Redwood Coast Energy Authority
633 3rd Street, Eureka, CA 95501
Phone: (707) 269-1700 Toll-Free (800) 931-7232 Fax: (707) 269-1777 E-mail: [email protected] Web: www.redwoodenergy.org
BOARD OF DIRECTORS MEETING AGENDA
June 23, 2022 -Thursday, 3:30 p.m.
COVID-19 NOTICE
RCEA AND HUMBOLDT BAY MUNICIPAL WATER DISTRICT OFFICES
WILL NOT BE OPEN TO THE PUBLIC FOR THIS MEETING
Pursuant to the AB 361 Brown Act open public meeting law revisions signed into law on September 16, 2021, and Governor Newsom’s State of Emergency Proclamation of March 4, 2020, this meeting will not be convened in a physical location. Board members will participate in the meeting via an online Zoom video conference.
To listen to the meeting by phone, call (669) 900-6833 or (253) 215-8782. Enter webinar ID:
819 7236 8051. To watch the meeting online, join the Zoom webinar at https://us02web.zoom.us/j/81972368051.
You may submit written public comment by email to [email protected].
Please identify the agenda item number in the subject line. Comments will be included in the meeting record but not read aloud during the meeting.
To make a comment during the public comment periods, raise your hand in the online Zoom webinar, or press star (*) 9 on your phone to raise your hand. You will continue to hear the meeting while you wait. When it is your turn to speak, a staff member will unmute your phone or computer. You will have 3 minutes to speak.
While downloading the Zoom application may provide a better meeting experience, Zoom does not need to be installed on your computer to participate. After clicking the webinar link above, click “start from your browser.”
In compliance with the Americans with Disabilities Act, any member of the public needing special accommodation to participate in this meeting should call (707) 269-1700 or email [email protected] at least 3 business days before the meeting. Advance notice enables RCEA staff to make their best effort to reasonably accommodate access to this meeting while maintaining public safety.
Pursuant to Government Code section 54957.5, all writings or documents relating to any item on this agenda which have been provided to a majority of the Board of Directors, including those received less than 72 hours prior to the RCEA Board meeting, will be made available to the public at www.redwoodenergy.org.
1 RCEA June 23, 2022, Board of Directors Meeting Agenda
OPEN SESSION Call to Order
1. REPORTS FROM MEMBER ENTITIES
2. ORAL COMMUNICATIONS
This time is provided for people to address the Board or submit written communications on matters not on the agenda.
At the conclusion of all oral communications, the Board may respond to statements. Any request that requires Board action will be set by the Board for a future agenda or referred to staff.
3. CONSENT CALENDAR
All matters on the Consent Calendar are considered to be routine by the Board and are enacted in one motion. There is no separate discussion of any of these items. If discussion is required, that item is removed from the Consent Calendar and considered separately. At the end of the reading of the Consent Calendar, Board members or members of the public can request that an item be removed for separate discussion.
3.1 Approve Minutes of May 26, 2022, Board Meeting.
3.2 Approve Disbursements Report.
3.3 Accept Financial Reports.
3.4 Accept Update on Net Energy Metering Successor Tariff Comment Letter Submitted by RCEA Staff to the California Public Utilities Commission.
3.5 Adopt Resolution 2022-5 Adopting an Amended Conflict of Interest Code and Authorize the Board Clerk to Submit the Amended Conflict of Interest Code to the Humboldt County Board of Supervisors as the Code Reviewing Body.
3.6 Adopt Resolution No. 2022-6 Ratifying Governor Newsom’s March 4, 2020, State of Emergency Proclamation and Authorizing Remote Teleconference Meetings of RCEA’s Legislative Bodies, for the period June 27, 2022, through July 27, 2022, pursuant to Brown Act revisions of AB 361, and
Approve conducting RCEA Board and Community Advisory Committee meetings in a hybrid in-person and teleconference format at the Jefferson Community Center auditorium beginning July 28 for the Board and September 13, 2022, for the Community Advisory Committee.
4. REMOVED FROM CONSENT CALENDAR ITEMS
Items removed from the Consent Calendar will be heard under this section.
COMMUNITY CHOICE ENERGY (CCE) BUSINESS (Confirm CCE Quorum) Items under this section of the agenda relate to CCE-specific business matters that fall under RCEA’s CCE voting provisions, with only CCE-participating jurisdictions voting on these matters with weighted voting as established in the RCEA joint powers agreement.
5. OLD CCE BUSINESS
5.1. Annual Report on Humboldt Sawmill Company Memorandum of Understanding Regarding Biomass Plant Performance and Alternative Feedstock Uses (Information only)
2 RCEA June 23, 2022, Board of Directors Meeting Agenda
6. NEW CCE BUSINESS
6.1. Procuring PG&E Renewable Portfolio Standard Voluntary Allocation to Meet Compliance Requirements
Authorize the Executive Director to sign PG&E’s RPS Voluntary Allocation Attestation and execute the final Confirmation Agreement with PG&E, with changes from the Proforma Confirmation Agreement approved by Counsel.
END OF COMMUNITY CHOICE ENERGY (CCE) BUSINESS
7. OLD BUSINESS
7.1 Proposed Amendment to Sandrini Solar Power Purchase Agreement Approve First Amendment to 15-year power purchase agreement with EDPR CA Solar Park II LLC for its Sandrini solar project and authorize RCEA’s Executive Director to execute all applicable documents.
7.2 Fairhaven Energy Storage Mid-Term Reliability Procurement Approve Resource Adequacy Agreement with Fairhaven Energy Storage LLC and authorize the Executive Director to execute all applicable documents.
NOTE: The Resource Adequacy agreement was not available at the time of agenda publication. It will be made available by 5 p.m. Wednesday, June 22, 2022, on www.redwoodenergy.org.
7.3 Fiscal Year 2022-23 Proposed Budget and Addition of Staff Positions Approve:
1) Adoption of the proposed RCEA Fiscal Year 2022-23 budget, 2) Creation of an Infrastructure Programs Manager position, 3) Addition of a DSM Intake Coordinator position,
4) Addition of a Power Resources Specialist position,
5) Update to the RCEA Organization Chart, and
6) Revising the Assistant/Coordinator/Associate position to clarify the distinction between limited-term and permanent positions.
8. NEW BUSINESS – None.
9. STAFF REPORTS
9.1. Update on RCEA’s Public Agency Solar Program and the California Schools Healthy Air and Plumbing Efficiency Program by Demand-Side Management Director Stephen Kullmann, Senior DSM Manager Patricia Terry and DSM Manager Mike Avcollie
3 RCEA June 23, 2022, Board of Directors Meeting Agenda
9.2. Deputy Executive Director’s Report
10. FUTURE AGENDA ITEMS
Any request that requires Board action will be set by the Board for a future agenda or referred to staff.
11. CLOSED SESSION
11.1 Conference with real property negotiators pursuant to Government Code § 54956.8 in re: APNs 001-141-005 and 001-141-006; RCEA negotiator: Executive Director; Owner’s negotiating party: Wells Commercial; Under negotiation: price and terms.
12. RECONVENE TO OPEN SESSION
13. CLOSED SESSION REPORT
14. ADJOURNMENT
NEXT REGULAR MEETING
Thursday, July 28, 2022, 3:30 p.m.
Meeting location to be determined. Online and phone participation options will be available. 4 Redwood Coast Energy Authority
633 3rd Street, Eureka, CA 95501
Phone: (707) 269-1700 Toll-Free (800) 931-7232 Fax: (707) 269-1777 E-mail: [email protected] Web: www.redwoodenergy.org
BOARD OF DIRECTORS DRAFT MEETING MINUTES
May 26, 2022 - Thursday, 3:30 p.m.
Notice of this meeting was posted on May 20, 2022. Chair Stephen Avis called a regular meeting of the Board of Directors of the Redwood Coast Energy Authority to order on the above date at 3:32 p.m., stating that the teleconference meeting was being conducted pursuant to the AB 361 Brown Act open public meeting law revisions signed into law on September 16, 2021, and Governor Newsom’s State of Emergency Proclamation of March 4, 2020. Chair Avis stated that the posted agenda contained public teleconference meeting participation instructions.
PRESENT: Chair Stephen Avis, Scott Bauer (arrived 3:48 p.m.), Rex Bohn (left 5:45 p.m.), Vice Chair Chris Curran, Mike Losey (arrived 3:34 p.m.), Sarah Schaefer, Jack Tuttle, Frank Wilson, Sheri Woo. ABSENT: None. STAFF AND OTHERS PRESENT: Business Development and Finance Director Lori Biondini, Regulatory and Legislative Policy Manager Aisha Cissna, Power Resources Director Richard Engel, Senior Power Resources Manager Jocelyn Gwynn, Demand Side Management Director Stephen Kullmann, Community Strategies Manager Nancy Stephenson; Clerk of the Board Lori Taketa, Deputy Executive Director Eileen Verbeck, The Energy Authority Senior Portfolio Analyst Chris Weber.
New Trinidad Director Jack Tuttle introduced himself to the Board. He was hired by a South Humboldt solar company in 2006 and has worked in the solar industry for the last 16 years.
ORAL COMMUNICATIONS
There were no public comments on items not on the agenda. Chair Avis closed the oral communications portion of the meeting.
CONSENT CALENDAR
3.1 Approve Minutes of April 28, 2022, Board Meeting.
3.2 Approve Disbursements Report.
3.3 Accept Financial Reports.
No member of the Board or public requested items to be removed from the consent calendar.
M/S: Losey, Woo: Approve the consent calendar items.
The motion passed with a unanimous roll call vote. Ayes: Avis, Bohn, Curran, Losey, Schaefer, Tuttle, Wilson, Woo. Noes: None. Absent: Bauer. Abstain: None.
Chair Avis confirmed there was a quorum to conduct Community Choice Energy business.
OLD CCE BUSINESS
5 RCEA May 26, 2022, Board of Directors Meeting DRAFT Minutes
5.1 Power Procurement Update – Information only
Power Resources Director Richard Engel described current supply chain disruptions, inflation, rising oil and shipping costs and the U.S. Department of Commerce’s tariff circumvention investigation’s effects on RCEA’s state-mandated and Board-directed power procurement. The Sandrini solar project’s completion is delayed, and its developers have requested a price increase. Anticipated tariff increases resulting from the federal investigation could threaten the viability of this and other solar development projects nationwide. Should the Sandrini solar project fail, RCEA would need to replace a substantial portion of its Long-Term Renewable Portfolio Standard procurement with other resources, possibly PG&E’s Voluntary Allocation Market Offer product or less-desirable unbundled renewable energy certificates. Other solar projects short-listed to help RCEA meet mid-term reliability procurement mandates as well as local feed-in tariff projects could also be affected by supply shortages and pandemic-related delays. Staff is renegotiating the Sandrini project contract and recommends doing a short-term procurement solicitation this year to make up for the potential mandated procurement shortfall. The Energy Authority’s Senior Portfolio Analyst Chris Weber explained how RCEA’s financial modeling reflected the Sandrini project’s delayed completion and that RCEA’s financial outlook remains positive despite the project’s delay and potential price increase.
The directors discussed the possibility of finding resources to replace the Sandrini project, how RCEA may be able to negotiate the amount and timing of cash deposits for the Sandrini project, and how green energy projects are being built because of Humboldt County customer investment.
There were no responses from the public to Chair Avis’ invitation for comment. Chair Avis closed the public comment period.
NEW CCE BUSINESS
6.1. North Coast Renewables
Senior Power Resources Manager Jocelyn Gwynn reported on a proposed agreement between RCEA and Sonoma Clean Power to collaborate on shared renewable energy development interests such as state regulatory advocacy, funding pursuit and sharing of non-confidential public-private partnership agreement language and best practices. Both agencies are developing significant renewable power sources. SCP’s geothermal project could provide 500 MW or more to the electrical grid. While RCEA’s initial offshore wind project would produce 100-150 MW, full wind energy development off Humboldt County’s coast would produce more energy than the current infrastructure can transmit. One proposed improved transmission corridor runs from Humboldt County through Mendocino and Lake Counties and could service both RCEA’s and SCP’s renewable energy projects.
The directors discussed the potential transmission corridors and the importance of avoiding duplication of efforts between the agencies.
Chair Avis invited public comment. There were no comments from the public. Chair Avis closed the public comment period.
M/S: Bauer, Schaefer: Authorize the Executive Director to enter into the Memorandum of Understanding Between Redwood Coast Energy Authority and Sonoma Clean 6 RCEA May 26, 2022, Board of Directors Meeting DRAFT Minutes
Power Authority to Collaborate on Enabling Transformative Renewable Energy Development Along the Northern California Coast.
The motion passed with a unanimous roll call vote. Ayes: Avis, Bauer, Bohn, Curran, Losey, Schaefer, Tuttle, Wilson. Noes: None. Absent: None. Abstain: None. Non-Voting: Woo.
OLD BUSINESS
7.1. Board and Community Advisory Committee Meeting Method Options Deputy Executive Director Verbeck described the current Humboldt County COVID transmission levels, Humboldt Bay Municipal Water District Board Room attendance limitations due to social distancing requirements, and staff’s research of 18 meeting spaces between McKinleyville and Fortuna.
The directors expressed support for hybrid in-person and virtual meetings in centrally-located Eureka to address fluid COVID conditions and encourage public engagement. Relative merits of the Eureka Veterans Memorial Hall and Jefferson Community Center auditorium were discussed.
There were no responses from the public to Chair Avis’ invitation for comment. Chair Avis closed the public comment period.
M/S: Losey, Schaefer: Extend Resolution No. 2022-4 Ratifying Governor Newsom’s March 4, 2020, State of Emergency Proclamation and Authorizing Remote Teleconference Meetings of RCEA’s Legislative Bodies, for the period May 28, 2022, through June 26, 2022, pursuant to Brown Act revisions of AB 361, and direct staff to make arrangements for hybrid, socially-distanced, in-person public meetings beginning July 2022.
The motion passed with a unanimous roll call vote. Ayes: Avis, Bauer, Bohn, Curran, Losey, Schaefer, Tuttle, Wilson, Woo. Noes: None. Absent:None. Abstain: None.
7.2. Net Energy Metering Successor Tariff Proceeding Update Regulatory and Legislative Manager Cissna reviewed the history of CPUC net energy metering (NEM) tariffs and current proposed changes. CCA advocacy efforts and comment deadlines were outlined. The Board previously formed an ad hoc NEM Successor Tariff Subcommittee to study proposed NEM tariff changes from the perspective of RCEA customers and report back to the Board. The Board discussed the necessity of this subcommittee in light of the technical nature of the proposed changes and the Board’s adoption of a policy platform, which delegates regulatory advocacy to staff. The directors agreed to disband the ad hoc subcommittee. Staff will develop a comment letter for submission by the June 10 deadline and report back to the Board at the June meeting.
Paul Woodworth of Rise Energy submitted written comment asking RCEA to submit comments to the CPUC in defense of a viable NEM incentive program. Chair Avis closed the public comment period.
NEW BUSINESS
7 RCEA May 26, 2022, Board of Directors Meeting DRAFT Minutes
8.1.Proposed Agency Position Additions and Revisions
Deputy Executive Director Verbeck described three proposed, additional full-time RCEA staff positions necessitated by expanding agency work. The Community Choice Energy program is responding to an increasingly volatile energy market, negotiating agreements to fulfil rapidly developing energy procurement mandates and beginning to implement debt collection on unpaid customer bills. Staff are also needed to pursue substantial federal and state grant funds that have been set aside for transportation emissions reduction and resilience programs for building microgrids. Staff also requests creating a full-time, permanent position to match community members to a growing array of program offerings. This work is currently performed by temporary staff, and frequent turnover results in knowledge loss and recurring training costs. The cost for adding these positions would be $260,000 with a portion of the cost being funded by grants. Staff propose that these positions be funded as long-term positions and they have been included in the proposed budget. The directors discussed the importance of planning for future needs.
There were no public comments on this item. Chair Avis closed the public comment period.
M/S: Losey, Woo: Conditionally approve positions upon passage of budget next month with these positions included:
1) Creation of an Infrastructure Programs Manager position, 2) Addition of a DSM Intake Coordinator position,
3) Addition of a Power Resources Specialist position,
4) Update to the RCEA Organization Chart, and
5) Revising the Assistant/Coordinator/Associate position to clarify the distinction between limited-term and permanent positions.
The motion passed with a unanimous roll call vote. Ayes: Avis, Bauer, Curran, Losey, Schaefer, Tuttle, Wilson, Woo. Noes: None. Absent: Bohn. Abstain: None.
8.2.FY 2022-2023 Preliminary Draft Budget
Deputy Executive Director Verbeck introduced the draft fiscal year 2022-2023 budget, based on conservative modeling by The Energy Authority. Both revenues and power procurement costs are forecast to be much higher than this year, and delinquent utility bills are expected to decrease. The budget includes the Blue Lake Rancheria loan repayment and payment for power supply to MCE. Cash from these entities made it possible for RCEA to weather a large cash shortfall this fiscal year from extreme energy cost increases and pandemic-era bill non-payments. Three additional full-time positions and higher insurance costs increased the personnel budget. The draft budget does not include revenue sources that have not yet been confirmed, such as an electric vehicle charging stations grant and CPUC funding for the proposed Rural Regional Energy Network. If awarded, these funds will help offset personnel costs. Staff conservatively estimate $8 million in net revenue next year and strongly recommend replenishing the agency’s cash reserves to survive periods of reserve depletion such as the one that was averted this fiscal year.
There was support for replenishing agency reserves and staff was thanked for developing a budget despite the volatile energy market. The directors discussed the agency’s goal of 8 RCEA May 26, 2022, Board of Directors Meeting DRAFT Minutes
returning revenues to the community through providing cheaper power and funding customer programs.
STAFF REPORTS
9.1.Deputy Executive Director’s Report
Deputy Executive Director Verbeck reported that the Humboldt wind lease area sale notice was published in the Federal Register on May 31, opening a 60-day public comment period.
The Redwood Coast Airport Microgrid opening ceremony will be on June 22 at 10:30 a.m.
The meeting was adjourned at 6:16 p.m.
Lori Taketa
Clerk of the Board
9 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of April 30, 2022
Type Date Num Name Memo Amount
Bill Pmt -Check 04/06/2022 13058 Aiqueous, LLC PowerPath Project Team Hours - March -7,462.50 Bill Pmt -Check 04/06/2022 13059 AT&T Router charges - ACV: 2/19 - 3/18 -163.00 Bill Pmt -Check 04/06/2022 13060 AT&T Long Distance Phone charges 3/25 - 4/24 -254.20 Bill Pmt -Check 04/06/2022 13061 Bithell, M. Mileage reimbursement - February 2022 -47.15 Bill Pmt -Check 04/06/2022 13062 Braun Blaising Smith Wynne Legal Services - Regulatory -Feb 2022 -22,821.72 Bill Pmt -Check 04/06/2022 13063 CalCCA VOID: Rate Case Special Assessment 0.00 Bill Pmt -Check 04/06/2022 13064 CalCCA VOID: Operational Member dues Q4 21/22 0.00 Bill Pmt -Check 04/06/2022 13065 City of Arcata March 2022 Excessive Energy Use Tax -4,841.66 Bill Pmt -Check 04/06/2022 13066 City of Arcata March 2022 Utility User Tax -11,304.30 Bill Pmt -Check 04/06/2022 13067 Donald Dame Professional Services March 2022 -437.50 Bill Pmt -Check 04/06/2022 13068 Frontier Energy, Inc. Professional Services - Program Support -952.50 Bill Pmt -Check 04/06/2022 13069 Gelinas James, Inc. Consulting services -450.00 Bill Pmt -Check 04/06/2022 13070 Hilson, D. Travel reimbursement -20.07 Bill Pmt -Check 04/06/2022 13071 Humboldt Bay Coffee Co. Office Coffee -51.90 Bill Pmt -Check 04/06/2022 13072 HWMA Greenwaste disposal -7.00 Bill Pmt -Check 04/06/2022 13073 Klein, M. VOID: USPS certified mailing 0.00 Bill Pmt -Check 04/06/2022 13074 Mission Uniform & Linen MAR mat service, janitorial supplies -73.53 Bill Pmt -Check 04/06/2022 13075 North Coast Journal Job postings -340.00 Bill Pmt -Check 04/06/2022 13076 PG&E EV Account EV stations 2/14-3/15/2022 -623.45 Bill Pmt -Check 04/06/2022 13077 Pierson's Home Ctr safety and facility repairs supplies -69.23 Bill Pmt -Check 04/06/2022 13078 Ray Morgan Company Printer Charges: 03/06-04/05/22 -41.50 Bill Pmt -Check 04/06/2022 13079 Recology March 2022 garbage service -93.21 Bill Pmt -Check 04/06/2022 13080 Verizon Wireless March 2022 Tablet/cell service -1,473.84 Check 04/06/2022 13081 VISA March 2022 Statement 2/19/2022 - 3/22/2022 -7,773.41 Bill Pmt -Check 04/06/2022 13082 Suddenlink Communications Phone & Internet access - 3/28/2022 - 4/27/2022 -0.22 Bill Pmt -Check 04/06/2022 13083 Klein, M. USPS certified mailing -36.40 Liability Check 04/07/2022 E-pay EDD Taxes -6,278.14
Liability Check 04/07/2022 E-pay Internal Revenue Service Taxes -29,223.82 Liability Check 04/07/2022 E-pay EDD Taxes -101.95
Liability Check 04/07/2022 13084 Umpqua Bank Health Savings Account -148.72 Bill Pmt -Check 04/07/2022 13085 Blue Lake Rancheria Loan Interest Payment April 2022 -13,777.78 Paycheck 04/08/2022 ACH Employees Payroll -66,965.97
Check 04/11/2022 ACH VISA Statement 3/23-4/20/22 -5,730.35 Check 04/20/2022 Umpqua Bank Service Charge -21.33
Check 04/20/2022 13087 NEM Customer NEM Annual Payout Acct #2127771674 -36.38 Check 04/20/2022 13088 NEM Customer NEM Payout Acct#: 19631010 -105.35 Check 04/20/2022 13089 NEM Customer NEM Payout Acct#: 8709930752 -194.22 Check 04/20/2022 13090 NEM Customer NEM Payout Acct#: 5575692227 -8.89 Check 04/20/2022 13091 NEM Customer NEM Payout Acct#: 5920079809 -14.34 Check 04/20/2022 13092 NEM Customer NEM Payout Acct#: 5485399033 -8.35 Check 04/20/2022 13093 NEM Customer NEM Payout Acct#: 18025566019 -24.24 Check 04/20/2022 13094 NEM Customer NEM Payout Acct#: 5834536893 -182.46 Check 04/20/2022 13095 NEM Customer NEM Payout Acct#: 9511511096 -43.51 Check 04/20/2022 13096 CCE Customer EV Rebate #EV26 -500.00 Bill Pmt -Check 04/20/2022 13097 Ameritas - Dental Ameritas Dental - April & May 2022 -3,206.42 Bill Pmt -Check 04/20/2022 13098 Ameritas - Vision Ameritas Vision - April & May 2022 -631.60 Bill Pmt -Check 04/20/2022 13099 Arcata Technology Center Site Host Reimbursement 1/1 - 3/31/2022 -302.13 Bill Pmt -Check 04/20/2022 13100 AT&T ACV charges - March and April 2022 -1,724.72 Bill Pmt -Check 04/20/2022 13101 Blue Lake Rancheria Site Host Reimbursement 1/1 - 3/31/2022 -41.69 Bill Pmt -Check 04/20/2022 13102 City of Arcata Site Host Reimbursement 1/1 - 3/31/2022 -196.90 Bill Pmt -Check 04/20/2022 13103 City of Blue Lake Site Host Reimbursement 1/1-3/31/2022 -139.11 Bill Pmt -Check 04/20/2022 13104 City of Eureka-Water Water service, 2/23-03/24/22 -246.96 Bill Pmt -Check 04/20/2022 13105 City of Eureka - REVNet Site Host Reimbursement 7/1/2021 - 3/31/2022 -1,629.44 Bill Pmt -Check 04/20/2022 13106 City of Trinidad Site Host Reimbursement 1/1 - 3/31/2022 -377.36
10 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of April 30, 2022
Type Date Num Name Memo Amount
Bill Pmt -Check 04/20/2022 13107 David L. Moonie & Co., LLP Accounting Services -3,564.00 Bill Pmt -Check 04/20/2022 13108 Diamond, Nancy March legal services -13,378.60 Bill Pmt -Check 04/20/2022 13109 Humboldt Builders' Exchange Anual membership fee and 1/4 page ad -600.00 Bill Pmt -Check 04/20/2022 13110 Keyes & Fox, LLP March legal services -343.65 Bill Pmt -Check 04/20/2022 13111 North Coast Cleaning March monthly cleaning service -480.00 Bill Pmt -Check 04/20/2022 13112 North Coast Journal Job Postings: Sr. Tech/ CS Coord./ IT Tech -234.00 Bill Pmt -Check 04/20/2022 13113 North Coast Unified Air Quality Site Host Reimbursement 1/1-3/31/2022 -523.07 Bill Pmt -Check 04/20/2022 13114 NYLEX.net, Inc. Onsite network support services - may -3,200.00 Bill Pmt -Check 04/20/2022 13115 Open Door Site Host Reimbursement 1/1-3/31/2022 -154.24 Bill Pmt -Check 04/20/2022 13116 SDRMA P&L EV stations item insurance adjustments -198.42 Bill Pmt -Check 04/20/2022 13117 St. Joseph Hospital Site Host Reimbursement 1/1 - 3/31/2022 -898.28 Bill Pmt -Check 04/20/2022 13118 Stewart's Landscaping and Tractor Service Mowing services for ACV solar site -3,600.00 Bill Pmt -Check 04/20/2022 13119 Times Printing Company CCE mailers and DSM program printing services -2,536.43 Bill Pmt -Check 04/20/2022 13120 Winzler, John VOID: Office Lease - May 2022 0.00 Bill Pmt -Check 04/20/2022 13121 Winzler, John Office Lease - May 2022 -7,132.00 Bill Pmt -Check 04/22/2022 ACH Snow Mountain Hydro, LLC March 2022 Electricity -47,475.29 Bill Pmt -Check 04/22/2022 ACH Leapfrog Energy March 2022 RA -36,740.00 Bill Pmt -Check 04/22/2022 ACH Humboldt Sawmill Co. March 2022 Electricity -592,286.42 Bill Pmt -Check 04/22/2022 ACH CalPine Corporation Calpine March 2022 Costs -61,541.76 Liability Check 04/22/2022 E-pay EDD Taxes -5,934.02
Liability Check 04/22/2022 E-pay Internal Revenue Service Taxes -28,114.46 Liability Check 04/22/2022 E-pay EDD Taxes -35.93
Paycheck 04/25/2022 ACH Employees Payroll -63,967.52
Bill Pmt -Check 04/28/2022 ACH CA Dept. of Tax & Fee Administration Electrical Energy Surcharge Q1 2022 -50,774.00 Liability Check 04/29/2022 E-pay EDD Taxes -415.82
Liability Check 04/29/2022 E-pay EDD Taxes -45.91
Liability Check 04/29/2022 E-pay Internal Revenue Service Taxes -2,909.58 Liability Check 04/29/2022 E-pay Internal Revenue Service Taxes -983.18 Liability Check 04/29/2022 E-pay Arizona Department of Revenue Taxes -45.09 Liability Check 04/29/2022 E-pay Arizona Department of Revenue Taxes -33.40 Paycheck 04/29/2022 ACH Employee Final Paycheck -1,823.86 TOTAL -1,121,169.35
11 Redwood Coast Energy Authority
Profit & Loss Budget vs. Actual
July 2021 through April 2022
Jul '21 - Apr 22 Budget % of Budget
Ordinary Income/Expense
Income
5 REVENUE EARNED
Total 5000 · Revenue - government agencies 431,995.65 911,000.00 47.42% Total 5100 · Revenue - program related sales 21,626.94 31,000.00 69.76% Total 5400 · Revenue-nongovernment agencies 1,167,300.83 1,377,873.00 84.72% Total 5500 · Revenue - Electricity Sales 37,234,364.30 44,645,168.00 83.4% Total 5 REVENUE EARNED 38,855,287.72 46,965,041.00 82.73% Total Income 38,855,287.72 46,965,041.00 82.73%
Gross Profit 38,855,287.72 46,965,041.00 82.73%
Expense
Total 6 WHOLESALE POWER SUPPLY 41,120,391.77 41,084,582.00 100.09% Total 7 PERSONNEL EXPENSES 2,477,642.87 3,517,800.00 70.43% Total 8.1 FACILITIES AND OPERATIONS 524,235.16 3,313,389.00 15.82% Total 8.2 COMMUNICATIONS AND OUTREACH 76,313.83 118,570.00 64.36% Total 8.3 TRAVEL AND MEETINGS 4,060.83 44,300.00 9.17%
8.4 PROFESSIONAL & PROGRAM SRVS
8400 · Regulatory 150,898.45 180,000.00 83.83%
8410 · Contracts - Program Related Ser 283,214.39 393,000.00 72.07% 8420 · Accounting 8,145.00 55,000.00 14.81%
8430 · Legal 127,699.95 153,000.00 83.46%
8450 · Wholesale Services - TEA 545,820.00 639,088.00 85.41% 8460 · Procurement Credit - TEA 569,577.36 340,032.00 167.51% 8470 · Data Management - Calpine 615,063.36 738,144.00 83.33% Total 8.4 PROFESSIONAL & PROGRAM SRVS 2,300,418.51 2,498,264.00 92.08% Total 8.5 PROGRAM EXPENSES 489,835.34 631,393.00 77.58% Total 8.6 INCENTIVES & REBATES 94,955.15 601,000.00 15.8% Total 9 NON OPERATING COSTS 91,947.78 414,320.00 22.19% Total Expense 47,179,801.24 52,223,618.00 90.34%
Net Ordinary Income -8,324,513.52 -5,258,577.00 158.3%
Other Income/Expense
Total Other Income 0.00 6,600,000.00 0.0%
Net Other Income 0.00 6,600,000.00 0.0%
Net Income -8,324,513.52 1,341,423.00 -620.57%
12 Redwood Coast Energy Authority
Balance Sheet
As of April 30, 2022
Apr 30, 22
ASSETS
Current Assets
Checking/Savings
1010 · Petty Cash 300.00
1050 · GRANTS & DONATIONS 3840 15,995.51
1060 · Umpqua Checking Acct 0560 -33,289.49
1071 · Umpqua Deposit Cntrol Acct 8215 3,923,240.08
1075 · Umpqua Reserve Account 2300 99,978.67
1076 · First Republic Bank - 4999 62,263.94
8413 · COUNTY TREASURY 3839 5,329.01
Total Checking/Savings 4,073,817.72
Total Accounts Receivable 85,423.99
Other Current Assets
1101 · Allowance for Doubtful Accounts -2,143,053.86
1103 · Accounts Receivable-Other 10,160,753.82
1120 · Inventory Asset 21,715.00
1202 · Prepaid Expenses -12,792.59
1205 · Prepaid Insurance 11,998.61
1499 · Undeposited Funds 1,403.00
Total Other Current Assets 8,040,023.98
Total Current Assets 12,199,265.69
Total Fixed Assets 8,493,660.71
Other Assets
1700 · Retained Deposits 4,293,600.00
Total Other Assets 4,293,600.00
TOTAL ASSETS 24,986,526.40
LIABILITIES & EQUITY
Liabilities
Current Liabilities
Total Accounts Payable 5,211,055.63
Total Credit Cards 1,798.72
Other Current Liabilities
2002 · Deposits Refundable 244,845.00
2013 · Unearned Revenue - PA 2020-2023 1,156,963.30
2050 · Liabilities
2056 · BLR Short Term Loan 2,000,000.00
2057 · MCE Short Term Loan 4,000,000.00
Total 2050 · Liabilities 6,000,000.00
Total 2100 · Payroll Liabilities 174,402.07
Total Other Current Liabilities 7,576,210.37
Total Current Liabilities 12,789,064.72
Long Term Liabilities
2700 · Long-Term Debt
2704 · USDA Loan 6,287,592.00
Total 2700 · Long-Term Debt 6,287,592.00
Total Long Term Liabilities 6,287,592.00
Total Liabilities 19,076,656.72
Equity
2320 · Investment in Capital Assets 215,489.00
3900 · Fund Balance 14,018,894.20
Net Income -8,324,513.52
Total Equity 5,909,869.68
TOTAL LIABILITIES & EQUITY 24,986,526.40
13
STAFF REPORT
Agenda Item # 3.4
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Aisha Cissna, Regulatory and Legislative Policy Manager SUBJECT: Net Energy Metering Successor Tariff Update
BACKGROUND
The net energy metering (“NEM”) tariff allows customers who install rooftop solar, and other electric generation technology, to serve their onsite energy needs and receive credits on their electric bills for surplus energy sent to the electric grid. The NEM tariff was initially established in California in the late 90s’ and has been revised once. The original tariff is referred to as “NEM
1.0” and the current tariff is referred to as “NEM 2.0”.
In August 2020, the California Public Utilities Commission (CPUC) initiated a proceeding to develop a successor tariff to NEM 2.0.
On December 13, 2021, the CPUC issued a Proposed Decision establishing the proposed, new tariff provisions.
On February 3, 2022, the CPUC requested additional time to analyze the record and consider revisions to the proposed decision based on party comments, effectively putting the decision on hold.
On May 9, 2022, the CPUC issued a Ruling asking for comments on three specific portions of the previously issued Proposed Decision: the export compensation glide path approach, non-bypassable charges, and community solar.
On June 10, 2022, RCEA and three other CCAs submitted opening comments responding to the Ruling. These comments are summarized below.
Reply comments, which respond to the opening comments filed by other parties, are due July 1, 2022.
The earliest the CPUC is anticipated to arrive at a successor tariff decision is late July.
SUMMARY
On May 9, 2022, the CPUC issued a Ruling asking for comments on three specific portions of the previously issued Proposed Decision: the export compensation glide path approach, non-bypassable charges, and community solar (also referred to more broadly as “community distributed energy resources”).
The glide path approach describes the process by which the current NEM 2.0 tariff export compensation rate will transition to the successor tariff compensation rate. NEM 2.0 bases the 14
export compensation rate on the retail rate paid for solar. Under the successor tariff, customers would instead be compensated for their exports based on the avoided cost calculator (“ACC”) rate. The “Avoided Cost Calculator” refers to a CPUC tool which calculates the costs that the electric grid is able to avoid through the deployment of distributed energy resources (such as rooftop solar). The avoided cost calculator export compensation rate changes by climate zone and on an hourly basis, depending on the value that rooftop solar energy provides the grid. The ACC value compensates NEM customers at a lower value than the retail rate current NEM 2.0 customers receive.
The May 2022 Ruling introduces the “ACC Plus Adder” glide path approach. With this approach, the adder would be layered on top of the ACC-based hourly export credits. The adder would step down gradually over time to the ACC export compensation rate.
The Ruling primarily sought party input on what the adder amount should be and what the step-down timeline should look like. The Joint CCAs said that the adder amount should essentially be the difference between the ACC value and the electrification rate that is initially eligible for the successor tariff (see chart below)
For the step-down timeline, the Joint CCAs propose that the adder amount should decrease in-step with the amount of rooftop solar that is deployed. The adder would decrease by 10% when 1 GW of rooftop solar is installed until a total of 10GW of rooftop solar has been installed and the export rate is the ACC rate. This 10 GW goal is set based on the CPUC’s 2030 greenhouse gas reduction goals for the electric sector.
The second topic for which the CPUC seeks party comments is related to non-bypassable charges (NBCs). NBCs are fees that customers pay on every kilowatt-hour of electricity that they consume from the grid. These charges are used to fund things like wildfire mitigation, energy assistance programs for low-income households, energy efficiency programs, and nuclear decommissioning. Primarily, the Ruling asks whether NBCs on gross consumption should be collected from successor tariff customers, whether NBCs should only be collected $0
$50
$100
$150
$200
$250
$300
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Avoided Cost Calculator Rate ($/kWh)
Hour Ending (Standard Time)
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.24
$0.45
Electrification Rate
$0.45
$0.56
15
from a subset of successor tariff customers, and which electric program and securitization charges should be considered as NBCs.
On the principle of fairness and equity, the Joint CCAs say that customers participating in the successor tariff should pay the same set of NBCs that non-participating customers pay.
Regarding exemptions for a subset of tariff customers, the Joint CCAs say that low-income customers who participate in the tariff should be exempt from NBCs to the extent their low-income non-participating counterparts are exempt. If new NBCs are established in the future, the Joint CCAs reiterate that successor tariff customers should be treated the same as non-participating customers.
The third topic for which the CPUC seeks party comment is the design of a community solar program, or sub-tariff. Community solar programs allow customers who are not able to install their own rooftop solar to receive bill savings from a solar project installed in their community.
The Ruling asks parties to weigh-in on whether a new community solar program should be designed based off the successor tariff design, or existing community solar programs. The Joint CCAs respond with a set of guiding principles. Specifically, the Joint CCAs say that any community solar program that is developed should have a strong physical nexus to the community it serves, should serve both disadvantaged and low-income customers, should be large enough to serve all customers who are qualified to participate, and should yield guaranteed bill savings for community solar participants.
Note that this Ruling is not reopening other aspects of the Proposed Decision (for example, the Grid Participation Charge a.k.a. “solar tax”) for consideration and party input.
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
Under section 4.3 “Rates and Tariffs,” RCEA sets a goal to “Provide a net energy metering program that encourages more distributed local generation and more equitably compensates such generation.” Changes to the NEM tariff could impact RCEA’s compensation structure.
Under the “Provide Education on all Electric Rate Schedule Options”, RCEA sets a goal to “Provide information on all available rate schedules including Net Energy Metering...” Tracking NEM successor tariff developments is important to providing customers with up-to-date information on the NEM rate schedule.
EQUITY IMPACTS
This Ruling poses several considerations regarding the applicability of the glide path, non-bypassable charges, and community solar programs respective to low-income customers.
The Joint CCA opening comments state that low-income customers should always receive the electrification rate for their exports with no step-down to the ACC rate, that any community solar program should be open to both disadvantaged and low-income customers, and low-income customers should be exempt from NBCs to the extent non-participating low-income customers are also exempt.
RECOMMENDED ACTION
Accept Update on Net Energy Metering Successor Tariff Comment Letter Submitted by RCEA Staff to the California Public Utilities Commission.
16
ATTACHMENTS
Joint CCA Comment Letter: “Comments of East Bay Community Energy, Redwood Coast Energy Authority, San Diego Community Power, and Peninsula Clean Energy Authority on the Administrative Law Judge’s Ruling Setting Aside Submission of the Record to Take Comment on a Limited Basis”
17 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Order Instituting Rulemaking to Revisit Net
Metering Tariffs Pursuant to Decision 16-01-044,
and to Address Other Issues Related to Net Energy
Metering
Rulemaking No. 20-08-020
(Filed August 27, 2020)
COMMENTS OF EAST BAY COMMUNITY ENERGY, REDWOOD COAST ENERGY
AUTHORITY, SAN DIEGO COMMUNITY POWER, AND
PENINSULA CLEAN ENERGY AUTHORITY
ON THE ADMINISTRATIVE LAW JUDGE’S RULING SETTING ASIDE
SUBMISSION OF THE RECORD TO TAKE COMMENT ON A LIMITED BASIS Aisha Cissna
Regulatory and
Legislative Policy Manager
Redwood Coast Energy Authority
633 Third Street
Eureka, CA 95501
[email protected]
Telephone: 707-269-1700
Melissa Brandt
Vice President of Public Policy and
Deputy General Counsel
East Bay Community Energy
1999 Harrison Street, Suite 800
Oakland, CA 94612
[email protected]
Telephone: 510-570-5110
Laura Fernandez
Director of Regulatory and
Legislative Affairs
San Diego Community Power
815 E Street, Suite 12716
San Diego, CA 92112
[email protected]
Telephone: 619-657-0406
Jeremy Waen
Director of Regulatory Policy
Peninsula Clean Energy Authority
2075 Woodside Road
Redwood City, CA 94061
[email protected]
Telephone: 650-257-8026
Dated: June 10, 2022
FILED
06/10/22
04:59 PM
R2008020
18 2
TABLE OF CONTENTS
I. Introduction ............................................................................................................................ 4 II. Joint CCA Responses to Questions ....................................................................................... 5 a. Ruling Question 1: Explain why you would or would not support the ACC Plus residential customer glide path approach as an alternative to the current MTC approach. . 5 b. Ruling Question 2: All else equal, do you consider the ACC Plus glide path to be a more effective approach in ensuring that customer-sited renewable distributed generation continues to grow sustainably, compared to a glide path approach that sets export compensation rates at a declining percentage of the retail per-kWh rates, and/or is based on an MTC? Elaborate in your response. ................................................................................... 6 c. Ruling Question 3: If the Commission adopts the ACC Plus, would Tariff customers be more likely to provide higher value to the electric grid than under a glide path approach that is based on a percentage of retail rates, since price signals for exports would reflect the hourly differences in export value to the system based on ACC values? ................................. 6 d. Ruling Question 4: If the Commission adopts the ACC Plus, should the Commission consider alternatives to the fixed c/kWh adder value, such as a multiplier (Y) defined as a fixed percent that would increase export compensation in all hours by the same percentage in all hours (i.e., hourly ACC value * (1+Y))? Why or why not? .............................................. 7 e. Ruling Question 5: If the Commission adopts the ACC Plus, should a single adder apply to both solar-only and solar+storage systems, or should separate adders apply to solar-only systems and solar+storage systems? If a single adder is used, should the focus of the design be the customer economics of solar-only systems or solar+storage systems? If separate adders are used by technology, how would the investor-owned utilities (Utilities) distinguish between solar-only systems and solar+storage systems in their interconnection portals, and how would Utilities verify the technology associated with the Tariff applications to ensure the correct adder is being used? ............................................................. 7 f. Ruling Question 6: If the Commission adopts the ACC Plus, are there any potential impacts to how customers would dispatch battery systems that should be taken into consideration? For example, would the ACC Plus impact how solar+storage customers decide when to export versus consume behind-the-meter? ....................................................... 8 g. Ruling Question 7: Some parties expressed concerns that the proposed decision would lead to an abrupt change in bill savings for customer-generators and would not provide a smooth transition for the solar industry. ..................................................................................... 8 h. Ruling Question 8: The proposed decision recommends giving low-income customers, as defined in the proposed decision, a higher MTC than non-low-income customers so these customers can achieve similar customer economics. This is reflected in the MTC amounts proposed in the proposed decision’s Table 5. If the Commission adopts the ACC Plus, should the ACC Plus be a different amount in Year 1 of the glidepath for low-income customers compared to non-low-income customers? Should the ACC Plus be stepped down on a different timeframe or rate of change for low-income customers compared to non-low-19 3 income customers? Describe your rationale, including the basis for your proposed glide path for low-income customers (higher bill savings, lower payback period, etc.). ................ 10 i. Ruling Question 9: If the Commission adopts the ACC Plus, describe whether and why it should (or should not) apply to nonresidential customers. If you believe it should apply to nonresidential customers, should the ACC Plus be a different amount in Year 1 of the glide path compared to residential customers? Should the ACC Plus be stepped down on a different timeframe or rate of change for nonresidential customers compared to residential customers? Describe your rationale, including the basis for your proposed glide path for nonresidential customers. ........................................................................................................... 10 j. Ruling Question 10: If the Commission adopts the approach of collecting NBCs on gross consumption from Tariff customers, should the Commission consider collecting from all Tariff customers or only a subset of Tariff customers? For example, should the Commission consider collecting from all nonresidential and residential customers; only residential customers; only non-low-income residential customers; or all residential customers plus non-residential customers on certain rates? Explain your rationale. .......... 11 k. Ruling Question 11: If NBCs on gross consumption are collected from Tariff customers, which of the following list of electric program and securitization charges should be considered as NBCs for Tariff customers, and why? If there are any additional existing electric program or securitization charges that parties believe should be collected as NBCs that are not on this list, please include them and explain your rationale. Utilities are instructed to clarify which of these charges do and do not apply to their customers. .......... 11 l. Ruling Question 12: If the Commission imposes additional electric program or securitization charges in the future through other proceedings, what is the process by which the Commission should determine whether and how those charges should apply to Tariff customers as NBCs? ......................................................................................................... 13 m. Ruling Question 13: Would low-income customers and/or renters benefit from a community solar tariff program modeled on the Tariff structure compared to participation in the CSGT program? Please describe advantages and disadvantages between the two community solar models. ............................................................................................................ 13 n. Ruling Question 14: The CSGT program guarantees participants 20 percent bill savings, in addition to the California Alternate Rates for Energy (CARE) and Family Electric Rate Assistance (FERA) discounts. Should the Commission adopt a policy that any community solar program or tariff guarantee a certain level of bill savings for low-income participants and/or renters to increase participation and ensure consumer protections? If yes, how would a bill savings guarantee be monitored and enforced? Parties may wish to provide examples of how other states have incorporated a bill savings guarantee, as well as the level of guaranteed savings, into their community solar tariff programs, and lessons learned. ......................................................................................................................................... 15 III. Conclusion ......................................................................................................................... 16 20 4
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Order Instituting Rulemaking to Revisit Net
Metering Tariffs Pursuant to Decision 16-01-044,
and to Address Other Issues Related to Net Energy
Metering
Rulemaking No. 20-08-020
(Filed August 27, 2020)
COMMENTS OF EAST BAY COMMUNITY ENERGY, REDWOOD COAST ENERGY
AUTHORITY, SAN DIEGO COMMUNITY POWER, AND
PENINSULA CLEAN ENERGY
ON THE ADMINISTRATIVE LAW JUDGE’S RULING SETTING ASIDE
SUBMISSION OF THE RECORD TO TAKE COMMENT ON A LIMITED BASIS East Bay Community Energy, Redwood Coast Energy Authority, San Diego Community Power, and Peninsula Clean Energy Authority, (together, “Joint CCAs”) respectfully submit these comments in response to the Administrative Law Judge’s Ruling Setting Aside Submission of the Record to Take Comment on a Limited Basis, issued on May 9, 2022.
I. Introduction
The Joint CCAs support the sustainable growth of distributed solar and solar plus storage to enable the state and our local jurisdictions to meet our ambitious carbon reduction goals. The California Solar Initiative made substantial initial progress in enabling a solar rooftop industry in California. As renewables procurement has intensified and the grid now requires higher levels of renewables integration, encouraging battery installation on distributed generation is crucial to unlocking maximum value and carbon reduction benefits from rooftop solar. In addition to our large-scale solar plus storage procurements, the Joint CCAs are 21 5
focused on programs and mechanisms to incentivize distributed solar plus storage and our responses to the questions below reflect our desire to have 100% of future solar installations include storage.
II. Joint CCA Responses to Questions
a. Ruling Question 1: Explain why you would or would not support the ACC Plus residential customer glide path approach as an alternative to the current MTC approach.
The proposed Avoided Cost Calculator (“ACC”) Plus residential customer glide path approach is a better glide path for transition to the successor tariff for customers and the solar industry. Additionally, it is preferable to the Market Transition Credit (“MTC”) because it directly incentivizes more battery installation. The MTC would be a fixed $/kW of solar system size, provided as a monthly electricity bill credit. The ACC Plus, on the other hand, would provide a fixed $/kWh adder on top of the ACC credit from the expected hourly value of exports to the system. As the MTC supplements the ACC based on a fixed system size, it does nothing to encourage export in high value hours or minimize export in low value hours; in summary, it does not contribute to encouraging installation of batteries on solar systems nor matching onsite demand and supply. Battery installation is incentivized when customers obtain enough value from minimizing exports during low-value hours and instead relying on their stored generation during high-value hours when consumption is otherwise more costly. By amplifying the ACC, the ACC Plus provides more value to customers for their exports in higher-value hours, encouraging customers to install batteries to minimize exports in low-value hours. The ACC Plus adder amount needs to be high enough to serve as a true glide path, supporting the continued sustainable growth of distributed generation and solar plus storage. As further described below, the Joint CCAs suggest that the adder amount be set at the difference between the electrification 22 6
rate and ACC rate.
b. Ruling Question 2: All else equal, do you consider the ACC Plus glide path to be a more effective approach in ensuring that customer-sited renewable distributed generation continues to grow sustainably, compared to a glide path approach that sets export compensation rates at a declining percentage of the retail per-kWh rates, and/or is based on an MTC? Elaborate in your response.
Starting the glide path at an ACC with an adder or at a declining percentage of the retail export rate can both be effective (and very similar) strategies for growing customer-sited renewable distributed generation sustainably; it all depends on the amount of the adder and rate of decline. As currently proposed, the MTC does not adequately support the sustainable growth of distributed generation plus storage, in the same manner; four years is too short, and as indicated in our response to Ruling Question 1, the MTC does not encourage a higher storage attachment rate.
The Joint CCAs support Sierra Club’s proposal to set the glide path starting point at the utility electrification rate because electrification rates are also cost-based which inherently reduces cost shifting, electrification rates are understood by customers and installers, the high differentials in peak and off-peak rates align customer consumption and exports with greenhouse gas (GHG) reduction and system benefits, and electrification rates support adoption of other electrification technologies. Additionally, a glide path to an export credit rate based on avoided costs is necessary to prevent the sharp falloff in installations which occurred in Hawaii and Nevada when they moved too aggressively. The Sierra Club’s proposal would ensure the certainty which is necessary for customer investments by fixing to the rate of export compensation for 20 years and does not decline over time. c. Ruling Question 3: If the Commission adopts the ACC Plus, would Tariff customers be more likely to provide higher value to the electric grid than 23 7
under a glide path approach that is based on a percentage of retail rates, since price signals for exports would reflect the hourly differences in export value to the system based on ACC values?
Expecting customers to shift behavior based on the ACC hourly values assumes a level of complexity that may instead confuse many customers. Retail rates are inherently easier to understand and expecting responsiveness to an hourly-based ACC is unrealistic. However, the electrification rate is based on Time-of-Use (“TOU”) and may be a simpler way to incentivize behavioral changes that provide higher value to the electric grid. d. Ruling Question 4: If the Commission adopts the ACC Plus, should the Commission consider alternatives to the fixed c/kWh adder value, such as a multiplier (Y) defined as a fixed percent that would increase export compensation in all hours by the same percentage in all hours (i.e., hourly ACC value * (1+Y))? Why or why not?
Yes, the Commission should consider adopting a multiplier as a fixed percent instead of the fixed $/kWh approach of the proposed ACC Plus. A flat/fixed adder encourages exports at times when they are least valuable to the grid, by increasing the value of exports in those hours.
A percentage multiplier, however, would amplify the ACC TOU signals at a higher proportion in high-value hours versus low-value hours, encouraging more exports (or battery dispatch) in higher value hours. The multiplier would be more supportive of encouraging a higher storage attachment rate and dispatch of those batteries during high value hours. e. Ruling Question 5: If the Commission adopts the ACC Plus, should a single adder apply to both solar-only and solar+storage systems, or should separate adders apply to solar-only systems and solar+storage systems? If a single adder is used, should the focus of the design be the customer economics of solar-only systems or solar+storage systems? If separate adders are used by technology, how would the investor-owned utilities (Utilities) distinguish between solar-only systems and solar+storage systems in their interconnection portals, and how would Utilities verify the technology associated with the Tariff applications to ensure the correct adder is being used? 24 8
A single adder should apply to both solar-only and solar+storage systems. The underlying structure of the ACC Plus with its time-differentiated rates already provides incentives to encourage solar+storage. Adopting separate adders would be too complex and risks discriminating against one technology by giving it the wrong economic signals. The single adder approach aligns better with valuing benefits across different distributed energy resources based on the value they provide at a given point in time.
f. Ruling Question 6: If the Commission adopts the ACC Plus, are there any potential impacts to how customers would dispatch battery systems that should be taken into consideration? For example, would the ACC Plus impact how solar+storage customers decide when to export versus consume behind-the-meter? The ACC Plus would help to stimulate responsiveness to market prices. However, it is worth noting that installed batteries will primarily be used to maximize self-consumption and minimize a customer’s consumption in higher-value hours, which would result in less or no exports to the grid. Given that this behavior would reduce onsite demand by a corresponding amount, it would still support grid reliability.
g. Ruling Question 7: Some parties expressed concerns that the proposed decision would lead to an abrupt change in bill savings for customer-generators and would not provide a smooth transition for the solar industry. a. If the Commission adopts the ACC Plus, explain what the basis should be for determining the ACC Plus adder amount in Year 1 of the glide path and why. For example, should the ACC Plus amount target a certain payback period, or a certain level of bill savings, an approximate a percentage of retail rate, or some other metric? Provide any recommendations for what the ACC Plus amount should be in Year 1.
b. If the Commission adopts the ACC Plus, describe your proposed timeframe over which the ACC Plus is offered to prospective Tariff customers, the rate of step-down so the glide path ends at ACC-based values, and your rationale.
The Joint CCAs were among the parties expressing concerns about the abrupt change in 25 9
bill savings and the need for a more measured glide path approach. For the same reasons iterated in our comments on the Proposed Decision (“PD”), the Joint CCAs maintain that customer-generators should initially receive the electrification rate for exports with a glide path down towards the ACC in tranches, 10% reduction per tranche, each tranche consisting of an additional one GW installed capacity, until 10 GW have been installed and the export rate is the ACC, and no grid benefit charge. The ACC Plus adder should thus initially be set to the amount above the ACC that brings export compensation up to the electrification rate level. The electrification rate level will give customer-generators appropriate price signals to motivate additional adoption of solar+storage, with an adjustment period that is reasonable, allows time for the industry to adjust, and enables future sustainable growth. If the Commission adopts the grid benefit charge, the ACC Plus should also consider the bill savings impact the grid benefit charge will have.
The volumetric approach is the best way to determine the rate of step-down; in other words, by stepping down incrementally as additional solar and solar+storage capacity is installed. A volumetric step-down policy ensures that distributed generation is in fact growing sustainably; should the reduction in the ACC Plus slow the growth trajectory, the mechanism prevents further reduction until the industry has time to recover from the change. This mechanism was used successfully with the California Solar Initiative to ensure that support for new rooftop solar installation was provided at the levels needed when it was first rolled out in California and could decline as the installations grew across the state. Similarly, here, the step-down rate would be based on the success of growth. If solar+storage is thriving at a healthy level at the electrification rate, the step-down will happen more quickly; if not, there’s a built-in mechanism to slow the decline until a lower rate can be successful. 26 10
h. Ruling Question 8: The proposed decision recommends giving low-income customers, as defined in the proposed decision, a higher MTC than non-low-income customers so these customers can achieve similar customer economics. This is reflected in the MTC amounts proposed in the proposed decision’s Table 5. If the Commission adopts the ACC Plus, should the ACC Plus be a different amount in Year 1 of the glidepath for low-income customers compared to non-low-income customers? Should the ACC Plus be stepped down on a different timeframe or rate of change for low-income customers compared to non-low-income customers? Describe your rationale, including the basis for your proposed glide path for low-income customers (higher bill savings, lower payback period, etc.).
The Joint CCAs propose that the ACC Plus be set at the difference between the ACC and the electrification rate for low-income customers with no step-down. This policy would truly help low-income customers over time and is an essential path toward achieving a successor tariff that ensures equity among customers. Whenever a low-income customer installs a successor tariff-eligible distributed generation system, they should receive the benefits of the higher ACC Plus. Low-income customers on average are later adopters of distributed generation, and they should be able to rely on benefits whenever they are able to install solar, instead of missing out on the benefits given to other customers earlier on in the program. Starting low-income customers on the electrification rate will also continue to incentivize adoption of solar+storage for these customers. Enabling them to receive an adder beyond the ACC for a longer period provides needed support to encourage solar adoption among this customer segment for whom customer-sited distributed generation has historically been mostly out of reach. i. Ruling Question 9: If the Commission adopts the ACC Plus, describe whether and why it should (or should not) apply to nonresidential customers. If you believe it should apply to nonresidential customers, should the ACC Plus be a different amount in Year 1 of the glide path compared to residential customers? Should the ACC Plus be stepped down on a different timeframe or rate of change for nonresidential customers compared to residential customers? Describe your rationale, including the basis for your proposed glide path for nonresidential customers.
27 11
The ACC Plus should apply equally to residential and nonresidential customers, with the same amount for the adder and same glide path rate of change. This ensures equity among customer classes. It further ensures that the policy goals sought through NEM reform, including continuing to sustainably grow customer-sited distributed generation plus storage and reduce GHG emissions, can be achieved without unintended consequences or incentives that conflict among the customer classes. Additionally, one ACC Plus is simpler to calculate and administer. j. Ruling Question 10: If the Commission adopts the approach of collecting NBCs on gross consumption from Tariff customers, should the Commission consider collecting from all Tariff customers or only a subset of Tariff customers? For example, should the Commission consider collecting from all nonresidential and residential customers; only residential customers; only non-low-income residential customers; or all residential customers plus non-residential customers on certain rates? Explain your rationale.
Consistent with the Joint CCAs’ comments on the PD and as a matter of fairness and equity, Tariff customers should be treated in the same manner as non-Tariff customers. In other words, Tariff customers should receive the same treatment as non-Tariff customers that have similar load and/or other cost-related characteristics." For this reason, Nonbypassable Charges (“NBCs”) should be collected from all Tariff customers. There is no policy reason for excluding certain Tariff customers from charges that are meant to advance social policy and that all other customers pay. With respect to low-income customers, they should only be exempt from NBCs to the extent non-Tariff low-income customers are also exempt; in other words, they should be treated no differently from other low-income customers in terms of what NBCs they are subject to, merely because they are a Tariff customer.
k. Ruling Question 11: If NBCs on gross consumption are collected from Tariff customers, which of the following list of electric program and securitization charges should be considered as NBCs for Tariff customers, and why? If 28 12
there are any additional existing electric program or securitization charges that parties believe should be collected as NBCs that are not on this list, please include them and explain your rationale. Utilities are instructed to clarify which of these charges do and do not apply to their customers. • Public Purpose Programs (currently NEM 2.0 customers pay on imports) • DWR Bond Charge/Wildfire Fund (currently NEM 2.0 customers pay on imports)
• Competition Transition Charge (currently NEM 2.0 customers pay on imports)
• Nuclear Decommissioning (currently NEM 2.0 customers pay on imports) • New System Generation
• Reliability Services
• PUC Reimbursement Fee
• Energy Cost Recovery Account
• Wildfire Hardening
• Local Generation
• Power Charge Indifference Adjustment
It is the Joint CCAs’ understanding that current NEM customers are assessed the Public Purpose Program charge, the Department of Water Resources Bond Charge, the Competition Transition Charge, and the Nuclear Decommissioning Charge, as well as the Power Charge Indifference Adjustment, and exempted from the New System Generation Costs, Reliability Services, the PUC Reimbursement Surcharge, the Energy Cost Recovery Account (for Pacific Gas & Electric Company), Investor-owned Utility securitization costs relating to wildfires and other under-collections, and the Wildfire Fund Charge. The Joint CCAs’ position is that NEM customers should be assessed all of these NBCs; there is no reason to exempt NEM customers and treat them differently than non-NEM customers with respect to contributing to NBCs.
That said, the PCIA should continue to be collected as it presently is from NEM customers on an annualized net-usage basis. The IOUs do not currently deliver bill quality data in an interval format necessary for CCAs to properly account for PCIA assessed on either a gross consumption or hourly basis. Furthermore, since PCIA charges appear on customers’ generation 29 13
side of bills, while all other NBCs appear on the distribution portion of bills, it would likely require IOU billing system changes to alter how PCIA charges are assessed, charged to customers, and communicated to LSEs that serve these customers. For all of these reasons, the Joint CCAs recommend the Commission direct that only PCIA charges be collected from Tariff participants in the same manner as they are presently collected from NEM 2.0 participants. l. Ruling Question 12: If the Commission imposes additional electric program or securitization charges in the future through other proceedings, what is the process by which the Commission should determine whether and how those charges should apply to Tariff customers as NBCs?
In imposing additional electric NBCs in the future through other proceedings, the Commission should treat Tariff customers the same as other like customer classes (e.g., treat Tariff residential the same as non-Tariff residential, etc.) in determining whether and how the charges should apply.
m. Ruling Question 13: Would low-income customers and/or renters benefit from a community solar tariff program modeled on the Tariff structure compared to participation in the CSGT program? Please describe advantages and disadvantages between the two community solar models.
The Joint CCAs subscribe to three overarching principles that should be used to evaluate the merits of a community solar program. One, the program should have a strong physical nexus to the community it serves. Otherwise, the program is no different than the wholesale contracts for solar and solar+storage throughout the state already being undertaken by load-serving entities (“LSEs”) to serve their customers. Many LSEs already offer products to serve their customers with 100% renewable energy; these products provide options for tenants who cannot install their own customer-sited distributed generation. There is no clear policy reason to create a new structure for solar/solar+storage projects that are not situated in the community for which the 30 14
energy is intended; it becomes essentially wholesale procurement by non-LSEs. Two, if the purpose of the program is to provide a distributed generation-style solar product to low-income customers, it must come at a discount for those customers. Otherwise, the program will be increasing costs for our most vulnerable customers including both low-income customers who qualify for rate assistance programs like California Alternate Rates for Energy (CARE) and Family Electric Rate Assistance (FERA), and those who do not meet the minimum threshold but are still very much struggling to pay their electric bills. Three, the program should serve both disadvantaged communities (DACs) and low-income communities; in other words, enrollment should not be limited to only customers who live in CalEnviroScreen DAC communities.
The existing Community Solar Green Tariff (“CSGT”) program meets the first two criteria. Eligible projects have to be located in a disadvantaged community, and within five miles of the community served. Second, customers enrolled in CSGT receive a 20% electricity bill discount. Renters can apply, and there are no subscription or termination fees. However, one shortcoming of the CSGT as a community solar model is that it is not open to low-income customers who do not live in disadvantaged communities. Another shortcoming of the CSGT is that the presently authorized program size is nowhere large enough to serve all customers who are qualified to participate.
The Tariff structure, as articulated in the current Proposed Decision, does not adopt a community solar tariff program. Assuming a community solar tariff program modeled on the Tariff structure means a program by which a larger project can declare itself community solar and thus be eligible for the Tariff, the pros and cons will depend on implementation details.
What type and size of site will be eligible? Must the project be fully subscribed? Cost savings will be more uncertain using the Tariff which is hard to predict, versus the CSGT’s 20% 31 15
discount. It is unclear what subscription requirements and terms including length of contract and termination fees will be, etc. Furthermore, would the community solar tariff program be sited in or near the subscribers’ community to ensure that the benefit of the local project investment reaches the community and that the project is contributing to subscribers being part of local distributed generation versus LSE-style wholesale renewable project procurement? Without knowing the answers to these questions, it is premature to determine whether low-income customers and/or renters would benefit from a community solar tariff program modeled on the Tariff structure compared to participation in the CSGT program. n. Ruling Question 14: The CSGT program guarantees participants 20 percent bill savings, in addition to the California Alternate Rates for Energy (CARE) and Family Electric Rate Assistance (FERA) discounts. Should the Commission adopt a policy that any community solar program or tariff guarantee a certain level of bill savings for low-income participants and/or renters to increase participation and ensure consumer protections? If yes, how would a bill savings guarantee be monitored and enforced? Parties may wish to provide examples of how other states have incorporated a bill savings guarantee, as well as the level of guaranteed savings, into their community solar tariff programs, and lessons learned.
One of the clear benefits for customers enrolling in CSGT is the guaranteed bill savings.
Certainly, any community solar program targeting low-income participants should be providing them with a guaranteed bill savings benefit to ensure that these customers are not further economically burdened or taken advantage of. It is worth noting however that the CSGT program is costly; while providing its enrollees the 20% bill savings, other customers have to make up the difference, including other low-income customers that are not able to enroll in CSGT. Ideally any community solar program or tariff would provide bill savings protections for low-income participants without raising costs on other low-income non-participants. 32 16
III. Conclusion
For all the foregoing reasons, the Joint CCAs respectfully request consideration of the Comments herein and look forward to an ongoing dialogue with the Commission and stakeholders.
Respectfully submitted,
Melissa Brandt
Vice President of Public Policy and
Deputy General Counsel
East Bay Community Energy
Aisha Cissna
Regulatory and Legislative Policy Manager
Redwood Coast Energy Authority
Laura Fernandez
Director of Regulatory and Legislative Affairs
San Diego Community Power
Jeremy Waen
Director of Regulatory Policy
Peninsula Clean Energy Authority
Dated: June 10, 2022
33 STAFF REPORT
Agenda Item # 3.5
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Nancy Diamond, General Legal Counsel
SUBJECT: Conflict of Interest Code Biennial Review and Amendment
BACKGROUND
The Political Reform Act requires every local government agency to review its Conflict of Interest Code biennially. A Conflict of Interest Code identifies the employment positions within the agency which make or participate in the making of decisions that may foreseeably have a financial effect on any of the employee’s own financial interests. For each of these employment positions, the Conflict of Interest Code designates the types of investments, business decisions, investments in real property, or sources of income that must be disclosed each year on a Statement of Economic Interests (Form 700).
SUMMARY
In May 2021 RCEA underwent a reorganization whereby the Deputy Executive Director position was created to assume human resource, information technology, non-power procurement risk management, and general internal administration and operations responsibilities. Duties of the Director of Operations position were revised to focus on RCEA infrastructure planning and operations needs. The renamed Director of Infrastructure Planning and Operations position is responsible for planning regional low-carbon vehicle fueling infrastructure, managing RCEA’s public electric vehicle charging station network, operating RCEA’s airport microgrid systems, working with partners to plan and develop additional microgrids and regional energy-resiliency projects and planning efforts, and leading renovation or construction and operations of a new RCEA office facility. These changes require updating the list of Designated Employees in the Conflict of Interest Code. After approval by the RCEA Board, the amended Conflict of Interest Code must be forwarded to the Code Reviewing Body for review and approval, in this case, the Humboldt County Board of Supervisors.
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
N/A – Operations.
EQUITY IMPACTS
N/A – Operations.
34 FINANCIAL IMPACT
None.
STAFF RECOMMENDATION
Adopt Resolution 2022-5 Adopting an Amended Conflict of Interest Code and Authorize the Board Clerk to Submit the Amended Conflict of Interest Code to the Humboldt County Board of Supervisors as the Code Reviewing Body.
ATTACHMENTS
1. Resolution No. 2022-5 Adopting an Amended Conflict of Interest Code
2. Attachment A to Resolution 2022-5: Proposed Amended RCEA Conflict of Interest Code 35 ________________________
Conflict of Interest Code, 2022 Page 1 of 4
RESOLUTION NO. 2022-5
OF THE REDWOOD COAST ENERGY AUTHORITY
ADOPTING AN AMENDED CONFLICT OF INTEREST CODE
WHEREAS, California Government Code section 87300 requires all public agencies to adopt and promulgate a Conflict of Interest Code enumerating employee and consultant positions within the Authority who are involved in the making or participation in the making of decisions which may have a material effect on any financial interest of their own, identifying disclosure categories for such employees and consultants, and identifying disqualification requirements for such employees and consultants;
WHEREAS, specified public officials identified in California Government Code section 87200, including Authority Board members and the Executive Director are subject to the conflict of interest disclosure and disqualification requirements set forth in Government Code sections 87200 et seq.;
WHEREAS, Government Code section 87306.5 requires each local public agency to review its conflict of interest code biennially and, no later than October 1 of each even numbered year, amend it as necessary to reflect changed circumstances; and WHEREAS, an amendment to RCEA’s Conflict of Interest Code is necessary due to organizational changes within the RCEA that occurred over the last two years.
NOW, THEREFORE, BE IT RESOLVED, that the Board of the Redwood Coast Energy Authority hereby adopts as its Conflict of Interest Code those provisions set forth in Appendix A, attached hereto and incorporated herein. This Conflict of Interest Code replaces the previously adopted RCEA Conflict of Interest Code.
Adopted this day of , 2022.
ATTEST:
______________________________ ____________________________ Stephen Avis, RCEA Board Chair Clerk of the Board, RCEA Date: _________________________ Date: _______________________ 36 ________________________
Conflict of Interest Code, 2022 Page 2 of 4
CLERK'S CERTIFICATE
I hereby certify that the foregoing is a true and correct copy of Resolution No. 2022-5 passed and adopted at a regular meeting of the Redwood Coast Energy Authority, County of Humboldt, State of California, held on the day of _____________, 2022, by the following vote:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
Clerk of the Board, Redwood Coast Energy Authority
37 ________________________
Conflict of Interest Code, 2022 Page 3 of 4
APPENDIX A
REDWOOD COAST ENERGY AUTHORITY
CONFLICT OF INTEREST CODE
The Political Reform Act (Government Code Section 81000, et seq.) requires state and local government agencies to adopt and promulgate Conflict of Interest codes. The Fair Political Practices Commission has adopted a regulation (2 Cal. Code of Regs. Sec.18730) which contains the terms of a standard Conflict of Interest code, which can be incorporated by reference in an agency’s code. After public notice and hearing, it may be amended by the Fair Political Practices Commission to conform to amendments in the Political Reform Act. Therefore, the terms of 2 California Code of Regulations Section 18730 and any amendments to it duly adopted by the Fair Political Practices Commission are hereby incorporated by reference. This regulation and the attached Appendix of designated officials and employees and establishing disclosure categories, shall constitute the Conflict of Interest code of the Redwood Coast Energy Authority.
Those individuals identified below filing under Section 87200 and designated employees shall file their statements with the Redwood Coast Energy Authority Clerk of the Board who will retain the statements and make them available for public inspection and reproduction (Gov. Code Section 81008).
Public Officials Who Manage Public Investments:
The following positions are NOT covered by the Conflict of Interest code because they must file under section 87200 and, therefore, are listed for informational purposes only:
o Governing Board Members
o Executive Director
An individual holding one of the above listed positions may contact the Fair Political Practices Commission for assistance or written advice regarding their filing obligations if they believe that their position has been categorized incorrectly. The Fair Political Practices Commission makes the final determination whether a position is covered by section 87200.
Designated Positions Disclosure Categories
Community Advisory Committee Members 1, 2, 3, 4
Deputy Executive Director 1, 2, 3. 4. 5
Director Business Planning and Finance 1, 2, 3
Director Demand-Side Management 1, 2, 4
Director Infrastructure Planning and Operations 1, 2, 3, 4, 5 Director Power Resources 1, 2, 3, 4
38 ________________________
Conflict of Interest Code, 2022 Page 4 of 4
1 Consultants:
General Counsel 1, 2, 3, 4
Disclosure Categories:
1. Investments and business positions in any business entity and sources of income, including gifts, loans and travel payments, of the type which within the previous 12 months has contracted with the Authority to provide services, supplies, materials, machinery or equipment.
2. All interests in real property located in the jurisdiction of any member agency of the Authority or within 2 miles of any land owned or used by the Authority.
3. Investments and business positions in business entities and sources of income (including receipt of gifts, loans and travel payments) if the business entity or source finances, owns, operates, manages or otherwise engages in the design development, construction, sale, or the acquisition of facilities that generate electricity for commercial sale including without limitation wind, solar, biomass, and hydroelectric.
4. Investments and business positions in business entities and sources of income (including receipt of gifts, loans and travel payments) if the business entity or source provides energy, environmental, engineering, geotechnical or research consulting services to assist in the designing, building, manufacture, sale, distribution, or servicing of equipment of the type that is used, or may be used, by 1) electric power suppliers, 2) providers of energy efficiency, energy conservation measures, demand response, fuel shifting programs, or 3) any entity that is, or within the prior 12 months has been, party to a proceeding before any local, state, or regional regulatory or judicial entity in which the Authority is also a party.
5. Investments and business positions in business entities and sources of income (including receipt of gifts, loans and travel payments) if the business entity or source provides information technology or telecommunications goods, products or services including computer hardware or software companies, computer consultant services, IT training companies, or data processing firms.
1 Consultants shall be included in the list of designated employees and shall disclose pursuant to the broadest disclosure category in the Code subject to the following limitations: “The Executive Director may determine in writing that a particular consultant, although a ‘designated position,’ is hired to perform a range of duties that is limited scope and thus is not required to fully comply with the disclosure requirements described in this section.
Such written determination shall include a description of the consultant’s duties and, based upon that description, a statement of the extent of the disclosure requirements. The Executive Director’s determination is a public record and shall be retained for public inspection in the same manner and location as this Conflict-of-Interest code.” 39
STAFF REPORT
Agenda Item # 3.6
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Eileen Verbeck, Deputy Executive Director
SUBJECT: Board and CAC Hybrid Meeting Arrangements
BACKGROUND
In response to the COVID-19 public health emergency and in compliance with emergency Brown Act meeting law changes, the RCEA Board of Directors, Community Advisory Committee and the subcommittees of those bodies have been meeting online via the Zoom teleconference platform since April 2020. In September 2021 Governor Newsom signed AB 361 into law. This bill authorized legislative bodies to meet virtually provided there is a state of emergency, and either 1) state or local officials have imposed or recommended measures to promote social distancing, or 2) the legislative body determines by majority vote that meeting in person would present imminent risks to the health and safety of attendees.
COVID case counts continue to fluctuate locally. Humboldt and neighboring counties have moved from areas of high to low to medium transmissibility according to the Centers for Disease Control and Prevention. The California Department of Public Health continues to strongly recommend that all persons, regardless of vaccine status, mask in indoor public settings including at meetings and state and local government offices serving the public. To mitigate the spread of COVID-19 the Centers for Disease Control and Prevention recommends that people avoid crowded spaces, choose events that take place outside with enough space for attendees to stay at least six-feet apart, and have virtual gatherings.
SUMMARY
Many Humboldt County legislative bodies have returned to in-person and combination in-person and teleconference or “hybrid” meetings. Hybrid meetings allow for fewer people in the indoor meeting space and greater physical spacing. The Humboldt Bay Municipal Water District Board room where RCEA’s Board of Directors previously met is equipped to conduct hybrid meetings but limits the total number of in-person meeting participants to 15. The size of RCEA’s Board and Community Advisory Committee and General Counsel’s advice not to limit the number of public meeting attendees made it necessary to seek a larger meeting venue. Eighteen venues of adequate size between McKinleyville and Fortuna were identified and a summary was presented to the Board at the May meeting. The Board directed staff to make arrangements for hybrid meetings in Eureka.
40
Only two of the eighteen venues staff researched were in Eureka and available for all Board and Community Advisory Committee meeting times. The available venues included Jefferson Community Center auditorium (1000 B Street Eureka, CA 95501) and the Eureka Veterans Memorial Hall (1018 H Street Eureka, CA 95501).
Staff performed hybrid meeting technology tests at both locations to determine the quality of the hybrid meeting capabilities. The Jefferson Community Center auditorium rental fee includes all hybrid meeting equipment and technical support. The tests resulted in quality sound and video.
The Eureka Veterans Memorial Hall does not have any equipment and required staff to bring RCEA equipment. The quality of the sound and video using RCEA existing equipment was not acceptable. Additionally, the time required to set-up and transport all the equipment made the Eureka Veterans Memorial Hall not an ideal venue.
Based on the results of the hybrid meeting technology tests, staff recommends reserving the Jefferson Community Center auditorium for future Board and Community Advisory Committee hybrid meetings.
The first hybrid Board meeting will be held on July 28. The CAC will hold its first hybrid meeting on September 13, 2022.
For Board directors to participate online or by phone via Zoom without making their remote meeting location publicly accessible, the Board must continue to adopt or extend AB 361 resolutions every 30 days.
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
N/A – Operations.
EQUITY IMPACTS
N/A. Staff recommends taking measures to reduce health risks to vulnerable populations. Signs strongly recommending the wearing of masks will be posted at the meeting site and masks will be provided.
FINANCIAL IMPACT
Jefferson Community Center auditorium rental rates are $75/hour. The approximate cost of meeting in this auditorium for the year is $3,000. Annual teleconferencing subscription costs have been included in the Fiscal Year 2022-23 budget.
STAFF RECOMMENDATION
Adopt Resolution No. 2022-6 Ratifying Governor Newsom’s March 4, 2020, State of Emergency Proclamation and Authorizing Remote Teleconference Meetings of RCEA’s Legislative Bodies, for the period June 27, 2022, through July 27, 2022, pursuant to Brown Act revisions of AB 361, 41
and approve conducting RCEA Board and Community Advisory Committee meetings in a hybrid in-person and teleconference format at the Jefferson Community Center auditorium beginning July 28 for the Board and September 13, 2022, for the Community Advisory Committee.
ATTACHMENTS
1. Resolution No. 2022-6 Ratifying Governor Newsom’s March 4, 2020, State of Emergency Proclamation and Authorizing Remote Teleconference Meetings of RCEA’s Legislative Bodies, for the period June 27, 2022, through July 27, 2022, pursuant to Brown Act revisions of AB 361.
42
RESOLUTION NO. 2022-6
A RESOLUTION OF THE BOARD OF DIRECTORS
OF THE REDWOOD COAST ENERGY AUTHORITY
RATIFYING THE PROCLAMATION OF A STATE OF EMERGENCY
BY GOVERNOR GAVIN NEWSOM ON MARCH 4, 2020,
AND AUTHORIZING REMOTE TELECONFERENCE MEETINGS
OF THE LEGISLATIVE BODIES OF REDWOOD COAST ENERGY AUTHORITY FOR THE PERIOD JUNE 27, 2022, THROUGH JULY 27, 2022,
PURSUANT TO BROWN ACT PROVISIONS
WHEREAS, the Redwood Coast Energy Authority (RCEA) is committed to preserving and nurturing public access and participation in meetings of the Board of Directors; and WHEREAS, all meetings of RCEA’s legislative bodies are open and public, as required by the Ralph M.
Brown Act (Cal. Gov. Code 54950 – 54963), so that any member of the public may attend, participate, and watch RCEA’s legislative bodies conduct their business; and WHEREAS, the Brown Act, Government Code section 54953(e), makes provisions for remote teleconferencing participation in meetings by members of a legislative body, without compliance with the requirements of Government Code section 54953(b)(3), subject to the existence of certain conditions; and WHEREAS, a required condition is that a state of emergency is declared by the Governor pursuant to Government Code section 8625, proclaiming the existence of conditions of disaster or of extreme peril to the safety of persons and property within the state caused by conditions as described in Government Code section 8558; and
WHEREAS, a proclamation is made when there is an actual incident, threat of disaster, or extreme peril to the safety of persons and property within the jurisdictions that are within RCEA’s boundaries, caused by natural, technological, or human-caused disasters; and WHEREAS, it is further required that state or local officials have imposed or recommended measures to promote social distancing, or, the legislative body has determined that meeting in person would present imminent risks to the health and safety of attendees; and WHEREAS, such conditions now exist in Humboldt County, specifically, Governor Newsom’s Proclamation of a State of Emergency of March 4, 2020, remains in effect; and WHEREAS, the Humboldt County Department of Health and Human Services recommends practicing physical distancing at meetings of legislative bodies; and WHEREAS, COVID-19 public health emergency and increased risk of infection has caused, and will continue to cause, conditions of peril to the safety of persons within Humboldt County that are likely to be beyond the control of services, personnel, equipment, and facilities of RCEA, and desires to ratify the proclamation of state of emergency by the Governor of the State of California; and WHEREAS, as a consequence of the emergency, the Board of Directors does hereby find that the legislative bodies of RCEA shall conduct their meetings without compliance with paragraph (3) of subdivision (b) of Government Code section 54953, as authorized by subdivision (e) of section 54953, and that such legislative bodies shall comply with the requirements to provide the public with access to the meetings as prescribed in paragraph (2) of subdivision (e) of section 54953; and 43
WHEREAS, public access and participation in meetings of RCEA’s legislative bodies shall be provided via online video conferencing software which shall also allow for public participation and real-time public comment opportunity by telephone.
NOW, THEREFORE, THE BOARD OF DIRECTORS OF REDWOOD COAST ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:
Section 1. Recitals. The Recitals set forth above are true and correct and are incorporated into this Resolution by this reference.
Section 2. Ratification of Governor’s Proclamation of a State of Emergency. The Board hereby ratifies the Governor of the State of California’s Proclamation of State of Emergency, effective as of its issuance date of March 4, 2020.
Section 3. Remote Teleconference Meetings. The staff and legislative bodies of Redwood Coast Energy Authority, including but not limited to the Board of Directors and its subcommittees, and the Community Advisory Committee and its subcommittees, are hereby authorized and directed to take all actions necessary to carry out the intent and purpose of this Resolution including conducting open and public meetings in accordance with Government Code section 54953(e) and other applicable provisions of the Brown Act.
Section 4. Effective Date of Resolution. This Resolution shall take effect immediately upon its adoption and shall be effective for 30 days or until this Resolution is extended by a majority vote of the Board of Directors in accordance with Section 5 of this Resolution.
Section 5. Extension by Motion. The Board of Directors may extend the application of this Resolution by motion and majority vote by up to 30 days at a time, provided that it makes all necessary findings consistent with and pursuant to the requirements of Section 54953(e)(3).
Adopted this 23rd day of June 2022.
ATTEST:
Stephen Avis, RCEA Board Chair Lori Taketa, Clerk of the Board Date: _________________________ Date: ________________________ 44
CLERK'S CERTIFICATE
I hereby certify that the foregoing is a true and correct copy of Resolution 2022-6 passed and adopted at a regular meeting of the Redwood Coast Energy Authority, County of Humboldt, State of California, held on the 23rd day of June 2022, by the following vote:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
Clerk of the Board, Redwood Coast Energy Authority
45
STAFF REPORT
Agenda Item # 5.1
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Richard Engel, Director of Power Resources SUBJECT: Annual Report on Humboldt Sawmill Company Memorandum of Understanding
SUMMARY
When authorizing extension of RCEA’s power purchase agreement with Humboldt Sawmill Company (HSC) in April 2021, the Board directed staff to "periodically review the contract…assessing current alternate biomass uses and other environmental considerations." To create a framework for the requested periodic review, staff negotiated a memorandum of understanding (MOU) between RCEA and HSC, which the Board adopted in September 2021.
One provision of the MOU is as follows:
Annually on or around May 1 and continuing until the termination of the PPA, representatives of the Parties will meet to review the terms of the PPA and to discuss the continued viability of biomass power production by the HSC facility relative to other potential or actual uses of the biomass feedstock by HSC or other entities.
The MOU also calls for HSC to provide on request data on plant performance; types, quantities and sources of biomass feedstock; and plant emissions.
The first of the annual meetings between RCEA and HSC staff took place at HSC’s Scotia headquarters on May 25, 2022. HSC provided the data requested by RCEA along with information about a recent request for information issued by the company to assess opportunities to use biomass feedstock for production of alternative energy products.
Staff will present an overview of the data from HSC and their ongoing investigation of alternative biomass uses at the Board meeting.
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
RCEA’s consultations with HSC in implementing the terms of the MOU are in keeping with the following strategies in the RePower Humboldt plan:
• 4.1.11.3 Investigate the Impacts of Biomass Emissions • 4.1.11.6 Plan for a Long-Term Transition Away from Direct Combustion of Forest Derived Biomass and Toward Lower-Impact Uses of this Material
EQUITY IMPACTS
Not applicable.
46
STAFF RECOMMENDATION
None – information only.
ATTACHMENTS
None.
47 First Annual Report on Consultations with
Humboldt Sawmill Company Regarding
Alternative Biomass Uses
Presentation to RCEA Board of Directors
June 23, 2022
Topics
• Review of memorandum of
understanding with Humboldt
Sawmill Company
• Review of operations data
provided by HSC
•HSC’s ongoing investigation of
alternative biomass uses
•Q&A
Photo: Humboldt Sawmill Company
MOU with Humboldt Sawmill Company
• When authorizing extension of RCEA’s power purchase agreement (PPA) with HSC in April 2021, the Board directed staff to "periodically review the contract…assessing current alternate biomass uses and other environmental considerations."
• To implement this guidance, staff negotiated an MOU with HSC, adopted by Board in September 2021
• MOU calls for HSC to provide operational data on feedstock, plant performance, and emissions
• Also calls for annual meeting to discuss terms of PPA and continued viability of biomass power relative to other feedstock uses • First such meeting took place in Scotia May 25
0 5,000
10,000
15,000
20,000
25,000
May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Jan-22 Feb-22 Mar-22 Apr-22 Geographic Origin of HSC Feedstock
Sourced from Within Humboldt County (tons) Sourced from Outside Humboldt County (tons) Plant curtailed by PG&E for most
of August 2021 while Humboldt
Bay plant islanding
Scotia sawmill offline for capital
project in early 2022, sourced
feedstock from the company’s
Ukiah facility
Tons
0 5,000
10,000
15,000
20,000
25,000
May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Jan-22 Feb-22 Mar-22 Apr-22 Supplier Origin of HSC Feedstock
Sourced internally from HRC/MRC forestlands (tons) Sourced externally (tons) Tons
External materials normally come from PG&E line
clearing and Arcata Forest Products Increase in external sourcing in March-April 2022 from deal with Figas to reduce fuel stocks at the
closed Fairhaven plant
Redwood
74%
Doug Fir
20%
Other
6%
Feedstock Species
(May-21 through Apr-22)
Timberlands & Sawmill
95%
PG&E Line
Clearing
3%
Landscaping
Materials
1%
Almond Hulls
& Shells
1%
Source of Feedstock
(May-21 through Apr-22)
Biomass Use
98%
Diesel Use
2%
Fuel Use for HSC Generation
(MMBTU)
(May-21 through Apr-22)
Electric Sales
to RCEA
69%
Onsite Electric Use
(Sawmill & Other Loads)
31%
HSC Generation Dispatch (MWh)
(May-21 through Apr-22)
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2016 2017 2018 2019 2020
Annual Generation and GHG Emissions
Biomass GHG Non-Biomass GHG Net Generation
Metric
Tons
CO2e
MWh
January 2017
HSC begins
operation of Scotia
biomass plant
April 2017
Original contract between
RCEA & HSC begins
October 2016
HSC purchases
Scotia biomass
plant & begins
maintenance
HSC’s Existing Alternative Biomass Uses
• A portion of HSC’s biomass is
diverted to production of soil
amendments
• The parent company developed a
successful wood pellet facility in
Ukiah 4 years ago
• Biochar from the Scotia power
plant is distributed to local farms
as a soil amendment and to a
company that produces activated
charcoal for water treatment Photo: Humboldt Sawmill Company Biofuels Opportunity
• In July 2021 consultant ICF provided HSC’s sister company Humboldt Redwood Company with a proposal to perform a study on using forest biomass to make energy products as a Low Carbon Fuel Standard (LCFS) business opportunity and issue a follow-up request for information (RFI) to identify interested developers
• HSC’s sister company Mendocino Forest Products issued an RFI in February 2022 seeking interest in development of a biofuels facility using feedstock from the company’s Mendocino and/or Humboldt County operations
• They received several responses but consider most of them to require too much capital investment to be viable
• They are in discussions with the companies with the most attractive offers
Energy
Performance
• HSC provided data on energy inputs (biomass feedstock, diesel fuel) and outputs (electricity for sale to RCEA and for onsite use, thermal energy for lumber processing)
• RCEA staff need more time to review and discuss the energy data with HSC to confirm our understanding; staff will continue to work with HSC on this topic and present the data at a future meeting to give a high-level picture of the plant’s energy performance
Photo: Humboldt Sawmill Company
Q&A
STAFF REPORT
Agenda Item # 6.1
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Jocelyn Gwynn, Senior Power Resources Manager SUBJECT: PG&E Renewable Portfolio Standard Voluntary Allocation
BACKGROUND
As an outcome of the Power Charge Indifference Adjustment (PCIA) proceeding, the California Public Utilities Commission (CPUC) has authorized the investor-owned utilities (IOUs) to allocate benefits from their legacy Renewable Portfolio Standard (RPS) contracts to load-serving entities (LSEs) who serve customers that have departed from the IOUs’ generation service, including RCEA. Because the IOUs no longer serve that load, their need for the RPS energy is reduced and they can recoup the above-market costs for that energy from departed customers through the PCIA. RCEA is already receiving an allocation of PG&E’s large hydropower as an outcome of the same regulatory process. However, the Carbon-Free Allocation has been procured on a year-by-year basis, while the RPS Voluntary Allocation may include a commitment from 2023 up to 2045.
At the May board meeting, staff discussed with the Board a variety of challenges and risks facing our power procurement and projects in development. Since then, the outlook has improved, and the current expectation is for the Sandrini Solar project to come online in time to meet RCEA’s RPS and Resource Adequacy (RA) compliance requirements and mitigate exposure to high summer prices, as detailed in a separate item on this month’s Board agenda.
However, if the Sandrini project is delayed further, generates less than expected, or we see a substantial increase in customer load, RCEA could face high price exposure, non-compliance penalties and reputational damage.
In addition to these risks, The Energy Authority (TEA) has seen a tightening of the RPS market in recent months, and they expect near-term availability of firm renewable supply from existing resources, which until now have provided most of RCEA’s short-term renewable portfolio needs, to continue to be scarce. Electing to procure some of the RPS Voluntary Allocation is a strategy to mitigate all of these risks by securing a small portion of our RPS needs over the next 20+ years, despite the uncertainty in volume and price, discussed further in the financial impact section below.
48
SUMMARY
To comply with PG&E’s schedule based on the CPUC’s regulatory process to procure our RPS Voluntary Allocation, staff is seeking Board authorization to sign PG&E’s attestation (attachment 1) and enter a contract, should the final terms be amenable to staff and counsel. The Attestation is due on July 8 and the final contract needs to be executed by July 25, both of which are prior to RCEA’s next scheduled Board meeting. PG&E has not published their final proforma agreement, nor has RCEA negotiated any of the terms yet, but the most recent version of the draft agreement is provided as attachment 2. Due to a recent CPUC proposed decision, RCEA expects PG&E to revise their proforma agreement to include a provision that will allow LSEs to resell their RPS Voluntary Allocation if needed, which would enable RCEA to better optimize its portfolio based on changing market conditions and resource availability over the lengthy delivery term.
The attestation requires that RCEA elect to procure separate slices of the short-term resource pool, comprised of contracts with less than ten years left in the term, and the long-term resource pool, contracts with ten or more years left in the term. The resource mix changes from year to year due to contracts in PG&E’s portfolio expiring. Below is a summary of the resource types in both pools across the 22-year allocation term.
If RCEA were to elect a 100% allocation of volume for both the short- and long-term resource pools, during the first five years of the term it would supply an average of about 20% of our total load, 35% of our Board-adopted RPS procurement targets, and 40% of our RPS compliance need in the next Compliance Period (2025-2027). After consulting with TEA, staff determined taking the full long-term allocation wasn’t prudent given the price and volumetric uncertainty and our Board-adopted goal of procuring as much of our power as possible from local sources.
However, staff do not recommend foregoing the opportunity to procure some of this energy given the risks discussed previously. Staff are thus proposing to elect 100% of the short-term allocation and 20% of the long-term allocation. Despite the different percentage recommendations, the elections would result in RCEA receiving roughly the same volume of energy from each resource pool in the first few years, since the short-term pool is substantially smaller than the long-term pool.
49
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
While the RPS Voluntary Allocation is primarily a risk management tool, it will help RCEA meet its renewable energy procurement goals:
• 4.1.4 Maximize Renewable Energy Content of RCEA’s CCE Program. Procure a power mix that reaches 100% clean and renewable content by 2025.
EQUITY IMPACTS
Not applicable.
FINANCIAL IMPACT
The estimated annual cost of the recommended action is $750,000 in the first contract year, with that amount decreasing per year over the term, which is within RCEA’s projected procurement budget. The energy that RCEA receives under the RPS Voluntary Allocation will be compensated at the RPS Market Price Benchmark (MPB), a price that is calculated each year through a CPUC regulatory process. The MPB is based on transactions executed by all LSEs in the previous year, so although there is some lag time in accuracy, the MPB is generally reflective of market prices RCEA would otherwise pay for equivalent RPS power procured through bilateral contracts. We could potentially capture some savings through new-build power purchase agreements, but those come with development risk we are currently trying to hedge against.
STAFF RECOMMENDATION
Authorize the Executive Director to sign PG&E’s RPS Voluntary Allocation Attestation and execute the final Confirmation Agreement with PG&E, with changes from the Proforma Confirmation Agreement approved by counsel.
ATTACHMENTS
1. RPS Voluntary Allocation Attestation
2. PG&E RPS Voluntary Allocation Proforma Confirmation Agreement 50 2022 Power Charge Indifference Adjustment (PCIA) Renewables Portfolio Standard (RPS) Voluntary Allocation
Attestations Form
Please refer to the Instructions Document posted on PG&E's Voluntary Allocation webpage for additional information.
Eligible Load Serving Entity Name --------------------------- (hereinafter referred to as "LSE") Section I. LSE Authorization
By selecting "Yes" Yes D l?equired
(the "Authorized Representative") confirms that I am a "a duly authorized representative of the above-listed LSE"
Title
Electronic Signature
Select "Yes" to certify that the typed name acts as your signature Yes D Required Section II. Voluntary Allocation Participation
By selecting "Yes" the LSE confirms that it is participating in the 2022 l?equired Power Charge Indifference Adjustment (PCIA) Renewables Portfolio Standard (RPS) Voluntary Allocation ("the Voluntary Allocation") OR by selecting "No" the LSE confirms that it declines any Short Term and Long-Term Voluntary Allocation elections and agrees to no longer participate in the Voluntary Allocation
Title
Electronic Signature
Select "Yes" to certify that the typed name acts as your signature Yes D Required Only LSEs that are participating in the Voluntary Allocation should fill out Sections Ill - IV. If you declined to participate the Voluntary Allocation in Section II above, you do not need to complete the Sections below.
Section Ill. Voluntary Allocation Elections
Any LSE that is participating in the Voluntary Allocation should fill out the Allocation Election column in the Table below. The table below was taken from section 2.4 of PG&E's proposed Voluntary Allocation Contract (the "VA Contract"), and information provided by the LSE in the table below will be inputted in its VA Contract following CPUC approval of Advice 8517-E-A]1:
1 In line with Commission Decision 21-05-030 all allocation elections must be denoted in 10% increments. In addition, according to Section 2.4 of the VA Contract, the sum of the Short-Term B Allocation Election and Long-Term Allocation Election must be equal to or less than one hundred percent (100%). 51 Product Allocation Election - Short-Term A Buyer to select a 10% increment Required - Short-Term B Buyer to select a 10% increment - Long-Term Buyer to select a 10% increment - Title
Electronic Signature
Select "Yes" to certify that the typed name acts as your signature Yes 0 Required Section IV. LSE Information to be Inputted into VA Contract Any LSE that is participating in the Voluntary Allocation should provide the following information in the table below. Information provided will be included in the preamble of the VA Contract:
Information Input Required
Company Name
Place of formation
Type of Entity
Title
Electronic Signature
Select "Yes" to certify that the typed name acts as your signature Yes O Required Section V. Attestations
By providing the electronic signature below the LSE hereby attests Yes 0 Required that all information provided in response to this 2022 Power Charge Indifference Adjustment (PCIA) Renewables Portfolio Standard (RPS) Voluntary Allocation process is true and correct to the best of the LSE's knowledge as of the date such information is provided.
By providing the electronic signature below the LSE attests that it Yes D Required has obtained all relevant authorizations to execute the Voluntary Allocation contract and provide any documentation related to the Voluntary Allocation.
Title
Electronic Signature
Select "Yes" to certify that the typed name acts as your signature Yes 0 Reqwred 52 1
MASTER POWER PURCHASE AND SALE AGREEMENT
RENEWABLES PORTFOLIO STANDARD ENERGY ALLOCATION
CONFIRMATION LETTER
BETWEEN
[NAME] (“PARTY A”)
AND
PACIFIC GAS AND ELECTRIC COMPANY (“PARTY B”)
This confirmation letter (“Confirmation”) confirms the Transaction between [Name, place of formation, and type of entity] (“Party A” or “Buyer”), and Pacific Gas and Electric Company, a California corporation, (“Party B” or “Seller”), each individually a “Party” and together the “Parties”, which becomes effective on the date fully executed by both Parties (the “Confirmation Effective Date”), in which Seller agrees to provide to Buyer Product, as such term is defined in this Confirmation. This Transaction is governed by the Master Power Purchase and Sale Agreement between the Parties, effective as of [Date of EEI Master between Parties], together with the Cover Sheet, [the Collateral Annex and Paragraph 10 to the Collateral Annex,] and any other annexes thereto (collectively, as amended, restated, supplemented, or otherwise modified from time to time, the “Master Agreement”). The Master Agreement and this Confirmation are collectively referred to herein as the “Agreement”. Capitalized terms used but not otherwise defined in this Confirmation, have the meanings specified for such terms in the Master Agreement, the RPS (defined herein) or the Tariff (defined herein), as applicable. If there is a conflict between the terms in this Confirmation and those in the Master Agreement, this Confirmation shall control. Section references herein are to this Confirmation unless otherwise noted.
[Standard contract terms and conditions shown in shaded text are those that “may not be modified” per CPUC Decisions (“D.”) 07-11-025; D.10-03-021, as modified by D.11-01-025; and D.13-11-024.]
ARTICLE 1
PRODUCT
1.1 Product. “Product” means (a) all RPS Energy and Green Attributes generated and associated with the non-Greengate Resources in the Resource Pools, and (b) all Green Attributes associated with the Greengate Resources in the Resource Pools. During the Delivery Period, Seller shall provide Buyer Product equal to the Total Allocation Amount.
1.2 Buyer’s Exclusive Right. Buyer has exclusive right to Product for the Total Allocation Amount, including the right to account for or report Product equal to the Total Allocation Amount to a Governmental Entity.
ARTICLE 2
TOTAL ALLOCATION AMOUNT
2.1 Total Allocation Amount. “Total Allocation Amount” means the sum of the Total Short-Term Allocation Amount and the Total Long-Term Allocation Amount. 53 2
2.2 Total Short-Term Allocation Amount. The “Total Short-Term Allocation Amount” is the sum of all Monthly Short-Term Allocation Amounts in the Delivery Period. For every month in the Delivery Period, the “Monthly Short-Term Allocation Amount” will be the sum of all PCIA Short-Term Allocation Amounts in the month, where a “PCIA Short-Term Allocation Amount” will be calculated for every PCIA vintage applicable to Buyer as the sum of (a) the product of (i) Short-Term A Allocation Election, multiplied by (ii) Allocation Share for the applicable PCIA vintage, multiplied by (iii) the difference between (x) total RPS Energy for that month for every Resource in the Short-Term Resource Pool with the corresponding PCIA vintage, minus (y) any applicable Third Party Sales, plus (b) the product of (i) Short-Term B Allocation Election, multiplied by (ii) Allocation Share for the applicable PCIA vintage, multiplied by (iii) the difference between (x) total RPS Energy for that month for every Resource in the Long-Term Resource Pool with the corresponding PCIA vintage, minus (y) any applicable Third Party Sales.
2.3 Total Long-Term Allocation Amount. The “Total Long-Term Allocation Amount” is the sum of all Monthly Long-Term Allocation Amounts in the Delivery Period. For every month in the Delivery Period, the “Monthly Long-Term Allocation Amount” for a month will be the sum of all PCIA Long-Term Allocation Amounts in the month, where a “PCIA Long-Term Allocation Amount” will be calculated for every PCIA vintage applicable to Buyer as the product of (i) Long-Term Allocation Election, multiplied by (ii) Allocation Share for the applicable PCIA vintage, multiplied by (iii) the difference between (x) total RPS Energy for that month for every Resource in the Long-Term Resource Pool with the corresponding PCIA vintage, minus (y) any applicable Third Party Sales.
2.4 Allocation Election. The “Short-Term A Allocation Election,” “Short-Term B Allocation Election,” and “Long-Term Allocation Election” are the percentages specified in the table below and must be denoted in ten (10) percent increments. The sum of the Short-Term B Allocation Election and Long-Term Allocation Election must be equal to or less than one hundred percent (100%).
2.5 Change in Resource Pools. Seller may remove a Resource from the Resource Pools for the following reasons: (i) if Seller’s power purchase agreement corresponding to the Resource has expired or is terminated, (ii) if the Resource is no longer in Seller’s PCIA-eligible portfolio due to an order or direction from a Governmental Authority or Governmental Entity, or (iii) if the Resource is owned by Seller but ceases operation for Seller. Seller may add Resources to the Resource Pools in the following ways: (a) Seller may add Resources with PCIA vintages corresponding to the PCIA vintages where Buyer has an Allocation Share, or (b) Seller may add Resources from Customer Programs listed in Appendix D. With the exception of expirations of Seller’s power purchase agreements listed in Appendix B, Appendix C, and Appendix D, Seller will provide Notice to Buyer identifying the facility or facilities that constitute the Resources being removed or added to the Resource Pools as soon as reasonably practicable. Seller shall retain the sole and absolute discretion to modify, enforce, or terminate its power purchase Product Allocation Election
Short-Term A [Buyer to fill in] %
Short-Term B [Buyer to fill in] %
Long-Term [Buyer to fill in] %
54 3
agreements for Resources during the Delivery Period. Buyer shall not have any right to or discretion to request changes to the Resources or the Resource Pools during the Delivery Period.
2.6 Third Party Sales. From the Confirmation Effective Date throughout the Delivery Period, Seller shall have the right to sell all or any portion of Product to a third party (“Third Party Sale”). The amount of Third Party Sales will be incorporated in the calculation of the Monthly Short-Term Allocation Amount and Monthly Long-Term Allocation Amount for the applicable month in accordance with Article 2.
ARTICLE 3
DELIVERY
3.1 Delivery. Throughout the Delivery Period, Seller shall deliver, and Buyer shall receive, Product in accordance with the Confirmation. Seller, or a qualified third party designated by Seller, will act as Scheduling Coordinator to deliver Product in each hour to the CAISO at the Delivery Point. Buyer shall take title and risk of loss of Product at the applicable Delivery Point selected by Seller.
3.2 Delivery Point. The “Delivery Point” is and shall mean where Seller, or a qualified third party designated by Seller, shall deliver to, and Buyer shall take possession of, Product, which shall be NP 15, SP 15, and/or ZP 26, as selected by Seller, except for Product from Greengate Resources, which will be conveyed in accordance with Article 4.
3.3 Delivery Period. The “Delivery Period” shall commence on January 1, 2023 and last through and until (a) December 31, 2024 for deliveries of the Short-Term Allocation Amount and/or (b) the Long-Term End Date for deliveries of the Long-Term Allocation Amount; provided that with regards to the Green Attributes portion of Product, the Delivery Period shall last through and until that date upon which the amount of Green Attributes conveyed to Buyer meets the Total Allocation Amount. The Long-Term End Date will be determined by comparing the end dates of all power purchase agreements for Resources in the Long-Term Resource Pool with a PCIA vintage applicable to Buyer, and the latest end date will be the “Long-Term End Date.” ARTICLE 4
CONVEYANCE OF GREEN ATTRIBUTES
4.1 Green Attributes. Seller represents and warrants that Seller holds the rights to such Green Attributes from the Resources in the Resource Pools and Seller agrees to convey such Green Attributes to Buyer as included in the delivery of Product from the Resources in the Resource Pools subject to the terms and conditions of this Agreement.
4.2 Conveyance of Green Attributes. Seller shall convey to Buyer the Green Attributes associated with Product no later than twenty-five (25) Business Days once the following have occurred: (a) Seller has obtained the WREGIS Certificates for the Green Attributes for the applicable Calculation Period or calendar year and (b) Seller has received Buyer’s payment of the Monthly Cash Settlement Amount in accordance with Article 5 herein. Since WREGIS Certificates will only be created for whole MWh amounts of RPS Energy generated, any fractional MWh amounts (i.e., kWh) will be carried forward until sufficient generation is accumulated for the creation of a WREGIS Certificate. During the Delivery Period, Seller shall 55 4
transfer all right, title, and interest in and to the WREGIS Certificates to Buyer’s WREGIS account in an aggregate amount equivalent to the Total Allocation Amount.
4.3 WREGIS Certificate True-Up. A “WREGIS Certificate True-Up” means any deficit or surplus in WREGIS Certificates delivered to Buyer for a calendar month as compared to the sum of the (a) Monthly Short-Term Allocation Amount, plus (b) the Monthly Long-Term Allocation Amount for the same calendar month (“True-Up Month”). Any adjustments to resolve a WREGIS Certificate True-Up will be made as an adjustment on Seller’s monthly invoice to Buyer in accordance with Article 5, provided that no adjustments will be made for any WREGIS Certificate True-Up after twenty-four (24) months from the True-Up Month.
ARTICLE 5
COMPENSATION
5.1 Calculation Period. The “Calculation Period” shall be each calendar month or portion thereof that Delivery was conveyed to Buyer.
5.2 Monthly Cash Settlement Amount. Buyer shall pay Seller the Monthly Cash Settlement Amount, in arrears, for each Calculation Period.
The “Monthly Cash Settlement Amount” for a particular Calculation Period shall be equal to (a) plus (b) minus (c), where:
(a) equals the product of the (i) Index Price multiplied by (ii) the sum of (x) Monthly Short-Term Allocation Amount, plus (y) Monthly Long-Term Allocation Amount; and
(b) equals the product of (i) either (x) the forecasted RPS MPB for the applicable year, or (y) if available, the final RPS MPB for the applicable year, multiplied by (ii) the sum of (a) Monthly Short-Term Allocation Amount, plus (b) Monthly Long-Term Allocation Amount; and
(c) equals the product of the (i) Index Price multiplied by (ii) the sum of (x) Monthly Short-Term Allocation Amount, plus (y) Monthly Long-Term Allocation Amount.
5.3 Annual Cash Settlement Amount. By March 31 of each calendar year, Seller will perform a true-up process for every Monthly Cash Settlement Amount from the previous year (“Annual Cash Settlement Amount”), where Seller will recalculate every Monthly Cash Settlement Amount from the prior calendar year that used the forecasted RPS MPB to instead use the final RPS MPB in congruence with Section 5.2.
(a) If, after determination of the Annual Cash Settlement Amount, Buyer owes Seller, Seller will invoice Buyer on the next monthly invoice. (b) If, after determination of the Annual Cash Settlement Amount, Seller owes Buyer, Seller shall credit Buyer within each future monthly invoice until the Annual Cash Settlement Amount is paid. If Seller owes Buyer and there are no remaining Calculation 56 5
Periods, Seller shall pay Buyer the remaining Annual Cash Settlement Amount balance on the last monthly invoice.
5.4 Payment. Notwithstanding anything to the contrary in Article Six of the Master Agreement, Buyer shall pay Seller the Monthly Cash Settlement Amount four (4) calendar months following the applicable Calculation Period and on or before the later of: (a) the twenty-fifth (25th) day of the month in which Buyer receives from Seller an invoice for the Calculation Period to which the Monthly Cash Settlement Amount pertains, or (b) within fifteen (15) days following receipt of an invoice issued by Seller for such applicable Calculation Period, provided that if such payment due date is not a Business Day, then on the next Business Day. This provision shall survive termination or expiration of the Agreement for all amounts due prior to such termination or expiration.
ARTICLE 6
CREDIT TERMS
The credit and collateral terms set forth in the Master Agreement shall not apply to either Party to this Confirmation.
ARTICLE 7
SELLER’S REPRESENTATIONS, WARRANTIES, AND COVENANTS
7.1 Seller Representations and Warranties. Seller, and, if applicable, its successors, represents and warrants that throughout the Delivery Term of this Agreement that: (i) the Project qualifies and is certified by the CEC as an Eligible Renewable Energy Resource (“ERR”) as such term is defined in Public Utilities Code Section 399.12 or Section 399.16; and (ii) the Project’s output delivered to Buyer qualifies under the requirements of the California Renewables Portfolio Standard. To the extent a change in law occurs after execution of this Agreement that causes this representation and warranty to be materially false or misleading, it shall not be an Event of Default if Seller has used commercially reasonable efforts to comply with such change in law. (a) For the avoidance of doubt, the term “Project” as used in the immediately preceding paragraph means Resources in the Resource Pool, and the phrase “Delivery Term” means the Delivery Period.
7.2 Seller and, if applicable, its successors, represents and warrants that throughout the Delivery Term of this Agreement the Renewable Energy Credits transferred to Buyer conform to the definition and attributes required for compliance with the California Renewables Portfolio Standard, as set forth in California Public Utilities Commission Decision 08-08-028, and as may be modified by subsequent decision of the California Public Utilities Commission or by subsequent legislation. To the extent a change in law occurs after execution of this Agreement that causes this representation and warranty to be materially false or misleading, it shall not be an Event of Default if Seller has used commercially reasonable efforts to comply with such change in law.
(a) For the avoidance of doubt, the phrase “Delivery Term” as used in the immediately preceding paragraph means the Delivery Period. 57 6
7.3 Seller warrants that all necessary steps to allow the Renewable Energy Credits transferred to Buyer to be tracked in the Western Renewable Energy Generation Information System will be taken prior to the first delivery under the contract. (a) For the avoidance of doubt, the term “contract” as used in the immediately preceding paragraph means this Confirmation, and the phrase “first delivery” means the first date of the Delivery Period.
7.4 In addition to the foregoing, Seller warrants, represents and covenants, as of the Confirmation Effective Date and throughout the Delivery Period, that:
(a) Seller has the contractual rights to sell all right, title, and interest in Product required to be delivered hereunder;
(b) at the time of delivery, all rights, title, and interest in Product required to be delivered hereunder are free and clear of all liens, taxes, claims, security interests, or other encumbrances of any kind whatsoever;
(c) Seller shall not substitute or purchase any Product from any generating resource other than the Resources in the Resource Pools hereunder; and (d) the facility(s) designated by Seller as the Resources in the Resource Pools and all electrical output from the facility(s) designated as the Resources in the Resource Pools are, or will be, by the first date of the Delivery Period, registered with WREGIS as RPS-eligible.
ARTICLE 8
TERMINATION AND CALCULATION OF TERMINATION PAYMENT
In the event this Transaction becomes a Terminated Transaction pursuant to Section 5.2 of the Master Agreement, then the Settlement Amount with respect to this Transaction shall not be calculated in accordance with the Master Agreement, but instead shall be calculated as follows:
The Non-Defaulting Party shall determine its Gains and Losses by determining the Market Quotation Average Price for the Terminated Transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts, to obtain the Market Quotation Average Price with respect to the Terminated Transaction, then the Non-Defaulting Party shall calculate its Gains and Losses for the Terminated Transaction in a commercially reasonable manner by calculating the arithmetic mean of the quotes of at least three (3) Broker or Index Quotes based on the offers to sell or bids to buy, as applicable, obtained for transactions substantially similar to the Terminated Transaction. Such Broker or Index Quotes must be obtained assuming that the Party obtaining the quote will provide sufficient credit support for the proposed transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts to obtain at least three (3) such Broker or Index Quotes with respect to the Terminated Transaction, then the Non-Defaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner by reference to information supplied to it by one or more third parties including, without limitation, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets. 58 7
Third parties supplying such information may include, without limitation, dealers in the relevant markets, end-users of the relevant product, information vendors and other sources of market information; provided, however, that such third parties shall not be Affiliates of either Party. Only in the event the Non-Defaulting Party is not able, after using commercially reasonable efforts, to obtain such third-party information, then the Non-Defaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner using relevant market data it has available to it internally. If the Non-Defaulting Party’s aggregate Gains exceed its aggregate Losses and Costs, if any, resulting from the termination of this Transaction, the Settlement Amount for this Transaction will be zero.
ARTICLE 9
GENERAL PROVISIONS
9.1 Buyer Audit Rights. In addition to any audit rights provided under the Master Agreement, Seller shall, upon the Confirmation Effective Date and continuing until the end of the Delivery Period, provide documentation (which may include, for example, WREGIS reports) sufficient to demonstrate that Product has been conveyed and delivered to Buyer.
9.2 Governing Law.
(a) Notwithstanding any provision to the contrary in the Master Agreement, the Governing Law applicable to this Agreement shall be as set forth herein. This Section 9.2 does not change the Governing Law applicable to any other confirmation or transaction entered into between the Parties under the Master Agreement. (b) Governing Law. This agreement and the rights and duties of the parties hereunder shall be governed by and construed, enforced and performed in accordance with the laws of the state of California, without regard to principles of conflicts of law. To the extent enforceable at such time, each party waives its respective right to any jury trial with respect to any litigation arising under or in connection with this agreement.
ACKNOWLEDGED AND AGREED TO:
59 8
Buyer, or Party A:
[NAME, place of formation, and type of
entity]
Sign:
Print:
Title:
Date:
Seller, or Party B:
PACIFIC GAS AND ELECTRIC
COMPANY, a California corporation
Sign:
Print:
Title:
Date:
60 A-1
APPENDIX A
DEFINED TERMS
Any capitalized terms used in this Confirmation but not otherwise defined below shall have the meaning ascribed to such term in the Master Agreement:
“Allocation Share” means Buyer’s most recent PCIA-vintaged share of RPS Energy, as determined by Seller, through Seller’s load forecasting processes to establish energy procurement revenue requirements for rate-setting purposes, within Energy Resource Recovery Account and/or Resource Adequacy proceedings, or successor proceedings. As of the Confirmation Effective Date, Buyer’s Allocation Share is listed in Appendix E. “Applicable Law” means any statute, law, treaty, rule, tariff, regulation, ordinance, code, permit, enactment, injunction, order, writ, decision, authorization, judgment, decree or other legal or regulatory determination or restriction by a court or Governmental Authority of competent jurisdiction, or any binding interpretation of the foregoing, as any of them is amended or supplemented from time to time, that apply to either or both of the Parties, the Product, or the terms of the Agreement.
“Annual Cash Settlement Amount” has the meaning set forth in Section 5.3. “Balancing Authority” has the meaning set forth in the Tariff. “Business Day” means all calendar days other than those days on which the Federal Reserve member banks in New York City are authorized or required by law to be closed, and shall be between the hours of 8:00 a.m. and 5:00 p.m. Pacific Prevailing Time for the relevant Party’s principal place of business where the relevant Party, in each instance unless otherwise specified, shall be the Party from whom written communications or payment or delivery is being sent and by whom written communications or payment or delivery is to be received. “Buyer” means Party A.
“CAISO” means the California Independent System Operator Corporation or the successor organization to the functions thereof.
“Confirmation Effective Date” means the date in which the Confirmation is fully executed by both Parties.
“CPUC” means the California Public Utilities Commission. “California Renewables Portfolio Standard” or “RPS” means the California renewables portfolio standard, as set forth in Cal. Pub. Util. Code §§ 399.11 et seq. and Cal. Pub. Res. Code §§ 25740-25751, and as administered by the CEC as set forth in the CEC RPS Eligibility Guidebook (9th Ed.), as may be subsequently modified by the CEC, and the California Public Utilities Commission (“CPUC”) as set forth in CPUC Decision (“D”) 08-08-028, D.08-04-009, D.11-01-025, D.11-12-020, D.11-12-052, D.12-06-038 and D.14-12-023, and as may be modified 61 A-2
by subsequent decision of the CPUC or by subsequent legislation, and regulations promulgated with respect thereto.
“CEC” means the California Energy Commission.
“CPUC” means the California Public Utilities Commission. “Customer Programs” means Green Tariff Shared Renewables (GTSR) and Disadvantaged Communities (DAC) programs.
“Disadvantaged Communities” or “DAC” means the DAC-Green Tariff program, as set forth in CPUC Decision 18-06-027, as such decision may be amended from time to time or as further defined or supplemented by any law, rule, regulation, or other legal or regulatory determination by a court or Governmental Authority.
“Delivery Period” has the meaning set forth in Section 3.3. “Delivery Point” has the meaning set forth in Section 3.2. “Energy” means electrical energy, measured in MWh.
“Energy Resource Recovery Account” means the balancing account where utilities, including Seller, record and track energy procurement costs, as described in CPUC Decision D.02- 10-062 and subsequent CPUC decisions addressing Energy Resource Recovery Account issues, as those obligations may be altered from time to time.
“FERC” means the Federal Energy Regulatory Commission.
“Green Attributes” means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Resource, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (a) any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants; (b) any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by Law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere ; (c) the reporting rights to these avoided emissions, such as Green Tag Reporting Rights. Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state Law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local Law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of Electric Energy. Green Attributes do not include (i) any Electric Energy, capacity, reliability or other power attributes from the Resource, (ii) production tax credits associated with the construction or operation of the Resource and other financial incentives in the form of credits, reductions, or 62 A-3
allowances associated with the Resource that are applicable to a state or federal income taxation obligation, (iii) fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or (iv) emission reduction credits encumbered or used by the Resource for compliance with local, state, or federal operating and/or air quality permits. If the Resource is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Resource. “Green Tariff Shared Renewables” or “GTSR” means the Green Tariff Shared Renewables Program implemented per Senate Bill (SB) 43 (Stats. 2013, ch. 413 (Wolk)) and CPUC Decision 15-01-051.
“Greengate Resources” means the Halkirk I Wind Project, Blackspring Ridge IA Wind Project, and Blackspring Ridge IB Wind Project (all affiliates of Greengate Power Corporation). “Governmental Authority” or “Governmental Entity” means any federal, state, local or municipal government, governmental department, commission, board, bureau, agency, or instrumentality, or any judicial, regulatory or administrative body, or the CAISO or any other transmission authority, having or asserting jurisdiction over a Party or the Agreement. “Index Price” means the Trading Hub price (as defined in the Tariff) measured in $/MWh, for each MWh of Product, and associated with the Product to the Delivery Point for each applicable hour as published by the CAISO on the CAISO website; or any successor thereto, unless a substitute publication and/or index is mutually agreed to by the Parties. “Long-Term Allocation Election” is the percentage specified in Section 2.4. “Long-Term End Date” has the meaning set forth in Section 3.3. “Long-Term Resource Pool” means Seller’s Resources in Appendix C reflecting power purchase agreements with terms that have 10 years or more remaining from the start of the Delivery Period.
“MWh” means megawatt-hour.
“Monthly Cash Settlement Amount” has the meaning set forth in Section 6.2. “Monthly Long-Term Allocation Amount” has the meaning set forth in Section 2.3. “Monthly Short-Term Allocation Amount” has the meaning seat forth in Section 2.2. “PG&E” means the Pacific Gas and Electric Company, its successors and assigns. “PCIA” or “Power Charge Indifference Adjustment” is a charge to ensure that both PG&E customers and those who have left PG&E service to purchase electricity from other providers pay for the above-market costs for electric generation resources that were procured by PG&E on their 63 A-4
behalf. “Above market” refers to expenditures for generation resources that cannot be fully recovered through sales of these resources at current market prices. “PCIA Long-Term Allocation Amount” has the meaning set forth in Section 2.3. “PCIA Short-Term Allocation Amount” has the meaning set forth in Section 2.2. “Product” has the meaning set forth in Section 1.1.
“Renewable Energy Credits” or “REC” has the meaning set forth in California Public Utilities Code Section 399.12(h) and CPUC Decision 08-08-028, as may be amended from time to time or as further defined or supplemented by Law.
“Resource(s)” means generation units owned by Seller or contracted by Seller, which corresponding costs are recovered through the PCIA.
“Resource Adequacy” or “RA” means the procurement obligation of load serving entities, as such obligations are described in CPUC Decisions D.04-10-035 and D.05-10-042 and subsequent CPUC decisions addressing Resource Adequacy issues, as those obligations may be altered from time to time, and all other capacity procurement obligations established by any other entity, including the CAISO.
“Resource Pools” means the Short-Term Resource Pool (Appendix B) and Long-Term Resource Pool (Appendix C).
“RPS Energy” means the Energy generated from Resources from the applicable Resource Pool(s).
“RPS Market Price Benchmark” or “RPS MPB” means the estimated incremental value of each unit of RPS-eligible energy that is attributable to the fact of that eligibility, in $/MWh, as defined in CPUC D.19-10-001 or subsequent CPUC Decisions defining calculations of the RPS MPB for PCIA purposes.
“Scheduling Coordinator (SC)” means an entity certified by the CAISO to perform the functions as described in the Tariff.
“Seller” means Party B.
“Short-Term A Allocation Election” is the percentage specified Section 2.4. “Short-Term B Allocation Election” is the percentage specified in Section 2.4. “Short-Term Resource Pool” means Seller’s Resources in Appendix B reflecting power purchase agreements with terms that have less than 10 years remaining from the start of the Delivery Period.
64 A-5
“Tariff” means the FERC-approved California Independent System Operator Tariff, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as may be amended, supplemented or replaced from time to time. “Third Party Sale” has the meaning set forth in Section 2.6. “Total Allocation Amount” has the meaning set forth in Section 2.1. “Total Long-Term Allocation Amount” has the meaning set forth in Section 2.3. “Total Short-Term Allocation Amount” has the meaning set forth in Section 2.2. “WREGIS” means the Western Renewable Energy Generation Information System or any successor renewable energy tracking program.
“WREGIS Certificate” has the same meaning as “Certificate” as defined by WREGIS in the WREGIS Operating Rules and are designated as eligible for complying with the California Renewables Portfolio Standard.
65 B-1
APPENDIX B
LIST OF RESOURCES IN SHORT-TERM RESOURCE POOL
Resource Name Technology CEC RPS ID PCIA
Vintage
End Date
Olsen Power Partners Small Hydro 60175 Non-Vintaged 12/31/2026 El Nido Biomass Facility Biomass 60473 2005 2/8/2031
Chowchilla Biomass Facility Biomass 60471 2005 2/8/2031 Klondike Wind Power III Project Wind 60602 2007 3/31/2023 CalRenew-1 Solar PV 60475 2015 4/29/2030
Shiloh II Wind Project Wind 60639 2007 1/31/2029
Rattlesnake Road Wind Power
Project Wind 60553 2008 1/4/2024
Hatchet Ridge Wind 60741 2008 12/13/2025
CM10 Solar PV 60713 2008 12/31/2028
CM48 Solar PV 60786 2009 1/31/2031
Mt. Poso Biomass 60695 2009 2/20/2027
Vantage Wind Energy Center Wind 60712 2009 10/3/2025
Big Creek Waterworks Small Hydro 60900 2009 6/22/2030
Norman Ross Burgess - Three Forks
Water Power Project Small Hydro 60502 2010 10/31/2031
Avenal Park Solar PV 60912 2009 8/4/2031
Sun City Project Solar PV 60913 2009 8/4/2031
Sand Drag Solar PV 60914 2009 8/4/2031
Halkirk I Wind Project Wind 60989 2010 12/18/2032
Coram Brodie Wind 60973 2010 6/5/2032
Shiloh III Wind Project Wind 61069 2010 3/8/2032
Wind Resource II Wind 61468 2012 9/30/2023
ABEC Bidart-Old River Digester Gas 62369 2012 3/9/2029
ABEC Bidart-Stockdale Digester Gas 60886 2012 9/11/2023 Diablo Winds Wind 60030 2013 6/30/2031
66 C-1
APPENDIX C
LIST OF RESOURCES IN LONG-TERM RESOURCE POOL
Resource Name Technology CEC RPS ID PCIA
Vintage
End Date
Montezuma Wind Energy
Center Wind 60543 2010 1/27/2036
High Plains Ranch II Solar PV 60603 2008 10/30/2038
Topaz Solar Farm Solar PV 61698 2008 10/26/2039
Ivanpah Unit 1 Solar Thermal 62273 2009 1/20/2039
Ivanpah Unit 3 Solar Thermal 62275 2009 1/26/2039
AV Solar Ranch One Solar PV 60790 2009 11/20/2039
Alpine Solar Project Solar PV 60755 2010 1/17/2033
Agua Caliente Solar Project Solar PV 60894 2009 6/22/2039 High Plains Ranch III Solar PV 60603 2010 9/30/2038
Mojave Solar Project Solar Thermal 60848 2009 12/3/2039 Genesis Solar Energy Project Solar Thermal 60605 2009 3/6/2039 DTE Stockton Biomass 60964 2009 2/20/2039
Alpaugh 50 Solar PV 60945 2010 3/7/2038
Alpaugh North Solar PV 60946 2010 3/7/2038
Atwell Island Solar PV 60947 2010 3/11/2038
Corcoran Solar PV 60948 2010 8/14/2038
White River Solar PV 60949 2010 6/26/2038
Sunshine Landfill Landfill Gas 60815 2010 8/31/2034
Potrero Hills Landfill Landfill Gas 63116 2010 4/12/2041 Blackspring Ridge IA Wind 60987 2010 5/11/2034
Blackspring Ridge IB Wind 60988 2010 5/11/2034
Desert Center Solar Farm Solar PV 61068 2010 12/16/2039 Mesquite Solar 1 Solar PV 60875 2010 3/7/2033
North Star Solar Solar PV 61198 2010 6/18/2035
Vasco Wind Energy Center Wind 61344 2010 3/12/2037
Montezuma II Wind Energy
Center Wind 61345 2010 3/13/2037
Kansas South Solar PV 61264 2011 6/24/2033
Westlands Solar Farms Solar PV 61755 2011 4/30/2034
Orion Solar Solar PV 61570 2011 6/25/2034
North Sky River Energy
Center Wind 61385 2011 12/20/2037
Copper Mountain Solar 2 Solar PV 60990 2011 5/12/2040
Shiloh IV Wind Project Wind 61617 2011 1/27/2038
Mammoth G3 Geothermal 60315 2012 3/31/2033
West Antelope Solar PV 61850 2012 2/8/2035
67 C-2
Western Antelope Blue Sky
Ranch A Solar PV 61517 2012 2/16/2035
Nevada Irrigation District
(NID) - Dutch Flat / Rollins /
Bowman Small Hydro
60264 / 60265 /
60171 2012 6/30/2033
SPI Biomass Portfolio –
Anderson 2 / Burney / Lincoln
/ Sonora / Quincy Biomass
61146 / 60087 /
60088 / 60576 /
60089 2012 9/8/2035
Kansas Solar PV 61263 2012 12/31/2037
Lost Hills Solar Solar PV 61893 2012 12/31/2043
Cuyama Solar Array Solar PV 61891 2012 12/31/2043
Blackwell Solar Solar PV 61892 2012 12/31/2043
Henrietta Solar Solar PV 61841 2012 9/30/2036
Kent South Solar PV 61262 2012 2/18/2035
Algonquin SKIC 20 Solar Solar PV 61558 2012 5/14/2035
White River Solar 2 Solar PV 62045 2012 10/1/2034
Mammoth G1 Geothermal 60306 2012 12/25/2033
Alamo Solar, LLC Solar PV 61453 2012 6/29/2035
CID Solar PV Project Solar PV 62285 2012 3/19/2035
Old River One Solar PV 60853 2013 2/8/2035
Shafter Solar Solar PV 62325 2013 7/15/2035
Rising Tree Wind Farm II Wind 62426 2013 8/6/2035
Kekawaka Creek
Hydroelectric Facility Small Hydro 60186 2013 5/31/2035 RE Astoria Solar PV 62284 2013 1/2/2034
Midway Solar Farm I Solar PV 61295 2013 5/31/2040
California Flats Solar Project Solar PV 62552 2013 4/9/2034 Portal Ridge Solar C Project Solar PV 61684 2014 4/20/2037 Sunray 2 Solar PV 62694 2014 8/24/2037
Bayshore Solar A Solar PV 63133 2015 1/22/2038
Bayshore Solar B Solar PV 63134 2015 1/22/2038
Bayshore Solar C Solar PV 63135 2015 1/22/2038
Java Solar Solar PV 63137 2016 12/31/2039
RE Gaskell West 3 Solar PV 63619 2017 1/14/2038
RE Gaskell West 4 Solar PV 63617 2017 1/14/2038
RE Gaskell West 5 Solar PV 63618 2017 1/14/2038
PGE Alta Small Hydro 60033 Pre-2002 N/A
PGE Coleman Small Hydro 60037 Pre-2002 N/A
PGE Cow Creek Small Hydro 60038 Pre-2002 N/A
PGE Crane Valley Small Hydro 60039 Pre-2002 N/A
PGE Deer Creek Small Hydro 60040 Pre-2002 N/A
PGE De Sabla Small Hydro 60041 Pre-2002 N/A
PGE Dutch Flat 1 Small Hydro 60042 Pre-2002 N/A
68 C-3
PGE Halsey Small Hydro 60043 Pre-2002 N/A
PGE Hat 1 Small Hydro 60045 Pre-2002 N/A
PGE Hat 2 Small Hydro 60046 Pre-2002 N/A
PGE Newcastle Small Hydro 60053 Pre-2002 N/A
PGE Oak Flat Small Hydro 60276 Pre-2002 N/A
PGE Phoenix Small Hydro 60054 Pre-2002 N/A
PGE Potter Valley Small Hydro 60055 Pre-2002 N/A
PGE Five Points Solar PV 61432 2010 N/A
PGE Stroud Solar PV 61434 2010 N/A
PGE Westside Solar PV 61433 2010 N/A
PGE Cantua Solar PV 61823 2011 N/A
PGE Giffen Solar PV 61822 2011 N/A
PGE Huron Solar PV 61821 2011 N/A
PGE Gates Solar PV 62353 2012 N/A
PGE Guernsey Solar PV 62354 2012 N/A
PGE West Gates Solar PV 62352 2012 N/A
PGE Rock Creek RPS Small Hydro 62269 Pre-2002 N/A
PGE San Joaquin 1A Small Hydro 60056 Pre-2002 N/A
PGE San Joaquin 2 Small Hydro 60057 Pre-2002 N/A
PGE South Small Hydro 60059 Pre-2002 N/A
PGE Spaulding 1 Small Hydro 60060 Pre-2002 N/A
PGE Spaulding 2 Small Hydro 60061 Pre-2002 N/A
PGE Spaulding 3 Small Hydro 60062 Pre-2002 N/A
PGE Spring Gap Small Hydro 60063 Pre-2002 N/A
PGE Toadtown Small Hydro 60064 Pre-2002 N/A
Vaca-Dixon Solar (PG&E) Solar PV 60966 2010 N/A
PGE Volta 1 Small Hydro 60066 Pre-2002 N/A
PGE Volta 2 Small Hydro 60067 Pre-2002 N/A
PGE West Point Small Hydro 60068 Pre-2002 N/A
PGE Wise 1 Small Hydro 60069 Pre-2002 N/A
PGE Wise 2 Small Hydro 60070 Pre-2002 N/A
PGE A.G.Wishon Small Hydro 60032 Pre-2002 N/A
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APPENDIX D
LIST OF PCIA-ELIGIBLE RESOURCES IN TEMPORARY RESOURCE POOLS Resource Name Resource
Pool
Technology CEC RPS
ID
PCIA
Vintage
End Date
Shafter Solar GTSR Solar PV 62325 2013 7/15/2035
Columbia Solar Energy GTSR Solar PV 62051 2012 12/13/2035 Morelos del Sol GTSR Solar PV 62272 2013 2/29/2036
Woodmere Solar Farm
GTSR,
DAC Solar PV 62429 2013 2/24/2036
CED Corcoran Solar 3 GTSR Solar PV 62783 2015 11/30/2036 CED Oro Loma Solar
Project A
GTSR
Solar PV 62841 2014 2/23/2037
Avenal Solar Project A GTSR Solar PV 62840 2014 3/9/2037 CED Oro Loma Solar
Project B
GTSR
Solar PV 62841 2014 3/9/2037
Avenal Solar Project B GTSR Solar PV 62840 2014 3/9/2037 Westside Solar GTSR Solar PV 61185 2015 5/1/2037
Aspiration Solar G GTSR Solar PV 61486 2015 10/26/2037
Summer Wheat
GTSR,
DAC Solar PV 61837 2015 12/9/2038
White River Solar 2 GTSR Solar PV 62045 2012 10/1/2034
70 E-1
APPENDIX E
BUYER’S ALLOCATION SHARE
PCIA
Vintage
Buyer’s
Allocation
Share (%)
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
71 PG&E Renewable Portfolio Standard
Voluntary Allocation
Presentation to RCEA Board of Directors
June 23, 2022
Background on the Voluntary Allocation
• Outcome of the Power Charge Indifference Adjustment
proceeding
• For Investor-Owned Utility Renewable Portfolio Standard contracts
• Hedge against development risk of RCEA’s new renewable projects and supply risk of market renewables
Voluntary Allocation Resource Pools
• Short-term pool: 2023 to 2032
• Long-term pool: 2023 to 2045
• Can elect 10% increments of each pool
• Compensated at RPS Market Price Benchmark, which is
regulatorily set price that changes year-to-year
Resource Pool Composition
Proposed Election of Voluntary Allocation
• 20% of long-term resource pool
• 100% of short-term resource pool
• Roughly 50,000 MWh in first year
Expected first-year volume as percent of
RCEA’s energy needs
% of annual load 8%
% of Board-adopted RPS target 16%
% of RPS compliance req’t 18%
STAFF REPORT
Agenda Item # 7.1
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Richard Engel, Director of Power Resources Jocelyn Gwynn, Senior Power Resources Manager
SUBJECT: Proposed Amendment to Sandrini Solar Power Purchase Agreement
BACKGROUND
As previewed in the May 2022 Board meeting, EDP Renewables (EDPR) informed RCEA staff earlier this year that permitting delays, inflation of equipment costs, and supply chain challenges would not allow them to stick to the schedule and pricing terms in the power purchase agreement (PPA) for the 100-megawatt Sandrini solar project that EDPR and RCEA executed in 2020. Per the PPA, the project was to be online by December 2022. EDPR requested an amendment to the PPA, which has been negotiated with the aid of RCEA’s consultants and general counsel and is being brought to the Board for approval.
SUMMARY
Staff researched recent price increases for solar PPAs, which have been significant, and in consultation with analysts from The Energy Authority determined it would be in RCEA’s best interest for financial and regulatory compliance reasons to agree to adjusted PPA terms. Staff made the best of the situation by requesting some additional changes to terms that are favorable to RCEA.
Key terms of the proposed amendment are:
• A price increase over the life of the contract of less than 10%. Staff’s research and TEA’s analysis show this is a modest increase compared with what it would cost RCEA to secure a similar solar PPA today and will still result in a more affordable project than the projected future cost of buying renewable energy and capacity on the short-term market.
• A delay of the project’s commercial operation date (COD) from late 2022 to mid-2023, due to delays in permitting the project with Kern County and a pause in project development while EDPR waited for resolution of the solar tariff issue staff discussed with the Board in its May 2022 meeting.1 EDPR have been providing periodic progress reports to RCEA that adequately document the delays they have experienced with local 1 One encouraging development is that, with the Biden administration’s recent decision to impose a two-year moratorium on certain solar equipment tariffs, this project can now be developed without being impacted by the potential tariff increases, or further delays while awaiting a tariff decision.
72
government permitting. These issues have been resolved and start of construction is imminent.
• A 20% reduction of the amount of buyer security that RCEA will be required to post. With approval of this amendment, security posted to date will meet RCEA’s full requirement with no further posting required.
• Narrowing of conditions under which EDPR can be granted an extension of the COD, with interconnection or permitting delays no longer allowed.
FINANCIAL IMPACTS
This amendment increases procurement costs for RCEA. However, staff and our consultants agree that refusal to renegotiate the contract would expose RCEA to risk of cancellation by the seller, with RCEA then facing a very challenging market in which to replace a large portion of our renewable power portfolio and the regulatory compliance capacity that this project is intended to provide for RCEA.
This situation is not unique to RCEA. Inflationary trends and increasing project costs are affecting many load-serving entities (LSEs) and placing pressure on LSEs to renegotiate contract terms. In the currently tight market for new renewable energy contracts, it may be necessary in many cases such as ours to make some concessions to stay on track toward the organization’s renewable energy procurement goals while keeping our rates competitive. Staff recommends approval of this amendment as the best means of ensuring those goals are met.
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
Approval of the proposed amendment will help RCEA to achieve these strategic goals:
• 4.1.2 Minimize Greenhouse Gas Emissions Associated with RCEA’s CCE Program. This one project will provide emissions-free power to cover close to half of RCEA’s needed electric portfolio.
• 4.1.4 Maximize Renewable Energy Content of RCEA’s CCE Program. Keeping this project in RCEA’s portfolio goes a long way in ensuring our goal of sourcing all electricity from renewable and carbon-free sources by 2025.
• 4.1.8.1 Support Utility Scale Solar Energy Development. Although the Sandrini project is not a local project like those envisioned in this strategy, it will ensure that close to half of RCEA’s power needs are provided by an in-state utility-scale solar project being newly built specifically on RCEA’s behalf.
• 4.3.7 Provide a 100% Carbon-Free Service Option for CCE Customers. The Sandrini project will ensure that RCEA’s REpower+ 100% carbon-free renewable energy option will meet its solar component over the life of the PPA without the need for any additional procurement.
EQUITY IMPACTS
Not applicable.
STAFF RECOMMENDATION
Approve First Amendment to 15-year power purchase agreement with EDPR CA Solar Park II LLC for its Sandrini solar project and authorize RCEA’s Executive Director to execute all applicable documents.
73
ATTACHMENTS
First Amendment to Renewable Power Purchase Agreement
74 1
FIRST AMENDMENT TO
RENEWABLE POWER PURCHASE AGREEMENT
This FIRST AMENDMENT TO RENEWABLE POWER PURCHASE AGREEMENT (this “Amendment”), is entered into as of ________, 2022 (the “Effective Date”) by and between Redwood Coast Energy Authority, a California joint powers authority (“Buyer” or “RCEA”) and EDPR CA Solar Park II LLC, a Delaware limited liability company (“Seller”), each individually a “Party” and collectively, the “Parties”.
RECITALS
WHEREAS, Buyer and Seller entered into that certain Power Purchase Agreement, dated May 5, 2020 (the “Agreement”);
WHEREAS, the Parties desire to amend the Agreement as set forth herein; and WHEREAS, the Parties are entering into this Amendment in accordance with Section 10.10 of the Agreement to implement such amendments.
AGREEMENT
NOW THEREFORE, in consideration of the mutual promises set forth below, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:
1. Amendments to the Agreement.
a. Section B(i)(a)(1)(A)-(D) of the Cover Sheet is hereby deleted in its entirety and replaced with the following:
“(A) The anticipated Construction Start Date: 8/27/2022 (B) The Guaranteed Construction Start Date: 8/27/2022
(C) The Expected Commercial Operation Date: 6/01/2023
(D) The Guaranteed Commercial Operation Date: 06/15/2023” b. Section B(i)(b) of the Cover Sheet is hereby deleted in its entirety and replaced with the following:
“(b) Project development Milestone schedule
Identify Milestone Date for Completion
Major Permitting 07/01/2022
GIA Execution Complete
Construction Start 08/27/2022
Start-Up and Commissioning 05/01/2023
Guaranteed Commercial Operation Date 06/15/2023
75 2
c. Section C (Contract Price) of the Cover Sheet is hereby deleted in its entirety and replaced with the following:
“C. Contract Price
The Contract Price for each MWh of Product as measured by Delivered Energy in the initial Contract Year shall be $ . In each succeeding Contract Year, the Contract Price shall be adjusted by multiplying the prior year’s Contract Price by .” d. Section 1.17 is hereby deleted in its entirety and replaced with the following:
“1.17 “Buyer Performance Assurance” means Phase I Buyer Security and/or Phase II Buyer Security, as applicable.”
e. Section 1.176 is hereby deleted in its entirety and replaced with the following:
“1.176 [RESERVED]”
f. Section 3.9(c)(iv) of the Agreement is hereby deleted in its entirety and replaced with the following:
“(iv) Extensions of the Guaranteed Dates. The Guaranteed Construction Start Date and the Guaranteed Commercial Operation Date shall, subject to notice and documentation requirements set forth below, be automatically extended on a day-for-day basis (the “Development Cure Period”) for the following delays:
(A) [RESERVED]
(B) A Force Majeure Event occurs;
(C) [RESERVED]
(D) Buyer has not made all necessary arrangements to receive the Project Energy at the Delivery Point by the Expected Commercial Operation Date (it being acknowledged that an extension under this paragraph (D) shall not limit other rights and remedies Seller may have for the default by Buyer in obtaining necessary arrangements).”
g. Section 8.4(a)(iii) of the Agreement is hereby deleted in its entirety and replaced with the following:
“(iii) [RESERVED]”
h. Section 8.4(c) is hereby deleted in its entirety and replaced with the following:
“(c) Payment and Transfer of Interest. Seller shall pay interest to Buyer on cash held as Phase I Buyer Security and Phase II Buyer Security, as applicable, at the Interest Rate.
After Buyer posts any and all Buyer Performance Assurance described in Section 8.4(a), 76 3
Seller shall transfer on or before each Interest Payment Date the Interest Amount due to Buyer for such Phase I Buyer Security and Phase II Buyer Security.” i. Section 8.4(d) is hereby deleted in its entirety and replaced with the following:
“(d) Return of Buyer Performance Assurance. Seller shall return the unused portion of Phase I Buyer Security and Phase II Buyer Security, as applicable, including the payment of any interest due thereon, pursuant to Section 8.4(c) above, to Buyer promptly after the following has occurred: (i) any one or more of the following terms A, B, or C has occurred: (A) the Term of the Agreement has ended, or an Early Termination Date has occurred, as applicable; (B) Buyer is assigned an Investment Grade Credit Rating as defined in Article 1 by one or more of the following credit rating agencies: Moody’s, Fitch Ratings, and Standard & Poor; (C) Buyer attains and sustains for at least six consecutive monthly balance sheet reports prepared and published for Buyer’s Board of Directors a Tangible Net Worth as defined in Article 1 of at least $35,000,000.00; and (ii) all payment obligations of the Buyer arising under this Agreement are paid in full (whether directly or indirectly such as through setoff or netting).”
2. General.
a. Definitions; Interpretation. All capitalized terms used in this Amendment (including the recitals hereof) and not otherwise defined herein shall have the meanings assigned to them in the Agreement.
b. Agreement Otherwise Not Affected. Except for the amendments pursuant hereto, the Agreement remains unchanged and in full force and effect and is hereby ratified and confirmed in all respects. The execution and delivery of, or acceptance of, this Amendment and any other documents and instruments in connection herewith by either Party shall not be deemed to create a course of dealing or otherwise create any express or implied duty by it to provide any other or further amendments, consents, or waivers in the future. c. Entire Agreement. This Amendment constitutes the entire agreement and understanding of the Parties with respect to its subject matter and supersedes all oral communication or prior writings related thereto.
d. Binding Effect. This Amendment shall be binding upon, inure to the benefit of and be enforceable by the Parties hereto and their respective successors and assigns. e. No Reliance. Each Party hereby acknowledges and confirms that it is executing this Amendment on the basis of its own investigation and for its own reasons without reliance upon any agreement, representation, understanding or communication by or with the other Party or its agents, representatives or attorneys not set forth within the Agreement or this Amendment.
f. Costs and Expenses. Each Party shall be responsible for any costs and expenses incurred by such Party in connection with the negotiation, preparation, execution and delivery of this Amendment and any other documents to be delivered in connection herewith. g. Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, CONSTRUED,
AND ENFORCED UNDER THE LAWS OF THE STATE OF CALIFORNIA WITHOUT
GIVING EFFECT TO ITS CONFLICTS OF LAW PRINCIPLES THAT WOULD REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER STATE.
77 4
h. Amendments. This Amendment may not be modified, amended or otherwise altered except by written instrument executed by the Parties’ duly authorized representatives. i. Interpretation. This Amendment is the result of negotiations between and has been reviewed by counsel to each of the Parties and is the product of all Parties hereto.
Accordingly, this Amendment shall not be construed against either Party merely because of such Party’s involvement in the preparation hereof.
j. Counterparts. This Amendment may be executed and delivered in counterparts, all of which taken together shall constitute one and the same instrument. Delivery of an executed signature page of this Amendment by electronic mail transmission (including PDF) shall be the same as delivery of a manually executed signature page. [Signature Page Follows]
78 5
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be duly executed as of the Effective Date.
EDPR CA SOLAR PARK II LLC, a Delaware
limited liability company
Sign:
Print:
Title:
Sign:
Print:
Title:
REDWOOD COAST ENERGY AUTHORITY,
a California joint powers authority
Sign:
Print:
Title:
Sign:
Print:
Title:
79
STAFF REPORT
Agenda Item # 7.2
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Richard Engel, Director of Power Resources Jocelyn Gwynn, Senior Power Resources Manager
SUBJECT: Fairhaven Energy Storage Resource Adequacy Agreement
BACKGROUND
In September 2021, RCEA launched a Request for Offers (RFO) for Long-term Reliability Resources in response to the California Public Utilities Commission’s (CPUC) June 2021 Mid-Term Reliability (MTR) Decision 21-06-035 to address reliability needs of the state’s grid in the 2023-2026 term. The Decision requires each load-serving entity (LSE) in California, including RCEA, to procure its allocated share of incremental resource adequacy (RA) capacity. RCEA is obligated to purchase RA on an annual and monthly basis as part of the state’s reliability program to ensure the California Independent System Operator has sufficient capacity to maintain reliable grid operations at all times. The additional requirement that the MTR Decision places on LSEs is a portion of that RA capacity must come from new resources to replace retiring gas and nuclear facilities in the coming years.
At its January 2022 meeting, the Board approved shortlisting three projects under the RFO, a battery storage project and two solar plus battery storage projects, all three of which will be local to the Humboldt Bay area. Staff are bringing the first of these contracts to the Board for approval.
SUMMARY
The Fairhaven Energy Storage project is a 17.25 MW battery system that is being developed jointly by Broad Reach Power and EWPRC in Samoa at the site of the non-operational DG Fairhaven biomass plant, of which EWPRC is the former owner. The developers have leased a portion of the property as well as access to the grid interconnection rights from the current owner, and they have provided RCEA staff with documentation of the lease and both lease parties’ intent to transfer interconnection rights. They have also retained services of local firm SHN for the permitting process which is on track to be completed in Q1 2023.
The project was originally shortlisted with the expectation that it could begin operation during summer 2023, thus allowing RCEA to count it toward our first MTR compliance milestone. 80
However, due to concerns around supply chain risk and securing equipment in time, the developer has revised the schedule to bring the project online in Q4 2023, meaning RCEA cannot claim the capacity for MTR compliance purposes until June 2024. Despite the schedule change, the project still has compliance value to RCEA, given our large 2024 MTR obligation of 20 MW, and that we will be able to utilize the capacity for our general RA compliance from the start of delivery. If the project is delayed, CPUC rules and contract terms allow that RCEA can procure, or the developer can supply, short-term replacement capacity.
The ten-year contract is for RA only, meaning RCEA will only be receiving capacity from the facility for compliance with the state’s reliability program. This is in contrast with other energy storage assets such as the Redwood Coast Airport Microgrid (RCAM) and the solar plus storage projects currently under negotiation, where RCEA can capture the full benefits of an energy storage system, albeit at greater cost and with greater operational responsibility in order to optimize those benefits.
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
Energy storage is not explicitly built into RCEA’s Strategic Plan yet, but this contract indirectly supports renewable energy and decarbonization goals of the CCE Program.
The following Strategic Plan goals are supported by this contract:
• 4.1.1 Maximize the Use of Local Renewable Energy to the Extent Technically and Economically Feasible and Prudent. The battery system will optimize renewable production by absorbing excess power from the grid when prices are low and renewable supply is high, and then supplying power to the grid when prices are high and the grid is mostly being powered by natural gas resources.
• 4.1.2 Minimize Greenhouse Gas Emissions Associated with RCEA’s CCE Program.
Optimizing renewable production as described above in turn reduces greenhouse gas emissions.
• 4.1.5 Ensure Diversity in Local Sources. This will be only the second utility-scale energy storage project in RCEA’s portfolio, following RCAM, and it will support diversification of local generation by supporting the addition of intermittent resources such as wind and solar.
EQUITY IMPACTS
Not applicable.
FINANCIAL IMPACT
The cost of Fairhaven’s capacity is equivalent to the projected value of the three RA products (System, Local, and Flex) that RCEA will receive over the term of the agreement. These costs are already accounted for in RCEA’s financial model and will be incorporated into RCEA’s budget starting in fiscal year 2023-2024. RA prices, especially in the summer months, have 81
skyrocketed in recent years, so if that trend continues this project will bring more value to RCEA’s long-term portfolio as a hedge against that price risk.
STAFF RECOMMENDATION
Approve Resource Adequacy Agreement with Fairhaven Energy Storage LLC and authorize the Executive Director to execute all applicable documents.
ATTACHMENTS
Resource Adequacy Agreement between RCEA and Fairhaven Energy Storage LLC NOTE: This agreement is linked above and available at https://redwoodenergy.org/board-of-directors/. 82 Fairhaven Energy Storage
Resource Adequacy Agreement
Presentation to RCEA Board of Directors
June 23, 2022
Topics
• Purpose of this procurement
• Project and site description
• Key contract terms
• Financial impacts
• Strategic plan alignment
• Staff recommendation
Purpose of this procurement
• June 2021 California Public Utilities Commission issued its mid-term reliability decision (MTR)
• MTR requires RCEA and other load-serving entities to contract for capacity from new resources to come online between 2023 and 2026 • RCEA issued request for offers in September 2021, with the Fairhaven project one of the few local offers received (others currently under negotiation)
• Resources to be contracted will replace nuclear and natural gas facilities being retired across the state
Project and Site Description
• 17.25 MW battery system
• To be built on site of idle Fairhaven biomass facility • Lease agreement with current site owner Figas
• Developer: partnership of EWPRC (former owner/operator of Fairhaven biomass plant) and Broad Reach Power
• Will occupy just 5 acres of 70-acre site (does not require dismantling the biomass plant)
• Will use the biomass plant’s existing utility interconnection • Local firm SHN assisting with permitting process
Key Contract Terms
• Resource adequacy only
• 10-year term
• Expected to be online by Oct. 2023 in order to help RCEA meet its 2024 MTR compliance obligation
Financial Impacts
• Will provide system, local and flex resource adequacy • Costs to be incorporated in RCEA’s budget starting in FY 2023-24 prior to the project coming online
• With resource adequacy prices on the rise, this long-term contract will provide a hedge against further price increases for these mandatory compliance
products
Alignment with RCEA’s Strategic Plan
• 4.1.1 Maximize the Use of Local Renewable Energy to the Extent Technically and Economically Feasible and Prudent. The battery system will optimize renewable production by absorbing excess power from the grid when prices are low and renewable supply is high, and then supplying power to the grid when prices are high and the grid is mostly being powered by natural gas resources.
• 4.1.2 Minimize Greenhouse Gas Emissions Associated with RCEA’s CCE Program. Optimizing renewable production as described above in turn reduces greenhouse gas emissions.
• 4.1.5 Ensure Diversity in Local Sources. This will be only the second utility-scale energy storage project in RCEA’s portfolio, following RCAM, and it will support diversification of local generation by supporting the addition of intermittent resources such as wind and solar.
STAFF REPORT
Agenda Item # 7.3
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Eileen Verbeck, Deputy Executive Director
Lori Biondini, Director of Business Planning and Finance SUBJECT: Fiscal Year 2022-23 Proposed Budget and Addition of Staff Positions
SUMMARY
Attached is the proposed fiscal year 2022-2023 (FY22-23) annual budget. As reported in May, this current fiscal year was marked by the continuing effects of the COVID-19 pandemic and significant uncertainty around energy revenue, energy costs, and the ability to implement customer programs. This current fiscal year also marks the completion of RCEA’s major capital investment, the microgrid project. As a result, the presented budget contains conservative estimates of anticipated revenue.
Following the May Board meeting budget presentation, staff worked with The Energy Authority (TEA) to refine forecasts for the coming year. The FY22-23 proposed budget presented at the May Board meeting included projected energy costs and revenue based on models provided by The Energy Authority dated April 30, 2022.
TEA presented staff with updated forecasts of energy costs and revenue based on financial models dated June 1, 2022. These updated models indicate a fourteen percent (14%) increase in revenues and a five percent (5%) increase in energy costs over the April 30 numbers.
Updating the proposed budget with the newer estimates would result in an increase in RCEA’s projected net revenue from $8 million to $16.6 million.
The updated financial modelling assumes that PG&E’s generation rates will increase 17.8% over current year rates. The PG&E rate increase is speculative at this point, and RCEA staff recognize there are many factors that could affect or delay any rate changes. Based on the Board’s direction to take a conservative approach to budgeting, RCEA staff proposes adopting the FY22-23 budget as presented to the Board in May 2022 with the more conservative estimates from the April 30 financial model.
The proposed FY22-23 budget uses the most conservative scenario modeled for energy cost and revenue and keeps RCEA rates 0.5% below corresponding PG&E rates. There was a misunderstanding between TEA and Staff, and it was mistakenly reported at the May meeting that the proposed budgeted revenue did not include a PG&E rate increase. However, the April 30 financial model does assume a modest 3.1% PG&E rate increase over the current year’s rates.
Highlights from the proposed FY22-23 annual budget are as follows:
REVENUES
• Government Agencies $1,101,031: Revenue in this category is this year’s share of the 3-year funding from the California Public Utilities Commission for energy efficiency programs anticipated to be about $877,031 (booked as it is expensed), and this year’s 83
share of a 2-year grant from the California Energy Commission for medium and heavy duty zero-emission vehicle planning anticipated to be about $150,000 (reimbursed as it is expensed). Revenue in this category also includes funds from California’s Electric Vehicle Infrastructure Project (CALeVIP) which provides reimbursements for new electric vehicle charging equipment and revenue from RCEA’s Electric Vehicle Network (REVNet) for an anticipated total of $112,000.
• Non-government Agencies $489,124: Revenue in this category includes the remaining $182,802 of grant funds from Humboldt State University Sponsored Programs Foundation / Schatz Energy Research Center for construction of the Airport Microgrid, and this year’s share of funding from Pacific Gas & Electric Company’s Local Government Partnership Program for energy efficiency programs which is $246,634.
Additionally, RCEA expects to receive an estimated $59,688 in Tech Quick Start Grant funds from Southern California Edison for identifying and assisting customers looking to purchase and install electric heat pumps.
• Electricity Sales $93,848,684: This line item includes electricity sales revenue, excess energy generated through RCEA’s power purchase agreements that is sold in the energy market, and the value of the energy produced by the Redwood Airport Microgrid.
Payments for excess energy generation by net-energy metering customers, estimated to be $250,000, is included in the total electricity sales line item, and $1,707,003 (2% of projected electricity sales) is assumed to be uncollectable due to customer non-payment. This line item has a degree of uncertainty and represents a conservative forecast.
EXPENSES
• Wholesale Power Supply $76,236,276: Energy costs continue to be RCEA’s largest expense. Power costs for the fiscal year represent what has already been procured through RCEA’s previously approved hedging strategy and existing power purchase agreements.
• Professional and Program Services $2,820,516: This budget line item includes contracted services for energy scheduling coordination, energy procurement credit fees, data management, legal services, accounting services, regulatory services, as well as program-specific professional services, including database development and engineering calculations. Additionally, funds have been budgeted for ramping up coordination with RCEA’s offshore wind project partners and to support community outreach related to the upcoming offshore lease auction and ancillary community projects.
• Personnel $4,071,684: The proposed budget includes the addition of three full-time positions (Infrastructure Programs Manager, Intake Coordinator and Power Resources Specialist). The budget includes an increase in health insurance benefits estimated at 7% from the current fiscal year. Overall, the proposed budget has 16% increase from the current year’s budget. Staff are anticipating an expansion of projects and programs in the upcoming year including, the proposed Rural REN ($96 million over five years), CEC Transportation Grant ($700,000), and the release of additional state and federal transportation grant funds. The next fiscal year will require a fully staffed organization to implement upcoming projects and programs.
All positions listed in the Board-adopted organization chart are full-time, fully benefited positions. Non-benefited, part-time, limited-term and intern positions can be created and dissolved at the discretion of the Executive Director if they fit within the Board-adopted 84
total personnel budget. The proposed personnel budget includes $291,564 in funds for part-time, limited-term and intern positions.
• Facilities and Operations $801,816: This budget line item is for operations costs such as information technology, office supplies and utilities, as well as costs associated with RCEA-owned or managed assets. The largest item in this budget are costs associated with operating the Airport Microgrid, increase in insurance costs (partly due to insuring the Airport Microgrid), upgrades to our IT infrastructure, and purchasing and maintaining a new financial software system. The draft budget does not currently include the planned purchase and/or renovation of a new office facility.
• Incentives and Rebates $477,823: This line item is for direct incentives and rebates paid out. This currently includes customer incentives funded through the RCEA-administered California Public Utilities Commission efficiency program and incentives approved as part of CCE-funded customer benefit programs. The following CCE-funded programs are included in the proposed budget: heat pump rebates, residential energy efficiency kits, mobile home solar program, grocery refrigeration program, electric vehicle rebates, electric vehicle charging station rebates and e-bike rebates.
RCEA received a $2 million loan from the Blue Lake Rancheria and arranged the temporary sale of power purchase agreement assets to MCE for $4 million that enabled RCEA to continue to operate through the FY21-22 cashflow challenges. The proposed FY22-23 budget includes repayment of the funds to Blue Lake Rancheria and cancelling the power sale to MCE. The projected net revenue for FY22-23 is $8 million. Staff recommends all projected net revenue be designated as cash reserves to replace the funds utilized in FY21-22.
Additionally, the Board of Directors conditionally approved the following personnel allocations and changes to the Organization Chart with the adoption of the budget. 1) Creation of an Infrastructure Programs Manager position, 2) Addition of a DSM Intake Coordinator position,
3) Addition of a Power Resources Specialist position,
The additional positions are included in the proposed budget.
Staff will provide a summary presentation on the final proposed budget at the Board meeting.
STAFF RECOMMENDATION
Approve:
1) Adoption of the proposed RCEA Fiscal Year 2022-23 budget, 2) Creation of an Infrastructure Programs Manager position, 3) Addition of a DSM Intake Coordinator position,
4) Addition of a Power Resources Specialist position,
5) Update to the RCEA Organization Chart, and
6) Revising the Assistant/Coordinator/Associate position to clarify the distinction between limited-term and permanent positions.
ATTACHMENTS
1. Proposed Fiscal Year 2022-23 RCEA Budget
2. Proposed changes to RCEA Organizational Chart
3. Proposed Infrastructure Programs Manager position description
4. Revised Assistant/Coordinator/Associate position description 85 Proposed Redwood Coast Energy Authority Fiscal Year 2022-2023 Budget Account
Core Power
Resources
Airport Solar
Microgrid
Redwood
Coast Offshore
Wind
TOTAL Power
Resources
Income
5 REVENUE EARNED
Total 5000 · Revenue - Government Agencies - - - -
Total 5100 · Revenue - Program-Related Sales - - - -
Total 5400 · Revenue-nongovernment agencies - 182,802 - 182,802 5500 · Revenue - Electricity Sales
5510 · Electricity Sales 85,350,127 - - 85,350,127
5550 · PPA Revenues 9,698,621 506,939 - 10,205,560
5580 · Uncollectable Accounts (1,707,003) - - (1,707,003) Total 5500 · Revenue - Electricity Sales 93,341,745 506,939 - 93,848,684 Total 5 REVENUE EARNED 93,341,745 689,741 - 94,031,486
Expense
Total 6 WHOLESALE POWER SUPPLY 72,160,478 75,798 - 72,236,276 Total 7 PERSONNEL EXPENSES 942,515 40,627 44,678 1,027,820 Total 8.1 FACILITIES AND OPERATIONS 69,080 183,302 100 252,482 Total 8.2 COMMUNICATIONS AND OUTREACH 72,750 1,000 80,000 153,750
8.4 PROFESSIONAL & PROGRAM SRVS
8400 · Regulatory 180,000 - - 180,000
8410 · Contracts - Program Related Ser 20,000 - 100,000 120,000 8420 · Accounting - - - -
8430 · Legal 60,000 2,000 75,000 137,000
8450 · Wholesale Services - TEA 624,984 30,000 - 654,984 8460 · Procurement Credit - TEA 690,545 - - 690,545
8470 · Data Management - Calpine 737,532 - - 737,532
Total 8.4 PROFESSIONAL & PROGRAM SRVS 2,313,061 32,000 175,000 2,520,061 Total 8.5 PROGRAM EXPENSES 623,600 - - 623,600
Total 8.6 INCENTIVES & REBATES - - - -
Total 9 NON OPERATING COSTS 5,000 194,000 - 199,000
Total Expense 76,186,484 526,727 299,778 77,012,989
Net Income 17,155,261 163,014 (299,778) 17,018,497
COMMUNITY CHOICE ENERGY (CCE) - POWER RESOURCES
86 Proposed Redwood Coast Energy Authority Fiscal Year 2022-2023 Budget Account
Income
5 REVENUE EARNED
Total 5000 · Revenue - Government Agencies
Total 5100 · Revenue - Program-Related Sales
Total 5400 · Revenue-nongovernment agencies
5500 · Revenue - Electricity Sales
5510 · Electricity Sales
5550 · PPA Revenues
5580 · Uncollectable Accounts
Total 5500 · Revenue - Electricity Sales
Total 5 REVENUE EARNED
Expense
Total 6 WHOLESALE POWER SUPPLY
Total 7 PERSONNEL EXPENSES
Total 8.1 FACILITIES AND OPERATIONS
Total 8.2 COMMUNICATIONS AND OUTREACH
8.4 PROFESSIONAL & PROGRAM SRVS
8400 · Regulatory
8410 · Contracts - Program Related Ser
8420 · Accounting
8430 · Legal
8450 · Wholesale Services - TEA
8460 · Procurement Credit - TEA
8470 · Data Management - Calpine
Total 8.4 PROFESSIONAL & PROGRAM SRVS
Total 8.5 PROGRAM EXPENSES
Total 8.6 INCENTIVES & REBATES
Total 9 NON OPERATING COSTS
Total Expense
Net Income
PG&E Local
Government
Partnership
Program
RCEA-Administered
CPUC Efficiency
Program
TECH
Grant
CCE-funded
DSM Services
and Programs TOTAL DSM
- 877,031 - - 877,031
- - - - -
246,634 - 59,688 - 306,322
- - - - -
- - - - -
- - - - -
- - - - -
246,634 877,031 59,688 - 1,183,353
- - - - -
239,434 571,408 59,688 641,119 1,511,649
3,200 3,800 - 2,800 9,800
4,000 6,000 - 3,100 13,100
- - - - -
- 55,000 45,000 100,000
- - - - -
- 2,500 6,500 9,000
- - - - -
- - - - -
- - - - -
- 57,500 - 51,500 109,000
- 1,000 - 1,000 2,000
- 237,323 - 181,000 418,323
- - - - -
246,634 877,031 59,688 880,519 2,063,872
- - - (880,519) (880,519)
DEMAND-SIDE MANAGEMENT (DSM)
87 Proposed Redwood Coast Energy Authority Fiscal Year 2022-2023 Budget Account
Income
5 REVENUE EARNED
Total 5000 · Revenue - Government Agencies
Total 5100 · Revenue - Program-Related Sales
Total 5400 · Revenue-nongovernment agencies
5500 · Revenue - Electricity Sales
5510 · Electricity Sales
5550 · PPA Revenues
5580 · Uncollectable Accounts
Total 5500 · Revenue - Electricity Sales
Total 5 REVENUE EARNED
Expense
Total 6 WHOLESALE POWER SUPPLY
Total 7 PERSONNEL EXPENSES
Total 8.1 FACILITIES AND OPERATIONS
Total 8.2 COMMUNICATIONS AND OUTREACH
8.4 PROFESSIONAL & PROGRAM SRVS
8400 · Regulatory
8410 · Contracts - Program Related Ser
8420 · Accounting
8430 · Legal
8450 · Wholesale Services - TEA
8460 · Procurement Credit - TEA
8470 · Data Management - Calpine
Total 8.4 PROFESSIONAL & PROGRAM SRVS
Total 8.5 PROGRAM EXPENSES
Total 8.6 INCENTIVES & REBATES
Total 9 NON OPERATING COSTS
Total Expense
Net Income
REVNET and
CALeVIP
CEC
Medium/Heavy
Duty ZEV Grant
CCE-funded
Transportation
Services and
Programs
TOTAL
Transportation
74,000 150,000 - 224,000
30,400 - - 30,400
- - - -
- - - -
- - - -
- - - -
- - - -
104,400 150,000 - 254,400
- - - -
189,859 57,816 52,500 300,175
155,800 - 200 156,000
2,500 2,184 - 4,684
- - - -
- 50,000 - 50,000
- - - -
4,000 - 5,000 9,000
- - - -
- - - -
- - - -
4,000 50,000 5,000 59,000
12,500 - - 12,500
- - 59,500 59,500
- - - -
364,659 110,000 117,200 591,859
(260,259) 40,000 (117,200) (337,459)
TRANSPORTATION
88 Proposed Redwood Coast Energy Authority Fiscal Year 2022-2023 Budget Account
Income
5 REVENUE EARNED
Total 5000 · Revenue - Government Agencies
Total 5100 · Revenue - Program-Related Sales
Total 5400 · Revenue-nongovernment agencies
5500 · Revenue - Electricity Sales
5510 · Electricity Sales
5550 · PPA Revenues
5580 · Uncollectable Accounts
Total 5500 · Revenue - Electricity Sales
Total 5 REVENUE EARNED
Expense
Total 6 WHOLESALE POWER SUPPLY
Total 7 PERSONNEL EXPENSES
Total 8.1 FACILITIES AND OPERATIONS
Total 8.2 COMMUNICATIONS AND OUTREACH
8.4 PROFESSIONAL & PROGRAM SRVS
8400 · Regulatory
8410 · Contracts - Program Related Ser
8420 · Accounting
8430 · Legal
8450 · Wholesale Services - TEA
8460 · Procurement Credit - TEA
8470 · Data Management - Calpine
Total 8.4 PROFESSIONAL & PROGRAM SRVS
Total 8.5 PROGRAM EXPENSES
Total 8.6 INCENTIVES & REBATES
Total 9 NON OPERATING COSTS
Total Expense
Net Income
Other
CAP/
CAPE
TOTAL
Strategic
Planning
- - - - 1,101,031
- - - - 30,400
- - - - 489,124
- - - -
- - - -
- - - -
- - - - 93,848,684
- - - - 95,469,239
- - - 4,000,000 76,236,276
- 183,380 183,380 1,048,660 4,071,684
- 100 100 383,434 801,816
- - - 5,470 177,004
- - - - 180,000
20,000 - 20,000 - 290,000
- - - 87,455 87,455
- - - 25,000 180,000
- - - - 654,984
- - - - 690,545
- - - - 737,532
20,000 - 20,000 112,455 2,820,516
- - - - 638,100
- - - - 477,823
- - - 2,047,020 2,246,020
20,000 183,480 203,480 7,597,039 87,469,239
(20,000) (183,480) (203,480) (7,597,039) 8,000,000
PROPOSED
FISCAL YEAR
2022-2023
BUDGET
STRATEGIC PLANNING GENERAL &
ADMIN
89 *Executive Director may approve the hiring of part-time, intern and limited-term positions if they fit within the Board adopted total personnel budget.
Community of Humboldt County
RCEA Board
Independent
Auditors Executive
Director*
Manager
Community
Strategies
Coordinator
Customer Service
Director
Infrastructure Planning &
Operations
Manager
Infrastructure
Programs
Specialist
Infrastructure
Director
Business Planning
& Finance
Manager
Finance
Coordinator
Admin
Manager
Contracts and Grants
Director
Power
Resources
Manager
Power Resources
Manager
Account Services
Specialist
Power Resources
Specialist
Power Resources
Contractor
Wholesale Power
Procurement
&
Scheduling
Director
Demand-Side Management
Manager
Direct Install, Energy
Efficiency, & Conservation
Technician
Energy
Efficiency
Technician
Energy
Efficiency
Technician
Energy
Efficiency
Coordinator
Intake
Manager
Demand Side
Projects
Manager
Demand Side
Projects
Technician
Energy
Efficiency
Specialist
Programs
Manager
Regulatory and
Legislative Policy
General Counsel
Deputy Executive
Director
Community
Advisory
Committee
Manager
Human Resources
& Workforce
Development
Specialist
Administration
Technician
Information
Technology
Specialist
Executive Support
Clerk of the Board
Draft RCEA Organization Chart
90 Humboldt County • Arcata • Blue Lake • Eureka • Ferndale • Fortuna • Rio Dell • Trinidad • Humboldt Bay Municipal Water District
Manager/Senior Manager – Infrastructure Programs
General Class Description: Under general direction of a Director, a program or project Manager assists in planning, organizing, coordinating, and managing programs or activities of their associated department; provides professional assistance to staff; and performs related work as assigned. This class has lead responsibility for planning and implementation for one or more programs or functional areas. A Manager is responsible for accomplishing program goals and objectives and directs the day-to-day operations and activities of their designated program or functional area within a department. A Manager works with their Director to ensure consistent and efficient implementation of agency operational policies and long-term operational excellence. This position class is distinguished by complex and widely-scoped duties related to program and project management, subject-matter expertise, and may include supervisorial responsibility. This position exercises considerable discretion and independent judgment in the coordination and prioritization of duties and responsibilities assigned, and in acting on behalf of the department Director in their absence.
Summary
The Infrastructure Programs Manager works under general direction of the Director of Infrastructure Planning and Operations and has responsibility for a wide range of matters related to RCEA’s infrastructure programs. The Infrastructure Programs Manager plans and manages implementation of transportation electrification, resiliency, and related initiatives and projects. The Infrastructure Programs Manager also assists with continuous program improvements and develops and enhances the overall capital asset portfolio. The Infrastructure Programs Manager manages staff scheduling and workloads, manages budgets, and oversees implementation of projects and deliverables, and may supervise other Infrastructure program staff. The Infrastructure Programs Manager has knowledge of transportation electrification and resiliency technologies, local and state policy and goals, and intermediate to advanced project management and coordination skills.
Essential Functions and Responsibilities
Duties are illustrative and may vary. Other duties may be assigned. • Oversee the day-to-day functions of RCEA’s Infrastructure programs to achieve programmatic goals, provide high-quality service, and exemplify efficient and adaptive design. • In collaboration with the Director, assist with strategic planning and development of infrastructure programs consistent with RCEA’s mission.
• Serve as the lead technical staff person for infrastructure topics such as transportation electrification and resiliency.
• Perform and oversee routine program activities such as capital asset operations and performance, site selection, agreements and construction, project design and analysis, consultation with customers, tracking, and reporting.
• Assist Director to manage overall budget, schedule, and resources to achieve project deliverables within a dynamic program environment.
• Seek, apply for, and manage funding agreements such as state and federal grants. • Collaborate with local, state, and federal public and private stakeholders to achieve shared regional and industry goals, including standards, legislative, and regulatory initiatives. • Represent rural community concepts and interests in local and state working groups and forums. • Manage vendor, contractor, consultant, and third-party relationships. 91 Manager/Senior Manager – Infrastructure Programs
• Provide logistical and administrative oversight of program operations, including supervising staff, inventory management, controlling and monitoring expenditures, representing and enforcing RCEA policies and procedures, training, and identifying resource gaps and solutions. • Provide technical assistance to the public, deliver training, and represent RCEA at external events.
Minimum Qualifications
Experience/Education:
• Any combination of training and experience that would provide the required knowledge, skills, and abilities is qualifying. A typical way to obtain the required qualifications would be:
• Education or experience equivalent to a bachelor’s degree or greater in transportation planning, energy management, engineering, environmental sciences, or a closely related field. • A minimum of 3 years of increasingly responsible project management experience, preferably energy, transportation, or public works project management. • Experience in supervisory responsibility, preferably for a staff delivering a variety of products and services for a diverse audience and using a range of program design, technologies, and supply and delivery channels.
Knowledge of:
• Clean transportation, resiliency, and distributed grid technologies. • Principles of usage, efficiency, and application of zero emission vehicles and distributed smart energy resources.
• Principles of capital asset management such as stakeholder engagement, business modeling, financing, construction, and operations.
• Local and state codes, policies, and goals for public works in general, as well as transportation electrification, resiliency, and decarbonization initiatives. • Principles of electric vehicle charging infrastructure, distributed generation resources, electric grid design and evolution.
• General legislative and regulatory framework for transportation, grid resiliency, and decarbonization.
• Principles and methods of program development, implementation, and project management.
Ability to:
• Work collaboratively with coworkers and third-party providers to identify and solve problems. • Prepare accurate, comprehensive, and timely reports and other deliverables as required. • Assist with program development and design, including needs assessments, proposal drafting, marketing tool preparation, program evaluation and reporting. • Learn, interpret, and apply policies, procedures, and regulations. Provide program-based guidance and interpretation for staff and the public.
• Assist with administration of project budgets, including control and monitoring of project-related expenditures.
• Establish and maintain effective relationships with diverse community stakeholders.
Communicate clearly and effectively with customers.
• Identify and solve problems effectively and expeditiously. • Direct, supervise and coordinate the work of assigned staff. • Manage multiple priorities, meet deadlines, and quickly adapt to changing priorities in a fast-paced dynamic environment. • Work well under pressure.
• Be thorough and detail-oriented.
• Demonstrate patience, tact, teamwork and commitment to superior service and performance. 92 Manager/Senior Manager – Infrastructure Programs
Working Conditions and Essential Requirements
The physical demands described here are representative of those required for the position. Position requires sitting, walking, standing, bending, and twisting in the performance of daily activities. The position requires hand manipulation and repetitive hand movement and fine coordination in using a computer keyboard and other office equipment. The position requires near and far vision in reading reports, use of a computer, and to perform testing and diagnostic tasks. Acute hearing is required in supporting meetings and providing phone and in-person customer service. Fine and gross motor control is required to set up and operate diagnostic and data collection equipment in a variety of settings. The position requires the ability to use ladders and hand tools and to physically work in construction settings.
The position occasionally requires lifting and/or moving bulky and/or heavy objects. RCEA will make reasonable accommodation of the known physical or mental limitations of a qualified applicant with a disability upon request. Possession and continued maintenance of a valid class C California driver’s license or the ability to provide alternate transportation and a safe driving record is required.
Preferred Qualifications
• Master’s degree in a related field.
• Knowledge of RCEA programs.
• Knowledge of CARB, CEC, and CPUC transportation and resiliency programs. • Prior experience managing sub-contractors.
• Prior experience working with public agencies.
• Experience working with organizations involved with projects and programs in the areas of environmental and economic development.
• Experience working in an entrepreneurial context.
THE REDWOOD COAST ENERGY AUTHORITY IS COMMITTED TO A DIVERSE WORKFORCE AND IS AN EQUAL OPPORTUNITY EMPLOYER. RCEA MAINTAINS AND PROMOTES A POLICY OF
NONDISCRIMINATION AND NONHARASSMENT ON THE BASIS OF RACE, RELIGION, COLOR, SEX,
AGE, HANDICAP, MARITIAL STATUS, SEXUAL ORIENTATION, AND NATIONAL ORIGIN OR GENETIC CHARACTERISTIC.
93 Humboldt County • Arcata • Blue Lake • Eureka • Ferndale • Fortuna • Rio Dell • Trinidad • Humboldt Bay Municipal Water District
Assistant / Coordinator / Associate
Class Description: Under the supervision of a Manager or Director, an Assistant, Coordinator or Associate supports RCEA staff by providing general or clerical duties related to one or more programmatic or administrative functions. The Assistant/Coordinator/Associate may be a permanent staff position or a limited-term/part-time role. Permanent staff positions serve essential operations and support roles for a specific department or RCEA as a whole. Limited-term/part-time Assistant, Coordinator, and Associate positions provide internship-style career development opportunities related to energy, public policy, and/or government administration for those new to these fields.
Summary
Under direct supervision, provides varied administrative and programmatic support for agency operations, including office administration, customer service, and energy programs, as assigned.
Essential Functions and Responsibilities
Duties are illustrative only and may vary. Other duties may be assigned. • Provide administrative support to staff and assist in general office management. • Provide office and field–based customer service assistance. • Perform office tasks such as answering phones, processing paper and electronic records, and entering data.
Minimum Qualifications
Experience/Education:
Any combination of training and experience that would provide the required knowledge, skills, and abilities is qualifying. A typical way to obtain the required qualifications would be:
• Education or experience equal to an Associate’s degree in a related field, or two (2) years relevant work or educational experience, or any combination thereof.
Knowledge of:
• Basic office functions, such as operation of common office equipment, email and phone communications, scheduling, and document handling.
• Business software applications, including word processing, spreadsheets, email, calendars, and web browsers.
• Basic business terminology.
• Note taking, task management, and time management approaches and tools.
Ability to:
• Learn, understand, and effectively communicate information to coworkers, customers, and/or vendors.
• Promote and maintain a customer-centric approach to job duties. • Work effectively as part of a team.
• Handle multiple tasks simultaneously at a fast pace and within stringent time constraints. • Understand and apply office policies and procedures.
94 Assistant/ Coordinator/ Associate
• Exercise discretion and independent judgment when necessary.
Working Conditions and Essential Requirements
The physical demands described here are representative of those required for the position, which may include both office-based activities and field work. Position requires sitting, walking, standing, bending, and twisting in the performance of daily activities. The position requires hand manipulation and repetitive hand movement and fine coordination in using a computer keyboard and other office equipment. The position requires near and far vision in reading reports and use of a computer. Acute hearing is required in supporting meetings and providing phone and in-person customer service. Some placements may require fine and gross motor control to place and operate diagnostic and data collection equipment in a variety of settings.
Some placements may require the ability to use ladders and hand tools and to physically navigate building service spaces such as attics and crawlspaces or equivalent. The position occasionally requires lifting and/or moving objects. RCEA will make reasonable accommodation of the known physical or mental limitations of a qualified applicant with a disability upon request. Possession and continued maintenance of a valid class C California driver’s license or the ability to provide alternate transportation and a safe driving record is required.
Preferred Qualifications
• Bachelor’s degree in a related discipline from an accredited institution. • Knowledge of RCEA programs.
• Prior experience working with public agencies and/or public utilities. • Experience working with organizations involved with projects and programs in the areas of environmental and economic development.
• Experience working in an entrepreneurial context.
THE REDWOOD COAST ENERGY AUTHORITY IS COMMITTED TO A DIVERSE WORKFORCE AND IS AN EQUAL OPPORTUNITY EMPLOYER. RCEA MAINTAINS AND PROMOTES A POLICY OF
NONDISCRIMINATION AND NONHARASSMENT ON THE BASIS OF RACE, RELIGION, COLOR, SEX,
AGE, HANDICAP, MARITIAL STATUS, SEXUAL ORIENTATION, AND NATIONAL ORIGIN OR GENETIC CHARACTERISTIC.
95 Fiscal Year 2022-23
Proposed Budget
Overview
FY22-23 Budget Assumptions
• Energy revenue and costs based on model from April 30, 2022. • Financial modelling from June 1, 2022, resulted in a 14% increase in revenue and 5% increase in costs over April numbers. Based on continuing market volatility, staff recommends staying with the more conservative numbers from April for the budget.
• Modeled revenue adjusted down by 4% and costs adjusted up by 11%. Staff chose the most conservative scenario to present in our budget.
• Assumes 3.1% PG&E rate change in 2023.
Comparing Financial Models
$95,500,000
$108,549,535
$87,500,000
$91,936,599
$-
$20,000,000
$40,000,000
$60,000,000
$80,000,000
$100,000,000
$120,000,000
April 30, 2022 Projections June 1, 2022 Projections
Total Revenue Total Expenses
No
Changes to
Proposed
Budget
Proposed budget is the same as presented to the
Board in May 2022.
Includes addition of three full-time positions
(Infrastructure Manager, Power Resources Specialist
and Intake Coordinator).
Budget reflects 0.5% retail rate discount from PG&E
rates.
Budget does not reflect Rural REN and grants that
have not been awarded as of June 2022.
REVENUE
FY 21/22 $ 53,500,000
FY 22/23 $ 95,500,000
EXPENSES
FY 21/22 $52,200,000
FY 22/23 $87,500,000
87.2%
4.7%
0.9%
0.2%
3.2%
0.7% 0.5% FY 22/23 EXPENSES 2.6%
Wholesale power supply Personnel
Facilities and Operations Communications and Outreach
Professional & Program Services Program Expenses
Incentives & Rebates Non Operating Costs (loan repayment)
87.5%
10.7%
1.1% 0.7%
FY 22/23 REVENUE
Electricity Sales
Power Purcahse Agreements
Program-funding from grants, contracts, etc
Airport microgrid
Energy sales and costs
• Electricity sales revenue projected to be up $38.9M
• Wholesale power costs projected to be up $28.5M
• Delinquent customer utility-bill payments are expected to decrease.
It is calculated as 2% of electricity sales revenue.
$-
$20,000,000
$40,000,000
$60,000,000
$80,000,000
$100,000,000
$120,000,000
FY 21/22 FY 22/23
Total Revenue Total Expenses
Proposed Bottom-line
• In FY 21-22 we experienced negative net revenue
which caused RCEA to use all cash reserves and receive
loan funds.
• Current budgeted net revenue does not reflect actuals. • End result: Addition of $8M to reserves to replace
cash reserves utilized in FY 21-22.
Current Budget FY22-23 Preliminary Draft
Revenue $53.5M $95.5M
Expenses $52.2M $87.5M
Net Revenue $1.3M $8M
STAFF REPORT
Agenda Item # 9.1
AGENDA DATE: June 23, 2022
TO: Board of Directors
PREPARED BY: Stephen Kullmann, Director of Demand Side Management Patricia Terry, Senior Manager of Demand Side Management Mike Avcollie, Manager of Demand Side Management
SUBJECT: Update on RCEA’s Public Agency Solar Program (PASP) and the California Schools Healthy Air and Plumbing Efficiency Program (CalSHAPE)
BACKGROUND
In February 2018 RCEA’s Board of Directors approved $170,000 in funding for the pilot Public Agency Solar Program (PASP), which was launched by RCEA Demand Side Management (DSM) staff in May 2018. Its primary goal was to serve as a test case for a full-scale, turn-key program that would support local government agencies’ adoption of cost saving energy generation projects. Pilot objectives included but were not limited to:
• Exploring solar projects at five to seven public agencies, • The development of a flexible program design that can be scaled and replicated, • An end of year evaluation including recommended programmatic next steps.
RCEA’s approach has been to incorporate energy efficiency retrofits in the scopes of services where such measures have not already been implemented.
The California Energy Commission was authorized by Assembly Bill (AB) 841 (Chapter 372, Statutes of 2020) to design, administer, and implement the California Schools Healthy Air, Plumbing, and Efficiency Program (CalSHAPE). CalSHAPE includes two grant programs, CalSHAPE Plumbing and CalSHAPE Ventilation, for eligible parties within the service territories of the large electric and natural gas utilities in California.
RCEA staff has worked with local schools to navigate eligibility for this program and submit applications for funding as part of RCEA’s Local Government Partnership (LGP) Program. The LGP program is a partnership with PG&E launched in July 2020 to serve public agencies and other hard-to-reach customers in Humboldt County with energy services and is administered by DSM staff.
SUMMARY
PASP Achievements since 2018
96
The PASP saw immediate interest from public agencies in Humboldt County, with 12 public agencies signing up for services in the first year. PASP has served 24 agencies since the program launched. Program achievements are summarized in the table below.
Agencies Served 24
Solar Site Assessments 57
# of Projects Funded 13
Total Funding Awarded ($) $4,486,378
Projects Completed 10
Projects In Progress 3
Total Capacity Installed (kW-DC) 779.5
Annual Energy Produced/Saved (kWh-AC) 1,346,003
CalSHAPE Achievements through RCEA’s LGP Program
RCEA staff have helped Humboldt County schools qualify for and apply for CalSHAPE funding for HVAC and plumbing in Funding Rounds One and Two in 2021 and 2022. RCEA staff have provided public works project management services to the schools for projects funded through CalSHAPE. Staff are engaged and ready to work with local schools on applications for Funding Round Three when it launches in June and August 2022. Achievements are summarized in the table below.
Agencies Served 4
Number of Site Assessed 6
Applications Submitted 4
Applications in Progress 3
Projects Awarded 4
Total Funding Awarded $185,859
Through the LGP Program, RCEA staff provide additional energy services to public agencies, including assessments, benchmarking, referrals for energy efficiency services, and more.
ALIGNMENT WITH RCEA’S STRATEGIC PLAN
2.4.1 Support Customer Installation of Distributed Generation. Support the deployment of behind-the-meter grid-connected renewable energy and storage systems as core strategies toward achieving environmental, economic, and community stability/resilience goals.
2.4.2 Implement the Public Agency Solar Program. Continue to implement the solar and energy storage technical assistance program for public agencies; integrate grid-connected resources, efficiency, electrification and microgrids as feasible.
2.2.3 Increase Equipment Efficiency through Market Transformation. Prioritize the development and implementation of programs and services that promote the use of the most energy-efficient equipment for space and water heating, ventilation, lighting, 97
refrigeration, and air conditioning in all buildings, including residential, commercial and industrial facilities.
EQUITY IMPACTS
The PASP has worked with the Bear River Band of the Rohnerville Rancheria and the Wiyot Tribe performing solar site assessments, efficiency assessments and providing information about electric use and costs at selected sites. RCEA’s work, through the PASP and our LGP work on CalSHAPE has focused on schools and public agencies that serve diverse and underserved communities. DSM staff are also working with the Yurok Tribe on multiple projects through the LGP program.
FINANCIAL IMPACT
RCEA DSM staff have assisted Humboldt County public agencies in procuring over $4.5 million in outside funding
ATTACHMENTS
A presentation will be made at the Board meeting.
98 Public Agency Solar Program (PASP)
and California Schools Healthy Air
and Plumbing Efficiency (CalSHAPE) Presentation to RCEA Board of Directors June 23, 2022 Mike Avcollie, Project Manager DSM
CalSHAPE Program
• The California Energy Commission’s (CEC’s)
California School Healthy Air, Plumbing, and
Efficiency Program (CalSHAPE)
• authorized by Assembly Bill (AB) 841
• upgrade noncompliant plumbing fixtures
and appliances
• assessments and maintenance of heating,
air conditioning, and ventilation (HVAC)
systems.
• RCEA staff has worked with Local Education
Agencies (LEAs) to navigate eligibility for this
program and submit applications
• Leveraged RCEA’s Local Government
Partnership (LGP) Program serving public
agencies and other hard-to-reach customers
• The first round opened to LEAs in areas CalSHAPE Program determined to be Disadvantaged Communities
(DACs) or low-income communities.
• RCEA assisted four LEAs in applying for
Ventilation funding for that round.
• In the second round of funding, open to all
LEAs, RCEA will assist one LEA with a Plumbing
program application and two LEAs with
Ventilation program applications for sites that
were not in low-income communities.
• Future funding rounds may allow for projects
that add ventilation where there is none
existing and for upgrading inefficient
equipment.
Electric Load Analysis
Local Educational
Agencies (LEAs) Served:
• Loleta Union School District
• Arcata School District
• Coastal Grove Charter School
• Redwood Coast Montessori
Electric Load Analysis
Program Achievements:
▪ Total Sites Assessed: 6
▪ Applications Submitted: 6
▪ Applications in Progress: 3
▪ Total Projects Awarded: 4
▪ Total Funding Awarded: $185,859
RCEA’s Public
Agency Solar
Program (PASP)
• Launched by RCEA Demand Side
Management (DSM) staff in May
2018.
• The primary goal was to support local
government agencies’ adoption of cost
saving energy generation projects.
• The program signed up 12 public
agencies in its first year.
• PASP has served 24 agencies since
launch.
• Work continues through LGP program
and Key Account Management
services.
RCEA’s Public
Agency Solar
Program (PASP)
Services Include:
• Electric Load Analysis
• Energy Efficiency Upgrade
Options
• Solar Site Assessments
• Project Feasibility Studies
• Identification of Funding Sources
• Contracting Assistance
0 1000
2000
3000
4000
5000
6000
7000
8000
9000
Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec
KWH
Ridgewood Electric Use vs Solar Output (kWh)
Monthly Solar PV Output (kWh) Ridgewood Load (kWh) Portables Load (kWh) RCEA’s Public Agency Solar Program
Program Achievements:
▪ Agencies Served: 24
▪ Solar Site Assessments: 57
▪ # Of Projects Funded: 13
▪ Total Funding Awarded: $4,486,378
▪ Projects Completed: 10
▪ Total Installed Capacity: 780 kW (DC)
▪ Annual Energy Production: 1,346 MWh
Public Agency Solar Program (PASP)
Projects
PASP Projects
Agency: City of Trinidad
Funding Source: Self
funded solar, SGIP
incentives for storage
Project Description: 14.4
kW solar array with
battery storage at Town
Hall
PASP Projects
Agency: City of Rio Dell
Funding Source: CalOES
Grant
Project Description: 22
kW solar array with
battery storage and
backup generator at City
Hall
PASP Projects
Agency: City of Ferndale
Funding Source: CEC
Loan
Project Description: 63
kW solar array at WWTP
And 5.6 kW solar array at
the Police Station
PASP Projects
Agency: City of Eureka
Funding Source: CEC
Loan
Project Description: 343
kW solar array at WTP
And 76 kW solar array at
the High Tank Site
PASP Projects
Agency: Cutten School
District
Funding Source: CEC
loan
Project Description: 52
kW solar array at
Ridgewood Elementary
PASP Projects
Agency: Mattole School
District
Funding Source: CEC loan
Project Description:
8 kW solar array at Mattole
Elementary and
4.8 kW solar array at
Honeydew Elementary
PASP Projects
Agency: Southern
Humboldt School District
Funding Source: CEC
loan
Project Description:
273 kW solar array at
South Fork High School
in Miranda
PASP Projects
Agency: Eureka City School
District
Funding Source: CEC
loan
Project Description: 144
kW solar array at the
Corporation Yard
PASP Projects
Agency: Kneeland Fire
Protection District
Funding Source: Private
Grant
Project Description:
3.4 kW solar array with
battery storage at new
facility
PASP Projects
Agency: Burnt Ranch
Elementary School
Funding Source: CalOES
Grant
Project Description:
60 kW solar array
Thank You
Questions?
STAFF REPORT
Agenda Item # 9.2
AGENDA DATE: June 23, 2022
TO: Board of Directors
FROM: Eileen Verbeck, Deputy Executive Director
SUBJECT: Deputy Executive Director’s Report
SUMMARY
Deputy Executive Director Eileen Verbeck will provide a brief update on:
• Local and national offshore wind related activities,
• RCEA recent activities, and
• Other topics as needed.
RECOMMENDED ACTION
None. (Information only.)
99