commonalities and differences among proposed locations, developer options, and other considerations for transmission lines will like-ly impact potential approaches to financing (see “next steps” below). For example, the potential large-scale solar development in the Westlands Wa-ter District area of Fresno County (approximately 110,000 acres with 15-20 gigawatts of solar) may be an ideal project to consider and evaluate, given the need for new transmission as part of the large-scale build-out and the current work to move forward with the project (see “next steps” below).
2. Engage the Governor’s Office to designate a coordinator for high priority lines and support a process to speed implementation and financing. This approach worked well when Governor Schwarzenegger des-ignated a coordinator for large-scale solar projects, making solar a statewide priority. The coordinator convened meetings with federal, state, and local government officials as well as stakeholders, coordinated state agency par-ticipation, and mediated disputes.
3. Establish a liability backstop for the entity or entities owning new transmission. As precedent, the California Legislature has established a liability backstop based on actions to reduce fire risk for the IOUs for the existing transmission system.
4. Minimize risk through insurance, contract, indemnity, and first loss protection, and other mechanisms, subject to negotiation and legisla-tion, as New Mexico has done through its Renewable Transmission Authority (RETA), discussed in Appendix 1 on page 16.
5. Modify California Independent System Operator rules to allow for an additional competitive bid process, opening more transmission to 11 Center For Law, Energy & the Environment
private development and private funding. Under existing California Inde-pendent System Operator rules, some (albeit few) potential transmission lines are already eligible for competitive bids by private developers. The operator has sufficient existing authority to expand the lines eligible for competitive bidding.
6. Explore credit enhancements from the state or federal government.
Credit enhancements have encouraged investment and reduced borrowing costs in multiple contexts. Examples could include the establishment of a state loan loss reserve, loan guarantee, or loan loss insurance to improve the creditworthiness of private transmission developers seeking financing.
The U.S. Department of Energy’s Loan Programs Office can also issue credit enhancements to state-administered clean energy programs.
7. Assess opportunities to finance some transmission lines through general obligation (GO) and revenue bonds, the former funded by tax-payers through the budget process to build needed infrastructure while reducing transmission costs included on ratepayer bills. However, a GO bond approach should only be implemented after serious consideration because relying on budget and legislative processes for funding can be politically fraught. Legislators could also explore issuing revenue bonds, which do not require voter approval and are used to finance income-generating projects built with the proceeds of the bonds.
8. Explore options for applying existing federal models to California.
Specifically, convening participants noted that the Western Area Power Ad-ministration (WAPA) could potentially finance transmission, or a state version of WAPA could be established (potentially within the Department of Water Resources) to finance transmission and provide electricity at a wholesale rate to municipal utility customers and community choice aggregators. This model is somewhat novel and warrants further evaluation.
CONCLUSION:
Reducing the cost of building needed transmission lines will only become more critical in the coming years, as electricity rates increase due to the strain of climate impacts on the grid and the large build-out required to electrify most energy needs. California policymakers can play a leading role in addressing this issue by exploring alternative options for transmission, potentially by starting with key, high-priority lines. Through an inclusive process, decisionmakers have an opportunity to meet the needs of var-ious stakeholders while accelerating the urgent construction of these lines. Ongoing research, convening, and implementation efforts can lay down a foundation for fu-ture work in California, serving as a model for other states and regions interested in pursuing alternative financing.
12 Improving T ransmission F inanc ing in Cal ifornia
References
1 See “2024 Q2 Electric Rates Report,” California Public Advocates Office. Available at: https://www.publicad-vocates.cpuc.ca.gov/press-room/reports-and-analy-ses/2024-q2-electric-rates-report (accessed October 18, 2024).
2 Nationwide, electric utilities averaged a 9.71% rate of return in rate cases in the first quarter of 2023, up
from an average of 9.54% in 2022. Dan Lowrey, “Elec-tric Beats Gas in Exceeding Authorized Equity Returns over Past 15 Years,” S&P Global, May 25, 2023. Avail-able at: https://www.spglobal.com/marketintelligence/ en/news-insights/research/electric-beats-gas-in-exceed-ing-authorized-equity-returns-over-past-15-years#:~:- text=The%20average%20ROE%20authorized%20
for,observed%20in%20full%20year%202022. (accessed
September 9, 2024).
14 Improving T ransmission F inanc ing in Cal ifornia
II. Appendix I: Approac hes to
Transmission Financing
This appendix explores options to reduce the cost and time needed for expansion of the electric transmission system within the state of California, as well as the hurdles and challenges to the various options.
The report includes (1) information on the transmission development and financing process in California, (2) a survey and evaluation of financial instruments that may be used to finance transmission, and (3) an initial assessment of potential policy options for California, including options for public financing and public-private partnerships.
Finally, the report sets out some initial legal and administrative considerations for various policy solutions.
The cost of transmission in California, currently borne primarily by utility ratepayers, is expected to increase by $45 to $60 billion over the next two decades, potentially spiking California’s already high energy rates.3 Key strategies for reducing this cost include public financing of transmission, public-private partnerships, green banks, credit enhancements (such as loan guarantees), and adoption of technologies that expand the capacity of existing transmission (such as reconductoring). In addition, moving some transmission costs from ratepayers to taxpayers could reduce the burden on electricity rates.
Each strategy has risks and benefits, so some mix of approaches may provide the most value. For example, a new government transmission agency may be best suited to finance major transmission lines that decision-makers have determined to be es-sential for California’s energy grid and renewables deployment, while some form or combination of public and private financing and loan guarantee through the California Infrastructure and Economic Development Bank (IBank) or other state institution may make sense for a subset of transmission needs. This appendix details some of the key risks and benefits, including cost savings, cost to state agencies, need for ongoing ex-pertise, relation of a new agency to existing agencies, state budget uncertainties, risks associated with loan guarantees, impact of loss of revenue for investor-owned utilities, and liability around public ownership of transmission lines, among other considerations. 16 Improving T ransmission F inanc ing in Cal ifornia
In light of the cost burden to ratepayers of the current approach to transmission, reforms are essential, and forms of public finance and direct public participation, including some role for a state transmission agency, provide possible benefits and challenges worth exploring.
CALIFORNIA NEEDS MORE TRANSMISSION CAPACITY
In 2022, the California Independent System Operator (CAISO) approved 23 new trans-mission projects, with an estimated cost of approximately $3 billion.4 In its 2022-2023
Transmission Plan, the California Independent System Operator identified a further need for $7.53 billion in transmission projects.5 This figure was based on studies indi-cating that California will need to add 40 gigawatts to the grid within a decade and 70 gigawatts by 2032 in order to maximize economy-wide electrification, particularly in the transportation and building industries.6 Looking even further into the future, the California Independent System Operator’s 20-year Transmission Outlook estimated that approximately $45 to $60 billion in investment over the next two decades will be necessary for California to reach its greenhouse gas emission reduction targets.7 But because transmission development is capital-intensive, access to capital remains a hurdle for would-be developers of transmission infrastructure in California. Under the current system, most transmission is financed by investor-owned utilities (IOUs) and paid for by utility ratepayers. Ratepayers also pay for a rate of return for the IOUs for each project, which can average close to 10%.8 This rate creates a significant and increasingly unsustainable burden on ratepayers as more necessary transmission lines are constructed. As a result, policymakers should consider and evaluate other options to transmission financing, including public financing, to meet California’s objectives.9 At the same time, the monetary value of new transmission is increasing because it will help relieve more grid congestion.10 In 2022, estimated savings from transmission expansion reached a decadal high of $200 to $300 million per 1000 MW of transmis-sion capacity (or $23 to $34 per MWh), varying by region.11 PUBLIC FINANCING COULD HELP MEET CALIFORNIA’S
TRANSMISSION NEEDS AFFORDABLY
In a recent analysis, the Public Advocates Office of the California Public Utilities Com-mission (CPUC) estimated that California ratepayers could save up to $28 billion over the coming decades “if California’s transmission infrastructure is financed with public investment as opposed to traditional utility-financing.”12 These savings to ratepayers from public financing result from public sector access to lower interest rates, replacing equity in project financing, and reducing taxes owed. The State of California has a better credit rating than do California’s IOUs, which makes it easier for the State to raise capital compared to IOUs.13 In addition, as noted above, IOUs receive a significant rate of return that adds substantial cost and creates an incentive for IOUs to pursue full build-out of transmission projects when alternatives such as reconductoring could be more appropriate. Financing through public bonds can also be tax free, yielding additional savings. Public financing would therefore relieve some of the burden on utility ratepayers. Finally, public financing combined with legislative reform focused on transmission lines determined to be essential to California’s clean energy needs 17 Center For Law, Energy & the Environment
could also streamline build-out, resulting in additional cost savings and accelerating uptake of renewables.
Given the potential benefits of public and public-private financing, this report explores its various pros and cons and implementation considerations, including the creation of wholly new state agencies, expanded authorities for existing agencies, and leveraging municipal and federal agencies that have the potential to finance transmission.
TRANSMISSION OVERVIEW: A LENGTHY, EXPENSIVE, AND
COMPARTMENTALIZED PROCESS
This section briefly surveys the transmission development process as context for discus-sion of transmission financing. Transmission development requires that a project survive an extensive and burdensome regulatory process before federal and state agencies.
Developing Transmission in California
CATF | Transmission Development in California – What’s the Slowdown? 3 From Concept to Completion –
How Transmission is Built in California
The CPUC typically anticipates major transmission projects require five or six years to progress from a concept to fully constructed under ideal conditions.3 In reality the process is often delayed and can take ten or more years to complete. The following section provides an overview of the key phases of the transmission development process, from concepts in CAISO’s Transmission Planning Process (TPP) to active transmission infrastructure.
New transmission projects are first identified in CAISO’s annual TPP. Most of these projects are built and owned by the incumbent utility providing retail service to the area, but major regional projects above 200 kV are awarded to developers following a CAISO-led competitive solicitation process. Developers may be the utilities or third-party companies specializing in transmission project design, construction, and operation. After the projects are awarded, developers will begin to design and scope the project and prepare permit applications for the CPUC. The CPUC then leads two review processes: an environmental review and a review for permits and certificates. Once the developer is awarded the necessary certificates and permits from this process, they are free to construct the project. Each of these phases is discussed in more detail below.
California’s Transmission Development Process
Responsible Organization:
CAISO
Developer
CPUC
PLANNING PERMITTING CONSTRUCTION
Annual Transmission
Planning Process (TPP)
Identifies and assigns new
transmission projects
Competitive Solicitation
Project is awarded to
developer
Pre-Application Planning
and Design
Coordination with CPUC
Submit
PEA to the
CPUC
Submit
CPCN or PTC
application
to the CPUC
CEQA
Environmental
Review
CPUC
Permitting
Review for
CPCN or PTC
Final Decision Review
by the CPUC
Certificates & Permits Issued
Obtain Additional Permits
from State Resource
Agencies as Required
Procurement and
Preliminary Engineering
Construction
3 California Public Utilities Commission (CPUC), “General Information on Permitting Electric Transmission Projects at the CPUC”, June 2009. https://www.cpuc.ca.gov/-/media/cpuc-website/files/legacyfiles/g/5065-general-information-on-permitting-electric-transmission.pdf Figure 1: chart from the Clean Air Task Force (Transmission Development in California – What’s the Slowdown [Jan 2023]) showing a simplified version of the transmission development process. This chart excludes the Federal Energy Regulatory Commission process for setting rates for interstate/high voltage transmission lines. 18 Improving T ransmission F inanc ing in Cal ifornia
Transmission development in California is a lengthy, expensive, and historically “re-active and compartmentalized” process (see Figure 1).14 It involves the participation of three primary parties: the transmission project developer, the California Public Utilities Commission, and the California Independent System Operator, plus the Fed-eral Energy Regulatory Commission (FERC) when developing high-voltage interstate transmission lines.15
First, the California Independent System Operator performs its annual Transmission Planning Process (TPP) to determine which transmission projects are needed on the grid.16 Through competitive solicitation, the operator awards a project to a particular developer.17
The developer coordinates with the California Public Utilities Commission on planning and design for its project before it officially submits its application.18 Then the de-veloper submits its application for a Certificate of Public Convenience and Necessity (CPCN) or for a Permit to Construct (PTC).19 The developer also submits its Propo-nent’s Environmental Assessment (PEA) to the California Public Utilities Commission.20 After receiving the PEA, the commission performs environmental review pursuant to the California Environmental Quality Act (CEQA).21
Following its review of the developer’s application and its environmental review under CEQA, the California Public Utilities Commission issues a final decision. If the commission decides to approve the project, it issues the relevant certificates and permits.22 The developer obtains any other necessary permits from state natural resource agencies and then begins procurement, engineering, and construction.23 In addition to California state regulations, federal law also applies to transmission projects that implicate “the transmission of electric energy in interstate commerce,” placing them within the reach of the Federal Power Act.24 The Federal Energy Regula-tory Commission (FERC) has jurisdiction “over all facilities for such transmission … of electric energy.”25 The Commission also has authority over the transmission revenue requirement, as the agency’s jurisdiction covers the establishment of the transmission revenue requirement through the Transmission Access Charge. But the Commission does not have jurisdiction over facilities “only for the transmission of electric ener-gy in intrastate commerce, or over facilities for the transmission of electric energy consumed wholly by the transmitter.”26 In other words, purely intrastate transmission projects that do not connect to the interstate grid are not subject to Federal Energy Regulatory Commission jurisdiction, but transmission projects that cross state lines or connect to the interstate grid are subject.27
Transmission Process Challenges
Beyond navigating the complex transmission permitting process, the transmission de-velopment process at both the federal and state levels encounters other legal and regulatory hurdles that can lengthen approval and development timelines and increase cost and risk for developers and ratepayers.
19 Center For Law, Energy & the Environment
Federal Challenges
Where lines are subject to federal approvals, three primary obstacles can hinder trans-mission development. First, if lines travel between California and neighboring states, the siting and approval process for those interstate transmission lines is divided among various state and local jurisdictions, making it more difficult for developers to acquire all necessary approvals and increasing the likelihood that one jurisdiction will block transmission even if all the other jurisdictions support the project.28 Second, the in-terconnection process is considered “speculative and opaque” because applicants are “unsure of the cost of interconnection until the [grid impact] studies are complete.”29 These studies and the energization process can create considerable uncertainty for and discourage developers. Third, where federal review is needed, lack of federal agency capacity to process permits can increase transmission development timelines.
California Challenges
As identified by the Clean Air Task Force in 2023, similar challenges for timely and cost-efficient transmission development exist for state-level approvals in California as well. Project dates “frequently stretch beyond completion dates anticipated by the California Independent System Operator.”30 Of thirteen projects reviewed in that publication, two were completed but delayed, two were canceled or put on hold by the California Independent System Operator, eight were delayed and incomplete, and one is incomplete but on schedule.31 Moreover, between 2013 and 2017, estimated final costs of CAISO-approved projects were 33% higher on average than the original costs submitted to the California Public Utilities Commission for those projects.32 In the California context, three key stages of the process that create most delays include preparation of the project application, California Public Utilities Commission environmental review, and federal agency review, when applicable.33 Recent agency coordination and legislation may help address delays and inefficiencies and drive down costs in the transmission development process. In December 2022, the California Independent System Operator, the California Public Utilities Commis-sion, and the California Energy Commission (CEC) entered into a Memorandum of Understanding with the goal of better coordinating transmission and resource planning and implementation across the state.34 For example, the California Independent Sys-tem Operator committed that its transmission planning process would “consider and incorporate the scenarios and portfolios developed by the [California Public Utilities Commission] with input from the [California Energy Commission],” and the California Public Utilities Commission in turn agreed that its “siting/permitting process will then give substantial weight to project applications that are consistent with the [Independent System Operator’s] final transmission plan.”35 Although it remains to be seen how the CAISO-CPUC-CEC Memorandum of Understanding will actually affect the transmission planning and development process over the medium- and long-term, better interagency coordination may help streamline the onerous approval and development process.
In October 2023, Governor Newsom signed Senate Bill 410 (Becker) to expedite in-terconnection.36 The new law requires that the California Public Utilities Commission establish “reasonable average and maximum target energization time periods … and a procedure for customers to report energization delays to the PUC” by September 30, 2024.37 SB 410 also mandates that the Commission require electrical corporations to 20 Improving T ransmission F inanc ing in Cal ifornia
“take remedial actions necessary to achieve the [CPUC’s] targets” and that “all reports … be publicly available[.]”38 In light of recent supply chain bottlenecks that have slowed grid buildout, SB 410 mandates that the Commission formulate and follow “realistic standards” for supply chains and workforce development.39
TRANSMISSION FINANCE OVERVIEW
Who Finances Transmission Today
Transmission lines in the U.S. are primarily owned by private, for-profit companies including IOUs, although a minority are owned by public entities including the federal government, municipally-owned utilities, and member-owned electric cooperatives.40 Most transmission development projects are taken on by incumbent transmission owners, rather than through competitive solicitation.41 Accordingly, the development of transmission lines is primarily financed up-front by private parties, with IOUs.42 Utilities have accelerated their nationwide spending on transmission in recent years, a trend also reflected in California. The California Independent System Operator’s 2022-2023 Transmission Plan proposed 45 new transmission projects for California at a combined estimated cost of $7.3 billion.43 IOUs are already raising capital to build out new transmission lines. For example, in March 2024 PG&E filed a request to raise up to $1 billion for transmission “by leasing parts of its transmission assets to Citizens Energy, a non-profit power provider” with the California Public Utilities Commission.44 Public funding of transmission has begun to take on a more prominent role in recent years, particularly at the federal level. The U.S. Department of Energy (DOE) now offers a $2.5 billion Transmission Facilitation Program for revolving loans, a $2.3 billion Grid Resilience State and Tribal Formula Grant Program, and a $3.25 billion Western Area Power Administration Transmission Infrastructure Program.45 On October 18, 2023, DOE also announced $3.5 billion in Grid Resilience and Innovation Partnerships Program investments, including substantial funds for transmission.46 Like the federal government, the state of California has also started to expand pub-lic financing options. For example, in 2020, the California Legislature created a $47 million Climate Catalyst Revolving Loan Fund within the California Infrastructure and Economic Development Bank (IBank).47 The Climate Catalyst Revolving Loan Fund, discussed further below, is a “green bank” intended to support small-scale renewable energy projects and vested with authority to finance transmission.48 Transmission costs may also be reduced by innovative engineering approaches, which may inform policymakers’ decisions regarding financing policies. For example, reconduc-toring, or replacing the conductors in existing transmission lines with newer conductors that carry more current, can be a cost-efficient way to increase overall transmission capacity. Reconductoring is eligible for federal loans from DOE under Section 1706 of the Inflation Reduction Act, which establishes the Energy Infrastructure Reinvestment loan program (discussed further below).49 Notably, reconductoring has not yet been widely adopted nationwide as a strategy to increase transmission capacity, in part because of the dominance of the utilities in the transmission space. Utility companies “earn a guaranteed rate of return on the cost of capital investments such as trans-21 Center For Law, Energy & the Environment mission projects, giving them no reason to strive to reduce those costs,” according to the DOE.50 And because the utilities “don’t bear the costs of transmission line losses, which are passed on to customers,” they have “little incentive to choose projects that emphasize those long-term savings.”51
Studies show that reconductoring, along with other grid-enhancing technologies, has the ability to unlock capacity and facilitate interconnection without requiring the con-struction of entirely new transmission lines.52 To address the challenge, Federal Energy Regulatory Commission Order 1920 now requires regional transmission planners to consider grid-enhancing technologies (GET) and other advanced grid technologies.53 However, even if transmission planners pursue these options, the grid will require sig-nificant new transmission infrastructure to meet renewable energy deployment goals.
How Transmission is Financed Today
The following table summarizes current and potential instruments for financing trans-mission projects as well as their primary benefits and drawbacks.
MECHANISM PROS CONS
Ratepayer charges: When IOUs build
transmission lines themselves, they
pass the cost to consumers through
Transmission Access Charges on
ratepayers’ electricity bills.
Currently enables utilities to play
a leading role in transmission
development with guaranteed profits
that support utilities’ continued
financial viability as providers of
electric service.
Results in high and increasing
charges to ratepayers, and market
distortions where ratepayers are
disincentivized from investing
in distribution grid assets that
rely on less or no transmission.54
For transmission projects
outside of the CAISO planning
process, utilities lack incentives
to pursue lower-cost options like
reconductoring because capital
expenses are added to their rate
base in ratemaking calculations.
For transmission lines within
the CAISO planning process,
Transmission Access Charges
create similar problems.
Private developer funding: Some
transmission projects are funded entirely
by private energy developers. As one
example, a privately funded and operated
TransWest wind project in Wyoming is
building its own dedicated transmission
line to California.
No direct taxpayer expense. Limited capital and slow
development of transmission.
Could add high and increasing
ratepayer costs.
22 Improving T ransmission F inanc ing in Cal ifornia
MECHANISM PROS CONS
Public co-development: P3
arrangements, in which both public
entities55 and private developers
participate, are an established means
of transmission financing. For example,
the New Mexico Renewable Energy
Transmission Authority (RETA),
discussed below, is a state agency that
serves as “co-developer” with private
development companies on a number of
transmission lines.
Rapid deployment of investment.
Some degree of public control
over projects, depending on the
government’s ownership share.
Requires significant outlay of
government funds.
Public loans: Public entities may issue
direct loans to private transmission
developers,56 including by the federal
government. For example, DOE is
newly empowered to issue loans
to transmission projects, through
the Transmission Facility Financing
program, under the Inflation Reduction
Act. Likewise, DOE’s Loan Programs
Office has authority to issue loans to
transmission projects.
Profit for issuing government agency. Requires upfront outlay of government funds pending
repayment.
Public bonds:
57 Public entities may
issue bonds in order to raise capital
for privately developed transmission
projects.58 For example, the New Mexico
RETA issued $50 million in revenue
bonds for transmission upgrades to the
privately-operated High Lonesome Mesa
wind farm.
Defers government and taxpayer
expense across long timeframe.
Government and taxpayers must
pay interest throughout the life of
the bonds.
Credit enhancements: Private and
public entities may issue59 credit
enhancements by providing a loan
loss reserve, a loan guarantee, or
loan loss insurance to improve the
creditworthiness of private transmission
developers seeking financing. DOE‘s
Loan Programs Office can issue credit
enhancements to state-administered
clean energy programs “[t]hrough
the State Energy Financing Institution
(SEFI)-Supported category of the Title 17
Clean60 Energy Financing Program.”
Support private access to investment
without directly involving public funds.
Outcomes are subject to private
investment decisions outside
government control.
23 Center For Law, Energy & the Environment
MECHANISM PROS CONS
Federal funds Substantial capital inde61pendent
of state and private funds.
Reconductoring projects are eligible
for IRA Section 1706 loans.
Outcomes are subject to federal
financing decisions outside state
government control.
Summary of Financing Mechanisms for California Transmission Ratepayer Charges
Ratepayers usually pay for transmission built by utilities, either through Transmission Access Charges (TAC) for projects within the California Independent System Operator jurisdiction or through regulator-approved rates for projects outside the operator’s jurisdiction. A TAC is “a two-part rate for each megawatt hour of internal load and exports and is used to recover transmission revenue requirements.”62 Notably, “trans-mission operations and maintenance (O&M) costs account for almost 10 times more cost impact on ratepayers than the upfront costs of transmission infrastructure[.]”63 These operations and management costs are assessed to ratepayers “for 50 years, the typical lifetime of transmission investments.”64
In assessing TACs, the utilities do not just recoup their costs: they also turn a profit.
Transmission is a capital expense, and the utility earns profits on these expenditures over a long period of time as the related asset depreciates.65 For transmission lines not approved by the California Independent System Operator — the majority of transmis-sion lines built in California — the capital cost of approved transmission construction is simply added to the utility’s rate base for purposes of ratemaking before the Cal-ifornia Public Utilities Commission.66 As public utilities, IOUs earn a guaranteed rate of return on these expenses.
Ratepayer and distributed generation advocates have also criticized ratepayer charges, as currently structured, for creating market distortions that disincentivize local clean energy development.67 Californians are charged for the transmission system even if they rely exclusively on locally generated electricity that may not require this infra-structure, therefore creating a potential disincentive to invest in the distribution grid.68 Bonds
Instead of passing costs directly to ratepayers, one particularly attractive option is to finance transmission by bonds issued by a government agency. These bonds can take two forms: general obligation (GO) bonds or revenue bonds.
GO bonds are paid out of the state general fund and are guaranteed by the full faith and credit of the state.69 GO bonds must be approved by a majority of the electorate voting at a general election or direct primary.70 By contrast, revenue bonds are used “to finance an income-generating project, such as water projects, higher education facilities or other public facilities built with the proceeds of the revenue bonds.”71 Income generated by the underlying project pays the principal and interest on its 24 Improving T ransmission F inanc ing in Cal ifornia
related revenue bonds.72 Unlike GO bonds, revenue bonds do not require voter ap-proval, and the state’s full faith and credit and taxing power are not pledged towards the repayment of revenue bonds.73
A lease revenue bond is a subtype of revenue bond where the “revenue stream paying the debt service on the bond is created from lease payments made by the occupying department to the governmental financing entity which constructs the facility or caus-es it to be constructed.”74 Regardless of whether the state agency in question issues revenue bonds or lease revenue bonds, it would not need a vote of the electorate to do so.75 However, from the point of view of an investor, GO bonds have historically been considered “more secure” compared to revenue bonds “because they are backed by the full faith and credit” of the government.76
Additionally, the bonds issued by a state authority to support transmission projects may be classified as “green bonds.” Green bonds can be unique from other govern-mental infrastructure bonds in that “(a) they finance projects that reduce/mitigate environmental impacts; (b) offer sufficient, if not robust, project detail in the Official Statement; and (c) ideally, offer an annual disclosure on the funded project’s envi-ronmental impacts.” As compared to rate-based transmission funding, bonds have advantages and disad-vantages. Historically, bonds have been used by government entities to finance large, capital-intensive infrastructure projects for two primary reasons: (1) the total sum is difficult to raise at once and (2) the paid-for project will provide benefits over a period of years, so policymakers consider it fair to make future generations of taxpayers pay their share.77 Additionally, most state bonds are tax-exempt, meaning that bondholders do not have to pay federal and/or state taxes on the interest they earn.78 For energy projects specifically, bonds are often selected as a financing option “because they are familiar, offer low borrowing costs, and have longer terms.”79 Bonds offer “security (e.g., assurance repayment will occur)[.]”80 If bonds are tax-exempt, their tax-exempt status “often translates to lower borrowing costs compared to alternative financing options.”81 In the transmission context, it may be easier for government agencies to issue bonds than to directly loan or appropriate the full sum it seeks to use to finance a transmission project.
Additionally, the long-term nature of transmission investments is consistent with common justifications for bond financing. Transmission projects are likely to be durable in the long-term, since they can last up to 100 years if properly maintained. This longevity is consistent with the idea that future generations of taxpayers will benefit from, and therefore should contribute to paying for, bonds.82
Because bond issuances involve relatively fixed transaction costs (ranging from 1-3% of bond proceeds depending on the size of the issuance), bonds are more cost-efficient “when used for larger dollar amount projects that can achieve economies of scale.”83 Individual transmission projects may be sufficiently large to benefit from relatively low transaction costs of bonding.84 Or a “pooled” bond issuance comprising multiple issuances for multiple projects would “reduce the transaction cost per dollar of … renewable energy work financed[.]”85
25 Center For Law, Energy & the Environment
When comparing state bonds to state loans, the state could directly loan funds to transmission developers rather than first issuing bonds to raise capital. This approach could be preferable because the government must pay interest on bond financing, but it does not have to pay interest on appropriations.86 Ratepayer Perspective: Rates v. Bonds
An important consideration for policymakers is the relative cost of ratepayer-funded transmission as compared to taxpayer-funded transmission to low-income Californians.
Electricity rates are subsidized for qualifying low-income California ratepayers. Under the California Alternative Rates for Energy (CARE) program, low-income ratepayers are entitled to a 30-35% discount on electric bills.87 In order to qualify, ratepayers must have household incomes below certain thresholds or be enrolled in certain public assistance programs like Medical or SNAP.88 In light of potential equity concerns, the relative burden of ratepayer financing versus bond financing to low-income Califor-nians will likely be an important topic for future research and a key consideration for policymakers choosing between financing mechanisms. This issue is particularly important given that electricity prices rose 5% over the last year, faster than inflation and the price of any other single commodity, partly due to the costs of transmission. 89 Credit Enhancements
A credit enhancement is any mechanism that “improves the chances that financing will be repaid.”90 For example, a credit enhancement can take the form of a loan loss reserve, a loan guarantee, or loan loss insurance.91 Credit enhancements can be used by state governments, the federal government, and private entities.
According to the U.S. Environmental Protection Agency, state governments usually offer credit enhancements either through (1) loan loss reserves (LLR) or (2) interest rate buy-downs (IRB).92 A LLR is a state government reserve of funds that “will cover a pre-specified amount of loan losses.”93 An IRB is a type of credit enhancement in which the government buys down the market interest rate of a loan by making a payment to the lender, making the loan easier to pay.94
MODELS FOR STATE TRANSMISSION FINANCE REFORM
This section of the report discusses various ways that California policymakers can either form new agencies, build out the capacities of existing agencies, or otherwise provide public support to accelerate transmission development. Potential institutional and policy solutions for public financing and other support of transmission in California are summarized as follows:
GOVERNMENT ENTITY IMPLEMENTATION PATHWAY
A new California “Renewable Energy
Transmission Authority”
Create authority to develop public transmission projects or co-develop private transmission projects. Create authority to issue bonds to raise revenue. 26 Improving T ransmission F inanc ing in Cal ifornia
GOVERNMENT ENTITY IMPLEMENTATION PATHWAY
A new California “Green Bank” Create authority to issue loans.
New municipal-level “Green Banks” Create authority to issue loans.
California Infrastructure and
Economic Development Bank (IBank) Expand existing authority to issue loans and credit enhancements.
California Alternative Energy and
Advanced Transportation Financing
Authority (CAEATFA)
Expand existing authority to issue bonds and loans.
California Public Utilities Commission
(CPUC)
Create authority to redirect AB 1373 funds from direct power procurement to transmission financing.
Department of Water Resources
(DWR)
Expand authority to use transmission lines and establish clear authority to construct transmission lines.
Federal government Coordinate state government support of public and private applications for strategic loans and project development assistance from the federal government.
Forming New or Expanding Existing Agencies
The California Legislature could consider forming new agencies, including a Renewable Energy Transmission Authority, that could serve as a public transmission developer or a statewide “Green Bank,” or authorize municipalities to form their own local “Green Banks.”
The creation of a new state agency, such as a Renewable Energy Transmission Authority or a California Green Bank, would raise important legal, budgetary, and governance considerations. Some of these include:
• Enabling legislation. A new state agency would require a new organic statute, as opposed to an amendment to an existing agency’s organic statute. • Budget demands. A new state agency would require appropriations to build up its staffing, capacity, and physical resources.95 • Governance design. Creating a new agency would require policymakers to consider how to allocate decision-making authority, for example by estab-lishing a supervisory board or commission with members appointed by the governor or selected by the governor and legislature together. • Relationships with existing entities. Creating a new agency with trans-mission mandates would require policymakers to consider how to eliminate duplication or avoid interference with the responsibilities of existing bodies such as the California Independent System Operator, the California Energy Commission, and the California Public Utilities Commission.96 27 Center For Law, Energy & the Environment
1. A Renewable Energy Transmission Authority
California could establish a new Renewable Energy Transmission Authority (RETA), drawing inspiration from New Mexico’s RETA97 and the Colorado Electric Transmission Authority.98 The Public Advocates Office of the California Public Utilities Commission recently recommended that California policymakers explore an infrastructure authority in the style of New Mexico’s RETA as a transmission development option that would reduce ratepayer costs.99
a. New Mexico Renewable Transmission Authority
New Mexico’s RETA was established by the state legislature in 2007 to “plan, finance, develop and acquire high voltage transmission lines and storage projects in order to promote economic development in New Mexico.”100 As of 2021, it was “one of seven state-level transmission authorities in the United States and only the second to have issued Bonds.”101 New Mexico RETA-sponsored projects must include 30% of their power from renewable resources, and current projects are planned to have 100% of their power originate from renewable resources.102
The Renewable Transmission Authority Act, which created New Mexico’s RETA, may offer lessons for California legislators. The Act, created by House Bill 188 (2007), moved through the New Mexico legislative process with relative ease.103 Governor Bill Richardson signed the RETA Act into law on March 5, 2007.104 The state’s RETA is overseen by a mix of legislative and executive appointees.105 Three members are appointed by the governor and confirmed by the state senate. One is the state treasurer or his designee, one is appointed by the speaker of the house of repre-sentatives, and one is appointed by the president pro tempore of the state senate.106 RETA has statutory authority to issue bonds and enter into contracts for the lease and operation of its facilities, provided that the agency deposit any revenue into a renewable energy transmission bonding fund.107 Further, New Mexico RETA can collect payments of “reasonable rates, fees, interest or other charges” to finance the facilities and other services, with the similar deposit requirement. The agency can also borrow money and take out mortgages.108 According to New Mexico RETA’s website, the au-thority “derives its funding from developers based upon services provided by RETA.”109 New Mexico RETA is not limited to financing and developing purely public projects — it also has the ability to collaborate with private developers. The organic statute specifically provides that New Mexico RETA may “enter into partnerships with public or private entities[.]”110 New Mexico actively exercises this authority to partner with private entities on transmission lines, both as a co-developer and as a financier.
For example, the Western Spirit Transmission Line was developed jointly by the RETA and Pattern Energy Group LP, a private energy company.111 New Mexico RETA is a “co-developer” with a private development company for each of the four transmis-sion lines currently in development — Rio Sol, SunZia, North Path, and the Mora Line Project.112 And New Mexico RETA provided only financial support — $50 million in revenue bonds — for transmission upgrades to the privately-operated High Lonesome Mesa wind farm.113
28 Improving T ransmission F inanc ing in Cal ifornia
b. Colorado Electric Transmission Authority
In 2021, the Colorado Legislature created the Colorado Electric Transmission Authority (CETA) as an independent special purpose authority with Senate Bill 21-027.114 Governor Jared Polis signed the bill into law on June 24, 2021.115 Opposition to SB 21-027 was primarily articulated as concern about increased costs to consumers. Xcel Energy-Colorado, the state’s largest electric utility, claimed that the bill language “duplicates the existing well-established and transparent transmission planning processes” and raised “concern[] this would result in higher costs for our customers without oversight.”116 Although Xcel Energy phrased its concern about the bill in terms of cost to ratepayers, the bill would also increase potential competition for transmission development in the state. The utility had “recently proposed building a $1.7 billion, 560-mile corridor of transmission lines in mainly rural areas.”117 Today, CETA is a “transmission builder of last resort” intended to step in where pri-vate developers are unable or unwilling to build transmission.118 CETA has statutory authority to own property and enter into leases and contracts,119 identify and establish transmission corridors,120 participate in interstate transmission planning,121 exercise eminent domain,122 and issue and sell electric transmission bonds to raise revenue for transmission projects.123 CETA is anticipated to receive “most of its funding from fees charged to developers and users of CETA-managed systems.”124 Like New Mexico’s RETA, CETA is governed by a mix of executive and legislative ap-pointees, although power is shared more evenly between the two branches of gov-ernment.125 Two members of the board of directors are “appointed by the governor with the consent of the senate,” one members is the “director of the Colorado energy office” or the “director’s designee[,]” three members are “appointed by the speaker of the house of representatives[,]” and three members are “appointed by the presi-dent of the senate.”126 c. Imagining a California RETA
California could implement a RETA with the same kind of flexibility that New Mexico RETA enjoys. Its enabling statute could ensure that the RETA is empowered not only to self-finance and develop transmission lines, but also to collaborate with private developers that can provide additional capital, capacity, and expertise.127
2. A state “Green Bank”
California could create a new, public “Green Bank” dedicated to financing transmission statewide. According to the Coalition for Green Capital, a “green bank” is a governmen-tal, quasi-governmental, or nonprofit institution that provides financing for renewable energy and/or transmission projects.128 A number of jurisdictions have already created freestanding public green banks.129 Some examples of jurisdictions with green banks include Nevada,130 Colorado,131 Connecticut,132 New York,133 and Washington D.C.134 The Connecticut Green Bank, formed in 2011, is the oldest and most established.135 29 Center For Law, Energy & the Environment
An important choice policymakers face when establishing green banks is whether to form them as independent nonprofits or as agencies of the state government. Some green banks are nonprofits created by, but legally separate from, the state government.
For example, the Nevada Clean Energy Fund was formed by Nevada’s SB 407 (2017) as an independent nonprofit and launched in January 2022.136 Likewise, Colorado Clean Energy Fund was created as a nonprofit in 2018 by Colorado Governor John Hick-enlooper.137 The Colorado Clean Energy Fund subsequently received a one-time $40 million appropriation from the Colorado Legislature in 2021, but otherwise remains separate from the state government.138
However, there are also examples of green banks created not as independent non-profits but as government agencies. The D.C. Green Bank, for example, was created by the Green Finance Authority Establishment Act of 2018 (D.C. Law 22-155), which established a “Green Finance Authority” within the District government.139 Likewise, the New York Green Bank is an entity of the New York state government — it is a division of the New York State Energy Research and Development Authority.140 In the view of the Coalition for Green Capital, California already has at least one green bank. The Coalition identifies the California Infrastructure and Economic Development Bank (IBank)’s Climate Catalyst Revolving Loan Fund, established in 2022 with $47 million in capital, as a green bank.141 Therefore, the creation of a new, standalone California green bank could arguably be unnecessary and duplicative of IBank’s existing Climate Catalyst Fund.
But there may be advantages to the Legislature creating a new green bank, either as a state government-supported nonprofit or as a state government authority or agency, dedicated to transmission finance rather than building off of the Climate Catalyst Fund.
Benefits of a new, transmission-focused green bank may include a greater amount of capital available for projects and increased willingness on the part of a new green bank to fund large, institutional projects rather than smaller, riskier projects which the Climate Catalyst Fund was intended to support.142
3. Municipal-level Green Banks
Instead of (or in addition to) a single, statewide green bank, California might decide to allow municipalities to create their own green banks. Municipal green banks can increase the availability of local capital, but this capital would likely be less than a single statewide green bank, and potentially contribute to more piecemeal financing than a statewide green bank.
Municipal-level public banking is an emerging practice in California143 since the passage of Assembly Bill 825 (2020), which created a process for a local agency to establish a public bank.144 The text of AB 825 makes it clear that the Legislature intended municipal banks to serve the public interest: “achieving cost savings, strengthening local econ-omies, supporting community economic development, and addressing infrastructure and housing needs for localities[.]”145
Because they are governmental and not private banks, municipal banks can be subject to the political priorities of the municipal constituency and directed to finance partic-ular issues, which could include clean energy infrastructure. Therefore, some experts 30 Improving T ransmission F inanc ing in Cal ifornia
have noted the potential for municipal banks in California to finance transmission146 in addition to other renewable energy projects.147 Municipal-level green banking might also lead to an increase in the community’s engagement with, awareness of, and in-vestment in transmission projects of local significance (recognizing that it could also engender additional local opposition).
In addition to generic municipal banks that can choose to support transmission proj-ects — which is now possible under AB 825 — the California Legislature could go even further and explicitly authorize municipal green banking by providing statutory language directed towards the financing of renewable energy projects including trans-mission lines.
Virginia is already experimenting with this type of municipal-level “green” banking. In March 2021, Virginia passed a law allowing municipalities to create their own green banks.148 Virginia municipal green banks may do the following:
• Finance investment or support of investment in clean energy technologies to foster the growth and development of renewable energy sources149 • Stimulate the demand for renewable energy and the deployment of clean energy technologies that serve end-use customers150
• Provide financing or financial support for clean energy technologies151 To date, municipal green banks have “focus[ed] on smaller-scale clean energy projects” and not larger projects like transmission.152
One model for a discrete municipal-level green bank can be found in the Philadelphia Green Bank,153 the “nonprofit green bank affiliate” of the Philadelphia Energy Authority, an independent municipal authority focused on energy affordability and sustainability in the City of Philadelphia.154 The Philadelphia Green Bank launched in 2021 with $250 million to invest.155 Like Virginia’s municipal-level green banking, the Philadelphia Green Bank is aimed mostly at smaller-scale projects: “providing financing solutions that focus mainly on areas that have not traditionally had easy access to capital for green projects including low-income homes, small and medium-sized businesses, nonprofits, and multifamily buildings.”156 Municipal-level green banking may therefore either be a supplementary (not primary) source of financing for transmission or a source of financing for smaller-scale projects.
Expanding Existing Agencies
Instead of creating a wholly new state agency, California policymakers could instead expand the capabilities and legal authorities of existing agencies like the California Infrastructure and Economic Development Bank (IBank), the California Alternative Energy and Advanced Transportation Financing Authority (CAEATFA), the California Public Utilities Commission, and the Department of Water Resources (DWR).
1. Expanding IBank
California could expand IBank’s current authority, including its new Climate Catalyst Revolving Loan Fund, and further tailor its authorities for transmission financing.157 31 Center For Law, Energy & the Environment
IBank is a California state agency created in 1994 to finance public infrastructure and private development.158 One of IBank’s primary functions is offering traditional infrastructure loans for projects like street repairs and water treatment plants. These infrastructure loans are currently only available to state and local government entities, not private developers.159
a. Loans
The Climate Catalyst Revolving Loan Fund represents IBank’s first major foray into renewables infrastructure financing. According to the Climate Catalyst Fund’s guidelines, the Fund prioritizes “projects that advance the state’s climate goals, covering both climate mitigation (the reduction of climate harms by addressing the root causes of climate change) and climate resiliency (infrastructure investments that improve our ability to withstand and manage the effects of a changing climate).”160 At present, the Climate Catalyst Fund supports three categories of projects.161 These include (1) projects “that reduce wildfire threats through forest biomass management and utilization[,]” (2) projects “that increase access to zero-carbon resources through new clean energy transmission infrastructure[,]” and (3) projects that “promote cli-mate-smart technologies and practices across the agricultural value chain[.]”162 Notably, IBank’s Climate Catalyst Fund already has specific legal authority to finance transmission.163 The operative statute provides that IBank shall establish a separate “Clean Energy Transmission Financing Account” within the Fund.164 Eligible transmission projects must meet the following conditions to receive IBank funding:
• Has at least one interconnection point within a California balancing authority area.165
• Has a developer or associated applicant who has previously completed a transmission project in California.166
• Will primarily deliver electricity to the Independent System Operator balancing authority area from clean resources located in identified resource areas that do not have adequate deliverability to a California balancing authority area.167 • Will support new high-voltage (200 kilovolts or higher) transmission projects or upgrades of existing transmission lines and high-voltage substations that are consistent with the state’s reliability and greenhouse gas policy objectives.168 • Must also have entered into a project labor agreement that meets the require-ments of Section 2500 of the Public Contract Code (including a prevailing wage agreement), target hiring provisions for disadvantaged workers, and offer apprenticeship utilization provisions.169
Priority shall be given to transmission projects that have not already been approved through the Independent System Operator’s transmission planning process or projects that have not been recently studied in the Independent System Operator’s transmission planning process and found to be unneeded or uneconomical.170 32 Improving T ransmission F inanc ing in Cal ifornia
Additionally, the funded Climate Catalyst project or projects can support new resources located in the Salton Sea region.171 The 2022 Budget Act specifically “included $250 million for transmission line project financings with an initial focus in Lithium Valley, $200 million in 2022-2023 and $50 million in 2023-2024.”172 Ultimately, IBank would need expanded staff capacity in order to support transmission financing on the necessary scale. As of report publication, IBank had a total of 37 em-ployees, only two of whom are dedicated to the “Climate Financing” team.173 But to the extent that IBank already has statutory authority to provide loans to transmission projects — and likely only needs an increase in available funds and staff capacity — it could be a strong contender to lead California’s public financing of transmission. b. Credit Enhancements
Separately from its lending powers, IBank could use its credit enhancement authorities to help private transmission developers seek non-state financing by boosting the cred-itworthiness of those developers.174 IBank is empowered to make credit enhancements as “financial assistance for a project.”175
IBank has issued credit enhancements in the context of its Small Business Loan Guar-antee Program, which was intended to help small businesses qualify for a term loan or line of credit.176 This credit enhancement, as the name of the program suggests, was a loan guarantee.
Compared to public loans, credit enhancements require less initial cost because the state would be guaranteeing a loan, reserving specified funds to cover partial loan losses, or making only an initial payment against loan interest, rather than issuing a loan in its entirety. However, because credit enhancements are not direct public financing, but rather public support for private financing, the underlying financing decisions are subject to the decisions of private investors. Potentially, the state or other credit enhancement provider could impose requirements as a condition for a credit enhancement, similar to conditions imposed on bonds. Additionally, IBank would need to decide which kinds of developers receive its credit enhancements. If IBank were simply subsidizing IOU-developed transmission lines with credit enhancements, this support would probably not address the problem of rising ratepayer expenses.
2. Expanding CAEATFA
California could build off of the California Alternative Energy and Advanced Transpor-tation Financing Authority (CAEATFA),177 which issues some bonds to green projects.178 CAEATFA is a state government authority sitting at the intersection of climate and finance policy. It has five members: the Director of Finance, the Chair of the California Energy Commission, the President of the California Public Utilities Commission, the State Controller, and the State Treasurer (who chairs the authority).179 As it currently exists, CAEATFA has a small staff of only 25 employees, with two vacant positions.180 Of those, 15 employees and 1 vacancy are devoted to the “CHEEF” program for energy efficiency retrofits.181 Therefore, if CAEATFA were to assume a larger role 33 Center For Law, Energy & the Environment
in transmission financing, such a mandate would likely need to be accompanied with an increase in capacity and funding.
Compared to other renewable energy state agencies, CAEATFA is a relatively estab-lished authority, formed in 1980.182 The agency was originally named the “California Alternative Energy Source Financing Authority”183 and was renamed in 1995 to its current name to reflect its expanded mandate.184
Although it is a relatively small entity, CAEATFA’s statutory mission statement suggests that, with minor statutory amendments, it could be well-suited to finance transmis-sion.185 CAEATFA’s objective is to “advance the state’s goals of reducing the levels of greenhouse gas emissions, increasing the deployment of sustainable and renewable energy sources, implementing measures that increase the efficiency of the use of energy, creating high quality employment opportunities, and lessening the state’s de-pendence on fossil fuels[.]”186 To that end, CAEATFA is charged with providing “an alternative method of financing in providing and promoting the establishment of both of the following:
• Facilities utilizing alternative methods and sources of energy.187 • Facilities needed for the development and commercialization of advanced transportation technologies.”188
CAEATFA has an expansive toolkit that it may use to financially support deserving projects, including both bonds and loans. First, CAEATFA has broad authority to issue bonds, notes, and other obligations.189
Second, CAEATFA can issue loans. CAEATFA’s statutory authorities also enable it to “provide financial assistance to a participating party, to enter into loan agreements with a participating party for the financing of a project including creating a lien or security interest in the property, to construct, reconstruct, renovate, replace, lease, as lessor or lessee, and regulate the same, and to enter into contracts for the sale of a project, including installment sales or sales under conditional sales contracts.”190 CAEATFA currently issues bonds for only two purposes, neither of which relates to transmission. First, CAEATFA issues “Qualified Energy Conservation Bonds,” which are tax credit bonds that “can be used for projects that reduce energy consumption in publicly owned buildings, implementing green community programs, rural development involving the production of electricity from renewable energy resources, technologies that capture and sequestration of carbon dioxide produced by fossil fuels, technologies that reduce energy use, and more.”191 Second, CAEATFA issues private activity bonds to provide long-term financing for district heating and cooling.192 CAEATFA would likely require a statutory amendment in order to finance transmission, regardless of whether it uses bonds or loans. Nothing in CAEATFA’s organic statute specifically references transmission projects. Rather, CAEATFA is generally empowered to support “project[s],” defined broadly as “land, building, improvement to the land or building, rehabilitation, work, property, or structure … [including] machinery and equipment utilized in the state … that utilizes, or is designed to utilize, an alternative source, or that is utilized for the design, technology transfer, manufacture, production, assembly, distribution, or service of advanced transportation technologies or alterna-34 Improving T ransmission F inanc ing in Cal ifornia tive source components.”193 The CAEATFA’s definition of “project” does not include transmission infrastructure. As a result, CAEATFA cannot currently fund “projects” that only constitute transmission lines. And under its present regulations, CAEATFA only actually finances residential and commercial clean energy upgrades.194 But with additional funding, increased staff capacity, and an explicit statutory directive to fund transmission, CAEATFA could be an important source of public financing for trans-mission projects in California.
3. Department of Water Resources: Building off AB 1373
New legislation, building off of AB 1373, might permit the state to finance new trans-mission through revenues generated from direct power procurement. AB 1373 (Garcia, 2023) empowered the DWR, when directed by the California Public Utilities Commission, to directly procure renewable energy.195 AB 1373 promotes resources like offshore wind and geothermal energy, because those sources “often carry higher maintenance, operation, or development costs, resulting in individual Load-Serving Entities (LSEs) – companies or agencies that provide electrical powers to everyday Californians – forgoing investment[.]”196 The legislature could relatively straightforwardly add transmission financing to the Department’s authority.
a. California Public Utilities Commission
Under AB 1373, the California Public Utilities Commission has authority to identify procurement needs through the existing Integrated Resource Planning (IRP) process and request that the Department of Water Resources procure needed resources after six months.197 This six-month window is intended to allow other load-serving entities to procure their share of their load if they elect to do so, a long-held principle pre-viously applied to community choice aggregators (CCAs).198 Importantly, AB 1373 contains two new financial authorities.199 First, the bill gives the California Public Utilities Commission the authority to impose a non‑bypassable charge to ratepayers to cover the Department of Water Resources’ procurement costs, as long as the commission finds that the charge would not “unreasonably increase costs to customers[.]”200 A new “Eligible Energy Resource Central Procurement Fund” will receive these customer charges and support the Department’s procurement activities.201 Second, AB 1373 gives the Department the authority to issue bonds, if necessary, to fund upfront costs for its central procurement activities.202 These bonds will be repaid with the ratepayer charges received by the Clean Energy Procurement Fund.203 Through these authorities, the bill can provide a stepping-stone for the Department to play a prominent role in transmission development. In particular, AB 1373 direct procurement may provide a new revenue source for transmission financing. Direct procurement under AB 1373 empowers the California Public Utilities Commission to directly charge ratepayers on the Department’s behalf, bypassing the IOUs entirely, and funnel the revenues into the Clean Energy Procurement Fund.204 AB 1373 alone will not funnel ratepayer charges to transmission financing. Under the current bill text, the Clean Energy Procurement Fund can only be used for limited purposes, which does not include financing for new transmission infrastructure.205 35 Center For Law, Energy & the Environment
The bill authorized payments for the fund only to satisfy “bonds or other contractual obligations,” “cost of energy and transmission, scheduling, and other related expenses,” and administrative costs incurred through direct procurement.206 The legislature specifically provided that the Department of Water Resources is pro-hibited from “recovering funds pursuant to a nonbypassable charge on the ratepayers of a load-serving entity for purposes other than providing for the department’s acqui-sition costs for eligible energy resources, including transmission, scheduling, financing, program administration, and other related costs[.]”207
However, if the Clean Energy Procurement Fund has sufficient revenue from direct procurement charges to ratepayers to cover its expenses with a surplus remaining (even though the California Public Utilities Commission’s charges to ratepayers would be limited by the mandate that they not unreasonably increase costs to customers208), the fund could serve as a new revenue source for transmission finance in the future.209 But this purpose would require a statutory change providing that charges could be assessed and withdrawals from the fund made for that purpose.210 b. Department of Water Resources
Although the Department has transmission-related authorities, some of which predated AB 1373, these powers are relatively limited. Since the 2000-2001 energy crisis, the Department has had the authority to purchase power on behalf of California’s retail customers.211 The relevant provisions of the Water Code grant the Department some limited powers with respect to transmission. The Department may “pay or provide for the payment of power or use of transmission” facilities related to its contracts to purchase power.212 The agency may then contract with an electrical corporation “to transmit or provide for the transmission of” power made available by the Depart-ment.213 In 2023, AB 1373 added one more state authority related to transmission; at the request of Department leaders, the California Public Utilities Commission may “order an electrical corporation… to transmit or provide for the transmission of… all electricity made available by the department[.]”214
The common thread through these statutory provisions is that the Department of Water Resources may “provide for” transmission and the use of transmission facilities.
A conservative reading of this phrase suggests that the Department may make use of existing transmission facilities incidental to its power purchase and sale contracts but that it does not have clear authority to create new transmission lines as part of “provid[ing] for” transmission.
If the California Legislature wanted to empower the Department to not only use, but also create, transmission infrastructure, then it could easily do so by sharpening the language in these sections. For example, a revised Section 80102, subdivision (c) of the Water Code might read “[n]otwithstanding any other provision of law, the department may pay or provide for the payment of power, or for the construction and/or use of transmission or distribution facilities and other related services prior to the delivery or utilization thereof, provided that the department determines that prepayment is beneficial to ratepayers and that adequate provision has been made for the security of the department.”215
36 Improving T ransmission F inanc ing in Cal ifornia
OTHER OPTIONS FOR PUBLIC SUPPORT
1. Leveraging Federal Support
As the Public Advocates Office has proposed, California could leverage “federal financing programs such as the U.S. Department of Energy’s Western Area Power Administra-tion’s (WAPA) transmission finance program.”216 According to the Roosevelt Institute, the federal government may be uniquely well-positioned to provide funding for trans-mission, since as compared to incumbent investor-owned utilities and independent system operators (ISO/regional transmission operators or non-utility private players), it is “a strong regional and interregional mandate, long-term planning horizons, and an ability to absorb the financial risks[.]”217
Western Area Power Administration’s Transmission Infrastructure Program California-based transmission projects could take advantage of the Western Area Power Administration’s Transmission Infrastructure Program, which has a primary goal to leverage federal funds and attract private and other non-federal investment to support the development of critical transmission and related infrastructure.218 The Transmission Infrastructure Program manages the Western Area Power Administration’s $3.25 billion borrowing authority (referring to funds borrowed by the Administration from the Treasury).219 The Western Area Power Administration can offer both strategic loans and project development assistance to transmission developers.220 In order to receive Administration support, prospective utility-scale transmission proj-ects must demonstrate that they will, at minimum:
• Have at least one terminus in the Western Area Power Administration’s 15-state service territory221
• Demonstrate a reasonable expectation of repayment222
• Facilitate the delivery of clean energy223
• Not adversely impact system reliability or operations224 • Serve the public interest.225
The Western Area Power Administration has previously supported transmission projects, including the 254 MW Electrical District 5 – Palo Verde Hub line in Arizona, which is in active repayment status, and the MATL line delivering wind energy from Montana, which received and fully repaid a $162 million construction loan.226 The state could leverage the Western Area Power Administration’s Transmission In-frastructure Program through the following:
• Promoting private applications for Administration funding to the federal government and expressing the state government’s support for those ap-plications to the Western Area Power Administration. • Applying, directly or through a private partner, for Administration funding for public-private partnership (P3) projects.
37 Center For Law, Energy & the Environment
• Applying directly for Administration funding for purely public transmission projects. The U.S. Department of Energy’s Western Area Power Administration regulation defines “Project Applicant” only as “an entity that submits a Proj-ect Proposal and Business Plan Proposal” and does not seem to distinguish between public and private applicants.227 Therefore, state governments, if acting as transmission developers, may be eligible for Administration funds. • Coordinating Administration funds with state government financing options, such as funds from IBank or CAEATFA.
2. Public-Private Partnerships
In addition to supporting purely private transmission projects, the state could enter into public-private partnerships (P3) with private entities, which could encompass virtually all of the institutional options listed above.
Defining P3
P3 commonly refers to long-term (typically 25 or more years) performance-based contracts with public-sector entities in which the private sector takes or shares re-sponsibility and risk for the design-build-finance-operate-maintain (DBFOM) elements of a public infrastructure project.228
The state of California has ample experience with P3 development projects, albeit in other contexts. According to the Bay Area Council Economic Institute, in 1989 California was one of the first states to pass P3 legislation, and two of the nation’s first P3 highway projects were built in Southern California under that legislation.229 Potential models for state public-private partnerships may be found in Caltrans’s P3 arrangements for transportation projects,230 the University of California’s privatized development projects,231 and the state-private Hydrogen Fuel Cell Partnership.232 Supporters of P3 development argue that it provides an important option for public agencies, which may not have capacity or expertise to complete development projects on their own.233 But critics argue that P3s may “not provide the transfer of risk that they promise” and that the public sector could ultimately be responsible for any cost overruns, which could result in higher costs for taxpayers and ratepayers.234 P3 Transmission
According to the Public Advocates Office, which has encouraged the state to explore public-private arrangements to finance transmission in addition to purely public financing approaches, public-private partnerships “would likely result in intermediate ratepayer savings between the bookends of pure public and pure private investment options.”235 38 Improving T ransmission F inanc ing in Cal ifornia
a. Section 1222: Federal Co-Ownership Model
A potentially illustrative model for public-private transmission development, albeit at the federal level, is the Department of Energy’s Section 1222 Program.236 Under Section 1222, part of the Energy Policy Act of 2005, the Secretary of Energy has authority to “design, develop, construct, operate, own, or participate with other entities in designing, developing, constructing, operating, maintaining, or owning two types of projects[.]”237 First, DOE can co-develop electric power transmission facilities and related facilities needed to upgrade existing transmission facilities owned by the Southwestern Power Administration (SWPA) or by the Western Area Power Administration.238 Second, DOE can co-develop new electric power transmission facilities and related facilities located within any state in which the Southwestern Power Administration or Western Area Power Administration operates.”239 Section 1222 represented “a broad expansion of federal involvement in electric transmission siting and development[.]”240 But Section 1222 has been underutilized in the nearly 20 years since its enactment.
DOE issued its first request for proposals under Section 1222 in 2010.241 In March 2016, DOE published its decision to partner with Clean Line Energy Partners via the Southwestern Power Administration.242 But this Clean Line project fell apart due to “political and commercial” pressures, and Section 1222 has been neglected since.243 Despite its underutilization in practice, however, Section 1222 is an important prece-dent and statutory model for P3 transmission development.
Whether or not a P3 program to encourage transmission development or provide financing requires an act of the California Legislature would depend on how such a program was structured. Not all public-private partnerships exist by virtue of statute.
For example, the Hydrogen Fuel Cell Partnership (H2FCP) is a “collaborative of auto manufacturers, energy companies, fuel cell technology companies and government agencies” that work to promote hydrogen fuel cells.244 Among other public agencies, the Governor’s Office, California Air Resources Board (CARB), and California Energy Commission are members of the H2FCP, which evolved out of 1999’s California Fuel Cell Partnership.245 The H2FCP is a nonprofit public benefit corporation.246 If a transmission-promotion P3 were similarly arranged as a nonprofit corporation or as an informal association of state agencies and private entities, then it is possible that, like the H2FCP, it would not require any enabling legislation, so long as the state agencies would act within their existing authorities.247 However, if a transmission P3 were to directly apply new state authority into the transmission development process, then enabling legislation, like the legislation that empowered Caltrans to build P3 transportation projects,248 would be appropriate.
For example, as previously discussed, a Renewable Energy Transit Authority (RETA) would need an organic statute before the RETA could enter into P3 arrangements with private developers.249
39 Center For Law, Energy & the Environment
b. The “Citizens/Morongo” Public-Private Model
The “Citizens/Morongo” approach to transmission ownership, financing, and siting may provide a particularly useful model for public-private partnerships in situations where local communities are opposed to and/or will suffer uncompensated losses from transmission projects.
The “Citizens/Morongo” model, a term coined by former Federal Energy Regulatory Commissioner Suedeen Kelly,250 refers to an ownership arrangement between Citizens Energy, the Morongo Band of Mission Indians, San Diego Gas & Electric, and Southern California Edison.251 Citizens Energy and the Morongo Band, working as a joint venture, purchased a 30-year leasehold interest in a utility-operated transmission line running through Morongo land.252 Following approval of the transaction by the Federal Energy Regulatory Commission, the Morongo Band became the first Native American Tribe to have an ownership interest in transmission in the United States.253 This “Citizens/Morongo” model is intended to better align the costs and benefits of transmission to local communities in order to accelerate the siting process. As joint owners of the transmission line, Citizens Energy and the Morongo Band distribute the profit made from transmission rates to nearby local governments and the Morongo Tribal government.254 The Federal Energy Regulatory Commission’s sign-off on three aspects of the arrangement were critical.
First, Citizens and Morongo can “raise the capital for the investment with 100% debt rather than a combination of debt and equity. This both lowers the cost of the in-vestment and makes it possible for these entities, which do not have easy access to equity, to participate in the joint venture.”255 Since the Federal Energy Regulatory Commission usually prefers a roughly 50-50 ratio between debt and equity financing, in order to mitigate risk and confirm that transmission developers are capable of raising equity, the Commission’s approval of a 100% debt and 0% equity formula is unusual.
Second, the Federal Energy Regulatory Commission approved an “essentially fixed, 30-year transmission rate rather than a stated or formula rate subject to change through a Federal Power Act Section 205 or 206 action.”256 This fixed transmission rate “provides the certainty needed by Citizens/Morongo to procure the long-term debt at the lowest possible rate.”257
Third, Citizens and Morongo can charge the same rate as that charged by San Diego Gas & Electric and Southern California Edison.
258 Since the utilities’ rates “recover
costs which they incur but Citizens/Morongo do not (e.g., taxes and return on equity), Citizens/Morongo distributes this part of the revenue to the impacted communities to compensate for the intangible costs of transmission siting borne by them.”259 The Citizens/Morongo joint venture appears to have been relatively uncontroversial. In addition to its partnerships with major IOUs, the project received support from the “US Department of the Interior, the Governor of California, the California Public Utilities Commission, the California Independent System Operator, Los Angeles Department of Water and Power, California lawmakers, and the Natural Resources Defense Council.”260 The Citizens/Morongo model was relatively unique because it was financed entirely with long-term, tax-free debt, which may not be a feasible financing strategy for publicly 40 Improving T ransmission F inanc ing in Cal ifornia
funded transmission lines such as those developed by a Renewable Energy Transmission Authority. But the Citizens/Morongo model could be replicated in situations where non-public actors seek to expedite siting and construction and are willing to enter into ownership arrangements with public entities that allow for payments to the affected local communities to that end.
As a result, the model might be most useful in situations where local opposition to siting is a major concern for the viability of a proposed transmission project, such as when alternate routes would be prohibitively expensive. Public partners could be federally recognized tribes like the Morongo Band or municipal governments of suf-ficient size and capacity.
CONCLUSION
The current system, cost, and timing for new transmission represent serious barriers to achieving California’s clean energy goals. Some form of public financing and stream-lining for at least some portion of new transmission will be needed, but the form and extent of the reform is an open question that needs further evaluation. The initial summary of conclusions in this document offers potential pathways for reform and the necessary steps needed to implement them. Future study could focus on priority transmission lines and assessments of optimal and practical financing options and the policies need to enable them.
41 Center For Law, Energy & the Environment
References
3 See California Independent System Operator, 2024 20-
Year Transmission Outlook, July 31, 2024. Available at:
https://www.caiso.com/documents/2024-20-year-trans-mission-outlook-jul-31-2024.pdf (accessed October 9, 2024).
4 Kavya Balaraman, CAISO approves nearly $3B of
transmission projects to prepare for California’s clean energy goals, UtilityDive (March 18, 2022), https://www. utilitydive.com/news/caiso-approves-nearly-3b-of-trans-mission-projects-to-prepare-for-californi/620585/; see also Memorandum, Neil Millar, California Independent
System Operator, Decision on the ISO’s 2021-2022
transmission plan (March 9, 2022), available at: https:// www.caiso.com/Documents/Decision-on-2021-2022-
Transmission-Plan-Memo-Mar172022.pdf (accessed
October 22, 2024).
5 California Independent System Operator, 2022-2023
Transmission Plan (May 18, 2023), available at: https:// www.caiso.com/InitiativeDocuments/ISO-Board-Ap-proved-2022-2023-Transmission-Plan.pdf (accessed October 22, 2024); see also California Independent
System Operator, Draft 2022-2023 Transmission Plan
posted (Apr. 3, 2023), https://www.caiso.com/about/
Pages/Blog/Posts/Draft-2022-2023-Transmission-Plan-posted.aspx; Sammy Roth, California’s race against time to build power lines, Los Angeles Times (Apr. 6,
2023), Available at: https://www.latimes.com/environ-ment/newsletter/2023-04-06/californias-race-against-time-to-build-power-lines-boiling-point (accessed October 8, 2024).
6 California Independent System Operator, 2022-2023
Transmission Plan 2 (May 18, 2023), available at:
https://www.caiso.com/InitiativeDocuments/ISO-Board-Approved-2022-2023-Transmission-Plan.pdf. 7 California Independent System Operator, 20-Year
Transmission Outlook 4 (Jul. 31, 2024), available at:
https://www.caiso.com/documents/2024-20-year-trans-mission-outlook-jul-31-2024.pdf (accessed October 8, 2024).
8 See California Public Utilities Commission, “Rate of
Return” webpage. Available at: https://www.cpuc.
ca.gov/industries-and-topics/electrical-energy/elec-tric-costs/historical-electric-cost-data/rate-of-return (accessed October 8, 2024).
9 See Center for Energy Efficiency and Renewable
Technologies, Transmission in California 31 (March
2023), available at: https://gridlab.org/wp-content/
uploads/2023/03/Transmission-in-California.pdf?utm_
id=92549&sfmc_id=723525 (accessed October 8, 2024).
10 Dev Milstein et. al, The Latest Market Data Show that the Potential Savings of New Electric Transmission
was Higher Last Year than at Any Point in the Last
Decade, Lawrence Berkeley National Laboratory (Feb.
2023), available at: https://eta-publications.lbl.gov/sites/ default/files/lbnl-transmissionvalue-fact_sheet-2022up-date-20230203.pdf (accessed October 8, 2024). 11 Dev Milstein et. al, The Latest Market Data Show that the Potential Savings of New Electric Transmission
was Higher Last Year than at Any Point in the Last
Decade, Lawrence Berkeley National Laboratory (Feb.
2023), available at: https://eta-publications.lbl.gov/sites/ default/files/lbnl-transmissionvalue-fact_sheet-2022up-date-20230203.pdf (accessed October 8, 2024). 12 The Public Advocates Office, Public investment in
infrastructure is a promising option to support Cali-fornia’s energy transition and reduce ratepayer costs 4 (May 16, 2023), available at: https://www.publicadvo-cates.cpuc.ca.gov/-/media/cal-advocates-website/files/ reports/230516-caladvocates-public-investment-in-infra-structure.pdf (accessed October 8, 2024). 13 See Center for Energy Efficiency and Renewable
Technologies, Transmission in California 31 (March
2023), available at: https://gridlab.org/wp-content/
uploads/2023/03/Transmission-in-California.pdf?utm_
id=92549&sfmc_id=723525 (accessed October 8, 2024).
According to Fitch, the state’s credit rating is AA. Id.
At 31, fn 23. But San Diego Gas & Electric’s (SDG&E)
credit rating is BBB+. Id. At 31. Southern California
Edison’s (SCE) credit rating is worse, at BBB-. Id. At
31. Pacific Gas & Electric’s (PG&E) is even lower, at
BB, which indicates “an elevated level of default risk.” Id. At 31.
14 See Jennifer Danis et. al, Transmission Planning for the Energy Transition: Rethinking Modeling Approach-es, Institute for Policy Integrity 1 (Dec. 2023), available at: https://policyintegrity.org/files/publications/Trans-mission_Report_2023.pdf (accessed October 8, 2024). 15 Clean Air Task Force, Transmission Development in
California — What’s the Slowdown? 3 (Jan. 2023),
available at: https://cdn.catf.us/wp-content/up-loads/2023/03/16151853/california-transmission-develop-ment.pdf (accessed October 8, 2024). 16 Id.; see also California Independent System Operator, Transmission planning for a reliable, economic and
open grid, available at: https://www.caiso.com/planning/ Pages/TransmissionPlanning/Default.aspx (accessed Oc-tober 8, 2024). 42 Improving T ransmission F inanc ing in Cal ifornia
17 Clean Air Task Force, Transmission Development in
California — What’s the Slowdown? 3 (Jan. 2023),
available at: https://cdn.catf.us/wp-content/up-loads/2023/03/16151853/california-transmission-develop-ment.pdf (accessed October 8, 2024). 18 Id.
19 Id.
20 Id.
21 Id.
22 Id.
23 Id.
24 16 U.S.C. 824, subd. (b).
25 Id.
26 Id.
27 One key implication of federal jurisdiction is FERC
Order 888, which requires that regulated transmission
operators offer nondiscriminatory fees and access for
unaffiliated generators to transmit their power along
the operators’ lines. See Federal Energy Regulatory
Commission, Order 888, available at: https://www.ferc.
gov/industries-data/electric/industry-activities/open-ac-cess-transmission-tariff-oatt-reform/history-oatt-re-form/order-no-888 (accessed October 8, 2024). 28 Congressional Research Service, Electricity Transmis-sion Permitting Reform Proposals 1-2 (Oct. 11, 2023), available at: https://crsreports.congress.gov/product/
pdf/R/R47627#:~:text=Much%20congressional%20
interest%20in%20electricity,transmission-related%20
issues%20and%20processes (accessed October 8,
2024).
29 Johanna Bozuwa & Dustin Mulvaney, A Progressive
Take on Permitting Reform: Principles and Policies to
Unleash a Faster, More Equitable Green Transition 12,
Roosevelt Institute (Aug. 21, 2023), available at: https:// rooseveltinstitute.org/wp-content/uploads/2023/08/RI_
Progressive_Permitting_Report_202308.pdf (accessed
October 8, 2024).
30 Clean Air Task Force, Transmission Development in
California — What’s the Slowdown? 7 (Jan. 2023).
31 Id.
32 Id. (citing The Brattle Group, Cost Savings Offered by Competition in Electric Transmission 55 (Apr. 2019),
available at: https://www.brattle.com/wpcontent/up-loads/2021/05/16726_cost_savings_offered_by_competi-tion_in_electric_transmission.pdf (accessed October 8, 2024).
33 Clean Air Task Force, Transmission Development in
California — What’s the Slowdown? 7 (Jan. 2023).
34 Memorandum of Understanding Between The Califor-nia Public Utilities Commission (CPUC) And The Cal-ifornia Energy Commission (CEC) And The California Independent System Operator Regarding Transmission
and Resource Planning and Implementation (Dec. 23,
2022), available at: https://www.caiso.com/Documents/
ISO-CEC-and-CPUC-Memorandum-of-Understanding-Dec-2022.pdf (accessed October 8, 2024). 35 Id.
36 Sen. Bill 410 (2022-2023 Reg. Sess.), available at:
https://leginfo.legislature.ca.gov/faces/billTextClient. xhtml?bill_id=202320240SB410 (accessed October 8,
2024).
37 Id.
38 Id.
39 Jeff St. John, California’s grid is hindering its climate goals. Can a new law fix it?, Canary Media (Nov. 20,
2023), available at: https://www.canarymedia.com/
articles/transmission/californias-grid-is-hindering-its-cli-mate-goals-can-a-new-law-fix-it? (accessed October 8, 2024).
40 Congressional Research Service, Introduction to
Electricity Transmission 1 (Nov. 18, 2022). Available at:
https://crsreports.congress.gov/product/pdf/IF/IF12253
(accessed October 8, 2024).
41 See The Brattle Group, Cost Savings Offered by Com-petition in Electric Transmission. 42 While state public utilities commissions have rate-making authority over retail electricity sales, FERC retains jurisdiction, under the Federal Power Act over
ratemaking for interstate wholesale electricity sales.
43 California Independent System Operator, 2022-2023
Transmission Plan 3 (May 10, 2023), available at:
https://www.caiso.com/InitiativeDocuments/Revised-Draft-2022-2023-Transmission-Plan.pdf (accessed Octo-ber 8, 2024). 43 Center For Law, Energy & the Environment
44 Ethan Howland, PG&E aims to raise up to $1B for
transmission through leases to Citizens Energy,
UtilityDive (March 15, 2023). Available at: https://www. utilitydive.com/news/pge-pacific-gas-citizens-ener-gy-puc-transmission-leases/710405/ (accessed October 8, 2024).
45 U.S. Department of Energy Grid Deployment Office,
Federal Financing Tools. Available at: https://www.ener-gy.gov/gdo/federal-financing-tools (accessed October 8, 2024).
46 U.S. Department of Energy Grid Deployment Of-fice, Grid Resilience and Innovation Partnerships (GRIP) Program Projects. Available at: https://www.
energy.gov/gdo/grid-resilience-and-innovation-part-nerships-grip-program-projects (accessed October 8, 2024).
47 Assem. Bill 78 (2019-2020 Reg. Sess.), available at:
https://leginfo.legislature.ca.gov/faces/billTextClient. xhtml?bill_id=201920200AB78 (accessed October 8,
2024).
48 Id.
49 U.S. Department of Energy Loan Programs Office,
Title 17 Clean Financing Program, available at: https:// www.energy.gov/lpo/articles/t17-downloadable-hand-out-eir-projects (accessed October 8, 2024); U.S.
Department of Energy Loan Programs Office, Title
17 Clean Energy Financing – Energy Infrastructure
Reinvestment. Available at: https://www.energy.gov/lpo/ energy-infrastructure-reinvestment (accessed October
8, 2024).
50 Jeff St. John, New transmission tech can easily double clean energy capacity. Will utilities buy it?, Canary
Media (Nov. 17, 2021). Available at: https://www.cana-rymedia.com/articles/transmission/new-transmission-tech-can-easily-double-clean-energy-capacity-will-utili-ties-buy-it (accessed October 8, 2024). 51 Id.
52 See Katie Mulvaney et. al, GETting Interconnected
in PJM: Grid-Enhancing Technologies (GETs) Can
Increase the Speed and Scale of New Entry from
PJM‘s Queue, RMI (Feb. 2024), available at: https://rmi. org/wp-content/uploads/dlm_uploads/2024/02/GETs_in-sight_brief_v3.pdf (accessed October 8, 2024). 53 See “Fact Sheet | Building for the Future Through
Electric Regional Transmission Planning and Cost
Allocation,” FERC. Available at: https://www.ferc.gov/
news-events/news/fact-sheet-building-future-through-electric-regional-transmission-planning-and (accessed October 21, 2024).
54 See California Independent System Operator, Trans-mission operations ensure the flow of electricity, available at: https://www.caiso.com/market/Pages/Trans-missionOperations/Default.aspx (accessed October 8, 2024, defining Transmission access charges as “[c]
harges assessed, on behalf of the Participating Trans-mission Owner, to parties who require access to the ISO grid.”)
55 See Sammy Roth, This power line could save Cali-fornia — and forever change the American West, Los Angeles Times (Aug. 23, 2022, 9:00 AM PST),
available at: https://www.latimes.com/environment/
story/2022-08-23/wyoming-clean-energy-california
(accessed October 8, 2024); see also Dustin Bleizeffer, TransWest Express poised to expand reach of Wyo re-newables, WyoFile (June 14, 2023), available at: https:// wyofile.com/transwest-express-posed-to-expand-reach-of-wyo-renewables/ (accessed October 8, 2024). 56 New Mexico Renewable Energy Transmission Author-ity, Transmission Lines: Creating a Highway for Clean Energy, available at: https://nmreta.com/transmis-sion-lines/#transmissionprojects (accessed October 8, 2024).
57 42 U.S.C. 18715.
58 See, e.g., Kavya Balaraman, Roughly $7B federal loan could offer PG&E ‘cheap money’ to upgrade electric
grid in California, UtilityDive (July 6, 2023), avail-able at: https://www.utilitydive.com/news/pge-feder-al-doe-loan-program-grid-upgrade-california/685172/ (accessed October 8, 2024).
59 New Mexico Renewable Energy Transmission Author-ity, Transmission Lines: Creating a Highway for Clean Energy, available at: https://nmreta.com/transmis-sion-lines/#transmissionprojects (accessed October 8, 2024).
60 U.S. Department of Energy, Office of State and
Community Energy Programs, Credit Enhancements,
available at: https://www.energy.gov/scep/slsc/credit-en-hancements#:~:text=A%20credit%20enhancement%20 is%20anything,as%20residential%20clean%20ener-gy%20lending (accessed October 8, 2024). 61 U.S. Department of Energy, Loan Programs Office,
available at: https://www.energy.gov/lpo/state-energy-fi-nancing-institutions-sefi-supported-projects (accessed October 8, 2024).
62 California Independent System Operator, Transmission access charge options, available at: https://www.caiso. com/informed/Pages/StakeholderProcesses/Completed-ClosedStakeholderInitiatives/TransmissionAccessChar-geOptions.aspx (accessed October 8, 2024). 44 Improving T ransmission F inanc ing in Cal ifornia
63 Craig Lewis, How to protect California ratepayers,
expand clean local energy and avoid bailing out PG&E,
UtilityDive (May 13, 2019), available at: https://www.
utilitydive.com/news/how-to-protect-california-rate-payers-expand-clean-local-energy-and-avoid-b/554564/ (accessed October 8, 2024).
64 Craig Lewis, How Two Simple Fixes Can Fairly
Compensate the True Value of DERs in Califor-nia, T&DWorld (June 2, 2020), available at: https:// www.tdworld.com/distributed-energy-resources/
article/21132853/how-two-simple-fixes-can-fairly-com-pensate-the-true-value-of-ders-in-california (accessed October 8, 2024).
65 Bridget Sieren-Smith et. al, Utility Costs and Afford-ability of the Grid of the Future: An Evaluation of Electric Costs, Rates, and Equity Issues Pursuant to
P.U. Code Section 913.1 20, California Public Utility
Commission (May 2021), available at: https://www.cpuc.
ca.gov/-/media/cpuc-website/divisions/office-of-govern-mental-affairs-division/reports/2021/senate-bill-695-re-port-2021-and-en-banc-whitepaper_final_04302021.pdf (accessed October 8, 2024).
66 See California Public Utilities Commission, Rate
Base, available at: https://www.cpuc.ca.gov/indus-tries-and-topics/electrical-energy/electric-costs/histori-cal-electric-cost-data/rate-base ((accessed October 8, 2024, defining rate base as “[t]he value of property
on which the utility is allowed to earn a specified rate of return, in accordance with rules set by the Com-mission.”). 67 Clean Coalition, Transmission Access Charges, available at: https://clean-coalition.org/policy/transmission-ac-cess-charges/ (accessed October 8, 2024). 68 Id.; see also Craig Lewis, How to protect California ratepayers, expand clean local energy and avoid bail-ing out PG&E. 69 California Department of General Services,
LEASE-REVENUE BONDS - 6872 (Sept. 2017), avail-able at: https://www.dgs.ca.gov/Resources/SAM/ TOC/6000/6872 (accessed October 8, 2024); Cali-fornia State Treasurer’s Office, State of California Investor Relations, available at: https://www.buycalifor-niabonds.com/state-of-california-ca/resources/faq/i27 (accessed October 8, 2024).
70 California State Treasurer’s Office, State of California Investor Relations, available at: https://www.buycalifor-niabonds.com/state-of-california-ca/resources/faq/i27 (accessed October 8, 2024).
71 Id.
72 Id.
73 Id.
74 California Department of General Services,
LEASE-REVENUE BONDS - 6872 (Sept. 2017), avail-able at: https://www.dgs.ca.gov/Resources/SAM/ TOC/6000/6872 (accessed October 8, 2024).
75 See California State Treasurer’s Office, State of Cali-fornia Investor Relations. 76 Cooper Howard, Choosing Municipal Bonds: GO or
Revenue?, Charles Schwab (Jan. 18, 2023), available at:
https://www.schwab.com/learn/story/choosing-munici-pal-bonds-go-or-revenue (accessed October 8, 2024). 77 Legislative Analyst’s Office, Frequently Asked Ques-tions About Bond Financing (Feb. 2007), Available at:
https://lao.ca.gov/2007/bond_financing/bond_financ-ing_020507.aspx (accessed October 8, 2024). 78 California State Treasurer’s Office, What Are Bonds
And Why Are They Used?, available at: https://www.
treasurer.ca.gov/cdlac/bonds.asp#:~:text=Municipal%20
Bonds&text=Most%20bonds%20issued%20by%20gov-ernment,authority%20of%20the%20government%20 agencies (accessed October 8, 2024); California In-frastructure and Economic Development Bank, Public Agency Revenue Bonds, available at: https://www.ibank.
ca.gov/bonds/public-agency-revenue-bonds/ (accessed
October 8, 2024).
79 U.S. Department of Energy Office of Energy Efficien-cy & Renewable Energy, Leveraging Bond Financing to Support Energy Efficiency and Renewable Ener-gy Goals: A Resource Summary for State and Local Governments 1 (Oct. 2020), available at: https://www.
energy.gov/sites/default/files/2020/11/f80/Leverag-ing-Bond-Financing_resource-summary_0.pdf (ac-cessed October 8, 2024). 80 Id.
81 Id.
82 Jennifer Sutton, How do electricity transmission lines withstand a lifetime of exposure to the elements?,
MIT School of Engineering (Apr. 26, 2010), available
at: https://engineering.mit.edu/engage/ask-an-engineer/ how-do-electricity-transmission-lines-withstand-a-life-time-of-exposure-to-the-elements/#:~:text=As%20 long%20as%20electrical%20transmission,wrapped%20
around%20steel%2Dreinforced%20cores (accessed
October 8, 2024).
83 U.S. Department of Energy Office of Energy Efficiency & Renewable Energy.
84 Id.
85 Id.
45 Center For Law, Energy & the Environment
86 Legislative Analyst’s Office, Frequently Asked Ques-tions About Bond Financing (Feb. 2007), available at:
https://lao.ca.gov/2007/bond_financing/bond_financ-ing_020507.aspx (accessed October 8, 2024). 87 California Public Utilities Commission, California
Alternative Rates for Energy (CARE), available at:
https://www.cpuc.ca.gov/consumer-support/finan-cial-assistance-savings-and-discounts/california-alter-nate-rates-for-energy (accessed October 8, 2024). 88 Id.
89 Bureau of Labor Statistics, Consumer Price Index
Summary (Apr. 10, 2024), available at: https://www.
bls.gov/news.release/cpi.nr0.htm (accessed October 8,
2024).
90 U.S. Department of Energy, Office of State and
Community Energy Programs, Credit Enhancements,
available at: https://www.energy.gov/scep/slsc/credit-en-hancements#:~:text=A%20credit%20enhancement%20 is%20anything,as%20residential%20clean%20ener-gy%20lending (accessed October 8, 2024). 91 Id.
92 U.S. Environmental Protection Agency, Energy Re-sources for State and Local Governments: Loans and Credit Enhancements, available at: https://www.epa.
gov/statelocalenergy/loans-and-credit-enhancements
(accessed October 8, 2024).
93 Id.
94 Id.
95 Legislative Analyst’s Office, Under LAO Revenue
Update, Budget Problem Grows by $15 Billion (Feb.
20, 2024), available at: https://lao.ca.gov/Publications/ Report/4850 (accessed October 8, 2024).
96 Cal. Const., art. XII, § 8. Note that this section os-tensibly applies to local governments like cities and counties but nonetheless uses the broad term “other
public body” which might also apply to state-level
agencies.
97 See New Mexico Renewable Energy Transmission
Authority, available at: https://nmreta.com/ (accessed
October 8, 2024).
98 See Colorado Electric Transmission Authority, available at: https://www.cotransmissionauthority.com/ (accessed
October 8, 2024).
99 The Public Advocates Office suggested “a public
California ‘infrastructure’ authority” with bonding
authority and/or the ability to own infrastructure, a
model that has been instituted in other states such as
New Mexico[.]” The Public Advocates Office, Public
investment in infrastructure is a promising option to
support California’s energy transition and reduce rate-payer costs 4 (May 16, 2023), available at: https://www. publicadvocates.cpuc.ca.gov/-/media/cal-advocates-web-site/files/reports/230516-caladvocates-public-invest-ment-in-infrastructure.pdf (accessed October 8, 2024). 100 New Mexico Renewable Energy Transmission Au-thority, New Mexico Renewable Energy Transmission Authority Update: Science, Technology & Telecommu-nications Committee 1 (Sept. 14, 2021), available at:
https://www.nmlegis.gov/handouts/STTC%20091621%20
Item%202%20--%20RETA%20Updates--Science,%20
Technology%20&%20Telecommunications%20Com-mittee%2009-16-2021.pdf (accessed October 8, 2024); see also New Mexico Renewable Energy Transmission
Authority, Transmission Lines: Creating a Highway for
Clean Energy, available at: https://nmreta.com/trans-mission-lines/ (accessed October 8, 2024). 101 New Mexico Renewable Energy Transmission Au-thority, New Mexico Renewable Energy Transmission Authority Update: Science, Technology & Telecommu-nications Committee 1. 102 Id.
103 See New Mexico Legislature, 2007 Regular Session
- HB 188, available at: https://www.nmlegis.gov/Legisla-tion/Legislation?Chamber=H&LegType=B&LegNo=188&- year=07 (accessed October 8, 2024).
104 Id.
105 New Mexico Renewable Energy Transmission Authority
Act, N.M. Stat. § 62-16A-3.
106 id.
107 Id. At § 62-16A-4.
108 Id.
109 New Mexico Renewable Energy Transmission Au-thority, Resources & Common Questions, available at: https://nmreta.com/resources/#:~:text=RETA%20
derives%20its%20funding%20from,partner%20in%20
public%2Dprivate%20partnerships (accessed October
8, 2024).
110 New Mexico Renewable Energy Transmission Authority
Act, N.M. Stat. § 62-16A-4.
46 Improving T ransmission F inanc ing in Cal ifornia
111 Press Release, Pattern Energy Group LP, Pattern
Energy and RETA Announce Energization of West-ern Spirit Transmission Line in New Mexico (Dec. 6, 2021, 7:00 AM EST), available at: https://www.
prnewswire.com/news-releases/pattern-energy-and-re-ta-announce-energization-of-western-spirit-transmis-sion-line-in-new-mexico-301437725.html. 112 New Mexico Renewable Energy Transmission Author-ity, Transmission Lines: Creating a Highway for Clean Energy.
113 New Mexico Renewable Energy Transmission Author-ity, High Lonesome Mesa, available at: https://nmreta. com/project/high-lonesome-mesa/ (accessed October
8, 2024).
114 Colorado General Assembly, SB21-072: Public Utilities Commission Modernize Electric Transmission Infra-structure (2021 Reg. Sess.), available at: https://leg.col-orado.gov/bills/sb21-072 (accessed October 8, 2024). 115 VoteSmart, SB 21-072 - Expands Electric Transmission Facilities to Meet Clean Energy Goals - Colorado Key
Vote (June 24, 2021), available at: https://justfacts.
votesmart.org/bill/31772/82880/106220/expands-elec-tric-transmission-facilities-to-meet-clean-ener-gy-goals#82880 (accessed October 8, 2024). 116 Judith Kohler, Lawmakers don’t want Colorado to
be like Texas; they want to make state’s electric grid
regional, The Denver Post (March 29, 2021), available
at: https://www.denverpost.com/2021/03/29/colora-do-lawmakers-want-to-expand-electric-grid/ (accessed October 8, 2024).
117 Id.
118 Allen Best, Colorado’s new transmission authority, Big Pivots (March 6, 2022), available at: https://bigpivots. com/colorados-new-transmission-authority/ (accessed
October 8, 2024).
119 CO Code § 40-42-104, subd. (1)(g).
120 CO Code § 40-42-104, subd. (1)(m)
121 CO Code § 40-42-104, subd. (1)(n).
122 CO Code § 40-42-104, subd. (1)(p).
123 CO Code § 40-42-105.
124 Scott Weiser, New regulatory agency over electric grid expansion begins early phase of work, The Denver
Gazette (June 18, 2023), available at: https://denverga-zette.com/news/business/new-regulatory-agency-over-electric-grid-expansion-begins-early-phase-of-work/ article_d06ffc98-80ec-11ed-aec8-df72a963504e.html
(accessed October 8, 2024).
125 CO Code § 40-42-103, subd. 2.
126 Id.
127 See N.M. Stat. § 62-16A-4.
128 Coalition for Green Capital, What is a Green Bank?:
Resource Library, available at: https://coalitionfor-greencapital.com/what-is-a-green-bank/resource-library/ (accessed October 8, 2024); Coalition for Green
Capital, What is a Green Bank?, available at: https://
coalitionforgreencapital.com/what-is-a-green-bank/ (ac-cessed October 8, 2024); United States Environmental Protection agency, Green Banks, available at: https://
www.epa.gov/statelocalenergy/green-banks (accessed
October 8, 2024).
129 Coalition for Green Capital, Green Banks in the United States: 2022 U.S. Green Bank Annual Industry Report
With Data from Calendar Year 2021 and 2022 5-11.
Note that, in addition to subnational green banks,
the federal government’s “National Clean Investment
Fund,” a $14 billion lending facility within the U.S.
EPA, has also been referred to as a “national green
bank” even though no standalone federal green bank
exists. See Jean Chemnick, Here’s who wants to run
the country’s $14B ‘green bank’, E&E News (Nov. 6,
2023), available at: https://www.eenews.net/articles/
heres-who-wants-to-run-the-countrys-14b-green-bank/
(accessed October 8, 2024). The National Clean In-vestment Fund is part of EPA’s $27 billion Greenhouse Gas Reduction Fund created pursuant to the Inflation
Reduction Act. U.S. Environmental Protection Agency,
Greenhouse Gas Reduction Fund, available at: https://
www.epa.gov/greenhouse-gas-reduction-fund (accessed
October 8, 2024).
130 Nevada Governor’s Office of Energy, Nevada Clean En-ergy Fund, available at: https://energy.nv.gov/Resources/ Nevada_Clean_Energy_Fund/ (accessed October 8,
2024).
131 Colorado Clean Energy Fund, About Us, available at:
https://cocleanenergyfund.com/about/ (accessed Octo-ber 8, 2024). 132 Connecticut Green Bank, available at: https://www.
ctgreenbank.com/.
133 New York Green Bank, available at: https://greenbank. ny.gov/.
134 DC Green Bank, available at: https://dcgreenbank.com/. 135 See Coalition for Green Capital, Connecticut Green
Bank – Organization Fact Sheet, available at: https://co-alitionforgreencapital.com/wp-content/uploads/2017/04/ CT-Green-Bank-Org-Fact-Sheet.pdf (accessed October
8, 2024).
47 Center For Law, Energy & the Environment
136 Nevada Governor’s Office of Energy, Nevada Clean En-ergy Fund, available at: https://energy.nv.gov/Resources/ Nevada_Clean_Energy_Fund; Nevada Senate Bill 407
(2017) (BDR 58-1133), available at: https://www.leg.
state.nv.us/App/NELIS/REL/79th2017/Bill/5472/Overview
(accessed October 8, 2024).
137 Colorado Clean Energy Fund, About Us, available at:
https://cocleanenergyfund.com/about/; Coalition for
Green Capital, Colorado Announces Green Bank (Dec.
10, 2018), available at: https://coalitionforgreencapital. com/colorado-announces-green-bank/ (accessed Octo-ber 8, 2024). 138 Colorado Senate Bill 230 (2021), available at: https:// leg.colorado.gov/bills/sb21-230 (accessed October 8,
2024).
139 DC Green Bank; Green Finance Authority Establish-ment Act of 2018 (D.C. Law 22-155), available at:
https://code.dccouncil.gov/us/dc/council/laws/22-155
(accessed October 8, 2024).
140 Coalition for Green Capital, New York Green Bank,
available at: https://coalitionforgreencapital.com/
new-york-green-bank/ (“NY Green Bank is the largest
Green Bank in the US, founded in 2013 and a division
of NYSERDA.”); see also New York State Public Service
Commission, Order Establishing New York Green Bank
and Providing Initial Capitalization (Dec. 19, 2013),
Case No. 13-M-0412, available at: https://documents.
dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId={B-D3AAFB0-FAA2-4DA6-B56B-0FF22EE34EDF. 141 Coalition for Green Capital, Green Banks in the
United States: 2022 U.S. Green Bank Annual Industry
Report With Data from Calendar Year 2021 and 2022
9 (March 2023), available at: https://mcusercontent.
com/3e3337737c870aa879b2ef144/files/58657110-26b4-
3ee5-a3e4-45fda1bb6594/CGC_Consortium_AnnualRe-port.01.pdf (accessed October 8, 2024). 142 Judy Lin & Rachel Becker, Exclusive: California climate budget to include $1 billion green loan fund, Calmat-ters (Jan. 9, 2020), available at: https://calmatters.org/ environment/2020/01/california-budget-billion-dollar-cli-mate-innovation-loan-fund/. 143 Oscar Perry Abello, Public Banking Efforts Are Gaining Momentum And Clarity In California, Next City (June
27, 2023), available at: https://nextcity.org/urban-ist-news/public-banking-efforts-are-gaining-momen-tum-and-clarity-in-california. 144 California Department of Financial Protection and In-novation, Public Banks, https://dfpi.ca.gov/public-banks/; Assembly Bill 857 (2019-2020 Reg. Sess.), available
at: https://leginfo.legislature.ca.gov/faces/billNavClient. xhtml?bill_id=201920200AB857.
145 Assembly Bill 857 (2019-2020 Reg. Sess.), § 1, available at: https://leginfo.legislature.ca.gov/faces/billNavClient. xhtml?bill_id=201920200AB857.
146 See Yakov Feygin et. al, Municipal Bank of LA: Clean Energy Portfolio Options 9-10, Jain Family Institute
(May 2023), available at: https://jainfamilyinstitute.org/ wp-content/uploads/2023/05/JFI-Berggruen_MBLA_
Clean-Energy-Portfolio_May-2023.pdf (identifying mu-nicipal banking’s impact on transmission as uncertain due to “regulatory infancy” but nonetheless “an area
of future interest” for research.)
147 Carla Santos Skandier, Could California’s Public Banks Finance a Statewide Green New Deal?, Truthout (Nov.
29, 2019), available at: https://truthout.org/articles/ could-californias-public-banks-finance-a-statewide-green-new-deal/ (accessed October 8, 2024). 148 Va. Code. Ann. § 15.2-958.3:1; Virginia House Bill 1919 (2021 Special Sess. 1), available at: https://lis.virginia. gov/cgi-bin/legp604.exe?212+ful+CHAP0405 (accessed
October 8, 2024). Code of Virginia section 15.2-958.3:1 provides that “[a]ny locality may, by ordinance,
establish a green bank to promote the investment in
clean energy technologies in its locality and provide
financing for clean energy technologies.” Va. Code.
Ann. § 15.2-958.3:1.
149 Va. Code. Ann. § 15.2-958.3:1.
150 Id.
151 Id.
152 Elizabeth McGowan, Meet the new state official sup-porting the rollout of green banks in Virginia, Energy News Network (June 28, 2021), available at: https://
energynews.us/2021/06/28/meet-the-new-state-offi-cial-supporting-the-rollout-of-green-banks-in-virginia/ (accessed October 8, 2024).
153 Philadelphia Green Capital Corp., Philadelphia Green Capital Corp., available at: https://phillygreencapital. org/ (accessed October 8, 2024).
154 Id.
155 Press Release, Philadelphia Energy Authority, Phila-delphia Energy Authority Launches New Green Bank - Philadelphia Green Capital Corp. - to Grow City’s
Clean Energy Economy (Sept. 21, 2021), available at:
https://www.prnewswire.com/news-releases/philadel-phia-energy-authority-launches-new-green-bank--phi-ladelphia-green-capital-corp--to-grow-citys-clean-en-ergy-economy-301381938.html (accessed October 8, 2024).
48 Improving T ransmission F inanc ing in Cal ifornia
156 Maryrose Myrtetus, Can Philadelphia Green Capital
Corp. bring the best of green banks to the city?,
Technical.ly (Apr. 18, 2022), available at: https://techni-cal.ly/civic-news/philadelphia-green-capital-corp-bank/ (accessed October 8, 2024).
157 See California Infrastructure and Economic Develop-ment Bank, Climate Catalyst Program, available at:
https://www.ibank.ca.gov/climate-financing/climate-cata-lyst-program/ (accessed October 8, 2024). 158 California Infrastructure and Economic Development
Bank, About IBank, available at: https://www.ibank.
ca.gov/about/about-ibank/ (accessed October 8, 2024).
159 California Infrastructure and Economic Development
Bank, Infrastructure Loans, available at: https://www.
ibank.ca.gov/loans/infrastructure-loans/ (accessed Oc-tober 8, 2024). 160 California Infrastructure and Economic Develop-ment Bank, Criteria, Priorities, and Guidelines for the Selection of Projects for IBank Financing under
the Climate Catalyst Revolving Loan Fund Program
(Jan. 2022), available at: https://ibank.ca.gov/wp-con-tent/uploads/2022/08/Criteria-Priorities-and-Guide-lines-for-IBanks-Climate-Catalyst-Revolving-Loan-Fund. pdf (accessed October 8, 2024).
161 California Infrastructure and Economic Development
Bank, Climate Catalyst Program.
162 Id.
163 California Infrastructure and Economic Development
Bank, Resolution NO. 22-23: Resolution of the Califor-nia Infrastructure and Economic Development Bank Adopting a Climate Catalyst Fund Financing Plan –
Clean Energy Transmission (Dec. 21, 2022), available at:
https://ibank.ca.gov/wp-content/uploads/2022/12/Execut-ed-Resolution-No-22-23-Climate-Catalyst-Fund-Financ-ing-Plan.pdf; Cal. Gov. Code § 63048.93, subd. (f)(3). 164 Gov. Code § 63048.93, subd. (c)(2).
165 Gov. Code § 63048.93, subd. (f)(3)(C)(i).
166 Gov. Code § 63048.93, subd. (f)(3)(C)(ii).
167 Gov. Code § 63048.93, subd. (f)(3)(C)(iii).
168 Gov. Code § 63048.93, subd. (f)(3)(C)(iv).
169 Cal. Gov. Code § 63048.93, subd. (f)(3)(D).
170 Gov. Code § 63048.93, subd. (f)(3)(C)(v).
171 Gov. Code § 63048.93, subd. (f)(3)(B).
172 California Economic Development and Infrastruc-ture Bank, Annual Comprehensive Financial Report for the Fiscal Year Ended June 10, 2022 (Aug. 28,
2023), available at: https://ibank.ca.gov/wp-content/up-loads/2023/08/IBank-2022-ACFR.pdf (accessed October 8, 2024).
173 California Infrastructure and Economic Development
Bank, IBank Team, available at: https://www.ibank.
ca.gov/about/our-team/ (accessed October 8, 2024).
174 Gov. Code § 63025.1, subd. (m) (IBank may “[m]ake,
receive, or serve as a conduit for the making of, or
otherwise provide for, grants, contributions, guaran-tees, insurance, credit enhancements or liquidity fa-cilities, or other financial enhancements to a sponsor or a participating party as financial assistance for a
project.”); see also Center for Energy Efficiency and
Renewable Technologies, Transmission in California
31 fn.4 (March 2023), available at: https://gridlab.org/ wp-content/uploads/2023/03/Transmission-in-California.
pdf?utm_id=92549&sfmc_id=723525 (suggesting that
IBank utilize its credit enhancement authority to sup-port transmission financing). 175 Gov. Code § 63025.1, subd. (m).
176 California Infrastructure and Economic Development
Bank, Annual Report to the Governor and Legisla-ture 2014-2015 3 (2015), available at: https://www. ibank.ca.gov/wp-content/uploads/2020/06/SBFC-Annu-al-Rep-FY14-15.pdf; California Infrastructure and Eco-nomic Development Bank, Loan Guarantee Program, available at: https://www.ibank.ca.gov/small-business/
loan-guarantees/ (accessed October 8, 2024).
177 California State Treasurer’s Office, California Alterna-tive Energy and Advanced Transportation Financing Authority (CAEATFA), available at: https://www.trea-surer.ca.gov/caeatfa/; Pub. Res. Code § 26000-26037. 178 California State Treasurer’s Office, California Alterna-tive Energy and Advanced Transportation Financing Authority, Clean Energy Bond Financing, available at:
https://www.treasurer.ca.gov/caeatfa/incentives.asp
(accessed October 8, 2024).
179 Pub. Res. Code § 26004.
180 California State Treasurer’s Office, California Alterna-tive Energy and Advanced Transportation Financing Authority, Contacts, available at: https://www.treasurer. ca.gov/caeatfa/contacts.asp (accessed October 8,
2024).
181 Id.
182 Stats. 1980, Ch. 908, Sec. 1, available at:
49 Center For Law, Energy & the Environment
https://clerk.assembly.ca.gov/sites/clerk.assembly.ca.gov/files/ archive/Statutes/1980/80Vol2.PDF p. 1354
183 Id.
184 Stats.1994, c. 1218 (S.B.1952), § 3.
185 Pub. Res. Code § 26002.
186 Id.
187 Pub. Res. Code § 26002, subd. (a).
188 Pub. Res. Code § 26002, subd. (b).
189 Pub. Res. Code § 26011, subd. (c).
190 Pub. Res. Code § 26011, subd. (d).
191 California State Treasurer’s Office, California Alter-native Energy and Advanced Transportation Financ-ing Authority, Qualified Energy Conservation Bonds (QECBs), available at: https://www.treasurer.ca.gov/
caeatfa/qecb.asp (accessed October 8, 2024).
192 California State Treasurer’s Office, California Alterna-tive Energy and Advanced Transportation Financing Authority, Private Activity Bonds for District Heating
& Cooling, available at: https://www.treasurer.ca.gov/ca-eatfa/heating_cooling.asp (accessed October 8, 2024). 193 Pub. Res. Code § 26002, subd. (a)(8)(A).
194 Because transmission does not fall within the meaning of “advanced transportation technologies,” transmis-sion could only theoretically fit within CAEAFTA’s statute as an “alternative source.” Advanced transpor-tation technologies are defined as “emerging commer-cially competitive transportation-related technologies identified by the authority as capable of creating
long-term, high-value-added jobs for Californians while enhancing the state’s commitment to energy conser-vation, pollution and greenhouse gas emissions reduc-tion, and transportation efficiency.” Pub. Res. Code § 26003, subd. (a)(2)(A). “Alternative source” is defined in the statute as “devices or technologies used for a
renewable electrical generation facility … a combined
heat and power system … distributed generation and
energy storage technologies … or a facility designed
for the production of renewable fuels, the efficient
use of which reduces the use of fossil or nuclear
fuels, and energy efficiency devices or technologies
that reduce the need for new electric generation and
reduce emissions of toxic and criteria pollutants and
greenhouse gases.” Pub. Res. Code § 26003, subd. (a)
(3)(A). Although it is an integral part of renewable
energy infrastructure, transmission is not “generation” or “production” infrastructure because it does not
generate electricity or produce renewable energy. See
Pub. Res. Code § 26003, subd. (a)(3)(A). Transmission
also likely does not qualify as an “energy efficiency
device[] or technolog[y]” although it would arguably
reduce the need for new generation and reduce emis-sions. See Pub. Res. Code § 26003, subd. (a)(3)(A).
Cal. Code Regs § 10010 et seq.
195 Assem. Bill 1373 (2023-2024 Reg. Sess.), available at:
https://leginfo.legislature.ca.gov/faces/billTextClient.xht-ml?bill_id=202320240AB1373; Kaasia Micek, California governor signs law on centralized procurement system
for clean energy resources, S&P Global Commodi-ty Insights (Oct. 9, 2023), available at: https://www. spglobal.com/commodityinsights/en/market-insights/
latest-news/electric-power/100923-california-gov-ernor-signs-law-on-centralized-procurement-sys-tem-for-clean-energy-resources; see also Department of Finance, Trailer Bill Language, Energy, available
at: https://esd.dof.ca.gov/trailer-bill/public/trailerBill/ pdf/846.
196 Laura Deehan, California Assembly votes to advance
clean energy and reliability solution, Environment
California (May 26, 2023), available at: https://environ-mentamerica.org/california/articles/california-assem-bly-votes-to-advance-clean-energy-and-reliability-solu-tion/ (accessed October 8, 2024). 197 Pub. Utilities Code § 454.42, subd. (a)(4)(C).
50 Improving T ransmission F inanc ing in Cal ifornia
198 Sen. Rules Comm., Rep. on Assem. Bill 1373 (2023-
2024 Reg. Sess.) 8, Sept. 13, 2023, available at: https:// billtexts.s3.amazonaws.com/ca/ca-analysishttps-legin-fo-legislature-ca-gov-faces-billAnalysisClient-xhtml-bill-id-202320240AB1373-ca-analysis-368787.pdf (accessed October 8, 2024).
199 Id; Legislative Analyst’s Office, The 2023-2024 Bud-get: Proposed Energy Policy Changes (March 10, 2023), available at: https://lao.ca.gov/Publications/
Report/4735#:~:text=The%20proposal%20requires%20
DWR%20to,geothermal%2C%20and%20long%20dura-tion%20storage (accessed October 8, 2024). 200 Wat. Code § 80821, subd. (b)(2).
201 Wat. Code § 8030; see also Legislative Analyst’s Of-fice, The 2023-2024 Budget: Proposed Energy Policy Changes (March 10, 2023), available at: https://lao.
ca.gov/Publications/Report/4735#:~:text=The%20pro-posal%20requires%20DWR%20to,geothermal%2C%20 and%20long%20duration%20storage (accessed Octo-ber 8, 2024). 202 Legislative Analyst’s Office, The 2023-2024 Bud-get: Proposed Energy Policy Changes (March 10, 2023), available at: https://lao.ca.gov/Publications/
Report/4735#:~:text=The%20proposal%20requires%20
DWR%20to,geothermal%2C%20and%20long%20dura-tion%20storage (accessed October 8, 2024). 203 Id.
204 Id.
205 Assem. Bill 1373 (2023-2024 Reg. Sess.), § 8080, subd. (c), available at: https://leginfo.legislature.ca.gov/faces/ billTextClient.xhtml?bill_id=202320240AB1373 (accessed
October 8, 2024).
206 Wat. Code § 80830, subd. (d).
207 Wat. Code § 80802, subd. (b)(3).
208 See Wat. Code § 80821, subd. (b)(2).
209 But see the Legislative Analyst Office’s warning that the effect of non-bypassable charges on customer
rates is unclear and that “California’s electricity rates already are among the highest in the nation and
rising faster than inflation[.]” Legislative Analyst’s
Office, The 2023-2024 Budget: Proposed Energy Policy
Changes (March 10, 2023), available at: https://lao.
ca.gov/Publications/Report/4735#:~:text=The%20pro-posal%20requires%20DWR%20to,geothermal%2C%20 and%20long%20duration%20storage (accessed Octo-ber 8, 2024). 210 See Assem. Bill 1373 (2023-2024 Reg. Sess.), § 8080, subd. (c), available at: https://leginfo.legislature.ca.gov/ faces/billTextClient.xhtml?bill_id=202320240AB1373
(accessed October 8, 2024).
211 See Stats. 2001, 1st Ex. Sess., Ch. 9, Sec. 3.
212 Wat. Code § 80102, subd. (c).
213 Wat. Code § 80106, subd. (a).
214 Wat. Code § 80823.
215 See Wat. Code § 80102, subd. (c) (texted in italics added).
216 The Public Advocates Office, Public investment in
infrastructure is a promising option to support Cali-fornia’s energy transition and reduce ratepayer costs 4 (May 16, 2023), available at: https://www.publicadvo-cates.cpuc.ca.gov/-/media/cal-advocates-website/files/ reports/230516-caladvocates-public-investment-in-in-frastructure.pdf. Importantly, WAPA is not the only federal entity that may provide federal support to
transmission development. See U.S. Department
of Energy Grid Deployment Office, Federal Financ-ing Tools, available at: https://www.energy.gov/gdo/ federal-financing-tools. A matrix intended to help
developers choose which federal financing route to
pursue is available at U.S. Department of Energy Grid
Deployment Office, Grid and Transmission Program
Conductor, available at: https://www.energy.gov/gdo/
grid-and-transmission-program-conductor (accessed
October 8, 2024).
217 Johanna Bozuwa & Dustin Mulvaney, A Progressive
Take on Permitting Reform: Principles and Policies to
Unleash a Faster, More Equitable Green Transition 21,
Roosevelt Institute (Aug. 21, 2023), available at: https:// rooseveltinstitute.org/wp-content/uploads/2023/08/RI_
Progressive_Permitting_Report_202308.pdf (accessed
October 8, 2024).
218 Western Area Power Administration, Transmission
Infrastructure Program (TIP), available at: https://
www.wapa.gov/transmission/TIP/Pages/AboutTIP.aspx
(accessed October 8, 2024).
51 Center For Law, Energy & the Environment
219 WAPA’s statute provides that “(A) the Western Area
Power Administration may borrow funds from the
Treasury; and (B) the Secretary shall, without further
appropriation and without fiscal year limitation, loan
to the Western Area Power Administration, on such
terms as may be fixed by the Administrator and the
Secretary, such sums (not to exceed, in the aggre-gate (including deferred interest), $3,250,000,000 in outstanding repayable balances at any one time) as, in
the judgment of the Administrator, are from time to
time required for the purpose of— (i) constructing,
financing, facilitating, planning, operating, maintaining, or studying construction of new or upgraded electric
power transmission lines and related facilities with
at least one terminus within the area served by the
Western Area Power Administration; and (ii) deliver-ing or facilitating the delivery of power generated by renewable energy resources constructed or reason-ably expected to be constructed after February 17, 2009.” 42 U.S.C. § 16421a.
220 Western Area Power Administration, Transmission
Infrastructure Program (TIP), available at: https://www. wapa.gov/transmission-infrastructure-program-tip/
(accessed October 8, 2024).
221 Western Area Power Administration, Project Criteria, available at: https://www.wapa.gov/transmission-in-frastructure-program-tip/project-criteria/ (accessed October 8, 2024).
222 Id.
223 Id.
224 Id.
225 Id.
226 Id.
227 79 Fed. Reg 19065, 19072 (2014).
228 Bay Area Council Economic Institute, Public-Private Partnerships in California How Governments Can
Innovate, Attract Investment, and Improve Infrastruc-ture Performance 1 (Aug. 2018), available at: http:// www.bayareaeconomy.org/files/pdf/P3inCaliforniaWeb.
pdf (accessed October 8, 2024).
229 Id; Alan T. Marks et. al, California Public Private Partnership Developments, Milbank (March 23,
2009), available at: https://www.milbank.com/a/
web/606/032309_California_Public_Private_Partner-ship_Developments.pdf (discussing AB 680 (1989)); Assem. Bill 680 (1989-90 Reg. Sess.) available at:
https://ppp.worldbank.org/public-private-partnership/
sites/ppp.worldbank.org/files/ppp_testdumb/docu-ments/California0Toll0Road0Law.pdf). 230 California Transportation Commission, Public-Private Partnerships (P3), available at: https://catc.ca.gov/
programs/public-private-partnerships; Caltrans, NCOE
Peer Exchange: P3s, available at: https://transops.s3.am-azonaws.com/uploaded_files/Caltrans%20P3s.pdf. 231 University of California Office of the President, Real Estate Services & Strategies: Privatized development,
available at: https://www.ucop.edu/real-estate-services/ transaction-processes/privatized-development/index.
html (accessed October 8, 2024).
232 Hydrogen Fuel Cell Partnership, available at: https:// h2fcp.org/ (accessed October 8, 2024).
233 See generally Bay Area Council Economic Institute.
234 Id.
235 The Public Advocates Office, Public investment in
infrastructure is a promising option to support Cali-fornia’s energy transition and reduce ratepayer costs 4 (May 16, 2023), available at: https://www.publicadvo-cates.cpuc.ca.gov/-/media/cal-advocates-website/files/ reports/230516-caladvocates-public-investment-in-infra-structure.pdf (accessed October 8, 2024). 236 U.S. Department of Energy, Office of Electricity, Sec-tion 1222 Program – Proposed Plains & Eastern Clean Line Project Frequently Asked Questions, available
at: https://www.energy.gov/oe/section-1222-program-proposed-plains-eastern-clean-line-project-frequently-asked-questions (accessed October 8, 2024). 237 Id.
238 42 U.S.C § 16421(a); U.S. Department of Energy, Office of Electricity, Section 1222 Program – Proposed Plains
& Eastern Clean Line Project Frequently Asked Ques-tions. 239 Id.
240 David Perlman, EPAct 2005: A Game Changer for
Transmission? Part One, Renewable Energy World
(June 27, 2016), available at: https://www.renewableen-ergyworld.com/wind-power/epact-2005-a-game-chang-er-transmission-part-one/#gref (accessed October 8, 2024).
241 Request for Proposals for New or Upgraded Transmis-sion Line Projects Under Section 1222 of the Energy Policy Act of 2005, 75 Fed. Reg. 32,940 (June 10,
2010).
242 U.S. Dep’t of Energy, Summary of Findings In re Appli-cation of Clean Line Energy Partners LLC Pursuant to Section 1222 of the Energy Policy Act of 2005 at 21 &
n.111 (2016).
52 Improving T ransmission F inanc ing in Cal ifornia
243 See Avi Zevin, Justin Gundlach & Isabel Carey,
“Building a New Grid without New Legislation:
A Path to Revitalizing Federal Transmission Au-thorities,” Columbia University, December 2020, available at: https://www.energypolicy.columbia.edu/
publications/building-new-grid-without-new-legisla-tion-path-revitalizing-federal-transmission-author-ities/#:~:text=Section%201222%20of%20the%20 Energy,with%20federal%20eminent%20domain%20
authority (accessed October 22, 2024).
244 Hydrogen Fuel Cell Partnership.
245 Hydrogen Fuel Cell Partnership, About Us.
246 Hydrogen Fuel Cell Partnership, Articles of Incorpo-ration of Hydrogen Fuel Cell Partnership (July 26, 2022), available at: https://h2fcp.org/sites/default/files/ HFCP-Articles-of-Incorporation-2022.pdf; Hydrogen
Fuel Cell Partnership, Bylaws of Hydrogen Fuel Cell
Partnership (July 27, 2022), available at: https://h2fcp. org/sites/default/files/HFCP-Bylaws.pdf (accessed
October 8, 2024).
247 See Hydrogen Fuel Cell Partnership, About Us.
248 See Assem. Bill 680 (1989-90 Reg. Sess.).
249 See New Mexico Renewable Energy Transmission
Authority Act, N.M. Stat. § 62-16A-4 for the portion
of the New Mexico RETA’s organic statute providing
P3 authority.
250 Kelly, an attorney at Jenner & Block, represented
Morongo Transmission. Jenner & Block LLP, Land-mark FERC Decision Paves Way For Clean Energy Tribal-Private Partnerships (Feb. 8, 2022), available
at: https://www.mondaq.com/unitedstates/renew-ables/1159296/landmark-ferc-decision-paves-way-for-clean-energy-tribal-private-partnerships (accessed October 8, 2024).
251 Suedeen Kelly, If Only A Transmission Line Were Like A Rose Bush, WIRES (Nov. 29, 2023), available at:
https://myemail.constantcontact.com/WIRES-Quar-terly-Newsletter.html?soid=1102470513948&aid=QjZ-R3VHJqwE (accessed October 8, 2024). 252 Id.
253 Press Release, Morongo Band of Mission Indians,
Morongo Becomes First Native American Tribe to be
Approved as a Participating Transmission Owner in
Nation (July 19, 2021), available at: https://morongo-nation.org/news/morongo-becomes-first-native-amer-ican-tribe-to-be-approved-as-a-participating-transmis-sion-owner-in-nation/ (accessed October 8, 2024). 254 Suedeen Kelly.
255 Id.
256 Id.
257 Id.
258 Id.
259 Id.
260 Charles W. Galbraith & Suedeen G. Kelly, Land-mark FERC Decision Paves Way for Clean Energy Tribal-Private Partnerships, Jenner & Block (Feb.
7, 2022), available at: https://www.jenner.com/en/
news-insights/news/landmark-ferc-decision-paves-way-for-clean-energy-tribal-private-partnerships (accessed October 8, 2024).
53 Center For Law, Energy & the Environment
III. Appendix II: Public Sector
Financing of Electricity
Transmission Lines in Cal ifornia
Public Sector Financing of Electricity
Transmission Lines in California
Financial and Institutional Options for Reducing
Customer Costs
May, 2024
55 Center For Law, Energy & the Environment
CONTENTS
EXECUTIVE SUMMARY................................................. I SECTION 1 INTRODUCTION...................................... 1 SECTION 2 INSTITUTIONAL OPTIONS FOR PUBLIC
FINANCING ....................................................................... 4
2.1 The Range of Institutional Options
2.2 Allocation of Rights, Responsibilities and Risks
2.3 Advantages of PPP Arrangements
SECTION 3 PUBLIC FINANCING AND PPPS IN
TRANSMISSION PROJECTS ......................................12
3.1 Direct and Indirect Impacts of Public Financing
3.2 Institutional Factors Affecting the Revenue Requirement
3.3 Compatible Institutional Models
3.4 California Transmission PPP Examples
SECTION 4 IDENTIFYING TRANSMISSION PROJECTS
FOR PUBLIC FINANCING STUDY ...........................27
4.1 Transmission Projects For Consideration
4.2 Criteria for Determining Project Eligibility
4.3 Applying Order 1000 Criteria to CAISO 20-Year Transmission Outlook
4.4 Further Observations on Competition Eligibility
SECTION 5 REVENUE REQUIREMENT MODEL . 36
5.1 Assumptions
5.2 Sensitivities
5.3 Scenarios
5.4 Conclusion
56 Improving T ransmission F inanc ing in Cal ifornia
Figures
Figure 2.1: Range of Institutional Options for Delivering Infrastructure Services ................................................................................................................................... 7 Figure 2.2: Allocation of Rights and Responsibilities under Alternative Institutional Models............................................................................................... 8 Figure 2.3: Illustration of a Lease-Type PPP Arrangement.........................11 Figure 3.1: Building Blocks of the Revenue Requirement ..........................13 Figure 4.1: CAISO 2022-2023 Transmission Plan........................................31 Figure 5.1: Impact on RR of a 10% Reduction in Principal Input Variables39 Figure 5.2: Revenue Requirement for Eligible Transmission Lines—Business-as-Usual (BAU) Case ................................................................................................. 40 Figure 5.3: Comparison of Scenarios—Average Annual Revenue Requirement ................................................................................................................................. 40 Figure 5.4: Timelines for Mayor Electricity Transmission Projects in California ................................................................................................................................. 48 Tables
Table 2.1: Allocation of Functions in Typical Greenfield PPP Arrangements9 Table 3.1: Comparison of State, Power Authority, and IOU Credit Ratings14 Table 3.2: How Alternative Institutional Models Can Reduce Costs .......21 Table4.1: Sample Classification of Projects ...................................................32 Table 4.2: Summary of Projects Eligible for Competitive Procurement ..32 Table 4.3: Projects Ineligible for Competitive Procurement ......................33 Table 5.1: Input Assumptions for IOU Scenario (Business-As-Usual) ......36 Table 5.2: Summary of Scenario Assumptions ..............................................37 Table 5.3: Comparison of Input Assumptions and RR Components (Public Sector Scenario) ...................................................................................................41 Table 5.4: Comparison of Input Assumptions and RR Components (Concession-Type PPP Scenario) .............................................................................................42 Table 5.5: Comparison of Input Assumptions and RR Components (Lease-Type PPP Scenario)........................................................................................................43 57 Center For Law, Energy & the Environment
EXECUTIVE SUMMARY PAGE i
EXECUTIVE SUMMARY
California has established ambitious clean energy deployment goals that require a rapid and extensive build-out of new transmission. A key barrier to this build-out is the high cost of new transmission, which has the potential to substantially increase electricity customer rates.
This report evaluates alternative approaches to financing and developing new transmission in California. We find that the use of public sector financing and targeted institutional changes can reduce the cost of California’s needed transmission build-out by tens of billions of dollars over the next two decades. Public-private partnerships (PPPs) with public sector ownership and private sector operation are a promising and cost-effective alternative to the business-as-usual approach of having investor-owned utilities develop all new transmission lines.
Public financing strategies can reduce transmission costs Transmission is a key and growing component of investor-owned utilities’ costs of service. The way these assets are financed and developed has a major bearing on what is ultimately charged to ratepayers.
A public financing approach to deploying transmission can reduce costs in three key ways:
• The use of low-cost public debt (bonds) can directly reduce costs to ratepayers. Low-cost debt would result in lower debt servicing and therefore a lower transmission tariff. To the extent that such debt replaces equity in the capital structure, the costs to ratepayers would be further reduced, as the cost of equity is considerably higher than the cost of debt. Finally, taxes are also typically lower when returns on capital are lower, putting additional downward pressure on the cost of service. • The need for new institutional models to facilitate public financing, including certain types of PPPs or a wholly public entity, can indirectly reduce costs to ratepayers. These models can help to increase competition for the development of new transmission (through more competitive solicitation) as well as reduce the tax obligations of the transmission owner through public ownership. PPPs offer the additional benefit of retaining private sector innovation and efficiency for operating and maintaining the transmission line, and—by using special purpose vehicles to implement projects—can shield the public owner from certain operational risks.
• Accompanying policies that seek to reduce the length and risks of the pre-investment development phase could deliver a third tranche of savings. As transmission development is high-risk and requires significant pre-investment capital, investors require a high-risk premium. As a result, policies that reduce the length and risk of this phase, such as clear and predictable siting and permitting processes, would generate direct cost reductions.1
Estimating the benefit of transmission public financing We estimate the cost savings that could occur under alternative transmission financing and deployment approaches in California. We use the California Independent System Operator’s (CAISO’s) 20-Year Outlook as the basis for the analysis, which identifies the new high-voltage transmission lines (230 kV and 500 kV) 1 This report evaluates transmission cost savings from the use of low-cost public debt and new institutional models only. We provide a separate and very rough estimate of the potential savings from de-risking pre-investment development further below.
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and related upgrades necessary for the state to achieve its SB 100 power sector decarbonization goals. The total capital cost of this new infrastructure—including engineering and construction costs only and excluding all other financing and development costs—is estimated at $25.5 billion.2 We considered four alternative scenarios to financing and developing this new infrastructure:
1. A business-as-usual scenario of an investor-owned utility developing, financing, and operating the lines;
2. A wholly government-owned company developing, financing, and operating the lines;
3. A lease-type PPP, in which a government-owned holding company or special purpose vehicle provides financing for the transmission asset, but hires a private company to operate the assets; and
4. A concession-type PPP, in which the government-owned asset is designed, built, operated, and financed by a private company over the life of the asset, and then ultimately returned to the government at the end of the concession agreement.
We find that the business-as-usual approach to transmission development could—over 40 years—cost ratepayers $100 billion, more than twice the cost of alternative approaches. The difference is due primarily to the higher cost financing used by investor-owned utilities, and what other studies have found to be a lack of sufficient competition in procuring new transmission lines.3 The use of public sector financing and accompanying institutional changes could reduce costs to ratepayers by as much as 57%—or nearly $60 billion—over the 40-year period (Figure ES.1). This is equivalent to savings of $1.5 billion per year. 2 Note that this figure excludes interregional transmission for out-of-state wind that is already being developed. These projects add an additional $5 billion to the total to equal the $30.5 billion amount that is identified in CAISO’s 20-Year Outlook. These costs will be paid by the line subscribers.
3 See, for example: Pfeifenberger, J.P. et al. “Report by Brattle Economists Discusses the Benefits of Competitive Transmission.” Prepared for LSP Transmission Holdings, Brattle, June 21, 2021. https://www.brattle.com/insights-events/publications/report-by-brattle-economists-discusses-the-benefits-of-competitive-transmission/. 59 Center For Law, Energy & the Environment
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Figure ES.1: Total revenue requirement (undiscounted) of four scenarios to develop, finance and operate the CAISO 20-Year Outlook transmission package. The percentages shown on the columns indicate the cost relative to the IOU scenario.
Similar results can be seen for individual lines. For example, more recent and detailed capital cost estimates have been developed for North Coast offshore wind, where a $7.7 billion line is planned to accommodate 7.2 GW of development.4 Under the investor-owned utility scenario, this line would have an annual average cost to ratepayers of $774 million. Under a lease-type PPP, this cost would fall to $332 million per year.
Pros and cons of alternative institutional models
Each of the alternative institutional models to facilitate public financing has its own pros and cons. A lease-type PPP could provide the lowest-cost approach to delivering California’s transmission goal. A lease-type PPP has the advantage of using lower cost public debt, exemption from certain taxes, and the retention of private sector efficiency in operating and maintaining the transmission line. The contracts with the private sector can also shield the public entity from operational risks and allow for better control of costs.
A key advantage of the lease-type PPP over the concession-type PPP is that the latter relies on private sector financing and the return on equity and commercial debt that comes with that. The wholly public model provides a greater degree of public control but does not build in the participation of the private sector beyond the design and build stage and potentially exposes the state to additional financial and legal risk. The investor-owned utility approach is the most expensive to ratepayers and may forego institutional changes that could increase the speed of transmission deployment.
Discussion and next steps
California’s ambitious climate goals require the build-out of a significant amount of new transmission. How this infrastructure is financed, developed, and operated could result in vastly different impacts on ratepayers.
This analysis provides evidence that the use of public sector financing in the form of low-cost public debt that displaces equity and provides tax benefits and that is facilitated by either public-private partnership or wholly public models could deliver significant cost savings relative to investor-owned utility approaches.
We highlight three key limitations to this analysis that suggest the cost savings identified in this report may be conservative. The first is that the CAISO 20-Year Outlook capital costs exclude right-of-way acquisition costs.5 The second is that additional cost savings could be achieved by de-risking the pre-investment project phase.6 The third is that the cost estimates largely exclude the costs of undergrounding transmission. As 4 Zoellick, J. et al. “Northern California and Southern Oregon Offshore Wind Transmission Study.” Schatz Energy Research Center, October 1, 2023. https://doi.org/10.2172/2205318. 5 This is based upon Participating Transmission Owner (PTO) cost guides submitted to CAISO as part of the 20-Year Outlook report: https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/Participating-transmission-owner-per-unit-costs-2023.
Right-of-way acquisition costs would be expected to increase the $25.5 billion base estimate and therefore cost savings from public financing.
6 This report does not attempt to specifically identify policies to shorten the length or reduce the risk of transmission pre-investment development. However, as a simple, illustrative example, if we assume a 50% probability of project failure and pre-investment costs totaling 20% of the total, this would require a 10% risk premium. On a $1 billion project, this would add $100 million to the capital cost. Recent transmission projects in New Hampshire (Northern Pass) and Maine (Hydro-Quebec) with estimated total costs of approx. $1 billion both incurred pre-investment costs equal to 20% and 43%, respectively, of these totals. Overall, policies that provide stronger assurances to successful siting and approval would be expected to directly reduce transmission capital costs.
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described in Section 5, if the costs of fire hardening by undergrounding are included, the total cost to customers would 8-10 times the cost of transmission without such measures.
To the extent that a public financing model is of interest and considered viable, an important next step would be to evaluate the legal and/or regulatory changes necessary to establish one or more of the institutional models within California state government. Colorado and New Mexico are two states with alternative transmission models that could be relevant to California. Internationally, tenders for transmission have most often been concession-type PPP contracts, but there is precedent in the United States in other infrastructure sectors with lease-type PPPs, including road and social infrastructure projects (e.g., schools, and hospitals). 61 Center For Law, Energy & the Environment
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SECTION 1 INTRODUCTION
California’s electricity sector has a diverse mix of energy sources including natural gas, nuclear power, and renewable energy (solar, wind, hydroelectric power), and is the national leader in solar energy production. 7 California’s energy policy framework emphasizes sustainability and environmental protection by transitioning away from fossil fuels, with ambitious goals to reduce greenhouse gas emissions to 40% below 1990 levels by 2030, reaching 90% electricity sector decarbonization by 2035, and achieving, by 2045, carbon neutrality and 100% clean electricity retail sales.
8 To achieve this, California must considerably increase its renewable generation capacity9 and substantially expand its transmission infrastructure for generation to reach load centers at an estimated investment cost of $30 billion. 10 This is in line with the global trend. According to the International Energy Agency,
11 by 2030, global energy generation is expected to almost double, for which annual investments of around $600 billion will be required for transmission and distribution networks . 12 Expanding and upgrading the electricity transmission infrastructure to accommodate the growing share of renewable energy poses regulatory, permitting, environmental, funding and debt rating challenges, including potential negative financial impact on consumers. Furthermore, California faces direct impacts from climate change, including increased frequency and severity of wildfires, droughts, and heatwaves that pose additional challenges to energy production, transmission, and distribution systems, requiring robust resilience and adaptation strategies.
California's energy sector operates under a mixed model that includes both publicly owned utilities and investor owned utilities (IOUs). The state has shown a preference for regulating rather than seeking ownership of the IOUs, focusing on oversight through the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC).
Transmission projects in California are governed by a complex regulatory framework that can significantly affect their development, operation, and expansion (See Appendix A:). The state's constitution and regulatory environment prioritize a competitive market structure to encourage efficiency and innovation. The CPUC and the Federal Energy Regulatory Commission (FERC) regulate California's electricity market, imposing rules that protect consumer interests and ensure competition, including transmission access charges and the allocation of transmission costs through transmission tariffs that meet the “just and reasonable” rate doctrine. This 7 California Energy Commission, “Data Show Clean Power Increasing, Fossil Fuel Decreasing in California,” California Energy Commission, current-date, https://www.energy.ca.gov/news/2023-08/data-show-clean-power-increasing-fossil-fuel-decreasing-california. 8 “California Climate Policy Dashboard,” Berkeley Law, accessed March 16, 2024, https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard/. 9 “2022 Scoping Plan Documents | California Air Resources Board,” accessed March 16, 2024, https://ww2.arb.ca.gov/es/node/20106#.
10 Darrell Proctor, “CAISO Plan Calls for $30.5 Billion for Transmission—and More Renewable Energy,” POWER Magazine, February 3, 2022, https://www.powermag.com/caiso-plan-calls-for-30-5-billion-for-transmission-and-more-renewable-energy/. 11 “World Energy Investment 2023 – Analysis,” IEA, accessed March 16, 2024, https://www.iea.org/reports/world-energy-investment-2023. 12 “Lack of Ambition and Attention Risks Making Electricity Grids the Weak Link in Clean Energy Transitions - News,” IEA, accessed March 16, 2024, https://www.iea.org/news/lack-of-ambition-and-attention-risks-making-electricity-grids-the-weak-link-in-clean-energy-transitions. 62 Improving T ransmission F inanc ing in Cal ifornia
INTRODUCTION PAGE 2
regulatory oversight extends to transmission projects, where the aim is to balance the need for infrastructure development with the principles of a competitive market.
The permitting process for electricity transmission projects is complex due to the involvement of multiple regulatory bodies across local, state, and federal levels, stringent environmental regulations like the California Environmental Quality Act (CEQA),
13 and land use and right-of-way acquisition challenges. Projects must navigate through rigorous environmental impact assessments, extensive public and stakeholder engagement, and comply with strict land use and zoning regulations, all of which can significantly delay timelines and escalate costs.
The increasing ratepayer costs of transmission development motivated the CPUC’s Public Advocate’s Office to question whether the transmission costs could be brought down by replacing IOU investment with public investment. Their initial analysis suggested that a net ratepayer savings of 25% could be achieved (compared to current recovery mechanisms) through lower interest rates, elimination of shareholder returns, and tax benefits not available to private companies.
14 Further reductions could be achieved by lowering the permitted rate of return for utilities, offering bond financing or other forms of securitization to cover some costs, or substituting financing with direct government spending.15 With California's need for billions in annual investments to upgrade its power grid and meet clean energy targets, tapping into public financing could result in significant long-term savings for ratepayers. Changes to the ways in which transmission projects are procured, and the institutional models used to develop and operate them, may offer additional, indirect savings because of the impact they could have on the cost of financing, competition for, and taxation of transmission projects.
These initial insights on ways to reduce the ratepayer cost of transmission have motivated this report. The purpose of the report is to provide a more in-depth exploration of options to reduce ratepayer costs, focusing on increased public support in infrastructure development and the institutional models that could support the delivery of such financing. The remainder of the report is structured as follows:
• Section 2 describes the range of possible institutional options that could potentially be used to deliver public financing. These range from wholly public (government) ownership and operation, to wholly private, with mixed Public Private Partnership (PPP) models, in between. • Section 3 describes the potential direct effects of public financing of transmission and the indirect impacts that could be associated with the use of the alternative institutional models described in Section
2. • Section 4 identifies a set of transmission lines that could possibly be eligible for public sector financing under alternative institutional models.
13 “California Environmental Quality Act (CEQA),” accessed January 19, 2024, https://www.cpuc.ca.gov/ceqa/. 14 California Public Advocates Office, “Public Investment in Infrastructure Is a Promising Option to Support California’s Energy Transition and Reduce Ratepayer Costs,” May 16, 2023, https://www.publicadvocates.cpuc.ca.gov/press-room/reports-and-analyses/public-investments-in-infrastructure. 15 Conservation Strategy Group and Clean Air Task Force, “California Public Finance for Clean Energy Infrastructure: Concept Note,” July 2023.
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• Section 5 quantifies the possible impact on the cost of service of the direct and indirect effects identified in Section 3.
The evidence suggests that substantial direct cost savings could be achieved through the use of public sector financing, and additional savings could be achieved by delivering such financing through alternative institutional models.
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SECTION 2 INSTITUTIONAL OPTIONS FOR PUBLIC FINANCING
Public financing of infrastructure is common throughout the world. State and local governments in the US, and governments internationally issue bonds or use general tax revenue to fund infrastructure investment.
The advantages and disadvantages of using public financing are—to some extent—isolated from decisions about which institutions would be involved in providing the financing and developing the infrastructure project. The public sector will almost always be able to borrow at a lower cost than private companies in the same jurisdiction.
There are, however, important interdependencies between the use of public financing, and the institutional model chosen to deliver such financing. The choice of institutional model will determine the creditworthiness of the borrower and hence the cost at which they can borrow. The choice of institutional model may also bring other benefits, such as the introduction of operating efficiencies, or the reduction of tax obligations.
Section 2.1 describes the range of institutional models that have been used to develop electricity transmission infrastructure globally. Section 2.2 describes how rights, responsibilities, and risks are allocated under each of the institutional models.
2.1 THE RANGE OF INSTITUTIONAL OPTIONS
Infrastructure services, including electricity, water and sanitation, transportation, or telecommunications are delivered under a wide range of institutional arrangements that may involve public sector entities, private companies, or both.
Tradition in the United States is for electricity to be delivered by private companies for whom market entry, pricing, and service quality are regulated by state public service commissions or (for interstate service delivery) a federal regulatory agency (FERC).16 Water supply and sanitation, in contrast, are more often delivered by municipalities and are thus fully publicly owned and operated and there is precedent in many states for the creation of wholly public “power authorities” or “transmission authorities” responsible for various aspects of transmission development and operation. The Colorado Electric Transmission Authority (CETA) and The New Mexico Renewable Energy Transmission Authority (RETA) are two of eight state-level transmission authorities in the United States (there are others in Utah, North Dakota, South Dakota, Wyoming, Kansas, and Idaho). CETA was modeled on New Mexico’s RETA, but they differ in that Colorado has a higher population and considerably more internal demand for electricity than New Mexico. RETA is thus more focused on electricity exports.17
Box 1: The Colorado Electric Transmission Authority
The Colorado Electric Transmission Authority (CETA) is an independent, special purpose authority of Colorado established in 2021 by state legislators. CETA facilitates the development of electric transmission infrastructure for Colorado and neighboring states. Under sections 4 and 7 of Colorado General Assembly SB21-072, CETA is 16 The extent and nature of regulation in the US electricity sector has changed substantially since the wave of power sector unbundling in the 1990s, but the transmission and distribution functions are still typically highly regulated. 17 https://bigpivots.com/. “Colorado’s ‘Transmission Developer of Last Resort’ - Big Pivots.” Accessed April 12, 2024. https://bigpivots.com/colorados-transmission-developer-of-last-resort/. 65 Center For Law, Energy & the Environment
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authorized to select a qualified transmission operator to finance, plan, acquire, maintain, and operate eligible electric transmission and interconnected storage facilities.
CETA is entitled to issue revenue bonds, identify, and establish intrastate electric transmission corridors, and coordinate with other entities to establish interstate electric transmission corridors. The authority may also exercise the power of eminent domain to acquire eligible facilities, and collect payments of reasonable rates, fees, and interest from people using eligible facilities.
CETA operates within a strict set of guidelines from the Colorado legislature, which specify that the authority would only develop transmission necessary to achieve Colorado’s decarbonization goals if unable to identify another party capable of doing so. Legislation prohibits CETA from competing directly with other transmission providers; it cannot plan, finance, or construct any transmission that another developer has pursued.
While CETA does not function as an active transmission developer, it encourages outside planning by identifying and publicizing projects that it views as necessary and allowing other utilities to take ownership of them. If another party pursues the project, CETA withdraws itself from its development. If no other entity shows interest, CETA may become the developer.
Sources:
“About CETA.” Accessed April 12, 2024. https://www.cotransmissionauthority.com/about.
Catlin, Marc, Alex Valdez, Don Coram, and Chris Hansen. Public Utilities Commission Modernize Electric Transmission Infrastructure, Pub. L. No. SB21- 072 (n.d.).
https://bigpivots.com/. “Colorado’s ‘Transmission Developer of Last Resort’ - Big Pivots.” Accessed April 12, 2024. https://bigpivots.com/colorados-transmission-developer-of-last-resort/. 66 Improving T ransmission F inanc ing in Cal ifornia
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Box 2: The New Mexico Renewable Energy Transmission Authority The New Mexico Renewable Energy Transmission Authority (RETA) was established in 2007 by state legislation to plan, finance, and acquire high voltage transmission lines and storage projects for the development of renewable resources across New Mexico. RETA sponsored projects must draw at least 30 percent of their energy from renewable sources. Currently, all projects plan to use 100 percent renewable energy.
RETA seeks a mutually beneficial collaboration with its private development partners. Their developers are expected to provide transmission design and construction expertise, as well as contributions to RETA administrative expenses via lease agreements. In turn, RETA offers tax exemptions (property, gross receipts, and compensating tax), high-level assistance with and streamlining on permitting and siting, and bond financing if necessary.
RETA has the authority to plan, finance, and acquire transmission; it currently has agreements with several developers to realize its goals. In 2010, the authority commissioned Los Alamos National Labs (LANL) to evaluate statewide transmission concepts and create a long-range infrastructure plan for the state. Today, RETA sponsors two projects that rely on the LANL report findings and recommendations, and as a result, has become the authority to act as a developer and potential owner of a merchant-based transmission project.
RETA’s strides in both development and ownership reflect an effort to overcome the existing regulatory barriers to transmission development. RETA partnered with Clean Line Energy Partners (Clean Line) to develop the Western Spirit Project, which creates about 200 miles of construction before connecting with and drawing on the Public Service Company of New Mexico’s (PNM) transmission system. To accelerate the project, RETA and PNM approached FERC to request a streamlined approval. Ultimately, FERC did not accept their request due to claims of harm from others in PNM’s queue. To this date, none of the intervenors with claims have constructed a line and several intervenors have left the queue.
To date, RETA has completed two operational lines and established plans for four additional projects. Finishing its first project in 2010, the authority provided $50 million in revenue bonds to the upgrade of the High Lonesome Mesa line. In 2021, it completed its second line, a $150 million co-development of RETA and Pattern Energy named Western Spirit.
Currently, RETA is co-developing four lines, all under lease agreements: SunZia, Rio Sol, Mora, and North Path.
Sunzia is set to be a $1.8 billion collaboration between RETA and SunZia, starting operation in 2025. The Rio Sol line is a $1.3 billion partnership between RETA and Rio Sol set to begin operating in 2028. Also in development, the Mora line is set to cost $83 million from the partnership of RETA and Lucky Corridor, and expects to start operation at the end of 2024. Finally, the North Path line, from RETA and Invenergy Transmission, remains in the early stages of planning and anticipates completion after 2030.
Sources:
RETA New Mexico. “Creating a Highway for Clean Energy - Transmission Lines NM RETA.” Accessed April 12, 2024. https://nmreta.com/transmission-lines/.
RETA New Mexico. “New Mexico Renewable Energy Transmission and Storage Study Update” February, 2022. Accessed April 12, 2024. https://nmreta.com/wp-content/uploads/2022/03/010522-RETA-Executive-Summary-FINAL.pdf.
RETA New Mexico. “New Mexico Renewable Energy Transmission Authority. Presentation to Science, Technology and Telecommunications Committee”. September 1, 2023. Accessed April 12, 2024. https://www.nmlegis.gov/handouts/STTC%20083123%20Item%2010%20%20RETA%20Presentation%2009-01- 2023.pdf.
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Between these “wholly private” and “wholly public” institutional models are a range of PPP arrangements in which government has some responsibility for delivering service, and a private company has some responsibility. PPP arrangements are more common internationally than in the United States, but there are examples, especially in the roads sector, where PPP-type arrangements have proven more common than in other sectors.
Figure 2.1 shows the range of possible institutional options from wholly public (on the left of the figure) to wholly private (on the right of the figure), with varieties of PPPs in between. An important distinction shown in the figure is the one between institutional arrangements for existing assets and new assets. This report will focus primarily on PPPs that would involve the creation of new transmission assets.
Figure 2.1: Range of Institutional Options for Delivering Infrastructure Services Source: Adapted from World Bank Group, ADB, EBRD, GI Hub, IADB, IsDB, OECD, UNECE, and UNESCAP, Public-Private Partnerships:
Reference Guide, Version 3 (Washington DC: The World Bank Group, 2017), https://ppp.worldbank.org/public-private-partnership/sites/ppp.worldbank.org/files/documents/PPP%20Reference%20Guide%20Version%203.pdf Note: *Operations and maintenance
2.2 ALLOCATION OF RIGHTS, RESPONSIBILITIES AND RISKS
An important feature of PPP arrangements is the existence of a contract between the public and private partners which details the allocation of rights and responsibilities between the parties, including pricing and the expected level of service. The types of contracts can be distinguished from one another by the allocation of functions between public and private partners. Figure 2.2 compares the allocation of functions between public an private partners for wholly public, wholly private, and three archetypal PPP arrangements. 68 Improving T ransmission F inanc ing in Cal ifornia
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Figure 2.2: Allocation of Rights and Responsibilities under Alternative Institutional Models Source: Adapted from United Nations Economic and Social Commission for Asia and the Pacific (UNESCAP), A Primer to Public-Private Partnerships in Infrastructure Development (Bangkok: UNESCAP 2008), https://www.unescap.org/resources/public-private-partnerships-infrastructure-development-primer Notes:
† Demand risk differs between lease and affermage contracts. ‡ The outside operator may manage implementation.
It is more important to understand the allocation of functions typical for different PPPs than it is to understand the “alphabet soup” of acronyms that are often used to describe different types of PPPs. The functions that matter the most are: designing and building the asset, operating the asset, and financing the asset. The table includes examples of acronyms used to describe projects with each allocation of functions.
Table 2.1 summarizes how these functions are typically allocated in “greenfield” projects (i.e., projects that involve new construction).
18 18 “Brownfield” projects, on the other hand, involve investment (such as rehabilitation) in existing infrastructure. 69 Center For Law, Energy & the Environment
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Table 2.1: Allocation of Functions in Typical Greenfield PPP Arrangements Who design
and builds?
Who operates and
maintains? Who finances? Examples of PPP acronyms
Private Public Public
Design-Bid-Build (DBB)
Design-Build (DB)
Build-Transfer (BT)
Private Private Public
▪ Design-Build-Lease (DBL)
▪ Build-Transfer-Lease (BTL)
▪ Built-Transfer-Operate (BTO)
Private Private Private
▪ Build-Operate-Transfer (BOT)
▪ Build-Own-Operate-Transfer or (BOOT)
▪ Design-Build-Finance-Operate (DBFO)
▪ Build-Own-Operate (BOO)
The allocation of functions is important because it determines which risks the public and private partners must bear, and how they are remunerated. Generally speaking:
• With design and build-type PPP contracts the private partner’s revenues come from government payments for design and construction materials and services. These arrangements are often fixed-fee contracts: the public partner pays an agreed fee for the construction and then owns and operates the new asset. With fixed-fee arrangements, the private partner typically assumes the risks associated with construction, such as materials cost overruns or delays. • With design, build, and operate-type PPP contracts, the private partner’s revenues come from user fees (tariffs) or, if user fees cannot be charged, from monthly, quarterly, or annual government payments, sometimes referred to as availability payments. The user fees or government payments are intended to cover the private partner’s operating and maintenance expenses. If user fees are charged for the infrastructure service, the private partner must transfer a portion of the user fees to the public partner, as compensation for the public partner’s financing of the investment (this is sometimes referred to as a “lease fee”). The private partner assumes risks associated with operating the asset, and the public partner assumes risks related to financing the asset (for example, foreign exchange risk), and the overall asset condition and asset life.
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• With design, build, operate and finance-type PPP contracts, the private partner collects user fees (or if user fees cannot be charged) a payment from government which covers all of its operating and maintenance, and financing costs. The private partner therefore assumes most if not all of the risks related to construction, operation and maintenance, financing, and the condition and life of the asset.
Government ultimately owns the asset, but during the PPP contract period, the private partner has many rights of ownership, which may include the ability to pledge the assets as collateral for financing, or to dispose of some of the assets. They will also be required to hand over the assets in a certain agreed condition at the end of the contract period.
2.3 ADVANTAGES OF PPP ARRANGEMENTS
One of the principal advantages of PPPs is the existence of a contract in which risk allocation between the public and private partners can be made explicit; studies have shown that most of the cost advantages of PPPs are achieved through better risk allocation.19 Moreover, at the heart of a PPP arrangement is as Special Purpose Vehicle (SPV) or Special Purpose Entity (SPE). The SPV is a separate legal entity created specifically for the PPP project. Its purpose is to isolate the project's assets, liabilities, and risks from those of the sponsoring entities (the public and private partners).
Another advantage of PPPs is the built-in allowance for competition for all aspects of development and operation. A single PPP contract is the binding instrument between the public and the principal private sector partner, but there are then multiple contracts between the principal private partner (the SPV) and its subcontractors for construction, operations, financing, insurance and other functions. Figure 2.3 is a stylized representation of a lease-type PPP contract, and the risks allocated between the various parties. 19 Pauline Hovy and IMG Rebel, “Risk Allocation in Public-Private Partnerships: Maximizing Value for Money,” Discussion Paper, August 2015, https://www.iisd.org/system/files/publications/risk-allocation-ppp-maximizing-value-for-money-discussion-paper.pdf. 71 Center For Law, Energy & the Environment
INSTITUTIONAL OPTIONS FOR PUBLIC FINANCING PAGE 11
Figure 2.3: Illustration of a Lease-Type PPP Arrangement 72 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 12 SECTION 3 PUBLIC FINANCING AND PPPS IN TRANSMISSION
PROJECTS
Electricity customer rates or tariffs are determined in large part by the cost of providing service. Electricity sector regulators are concerned with ensuring that asset owners and operators recover the reasonable costs of delivering a given service. In the US, state regulatory commissions have authority only over IOUs. An IOU’s cost of service is quantified by its “revenue requirement”. The revenue requirement is the sum of a utility’s costs, and typically includes operating costs (OPEX), capital costs (CAPEX), a return of capital invested (recovered through a depreciation charge or the principal component of debt service), a return on capital invested (interest payments to lenders and—if applicable—equity returns to the asset owners), and taxes.
Federal and state regulators in the United States predominantly use a “rate of return” approach to determine an asset owner’s revenue requirement.
20 There are other methods (such as the “cash needs” approach used by some municipally owned utilities) but the rate of return approach predominates, and is the methodology FERC allows for determining the revenue requirements of transmission owners and operators who bid in transmission line tenders administered by the CAISO. In California, as with many Federally regulated transmission owners, the three IOUs use a variation of the standard “rate of return” method called “formula rates.”21 These rates are updated annually according to a formula rather than requiring a new rate case with a new test year.22 A study by the National Association of Regulatory Utility Commissions (NARUC) explains them as “A ratemaking method in which the utility adjusts its base rates outside of a general rate case, usually annually, based on an actual or projected rate of return on rate base or equity that falls outside some commission defined band.”23
Figure 3.1 is a stylized illustration of the components or “building blocks” of a transmission line owner’s revenue requirement, using the rate of return approach. The RR is the sum of the asset owner’s return on capital invested (a weighting of its borrowing costs and expected equity returns), depreciation (a return of the initial capital invested), OPEX costs, and taxes.
20 The term “asset owner” is used instead of “utility” because some asset owners (e.g., merchant transmission owners) may not meet some readers’ definitions of what is typically considered to be an “electric utility”. Ther term “electric utility” is often reserved for IOUs.
21 “Electric Transmission Rates and FERC Proceedings,” accessed February 20, 2024, https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/electric-transmission-rates-and-ferc-proceedings. 22 WIRES Group, “Primer on Transmission Formula Rates,” Wires Group (blog), February 16, 2023, https://wiresgroup.com/primer-on-transmission-formula-rates/; ELCON, “Formula Rates,” ELCON | Electricity Consumers Resource Council (blog), accessed December 19, 2023, https://elcon.org/formula-rates/. 23 Ken Costello, “Alternative Rate Mechanisms and Their Compatibility with State Utility Commission Objectives” (National Regulatory Research Institute (NRRI), April 2014), https://pubs.naruc.org/pub/FA86C519-AF31-D926-BE12- 2AC7AE0CD8D6.
73 Center For Law, Energy & the Environment
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 13 Figure 3.1: Building Blocks of the Revenue Requirement
As the figure indicates, some of the impacts of public financing are direct: Reducing the amount of equity in the capital structure and reducing the cost of debt would both reduce the revenue requirement. Other effects are indirect: Reducing the return on equity would—all else equal—reduce corporate taxes owed on that return.
Section 3.1 describes these possible direct and indirect impacts.
A third set of possible impacts depends largely on the institutional model chosen for delivering the public financing. There are a range of possible institutional models that could capture the direct and indirect cost savings of public sector financing while also bringing other possible savings to consumers. These impacts are described in Section 3.2.
3.1 DIRECT AND INDIRECT IMPACTS OF PUBLIC FINANCING
Public financing would have a direct impact on a transmission line’s rate of return, by reducing the cost of debt and reducing the need for higher cost equity in the capital structure. A reduction in return on equity could also mean lower corporate tax payments, further reducing the RR for a new transmission line.
3.1.1 RATE OF RETURN
The rate of return is—among the components of the revenue requirement—the most obviously and directly affected by public sector financing. The rate of return is a weighted average of the cost debt and cost of equity; it depends on the mix of debt and equity used to finance the transmission asset and the returns expected on debt and equity. In the case of debt, the returns are the interest payment required by lenders on loans; in the case of equity, the returns are what shareholders require in terms of dividend payments and changes in the value of the stock they own.
74 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 14
COST OF DEBT
Governments, and government agencies, are typically able to borrow at lower interest rates than private companies. Public sector borrowers are regarded as more creditworthy because they have the guarantee (explicit or implicit) of government, and government has access to recurring tax revenue. The public sector typically borrows by issuing bonds, with the interest rate determined by the bond “coupon”. Public sector entities with better creditworthiness—as measured by their credit ratings—will typically have bonds with lower coupons than those that are viewed as less creditworthy.
Table 3.1: Comparison of State, Power Authority, and IOU Credit Ratings State/ territory
State credit
rating/outlook
Power Authority credit
rating/ outlook
Biggest IOU credit
rating/outlook
New York AA+/Stable AA/Stable
BBB-/Stable (national
grid)
Long Island N/A A/positive BBB+/Stable (KeySpan)
Colorado AA/Stable AA/Stable BBB+/Stable (Xcel)
California AA/Stable AA/Stable BB+/Stable (PG&E)
Sources:
“Credit Ratings & Analysis for Financial Markets.” Fitch Ratings, www.fitchratings.com/#insights. Accessed 2 Apr. 2024. (used for all issuers except LADWP)
“KBRA: Credit Rating Analysis Agency: Bond Rating Agency.” Kroll Bond Rating Agency, 28 Feb. 2024, www.kbra.com/publications/LVNmTQGn/kbra-assigns-aa-rating-to-the-department-of-water-and-power-of-the-city-of-los-angeles-power-system-revenue-bonds-outlook-is-stable. (used for LADWP) Public corporations or agencies (such as a power authority) will have lower credit ratings than the state or local governments that own them. This can be seen in the table above by comparing the state of New York’s credit rating to that of the New York Power Authority (NYPA) and the Long Island Power Authority (LIPA).
Bonds issued by state and local governments have the added advantage that they are often tax-free, meaning the bondholders (the lenders) do not pay taxes on the payments they receive from the bond issuers (the borrowers). This helps to further reduce the coupon relative to bonds that are not tax-free (e.g., corporate bonds). The IRS also allows a special kind of tax-free bonds for capital projects. IRS Rule 63-20 allows state 75 Center For Law, Energy & the Environment
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 15 and local government to issue tax-exempt revenue bonds for a third party through a) established conduit issuers or b) the creation of nonprofit corporations applicable to IRS Revenue Ruling 63-20. Box 3 describes 63-20 financing and its perceived advantages.
Box 3: IRS 63-20 Alternative Project Delivery
63-20 financing involves a nonprofit corporation issuing tax-exempt bonds on behalf of a state or political subdivision. These bonds are used to finance governmental facilities. The name “63-20” originates from Revenue Ruling 63-20, which outlines the rules for this type of financing. The primary goal is not just tax-exempt financing but also an alternative development approach.
With 63-20 financing a nonprofit corporation issues bonds to finance the development of an asset on behalf of a state or municipal entity. The bond proceeds cover acquisition, construction, and equipping of the facility. The nonprofit issuer manages a private development team responsible for the project. The nonprofit issuer hires a private development team responsible for the project.
The perceived advantages of using 63-20 financing are often describe as the following:
• Reduced project delivery time: The approach circumvents the often protracted government financing and procurement processes, leading to faster project delivery. • Public assumption of responsibility for permitting. The SPE secures the required project entitlements upfront, instead of leaving that to a private operator. • Operations & maintenance efficiency: The utilization of private property management allows for improved lifecycle costing and the transfer of O&M risk to the private sector, reducing the likelihood of deferred maintenance.
• Cost Transparency: The use of tax-exempt financing results in debt service costs equivalent to traditional public financing options, ensuring transparency and predictability in project costs. • Protection from Risk: The SPE is bankruptcy remote, protecting the public agency from construction and other risks.
Sources:
“Fifty Years of 63-20 Financing: Revisiting an Alternative ...” MRSC, mrsc.org/getmedia/530A597A-4D81-41AE-9279- 3523D1BE0BAC/m58-63_20.aspx. Accessed 2 Apr. 2024.
Tax-Exempt Financing by Nonprofit Corporations ..., files.klgates.com/files/publication/d1586c6b-e6e4-42df-b131- 919ed1d163cc/presentation/publicationattachment/ec29a420-819b-46ab-9e28- 9479dc50ec26/tax_exempt_financing_by_nonprofit_corporations.pdf. Accessed 2 Apr. 2024. 63-20-PDB-Improving-upon-P3.Pdf - Public Facilities Group, 2020, publicfacilitiesgroup.org/wp-content/uploads/2020/09/63-20-PDB-Improving-upon-P3.pdf.
Public Facilities Group. Four Principles: How to Maximize Public Benefits When Using P3 Delivery, 2020 Public Facilities Group.
COST OF EQUITY
Equity typically has a higher cost than debt because shareholders have higher risks than lenders. Banks making loans to an infrastructure project will have legal rights, determined in loan agreements, which—if it does not receive the expected payments of principal and interest—give it recourse to the assets being financed. Equity owners have little or no such recourse and thus require higher returns to compensate them for the risk of their investments.
76 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 16 To the extent that debt is used instead of equity in the capital structure, it will reduce the overall cost of capital. Capital structures in US electric utilities are typically in the range of 40 to 60 percent debt and 40 to 60 percent equity. This is consistent with the ranges for California’s major IOUs which CPUC authorizations ranged in 2021 from 43.00 to 47.50 percent Long-term Debt, 0.50 to 5.00 percent for Preferred Stock, and
52.00 percent Common Equity; actual capital structures in that time ranged from 44.00 to 56.44 percent Long-term Debt, 0.00 to 4.70 percent Preferred Stock, and 43.00 to 56.00 percent Common Equity.24 Nationwide, annual average Return on Equity (ROE) for electric utilities have ranged from 9.63 percent to
10.81 percent since 2019.25 Authorized ROEs for California's major IOUs ranged from 10.20 percent to 11.60 percent from 2006-2021, while actual ROE's ranged from -35.38 percent to 13.64 percent in that same period.26
Utilities' actual returns on equity can fluctuate for a variety of operational, financial, and regulatory factors, leading to differences between actual ROE and the authorized ROE, the latter of which is used for rate setting but is not a guarantee of any given level of return. For example, in 2021, though SCE was authorized to earn as much as 10.30 percent on equity ; but achieved only 3.45.27 One of many contributing factors included material losses connected with wildfires in SCE territory in December 2017 and November 2018. Litigation costs, settlement activities, and damages in excess of available insurance resulted in significant losses exceeding $1.3 billion more than original estimates in the third quarter of 2021.28
3.1.2 TAXES
Public sector financing could have an indirect impact on taxes if it reduces the rate of return. A lower ROE will—all else equal—reduce the income tax obligations of a regulated transmission line.
3.2 INSTITUTIONAL FACTORS AFFECTING THE REVENUE REQUIREMENT There are a range of institutional factors which—whereas not directly related to the source of financing— could have an impact on the revenue requirement of a new transmission line. These factors are:
• More competitive procurement, which can bring down CAPEX costs of transmission lines • Accelerated clearance of pre-construction development, including permitting and regulatory approvals
• Private sector involvement in development and operations, which retains the efficiency advantages of having an experienced private sector operator.
24 CPUC, “Capital Structure,” accessed 4/1/2024 at https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/historical-electric-cost-data/capital-structure 25 NARUC, “Cost of Capital and Capital Markets Primer for Utility Regulators,” December 2019, https://pubs.naruc.org/pub.cfm?id=CAD801A0-155D-0A36-316A-B9E8C935EE4D 26 CPUC, “Return on Equity,” accessed 4/1/2024 at https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/historical-electric-cost-data/return-of-equity 27 California Public Utilities Commission. "Return of Equity." Accessed May 24, 2024, https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/historical-electric-cost-data/return-of-equity 28 Southern California Edison. "2021 Annual Report Edison International and Southern California Edison." 2021. https://download.edison.com/405/files/202210/2021-eix-sce-annual-report.pdf?Signature=bTLt6rslBQQD9tuFM70l7JXo%2BoU%3D&Expires=1716635813&AWSAccessKeyId=AKIAJX7XEOOELCYGIV DQ&versionId=J7O.wRg0NotvVA1WzSMV9w4b4oEXipVL&response-content-disposition=attachment 77 Center For Law, Energy & the Environment
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 17 All of these factors could potentially reduce the RR of a new transmission line; whether they do depends heavily on the institutional model chosen.
3.2.1 MORE COMPETITION
There is evidence that increased competition in the procurement of transmission lines could reduce costs to end-users. Work by consultants at the Brattle Group indicates that more competitive processes in procuring transmission in the US could reduce capital costs by as much as 20-30%.29 The Brattle Study looked at the results of competitive procurement in transmission in the US, Canada, the UK, Brazil, Chile, and Australia.
Similar results can also be seen in competitive auctions in other countries. Box 4 shows, for example, the cost savings from competitive auctions for transmission lines in Peru when concession-type PPPs were used instead of letting the incumbent utility develop and operate the lines. 29 Pfeifenberger, Johannes P., Judy Chang, Akarsh Sheilendranath, J. Michael Hagerty, Simon Levin, and Wren Jiang. “Report by Brattle Economists Discusses the Benefits of Competitive Transmission.” Prepared for LSP Transmission Holdings, Brattle, June 21, 2021. https://www.brattle.com/insights-events/publications/report-by-brattle-economists-discusses-the-benefits-of-competitive-transmission/. 78 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 18 Box 4: Competitive Auctions for Transmission in Peru
Since 2002 in Peru, the private sector has competed in bids for 30-year operation and maintenance concession contracts guaranteeing fixed annual payments. PPP investments in electric transmission lines have exceeded 3,600 million Peruvian Sol (about 970K USD) from 2001 to 2020 and are steadily increasing. The successive competitive auctions have been tied to the system operator’s biennial transmission expansion planning process since 2006, resulting in substantial whole-of-life cost reductions and increased competition for the investment of transmission systems. • Cost Reductions: Winning bids for 15 projects between 1994 and 2013 were, on average, 36 percent lower than the estimated annual costs. One project developed in 2008 was a remarkable 58 percent lower. Private remuneration linked to 30 years of infrastructure operation ensured a long-term commitment to operational efficiency. This model promoted sustained growth, particularly in high and ultra-high voltage lines, with lower losses over long distances.
• Increased Competition: Competitive securities from bidders incentivized significant savings for the country.
Competitive bidding led to bids averaging at least 40 percent lower than the government's maximum value in ten tenders from 2015 to 2021. The competitive nature of the auctions resulted in increased participation, fostering a healthier competitive environment. From 2015-2021, PROINVERSIÓN, the entity commissioned to award projects, saw five bidders on average per project in transmission line tenders.
Of the 27 projects awarded since 2008, 16 are operational. Once awarded, transmission projects in Peru cannot start the operational stage until they are granted all the needed permits, including environmental, technical and social approvals. Most of the awarded projects that are not yet operational are delayed in obtaining environmental certifications because of political conflict in the country, and because of delays in acquiring essential permits despite legal deadlines, the need for prior consultation with indigenous communities following recent legal changes, and bureaucratic hurdles in approving schedule extensions. Nonetheless, the overall perception of PPP transmission projects in Peru is positive. In 2023 alone, 14 projects were awarded, with investments totaling over US$ 2,330 million. Of these PPPs, 8 were transmission projects, for a total of US$1.2 billion, which represents more than 53% of the total awarded value. For 2024, 4 groups of transmission projects are expected to be awarded, with a value of more than US$ 900 million.
Beyond cost savings and increased competition, Peru's transmission PPPs have brought about additional benefits such as job creation, enhanced reliability, minimized service disruptions, improved efficiency, and balanced energy prices across regions.
To tackle some of the challenges of implementing PPP projects, recent legal and regulatory changes in Peru's PPP framework, highlighted by the implementation of Legislative Decree No. 1362, aim to streamline processes and enhance transparency, reduce bureaucratic delays and foster better public-private coordination. These reforms are designed to stabilize the investment environment, addressing chronic issues such as contract renegotiations and permit delays, to ensure the timely execution of infrastructure projects.
Sources:
Pedro E. Sanchez and Samuel Oguah, "Private Sector Participation in Transmission Systems: Making It Work," World Bank Group Livewire: A Knowledge Note Series for the Energy & Extractives Global Practice, 2015, https://ppi.worldbank.org/content/dam/PPI/resources/ppi_publication/web_publication/100989-BRI-VC-PUBLIC-ADD-SERIES-Box393254B-Knowledge-Notes-LW52-OKR.pdf PROINVERSIÓN, "Investments in PPP Exceed $ 3,600 Million and Contribute to Sustaining Economic Activity," September 1, 2021, https://www.investinperu.pe/en/ppp/detalle-noticia/investments-in-ppp-exceed-3600-million-and-contri Diana Briones Morey and Diego Morales Alferrano, “Proyectos de transmisión de electricidad: problemas recurrentes y agenda pendiente | IUS 360,” April 3, 2023. https://ius360.com/proyectos-de-transmision-de-electricidad-problemas-recurrentes-y-agenda-pendiente/. 79 Center For Law, Energy & the Environment
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 19 Cost savings from competitive procurement have an impact on the revenue requirement through the “rate base”. The rate base for a transmission line is the asset value of that line at any given point in time. The value of the rate base is driven largely by the capital expenditure (CAPEX) cost of that asset and its age.30 The CAPEX cost is the cost of building the line but may also include pre-construction project development costs, as FERC’s Uniform System of Accounts considers construction costs to includes a wide range of development costs beyond materials & supplies. Some of the other costs include: contract work, labor, privileges and permits, engineering and supervision, legal expenditures, studies, training costs.31 Financing costs are also allowed as an Allowance for Funds Used During Construction (AFUDC). All of these costs may be included in the rate base once the asset becomes operational.32
A reduction in rate base has the following cumulative impacts on a revenue requirement:
• The total dollar return on debt and (if applicable) equity will be lower because the WACC is applied to a lower asset value
• Corporate tax obligations will be lower, because the return is lower • Depreciation charges will be lower, because the asset cost is lower • OPEX may also be lower to the extent—as we assume in Section 5—that they are a percentage of CAPEX costs.
There are thus spillover effects of a reduction in rate base, potentially leading to a lower revenue requirement overall and lower tariffs.
3.2.2 ACCELERATED DEVELOPMENT
As noted above, non-construction development costs may be capitalized or “rolled-in” to a utility’s rate base and may even be recovered (as Construction Work in Progress, CWIP) before an asset is operational. The longer development period, the higher the costs are likely to be. Moreover, the likelihood of a project going forward reflects risk, which also has a cost in terms of ROE (higher risk projects will typically have a higher ROE).
The extent to which regulators allow such development costs to be included in a rate base will differ by jurisdiction and circumstance. It is therefore difficult to know the magnitude of such costs, but evidence from canceled transmission projects indicates that they are substantial. The costs include expenses for financing arrangements, permitting, and regulatory compliance. Evidence of the magnitude of such expenditures can be seen where projects have been abandoned. As noted above, the Northern Pass project in New Hampshire incurred $318 million in sunk costs for pre-development activities, representing roughly 20% of its estimated total cost of $1.6 billion.33 Similarly, the Hydro-Québec US transmission line project in Maine saw $450 30 The asset’s age matters because assets deteriorate over time, and with that deterioration, lose value. See the discussion in Section Error! Reference source not found. on depreciation. 31 “18 CFR Part 101 -- Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act.” Accessed April 1, 2024. https://www.ecfr.gov/current/title-18/part-101. 32 Utilities may also be able to recover some of them before the line is commissioned, as “Construction Work in Progress” or CWIP.
33 Michael Cousineau, “Eversource giving away land bought for failed Northern Pass project,” New Hampshire Union Leader, June 26, 2023, https://news.yahoo.com/eversource-giving-away-land-bought-225400675.html 80 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 20 million (43% of the estimated total project costs) spent in pre-development.34 If there is a 50% probability of failure and a 20% cost for failure, then every developer has to build in a minimum 10% risk adder to the CAPEX.
The potential savings to ratepayers is in reducing the window of time for permitting and regulatory approval as well as reducing the development risk that extended review implies. This could reduce development costs that later enter into the rate base. The savings would come first from reducing the number of years and level of effort utility staff have to work on pre-construction project development. Second, it would come from early termination for projects rejected by regulatory agencies as in the case of Northern Pass. The early termination limits the amount spent on failed projects and thus the risk premium for development.
3.2.3 PRIVATE SECTOR EXPERTISE AND EFFICIENCY
There is an extensive body of literature devoted to analyzing the efficiency and effectiveness of public sector institutions versus private. The literature is—as a whole—largely inconclusive, in part because the results are so often highly dependent on context.
Without entering into specific arguments on either side, there is at least anecdotal evidence that the private sector can be given incentives to operate more efficiently than the public sector in delivering infrastructure services. In the Peru example in Box 4, it is apparent that the private transmission concessionaires helped to reduce whole-of-life costs of transmission and not just CAPEX costs. Common sense also suggests that:
• There are advantages in having a specialized private sector developer and operator who can bring the right skills to a project.
• Giving a developer/operator a profit incentive can be a powerful performance motivator. • Making potential developers/operators compete for a market (i.e., for the exclusive right to earn revenue from a transmission asset) has the potential to reduce costs.
What is clear is that supply chain challenges and skilled labor shortages are one important factor in the delays experienced in developing new transmission lines. The creation of a public sector entity responsible for transmission development would be competing with long-established, experienced private developers and IOUs for materials and labor.
3.2.4 TAXATION
One possible advantage of having a public asset owner—such as Power Authority—is that these public entities are not typically required to pay income taxes and may be exempt from some other taxes, including sales or property tax.35 NYPA, for example, is exempt from income taxes and properties acquired for its projects.36 PRPA is similarly exempt from income and property taxes.37 LIPA is not obliged to pay income tax, but its status for property and sales tax have been the subject of a series of disputes over the years. 34 “Hydro-Quebec scores legal victory in Maine over $1B US transmission line project,” CBC News, April 20, 2023, https://www.cbc.ca/news/canada/montreal/hydro-quebec-1.6816752 35 A utility may, in some circumstances, make “payments in lieu of taxes” to reimburse local governments for foregone property taxes.
36 Tu, Kailin. “Proposed 2023 Budget and 2023–2026 Financial Plan,” 2023. 37 https://www.prpa.org/wp-content/uploads/2021/04/Organization-Governance-April-2020.pdf 81 Center For Law, Energy & the Environment
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 21
3.3 COMPATIBLE INSTITUTIONAL MODELS
The discussion above suggests that the most appropriate institutional models will be those that:
• Allow for the use of public debt in financing transmission lines and facilitate savings in other areas, such as taxes.
• Foster competition among bidders in ways that reduce project costs. • Allow for private sector involvement in development and/or operations. • Accelerate the transmission development process, especially the period before construction which is the riskiest from an investor perspective.
Table 3.2 summarizes how four possible institutional models, ranging from wholly public to wholly private rank against these criteria.
Table 3.2: How Alternative Institutional Models Can Reduce Costs Facilitates Savings
from the Use of
Public Financing?
Facilitates
Competition?
Facilitates Private
Sector
Involvement?
Accelerates
Development?
Wholly Public Yes
Would likely
involve a
competitive tender
for design and
build functions
only
Limited to design
and build
functions
Possibly, but
would likely
require substantial
institutional, legal,
and regulatory
changes
Lease Contract
Yes, the
government is an
asset owner
Yes, would involve
competitive tender
for the design,
build, and operate
functions over
short-term
(typically 3-5
years)
Yes, a private
sector operator is
hired as a lessee
Concession
Contract
Typically, privately
financed
Yes, would involve
competitive tender
for the design,
build, and operate
functions over the
life of the asset
Yes, private sector
operator is hired
as concessionaire
Wholly Private
(IOUs)
Typically, privately
financed
Depends on the
type of tender, but
for many lines
tendered by
CAISO, incumbent
utilities already
have access to
property or rights-of-way
Yes, utility is
private company
No. Current
process takes 5-15
years
82 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 22 A lease contract-type PPP offers—in our view—the best mix of ability to inject public financing, harness other possible benefits of public ownership (e.g., some degree of tax-exempt status and the ability to issue tax-exempt bonds), and involve private sector expertise. Any of the models could conceivably help to accelerate the development process—for example, the creation of a “one stop shop” for expedited regulatory approvals— but would require substantial institutional, legal, and regulatory changes in any case.
The principal disadvantages of other models are:
• The wholly public model does not build in the participation of the private sector beyond the design and build stage.
• The concession-type PPP would mean private sector financing, and the ROE and commercial debt that comes with it. It is conceivable, however, that the public sector could provide some concessional financing (or even grants) to reduce the cost of capital. • The wholly private model is “business-as-usual”, with private sector financing costs, and no solution to the long delays in project development.
As noted in the table, none of the models offers an easy solution to accelerating project development without substantial institutional, legal, and regulatory changes. These would be required, regardless of the model chosen.
Most international tenders for transmission have been concession-type PPP contracts, but there is precedent in the US, and in other infrastructure sectors, with lease-type PPPs. Lease-type contracts have been used, for example, in the development of road projects. Such leases are longer-term than those typically seen for other infrastructure projects, but the principles of upfront public financing and private operation are the same. Box 5 describes some of the projects. In the case of the Pocahontas Parkway, tax-exempt IRS 63-20 financing was used.
83 Center For Law, Energy & the Environment
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 23 Box 5: Lease-type Roads Contracts in the United States
PPPs for infrastructure are more common internationally than in the United States; they have been more common in the US roads sector than in other sectors. The following are examples of lease-type PPPs used in US roads sectors:
• Chicago Skyway: In 2004, the Chicago Skyway toll road's lease was awarded to Cintra and Macquarie for $1.83 billion, marking the first long-term lease of an existing toll road in the United States. In 2015, they sold their interest to Calumet Concession Partners LLC, a consortium of Canadian pension funds, for $2.8 billion. Calumet now operates the Skyway, collecting tolls until the lease expires in 2104, ensuring its continued functionality as a crucial transportation link. • Indiana Toll Road: In 2006, the Indiana Finance Authority (IFA) leased the Indiana Toll Road to the Indiana Toll Road Concessions Company (ITRCC) for 75 years, with ITRCC assuming authority in June of the same year. The lease mandated a $200 million investment in capital improvements within the first three years and a total of $4.4 billion over its duration. However, in 2015, ITRCC filed for bankruptcy, leading to the IFA awarding a new 66-year lease to IFM Investors for $5.725 billion. • Northwest Parkway: The Northwest Parkway connects E-470 in Denver to US Route 36 in Broomfield Colorado. It was initially opened in 2003 and financed through toll revenue bonds. The project faced financial challenges due to lower-than-expected traffic volume by 2007, leading to its lease to a private consortium, Northwest Parkway LLC, for 99 years. The agreement entailed an upfront cash payment, the takeover of existing debt, and an annual administrative fee to the Authority over the lease's duration. A portion of the debt was held in escrow pending issuance of notices to proceed by the end of 2018, aiming to extend the parkway's operations.
• Pocahontas Parkway/Richmond Airport Connector: The Pocahontas Parkway was primarily financed by tax-exempt revenue bonds totaling $354 million issued by the Pocahontas Parkway Association in 1998 under Virginia’s Public Private Transportation Act of 1995. Financing also included a State Infrastructure Bank loan of $18 million and $9 million from the federal government for roadway design. In 2006, a 99- year lease of the Parkway was granted to Transurban, a private Australian toll road operator with US subsidiaries. In exchange for assuming exclusive rights to enhance, manage, operate, maintain, and collect tolls on the Parkway, Transurban committed to constructing the Richmond Airport Connector, a
1.58-mile extension linking the toll road to Richmond International Airport.
Sources:
“Project Profile: Chicago Skyway.” FHWA, US Department of Transportation Federal Highway Administration, www.fhwa.dot.gov/ipd/project_profiles/il_chicago_skyway.aspx. Accessed 2 Apr. 2024. “Project Profile: Indiana Toll Road.” FHWA, US Department of Transportation Federal Highway Administration, www.fhwa.dot.gov/ipd/project_profiles/in_indiana_toll.aspx. Accessed 2 Apr. 2024. “Project Profile: Northwest Parkway.” FHWA, US Department of Transportation Federal Highway Administration, www.fhwa.dot.gov/ipd/project_profiles/co_northwest_parkway.aspx. Accessed 2 Apr. 2024. “Project Profile: Pocahontas Parkway / Richmond Airport Connector.” FHWA, US Department of Transportation Federal Highway Administration, www.fhwa.dot.gov/ipd/project_profiles/va_pocahontas.aspx. Accessed 2 Apr. 2024.
Lease-type contracts have also been used in social infrastructure projects, including educational facilities, civic buildings, and healthcare facilities. The nonprofit “Grow America” (formerly the National Development 84 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 24 Council) pioneered the approach and an organization called the Public Facilities Group has been involved in disseminating it, and advising on transactions.
38 Box 6 summarizes the principles behind the approach.
Box 6: The “New American” Approach to PPPs
The “New American Approach” involves the following steps:
1. A public agency hires a not-for-profit partner through competitive tender to lead development of the project. The not-for-profit partner will issue the debt and own the facility on behalf of the public agency.
The not-for-profit partner is remunerated through a portion of the bond proceeds.
2. The public agency and not-for-profit partner select (again through competitive tender) a development team consisting of a lead developer, general contractor, and architect.
3. The development team works with the public agency and not-for-profit partner to design the project. The not-for-profit partner also secures approval of all project entitlements required to develop the project. The public agency and not-for-profit partner negotiate a long-term lease between themselves for the planned facility.
4. The not-for-profit partner creates a special purpose entity (SPE) to own and finance the asset. The SPE issues bonds (working with a bond underwriter) to sell to investors. The bond proceeds are held by a separate agency appointed as a trustee.
5. The not-for-profit partner staffs the SPE and manages construction and contractor payments. A private property management firm is selected through competitive tender to operate the facility once it is completed.
6. Once construction is completed, the public agency (or the intended beneficiaries) move into the building and the lease takes effect. The public agency makes lease payments (as rent) to the SPE which cover debt service, operating costs, and contributions to a repair and replacement reserve. Repair and replacement reserves are held by the trustee.
7. The property management firm works for the SPE, taking responsibility for managing the facility and undertaking routine operations and maintenance. The management agreement is re-tendered every 3-5 years.
8. Once the public agency has made its last lease payment, the debt is retired and excess funds from the repair and replacement reserve return to the public agency. The public agency may then take on responsibility for property management and ownership of the project.
Sources:
Public Facilities Group. “Our Approach.” Public Facilities Group (blog). Accessed April 1, 2024. https://publicfacilitiesgroup.org/our-approach/.
A number of non-IOU companies specialize in owning, operating, and maintaining high-voltage transmission lines and related infrastructure. These are just examples of some of the private partners who may potentially be interested in additional transmission projects in California. Some independent power transmission companies in North America including the ITC Holdings Corp (operating assets in Michigan, Illinois, Iowa, Kansas, Minnesota, Missouri, Oklahoma, and Wisconsin), NextEra Energy Transmission (subsidiaries 38 Public Facilities Group, “Our Approach,” Public Facilities Group (blog), accessed January 12, 2024, https://publicfacilitiesgroup.org/our-approach/.
85 Center For Law, Energy & the Environment
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 25 operating assets in California, Illinois, Indiana, Kansas, Kentucky, Nevada, New Hampshire, New York, Oklahoma, Texas and Ontario, Canada), and Sharyland Utilities LLC (operating assets in Texas and Mexico).39 Other energy infrastructure companies whose business has been traditionally focused on natural gas pipelines or energy generation assets have also begun entering partnerships to develop transmission capabilities, such as Enbridge's recent partnership with NextEra Energy Canada and OMERS Infrastructure to build and operate the East-West Tie (EWT) Transmission Project, now operational in northern Ontario.40 Specialized investment funds that focus on acquiring and managing infrastructure assets, such as Meridiam and Boundless Energy, have also teamed up with grid operators to develop, construct, and operate large-scale transmission assets.41 Private equity firms also sometimes invest in or acquire and manage electricity transmission assets, either directly or through portfolio companies. For example, Atlantic Power Transmission, LLC. is a Blackstone Infrastructure Partners Portfolio Company, constructing and operating planned transmission systems along the US East Coast.
42 3.4 CALIFORNIA TRANSMISSION PPP EXAMPLES
Some transmission projects in California can also be classified as PPP projects. Three examples are summarized in Appendix A: a) the Path 15 project completed in 2004, b) the Trans-Bay Cable completed in 2010, and c) the West of Devers Upgrade Project completed in 2021.
In each case, although there was a partnership with a public entity, the tariff included a ROE. In the case of Path 15 and Trans-Bay Cable (catalogued as a critical transmission asset), an initial ROE of 13.5% was granted by FERC as part of a policy to stimulate construction of transmission.43 The rates for Path 15 and the Trans-Bay Cable were contested, but only the Path 15 ROE was reduced to 10.6%.44 In the case of the West of 39 ITC Holdings Corp. "Home." Accessed May 24, 2024, https://www.itc-holdings.com/; Sharyland Utilities. "About." Accessed May 24, 2024, http://www.sharyland.com/about.aspx; NextEra Energy Transmission. "Home." Accessed May 24, 2024, https://www.nexteraenergytransmission.com/ 40 Enbridge. "Power transmission." Accessed May 24, 2024 https://www.enbridge.com/about-us/renewable-energy/power-transmission 41 Shumkov, Ivan. "Italy's Terna, France's Meridiam team up in US to build power links." October 25, 2022.
Renewables New. Accessed May 24, 2024. https://renewablesnow.com/news/italys-terna-frances-meridiam-team-up-in-us-to-build-power-links-802246/ 42 Chirhart, Paula. "Atlantic Power Transmission LLC, a Blackstone Infrastructure Partners Portfolio Company, Announces $50 Million Commitment to New Jersey Workforce Development." April 22, 2022. Blackstone.
Accessed May 24, 2024 https://www.blackstone.com/news/press/atlantic-power-transmission-llc-a-blackstone-infrastructure-partners-portfolio-company-announces-50-million-commitment-to-new-jersey-workforce-development/ 43 “Analysis of FERC’s Notice of Proposed Rulemaking on Electric Transmission Incentives,” Steptoe, accessed March 25, 2024, https://www.steptoe.com/en/news-publications/analysis-of-fercs-notice-of-proposed-rulemaking-on-electric-transmission-incentives.html. 44 “E-6 ER20-1006-001 | Federal Energy Regulatory Commission,” accessed March 24, 2024, https://www.ferc.gov/media/e-6- er20-1006-001.
86 Improving T ransmission F inanc ing in Cal ifornia
PUBLIC FINANCING AND PPPS IN TRANSMISSION PROJECTS PAGE 26 Devers Upgrade Project, the Morongo Tribe partnered with Southern California Edison (SCE). The Morongo Tribe was granted an ROE of 10.8% based on the approved SCE rate of 10.3% plus a 0.5% premium.45 45 FERC, “Order on Rehearing, Morongo Transmission LLC Transmission Owner Tariff,” FERC Docket ER21-669-001, May 5, 2021, https://elibrary.ferc.gov/eLibrary/filedownload?fileid=15786960. 87 Center For Law, Energy & the Environment
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 27 SECTION 4 IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC
FINANCING STUDY
The objective of this study is to estimate possible ratepayer savings that could be achieved through public financing and new institutional arrangements. This is motivated by the increasing costs driven by the renewable buildout.
The California ISO 20-Year Transmission Outlook is the benchmark study for cost savings because it is the longest-term plan and is designed to meet the needs of the renewable generation buildout of Senate Bill 100.46 The 20-Year Transmission Outlook identifies $30.5 Billion of transmission infrastructure buildout deemed necessary to meet the goals of Senate Bill 100.
However, perhaps not all projects in the 20-Year Transmission Outlook would benefit from the new institutional arrangements. There may also be additional transmission projects outside the 20-Year Transmission Outlook that we should consider as potential candidates.
This section identifies the scope of transmission projects that could take advantage of the new approach.
There are two questions:
1. Which source of planned projects should form the set of transmission improvements to examine in the cost savings analysis?
2. Of all the possible transmission projects, which projects could adopt the new institutional arrangement? Some projects are IOU-financed by law and the law cannot be changed quickly or easily.
4.1 TRANSMISSION PROJECTS FOR CONSIDERATION
EXISTING TRANSMISSION MAINTENANCE AND UPGRADES
Existing transmission can and does cause significant cost increases. IOUs have the authority to replace existing equipment and recover the cost under their existing tariffs. This is allowed under the use of existing formula rates. State regulators both in and outside California have identified this activity as a major cause of increasing rates. The CPUC noted that in California:47
…a majority of transmission projects have received no review and approval by the CAISO or the Commission, and in years 2019-2021, these Utility Self-Approved (“self-approved”) Projects represented over 63% (i.e., $4.2 billion) of the $6.6 billion of capital additions added to the three TOs’ transmission rate bases.
46 CAISO, “20-Year Transmission Outlook,” May 2022, https://www.caiso.com/InitiativeDocuments/20- YearTransmissionOutlook-May2022.pdf.
47 CPUC, “Resolution Establishing the Transmission Project Review Process,” Final Resolution E-5252, May 2, 2023, https://webprod103.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/transmission-project-review-process. 88 Improving T ransmission F inanc ing in Cal ifornia
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 28 Outside California the same issue has been raised through a FERC complaint by the Ohio Consumers’ Counsel.48 The underlying problem is that FERC jurisdictional utilities may replace transmission assets as part of on-going business, and this may only “incidentally” increase transmission capacity.
While these replacement activities that incidentally increase transmission capacity are costly, their regulatory treatment is an area of active litigation. Furthermore, the transmission maintenance and upgrades are a core IOU activity. Transferring those assets and investments to a public or nonprofit entity would face high legal hurdles. We will not include these projects in our cost analysis.
CAISO 2022-2023 TRANSMISSION PLAN PROJECTS
The CAISO proposes transmission projects for grid expansion. These are—in theory—eligible to participate in the competitive tender. Any type of entity, including the PPPs proposed here, may participate in the tender.
The CAISO has a tariff-required annual transmission planning process that examines transmission needs over the next ten years. The CAISO 2022-2023 Transmission Plan identified $7.3 Billion of projects. Of these projects the majority were improvements to existing infrastructure such as upgrading transformers from 230 kV to 500 kV, or reconductoring existing lines to allow for a higher thermal limit.
Three projects identified in the 2022-2023 Transmission Plan were eligible for competitive procurement.
They amounted to an estimated $3.1 Billion or approximately 43% of the $7.3 Billion total.
The 2022-2023 Transmission Plan included expanded electrification as part of the base case and this partially led to the $1.3 Billion of “Reliability-Driven” projects associated with the higher load.
The distinction of what is and is not eligible to be part of a competitive tender determines the size of the savings that can be achieved. The 2022-2023 Transmission Plan is essential to reverse engineering the criteria used by the CAISO in determining what should be eligible for a competitive tender, and what not. These criteria will be discussed at more length below in Section 4.2.
The CAISO 2022-2023 Transmission Plan does not fulfill the needs imposed by Senate Bill 100 as the 20- Year Outlook does. It also includes many projects that the CAISO has not identified as eligible for competitive tender. These are “reliability-driven” and reflect increased demand from electrification.
While the CAISO 2022-2023 Transmission Plan does not represent the full set of projects required for Senate Bill 100, it does provide detail that can be used to confirm the criteria the CAISO uses to identify which projects can be submitted to a competitive tender.
PROJECTS IN THE CALIFORNIA ENERGY COMMISSION OFF-SHORE WIND STUDY The CEC was charged by Assembly Bill (AB) 525 (Chiu, Chapter 231, Statutes 2021) to produce a strategic for floating offshore wind energy development in federal waters off the California coast. The resulting report estimated the cost of transmission to support off-shore wind turbines on the north coast of California at $7.51-$41.35 Billon.
48 Ohio Consumers Counsel, “Ohio Consumers’ Counsel Complaint Re Local Transmission Planning Oversight,” FERC Docket No. EL23-105-000 (Office of the Ohio Consumers’ Counsel, September 28, 2023), https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231205-5021&optimized=false. 89 Center For Law, Energy & the Environment
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 29 This report only looked at transmission for off-shore wind and did not examine the cost of meeting Senate Bill 100. However, the supporting analysis provides additional details, such as the length of useful life for transmission assets, that will be used in the cost analysis.
BEST CANDIDATE: CAISO 20-YEAR TRANSMISSION OUTLOOK
The CAISO 20-Year Transmission Outlook provides the best set of proposed transmission projects to evaluate in the cost analysis. However, the CAISO 2022-2023 transmission plan provides details that are useful in determining what criteria determine eligibility for competitive tenders, and the CEC Off-Shore Wind Study provides useful cost modeling details.
4.2 CRITERIA FOR DETERMINING PROJECT ELIGIBILITY
The potential for savings depends on the scope of transmission projects that can use innovative public financing structures. The competitive tenders run by CAISO for new projects provide a straightforward application scenario. These would not require challenging IOU rights or current CAISO practices.
This section will review the regulatory framework supporting—and limiting—competitive tenders.
FERC ORDER 1000
FERC Order 1000 eliminated transmission owners’ right of first refusal, the right to build any required new transmission in their area.49 The existing transmission owners were strongly opposed to the rule and FERC’s final rule included text that limited the scope of the change. Incumbent transmission owners maintain control over their existing infrastructure:50
[Order 1000 reforms] do not affect the right of an incumbent transmission provider to build, own, and recover costs for upgrades to its own transmission facilities, such as in the case of tower change outs or reconductoring, regardless of whether or not an upgrade has been selected in the regional transmission plan for purposes of cost allocation.
Further, Order 1000 did not remove the right of rest refusal from “local” transmission, defined as:51 “..a transmission facility located solely within a public utility transmission provider’s retail distribution service territory or footprint that is not selected in the regional transmission plan for purposes of cost allocation.”
Over time the implementation of FERC Order 1000 has interpreted the competitive solicitation requirement as applying when:
a) The transmission project is an expansion of the grid. b) The project is not part of “local” transmission.
49 FERC, “FERC Order No. 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,” FERC Docket Docket No. RM10-23-000 (FERC, July 21, 2011), https://www.ferc.gov/sites/default/files/2020- 04/OrderNo.1000.pdf.
50 FERC, at 319.
51 FERC, at 63.
90 Improving T ransmission F inanc ing in Cal ifornia
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 30 c) The project is not an upgrade of the transmission owners’ facilities.
APPLICATION OF FERC ORDER 1000 IN CALIFORNIA
As the California Public Advocate noted, the application of the FERC criteria in California depends on an arbitrary definition of local transmission as all equipment below 200 kV. The CAISO tariff defines a Local Transmission Facility as:52
a) Under the CAISO Operational Control,
b) Is owned by a Participating TO [Transmission Owner or equivalent], c) Operates at a voltage below 200 kilovolts, and… is located entirely within a Participating Transmission Owner’s [PTO] footprint or PTO Service Territory.
As the Public Advocate further pointed out other RTOs have more permissive limits (Southwest Power Pool and ISO-NE have limits of 100 kV, NYISO does not use a kV limit).
The second benchmark test is whether a project can be classified as “upgrade” or an “expansion.” An expansion falls under FERC Order 1000 transmission planning and would be subject to competitive procurement, an upgrade does not.
The distinction between “upgrade” and “expansion” does not have a basis in electric power; an increase of 500 MW transfer capacity between two points has the same result however it is categorized. However, if one category is applied the incumbent has an exclusive right, in the other a competitive tender is held.
This second benchmark test is not defined. The next section examines how this has been implemented in practice by the CAISO as part of determining which projects are eligible for competition, and hence innovative financing structures such as PPPs.
ORDER 1000 CRITERIA IMPLICIT IN CAISO DETERMINATION OF COMPETITION ELIGIBILITY IN CAISO 2022-2023 TRANSMISSION PLAN
The CAISO 2022-2023 Transmission Plan approved 46 new transmission projects. Of these only three projects were identified as eligible for competitive procurement, although they were large projects and accounted for 43% of the total cost53. These three (numbers 13, 14, and 16) are circled in red in Figure 4.1. 52 CAISO, “California Independent System Operator Corporation: Fifth Replacement FERC Electric Tariff,” Open Access Transmission Tariff, January 1, 2023, https://www.caiso.com/rules/Pages/Regulatory/eTariff.aspx, Appendix A; California Public Advocates Office, “Competitive Solicitation in Transmission Line Development Lowers Ratepayer Costs and Decreases Delays,” June 9, 2023, https://www.publicadvocates.cpuc.ca.gov/-/media/cal-advocates-website/files/press-room/reports-and-analyses/230609-caladvocates-increasing-competitive-solicitation-in-transmission.pdf. 53 CAISO, “2022-2023 Transmission Plan,” May 18, 2023,
https://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=13E8A7DF-2D59-4BAE-9794-C99CC5945FA5. 91 Center For Law, Energy & the Environment
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 31 Figure 4.1: CAISO 2022-2023 Transmission Plan
Source: Jeff Billinton, “Decision on ISO 2022-2023 Transmission Plan” (ISO Board of Governors Meeting, California ISO, May 18, 2023), http://www.caiso.com/Documents/Decisionon2022-2023TransmisisonPlan-Presentation-May2023.pdf.
The three competitive projects are all in the Imperial Valley region and are all new lines. In contrast, project 15 is classified as a reinforcement although its cost is $1,125 Million.
It appears that only new lines are eligible for competitive procurement. The bright line test appears whether the project requires new land, i.e., is a greenfield project. Simply replacing the conductors and the towers would not constitute a new line. As noted above, FERC specified that tower replacement and reconductoring would be seen as an upgrade to existing facilities owned by the incumbent. Brownfield projects that use existing property and right-of-way, such as adding a third underground cable in project 12 or reconductoring, are not eligible for competitive procurement.
4.3 APPLYING ORDER 1000 CRITERIA TO CAISO 20-YEAR TRANSMISSION
OUTLOOK
Here we extend the greenfield/brownfield test to the CAISO 20-Year Transmission Outlook. The following two projects provide an example of how the test is applied. Both are estimated at a $0.5 B cost. Both are 500 kV lines. However, the competitive project is a new line while the second, the IOU project replaces an existing 230 kV line with a 500 kV line. The replacement uses existing property but requires tower replacement.
92 Improving T ransmission F inanc ing in Cal ifornia
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 32 Table4.1: Sample Classification of Projects
Project Classification Project Description Estimated Cost Competitive
Procurement
North Gila – Imperial
Valley 500 kV line
- 85 mi of 500 kV line.
- Series compensation. $0.5 B
IOU Upgrade Westland 500/230 kV
station
- 50 mi of 500 kV line
(replacement of 230
kV).
- New 500/230 kV
substation with two
transformers ($200M)
$0.5 B
Using this greenfield/brownfield criteria to identify projects eligible for competitive procurement, we find that approximately 83% of the total estimated costs are eligible for competitive procurement (Table 4.2).
Table 4.2: Summary of Projects Eligible for Competitive Procurement Type of Project
20-Year
Outlook Total
($ B)
Competition
Eligible
($ B)
Comments
Changes to Existing
Footprint 10.74 10.4 Excludes upgrades to existing infrastructure Off-Shore Wind 8.11 8.11 Lower total cost than in CEC off-shore wind report54
Out-of-State Wind 11.65 6.95
Excludes subscriber lines already under
construction (Sunzia and Transwest
Express)
Total 30.5 25.46
Percent of Total 100% 83%
There were four projects that were deemed not eligible for competitive procurement. These are shown in Table 4.3.
54 California Energy Commission, “California Energy Commission Draft Commission Report, Volume I: Overview of AB 525 Strategic Plan,” CEC Docket Number 17-MISC-01, January 19, 2024, https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=17-MISC-01. 93 Center For Law, Energy & the Environment
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 33 Table 4.3: Projects Ineligible for Competitive Procurement Project Description
Cost
($ B)
Westland 500/230 kV station
50 mi of 500 kV line (replacement of 230 kV).
New 500/230 kV substation with two
transformers ($200M)
0.5 Third Collinsville – Pittsburg 230 kV cable 230 kV cable 0.14 Round Mountain 500/230 kV
Transformer Add one 500/230 kV transformer 0.1
Lugo 500/230 kV Transformers Add one 500/230 kV transformer 0.1 94 Improving T ransmission F inanc ing in Cal ifornia
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 34 Box 7 Fire Hardening Measures: Costs and Tradeoffs
"Fire-hardening" refers to a series of measures and improvements designed to enhance the resilience of electric transmission and distribution systems against wildfires. The most effective way to reduce wildfire risk is a process known as “undergrounding.” This involves placing power lines and related electrical equipment below the ground, rather than using overhead lines strung on poles or towers. Placing new transmission lines underground is about eight to ten times the cost of building overhead lines; placing new distribution lines underground is typically four to six times more expensive.
Other examples of fire-hardening measures include covering conductors to eliminate line slap arcing, using alternative materials (e.g. composite, steel, concrete, or fire-resistive protection) on or instead of wood poles, and establishing other physical barriers to reduce possible contact with animals or vegetation.
Fire-hardening measures vary in risk-mitigation effectiveness and associated costs per mile when rehabilitating an existing system. Undergrounding reportedly eliminates close to 99 percent of fire risk. Covering conductors, however, may be implemented in half the time, at a third of the cost of undergrounding, and mitigate about 60 percent of fire risks.
There are also tradeoffs to system reliability to consider. Some comparisons suggest underground systems see 50 percent fewer outages, yet the average duration of an underground outage may be up to 58 percent longer.
Long-term reliability is also a trade-off. One Maryland utility observed that customers served by a 40-year-old overhead line had better reliability than a 20-year-old underground line.
Sources:
Baker, Matt. “Why We Support the Levels of Undergrounding Approved in PG&E’s General Rate Case.” California Public Advocates Office. Accessed May 21,
2024. https://www.publicadvocates.cpuc.ca.gov/press-room/commentary/231117-undergrounding-pge-grc SCE&G. "Underground vs. Overhead Power Lines." ND. https://pdi2.org/wp-content/uploads/2021/03/130- SC-SCANA-Undergroundvs1.pdf
Apparatus & Standards Engineering Group. "Covered Conductor - Everything You Need To Know (Compendium)." Southern California Edison. October 8, 2018. https://www.sce.com/sites/default/files/AEM/Supporting%20Documents/2023- 2025/Covered%20Conductor%20Compendium.pdf
California Department of Forestry & Fire Protection, CPUC, PG&E, SCE, SDGE., "California Power Line Fire Prevention Field Guide." 2020. https://www.osfm.fire.ca.gov/media/11015/2020-power-line-fire-prevention-field-guide_20200818.pdf
4.4 FURTHER OBSERVATIONS ON COMPETITION ELIGIBILITY
The projects listed in the CAISO 20-Year Transmission Outlook do not include projects to address electrification demand increases or what CAISO identifies as “reliability-driven” projects rather than driven by the need to access renewable generation. These projects are not competition eligible and amounted to approximately 57% of the total cost. This suggests both that the 20-Year Transmission Outlook represents less than half of the total energy transition cost and that the IOUs will capture 50%-60% of the total new transmission construction.
95 Center For Law, Energy & the Environment
IDENTIFYING TRANSMISSION PROJECTS FOR PUBLIC FINANCING STUDY PAGE 35 The implicit greenfield requirement for competitive procurement is a significant barrier to entry for non-incumbent transmission providers. This is especially true in urban areas where permitting and siting is especially difficult.
Workarounds for this issue are beyond the scope of this report. However, it is worth noting that sharing of the right-of-way between incumbents and non-incumbents may be a worthwhile area for investigation. FERC noted in Order 1000 that the order does not change existing right-of-way laws.55 55 FERC, “FERC Order No. 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities”, at 319.
96 Improving T ransmission F inanc ing in Cal ifornia
REVENUE REQUIREMENT MODEL PAGE 36
SECTION 5 REVENUE REQUIREMENT MODEL
Section 3 identified possible cost savings to customers from the use of public sector financing in transmission, and the use of alternative institutional models (from Section 2) to deliver such financing. Section 4 identified the lines that could conceivably be eligible for competitive tender and hence alternative modes of procurement and financing. This section attempts to quantify the possible cost savings—as a change in revenue requirement—on the lines in Table 4.2 that are competition-eligible.56
5.1 ASSUMPTIONS
Sensitivity analysis was first used to understand the possible impact on the transmission lines’ revenue requirements of changes to the magnitudes of the building blocks shown in Table 5.1. Scenario analysis was then used to simulate a collection of sensitivities that seemed reasonable under alternative institutional models. The “business-as-usual” or base case is an IOU. In this scenario, IOUs are assumed to win CAISO competitive tenders to own and operate the lines. Table 5.1 shows the input assumptions used for the IOU Scenario. We used CAISO’s assumptions that the new investments have a 50-year asset life; upgrades have 40-year lives.57
Table 5.1: Input Assumptions for IOU Scenario (Business-As-Usual) Assumption Assumptions Value
Cost of equity (%) Average of PG&E, SCE, SDG&E
cost of equity*
10.37 Cost of debt (%) Average of PG&E, SCE, SDG&E
cost of debt*
5.33 Equity participation (%) Average of PG&E, SCE, SDG&E capital structures*
53.27 Tax rate (%) Federal = 21%; State = 8.84% 27.98
CAPEX Cost (US$ bln) As per Table 4.2 (above) 25.46
Depreciation (US$ mln/year)58 2%/year for new assets;
2.5%/year for upgrades
513.97
Operating Cost (US$ mln/year)59 2% of CAPEX per year 512.80 *Assumptions about cost of equity, cost of debt and capital structure were taken from: (i) Pacific Gas and Electric Company, 2022 Joint Annual Report to Shareholders; (ii) Edison International and Southern California Edison, 2022 Financial & Statistical Report; (iii) Sempra, 2022 Statistical Report, (iv) San Diego Gas and Electric, "Test Year 2023 Cost of Capital Application", California docket A.22-04-12.
Other scenarios were then developed based to include:
56 Lines not tendered by CAISO may be subject to different regulatory treatment and therefore may have different cost savings potential.
57 California ISO, 2018-2019 Transmission Plan.
58 California ISO, 2018-2019 Transmission Plan.
59 California ISO, 2018-2019 Transmission Plan.
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REVENUE REQUIREMENT MODEL PAGE 37
• A “Public Sector” scenario in which a public entity—such as the power authorities or transmission authorities found in some other states—owns and operates the transmission lines • Two PPP scenarios which include:
o A lease-type PPP case for this analysis assumes a public sector owner (such as an asset holding company) would—through competitive tender—hire a private contractor to operate and maintain the transmission lines for a period of time (for example, 3-5 years). The public sector entity provides financing and is generally responsible for managing design and construction.
o A concession-type PPP in which a public sector entity would—through competitive tender— grant a private company (and SPE or SPV) the right to build, finance, own and operate the new transmission lines for a fixed period of time (for example, 40 years) after which time, the line would revert to the public sector.60
Table 5.2 summarizes the assumptions of each Scenario.
Table 5.2: Summary of Scenario Assumptions
Variable IOU Scenario Wholly Public
Scenario
PPP-Lease
Scenario
PPP-Concession
Scenario
Cost of equity (%) 10.37 N/A N/A 10.37
Cost of debt (%) 5.33 2.75 4.04 5.33
Equity (%) 53.27 0 0 53.27
Tax rate (%) 27.98 0 0 27.98
CAPEX Cost (US$
bln) 25.64 22.43 19.23 19.23
Operating cost (%
of CAPEX) 2 2.1 2 2
The rationale behind the assumptions is as follows:
• A publicly owned entity would finance the transmission lines with 100% public debt. This is why no cost of equity is included in the Public Scenario or the Lease-type PPP Scenario, where the owners of the assets would be public entities (either a power authority or an asset holding company). 60 The public sector entity may then choose to re-tender the line for refurbishment. 98 Improving T ransmission F inanc ing in Cal ifornia
REVENUE REQUIREMENT MODEL PAGE 38
• A publicly owned entity (whether a power authority or an asset holding company) would be able to borrow at rates that the State of California is currently able to borrow at (in the case of a power authority) or at slightly higher rates (as in the case of an asset holding company, but still lower than commercial borrowing rates.
• A publicly owned entity (whether a power authority or an asset holding company) would not pay income taxes and would therefore not have taxes as part of its revenue requirement. • Transmission lines tendered under the Public Scenario or PPP Scenarios would have lower CAPEX costs than transmission lines tendered by CAISO to the IOUs. This is based on:
o The Brattle Group report that indicates more competitive processes in procuring transmission in the US could reduce capital costs by 20-30 percent. 61 o Evidence from elsewhere in the world that successive competitive tenders for transmission lines under a PPP arrangement can bring down whole-of-life costs substantially, especially under a concession model, because of competitive bidding and because of more efficient risk allocation between the public and private partners. • An assumption that publicly owned and operated transmission lines would have slightly higher operating costs than privately owned and/or operated lines, because of the absence of a private sector profit incentive and because PPP arrangements typically have lower whole-of-life costs than transmission built by incumbent utilities.
As described in Section 3 many of the input assumptions depend heavily on the detailed design of the institutional options.
5.2 SENSITIVITIES
Figure 5.1 shows the impact of a 10% reduction in the principal inputs to the revenue requirement calculation.
This is useful in understanding the biggest drivers of cost in the revenue requirement. As the figures show, the capital cost itself, which makes up the rate base, is the single most influential driver of the RR, followed by taxes, the cost of equity, capital structure and the cost of debt; the impacts on the RR of reductions in OPEX and depreciation are considerably lower.
61 Pfeifenberger, Johannes P., Judy Chang, Akarsh Sheilendranath, J. Michael Hagerty, Simon Levin, and Wren Jiang. “Report by Brattle Economists Discusses the Benefits of Competitive Transmission.” Prepared for LSP Transmission Holdings, Brattle, June 21, 2021. https://www.brattle.com/insights-events/publications/report-by-brattle-economists-discusses-the-benefits-of-competitive-transmission/. 99 Center For Law, Energy & the Environment
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Figure 5.1: Impact on RR of a 10% Reduction in Principal Input Variables62
5.3 SCENARIOS
Figure 5.2 shows the revenue requirement under the IOU Scenario defined in Section 5.1. The package of transmission lines would have an average annual revenue requirement of roughly $2.5 billion, or $100 billion over 40 years. If the costs of undergrounding are included (See Box 7), the average annual revenue requirement would be nearly $21 billion, or $825 billion over 40 years. 63 62 Based on an estimate of the transmission line’s first full-year revenue requirement. 63 Undergrounding is estimated to increase the capital costs of transmission projects by 8-10 times. 100 Improving T ransmission F inanc ing in Cal ifornia
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Figure 5.2: Revenue Requirement for Eligible Transmission Lines—Business-as-Usual (BAU) Case64 As the figure shows, the return on rate base is the largest cost component under this scenario. It is based on an average of costs of debt, equity, and capital structures of Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDGE), and SCE. The next largest component is income taxes, followed by depreciation and OPEX.
Figure 5.3 compares the IOU Scenario to the other scenarios described in Section 5.1. Sections 5.3.1 through
5.3.2 describe the most important differences between the scenarios, and their results.
Figure 5.3: Comparison of Scenarios—Average Annual Revenue Requirement 64 Taken as the average over 40 years. Revenue requirements change over time as the rate base is depreciated and the nominal return on the rate base is also reduced. The average assumes, for the simplicity of comparison, that all lines are built at the same time.
101 Center For Law, Energy & the Environment
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5.3.1 PUBLIC SECTOR SCENARIO
The public sector case for this analysis assumes a public entity (for example, a power authority) would own and operate the new transmission lines. The transmission lines would have an average annual revenue requirement of roughly $1.2 billion over 40 years, less than half of the average annual revenue requirement under the wholly public case. Table 5.3 shows the average annual revenue requirement for all lines, disaggregated by cost component, as well as the input assumptions used.
Table 5.3: Comparison of Input Assumptions and RR Components (Public Sector Scenario) Variable Average value in Revenue
Requirement (US$ million) Assumption
Return on Rate Base 269.49
100% public debt
financing; public sector
financing costs
Income Taxes 0 N/A
Depreciation 449.72 2%/year for new assets;
2.5%/year for upgrades
OPEX 471.4 2% of CAPEX per year
As the table shows, OPEX is the largest cost component under this scenario, followed by depreciation, the return on rate base, and taxes. The biggest differences between this Scenario and the IOU Scenario are:
• Rate base. It is assumed that CAPEX costs would be 12.5% lower than under the IOU Scenario, based on the assumption that there are more opportunities to introduce competition in procurement under the PPP models than under the Public Sector Scenario.65 • Return on rate base. The return on rate base is lower because the rate base is lower and it is assumed that the public entity would use 100% debt financing (no equity) at the cost of public sector debt. • Taxes. It is assumed that a public sector entity would not be required to pay state or federal income tax.
• Operating Costs. It is assumed that the public sector entity would have slightly higher OPEX costs than a private sector entity. We have assumed OPEX costs of 2.1% of CAPEX instead of (in the IOU case) 2%. PPP arrangements have the benefit of specifying risk allocations upfront, in a contract. This optimization of risk allocation is one of the most important sources of potential cost savings in a lease-or concession-type contract. Moreover, an SPV or SPE is at the heart of a PPP arrangement; this further protects the public owner from liability beyond the project itself. • Depreciation. Depreciation is lower because the value of the rate base is lower.
These differences collectively put the Public Sector Scenario at less than half of the cost of the IOU Scenario. 65 The basis for these assumptions will be detailed in the forthcoming report which includes this memo as a chapter. 102 Improving T ransmission F inanc ing in Cal ifornia
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5.3.2 CONCESSION-TYPE PPP
The concession-type PPP case for this analysis assumes a public sector entity would—through competitive tender—grant a private company the right to own and operate the new transmission lines for a fixed period of time (e.g., 40 years) after which time, the lines would revert to the public sector. The transmission lines would have an average revenue requirement of roughly $1.9 billion over 40 years. Table 5.4 shows the average revenue requirement for all lines, disaggregated by cost component, as well as the input assumptions used.
Table 5.4: Comparison of Input Assumptions and RR Components (Concession-Type PPP Scenario) Variable Average value in Revenue
Requirement (US$ million) Assumption
Return on Rate Base 710.33
Same financing structure
and costs as IOU case but
with 25% reduced CAPEX
Income Taxes 451.43 Same as for IOU Case
Depreciation 385.48 Same as for IOU Case
OPEX 384.60 Same as for IOU Case
As the table shows, return on rate base is the largest cost components under this scenario, followed by the taxes, OPEX and depreciation. The differences between this Scenario and the IOU Scenario are:
• Rate base. It is assumed that CAPEX costs would be 25% lower than under the IOU Scenario because of the benefits of greater competition in procurement per the Brattle study.66 • Return on rate base. The return on rate base is lower because the rate base is lower and it is assumed that the public entity would use 100% debt financing. The costs of debt and equity financing, and capital structure are assumed to be the same as in the IOU case as both commercial debt and equity would be needed by the developer.
• Depreciation. Depreciation is lower because the value of the rate base is lower.
5.3.3 LEASE-TYPE PPP
The lease-type PPP case for this analysis assumes a public entity would own and operate the new transmission lines and hire a private company to operate and maintain the lines. The transmission lines would have an average revenue requirement of $1.1 billion over 40 years. Table 5.5 shows the annual average revenue requirement for all lines, disaggregated by cost component, as well as the input assumptions used. 66 Brattle, 2021
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Table 5.5: Comparison of Input Assumptions and RR Components (Lease-Type PPP Scenario) Variable Average value in Revenue
Requirement (US$ million) Assumption
Return on Rate Base 339.28
100% public debt
financing; public sector
financing costs
Income Taxes 0 N/A
Depreciation 385.48 2%/year for new assets;
2.5%/year for upgrades
OPEX 384.60 2% of CAPEX per year
As the table shows, OPEX and depreciation are the largest cost components under this scenario, followed by the return on rate base, and taxes. As noted in Section 5.3.1, OPEX with a PPP arrangement is assumed to be lower than a wholly public arrangement because PPP arrangements have the benefit of specifying risk allocations upfront, optimizing risk allocation in a way that reduces costs, and protecting the public owner from liability by virtue of the establishment of an SPV.
The differences between this Scenario and the IOU Scenario are:
• Rate base. It is assumed that CAPEX costs would be 25% lower than under the IOU Scenario because of the benefits of greater competition in procurement per the Brattle study.67 • Return on rate base. The return on rate base is lower because the rate base is lower and it is assumed that the public entity would use 100% debt financing (no equity) and at the cost of public sector debt. • Taxes. It is assumed that a public sector holding company would not be required to pay state or federal income tax.
• Depreciation. Depreciation is lower because the value of the rate base is lower.
5.4 CONCLUSION
The estimates above show that substantial possible savings to customers are achievable by using public sector financing for transmission projects. A wholly public delivery model or a lease-type PPP—both of which assume 100% financing with tax free bonds—could cut the annual revenue requirements of transmission lines by more than half. The average annual savings to customers could be as much as nearly $1.5 billion, or a total of $58 billion over a 40-year operation of the transmission lines.68 Much of the potential savings are directly related to the removal of equity from the financing structure and the use of lower cost public debt. Other potential savings relate to the institutional model chosen and their potential impact on competition for developing transmission lines; competition which—according to other studies—can reduce capital costs over time. The choice of institutional model also has tax implications: a 67 Brattle, 2021.
68 Estimates are not discounted for the time value of money and exclude the costs of fire hardening. 104 Improving T ransmission F inanc ing in Cal ifornia
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publicly owned transmission line may be liable for less income (and possibly other) taxes than a privately owned line.
Whereas this section uses estimates of the revenue requirement for all lines foreseen to be eligible for competition under the CAISO plan, it is important to note that the opportunities for cost savings depend very little on which transmission line is chosen for analysis. The potential percentage savings would be similar for any line tendered by CAISO. For example, more recent and more detailed CAPEX cost estimates have been developed for a package of transmission investments foreseen to evacuate offshore wind from the North Coast.69 The $7.7 billion line (referred to as “Alternative 7.2a”) is planned to accommodate 7.2 GW of offshore wind development; this will include 480 wind turbines with 9 HVAC floating platforms. The transmission investments will include (i) radial connections via 500kV AC export cables between the proposed offshore wind farms and nearby onshore substations, and (ii) A connection to the planned Fern Road substation in Central Valley, connecting to the main 500 kV transmission line running along the I-5 corridor. Under the IOU scenario, this line would have an annual average revenue requirement of $774 million over 40 years; the same investments would have an annual average revenue requirement of $358 million under the wholly public scenario.
69 Zoellick, J., G. Adams, A. Mustafa, Aubryn Cooperman, R. Anilkumar, Patrick Duffy, A. Sparks, et al. “Northern California and Southern Oregon Offshore Wind Transmission Study.” Schatz Energy Research Center, October 1, 2023. https://doi.org/10.2172/2205318.
105 Center For Law, Energy & the Environment
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APPENDIX A: THE CONTEXT FOR TRANSMISSION
DEVELOPMENT IN CALIFORNIA
In general terms, transmission projects are considered as low risk assets due to their predictable performance, “easy” operation and simplicity in their rate of return mechanism,70 despite conveying intrinsic complications or barriers resulting from their capital-intensive nature, with long payback periods, potential public opposition71 and their difficulty in assigning costs (public goods dilemma).
While development cost reduction and permitting reform are not the primary focus of this report, we review some key points here.
REGULATORY COMPLEXITY
The regulation of high voltage transmission in the United States is highly intricate due to several jurisdictions’ overlaps between federal, state, district, and territorial authorities.72 FERC oversees stand-alone transmission services, rates, and infrastructure, including regional wholesale power markets that utilize the transmission grid (“interstate commerce”) (excluding certain publicly owned utilities, federal power marketing agencies, and unsynchronized single-state power grids).73 In contrast, state and local authorities are in charge of generation and distribution (infrastructure and operation), including retail electricity services, and usually oversee transmission lines’ siting, permitting, construction, and retail costs within their jurisdictions (intrastate).
All market participants shall have non-discriminatory/open access to the transmission system,74 through Independent System Operators (“ISOs”) and Regional Transmission Operators (“RTOs”),75 allowing competitive interstate trading and ensuring grid reliability.
PERMITTING DELAYS FOR TRANSMISSION ON FEDERAL LAND
At a federal level, energy transition efforts and the impacts of climate change have brought to light, more than ever, the permitting delays in energy projects and grid infrastructure76 which have resulted in several 70 Crédit Agricole Securities, “Project Bond Focus Power Transmission Lines,” May 2019, https://www.ca-cib.com/sites/default/files/2020-03/Project-Bond-Focus-2019-Transmission-Lines.pdf. 71 “Trouble at the End of the Line: Local Activism and Social Acceptance in Low-Carbon Electricity Transmission in Lower Franconia, Germany - ScienceDirect,” accessed March 20, 2024, https://www.sciencedirect.com/science/article/abs/pii/S2214629618301233?via%3Dihub. 72 Joe III DeLosa, Johannes P. Pfeifenberger, and Paul Joskow, “Regulation of Access, Pricing, and Planning of High Voltage Transmission in the U.S.,” Working Paper Series, March 5, 2024, https://ceepr.mit.edu/workingpaper/regulation-of-access-pricing-and-planning-of-high-voltage-transmission-in-the-u-s/. 73 “What FERC Does | Federal Energy Regulatory Commission,” accessed March 18, 2024, https://www.ferc.gov/what-ferc-does. 74 “Order No. 888 | Federal Energy Regulatory Commission,” accessed March 18, 2024, https://www.ferc.gov/industries-data/electric/industry-activities/open-access-transmission-tariff-oatt-reform/history-oatt-reform/order-no-888. 75 “OrderNo.2000-A | Federal Energy Regulatory Commission,” accessed March 18, 2024, https://www.ferc.gov/sites/default/files/2020-06/OrderNo.2000-A.pdf. 76 “Congressional Action on Energy Permitting Remains Stuck, but States, Developers Are Finding Solutions,” Utility Dive, accessed March 21, 2024, https://www.utilitydive.com/news/federal-energy-permitting-reform-doe-ferc-congress/705818/. 106 Improving T ransmission F inanc ing in Cal ifornia
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energy permitting reform bills in Congress77 and further analysis of potential reforms to the “federal permitting process for clean energy infrastructure.”78 A study by the Brookings Institute79 reveals that reviews under the National Environmental Policy Act (NEPA) and permitting processes from the Bureau of Land Management (BLM) represent the most significant bottlenecks in permitting delays, particularly for transmission lines and wind projects.80 The figure below highlights the duration of each permitting phase for 13 projects analyzed (red dots). The preparation of Environmental Impact Statements under NEPA is identified as one of the lengthiest steps in federal permitting, taking a median of 3.5 years, and up to nine years in some instances. However, the process of obtaining right-of-way (ROW) authorization from BLM is even more protracted, with a median duration of over nine years from application submission to BLM approval, largely because it encompasses an NEPA review. This lengthy duration is partly due to the additional layers of review and bureaucratic processes involved.
Source: From Sud, Rayan, Sanjay Patnaik, and Robert Glicksman. “How to Reform Federal Permitting to Accelerate Clean Energy Infrastructure.” Brookings Institute, February 2023.
Another example of significant delays is illustrated by New York’s Champlain Hudson Power Express Project.
This $6 billion 1,250 Megawatts (MW) renewable power transmission initiative, which began its permitting 77 “Permitting Reform Bills in Congress,” Citizens’ Climate Lobby, accessed March 21, 2024, https://citizensclimatelobby.org/clean-energy-permitting-reform-in-congress/. 78 Rayan Sud, Sanjay Patnaik, and Robert Glicksman, “How to Reform Federal Permitting to Accelerate Clean Energy Infrastructure” (Brookings Institute, February 2023), https://www.brookings.edu/wp-content/uploads/2023/02/20230213_CRM_Patnaik_Permitting_FINAL.pdf. 79 Sud, Patnaik, and Glicksman.
80 This insight comes from examining a non-representative sample of 13 large and nationally significant projects listed on the Federal Permitting Dashboard, focusing on completed renewable energy and electric transmission projects. 107 Center For Law, Energy & the Environment
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phase in 2010, only received its final permits to commence construction in 2022 and is anticipated to be fully functional by the spring of 2026.81
DELAYS IN THE TRANSMISSION DEVELOPMENT PROCESS IN CALIFORNIA In California, the process of developing transmission projects is intricate and long-lasting, involving continuous coordination among the California Independent System Operator (CAISO), the CPUC, and utilities for the planning, permitting, and construction phases, which usually result in considerable delays82,83,84 that tend to increase the costs of projects.
Slow transmission deployment in California is largely due to delays in CAISO’s projects’ approval and subsequent permit application submissions by IOUs to the CPUC (compounded by lengthy permitting processes). California's transmission permitting process is notably slower than those in New York or Texas, and even other Western states.85 A study conducted by Southern California Edison concluded that CPUC’s average review and approval time across 28 applications was 836 days (about 2.3 years) and for some applications over 1,000 days (about 2.7 years).86 The figure below87 shows the considerable delays for a sample of transmission projects in California. Delays within transmission permitting in California are well documented and increasingly high profile. There have been recent efforts within the state to reform the transmission permitting process to reach policy and climate goals.88 81 Champlain Hudson Power Express Project, “Champlain Hudson Power Express Project: Regulatory Documents,” TDI CHPExpress, accessed March 18, 2024, https://chpexpress.com/overview-of-public-documents/regulatory-documents/. 82 “Transmission Development in California – What’s the Slowdown?,” Clean Air Task Force, accessed March 20, 2024, https://www.catf.us/resource/transmission-development-california-slowdown/. 83 Alex Breckel et al., “Growing the Grid: A Plan to Accelerate California’s Clean Energy Transition” (Clean Air Task Force and Environmental Defense Fund, October 2022), https://www.catf.us/resource/growing-grid-plan-accelerate-californias-clean-energy-transition/. 84 GridLab and CEERT, “California’s Progress in Advancing Transmission Planning and Permitting: A 2023 Review,” 2023, https://ceert.org/wp-content/uploads/2023/pdf/231207_CA-progress-in-advancing-transmission-planning-permitting.pdf. 85 Kara Hunt, “California’s Transmission Permitting: Slowest in the West?,” Clean Air Task Force, May 30, 2023, https://www.catf.us/2023/05/californias-transmission-permitting-slowest-in-the-west/. 86 GridLab and CEERT, “California’s Progress in Advancing Transmission Planning and Permitting: A 2023 Review.” 87 Breckel et al., “Growing the Grid.”
88 GridLab and CEERT, “California’s Progress in Advancing Transmission Planning and Permitting: A 2023 Review.” 108 Improving T ransmission F inanc ing in Cal ifornia
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Figure 5.4: Timelines for Mayor Electricity Transmission Projects in California Source: Breckel, Alex, Michael Covin, John Herter, Armond Cohen, and Julia Souder. “Growing the Grid: A Plan to Accelerate California’s Clean Energy Transition.” Clean Air Task Force and Environmental Defense Fund, October 2022.
These delay barriers are found before and during the permitting process stage in California. The delays and risk of rejection during the development phase make transmission development a high-risk business.
While permitting and siting risks are not the focus of this study, we note that the risk and delays significantly increase the cost of transmission. The costs include expenses for financing arrangements (working capital, at a minimum), permitting, and regulatory compliance. For example, the Northern Pass project in New Hampshire incurred $318 million in sunk costs for pre-development activities, representing roughly 20% of its estimated total cost of $1.6 billion.89 Similarly, the Hydro-Québec US transmission line project in Maine saw $450 million (43% of the estimated total project costs) spent in pre-development.90 If there is a 50% probability of failure and a 20% cost for failure, then every developer has to build in a minimum 10% risk adder to the CAPEX.
89 Michael Cousineau, “Eversource giving away land bought for failed Northern Pass project,” New Hampshire Union Leader, June 26, 2023, https://news.yahoo.com/eversource-giving-away-land-bought-225400675.html 90 “Hydro-Quebec scores legal victory in Maine over $1B US transmission line project,” CBC News, April 20, 2023, https://www.cbc.ca/news/canada/montreal/hydro-quebec-1.6816752 109 Center For Law, Energy & the Environment
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TRANSMISSION PLANNING AND TENDERING PARAMETERS
FERC’s Order 100091 required that transmission planning cover reliability, economic and public policy needs.
It introduced proactive involvement from transmission providers in crafting regional plans, encouraging stakeholder engagement and choosing the most cost-effective solutions for meeting regional transmission requirements, demanding that transmission plans consider both state and federal public policy objectives.
Additionally, it stipulated that the expenses for these projects be distributed among transmission customers across the planning region and allowed competitive transmission developers to propose bids for transmission expansions with regional cost allocation, challenging incumbent owners.92 In this sense, competitive bidding is encouraged for transmission projects but is limited to regional transmission facilities. Specifically, in California, any regional transmission facility that is 200 kV or higher and identified for reliability, policy, or economic reasons must go through competitive solicitation within the CAISO region. Projects under 200 kV that cross more than two transmission service areas or exceed CAISO's jurisdiction are also eligible for competitive bidding. However, upgrades to existing facilities, whether they meet or fall outside these criteria, and projects that are locally funded, do not require solicitation.93 91 FERC, “FERC Order No. 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.”
92 DeLosa, Pfeifenberger, and Joskow, “Regulation of Access, Pricing, and Planning of High Voltage Transmission in the U.S.” 93 “Transmission Development in California – What’s the Slowdown?” 110 Improving T ransmission F inanc ing in Cal ifornia
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APPENDIX B: EXAMPLES OF CALIFORNIA TRANSMISSION PPPS
Path 15 Project
The Path 15 Project is an upgrade of an existing transmission path. It started operations in 2004 (18 months after the beginning of construction), upgrading an existing line and adding an extra 500 kV line over approximately 84 miles, which significantly increased the corridor's capacity (5,400 MW).94 Path 15 is an electricity transmission corridor in California, linking the northern and southern parts of the state's power grid (Los Banos and Gates), and part of the Western Electricity Coordinating Council's (WECC) network of transmission paths. The upgrade project was initiated after the California Energy Crisis of 2000- 2001 in which Path 15 was identified as a contributing factor to blackouts, reliability issues, and high market prices.
Economic incentives were approved for the development of this Project (that were later contested),95 that included higher rates of return and accelerated depreciation that would allow better cashflow provision.96 The Western Area Power Authority (WAPA) is the public partner and owns the physical transmission line and the associated land, it was also assigned as the project manager and had the role of the lead Federal Agency for the NEPA process, and was also in charge of procuring the required land rights (at an estimated cost of 10% of the project's budget), in exchange of a 10% interest in the rights to the Project. PG&E oversaw construction/refurbishment of substations of existing transmission lines, in exchange for an interest payment and retained ownership of the substations. The primary entity investor was Trans-Elect with ownership of 72% of the transmission system rights entitled to the transmission tariff revenues (today owned by Duke-American Transmission Co. – DATC). PG&E received 18% and WAPA 10%.97, 98,99 The new line of Path 15 was subject to a competitive tender (managed by WAPA), structured as a design-build project, with a sole contractor in charge of engineering, procurement, and construction (EPC).100 The project manager at WAPA claims that this mechanism derived in overall cost reductions of the Project and an 94 Anne Warren, “Transmission Infrastructure By Public-Private Model - Law360,” November 6, 2009, https://www.law360.com/articles/130713/transmission-infrastructure-by-public-private-model. 95 “Public Utilities Commission of the State of California, Petitioner v. Federal Energy Regulatory Commission, Respondent Trans-Elect, Inc., et al., Intervenors, 367 F.3d 925 (D.C. Cir. 2004),” Justia Law, January 31, 2024, https://law.justia.com/cases/federal/appellate-courts/F3/367/925/495858/. 96 WAPA, Transelect, and PGE, “Letter Agreement Filing,” FERC Docket No. ER02-11672-000, April 30, 2002, https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20020507-0016&optimized=false. 97 WAPA, Transelect, and PGE.
98 WAPA and PGE, “Construction And Coordination Agreement,” December 30, 2002, https://web.archive.org/web/20130324172556/http://www.wapa.gov/sn/ops/transmission/path15/ConstructionAndCoord inationAgreement.pdf.
99 Duke Energy, “DATC to Purchase Interest in California’s Path 15 Transmission Line,” Duke Energy | News Center, 2013, https://news.duke-energy.com/releases/datc-to-purchase-interest-in-california-s-path-15-transmission-line. 100 “20 Years of Path 15 T-Line – Western Area Power Administration,” October 8, 2023, https://www.wapa.gov/20-years-of-path-15-t-line/. 111 Center For Law, Energy & the Environment
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accelerated mise-en-service (18 months) than originally anticipated, and that the Project resulted in reduced congestion costs.101
Initial funding for this Path 15 upgrade Project was estimated at $306 million USD and it was partly funded by the federal government, but its final cost was approximately $50 million USD below the initial project estimate.102
The total financing for the Project (facilitated by four banks: Citigroup, Macquarie, DZ Bank, and Société Générale) reached $220 million USD by September 2003, comprising four key components:
1. Around $95.5 million in takedown bonds to the Trans-Elect NTD Path 15 operating company,
2. $56 million in bonds to the Trans-Elect NTD Holdings Path 15 holding company,
3. a $19.5 million construction overrun facility, and
4. a $38.3 million equity bridge facility provided by Energy Investors Funds Group, ArcLight Energy Partners Fund, and KB Transmission.103
In this Project, rates set by Trans-Elect and PG&E are regulated by FERC. The Transmission Revenue Requirement (TRR) was originally estimated by Trans-Elect at around $50 million per year.104 Under this model, and with CAISO in charge of the operation of the line, FERC authorized revenues based on the cost of service model, granting Trans-Elect a 13.5% ROE, a 50%/50% debt/equity target capital structure, and a fixed revenue requirement (TRR) and a rate moratorium for 36 months following the effective date of the rates (start of operations). FERC approved that PG&E could obtain full recovery of its costs derived from the Project and granted a 200 basis point increase in ROE, allowing accelerated depreciation for facilities constructed (10 years of useful life).105
This rate structure and its incentives were contested by the CPUC. Ultimately, the petition for judicial review was denied, with the Court of Appeal recognizing FERC’s authority to approve rate incentives for projects like Path 15 that seek to enhance energy supply and address significant transmission bottlenecks. It also concurred with FERC's rationale, emphasizing the need for incentives to stimulate project development and increase energy availability, despite CPUC's objections to the costs and methodology of the incentives.106 In 2021 a reduction to 10.6% ROE for the new owner Duke-American Transmission Company (DATC) was 101 “Path 15: A to Z,” Electric Energy Online, accessed March 24, 2024, https://electricenergyonline.com/energy/magazine/206/article/path-15-a-to-z.htm. 102 “Path 15.”
103 Warren, “Transmission Infrastructure By Public-Private Model - Law360.” 104 Trans-Elect, “Trans-Elect NTD Path 15, LLC Application For Participating Transmission Owner Status,” March 3, 2003, https://www.caiso.com/Documents/RevisedTrans-ElectNTDPath15_LLCPTOApplication.pdf. 105 WAPA, Transelect, and PGE, “Letter Agreement Filing.” 106 “Public Utilities Commission of the State of California, Petitioner v. Federal Energy Regulatory Commission, Respondenttrans-Elect, Inc., et al., Intervenors, 367 F.3d 925 (D.C. Cir. 2004).” 112 Improving T ransmission F inanc ing in Cal ifornia
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ordered by FERC.107, 108 Furthermore, following these FERC’s orders, in February 2023 the CAISO updated the wheeling access charge rates for DATC.109
Trans Bay Cable
The Trans Bay Cable (TBC) Project is a high voltage transmission line with a 400 megawatts (MW) capacity (able to provide over 40% of power to San Francisco), running 53 miles from Pittsburg, California, in the East Bay to San Francisco, with a significant portion submerged underwater across the San Francisco Bay, which reduced risks from landing acquisition rights and wildfires. The project, considered as a critical transmission asset, was completed and operational in November 2010.
The TBC project is a PPP that covered development, financing, construction, and operation, between the city of Pittsburg, the Pittsburg Power Company, and Steel River Infrastructure Partners (who acquired Babcock & Brown, the original constructor of the project).110 It included a $515 million financing package, that closed in August 2007.111 Its transmission tariff is set by the FERC and revenues are paid by the CAISO.
The Pittsburg Power Company owns the transmission line and equipment, while Trans Bay Cable LLC acquired the transmission system rights for 99 years (before needing to revert them to the City of Pittsburg), with operational control by the CAISO. In 2019, NextEra Energy Transmission acquired TBC from Steel River Infrastructure Partners for about $1 billion.112
Following the same incentives model initially approved by FERC in the Path 15 Project, TBC proposed a
13.5% ROE, with a three-year rate moratorium, a 50/50 debt/equity capital structure, and a 30-year depreciation period for the project.113 A TRR of around $134 million was approved, of which 99.9% corresponds to the Base TRR and the rest to the Transmission Revenue Balancing Account Adjustment. In 2019 TBC requested an increase of its TRR to over $157 million and to maintain the enhanced 13.5% ROE, which was contested by the CAISO and other parties. FERC stated that TBC’s “rates may yield substantially excessive revenues.” FERC ordered a hearing and settlement judge procedures for a full evaluation of TBC’s proposed ROE and overall TRR for final determination.114 A settlement was reached in 2020 increasing TBC’s 107 “Analysis of FERC’s Notice of Proposed Rulemaking on Electric Transmission Incentives.” 108 DATC Path 15, LLC, “DATC Path 15, LLC, Unopposed Offer of Settlement,” FERC Docket Nos. ER20-1006-000 and EL20- 43-000, June 17, 2021, https://elibrary.ferc.gov/eLibrary/search. 109 “Updated Wheeling Access Charge Rates Effective 6/13/22 and 1/1/23,” accessed March 24, 2024, http://www.caiso.com/Documents/updated-wheeling-access-charge-rates-effective-61322-and-1123.html. 110 “Babcock & Brown Infrastructure Fund Gets Acquired,” Reuters, May 17, 2009, sec. Funds, https://www.reuters.com/article/idUSN17287902/.
111 Warren, “Transmission Infrastructure By Public-Private Model - Law360.” 112 Umesh Ellichipuram, “NextEra Energy Transmission to Acquire TBC for Nearly $1bn,” Power Technology (blog), November 21, 2018, https://www.power-technology.com/news/nextera-energy-tbc/; “NextEra Energy Transmission Completes Acquisition of Underwater Transmission Cable System,” NextEra Energy Newsroom, accessed March 25, 2024, https://newsroom.nexteraenergy.com/2019-07-16-NextEra-Energy-Transmission-completes-acquisition-of-underwater-transmission-cable-system. 113 FERC, “Order Accepting Operating Memorandum,” FERC Docket No. ER05-985-000, July 22, 2005, https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20050722-3056&optimized=false. 114 FERC, Order Accepting and Suspending Proposed Tariff Revisions and Establishing Hearing and Settlement Judge Procedures, No. ER19-2846-000 (FERC November 21, 2019). 113 Center For Law, Energy & the Environment
REVENUE REQUIREMENT MODEL PAGE 53
tariffs (to a TRR of around $136.5 million) but also TBC had to refund the CAISO for the excess charged after the previous provisional approval from FERC, the 13.5% ROE was maintained.115 West of Devers Project - Morongo Transmission
The West of Devers Project is a $1 billion Southern California Edison Co. (SCE) initiative to upgrade existing transmission lines enhancing capacity by 3.2 GW between Riverside County and areas east of Los Angeles.116 This project crosses Morongo Reservation land, for which the Morongo Native American Tribe granted SCE a 50-year right-of-way through its reservation. The approval of this arrangement enables the avoidance of an estimated $500 million cost to reroute transmission lines around the Reservation.117 In exchange for this right-of-way, the Morongo Tribe received the right to invest in the transmission with debt and receive a FERC transmission tariff, including an ROE. Morongo Transmission LLC (Morongo Transmission) received the right to invest up to $400 million (or 50% of the project's final cost) in the project.
Morongo Transmission was allowed to finance its investment entirely with debt. Approved in 2021 by the CAISO, Morongo Transmission became the first Native American tribe as a participating transmission owner,118
Profits from transmission rates were to be distributed to impacted communities. The arrangement was outlined in the Development and Coordination Agreement (DCA).119 This was an innovative PPP agreement between SCE and Morongo to finance a part of the project, marking a pioneering arrangement between a utility and a Native American tribe.
In 2014 FERC approved Morongo Transmission’s capital cost recovery methodology, including a hypothetical capital structure and a formula rate for operating costs recovery. The DCA was later amended to allow Morongo Transmission additional investment options.120
In December 2020, Morongo filed a request with the FERC (Docket No. ER21-669) for a transmission formula rate related to its investment in the West of Devers Upgrade Project. Morongo’s revenue requirement consisted of capital and operating costs, with a proposal of a TRR of over $40 million, a base ROE of 10.3% (SCE’s authorized ROE), and an RTO Participation Adder of 100 basis points, and its commitment to transfer 115 Trans Bay Cable LLC, “Uncontested Offer of Settlement,” FERC Docket ER19-2846-001, September 4, 2020, https://www.ferc.gov/.
116 “CAISO Board Approves Native American Tribe as Transmission Owner,” accessed December 12, 2023, https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/caiso-board-approves-native-american-tribe-as-transmission-owner-62499840. 117 “Landmark FERC Decision Paves Way for Clean Energy Tribal-Private Partnerships,” Jenner & Block LLP | Law Firm - Jenner & Block | Landmark FERC Decision Paves Way for Clean Energy Tribal-Private Partnerships, accessed March 25, 2024, https://www.jenner.com/en/news-insights/news/landmark-ferc-decision-paves-way-for-clean-energy-tribal-private-partnerships. 118 “Morongo Becomes First Native American Tribe to Be Approved as a Participating Transmission Owner in Nation – Morongo,” accessed March 25, 2024, https://morongonation.org/news/morongo-becomes-first-native-american-tribe-to-be-approved-as-a-participating-transmission-owner-in-nation/. 119 “West of Devers Upgrade Row Agreement.Pdf,” accessed March 25, 2024, https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M080/K274/80274785.PDF. 120 “Notational Order 2021-05-05 | Federal Energy Regulatory Commission,” accessed March 25, 2024, https://www.ferc.gov/news-events/events/notational-order-2021-05-05-05052021. 114 Improving T ransmission F inanc ing in Cal ifornia
REVENUE REQUIREMENT MODEL PAGE 54
operational control to CAISO.121 FERC approved the proposed TRR and adjusted the RTO Participation Adder to 50 basis points.
With approval of Morongo Transmission’s tariff, FERC granted a unique ratemaking methodology, featuring 100 percent debt financing, a fixed 30-year transmission rate, and parity with the rates charged by utilities, benefitting landowners by honoring their contribution, simplifying regulatory decisions by reducing local contention, ensuring transmission customers are not financially disadvantaged, and supporting transmission developers by facilitating easier siting approval and reducing litigation risks.122 SCE updates yearly the Morongo West of Devers Rate Year Cost, which by the end of 2023 was of $7.59 million, compared to $11.5 million in the previous update, a decrease of $3.9 million, mainly attributable to property taxes.123
121 “Morongo Transmission Requests a 100 BP ROE Incentive from FERC,” Energy Central, January 21, 2021, https://energycentral.com/c/tr/morongo-transmission-requests-100-bp-roe-incentive-ferc. 122 Suedeen Kelly, “If Only Transmission Lines Were like Rose Bushes,” November 29, 2023, https://www.jenner.com/en/news-insights/publications/if-only-a-transmission-line-were-like-a-rose-bush-wires-quarterly-newsletter. 123 “2024 Annual Update WOD Filing Letter.Pdf,” accessed March 25, 2024, https://www.sce.com/sites/default/files/Regulatory/OpenAccessInformation/MorongoWOD/2024%20Annual%20Update% 20WOD%20Filing%20Letter.pdf.
115 Center For Law, Energy & the Environment
Center for Law, Energy
& the Environment
University of California
Berkeley School of Law
1995 University Avenue, Suite 460
Berkeley, CA 94704
clee.berkeley.edu
TWITTER: @CLEEBerkeley
FACEBOOK: @CLEEBerkeley
INSTAGRAM: @CLEEBerkeley
LINKEDIN: Center for Law, Energy
& the Environment
Executive Summary
An unprecedented expansion in electrical transmission is key to meeting California’s climate goals. However, there is a risk that traditional investor-owned utility financing and development of this multi-billion-dollar infrastructure portfolio could substantially increase consumer rates.
Net-Zero California (NZC) and Clean Air Task Force (CATF) commissioned research to evaluate whether alternative transmission financing and development models could generate ratepayer savings. The analysis was limited to the California Independent System Operator’s 20-Year Outlook, which identifies the new high-voltage transmission lines needed to meet the state’s energy demand in 2045.
The results show the potential for substantial ratepayer savings of up to $3 billion per year, or about $123 billion over 40 years, to the extent this infrastructure is financed and developed through a public-private partnership.
The key drivers of savings include: using low-cost public debt to replace equity in the capital structure; ensuring competitive selection of the transmission line developer; public ownership to reduce taxes; and private operations to increase efficiency. This portfolio of actions could also increase the speed of transmission development.
Existing California state agencies have some, but not all, of the authority necessary to implement a public financing and development strategy. Further work is needed to identify the optimal implementation of a public-private partnership or similar model in California.
Wired for Savings
Evaluating the Impact of Alternative
Transmission Financing and Development
Models on California Ratepayers
CATF & NZC | Wired for Savings Summary 2
1 Senate Bill 100 (SB 100, De León, Chapter 312, Statutes of 2018) 2 SB 100 Joint Agency Report (2021) https://www.energy.ca.gov/sb100 3 California Public Advocates Office, 2024. 2024 Q2 Electric Rates Report 4 Natural Resources Defense Council, 2024. Equitable rate reform is required to meet our climate goals. 5 SB 1006 (Padilla): https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=202320240SB1006. 6 West-Wide Governance Pathways Initiative: https://www.westernenergyboard.org/wwgpi/. 7 California Public Advocates Office, 2023. California’s facing climate and electricity rate crises. Here’s how to solve them. 8 DHInfrastructure and EE-Analysis, 2024. Public sector financing of electricity transmission lines in California. 9 UC Berkeley Center for Law, Energy and the Environment, 2024. Improving transmission financing in California: Policy strategies to increase affordability.
Overview
California set ambitious clean energy deployment goals, requiring that renewable and zero-carbon energy resources supply 100 percent of electric retail sales to customers by 2045.1 Delivering on this goal will require
quadrupling clean energy capacity2
alongside an enormous expansion in new transmission to bring these resources from various regions, including the North and Central Coast (offshore wind), Central Valley (solar), and Salton Sea (geothermal), to load centers.
This presents an issue where rates could further increase to pay for this grid infrastructure and potentially undermine the transition to clean energy. With rates having increased by about 50 percent in the last three years for many investor-owned utility (IOU) customers,3
proactive actions are needed to bring down energy costs and keep rates as low as possible.
Stakeholders have identified multiple strategies with the potential to reduce rates, such as equitable rate reform,4 increased use of grid-enhancing technologies,5
an expansion in western power markets,6 and removing non-essential utility programs from electric bills.7
NZC and CATF partnered to evaluate a less-examined strategy with potential for significant upside: changing the way transmission infrastructure is financed and developed in California.
This policymaker brief summarizes two analyses commissioned by NZC and CATF to investigate this issue:
1. A financial analysis by DHInfrastructure (DHI) and EE-Analysis (EEA) that quantifies the potential ratepayer savings of alternative transmission financing and development models compared to a IOU financing and development scenario.8
2. A legal and policy analysis by UC Berkeley’s Center for Law, Energy and the Environment (CLEE) that identifies potential options and challenges to implementing an alternative transmission financing and development model in California. The CLEE analysis also examines a series of near-term policymaker recommendations to address these challenges.9 The CLEE report incorporates feedback from an in-person convening of transmission experts held in June 2024.
CATF & NZC | Wired for Savings Summary 3
10 IOU “self-approved” transmission projects are an example of non-TPP projects. For more information, see pp. 30-31 of the 2023 California Electric and Gas Utility Costs Report.
11 California Public Utilities Commission, 2024. 2023 California Electric and Gas Utility Costs Report. 12 California Independent System Operator, 2024. 2024 20-Year Transmission Outlook. High-voltage is defined as transmission lines and related upgrades equal to or greater than 230 kV.
13 CAISO’s 2024 20-Year Outlook is limited to identifying potential high-voltage transmission needs but recognizes the need for expansions in lower-voltage transmission, which would also add to the rate base.
Background on California transmission financing
and development
Transmission lines in California are primarily owned, financed and developed by private, for-profit IOUs. The three main IOUs are Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, who collectively own and operate the majority of transmission lines in the state. IOUs must file with the Federal Energy Regulatory Commission (FERC) for approval to recover their transmission costs in rates for projects identified as part of a formal planning process, such as the California Independent System Operator’s (CAISO) annual Transmission Planning Process (TPP), or separately by the IOUs themselves.10 FERC authorizes cost recovery, and IOUs are able to obtain financing (including third party debt and equity) to develop projects.
Transmission in the rate base
Transmission currently comprises about 30 percent of the California IOU rate base, representing a key factor in determining electric rates (Figure 1).11 This amount is expected to grow considerably in the coming years.
CAISO’s 2024 20-Year Outlook identifies $46 to $63 billion of new high-voltage transmission to achieve the state’s SB 100 goal.12 Significant expansion of lower-voltage transmission will also be needed.13 As project financing (cost of capital) and development have the potential to substantially increase overall transmission costs, actions to minimize rate impacts are needed.
Figure 1 – Calculating the Revenue Requirement
The “revenue requirement” refers to the total revenue that IOUs are authorized to collect from ratepayers in a given year. The book value of an IOU’s generation, distribution and transmission assets (rate base), and just as importantly the cost of capital associated with servicing that rate base (rate of return), directly impacts what is ultimately charged to ratepayers. Transmission is a key and growing component of the IOU rate base. Note: this graphic shows simplified processes regulated by FERC and California Public Utilities Commission to determine revenue requirements for IOU-owned transmission and distribution assets, respectively.
Revenue
Requirement
Return on
Rate Base Depreciation Operations andMaintenance Taxes
Rate of Return Rate Base
CATF & NZC | Wired for Savings Summary 4
14 Pfeifenberger, J. et al. The Brattle Group. (April 2019). Cost Savings Offered by Competition in Electric Transmission: Experience to Date and the Potential for Additional Customer Value. https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_ competition_in_electric_transmission.pdf
15 For more information on the transmission planning and permitting process, see CATF’s factsheet: “Transmission Development in California – What’s the Slowdown?”
Alternative financing and development approaches
NZC and CATF commissioned DHI and EEA to evaluate whether alternative approaches to transmission financing and development could generate cost savings. The research identified three key opportunities: the use of low-cost public debt; new institutional models to facilitate public financing; and reducing the risk of pre-investment development. These opportunities are summarized below.
I. The use of low-cost public debt (bonds) could directly reduce costs to ratepayers by enabling lower interest rates, replacing equity in the capital structure, and reducing taxes. a. Lower interest rates: A public entity issuing a bond typically provides access to the lowest-cost debt due to the high credit rating of governments, resulting in lower debt servicing and therefore a lower revenue requirement compared to traditional private sector borrowing. b. Debt replacing equity: To the extent that public debt replaces equity in the capital structure, costs would be further reduced, as the cost of equity (dividends) is considerably higher than the cost of debt (interest). c. Reducing taxes: Public bonds and loans are in many cases tax-exempt. Additionally, a lower rate of return (i.e., more debt vs. equity) will further reduce income tax obligations.
II. New institutional models to facilitate public financing, including certain types of public-private partnerships or a wholly public development model, could indirectly reduce costs to ratepayers.
A new or expanded public agency or authority that facilitates public financing could enable a range of additional cost reductions. For example, a public-private partnership (PPP) could help to increase competition for the development of new transmission, which has been shown to reduce costs.14 Public ownership, whether as part of a PPP or wholly public model, could reduce tax obligations. PPPs offer the additional benefit of retaining private sector innovation and efficiency for operating and maintaining a transmission line and–by using special purpose vehicles to implement projects–can shield the public owner from certain operational risks.
III. Accompanying policies that seek to reduce the length and risks of pre-investment development could deliver a third tranche of savings.
As transmission development is high risk and requires significant pre-investment capital, investors require high risk premiums. As a result, policies that reduce the length and risk of this phase, such as clear and predictable siting and permitting processes, could generate direct cost reductions.15 CATF & NZC | Wired for Savings Summary 5
Evaluating the alternative models for ratepayer savings DHI and EEA analyzed the potential savings that could occur under alternative transmission financing and development models in California. CAISO’s 20-Year Outlook, which identifies a portfolio of high-voltage transmission lines and related upgrades necessary to achieve the state’s SB 100 goal, was used as a basis for the analysis. The analysis examined four alternative models for financing and developing this new infrastructure, which leverage a combination of the approaches outlined above:
1. IOU Financing and Development: A current scenario of an IOU developing, financing, and operating transmission lines.
2. Wholly Public: A wholly government-owned entity developing, financing, and operating the lines.
3. Public-Private Partnership (Concession): A concession-type PPP in which a private company designs, builds, operates, and finances a publicly-owned asset over the life of the asset, and the asset is ultimately returned to the government at the end of the concession agreement.
4. Public-Private Partnership (Lease): A lease-type PPP, in which a government-owned holding company or special purpose vehicle provides financing for the transmission asset but hires a private company to build and operate the assets.
The estimated cost of the 2024 20-Year Outlook infrastructure is between $39 and $54 billion for engineering and construction costs only.16 Adding in financing and development costs, this number increases to up to $216 billion over 40 years under a IOU financing and development scenario.
Alternative approaches show significant opportunity to reduce the financing and development costs by as much as 57 percent, or up to $123 billion, over the same period. This is equivalent to ratepayer savings (or a reduction in the revenue requirement) of $3 billion per year. The results are summarized in Figure 2.17 16 Note that Figure 2 excludes interregional transmission for out-of-state wind that is already being developed. These costs will be paid by the line subscribers. It additionally does not include costs for upgrades to existing utility transmission facilities that are likely not eligible for competitive solicitation.
17 Figure updated to reflect the 2024 20-Year Transmission Outlook; original analysis by DHI and EEA used inputs from the 2022 Outlook.
Figure 2 – Alternative Financing
Models: Annual and Total Cost
Savings Potential
This figure shows the potential for
57 percent cost savings – equal to
$3 billion annually (left-hand axis) or
up to $123 billion over a 40-year asset
lifetime (right-hand axis) – via a PPP-Lease model relative to an IOU financing and development scenario
of the 20-Year Outlook portfolio.
Taxes
Return on Rate Base
Depreciation Expense
Operating Expense
IOU PPP-Concession Wholly Public PPP-Lease
Annual Cost (Billions)
$6.0
$5.0
$4.0
$3.0
$2.0
$1.0
$0
$240
$200
$160
$120
$80
$40
$0
Total 40-Year Lifetime Cost (Billions)
25%
54% 57%
CATF & NZC | Wired for Savings Summary 6
DHI and EEA also applied these results to individual lines. For example, recent and detailed capital cost estimates have been developed for North Coast offshore wind, where a $7.7 billion line is planned to accommodate 7.2 GW of development.18 Under the IOU model, this line would have an annual average cost to ratepayers of $774 million.
Under the PPP-Lease model, this cost would fall to $332 million.
The drivers of the cost savings, identified in Figure 3, include: using low-cost public debt to replace equity in the capital structure; ensuring competition in the procurement of the lines; public ownership to reduce taxes; and private operations and maintenance to increase efficiency.
The analysis found the PPP-Lease model, which contains all these elements, provides the lowest-cost approach to delivering California’s transmission goals, followed by a wholly public model. A key advantage of the PPP-Lease model is the blend of public and private sector involvement which leverages the strengths of each sector.
A PPP-Lease model offers exemption from certain taxes, retention of private sector expertise and cost-effectiveness through competitive bidding and contracts, and the use of lower cost public debt. A concession-type PPP is comparatively more costly as it retains private sector financing. 18 Schatz Energy Research Center, 2023. Northern California and Southern Oregon Offshore Wind Transmission Study. 19 IOUs are also able to “self-approve” rates for certain transmission projects that do not expand capacity of the grid, such as repair and replacement projects for maintaining the grid. Between 2013 and 2022 self-approved projects accounted for 50 percent ($11 billion) of their collective transmission investment. California Public Utility Commission. (April 2024). 2023 California Electric and Gas Utility Costs Report. https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/office-of-governmental-affairs-division/reports/2024/2023-ab-67-report.pdf Financing and Development Models
IOU PPP-Concession PPP-Lease Wholly Public
Drivers of Cost Savings
Low-Cost Public Debt
Competitive Solicitation
Tax-Exempt Public Ownership
Efficient Private Operations
Figure 3 – Alternative Financing
Models: Drivers of Cost Savings
This figure highlights the cost
drivers modeled in the alternative
transmission development scenarios.
Study limitations
DHI and EEA identified key limitations that suggest the cost savings described above are likely conservative. CAISO’s 2024 20-Year Outlook capital costs exclude costs associated with right-of-way acquisition and undergrounding transmission for wildfire mitigation.
The 2024 20-Year Outlook capital costs only include new transmission and related upgrades greater than 230 kV, leaving out smaller lines and IOU “self-approved” projects.19 The scenarios do not model additional savings that could be achieved by de-risking the pre-investment development phase.
CATF & NZC | Wired for Savings Summary 7
Potential implementation options
DHI and EEA’s financial analysis identifies the potential cost savings associated with financing and developing transmission under alternative models. To accompany this financial analysis, and situate it in the California context, NZC and CATF commissioned CLEE to conduct a legal and policy review of California agency authorities and structures. CLEE identified a range of potential models that build on existing transmission permitting or financing authorities and draw inspiration from other state and federal models. CLEE considered the benefits and drawbacks of creating new authorities, such as a California Renewable Energy Transmission Authority, or a California Green Bank, which could both finance new transmission and facilitate PPPs.
CLEE also evaluated expanding authorities of existing agencies, including the California Infrastructure and Economic Development Bank, the California Alternative Energy and Advanced Transportation Financing Authority, and the Department of Water Resources, all of which have some existing bonding authority or ability to procure energy resources. Finally, CLEE identified the potential use of federal financing programs through the Western Area Power Administration’s Transmission Infrastructure Program, which has $3.25 billion of borrowing authority and the ability to offer loans.20
Policymaker recommendations
With an opportunity for ratepayer savings of up to 57 percent when compared to the IOU financing and development scenario, or $3 billion per year and $123 billion over 40 years on the 20-Year Outlook portfolio, California policymakers should further evaluate the potential of public financing and development models to reduce the cost of transmission and consider advancing near-term actions.
The passage and signing of AB 3264 (Petrie-Norris) is a critical next step for further evaluating the cost savings potential of alternative financing and ownership models. AB 3264 directs the Public Utilities Commission, Energy Commission, California Infrastructure and Development Bank, and CAISO to conduct a study to evaluate public financing, costs and benefits of different ownership models, and other proposals to reduce the cost to ratepayers of expanding the transmission grid.21 State agencies may consider leveraging the analyses underlying this brief as an input to delivering this study by the July 1, 2025 due date.
In addition to further evaluation, policymakers should consider advancing near-term actions. CLEE identified several potential actions to facilitate transmission public financing and speed transmission development, which emerged from a convening of experts including state government, grid operators, non-profits, ratepayer advocates, and industry associations. These near-term actions include:
1. Focus on demonstrating alternative financing and development arrangements for key transmission lines identified in the CAISO 20-Year Outlook. Commonalities and differences between proposed locations, developer options, and other considerations for transmission lines will likely shape approaches to financing.
For example, the potential large-scale solar development in the Westlands Water District area of Fresno County (approximately 110,000 acres with 15-20 gigawatts of solar) may have different needs than the approximately 14.7 GW of Northern California offshore wind across multiple resource areas and substations.
2. Establish a liability backstop for whatever entity or entities own new transmission. As precedent, the California Legislature has established a liability backstop based on actions to reduce fire risk for IOUs operating the existing transmission system.
20 For more information on the pros, cons and trade-offs of these model options, see Appendix I of the CLEE report. 21 AB 3264 (Petrie-Norris) (2024) Chapter 762. https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=202320240AB3264 CATF & NZC | Wired for Savings Summary 8
3. Minimize risk through insurance, contract, indemnity, and first loss protection, and other mechanisms, subject to negotiation and legislation, as New Mexico has done through its Renewable Energy Transmission Authority (RETA).22
4. Modify CAISO rules to allow for an additional competitive bid process, opening more transmission to private development and private funding. Under existing CAISO rules, some (albeit few) potential transmission lines are already eligible for competitive bids by private developers. CAISO has sufficient existing authority to expand the lines eligible for competitive bidding.
5. Explore credit enhancements from the state or federal government. Credit enhancements have encouraged investment and reduced borrowing costs in multiple contexts. Examples could include the establishment of a state loan loss reserve, loan guarantee, or loan loss insurance to improve the creditworthiness of private transmission developers seeking financing. The federal Department of Energy’s Loan Programs Office can also issue credit enhancements to state-administered clean energy programs.
6. Assess opportunities to finance some transmission lines through general obligation bonds, funded by taxpayers through the budget process. This can remove some transmission costs from the revenue requirement. Legislators could explore issuing revenue bonds, which do not require voter approval and are used to finance income-generating projects built with the proceeds of the bonds.
7. Explore options for applying existing federal models to California. Specifically, workshop participants noted that the Western Area Power Administration (WAPA) could potentially finance transmission, or a state version of WAPA could be established to finance transmission and provide electricity at a wholesale rate to municipal utility customers and community choice aggregators. This is a novel model and warrants further evaluation.
8. Engage the Governor’s Office to designate a coordinator for high priority lines and support a process to speed implementation and financing. This approach worked well when Governor Schwarzenegger designated a coordinator for large-scale solar projects, making solar a state-wide priority. The coordinator convened meetings with federal, state, and local government officials as well as stakeholders, coordinated state agency participation, and mediated disputes.
22 For more information on New Mexico RETA, see Appendix I of the CLEE report.
SB 540 - Pathways Initiative
SUMMARY
SB 540 provides the California Independent
System Operator (CAISO) the authority
necessary to implement the Pathways Initiative
Proposal if it determines an independent regional
organization (RO) meets specific requirements.
The bill allows CAISO to tap into a wider
market of electricity resources which studies
have shown stand to provide significant benefits
to Californians including cost savings, enhanced
grid reliability, and reduced air pollution.
While prior attempts to create a wider regional
market have failed out of concerns that
California would lose control over its
environmental policies, SB 540 enables an
innovative approach that would secure the gains
of an expanded market while protecting
California’s ability to set and enforce its own
procurement, environmental, reliability, and
other public policies.
PROBLEM
For many years, California’s energy regulators
have explored how they could optimize
available energy supplies across other western
states to expand our energy markets and enable
an affordable, clean, and reliable grid.
Studies have shown that there are significant
benefits for California in an expanded energy
market. For example, a Stanford Woods Institute
(2024) study found that an expanded market
would relieve strain on the electric grid during
extreme heat events–in an expanded market
scenario the grid was strained 40% fewer hours.
1 A study commissioned by the California Energy
Commission (CEC) found that under an
expanded market, California would save nearly
$800 million per year and gas generation would
fall by 31%, moving us closer to our 100% clean
1 Stanford Woods Institute: “Grid Regionalization in
the West”
energy goals while reducing air pollution.
2 However, these benefits only materialize if
other states want to join the regional market, a
market they are wary of if it’s solely under
California’s control.
Several different proposals, that would reassure
other Western states of California’s willingness
to work jointly, have made their way before the
Legislature. Most recently, AB 538 (Holden,
2023) would have transformed CAISO into a
regional transmission organization (RTO).
However, these previous efforts have failed over
reasonable concerns about losing control of the
state’s critical public policies.
The Pathways Proposal offers a way to solve
these problems. Instead of creating an RTO, the
Pathways Proposal creates an RO that only
governs the market rules for energy markets
while retaining CAISO’s role as a
California-governed balancing authority so that
California and CAISO retain control over
procurement, environmental, reliability, and
other public policies.
CURRENT LAW
Existing law enables CAISO to, and instructs
how it will, manage the transmission grid and
related energy markets. It requires, among other
things, that CAISO manage those markets in a
manner that maximizes efficiency, reduces costs
to consumers, protects public health and the
environment, and ensures reliability. However,
additional authority is required in order for
CAISO and California utilities to use energy
markets overseen by an RO as proposed by the
Pathways Initiative.
THIS BILL
SB 540 enables the CAISO and California
utilities to participate in energy markets
governed by a separate, independent regional
2 Brattle: “Preliminary Day-Ahead Market Impacts
Study”
Last Updated 02/20/2025
organization. If the RO meets specific criteria,
CAISO would be authorized to enact a
resolution allowing the RO’s rules to govern
CAISO’s energy markets. The CAISO would
continue to be the operator of the energy
markets.
SB 540 does not transfer authority for
transmission planning, transmission cost
allocation, balancing authority functions, or
reliability coordination–this authority would
remain with the existing CAISO board structure.
The bill also does not immediately authorize
utilities to enter a market governed by an RO,
CAISO must first demonstrate the RO meets a
number of statutory requirements before moving
control of the market rules to the RO including:
confirming that California regulatory agencies
and CAISO retain control over Renewables
Portfolio Standard requirements, climate policy,
other procurement requirements, transmission
planning, CAISO’s interconnection queue, and
resource adequacy requirements; requiring that
the RO provides a procedure for withdrawal
from the market, should it no longer benefit
California to participate; maintaining the
capability to operate its own market, should
California decide to withdraw from the RO;
ensuring the RO is obligated to make decisions
in an open process; making funding available
for consumer advocates to engage in the process,
and more.
The expanded market that SB 540 would enable
will save ratepayers money, improve grid
reliability, and reduce air pollution from power
plants in California by:
1) Optimizing the use of generation, storage and
transmission resources.
2) Securing California’s ability to export excess
renewables rather than curtailing them and
importing them from other states when
available.
3) Allowing California to draw upon a wider set
of Western renewable resources when our grid is
stressed.
4) Making less use of back-up diesel generators
and the oldest, dirtiest gas plants during system
peaks.
SB 540 will ensure that we reach our climate
goals in the most cost-effective and reliable
manner possible by tapping into a much wider
set of Western resources–lowering energy bills,
improving grid reliability, and reducing
pollution in front-line communities, while also
retaining control of our procurement,
environmental, reliability, and other public
policies.
SUPPORT
Coalition of California Utility Employees
(co-sponsor)
State Association of Electrical Workers
(co-sponsor)
Environmental Defense Fund (co-sponsor)
Natural Resources Defense Council (co-sponsor)
American Clean Power–California
California Community Choice Association
California Environmental Voters
Clean Energy Buyers Association
Pattern Energy
Peninsula Clean Energy
FOR MORE INFORMATION
Erika Romero
Policy Analyst
[email protected]
Last Updated 02/20/2025
DOCKETED
Docket Number: 24-IEPR-01
Project Title: General Scope
TN #: 261300
Document Title: Presentation - Preliminary Day-Ahead Market Impacts Study Description: *** THIS DOCUMENT SUPERSEDES DOCUMENT TN
#264264***6A. John Tsoukalis, Brattle-Group
Filer: Raquel Kravitz
Organization: California Energy Commission
Submitter Role: Commission Staff
Submission Date: 1/27/2025 8:55:48 AM
Docketed Date: 1/27/2025
January 24, 2025
PREPARED BY PREPARED FOR
John Tsoukalis
Kai Van Horn
Johannes Pfeifenberger
Evan Bennett
Alison Savage Brooks
IMPACT OF MARKET FOOTPRINTS ON CALIFORNIA CUSTOMERS
Preliminary Day-Ahead
Market Impacts Study
brattle.com | 1
The benefits of EDAM
will depend on the size
and diversity of
members that join. A
larger and more
diverse EDAM
footprint will deliver
more benefits to
customers in
California.
Several utilities in CA and neighboring states have committed to joining EDAM, while other utilities in the western U.S. are exploring a different day-ahead market (Markets+) that will not include CA.
Regional markets deliver cost savings to customers due to efficiency gains, environmental benefits through lower emissions, and reliability benefits by making it easier to manage the grid during extreme weather events.
This study calculates the benefits to CA customers if additional utilities across the western U.S. participate in EDAM.
We study 2032 as a proxy for the first decade of market operations – We use resource assumptions from utility IRPs and the CAISO’s TPP – We build off the modeling efforts conducted for over a dozen utilities in the last two years
Overview of the Study and Drivers of Benefits
brattle.com | 2
Market Dynamics and Expected Outcomes
• Lower emissions due to avoided curtailed energy displacing fossil generation.
Environmental Benefit
• Lower power costs for customers due to zero variable cost energy displacing higher variable cost energy. Customer Cost Savings
• Better investment environment for renewable projects. Customer Cost Savings Reduced Curtailment of
Wind and Solar due to
Increased Resource and
Load Diversity
• Reduced bilateral trading as markets trades become more profitable, lost bilateral trading margins. Customer Cost Increase
• Increased market congestion and transfer revenues. Customer Cost Savings Increased Trading
between Market
Members
• Shift from less efficient to more efficient resources, leading to production cost savings for customers. Customer Cost Savings
• Emissions potentially decline due to shift to more efficient generation.
Potential Environmental Benefit
• Better management of extreme weather events and unexpected grid challenges (e.g., outages). Reliability Benefit
• Reduced sale of short-term transmission service, as transmission is “donated” to the market (offset by EDAM TRR Settlement). Customer Cost Increase Larger and More
Diverse Pool
Transmission and
Generation Resources
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
brattle.com | 3
To test the impacts for California DA market participation benefits of several potential DA market outcomes, we simulated four market footprints
Simulated Market Footprints
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline Case
(Approved EDAM Commitments)
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Expanded EDAM Case
(Maximum EDAM Potential)
Split Market Case
(Likely EDAM Entities w/ Markets+)
WEIS
SPP RTO West (co-optimizes w/ M+)
EDAM (also in WEIM)
Markets+ (DA & RT)
WEIM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline+ Case
(Likely EDAM Commitments)
brattle.com | 4
CA Customer Benefits Increase with the Size of the EDAM Footprint AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline Case
(Approved EDAM Commitments)
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Expanded EDAM Case
(Maximum EDAM Potential)
WEIS
SPP RTO West
EDAM (also in WEIM)
WEIM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline+ Case
(Likely EDAM Commitments)
These benefits are
incremental to the
benefits of the
formation of EDAM
with the Baseline
footprint of
committed entities
Intermediate EDAM
footprints likely to
produce benefits
between the
Baseline+ and
Expanded EDAM
“bookend”
CA Total System Cost
($million per year) $4,511 $4,399 $3,721
Δ to Baseline $112 $790
Δ to Baseline+ $678
Expansion of EDAM footprint could produce over $500 million/year in market benefits to CA customers AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
brattle.com | 5
California Benefits from a Two Market Outcome
Split Market Case
(Likely EDAM Entities w/ Markets+)
(Assumes Relatively Efficient Seams)
WEIS
SPP RTO West
EDAM (also in WEIM)
Markets+ (DA & RT)
WEIM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.
CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline+ Case
(Likely EDAM Commitments)
Two offsetting effects lead to a small gain for CA
customers in the Split Market case:
CA customers experience a loss from utilities leaving the WEIM (~40% of load in WEIM today).
CA customers benefit from increased access to low-cost resources in the M+ footprint due to elimination of seams in the WECC and increased DA trading at the market seam.
Several assumptions drive this result:
A relatively efficient seam between M+ and EDAM (lower trading costs than bilateral trading in the Baseline cases). Hourly modeled real-time trading at the seam fails to capture full loss from utilities leaving WEIM, which
optimizes on a sub-hourly level.
M+ co-optimizes with RTO West, giving low-cost thermal resources in that region hurdle-free access major CA
import locations (e.g., Malin, PV).
The Split Market case assumes ~60% of load in the WEIM today joins EDAM; assuming more of the WEIM leaves
would increase the loss to CA customers.
CA Total System
Cost ($million per year) $4,399 $4,217
Δ to Baseline+ $182
CA Benefits ~$500 million/year higher in the
Expanded EDAM Case (see previous slide)
brattle.com | 6
The expansion of EDAM reduces gas generation and the curtailment of wind and solar in California, resulting in lower GHG emissions in the state. …
…
GHG Emissions Impacts
-4,000
-3,000
-2,000
-1,000
0 1,000
2,000
Expanded EDAM Split Market
Wind
Solar
Other
Nuclear
Hydro
Geothermal
Gas-ST
Gas-CT
Gas-CC
Coal
GWh
California-Wide Generation
(Relative to Baseline+)
CA gas
generation
falls 31%
with an
expanded
EDAM
0 2,000
4,000
6,000
8,000
10,000
12,000
Baseline Baseline+ Expanded
EDAM
Split Market
GWh
Total California Curtailments by Case
Wind and solar
curtailments fall 10%
with an expanded EDAM
Change in CO2 Emissions
CA CO2
emissions fall
11.2% with an
expanded EDAM
CA CO2
emissions fall
3.5% in the Split
Market Case
Expanded
EDAM
Split
Market
WECC CO2
emissions rise
1.3% with an
expanded EDAM
WECC CO2
emissions rise
2.1% in the Split
Market Case
brattle.com | 7
Market supply cushion is the total unutilized capacity accessible by participants from available market generation in each hour, i.e., the available generating capacity not committed to serving load. It includes generators that are online and below maximum output It excludes resources that are on planned or forced outage Storage resources are further limited by their stored energy We conservatively assume that hydro, wind, and solar provide no incremental supply cushion.
We use this metric as a proxy for the impacts of market footprint on access to capacity, especially during tight-supply periods with high risk of resource adequacy shortfalls.
Market Supply Cushion Overview
Online
generator
Supply Cushion
Example
Available
supply cushion
Generator
energy dispatch
Pmax
0 5,000
10,000
15,000
20,000
25,000
30,000
35,000
12:00
AM
2:00
AM
4:00
AM
6:00
AM
8:00
AM
10:00
AM
12:00
PM
2:00
PM
4:00
PM
6:00
PM
8:00
PM
10:00
PM
Coal Gas-CC Gas-CT Gas-Other Storage
brattle.com | 8
The supply cushion in the EDAM footprint is
significantly higher in the Expanded EDAM
case relative to the Split Market case.
The supply cushion is ~25,000 MW more in the
Extended EDAM case than the Split Market case.
Higher supply cushion in midday hours when
storage is charging.
– The Expanded EDAM case has more storage in the
EDAM compared to the Split Market case, as well as a
higher average state-of-charge due to increased
renewables diversity in the larger footprint.
Expanding the EDAM footprint Increases Supply Cushion
Expanded EDAM Case minus Split Market Case
Day-Ahead Market Supply Cushion
Average by Hour of Day and Capacity Type
MW
Added Supply Cushion Due
to Expanded EDAM
Focusing on the 10 tightest hours of the year, the
supply cushion in the EDAM is 20,000 MW larger
in the Expanded EDAM case than in the Split
Market case (27.8% of load vs. 24% of load)
brattle.com | 9
The benefits of regional markets are likely understated due to several factors:
Overstated Bilateral Market Efficiency: our simulation of bilateral markets is more efficient than reality – Hourly model fails to captures the benefit of real-time markets to economically and reliability manage energy imbalances through sub-hourly re-dispatch and energy exchange across market members. – The model assumes all balancing authorities have optimal security-constrained unit-commitment and dispatch (SCUC and SCED) in both DA and RT, making the simulated dispatch more optimal than reality. – Inefficient utilization of transmission by bilateral trades is not fully modeled, understating the extent M+ and EDAM will be able to make better use of all physically and contractually available transmission. – Transmission outages are not modeled, which would magnify the benefit of SCED-based congestion management in EDAM and M+ compared to the bilateral markets.
Normalized loads and fuel prices: the model uses weather-normalized loads and averaged monthly natural gas prices without daily volatility
– Challenging market conditions (beyond the included heat wave and cold snap), such during as the 2022 gas price spikes or 2024 MLK Day cold snap, will magnify benefits from a regional market. Illustrated by the WEIM experience of much higher benefits during those events.
– The Base Case does not reflect the limited liquidity of bilateral market during challenging market conditions Estimated Benefits are Conservatively Low
brattle.com | 10
The four cases simulated provide significant insight on the impact of market expansion for CA and raise questions for future analyses to address. Footprint Assumptions:
– Simulate a “Status Quo” case without any EDAM footprint, which would allow us to calculate the benefit of EDAM forming relative to just the WEIM.
– The Expanded EDAM and Split Market cases represent two approximate bookends, we could test intermediate footprints with different combinations of utilities joining EDAM or Markets+. Market Seam Assumptions:
– The level of coordination that will be achieved between the two markets is unknown. Future sensitivities could explore the impact to CA customers of different forms coordination and co-optimization across market seams. – Sub-hourly modeling could be used to calculate the benefit of 15-minute and 5-minute optimization conducted by the WEIM for CA customers and WEIM/EDAM members.
Resource mix, load forecasts, and fuel price assumptions Impact of extreme weather volatility
– Weather-relative system conditions – load, thermal generation outages, and renewable production – Daily and regional gas price volatility
Brainstorming Possible Further Analysis
Appendix A:
Modeling Assumptions and
Detailed Results
brattle.com | 12
The nodal WECC model we used for this study includes system-specific data from more than a dozen utilities in the WECC, giving us a detailed view of the western system, including:
Long-term transmission rights, contracted resources (and transmission encumbrances), generation additions, transmission additions, renewable diversity and forecast errors, and market design detail/implementation Study participants have helped refine our model by performing full reviews of relevant modeling assumptions for their systems, including transmission rights & costs, load forecasts, fuel prices, generation mix & costs, etc. – Study participants include the Balancing Authority of Northern California, El Paso Electric, Idaho Power, LA Department of Power and Water, NV Energy, Portland General Electric, PacifiCorp, Public Service Company of New Mexico, Sacramento Municipal Utility District, and other utilities, transmission owners and independent power producers – Several of these reviewers were able to provide details relevant to the CA system, including input from CAISO and others Timeline of the Brattle Team’s Western Markets Studies
Pre-2022 Studies 2022 EDAM Study 2023-24 EDAM-M+ Studies 2022 EDAM Benefits Study
We produced an updated
assessment of EDAM benefits for
five study participants, building on
the work done for the 2019 EDAM
feasibility study:
• BANC, Idaho Power, LADWP,
PacifiCorp, SMUD
Comparative EDAM-M+ Studies
We further refined our 2022 EDAM
benefits study model with input
from study participants and the
Markets+ design documents to
conduct benefits studies for several
additional utilities , including:
• Portland General Electric, NV
Energy, Public Service New Mexico,
El Paso Electric, and others
Western Market Studies
• EDAM Feasibility Study
• SPP RTO Expansion Study
• CAISO EIM GHG Structure Study
• Xcel Colorado WEIS/WEIM Study
• WEIS and SPP Integration Study
• Mountain West RTO Study
• CA SB350 Study
1 2 3
CEC Pathways Study
We leveraged our work and
modeling enhancements from all
prior studies to assess the value of a
nearly-WECC-wide day-ahead
market (i.e., an EDAM with a large
footprint) compared to an outcome
with two competing day-ahead
markets in the WECC (i.e., split
between EDAM and Markets+).
4 This Study
brattle.com | 13
Multi-Functional Simulation of WECC
Physical grid with ~20k buses, ~25k lines and
~5k generators represented as DC power flow
38 Balancing Authority Areas (BAAs) and
contract paths
WECC reserve sharing groups
Diverse state clean energy policies
Major trading hubs (e.g., Mid-C, Malin, PV, FC)
Bilateral (long-term) transmission rights
Renewable diversity, day-ahead forecast
uncertainty, real-time operations
CAISO, SPP RTO West, Markets+, EDAM, WEIM,
& WEIS footprints
Markets/RTO
Functions &
Configurations
Reserve
Sharing
Clean Energy
Policies
BAA
Functions
Bilateral
Contract
Paths and
Transmission
Rights
Physical
Flows and
Constraints
We employ multi-layer simulations to
represent the various physical, policy, and
operational facets of the WECC
brattle.com | 14
We conduct all study simulations using a nodal production cost model of the WECC with added markets, transmission rights, and contract-path trading functionality Model developed in PSO/Enelytix, which contains state-of-the-art features – Simultaneously optimizes contract path and physical constraints – Models bilateral, day-ahead, and real-time markets (including uncertainty) sequentially through multiple solution cycles – Co-optimizes storage resources with other resources in unit-commitment and dispatch – Detailed ancillary service and operating reserve modeling (including reserve sharing) and co-optimization of ancillary services with energy The study year is 2032, which aims to reflect the first decade of markets operations, representing an intermediate year that captures known changes in resource mix and transmission infrastructure Model includes two extreme weather events based on a historic cold snap and a historic heat wave – These events are modeled as single weeks in which we increase modeled loads (peak and energy) and gas prices, including gas price volatility beyond typical weather-normalized values to reflect the increased strain on the system and the ability of markets for addressing such strain – Capturing non-weather-normal impacts is becoming increasingly important due to the increasing frequency of severe weather events Detailed modeling of EDAM and Markets+ specific GHG rules which helps capture transfers into GHG pricing states – This includes the limits each market will place on sales to balancing authorities that price GHG emissions and the unit-type GHG cost representations instead of generic GHG charges
– We also model BPA’s status as an asset-controlling supplier for CA and WA, reflecting their lower cost to sell power into those zones Key Model Features
brattle.com | 15
California benefits from day-ahead market expansion under all four scenarios, but the incremental benefits of a nearly WECC-wide EDAM are ~3x those of a Split Market scenario California-Wide Day-Ahead Market Expansion Benefits
Summary of California-Wide System Costs & Revenues by Case ($ Million per year)
Note: Bilateral trading revenues refers to short-term bilateral trading of energy. Under our Expanded EDAM scenario, California benefits from the wider market footprint to expand trading and
reduce internal generation, resulting in $678 million lower net total system costs compared to the Baseline+ case:
– Adjusted production cost savings of $366 million from 3,200 GWh of reduced gas generation, lower purchase costs, and increased sales prices – Total trading and congestion revenues increase $182 million – Short-term wheeling revenues decline of $82 million as almost all of California’s trading partners join EDAM
Under our Split Market scenario, California similarly reduces internal generation and increases trading, but to a lesser extent, resulting in $182 million in lower net total system costs compared to the Baseline+ case:
– Adjusted production cost savings of $200 million from 1,200 GWh of reduced gas generation and slightly increased average sales prices – Relatively static trading gains and congestion revenues as trading modestly shifts between bilateral and EDAM trading.
– Short-term wheeling revenues decline $23 million as some bilateral trading dries up with the creation of Markets+
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $5,172 $4,952 $4,585 $4,752
Production Cost $1,744 $1,440 $1,258 $1,370
Purchases Cost $3,674 $3,907 $3,968 $3,805
Sales Revenue (subtracted from costs) $246 $395 $640 $423 Short-Term Wheeling Revenues $227 $108 $25 $84
Bilateral Trading Revenues $199 $157 $23 $106
WEIM Congestion Revenues $66 $73 $55 $42
EDAM Congestion and Transfer Revenues $170 $204 $538 $292 EDAM Transfer Revenue $85 $105 $255 $112
EDAM Congestion Revenue $84 $99 $283 $179
Net TRR Settlement $0 $6 $112 $6
Total System Production Cost and Market Revenues $4,511 $4,399 $3,721 $4,217 Benefit Relative to Baseline $112 $790 $294
Benefit % of Baseline Production Cost and Market Revenues 2% 18% 7% Benefit Relative to Baseline+ $678 $182
Benefit % of Baseline+ Production Cost and Market Revenues 15% 4% Metric
Adjusted Production
Cost (APC)
We anticipate the large majority of APC benefits would flow to customers. The timing will depend on provision in the PPAs:
• Flow through provisions in PPAs would see benefits passed through to customers. • Over the longer-term this could happen through the renegotiation of PPAs. • Reduced curtailments will impact future renewable PPAs. • Our study does not estimate any feedback effects this may have on RA prices.
Short-term wheeling
revenue
Most of the impact flows through to customers, since changes in these revenues will impact transmission access charges.
Market congestion
revenues
A large share of benefit flow to customers:
• EDAM Transfer Revenues are allocated to measured demand, which is mostly load. • EDAM Congestion Revenues are placed in the CRR Balancing Account. We have not analyzed the portion that will flow to customers, which will depend on the efficiency of CRR auctions in returning revenues to load-serving entities.
Bilateral trading
revenues
Customers would benefit from revenues on trades executed by load-serving entities, but potentially not from those executed by third-parties or generators.
Emissions Emissions reductions generally benefit all CA residents, but there may be distributional impacts depending on the geography of emitting generation changes.
Supply cushion Reliability benefits flows to customers and CA residents. brattle.com | 16
Non-vertically integrated regions, such as CAISO, may have a more complex accounting of benefits to identify the portion of benefits that flows back to customers Interpretation of Benefits in CAISO
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 344,267 342,584 -1,683 $4.18 $3.67 -$0.51 1,439,851 1,257,800 -$182,051 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 66,003 69,998 3,995 $53.81 $52.15 -$1.66 3,551,652 3,650,703 $99,051 Real-Time Market [5] 9,085 8,472 -613 $39.08 $37.43 -$1.65 355,030 317,101 -$37,928 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 80,650 83,113 2,463 $2.26 $4.82 $2.56 182,145 400,738 $218,593 Real-Time Market [8] 9,867 9,104 -763 $21.57 $26.33 $4.76 212,791 239,689 $26,898 Total Cost (Negative Difference = Benefit) [9] 328,837 328,837 0 $15.06 $13.94 -$1.11 4,951,597 4,585,177 -$366,419 % Change in APC -7.4%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost. brattle.com | 17
California’s APCs fall $366 million per year in the EDAM case, driven by:
(1) $182 million/yr reduction in production costs as California generation declines on the net by ~1,700 GWh (~3,200 GWh lower gas generation offset by ~1,500 GWh more renewables and other generation) (2) $61 million/yr increase in purchase costs as California purchases about 4,000 GWh more in the day-ahead to substitute for lower internal gas generation, offset by lower real-time purchases (3) $245 million/yr increase in sales revenue as California sells about 2,500 GWh more in the day-ahead and does so at an average price about $2.5/MWh higher than in Baseline+ California Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
California-Wide Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 344,267 342,887 -1,379 $4.18 $4.00 -$0.19 1,439,851 1,370,114 -$69,737 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 66,003 67,264 1,261 $53.81 $52.02 -$1.79 3,551,652 3,499,355 -$52,297 Real-Time Market [5] 9,085 7,984 -1,100 $39.08 $38.29 -$0.79 355,030 305,747 -$49,283 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 80,650 80,751 100 $2.26 $2.67 $0.41 182,145 215,481 $33,336 Real-Time Market [8] 9,867 8,549 -1,319 $21.57 $24.29 $2.72 212,791 207,646 -$5,145 Total Cost (Negative Difference = Benefit) [9] 328,837 328,837 0 $15.06 $14.45 -$0.61 4,951,597 4,752,089 -$199,507 % Change in APC -4.0%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost. brattle.com | 18
California’s APCs fall $200 million per year in the Split Market case, driven by:
(1) $70 million/yr reduction in production cost as California gas generation falls ~1,200 GWh (non-gas generation falls also, with renewable curtailments increasing ~200 GWh) (2) $100 million/yr reduction in purchase costs despite modestly higher overall purchase volumes due to lower purchase prices in day ahead and lower real-time purchases and prices (3) $28 million/yr in increased sales revenue due to higher day-ahead sales prices and higher real-time sales prices offsetting lower real-time volumes, drive in part by the breakup of the WEIM California Adjusted Production Cost in the Split Market Case (1)
(2)
(3)
California Adjusted Production Cost
brattle.com | 19
Gas Generation in California
MMT CO2
Pastoria
La Paloma
Walnut Creek
Sunrise
Tracy
Select Plant-Specific CO2 Emissions by Case
In the Expanded EDAM case, gas generation
in California declines by 31% relative to the
Baseline+ Case.
Emissions from some of the larger gas plants in
California fall across the board, but dramatically
more in the Expanded EDAM case.
The decline in gas generation in the Expanded
EDAM case is broadly consistent across all areas of
California.
0 20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
Baseline Baseline+ Expanded
EDAM
Split Market
GWh
brattle.com | 20
California trade volumes are highest in the Expanded
EDAM case, driven by increased opportunity in the
broader market footprint
Total trade volumes increase 26 GWh (21%) for California from Baseline+ to the Expanded EDAM case
Market transactions (EDAM + WEIM) make up 81% of all California trading in Baseline+ and 99% in the Expanded EDAM case
– Remaining bilateral transactions are with CFE in Mexico – Baseline market transactions are 65% of California trades – Split market case market transactions are 79% of California trade, as some seam trading returns with the PNW and Desert SW
From Baseline+ to the Expanded EDAM case, California is mainly increasing trading with the Desert Southwest and Pacific Northwest California Trading Volume by Case
Total California Trading
by Trade Type
EDAM
WEIM
Block
Short-Term Bilateral
Note: Trade totals only include short-term and market trading. Long-term resource contracts are not included in these totals. Short-term bilateral trades include EDAM-Markets+ seam trades. 0 50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
Baseline Baseline+ Expanded
EDAM
Split Market
GWh
brattle.com | 21
WECC-wide trade volumes are highest in the Split
Market case, due in part to transfers between the
PNW and SW portions of Markets+
Markets+ transactions between the Southwest and PNW require trading across several entities compared to more direct connections in a WECC-wide market like the Expanded EDAM case – For example, a trade from AZPS to BPAT in the Markets+ footprint requires power transacting several times across the M+ and RTO West entities in the Rocky Mountains
– In the Expanded EDAM case, AZPS could trade more directly via Nevada or California into the PNW
Market transactions (EDAM or Markets+) are the highest share of trades in the Expanded EDAM case (93% of all WECC trading vs. 77% in the Split Market case)
– Remaining hourly and block trades between the markets (i.e., seam transactions) account for the majority of non-market trades
WECC-Wide Trading Volume by Case
Total WECC-Wide Trading
by Trade Type
EDAM
WEIM
Block
Short-Term Bilateral
Markets+ RT
Markets+ DA
Note: Trade totals only include short-term and market trading. Long-term resource contracts are not included in these totals. Short-term bilateral trades include EDAM-Markets+ seam trades. brattle.com | 22
In the Expanded EDAM case, California trading
increases with the new EDAM participants in the
Desert Southwest and Pacific Northwest
Hydro entities in the Pacific Northwest export 7 TWh
more to California, mostly in the morning and
evening
California exports 20 TWh more to the Desert
Southwest and imports 15 TWh more, exchanging
renewables and efficient gas
Trading with existing EDAM entities in the center of
the WECC declines about 10 TWh
– Idaho Power, NV Energy, and PacifiCorp increase direct trades with entities in the Pacific Northwest, Rocky Mountains, and Desert Southwest at the same time trades decease with
California
California Trading Changes: Baseline+ to Expanded EDAM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy
Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains
WAPA CO/MO
WAPA Lower
CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Expanded EDAM Case
(Maximum EDAM Potential)
+35 TWh
with DSW
+8 TWh
with PNW
-10 TWh
with Existing
EDAM
Baseline+
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains
WAPA CO/MO
WAPA Lower
CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
brattle.com | 23
In the Split Market case, California trading
increases with existing EDAM members, but falls
with the Pacific Northwest and Southwest as those
regions shift to trading within the Markets+
footprint
Hydro entities in the Pacific Northwest export about
the same to California, but California exports about 1.5 TWh less to the PNW
California exports 6 TWh less to the Desert Southwest and imports 7 TWh less, reducing trading in both
directions
Trading with existing EDAM entities in the center of
the WECC increases about 5 TWh
Trading between EDAM entities within California also
increases about 3 TWh
California Trading Changes: Baseline+ to Split Market
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy
Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains
WAPA CO/MO
WAPA Lower
CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Split Market Case
(Likely EDAM Entities w/ Markets+)
-13 TWh
with DSW
-1 TWh
with PNW
+5 TWh
with Existing
EDAM
Baseline+
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains
WAPA CO/MO
WAPA Lower
CO
CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Appendix B:
Individual BAA Benefits
brattle.com | 25
Compared to the Baseline+ case, CAISO sees
benefits in the Expanded EDAM case of $471
million/yr compared to $171 million/yr in the
Split Market case
CAISO sees an APC benefits in both cases, though about $136 million more in EDAM
Short-term wheeling revenues fall more in the
Expanded EDAM case, declining $22 million from
Baseline+ to Split Market compared to the EDAM decline
of $60 million
Total trading revenues increase $134 million in the
EDAM case compared to just $3 million in the Split
Market case
Individual BA Benefits: CAISO
Summary of CAISO System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $4,642 $4,441 $4,115 $4,250
Short-Term Wheeling Revenues $171 $85 $25 $63
Trading Revenues
Bilateral Trading Revenues $111 $88 $23 $61
WEIM Congestion Revenues $47 $55 $41 $31
EDAM Congestion and Transfer Revenues $146 $185 $398 $238 EDAM Transfer Revenue $113 $112 $228 $123
EDAM Congestion Revenue $33 $72 $170 $115
Net TRR Settlement $9 $80 $9
Total System Production Cost and Market Revenues $4,167 $4,019 $3,548 $3,848 Benefit Relative to Baseline $148 $619 $319
Benefit % of Baseline Production Cost and Market Revenues 4% 15% 8% Benefit Relative to Baseline+ $471 $171
Benefit % of Baseline+ Production Cost and Market Revenues 12% 4% brattle.com | 26
CAISO’s adjusted production costs fall $326 million in the EDAM case, driven by:
(1) $112 million/yr reduction in production costs as CAISO generation declines on the net by ~1000 GWh (~2,000 GWh lower gas generation offset by ~1,000 GWh more renewables and other generation) (2) $40 million/yr increase in purchase costs as CAISO purchases about 2,900 GWh more in the day-ahead to offset declining gas generation (3) $250 million/yr increase in sales revenue as CAISO sells about 2,400 GWh more in the day-ahead and does so at an average price about $3.0/MWh higher than in Baseline+ CAISO Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
CAISO Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 295,759 294,762 -996 $4.17 $3.81 -$0.37 1,234,372 1,121,700 -$112,672 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 53,447 56,344 2,897 $56.04 $54.23 -$1.81 2,995,068 3,055,363 $60,295 Real-Time Market [5] 6,488 6,488 0 $41.38 $38.27 -$3.11 268,462 248,274 -$20,188 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 73,205 75,653 2,448 -$0.60 $2.44 $3.03 -43,575 184,255 $227,830 Real-Time Market [8] 6,054 5,506 -547 $16.65 $22.93 $6.28 100,804 126,274 $25,470 Total Cost (Negative Difference = Benefit) [9] 276,435 276,435 0 $16.06 $14.89 -$1.18 4,440,673 4,114,808 -$325,865 % Change in APC -7.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 27
CAISO’s APC falls $190 million in the Split Market case, driven by:
(1) $55 million/yr decrease in production cost due to gas generation falling by ~930 GWh (non-gas generation also declines, with renewable curtailments increasing ~260 GWh) (2) $67 million/yr decrease in purchase cost despite higher purchase volumes as the remaining EDAM market generation mix is renewable heavy
(3) $58 million/yr increase in sales revenue as volumes and average sales prices increase slightly due to opportunities to sell into EDAM and Markets+
CAISO Adjusted Production Cost in the Split Market Case (1)
(2)
(3)
CAISO Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 295,759 294,501 -1,258 $4.17 $4.01 -$0.17 1,234,372 1,179,767 -$54,605 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 53,447 54,741 1,294 $56.04 $53.94 -$2.09 2,995,068 2,952,969 -$42,099 Real-Time Market [5] 6,488 6,181 -307 $41.38 $39.34 -$2.04 268,462 243,149 -$25,312 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 73,205 73,593 388 -$0.60 $0.20 $0.79 -43,575 14,409 $57,984 Real-Time Market [8] 6,054 5,395 -659 $16.65 $20.59 $3.94 100,804 111,097 $10,293 Total Cost (Negative Difference = Benefit) [9] 276,435 276,435 0 $16.06 $15.38 -$0.69 4,440,673 4,250,380 -$190,292 % Change in APC -4.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 28
Compared to the Baseline+ case, LDWP sees a
benefit in the Expanded EDAM case of $66
million/yr compared to $18 million/yr in the
Split Market case
LDWP sees an APC benefits in both cases, $38 million
in EDAM and $18 million in the Split Market case
Short-term wheeling revenues decline most in the
Expanded EDAM case, falling $13 million
Total trading revenues increase $24 million in the
Expanded EDAM case compared to just $6 million in
the Split Market case
Individual BA Benefits: LDWP
Summary of LDWP System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $371 $354 $328 $336
Short-Term Wheeling Revenues $38 $13 $0 $6
Trading Revenues
Bilateral Trading Revenues $40 $39 $0 $17
WEIM Congestion Revenues $7 $9 $4 $5
EDAM Congestion and Transfer Revenues $17 $13 $81 $46
EDAM Transfer Revenue -$25 -$6 $17 -$8
EDAM Congestion Revenue $42 $19 $64 $54
Net TRR Settlement -$2 $26 -$2
Total System Production Cost and Market Revenues $269 $281 $216 $263 Benefit Relative to Baseline -$13 $53 $6
Benefit % of Baseline Production Cost and Market Revenues -5% 20% 2% Benefit Relative to Baseline+ $66 $18
Benefit % of Baseline+ Production Cost and Market Revenues 23% 6% brattle.com | 29
LDWP’s adjusted production costs fall $26 million in the EDAM case, driven by:
(1) $8.5 million/yr reduction in production costs as LDWP generation declines on the net by ~3 GWh (~120 GWh lower gas generation offset by ~117 GWh more renewables and other generation) (2) $14 million/yr decrease in purchase costs due to reduced average cost of purchasing in the EDAM market by about $2/MWh
(3) $3 million/yr increase in sales revenue as LDWP sells about 7 GWh more in the day-ahead and does so at an average price about $2.7/MWh higher than in Baseline+ LDWP Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
LDWP Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 21,157 21,154 -3 $1.29 $0.89 -$0.40 27,272 18,764 -$8,508 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 7,928 7,955 27 $46.43 $44.59 -$1.84 368,108 354,708 -$13,400 Real-Time Market [5] 431 412 -19 $27.01 $27.84 $0.83 11,642 11,466 -$176 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,067 1,074 7 -$7.72 -$5.01 $2.71 -8,237 -5,383 $2,854 Real-Time Market [8] 2,179 2,177 -2 $28.10 $28.72 $0.62 61,232 62,528 $1,296 Total Cost (Negative Difference = Benefit) [9] 26,270 26,270 0 $13.48 $12.48 -$1.00 354,027 327,793 -$26,235 % Change in APC -7.4%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 30
LDWP’s APC falls $18 million in the Split Market case, driven by:
(1) $0.3 million/yr decrease in production cost due to ~10 GWh of reduced gas generation (non-gas generation increases by ~40 GWh)
(2) $14 million/yr reduction in purchase costs as the remaining EDAM market is very renewable heavy renewable heavy
(3) $1 million/yr increase in sales revenue as volumes and average sales prices increase slightly due to opportunities to sell into EDAM and Markets+
LDWP Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
LDWP Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 21,157 21,204 47 $1.29 $1.27 -$0.02 27,272 27,004 -$269 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 7,928 7,952 24 $46.43 $44.53 -$1.91 368,108 354,077 -$14,031 Real-Time Market [5] 431 407 -24 $27.01 $27.97 $0.96 11,642 11,379 -$263 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,067 1,083 15 -$7.72 -$6.36 $1.36 -8,237 -6,886 $1,351 Real-Time Market [8] 2,179 2,210 32 $28.10 $28.56 $0.46 61,232 63,137 $1,905 Total Cost (Negative Difference = Benefit) [9] 26,270 26,270 0 $13.48 $12.80 -$0.68 354,027 336,209 -$17,819 % Change in APC -5.0%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 31
Compared to the Baseline+ case, BANC sees a
benefit in the Expanded EDAM case of $10
million/yr compared to a loss of $4 million/yr
in the Split Market case
BANC’s adjusted production cost remains about the
same in all three cases
Short-term wheeling revenues decline $4 million in
EDAM
Total trading revenues increase $10 million in the
Expanded EDAM case but decline $2 million in the Split
Market case
BANC benefits and results are not inclusive of SMUD,
which is reported separately
Individual BA Benefits: BANC
Summary of BANC System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $56 $57 $56 $59
Short-Term Wheeling Revenues $5 $4 $0 $4
Trading Revenues
Bilateral Trading Revenues $15 $10 $0 $8
WEIM Congestion Revenues $2 $1 $0 $1
EDAM Congestion and Transfer Revenues $0 $1 $21 $1
EDAM Transfer Revenue -$6 -$5 -$6 -$5
EDAM Congestion Revenue $7 $6 $27 $6
Net TRR Settlement -$1 $3 -$1
Total System Production Cost and Market Revenues $34 $42 $31 $46 Benefit Relative to Baseline -$8 $2 -$12
Benefit % of Baseline Production Cost and Market Revenues -23% 7% -36% Benefit Relative to Baseline+ $10 -$4
Benefit % of Baseline+ Production Cost and Market Revenues 24% -11% brattle.com | 32
BANC’s adjusted production costs fall $1.7 million in the EDAM case, driven by:
(1) $17 million/yr reduction in production costs as BANC generation declines on the net by ~260 GWh (~325 GWh lower gas generation offset by ~64 GWh more renewables and other generation) (2) $5 million/yr increase in purchase costs as BANC purchases about 140 GWh more in the day-ahead to offset declining gas generation and make additional market sales (3) $11 million/yr decrease in sales revenue due to ~$5/MWh decrease in day ahead market prices received
BANC Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
BANC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 6,206 5,944 -262 $12.63 $10.28 -$2.35 78,379 61,077 -$17,302 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 689 834 144 $44.22 $46.49 $2.27 30,483 38,755 $8,271 Real-Time Market [5] 303 247 -56 $42.32 $37.52 -$4.80 12,824 9,270 -$3,554 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,201 927 -274 $46.64 $41.74 -$4.90 56,015 38,684 -$17,331 Real-Time Market [8] 193 293 100 $42.69 $50.17 $7.48 8,224 14,704 $6,479 Total Cost (Negative Difference = Benefit) [9] 5,804 5,804 0 $9.90 $9.60 -$0.30 57,447 55,713 -$1,733 % Change in APC -3.0%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 33
BANC’s APC rises $1.6 million in the Split Market case, driven by:
(1) $11 million/yr reduction in production cost due to ~200 GWh decreased gas generation(non-gas generation falls also, with renewable curtailments increasing ~14 GWh), but does not offset revenue loss (2) $3 million/yr increase in purchase costs despite falling real time prices because of increased day ahead purchases
(3) $10 million/yr decrease in sales revenue as day-ahead sales volumes decrease and real-time volumes only increase by ~12 GWh
BANC Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
BANC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 6,206 5,994 -212 $12.63 $11.24 -$1.39 78,379 67,376 -$11,002 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 689 776 86 $44.22 $44.47 $0.25 30,483 34,497 $4,014 Real-Time Market [5] 303 288 -15 $42.32 $39.35 -$2.96 12,824 11,352 -$1,471 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,201 1,049 -152 $46.64 $42.57 -$4.07 56,015 44,653 -$11,361 Real-Time Market [8] 193 204 12 $42.69 $46.60 $3.91 8,224 9,530 $1,306 Total Cost (Negative Difference = Benefit) [9] 5,804 5,804 0 $9.90 $10.17 $0.28 57,447 59,043 $1,596 % Change in APC 2.8%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 34
Compared to the Baseline+ case, SMUD sees a
slight loss in the Expanded EDAM case of $9
million/yr compared to a benefit of $4
million/yr in the Split Market case
SMUD adjusted production cost remains about the
same in all three cases, but declines slightly more in
the Split Market case
Total trading revenues decline $6 million in the
Expanded EDAM case but increase $1 million in the
Split Market case due to increased internal California
trading
Individual BA Benefits: SMUD
Summary of SMUD System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $74 $73 $72 $70
Short-Term Wheeling Revenues $0 $0 $0 $0
Trading Revenues
Bilateral Trading Revenues $16 $15 $0 $15
WEIM Congestion Revenues $4 $4 $4 $4
EDAM Congestion and Transfer Revenues $6 $6 $15 $7
EDAM Transfer Revenue $3 $4 $11 $3
EDAM Congestion Revenue $3 $2 $5 $4
Net TRR Settlement -$1 -$6 -$1
Total System Production Cost and Market Revenues $48 $49 $58 $45 Benefit Relative to Baseline -$1 -$11 $2
Benefit % of Baseline Production Cost and Market Revenues -3% -22% 5% Benefit Relative to Baseline+ -$9 $4
Benefit % of Baseline+ Production Cost and Market Revenues -18% 8% brattle.com | 35
SMUD’s adjusted production costs fall $1 million in the EDAM case, driven by:
(1) $0.1 million/yr increase in production costs as SMUD generation increases by ~100 GWh, mostly from renewables and geothermal
(2) $3 million/yr increase in purchase costs as SMUD purchases about 60 GWh more in the day-ahead (3) $4 million/yr increase in sales revenue as SMUD sells about 200 GWh more in the day-ahead and does so at an average price about $0.1/MWh higher than in Baseline+ SMUD Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
SMUD Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 12,180 12,289 109 $0.82 $0.83 $0.00 10,044 10,179 $135 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 2,022 2,081 59 $50.40 $51.49 $1.10 101,888 107,144 $5,256 Real-Time Market [5] 861 802 -59 $41.24 $41.52 $0.28 35,520 33,317 -$2,203 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 2,101 2,283 182 $25.26 $25.38 $0.12 53,069 57,934 $4,866 Real-Time Market [8] 707 634 -73 $30.67 $33.22 $2.55 21,679 21,053 -$626 Total Cost (Negative Difference = Benefit) [9] 12,255 12,255 0 $5.93 $5.85 -$0.09 72,704 71,652 -$1,052 % Change in APC -1.4%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 36
SMUD’s APC falls $2 million in the Split Market case, driven by:
(1) $13 million/yr increase in production cost due to a reduction of ~6 GWh of generation (2) $4 million/yr decrease in purchases cost because of slight reductions in price and volume in the day-ahead and real-time markets
(3) $2 million/yr reduction in sales revenues due to a $1.3/MWh drop in day-ahead prices and ~50 GWh fewer sales in the real-time market
SMUD Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
SMUD Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 12,180 12,174 -6 $0.82 $0.83 $0.00 10,044 10,056 $13 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 2,022 2,015 -7 $50.40 $49.16 -$1.24 101,888 99,068 -$2,820 Real-Time Market [5] 861 855 -6 $41.24 $39.91 -$1.33 35,520 34,121 -$1,399 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 2,101 2,128 28 $25.26 $23.98 -$1.28 53,069 51,040 -$2,029 Real-Time Market [8] 707 660 -47 $30.67 $33.15 $2.48 21,679 21,875 $195 Total Cost (Negative Difference = Benefit) [9] 12,255 12,255 0 $5.93 $5.74 -$0.19 72,704 70,330 -$2,373 % Change in APC -3.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 37
Compared to the Baseline+ case, IID sees a
benefit in the Expanded EDAM case of $18
million/yr compared to a loss of $9 million/yr
in the Split Market case
IID’s adjusted production cost doesn’t change in the
Expanded EDAM case, but increases $9 million in the
Split Market case
Short-term wheeling revenues decline $6 million in
EDAM and increase $6 million in the Split Market case
Total trading revenues increase $13 million in the
Expanded EDAM case but decline $3 million in the Split
Market case
Individual BA Benefits: IID
Summary of IID System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost -$83 -$85 -$85 -$74
Short-Term Wheeling Revenues $13 $5 $0 $11
Trading Revenues
Bilateral Trading Revenues $15 $4 $0 $4
WEIM Congestion Revenues $6 $3 $5 $0
EDAM Congestion and Transfer Revenues $0 $0 $15 $0
EDAM Transfer Revenue $0 $0 $6 $0
EDAM Congestion Revenue $0 $0 $9 $0
Net TRR Settlement $11
Total System Production Cost and Market Revenues -$116 -$97 -$115 -$89 Benefit Relative to Baseline -$19 -$1 -$27
Benefit % of Baseline Production Cost and Market Revenues 16% -1% -23% Benefit Relative to Baseline+ $18 -$9
Benefit % of Baseline+ Production Cost and Market Revenues 18% -9% brattle.com | 38
IID’s adjusted production costs remains relatively steady, due to:
(1) $0.2 million/yr reduction in production costs as IID generation increases by ~45 GWh, all from renewable and other non-gas generation
(2) $5 million/yr decrease in purchase costs as IID purchases about 100 GWh more in the day-ahead and reduces sales in the real time market
(3) $5 million/yr decrease in sales revenue as BANC reduces sales volume by ~240 GWh in the real time market despite increased prices
IID Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
IID Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 7,301 7,346 45 $5.81 $5.79 -$0.01 42,401 42,551 $150 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 478 635 157 -$3.09 -$2.87 $0.22 -1,477 -1,823 -$345 Real-Time Market [5] 858 520 -338 $21.90 $28.14 $6.24 18,778 14,631 -$4,147 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 3,068 3,176 108 $40.50 $39.44 -$1.07 124,249 125,245 $997 Real-Time Market [8] 733 489 -244 $28.17 $29.96 $1.79 20,645 14,640 -$6,005 Total Cost (Negative Difference = Benefit) [9] 4,837 4,837 0 -$17.61 -$17.48 $0.14 -85,191 -84,525 $666 % Change in APC -0.8%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 39
IID’s APC increases $11 million in the Split Market case, driven by:
(1) $0.3 million/yr increase in production cost due to limited shifts in production and prices (2) $20 million/yr decrease in purchases cost as the remaining EDAM market is very renewable heavy, resulting in a $12/MWh decrease in day-ahead prices
(3) $31 million/yr decrease in sales revenue as IID reduces sales by ~840 GWh across day-ahead and real-time markets
IID Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
IID Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 7,301 7,399 98 $5.81 $5.77 -$0.04 42,401 42,674 $273 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 478 247 -231 -$3.09 -$14.68 -$11.59 -1,477 -3,623 -$2,146 Real-Time Market [5] 858 155 -703 $21.90 $2.70 -$19.20 18,778 418 -$18,361 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 3,068 2,893 -175 $40.50 $38.70 -$1.80 124,249 111,976 -$12,273 Real-Time Market [8] 733 71 -662 $28.17 $19.58 -$8.59 20,645 1,385 -$19,260 Total Cost (Negative Difference = Benefit) [9] 4,837 4,837 0 -$17.61 -$15.28 $2.34 -85,191 -73,892 $11,299 % Change in APC -13.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 40
Compared to the Baseline+ case, TIDC sees
a benefit in the Expanded EDAM case of
$17 million/yr compared to $2 million/yr in
the Split Market case
TIDC’s adjusted production cost declines $12
million in the Expanded EDAM case but just $2
million in the Split Market case
Total trading revenues increase $6 million in the
Expanded EDAM case and don’t change in the
Split Market case
Individual BA Benefits: TIDC
Summary of TIDC System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $112 $112 $100 $110
Short-Term Wheeling Revenues $0 $0 $0 $0
Trading Revenues
Bilateral Trading Revenues $1 $1 $0 $1
WEIM Congestion Revenues $1 $0 $0 $0
EDAM Congestion and Transfer Revenues $0 $0 $7 $0
EDAM Transfer Revenue $0 $0 -$2 $0
EDAM Congestion Revenue $0 $0 $8 $0
Net TRR Settlement -$2
Total System Production Cost and Market Revenues $110 $111 $95 $109 Benefit Relative to Baseline -$2 $15 $1
Benefit % of Baseline Production Cost and Market Revenues -1% 14% 1% Benefit Relative to Baseline+ $17 $2
Benefit % of Baseline+ Production Cost and Market Revenues 15% 2% brattle.com | 41
TIDC’s adjusted production costs fall $12 million in the EDAM case, driven by:
(1) $44 million/yr reduction in production costs as TIDC’s gas generation declines by ~575 GWh (2) $30 million/yr increase in purchase costs as TIDC purchases about 710 GWh more in the day-ahead to offset declining gas generation
(3) $0.4 million/yr decrease in sales revenue and reduces day ahead sales given the large price drop of $59/MWh in the day ahead market
TIDC Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
TIDC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 1,664 1,089 -575 $28.48 $3.24 -$25.24 47,383 3,529 -$43,854 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 1,439 2,150 711 $40.01 $44.91 $4.90 57,582 96,556 $38,974 Real-Time Market [5] 144 2 -141 $54.34 $67.78 $13.44 7,804 144 -$7,660 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 9 0 -8 $73.37 $14.18 -$59.19 625 3 -$623 Real-Time Market [8] 3 6 3 $71.28 $88.53 $17.25 207 490 $283 Total Cost (Negative Difference = Benefit) [9] 3,235 3,235 0 $34.60 $30.83 -$3.77 111,937 99,736 -$12,201 % Change in APC -10.9%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment. brattle.com | 42
TIDC’s APC falls $2 million in the Split Market case, driven by:
(1) $4 million/yr decrease in production cost due to ~50 GWh reduction of gas generation (TIDC does not have renewable generation)
(2) $2 million/yr increase in purchases cost because of ~94 GWh of increased purchases to compensate for gas generation reduction
(3) $0.1 million/yr increase in sales revenue caused by increases in real-time revenues despite a $2.9/MWh decrease in day-ahead prices
TIDC Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
TIDC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 1,664 1,617 -47 $28.48 $26.74 -$1.74 47,383 43,237 -$4,147 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 1,439 1,533 94 $40.01 $40.68 $0.67 57,582 62,366 $4,785 Real-Time Market [5] 144 98 -46 $54.34 $54.32 -$0.02 7,804 5,328 -$2,476 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 9 4 -4 $73.37 $70.47 -$2.90 625 289 -$336 Real-Time Market [8] 3 9 6 $71.28 $72.23 $0.95 207 622 $416 Total Cost (Negative Difference = Benefit) [9] 3,235 3,235 0 $34.60 $34.01 -$0.59 111,937 110,019 -$1,918 % Change in APC -1.7%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.
Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.
Appendix C:
Description of Benefit Metrics
The APC is calculated for the BAU cases and the market cases to determine the market related reductions in APC
By using the generation price of the exporter and load price of the importer for sales revenues and purchase costs, the APC metric does not capture wheeling revenues and the remaining portion of the value of the trade to the counterparties (see next slide) Benefit Metric: Adjusted Production Cost
brattle.com | 44
The APC is the sum of production costs and purchased power less off-system sales revenue:
(+) Production costs (fuel, startup, variable O&M, emissions costs) for generation owned or contracted by the load-serving entities (+) Cost of bilateral and market purchases valued at the BAA’s load-weighted energy price (“Load LMP”) (−) Revenues from bilateral and market sales valued at the BAA’s generation-weighted energy price (“Gen LMP”) Adjusted Production Cost (APC) is a standard metric used to capture the direct variable energy-related costs from a customer impact perspective brattle.com | 45
Based on the simulation results, we also estimate several additional impacts from increased trading facilitated by the market reforms, which is not fully captured in APC Wheeling Revenues: collected by the exporting BAAs based on OATT rates Trading Gains: buyer and seller split 50/50 the trading margin (and congestion revenues in EIM/EDAM) EXAMPLE: Bilateral Trade
Benefit Metrics: Wheeling Revenues, Trading Gains
A sells
50 MWh A to B
Internal
Gen Price
$30/MWh
B
Internal
Load Price
$50/MWh
The APC metric only uses area-internal prices for purchase cost and sales revenues, which does not capture part of the value:
• A receives $30×50MWh=$1,500 in APC sales revenues
• B pays $50×50MWh=$2,500 in APC purchase costs
$1,000 of trading value not captured in APC metric
Trading value = $20/MWh Δprice x 50 MWh = $1000
• Exporter A receives wheeling revenues: $8/MWhx50MWh = $400 • Remaining $600 trading gain split 50/50: both A and B receive $300 $8/MWh
Wheeling Charge
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Illustration of Markets+ Congestion Revenues
BA1
(exporter)
BA2
(importer)
Avg. Gen Cost = fuel
+ variable O&M
Gen LMP = Sales revenue
to BA generators
Load LMP = Purchase cost
to serve load
Avg. Gen Cost
Gen LMP
Load LMP
Markets+ congestion revenues are
rolled together and estimated
based on BA load and gen LMPs:
• The BAA is assumed to own all rights
on congested paths within their BAA,
unless we have information on third-party contracts.
• Similarly, unless we have information
on third-party contracts, we assume
congestion between market
members is owned 50/50 by the two
BAAs
• Congestion/Transfer Revenue
Payment (split 50/50) = MW x (Load
LMP2 – Gen LMP1)
brattle.com | 47
Illustration of EDAM Congestion and Transfer Revenues
BA1
(exporter)
BA2
(importer)
Avg. Gen Cost = fuel
+ variable O&M
Gen LMP = Sales revenue
to BA generators
Load LMP = Purchase cost
to serve load
Avg. Gen Cost
Gen LMP
Load LMP
EDAM congestion and transfer
revenues estimated based on
individual tieline LMPs:
• Congestion Payment (to exporter)
= MW x (Tie LMP1 – Gen LMP1)
• Congestion Payment (to importer)
= MW x (Load LMP2 – Tie LMP2)
• Transfer Payment (split 50/50)
= MW x (Tie LMP2 – Tie LMP1)
Tieline LMP2-LMP1
Transfer payments
brattle.com | 48
Illustration of Congestion/Transfer Revenues vs. APC
Generators and loads get paid/pay the prices within their BAAs • Therefore, congestion on internal transfers (between a member’s own gen and load) is captured in the APC metric. • However, congestion/transfer revenue on external transactions (to neighboring members) is not captured in APC. • In the example below, for an external market transaction, the selling BAA has a price of $25 and the purchasing BAA has a price of $45.
o The $20 difference between the seller and buyer is the congestion and transfer revenue. o $5/MWh of congestion revenue is allocated to the seller ($30 on their side of the intertie less $25 internal gen price) o $8/MWh of congestion revenue is allocated to the buyer ($45 internal load price less $37 on their side of the intertie) o $7/MWh of transfer revenue is split 50/50 between the buyer and seller ($37 on the buyer side of the intertie less $30 on the seller side)
G L
$25 $45
Tiepoint
$30 $37
Exporting BAA Importing BAA
100 MW 100 MW
Sales revenue of
export reflected
in APC = $2,500
$5/MWh Congestion
Revenues = $500
$8/MWh Congestion
Revenues = $800
$7/MWh Transfer
Revenues = $700
(50/50 split between BAAs)
Purchase cost of
import reflected
in APC = $4,500
$20/MWh Value of Transaction not Captured in APC = $2,000 Appendix D:
Overview of Power System
Optimizer (PSO)
brattle.com | 50
Modeling assumptions based on public sources and refined with input from study participants Key Modeling Assumption Sources
Assumption Category California Rest of WECC
Resource Mix • CAISO resource mix assumptions reflect the 2023- 2024 CAISO TPP portfolio
• LADWP and BANC/SMUD provided resource mix
assumptions directly during the 2022
• Participant updates for El Paso Electric, Idaho Power, NV Energy, Portland General Electric, PacifiCorp, Public
Service Company of New Mexico
• Recent IRP updates for Arizona Public Service, Tucson Electric Power, Avista, and Puget Sound Energy
Load • CAISO load assumptions are based on the 2022 IEPR mid baseline load forecast
• LADWP and BANC/SMUD provided resource mix
assumptions
GHG Prices • GHG prices are based on the CEC’s 2022 mid case, with the modeled CA & WA price in 2032 at ~$64/metric ton • We assume the WA and CA carbon markets are linked by 2032 Natural Gas Prices • Gas prices were provided by the study participants in prior iterations of EDAM/Markets+ studies.
Transmission • Participant updates for specific projects, and addition of interregional projects anticipated to be online by 2032, including SunZia, SWIP-N, TransWest Express, Cross-Tie, Greenlink North & West, B2H, Gateway Projects • Enforced physical limits include WECC-rated paths and specific constraints identified by pariticpants • Contract path limits based on public data and participant input and enforced for all BA-to-BA connections Utilized the Polaris Power System Optimizer (PSO), an advanced market simulation model Nodal mixed-integer model representing each load and generator bus in the WECC Licensed through Enelytix
Detailed operating reserve and ancillary service product definition Detailed representation of the transmission system (both physical power flows and contract paths) Sub-hourly granularity (but used hourly simulations due to limited data availability) Designed for multiple commitment and dispatch cycles (e.g., DA and RT) with different levels of foresight
EDAM feasibility study assumptions updated to reflect the most recent utility resource plans and forecasts of system conditions and costs
PSO is uniquely suited to simulate bilateral trading, joint dispatch, imbalance markets, and RTOs, reflecting multiple stages of system operator decision making
Overview of Modeling Approach
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We utilize the WECC ADS nodal production cost model as a starting point imported into Power System Optimizer (PSO), as refined during the EDAM feasibility study and follow-on engagements
brattle.com | 52
PSO simulates multiple independent decision cycles to capture day-ahead vs. real-time unit commitment and dispatch
Independent Simulation of Multiple Time Horizons
Independent real-time decision cycle
used to simulate DA vs. RT, including
forecast errors for wind and solar
Real Time Cycle
DA Bilateral
Markets
DA block trades on
long-term
transmission rights
and incremental
transmission
D-1 (am)
Day-Ahead
Market
Intra-Day
Markets
EIM
(RT Balancing)
• CAISO, EDAM, and
RTO market clearing
• Hourly intertie trading
• Hourly trading with
long-term
transmission rights
• Hourly bilateral
trades on remaining
transmission
• WEIM/WEIS/RTO
trading of economic
energy
• Remaining Tx
released for
WEIM/WEIS
• RT balancing in BAAs
D-1 (~noon) D-1 (pm-D) D
Unit Commitment Cycle Economic Dispatch Cycle
Decision cycles capture bilateral trading, market
clearing, BAA functions in DA and RT, and market cycles (EDAM “GHG reference” pass, EDAM market, and EIM)
Independent real-time decision cycle
used to simulation
EIM functions
brattle.com | 53
Day-Ahead Unit Commitment Cycle: the model optimizes unit commitment decisions, 24 hours at a time (with 48-hour look ahead), for long-lead time resources such as coal and nuclear plants, based on their relative economics and operating characteristics (e.g., minimum run time, maintenance schedules, etc.), transmission constraints, and trading frictions. The model ensures that enough resources are committed to serve forecasted load, accounting for average transmission losses and the need for ancillary services. Separate regions’ commitment decisions are segregated through higher hurdle rates on imports and exports. Trading within a single balancing area, like the various RTO sub-zones, is not subject to any hurdles.
Day-Ahead Economic Dispatch Cycle: the model solves for the optimal level of hourly day-ahead dispatch and trading in 24-hour forward-looking optimization cycles, with 48-hour look ahead periods. Dispatch across the study footprint is optimized based on resource economics. In this cycle, the model also co-optimizes ancillary service procurement for each area. The high hurdle rates for unit commitment are lowered to enable more bilateral trading between balancing areas. Intra-day trading: the model simulates market activity through one-hour optimization horizons. Trading is assumed to utilize unused transmission, represented as the difference between their day-ahead trading volume and the total contract path limits.
No unit re-commitment is allowed due to the non-firm nature of the transactions. Changes to generation availability, such as forced outages, which were not “visible” during the day-ahead cycle become visible during this cycle.
Real-Time Cycle: this cycle simulates the operation of the real-time imbalance markets, such as through EIM transactions. In this cycle, the model can re-optimize dispatch levels and unit commitment decisions for fast-start thermal resources (based on the assumption that the real-time market design allows for unit re-commitment). Deviations from day-ahead forecasts (due to uncertainty) need to be balanced in real-time.
The model setup for wholesale market simulation effort contains several cycles to simulate unit commitment and dispatch decisions in three different timeframes and within different market structures. For example, cycles simulated can include are:
These cycles can take on different assumptions, depending on market structure. In a bilateral setting, all are set up to analyze utility-specific unit commitment and dispatch decisions, with each of them including hurdle rates and transmission fees that limit the amount of economic transactions that can take place between the utilities. In EIM and EDAM+EIM scenarios, all of the cycles are set up to simulate market-wide optimization of unit commitment and dispatch, including the EDAM “reference pass” cycle. In the EDAM case, there would be no hurdle rates between EDAM participants in any of the cycles, allowing the model to optimize both unit commitment and dispatch in the market footprint on both a day-ahead and real-time basis.
Simulating Several Wholesale Market Cycles in PSO
Types of Trades and Transmission Reservations Modelled
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Types of Trades Modeled
Unscheduled/unsold Transmission
EIM Trades
Total Transmission Capability (TTC)
Block Trades on ETCs
Block Trades on Incremental
Transmission
Hourly Bilateral Trades on ETCs
Hourly Bilateral Trades on Incremental
Transmission
Hourly EDAM, CAISO DA Intertie Trades
The model simulates the use of different
types of contract-path transmission
reservations for bilateral trading in DA and RT
• Existing long-term transmission contracts (ETCs) and
incrementally purchased transmission
• Total reservations on each contract path is limited by the total transfer capability (TTC)
• Trades are structured as blocks or hourly
• Bilateral trades between BAAs, at major hubs, or
across CAISO interties
• Account for renewable diversity and day-ahead
forecast uncertainty vs. real-time operations
• Unscheduled transfer capability released for EIM
trades in real-time
brattle.com | 55
Nodal Simulations Based on Physical Transmission
WECC-Defined Paths Modeled
Limits on the physical transmission
system include all the paths defined in
WECC Path Rating Catalogue
• Additional transmission paths to represent
congestion internal to each BA
• Limits on all paths and constraints reflect
updates provided by the study participants
75 Power System Optimizer (PSO), developed by Polaris Systems Optimization, Inc. is a state-of-the-art market and production cost modeling tool that simulates least-cost security-constrained unit commitment and economic dispatch with a full nodal representation of the transmission system, similar to actual RTO and ISO market operations. Such nodal market modeling is a commonly used method for assessing the operational benefits of wholesale market reforms (e.g., JDAs, EIMs, RTOs).
PSO can be used to test system operations under varying assumptions, including but not limited to: generation and transmission additions or retirements, de-pancaked transmission and scheduling charges, changes in fuel costs, novel environmental and clean energy regulations, alternative reliability criteria, and jointly-optimized generating unit commitment and dispatch. PSO can report hourly or sub-hourly energy prices at every bus, generation output for each unit, flows over all transmission facilities, and regional ancillary service prices, among other results. Comparing these results among multiple modeled scenarios reveals the impacts of the study assumptions on the relevant operational metrics (e.g. power production, emissions, fuel consumption, or production costs). Results can be aggregated on a unit, state, utility, or regional level.
PSO has important advantages over traditional production cost models, which are designed primarily to model dispatchable thermal generation and to focus on wholesale energy markets only. The model can capture the effects of increasing system variability due to large penetrations of non-dispatchable, intermittent renewable resources on thermal unit commitment, dispatch, and deployment of operating reserves. PSO simultaneously optimizes energy and multiple ancillary services markets on an hourly or sub-hourly timeframe.
brattle.com | 56
Like other production cost models, PSO is designed to mimic ISO operations: it commits and dispatches individual generating units to meet load and other system requirements, subject to various operational and transmission constraints. The model is a mixed-integer program minimizing system-wide operating costs given a set of assumptions on system conditions (e.g., load, fuel prices, transmission availability, etc.). Unlike some production cost models, PSO simulates trading between balancing areas based on contract-path transmission rights to create a more realistic and accurate representation of actual trading opportunities and transactions costs. This feature is especially important for modeling non-RTO regions.
One of PSO’s distinguishing features is its ability to evaluate system operations at different decision points, represented as “cycles,” which occur at different times ahead of the operating hour and with different amounts of information about system conditions available. Under this sequential decision-making structure, PSO can simulate initial cycles to optimize unit commitment, calculate losses, and solve for day-ahead unit dispatch targets. Subsequent cycles can refine unit commitment decisions for fast-start resources and re-optimize unit dispatch based on the parameters of real-time energy imbalance markets. The market structure can be built into sequential cycles in the model to represent actual system operation for utilities that conduct utility-specific unit commitment in the day-ahead period but participate in real-time energy imbalance markets that allow for re-optimization of dispatch and some limited re-optimization of unit commitment. For example, PSO can simulate an initial cycle that determines day-ahead unit commitment decisions that reflects the constraints faced by, and decisions made by, individual utilities when committing their resources in the day-ahead timeframe. The initial day-ahead commitment cycle is followed by cycles that simulate day-ahead economic dispatch, including bilateral trading of power, and a real-time economic dispatch, reflecting trades in real time (whether bilateral or optimized through an EIM or RTO). Explicit commitment and dispatch cycle modeling allows more accurate representation of individual utility preference to commit local resources for reliability, but share the provision of energy around a given commitment.
January 2025
According to the California Legislative Analyst’s Office January 2025 report, California’s residential electricity rates are the second highest in the nation (after Hawaii) and “close to double those in the rest of the nation.” Increasing rates are largely driven by rising distribution and transmission costs.
Between 2020 and 2023, investor-owned utilities’ distribution revenue requirement grew by 42% and transmission by 34%. In comparison, IOU generation costs grew only 4%. Meeting California’s energy goals requires affordable rates that encourage increased electrification. Community choice aggregators (CCAs) across the state are dedicated to reducing consumer costs while preserving climate goals. CCAs have identified three opportunities where policymakers could provide ratepayer relief now and in the future.
1. Leverage the Greenhouse Gas Reduction Fund (GGRF) to Support Affordability California’s quarterly cap-and-trade greenhouse gas allowance auctions generate an average of $4.2 billion annually for the state’s GGRF. The Legislature appropriates these funds for a variety of purposes; roughly 65% are continuous appropriations and the remainder is available for discretionary appropriation. Separately, IOUs receive an allocation of allowances from the Air Resources Board that they monetize in the auction. For 2022, the allocation produced $1.4 billion for distribution to customers in the form of the California Climate Credit.
Investments of GGRF funds to boost the California Climate Credit can provide immediate ratepayer relief. An additional $650 million per year in GGRF funding would increase the Climate Credit by approximately $60 annually per household. The credits could be provided to customers monthly or allocated for the four summer months (June-September) when electricity rates are highest. • Alternatively, GGRF funds could be allocated for policy-driven transmission projects that are approved by the California Independent System Operator in the grid operator’s annual Transmission Plan. This would support affordability in the future by buying down the costs of building transmission infrastructure vital to the achieving the state’s climate goals.
2. Reduce Ratepayer Costs by Reducing Artificial Resource Adequacy Demand California load-serving entities (LSEs) must meet their resource adequacy (RA) obligations on an hourly basis but are required to transact with a resource for all hours that it provides RA. If an LSE is short of RA in only one hour, for example, it may be required to procure RA for the full 16 hours a resource operates to fill that hour. This mismatch leads to unnecessary costs for ratepayers due to overprocurement, higher RA prices driven by artificial demand, and non-compliance penalties levied upon LSEs.
• Permitting LSEs to trade hourly load obligations would reduce the cost of RA procured to meet customer requirements through lower prices, less overprocurement, and fewer penalties, which, for non-profit LSEs, flow through directly to customers. CalCCA estimates that adopting hourly load obligation trading would save California ratepayers over $180 million annually.
Electricity Affordability
3. Increase Accountability and Transparency
The California Public Utilities Commission (CPUC) is responsible for regulating IOUs and implementing policies as directed by the Legislature. The Legislature can encourage long-term fiscal discipline by implementing recommendations included in the California State Auditor (CSA) report on the CPUC and expanding the requirements for considering the impact of the Commission’s actions on affordability.
• CPUC Affordability Analysis. Requiring the Commission to publish an “Affordability Analysis” for each major policy change it proposes would increase awareness of the affordability impacts of CPUC decision-making. When considering changes to existing policies or implementing new policies, the CPUC should be required to quantify the potential rate impacts associated with a proposed policy and consider potential alternatives and their price tag. • Audits of IOU Balancing Accounts. The CSA report recommends more frequent audits of spending tracked and costs recovered via IOU balancing accounts. The Legislature should implement this recommendation and adopt new requirements for the California Public Advocates Office (PAO) and CPUC to review and audit IOU balancing accounts that (1) present a risk of a material rate increase and (2) present a risk of double recovery.
• Enhance Oversight of IOU Rate of Return. Because rates are set on a forecast basis, an IOU’s actual rate of return may exceed its authorized rate of return. The Legislature should direct an annual CPUC review of actual IOU returns and provide a report explaining the factors contributing to any excess return. The Legislature further should direct the CPUC to increase verification of IOU work to ensure the IOU is spending its authorized budget as proposed in its General Rate Case.
• Adequately Fund the CPUC and PAO. The CPUC and PAO require sufficient funding to ensure each has the resources necessary to adequately scrutinize utility spending requests. With more resources, the CPUC and PAO are better able to process utility spending requests and audit actual spending. Greater oversight will encourage IOU spending discipline.
Executive Order Summary
Wind Energy Moratorium (Signed January 20, 2025)
• Withdraws all areas of the Outer Continental Shelf from new or renewed wind energy leasing. The withdrawal does not affect “rights under existing leases in the withdrawn areas.”
• Directs the Attorney General and the Interior Secretary to “conduct a comprehensive review of the ecological, economic, and environmental necessity of terminating or amending any existing wind energy leases, (and) identifying any legal bases for such removal.” There is no explicit timeline for when this review must be completed. • Prohibits agencies from issuing “new or renewed approvals, rights of way, permits, leases, or loans for onshore or offshore wind projects pending the completion of a comprehensive assessment and review of Federal wind leasing and permitting practices.” There is no explicit timeline for when this review must be completed. • Directs Interior to place a temporary moratorium on the Lava Ridge Wind Project in Idaho’s Magic Valley while Interior reviews the Record of Decision related to BLM’s final Environmental Impact Statement for this project.
• According to the federal permitting dashboard, there were seven offshore wind projects whose permitting was underway (all on the East Coast) and several more in earlier stages (5 off the California coast) at the time of this order.
• According to a recent NREL study, only about 4% of total utility-scale land-based renewable energy (wind, solar, geothermal) is generated on federal lands.
Declaring A National Energy Emergency (Signed January 20, 2025) • Citing an “inadequate and intermittent energy supply,” this order declares a national emergency.
• The term “energy” or “energy resources” in this order is defined as: crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, coal, biofuels, geothermal heat, the kinetic movement of flowing water, and critical minerals.
Note no inclusion of wind, solar, or storage.
• The order calls out the U.S. Northeast and West Coast regions specifically, claiming that “dangerous” state and local policies in those regions “jeopardize our Nation’s core national defense and security needs, and devastate the prosperity of not only local residents but the entire United States population.”
• Directs agencies to use existing “lawful” emergency authorities “to facilitate the identification, leasing, siting, production, transportation, refining, and generation of domestic energy resources.”
• Directs agencies to identify and use existing emergency authorities “to facilitate the supply, refining, and transportation of energy in and through the West Coast of the United States, Northeast of the United States, and Alaska.”
Executive Order Summary
• Tasks the Army Corps and other agencies to identify and report on all “planned or potential” energy projects that could be considered for emergency treatment and expedited permitting under the Clean Water Act and Endangered Species Act. • Directs the Defense and Interior Departments to assess and report on DOD’s “ability to acquire and transport the energy, electricity, or fuels needed to protect the homeland and to conduct operations abroad.” The assessment is directed to examine “potentially insufficient (energy) transportation and refining infrastructure” nationwide, with a specific focus on “such vulnerabilities within the Northeast and West Coast.” Unleashing American Energy (Signed January 20, 2025)
• Establishes the policy of the U.S. to encourage energy exploration and production on Federal lands and waters, eliminate the “electric vehicle (EV) mandate,” and promote consumer choice in vehicles and appliances, among other things. • Directs all agencies to review all existing regulations and policies to identify those that impose an “undue burden” on the development of domestic energy resources — with particular attention to oil, natural gas, coal, hydropower, biofuels, critical mineral, and nuclear energy resources.
• Directs agencies to prioritize “efficiency and certainty” over any other objectives that could otherwise “add delays and ambiguity” to the energy permitting process. Orders agencies to “undertake all available efforts to eliminate all delays within their respective permitting processes” and allows agencies to use emergency authorities to expedite permitting for energy projects they deem “essential for the Nation’s economy or national security.” • Orders all agencies to “immediately pause the disbursement of funds” appropriated through the IRA or IIJA. An OMB memo later clarified that the guidance in this section only applies to grants and loans, not tax credits.
Putting America First In International Environmental Agreements (Signed January 20, 2025) • Directs the U.S. Ambassador to the United Nations to formally withdraw the U.S. from the Paris Climate Agreement and revoke any “purported financial commitment” made by the U.S. under the UN’s framework, effective immediately. The agreement, adopted by 196 countries at COP21 in December 2015, aims to hold the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels. • Orders any agency that plans or coordinates international energy agreements to “prioritize economic efficiency, the promotion of American prosperity, consumer choice, and fiscal restraint in all foreign engagements that concern energy policy.” Imposing Duties to Address the Flow of Illicit Drugs Across Our Northern Border (Signed February 1, 2025)
Executive Order Summary
• Imposes an additional 25% tariff on all goods imported from Canada – excluding energy imports, which are subject to an additional 10% tariff – beginning on February 4, 2025. The enforcement of this order was later delayed 30 days on February 3, 2025.
Imposing Duties to Address the Synthetic Opioid Supply Chain in the People’s Republic of China (Signed February 1, 2025)
• Imposes an additional 10% tariff on all goods imported from China beginning on February 4, 2025. This includes major imports from China like solar panels, batteries and electronics. • In response, China announced a raft of retaliatory actions, including a 15% tariff on U.S. coal and liquefied natural gas products as well as a 10% tariff on crude oil, agricultural machinery and large-engine cars, which took effect on February 10. China also announced added export controls on several critical minerals used to make popular electronic equipment, as well as an antitrust investigation into Google.
Imposing Duties to Address the Situation at Our Southern Border (Signed February 1, 2025) • Imposes an additional 25% tariff on all goods imported from Mexico beginning on February 4, 2025. The enforcement of this order was later delayed 30 days on February 3, 2025.
Adjusting Imports of Aluminum into The United States (Signed February 11, 2025) • Increases the tariff rate on all imported aluminum to 25% for all nations beginning March 12, 2025.
Adjusting Imports of Steel into The United States (Signed February 10, 2025) • Increases the tariff rate on all imported steel to 25% for all nations beginning March 12, 2025.
Establishing the National Energy Dominance Council (Signed February 14, 2025) • Will advise the President on how to make the country more energy dominant (with specific attention to crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, coal, biofuels, geothermal heat, the kinetic movement of flowing water, and critical minerals). Within 100 days, the council must recommend to the President how to “rapidly and significantly increase electricity capacity,” and on how to rapidly approve energy infrastructure (and undefined term, but likely references oil and gas). The council must consult with officials from state, local, and tribal governments and individuals from the private sector to solicit feedback on how best to expand all forms of energy production. DOE is Vice Chair.
Ensuring Accountability for All Agencies (Signed February 18, 2025) Executive Order Summary
• Establishes the policy of the executive branch to increase Presidential oversight and control of all federal agencies, including independent regulatory agencies and commissions, by:
o Requiring agencies to submit all proposed and final regulatory actions to the White House for review and approval by the President and the OMB Director; o Tasking the OMB Director with establishing performance standards and management objectives for independent agency heads and to report to the President on their performance;
o Ordering the OMB Director to review and adjust independent agencies’ funding obligations;
o Requiring all independent agencies to install a “White House Liaison” position within their respective agencies; and
o Giving the President and the Attorney General ultimate authority to interpret the law for the executive branch.
© Aurora Energy Research Ltd. – CONFIDENTIAL
Impact of reform to clean
energy tax credits on
investment, jobs and
consumer bills
Public report | January 6, 2025
2 This independent report analyses the potential impact of reform to clean energy tax credits on investment, jobs, and consumer bills ▪ The Inflation Reduction Act of 2022 (IRA) extended and expanded the Clean Energy Tax Incentives available to businesses, in particular 48E, the technology-neutral Investment Tax Credit (ITC) and 45Y, the technology-neutral Production Tax Credit (PTC) ▪ This report quantifies the impacts of removing the ITC and PTC available for utility-scale onshore and offshore wind, solar PV and battery storage on investment, generation capacity, job creation, and wholesale and retail power prices between 2025 and 2040 across competitive power markets in the United States: ERCOT, CAISO, PJM, MISO, NYISO, ISO-NE and SPP. ▪ The analysis in this report is based on Aurora's modeling of two distinct scenarios: the base case, where tax credits are continued, and the Tax Credit Removal scenario where the ITC and PTC are removed for wind, solar and battery deployment. See more details in the Appendix.
Study limitations
▪ All analysis in this report address dynamics within the seven competitive wholesale electricity markets—representing around two-thirds of total US power consumption – and excludes regulated regions such as the WECC1 and the SERC2 in western and southeastern states. ▪ Results are likely to be a conservative estimate of the impact on investment, jobs, and clean tech deployment. The study focuses only on wind, solar and storage ITC/PTCs. Other clean energy policies (e.g. support for electric vehicles, hydrogen, CCS), behind-the-meter projects, and the potential impact on other sectors like manufacturing were not considered as part of the project scope.
About Aurora Energy Research
▪ Aurora Energy Research is a leading global provider of independent power-market forecasts and analytics for critical investment and financing decisions.
▪ This report is fully independent, technology-agnostic, and does not advocate for any specific policy or regulation. 1) Western Electricity Coordinating Council. 2) Southeastern Electric Reliability Council. 3 E x e c u t i v e
S u m m a r y
1) CAISO, ERCOT, ISO-NE, MISO, PJM, NYISO, SPP.
Sources: Aurora Energy Research, ERCOT
1 Across US competitive electricity markets1, the removal of tax credits for wind, solar, and battery deployments could result in at least $336bn less investment and 237GW less clean energy deployed over the next 15 years – all amid rapidly growing electricity demand. ▪ Rapid electricity demand growth data centers and electrification across the US is driving a need for new generation capacity. Clean energy deployment averaged 25GW per year for the last five years. ▪ On an absolute basis, New York and Texas are the states that see the largest decline in clean energy investment—losing $4.4bn/year and $3.3bn/year on average through 2040, respectively. ▪ In relative terms, the removal of tax credits impacts investment in the Great Plains and Midwest most acutely, where total foregone clean energy investment exceeds 3% of 2023 state GDP.
Decreased capacity would result in 97,000 net fewer American jobs created in construction, maintenance, and operations of power generation facilities. ▪ Utility-scale renewables employed over 150,000 people across the United States in 2023. The clean energy job sector grew 4.2% from 2022 to 2023.
▪ Elimination of tax credits costs at least 103,000 full-time jobs across clean energy generation technologies.
This is only partially offset by an increase in 6,000 fossil fuel jobs, resulting in a net loss of 97,000 energy jobs. ▪ These estimates are likely conservative since they do not capture indirect impacts (e.g. resulting from higher power prices) or the impact on regulated regions covering a third of the country’s electricity demand.
Removal of tax credits increases residential electricity bills by 10% on average, and up to 22% in certain states by 2040.
▪ On average, annual power bills increase $142/year for consumers by 2040. ▪ Bills are expected to rise most sharply in states where average residential power prices are already high, like New York ($39/month increase) and Minnesota ($22/month increase), but also in states where residential energy demand is highest, such as Texas ($29/month increase) and Louisiana ($21/month increase). 2 3
4 Historical
Historical and forecasted peak load, aggregated across the seven competitive Independent System Operators (ISO)1,2 GW
Sources: Aurora Energy Research, historic data and ISO forecasts come from respective ISOs Accelerating power demand growth from electrification and data centers is driving the need for new generation capacity across the United States 1) CAISO, ERCOT, ISO-NE, MISO, PJM, NYISO, SPP. For more details on ISOs, see appendix. 2) SPP short-term load forecast is available through 2029; values are extrapolated linearly through 2033 here to match data availability from other ISOs. 3) Annualized average rate of growth.
Impact of reform to clean energy tax credits on investment, jobs and consumer bills 2024 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 500
2019
550
2020
600
2021
650
2022
700
2023
750
2025
0 +0.2%
+2.4%
+1.1%
Historical ISO forecast aggregation1,2 Aurora Central forecast aggregation ▪ After relatively flat load growth over the last decade, grid operators are forecasting a combined 2.4% annual growth rate in load between 2025 and 2033 as data centers and the continued electrification of industry, transportation, and homes raise power demand across the country. ▪ Aurora also forecasts an acceleration in power demand growth, albeit more conservative across competitive markets with a CAGR of 1.1% per year through 2040.
Compound Annual
Growth Rate (CAGR)3
5 Sources: Aurora Energy Research, Rhodium, EIA, individual ISOs, US Department of Energy In the last five years, 127GW of clean energy has been deployed across the US, bringing with it new jobs and contributing to stable electricity prices Annual US-wide clean energy deployment by technology
GW
Actual clean energy investment by technology4
$ billion (2023 real)
Full-time jobs by technology4
Thousands of jobs
Day-ahead wholesale electricity prices by ISO2
$/MWh (nominal)
1) 2024 data through end of Q3. 2) To increase readability, this graph excludes February 2021 prices in ERCOT, when Winter Storm Uri skyrocketed average day-ahead wholesale prices to $1,483/MWh. Including February, average 2021 day-ahead wholesale price in ERCOT was $155/MWh. 3) Includes both utility-scale and residential / behind-the-meter capacity. 4) These numbers do not include the investment or jobs in manufacturing for these technologies.
Impact of reform to clean energy tax credits on investment, jobs and consumer bills 0 20
40 2019 2020 2021 2022 2023
15 26
32 24
30 Onshore wind Offshore wind Utility-scale solar PV Battery storage 127GW of utility-scale wind, solar, and battery storage have been deployed since 2019 across the US, aided by federal tax credits 1 Clean energy jobs have grown in line with investment, growing to 54% of total electric power jobs in 2024 3
Over $300bn in public and private investments have been made in wind, solar, and storage deployments since 2019 2
Electricity prices have remained relatively flat over the past five years, due in part to rapid renewables penetration and limited load growth 4 0 50
100
2019 2020 2021 2022 2023 20241
31 50 49 52
71 57
0 600
300
2019 2020 2021 2022 2023
416 429
500 558 585
Solar PV3 Onshore wind Battery storage3
2019 2020 2021 2022 2023
0 50
100
Onshore + offshore wind Utility-scale solar PV Battery storage Indidivual ISOs ISO average
6 Aurora base case assumptions and Tax Credit Removal scenario methodology In this study, Aurora modelled the seven competitive power markets in the US to explore the impact of tax credit removal on generators and consumers 1) Including the DoE’s US Energy Employment and Jobs Report.
Key assumption Aurora Base Case Tax Credit Removal scenario Capacity
build
▪ Aurora’s production cost and capacity expansion modelling yields detailed forecasts for plant-level economic build and retirements out to 2060 across competitive wholesale markets, with all assets meeting a target rate-of-return.
▪ Tax credit removal impacts project economics.
Investment
▪ Calculated based on project CAPEX for new build assets. ▪ Impact of capacity build across competitive markets is translated into investment impact in all states building solar PV, onshore and offshore wind, or BESS.
Jobs
▪ Data from industry publications1 and academic research are used to estimate job creation per MW of installed capacity by technology. ▪ Capacity changes relative to the base case are translated into increases and decreases in jobs by technology.
Electricity
prices
▪ Hourly wholesale prices are modelled out to 2060 across competitive electricity markets (Independent System Operators – ISOs) internally consistent with capacity build.
▪ Historical data from EIA are used to correlate wholesale and residential electricity prices from 2014-2023. This correlation is applied to Aurora’s forecasted wholesale prices to project retail rate impacts by state. For a view on wholesale electricity prices in states covered by multiple ISOs, we take a load distribution as proxy.
Load
growth
▪ Aurora takes a comprehensive view on load growth across the modelled ISOs, considering population growth, electrification (of transportation, heating, oil and gas operations, etc.), and data center expansion. ▪ No changes to load assumptions in the Tax Credit Removal scenario.
Tax credits
▪ Aurora assumes all clean energy projects achieve base PTC and ITC rates; Energy Community adder depends on project location. Credit stepdown in the mid 2030s reflects policy uncertainty. See appendix slide for more details.
▪ PTCs and ITCs for wind, solar, and batteries are discontinued in 2025; safe harbor assumptions means projects under construction today can still receive tax credits, but no projects beyond this time frame receive tax credits. See appendix slide for more details.
Sources: Aurora Energy Research, EIA, US Department of Energy Impact of reform to clean energy tax credits on investment, jobs and consumer bills 7 -80 -60 -40 -20 0 20
-4
-15
-6
-8
-10
-17
-15
▪ Across competitive electricity
markets in the United States,
76GW less clean energy
projects are deployed by 2030
in a world without tax credits
supporting the deployment of
solar PV, wind, and battery
storage technologies, and
237GW by 2040. Compared to
the 256GW of capacity
operational in 2023, this is a
substantial reduction in future
growth.
▪ Utility-scale solar PV is most
impacted by the discontinuation
of tax credits, seeing 41GW less
buildout by 2030 and 93GW
less by 2040.
▪ Offshore wind capacity is
reduced 33GW by 2040; this
affects coastal regions, where
state support for offshore wind
deployment is insufficient to
make up for loss of federal
support.
Sources: Aurora Energy Research
A rollback of federal tax credits could reduce clean energy deployment 76GW by 2030 and 237GW by 2040
Cumulative capacity delta to base case resulting from tax credit removal by ISO (Independent System Operator) GW
Impact by 2030
Utility-scale solar PV Battery storage Onshore wind Offshore wind Impact by 2040
CAISO (California)
ERCOT (Texas)
MISO (Midwest)
NYISO (New York)
PJM (Mid-Atlantic)
SPP (Great Plains)
Net total: -76GW
-80 -60 -40 -20 0 20
-8
-36
-22
-63
-48
-23
-36
ISO-NE (New England)
Tax credit removal
decreases clean
energy deployment
Net total: -237GW
ISO
Impact of reform to clean energy tax credits on investment, jobs and consumer bills 8 ▪ ISO-wide investment in battery
storage, solar, and wind projects
totalled $57 billion in Q1-Q3 of
2024.
▪ Texas saw $24.8 billion, or 1% of
state GDP, invested in the last 4
quarters alone. Tax credit
removal would cut investment
by twice that amount by 2040.
▪ New York and Texas alone
would lose out on $116bn in
investment, or 34% of the total.
▪ Cumulative investment lost in
the Great Plains states is
between 3 and 5% of 2023 GDP,
and as much as 8% in Oklahoma.
▪ These numbers do not include
the impact on investment in
manufacturing of wind, solar
and battery technologies.
Sources: Aurora Energy Research, Rhodium Group-MIT/CEEPR Clean Investment Monitor Removal of tax credits could lead to a loss of $22bn/year in clean power investment
1) Analysis available for deregulated wholesale markets covering 31 states and the District of Columbia. Includes impact to deployment of utility-scale wind, solar, and battery storage systems; excludes impact to manufacturing sector. 2) Delta with Aurora baseline forecast for 2025-2040.
Impact of reform to clean energy tax credits on investment, jobs and consumer bills Investment gap for clean power deployment1, Tax Credit Removal scenario relative to base case 0% 8%
Value: annual investment gap2
Billion US$ (real 2023)
Color: cumulative investment gap by 2040
% of state GDP (real 2023)
-$22bn
In annual foregone clean
power investment
9 ▪ Utility-scale wind, solar, and
battery technologies employed
over 150,000 people across
construction, maintenance and
operation, and professional
services in 2023.
▪ Jobs in clean energy grew 4.2%
from 2022 to 2023, more than
double the speed of the overall
economy at 2.0%.
▪ Cutting tax credits would be
equivalent to 3+ years of lost
jobs growth in American clean
energy deployment and
maintenance.
▪ These numbers do not include
the impact on jobs in
manufacturing of wind, solar
and battery technologies.
Sources: Aurora Energy Research, US Department of Energy, IWEC, GWEC, Aldieri et al. (2020) Elimination of tax credits for wind, solar, and battery deployment puts at risk 31,000 jobs by 2030 and at least 103,000 jobs by 2040 1) Analysis available for deregulated wholesale markets covering 31 states and the District of Columbia. Includes impacts on construction and operation of utility-scale wind, solar, and battery storage systems; excludes impacts on manufacturing sector. 2) Delta with Aurora baseline forecast for 2040, assuming constant relationship between new capacity and job creation.
Impact of reform to clean energy tax credits on investment, jobs and consumer bills Jobs gap for clean power deployment by 20401,2
0 >15k
Jobs gap by 2040 2
’000s of jobs
-103,000
Full-time American clean
power jobs by 2040
10 Sources: Aurora Energy Research, EIA
Job losses are partially offset by a 6,000 increase in the fossil fuel sector, though not enough to make up for the 103,000 clean energy jobs lost 1) The reduction in onshore wind, offshore wind, and solar PV generation in the Tax Credit Removal scenario relative to base case. 2) Other balancing effects include increased generation from dispatchable non-gas, coal, or nuclear plants (e.g. hydro), reduced battery storage losses from less battery storage on the system, reduced demand from price-responsive demand technologies (such as Bitcoin mines in ERCOT).
Impact of reform to clean energy tax credits on investment, jobs and consumer bills Job impact by technology in Tax Credit Removal scenario relative to base case Thousands of jobs
Electricity production comparing Tax Credit Removal scenario to base case (2025-2040), TWh
▪ The loss in clean electricity generation from the discontinuation of tax credits means that demand must be met in other ways, primarily through fossil-fuel fired generation such as natural gas and coal.
▪ Most demand is made up through more production from existing plants (35%), meaning these plants are running for longer hours and/or at higher output levels. Some projects that retired in the base case scenario see longer lifetimes in Tax Credit Removal scenario because of more favorable economics due to clean energy decline (making up 17% of lost generation), and the rest is made up for by new build thermal plants (29%).
▪ The increase in fossil-fueled fired generation lends to more jobs, though not enough to make up for the loss of clean energy jobs.
▪ Higher load factors from operational plants results in minimal new jobs, construction of new thermal plants altogether create four thousand new jobs.
Clean
electricity loss1
New thermal
plants
Operational
plants increase
production
Delayed
retirements
Other
balancing
effects2
1,055
1,262
615
4,000 new
jobs
-1 -7
-16
-8
2030
-5
-15
-38
-44
6 2040
Battery
Solar
Onshore wind
Offshore wind
Gas-fired generation
Coal-fired generation
-30,000
lost jobs
Tax Credit Removal decreases
net clean energy employment
-97,000
lost jobs
Gas Coal Nuclear
No impact 2,000 jobs
retained
Fossil fuel
job impact
Net energy
job impact
11 ▪ The elimination of tax credits for
renewables and storage
deployment results in wholesale
power prices rising across every
competitive market throughout
the next two decades.
▪ ERCOT (ISO covering the
majority of Texas) is
disproportionately impacted by
tax credit removal. Given high
load growth in the state and a
lack of state policies supporting
clean energy deployment the
state loses a lot of cheap
electricity generation, raising
wholesale electricity prices by
$5/MWh by 2030 and
$12/MWh by 2040.
▪ Wholesale power prices rise
much faster through the 2030s
due to lower investment in
renewable energy in a world
without clean energy tax credits.
Around the Clock (ATC) price deltas by US ISO, Tax Credit Removal scenario relative to base case $/MWh (2023 real)
Sources: Aurora Energy Research
Removal of tax credits leads to higher wholesale power prices across markets
2 6
5 12
2 4
0 1
2 2
8 2
9 0
5 10
15 2030 2040
5 CAISO (California)
ERCOT (Texas)
SPP (Great Plains)
MISO (Midwest)
PJM (Mid-Atlantic)
NYISO (New York)
ISO-NE (Northeast)
Impact of reform to clean energy tax credits on investment, jobs and consumer bills 12 Sources: Aurora Energy Research, EIA
By 2040, removal of tax credits could raise retail rates by ~10% and yearly energy bills by ~$142 on average
1) Compared to estimated retail prices in 2040 from a baseline scenario with investment and production tax credits. In this scenario, renewable energy generation is typically replaced with gas and peaking generation, which has a higher short run marginal cost. 2) Analysis available for deregulated wholesale markets covering 31 states and the District of Columbia. No data available for states in gray. 3) Forecasted retail rate multiplied by state-specific 2023 average monthly residential demand Impact of reform to clean energy tax credits on investment, jobs and consumer bills Monthly residential energy bill increases by selected state2,3 $ over base case (2023 real)
4 3
1 1
6 17
3 3
21 22
4 39
11 3
0 10
20 30
40 California Louisiana Minnesota Nebraska New York Texas Vermont Virginia 8 29
2030 2040
Retail rate increases by state, 20401,2
% delta from base case
▪ Without tax credits to incentivize renewable energy development, average retail electricity rates are expected to be 3% higher in 2030, rising to 10% higher on average by 2040.1,2
▪ Removing 169GW of low marginal cost wind and solar generation from the system by 2040 leads to higher power prices rise as more expensive generation must be used to meet demand.
▪ Monthly residential energy bills are likely to rise sharply in states where consumers have the highest energy demand (Louisiana, Texas) or already pay high average rates (New York).
13 Agenda
I. Additional context
II. Additional results
III. About Aurora
14 Sources: Aurora Energy Research, FERC, NERC, individual ISOs Aurora models all seven competitive electricity markets in the United States
1) Gray areas are regulated, meaning they are vertically integrated utilities responsible for the production, transportation, and sale of electricity to consumers. 2) Data from December 2023 EIA 860m and ERCOT CDR. Includes capacities of plants not bidding fully into wholesale or capacity market. 3) 2023 data. 4) Compares 2024 through 2030. SPP data from individual ISO market report. 2 5
4 7
3 6
1 A
B
ISO
Installed
capacity,2 GW
Annual
load,3 TWh
Projected peak
load growth4
Renewables
penetration3
CAISO 82 220 9.7% 42%
ERCOT 140 447 9.2% 41%
SPP 100 284 9.9% 40%
MISO 200 656 6.0% 20%
PJM 219 770 3.7% 10%
NYISO 44 147 17.0% 24%
ISO-NE 38 110 11.4% 18%
1 2
3 4
5 6
Non-ISO
WECC
Out of scope for this study
SERC
7 Map of US wholesale electricity markets1
Two thirds of overall electricity demand in the lower 48 states is served by Independent System Operators (ISOs). ISOs use competitive market mechanisms that allow independent power producers and non-utility generators to trade power. The WECC and SERC regions remain vertically integrated by utility or balancing authority (BA).
A
B
I Appendix—Additional context
15 Sources: Aurora Energy Research, EPA
▪ The Aurora base case assumes
all economically-built projects
meet labor requirements; some
projects realize the Energy
Community adder depending on
location. No projects in the base
case achieve the Domestic
Content adder.
▪ ITC adders are relatively more
attractive than PTC adders: ITC
adders are 10p.p. additions to
the base rate + wage
requirement values, whereas
PTC adders are a 10% addition
of the base rate + wage
requirement values.
▪ Values step down in the base
case in the 2030s to reflect
some level of policy uncertainty.
▪ All PTC and ITC value is subject
to a 10% haircut per Aurora’s
assumptions, reflecting some
value lost to tax credit
transactions.
Aurora assumes a minimum $25.7/MWh PTC and 27% ITC; the Tax Credit Removal scenario eliminates these values in 2025 PTC value (post transaction cost)
$/MWh (real 2023)
ITC value (post transaction cost)
% capital expenditure
1) Legacy project rules enable a 4 year construction time for projects. 2) Excludes transaction costs. 2015 2020 2025 2030 2035 2040 2045 2050
0 10
20 30
40 2015 2020 2025 2030 2035 2040 2045 2050
0 10
20 30
40 Construction start year Construction start year1 1
Appendix—Additional context
Historic values Aurora base case tax credit value, upper and lower bound Tax Credit Removal scenario Aurora base case range
Aurora base case range
Tax Credit Removal scenario Tax Credit Removal scenario I
16 Agenda
I. Additional context
II. Additional results
III. About Aurora
17 Sources: Aurora Energy Research
Capacity delta by state, 2030
1) Analysis available for deregulated wholesale markets covering 31 states and the District of Columbia.
Appendix—Additional results
-20
-15
-10
-5
0 5
NY OK CA VA IL NJ OH KS PA MA IN MI CT LA ME NE DE MS ND AR MD RI NH WV MO SD DC IA WI MN VT -18
-10
-7
-4
-3 -3 -3 -3 -3
-2 -2 -2
-2 -2 -1 -1
TX
-1 -1 -1 -1 -1
-1 0
-1
0 0 0 0 0 0 0
0 Battery storage Solar photovoltaics Onshore wind Offshore wind Installed capacity deltas compared to base case by state1 GW (2030)
II
18 Sources: Aurora Energy Research
Capacity delta by state, 2040
1) Analysis available for deregulated wholesale markets covering 31 states and the District of Columbia.
Appendix—Additional results
-50
-40
-30
-20
-10
0 10
TX OK MA IN NJ MI IL MN CA VA KS NE MO CT LA ND IA WI AR OH MS DE ME NH PA SD RI MD WV DC VT -48
-44
-17
-15
-11 -11 -10 -10 -10
-8
-7
-5 -5 -5
NY
-4 -3 -3 -3 -3 -3
-2 -2
-4
-1 -1 -1 -1
-1
0 0 0
-1
Battery storage Solar photovoltaics Onshore wind Offshore wind Installed capacity deltas compared to base case by state1 GW (2040)
II
19 Sources: Aurora Energy Research
Results by state, 2030
Appendix—Additional results
State Battery storage
delta (MW)
Solar
photovoltaics
delta (MW)
Onshore wind
delta (MW)
Offshore wind
delta (MW)
Total capacity
delta (MW)
Investment
delta ($bn, 2023
real)
Clean energy
jobs delta
Monthly retail
price delta (%)
Monthly retail
price delta ($,
2023 real)
Arkansas -82.5 -696.6 -5.0 0.0 -784.1 -0.89 -127 0.1% $0.18 California -305.8 -2406.2 -1205.4 -150.0 -4067.4 -6.69 -1710 3.5% $3.85 Connecticut -141.2 -1143.0 -8.3 -229.4 -1521.8 -2.16 -518 4.0% $6.28 Delaware 0.0 -1121.4 20.9 0.0 -1100.5 -1.18 -168 2.7% $3.55 District of Columbia 0.0 -159.8 0.0 0.0 -159.8 -0.17 -27 1.5% $1.25 Illinois -577.1 -2467.2 -225.0 0.0 -3269.3 -3.65 -654 1.2% $1.62 Indiana -139.7 -1548.0 -516.0 0.0 -2203.7 -2.74 -733 0.9% $1.35 Iowa 0.0 -6.0 -110.0 0.0 -116.0 -0.19 -100 1.2% $1.38
Kansas -115.6 -924.7 -1644.0 0.0 -2684.2 -3.91 -1642 7.4% $5.12 Louisiana -30.0 -1457.6 -5.0 0.0 -1492.6 -1.66 -250 1.5% $3.29 Maine -23.4 -1063.0 -304.6 0.0 -1390.9 -1.79 -453 3.8% $4.53 Maryland 0.0 283.9 -2.1 -913.0 -631.2 -2.98 -1187 1.5% $1.58 Massachusetts 1.4 -1457.0 0.0 -760.8 -2216.4 -4.02 -1270 3.9% $5.24 Michigan -52.4 -1057.7 -506.1 0.0 -1616.3 -2.07 -636 1.0% $1.38 Minnesota -15.0 -6.0 -10.0 0.0 -31.0 -0.04 -11 1.0% $1.48 Mississippi 0.0 -906.0 -5.0 0.0 -911.0 -1.04 -156 1.4% $1.97 II
20 Sources: Aurora Energy Research
Results by state, 2030
Appendix—Additional results
State Battery storage
delta (MW)
Solar
photovoltaics
delta (MW)
Onshore wind
delta (MW)
Offshore wind
delta (MW)
Total capacity
delta (MW)
Investment
delta ($bn, 2023
real)
Clean energy
jobs delta
Monthly retail
price delta (%)
Monthly retail
price delta ($,
2023 real)
Missouri -29.6 -186.0 -43.5 0.0 -259.1 -0.32 -72 2.1% $2.40 Nebraska -245.5 -378.8 -529.1 0.0 -1153.4 -1.57 -556 1.1% $0.74 New Hampshire -8.9 -421.0 0.0 0.0 -429.9 -0.47 -71 3.8% $5.05 New Jersey -354.0 -1496.5 -1.6 -1306.0 -3158.0 -6.64 -2039 2.7% $3.31 New York -3818.7 -4706.2 -668.5 -1035.6 -10228.9 -14.48 -3049 3.1% $6.01 North Dakota -338.0 -207.4 -312.5 0.0 -857.9 -0.98 -339 2.5% $2.01 Ohio -64.8 -2805.7 -38.0 0.0 -2908.5 -3.30 -507 0.7% $0.67 Oklahoma -1312.6 -3457.4 -2581.2 0.0 -7351.2 -9.38 -2991 -2.1% -$1.71 Pennsylvania -2.0 -2180.3 -53.0 0.0 -2235.3 -2.53 -412 1.8% $2.49 Rhode Island -7.9 -483.0 0.0 -44.8 -535.7 -0.69 -142 3.8% $3.81 South Dakota -62.5 -58.0 -94.7 0.0 -215.3 -0.26 -99 3.3% $2.16 Texas -3608.8 -5590.9 -9051.9 0.0 -18251.6 -23.42 -9329 11.2% $16.75 Vermont -7.5 -3.0 0.0 0.0 -10.5 -0.01 -1 3.8% $3.22
Virginia -107.4 -2069.7 -15.0 -1147.0 -3339.2 -6.58 -1915 2.0% $2.87 West Virginia 0.0 -409.0 -16.0 0.0 -425.0 -0.49 -83 1.5% $2.72 Wisconsin 0.0 -93.4 -13.9 0.0 -107.3 -0.14 -28 0.8% $0.88 II
21 Sources: Aurora Energy Research
Results by state, 2040
Appendix—Additional results
State Battery storage
delta (MW)
Solar
photovoltaics
delta (MW)
Onshore wind
delta (MW)
Offshore wind
delta (MW)
Total capacity
delta (MW)
Investment
delta ($bn, 2023
real)
Clean energy
jobs delta
Monthly retail
price delta (%)
Monthly retail
price delta ($,
2023 real)
Arkansas -82.5 -2717.3 22.3 0.0 -2777.5 -2.78 -439 7.0% $15.85 California -1094.5 -2366.2 -204.2 -4350.0 -8014.9 -22.08 -6527 9.7% $8.22 Connecticut -757.6 -1748.0 -7.4 -1376.2 -3889.2 -6.71 -2209 16.5% $18.47 Delaware 0.0 -1618.0 26.0 0.0 -1592.1 -1.81 -247 7.4% $8.68 District of Columbia 0.0 -256.9 0.0 0.0 -256.9 -0.27 -43 3.8% $2.77 Illinois -4004.0 -3475.6 -2483.1 0.0 -9962.7 -11.40 -3092 4.0% $6.25 Indiana -1714.7 -6543.0 -2671.6 0.0 -10929.2 -12.47 -3615 3.3% $5.32 Iowa -500.0 -400.0 -1954.0 0.0 -2854.0 -4.02 -1860 10.7% $13.11 Kansas -463.9 -2037.3 -2904.6 0.0 -5405.8 -7.40 -2986 14.1% $8.95 Louisiana -1078.8 -2554.8 -2.0 0.0 -3635.6 -3.68 -503 6.7% $20.72 Maine -23.4 -2460.0 1016.7 0.0 -1466.6 -0.84 503 16.7% $15.25 Maryland 0.0 2247.8 16.7 -2821.0 -556.5 -7.61 -3418 4.9% $4.05 Massachusetts -7697.6 -2664.6 1.7 -4564.7 -14925.2 -22.73 -7137 16.6% $16.48 Michigan -1663.8 -4977.6 -3597.4 0.0 -10238.8 -12.34 -4184 3.0% $4.93 Minnesota -1143.3 -3500.0 -5162.9 0.0 -9806.2 -12.82 -5310 12.4% $21.85 Mississippi -162.1 -1627.2 -2.0 0.0 -1791.3 -1.91 -285 6.9% $8.61 II
22 Sources: Aurora Energy Research
Results by state, 2040
Appendix—Additional results
State Battery storage
delta (MW)
Solar
photovoltaics
delta (MW)
Onshore wind
delta (MW)
Offshore wind
delta (MW)
Total capacity
delta (MW)
Investment
delta ($bn, 2023
real)
Clean energy
jobs delta
Monthly retail
price delta (%)
Monthly retail
price delta ($,
2023 real)
Missouri -1747.0 -1420.2 -1659.2 0.0 -4826.4 -5.65 -1851 8.9% $10.44 Nebraska -1217.0 -1746.0 -2152.5 0.0 -5115.6 -6.38 -2313 8.7% $3.81 New Hampshire -9.0 -1306.8 0.0 0.0 -1315.7 -1.36 -219 16.7% $16.30 New Jersey -1753.6 -1471.6 12.7 -7680.3 -10892.8 -29.41 -10724 8.0% $9.11 New York -20672.0 -19106.5 -1395.6 -6979.9 -48154.0 -66.04 -15296 17.1% $39.46 North Dakota -1662.7 -541.5 -1027.9 0.0 -3232.0 -3.62 -1130 8.4% $5.89 Ohio -957.2 -2792.5 1054.5 0.0 -2695.2 -2.26 417 1.9% $1.56 Oklahoma -2512.3 -7303.5 -6762.4 0.0 -16578.2 -21.01 -7479 3.9% $2.29 Pennsylvania -197.6 -1014.9 0.9 0.0 -1211.6 -1.63 -182 5.3% $6.45 Rhode Island -7.9 -544.0 0.0 -269.1 -821.0 -1.45 -455 16.7% $13.44 South Dakota -331.6 -205.8 -324.9 0.0 -862.4 -1.01 -350 12.4% $7.02 Texas -12474.7 -17406.2 -13758.2 0.0 -43639.1 -50.12 -16150 22.1% $28.54 Vermont -7.5 0.0 0.0 0.0 -7.5 -0.01 -1 16.7% $10.96
Virginia -4158.1 -317.8 43.3 -2080.0 -6512.6 -11.25 -3109 2.8% $3.44 West Virginia 0.0 -406.0 14.1 0.0 -391.9 -0.44 -55 2.4% $4.18 Wisconsin -451.2 -1166.2 -1185.6 0.0 -2803.0 -3.48 -1293 10.3% $9.46 II
23 Agenda
I. Additional context
II. Additional results
III. About Aurora
24 Source: Aurora Energy Research
Aurora provides independent forecasts and data-driven intelligence for the global energy transition
Regular detailed coverage Analytics on demand
Power markets
Renewables & PPAs
Storage
Hydrogen
Natural gas
Carbon
Electric vehicles
H2
CO2
São Paulo
Austin
Oakland
Grid & Congestion
Stockholm
Sydney
Melbourne
Tokyo
Singapore
Delhi
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Berlin
Paris
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Oxford
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16 offices
900+
market experts
850+
subscribing
companies
150+
transactions
supported in
2024
III Appendix—About Aurora
25 Source: Aurora Energy Research
Our market-leading models underpin a comprehensive range of seamlessly integrated services to best suit your needs
Advisory
Access tailored expert advice and analytics for your crucial projects. Dedicated support for strategy, investments,
transactions and policy engagements
Software Solutions
Make standard analysis bespoke with direct access to our models. Unique SaaS subscriptions to create your own
scenarios and asset-specific investment cases
Subscription Analytics
Receive quarterly outlook reports, bankable price
forecasts, sample investment cases and timely
strategic insights for power and commodities
Models & Data
Market-leading models for power, gas,
hydrogen, carbon, oil & coal markets
100+ company licenses
1400+ projects globally
850+ subscribing companies
Customization of services
Proprietary and continuously updated cutting-edge models populated with highest quality curated datasets
Developed over 10 years, 70+ dedicated modellers
Power & Renewables fundamental reports including
bankable price forecasts & strategic insights
Bankable battery storage analysis with detailed costs and revenue for investment cases
Bankable nodal basis forecasts, spatial analysis & nodal trends based on bottom-up power flow modelling
Trusted consulting for project valuation, debt/tax equity financing, capital raises, project siting, policy analysis, and PPA support
Market-level simulation tool: Origin
Asset-level valuation tools for batteries, wind, and solar Aurora Maps visualizer for siting analysis and nodal forecasts III Appendix—About Aurora
26 CONFIDENTIAL
What the service is:
• Bankable monthly forecasts (2050) to
support asset financing , scenario analysis;
in-depth fundamental analysis to underpin
your investment strategies
• Roundtable discussions, workshops and
ongoing support from dedicated teams
What the service is:
• Detailed analysis and hourly granular
forecasts for power, balancing, and ancillary
services plus investment case data for
battery & peakers
• Roundtable discussions, workshops and
ongoing support from dedicated teams
What the service is:
• Bankable nodal forecasts, spatial
congestion analysis, site-specific valuation
and other features through bottom-up
power flow modelling
• Roundtable discussions, workshops and
ongoing support from dedicated teams
What the service is:
• Tailored expert advice and analytics
support to deliver diligence on a specific
project including advisory transactions,
policy views, and strategy insights
Assorted use case examples:
• Understanding a market at depth and
keeping up to date with market and policy
developments, with on-call, ad hoc support
• Reliable, bankable wholesale price forecasts
to support asset financing and valuations -
six scenarios updated quarterly
Assorted use case examples:
• Developer seeking to understand detailed
battery costs and revenue streams/stacking
across various configurations
• Investor comparing differences in BESS
gross margin, IRR, NPV across hubs and
entry years with representative nodal basis
Assorted use case examples:
• Investor evaluating site specific risks and
implications during phase 1 of a transaction
• Developer seeking to identify the drivers
and trends in congestion patterns and nodal
pricing outcomes throughout the system to
support early development pipeline
Assorted use case examples:
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Aurora services: subscriptions providing price forecasts and market analytics for developers, asset owners, investors, energy consumers, and regulators 1 Power & Renewables 2 Flexible Energy Add-on Nodal Add-on 4 Advisory Keep up to date on a specific power market;
zonal price curves as well as in-depth quarterly
reports and events to keep a pulse on market
(Quarterly updates)
3 Subscription Analytics: Receive regularly updated forecasts, sample investment cases and timely deep-dives Ad-hoc customized support: