ARTICLE 6
MAINTENANCE OF THE FACILITY
6.1 Maintenance of the Facility. Seller shall comply with Law and Prudent Operating Practice relating to the operation and maintenance of the Facility and the generation and sale of Product.
(a) Seller shall provide to Buyer no later than ninety (90) days prior to the Commercial Operation Date for the period from the Commercial Operation Date through the end of the then-current calendar year, and no later than September 1 of each calendar year thereafter for the following calendar year, a schedule of all planned outages or derates of the Facility for maintenance purposes (“Scheduled Maintenance”). Seller may perform no more than fifty (50) hours of Scheduled Maintenance that involves a reduction in the Available Generating Capacity and/or Available Storage Capacity of the Facility per Contract Year. Seller shall not conduct Scheduled Maintenance between June 1 and October 31 of each year. Seller shall use commercially reasonable efforts to accommodate reasonable requests of Buyer with respect to adjusting the timing of Scheduled Maintenance. Seller may modify its schedule of Scheduled Maintenance upon reasonable advance notice to Buyer, subject to reasonable requests of Buyer and consistent with Section 4.4 and this Section 6.1.
(b) Seller shall use commercially reasonable efforts to perform during periods of Scheduled Maintenance all maintenance that will reduce the Facility’s output or availability.
Seller shall arrange for any necessary non-emergency maintenance that is not Scheduled Maintenance and that reduces the Available Generating Capacity and/or Available Storage Capacity of the Facility by more than ten percent (10%) to occur only between November 1 and May 31 of each year, unless (i) such outage is required to avoid damage to the Facility, (ii) such maintenance is necessary to maintain equipment warranties and cannot be scheduled outside the months of June through September, or (iii) the Parties agree otherwise in writing. (c) Seller shall use commercially reasonable efforts to schedule all maintenance outages, including those associated with Scheduled Maintenance (i) within a single month, rather than across multiple months, (ii) during periods in which CAISO does not require resource substitution or replacement, and (iii) otherwise in a manner to avoid reductions in the Resource 242
50 Adequacy Benefits available from the Facility to Buyer, if applicable; provided, Seller shall not be required to consolidate preventative maintenance activities into a single month where such consolidation is inconsistent with vendor-recommended maintenance schedules.
6.2 Maintenance of Health and Safety. Seller shall take reasonable safety precautions with respect to the operation, maintenance, repair and replacement of the Facility. If Seller becomes aware of any circumstances relating to the Facility that create an imminent risk of damage or injury to any Person or any Person’s property, Seller shall take prompt, reasonable action to prevent such damage or injury and shall give Buyer’s emergency contact identified on Exhibit R Notice of such condition. Such action may include disconnecting and removing all or a portion of the Facility, or suspending the supply of Energy to Buyer.
6.3 Permits and Approvals. As between Buyer and Seller, Seller shall obtain any required permits and approvals in connection with the development, construction, and operation of the Facility, including without limitation, environmental clearance under the California Environmental Quality Act or other environmental Law, from the local jurisdiction where the Facility will be constructed.
6.4 Energy to Serve Station Use. Notwithstanding anything to the contrary in this Agreement, the Parties acknowledge (a) Seller is responsible for providing all Energy to serve Station Use (including paying the cost of any Energy used to serve Station Use and the cost of energy provided by third parties used to serve Station Use); and (b) Seller may utilize Energy to serve Station Use to the extent permissible in accordance with the CAISO Tariff and subject to the following requirements and restrictions:
(i) Seller shall not bill Buyer and Buyer will not pay Seller for any Energy that serves Station Use, and Seller shall bear all costs associated with Energy that serves Station Use (“Reimbursable Station Use”), including any Stored Energy or Energy discharged from the Storage Facility that serves Station Use during periods when the Storage Facility is charging or discharging pursuant to a Charging Notice or Discharging Notice, as applicable (when such service is permissible in accordance with the CAISO Tariff); (ii) Seller shall separately meter all Station Use to ensure that records and invoices to Buyer are accurate and do not improperly bill Buyer for Energy that serves Station Use and to enable Buyer to invoice Seller for Reimbursable Station Use Costs; (iii) Seller shall ensure that any use of Stored Energy or Energy discharged from the Storage Facility to serve Station Use complies with and does not interfere with or impair Buyer’s or the CAISO’s dispatch of or schedule for the Facility, and if Seller fails to comply with such requirements, then, without prejudice to Buyer’s other rights and remedies hereunder, Seller shall reimburse Buyer for (A) any charges, costs, and penalties imposed by the CAISO for the Storage Facility’s failure to comply with dispatch instructions, the CAISO schedule, or any CAISO requirements; and (B) any loss of revenue if the CAISO adjusts dispatch instructions due to the use of Stored Energy or Energy discharged from the Storage Facility to serve Station Use, in each case only to the extent imposed or incurred as a direct result of Seller’s use of Stored Energy or Energy discharged from the Storage Facility to serve Station Use; 243
51 (iv) Any use of Energy generated by the Generating Facility, Energy discharged from the Storage Facility or Stored Energy for Station Use shall not (A) reduce Seller’s obligations to achieve the Guaranteed Storage Availability and Guaranteed Round-Trip Efficiency, or (B) count toward limits specified in the Operating Restrictions; and (v) Seller shall provide to Buyer upon Buyer’s request all records and data, including detailed meter, charging, discharging, and state of charge data, that may be necessary or useful for Buyer to verify that service of Station Use occurred in compliance with this Section 6.4, and to calculate and verify the accuracy of invoices and amounts required to be reimbursed hereunder.
ARTICLE 7
METERING
7.1 Metering.
(a) Subject to Section 7.1(b) (with respect to the entirety of the following Section 7.1(a)), the Facility shall have a single CAISO Resource ID for both the Generating Facility and the Storage Facility, but shall not share or otherwise associate such CAISO Resource ID with any other generating or storage capacity or facility. The Facility shall be configured as a CAISO Metered Entity. Seller shall measure the following using CAISO Approved Meters and CAISO approved methodologies: the amount of Facility Energy produced by the Facility; the amount of PV Energy produced by the Generating Facility; the amount of Charging Energy and Discharging Energy. The CAISO Approved Meter shall be installed and maintained at Seller’s cost. Metering will be consistent with the Metering Diagram set forth in Exhibit P. The meter(s) shall be kept under seal, such seals to be broken only when the meters are to be tested, adjusted, modified or relocated. In the event that Seller breaks a seal, Seller shall notify Buyer as soon as practicable. In addition, Seller hereby agrees to provide all meter data to Buyer in a form reasonably acceptable to Buyer, and consents to Buyer obtaining from CAISO all CAISO meter data applicable to each of the Generating Facility and the Storage Facility and all inspection, testing and calibration data and reports. Seller and Buyer shall cooperate to allow both Parties to retrieve the meter reads from the CAISO Operational Meter Analysis and Reporting (OMAR) web and/or directly from the CAISO meter(s) at the Generating Facility and the Storage Facility. (b) The foregoing Section 7.1(a) is based on the Parties’ mutual understanding as of the Effective Date that (i) the CAISO requires the configuration of the Facility to include as the sole meters for the Facility, the Generating Facility Meter and the Storage Facility Meter, (ii) the CAISO requires the Generating Facility Meter and the Storage Facility Meter to be programmed for Electrical Losses as set forth in the definition of Electrical Losses in this Agreement, and (iii) the automatic adjustments to Charging Notices and Discharging Notices as set forth in the definitions of Charging Notice and Discharging Notice in this Agreement will not result in the Scheduling Coordinator violating, or incurring any costs, penalties, or charges under, the CAISO Tariff. If any of the foregoing mutual understandings in (i), (ii), or (iii) between the Parties become incorrect during the Delivery Term, the Parties shall cooperate in good faith to make any amendments and modifications to the Facility and this Agreement as are reasonably necessary to conform this Agreement to the CAISO Tariff and avoid, to the maximum extent practicable, any CAISO charges, costs, or penalties that may be imposed on either Party due to 244
52 non-conformance with the CAISO Tariff, such agreement not to be unreasonably delayed, conditioned, or withheld.
7.2 Meter Verification. If Buyer or Seller has reason to believe there may be a meter malfunction, Seller shall test the meter. Annually, upon Buyer’s reasonable request, Seller shall test the meter. The tests shall be conducted by independent third parties qualified to conduct such tests. Buyer shall be notified seven (7) days in advance of such tests and have a right to be present during such tests. If a meter is inaccurate it shall be promptly repaired or replaced. If a meter is inaccurate by more than one percent (1%) and it is not known when the meter inaccuracy commenced (if such evidence exists such date will be used to adjust prior invoices), then the invoices covering the period of time since the last meter test shall be adjusted for the amount of the inaccuracy on the assumption that the inaccuracy persisted during one-half of such period so long as such adjustments are accepted by CAISO and WREGIS; provided, such period may not exceed twelve (12) months.
ARTICLE 8
INVOICING AND PAYMENT; CREDIT
8.1 Invoicing. Seller shall deliver an invoice to Buyer for Product no later than ten (10) days after the end of the prior monthly billing period. Each invoice shall provide Buyer (a) records of metered data, including CAISO metering and transaction data sufficient to document and verify the generation of Product by the Generating Facility and the Storage Facility for any Settlement Period during the preceding month, the amount of Product in MWh produced by the Facility as read by the Generating Facility Meter, Storage Facility Meter, and CAISO Approved Meter, the calculation of Deemed Delivered Energy and Adjusted Energy Production, and the Contract Price applicable to such Product, Station Use and Reimbursable Station Use for any Settlement Period during the preceding month; (b) records and calculations sufficient to show the calculation of the Storage Capacity Payment, including calculations of any applicable Storage Availability Adjustment and RTE Shortfall Payment; and (c) access to any records, including invoices or settlement data from the CAISO, necessary to verify the accuracy of any amount. Invoices shall be in a format specified by Buyer, covering the services provided in the preceding month determined in accordance with the applicable provisions of this Agreement. Buyer shall, and shall cause its Scheduling Coordinator to, provide Seller with all reasonable access (including, in real time, to the maximum extent reasonably possible) to any records, including invoices or settlement data from the CAISO, forecast data and other information, all as may be necessary from time to time for Seller to prepare and verify the accuracy of all invoices.
8.2 Payment. Buyer shall make payment to Seller for Product by wire transfer or ACH payment to the bank account provided on each monthly invoice. Buyer shall pay undisputed invoice amounts within forty-five (45) days after receipt of the invoice. If such due date falls on a weekend or legal holiday, such due date shall be the next Business Day. Payments made after the due date will be considered late and will bear interest on the unpaid balance. If the amount due is not paid on or before the due date or if any other payment that is due and owing from one Party to another is not paid on or before its applicable due date, a late payment charge shall be applied to the unpaid balance and shall be added to the next billing statement. Such late payment charge shall be calculated based on an annual interest rate equal to the prime rate published on the date of the invoice in The Wall Street Journal (or, if The Wall Street Journal is not published on that day, the 245
53 next succeeding date of publication), plus two percent (2%) (the “Interest Rate”). If the due date occurs on a day that is not a Business Day, the late payment charge shall begin to accrue on the next succeeding Business Day.
8.3 Books and Records. To facilitate payment and verification, each Party shall maintain all books and records necessary for billing and payments, including copies of all invoices under this Agreement, for a period of at least two (2) years or as otherwise required by Law. Either Party, upon fifteen (15) days written Notice to the other Party, shall be granted reasonable access to the accounting books and records within the possession or control of the other Party pertaining to all invoices generated pursuant to this Agreement.
8.4 Payment Adjustments; Billing Errors. Payment adjustments shall be made if Buyer or Seller discovers there have been good faith inaccuracies in invoicing that are not otherwise disputed under Section 8.5, an adjustment to an amount previously invoiced or paid is required due to a correction of data by the CAISO, or there is determined to have been a meter inaccuracy sufficient to require a payment adjustment. If the required adjustment is in favor of Buyer, Buyer’s next monthly payment shall be credited in an amount equal to the adjustment. If the required adjustment is in favor of Seller, Seller shall add the adjustment amount to Buyer’s next monthly invoice. Adjustments in favor of either Buyer or Seller shall bear interest, until settled in full, in accordance with Section 8.2, accruing from the date on which the adjusted amount should have been due. Except for adjustments required due to a correction of data by the CAISO, any adjustment described in this Section 8.4 is waived if Notice of the adjustment is not provided within twelve (12) months after the invoice is rendered or subsequently adjusted.
8.5 Billing Disputes. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice rendered under this Agreement, or adjust any invoice for any arithmetic or computational error, within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within five (5) Business Days of such resolution along with interest accrued at the Interest Rate from and including the original due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment. Any dispute with respect to an invoice is waived if the other Party is not notified in accordance with this Section 8.5 within twelve (12) months after the invoice is rendered or subsequently adjusted, except to the extent any misinformation was from a party other than the Party seeking the adjustment and such party corrects its information after the twelve-month period.
If an invoice is not rendered within twelve (12) months after the close of the month during which performance occurred, the right to payment for such performance is waived.
8.6 Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other on the same date through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Product 246
54 during the monthly billing period under this Agreement, including any related damages calculated pursuant to Exhibits B and D, interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it.
8.7 Seller’s Development Security. To secure Seller’s obligations under this Agreement, including the obligations of Seller to pay liquidated damages to Buyer as provided in this Agreement, Seller shall deliver Development Security to Buyer within eighty-five (85) Business Days after the Effective Date. Buyer will have the right to draw upon the Development Security if Seller fails to pay liquidated damages owed to Buyer pursuant to Exhibit B to this Agreement, or if Seller fails to pay a Damage Payment owed to Buyer pursuant to Section 11.2.
Seller shall maintain the Development Security in full force and effect and Seller shall replenish the Development Security in the event Buyer collects or draws down any portion of the Development Security for any reason permitted under this Agreement other than to satisfy a Damage Payment. Following the earlier of (i) Seller’s delivery of the Performance Security, or (ii) sixty (60) days after termination of this Agreement, Buyer shall promptly return the Development Security to Seller, less the amounts drawn in accordance with this Agreement.
8.8 Seller’s Performance Security. To secure its obligations under this Agreement, Seller shall deliver Performance Security to Buyer on or before the Commercial Operation Date.
Seller shall maintain the Performance Security in full force and effect and Seller shall replenish the Performance Security in the event Buyer collects or draws down any portion of the Performance Security for any reason permitted under this Agreement within twenty (20) Business Days after such draw, other than to satisfy a Termination Payment. Seller shall maintain the Performance Security in full force and effect until the date on which the following have occurred (“Performance Security End Date”): (A) the Delivery Term has expired or terminated early; and (B) all payment obligations of the Seller arising under this Agreement, including compensation for penalties, Termination Payment, indemnification payments or other damages are paid in full (whether directly or indirectly such as through set-off or netting). Following the occurrence of the Performance Security End Date, Buyer shall promptly return to Seller the unused portion of the Performance Security. Provided that no Event of Default has occurred with respect to Seller, Seller may replace or change the form of Performance Security to another form of Performance Security from time to time upon reasonable prior written notice to Buyer.
8.9 First Priority Security Interest in Cash or Cash Equivalent Collateral. To secure its obligations under this Agreement, and until released as provided herein, Seller hereby grants to Buyer a present and continuing first-priority security interest (“Security Interest”) in, and lien on (and right to net against), and assignment of the Development Security, Performance Security, any other cash collateral and cash equivalent collateral posted pursuant to Sections 8.7 and 8.8 and any and all interest thereon or proceeds resulting therefrom or from the liquidation thereof, whether now or hereafter held by, on behalf of, or for the benefit of Buyer, and Seller agrees to take all action as Buyer reasonably requires in order to perfect Buyer’s Security Interest in, and lien on (and right to net against), such collateral and any and all proceeds resulting therefrom or from the liquidation thereof.
Upon or any time after the occurrence of an Event of Default caused by Seller, an Early Termination Date resulting from an Event of Default caused by Seller, or an occasion provided for in this Agreement where Buyer is authorized to retain all or a portion of the Development Security 247
55 or Performance Security, Buyer may do any one or more of the following (in each case subject to the final sentence of this Section 8.9):
(a) Exercise any of its rights and remedies with respect to the Development Security and Performance Security, including any such rights and remedies under Law then in effect;
(b) Draw on any outstanding Letter of Credit issued for its benefit and retain any cash held by Buyer as Development Security or Performance Security; and (c) Liquidate all Development Security or Performance Security (as applicable) then held by or for the benefit of Buyer free from any claim or right of any nature whatsoever of Seller, including any equity or right of purchase or redemption by Seller.
Buyer shall apply the proceeds of the collateral realized upon the exercise of any such rights or remedies to reduce Seller’s obligations under this Agreement (Seller remains liable for any amounts owing to Buyer after such application), subject to Buyer’s obligation to return any surplus proceeds remaining after these obligations are satisfied in full.
ARTICLE 9
NOTICES
9.1 Addresses for the Delivery of Notices. Any Notice required, permitted, or contemplated hereunder shall be in writing, shall be addressed to the Party to be notified at the address set forth in Exhibit R or at such other address or addresses as a Party may designate for itself from time to time by Notice hereunder.
9.2 Acceptable Means of Delivering Notice. Each Notice required, permitted, or contemplated hereunder shall be deemed to have been validly served, given or delivered as follows: (a) if sent by United States mail with proper first class postage prepaid, three (3) Business Days following the date of the postmark on the envelope in which such Notice was deposited in the United States mail; (b) if sent by a regularly scheduled overnight delivery carrier with delivery fees either prepaid or an arrangement with such carrier made for the payment of such fees, the next Business Day after the same is delivered by the sending Party to such carrier; (c) if sent by electronic communication (including electronic mail, facsimile, or other electronic means) and either (i) the receiving Party sends a written acknowledgment of receipt, or (ii) concurrently with the transmittal of such electronic communication the sending Party provides a copy of such electronic Notice by hand delivery or express courier, at the time indicated by the time stamp upon delivery; or (d) if delivered in person, upon receipt by the receiving Party. Notwithstanding the foregoing, Notices of outages or other scheduling or dispatch information or requests, may be sent by electronic communication and shall be considered delivered upon successful completion of such transmission.
ARTICLE 10
FORCE MAJEURE
10.1 Definition.
248
56 (a) “Force Majeure Event” means any act or event that delays or prevents a Party from timely performing all or a portion of its obligations under this Agreement or from complying with all or a portion of the conditions under this Agreement if such act or event, despite the exercise of reasonable efforts, cannot be avoided by and is beyond the reasonable control (whether direct or indirect) of and without the fault or negligence of the Party relying thereon as justification for such delay, nonperformance, or noncompliance. (b) Without limiting the generality of the foregoing, so long as the following events, despite the exercise of reasonable efforts, cannot be avoided by, and are beyond the reasonable control (whether direct or indirect) of and without the fault or negligence of the Party relying thereon as justification for such delay, nonperformance or noncompliance, a Force Majeure Event may include an act of God or the elements, such as flooding, lightning, hurricanes, tornadoes, or ice storms; explosion; fire volcanic eruption; flood; epidemic landslide; mudslide; sabotage; terrorism;
earthquake; or other cataclysmic events; an act of public enemy; war; blockade; civil insurrection; riot; civil disturbance; or strikes or other labor difficulties caused or suffered by a Party or any third party except as set forth below.
(c) Notwithstanding the foregoing, the term “Force Majeure Event” does not include (i) economic conditions that render a Party’s performance of this Agreement at the Contract Price unprofitable or otherwise uneconomic (including an increase in component or compliance costs for any reason, including foreign or domestic tariffs, Buyer’s ability to buy Product at a lower price, or Seller’s ability to sell Product at a higher price, than the Contract Price); (ii) Seller’s inability to obtain permits or approvals of any type for the construction, operation, or maintenance of the Facility; (iii) the inability of a Party to make payments when due under this Agreement, unless the cause of such inability is an event that would otherwise constitute a Force Majeure Event as described above that disables physical or electronic facilities necessary to transfer funds to the payee Party; (iv) a Curtailment Period, except to the extent such Curtailment Period is caused by a Force Majeure Event; (v) Seller’s inability to obtain sufficient labor, equipment, materials, or other resources to build or operate the Facility except to the extent such inability is caused by a Force Majeure Event; (vi) a strike, work stoppage or labor dispute limited only to any one or more of Seller, Seller’s Affiliates, Seller’s contractors, their subcontractors thereof or any other third party employed by Seller to work on the Facility; (vii) any equipment failure except if such equipment failure is caused by a Force Majeure Event; (viii) variations in weather, including wind, rain and insolation, within one in fifty (1 in 50) year occurrence; or (ix) failure to complete the interconnection facilities or network upgrades required to connect the Facility and to deliver Product to the Delivery Point by the Guaranteed Commercial Operation Date except to the extent such inability is caused by a Force Majeure Event or (x) Seller’s inability to achieve Construction Start of the Facility following the Guaranteed Construction Start Date or achieve Commercial Operation following the Guaranteed Commercial Operation Date; it being understood and agreed, for the avoidance of doubt, that the occurrence of a Force Majeure Event may give rise to a Development Cure Period. 249
57 10.2 No Liability If a Force Majeure Event Occurs. Neither Seller nor Buyer shall be liable to the other Party in the event it is prevented from performing its obligations hereunder in whole or in part due to a Force Majeure Event. Buyer shall not be obligated to pay for any Product that Seller was not able to deliver as a result of a Force Majeure Event. The Party rendered unable to fulfill any obligation by reason of a Force Majeure Event shall take reasonable actions necessary to remove such inability with due speed and diligence. Nothing herein shall be construed as permitting that Party to continue to fail to perform after said cause has been removed. The obligation to use due speed and diligence shall not be interpreted to require resolution of labor disputes by acceding to demands of the opposition when such course is inadvisable in the discretion of the Party having such difficulty. Neither Party shall be considered in breach or default of this Agreement if and to the extent that any failure or delay in the Party’s performance of one or more of its obligations hereunder is caused by a Force Majeure Event. The occurrence and continuation of a Force Majeure Event shall not suspend or excuse the obligation of a Party to make any payments due hereunder.
10.3 Notice. In the event of any delay or nonperformance resulting from a Force Majeure Event, the Party suffering the Force Majeure Event shall (a) as soon as practicable, notify the other Party in writing of the nature, cause, estimated date of commencement thereof, and the anticipated extent of any delay or interruption in performance, and (b) notify the other Party in writing of the cessation or termination of such Force Majeure Event, all as known or estimated in good faith by the affected Party; provided, a Party’s failure to give timely Notice shall not affect such Party’s ability to assert that a Force Majeure Event has occurred unless the delay in giving Notice materially prejudices the other Party.
10.4 Termination Following Force Majeure Event. If a Force Majeure Event has occurred that has caused either Party to be wholly or partially unable to perform its obligations hereunder, and has continued for a consecutive twelve (12) month period, then the non-claiming Party may terminate this Agreement upon written Notice to the other Party with respect to the Facility experiencing the Force Majeure Event. Upon any such termination, neither Party shall have any liability to the other, save and except for those obligations specified in Section 2.1(b), and Buyer shall promptly return to Seller any Development Security or Performance Security then held by Buyer.
ARTICLE 11
DEFAULTS; REMEDIES; TERMINATION
11.1 Events of Default. An “Event of Default” shall mean, (a) with respect to a Party (the “Defaulting Party”) that is subject to the Event of Default the occurrence of any of the following:
(i) the failure by such Party to make, when due, any payment required pursuant to this Agreement and such failure is not remedied within five (5) Business Days after Notice thereof;
250
58 (ii) any representation or warranty made by such Party herein is false or misleading in any material respect when made or when deemed made or repeated, and such default is not remedied within thirty (30) days after Notice thereof; (iii) the failure by such Party to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default) and such failure is not remedied within thirty (30) days after Notice thereof (iv) such Party becomes Bankrupt;
(v) such Party assigns this Agreement or any of its rights hereunder other than in compliance with Sections 14.2 or 14.3, as applicable; or (vi) such Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party by operation of Law or pursuant to an agreement reasonably satisfactory to the other Party. (b) with respect to Seller as the Defaulting Party, the occurrence of any of the following:
(i) if at any time, Seller delivers or attempts to deliver to the Delivery Point for sale under this Agreement Energy that was not generated or discharged by the Facility; (ii) the failure by Seller to achieve the Construction Start Date within one hundred twenty (120) days after the Guaranteed Construction Start Date, or the failure by Seller to achieve Commercial Operation within days after the Guaranteed Commercial Operation Date;
(iii) the failure by Seller to timely obtain CEC Final Certification and Verification in accordance with Section 3.10;
(iv) if, in the first six (6) months or the second six (6) months of any Contract Year, the Adjusted Energy Production amount is not at least ten percent (10%) of the Expected Energy amount for that Contract Year, and Seller fails to demonstrate to Buyer’s reasonable satisfaction, within ten (10) Business Days after Notice from Buyer, a legitimate reason for the failure to meet the ten percent (10%) minimum;
(v) if in any two (2) consecutive Contract Years, the Adjusted Energy Production amount is not at least sixty-five percent (65%) of the Expected Energy amount in each Contract Year; provided, it will not be an Event of Default under this Section 11.1(b)(v) if (a) the failure to meet the respective standard results from a Transformer Failure, (b) during the one hundred eighty (180) day period following the date of such Transformer Failure Seller diligently pursues a cure to such Transformer Failure and delivers to Buyer a certificate from a Licensed 251
59 Professional Engineer within thirty (30) days following the date of the Transformer Failure that cure can be made within such one hundred eighty (180) day period, and (c) Seller completes the cure of such Transformer Failure within such one hundred eighty (180) day period; (vi) if, in the first Contract Year during the Delivery Term, the average Monthly Storage Availability is not at least fifty percent (50%), or for any Contract Year thereafter, the average Monthly Storage Availability is not at least seventy percent (70%); provided, it will not be an Event of Default under this Section 11.1(b)(vi) if one (1) time during the Delivery Term, (a) the failure to meet the respective standard results from a Transformer Failure, (b) during the one hundred eighty (180) day period following the date of such Transformer Failure Seller diligently pursues a cure to such Transformer Failure and delivers to Buyer a certificate from a Licensed Professional Engineer within thirty (30) days following the date of the Transformer Failure that cure can be made within such one hundred eighty (180) day period, and (c) Seller completes the cure of such Transformer Failure within such one hundred eighty (180) day period; (vii) if, for any two (2) consecutive Contract Years, the annual average Round-Trip Efficiency is not at least seventy-five percent (75%); (viii) if, in any Contract Year, Seller fails to maintain an average Storage Capacity determined pursuant to one or more Storage Capacity Tests equal to at least seventy-five percent (75%) of the Installed Storage Capacity; provided, it will not be an Event of Default under this Section 11.1(b)(viii) if (a) the failure to meet such standard results from a Transformer Failure, (b) during the one hundred eighty (180) day period following the date of such Transformer Failure Seller diligently pursues a cure to Transformer Failure and delivers to Buyer a certificate from a Licensed Professional Engineer within thirty (30) days following the date of the Transformer Failure that cure can be made within such one hundred eighty (180) day period, and (c) Seller completes the cure of such Transformer Failure within such one hundred eighty (180) day period; (ix) failure by Seller to satisfy the collateral requirements pursuant to Sections 8.7 or 8.8, including the failure to replenish the Development Security or Performance Security amount in accordance with this Agreement in the event Buyer draws against either for any reason other than to satisfy a Damage Payment or a Termination Payment, if such failure is not remedied within five (5) Business Days after Notice thereof; (x) if at any time Seller owns, operates or manages any equipment, facility, property or other asset, other than the Facility or engages in any business or activity other than the development, financing, ownership or operation of the Facility; (xi) the occurrence of six (6) consecutive months in which a WREGIS Certificate Deficit was caused, or was the result of any action or inaction, by Seller; provided, if Seller is taking reasonable steps to prevent subsequent WREGIS Certificate Deficits and is reasonably likely to succeed in preventing the occurrence in the seventh (7th) consecutive month, then an Event of Default shall not be deemed to have occurred until the seventh (7th) consecutive month; or
(xii) with respect to any outstanding Letter of Credit provided for the benefit of Buyer that is not then required under this Agreement to be canceled or returned, the 252
60 failure by Seller to provide for the benefit of Buyer either (1) cash, or (2) a substitute Letter of Credit from a different issuer meeting the criteria set forth in the definition of Letter of Credit, in each case, in the amount required hereunder within five (5) Business Days after Seller receives Notice of the occurrence of any of the following events:
(A) the issuer of the outstanding Letter of Credit shall fail to maintain a Credit Rating of at least “A-” by S&P or “A3” by Moody’s; (B) the issuer of such Letter of Credit becomes Bankrupt; (C) the issuer of the outstanding Letter of Credit shall fail to comply with or perform its obligations under such Letter of Credit and such failure shall be continuing after the lapse of any applicable grace period permitted under such Letter of Credit;
(D) the issuer of the outstanding Letter of Credit shall fail to honor a properly documented request to draw on such Letter of Credit; (E) the issuer of the outstanding Letter of Credit shall disaffirm, disclaim, repudiate or reject, in whole or in part, or challenge the validity of, such Letter of Credit;
(F) such Letter of Credit fails or ceases to be in full force and effect at any time; or
(G) Seller shall fail to renew or cause the renewal of each outstanding Letter of Credit on a timely basis as provided in the relevant Letter of Credit and as provided in accordance with this Agreement, and in no event less than sixty (60) days prior to the expiration of the outstanding Letter of Credit.
11.2 Remedies; Declaration of Early Termination Date. If an Event of Default with respect to a Defaulting Party shall have occurred, the other Party (“Non-Defaulting Party”) shall have the following rights:
(a) to send Notice, designating a day, no earlier than the day such Notice is deemed to be received and no later than twenty (20) days after such Notice is deemed to be received, as an early termination date of this Agreement (“Early Termination Date”) that terminates this Agreement (the “Terminated Transaction”) and ends the Delivery Term effective as of the Early Termination Date;
(b) to accelerate all amounts owing between the Parties, and to collect as liquidated damages (i) the Damage Payment (in the case of an Event of Default by Seller under Section 11.1(b)(ii)) or (ii) the Termination Payment, each as calculated in accordance with Section
11.3 below;
(c) to withhold any payments due to the Defaulting Party under this Agreement; (d) to suspend performance; and/or
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61 (e) to exercise any other right or remedy available at law or in equity, including specific performance or injunctive relief, except to the extent such remedies are expressly limited under this Agreement;
provided, payment by the Defaulting Party of the Damage Payment or Termination Payment, as applicable, shall constitute liquidated damages and the Non-Defaulting Party’s sole and exclusive remedy for any Terminated Transaction and the Event of Default related thereto.
11.3 Damage Payment; Termination Payment. If an Early Termination Date has been declared, the Non-Defaulting Party shall calculate, in a commercially reasonable manner, the Damage Payment or Termination Payment, as applicable, in accordance with this Section 11.3. (a) Damage Payment Prior to Commercial Operation Date. If the Early Termination Date occurs before the Commercial Operation Date, then the Damage Payment shall be calculated in accordance with this Section 11.3(a).
(i) If Seller is the Defaulting Party, then the Damage Payment shall be owed to Buyer and shall be a dollar amount that equals the amount of the Development Security plus, if the Development Security is posted as cash, any interest accrued thereon. Buyer shall be entitled to immediately retain for its own benefit those funds held as Development Security and any interest accrued thereon if the Development Security is posted as cash, and any amount of Development Security that Seller has not yet posted with Buyer shall be immediately due and payable by Seller to Buyer. There will be no amounts owed to Seller. The Parties agree that Buyer’s damages in the event of an Early Termination Date prior to the Commercial Operation Date caused by Seller’s default would be difficult or impossible to determine and that the damages set forth in this Section 11.3(a)(i) are a reasonable approximation of Buyer’s harm or loss.
(ii) If Buyer is the Defaulting Party, then the Damage Payment shall be calculated in the same manner as the Termination Payment in Section 11.3(b). (b) Termination Payment On or After the Commercial Operation Date. The payment owed by the Defaulting Party to the Non-Defaulting Party for a Terminated Transaction occurring after the Commercial Operation Date (“Termination Payment”) for a Terminated Transaction shall be the Settlement Amount plus any or all other amounts due to or from the Non-Defaulting Party netted into a single amount. If the Non-Defaulting Party’s aggregate Gains exceed its aggregate Losses and Costs, if any, resulting from the termination of this Agreement, the net Settlement Amount shall be zero. The Non-Defaulting Party shall calculate, in a commercially reasonable manner, a Settlement Amount for the Terminated Transaction as of the Early Termination Date. Third parties supplying information for purposes of the calculation of Gains or Losses may include, without limitation, dealers in the relevant markets, end-users of the relevant product, information vendors and other sources of market information. The Settlement Amount shall not include consequential, incidental, punitive, exemplary, indirect or business interruption damages; provided, any lost Capacity Attributes shall be deemed direct damages covered by this Agreement. Without prejudice to the Non-Defaulting Party’s duty to mitigate, the Non-Defaulting Party shall not have to enter into replacement transactions to establish a Settlement Amount. Each Party agrees and acknowledges that (i) the actual damages that the Non-Defaulting Party would 254
62 incur in connection with a Terminated Transaction would be difficult or impossible to predict with certainty, (ii) the Termination Payment described in this Section 11.3(b) is a reasonable and appropriate approximation of such damages, and (iii) the Termination Payment described in this Section 11.3(b) is the exclusive remedy of the Non-Defaulting Party in connection with a Terminated Transaction but shall not otherwise act to limit any of the Non-Defaulting Party’s rights or remedies if the Non-Defaulting Party does not elect a Terminated Transaction as its remedy for an Event of Default by the Defaulting Party.
11.4 Notice of Payment of Termination Payment. As soon as practicable after a Terminated Transaction, Notice shall be given by the Non-Defaulting Party to the Defaulting Party of the amount of the Termination Payment and whether the Termination Payment is due to or from the Non-Defaulting Party. The Notice shall include a written statement explaining in reasonable detail the calculation of such amount and the sources for such calculation. The Termination Payment shall be made to or from the Non-Defaulting Party, as applicable, within ten (10) Business Days after such Notice is effective.
11.5 Disputes With Respect to Termination Payment. If the Defaulting Party disputes the Non-Defaulting Party’s calculation of the Termination Payment, in whole or in part, the Defaulting Party shall, within five (5) Business Days of receipt of the Non-Defaulting Party’s calculation of the Termination Payment, provide to the Non-Defaulting Party a detailed written explanation of the basis for such dispute. Disputes regarding the Termination Payment shall be determined in accordance with Article 16.
11.6 Limitation on Seller’s Ability to Make or Agree to Third-Party Sales from the Facility after Early Termination Date. If the Agreement is terminated prior to the Commercial Operation Date for any reason other than a Buyer Event of Default, neither Seller nor Seller’s Affiliates may sell, market or deliver any Product associated with or attributable to the Facility to a party other than Buyer for a period of two (2) years following the early termination date, unless prior to selling, marketing or delivering such Product, or entering into the agreement to sell, market or deliver such Product to a party other than Buyer, Seller or Seller’s Affiliates provide Buyer with a written offer to sell the Product on terms and conditions materially similar to the terms and conditions contained in this Agreement (including price) and Buyer fails to accept such offer within forty-five (45) days of Buyer’s receipt thereof.
Neither Seller nor Seller’s Affiliates may sell or transfer the Facility, or any part thereof, or land rights or interests in the Site (including the interconnection queue position of the Facility) so long as the limitations contained in this Section 11.6 apply, unless the transferee agrees to be bound by the terms set forth in this Section 11.6 pursuant to a written agreement approved by Buyer.
Seller shall indemnify and hold Buyer harmless from all benefits lost and other damages sustained by Buyer as a result of any breach by Seller of its covenants contained within this Section 11.6.
11.7 Rights And Remedies Are Cumulative. Except where liquidated damages are provided as the exclusive remedy, the rights and remedies of a Party pursuant to this Article 11 shall be cumulative and in addition to the rights of the Parties otherwise provided in this Agreement.
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63 11.8 Mitigation. Any Non-Defaulting Party shall be obligated to mitigate its Costs, Losses and damages resulting from any Event of Default of the other Party under this Agreement.
ARTICLE 12
LIMITATION OF LIABILITY AND EXCLUSION OF WARRANTIES.
12.1 No Consequential Damages. EXCEPT TO THE EXTENT PART OF AN
EXPRESS REMEDY, INDEMNITY PROVISION, OR MEASURE OF DAMAGES HEREIN,
NEITHER PARTY SHALL BE LIABLE TO THE OTHER OR ITS INDEMNIFIED PERSONS
FOR ANY SPECIAL, PUNITIVE, EXEMPLARY, INDIRECT, OR CONSEQUENTIAL
DAMAGES, OR LOSSES OR DAMAGES FOR LOST REVENUE OR LOST PROFITS,
WHETHER FORESEEABLE OR NOT, ARISING OUT OF, OR IN CONNECTION WITH THIS AGREEMENT, BY STATUTE, IN TORT OR CONTRACT.
12.2 Waiver and Exclusion of Other Damages. EXCEPT AS EXPRESSLY SET
FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR
A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND
MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. ALL LIMITATIONS OF LIABILITY CONTAINED IN
THIS AGREEMENT, INCLUDING, WITHOUT LIMITATION, THOSE PERTAINING TO SELLER’S LIMITATION OF LIABILITY AND THE PARTIES’ WAIVER OF
CONSEQUENTIAL DAMAGES, SHALL APPLY EVEN IF THE REMEDIES FOR BREACH OF WARRANTY PROVIDED IN THIS AGREEMENT ARE DEEMED TO “FAIL OF THEIR ESSENTIAL PURPOSE” OR ARE OTHERWISE HELD TO BE INVALID OR UNENFORCEABLE.
FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS AND EXCLUSIVE
REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR
MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED.
IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN, THE OBLIGOR’S LIABILITY SHALL BE LIMITED TO DIRECT DAMAGES ONLY. THE
VALUE OF ANY TAX BENEFITS, DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER
USE OF REASONABLE EFFORTS) AND AMOUNTS DUE IN CONNECTION WITH THE
RECAPTURE OF ANY RENEWABLE ENERGY INCENTIVES, IF ANY, SHALL BE DEEMED TO BE DIRECT DAMAGES.
TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, INCLUDING THE DAMAGE PAYMENT UNDER SECTION 11.3(a) AND THE TERMINATION PAYMENT UNDER SECTION 11.3(b), AND AS PROVIDED IN
EXHIBIT B AND EXHIBIT D, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES
ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, THAT OTHERWISE OBTAINING AN
ADEQUATE REMEDY IS INCONVENIENT, AND THAT THE LIQUIDATED DAMAGES 256
64 CONSTITUTE A REASONABLE APPROXIMATION OF THE ANTICIPATED HARM OR
LOSS, AND (UNLESS EXPRESSLY STATED TO THE CONTRARY) AN EXCLUSIVE REMEDY. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN
IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD
TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF
ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. THE PARTIES HEREBY WAIVE ANY RIGHT TO CONTEST SUCH PAYMENTS AS AN UNREASONABLE PENALTY.
ARTICLE 13
REPRESENTATIONS AND WARRANTIES; AUTHORITY
13.1 Seller’s Representations and Warranties. As of the Effective Date, Seller represents and warrants as follows:
(a) Seller is a limited liability company, duly organized, validly existing and in good standing under the laws of the State of Delaware, and is qualified to conduct business in each jurisdiction where the failure to so qualify would have a material adverse effect on the business or financial condition of Seller.
(b) Seller has the power and authority to enter into and perform this Agreement and is not prohibited from entering into this Agreement or discharging and performing all covenants and obligations on its part to be performed under and pursuant to this Agreement, except where such failure does not have a material adverse effect on Seller’s performance under this Agreement. The execution, delivery and performance of this Agreement by Seller has been duly authorized by all necessary corporate action on the part of Seller and does not and will not require the consent of any trustee or holder of any indebtedness or other obligation of Seller or any other party to any other agreement with Seller.
(c) The execution and delivery of this Agreement, consummation of the transactions contemplated herein, and fulfillment of and compliance by Seller with the provisions of this Agreement will not conflict with or constitute a breach of or a default under any Law presently in effect having applicability to Seller, subject to any permits that have not yet been obtained by Seller, the documents of formation of Seller or any outstanding trust indenture, deed of trust, mortgage, loan agreement or other evidence of indebtedness or any other agreement or instrument to which Seller is a party or by which any of its property is bound. (d) This Agreement has been duly executed and delivered by Seller. This Agreement is a legal, valid and binding obligation of Seller enforceable in accordance with its terms, except as limited by Laws of general applicability limiting the enforcement of creditors’ rights or by the exercise of judicial discretion in accordance with general principles of equity. (e) The Facility is located in the State of California. (f) All Energy and associated Green Attributes sold and delivered to Buyer hereunder, qualify as PCC1.
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65 13.2 Buyer’s Representations and Warranties. As of the Effective Date, Buyer represents and warrants as follows:
(a) Buyer is a joint powers authority and a validly existing community choice aggregator, duly organized, validly existing and in good standing under the laws of the State of California and the rules, regulations and orders of the California Public Utilities Commission, and is qualified to conduct business in each jurisdiction of the Joint Powers Agreement members. All persons making up the governing body of Buyer are the elected or appointed incumbents in their positions and hold their positions in good standing in accordance with the Joint Powers Agreement and other Law.
(b) Buyer has the power and authority to enter into and perform this Agreement and is not prohibited from entering into this Agreement or discharging and performing all covenants and obligations on its part to be performed under and pursuant to this Agreement, except where such failure does not have a material adverse effect on Buyer’s performance under this Agreement. The execution, delivery and performance of this Agreement by Buyer has been duly authorized by all necessary action on the part of Buyer and does not and will not require the consent of any trustee or holder of any indebtedness or other obligation of Buyer or any other party to any other agreement with Buyer.
(c) The execution and delivery of this Agreement, consummation of the transactions contemplated herein, and fulfillment of and compliance by Buyer with the provisions of this Agreement will not conflict with or constitute a breach of or a default under any Law presently in effect having applicability to Buyer, including but not limited to community choice aggregation, the Joint Powers Act, competitive bidding, public notice, open meetings, election, referendum, or prior appropriation requirements, the documents of formation of Buyer or any outstanding trust indenture, deed of trust, mortgage, loan agreement or other evidence of indebtedness or any other agreement or instrument to which Buyer is a party or by which any of its property is bound.
(d) This Agreement has been duly executed and delivered by Buyer. This Agreement is a legal, valid and binding obligation of Buyer enforceable in accordance with its terms, except as limited by Laws of general applicability limiting the enforcement of creditors’ rights or by the exercise of judicial discretion in accordance with general principles of equity. (e) Buyer warrants and covenants that with respect to its contractual obligations under this Agreement, it will not claim immunity on the grounds of sovereignty or similar grounds with respect to itself or its revenues or assets from (1) suit, (2) jurisdiction of court, (3) relief by way of injunction, order for specific performance or recovery of property, (4) attachment of assets, or (5) execution or enforcement of any judgment.
(f) Buyer is a “local public entity” as defined in Section 900.4 of the Government Code of the State of California.
13.3 General Covenants. Each Party covenants that commencing on the Effective Date and continuing throughout the Contract Term:
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66 (a) It shall continue to be duly organized, validly existing and in good standing under the Laws of the jurisdiction of its formation and to be qualified to conduct business in each jurisdiction where the failure to so qualify would have a material adverse effect on its business or financial condition;
(b) It shall maintain (or obtain from time to time as required) all regulatory authorizations necessary for it to legally perform its obligations under this Agreement; and (c) It shall perform its obligations under this Agreement in compliance with all terms and conditions in its governing documents and any contracts to which it is a party and in material compliance with any Law.
ARTICLE 14
ASSIGNMENT
14.1 General Prohibition on Assignments. Except as provided below and in Article 15, neither Seller nor Buyer may voluntarily assign its rights nor delegate its duties under this Agreement, or any part of such rights or duties, without the written consent of the other Party.
Neither Seller nor Buyer shall unreasonably withhold, condition or delay any requested consent to an assignment that is allowed by the terms of this Agreement. Any such assignment or delegation made without such written consent or in violation of the conditions to assignment set out below shall be null and void.
14.2 Permitted Assignment; Change of Control of Seller. Seller may, without the prior written consent of Buyer, transfer or assign this Agreement to: (a) an Affiliate of Seller; or (b) subject to Section 15.1, a Lender as collateral. Any direct or indirect Change of Control of Seller (whether voluntary or by operation of Law) shall be deemed an assignment under this Article 14 and will require the prior written consent of Buyer, which consent shall not be unreasonably withheld.
14.3 Permitted Assignment; Change of Control of Buyer. Buyer may assign its interests in this Agreement to an Affiliate of Buyer or to any entity that has acquired all or substantially all of Buyer’s assets or business, whether by merger, acquisition or otherwise without Seller’s prior written consent, provided, in each of the foregoing situations, (a) the assignee (i) has a Credit Rating of Baa2 or higher by Moody’s or BBB or higher by S&P, and (ii) is a community choice aggregator or publicly-owned electric utility with retail customers located in the state of California, and (b) no fewer than fifteen (15) Business Days before such assignment Buyer (i) notifies Seller of such assignment and (ii) provides to Seller a written agreement signed by the Person to which Buyer wishes to assign its interests stating that such Person agrees to assume all of Buyer’s obligations and liabilities under this Agreement and under any consent to assignment and other documents previously entered into by Seller as described in Section 15.2. Any assignment by Buyer, its successors or assigns under this Section 14.3 shall be of no force and effect unless and until such Notice and agreement by the assignee have been received and accepted by Seller.
14.4 Buyer Financing Assignment. Seller agrees that Buyer may assign a portion of its rights and obligations under this Agreement to a Person in connection with a municipal 259
67 prepayment financing transaction (“Buyer Assignee”) at any time upon not less than fifteen (15) Business Days’ notice by delivering Notice of such assignment, which notice must include a proposed assignment agreement in form reasonably acceptable to both Parties (the “Assignment Agreement”), provided, at the time of such assignment, such Buyer Assignee has a Credit Rating equal to the higher of (a) Buyer’s Credit Rating at the time of such assignment (if applicable), and (b) Baa2 from Moody’s and BBB from S&P. As reasonably requested by Buyer Assignee, Seller shall (i) provide Buyer Assignee with information and documentation with respect to Seller, including but not limited to account opening information, information related to forecasted generation, Credit Rating, and compliance with anti-money laundering rules, the Dodd-Frank Act, the Commodity Exchange Act, the Patriot Act and similar rules, regulations, requirements and corresponding policies; and (ii) promptly execute such Assignment Agreement and implement such assignment as contemplated thereby, subject only to the countersignature of Buyer Assignee and Buyer and the requirements of this Section 14.4.
ARTICLE 15
LENDER ACCOMMODATIONS
15.1 Granting of Lender Interest. Notwithstanding Section 14.2 or Section 14.3, either Party may, without the consent of the other Party, grant an interest (by way of collateral assignment, or as security, beneficially or otherwise) in its rights and/or obligations under this Agreement to any Lender. Each Party’s obligations under this Agreement shall continue in their entirety in full force and effect. Promptly after granting such interest, the granting Party shall notify the other Party in writing of the name, address, and telephone and facsimile numbers of any Lender to which the granting Party’s interest under this Agreement has been assigned. Such Notice shall include the names of the Lenders to whom all written and telephonic communications may be addressed. After giving the other Party such initial Notice, the granting Party shall promptly give the other Party Notice of any change in the information provided in the initial Notice or any revised Notice.
15.2 Rights of Lender. If a Party grants an interest under this Agreement as permitted by Section 15.1, the other Party shall in good faith work with such Party and its Lender to execute a consent to collateral assignment of this Agreement substantially in the form attached hereto as Exhibit T (“Consent to Collateral Assignment”).
ARTICLE 16
DISPUTE RESOLUTION
16.1 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.
16.2 Dispute Resolution. In the event of any dispute arising under this Agreement, within ten (10) days following the receipt of a written Notice from either Party identifying such dispute, the Parties shall meet, negotiate and attempt, in good faith, to resolve the dispute quickly, informally and inexpensively. If the Parties are unable to resolve a dispute arising hereunder within 260
68 the earlier of either thirty (30) days of initiating such discussions, or within forty (40) days after Notice of the dispute, either Party may seek any and all remedies available to it at Law or in equity, subject to the limitations set forth in this Agreement.
16.3 Attorneys’ Fees. In any proceeding brought to enforce this Agreement or because of the breach by any Party of any covenant or condition herein contained, the prevailing Party shall be entitled to reasonable attorneys’ fees (including reasonably allocated fees of in-house counsel) in addition to court costs and any and all other costs recoverable in said action.
16.4 Venue. The Parties agree that any litigation arising with respect to this Agreement is to be venued in the Superior Court for the county of San Mateo, California ARTICLE 17
INDEMNIFICATION
17.1 Indemnification.
(a) Each Party (the “Indemnifying Party”) agrees to indemnify, defend and hold harmless the other Party and its Affiliates, directors, officers, employees and agents (collectively, the “Indemnified Party”) from and against all third-party claims, demands, losses, liabilities, penalties, and expenses (including reasonable attorneys’ fees) for personal injury or death to Persons and damage to the property of any third party to the extent arising out of, resulting from, or caused by the violation of Law or the negligent or willful misconduct of the Indemnifying Party, its Affiliates, its directors, officers, employees, or agents. (b) Nothing in this Section 17.1 shall enlarge or relieve Seller or Buyer of any liability to the other for any breach of this Agreement. Neither Party shall be indemnified for its damages resulting from its sole negligence, intentional acts or willful misconduct. These indemnity provisions shall not be construed to relieve any insurer of its obligation to pay claims consistent with the provisions of a valid insurance policy.
17.2 Claims. Promptly after receipt by a Party of any claim or Notice of the commencement of any action, administrative, or legal proceeding, or investigation as to which the indemnity provided for in this Article 17 may apply, the Indemnified Party shall notify the Indemnifying Party in writing of such fact. The Indemnifying Party shall assume the defense thereof with counsel designated by such Party and satisfactory to the Indemnified Party, provided, if the defendants in any such action include both the Indemnified Party and the Indemnifying Party and the Indemnified Party shall have reasonably concluded that there may be legal defenses available to it which are different from or additional to, or inconsistent with, those available to the Indemnifying Party, the Indemnified Party shall have the right to select and be represented by separate counsel, at the Indemnifying Party’s expense, unless a liability insurer is willing to pay such costs.
If the Indemnifying Party fails to assume the defense of a claim meriting indemnification, the Indemnified Party may at the expense of the Indemnifying Party contest, settle, or pay such claim, provided, settlement or full payment of any such claim may be made only following consent of the Indemnifying Party or, absent such consent, written opinion of the Indemnified Party’s counsel that such claim is meritorious or warrants settlement. Except as otherwise provided in this Article 261
69 17, in the event that a Party is obligated to indemnify and hold the other Party and its successors and assigns harmless under this Article 17, the amount owing to the Indemnified Party will be the amount of the Indemnified Party’s damages net of any insurance proceeds received by the Indemnified Party following a reasonable effort by the Indemnified Party to obtain such insurance proceeds.
ARTICLE 18
INSURANCE
18.1 Insurance.
(a) General. Seller shall comply at all times during the Contract Term with the requirements of Exhibit J.
(b) Subcontractor Insurance. Seller shall require all of its subcontractors to carry: (i) comprehensive general liability insurance in amounts equal to those set forth for Seller in Exhibit J; (ii) workers’ compensation insurance and employers’ liability coverage in accordance with applicable requirements of Law; and (iii) business auto insurance for bodily injury and property damage, in each case, in amounts equal to those set forth for Seller in Exhibit J. All subcontractors shall name Seller as an additional insured to insurance carried pursuant to clauses (b)(i) and (b)(iii). All subcontractors shall provide a primary endorsement and a waiver of subrogation to Seller for the required coverage pursuant to this Section 18.1(b). (c) Evidence of Insurance. Within ten (10) days after execution of the Agreement and upon annual renewal thereafter, Seller shall deliver to Buyer certificates of insurance evidencing such coverage. These certificates shall specify that Buyer shall be given at least thirty (30) days prior Notice by Seller in the event of any material modification, cancellation or termination of coverage. Such insurance shall be primary coverage without right of contribution from any insurance of Buyer. Any other insurance maintained by Seller is for the exclusive benefit of Seller and shall not in any manner inure to the benefit of Buyer. Seller shall also comply with all insurance requirements by any renewable energy or other incentive program administrator or any other applicable authority.
(d) Failure to Comply with Insurance Requirements. If Seller fails to comply with any of the provisions of this Article 18, Seller, among other things and without restricting Buyer’s remedies under the Law or otherwise, shall, at its own cost and expense, act as an insurer and provide insurance in accordance with the terms and conditions above. With respect to the required general liability, umbrella liability and commercial automobile liability insurance, Seller shall provide a current, full and complete defense to Buyer, its subsidiaries and Affiliates, and their respective officers, directors, shareholders, agents, employees, assigns, and successors in interest, in response to a third-party claim in the same manner that an insurer would have, had the insurance been maintained in accordance with the terms and conditions set forth above. In addition, alleged violations of the provisions of this Article 18 means that Seller has the initial burden of proof regarding any legal justification for refusing or withholding coverage and Seller shall face the same liability and damages as an insurer for wrongfully refusing or withholding coverage in accordance with the laws of California.
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70 ARTICLE 19
CONFIDENTIAL INFORMATION
19.1 Definition of Confidential Information. The following constitutes “Confidential Information,” whether oral or written, and whether delivered by Seller to Buyer or by Buyer to Seller: (a) proposals and negotiations of the Parties in the negotiation of this Agreement; (b) the terms and conditions of this Agreement; and (c) information that either Seller or Buyer stamps or otherwise identifies as “confidential” or “proprietary” or words of similar import before disclosing it to the other. Confidential Information does not include (i) information that was publicly available at the time of the disclosure, other than as a result of a disclosure in breach of this Agreement; (ii) information that becomes publicly available through no fault of the recipient; (iii) information that was rightfully in the possession of the recipient (without confidential or proprietary restriction) at the time of delivery or that becomes available to the recipient from a source not subject to any restriction against disclosing such information to the recipient; and (iv) information that the recipient independently developed without a violation of this Agreement.
19.2 Duty to Maintain Confidentiality. The Party receiving Confidential Information shall treat it as confidential, and shall adopt reasonable information security measures to maintain its confidentiality, employing the higher of (a) the standard of care that the receiving Party uses to preserve its own confidential information, or (b) a standard of care reasonably tailored to prevent unauthorized use or disclosure of such Confidential Information. Confidential Information may be disclosed by the recipient if and to the extent such disclosure is required (a) by Law, (b) pursuant to an order of a court or (c) in order to enforce this Agreement. The Party that originally discloses Confidential Information may use such information for its own purposes, and may publicly disclose such information at its own discretion. Notwithstanding the foregoing, Seller acknowledges that Buyer is required to make portions of this Agreement available to the public in connection with the process of seeking approval from its board of directors for execution of this Agreement. Buyer may, in its discretion, redact certain terms of this Agreement as part of any such public disclosure, and will use reasonable efforts to consult with Seller prior to any such public disclosure. Seller further acknowledges that Buyer is a public agency subject to the requirements of the California Public Records Act (Cal. Gov. Code section 6250 et seq.). Upon request or demand from any third person not a Party to this Agreement for production, inspection and/or copying of this Agreement or other Confidential Information provided by Seller to Buyer, Buyer shall, to the extent permissible, notify Seller in writing in advance of any disclosure that the request or demand has been made; provided, upon the advice of its counsel that disclosure is required, Buyer may disclose this Agreement or any other requested Confidential Information, whether or not advance written notice to Seller has been provided. Seller shall be solely responsible for taking whatever steps it deems necessary to protect Confidential Information that is the subject of any Public Records Act request submitted by a third person to Buyer.
19.3 Irreparable Injury; Remedies. Buyer and Seller each agree that disclosing Confidential Information of the other in violation of the terms of this Article 19 may cause irreparable harm, and that the harmed Party may seek any and all remedies available to it at Law or in equity, including injunctive relief and/or notwithstanding Section 12.2, consequential damages.
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71 19.4 Disclosure to Lender. Notwithstanding anything to the contrary in this Article 19, Confidential Information may be disclosed by Seller to any potential Lender or any of its agents, consultants or trustees so long as the Person to whom Confidential Information is disclosed agrees in writing to be bound by the confidentiality provisions of this Article 19 to the same extent as if it were a Party.
19.5 Disclosure to Credit Rating Agency. Notwithstanding anything to the contrary in this Article 19, Confidential Information may be disclosed by either Party to any nationally recognized credit rating agency (e.g., Moody’s Investors Service, Standard & Poor’s, or Fitch Ratings) in connection with the issuance of a credit rating for that Party or its Affiliates, provided, any such credit rating agency agrees in writing to maintain the confidentiality of such Confidential Information.
19.6 Public Statements. Neither Party shall issue (or cause its Affiliates to issue) a press release regarding the transactions contemplated by this Agreement unless both Parties have agreed upon the contents of any such press release.
ARTICLE 20
MISCELLANEOUS
20.1 Entire Agreement; Integration; Exhibits. This Agreement, together with the Cover Sheet and Exhibits attached hereto constitutes the entire agreement and understanding between Seller and Buyer with respect to the subject matter hereof and supersedes all prior agreements relating to the subject matter hereof, which are of no further force or effect. The Exhibits attached hereto are integral parts hereof and are made a part of this Agreement by reference. The headings used herein are for convenience and reference purposes only. In the event of a conflict between the provisions of this Agreement and those of the Cover Sheet or any Exhibit, the provisions of first the Cover Sheet, and then this Agreement shall prevail, and such Exhibit shall be corrected accordingly. This Agreement shall be considered for all purposes as prepared through the joint efforts of the Parties and shall not be construed against one Party or the other as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof.
20.2 Amendments. This Agreement may only be amended, modified or supplemented by an instrument in writing executed by duly authorized representatives of Seller and Buyer; provided, this Agreement may not be amended by electronic mail communications.
20.3 Time is of the Essence. The Parties agree that time is of the essence with respect each Party’s performance of its obligations under the Agreement.
20.4 No Waiver. Waiver by a Party of any default by the other Party shall not be construed as a waiver of any other default.
20.5 No Agency, Partnership, Joint Venture or Lease. Seller and the agents and employees of Seller shall, in the performance of this Agreement, act in an independent capacity and not as officers or employees or agents of Buyer. Under this Agreement, Seller and Buyer intend to act as energy seller and energy purchaser, respectively, and do not intend to be treated as, and shall not act as, partners in, co-venturers in or lessor/lessee with respect to the Facility or 264
72 any business related to the Facility. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement).
20.6 Severability. In the event that any provision of this Agreement is unenforceable or held to be unenforceable, the Parties agree that all other provisions of this Agreement have force and effect and shall not be affected thereby. The Parties shall, however, use their best endeavors to agree on the replacement of the void, illegal or unenforceable provision(s) with legally acceptable clauses which correspond as closely as possible to the sense and purpose of the affected provision and this Agreement as a whole.
20.7 Mobile-Sierra. Notwithstanding any other provision of this Agreement, neither Party shall seek, nor shall they support any third party seeking, to prospectively or retroactively revise the rates, terms or conditions of service of this Agreement through application or complaint to FERC pursuant to the provisions of Section 205, 206 or 306 of the Federal Power Act, or any other provisions of the Federal Power Act, absent prior written agreement of the Parties. Further, absent the prior written agreement in writing by both Parties, the standard of review for changes to the rates, terms or conditions of service of this Agreement proposed by a Party, a non-Party or the FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956).
20.8 Counterparts. This Agreement may be executed in one or more counterparts, all of which taken together shall constitute one and the same instrument and each of which shall be deemed an original.
20.9 Facsimile or Electronic Delivery. This Agreement may be duly executed and delivered by a Party by execution and facsimile or electronic format (including portable document format (.pdf)) delivery of the signature page of a counterpart to the other Party, and, if delivery is made by facsimile or other electronic format, the executing Party shall promptly deliver, via overnight delivery, a complete original counterpart that it has executed to the other Party, but this Agreement shall be binding on and enforceable against the executing Party whether or not it delivers such original counterpart.
20.10 Binding Effect. This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns.
20.11 No Recourse to Members of Buyer. Buyer is organized as a Joint Powers Authority in accordance with the Joint Exercise of Powers Act of the State of California (Government Code Section 6500, et seq.) pursuant to its Joint Powers Agreement and is a public entity separate from its constituent members. Buyer shall solely be responsible for all debts, obligations and liabilities accruing and arising out of this Agreement. Seller shall have no rights and shall not make any claims, take any actions or assert any remedies against any of Buyer’s constituent members, or the employees, directors, officers, consultants or advisors of Buyer or its constituent members, in connection with this Agreement.
20.12 Change in Electric Market Design. If a change in the CAISO Tariff renders this Agreement or any provisions hereof incapable of being performed or administered, then any Party 265
73 may request that Buyer and Seller enter into negotiations to make the minimum changes to this Agreement necessary to make this Agreement capable of being performed and administered, while attempting to preserve to the maximum extent possible the benefits, burdens, and obligations set forth in this Agreement as of the Effective Date. Notwithstanding the foregoing, (i) a change in cost shall not in and of itself be deemed to render this Agreement or any of the provisions hereof incapable of being performed or administered, or constitute, or form the basis of, a Force Majeure Event, and (ii) this Agreement shall remain in full force and effect, subject to any necessary changes, if any, agreed to by the Parties or determined through dispute resolution.
ARTICLE 21
CPUC MODIFIABLE STANDARD CONTRACT TERMS
21.1 STC 18: Application of Prevailing Wage.
To the extent applicable, Seller shall comply with the prevailing wage requirements of Public Utilities Code section 769.2(b)(1).
266
Exhibit A - 1
EXHIBIT A
DESCRIPTION OF THE FACILITY
Facility Name: King Kettle Clean Power I, Unit B
Site Name: King Kettle Clean Power I
Site Description: The Facility is located on an unincorporated portion of Kings County, California, approximately 0.5 miles northeast of the intersection of Interstate 5 and Highway 41, near Kettleman City, CA 93239.
Site Address: 0.5 mi NE of intersection of Interstate 5 and State Route 41, Kettleman City, CA 93239. The Site and various Shared Facilities are shared with another separately metered generating and storage project called “King Kettle Clean Power I, Unit A”.
GPS Coordinates: 35.965581, -119.957308
Site Map:
APNs:
267
2 County: Kings County
CEQA Lead Agency: Kings County Community Development Agency – Planning Division
Generation Technology: The Facility is a ground-mounted photovoltaic system consisting of Storage Technology: Lithium-ion (LFP) battery energy storage system; 2 MW AC / 8 MWh, minimum four (4) hours of continuous discharging at the maximum rate of discharge; DC-coupled with the Generating Facility via DC/DC converters P-node/Delivery Point:
Point of Interconnection:
Description of Interconnection Facilities and Metering:
CAISO Queue Number:
268
269
Exhibit B - 1
EXHIBIT B
FACILITY CONSTRUCTION AND COMMERCIAL OPERATION
1. Construction of the Facility.
a. Seller shall cause construction to begin on the Facility by December 31st, 2027, (as such date may be extended by the Development Cure Period, the “Guaranteed Construction Start Date”). Seller shall demonstrate the beginning of construction through execution of Seller’s engineering, procurement and construction contract, Seller’s issuance of a notice to proceed under such contract, mobilization to site by Seller and/or its designees, and includes the physical movement of soil at the Site (“Construction Start”). On the date of the beginning of construction (the “Construction Start Date”), Seller shall deliver to Buyer a certificate substantially in the form attached as Exhibit H hereto.
b. If Construction Start is not achieved by the Guaranteed Construction Start Date, Seller shall pay Daily Delay Damages to Buyer on account of such delay. Daily Delay Damages shall be payable for each day for which Construction Start has not begun by the Guaranteed Construction Start Date. Daily Delay Damages shall be payable to Buyer by Seller until the earlier of one hundred twenty (120) days after the Guaranteed Construction Start Date, or the date on which Seller reaches Construction Start of the Facility. On or before the tenth (10th) day of each month, Buyer shall invoice Seller for Daily Delay Damages, if any, accrued during the prior month and, within ten (10) Business Days following Seller’s receipt of such invoice, Seller shall pay Buyer the amount of the Daily Delay Damages set forth in such invoice. Daily Delay Damages shall be refundable to Seller pursuant to Section 3(b) of this Exhibit B. The Parties agree that Buyer’s receipt of Daily Delay Damages shall be Buyer’s sole and exclusive remedy for the first one hundred twenty (120) days of the delay in achieving the Construction Start Date on or before the Guaranteed Construction Start Date, but shall (x) not be construed as Buyer’s declaration that an Event of Default has occurred under any provision of Section 11.1 and (y) not limit Buyer’s right to declare an Event of Default pursuant to Section 11.1(b)(ii) and receive a Damage Payment upon exercise of Buyer’s rights pursuant to Section 11.2.
2. Commercial Operation of the Facility. “Commercial Operation” means the condition existing when (i) Seller has fulfilled all of the conditions precedent in Section 2.2 of the Agreement and (ii) Seller has provided Notice to Buyer that Commercial Operation has been achieved and specifying the “placed in service” date per Internal Revenue Service Requirements of the Facility.
The “Commercial Operation Date” shall be the later of (x) December 31st, 2028 or (y) the date on which Commercial Operation is achieved.
a. Seller shall cause Commercial Operation for the Facility to occur by December 31st, 2028 (as such date may be extended by the Development Cure Period (defined below), the “Guaranteed Commercial Operation Date”). Seller shall notify Buyer that it intends to achieve Commercial Operation at least sixty (60) days before the anticipated Commercial Operation Date. b. If Seller achieves Commercial Operation by the Guaranteed Commercial Operation Date, all Daily Delay Damages paid by Seller shall be refunded to Seller. Seller shall include the 270
Exhibit B - 2
request for refund of the Daily Delay Damages with the first invoice to Buyer after the Commercial Operation Date.
c. If Seller does not achieve Commercial Operation by the Guaranteed Commercial Operation Date, Buyer shall retain Daily Delay Damages, as applicable, and Seller shall pay Commercial Operation Delay Damages to Buyer for each day after the Guaranteed Commercial Operation Date until the Commercial Operation Date. Commercial Operation Delay Damages shall be payable to Buyer by Seller until the Commercial Operation Date. On or before the tenth (10th) day of each month, Buyer shall invoice Seller for Commercial Operation Delay Damages, if any, accrued during the prior month. The Parties agree that Buyer’s retention of Daily Delay Damages and receipt of Commercial Operation Delay Damages shall be Buyer’s sole and exclusive remedy for the first of delay in achieving the Commercial Operation Date on or before the Guaranteed Commercial Operation Date, but shall (x) not be construed as Buyer’s declaration that an Event of Default has occurred under any provision of Section 11.1 and (y) not limit Buyer’s right to declare an Event of Default under Section 11.1(b)(ii) and receive a Damage Payment upon exercise of Buyer’s default right pursuant to Section 11.2.
3. Termination for Failure to Timely Achieve Construction Start or Commercial Operation. If the Facility has not achieved Construction Start within one hundred twenty (120) days after the Guaranteed Construction Start Date, or Commercial Operation within after the Guaranteed Commercial Operation Date, Buyer may elect to terminate this Agreement pursuant to Sections 11.1(b)(ii) and 11.2(a), which termination shall become effective as provided in Section 11.2(a).
4. Extension of the Guaranteed Dates. The Guaranteed Construction Start Date and the Guaranteed Commercial Operation Date shall be extended on a day-for-day basis, as applicable, (the “Development Cure Period”) for the duration of each of the following delays:
a. a Force Majeure Event occurs; or
b. for the Guaranteed Commercial Operation Date only, Buyer has not made all necessary arrangements to receive the Energy at the Delivery Point by the Guaranteed Commercial Operation Date.
Notwithstanding anything in this Agreement to the contrary, the cumulative extensions granted under the Development Cure Period (other than the extensions granted pursuant to clause 4(b) above) shall not exceed one hundred eighty (180) days, for any reason, and, without limiting the provisions of Section 10.3, no extension shall be given to the extent that (i) the delay was the result of Seller’s failure to take all commercially reasonable actions to meet its requirements and deadlines; (ii) Seller failed to provide prompt written notice to Buyer of a delay due to a Force Majeure Event, but in no case more than thirty (30) days after Seller became aware of an actual delay (not including Seller’s receipt of generic notices of potential delays due to a Force Majeure Event) affecting the Facility, except that in the case of a delay occurring within sixty (60) days of the Guaranteed Commercial Operation Date, or after such date, Seller must provide written notice within seven (7) Business Days of Seller becoming aware of such delay; or (iii) Seller failed, upon written request from Buyer, to provide documentation demonstrating to Buyer’s reasonable 271
Exhibit B - 3
satisfaction that the delay was a result of a Force Majeure Event and did not result from Seller’s actions or failure to take commercially reasonable actions.
5. Failure to Reach Guaranteed PV Capacity or Guaranteed Storage Capacity. If, at Commercial Operation, the Installed PV Capacity is at least ninety-five percent (95%) of Guaranteed PV Capacity, but less than the Guaranteed PV Capacity, or the Installed Storage Capacity is at least ninety-five percent (95%) of the Guaranteed Storage Capacity but less than the Guaranteed Storage Capacity, Seller shall have ninety (90) days after the Commercial Operation Date to install additional generating and/or storage capacity such that the Installed PV Capacity and/or the Installed Storage Capacity, as applicable, is increased, but not to exceed the Guaranteed PV Capacity or Guaranteed Storage Capacity. If Seller installs additional storage or generating capacity pursuant to the immediately preceding sentence, Seller shall provide to Buyer a new certificate substantially in the form attached as Exhibit G-2 hereto specifying the new Installed PV Capacity and Installed Storage Capacity. In the event that the Installed PV Capacity is still less than the Guaranteed PV Capacity or the Installed Storage Capacity is still less than the Guaranteed Storage Capacity as of such date, Seller shall pay “Capacity Damages” to Buyer, in an amount equal to Three Hundred Fifty Thousand Dollars ($350,000) for each MW that the Guaranteed PV Capacity exceeds the Installed PV Capacity and Five Hundred Thousand Dollars ($500,000) for each MW that the Guaranteed Storage Capacity exceeds the Installed Storage Capacity, and the Guaranteed PV Capacity, Guaranteed Storage Capacity, and other applicable portions of the Agreement shall be reduced based on the ratio of the Installed PV Capacity as of such date to the original Guaranteed PV Capacity or the Installed Storage Capacity as of such date to the original Guaranteed Storage Capacity, as applicable.
6. Buyer’s Right to Draw on Development Security. If Seller fails to timely pay any Daily Delay Damages or Commercial Operation Delay Damages, Buyer may draw upon the Development Security to satisfy Seller’s payment obligation thereof, and Seller shall replenish the Development Security to its full amount within five (5) Business Days after such draw. 272
Exhibit C - 1
EXHIBIT C
[Intentionally Omitted]
273
Exhibit D - 1
EXHIBIT D
GUARANTEED ENERGY PRODUCTION DAMAGES CALCULATION
In accordance with Section 4.8, if Seller fails to achieve the Guaranteed Energy Production during any Performance Measurement Period, a liquidated damages payment shall be due from Seller to Buyer, calculated as follows:
[(A – B) * (C – D)]
where:
A = the Guaranteed Energy Production amount for the Performance Measurement Period, in MWh
B = the Adjusted Energy Production amount for the Performance Measurement Period, in MWh
C = Replacement price for the Performance Measurement Period, in $/MWh, which is calculated as (a) the simple average of the Integrated Forward Market hourly price for all the hours in the Performance Measurement Period, as published by the CAISO, for the Existing Zone Generation Trading Hub (as defined in the CAISO Tariff) for the Delivery Point, plus (ii) for any portion of the Production Shortfall for which Buyer purchased replacement RECs, the amount of Buyer’s cost of such replacement RECs, plus (iii) for any portion of the Production Shortfall for which Buyer did not purchase replacement RECs, the lesser of (A) the current prevailing market value of such PCC1 RECs, as reasonably determined by Buyer, or (B) $100/MWh, minus (c) the Renewable Rate
D = the average Renewable Rate for the Performance Measurement Period, in $/MWh
No payment shall be due if the calculation of (A - B) or (C - D) yields a negative number.
Within sixty (60) days after each Performance Measurement Period, Buyer will send Seller Notice of the amount of damages owing, if any, which shall be payable to Buyer before the later of (a) thirty (30) days of such Notice and (b) ninety (90) days after each Performance Measurement Period.
Additional Definitions:
“Adjusted Energy Production” means the sum of the following: PV Energy + Deemed Delivered Energy + Lost Output – Excess MWh.
“Lost Output” means the amount of Energy that qualifies as PCC1, expressed in MWh, that the Generating Facility would have generated and delivered, but did not, on account of Force Majeure Event, Buyer Default, or Curtailment Order, which amount shall be equal to (a) the VER 274
Exhibit D - 2
Forecast expressed in MWh, applicable to the Buyer Curtailment Period, or (b) if there is no VER Forecast available or Seller demonstrates to Buyer’s reasonable satisfaction that the VER Forecast does not represent an accurate forecast of generation from the Generating Facility, the amount determined by a third party reasonably acceptable to Buyer using an industry standard forecasting or back-casting methodology to determine the potential generation of the Generating Facility as a function of Available Generating Capacity, solar insolation and panel temperature, and using relevant Facility availability, weather, historical and other pertinent data for the period of time during the period in which the Force Majeure Event, Buyer Default, or Curtailment Order occurred.
“Production Shortfall” means the amount of Energy shortfall calculated as A – B in the formula above.
275
Exhibit E - 1
EXHIBIT E
PROGRESS REPORTING FORM
Within fifteen (15) days after the close of (i) each calendar quarter from the first calendar quarter following the Effective Date until the Construction Start Date, and (ii) each calendar month from the first calendar month following the Construction Start Date until the Commercial Operation Date, Seller shall provide to Buyer a written Progress Report in the form specified below.
Each Progress Report must include the following items:
1. Executive summary.
2. Facility description.
3. Site plan of the Facility.
4. Description of any planned changes to the Facility or the Site.
5. Gantt chart schedule showing progress on achieving each of the Milestones.
6. Summary of activities during the previous calendar quarter or month, as applicable, including any OSHA labor hour reports.
7. Forecast of activities scheduled for the current calendar quarter.
8. Written description about the progress relative to Seller’s Milestones, including whether Seller has met or is on target to meet the Milestones.
9. List of issues that could potentially affect Seller’s Milestones.
10. A status report of start-up activities including a forecast of activities ongoing and after start-up, a report on Facility performance including performance projections for the next twelve (12) months.
11. Progress and schedule of all agreements, contracts, permits, approvals, technical studies, financing agreements and major equipment purchase orders showing the start dates, completion dates, and completion percentages.
12. Pictures, in sufficient quantity and of appropriate detail, in order to document construction and startup progress of the Facility, the interconnection into the Transmission System and all other interconnection utility services.
13. Workforce Development or Supplier Diversity Reporting (if applicable). Format to be provided by Buyer.
14. Any other documentation reasonably requested by Buyer. 276
Exhibit F - 1
EXHIBIT F
BUYOUT OPTION
(1) Buyout Option. No later than ninety (90) days prior to the last day of each of (i) the tenth (10th) Contract Year of the Contract Term, (ii) the fifteenth (15th) Contract Year of the Contract Term and (iii) the twentieth (20th) Contract Year of the Contract Term, Buyer may deliver Notice to Seller indicating whether it elects to purchase the Facility. If Buyer elects to make a purchase, Buyer shall pay to Seller a “Buyout Payment” within thirty (30) days prior to the last day of such Contract Year equal to the Fair Market Value of the Facility as of such date, as determined pursuant to clause (2) below.
(2) Calculation of Fair Market Value. If Buyer provides Notice to Seller that it is contemplating exercising its rights under this Exhibit F, the Parties shall mutually agree upon an independent appraiser on or before the date that is sixty (60) days prior to the last day of (i) the tenth (10th) Contract Year of the Contract Term, (ii) the fifteenth (15th) Contract Year of the Contract Term, or (iii) the twentieth (20th) Contract Year of the Contract Term, if applicable. Such appraiser shall determine, at equally shared expense of Buyer and Seller, the fair market value of the Facility as of the date on which the Buyout Payment is to be paid, taking into account such items as deemed appropriate by the appraiser, which may include the resale value of the Facility, and the price of the Product (the “Fair Market Value”). In the event that Buyer and Seller cannot agree upon a single independent appraiser, each Party shall contract for an independent appraiser at its own expense, and the Fair Market Value shall be the simple average of the determinations of the two independent appraisers. On or prior to the date that is thirty (30) days prior to the last day of such Contract Year, the appraiser shall deliver its determination of Fair Market Value to each of Buyer and Seller. After the appraiser provides the Parties with its appraisal of Fair Market Value of the Facility, Buyer shall have thirty (30) days to decide whether to consummate its option to purchase the Facility. If Buyer does not provide Notice to Seller that Buyer intends to exercise its option to purchase the Facility within thirty (30) days of receipt of the Fair Market Value appraisal, Buyer shall be deemed to have not exercised its option to purchase the Facility. (3) Passage of Title. Upon receipt of the Buyout Payment, the Parties shall execute all documents necessary to cause title to the Facility to pass to Buyer on an as-is, where-is, with-all-faults basis; provided, Seller shall remove any encumbrances held by Seller with respect to the Facility.
277
Exhibit G1 - 1
EXHIBIT G-1
FORM OF COMMERCIAL OPERATION DATE CERTIFICATE
This certification (“Certification”) of Commercial Operation is delivered by _______[Licensed Professional Engineer] (“Engineer”) to WestLight Energy (“Buyer”) in accordance with the terms of that certain Power Purchase and Sale Agreement dated _______ (“Agreement”) by and between [Seller] and Buyer. All capitalized terms used in this Certification but not otherwise defined herein shall have the respective meanings assigned to such terms in the Agreement.
Engineer hereby certifies and represents to Buyer the following:
(1) Seller has installed generating equipment with a nameplate capacity of no less than ninety-five percent (95%) of the Guaranteed PV Capacity. (2) Seller has installed and commissioned storage equipment with a capacity of at least ninety-five percent (95%) of the Guaranteed Storage Capacity in accordance with Exhibit M of the Agreement.
(3) The Storage Facility is capable of receiving Charging Energy from and delivering Discharging Energy to the Delivery Point and commissioning of equipment at the Storage Facility has been completed in accordance with the manufacturer’s specifications. (4) The Generating Facility’s testing included a performance test demonstrating peak electrical output of no less than ninety-five percent (95%) of the Guaranteed PV Capacity at the Delivery Point.
(5) Authorization to parallel the Facility was obtained by the Participating Transmission Owner, [Name of Participating Transmission Owner as appropriate] on___[DATE]____ (6) The Participating Transmission Owner or Distribution Provider has provided documentation supporting full unrestricted release for Commercial Operation by [Name of Participating Transmission Owner as appropriate] on _______[DATE]_____. (7) The CAISO has provided notification supporting the Facility’s Commercial Operation, inclusion in the Full Network Model and authorization to provide Ancillary Services from the Storage Facility, all in accordance with the CAISO tariff on _______[DATE]_____. (8) Seller has segregated and separately metered Station Use in accordance with Prudent Operating Practice, and any such meter(s) have the same or greater level of accuracy as is required for CAISO certified meters used for settlement purposes. (9) The total rated power of the Storage Facility inverters associated with the Installed Storage Capacity as measured to the Delivery Point is at least [____] MW charging and [____] MW discharging at 45°C ambient air temperature.
278
Exhibit G1 - 2
29181659v1
EXECUTED by [licensed professional engineer]
this ________ day of _____________, 20__.
[LICENSED PROFESSIONAL
ENGINEER]
By:
Its:
Date:
279
Exhibit G1
-3
29181659v1
280
Exhibit G2 - 1
EXHIBIT G-2
FORM OF INSTALLED CAPACITY CERTIFICATE
This certification (“Certification”) of Installed Capacity is delivered by [Licensed Professional Engineer] (“Engineer”) to WESTLIGHT ENERGY (“Buyer”) in accordance with the terms of that certain Power Purchase and Sale Agreement dated __________ (“Agreement”) by and between [SELLER ENTITY] and Buyer. All capitalized terms used in this Certification but not otherwise defined herein shall have the respective meanings assigned to such terms in the Agreement.
The initial Generating Facility performance test under Seller’s engineering, procurement and construction contract or primary solar module supply agreement for the Generating Facility conducted on [Date] demonstrated peak Generating Facility electrical output of __MW AC at the Delivery Point, as adjusted for ambient conditions on the date of the performance test (“Installed PV Capacity”).
The Commercial Operation Storage Capacity Test conducted on [Date] demonstrated a maximum dependable operating capability to discharge electric energy of __ MW AC to the Delivery Point at four (4) hours of continuous discharge, in accordance with the testing procedures, requirements and protocols set forth in Section 4.13 and Exhibit N (“Installed Storage Capacity”).
EXECUTED by [LICENSED PROFESSIONAL ENGINEER]
this ________ day of _____________, 20__.
[LICENSED PROFESSIONAL
ENGINEER]
By:
Its:
Date:
281
Exhibit H - 1
EXHIBIT H
FORM OF CONSTRUCTION START DATE CERTIFICATE
This certification (“Certification”) of the Construction Start Date is delivered by [SELLER ENTITY] (“Seller”) to WESTLIGHT ENERGY (“Buyer”) in accordance with the terms of that certain Power Purchase and Sale Agreement dated __________ (“Agreement”) by and between Seller and Buyer. All capitalized terms used in this Certification but not otherwise defined herein shall have the respective meanings assigned to such terms in the Agreement.
Seller hereby certifies and represents to Buyer the following:
1. the engineering, procurement and construction contract related to the Facility was executed on __________;
2. the limited notice to proceed with the construction of the Facility was issued on ______________ (attached);
3. the Construction Start Date has occurred;
4. the precise Site on which the Facility is located is, which must be within the boundaries of the previously identified Site:
_____________________________________________________________________ (such description shall amend the description of the Site in Exhibit A).
IN WITNESS WHEREOF, the undersigned has executed this Certification on behalf of Seller as of the ___ day of ________.
[SELLER ENTITY]
By:
Its:
Date:
282
Exhibit I - 1
EXHIBIT I
FORM OF LETTER OF CREDIT
[Issuing Bank Letterhead and Address]
IRREVOCABLE STANDBY LETTER OF CREDIT NO. [XXXXXXX]
Date:
Bank Ref.:
Amount: US$[XXXXXXX]
Expiry Date:
Beneficiary:
WestLight Energy
[Address]
Ladies and Gentlemen:
On behalf of [XXXXXXX] (“Applicant”), we, [insert bank name and address] (“Issuer”) hereby issue our Irrevocable Standby Letter of Credit No. [XXXXXXX] (the “Letter of Credit”) in favor of WestLight Energy, Address__________, for an amount not to exceed the aggregate sum of U.S. $[XXXXXXX] (United States Dollars [XXXXXXX] and 00/100), pursuant to that certain [Agreement] dated as of ____________ (the “Agreement”) between Applicant and Beneficiary.
This Letter of Credit shall become effective immediately and shall have an initial expiry date of __________ __, 201_ subject to the automatic extension provisions herein.
Funds under this Letter of Credit are available to you against your draft(s) drawn on us at sight, mentioning thereon our Letter of Credit No. [XXXXXXX] accompanied by your dated statement purportedly signed by your duly authorized representative, in the form attached hereto as Exhibit A, containing one of the two alternative paragraphs set forth in paragraph 2 therein.
We hereby agree with the Beneficiary that all drafts drawn under and in compliance with the terms of this Letter of Credit will be duly honored upon presentation to the Issuer in person, by courier or by fax at [insert bank address]. Payment shall be made by Issuer in U.S. dollars with Issuer’s own immediately available funds.
The document(s) required may also be presented by fax at facsimile no. (xxx) xxx-xxx on or before the expiry date (as may be extended below) on this Letter of Credit in accordance with the terms and conditions of this Letter of Credit. No mail confirmation is necessary and the facsimile transmission will constitute the operative drawing documents without the need of originally signed documents.
Partial draws are permitted under this Letter of Credit. 283
Exhibit I - 2
It is a condition of this Letter of Credit that it shall be deemed automatically extended without an amendment for a one year period beginning on the present expiry date hereof and upon each anniversary for such date, unless at least ninety (90) days prior to any such expiry date we have sent to you written notice by overnight courier service that we elect not to permit this Letter of Credit to be so extended, in which case it will expire on its then current expiry date. No presentation made under this Letter of Credit after such expiry date will be honored.
Notwithstanding any reference in this Letter of Credit to any other documents, instruments or agreements, this Letter of Credit contains the entire agreement between Beneficiary and Issuer relating to the obligations of Issuer hereunder.
This Letter of Credit is subject to the Uniform Customs and Practice for Documentary Credits (2007 Revision) International Chamber of Commerce Publication No. 600 (the “UCP”), except to the extent that the terms hereof are inconsistent with the provisions of the UCP, including but not limited to 36 of the UCP, in which case the terms of this Letter of Credit shall govern. In the event of an act of God, riot, civil commotion, insurrection, war or any other cause beyond Issuer’s control (as defined in Article 36 of the UCP) that interrupts Issuer’s business and causes the place for presentation of the Letter of Credit to be closed for business on the last day for presentation, the expiry date of the Letter of Credit will be automatically extended without amendment to a date thirty (30) calendar days after the place for presentation reopens for business.
Please address all correspondence regarding this Letter of Credit to the attention of the Letter of Credit Department at [insert bank address information], referring specifically to Issuer’s Letter of Credit No. [XXXXXXX]. For telephone assistance, please contact Issuer’s Standby Letter of Credit Department at [XXX-XXX-XXXX] and have this Letter of Credit available. [Bank Name]
___________________________
[Insert officer name]
[Insert officer title]
284
Exhibit I - 3
(DRAW REQUEST SHOULD BE ON BENEFICIARY’S LETTERHEAD)
Drawing Certificate
[Insert Bank Name and Address]
Ladies and Gentlemen:
The undersigned, a duly authorized representative of WestLight Energy, Address___________ as beneficiary (the “Beneficiary”) of the Irrevocable Letter of Credit No. [XXXXXXX] (the “Letter of Credit”) issued by [insert bank name] (the “Bank”) by order of [XXXXXXX] (the “Applicant”), hereby certifies to the Bank as follows:
1. Applicant and Beneficiary are party to that certain Agreement dated as of [XXXXXXX] (the “Agreement”).
2. Beneficiary is making a drawing under this Letter of Credit in the amount of U.S. $___________.
or
3. Beneficiary is making a drawing under this Letter of Credit in the amount of U.S. $___________, which equals the full available amount under the Letter of Credit, because the Bank has provided notice of its intent to not extend the expiry date of the Letter of Credit and Applicant failed to provide acceptable replacement security to Beneficiary at least thirty (30) days prior to the expiry date of the Letter of Credit.
4. The undersigned is a duly authorized representative of WestLight Energy and is authorized to execute and deliver this Drawing Certificate on behalf of Beneficiary.
You are hereby directed to make payment of the requested amount to WestLight Energy by wire transfer in immediately available funds to the following account:
[Specify account information]
WestLight Energy_______________________________
Name and Title of Authorized Representative
Date___________________________
285
Exhibit J - 1
EXHIBIT J
INSURANCE
Liability Insurance
To the fullest extent allowable by law, Seller shall purchase and maintain such insurance as will protect it from the claims set forth below which may arise out of or result from Seller’s operations under this Agreement whether such operations be by itself or by anyone directly or indirectly employed by them, or by anyone for whose acts any of them may be liable. Limits shall be all the Insurance Coverage and/or limits carried by or available to the Seller, the minimum limits as required herein.
General Conditions
Seller shall maintain completed operations liability insurance for the entire Contract Term plus the period of time Seller may be held legally liable for.
Seller shall maintain policies of insurance in full force and effect, at all times during the performance of the Agreement, plus any statute of repose or statute of limitations applicable to the jurisdiction where any work is performed.
All insurance companies shall have a Best’s rating of A-VII or better.
In addition, Seller shall provide Buyer with 45 days’ notice in case of cancellation or non- renewal, except 10 days for non-payment of premium.
Certificates of Insurance Acord Form 25 and all required Endorsements shall be filed with Buyer within (5) working days of execution of the contract and/or prior to commencement of any work performed.
If requested by the Buyer, Seller shall provide a certified and true copy of any or all policies.
Acceptance of the certificates or endorsements by the Buyer shall not constitute a waiver of Seller’s obligations hereunder.
If Seller fails to secure and/or pay the premiums for any of the policies of insurance required herein, or fails to maintain such insurance, Buyer may, in addition to any other rights it may have under this Agreement or at law or in equity, terminate this Agreement or secure such policies or policies of insurance for the account of Seller and charge Seller for the premiums paid therefore, or withhold the amount thereof from sums otherwise due from Buyer to Seller. Neither the Buyer’s rights to secure such policy or policies nor the securing thereof by Buyer shall constitute an undertaking by Buyer on behalf of or for the benefit of Seller or others to determine or warrant that such policies are in effect.
Seller shall be fully and financially responsible for all deductibles or self-insured retentions. 286
Exhibit J
-2
287
Exhibit J - 3
Coverage Forms & Limits
Seller’s Commercial General Liability insurance shall be written on an industry standard Commercial General Liability Occurrence from (CG 00 01, 12/07) or its equivalent and shall include but not be limited to products/completed operations; premises and operations; blanket contractual; advertising/personal injury; independent Buyers.
Coverage shall be on an occurrence form with policy limits of not less than:
• $1,000,000 Each Occurrence Bodily Injury & Property Damage • $1,000,000 Personal & Advertising Injury
• $2,000,000 General Aggregate to apply on a Per Project basis • $2,000,000 Products/Completed Operations Aggregate
Business Auto Liability – Coverage shall be no less than that provided by Insurance Services Office, Inc. (ISO) form CA 00 01, written on an occurrence basis to apply to “any auto” or at a minimum “all owned, hired and non-owned autos”, with policy limits of not less than $1,000,000 per accident for bodily injury and property damage.
If applicable, Broadened Pollution for Covered Autos shall apply. This requirement may also be satisfied by providing proof of separate Pollution Liability that includes coverage for transportation exposures.
Workers’ Compensation and (b) employers’ liability – Sellers shall provide coverage for industrial injury to their employees (or leased employees as applicable) in strict accordance with the provisions of the State or States in which project work is performed or where jurisdiction is deemed to be applicable. Workers’ Compensation shall be provided in a statutory form on either a state or, where applicable, federal (U.S. Longshore & Harbor Workers Act, Maritime- Jones Act, etc.) basis as required in the applicable jurisdiction.
Such insurance shall be in an amount of not less than:
• Workers Compensation: Statutory
• Employers Liability
o $1,000,000 Bodily Injury by Accident – Each Accident
o $1,000,000 Bodily Injury by Disease – Total Limit
o $1,000,000 Bodily Injury by Disease – Each Employee
Commercial Umbrella or Excess Liability Insurance over Seller’s primary Commercial General Liability, Business Auto Liability and Employers Liability. All coverage terms required under the Commercial General Liability, Business Auto Liability and Employers Liability above must be included on the Umbrella or Excess Liability Insurance.
Coverage shall be written on an occurrence form with policy limits not less than:
• $5,000,000 Each Occurrence
• $5,000,000 Personal & Advertising Injury
• $5,000,000 Aggregate (where applicable, following the terms of the underlying) 288
Exhibit J - 4
Pollution liability – Seller shall provide evidence prior to the Construction Start Date of Pollution Liability; covering all operations necessary or incidental to the fulfillment of all contract obligations hereunder. Such insurance shall provide coverage for bodily injury, property damage (including loss of use of damaged property or of property that has not been physically injured), clean- up costs and remediation expenses (including costs for investigation, sampling, characterization, and monitoring), legal costs, defense costs, natural resource damage, transportation of pollutants on and off the project site, and non-owned disposal site liability if Seller’s scope of work (or Seller’s consultants) includes the responsibility of manifesting and disposing of contaminated material or waste from its activities. Coverage shall also extend to pollution conditions arising out of the Seller’s operations including coverage for sudden as well as gradual release arising from Seller’s operations including operations of any of its Seller’s or consultants. Such insurance shall provide coverage for wrongful acts, which may arise from all activities from the first point of Seller engagement and shall continue on a practice basis for not less than 36 months after completion, or the period of time Seller may be held legally liable for its work, whichever is longer. The retro date if any such coverage shall be prior to the commencement of Seller’s work.
Such insurance shall be in an amount of not less than $5,000,000 per claim or occurrence and $5,000,000 annual aggregate.
If Seller maintains Pollution Liability limits greater than what is required herein, such limits carried become what we require under this contract.
Professional Liability and/or Errors & Omissions – Seller shall provide evidence of Professional Liability insurance covering claims that arise from the actual or alleged errors, omissions or acts of the Seller or any entity for which the Seller is legally responsible, for the provision of all professional services necessary or incidental to the fulfillment of all contract obligations hereunder.
Such insurance shall be in an amount of not less than $2,000,000 each claim / $4,000,000 aggregate.
If Seller maintains Professional Liability limits greater than what is required herein, such limits carried become what we require under this Agreement.
The policy shall be effective from the date of commencement of all professional services in connection with the fulfillment of all contract obligations hereunder. The retroactive date in the current and future policies shall be prior to the commencement of all professional services.
Coverage shall be maintained for a period not less than 36 months or the period of time Seller may be held legally liable for its work, (whichever is longer) following the completion of the work; or an extended reporting period of 36 months following completion of the work shall be purchased.
Coverages shall not include any exclusion or other limitations related to scopes of services or project type or construction type, or delays in project completion and cost overruns.
Additional Insured / Primary-Noncontributory / Waiver of Subrogation Requirements To the fullest extent of coverage allowed under applicable law, Buyer shall be named as additional insured on a primary and non-contributory basis for all required lines of coverage except Statutory 289
Exhibit J - 5
Workers Compensation and Professional Liability, arising out of all operations performed by or for the Seller under this Agreement. Buyer shall accept General Liability Additional Insured forms CG 20 10 11/85, CG 20 10 10/01 & CG 20 37 10/01 or their equivalent.
Additional Insured status shall be for all limits carried, not limited to the minimum acceptable as required herein. Seller’s insurance shall be Primary as respects to Buyer and Owner, and any other insurance maintained by Buyer and Owner shall be excess and not contributing insurance with Seller’s insurance until such time as all limits available under the Seller’s insurance policies have been exhausted.
Additional Insured endorsements that contain comparative fault, vicarious liability or sole negligence limitations of the Buyer / Owner or any other party required by the contract, will not be accepted.
In the event that any policy provided in compliance with this Agreement states that the coverage provided to an additional insured shall be no broader than that required by contract, or words of similar meaning, the Parties agree that nothing in this Agreement is intended to restrict or limit the breadth of coverage or limits available.
The additional insured status shall remain in full force and effect for the Contract Term plus the applicable statute of repose, or the amount of time you are legally liable, whichever is longer.
It is further agreed that the additional insured coverage required under this Agreement shall not be subject to any Defense Costs Endorsements such as Form IL 01 23 11 13, allowing for the recovery of defense costs by the insurer if the insurer initially pays defense costs but later determines the claims are not covered.
Buyer reserves the right, in its sole and subjective discretion, to reject any Additional Insured forms that are deemed not equivalent to what is required herein.
Waiver of Subrogation – Seller shall provide a Waiver of Subrogation Endorsement naming Buyer for all lines of coverage.
Additional Requirements
Property Insurance
Seller shall procure and maintain, at the Seller’s own expense, Builder’s Risk, property and equipment insurance, including for any property stored off the Site, in transit or any of the Buyer’s property in the care, custody or control of Seller. Seller and Seller’s insurance carrier(s) hereby waive all rights of subrogation against Buyer for damage including loss of use.
Buyer neither represents nor assumes responsibility for the adequacy of the Builders Risk Insurance to protect the interests of the Seller. It shall be the obligation of the Seller to purchase and maintain any supplementary property insurance that it deems necessary to protect its interest in the Work, including without limitation off site stored materials and materials in transit.
Seller is solely responsible for loss or damage to its personal property. 290
Exhibit K - 1
EXHIBIT K
[INTENTIONALLY OMITTED]
291
Exhibit L1 - 1
EXHIBIT L-1
Annual Energy Forecast
The following table is provided for informational purposes only.
Please provide the expected PV Energy in Pacific Prevailing Time. For the Daylight Savings Day in March, the HE3 volume should be 0 MWh. For the Daylight Savings Day in November, the HE2 volume should represent two hours of generation.
Date Datetime (Hour
Beginning)
Hour Ending MWh
1/1/2022 1/1/2022 0:00 1
1/1/2022 1/1/2022 1:00 2
1/1/2022 1/1/2022 2:00 3
1/1/2022 1/1/2022 3:00 4
1/1/2022 1/1/2022 4:00 5
1/1/2022 1/1/2022 5:00 6
[insert additional rows] … …
12/31/2022 12/31/2022 18:00 19
12/31/2022 12/31/2022 19:00 20
12/31/2022 12/31/2022 20:00 21
12/31/2022 12/31/2022 21:00 22
12/31/2022 12/31/2022 22:00 23
12/31/2022 12/31/2022 23:00 24
292
Exhibit L2 - 1
EXHIBIT L-2
Monthly Expected Available Generating Capacity
The following table is provided for informational purposes only.
Please adjust the table for the appropriate number of days in the month for each month of the year.
Monthly Forecast of Available Generating Capacity (MW)
c 1:00* 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 24:00 Day 1
Day 2
Day 3
Day 4
Day 5
[insert additional rows for each day of the month]
Day
26 Day
27 Day
28 Day
29**
Day
30**
Day
31**
293
Exhibit L2 - 2
*All times are designated as “Hour-Ending [__]”.
**Include these rows if needed for each month.
294
Exhibit L3 - 1
EXHIBIT L-3
Monthly Expected Available Storage Capacity
The following table is provided for informational purposes only.
Please adjust the table for the appropriate number of days in the month for each month of the year.
Monthly Expected Available Storage Capacity (MW) per hour – [Insert Month] 1:00* 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 24:00 Day 1
Day 2
Day 3
Day 4
Day 5
[insert additional rows for each day of the month]
Day 26
Day 27
Day 28
Day
29**
Day
30**
Day
31**
*All times are designated as “Hour-Ending [__]”.
295
Exhibit L3 - 1
**Include these rows if needed for each month.
296
Exhibit L3 - 1
EXHIBIT L-4
Monthly Expected PV Energy
The following table is provided for informational purposes only.
Please adjust the table for the appropriate number of days in the month for each month of the year.
Monthly Expected PV Energy (MWh)
1:00* 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 24:00 Day 1
Day 2
Day 3
Day 4
Day 5
[insert additional rows for each day of the month]
Day 26
Day 27
Day 28
Day
29**
Day
30**
Day
31**
297
Exhibit L3 - 1
*All times are designated as “Hour-Ending [__]”.
**Include these rows if needed for each month.
298
299
Exhibit M - 2
“AVAILABLE STORAGE CAPABILITY” = the sum of the following (taking into account the SOC at the time of calculation):
i. The battery capability (in MWh) available to receive Charging Energy from the Delivery Point in the applicable Calculation Interval ii. The battery capability (in MWh) available to deliver Discharging Energy to the Delivery Point in the applicable Calculation Interval “TOTAL CALCULATION INTERVALS” = the total number of Calculation Intervals in the applicable month.
(b) If the total rated power of the Storage Facility inverters as measured to the Delivery Point at forty-five degrees (45°) C ambient air temperature is less than the Installed Storage Capacity, then Buyer shall have the right, in its reasonable discretion, to reduce the Available Storage Capacity by applying an ambient temperature derate to the applicable Calculation Interval.
2. Storage Availability Adjustment. The “Storage Availability Adjustment” shall be calculated as follows and applied to the Storage Capacity Payment due for the next month after the end of the monthly period for which the Monthly Storage Availability is calculated. (a) If the Monthly Storage Availability is greater than or equal to the Guaranteed Storage Availability, then:
Storage Availability Adjustment = 100% (expressed as a decimal) 300
Exhibit M - 3
(b) If the Monthly Storage Availability is less than the Guaranteed Storage Availability but greater than or equal to seventy percent (70%), then:
where:
Secondary Unavailability = the sum of all Unavailable Calculation Intervals in the applicable month that resulted from either (i) a Force Majeure Event for which Seller is the claiming party, or (ii) a Curtailment Order, divided by the Total Calculation Intervals for the month
(c) If (i) the Monthly Storage Availability is less than seventy percent (70%), then:
Storage Availability Adjustment = 0
301
Exhibit N - 1
EXHIBIT N
STORAGE CAPACITY TESTS
Storage Capacity Test Notice and Frequency
A. Commercial Operation Storage Capacity Test(s). Upon no less than ten (10) Business Days’ prior Notice to Buyer, Seller shall schedule and complete a Commercial Operation Storage Capacity Test prior to the Commercial Operation Date. Such initial Commercial Operation Storage Capacity Test (and any subsequent Commercial Operation Storage Capacity Test permitted in accordance with Exhibit B) shall be performed in accordance with this Exhibit N and shall establish the Installed Storage Capacity hereunder based on the actual capacity and capabilities of the Storage Facility determined by such Storage Capacity Test(s).
B. Subsequent Storage Capacity Tests. Following the Commercial Operation Storage Capacity Test(s), at least fifteen (15) days in advance of the start of each Contract Year, upon no less than ten (10) Business Days’ prior Notice to Buyer, Seller shall schedule and complete a Storage Capacity Test. In addition, Buyer shall have the right to require a retest of the Storage Capacity Test at any time upon no less than five (5) Business Days prior Notice to Seller. Seller shall have the right to run a retest of any Storage Capacity Test at any time upon five (5) Business Days’ prior Notice to Buyer (or any shorter period reasonably acceptable to Buyer consistent with Prudent Operating Practice).
C. Test Results and Re-Setting of Storage Capacity. No later than five (5) days following any Capacity Test, Seller shall submit a testing report detailing results and findings of the test. The report shall include Storage Facility Meter readings and plant log sheets verifying the operating conditions and output of the Storage Facility. In accordance with Section 4.13(c) of the Agreement and Part II.I. below, after the Commercial Operation Storage Capacity Test(s), the Storage Capacity (up to, but not in excess of, the Installed Storage Capacity) determined pursuant to such Storage Capacity Test shall become the new Storage Capacity at the beginning of the first day of the month following the completion of the test for calculating the Storage Capacity Payment and all other purposes under this Agreement.
Capacity Test Procedures
PART I. GENERAL.
(1) Each Capacity Test shall be conducted in accordance with Prudent Operating Practices, the Operating Restrictions and the provisions of this Exhibit N. For ease of reference, a Capacity Test is sometimes referred to in this Exhibit N as a “CT”.
Buyer or its representative may be present for the CT and may, for informational purposes only, use its own metering equipment (at Buyer’s sole cost). (2) Conditions Prior to Testing.
(1) EMS Functionality. The EMS shall be successfully configured to receive data from the Battery Management System (BMS), exchange Distributed Network Protocol 3 data with the Buyer 302
Exhibit N - 2
SCADA device, and transfer data to the database server for the calculation, recording and archiving of data points.
(2) Communications. The Remote Terminal Unit (RTU) testing should be successfully completed prior to any testing. The interface between Buyer’s RTU and the Facility SCADA system should be fully tested and functional prior to starting any testing, including verification of the data transmission pathway between Buyer’s RTU and Seller’s EMS interface and the ability to record SCADA system data.
(3) Commissioning Checklist. Commissioning shall be successfully completed per manufacturer guidance on all applicable installed Facility equipment, including verification that all controls, set points, and instruments of the EMS are configured.
PART II. REQUIREMENTS APPLICABLE TO ALL CAPACITY TESTS.
A. Test Elements. Each CT shall include the following individual test elements. The Parties acknowledge and agree that should Seller fall short of demonstrating one or more of the Test Elements as specified below, the CT will still be deemed “complete,” and any adjustments necessary to the Storage Capacity resulting from such CT, if applicable, will be made in accordance with this Exhibit N.
(1) Electrical output at the lesser of the maximum discharging level (MW) and Guaranteed Storage Capacity for four (4) continuous hours; and (2) Electrical input at maximum charging level at the Storage Facility Meter (MW), as sustained until the SOC reaches at least 90%, continued by the electrical input at a rate up to the maximum charging level at the Storage Facility Meter (MW), as sustained until the SOC reaches 100%, not to exceed five (5) hours of total charging time.
(3) The dispatch of the Storage Facility during the CT shall only be done through the ADS signal from the CAISO to the Storage Facility. Seller shall not interfere with or alter the Storage Facility’s response to the ADS signal during the CT or manually alter any EMS or SCADA data recorded by the Storage Facility.
B. Parameters. During each CT, the following parameters shall be measured and recorded simultaneously for the Storage Facility, at two (2) second intervals:
(1) Time;
(2) The amount of Charging Energy;
(3) The amount of Discharging Energy;
(4) SOC; and
303
Exhibit N - 3
(5) Station Use.
C. Site Conditions. During each CT, the following conditions at the Site shall be measured and recorded simultaneously at thirty (30) minute intervals:
(1) Relative humidity (%);
(2) Barometric pressure (inches Hg) near the horizontal centerline of the Storage Facility; and
(3) Ambient air temperature (°F).
D. Test Showing. Each CT shall record and report the following datapoints:
(1) That the CT successfully started;
(2) The maximum sustained discharging level for four (4) consecutive hours pursuant to A(1) above; (3) The maximum sustained charging level for four (4) consecutive hours pursuant to A(2) above; (4) Amount of time between the Storage Facility’s electrical output going from 0 to the maximum sustained discharging level registered during the CT (for purposes of calculating the ramp rate); (5) Amount of time between the Storage Facility’s electrical input going from 0 to the maximum sustained charging level registered during the CT (for purposes of calculating the ramp rate); (6) Amount of Charging Energy to go from 0% SOC to 100% SOC; and (7) Amount of Discharging Energy to go from 100% SOC to 0% SOC.
E. Test Conditions.
(1) General. At all times during a CT, the Storage Facility shall be operated in compliance with Prudent Operating Practices, the Operating Restrictions, and all operating protocols recommended, required or established by the manufacturer for the Storage Facility. (2) Abnormal Conditions. If abnormal operating conditions that prevent the testing or recordation of any required parameter occur during a CT, Seller may postpone or reschedule all or part of such CT in accordance with Part II.F below.
(3) Instrumentation and Metering. Seller shall provide all instrumentation, metering and data collection equipment required to perform the CT. The instrumentation, metering and data collection equipment electrical meters shall be calibrated in accordance with Prudent Operating Practice and, as applicable, the CAISO Tariff. At Buyer’s request, Seller shall provide documentation of all equipment calibration and certification. (4) Ambient Temperature. For tests requested by Buyer (and not for any CAISO-initiated test, which shall occur when directed by CAISO), the average ambient temperature, based on an aggregate of 304
Exhibit N - 4
1-minute resolution data collected throughout the SCT, must be within the range of 8 – 33 degrees Celsius.
F. Incomplete Test. If any CT is not completed in accordance herewith, Buyer may in its sole discretion: (i) accept the results up to the time the CT stopped without any modification to the Storage Capacity pursuant to Section I below; (ii) require that the portion of the CT not completed, be completed within a reasonable specified time period; or (iii) require that the CT be entirely repeated within a reasonable specified time period. Notwithstanding the above, if Seller is unable to complete a CT due to a Force Majeure Event or the actions or inactions of Buyer or the CAISO or the Transmission Provider, Seller shall be permitted to reconduct such CT on dates and at times reasonably acceptable to the Parties.
G. Test Report. Within five (5) Business Days after the completion of any CT, Seller shall prepare and submit to Buyer the completed Installed Capacity Certificate together with a written report of the results of the CT, which report shall include:
(1) A record of the personnel present during the CT that served in an operating, testing, monitoring or other such participatory role;
(2) The measured and calculated data for each parameter set forth in Part II.A through D and Part III below, including copies of the raw data taken during the test; and
(3) Seller’s statement of either Seller’s acceptance of the CT or Seller’s rejection of the CT results and reason(s) therefor.
Seller’s CT report and any submitted capacity certificate shall be deemed invalid if not delivered to Buyer within five (5) Business Days after the completion of any CT. Within five (5) Business Days after receipt of such report, Buyer shall notify Seller in writing of either Buyer’s acceptance of the CT results or Buyer’s rejection of the CT and reason(s) therefor.
If either Party rejects the results of any CT, such CT shall be repeated in accordance with Part II.F.
H. Supplementary Capacity Test Protocol. No later than sixty (60) days prior to any CT, Buyer may deliver to Seller for its review and approval (such approval not to be unreasonably delayed or withheld) a supplement to this Exhibit N with additional and supplementary details, procedures and requirements applicable to Capacity Tests based on the then-current design of the Storage Facility (“Supplementary Capacity Test Protocol”). Any additional Supplementary Capacity Test Protocol (and each update thereto), once approved by Seller, shall be deemed an amendment to this Exhibit N.
I. Adjustment to Storage Capacity. The Storage Capacity shall equal the quotient of (a) the total amount of Discharging Energy delivered to the Delivery Point (expressed in MWh AC) during the first four (4) hours of discharge (up to, but not 305
Exhibit N - 5
in excess of, the product of (i) (A) the Guaranteed Storage Capacity (in the case of a Commercial Operation Storage Capacity Test, including under Section 5 of Exhibit B) or (B) the Installed Storage Capacity (in the case of any other Storage Capacity Test), multiplied by (ii) four (4) hours) divided by (b) four (4) hours, expressed in MW AC.
PART III –CAPACITY TEST PROTOCOL.
A. Storage Capacity
• Procedure:
(1) System Starting State: The Storage Facility will be in the on-line state at 0% SOC. (2) Record the initial value of the Storage Facility SOC. (3) Command via ADS signal a real power charge that results in an AC power of Storage Facility’s maximum charging level, and continue charging until the earlier of (a) the Storage Facility has reached 100% SOC or (b) five (5) hours have elapsed since the Storage Facility commenced charging.
(4) Record and store the Storage Facility SOC after the earlier of (a) the Storage Facility has reached 100% SOC or (b) five (5) hours of continuous charging. Such data point shall be used for purposes of calculation of the Battery Charging Factor.
(5) Record and store the Charging Energy.
(6) Following an agreed-upon rest period, command via ADS signal a real power discharge that results in an AC power output of the lesser of (i) the Storage Facility’s maximum discharging level and (ii) the Guaranteed Storage Capacity, and maintain the discharging state until the earlier of (a) the Facility has discharged at the maximum discharging level for four (4) consecutive hours, (b) the Storage Facility has reached 0% SOC, or (c) the sustained discharging level is at least 2% less than the lesser of (i) the maximum discharging level and (ii) the Guaranteed Storage Capacity. (7) Record and store the Storage Facility SOC after four (4) hours of continuous discharging. (8) Record and store the Discharging Energy as measured at the Storage Facility Meter. Such data point shall be used for purposes of calculation the Effective Storage Capacity. (9) If the Storage Facility has not reached 0% SOC pursuant to Section III.A.6, continue discharging the Storage Facility until it reaches a 0% SOC. Record and store the additional Discharging Energy, if applicable.
• Test Results
(1) The resulting Effective Storage Capacity measurement is the quotient of (a) the total Discharging Energy at the Storage Facility Meter pursuant to Part III Section A(8) above, divided by (b) four (4) hours.
306
Exhibit N
-6
307
Exhibit O - 1
EXHIBIT O
OPERATING RESTRICTIONS
Maximum Cycle Limits: Number of times Buyer may fully charge and discharge the Storage Facility. A full charge will be deemed to have occurred when the cumulative amount of energy added to the Storage Facility over the course of a calendar year equals the Maximum Stored Energy Level (as defined in this Exhibit O). This could occur in one continuous charge or over multiple charges, even if some energy is discharged in between. The inverse is true for a full discharge.
Annual: 365 cycles
Ramp Rates: Dmin to Dmax: up to 100%/s
Cmin to Cmax: up to 100%/s
Dmax to Dmin: up to 100%/s
Cmax to Cmin: up to 100%/s
Frequency ramp rate: 100% MW/Hz
System Response Time: Idle to Dmax: <1s
Idle to Cmax: <1s
Dmax to Cmax: <1s
Cmax to Dmax: <1s
Dmin to Cmin: <1s
Cmin to Dmin: <1s
308
Exhibit O - 2
Maximum Stored Energy Level:
Minimum Stored Energy Level:
Maximum Charging Capacity:
Minimum Charging Capacity:
Maximum Discharging Capacity:
Minimum Discharging Capacity:
Maximum State of Charge (SOC)
during Charging:
Minimum State of Charge (SOC)
during Discharging:
Ramp Rate:
309
310
Exhibit Q - 1
EXHIBIT Q
RTE SHORTFALL PAYMENTS
In the event that the RTEM is less than the GRTE, the monthly Storage Capacity Payment under Section 3.3(e) shall be reduced by the “RTE Shortfall Payment”, calculated as follows:
(GRTE – RTEM) x Average Monthly T4B5 Price x RTEFM x TCEM where:
GRTE = the Guaranteed Round-Trip Efficiency
RTEM = the “Round-Trip Efficiency”, as calculated by dividing (a) the total Discharging Energy for the applicable month by (b) the difference of (i) the total Charging Energy for the applicable month, minus (ii) Reimbursable Station Use for the applicable month The “Average Monthly T4B5 Price” means the average of the four (4) highest hourly average Day-Ahead Market LMPs and the five (5) lowest hourly average Day-Ahead Market LMPs, in each case in the applicable month.
The “Round-Trip Efficiency Factor” or “RTEFM” for each month is determined as follows:
If RTEM > GRTE, then RTEFM = 0
If RTEM < GRTE and RTEM > 70%, then RTEFM = 1.2
If RTEM < 70%, then RTEFM = 1.5
TCEM = the total Charging Energy charged to the Storage Facility in the applicable month. 311
Exhibit R - 1
EXHIBIT R
NOTICES
King Kettle Clean Power I LLC
(“Seller”)
WESTLIGHT ENERGY, a California joint
powers authority (“Buyer”)
All Notices:
Street: 2075 Woodside Road
City: Redwood City, CA 94061
Attn: Director of Power Resources
Phone:
Email: [email protected]
Emergency Contact:
Attn: Director of Power Resources
Phone:
E-mail: [email protected]
Reference Numbers:
Duns:
Federal Tax ID Number:
Invoices:
Attn: Settlements
Phone:
E-mail: [email protected]
Scheduling:
Attn: Market Operations
Phone:
Email: [email protected]
Confirmations:
Attn: Director of Power Resources
Phone:
Email: [email protected]
Payments:
Attn: Settlements
Phone:
E-mail: [email protected]
Wire Transfer:
BNK:
ABA:
ACCT:
312
EXHIBIT S
SUPPLY CHAIN CODE OF CONDUCT
Buyer is committed to ensuring that the fundamental human rights of workers are protected, including addressing the potential risks of forced labor, child labor, servitude, human trafficking and slavery across our portfolio.
Our requirements and expectations for Seller’s supply chain are detailed below in our Supply Chain Code of Conduct (“Supply Chain Code”). Seller must comply with all applicable Laws and this Supply Chain Code, even when this Supply Chain Code exceeds the requirements of applicable Law.
These standards are derived from the United Nations Guiding Principles on Business and Human Rights, the Core Conventions of the International Labour Organization (“ILO”), including the ILO Declaration on Fundamental Principles and Rights at Work, the Solar Energy Industries Association Solar Industry Commitment to Environmental & Social Responsibility, and the Responsible Business Alliance Code of Conduct.
1. Freely Chosen Employment
Forced, bonded (including debt bondage) or indentured labor, involuntary or exploitative prison labor, slavery or trafficking of persons is not permitted. This includes transporting, harboring, recruiting, transferring, or receiving persons by means of threat, force, coercion, abduction or fraud for labor or services. There shall be no unreasonable restrictions on workers’ freedom of movement in the facility in addition to unreasonable restrictions on entering or exiting company provided facilities including, if applicable, workers’ dormitories or living quarters. All work must be voluntary, and workers shall be free to leave work at any time or terminate their employment without penalty if reasonable notice is given as per worker’s contract. Employers, agents, and sub-agents’ may not hold or otherwise destroy, conceal, or confiscate identity or immigration documents, such as government-issued identification, passports, or work permits. Employers can only hold documentation ifsuch holdings are required by law.In this case, at no time should workers be denied access to their documents. Workers shall not be required to pay employers’ agents or sub-agents’ recruitment fees or other related fees for their employment. If any such fees are found to have been paid by workers, such fees shall be repaid to the worker.
2. Young Workers
Child labor is not to be used in any stage of manufacturing. The term “child” refers to any person under the age of 15, or under the age for completing compulsory education, or under the minimum age for employment in the country, whichever is greatest. Suppliers shall implement an appropriate mechanism to verify the age of workers. The use of legitimate workplace learning programs, which comply with all laws and regulations, is supported. Workers under the age of 18 shall not perform work that islikely to jeopardize their health or safety, including night shifts and overtime. Suppliers shall ensure proper management of student workers through proper maintenance of student records, rigorous due diligence of educational partners, and protection of students’ rights in 313
accordance with applicable laws and regulations. Suppliers shall provide appropriate support and training to all student workers. In the absence of local law, the wage rate for student workers, interns, and apprentices shall be at least the same wage rate as other entry-level workers performing equal or similar tasks. If child labor is identified, assistance/remediation is provided.
3. Working Hours
Studies of business practices clearly link worker strain to reduced productivity, increased turnover, and increased injury and illness. Working hours are not to exceed the maximum set by local law.
Further, a workweek should not be more than 60 hours per week, including overtime, except in emergency or unusual situations. All overtime must be voluntary. Workers shall be allowed at least one day off every seven days.
4. Wages and Benefits
Compensation paid to workers shall comply with all applicable wage laws, including those relating to minimum wages, overtime hours and legally mandated benefits. In compliance with local laws, workersshall be compensated for overtime at pay rates greaterthan regular hourly rates. Deductions from wages as a disciplinary measure shall not be permitted. For each pay period, workers shall be provided with a timely and understandable wage statement that includes sufficient information to verify accurate compensation for work performed. All use of temporary, dispatch and outsourced labor will be within the limits of the local law.
5. Humane Treatment
There is to be no harsh or inhumane treatment including violence, gender-based violence, sexual harassment, sexual abuse, corporal punishment, mental or physical coercion, bullying, public shaming, or verbal abuse of workers; nor is there to be the threat of any such treatment.
Disciplinary policies and procedures in support of these requirements shall be clearly defined and communicated to workers.
6. Non-Discrimination/Non-Harassment
Suppliers should be committed to a workplace free of harassment and unlawful discrimination.
Companies shall not engage in discrimination or harassment based on race, color, age, gender, sexual orientation, gender identityand expression, ethnicity or national origin, disability, pregnancy, religion, political affiliation, union membership, covered veteran status, protected genetic information or marital status in hiring and employment practices such as wages, promotions, rewards, and access to training. Workers shall be provided with reasonable accommodation for religious practices. In addition, workers or potential workers should not be subjected to medical tests that could be used in a discriminatory way or otherwise in violation of applicable law. This was drafted in consideration of ILO Discrimination (Employment and Occupation) Convention (No.111).
7. Freedom of Association
In conformance with local law, Suppliers shall respect the right of all workers to form and join trade unions of their own choosing, to bargain collectively, and to engage in peaceful assembly as 314
well as respect the right of workers to refrain from such activities. Workers and/or their representatives shall be able to openly communicate and share ideas and concerns with management regarding working conditions and management practices without fear of discrimination, reprisal, intimidation, or harassment.
8. Restricted Jurisdictions
Supplier shall not manufacture or produce products in the Xinjiang Uyghur Autonomous Region of China, or knowingly procure goods and services mined, produced or manufactured in the same. 315
EXHIBIT T
FORM OF CONSENT TO COLLATERAL ASSIGNMENT
This Consent to Collateral Assignment (this “Consent”) is entered into among (i) WestLight Energy, a California joint powersauthority (“WESTLIGHT”), (ii) [Name of Seller], a [Legal Status of Seller] (the “Project Company”), and (iii) [Name of Collateral Agent], a [Legal Status of Collateral Agent], as Collateral Agent for the secured parties under the Financing Documents referred to below (such secured parties together with their successors permitted under this Consent in such capacity, the “Secured Parties”, and, such agent, together with its successors in such capacity, the “Collateral Agent”). WESTLIGHT, Project Company and Collateral Agent are hereinafter sometimes referred to individually as a “Party” and jointly as the “Parties”.
Capitalized terms used but not otherwise defined in this Consent shall have the meanings ascribed to them in the ESA (as defined below).
RECITALS
The Parties enter into this Consent with reference to the following facts:
A. Project Company and WESTLIGHT have entered into that certain Energy Storage Agreement, dated as of [Date] [List all amendments as contemplated by Section 3.4] (“ESA”), pursuant to which Project Company will develop, construct, commission, test and operate the Facility and sell the Product to WESTLIGHT, and WESTLIGHT will purchase the Product from Project Company;
B. As collateral for Project Company’s obligations under the ESA, Project Company has agreed to provide to WESTLIGHT certain collateral, which may include Performance Security and Development Security and other collateral described in the ESA (collectively, the “ESA Collateral”);
C. Project Company has entered into that certain [Insert description of financing arrangements with Lender], dated as of [Date], among Project Company, the Lenders party thereto and the Collateral Agent (the “Financing Agreement”), pursuant to which, among otherthings, the Lenders have extended commitments to make loans to Project Company; D. As collateral security for Project Company’s obligations under the Financing Agreement and related agreements (collectively, the “Financing Documents”), Project Company has, among other things, assigned all of its right, title and interest in, to and under the ESA and Project’s Company’s owners have pledged their ownership interest in Project Company (collectively, the “Assigned Interest”) to the Collateral Agent pursuant to the Financing Documents; and
E. It is a requirement under the Financing Agreement and the ESA that WESTLIGHT and the other Parties hereto shall have executed and delivered this Consent.
AGREEMENT
In consideration of the foregoing, and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, and intending to be legally bound, the Parties hereto hereby agree as follows:
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SECTION 1. CONSENT TO ASSIGNMENT, ETC.
1.1 Consent and Agreement.
WESTLIGHT hereby acknowledges:
(a) Notice of and consents to the assignment as collateral security to Collateral Agent, for the benefit of the Secured Parties, of the Assigned Interest; and (b) The right (but not the obligation) of Collateral Agent in the exercise of its rights and remedies under the Financing Documents, to make all demands, give all notices, take all actions and exercise all rightsof Project Company permitted under the ESA (subject to WESTLIGHT’s rights and defenses under the ESA and the terms of this Consent) and accepts any such exercise; provided, insofar as the Collateral Agent exercises any such rights under the ESA or makes any claims with respect to payments or other obligations under the ESA, the terms and conditions of the ESA applicable to such exercise of rights or claims shall apply to Collateral Agent to the same extent as to Project Company.
1.2 Project Company’s Acknowledgement.
Each of Project Company and Collateral Agent hereby acknowledges and agrees that WESTLIGHT is authorized to act in accordance with Collateral Agent’s instructions, and that WESTLIGHT shall bear no liability to Project Company or Collateral Agent in connection therewith, including any liability for failing to act in accordance with Project Company’s instructions.
1.3 Right to Cure.
If Project Company defaults in the performance of any of its obligations under the ESA, or upon the occurrence or non-occurrence of any event or condition under the ESA which would immediately or with the passage of any applicable grace period or the giving of notice, or both, enable WESTLIGHT to terminate or suspend its performance under the ESA (a “ESA Default”), WESTLIGHT will not terminate or suspend its performance under the ESA until it first gives written notice of such ESA Default to Collateral Agent and affords Collateral Agent the right to cure such ESA Default within the applicable cure period under the ESA, which cure period shall run concurrently with that afforded Project Company under the ESA. In addition, if Collateral Agent gives WESTLIGHT written notice prior to the expiration of the applicable cure period under the ESA of Collateral Agent’s intention to cure such ESA Default (which notice shall include a reasonable description of the time during which it anticipates to cure such ESA Default) and is diligently proceeding to cure such ESA Default, notwithstanding the applicable cure period under the ESA, Collateral Agent shall have a period of sixty (60) days (or, if such ESA Default is for failure by the Project Company to pay an amount to WESTLIGHT which is due and payable under the ESA other than to provide ESA Collateral, thirty (30) days, or, if such ESA Default is for failure by Project Company to provide ESA Collateral, ten (10) Business Days) from the Collateral Agent’s receipt of the notice of such ESA Default from WESTLIGHT to cure such ESA Default; provided, (a) if possession of the Facility is necessary to cure any such non-monetary ESA Default and Collateral Agent has commenced foreclosure proceedings within sixty (60) days after notice of the ESA Default and is diligently pursuing such foreclosure proceedings, Collateral Agent will 317
be allowed a reasonable time, not to exceed one hundred eighty (180) days after the notice of the ESA Default, to complete such proceedings and cure such ESA Default, and (b) if Collateral Agent is prohibited from curing any such ESA Default by any process, stay or injunction issued by any Governmental Authority or pursuant to any bankruptcy or insolvency proceeding or other similar proceeding involving Project Company, then the time periods specified herein for curing a ESA Default shall be extended for theperiod of such prohibition, so long as Collateral Agent has diligently pursued removal of such process, stay or injunction. Collateral Agent shall provide WESTLIGHT with reports concerning the status of efforts to cure a ESA Default upon WESTLIGHT’s reasonable request.
1.4 Substitute Owner.
Subject to Section 1.7, the Parties agree that if Collateral Agent notifies (such notice, a “Financing Document Default Notice”) WESTLIGHT that an event of default has occurred and is continuing under the Financing Documents (a “Financing Document Event of Default”) then, upon a judicial foreclosure sale, non-judicial foreclosure sale, deed in lieu of foreclosure or other transfer following a Financing Document Event of Default, Collateral Agent (or its designee) shall be substituted for Project Company (the “Substitute Owner”) under the ESA, and, subject to Sections
1.7(b) and 1.7(c) below, WESTLIGHT and Substitute Owner will recognize each other as counterparties under the ESA and will continue to perform their respective obligations (including those obligations accruing to WESTLIGHT and the Project Company prior to the existence of the Substitute Owner) under the ESA in favor of each other in accordance with the terms thereof; provided, before WESTLIGHT is required to recognize the Substitute Owner, the Substitute Owner must have demonstrated to WESTLIGHT’s reasonable satisfaction that the Substitute Owner has financial qualifications and operating experience [TBD] (a “Permitted Transferee”).
For purposes of the foregoing, WESTLIGHT shall be entitled to assume that any such purported exercise of rights by Collateral Agent that results in substitution of a Substitute Owner under the ESA is in accordance with the Financing Documents without independent investigation thereof but shall have the right to require that the Collateral Agent and its designee (if applicable) provide reasonable evidence demonstrating the same.
1.5 Replacement Agreements.
Subject to Section 1.7, if the ESA is terminated, rejected or otherwise invalidated as a result of any bankruptcy, insolvency, reorganization or similar proceeding affecting Project Company, its owner(s) or guarantor(s), and if Collateral Agent or its designee directly or indirectly takes possession of, or title to, the Facility (including possession by a receiver or title by foreclosure or deed in lieu of foreclosure) (“Replacement Owner”), WESTLIGHT shall, and Collateral Agent shall cause Replacement Owner to, enter into a new agreement with one another for the balance of the obligations under the ESA remaining to be performed having terms substantially the same as the terms of the ESA with respect to the remaining Contract Term (“Replacement ESA”); provided, before WESTLIGHT is required to enter into a Replacement ESA, the Replacement Owner must have demonstrated to WESTLIGHT’s reasonable satisfaction that the Replacement Owner satisfies the requirements of a Permitted Transferee. For purposes of the foregoing, WESTLIGHT is entitled to assume that any such purported exercise of rights by Collateral Agent that results in a Replacement Owner is in accordance with the Financing Documents without independent investigation thereof but shall have the right to require that the Collateral Agent and 318
its designee (if applicable) provide reasonable evidence demonstrating the same. Notwithstanding the execution and delivery of a Replacement ESA, to the extent WESTLIGHT is, or was otherwise prior to its termination as described in this Section 1.5, entitled under the ESA, WESTLIGHT may suspend performance of its obligations under such Replacement ESA, unless and until all ESA Defaults of Project Company under the ESA or Replacement ESA have been cured.
1.6 Transfer.
Subject to Section 1.7, a Substitute Owner or a Replacement Owner may assign all of its interest in the Facility and the ESA and a Replacement ESA to a natural person, corporation, trust, business trust, joint venture, joint stock company, association, company, limited liability company, partnership, Governmental Authority or other entity (a “Person”) to which the Facility is transferred; provided, the proposed transferee shall have demonstrated to WESTLIGHT’s reasonable satisfaction that such proposed transferee satisfies the requirements of a Permitted Transferee.
1.7 Assumption of Obligations.
(a) Transferee.
Any transferee under Section 1.6 shall expressly assume in a writing reasonably satisfactory to WESTLIGHT all of the obligations of Project Company, Substitute Owner or Replacement Owner under the ESA or Replacement ESA, as applicable, including posting and collateral assignment of the ESA Collateral. Upon such assignment and the cure of any outstanding ESA Default, and payment of all other amounts due and payable to WESTLIGHT in respect of the ESA or such Replacement ESA, the transferor shall be released from any further liability under the ESA or Replacement ESA, as applicable.
(b) Substitute Owner.
Subject to Section 1.7(c), any Substitute Owner pursuant to Section 1.4 shall be required to perform Project Company’s obligations under the ESA, including posting and collateral assignment of the ESA Collateral; provided, the obligations of such Substitute Owner shall be no more than those of Project Company under the ESA.
(c) No Liability.
WESTLIGHT acknowledges and agrees that neither Collateral Agent nor any Secured Party shall have any liability or obligation under the ESAas a result of this Consent (except to the extent Collateral Agent or a Secured Party is a Substitute Owner or Replacement Owner) nor shall Collateral Agent or any other Secured Party be obligated or required to (i) perform any of Project Company’s obligations under the ESA, except as provided in Sections 1.7(a) and 1.7(b) and to the extent Collateral Agent or a Secured Party is a Substitute Owner or Replacement Owner, or (ii) take any action to collect or enforce any claim for payment assigned under the Financing Documents. If Collateral Agent becomes a Substitute Owner pursuant to Section 1.4 or enters into a Replacement ESA, Collateral Agent shall not have any personal liability to WESTLIGHT under the ESA or Replacement ESA and the sole recourse of WESTLIGHT in seeking enforcement of such obligations against Collateral Agent shall be to the aggregate interest of the Secured Parties 319
in the Facility; provided, such limited recourse shall not limit WESTLIGHT’s right to seek equitable or injunctive relief against Collateral Agent, or WESTLIGHT’s rights with respect to any offset rights expressly allowed under the ESA, a Replacement ESA or the ESA Collateral.
1.8 Delivery of Notices.
WESTLIGHT shall deliver to Collateral Agent, concurrently with the delivery thereof to Project Company, a copy of each notice, request or demand given by WESTLIGHT to Project Company pursuant to the ESA relating to (a) a ESA Default by Project Company under the ESA, (b) any claim regarding a Force Majeure Event by WESTLIGHT under the ESA, (c) any notice of dispute under the ESA, (d) any notice of intent to terminate or any termination notice, and (e) any matter that would require the consent of Collateral Agent pursuant to Section 1.11 or any other provision of this Consent. Collateral Agent acknowledges that delivery of such notice, request and demand shall satisfy WESTLIGHT’s obligation to give Collateral Agent a notice of ESA Default under Section 1.3. Collateral Agent shall deliver to WESTLIGHT, concurrently with delivery thereof to Project Company, a copy of each notice, request or demand given by Collateral Agent to Project Company pursuant to the Financing Documents relating to a default by Project Company under the Financing Documents.
1.9 Confirmations.
WESTLIGHT will, as and when reasonably requested by Collateral Agent from time to time, confirm in writing matters relating to the ESA (including the performance of same by Project Company); provided, such confirmation may be limited to matters of which WESTLIGHT is aware as of the time the confirmation is given and such confirmations shall be without prejudice to any rights of WESTLIGHT under the ESA as between WESTLIGHT and Project Company.
1.10 Exclusivity of Dealings.
Except as provided in Sections 1.3, 1.4, 1.8, 1.9 and 2.1, unless and until WESTLIGHT receives a Financing Document Default Notice, WESTLIGHT shall deal exclusively with Project Company in connection with the performance of WESTLIGHT’s obligations under the ESA. From and after such time as WESTLIGHT receives a Financing Document Default Notice and until a Substitute Owner is substituted for Project Company pursuant to Section 1.4, a Replacement ESA is entered into or the ESA is transferred to a Person to whom the Facility is transferred pursuant to Section
1.6, WESTLIGHT shall, until Collateral Agent confirms to WESTLIGHT in writing that all obligations under the Financing Documents are no longer outstanding, deal exclusively with Collateral Agent in connection with the performance of WESTLIGHT’s obligations under the ESA, and WESTLIGHT may irrevocably rely on instructions provided by Collateral Agent in accordance therewith to the exclusion of those provided by any other Person.
1.11 No Amendments.
To the extent permitted by applicable laws, WESTLIGHT agrees that it will not, without the prior written consent of Collateral Agent (not to be unreasonably withheld, delayed or conditioned) (a) enter into any material supplement, restatement, novation, extension, amendment or modification of the ESA (b) terminate or suspend its performance under the ESA (except in accordance with Section 1.3) or (c) consent to or accept any termination or cancellation of the ESA by Project 320
Company.
SECTION 2. PAYMENTS UNDER THE ESA
2.1 Payments.
Unless and until WESTLIGHT receives written notice to the contrary from Collateral Agent, WESTLIGHT will make all payments to be made by it to Project Company under or by reason of the ESA directly to Project Company. WESTLIGHT, Project Company, and Collateral Agent acknowledge that WESTLIGHT will be deemed to be in compliance with the payment terms of the ESA to the extent that WESTLIGHT makes payments in accordance with Collateral Agent’s instructions.
2.2 No Offset, Etc.
All payments required to be made by WESTLIGHT under the ESA shall be made without any offset, recoupment, abatement, withholding, reduction or defense whatsoever, other than that expressly allowed by the terms of the ESA.
SECTION 3. REPRESENTATIONS AND WARRANTIES OF WESTLIGHT
WESTLIGHT makes the following representations and warranties as of the date hereof in favor of Collateral Agent:
3.1 Organization.
WESTLIGHT is a joint powers authority and community choice aggregator duly organized and validly existing under the laws of the state of California, and the rules, regulations and orders of the California Public Utilities Commission, and is qualified to conduct business in each jurisdiction of the Joint Powers Agreement members. WESTLIGHT has all requisite power and authority, corporate and otherwise, to enter into and to perform its obligations hereunder and underthe ESA, and to carry out the terms hereof and thereof and the transactions contemplated hereby and thereby.
3.2 Authorization.
The execution, delivery and performance by WESTLIGHT of this Consent and the ESA have been duly authorized by all necessary corporate or other action on the part of WESTLIGHT and do not require any approval or consent of any holder (or any trustee for any holder) of any indebtedness or other obligation of WESTLIGHT which, if not obtained, will prevent WESTLIGHT from performing its obligations hereunder or under the ESA except approvals or consents which have previously been obtained and which are in full force and effect.
3.3 Execution and Delivery; Binding Agreements.
Each of this Consent and the ESA is in full force and effect, has been duly executed and delivered on behalf of WESTLIGHT by the appropriate officers of WESTLIGHT, and constitutes the legal, valid and binding obligation of WESTLIGHT, enforceable against WESTLIGHT in accordance 321
with its terms,except as the enforceability thereof may be limited by (a) bankruptcy, insolvency, reorganization, moratorium or other similar laws of general application affecting the enforcement of creditors’ rights generally and (b) general equitable principles (whether considered in a proceeding in equity or at law).
3.4 No Default or Amendment.
Except as set forth in Schedule A attached hereto: (a) Neither WESTLIGHT nor, to WESTLIGHT’s actual knowledge, Project Company, is in default of any of its obligations under the ESA; (b) WESTLIGHT and, to WESTLIGHT’s actual knowledge, Project Company, has complied with all conditions precedent to the effectiveness of its obligations under the ESA; (c) to WESTLIGHT’s actual knowledge, no event or condition exists which would either immediately or with the passage of any applicable grace period or giving of notice, or both,enable either WESTLIGHT or Project Company to terminate or suspend its obligations under the ESA; and (d) the ESA has not been amended, modified or supplemented in any manner except as set forth herein and in the recitals hereto.
3.5 No Previous Assignments.
WESTLIGHT has no notice of, and has not consented to, any previous assignment by Project Company of all or any part of its rights under the ESA, except as previously disclosed in writing and consented to by WESTLIGHT.
SECTION 4. REPRESENTATIONS AND WARRANTIES OF PROJECT COMPANY Project Company makes the following representations and warranties as of the date hereof in favor of the Collateral Agent and WESTLIGHT:
4.1 Organization.
Project Company is a [Legal Status of Seller] duly organized and validly existing under the laws of the state of its organization, and is duly qualified, authorized to do business and in good standing in every jurisdiction in which it owns or leases real property or in which the nature of its business requires it to be so qualified, except where the failure to so qualify would not have a material adverse effect on its financial condition, its ability to own its properties or its ability to transact its business. Project Company has all requisite power and authority, corporate and otherwise, to enter into and to perform its obligations hereunder and under the ESA, and to carry out the terms hereof and thereof and the transactions contemplated hereby and thereby.
4.2 Authorization.
The execution, delivery and performance of this Consent by Project Company, and Project Company’s assignment of its right, title and interest in, to and under the ESA to the Collateral Agent pursuant to the Financing Documents, have been duly authorized by all necessary corporate or other action on the part of Project Company.
4.3 Execution and Delivery; Binding Agreement.
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This Consent is in full force and effect, has been duly executed and delivered on behalf of Project Company by the appropriate officers of Project Company, and constitutes the legal, valid and binding obligation of Project Company, enforceable against Project Company in accordance with its terms, except as the enforceability thereof may be limited by (a) bankruptcy, insolvency, reorganization, moratorium or other similar laws of general application affecting the enforcement of creditors’ rights generally and (b) general equitable principles (whether considered in a proceeding in equity or at law).
4.4 No Default or Amendment.
Except as set forth in Schedule B attached hereto: (a) neither Project Company nor, to Project Company’s actual knowledge, WESTLIGHT, is in default of any of its obligations under the ESA; (b) Project Company and, to Project Company’s actual knowledge, WESTLIGHT, has complied with all conditions precedent to the effectiveness of its obligations under the ESA; (c) to Project Company’s actual knowledge, no event or condition exists which would either immediately or with the passage of any applicable grace period or giving of notice, or both, enable either WESTLIGHT or Project Company to terminate or suspend its obligations under the ESA; and (d) the ESA has not been amended, modified or supplemented in any manner except as set forth herein and in the recitals hereto.
4.5 No Previous Assignments.
Project Company has not previously assigned all or any part of its rights under the ESA.
SECTION 5. REPRESENTATIONS AND WARRANTIES OF COLLATERAL AGENT Collateral Agent makes the following representations and warranties as of the date hereof in favor of WESTLIGHT and Project Company:
5.1 Authorization.
The execution, delivery and performance of this Consent by Collateral Agent have been duly authorized by all necessary corporate or other action on the part of Collateral Agent and Secured Parties.
5.2 Execution and Delivery; Binding Agreement.
This Consent is in full force and effect, has been duly executed and delivered on behalf of Collateral Agent by the appropriate officers of Collateral Agent, and constitutes the legal, valid and binding obligation of Collateral Agent as Collateral Agent for the Secured Parties, enforceable against Collateral Agent (and the Secured Parties to the extent applicable) in accordance with its terms, except as the enforceability thereof may be limited by (a) bankruptcy, insolvency, reorganization, moratorium or other similar laws of general application affecting the enforcement of creditors’ rights generally and (b) general equitable principles (whether considered in a proceeding in equity or at law).
SECTION 6. MISCELLANEOUS
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6.1 Notices.
All notices and other communications hereunder shall be in writing, shall be deemed given upon receipt thereof by the Party or Parties to whom such notice is addressed, shall refer on their face to the ESA (although failure to so refer shall not render any such notice or communication ineffective), shall be sent by first class mail, by personal delivery or by a nationally recognized courier service, and shall be directed (a) if to WESTLIGHT or Project Company, in accordance with [Notice Section of the ESA] of the ESA, (b) if to Collateral Agent, to [Collateral Agent Name], [Collateral Agent Address], Attn: [Collateral Agent Contact Information], Telephone: [___], Fax:
[___], and (c) to such other address or addressee as any such Party may designate by notice given pursuant hereto.
6.2 Governing Law; Submission to Jurisdiction.
(a) THIS CONSENT SHALL BE CONSTRUED IN ACCORDANCE WITH, AND THIS
CONSENT AND ALL MATTERS ARISING OUT OF THIS CONSENT AND THE TRANSACTIONS
CONTEMPLATED HEREBY SHALL BE GOVERNED BY, THE LAW OF THE STATE OF
CALIFORNIA WITHOUT REGARD TO ANY CONFLICTS OF LAWS PROVISIONS THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAW OF ANOTHER JURISDICTION. (b) All disputes, claims or controversies arising out of, relating to, concerning or pertaining to the terms of this Consent shall be governed by the dispute resolution provisions of the ESA. Subject to the foregoing, any legal action or proceeding with respect to this Consent and any action for enforcement of any judgment in respect thereof may be brought in the courts of the State of California or of the United States of America for the Central District of California, and, by execution and delivery of this Consent, each Party hereby accepts for itself and in respect of its property, generally and unconditionally, the non-exclusive jurisdiction of the aforesaid courts and appellate courts from any appeal thereof. Each Party further irrevocably consents to the service of process out of any of the aforementioned courts in any such action or proceeding by the mailing of copies thereof by registered or certified mail, postage prepaid, to its notice address provided pursuant to Section 6.1 hereof. Each Party hereby irrevocably waives any objection which it may now or hereafter have to the laying of venue of any of the aforesaid actions or proceedings arising out of or in connection with this Consent brought in the courts referred to above and hereby further irrevocably waives and agrees not to plead or claim in any such court that any such action or proceeding brought in any such court has been brought in an inconvenient forum. Nothing herein shall affect the right of any Party to serve process in any other manner permitted by law.
6.3 Headings Descriptive.
The headings of the several sections and subsections of this Consent are insertedfor convenience only and shall not in any way affect the meaning or construction of any provisionof this Consent.
6.4 Severability.
In case any provision in or obligation under this Consent shall be invalid, illegal or unenforceable in any jurisdiction, the validity, legality and enforceability of the remaining provisions or obligations, or of such provision or obligation in any other jurisdiction, shall not in any way be affected or impaired thereby.
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6.5 Amendment, Waiver.
Neither this Consent nor any of the terms hereof may (a) be terminated, amended, supplemented or modified, except by an instrument in writing signed by WESTLIGHT, Project Company and Collateral Agent or (b) waived, except by an instrument in writing signed by the waiving Party.
6.6 Termination.
Each Party’s obligations hereunder are absolute and unconditional, and no Party has any right, and shall have no right, to terminate this Consent or to be released, relieved or discharged from any obligation or liability hereunder until WESTLIGHT has been notified by Collateral Agent that all of the obligations under the Financing Documents shall have been satisfied in full (other than contingent indemnification obligations) or, with respect to the ESA or any Replacement ESA, its obligations under such ESA or Replacement ESA have been fully performed.
6.7 Successors and Assigns.
This Consent shall be binding upon each Party and its successors and assigns permitted under and in accordance with this Consent, and shall inure to the benefit of the other Parties and their respective successors and assignee permitted under and in accordance with this Consent. Each reference to a Person herein shall include such Person’s successors and assigns permitted under and in accordance with this Consent.
6.8 Further Assurances.
WESTLIGHT hereby agrees to execute and deliver all such instruments and take all such action as may be necessary to effectuate fully the purposes of this Consent.
6.9 Waiver of Trial by Jury.
TO THE EXTENT PERMITTED BY APPLICABLE LAWS, THE PARTIES HEREBY
IRREVOCABLY WAIVE ALL RIGHT OF TRIAL BY JURY IN ANY ACTION,
PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR IN CONNECTION WITH THIS CONSENT OR ANY MATTER ARISING HEREUNDER. EACH PARTY FURTHER
WARRANTS AND REPRESENTS THAT IT HAS REVIEWED THIS WAIVER WITH ITS
LEGAL COUNSEL, AND THAT IT KNOWINGLY AND VOLUNTARILY WAIVES ITS JURY TRIAL RIGHTS FOLLOWING CONSULTATION WITH LEGAL COUNSEL.
6.10 Entire Agreement.
This Consent and any agreement, document or instrument attached hereto or referred to herein integrate all the terms and conditions mentioned herein or incidental hereto and supersede all oral negotiations and prior writings in respect to the subject matter hereof. In the event of any conflict between the terms, conditions and provisionsof this Consent and any such agreement, document or instrument, the terms, conditions and provisions of this Consent shall prevail.
6.11 Effective Date.
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This Consent shall be deemed effective as of the date upon which the last Party executes this Consent.
6.12 Counterparts; Electronic Signatures.
This Consent may be executed in one or more counterparts, each of which will be deemed to be an original of this Consent and all of which, when taken together, will be deemed to constitute one and the same agreement. The exchange of copies of this Consent and of signature pages by facsimile transmission, Portable Document Format (i.e., PDF), or by other electronic means shall constitute effective execution and delivery of this Consent as to the Parties and may be used in lieu of the original Consent for all purposes.
[Remainder of Page Left Intentionally Blank.]
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IN WITNESS WHEREOF, the Parties hereto have caused this Consent to be duly executed and delivered by their duly authorized officers on the dates indicated below their respective signatures. [NAME OF PROJECT COMPANY],
[Legal Status of Project Company].
WESTLIGHT ENERGY,
a California joint powers authority.
By:
___________________________________
[Name]
[Title]
Date: ___________________________
By:
___________________________________
[Name]
[Title]
Date: ___________________________
[NAME OF COLLATERAL AGENT],
[Legal Status of Collateral Agent].
By:
________________________________
[Name]
[Title]
Date: ___________________________
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SCHEDULE A
[Describe any disclosures relevant to representations and warranties made in Section 3.4] 328
DATE: July 10, 2026
MEETING DATE: July 23, 2026
VOTE REQUIRED: Majority Vote
TO: Honorable WestLight Energy Board of Directors
FROM: Roy Xu, Senior Director of Power Resources
Sara Maatta, Senior Power Resources Manager
Mehdi Shahriari, Senior Manager of Planning and Analytics Shayna Levia, Associate Manager of Power Resources
Katarina Malmgren, Power Resources Analyst
SUBJECT: Approval of the 2026 California Public Utilities Commission Integrated Resource Plan Submission (Action)
Item No. 7
WestLight Energy
JPA Board Correspondence
RECOMMENDATION
Approve the results of the Integrated Resource Plan analysis and the submission of results as presented by staff, or in a form substantially similar to that presented by staff, and direct the CEO, or designee, to prepare and submit the final narrative and data templates to the California Public Utilities Commission (CPUC) on or before August 10, 2026.
BACKGROUND
The California Public Utilities Commission (CPUC) Integrated Resource Plan (IRP) proceeding is California's long-term electricity planning process. Established pursuant to Senate Bill (SB) 350 (de Leon, 2015), the IRP provides the framework for planning California's future electric system and helps ensure the state can achieve its clean energy, reliability, and affordability goals by identifying the resources needed to serve future electricity demand while reducing greenhouse gas emissions. The IRP also serves as a key implementation mechanism for SB 100 (de Leon, 2018), which established California's goal of supplying 100 percent of retail electricity sales with renewable and zero-carbon resources by 2045, including a requirement to achieve a 60 percent Renewable Portfolio Standard by 2030.
As a Load-Serving Entity (LSE), WestLight Energy is required to prepare and submit an Integrated Resource Plan to the CPUC. The 2026 IRP is due on August 10, 2026. Consistent with California Public Utilities Code Section 454.52(b)(3), the IRP must be approved by WestLight Energy's governing board prior to submission.
Following submission, the CPUC aggregates the Integrated Resource Plans submitted by California's LSEs to evaluate statewide resource needs and develop a Preferred System Plan. 329
The Preferred System Plan is then provided to the California Independent System Operator (CAISO), where it informs long-term transmission planning and helps identify transmission investments needed to support California's future resource portfolio. As a result, WestLight Energy's IRP not only demonstrates compliance with CPUC requirements but also provides an opportunity to help shape statewide resource and transmission planning through its portfolio and policy recommendations.
The complete IRP filing package consists of the Narrative Template, Resource Data Template (RDT), and Clean System Power Calculator (CSP). The Narrative Template, included in the Board packet, summarizes WestLight Energy's planning methodology, modeling assumptions, portfolio results, and policy recommendations. The RDT and CSP are technical workbooks that support the filing and will be submitted electronically to the CPUC as part of the complete filing package.
Staff recommends that the Board:
1. Approve WestLight Energy's 2026 Integrated Resource Plan and authorize its submission to the California Public Utilities Commission.
2. Authorize the Chief Executive Officer, or designee, to finalize and submit the Narrative Template, Resource Data Template, Clean System Power Calculator, and any other required filing materials, including any non-substantive revisions necessary to complete the filing, on or before August 10, 2026.
DISCUSSION
CPUC Required Planning Assumptions
The CPUC's IRP process requires each LSE to develop its portfolio using a common set of planning assumptions so that portfolios can be evaluated on a consistent basis and aggregated into a statewide Preferred System Plan. These standardized assumptions include the assigned load forecast, available resource options, reliability requirements, and greenhouse gas (GHG) emissions benchmarks.
While many of these assumptions are prescribed by the CPUC, LSEs retain flexibility in certain aspects of the analysis. WestLight was required to use its CPUC-assigned load forecast, Reliability Procurement Requirement (RPR), and GHG emissions benchmarks.
However, consistent with the filing requirements, WestLight developed its own hourly load shapes, renewable generation profiles, storage dispatch profiles, and resource cost assumptions to better reflect its service territory and market experience.
This standardized framework ensures that each LSE's portfolio can be evaluated consistently while still allowing LSEs to incorporate localized knowledge where permitted. As a result, the IRP represents a planning scenario developed under CPUC-established assumptions rather than WestLight's internal procurement plan.
Relationship to WestLight’s Internal Resource Planning
While the CPUC IRP is an important long-term planning exercise, it is distinct from WestLight's internal resource planning process and should not be interpreted as a procurement plan or spending authorization.
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The CPUC IRP is developed using standardized assumptions to be compliant with the CPUC’s filing requirements. In contrast, WestLight’s internal planning is more customized and realistic for its service territory. One of the most significant differences between the two analyses is the load forecast. The CPUC-assigned load forecast used in the IRP is substantially higher than WestLight's internal forecast, resulting in a portfolio that includes significantly more resource additions than WestLight currently expects to require.
Accordingly, the portfolio presented in the IRP is a planning scenario developed to satisfy CPUC filing requirements. Approval of this item does not authorize WestLight to procure the resources identified in the IRP, approve future expenditures, or commit WestLight to a specific procurement strategy. Future procurement decisions will continue to be brought before the Board for approval, as required by WestLight's procurement policies.
Likewise, the CPUC does not require WestLight's future procurement activities to match the specific portfolio presented in the IRP. Rather, the IRP is used by the CPUC to evaluate statewide resource needs to inform transmission planning.
Although the IRP is not a procurement commitment, it provides WestLight an opportunity to help shape California’s long-term clean energy strategy by identifying resource and transmission needs, and policy recommendations based on WestLight’s analysis.
Modeling Approach and Planning Methodology
WestLight's modeling objective was to identify the least-cost portfolio capable of meeting both WestLight's strategic objectives and the CPUC's planning requirements. Consistent with Board-adopted goals, staff sought to identify a portfolio that achieves 100 percent renewable energy on an annual basis by 2030 through strategic and cost-effective procurement while maximizing the hourly alignment of renewable energy generation with customer demand and prioritizing reductions in grid emissions and customer costs.
The modeled portfolio was then required to satisfy the CPUC's planning requirements by:
Meeting WestLight's CPUC-assigned load forecast;
Meeting WestLight's assigned Reliability Procurement Requirement (RPR) in each planning year; and
Achieving greenhouse gas emissions below WestLight's assigned emissions benchmarks.
Modeling Results
Staff are providing and requesting Board approval of the results of the 2026 IRP Preferred Portfolio. Net of contract expirations, the Preferred Portfolio adds an additional 561 MW of storage, 358 MW of solar, 536 MW of in-state onshore wind, 400 MW of out-of-state onshore wind, and 297 MW of geothermal by 2045. Due to contract expiration, the Preferred Portfolio results in 15 MW less small hydro in 2045 than is currently contracted. The selected capacity results in the lowest cost portfolio that meets WestLight’s internal voluntary targets, and the assigned reliability and emissions targets.
Figure 1. Cumulative Capacity of WestLight’s Preferred Portfolio 331
The Preferred Portfolio performs better than WestLight’s assigned GHG emissions targets.
Table 1: Preferred Portfolio Emissions Results
2030 2035 2040 2045
Assigned Load
Forecast (GWh)
4,452 5,998 7,181 7,957
8 MMT GHG
Benchmark (MMT
CO2)
0.359 0.310 0.280 0.151
WestLight
Preferred Portfolio
Emissions (MMT
CO2)
0.226 0.253 0.212 0.150
The Preferred Portfolio meets or exceeds WestLight’s reliability requirements in all years of the planning horizon.
Figure 2: WestLight’s Preferred Portfolio Capacity by Contract Status 332
Policy Recommendations
In addition to demonstrating compliance with CPUC planning requirements, the IRP provides WestLight with an opportunity to inform statewide resource planning by identifying opportunities to improve California's long-term planning framework. WestLight is advancing several policy recommendations based on its analysis, which include the following:
Acknowledge Uncertainty in Load Forecasting
Statewide load forecasts should better account for uncertainty, particularly with respect to large speculative new loads. Working more closely with Community Choice Aggregators and other Load-Serving Entities to distinguish between verified and speculative projects would improve planning accuracy and reduce the risk of unnecessary customer costs.
Support Development of Diverse Clean Energy Resources
WestLight's Preferred Portfolio relies on a diverse mix of wind and geothermal resources because they provide a more balanced and cost-effective pathway to achieving California's clean energy goals. However, these resources are increasingly difficult to develop due to permitting challenges, transmission limitations, and market conditions. State planning and procurement programs should better reflect commercial development realities and support development of these resources.
Avoid Market-Distorting Procurement Mandates
Resource-specific procurement mandates can reduce competition and increase costs by requiring procurement of technologies that may be scarce or not the best fit for the grid or an individual LSE's portfolio. Procurement requirements should remain technology-neutral, allowing LSEs flexibility to procure the most cost-effective mix of resources that meets reliability and clean energy objectives.
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Improve Coordination Between Resource and Transmission Planning California's long-term resource plans increasingly rely on imported resources, yet transmission planning does not consistently plan for those imports or account for where new clean energy projects are most likely to be developed. Better coordination between resource planning, transmission planning, and commercial development trends will help ensure that transmission investments support California's future clean energy needs.
Next Steps
Following Board approval, the Chief Executive Officer, or designee, will review and approve the final 2026 Integrated Resource Plan filing package, including the Narrative Template, Resource Data Template, Clean System Power Calculator, and any other required supporting materials. Staff will incorporate any non-substantive revisions necessary to complete the filing prior to submission to the California Public Utilities Commission on or before August 10, 2026.
FISCAL IMPACT
There is no impact to WestLight Energy’s budget. The Integrated Resource Plan is a planning exercise mandated by the CPUC, not a procurement commitment.
STRATEGIC PLAN
The Integrated Resource Plan supports the Strategic Priority of Procurement.
ATTACHMENTS:
WestLight 2026 IRP Narrative_PUBLIC.pdf
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RESOLUTION NO. _____________
WESTLIGHT ENERGY, COUNTY OF SAN MATEO, AND THE CITY OF LOS BANOS,
STATE OF CALIFORNIA
APPROVAL OF THE 2026 CALIFORNIA PUBLIC UTILITIES COMMISSION INTEGRATED
RESOURCE PLAN SUBMISSION (ACTION)
RESOLVED, by WestLight Energy of the County of San Mateo, and the City of Los Banos, State of California, (“WestLight”) that:
WHEREAS, WestLight Energy was formed as Peninsula Clean Energy on February 29, 2016, and adopted the name WestLight Energy on May 28, 2026; and WHEREAS, all Load Serving Entities (LSEs) in California are required to produce and submit to the California Public Utilities Commission (CPUC) an Integrated Resources Plan (IRP) on or before August 10, 2026; and
WHEREAS, pursuant to California Public Utilities Code Section 454.52(b)(3), WestLight Energy is required to submit its Integrated Resource Plan to its governing board for approval prior to submission to the CPUC; and
WHEREAS, the Board has been provided with an overview of WestLight Energy's 2026 Integrated Resource Plan, including the planning methodology, modeling results, key policy recommendations, and the documents that comprise the filing to be submitted to the California Public Utilities Commission on or before August 10, 2026; and NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board approves the results of the IRP analysis and the submission of results as presented by staff, or in a form substantially similar to that presented by staff, and directs the CEO, or designee, to prepare and submit the final narrative and data templates to the CPUC on or before August 10, 2026.
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Standard LSE Plan
WESTLIGHT ENERGY
2026 INTEGRATED RESOURCE PLAN
AUGUST 10, 2026
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1 Table of Contents
I. Executive Summary .....................................................................................................3 a. About WestLight Energy...........................................................................................4 i. Enrolled Customers...............................................................................................7 ii. Retail Products......................................................................................................8 II. Study Design ................................................................................................................9 a. Objectives...............................................................................................................10 b. Methodology ..........................................................................................................12 a) Modeling Tool(s) .............................................................................................12 b) Modeling Approach.........................................................................................14 c) Alternative Assumptions.....................................................................................29 III. Study Results .............................................................................................................30 a. Conforming and Alternative Portfolios..................................................................30 b. Preferred Conforming Portfolio .............................................................................35 c. GHG Emissions Results...........................................................................................41 d. Local Air Pollutant Minimization and Disadvantaged Communities......................42 i. Local Air Pollutants .............................................................................................42 ii. Focus on Disadvantaged Communities ..............................................................42 e. Cost and Rate Analysis............................................................................................51 f. System Reliability Analysis .....................................................................................54 g. Existing Resource Planning.....................................................................................62 h. Hydro Generation Risk Management.....................................................................64 i. Long-Duration Storage Planning ............................................................................66 j. Clean Firm Power Planning ....................................................................................67 k. Non-CAISO, including Out-of-State, Wind Planning...............................................73 l. Offshore Wind Planning .........................................................................................73 m. Transmission Planning ........................................................................................75 a. Resources with flexible locations .......................................................................75 b. Planned and contracted resources with fixed locations, contracted imports need MIC....................................................................................................................77 c. Contracted Resources with CODs After Spring 2024 .........................................80 337
2 d. Resources Contracted with CODs Before Spring 2024 ...................................84 IV. Action Plan.................................................................................................................88 a. Proposed Procurement Activities and Potential Barriers......................................88 i. The LSE should provide responses for each of the following resource categories: Resources to meet IRP mandated procurement requirements, including D.21-06-035 and D.23-02-040:..................................................................................91 ii. Plans for resources that are currently non-candidate in CPUC’s IRPs not described above ........................................................................................................92 iii. Other renewable and/or zero carbon resources not described above..........93 iv. Other energy storage not described above....................................................93 v. Other demand response not described above...................................................93 vi. Other energy efficiency not described above.................................................94 vii. Other distributed generation not described above........................................95 viii. Transportation electrification, including any investments that correspond to different levels than what is included in Integrated Energy Policy Report (IEPR)....97 ix. Building electrification, including any investments that correspond to different levels than what is included in Integrated Energy Policy Report (IEPR)....98 x. Potential Centralized Procurement, pursuant to AB-1373 ................................99 xi. Other .............................................................................................................101 b. Disadvantaged Communities (DACs)....................................................................106 c. LSEs’ Tribal Customers..........................................................................................110 d. Procurement Products .........................................................................................111 e. Commission Direction of Actions.........................................................................112 V. Lessons Learned.......................................................................................................113 338
3 I. Executive Summary
In accordance with the requirements of Senate Bill 350 and the California Public Utilities Commission (CPUC or Commission) 2024-2027 IRP Filing Requirements, WestLight Energy (WestLight), formerly known as Peninsula Clean Energy (PCE), respectfully submits its 2026 Integrated Resource Plan (IRP). The IRP is comprised of this written narrative as well as the following attachments as provided by the CPUC:
i. Completed CPUC Resource Data Template (RDT) - 8MMT Conforming ii. Completed CPUC Clean System Power Calculator (CSP Calculator) - 8 MMT Conforming This IRP was approved by WestLight’s Board of Directors on July 23, 2026, and the resolution documenting this approval is attached as Appendix D.
In the 2024-2027 IRP cycle, WestLight staff performed the modeling in-house. WestLight staff used the MATCH (Modeling Around-The-Clock Hourly energy) model, as discussed in further detail in Section II.b, to develop the cost-optimal portfolio that met all the specified planning goals. Staff then used the proprietary PowerSIMM software, developed by Ascend Analytics, to perform a stochastic evaluation of the selected portfolio.
WestLight is submitting a single conforming portfolio that exceeds the emissions reduction goals of the 8 Million Metric Tons of CO2 (MMT) scenario. This preferred portfolio meets all the regulatory requirements of the IRP process and implements WestLight’s voluntary goal to deliver 100% renewable energy on an annual basis by 2030 in a manner that can maximize WestLight’s goal of hourly matching of renewable energy to its load while prioritizing reducing grid emissions and customer costs. Table 1 shows how WestLight’s Preferred Portfolio performs better than its emissions benchmarks. Figure 1 shows the portfolio composition by nameplate capacity. In the sections below, WestLight provides further details on the composition of this portfolio and discusses its methodology for portfolio development.
Table 1: WestLight Energy Preferred Portfolio Emissions 2028 2030 2035 2040 2045
Assigned Load Forecast (GWh) 3,899 4,452 5,998 7,181 7,957 8 MMT GHG Benchmark (MMT CO2) 0.359 0.310 0.280 0.151
WestLight Energy Preferred Portfolio
Emissions (MMT CO2) 0.131 0.226 0.253 0.212 0.150
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4 Figure 1: WestLight Energy Preferred Portfolio Capacity This Integrated Resource Plan is organized into the following sections. Section II, Study Design, describes WestLight's planning objectives, modeling methodology, and key assumptions used to develop its Preferred Portfolio. Section III, Study Results, presents the results of the portfolio analysis, including the Preferred Portfolio, greenhouse gas emissions, local air pollutant and disadvantaged community analyses, cost and rate impacts, system reliability, and planning assessments for existing resources, hydroelectric generation, long-duration storage, clean firm resources, out-of-state wind, offshore wind, and transmission. Section IV, Action Plan, describes WestLight's expected procurement activities, customer and community programs, procurement products, barriers and risks to implementing the Preferred Portfolio, and recommendations for improving California's integrated resource planning process. Finally, Section V, Lessons Learned, summarizes key observations from this planning cycle and identifies opportunities to improve future resource planning and procurement. a. About WestLight Energy
Following a comprehensive feasibility study and consistent with AB 32 voluntary action pathways, elected officials from each member jurisdiction within San Mateo County unanimously agreed to form Peninsula Clean Energy in February 2016 to meet local climate action goals and benefit San Mateo County. The agency was established as a joint powers authority consisting of the County of San Mateo and all twenty of its towns and cities. The mission of the agency is to provide affordable, clean electricity and advance local solutions that lower costs, reduce pollution, and strengthen community resilience. In 2020, following another comprehensive feasibility study, elected officials from the City of Los Banos voted to join the agency, and service for Los Banos customers began in 2022. In 2026, Peninsula Clean Energy adopted the name WestLight Energy to better reflect the communities it serves and provide a clearer, more recognizable identity as the organization continues to grow and support the clean energy transition. While the name has changed, WestLight Energy's mission, programs, and commitment to serving its communities remain unchanged. Today, WestLight Energy is a joint powers authority consisting of the County of San Mateo, all twenty of its towns and cities, and the City of Los Banos in Merced County. 340
5 WestLight provides cleaner electricity at lower rates than the incumbent investor-owned utility (IOU), Pacific Gas & Electric Company (PG&E). WestLight plans for and secures commitments from a diverse portfolio of carbon free and renewable energy-generating resources to reliably serve the electric energy requirements of its customers over the near-, mid-, and long-term planning horizons. WestLight was the second CCA in California to obtain an investment-grade credit rating from Moody's in May 2019.
WestLight currently maintains investment-grade ratings of A3 from Moody's and A- from Standard &Poors (S&P). WestLight also offers programs to customers, including those that advance the adoption of electric transportation and transition building fuel uses to low carbon electricity. For more information on WestLight Energy, please go to www.westlightenergy.org.
As part of its mission-driven, collaborative, not-for-profit, locally focused roots, WestLight is committed to the following guiding principles1:
1. Environmental Impact
WestLight was founded on the vision of a sustainable world for everyone; a world in which energy choice can dramatically reduce harmful greenhouse gas emissions by accelerating the transition from a fossil-based grid to one that runs principally on carbon-free and renewable resources.
WestLight will continue to be a champion for the environment in its procurement and program initiatives. WestLight will continue to include environmental justice in its decision-making and support new clean energy technologies that leverage local renewables to benefit energy resilience and reliability.
2. Customer-Focused Approach
WestLight would not exist without its customers. Keeping customer and community needs at the forefront of decision-making and program design while seeking to provide affordable energy is central to WestLight’s continued success and will be at the core of what differentiates WestLight from other providers in the future. WestLight’s customers are not only the clients it serves; they are WestLight’s critical partners in the transition to a clean energy future.
3. Economic Development
In its quest to expand renewable energy production, support electrification, and reduce greenhouse gases, WestLight will serve as an economic engine for its service area. This includes maintaining affordable electric generation rates, investing in local decarbonization and electrification efforts, supporting the development of electrified housing, advancing new local renewable energy projects, and strengthening the green economy through local workforce development and jobs.
4. Driving Innovation
WestLight will continue to be an innovator and thought leader in the CCA industry — recognized locally, statewide and nationally for its leading-edge renewable procurement strategies, scalable building and transportation programs and policies, workforce DEAI initiatives, and piloted distributed energy resource projects. These efforts, designed to be replicated, will maximize environmental, economic, and customer impact while resulting in broader market change. 1 https://www.westlightenergy.org/wp-content/uploads/2026/03/Our-Strategy-at-a-Glance-2026-2030-Strategic-Plan.pdf 341
6 In addition to these guiding principles, WestLight is committed to the following strategic policies in its 2026-2030 strategic plan:
1. Procurement
WestLight will maintain a 100% zero-carbon power resource portfolio according to the CEC’s Power Source Disclosure Program while working towards delivering 100% renewable energy on an annual basis by 2030 through strategic and cost-effective procurement that can maximize WestLight’s 24/7 hourly matching of renewable energy to WestLight’s load while prioritizing reducing grid emissions and customer costs. This policy statement encompasses the following key elements:
• Continued commitment to achieving industry-leading renewable energy targets • Built-in flexibility on the 24/7 hourly matching goal to balance against cost impacts on WestLight’s customers
• Emphasis on strategic procurement to minimize cost and risk exposure to WestLight, limit cost pressures for customers, and maintain WestLight’s financial health • Targeted 60% minimum Renewable Portfolio Standard (RPS) of WestLight's annual retail sales prior to 2030, with flexibility on the remaining portfolio composition to balance incremental gains toward the 100% renewable goal while maintaining cost competitiveness • Operating WestLight's resource fleet to reduce grid emissions by displacing fossil fuel generation
2. Equity Programs
WestLight will reduce GHGs as quickly as possible by continuing to deliver programs and services that benefit all customers, including designing certain programs and services with equity and vulnerable customers’ needs in mind by:
• Prioritizing rate affordability for all customers
• Advancing policy initiatives and utilizing external (non-WestLight-ratepayer) funding for programs that benefit vulnerable and equity customers, improving affordability and access to WestLight services and benefits
• Partnering with community-based organizations (CBOs) as outreach partners to engage diverse and vulnerable communities, support equity customers, and gather feedback on ways to improve its services
3. Distributed Energy Resources
WestLight will accelerate the development of carbon-free distributed energy resources (DERs) to drive innovation and market transformation of distributed and advanced energy technologies, accelerate greenhouse gas (GHG) reductions, and enhance community resilience, including:
• Expanding DER project development support
• Increasing customer access to capital for DER/electrification projects • Providing technical assistance and support for local resiliency projects • Advancing relevant policy development and advocacy
4. Operational Excellence
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7 WestLight will invest in its people, infrastructure, systems, and processes to strengthen effectiveness, efficiency, and resiliency. WestLight operations will align with industry best practices, leverage technology, and support a high-performing workforce equipped to meet evolving customer and stakeholder needs, while advancing the Agency’s commitments to diversity, equity, and inclusion.
Operational enhancements support WestLight’s ability to meet its mission and include:
• Maintaining strong and effective Agency governance
• Best-in-class rate analysis/design and prudent financial management • Scaling project and process optimization through effective use of technology • Empowering an agile, motivated, and diverse workforce • Driving decisions with quality data
• Ensuring cybersecurity and IT resilience
• Promoting equity and accessibility in operations
• Managing risk and maintaining regulatory compliance
WestLight is governed by its publicly elected Board of Directors. Each member jurisdiction from San Mateo County, plus the City of Los Banos, has one seat on WestLight’s Board of Directors (except for San Mateo County, which has two) for a total of 23 elected officials acting as board members.
The Board of Directors is responsible for setting the overall strategy for WestLight Energy, including rate setting and energy procurement decisions. Board meetings are held on the fourth Thursday of each month at 6:30 PM at WestLight’s offices in Redwood City. As prescribed by the Brown Act, all Board meetings are open to the public both in-person and via online video conferencing and all meeting materials are posted online. The decisions of the Board are binding requirements for WestLight Energy.
WestLight is a member of California Community Power (CC Power), a joint powers authority comprised of nine CCAs that facilitates collaborative long-term resource procurement. Through CC Power, member agencies jointly procure large-scale and emerging clean energy resources, allowing participating CCAs to diversify risk, achieve economies of scale, and support development of technologies that may be difficult to procure independently.
WestLight is also a member of the California Community Choice Association (CalCCA), a statewide trade association representing community choice aggregators throughout California. Through CalCCA, WestLight collaborates with other CCAs on legislative, regulatory, and policy matters affecting community choice energy programs and their customers. CalCCA advocates before the California Public Utilities Commission, California Energy Commission, California Independent System Operator, and state legislature on issues including resource planning, procurement, resource adequacy, customer affordability, and local energy choice. Participation in CalCCA helps ensure that the interests of WestLight and its customers are represented in statewide energy policy discussions and decision-making processes. i. Enrolled Customers
WestLight serves over 315,000 customer accounts representing approximately 780,000 residents. Table 2 illustrates the breakdown between commercial/industrial customers and residential customers in WestLight’s service territory.
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8 Table 2: WestLight Energy Breakdown by Customer Type
Stats as of Dec. 2025 Total WestLight
Energy Residential Commercial, Industrial
Number of Customer Accounts 315,159 286,491 28,668
91% 9%
Total Retail Sales (MWh in 2025) 3,397,185 1,379,550 2,017,635 40% 60%
Customers are automatically enrolled in WestLight and have the option to opt-out and return to PG&E for bundled electric service. Customer participation rates are expressed as the proportion of customer accounts currently served by WestLight relative to the total number of electric customer accounts in the WestLight service territory eligible for WestLight service.2 The remaining percentages of accounts reflects the subset of customer accounts who have voluntarily opted out of the WestLight electric service, retaining bundled service by PG&E. As of publication, WestLight’s customer participation rate is approximately 97.5%.
ii. Retail Products
Most WestLight customers can choose between two different product options, ECOplus and ECO100. Each product has a different amount of energy from renewable sources such as solar and wind. Table 3 summarizes WestLight customer product choice available to all customers in 2025. WestLight offers two additional limited-capacity products, Green Access and Green Transit, to eligible customers. Green Access is the tariff offered to customers in WestLight’s Disadvantaged Communities Green Tariff (DAC-GT) program. Green Transit is a 100% renewable energy product that enables eligible public transit agencies to report zero-carbon intensity fuel under California Air Resources Board’s (CARB) Low Carbon Fuel Standard program.
Table 3: Customer Product Choice (2025)
Stats as of Dec. 2025 Total WestLight
Energy ECOplus Eco100
Number of Customer Accounts 315,159 308,939 6,220
98% 2%
Total Retail Sales (MWh in 2025) 3,397,185 3,155,091 242,094 93% 7%
ECOplus is WestLight’s default electric option, in which new customers are automatically enrolled.
ECOplus rates are typically set 5-10% below PG&E’s generation rates, inclusive of the Power Charge Indifference Adjustment. Beginning in 2021, approximately half of the electricity for ECOplus comes from renewable sources, and half comes from GHG-free sources like large hydroelectric. One of WestLight’s 2 Direct Access customers are not automatically enrolled in a CCA program and are therefore not reflected in WestLight’s participation rate. The Direct Access (DA) Program allows a limited selection of non-residential consumers in California to purchase their electricity from an energy service provider (ESP) rather than from their investor-owned utility (IOU) or default electricity supplier. 344
9 strategic goals is to increase the proportion of renewable energy in the ECOplus product to a target of 100% renewable by 2030.
Customers can choose to “opt up” to ECO100 and receive 100% of their electricity from renewable energy resources. As of publication, ECO100 costs $0.01 per kilowatt-hour (kWh) more than ECOplus. As of the end of 2025, 6,220 accounts have opted-up to ECO100. As part of their emission reduction targets and sustainability goals, 16 cities and the County of San Mateo enrolled their accounts in ECO100. The ECO100 option also provides an opportunity for corporate customers to meet their own sustainability goals. For example, Visa3 and Meta4 have both chosen the ECO100 offering for their electricity use in San Mateo County. The ECO100 product has been certified by the Center for Resource Solutions’ (CRS) Green-e certification program for each of the calendar years from 2018 through 2026.
II. Study Design
For the 2026 IRP filing, WestLight has developed one conforming portfolio (Preferred Portfolio) to meet the 8 MMT by 2045 target. WestLight’s conforming portfolio assumes market fundamentals consistent with Ascend Analytics’ AscendView forecast updated in the first half of 2026. WestLight’s Preferred Portfolio provides 100% renewable energy on an annual basis beginning in 2030.
WestLight performed all modeling, portfolio selection, and data template preparation internally.
WestLight’s Preferred Portfolio uses the California Energy Commission’s (CEC) 2024 Integrated Energy Policy Report (IEPR) Demand Forecast Update – Planning Forecast adopted on January 21, 2025, as modified by CPUC in the Administrative Law Judge’s Ruling Setting Requirements for Individual Integrated Resource Plans Due June 1, 2026 (subsequently revised with an updated due date of August 10, 2026).
WestLight’s disaggregated demand forecast was provided by the CPUC in the tab “LSE Demand Forecasts” of the “Load Forecasts + GHG Benchmarks” Excel document available on the 2024-2027 IRP Website:
https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/2024-27-irp-cycle-events-and-materials The portfolio uses inputs and assumptions consistent with those used to develop the 2025-2026 Transmission Planning Process (TPP) Portfolio with updates. WestLight’s Preferred Portfolio achieves emissions below the assigned GHG Benchmark for the 8 MMT target. The Preferred Portfolio is described in detail in Section III. Study Results below.
In Decision 24-02-047, the CPUC published its review of WestLight’s 2022 IRP. WestLight’s IRP was found to be adequate in all areas, and was lauded as Exemplary in the following sections:
a) Study Results: Preferred Conforming Portfolios, Local Air Pollutants, Focus on Disadvantaged Communities, Cost and Rate Analysis
b) Action Plan: Proposed Procurement Activities and Potential Barriers 3 https://www.westlightenergy.org/news-releases/peninsula-clean-energy-provides-visa-corporate-campus-100- renewable-electricity/
4 https://www.westlightenergy.org/news-releases/facebook-switches-to-peninsula-clean-energys-eco100/ 345
10 WestLight regularly undertakes an internal resource planning process to support its strategic goals and portfolio planning objectives. Because of the standardized assumptions required in the CPUC IRP process, WestLight’s Preferred Portfolio may differ from the portfolios identified through its internal analysis.
While the portfolios are generally similar in resource composition, where differences exist, WestLight’s internal analysis is designed to better reflect the specific characteristics of its service territory, customer needs, and procurement strategy.
a. Objectives
WestLight’s primary objectives in submitting this IRP are as follows:
1. To demonstrate that WestLight has a plan to meet its CEC 2024 IEPR load forecast through 2045, as modified by the CPUC in the Administrative Law Judge’s Ruling Setting Requirements for Individual Integrated Resource Plans Due June 1, 2026 (subsequently revised with an updated due date of August 10, 2026);
2. To present WestLight’s Preferred Portfolio, which complies with CPUC requirements to meet the 8 MMT by 2045 greenhouse gas emissions target and satisfies reliability requirements in all years of the planning horizon.
Further, WestLight meets both the requirements set out by the CPUC as well as continue to meet the objectives set out by WestLight’s Board, including the voluntary goal to provide 100% renewable energy on an annual basis by 2030 through strategic and cost-effective procurement that can maximize hourly matching of renewable energy to WestLight’s load while prioritizing reducing grid emissions and customer costs.
WestLight has been an early leader in advancing the concept of aligning renewable energy supply with customer demand on an hourly basis, helping to elevate industry understanding of the importance of hourly emissions reductions. Building on this foundation, WestLight is evolving its approach toward a more flexible framework that continues to prioritize emissions reductions while incorporating considerations of affordability and market availability. This refined strategy enables WestLight to make meaningful, incremental progress toward a portfolio capable of meeting its customers’ load on an hourly basis, while leveraging storage dispatch to reduce grid emissions and maintaining a cost-effective, balanced portfolio that supports long-term financial sustainability.
In 2025, WestLight served its load with 100% carbon free resources, including approximately 60% renewable resources and the remaining 40% non-renewable GHG-free energy resources (large hydroelectric and nuclear resources). Looking forward to 2030, WestLight intends to replace the non-renewable GHG-free energy resources in its supply portfolio with renewable resources. Actual annual renewable content percentages may differ from projections, if resource availability or market conditions preclude cost-effective procurement, but the primary goal is to achieve a 100% RPS-eligible renewable supply no later than 2030.
In addition, the WestLight Energy Board has adopted the following specific policies to guide power procurement:
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11 1. WestLight shall not use unbundled renewable energy credits (RECs) for meeting its renewable energy goals.5
2. In sourcing electricity and resource adequacy (RA), WestLight will not procure electricity or resource adequacy from coal facilities.6
3. WestLight has published an Inclusive and Sustainable Workforce Policy.7 WestLight desires to facilitate and accomplish the following objectives through this policy:
a. Support for and direct use of local businesses;
b. Support for and direct use of union members from multiple trades; c. Support for and use of training and State of California approved apprenticeship programs, and pre-apprenticeship programs from within WestLight Energy’s service territory; and d. Support for and direct use of green and sustainable businesses.
4. WestLight’s Energy Risk Policy8 (ERP), which provides a framework for effectively managing risks associated with energy procurement activities.
5. In March 2020, WestLight’s Board voted to prohibit the procurement of Biomass energy9.
WestLight’s goal is to fulfill its open position with a diverse set of contracts. WestLight uses a portfolio risk management approach in its power purchasing program, seeking low-cost supply as well as diversity among technologies, production profiles, project sizes, project locations, counterparties, term lengths and timing of market purchases to cost average over time, including remaining cognizant of the value of open market positions. These factors are taken into consideration when WestLight engages the market, and WestLight has developed specific guidelines for each of these diversification factors.
In 2024, WestLight’s Board adopted its Energy Risk Policy, which establishes a formal governance and risk management framework for energy procurement activities, including identification and categorization of key risk exposures such as market, counterparty, operational, and regulatory risks. The policy defines a structured system of internal controls, including segregation of duties across front, middle, and back-office functionsto ensure effective risk monitoring, compliance, and reporting. It also delineates roles and responsibilities across the organization, including oversight by WestLight’s Board and Risk Oversight Committee (ROC), and establishes delegated authorities and transaction limits to ensure that procurement activities are executed within defined risk tolerances and in alignment with organizational objectives.
5 WestLight policy on unbundled RECs: https://www.westlightenergy.org/wp-content/uploads/2017/01/PCE-Policy-11-final.pdf 6 WestLight policy excluding coal for power and resource adequacy: https://www.westlightenergy.org/wp-content/uploads/2017/01/Policy-12-Excluding-Coal-for-Power-and-Resource-Adequacy.pdf 7 WestLight Sustainable Workforce Policy: www.westlightenergy.org/wp-content/uploads/2024/11/Policy-10- Inclusive-and-Sustainable-Workforce-April-2023-.pdf
8 https://www.westlightenergy.org/wp-content/uploads/2025/02/Policy-23-Energy-Risk-Policy-November-2024.pdf 9 https://www.westlightenergy.org/wp-content/uploads/2020/04/2020-04-23-PCE-BOD-Agenda-Packet-updated.pdf 347
12 In 2025, WestLight conducted an internal planning process to inform key aspects of its procurement strategy. The outcomes of this process include the following:
Battery Operations: Operate WestLight’s dispatchable resources to maximize grid benefits using CAISO market signals in order to reduce grid emissions, maximize market value, and provide clean dispatchable capacity when the grid needs it.
Renewable vs. Carbon-Free: Maintain WestLight’s goal of achieving 100% renewable energy on an annual basis by 2030.
Contract Term Length: Target a portfolio mix in which approximately 60-85% of resources are secured through mid- and long-term contracts (greater than five years), with the remainder procured through short-term contracts.
Annual Long-Term Procurement Limit: Limit annual mid- and long-term procurement to no more than 20% of loss-adjusted load, with a recommended maximum contract term of 25 years. b. Methodology
a) Modeling Tool(s)
The 2026 IRP analysis was conducted using a modeling tool that WestLight developed to identify the lowest-cost portfolio of contracted renewable energy and energy storage resources that could match its customer demand on a 24/7 basis, called the MATCH (Matching Around-the-Clock Hourly energy) model.
The MATCH model is a deterministic portfolio optimization tool that determines the cost-optimal selection and dispatch of resources to meet load based on a set of assumptions and operating restrictions.
This portfolio and dispatch optimization model is based on the software architecture of an existing, open-source power system planning model called SWITCH10, but has been substantially redesigned to meet the needs of modeling time-coincident renewable power portfolios for entities like WestLight.
Some key features of MATCH are:
• Cost-optimal resource selection and dispatch
• Ability to match supply and demand on an hourly basis • Easy-to-use weather-correlated resource generation profiles • Ability to dispatch storage either to meet load or to respond to market signals The key inputs to the MATCH model are:
• Hourly load forecast
• Hourly market prices at each modeled node
• Available resource characteristics and costs (model can automatically develop resource generation profiles, or a user may enter a specified resource generation profile) • Resource adequacy requirements
10 The SWITCH model is available at switch-model.org/
348
13 Once the cost-optimal portfolio was selected in MATCH, staff used the proprietary PowerSIMM software, developed by Ascend Analytics, to perform a stochastic evaluation of the selected portfolio under a variety of possible weather patterns and market prices.
In order to develop some of the inputs required for the modeling, WestLight Energy used Ascend Analytics’ AscendView fundamental forecast released in January 2026. The AscendView fundamental forecast is updated twice a year and takes into account fundamental macro-level drivers such as market and regulatory structure, current federal and state policies, technology costs, and load forecasts. AscendView provides a forecast of market prices and a supply stack forecast for resource builds and retirements.
The CPUC used RESOLVE to develop the 2025-2026 TPP with updates, which identifies the new resources needed to meet the 8 MMT by 2045 GHG emissions target.
Both RESOLVE and AscendView are forecasting significant renewable resource capacity additions in future years to meet California’s emissions reductions targets, with over 9 GW of new wind, 37-53 GW of new solar, and about 20 GW of new storage resources added to CAISO by 2035. Although there are differences between the two supply stacks, WestLight does not expect the use of AscendView forecasts to cause significant differences in the selected resources in its Preferred Portfolio, versus what might have been selected if it relied only on RESOLVE outputs. Moreover, by using the AscendView forecasts, WestLight can use the hourly nodal price forecasts developed by Ascend Analytics, which enables it to do sophisticated hourly dispatch modeling of its selected portfolio.
Figure 2: Comparison of AscendView and RESOLVE Build Assumptions MATCH and RESOLVE both optimize dispatch for a system under a given set of deterministic inputs.
RESOLVE is a linear optimization model, which assesses dispatch based on representative days over a defined forecast horizon. MATCH differs in that it is a mixed integer program and performs hourly chronological dispatch for all 8760 hours in a simulation year. Both RESOLVE and MATCH identify the optimal resources to meet needs based on the available resources including generation and storage. Both models allow for the incorporation of different types of market and portfolio constraints including 349
14 renewable generation targets, capacity requirements and reserve margins, and timing of new build requirements. MATCH is further configurable to optimize for hourly renewable targets.
Table 4 below identifies the key differences between CPUC’s RESOLVE and WestLight’s MATCH modeling approaches.
Table 4: Differences Between RESOLVE and MATCH Modeling Approaches
RESOLVE MATCH
Groups resources into categories with similar
operational characteristics (e.g., nuclear, coal, gas
CCGT, gas peaker, renewables, storage, and
demand-side resources) and models them
collectively, while capturing key operational
constraints.
Models each generator independently.
Linearized unit commitment where the
commitment variable for each class of generators
is a continuous variable rather than an integer
variable.
Models the operating cost and performance
parameters on a plant-level basis, where the
optimization method uses a mixed integer
program (MIP) to determine capacity build of
each resource, and the hourly dispatch of each
resource.
Run for a sampled set of representative days to
approximate full-year operations, uses
representative load and renewable profiles to
reflect system conditions.
Modeled 8760 hours for each of the study years
(2028, 2030, 2035, 2040, and 2045)
Models an entire market, in this case primarily
CAISO, using a multi-zone framework that
represents transmission flows, interties, and
interactions with neighboring regions.
MATCH was used to model WestLight’s portfolio
within the CAISO market and does not model
transmission constraints or CAISO
import/exports. For this analysis, WestLight used
the AscendView fundamental forecast to provide
the background CAISO market assumptions and
modeled its portfolio within the market.
Allows for the incorporation of annual renewable
and clean energy targets.
Allows for the incorporation of annual renewable
generation goals or for hourly load-matching
renewable generation goals
b) Modeling Approach
WestLight took an iterative approach to modeling, as illustrated in Figure 3 below. First, WestLight designed scenarios to run in the MATCH model. After running the model, the results were examined and often led back to redesigning the scenarios. Once WestLight developed the appropriate scenarios and ran the MATCH model, it used the selected portfolio from MATCH as inputs into the PowerSIMM model to perform stochastic analysis of its portfolio’s performance. The evaluation of the stochastic performance could lead back to redesigning the scenarios. In this way, the modeling process was iterative until the final results were reached.
350
15 Figure 3: WestLight Energy Modeling Approach
WestLight used assumptions consistent with the 2024-2027 IRP Filing Requirements, with some modifications as described below. WestLight used its voluntary renewable and GHG-free goals, which exceed the RPS targets. Specifically, WestLight’s portfolios are designed to provide energy entirely from renewable and carbon free resources in years 2026 through 2029, and to provide 100% renewable energy on an annual basis in 2030 and later years.
Some key assumptions that are standardized by the Filing Requirements are the assigned load forecast, Reliability Procurement Requirement (RPR), and behind-the-meter solar capacity. WestLight used the annual volumes assigned by the Filing Requirements but used a customized load shape. WestLight used the Reliability Procurement Requirements as provided by the CPUC.
WestLight assumed resource availability consistent with the 2026-2027 TPP, with some updated assumptions regarding resource cost, based on its most recent procurement efforts. Resource costs were based on WestLight’s assessment of the market conditions as of the spring of 2026, including the impacts of the One Big Beautiful Bill Act (OBBBA).
WestLight developed a single conforming portfolio that achieves emissions that are less than the 8MMT by 2045 GHG target.
351
16 Figure 4: Comparison of RPS Target to WestLight Energy’s Internal Renewable Goals
Specific details on the modeling approach and assumptions are described in the sections below.
1. Load Assumptions
WestLight’s annual load forecast and load modifier volumes assume the California Energy Commission’s (CEC) 2024 Integrated Energy Policy Report (IEPR) demand forecast as modified by the CPUC in the Administrative Law Judge’s Ruling Setting Requirements for Individual Integrated Resource Plans Due June 1, 2026 (subsequently revised with an updated due date of August 10, 2026).
Table 5: CEC 2024 IEPR Assigned Load (Managed Retail Sales) Forecast for WestLight Energy WestLight Energy 2028 2030 2035 2040 2045
Load Forecast (GWh) 3,899 4,452 5,998 7,181 7,957
WestLight evaluated the projected load in the CEC 2024 IEPR demand forecast and the load profile in the CSP Calculator against internal forecasts. WestLight’s internal load forecast is developed based on historical hourly meter data, and projections of future growth, including growth of electric vehicles and behind-the-meter rooftop solar. Figure 5 compares WestLight’s load forecast with the CEC’s 2024 IEPR forecast, with the differences decomposed into baseline load and load modifier components. 352
17 Figure 5: CEC and WestLight Energy’s Internal Load Forecasts to 2045 and Sources of Differences WestLight Energy’s internal load forecast is lower than the IEPR forecast, particularly in the later years of the forecast period from 2035 to 2045. The difference is primarily driven by the CEC’s assumptions for higher baseline consumption growth and greater EV load in later years, though these impacts are partially offset by the CEC’s higher estimates of behind-the-meter solar PV capacity. WestLight incorporates the effects of energy efficiency, building electrification, and climate change directly into its baseline load forecast rather than modeling them as separate load modifiers. WestLight does not assume significant data center load growth within its service territory, which differs from statewide forecasting assumptions.
This assumption is based on WestLight's assessment of local land availability, development trends, and real estate costs, as well as the absence of indications from customers, local jurisdictions, and PG&E that significant data center development is anticipated within its service area.
Additionally, WestLight’s load shape differs significantly from the shapes in the CSP Calculator, due primarily to WestLight’s service territory including the mild coastal climate of the San Francisco Peninsula in the Bay Area, which results in relatively higher winter load than those represented in the CSP Calculator.
In order to model a conforming portfolio while still incorporating load shape from its internal forecast, WestLight used the CSP Calculator to develop a load profile that assumes the annual volumetric load and load modifier volumes assigned to WestLight by the CPUC (Managed Retail Sales Forecast, Behind-The-Meter Photovoltaics (BTM PV) Forecast, Electric Vehicle Load, Building Electrification, Energy Efficiency, Data Center Load, Climate Change Load Impact, and Behind-The-Meter Storage Losses), but uses custom shapes consistent with WestLight’s internal forecast for Baseline: Non C&I shape, Baseline: C&I shape, Electric Vehicle Load shape, and Behind-The-Meter Photovoltaics shape. WestLight also specified a custom C&I Fraction of Baseline Demand. Figure 6 demonstrates the differences in load shape between WestLight’s internal forecast, the default load shape in the CSP Calculator, and the customized load input that WestLight used for modeling. This figure shows average hourly load for each month of the year in 2035. WestLight’s forecasted load shape is higher in the winter months and lower in the summer months than the default CSP Calculator load profile.
353
18 Figure 6: 2035 Average Hourly Load by Month
The behind-the-meter solar capacity assumed was based on the forecast assigned by the CPUC.
WestLight’s estimates of behind-the-meter solar capacity (based on interconnection data) are lower than the assigned capacity.
Table 6: CPUC Assigned Behind-The-Meter Solar Capacity (MW) Reporting Year 2028 2030 2035 2040 2045
Assumed Behind-The-Meter Solar Capacity 386 419 515 584 652
2. Reliability Procurement Requirements
WestLight used the Reliability Procurement Requirements (RPR) assigned by the CPUC. Table 7 identifies the RPR for each of the reporting years. In the 2024-2027 IRP, resource capacity was modeled using a perfect capacity methodology, and a marginal effective load carrying capacity. Under this approach, LSE obligations are defined through RPR rather than peak load, and a planning reserve margin is not used.
Table 7: Assigned Reliability Procurement Requirements
Reporting Year 2028 2030 2035 2040 2045
RPR (MW) 807 674 808 956 1,078
3. GHG Benchmark
WestLight’s LSE-specific GHG Benchmarks for the 8 MMT target, as assigned in the ALJ Ruling and adjusted by the Energy Division in the CSP Calculator to account for WestLight’s share of state-wide behind-the-meter combined heat and power emissions, are identified in Table 8 below. 354
19 Table 8: LSE Specific GHG Emissions Benchmark
2030
(MMT)
2035
(MMT)
2040
(MMT)
2045
(MMT)
GHG Emissions Benchmark – 8 MMT
Conforming Portfolio 0.359 0.310 0.280 0.151
4. Other Assumptions
The inputs and assumptions used to develop and analyze WestLight’s 2026 IRP portfolio are consistent with the 2024-2027 Filing Requirements. Significant input and assumptions data include:
• Load forecast
• Market cost of load
• Resources available to contract
• Resource contract costs
• Resource generation profiles
• Market revenue of resource generation
• Reliability requirements
• Qualifying capacity of resources
• Resource adequacy market value
• State and internal RPS targets
• Renewable energy attribute market value
In developing candidate resources for the 2026 IRP, WestLight modeled specific generators that had offered into recent solicitations, as well as generic resources with contract costs consistent with the RESOLVE model outputs for the 2026-2027 TPP, which incorporates the policy impacts of the OBBBA and tariffs. In addition, WestLight restricted the availability of certain generic resource types to reflect its assessment of market conditions as of spring 2026. Notably, WestLight did not include onshore wind or geothermal resources as eligible resources in its model until 2035.
Table 6: Generation candidate resource contract cost assumptions used for WestLight’s 2026 IRP (Nominal PPA $/MWh)
Resource
Technology 2028 2030 2035 2040 2045
Solar PV $54-$65 $62-$70 $59-$67 $58-$66 $58-$65
Onshore Wind (in-state) N/A N/A $84-$148 $156 $165
Onshore Wind (Out-of-State) N/A N/A $114-$151 $122-$162 $130-$175 Offshore Wind N/A N/A N/A $294 $247-$298
Conventional
Geothermal (Existing) N/A N/A $90 $90 $90
Conventional
Geothermal (New) N/A N/A $102-$157 $113-$220 $171-$239
EGS Geothermal
(New) N/A N/A $125-$195 $125-$285 $304-$309
355
20 Table 7: Storage resource contract cost assumptions used for WestLight’s 2026 IRP (Nominal$/kw-mo) Resource Technology 2028 2030 2035 2040 2045
4 hr Storage (Paired with
Solar PV) $14.22 14.35 $15.47 $20.52 $21.06
4hr Storage (Stand-Alone) $14.22 $14.35 $15.47 $20.52 $21.06 8hr Storage (Stand-Alone) $20.70 $24.07 $25.70 $34.60 $35.32 12hr Storage (Stand-Alone) N/A N/A $45.41 $67.41 $69.91 24hr Storage (Stand-Alone) N/A N/A $56.20 $82.90 $85.14 100hr Storage (Stand-Alone) N/A N/A $63.51 $92.04 $94.49 Premiums for index-plus structured contracts for Portfolio Content Category 1 (PCC1) REC resources were developed based on AscendView and WestLight’s evaluation of current market conditions as of spring 2026. Because reselling RECs is an important risk reduction technique, and the ability to resell RECs is uncertain, WestLight differentiated between purchase cost and sale value of PCC1 index-plus contracts in its modeling. These prices are identified in Table 11 below.
Table 8: PCC1 Premium Costs Assumptions for Index-Plus Structured Contracts (Nominal$/MWh) 2028 2030 2035 2040 2045
PCC 1 - Buy
Premium ($/MWh) $19.00 $22.41 $18.37 $20.32 $25.31
PCC 1 - Sell
Premium ($/MWh) $17.10 $20.17 $16.53 $18.29 $22.78
Contract costs for short term resource adequacy contracts were developed based on AscendView and WestLight’s evaluation of current market conditions as of spring 2026. Because reselling excess resource adequacy is an important risk reduction technique in its Preferred Portfolio, and the ability to resell resource adequacy in the future is uncertain, WestLight differentiated between the purchase cost and sale value of RA. The MATCH model uses shaped costs over the course of a year, with September as the highest value month.
Table 12 summarizes the September RA market value assumed in WestLight’s modeling.
Table 9: Resource Adequacy Costs Assumptions for Short-Term RA-only Contracts (Nominal$/kw-mo) 2028 2030 2035 2040 2045
September RA – Buy $19.75 $21.33 $23.49 $53.62 $60.26
September RA – Sell $17.78 $19.20 $21.14 $48.26 $54.23
5. Existing Contracts
WestLight included all power purchase agreements (PPAs) currently under contract or in negotiation as of March 30th, 2026, in its modelling. These PPAs are identified in Table 13 below. 356
21 Table 10: Existing Project-Specific PPA Contracts
# Asset Name Capacity
(MW)
Storage
Depth
(MWh)
PPA Start
Date
Contract
Expiration Technology
1 Bidwell 2 03/09/17 03/08/34 Small Hydro
2 Roaring 2 03/16/17 03/15/34 Small Hydro
3 Hatchet 7.5 03/09/17 03/08/37 Small Hydro
4 Clover 1 04/01/18 03/31/33 Small Hydro
5 Mustang 100 11/11/20 11/10/35 Solar
6 Wright 200 01/03/20 01/02/45 Solar
7 Sky River B 30.2 09/17/21 09/16/41 Wind
8 Geysers 35 07/01/22 06/30/32 Geothermal
9 Heber 2 26 01/01/23 12/31/38 Geothermal
10 Chaparral
Solar 102 01/01/23 12/31/38 Solar
11 Chaparral
Storage 52 208 04/01/25 03/31/40 Storage
12 Arica Solar 100 04/01/25 03/31/40 Solar
13 Arica Storage 50 200 04/01/24 03/31/41 Storage
14 Tumbleweed 14.8 118 06/01/26 05/30/41 8hr Storage
15 OME Fishlake 2.3 07/01/27 06/3/47 Geothermal
16 Ormat
Portfolio 11 06/01/28 09/30/44 Geothermal
17 Dos Palos 3 08/01/23 07/31/43 DAC-GT Solar
18 Voyager 63.2 01/01/21 12/31/28 Wind
19 Shiloh 150 01/01/24 12/31/30 Wind
20 Buena Vista
Extension 38 01/01/23 12/31/27 Wind
357
22 21 Darden III
Solar 42.3 6/1/28 5/31/38 Solar
22 Darden III
Storage 45.7 183 6/1/28 5/31/38 Storage
23 Darden IV
Solar 42.3 6/1/28 5/31/38 Solar
24 Darden IV
Storage 45.7 183 6/1/28 5/31/38 Storage
25 Burney Creek 3 1/1/24 12/31/38 Small Hydro
26 Calwind 8.7 1/1/23 12/31/28 Wind
27 Sunzia 220 6/1/26 5/31/41 Wind
28 Coram 13.5 3/1/26 2/28/31 Wind
29 Sand Hill 50 4/1/28 3/31/43 Wind
30 Whitegrass 6 1/1/28 12/31/47 Geothermal
31 Nova 50 200 8/1/24 7/31/39 4 hr Storage
32 Lockhart 45 180 7/10/24 7/9/39 4 hr Storage
33 Gabriel 4 hr 65 260 6/1/27 5/31/42 4 hr Storage
34 Gabriel 8 hr 10 80 6/1/27 5/31/42 8 hr Storage
35 Wright
Storage 80 320 6/1/26 5/31/46 4 hr Storage
36 Willow Rock 15 120 12/31/30 12/30/50 8 hr Storage
In addition to the executed PPAs, existing Resource Adequacy (RA) contracts and environmental products were included in the model. In its modeling, WestLight assumed contract extensions for several existing resources in its current portfolio, including the wind resources Sunzia Wind, Voyager Wind, and Shiloh Wind, as well as the Geysers geothermal resource.
WestLight also accounted for the costs and benefits of the cost allocation mechanism (CAM) resources in its portfolio. For CAM resources, WestLight relied on the most recent CPUC-approved allocation data available at the time of analysis. For 2026, CAM values reflect the final CAM allocations and requirements published by the CPUC for the Resource Adequacy compliance year. For 2027 and subsequent years, CAM allocations were estimated using 2026 CAM allocation values and load share information as the basis for future-year projections. In particular, Central Procurement Entity (CPE) CAM allocations were estimated by applying WestLight's final 2026 monthly load share percentage to projected CPE procurement quantities for the applicable compliance year for the month of September. These estimates are intended to approximate future CAM allocations until updated CPUC allocation data become available. 358
23 CAM allocations may consist of a variety of resource types, including hydroelectric resources and thermal generation resources, such as combined-cycle and peaking natural gas facilities. For purposes of this analysis, WestLight assumed future CAM allocations would be consistent with the resource mix it has historically received through September CAM allocations, which are associated with thermal generation resources. Accordingly, WestLight modeled its CAM allocation using its proportional share of PG&E's September CPE system CAM resources, which consist of combined-cycle and peaking natural gas facilities.
Because CAM resources are allocated by the CPUC, load-serving entities cannot decline these allocations and must account for them in their portfolio planning regardless of whether the resources align with their preferred procurement strategy.
6. Renewable Generation and Storage Profiles
WestLight used renewable generation profiles and storage dispatch profiles generally consistent with the profiles used by staff to develop the 2025-2026 TPP with updates. WestLight generated resource profiles for specific resources in the MATCH model using the National Laboratory of the Rockies (NLR) System Advisory Model (SAM). By using the System Advisory Model, all of the resource profiles were generated using consistent weather assumptions. This improves the correlation between resource profiles for purposes of modeling. For new generic resources, WestLight used the profiles provided in the RESOLVE code base and inputs.
The solar resource profiles used in WestLight’s modeling are similar to the solar profiles provided by the CPUC in the CSP Calculator. Figure 7 compares the differences in the resource profiles. The WestLight Solar graphed below represents the generation-weighted average capacity of WestLight’s solar portfolio, which includes a mix of SAM shapes, for specific resources in its portfolio, and RESOLVE shapes, for new generic candidate resources.
359
24 Figure 7: Comparison of Solar Tracking Shapes
The wind resource profiles used in WestLight’s modeling are very similar to the wind profiles provided by the CPUC in the CSP Calculator. WestLight used the profiles provided by the CPUC for offshore wind and new onshore candidate resources, and wind profiles provided by project developers or NLR SAM profiles for existing, contracted wind resources. Figure 8 compares the differences in the resource profiles.
Figure 8: Comparison of Wind Shapes
360
25 WestLight’s strategy is to operate its storage to maximize grid benefits using CAISO market signals, which maximizes market revenue, provides ramping and clean dispatchable capacity when the grid needs it most, and results in greater marginal emissions reductions compared to load-following storage dispatch.
To determine storage dispatch, the MATCH model uses hourly nodal price forecasts for each storage node.
Storage resources are dispatched to charge during periods of lower prices and discharge when prices are higher to maximize economic value. Thus for the current IRP modeling, MATCH uses a dispatch-to-price versus a dispatch-to-load methodology to determine storage dispatch.
Figure 9: Comparison of Storage Dispatch
7. Geographic Distribution of New Resources
As described in the previous section, WestLight assumed resource availability based on specific resources offered in recent solicitations, as well as generic resources consistent with the 2026-2027 TPP. Specific resources have a known project location and can be grouped into geographic areas. Generic resources are assumed to be located within the geographic regions indicated in the 2026-2027 TPP.
WestLight’s analysis took into account the different resource contract cost and resource generation market revenue forecasts for different geographic areas. Resources costs reflect the development costs such as site control, labor, materials, financing and developer profit and are representative of the power purchase agreement contract costs that WestLight expects to encounter in the market. Transmission constraints were not explicitly modeled, and were evaluated in a post-processing step, as described below in Section III. m. Transmission Planning. In some cases, transmission constraints make capacity additions in specific geographic locations more costly and would lead to a different geographic distribution of new resource additions. WestLightstrongly supports the implementation of transmission expansion to support the addition of renewable capacity to the CAISO system in regions with promising renewable resource potential.
361
26 The tables below summarize the distribution of new resources into high-level geographic areas based on CPUC’s RESOLVE areas. These tables include capacity from energy-only contracts.
Table 11: Preferred Portfolio Geographic Distribution of New Solar & Storage Resources (Cumulative MW, decreases represent expiration of existing contracts) RESOLVE Area 2028 2030 2035 2040 2045
PGE Fresno – Solar 84.56 84.56 84.56 0 0
PGE Fresno – Storage 171.5 171.5 171.5 80 80
SCE Metro – Storage 75 75 75 75 0
SCE Northern – Solar 0 314 314 434 663.5
SCE Northern – Storage 0 314 329 449 678.5
Total 331.0 959.0 974.0 1,038.1 1,421.9
Table 12: Preferred Portfolio Geographic Distribution of New Wind Resources (Cumulative MW) RESOLVE Area or
Location 2028 2030 2035 2040 2045
PGE GBA 0 0 22 22 22
PGE Kern 0 0 22 22 22
PGE NE CA 0 0 0 0 51
PGE NGBA 50 50 245 245 245
SCE Eastern 0 0 72 72 72
SCE EOP 0 0 21 21 21
SCE NOL 0 0 108 108 108
SCE Northern 0 0 214 214 214
SDGE Imperial 0 0 85 85 85
Wyoming 0 0 0 330 400
Total 50 50 789 1,119 1,240
Table 13: Preferred Portfolio Geographic Distribution of New Geothermal Resources (Cumulative MW) RESOLVE Area or
Location 2030 2035 2040 2045
Nevada 13.8 13.8 13.8 13.8
Northeast CA 0.0 8.4 8.4 83.1
PGE NGBA 0.0 12.3 172.2 200.9
SCE NOL 0.0 16.8 16.8 16.8
SCE Eastern 0.0 3.4 3.4 3.4
SDGE Imperial 5.47 5.47 5.47 5.47
Total 19.3 60.1 220.0 323.4
362
27 8. Short-Term Contracts
WestLight’s strategic procurement goals include targeting a diversity of contract term lengths to help manage portfolio risk. The inclusion of short-term contracts in a portfolio allows flexibility to manage changes in load, regulatory uncertainty, changing goals, and changes in market conditions. WestLight’s current strategic target is for short-term contracts, defined as less than five years in length, to make up between 15% and 40% of its portfolio.
In the near term, WestLight plans to rely on short-term contracts to provide energy-only volumes of large hydroelectric energy in years 2026-2029. WestLight also uses short-term contracts to procure resource adequacy under capacity-only contracts.
New resources typically require a long-term contract in order to be financed. Because WestLight’s Preferred Portfolio includes mostly new resources to be added to its current portfolio, there is a disconnect between its short-term contracting goals and its plans to add new resources to its portfolio.
WestLight could address this disconnect by seeking short-term contracts, potentially with existing resources instead of new resources. This disconnect between the risk-reduction benefits of short-term contracts, and the emissions reductions benefits of long-term contracts, will challenge all load serving entities in the state as California works towards the zero-emissions goals of SB100. To achieve zero emissions in state-wide retail electricity sales will likely require load-serving entities to develop significant new resources via long-term contracts (long-term contracts are necessary to facilitate the financing of new resources). However, adding significant volumes of energy via long-term contracts will potentially be in conflict with those load-serving entities’ risk-reduction goals of limiting the proportion of long-term contracts in their portfolios and potentially increase customer costs. State-wide, the CPUC must be mindful of this fundamental conflict of risk reduction, affordability, and emissions reduction goals as Load Serving Entities navigate these issues.
9. Curtailment
WestLight assessed potential curtailment of resources in its Preferred Portfolio using a stochastic model in PowerSIMM. The model considers nodal prices to determine whether to curtail solar, wind, and other non-dispatchable resources on an hourly basis. WestLight tested two potential curtailment strategies:
curtailment at negative nodal prices and curtailment when the nodal price is below the negative REC price.
WestLight evaluated the curtailment level that has a 5% chance of being exceeded (P95), the curtailment level that has a 95% chance of being exceeded (P5), and the curtailment level that has a 50% chance of being exceeded (P50, or median). Table 17 below shows the P5, P50, and P95 curtailment estimates of the Preferred Portfolio in PowerSIMM.
The estimated curtailment of the portfolio is highest in 2030, when solar generation makes up the highest proportion of the portfolio. Given higher estimated energy prices for future years and increased proportion of wind and geothermal production in the portfolio, PowerSIMM calculates relatively little curtailment in the later model years. Under the strategy of curtailing production only when the nodal price is below the negative REC price (forecasted to be around $20 in future years), almost no curtailment occurs. The nodal price forecasts used in WestLight’s modeling incorporate fundamental market drivers such as new renewable capacity additions to the system. However, if the fundamental market drivers change, or if fuel prices decrease, WestLight would expect the modeling results to change.
WestLight also assessed curtailment of its portfolio using the CSP Calculator. The CSP Calculator uses SERVM modeling performed by the CPUC to estimate hours in which excess generation on the system will 363
28 be curtailed. The CSP Calculator estimates larger volumes of curtailment for the portfolio relative to PowerSIMM modeling from 2035-2045.
Table 17: Percent of Generation Curtailed under Different Curtailment Strategies Curtailment
Strategy Probability 2028 2030 2035 2040 2045
Curtail at
Negative
Pricing
Median (P50) 7.2% 14.7% 1.2% 1.2% 0.9%
Lower Curtailment (P5) 3.9% 6.1% 0.1% 0.1% 0.2%
Higher Curtailment (P95) 9.9% 16.8% 1.7% 1.9% 1.6%
Curtail at
Negative REC
Value
Median (P50) 0.3% 0.2% 0.3% 0.4% 0.1%
Lower Curtailment (P5) 0.0% 0.0% 0.0% 0.0% 0.0%
Higher Curtailment (P95) 1.4% 1.0% 1.0% 0.8% 0.4%
CSP
curtailment 6.4% 11.4% 10.6% 8.0% 9.5%
10. Metric Analysis
WestLight evaluated the model outputs using several key metrics. These metrics included cost, reliability, and RPS and emissions metrics.
Cost Metrics
WestLight evaluated portfolio cost on both an absolute and per-unit basis using the results of its stochastic analysis, allowing it to estimate the probability that portfolio costs will exceed specified levels. WestLight evaluated the P95 cost, the P5 cost, and the P50, or median cost. • Portfolio Total Cost ($)
• Weighted Average Cost to Serve Load ($/MWh)
• Probability of Cost Exceedances (P5, P50, P95)
Reliability Metrics
WestLight evaluated its Preferred Portfolio using two distinct reliability metrics: an annual analysis based on its assigned Reliability Procurement Requirements and an evaluation of its portfolio using the CPUC’s 24-hour Slice-of-Day RA Framework.
For the annual analysis of reliability, WestLight compared its assigned annual Reliability Procurement Requirement to the Net Qualifying Capacity of its portfolio in September to determine the open RA balance per the calculations in the Resource Data Template. The reliability metrics include the following:
• Surplus/Short megawatt (MW) compared to assigned Reliability Procurement Requirement The second reliability metric was to evaluate the portfolio using the CPUC’s 24-hour Slice-of-Day RA Framework. WestLight evaluated its Preferred Portfolio under the Slice-of-Day methodology using its share of the Total Reliability Need (TRN) from the IRP Filing Requirements to assess portfolio performance under this framework. The reliability metrics include the following:
• Comparison of 24-hr resource adequacy requirements vs supply, represented graphically 364
29 RPS and Emissions Metrics
WestLight evaluated the RPS content and the emissions associated with its portfolio. WestLight determined the RPS content as well as the long-term contract content (SB350 requires 65% of an LSE’s RPS content to be procured via a long-term contract of at least 10 years). WestLight also evaluated the carbon dioxide emissions associated with its portfolio using the CSP Calculator. These metrics can be summarized as:
• Long-term Contracting (% of Load);
• RPS Content (% of Load)
• Carbon Dioxide Emissions (MMT per year)
c) Alternative Assumptions
The alternative assumptions used in WestLight’s modeling are described throughout Section II.b and are therefore not repeated here in detail. In general, WestLight relied on the assumptions published in the CPUC’s 2025 Inputs and Assumptions document except where more recent, portfolio-specific, or resource-specific information was available and deemed more appropriate for evaluating WestLight’s Preferred Portfolio.
The primary differences from the CPUC assumptions relate to load profiles, resource production profiles, and resource costs. WestLight utilized a custom hourly load shape that reflects the characteristics of its customer load while maintaining consistency with the total annual load volumes assigned by the CPUC.
For existing and contracted resources included in WestLight’s portfolio, it utilized resource-specific production profiles, including profiles developed using the National Laboratory of the Rockies’ System Advisor Model, while generic candidate resources continued to use CPUC-provided generation profile assumptions. WestLight also utilized cost assumptions from the 2026-2027 TPP, which incorporates more recent market information and federal policy developments than the 2025-2026 TPP with updates. In addition, WestLight incorporated resource-specific cost information where available from recent solicitations and procurement activities, particularly for geothermal resources. Collectively, these alternative assumptions were intended to better reflect WestLight’s specific portfolio characteristics and current market conditions, which influenced the relative attractiveness of certain resource types in the Preferred Portfolio.
Table 18. CPUC and WestLight Geothermal Nominal PPA price assumptions 2026-2027 TPP WestLight Energy
Resource Type Region 2035 2040 2045 2035 2040 2045
Conventional
Geothermal
Northeast
CA $157 $220 $229 $102 -$157
$155 -
$220
$171 -
$229
Conventional
Geothermal
PGE NGBA $143 $207 $224 $102 -
$143
$113 -
$207
$171 -
$224
Conventional
Geothermal
SCE NOL $143 $207 $224 $110-
$143 $207 $224
Conventional
Geothermal
SCE Eastern $143 $207 $224 $102 -
$143 $207 $224
Near field EGS NorCal $182 $272 $294 $125 -
$195
$125 -
$285
$294 -
$309
365
30 III. Study Results
a. Conforming and Alternative Portfolios
WestLight’s Preferred Portfolio uses the assigned load forecast and uses inputs and assumptions consistent with those used by staff to develop the 2025-2026 TPP with updates to identify the least cost set of resources to meet the respective 2030, 2035, 2040, and 2045 GHG Benchmark emissions, as calculated by the CSP Calculator. WestLight developed a single portfolio that meets the emissions targets and is presenting this portfolio as its Preferred Portfolio. The Preferred Portfolio achieves lower emissions than WestLight’s proportional share of the 8 MMT GHG target. The load, GHG Benchmarks, and calculated GHG emissions for the portfolio, using the CSP Calculator, are presented in Table 19 below.
Table 19: Preferred Portfolio GHG Emissions Results
2028 2030 2035 2040 2045
Assigned Load Forecast (GWh) 3,899 4,452 5,998 7,181 7,957 8 MMT GHG Benchmark (MMT CO2) 0.359 0.310 0.280 0.151
WestLight Preferred Portfolio Emissions
(MMT CO2) 0.131 0.226 0.253 0.212 0.150
The Preferred Portfolio includes all of WestLight’s currently executed contracts, as summarized in Table 13 above.
Net of contract expirations, the Preferred Portfolio adds an additional 561 MW of storage, 358 MW of solar, 536 MW of in-state onshore wind, 400 MW of out-of-state onshore wind, and 297 MW of geothermal by 2045. Due to contract expiration, the Preferred Portfolio results in 15 MW less small hydro in 2045 than is currently contracted. The selected capacity results in the lowest cost portfolio that meets WestLight’s internal voluntary targets, and the assigned reliability and emissions targets. Figure 10 shows the annual cumulative capacity of the portfolio.
366
31 Figure 10: Preferred Portfolio Cumulative Capacity
Figure 11 shows how WestLight meets its load in each year from a combination of existing PPAs, new resources, short-term renewable contracts and market purchases.
Figure 11: Preferred Portfolio Load and Generation
WestLight’s Preferred Portfolio includes existing resources under contract, existing resources that it plans to contract with in the future, new resources under contract (expected to commence deliveries in 2026 and later), and new resources that it plans to contract with in the future. Existing resources are defined consistent with the definition used in the 2024-2027 IRP Filing Requirements Narrative Template and Resource Data Template (RDT), that is, resources in the RDT with contract statuses of “online” and 367
32 “planned existing.” New resources are defined consistent with the definition used in the 2024-2027 IRP Filing Requirements Narrative Template and RDT, that is, resources in the RDT with contract statuses other than “online” and “planned existing,” or rather, resources that are not online as of the IRP submission date of August 10, 2026.
The figures below provide a summary of the existing and new resources currently in WestLight’s portfolio, and those planned to be added between 2028 and 2045. Additional details are provided in the Resource Data Template.
Figure 12: Existing Resources in WestLight’s Preferred Portfolio 368
33 Figure 13: New Resources in WestLight’s Preferred Portfolio WestLight is not submitting an alternative portfolio.
Comparison to 2025-2026 Transmission Planning Process (TPP) Portfolio with Updates WestLight compared the new capacity assumed in the 2025-2026 TPP Portfolio with updates to the new capacity selected in its Preferred Portfolio. WestLight used its load share as calculated on the “Demand Inputs” tab of the CSP Calculator, which compares WestLight’s annual retail sales volume to the entire CAISO system demand volume. WestLight’s load share is approximately 1.7-2.1% depending on the model year.
As shown in Figure 14 below, WestLight’s Preferred Portfolio results in a similar amount of total new capacity built compared to its load share of the 2025-2026 TPP. WestLight is planning for more new storage, wind and geothermal capacity than its load share of the 2025-2026 TPP would imply, and less solar capacity. WestLight did not constrain its modeling to procure only its proportional share of the wind and geothermal resources identified in the TPP. Instead, WestLight limited the availability of in state wind resources such that wind would not make up more than 50% of its generation portfolio. When selecting resources to contract, WestLight seeks to maintain a diverse portfolio that aligns with its load profile.
WestLight utilized a custom load shape when developing its Preferred Portfolio, which includes higher winter peaks and lower summer peaks than the default CSP load profile. Wind and geothermal resources, as opposed to solar overbuild, emerged as a more cost-effective solution in order to meet assigned GHG emissions targets, reliability targets, and WestLight’s voluntary goal of being 100% renewable by 2030.
WestLight recognizes that if all load-serving entities pursued similar procurement strategies, the resulting 369
34 statewide portfolio composition would differ from the assumptions reflected in the TPP. Through its Preferred Portfolio, WestLight seeks to signal to state policymakers, regulators, and the market that wind and geothermal resources are favorable and valuable resources for achieving California's SB 100 goals, and that continued development of these resource types will be important to meeting the state's long-term decarbonization and reliability objectives. In addition, approximately half of the new storage capacity added between 2026 and 2028 consists of resources contracted to satisfy Mid-Term Reliability (MTR) procurement requirements. As a result, WestLight’s initial resource mix differs from the assumptions reflected in the TPP portfolio, as MTR procurement activity across load-serving entities resulted in significant storage development due in part to storage being the most commercially available and readily deployable resource during the procurement period.
Certain resources reflected in the 2025–2026 TPP are not included in WestLight’s Preferred Portfolio, including location-constrained 12-hour storage. WestLight’s Preferred Portfolio also includes resources not reflected in the TPP, including an 8-hour compressed air energy storage project under contract with WestLight and Enhanced Geothermal Systems (EGS) beginning in the 2040 model year. WestLight incorporated EGS resource availability and cost assumptions based on recent CC Power solicitation results, and these resources were selected as cost-effective beginning in 2040.
Figure 14: Comparison of WestLight’s Load Share of New Capacity in the 2025 Transmission Planning Portfolio (TPP) to New Capacity in WestLight Energy’s 2026 Preferred Portfolio 370
35 b. Preferred Conforming Portfolio
WestLight is submitting a single conforming portfolio, which is its Preferred Portfolio. The Preferred Portfolio adds a net additional 561 MW of storage, 358 MW of solar, 536 MW of in-state onshore wind, 400 MW of out-of-state onshore wind, and 297 MW of geothermal by 2045. Due to contract expiration, the Preferred Portfolio results in 15 MW less small hydro than is currently contracted. The selected capacity results in the lowest cost portfolio that meets WestLight’s internal voluntary targets, and the assigned reliability and emissions targets.
To support the description of how these selections are consistent with each relevant statutory and administrative requirement, WestLight has included the text of PU Code Section 454.52(a)(1) below and then describes how the Preferred Conforming Portfolio addresses each of the requirements herein.
Explain how the LSE’s Conforming Portfolio is consistent with each relevant statutory and administrative requirement. Specifically, the LSE should address the following relevant statutory and administrative requirements in PU Code Section 454.52(a)(1) and explain how its Preferred Conforming Portfolios satisfy those requirements:
(A) Meet the greenhouse gas emissions reduction targets established by the State Air Resources Board, in coordination with the commission and the Energy Commission, for the electricity sector and each load-serving entity that reflect the electricity sector’s percentage in achieving the economywide greenhouse gas emissions reductions of 40 percent from 1990 levels by 2030 (I.e. meet the LSE’s GHG benchmarks).
(B) Procure at least 60 percent eligible renewable energy resources by December 31, 2030, consistent with Article 16 (commencing with Section 399.11) of Chapter 2.3. (C) Enable each electrical corporation to fulfill its obligation to serve its customers at just and reasonable rates.
(D) Minimize impacts on ratepayers’ bills.
(E) Ensure system and local reliability on both a near-term and long-term basis, including meeting the near-term and forecast long-term resource adequacy requirements of Section 380, and require sufficient, predictable resource procurement and development to avoid unplanned energy supply shortfalls by taking into account impacts due to climate change, forecasted levels of building and transportation electrification, and other factors that can result in those shortfalls. (F) Comply with paragraph (1) of subdivision (b) of Section 399.13 (I.e., at least 65 percent of the LSE’s RPS procurement for each compliance period shall be from its contracts of 10 years or more in duration or in its ownership or ownership agreements for eligible renewable energy resources).
(G) Strengthen the diversity, sustainability, and resilience of the bulk transmission and distribution systems, and local communities.
371
36 (H) Enhance distribution systems and demand-side energy management. (I) Minimize localized air pollutants and other greenhouse gas emissions, with early priority on disadvantaged communities identified pursuant to Section 39711 of the Health and Safety Code. (J) Maintain a diverse portfolio of energy resources, which may include eligible energy resources procured by the Department of Water Resources.
WestLight’s Preferred Portfolio is consistent with each relevant statutory and administrative requirement stated in Public Utilities Code Section 454.52(a)(1), as described below:
(A) Meet the greenhouse gas emissions reduction targets WestLight’s Preferred Portfolio 2045 GHG emissions of 0.150 MMT (calculated using the CSP Calculator) are below WestLight’s assigned benchmark of 0.151 MMT. The Preferred Portfolio also performs better than WestLight’s 2030, 2035, and 2040 GHG emissions benchmarks. Please see Section III.c for more detailed information on WestLight’s Preferred Portfolio emissions results. (B) Procure at least 60% eligible renewable energy resources WestLight’s Preferred Portfolio results in annual renewable energy procurement equal to 100% of its load beginning in 2030, measured as the demand (at generator busbar) in the CSP template, exceeding the SB 100 target of 60% of annual load from renewable energy resources in 2030. In 2045, WestLight’s Preferred Portfolio results in net procurement of approximately 105% of annual load from renewable energy resources.
(C) Enable each electrical corporation to fulfill its obligation to serve its customers at just and reasonable rates
WestLight’s rates are currently set at 5% below PG&E’s rates. As detailed in Section III.e below, WestLight is committed to serving its customers at reasonable rates. In addition to setting rates that are competitive with PG&E, WestLight works to minimize rate volatility by constructing a balanced and conservatively hedged power supply portfolio, building financial reserves, 11utilizing a rate stabilization fund, and
minimizing rate changes to once per year when possible. (D) Minimize impacts on ratepayers’ bills
The MATCH model optimizes for portfolios that meet assigned objectives at least cost based on the inputs and assumptions. The Preferred Portfolio is the least cost option for meeting the requirements of the IRP and WestLight’s adopted internal goals.
(E) Ensure system and local reliability on both a near-term and long-term basis, including meeting the near-term and forecast long-term resource adequacy requirements 11 WestLIght Financial Reserves Policy: https://www.westlightenergy.org/wp-content/uploads/2024/11/Policy-18- Financial-Reserves-Feb-2021.pdf
372
37 WestLight evaluated the reliability of its portfolios using two metrics:
• The volume of system RA provided through the portfolio compared to the Reliability Procurement Requirements assigned by the CPUC, as determined in the RDT; • Evaluation of the portfolio using the CPUC’s Slice-of-Day RA methodology The results of this analysis are described further in Section III.f and indicate that the Preferred Portfolio helps ensure system and local reliability by satisfying the reliability requirements of the IRP under the marginal ELCC framework. In developing its portfolio, WestLight utilized the CPUC assigned load forecast, which incorporates expected impacts from climate change, transportation electrification, building electrification, and other factors affecting future electricity demand. WestLight’s supplemental evaluation of its portfolio under a 24-hour RA framework provided additional insights regarding charging sufficiency and reliability of its portfolio, as well as potential challenges in designing a portfolio to simultaneously meet two different reliability standards. WestLight will continue to procure and optimize resources as necessary to satisfy the near-term reliability RA requirements under the 24-hour Slice-of-Day Framework.
Please see Section III.f for a more thorough discussion of the System Reliability Analysis. (F) Ensure that at least 65% of RPS procurement is from long-term contracts.
WestLight’s internal guideline is for 60-85% of its retail sales to be procured through mid and long-term contracts of 5 years or more. WestLight’s minimum long-term contracting requirement is the statutory RPS minimum. The statutory long-term RPS contracting requirement refers to the portion of the RPS compliance period requirement that must come from long-term contracts, whereas WestLight’s target applies to its entire retail load. Table 20 below compares WestLight’s internal goal against the requirement to procure 65% of RPS procurement from long-term contracts.
Table 20: RPS Long-term Contract Requirements Compared to WestLight Targets 2028 2030 2035 2040 2045
California
RPS Target 55% 60% 60% 60% 60%
WestLight
Internal
RPS Target
90% 100% 100% 100% 100%
Long-Term
Required
(65% of RPS)
36% 39% 39% 39% 39%
WestLight
Minimum
Long-Term Target
36% 39% 39% 39% 39%
WestLight
Maximum
Long-Term
Target
85% 85% 85% 85% 85%
373
38 WestLight
Preferred
Portfolio
% Long-Term12
86% 98% 112% 111% 118%
WestLight’s Preferred Portfolio results in a higher percentage of long-term contracts than the target range established through WestLight’s internal planning process. For the model years 2035, 2040, and 2045, the calculated long-term contracting percentage exceeds not only WestLight's internal planning targets but also 100% of retail sales. This result is driven in part by differences between the RPS compliance methodology and the IRP modeling framework. Under the RPS program, long-term contracting requirements are calculated as renewable generation relative to retail sales, whereas the IRP models resources at the generator busbar and therefore includes generation needed to serve transmission and distribution losses. In addition, the current market for new resources largely consists of long-term contracting opportunities, which further increases the share of long-term contracts in WestLight’s Preferred Portfolio.
While the current market for new resources largely consists of long-term contracting opportunities, WestLight continues to view a balanced mix of short-, medium-, and long-term procurement as an important component of risk mitigation and portfolio management. As WestLight progresses through the planning horizon, it expects to utilize a mix of contract term lengths, including procurement from both new and existing resources, to achieve reliability and GHG emissions targets while maintaining flexibility and managing risk.
(G) Strengthen the diversity, sustainability, and resilience of the bulk transmission and distribution systems, and local communities.
WestLight’s Preferred Portfolio supports the diversity, sustainability, and resilience of the bulk transmission and distribution system by adding capacity from a variety of resource types as well as significant storage resources. WestLight has performed an analysis of the Preferred Portfolio with respect to the impacts to and reliance on the transmission system, as discussed further in Section III. m.
WestLight’s Preferred Portfolio uses the assigned load forecast from the CPUC, which is based on the 2024 IEPR Demand Forecast Update – Planning Forecast. Relative to the 2025 IEPR Planning Forecast, the 2024 IEPR Update assumes more aggressive adoption of load modifiers, while the 2025 IEPR Planning Forecast reflects recent federal policy changes that may moderate electrification growth. Utilizing this higher forecast in planning results in increased resource buildout and assumes the transmission and distribution system will need to accommodate higher electrification-driven load growth.
WestLight’s Preferred Portfolio includes out-of-state wind resources that will require additional transmission infrastructure to be built in order for those resources to be delivered to California. WestLight believes that expanding and strengthening the transmission system is critical to achieving the decarbonization of the electric system mandated in SB 100. 12 Calculated to be consistent with RPS compliance methodology, that is, generation from long-term contracts, excluding storage losses, as a percentage of retail sales 374
39 In addition, WestLight has a number of programs that support strengthening the resilience of the grid.
For example, WestLight’s electrification programs emphasize “right-sizing” or optimization of the available service capacity of a given building to avoid unnecessary service upgrades. Service upgrades increase the need for grid infrastructure, often in response to “peaky” demand profiles, and increase rates, in addition to numerous customer-side project costs and delays. By “right-sizing” electrification investments, WestLight is helping to reduce the need for service connections and thus reduce the strain on the distribution system and reduce the need for distribution system upgrades.
WestLight’s transportation and building electrification programs provide design guidelines, technical assistance, and financial support for maximizing EV charging and comprehensive residential electrification. These programs use best-in-class methods and technologies to deliver electrification benefits within available service capacity whenever possible. These strategies also support flatter load profiles which benefit grid stability.
In addition, WestLight has an expanding set of programs to actively shape and improve load shapes.
Specific programs WestLight operates that deliver grid benefits include:
• GovPV solar + storage for public buildings: Installation of solar and storage systems on local government facilities.
• Residential Solar & Storage: Installation of solar and storage on single-family homes. • FLEXmarket: Pay-for-performance program for energy efficiency that provides larger incentives for efficiency in peak periods.
• EV Ready: EV charging program focused on multi-family buildings that emphasizes load shaping and grid-friendly, low-power charging.
• Home Upgrade: Residential electrification program that emphasizes right-sized electrification. • EV Charging: WestLight led a multi-year managed charging pilot on load shaped EV charging13.
For a full list of WestLight programs, see Table 38.
Additionally, WestLight engages in programs and/or projects that focus on smaller in-front-of-the-meter (FTM), Distribution-Connected Resources (DCRs) on the scale of approximately 1 to 20 MWs. Like DERs, DCRs can provide significant benefit not only to local communities (in the form of local environmental and economic benefits) but also to the system as a whole (in the form of transmission and distribution grid benefits). WestLight provides additional detail on these programs and projects in the Action Plan Section IV.a.vii.
(H) Enhance distribution systems and demand-side energy management.
As discussed above in (G), WestLight has several programs that enhance distribution systems and demand-side energy management. WestLight is also launching a Virtual Power Plant (VPP) that will assist in achieving these objectives. These efforts are described further in Section IV.a below. 13 Report available at https://www.westlightenergy.org/pce-resources/pce-ev-managed-charging-pilot-results/ 375
40 (I) Minimize localized air pollutants and other greenhouse gas emissions, with early priority on disadvantaged communities
WestLight’s Preferred Portfolio performs better than its assigned GHG benchmarks. WestLight does not procure electricity directly from any natural gas or other fossil-fueled generation resources. Fifteen of WestLight’s executed PPAs are for resources located in DACs, including ten contracts for new resources. By entering long-term PPAs with WestLight, these projects will deliver renewable power to WestLight’s customers, while improving air quality, providing economic benefits, and creating hundreds of jobs in the projects’ regions. Please refer to Section III.d below for further details.
(J) Maintain a diverse portfolio of energy resources, which may include eligible energy resources procured by the Department of Water Resources.
WestLight's Preferred Portfolio maintains a diverse mix of energy resources, including solar, wind, geothermal, and storage, throughout the planning horizon. Selected resources are located across California and the broader Western Interconnection, as described further in Section II.b, Tables 14, 15, and 16. This diversity supports achievement of reliability and greenhouse gas emissions reduction targets while reducing portfolio cost and risk.
LSEs were not required to include resources that may be procured by the Department of Water Resources (DWR) under AB 1373 in the development of their Preferred Portfolios. However, WestLight evaluated the potential impacts of centralized procurement on its portfolio and has included an analysis of those impacts in Section IV.a.
Comparison to WestLight’s 2022 IRP – 25 MMT by 2035 Portfolio A comparison of WestLight’s 2026 Preferred Portfolio and 2022 Preferred Portfolio is shown in Figure 15 below. The portfolios are broadly similar in the 2030 model year, with the primary differences being higher levels of solar and storage and less wind in the 2026 Preferred Portfolio.
In its 2026 modeling, WestLight constrained the availability of wind resources in 2030 based on its assessment of market conditions and the interconnection queue, resulting in greater selection of solar and storage resources.
The differences are more pronounced in the 2035 model year. WestLight’s 2022 Preferred Portfolio included offshore wind beginning in 2035, whereas the 2026 modeling did not assume offshore wind would be commercially available by that date. As a result, the 2026 Preferred Portfolio relies more heavily on geothermal and onshore wind resources, which were identified as the most cost-effective resources in the model.
In addition, the load forecast used in the 2026 IRP is approximately 50% higher than that used in the 2022 IRP for 2035. While other modeling assumptions also influence portfolio composition, the higher forecast load is a significant driver of the approximately 25% increase in resource capacity selected in the 2026 Preferred Portfolio in 2035.
376
41 Figure 15: Comparison of 2022 IRP and 2026 IRP Cumulative Capacity c. GHG Emissions Results
Table 21 below presents the GHG emissions associated with the Preferred Portfolio. The CSP Calculator was used to estimate the emissions. WestLight’s Preferred Portfolio performs better in reducing GHG Emissions in comparison to its assigned GHG Benchmark, reflecting WestLight’s internal goal of achieving 100% renewable energy on an annual basis by 2030 through strategic procurement that prioritizes hourly emissions reductions.
WestLight uses a custom hourly load shape, storage dispatch profiles, and renewable resource generation profiles in the CSP Calculator for its Preferred Portfolio. A detailed explanation of how its load shape and production profile were developed is included in Section II.b.
Table 21: GHG Emissions Results from CSP Calculator (8 MMT Target) 2028 2030 2035 2040 2045
Assigned Load Forecast (GWh) 3,899 4,452 5,998 7,181 7,957 8 MMT GHG Benchmark (MMT CO2) 0.359 0.310 0.280 0.151
WestLight Preferred Portfolio
Emissions (MMT CO2) 0.131 0.226 0.253 0.212 0.150
377
42 d. Local Air Pollutant Minimization and Disadvantaged Communities i. Local Air Pollutants
Table 22 below identifies the estimated emissions associated with the Preferred Portfolio based on the calculations in the CSP Calculator.
Table 22: Preferred Portfolio Criteria Air Pollutants (8 MMT Scenario) 2028 2030 2035 2040 2045
NOx (tonnes/yr) 16 22 27 14 15
PM2.5 (tonnes/yr) 8 14 17 14 13
SO2 (tonnes/yr) 1 1 2 1 1
WestLight does not currently procure and does not plan to procure electricity directly from any fossil-fueled power plants. WestLight’s only contribution to air pollutants is a result of reliance on system power, and an explanation of its plans to reduce its reliance on system power is described further in the Action Plan section below. The criteria pollutant emissions above from specified imports of coal generation are calculated for informational purposes but are not included in the total emissions because these emissions occur outside of California.
ii. Focus on Disadvantaged Communities
For the purposes of its IRP, WestLight defined disadvantaged communities consistent with the definition provided in the IRP filing requirements, based on the following CalEPA’s designation:14 I. Census tracts receiving the highest 25 percent of overall scores in CalEnviroScreen 4.0 (1,984 tracts).
II. Census tracts lacking overall scores in CalEnviroScreen 4.0 due to data gaps, but receiving the highest 5 percent of CalEnviroScreen 4.0 cumulative pollution burden scores (19 tracts) III. Census tracts identified in the 2017 DAC designation as disadvantaged, regardless of their scores in CalEnviroScreen 4.0 (307 tracts).
IV. Lands under the control of federally recognized Tribes. 15 Please refer to Table 23 below for a list of the census tracts and locations of disadvantaged communities.
WestLight identified seven census tracts in San Mateo County in the top 25% of impacted census tracts in CES 4.0, thereby meeting this definition of disadvantaged community. There were an additional 2 census tracts in San Mateo County that qualified as disadvantaged in CES 3.0 that are included as well. WestLight 14 SB 535 Disadvantaged Communities | OEHHA (ca.gov)
15 For purposes of this designation, a Tribe may establish that a particular area of land is under its control even if not represented as such on CalEPA’s DAC map and therefore should be considered a DAC by requesting a consultation with the CalEPA Deputy Secretary for Environmental Justice, Tribal Affairs and Border Relations. 378
43 identified five census tracts in the City of Los Banos that are in the top 25% of impacted census tracts in CES 4.0, including one census tract that was in the top 5% of cumulative pollution burden scores in CES
4.0. CES 5.0 has recently been released which resulted in the addition of 3 new disadvantaged census tracts. Six census tracts that qualified in CES 3.0 and/or CES 4.0 have either been removed and shifted into neighboring census tracts, or have dropped out of the top 25th Poverty Percentile, deeming these census tracts ineligible for future enrollment in WestLight’s DAC-GT program. The new census tracts have been added in Table 23 and the ones from CES 3.0 and CES 4.0 that will become ineligible are in bold.
Additionally, Figure 16 below provides a map to the location of each census tract in San Mateo County, and Figure 17 provides a map to a location of each census tract in the City of Los Banos.
Table 23: WestLight’s Disadvantaged Communities16,
Census Tract Approximate
Location
CES 4.0
Percentile
Range
Customer
Accounts Served
by WestLight
Qualification Map
Label
6047002201 Los Banos,
Merced 95-100% 84 Top 5% in CES 4.0 1
6047002302 Los Banos,
Merced 85-90% 2,917 Top 25% in CES 4.0 2
6047002202
Unincorporated
Merced County
area
85-90% 439 Top 25% in CES 4.0 3
6047002100
Unincorporated
Merced County
area
85-90% 1,058 Top 25% in CES 4.0 4
6081602100
South San
Francisco,
San Mateo
80-85% 1,012 Top 25% in CES 4.0 5
6081610201 Redwood City,
San Mateo 80-85% 8 Top 25% in CES 4.0 6
6047002000
Unincorporated
Merced County
area
80-85% 0 Top 25% in CES 4.0 7
6081602300
South San
Francisco,
San Mateo
80-85% 1,036 Top 25% in CES 4.0 8
6081606200 San Mateo,
San Mateo 75-80% 2,052 Top 25% in CES 4.0 9
6081612000 East Palo Alto,
San Mateo 75-80% 1,377 Top 25% in CES 4.0 10
16 Table 23 includes data from oehha.ca.gov/calenviroscreen/report/calenviroscreen-30, under CalEnviroScreen
3.0 Data and Additional Materials - ces3results.xlxs (updated June 2018) 379
44 6081604101 San Bruno,
San Mateo 75-80% 2,552 Top 25% in CES 4.0 11
6081610202 Redwood City,
San Mateo 75-80% 1 Top 25% in CES 4.0 12
6081611900 East Palo Alto,
San Mateo 70-75% 2,018 Top 25% in CES 3.0 13
6081604200 San Bruno,
San Mateo 65-70% 1,115 Top 25% in CES 3.0 14
6047002301 Los Banos, Merced
County 75-80% 6,759 Top 25% in CES 5.0 1
6047002303 Los Banos, Merced
County 80-85% N/A Top 25% in CES 5.0 2
6081602202
South San
Francisco, San
Mateo
75-80% 3,284 Top 25% in CES 5.0 5-8
380
45 Figure 16: Map of DACs in San Mateo County (Numbers correlate to “Map Label” in Table 23) with Caltrain line shown in purple.
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46 Figure 17: Map of DACs in the portion of Merced County that WestLight serves (City of Los Banos) (Numbers correlate to “Map Label” in Table 23)
WestLight estimates that it serves approximately 17,500 customer accounts, including residential and non-residential, serving a population of approximately 45,000 people, in DACs located within its service territory. This represents roughly 15.4% of WestLight’s total residential customer accounts. Of these DAC customers, 2,660 accounts, or about 15% of WestLight’s total DAC accounts, participate in WestLight’s DAC-GT program, which provides clean energy to income qualified residential customers at a 20% discount.
Additionally, WestLight’s Preferred Conforming Portfolio advances the statutory requirement to minimize localized air pollutants and greenhouse gas emissions, particularly in disadvantaged communities, through targeted procurement of 100% renewable electricity and innovative tariff design. Through its Green Transit Tariff, WestLight supplies Caltrain’s electrified rail system with 100% renewable energy, displacing diesel fuel use that has historically contributed to air pollution along the corridor. Caltrain’s electrification is projected to reduce annual emissions by approximately 250,000 metric tons of CO₂, equivalent to removing roughly 55,000 cars from the road, while significantly improving air quality for communities 382
47 along the corridor17. A recent study out of UC Berkeley showed that “the new electric trains reduced riders’ exposure to the carcinogen black carbon by an average of 89%, and significantly reduced ambient black carbon concentrations within and around the San Francisco station18”. Figure 16 above shows the Caltrain corridor runs through many of the most burdened census tracts, including 7 DACs in WestLight’s service area.
WestLight’s procurement strategy further enhances these outcomes by lowering the cost of electrification. The Green Transit Tariff allows Caltrain to generate maximum credits in the California Air Resources Board Low Carbon Fuel Standard Program and also compensates Caltrain for electricity exported back to the grid through regenerative braking – a first-of-its-kind compensation model designed to advance transit electrification. The Green Transit Tariff is available to other local transit agencies, and WestLight hopes to further reduce local air pollutants throughout the service area. By aligning renewable procurement with cost-effective electrification, WestLight’s portfolio delivers measurable emissions reductions and improved public health outcomes in disadvantaged communities, consistent with PU Code Section 454.52(a)(1).
Power Procurement in DACs
WestLight does not procure electricity directly from any natural gas or other fossil-fueled generation resources. Further, there are no polluting electricity generation resources located in the DACs in WestLight’s service territory identified above.
WestLight fully recognizes the need to help mitigate the impacts of air pollution in regions of the state where communities have been disproportionately impacted by the existing generating fleet as well as the need to bring economic benefits to communities with high levels of poverty and unemployment.
Consistent with this recognition, WestLight has executed long-term power purchase agreements (PPAs) to build new clean energy resources with ten projects in disadvantaged communities across the state, including six renewable energy projects – two solar projects located in Merced County, a solar project located in Kings County, two solar plus storage projects located in Fresno County, and a geothermal project located in Imperial County – and four storage projects, including one in Riverside County, two in Los Angeles County, and one in Kern County. WestLight also has contracts with five existing clean energy resources located in DACs, including two wind resources in Kern and Solano Counties and three hydroelectric resources in Shasta County. By entering into PPAs with WestLight, these projects will deliver renewable power to WestLight’s customers, while improving air quality, providing economic benefits and creating hundreds of jobs in the projects’ region.
Each of the five new solar projects and the four new storage projects used or are using a project labor agreement (PLA) with local unions for the construction of the projects. The geothermal project used prevailing wage for construction of the project.
17 https://www.caltrain.com/media/32757/download?inline#:~:text=In%20addition%2C%20electrification%20will%2 0eliminate,the%20state's%20emissions%20reduction%20goals.&text=Reduced%20Engine%20Noise%20Emanating %20from,less%20than%20diesel%20train%20engines
18 https://news.berkeley.edu/2025/04/16/electric-trains-are-quieter-more-reliable-than-diesel-new-study-finds-theyre-healthier-too/ 383
48 A PLA is a pre-hire collective bargaining agreement with one or more labor organizations that establishes the terms and conditions of employment for a specific construction project. Consistent with WestLight’s Sustainable Workforce policy, WestLight believes support of local businesses, union labor, and apprenticeship and pre-apprenticeship programs that create employment opportunities are important components of building and sustaining healthy and sustainable communities. As part of its procurement process, WestLight collects information from project owners on expected labor impacts. This information is used to evaluate potential workforce impacts of proposed projects with the goal of promoting fair compensation, fair worker treatment, multi-trade collaboration, and support for the existing wage base in local communities where contracted projects will be located.
Additionally, WestLight’s solicitation materials for its renewable procurements include specific criteria targeted at understanding the impacts of projects on disadvantaged communities. Respondents to RFOs are required to reply to questions regarding their outreach efforts, and any DAC, workforce development, and community benefits impacts associated with their projects. Specific questions include the following:
• Is your project located within a Disadvantaged Community (DAC)? • Does your project demonstrate benefits to DACs?
o If ‘Yes’, please describe the benefit
• Has the bidder consulted with local Native American tribes about whether the proposed project footprint is on lands that may contain cultural resources? o If the answer is 'Yes', please explain and provide supporting documentation, including a timeline of outreach and consultation activities, and responses from tribal members. • Has your project secured or will plan to secure a 5-trade project labor agreement or similar workforce agreement?
o If the answer is 'Yes' or 'Planned for the Future', does the PLA/workforce agreement have a targeted hire program in place for placing Equity Priority Workers (ex:
underemployed, custodial single parent, veteran of the US Military, etc.) • Regardless of whether or not your project is located in a DAC, have you conducted outreach to the communities around the project location?
o If the answer is 'Yes' or 'Planned in the Future', please describe the community outreach, including outreach methods (i.e. door knocking, phone banking, internet, social media, mailings, physical notices posted), the languages spoken in communities surrounding the proposed project and the languages in which materials been made available, state the number of responses by community members, describe substantive responses, and describe any changes to the project undertaken in response to community responses.
o If the answer is 'Yes' or 'Planned in the Future', please provide a timeline of community outreach activities to date and planned in the future.
o If the developer has conducted community outreach, was the community notified of how their input was used?
o If the answer is 'Yes' or 'Planned in the Future', has the developer partnered with local Community-Based Organizations (CBOs) in its outreach activities? • Has your project secured a community benefits agreement (CBA)? • Please describe any community benefits agreements your project has secured or will secure and the status of the agreements.
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49 • If a Community Benefits Agreement has been or will be negotiated, please describe how benefits will be measured and reported, and/or if an oversight committee will monitor the progress of delivery of community benefits.
WestLight has developed rubrics for each topic area and grades responses to each individual question against criteria designed for that specific question, which can include quality of response and alignment with industry best practice. For example, for the Community Benefits topic area, projects are awarded more points if responders provide a detailed timeline of community outreach, involve trusted messengers like CBOs in their outreach, and include details on how benefits from Community Benefits Agreements or Community Benefits Plans will be measured.
WestLight has conducted a geographic analysis of its contracted projects that are within DAC boundaries, and is providing this analysis in Figure 18 and a description of its projects in this section.
Figure 18: WestLight Power Procurement in Disadvantaged Communities Wright Solar is a 200 MW new solar project currently operating in Merced County, less than 100 miles south of San Mateo County. The facility is located in a disadvantaged community that ranks in the 85th overall percentile on CalEnviroScreen 4.0. The project produces power equivalent to that used by approximately 73,000 households. The construction of Wright Solar over the course of 2018 and 2019 produced approximately 180 jobs and resulted in over $2.7 million of sales and use tax in the county of Merced. The Wright Solar project also has a CBA in place with Merced County. As part of this CBA, the project makes an annual payment of $25,000 to Merced County’ General Fund. 385
50 Dos Palos Solar is a 3 MW new solar project currently operating in Merced County, roughly 100 miles south of San Mateo County. The facility is located in a disadvantaged community that ranks in the 80th overall percentile on CalEnviroScreen 4.0. Dos Palos produces power equivalent to that used by over 1,000 households. The project produced approximately 30 jobs during construction and utilized union labor. This project was procured to serve the needs of WestLight’s DAC-GT customers, which is described further above in Section III.b.
Mustang Two Solar is a 100 MW new solar project currently operating in Kings County, roughly 150 miles south of San Mateo County. The facility is located in a disadvantaged community that ranks in the 92nd overall percentile on CalEnviroScreen 4.0. The project produces power equivalent to that used by over 40,000 households. The project owner estimates that approximately $3.1 million was spent locally on materials and services, $3.6 million in tax revenue will go to Kings County and $8.1 million in tax revenue will go to the state.
Darden III and Darden IV are two new solar plus storage facilities, each 42.28 MW of solar and 45.74 MW of 4-hour battery storage. The projects are currently under construction in Fresno County, less than 150 miles south of San Mateo County. Darden III and IV are located in a disadvantaged community that ranks in the 83rd overall percentile on CalEnviroScreen 4.0. The projects will produce power equivalent to that used by over 16,000 households. The projects will create approximately 1,600 union labor jobs during construction.
Heber 2 Geothermal is a 26 MW new geothermal project currently operating in Imperial County, nearly 500 miles south of San Mateo County. The facility is located in a disadvantaged community that ranks in the 84th overall percentile on CalEnviroScreen 4.0. The project produces power equivalent to that used by nearly 30,000 households. The project paid prevailing wage for all construction work and created approximately 54 jobs during construction.
Nova Power III is a 50 MW new 4-hour storage project currently operating in Riverside County, approximately 450 miles south of San Mateo County. The facility is located within 5 miles of a disadvantaged community that ranks in the 82nd overall percentile on CalEnviroScreen 4.0.
San Gabriel II is a new storage project that includes a 10 MW, 8-hour battery and a 65 MW, 4-hour battery currently under development in Los Angeles County, approximately 300 miles south of San Mateo County. The facility is located in a disadvantaged community that ranks in the 83rd overall percentile and 100th cumulative pollution burden percentile on CalEnviroScreen 4.0. The project will have a PLA and is estimated to create approximately 130 jobs during construction.
Willow Rock is a 500 MW, 8-hour new compressed air storage project from which WestLight is contracted for 15 MW of offtake. The project is currently under development in Kern County, approximately 250 miles south of San Mateo County and is located within 5 miles of a disadvantaged community that ranks in the 77th overall percentile on CalEnviroScreen 4.0. The project will have a PLA.
Voyager Wind II is a 63.175 MW existing wind project operating in Kern County, approximately 250 miles south of San Mateo County. The facility is located within 5 miles of a disadvantaged community that ranks in the 77th overall percentile and 95th cumulative pollution burden percentile on CalEnviroScreen 4.0. The project produces power equivalent to that used by nearly 30,000 households. 386
51 Shiloh Wind is a 150 MW existing wind project operating in Solano County, approximately 50 miles northeast of San Mateo County. Shiloh Wind is located in a disadvantaged community that ranks in the 78th percentile on CalEnviroScreen 4.0. The project is producing power equivalent to that used by over 55,000 households. Shiloh Wind pays approximately $1M per year in Property Taxes.
Hatchet Creek is a 7.5 MW existing hydroelectric project operating in Shasta County, approximately 250 miles north of San Mateo County. The project is located within 5 miles of land under the control of federally recognized Tribes. Hatchet Creek produces power equivalent to that used by over 2,000 households.
Roaring Creek is a 2 MW existing hydroelectric project operating in Shasta County, approximately 250 miles north of San Mateo County. The project is located within 5 miles of land under the control of federally recognized Tribes. Roaring Creek produces power equivalent to that used by nearly 800 households.
Burney Creek is a 3 MW existing hydroelectric project operating in Shasta County, approximately 250 miles north of San Mateo County. The project is located within 5 miles of land under the control of federally recognized Tribes. Burney Creek produces power equivalent to that used by nearly 800 households.
Collectively, these projects demonstrate WestLight's commitment to procuring clean energy resources that provide benefits to disadvantaged communities while supporting California's clean energy transition. In addition, WestLight Energy has consistently advocated for transmission and local generation solutions to allow retirement of the many highly polluting gas plants in DACs retained for local reliability. Although these issues are not acute in WestLight Energy’s territory, this issue remains a top environmental justice concern in California.
e. Cost and Rate Analysis
WestLight’s rates are set by its Board of Directors. Since inception, WestLight’s goal has been to offer rates that are at parity or lower than PG&E rates. WestLight’s default retail product is called ECOplus and rates for this product are currently set at 5% below PG&E’s rates while providing customers with electricity that is supplied entirely from renewable or carbon-free sources through 2029. WestLight’s goal is to supply the ECOplus product with energy sources that are 100% renewable on an annual basis beginning in 2030.
WestLight’s long-term success depends on effectively managing costs, maintaining competitive customer rates, and preserving its financial sustainability.
To meet these goals, WestLight takes several actions to procure the lowest cost portfolio and protect its customers from unexpected price increases.
• Competitive procurement: WestLight engages in competitive procurement processes to secure the lowest cost resources possible for its customers.
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52 • Financial reserves: WestLight maintains cash reserves at least equivalent to 180 days of total operating expenses, which can help WestLight manage risk and remain financially solvent.19 • Credit rating: WestLight obtained an investment grade credit rating in 2019, and currently maintains two investment grade credit ratings: A3 from Moody’s and A- from S&P Global. This helps WestLight to secure the lowest cost power resources for its customers. • Rate Stabilization: In May 2024, the WestLight Board of Directors approved establishment of a Rate Stabilization Fund pursuant to Governmental Accounting Standards Board (GASB) Statement No. 62. to support customer rate stability and mitigate future rate volatility. • Risk Management: WestLight is subject to cost volatility and market price risk in meeting load requirements in the CAISO market. WestLight manages this risk through forward procurement of fixed price contracts for energy. WestLight Energy uses a portfolio risk management approach in its power purchasing program, seeking low-cost supply as well as diversity among technologies, production profiles, project sizes, project locations, counterparties, term lengths and timing of market purchases to cost average over time, including remaining cognizant of the value of open market positions. In 2024, WestLight's Board adopted an Energy Risk Policy20, which establishes a formal governance and risk management framework for energy procurement activities. The ERP defines risk management responsibilities, oversight structures, internal controls, and transaction authorities to ensure procurement activities are conducted in a manner consistent with WestLight's financial objectives and risk tolerance.
Considering these goals, WestLight analyzed the modeled cost of its Preferred Portfolio. Overall, WestLight ’s expected costs increase over time, largely reflecting the higher costs associated with new resource additions. WestLight notes that the cost results of the model outputs are sensitive to market conditions, and uncertainty increases in later years. These uncertainties are discussed further in the barriers analysis in the Action Plan below.
In order to evaluate the cost uncertainty and associated risk of its Preferred Portfolio, WestLight used a stochastic analysis to determine the probability that its costs would exceed certain thresholds. The stochastic analysis results in a probability distribution curve of potential portfolio costs. These results are summarized here by showing the 5th, 50th, and 95th percentile costs from the stochastic analysis.
WestLight’s expected portfolio costs for its Preferred Portfolio are depicted in Tables 24 and 25 below. A description of the cost components is provided below.
Table 24: Portfolio Total Cost Results (Nominal $M)
2028 2030 2035 2040 2045
Median (P50) $332 $436 $656 $955 $1,179
Lower Cost Estimate (P5) $310 $425 $637 $937 $1,160
Higher Cost Estimate (P95) $359 $451 $673 $983 $1,195
19 Financial Reserves Policy: https://www.westlightenergy.org/wp-content/uploads/2024/11/Policy-18-Financial-Reserves-Feb-2021.pdf 20 https://www.westlightenergy.org/wp-content/uploads/2025/02/Policy-23-Energy-Risk-Policy-November-2024.pdf 388
53 Table 25: Portfolio Weighted Average Cost Results (Nominal $/MWh) 2028 2030 2035 2040 2045
Median (P50) $78 $90 $100 $123 $136
Lower Cost Estimate (P5) $73 $88 $97 $120 $134
Higher Cost Estimate (P95) $84 $93 $103 $125 $138
For each portfolio, costs are comprised of the following components:
Market Cost of Customer Load:
WestLight Energy buys load to serve customers at the PG&E DLAP. The cost of this load is determined using the hourly day ahead and real-time imbalance CAISO market prices for the PG&E DLAP. For the stochastic analysis, WestLight assumed load volumes remain fixed but CAISO market prices for the PG&E DLAP vary.
Contract Costs:
WestLight Energy buys renewable energy under several contracting structures, primarily long-term PPAs with a fixed price over the project term. WestLight Energy pays a fixed price for the renewable energy generated by its contracted projects. For the stochastic analysis, WestLight assumed contract costs do not vary.
Market Revenue from Energy Generation:
WestLight Energy sells its renewable energy into the CAISO market at each contracted project delivery point, which generates revenue for WestLight Energy. If market prices at a particular node during a particular interval are negative and WestLight Energy chooses not to curtail generation at that node during that hour, then WestLight Energy would pay CAISO for the injection of that energy into the system. For the stochastic analysis, WestLight assumed resource generation varies with weather variability, and market prices vary.
REC and GHG-free Attribute Costs:
If WestLight Energy’s portfolio does not provide enough renewable and/or carbon-free energy through long-term PPAs to meet its targets, it would contract REC and GHG-free energy via short-term contract structures such as index-plus contracts. Under these contracting structures, WestLight Energy pays the market price for the energy plus an attribute premium. In the 2026 IRP, WestLight Energy’s Preferred Portfolio meets 100% of its annual load with renewable resources in all years except 2028, the only year in which its Preferred Portfolio includes net purchases of REC or GHG-Free attributes. The prices of these products were derived from AscendView’s forecast and are updated to reflect WestLight Energy’s most current assessment of the market.
Capacity Market Costs:
If WestLight Energy’s portfolio does not provide enough resource adequacy through long-term PPAs, it would contract for capacity via short-term contract structures for resource adequacy. Short-term capacity market costs are based on WestLight Energy’s assessment of the resource adequacy market, supported by broker quotes and third-party evaluations of market pricing, while long-term forecasts are derived from AscendView.
Other Costs:
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54 WestLight's portfolio costs include several additional cost categories, including CAISO administrative and ancillary services charges, Congestion Revenue Rights (CRR) costs, and forecasting services. These costs are necessary to support reliable market participation, manage transmission congestion risk, and ensure accurate forecasting for portfolio operations.
f. System Reliability Analysis
In this section, WestLight describes its methods for evaluating system reliability and how its Preferred Portfolio contributes to system reliability.
WestLight defines reliability as the ability of a resource portfolio to meet customer load and maintain adequate operating reserves across all hours and seasons, including periods of system stress, renewable variability, and extreme weather conditions. Reliable portfolios must provide not only sufficient capacity, but also sufficient energy and operational flexibility to ensure resources remain available when needed.
Accordingly, reliability should be evaluated not solely through peak demand conditions, but through a portfolio’s ability to serve load throughout the year under a range of operating conditions.
The transition to variable energy resources, especially wind and solar, will require an evolution of reliability evaluation beyond a peak load analysis. Reliability assessment of low carbon resources will also need to evaluate serving load across all hours, since resources to meet load during the solar window will not be the same as resources used to meet evening ramping or overnight load. The CPUC’s 24-hour Slice-of-Day framework used in the RA program meets this criterion of tracking the performance of resource portfolios in meeting load in all hours, as well as energy sufficiency of storage.
However, the CPUC’s current reliability planning is conducted under multiple coexisting frameworks, including Effective Load Carrying Capability (ELCC), marginal ELCC, and the 24-hour Slice-of-Day construct.
While each methodology may theoretically provide some useful insight into system reliability, they are not fully aligned and can produce differing signals regarding the reliability contribution of resources. In particular, marginal ELCC approaches, which estimate the incremental contribution of additional resources as system conditions evolve, may undervalue certain resource types—especially storage and hybrid resources—as penetration increases. ELCC methodologies are highly sensitive to assumptions of the precise resource mix and may not provide accurate results when used to evaluate a portfolio sharply different from the portfolio used to generate the ELCC values. Since the value of each resource type under ELCC methodologies depends critically on the full portfolio of resources, the valuation of each LSE’s portfolio could shift because of what other LSEs do or do not procure.
For example, under the marginal ELCC framework, an LSE may procure sufficient energy to charge all its storage resources, but if other LSEs do not, then the energy deficiency caused by other LSEs will devalue the storage resources of the LSE with sufficient charging, forcing additional generation procurement by that LSE. This dynamic shifts significant costs onto the customers of the LSE with adequate charging resources because of the deficiencies of other LSEs’ procurement. This inherent characteristic of ELCC methodologies can create significant cost shifts in which a LSE can fully meet its own customers’ load in all hours, yet still be required to procure additional resources because of the make up of other LSEs’ portfolios. This procurement outcome may be driven in part by portfolio-wide assumptions embedded within the ELCC methodology rather than solely by the reliability characteristics of the individual LSE portfolio. On the other hand, the Slice-of-Day framework evaluates resource sufficiency based on the 390
55 operational capabilities of an LSE’s resources on an hourly basis including the ability to meet load in all hours and ensure adequate charging of storage resources.
As a result, the same portfolio may appear sufficient under one framework while requiring additional procurement under another. WestLight’s own reliability analysis, which includes a supplemental Slice-of-Day evaluation in addition to the required marginal ELCC approach under the IRP filing requirements, demonstrates this point. The divergence of these two reliability frameworks introduces complexity into long-term planning and procurement, as load-serving entities must simultaneously satisfy multiple reliability constructs that are based on different assumptions about resource performance and system needs. Without further alignment, these frameworks may create duplicative or conflicting procurement signals, increasing costs without proportionate reliability benefits. WestLight therefore views this as both a modeling and policy consistency issue that warrants continued refinement as the Commission advances reliability and clean energy objectives.
The primary metric used to evaluate WestLight’s Preferred Portfolio is an analysis of its September NQC using the capacity counting rules established in the 2024-2027 IRP Filing Requirements. According to this metric, WestLight’s Preferred Portfolio meets its reliability need in all years of the study period (2026 to 2045). In WestLight's modeling of its Preferred Portfolio, the GHG emissions target, rather than the reliability requirements, was the binding constraint driving resource additions through 2045.
The Reliability summary analysis from the Reliability tab of the Resource Data Template for the Preferred Portfolio is presented below as Figure 19 and Figure 20, and demonstrates how WestLight’s Preferred Portfolio will meet its assigned reliability need in all years.
Figure 19: LSE Capacity by Resource Type Chart from the Reliability Tab of the RDT – WestLight Preferred Portfolio
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56 Figure 20: LSE Capacity by Contract Status from the Reliability Tab of the RDT – WestLight Preferred Portfolio
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57 Table 26: Load and Resource Table by Resource Type from the Resource Data Template 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 LSE reliability need
(MW)
775
791
807
741
674
701
727
754
781
808
837
866
896
926
956
980
1,004
1,028
1,053
1,078
ELCC by resource type (effective MW)
hybrid 204 189 321 219 292 281 270 258 247 236 240 243 247 305 236 313 308 303 298 293 in_state_wind_south 23 21 18 16 16 15 16 17 57 107 97 88 78 69 60 57 58 59 60 61 in_state_wind_north 45 42 53 61 80 80 81 81 81 148 88 82 76 69 63 76 77 79 80 81 out_of_state_wind_WY - - - - - - - - - - - 122 115 108 100 128 133 139 145 151 out_of_state_wind_IDW
AOR - - - - - - - - - - - - - - - - - - - -
out_of_state_wind_AZN
M
95 95 94 86 79 82 84 87 90 92 87 81 76 70 65 67 69 71 73 74 offshore_wind_north - - - - - - - - - - - - - - - - - - - - offshore_wind_south - - - - - - - - - - - - - - - - - - - - utility_pv 25 28 31 31 31 32 32 32 32 33 23 24 24 25 26 25 24 24 23 22 btm_pv 28 30 30 30 31 34 38 41 44 47 51 55 58 62 66 65 63 62 60 58 4hr_batteries 171 210 189 122 56 53 50 47 44 41 41 41 41 26 26 25 14 14 14 14 8hr_batteries 14 23 21 16 10 14 13 11 10 9 9 10 11 11 12 8 5 5 5 5 12hr_batteries - - - - - - - - - - - - - - - - - - - -
24hr_batteries - - - - - - - - - - - - - - - - - - - -
100hr_batteries - - - - - - - - - - - - - - - - - - - - pumped_storage - - - - - - - - - - - - - - - - - - - -
demand_response - - - - - - - - - - - - - - - - - - - - hydro 1 1 1 1 1 1 1 1 - - - - - - - - - - - -
small_hydro 0 0 0 0 0 0 0 - - - - - - - - - - - - -
geothermal 56 58 69 67 70 70 39 98 98 105 106 106 106 104 225 226 227 227 228 322 biomass_wood - - - - - - - - - - - - - - - - - - - -
biogas - - - - - - - - - - - - - - - - - - - -
nuclear - - - - - - - - - - - - - - - - - - - -
gas_cc 236 235 233 189 186 127 127 127 128 128 130 131 133 135 136 135 134 132 131 130 393
58 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 LSE reliability need
(MW)
775
791
807
741
674
701
727
754
781
808
837
866
896
926
956
980
1,004
1,028
1,053
1,078
ELCC by resource type (effective MW)
gas_ct - - - - - - - - - - - - - - - - - - - -
cogen - - - - - - - - - - - - - - - - - - - -
ice - - - - - - - - - - - - - - - - - - - -
LSE total supply
(effective MW) 898 931 1060 838 851 788 750 801 832 947 871 983 966 984 1,015 1,124 1,113 1,115 1,116 1,211 Net capacity position
(+ve = excess, -ve =
shortfall) (effective MW)
124 140 253 97 177 87 23 47 51 139 35 117 70 59 59 144 109 86 63 133 Table 27: Load and Resource Table by Contract Status from the Reliability Tab of the RDT 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 LSE reliability need
(MW)
775
791
807
741
674
701
727
754
781
808
837
866
896
926
956
980
1,004
1,028
1,053
1,078
ELCC by contract status (effective MW)
Online 797 768 740 606 514 453 423 454 453 441 375 373 371 330 297 259 259 259 259 258 Development 73 132 290 203 130 132 127 123 118 114 113 112 112 111 68 68 55 55 55 56 Review - - - - - - - 28 28 36 36 36 36 57 57 57 57 57 58 58 PlannedExisting - - - - - - - - - - - - - - - - - - - - PlannedNew - - - - 176 169 162 155 188 308 297 408 389 425 527 675 679 682 685 781 BTM PV 28 30 30 30 31 34 38 41 44 47 51 55 58 62 66 65 63 62 60 58 LSE total supply
(effective MW) 898 931 1060 838 851 788 750 801 832 947 871 983 966 984 1,015 1,124 1,113 1,115 1,116 1,211 Net capacity position
(+ve = excess, -ve =
shortfall) (effective MW)
124 140 253 97 177 87 23 47 51 139 35 117 70 59 59 144 109 86 63 133 394
59 WestLight also evaluated its Preferred Portfolio under the 24-hour Slice-of-Day RA framework as a supplemental reliability metric. This additional analysis examines whether portfolio resources can meet hourly reliability needs throughout the day and maintain sufficient charging capability for storage resources and also provides useful insight into how much of WestLight’s RA needs would be met with its Preferred Portfolio. To generate hourly RA obligations for each month of the model years, WestLight used its internal peak load forecast, developed using a “1-in-2” weather methodology, and scaled the results to its share of the CAISO’s Total Reliability Need (TRN). WestLight then used the Slice-of-Day exceedance profiles approved by the CPUC for the 2026 resource adequacy program to calculate the RA value of its selected portfolio.
The results of the Preferred Portfolio under Slice-of-Day accounting show that the portfolio cannot meet the 24-hour reliability needs in all hours. The primary driver of this result is not a shortage of installed battery capacity, but rather insufficient charging capability to fully utilize the portfolio's storage resources.
Despite having significant battery RA capacity, limited charging capacity leaves much of the battery value locked out of the portfolio, unable to count towards meeting reliability obligations. Because WestLight’s internal peak load forecast shows a winter peak, this issue is especially problematic in winter months, where limited charging capacity renders hundreds of MW of battery unusable in the RA portfolio. For example, in January 2030, there is less than 100 MWh of excess RA capacity in solar hours, leaving almost 4,000 MWh of battery locked out of the portfolio. The problem persists in the summer months, where increased solar values provide for higher charging capacity, but still not enough to completely utilize the battery RA.
This challenge may become increasingly important statewide over time as California's load profile continues to evolve. Current ELCC methodologies and IRP planning assumptions remain heavily influenced by summer peak conditions, while electrification of buildings and transportation is expected to increase winter demand and reduce the relative prominence of summer peaks. Because charging sufficiency is more constrained during winter months, portfolios that appear adequate under summer-focused reliability metrics, such as the 2024-2027 IRP which uses the September marginal ELCC framework, will face increasing challenges in fully utilizing battery capacity during periods of winter system stress.
The figures below display the performance of WestLight’s Preferred Portfolio under a Slice-of-Day framework for representative months in 2030 and 2035.
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60 Figure 21: January 2030 Slice-of-Day Position
Figure 22: September 2030 Slice-of-Day Position
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61 Figure 23: January 2035 Slice-of-Day Position
Figure 24: September 2035 Slice-of-Day Position
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62 WestLight Energy emphasizes that continued use of multiple potentially conflicting reliability methodologies—including ELCC, marginal ELCC, and the Slice-of-Day framework—will continue to create inconsistent planning signals and drive inefficient and more costly procurement outcomes, especially if ELCC accounting incentivizes portfolios that do not match reliability needs in a Slice-of-Day framework.
Greater coordination across these frameworks, along with sufficient transparency and implementation stability, will help reduce regulatory uncertainty and enable load-serving entities to make cost-effective, long-term investments in clean and reliable resources.
g. Existing Resource Planning
WestLight’s Preferred Portfolio includes a significant amount of capacity from new resources. In 2030, WestLight’s Preferred Portfolio is projected to be 2,298 MW, and includes 1,270 MW of existing resources, defined as resources in the RDT with contract statuses of “online” and “planned existing.” In 2045, the Preferred Portfolio is projected to be 3,440 MW, of which 455 MW will be resources already existing today.
This projected transition toward predominantly new resources reflects WestLight’s long-standing strategy to direct customer value toward incremental clean energy development, reliability resources, and long-term portfolio transformation. At the same time, legacy cost recovery obligations, including the Power Charge Indifference Adjustment (PCIA) and Financial Security Requirements (FSR), remain an important planning consideration because they affect the share of customer revenues available for new procurement. To the extent that revenues and financial capacity are diverted to PCIA and FSR these resources will not be available to procure the new resources California needs to maintain a clean and reliable grid. As a result, existing resource planning must balance historical system cost responsibilities with the need to accelerate investment in the next generation of clean and reliable resources.
WestLight has compared the existing resources in its portfolio to the existing21 resources in the 2025-2026 TPP, as shown in Figure 25. WestLight’s Preferred Portfolio depends heavily on new resources, and the proportion of existing resources in its portfolio declines over time as its current contracts expire, which WestLight expects to replace with new contracts. Relative to its load share of the 2025-2026 TPP, WestLight’s Preferred Portfolio has significantly less reliance on existing resources. 21 For the analysis here, WestLight is using capacity summarized in the RESOLVE Results Viewer for the IRP Least Cost Portfolio, specifically CAISO Baseline (Existing & In-Development) Capacity. 398
63 Figure 25: WestLight’s Load Share of Existing Resources in the 2025-2026 TPP versus its Preferred Portfolio for the 2026 IRP
WestLight also compared the existing resources in its 2026 Preferred Portfolio to those in its 2022 Preferred Portfolio. WestLight’s 2026 Preferred Portfolio includes more capacity from existing resources than its 2022 Preferred Portfolio, due to additional contracts it has executed with new battery storage, solar, and wind resources in the past three years that are now online and in its current portfolio. 399
64 Figure 26: Existing Resources in WestLight’s 2022 IRP versus 2026 IRP WestLight has executed contracts with the existing resources in its Preferred Portfolio. WestLight assumes contract extensions for a portion of the existing resources it has under contract, specifically for certain wind and geothermal resources. In other words, for the purposes of the Preferred Portfolio, WestLight is not assuming most existing resources will be re-contracted when they expire. WestLight believes these assumptions are appropriate and represents a conservative view of the market for existing resources and overall portfolio costs for its IRP analysis.
For purposes of its IRP modeling, WestLight conservatively assumes that existing contracted resources do not continue beyond their current contract terms unless an extension has been specifically modeled. In practice, however, WestLight may seek to re-contract with existing resources where commercially available and cost-effective. These opportunities may support WestLight’s broader procurement strategy of maintaining a balanced mix of short-, medium-, and long-term contracts, including procurement from existing resources, while still achieving reliability and greenhouse gas emissions targets. h. Hydro Generation Risk Management
The potential for frequent and prolonged in-state and west-wide drought and the impacts to hydro-electric generation poses a manageable risk in the near term and no direct risk in the long term since WestLight’s Preferred Portfolio reduces reliance on large hydroelectric resources with the objective of phasing out large hydroelectric resources from the portfolio by 2030. WestLight’s Preferred Portfolio currently includes about 15 MW of small hydroelectric capacity, decreasing to 11 MW in 2035 and 0 MW 400
65 in 2040 due to contract expiration. These small hydro resources play a minor role in a portfolio of more than 1.6 GW in 2028, and 3 GW in 2035.
Electrical generation from hydroelectric facilities depends on the volume of water available to flow through turbine generators. A lack of precipitation in drought years creates low water availability and hence lower hydro generation output. Hydro systems without large reservoirs that can store water for multiple years and that can average out generation over time are at particular risk. California’s hydro generation system is vulnerable to drought and has experienced lower-than-average hydro generation during droughts in 2007-2009, 2012-2016 and 2020-2022.
WestLight manages its risk to hydro generation fluctuation and prices by signing contracts from resources in both California and the Pacific Northwest, signing primarily firm delivery contracts and minimizing the volume procured through unit contingent contracts. WestLight also contracts for hydro resources through a mix of counterparties and for varying terms to manage risk associated with counterparty default on hydro resources. Finally, WestLight conducts statistical modeling on the volume of hydro it expects to be delivered for any unit contingent contracts, taking into account snowpack and precipitation levels and historical generation in similar years.
The risks that in-state drought pose to WestLight’s portfolio is consistent with the amount of hydro generation and level of risk borne by the 2025-2026 TPP with updates prior to 2030 and significantly less than the 2025-2026 TPP with updates after 2030. This is due to WestLight’s internal goal to phase out large hydro power by 2030 through procurement of additional renewable resources. During 2028, the sole study year in which large hydro was considered, approximately 431 GWh is included in the Preferred Portfolio. This is less than WestLight’s load share of large hydro and imported hydro expected to be available in 2028, per the CSP Calculator. However, in later years, WestLight plans to include zero large hydroelectric generation in its portfolio, which will eliminate the direct risk of drought to its portfolio.
There will continue to be effects of drought on its portfolio, through elevated market prices, which WestLight plans to mitigate through its hedging strategy and risk procedures, including net open position targets for future years and requirements around concentration and market risk.
Table 28: Comparison of Large Hydro Reliance in the CSP versus WestLight’s Preferred Portfolio 2028 2030 2035 2040 2045
WestLight Energy Load Share of Available
Large and Imported Hydro per the CSP
Calculator (GWh)
454 469 519 539 565
Large Hydro Included in WestLight Energy’s
Preferred Portfolio (GWh) 423 0 0 0 0
In its 2022 IRP, WestLight anticipated phasing out large hydroelectric resources by 2025 as part of its strategy to transition toward a 100% renewable portfolio. Since that time, market conditions, including increased costs and limited availability of certain RPS-eligible resources, have affected the feasibility and cost effectiveness of achieving this transition within the originally anticipated timeframe. WestLight’s Preferred Portfolio for its 2026 IRP continues to utilize large hydroelectric resources through 2029 in order to balance affordability and customer cost impacts while maintaining alignment with Board approved objectives.
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66 i. Long-Duration Storage Planning
Energy storage is critical to California meeting its reliability and environmental objectives. With respect to reliability objectives, energy storage can help the State meet its capacity needs, which will be amplified by the retirement of natural gas-fired power plants. Energy storage provides energy by shifting electricity from periods of surplus generation to periods when renewable generation is insufficient to serve load.
This capability is particularly valuable during times of day when solar and/or wind generation is limited.
In addition, energy storage can provide ancillary services, including regulation services required by CAISO to maintain grid frequency and support reliable system operations. Energy storage can help California meet its renewables and GHG goals by charging when there is excess renewable generation, thereby avoiding the need to curtail renewable energy generation, and discharging when the emissions intensity of the grid is highest, helping to displace generation from emitting fossil resources.
As California’s reliability needs evolve beyond traditional peak-hour capacity requirements toward longer-duration, multi-hour, and overnight reliability needs, WestLight views long-duration storage as an increasingly important component of the future resource mix. In addition to supporting resource adequacy requirements, long-duration storage can enhance portfolio flexibility, improve utilization of renewable generation, and reduce dependence on conventional fossil resources during extended periods of system stress. However, existing market conditions and RA program rules make long-duration storage less cost-effective than combining multiple shorter-duration contracts to achieve the same system benefits at lower cost. From both a reliability and financial perspective, the ability to charge these resources are critical to their deployment. With potential system-level shortfalls of generation capacity to charge storage generally, further LDES procurement would exacerbate this concern absent procurement or retention of significant generation capacity, such as Diablo Canyon Power Plant.
Furthermore, artificially restricting charging capability below real-world performance as adopted in the RA program threatens to undermine the economic value of these resources, which undermines both affordability and the financial resources available to procure further resources.
CPUC Decision 21-06-035, “the MTR Order,” requires LSEs, including WestLight Energy, to procure specific resources on a specific timeline and includes a requirement for WestLight to procure approximately 24 MW of nameplate capacity of 8-hr storage (“long-duration”) resources. CPUC Decision 23-02-040, the “Supplemental MTR Order” revised the required online dates for the long duration storage and firm clean resources to June 1, 2028. WestLight collaborated with 12 other CCAs to issue a joint Request for Information for long-duration storage resources in 2020. Later in 2020, WestLight participated in California Community Power (CC Power)’s Request for Offers for Long-Duration Storage Resources. As a result of that RFO, WestLight contracted for approximately 15 MW of a lithium-ion long-duration storage resource through CC Power. In 2024, WestLight contracted for an additional 10 MW of lithium-ion long-duration storage, and in 2026, contracted for 15 MW of compressed air long-duration storage through CC Power, exceeding its MTR requirements. CPUC Decision 26-02-057 ordered new procurement for the 2029-2032 timeframe, including a requirement that 25% of the ordered capacity come from either long-duration storage or firm clean resources. WestLight’s total obligation under this order is 114 MW NQC, including 29 MW from long-duration storage or firm clean resources. Based on the limited availability of geothermal resources in the development queue, development challenges associated with WestLight’s existing geothermal contracts, and results from recent RFOs seeking firm capacity, WestLight does not view additional geothermal procurement as commercially feasible until after 2032. As a result, WestLight expects compliance with this portion of the procurement order to rely primarily on long-duration storage resources, which, as already discussed, will exacerbate charging sufficiency issues on the grid and is less cost-effective than stacking two short-duration storage resources. Depending on ELCC values the 29 MW 402
67 NQC of long-duration storage could be between 32 MW (using MTR ELCCs for 2028) and 91 MW (using IRP Filing Requirement ELCCs for 2032) of nameplate capacity.
WestLight included its contracted long-duration storage resources as inputs to its IRP modeling. WestLight also included a variety of long-duration storage durations as candidate resources in its modeling, including 8-hour storage, 12-hour storage, 24-hour storage, and 100-hour storage, along with additional capacity from its compressed air long-duration storage. The Preferred Portfolio is the result of a portfolio optimization that determines the least-cost portfolio that meets the specified targets, including the regulatory requirements of the IRP and WestLight’s voluntary goals. The IRP filing requirements for this IRP did not require LSEs to model compliance with the new procurement order D.26-02-057. The modeled optimal portfolio did not select additional long-duration storage as a cost-optimal resource beyond what WestLight has already contracted. Although WestLight’s IRP modeling did not identify incremental long-duration storage as necessary to satisfy reliability or GHG requirements, Decision 26-02-057 established an additional procurement requirement for such resources as a matter of policy.
In its 2022 IRP, WestLight’s portfolio included 11 MW of 8-hr compressed air storage, 50 MW of 12-hr thermal storage, and 24 MW of 8-hr storage as ordered under the MTR. WestLight’s 2026 IRP includes 25 MW of 8-hr lithium-ion storage and 15 MW of 8-hr compressed air storage. WestLight’s model did not select additional long-duration storage beyond what has been contracted and instead selected additional generating resources like geothermal and wind, and a solar plus storage resource, in order to meet the reliability and GHG emissions targets at least cost.
WestLight’s experience also demonstrates that LSEs are already capable of actively procuring innovative long-duration storage resources through existing market structures, including bilateral contracting, joint procurement efforts, and portfolio optimization processes. This clearly indicates there is no need for central procurement of such resources. Long-duration storage and other firm clean resources may also represent viable pathways for satisfying recently adopted and emerging CPUC procurement requirements related to system reliability and clean energy needs. At the same time, the appropriate resource mix may depend on the final structure and implementation of those requirements, including any interaction with Diablo Canyon extension policies, associated resource adequacy allocations, or the treatment of clean energy attributes. Accordingly, WestLight supports maintaining procurement flexibility so that LSEs can pursue the most cost-effective combination of long-duration storage, firm clean resources, demand-side resources, and other reliability solutions while continuing progress toward California’s decarbonization objectives.
j. Clean Firm Power Planning
Clean Firm Power will be critical to enabling the transition of the California electricity system away from fossil fuels and to clean power. WestLight is particularly interested in clean renewable baseload resources, such as geothermal, to support California’s transition to a 100% clean electricity system by 2045 and to provide reliable carbon free energy that better aligns with WestLight’s load profile.
However, based on the CAISO interconnection queue, developers do not appear to be providing the volumes of clean firm resources that would be required to decarbonize California’s grid cost effectively.
Although the solar and storage that predominate the queue could be used, such an approach would be far from cost optimal. Thus, it is imperative that the Commission and other state leaders pursue effective strategies to incentivize and facilitate the deployment of clean firm resources. 403
68 The MTR and Supplemental MTR orders discussed above also require LSEs including WestLight Energy to procure clean firm power by 2028. CPUC Decision 24-02-047 acknowledged delays and commercial challenges for long lead time resources and allowed for additional compliance flexibility for long lead time resources to come online, until June 1, 2031. WestLight is required to procure approximately 20 MW of nameplate capacity from new clean firm resources by 2031. WestLight has actively pursued these resources and has currently contracted with 33 MW of incremental22 nameplate geothermal, thus meeting its MTR requirements.
To the extent existing resources such as Diablo Canyon continue to provide firm capacity and zero-emitting energy, future procurement requirements should appropriately account for those contributions in order to avoid duplicative customer costs and unnecessary incremental procurement burdens. At the same time, WestLight notes that the portfolio value of associated energy or environmental attributes may differ among load-serving entities depending on renewable goals, customer preferences, and procurement strategies. WestLight therefore supports transparent treatment of costs, attributes, and allocation structures, including flexible or voluntary approaches where feasible. In compliance with statute, WestLight did not include Diablo Canyon in its IRP portfolio modeling. WestLight separately evaluated the potential value of receiving a Diablo Canyon Cost Allocation Mechanism (CAM) allocation following the current extended operations period. Based on this analysis, WestLight estimates that a Diablo Canyon CAM allocation in 2031 would reduce its Resource Adequacy (RA) procurement costs by approximately $3.5 million for that year.
WestLight has included existing and new construction clean firm resources in its portfolio modeling, and the model selects clean firm resources to be included in its portfolio in order to meet WestLight’s voluntary 100% renewable goal and the assigned GHG emissions targets. WestLight's modeling inputs, including cost and resource availability assumptions, are consistent with the 2026-2027 TPP and market conditions as of Spring 2026. These assumptions were informed in part by recent results from CC Power's solicitation for clean generation and capacity resources, which received proposals for both conventional geothermal and Enhanced Geothermal Systems (EGS). WestLight’s preferred portfolio includes 35 MW of existing geothermal and 323 MW of new geothermal in 2045. Of the 323 MW new geothermal resources in its Preferred Portfolio, 18 MW are from EGS. Through WestLight’s iterative modeling process, clean firm resources emerged as increasingly important by 2045 for achieving GHG emissions targets under a fully clean electricity portfolio at least cost, particularly during overnight and winter peak periods. This became more apparent when WestLight utilized its custom load shape in the CSP Calculator, which exhibits higher winter peaks than the default CSP load profile. The winter-peaking characteristics of WestLight’s load increased the value of clean firm generation in maintaining reliability and reducing reliance on net system power during periods of lower variable renewable output. While solar and battery storage remain important portfolio resources, they were less effective at reducing emissions during overnight and winter peak periods when solar generation is limited and storage resources face duration and charging constraints. Under these conditions, the portfolio relied more heavily on net system power to serve load, making it more difficult to achieve lower emissions outcomes in the CSP Calculator.
Ultimately building more clean firm resources was selected as more cost effective than building excess solar plus storage, even given higher contract prices for clean firm resources. These results are consistent 22 WestLight defines "incremental" geothermal as geothermal capacity incremental to the CPUC's D.21-06-035 baseline generator list
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69 with other results that suggest clean firm resources become increasingly important for affordability as renewable energy content of the energy mix approaches 100%23.
In WestLight’s 2022 IRP, the Preferred Portfolio included 49 MW of geothermal resources by 2035, compared to 121 MW in the 2026 IRP Preferred Portfolio. This increase is driven by several factors, including the higher load forecast used in the 2026 IRP modeling and updated assumptions regarding the relative cost and availability of certain resource types. In particular, assumptions related to the significantly higher cost of offshore wind development relative to 2022 IRP assumptions resulted in geothermal resources emerging as a more cost-effective option in the modeling results.
WestLight’s contracted clean firm resources includes capacity from resources outside of CAISO since there is currently limited development within California. These resources must be imported into CAISO. In order for imported resources to qualify for resource adequacy inside CAISO, they must be paired with Import Capability where they are imported. Import Capability is allocated by CAISO to LSEs depending on contracts and requested imports and is subject to the Maximum Import Capability (MIC) at each intertie.
If LSEs collectively request more Import Capability at a given intertie than the Maximum Import Capability, CAISO allocates amounts pro rata to LSEs based on various criteria. WestLight conducted a comprehensive transmission assessment, including evaluation of potential transmission upgrades required for increased MIC to allow resource adequacy eligibility for these imported resources. The results of that assessment are presented in Section III.m.
Currently, internal analyses suggest that the assessment of the Maximum import Capability may be unduly conservative, underestimating the full ability of the system to simultaneously deliverable imports.
Furthermore, the current bilateral market of allocated Import Capability does not appear to be effective in matching import rights to contracted imports, with large volumes of import capability appearing to go unused or strategically held in reserve by market participants. WestLight is actively involved in pursuing enhancements to the MIC process to ensure that transmission capacity is fully utilized for actual energy flows and California can import the clean firm resources needed to ensure reliability and decarbonization.
WestLight anticipates that it will need more Import Capability than the current Maximum Import Capability at several of the interties where it plans to import its clean firm power, hence its initiating the CAISO stakeholder process for MIC reforms, along with its partners Shell, CalCCA, and Six Cities.
WestLight incorporates considerations related to Import Capability availability and transmission deliverability into its long-term procurement planning to manage reliability and resource adequacy risks associated with imported resources. WestLight supports transmission upgrades that would increase Maximum Import Capability at several interties, including IID-SDGE andIID-SCE, which may serve to alleviate these concerns.
23 J.C.S. Long, E. Baik, J.D. Jenkins, C. Kolster, K. Chawla, A. Olson, A. Cohen, M. Colvin, S.M. Benson, R.B. Jackson, D.G. Victor, and S.P. Hamburg, California Needs Clean Firm Power, and So Does the Rest of the World: Three Detailed Models of the Future of California’s Power System All Show That California Needs Carbon-Free Electricity Sources That Don’t Depend on the Weather (Environmental Defense Fund, Stanford University, Princeton University, and Energy & Environmental Economics, 2021) 405
70 California Community Power Geothermal Coordination
CC Power recognizes the long-term need for clean firm power for its members, and recently announced Geothermal Exploration, Offtake and Development Engagement (GEODE) agreements with three geothermal developers with innovative approaches to development targeted at unlocking scale-up of in-state geothermal capacity24. CC Power sees these proactive relationships between offtakers and industry as pivotal in overcoming the commercial and infrastructure challenges geothermal opportunities face.
Additionally, as a joint procurement entity representing 30,000 GWh of collective annual load, CC Power is able to engage with a larger diversity of developers and opportunities with different risk profiles than what could be pursued by an individual load serving entity.
CC Power GEODE Agreement Capacity
WestLight’s IRP includes its participation in CC Power’s GEODE agreements, which are expected to deliver 320 MW of total capacity in the early 2030s. The GEODE agreements are principally focused on development opportunities in Northern California that both avoid import constraints and directly offset power costs for CC Power’s members. CC Power has coordinated with its GEODE partners in representing expected development opportunities in the IRP. Both Atlantica and XGS have site control, and data in the RDT reflects the specific infrastructure requirements to unlock specific geothermal development opportunities. Atlantica and XGS are planning to deploy advanced closed-loop technology, which both enables development beyond the geologic constraints of conventional hydrothermal development and minimizes water requirements. Closed-loop technology has been demonstrated in the field and recently through commercial development in Germany25. Through its GEODE agreement, Zanskar is applying its unique capabilities leveraging artificial intelligence and modeling to discover new hydrothermal systems.
Zanskar has not secured site control for GEODE yet but is actively evaluating in-state opportunities. CC Power recommends that WestLight include its share of a 20 MW New Mexico project and 100 MW of California development split between three commercially attractive opportunities in California in its IRP to represent the expected transmission requirement to facilitate development of potential Zanskar projects. The GEODE projects are represented with online dates in the early 2030s but could be accelerated if transmission is readily available. GEODE projects are reported as “Review” status in the RDT to reflect the active commercial discussions between CC Power and developers on specific project opportunities.
CC Power Enhanced Geothermal System (EGS) Capacity
WestLight’s IRP also includes its participation in CC Power’s engagement with EGX, a developer of a near-field 100 MW enhanced geothermal system (EGS) project in Lake County. CC Power is currently under exclusivity for this project, which has site control and is planning to build upon Fervo Energy’s success in applying EGS technology to development in Nevada and Utah. This project is represented with an online date in 2033 but could be accelerated if transmission is made readily available. This project is also reported as “Review” status in the RDT given the advanced nature of commercial discussions.
CC Power Strategic Geothermal Capacity Coordination
24 See “CC Power Signs 3 GEODE Agreements to Incentivize California Geothermal Development” (April 13, 2026) at https://cacommunitypower.org/cc-power-signs-3-geode-agreements-to-incentivize-california-geothermal-development/ 25 See “Eavor’s First-of-Its-Kind Closed-Loop Geothermal Project Produces Grid Power in Germany” (January 8, 2026) at https://www.powermag.com/eavors-first-of-its-kind-closed-loop-geothermal-project-produces-grid-power-in-germany/ 406
71 WestLight has coordinated with CC Power on representing geothermal capacity needs beyond the opportunities described above. Collective, CC Power entities are anticipating nearly 500 MW of additional geothermal development need to meet 2045 needs. A key challenge with geothermal development is that even with next-generation technologies, the best opportunities are locationally constrained.
Accordingly, it’s critical that transmission is proactively planned to areas that are commercially viable for both developers and offtakers. CC Power strongly discourages the Commission from taking the default approach of mapping resource potential to areas with sufficient transmission capacity and instead work to support infrastructure that provides access to high-quality resource areas as recommended by American Clean Power26.
In the interest of providing a consistent indication of development areas with both high-quality resources and commercial offtake interest, CC Power members have taken a methodical process to mapping and representing long-term geothermal needs. First, CC Power has leveraged one of the best available datasets on next-generation geothermal potential: supply curves from Wilson Ricks and Jesse Jenkins’ May 2025 study on national-scale adoption of EGS27. The Ricks & Jenkins study leverages the recent Stanford thermal modeling already used by the Commission, but also specifically characterizes near-field EGS resources—which are likely to be the first and most economical projects to be developed. CC Power applied both technological and economic filters to the supply curve data (depth <= 4.5 km, temperature <= 275C, inferred LCOE <= $100/MWh, project capacity > 50 MW). Data points that met CC Power’s filter criteria are represented as the red dots in Figure 27 below. 26 See page 10-11 of “American Clean Power – California Opening Comments on the Proposed Decision Requiring 2029-2032 Electric Resource Procurement and Transmitting Portfolios for the 2026-27 Transmission Planning Process” at https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100948.PDF 27 Paper at https://zero.lab.princeton.edu/wp-content/uploads/2025/06/Ricks-Jenkins-2025-Pathways-to-national-scale-adoption-of-enhanced-geothermal-Joule.pdf; leveraged datasets available at https://zenodo.org/records/15485307
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72 Figure 27. CC Power Strategic Geothermal Mapping
Using the filtered data, CC Power identified clusters of opportunities with distinct transmission needs:
West North Bay, East North Bay, Humboldt, Shasta, Klamath, Pit River, Surprise Valley, Lassen, and Imperial Valley (see colored polygons in Figure 27). CC Power members strongly prefer resources in CAISO due to import capacity constraints, and accordingly did not carry Imperial Valley, Klamath, and Shasta further in the analysis. Although Surprise Valley and Lassen are currently outside the CAISO, CC Power is encouraged by the 2026-27 focus on adding import capacity to the Hilltop substation in Northeastern California and sees a lot of synergies with creating better access to Northern Nevada resources and in-state wind. Based on the supply curve filtering, the six remaining areas of interest individually represent
0.8 to 13.5 GW each of theoretical capacity. CC Power has represented its interest using two tiers: the East North Bay and West North Bay with 150 MW of total interest (out of 10+ GW theoretical capacity each) and the other four areas with 50 MW of interest (out of 0.8 to 1.6 GW of theoretical capacity each).
WestLight’s IRP includes its share of these opportunities with a substation designated that is indicative of the resource area’s transmission needs. Given their pre-commercial nature, these projects are listed as “PlannedNew” but flagged for retention priority given the need to proactively plan transmission. CC Power will continue developing relationships with industry to further commercialize this capacity. 408
73 k. Non-CAISO, including Out-of-State, Wind Planning
Out-of-state wind can offer several advantages over in-state wind. Specifically, it generally offers higher capacity factors and production profiles that differ from resources available in California. These production profiles are a better fit for WestLight’s portfolio, as their generation profile better complements solar resources. These attributes can make out of state wind an attractive resource.
However, the higher cost and risk associated with interconnection and import rights are a concern.
Additionally, WestLight’s Board has expressed concern around whether union labor would be used to construct of out of state wind projects and whether these projects would be subject to the same level of environmental siting analysis and permitting as in-state projects.
WestLight included several out-of-state wind resources as candidate resources in its 2026 IRP modeling, and 330 MW of Wyoming wind was selected in 2040 and additional 70 MW was selected in 2045.
WestLight also included its contracted New Mexico wind project, Sunzia, in its modeling. The Sunzia project has built its own transmission to deliver energy to California and utilizes the CAISO’s Subscriber Participating Transmission Owner (SPTO) structure. WestLight supports the SPTO framework and recognizes its potential to facilitate the development and delivery of out-of-state clean energy resources needed to support California’s long-term clean energy and reliability goals. The Wyoming wind would require construction of new transmission facilities, such as the TransWest Express project, which represents a significant risk. And, similar to the discussion of out-of-CAISO firm clean power, a Wyoming wind project would be subject to Import Capability allocations in order to qualify for resource adequacy.
WestLight notes that the long-term viability of out-of-state wind resources depends significantly on transmission development, intertie deliverability, and MIC availability. Recent stakeholder processes have increasingly recognized the need to enhance MIC frameworks so that load-serving entities can secure import capability when and where needed. WestLight is one of a group of CAISO stakeholders that is leading efforts at continued MIC reform and expansion efforts, along with transmission upgrades that improve practical and commercially viable access to high-quality out-of-state renewable resources. Better alignment between procurement planning and import deliverability would help reduce portfolio risk and expand cost-effective clean energy options for customers. WestLight conducted a comprehensive transmission assessment, including evaluation of potential transmission upgrades required for MIC expansion associated with out-of-state wind resources. The results of that assessment are presented in Section III.m. One key transmission development relevant to this analysis is the TransWest Express project, which is currently under development and construction and is intended to deliver up to 3,000 MW of Wyoming wind generation to western markets, including California.
In its 2022 IRP WestLight selected 326 MW of out of state wind in its portfolio by 2035. In its 2026 Preferred Portfolio, WestLight includes 220 MW of out of state wind in its 2035 portfolio, which corresponds to the out of state wind that it has already contracted. Additional out of state wind was not selected as a cost-optimal resource until 2040.
l. Offshore Wind Planning
Offshore wind is a promising resource that can offer several advantages over onshore wind. The generation profiles tend to have higher capacity factors and are anti-correlated with solar generation profiles, making offshore wind an important complement to California solar resources. Offshore wind has been successfully implemented in other areas of the world, however the process to implement it in 409
74 California is still in the early stages and currently subject to potentially severe development challenges. In 2023, the California Legislature passed AB 1373, which authorized the CPUC to determine the need for centralized procurement of certain long lead-time clean energy resources, including offshore wind, and, if warranted, direct the California Department of Water Resources (DWR) to procure those resources on behalf of load-serving entities. The 2025-2026 TPP with updates does not include any offshore wind capacity, likely due to the high levelized cost of energy of offshore wind resources. However, the complete assumptions for the IRP Inputs and Assumptions include the central procurement ordered by AB 1373, which includes offshore wind procurement in the statewide portfolio.
WestLight included offshore wind as a potential resource in its modeling beginning in 2040. However, the model did not select offshore wind to be included in its portfolio in any year. Offshore wind is significantly more expensive than other candidate resources and doesn’t provide corresponding benefits to offset the higher costs. Instead of offshore wind, WestLight’s modeling selects onshore wind or enhanced geothermal resources. Even when onshore wind and geothermal resources are unavailable, the model selects over-building solar plus storage rather than building offshore wind at the current forecasted prices.
WestLight is dedicated to clean and reliable electric system and acknowledges the potential of offshore wind. To support offshore wind development in California, WestLight, as a member of California Community Power, executed a Memorandum of Understanding with CADEMO in April 2024. CADEMO is a 60 MW offshore wind facility planned for development in the Morro Bay region. The project will act as a pilot project to test and demonstrate the processes necessary for wider deployment of offshore wind resources in California. Real and significant challenges face the development of offshore wind, including implementation and feasibility challenges, which the CADEMO project will test, providing real-world data and experience to inform the potential expansion of offshore wind. WestLight encourages the CPUC to incorporate real-world data on offshore wind and make decisions to achieve the state’s carbon goals in the most cost-effective way possible. SB 100 does acknowledge that the 2045 carbon goals are contingent on cost effectiveness.
AB 1373 directs DWR to procure offshore wind according to a specified timeline and provides for cost recovery from ratepayers. WestLight has concerns regarding the use of centralized procurement mechanisms for resources that may ultimately be funded by customers regardless of cost, local procurement preferences or existing resource commitments. Offshore wind is a promising technology with the potential to contribute to California’s long-term clean energy goals; however, affordability should remain an important consideration in resource procurement decisions. Given California’s already high electricity rates, procurement requirements for high-cost resources should be carefully evaluated to ensure that anticipated benefits justify the associated costs.
The limited development of offshore wind in California is driven primarily by project maturity, development challenges, and current project economics rather than a lack of buyer interest. Centralized procurement requirements may therefore have limited ability to address the underlying barriers to deployment. In addition, centralized procurement reduces local control over resource planning and procurement decisions by requiring load-serving entities to support procurement activities that may not align with their individual portfolio needs or existing procurement commitments. WestLight encourages the state to pursue approaches that balance long-term resource development objectives with customer affordability, local procurement flexibility, and recognition of resources already procured by load-serving entities.
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75 WestLight’s 2022 IRP included 288 MW of offshore wind in 2035. In the 2026 IRP, offshore wind is not selected by RESOLVE in the CPUC’s least cost portfolio, nor is it selected in WestLight’s own modeling.
Both the CPUC and WestLight are modeling a system that meets climate and reliability goals at least cost without using offshore wind. The non-selection of offshore wind reflects the much higher costs of developing offshore wind, and the lack of commensurate benefits relative to other onshore resources such as geothermal or onshore wind.
m. Transmission Planning
WestLight conducted a transmission analysis to assess whether the transmission system can support delivery of the resources included in its Preferred Portfolio and to identify potential transmission constraints or upgrade needs associated with those resources. a. Resources with flexible locations
Table 29 - Planned Resources with Flexible Locations shows planned resource quantities identified in the RDT and represent proposed MW allocations within broader study areas that can remain flexible for future refinement through the CPUC and CAISO busbar mapping process. For these resources that are not yet contracted or tied to specific interconnection queue positions, WestLight recognizes that some flexibility remains for staff-led refinement or relocation during transmission modeling and busbar mapping efforts, provided such adjustments do not materially impact procurement feasibility, commercial viability, or deliverability assumptions.
Table 29: Planned Resources with Flexible Locations
Project Name Technology
2028
Capacity
(MW)
2030
Capacity
(MW)
2035
Capacity
(MW)
2040
Capacity
(MW)
2045
Capacity
(MW)
PVHybrid_Desert Solar PV 314 314 434 663.5
Storage_Hybrid_Desert Hybrid
Storage 314 314 434 663.5
SCE_Northern_Wind Onshore
Wind 214 214 214
PGE_NGBA_Wind Onshore
Wind 165 165 165
SCE_NOL_Wind Onshore
Wind 108 108 108
San_Diego_Wind Onshore
Wind 85 85 85
SCE_Eastern_Wind Onshore
Wind 72 72 72
PGE_GBA_Wind Onshore
Wind 22 22 22
PGE_Kern_Wind Onshore
Wind 22 22 22
SCE_EOP_Wind Onshore
Wind 21 21 21
411
76 PGE_NE_CA_Wind Onshore
Wind 51
Additional Ormat Geothermal -
Nevada Geothermal 2.74 2.74 2.74 2.74
For projects in Table 29 the proposed areas and procurement ratios are consistent with the Base Case CPUC transmitted to CAISO for the 2026–2027 TPP cycle. In addition, CAISO’s 2025 TPD heatmap generally shows available TPD capacity in the areas where WestLight is proposing the largest portion of its planned MW procurement, notable exceptions including the Desert and SCE Eastern regions. By assigning procurement amounts to these areas, WestLight’s intent is to make best use of planned and existing transmission infrastructure that may become available through anticipated withdrawals from the interconnection queue. WestLight's portfolio includes significant quantities of solar PV and hybrid storage resources located within the Desert study area, growing from approximately 630 MW by 2030 to more than 1.3 GW by 2045. Desert regions are attractive development areas due to resource quality, real estate availability, permitting viability, community support, and existing transmission infrastructure. WestLight believes the level of desert resource development reflected in its portfolio is consistent with current commercial interest and developer expectations. As such, WestLight encourages the CPUC to view these portfolio assumptions as a meaningful signal of likely future development activity and to consider whether corresponding transmission planning and policy-driven upgrades are warranted to support that anticipated growth.
Looking far forward, to the CAISO 20-Year Transmission Outlook, CAISO identifies numerous conceptual transmission reinforcements across California and the Western Interconnection. Rather than restating the full list, WestLight highlights below the projects most relevant to its long-term portfolio, particularly within the Desert study area where the majority of WestLight's planned resource capacity is expected to be developed. These projects represent significant long-term critical-path transmission investments that will require substantial planning, permitting, and construction efforts. Accordingly, early consideration of these transmission corridors will be important to ensure they can support California's evolving resource portfolio and WestLight's long-term procurement needs.
Table 30: Transmission Upgrades in Desert Study Area
20-Year Outlook
Project Description Status
New Palo Verde –
Imperial Valley 500 kV
line
Supports Greater Imperial,
Riverside/Palm Springs solar, Arizona
solar, and assumed imports of ~2,882
MW of out-of-state wind injected at
Palo Verde. (California Independent
System Operator)
Not yet recommended by a
CAISO TPP
New Trout Canyon –
Lugo 500 kV line
Supports Southern Nevada solar,
Eldorado resources, and assumes
~3,500 MW of out-of-state wind
injected at Eldorado. It relieves the
Eldorado–Lugo corridor. (California
Independent System Operator)
CAISO approved this as a
policy-driven project in the
2025–2026 Transmission Plan,
and it is now in the
competitive solicitation phase.
412
77 b. Planned and contracted resources with fixed locations, contracted imports need MIC WestLight notes that certain planned and contracted resource categories are inherently geographically constrained and therefore should be treated as location-specific for transmission planning purposes. In particular, WestLight has significant geothermal procurement activities currently underway, and these resources can only reasonably be developed in areas with viable geothermal steam reservoirs.
Accordingly, the geothermal locations identified by WestLight should be considered investment-grade assumptions for long-term transmission planning and busbar mapping purposes, rather than resources that can be flexibly relocated during modeling refinement.
Table 31: Planned and Contracted Resources with Fixed Locations Plan Project
Name Technology 2028 MW
2030
MW
2035
MW
2040
MW
2045
MW Location
Representative
Point
of
Interconnection
Planned
CCPower
Zanskar
Lassen
Geothermal 4.6 4.6 4.6
Lassen
County,
CA
Shaffer 345 kV
(LMUD/NVE)
Planned
CCPower
Zanskar
SonomaMen
do
Geothermal 4.6 4.6 4.6
Sonoma
County,
CA
Cloverdale 115
kV
Planned
CCPower
Zanskar LakeGeothermal 4.6 4.6 4.6
Lake
County,
CA
Redbud 115 kV
Planned
CCPower
Atlantica
Obsidian
Geothermal 13.7 13.7 13.7
Inyo
County,
CA
Kramer 230 kV
Planned
CCPower
XGS
RedHillsPh1
Geothermal 2.0 2.0 2.0
Lake
County,
CA
Konocti 60 kV
Planned
CCPower
XGS
RedHillsPh2
Geothermal 8.6 13.7 13.7
Lake
County,
CA
Konocti 60 kV
Planned
CCPower
EGX
PluthRanch
Geothermal 18.4 18.4
Lake
County,
CA
Cache-Highlands
115 kV
Planned
CCPower
Zanskar OOSGeothermal 2.7 2.7 2.7 New
Mexico
Afton 345 kV
(New Mexico)
Contracted
Fish Lake
Geothermal Geothermal 2.31 2.31 2.31 2.31 2.31 Esmeralda , NV
Import - In
Development
NV Energy Silver
Peak 55kV
413
78 Contracted
Ormat
Geothermal
Portfolio -
Dogwood
Geothermal 4.28 4.28 4.28 4.28 4.28 Imperial,
CA
Import - In
Development
CAISO delivery at
IID-SDGE_ITC or
IID-SCE_ITC
Contracted
Ormat
Geothermal
Portfolio -
IID
Geothermal 1.19 3.93 3.93 3.93 3.93 IID
Import - In
Development
IID New Seaside
SS 161 kV ("L"
line) / CAISO
delivery at IID-SDGE_ITC or IID-SCE_ITC
Contracted
Whitegrass Geothermal 6 6 6 6 6 Lyon, NV
Import - In
Development
NV Energy North
System (#210
Distribution Line)
CAISO Delivery at
MONAIPPDC_ITC
Planned
CCPower
StrategicGeo
NGBA East Geothermal 73 73
Lake
County,
CA
Redbud 115 kV
Planned
CCPower
StrategicGeo
NGBA West Geothermal 63.4 73
Sonoma
County,
CA
Cloverdale 115
kV
Planned
CCPower
StrategicGeo
Humboldt Geothermal 23.4
Humboldt
County,
CA
Maple Creek 115
kV
Planned
CCPower
StrategicGeo
Surprise
Valley
Geothermal 23.4
Modoc
County,
CA Hilltop 345 kV
Planned
CCPower
StrategicGeo
Lassen Geothermal 23.4
Lassen
County,
CA
Shaffer 345 kV
(LMUD/NVE)
414
79 Planned
CCPower
StrategicGeo
PitRiver Geothermal 23.4
Shasta
County,
CA
Hat Creek 2 230
kV
Planned
SCE WY
Wind
Onshore
Wind 330 400 Wyoming
Planned import
WY to SCE -
Eldorado
WestLight emphasizes that achievement of California's long-term reliability and decarbonization goals will require proactive transmission planning sufficient to support geographically constrained clean energy resources, including geothermal generation and regional import resources. California policy frameworks and planning studies have consistently identified geothermal generation as a critical clean firm reliability resource, and statewide decarbonization targets are expected to require development of a substantial portion of the geothermal potential identified by the U.S. Geological Survey (USGS). Many of the geothermal resources reflected in WestLight's portfolio, both within and outside the CAISO balancing authority area, represent new generation development that will require additional deliverability and transmission infrastructure to fully contribute toward California's 2045 policy objectives.
WestLight appreciates CPUC staff's efforts in the 2026–2027 TPP to identify unaccounted-for TPD associated with long lead-time resources and transmit those quantities to CAISO for consideration in transmission planning studies intended to preserve future deliverability. WestLight believes this framework represents an important evolution beyond reliance on residual MIC availability and after-the-fact import capability expansion by proactively incorporating long lead-time resource needs into the TPP process and associated transmission upgrade assessments. Continued refinement of this approach may help ensure that geographically constrained best-fit resources, including geothermal and out-of-state wind resources, remain commercially viable and deliverable as California advances toward its long-term reliability and decarbonization goals.
Given WestLight's contracted import portfolio, ongoing geothermal procurement efforts, and the State's increasing need for diverse clean and reliable resources, WestLight respectfully encourages the CPUC to continue expanding consideration of these resource types within the IRP-to-TPP planning process, including through base case assumptions and transmission studies that evaluate deliverability needs before resource development is constrained by limited available import capability. Such an approach would be consistent with California's broader regionalization and market integration objectives, including EDAM and DAME, while supporting reliability, affordability, and efficient utilization of transmission infrastructure across the Western Interconnection.
Also, in the 2022-2023 TPP CAISO identified upgrades needed to enable MIC expansion that was, at that time, directed by the CPUC. WestLight considers the upgrades below, which originated in that analysis, as necessary for its portfolio.
Table 32: Transmission Upgrade Projects for MIC Expansion TP Project ID Project PTO
2223-P-10 Mira Loma-Mesa Upgrade SCE
415
80 2223-P-17 Serrano-Alberhill-Valley 500 kV 1 Line Upgrade SCE 2223-P-21 Vista-Etiwanda 230 kV 1 Line Upgrade SCE
2223-P-08 IV-North of Songs 500 kV line SDG&E
2223-P-19 Upgrade on Hoodoo Wash-North Gila and
Hassayampa-North Gila Transmission Lines SDG&E
2223-P-12 North of Songs-Sorreno 500 kV Line
Lotus
Infrastructure
Global Operations
2223-P-11 North Gila–Imperial Valley 500 kV line HWT
2223-P-08 IV-North of Songs 500 kV line and North of Songs Substation HWT
WestLight’s long-term portfolio includes Wyoming wind resources beginning in the 2040–2045 timeframe, which are likely to be delivered via the TransWest Express transmission project. The TransWest Express transmission project, currently under development and construction, is intended to deliver up to 3,000 MW of Wyoming wind generation to western markets, including California. As such, TWE can provide an important transmission pathway supporting future development and deliverability of Wyoming wind resources that are consistent with WestLight's long-term procurement assumptions. c. Contracted Resources with CODs After Spring 2024
416
81 Table 33 - Resources Contracted with CODs After Spring 2024 Plan Project
Name Technology 2028MW
2030
MW
2035
MW
2040
MW
2045
MW
Queue
Position Location Point of Interconnection COD Deliverability Contracted
Wright
Storage 4hr Storage 80 80 80 80 80 Q779 Merced, CA
PG&E Q779
Switching Station
bus connection to
the Los Banos –
Panoche #1 230 kV
Transmission Line
Planned COD
10/21/2026
Deliverability
studied,
allocation
locked
Contracted
SandHill Onshore
Wind 50 50 80 80 80 Q1363 Alameda, CA
Delta Switching
Yard – Tesla 230kV
line
Planned COD
4/28/2027
Deliverability
studied,
allocation
locked
Contracted
Tumbleweed
Storage 8hr Storage 14.77 14.77 14.77 14.77 Q1217 Kern, CA Whirlwind Substation 230kV Planned COD
6/1/26
Deliverability
studied,
allocation
locked
Contracted
WillowRock
Storage 4hr Storage 15 15 15 Q1782 Kern, CA Whirlwind Substation 230kV Planned COD
7/1/2030
Deliverability
studied,
allocation
locked
Contracted
Darden Solar Solar PV 84.56 84.56 84.56 Q1949 Fresno, CA PG&E Los Banos-Midway #3 500kV
Transmission Line
Planned COD
6/1/202828
Deliverability
studied,
allocation
locked
28 Queue COD is accelerated compared to contract COD. WestLight is including contract COD in this table 417
82 Plan Project
Name Technology 2028MW
2030
MW
2035
MW
2040
MW
2045
MW
Queue
Position Location Point of Interconnection COD Deliverability Contracted
Darden
Storage 4hr Storage 91.48 91.48 91.48 Q1949 Fresno, CA
PG&E Los Banos-Midway #3 500kV
Transmission Line
Planned COD
6/1/202829
Deliverability
studied,
allocation
locked
Contracted
Gabriel
Storage 4hr Storage 65 65 65 65 Q2113
Los
Angeles,
CA
Rio Hondo
Substation 220kV
Bus
Planned COD
6/1/202730
Deliverability
studied,
allocation
locked
Contracted
Gabriel
Storage 8hr Storage 10 10 10 10 Q2113
Los
Angeles,
CA
Rio Hondo
Substation 220kV
Bus
Planned COD
6/1/202731
Deliverability
studied,
allocation
locked
Contracted
Arica Solar
Solar Plus
Storage
Hybrid
100 100 100 100 Online Riverside,
CA
SCE Red Bluff 230
kV 3/26/2024
Deliverability
studied,
allocation
locked
Contracted
Arica Hybrid
Storage
Solar Plus
Storage
Hybrid
50 50 50 50 Online Riverside,
CA
SCE Red Bluff 230
kV 3/26/2024
Deliverability
studied,
allocation
locked
Contracted
Chaparral
Solar
Solar Plus
Storage
Hybrid
102 102 102
Online/
Q1215
Q1319
Kern, CA Whirlwind 220 kV 5/8/2025
Deliverability
studied,
allocation
locked
29 Ibid.
30 WestLight is including contract COD for this resource, which is in advance of the planned Queue COD. This resource is undergoing a CAISO Limited Operation Study (LOS)
31 Ibid.
418
83 Plan Project
Name Technology 2028MW
2030
MW
2035
MW
2040
MW
2045
MW
Queue
Position Location Point of Interconnection COD Deliverability Contracted
Chaparral
Hybrid
Storage
Solar Plus
Storage
Hybrid
52 52 52
Online/
Q1215
Q1319
Kern, CA Whirlwind 220 kV 5/8/2025
Deliverability
studied,
allocation
locked
Contracted
Lockhart
Storage 4hr Storage 45 45 45
Online/
0043CON
V Q1617
Q1775
San
Bernardin
o, CA
SCE Kramer 220 kV 4/1/2026
Deliverability
studied,
allocation
locked
Planned
Additional
Ormat
Geothermal -
Nevada
Geothermal 2.74 2.74 2.74 2.74
Will
either go
to a
Vegas
Node or
Utah/IPP
Node
Nevada Nevada
not in
interconnection
queue yet LLR
no clear
transmission
plan for this
yet, WestLight
has no MIC,
Ormat has to
assign specific
resources into
the contract,
which is "more
likely to be
eligible for MIC
in the 2030
timeline"
Contracted
Nova Storage
4hr Storage 50 50 50 Q1645 Riverside, CA
SCE 500kV Valley
Substation
Not online yet
but NCQ sheet
has FC on other
tab
Deliverability
studied,
allocation
locked
419
84 For contracted resources executed after formation of the Spring 2024 IRP baseline portfolio, WestLight recognizes that certain associated transmission assumptions and deliverability needs may not yet be fully incorporated into prior CAISO TPP studies or baseline busbar mapping efforts. WestLight did consider available interconnection queue information, transmission capability assessments, and project study results when choosing these resources. The resources identified in Table 33 are executed procurement commitments made after formation of the baseline portfolio. WestLight therefore encourages the CPUC and CAISO to consider these contracted resources during future busbar mapping, deliverability preservation efforts, and transmission planning studies so that transmission planning assumptions appropriately reflect actual procurement commitments and the transmission infrastructure necessary to support their successful interconnection and deliverability. d. Resources Contracted with CODs Before Spring 2024
Table 34 - Resources Contracted with CODs Before Spring 2024 Project Name Technology
2028
Capacity
(MW)
2030
Capacity
(MW)
2035
Capacity
(MW)
2040
Capacity
(MW)
2045
Capacity
(MW)
Point of Interconnection
Heber 2 Geothermal 26 26 26 0 0 Mirage 230 kV, MIC locked until 2037
Bidwell Ditch Small Hydro 2 2 0 0 0 Private 60 kV tap to PG&E transmission line
Burney Snow
Mountain Small Hydro 3 3 3 0 0 SPI 230 kV tap to PG&E’s Pit #3 – Pit #1 230 kV line Calwind Onshore
Wind 8.71 0 0 0 0 AR1946 Pinwheel 12 kV
Clover Small Hydro 0.99 0.99 0 0 0
Private 60 kV tap to PG&E
transmission line, cedar
creek
Coram 1 Onshore
Wind 3 3 0 0 0
Tempest 12kV distribution
out of Midwind 12kV
Substation
Coram 2 Onshore
Wind 3 3 0 0 0
Puff 12kV distribution line
out of Midwind 12kV
Substation
Coram 3 Onshore
Wind 7.5 7.5 0 0 0
Windhub-Dutchwind-Flowind 66kV distribution
line out of Dutchwind 66kV
Substation
DosPalos
Solar Solar PV 3 3 3 3 0 Dos Palos Substation
Geysers Geothermal 35 35 35 35 35 N/A Portfolio
Hatchet
Creek Small Hydro 7.5 7.5 7.5 0 0 Private 230 kV tap to PG&E transmission line, Cove rd Mustang 2 Solar PV 100 100 100 0 0 PG&E Mustang Switching Station 230kV
420
85 Roaring
Creek Small Hydro 2 2 0 0 0
Private 230 kW tap to
PG&E transmission line,
Cove rd
Shiloh Onshore
Wind 150 150 150 0 0 PG&E Birds Landing Substation
Sky River Onshore
Wind 30.2 30.2 30.2 30.2 0 SCE 220 kV Highwind Substation Voyager 2 Onshore
Wind 63.175 63.175 0 0 0 SCE Windhub Substation
Wright Solar Solar PV 200 200 200 200 200 Los Banos – Panoche #1 230kV line
For contracted resources that were already online or otherwise included in the IRP baseline portfolio formation process, WestLight notes that associated transmission needs have generally already been contemplated through prior IRP and CAISO TPP processes. The IRP baseline utilized for the 2025 Inputs & Assumptions was formed using online resources reflected in the CAISO Master Generating Capability List as of Spring 2024, together with in-development resources identified through December 2023 LSE filings and subsequent minimum-build assumptions. As a result, many currently contracted resources reflected in WestLight’s portfolio have already been incorporated into statewide transmission planning assumptions and associated reliability and deliverability assessments.
Table 35 shows a unique project that has a COD after Spring 2024 but was included in the 2022-2023 TPP base case. No further consideration is needed to secure this project’s deliverability.
Table 35: Contracted Resources with Studied and Secured Deliverability Project
Name Technology 2028 MW
2030
MW
2035
MW
2040
MW
2045
MW Location Point of Interconnection Deliverability
Sunzia Onshore
Wind 220 220 220 220 220
Lincoln,
Torrance, and
Guadalupe,
NM
Palo Verde - 500
kV Pinal Central
Substation
MIC is locked
until 2040
WestLight evaluated available information regarding transmission deliverability, interconnection status, and transmission upgrade requirements for contracted and planned resources using CAISO and CPUC planning materials, interconnection study information, and in-service schedules for planned transmission, and current transmission capability. Transmission needs vary by resource type, location, and stage of development. Some contracted resources are located in areas where transmission upgrades have already been identified and placed into service, some contracted resources are still waiting on in flight transmission upgrades to secure full capacity deliverability status. In Table 36 WestLight has identified the following transmission upgrades as specifically necessary for generators in the portfolio, including resources outside of the CAISO balancing authority area. 421
86 Table 36: Transmission Upgrades required to support WestLight’s portfolio ID Network Upgrade PTO Study Type of
Upgrade
In-service Year
at Approval in
Transmission
Plan
Expected
CPUC Filing
Current
Expected
Construction
Start
Current
Expected In-Service Date
C14P2-FGR06 Transient Stability: Updated
dynamic models required PG&E C14 Reliability TBD TBD
C14P2-GGR14 Birds Landing Sw Sta 230 kV CB
212, 412 overload mitigation PG&E C14 Reliability TBD TBD C14P1-GGR09 Tesla 230 kV Bus Overstress (2
CB with Line relocations) PG&E C14 Reliability Jan 2029 Apr 2031 Apr 2031 C14P2-FGR04
Los Banos 500 kV circuit
breakers 822, 832 & 842
overstress
PG&E C14 Reliability Apr 2026 Sep 2026 Sep 2026
C14P2-GGR17
Midway 230 kV reactor
replacement: Replace existing 9
ohm Midway 500/230 kV
reactors with 13 ohm reactors
PG&E C14 Reliability Sep 2028 Mar 2029 Mar 2029
2122-R-12 Series Compensation on Los
Esteros-Nortech 115 kV Line PG&E
2022-2023
Transmission
Plan
Reliability Dec 2028 TBD Jan 2026 Apr 2026
2425-R-11 Konocti – Eagle Rock 60 kV Line
Reconductoring PG&E
2017-2018
Transmission
Plan
Reliability Dec 2021 TBD Apr 2030 May 2030
2223-R-23 Tesla 115 kV Bus
Reconfiguration Project PG&E
2023-2024
Transmission
Plan
Reliability May 2034 TBD Nov 2027 Jun 2028
1213-P-02 Lugo – Eldorado series cap and
terminal equipment upgrade SCE
2012-2013
Transmission
Plan
Policy 2016 May 2018 Dec 2020 Jun 2026
422
87 ID Network Upgrade PTO Study Type of
Upgrade
In-service Year
at Approval in
Transmission
Plan
Expected
CPUC Filing
Current
Expected
Construction
Start
Current
Expected In-Service Date
1314-P-01 Lugo-Mohave series capacitor
upgrade SCE
2013-2014
Transmission
Plan
Policy 2016 May 2018 Dec 2020 Jun 2026
2223-P-09
Lugo-Victor-Kramer Upgrade
(1/3)
Add 3rd Lugo 500/230 kV
Transformer
SCE
2022-2023
Transmission
Plan
Policy 2028 Exempt Jan 2028 Jun 2029
423
88 To better understand the transmission requirements associated with each resource, and identify which specific transmission needs the contracted resources needed, WestLight reviewed each project's CAISO queue position, point of interconnection (POI), applicable group study reports and restudies, and applicable transmission constraints. WestLight also reviewed CAISO Net Qualifying Capacity (NQC) lists, interconnection study materials, and other publicly available CAISO resources to assess whether the transmission and deliverability necessary to support each resource have already been established or whether additional transmission development may be required. A summary of this assessment is provided in the table above.
WestLight notes that several transmission upgrades relevant to resource deliverability, including the Konocti–Eagle Rock 60 kV Line Reconductoring Project, the Lugo–Mohave Series Capacitor Upgrade, and the Lugo–Victor–Kramer Upgrade (including addition of a third Lugo 500/230 kV transformer), have experienced substantial extensions to their original planned implementation timelines. Given the importance of these projects to supporting resource deliverability, reliability, and policy goals, WestLight respectfully encourages the CPUC to continue affording these projects appropriate priority within ongoing transmission planning and oversight processes to the extent practicable, and enable the Participating Transmission Owners (PTOs) to pursue construction and implementation of these upgrades as expeditiously as reasonably possible and, where feasible, evaluate opportunities to accelerate project development schedules. Timely completion of these transmission investments will help reduce reliability uncertainty.
As California increasingly relies on geographically diverse renewable resources, clean firm resources, storage, and imports, transmission planning has become a critical determinant of whether procurement objectives can be achieved in practice. WestLight supports continued improvement in alignment among CPUC Integrated Resource Planning assumptions, CAISO Transmission Planning Process studies, interconnection timelines, and actual LSE procurement activity. Given the scale of future transmission investment under consideration, timely and well-coordinated planning will be important to reduce portfolio risk, avoid unnecessary customer costs, and enable resources such as offshore wind, geothermal, and out-of-state renewables to contribute to California’s clean energy and reliability goals.
In particular, WestLight has partnered with Sonoma Clean Power and a team from the Zero lab at Princeton University to develop and advocate for planning methods that can incorporate large scale uncertainties to develop a least-regrets resource portfolio and transmission plan that would be robust to major uncertainties, such as changes in resource availability and retirements, the success or failure of offshore wind, changes to renewable incentives, etc. By planning for a range of foreseeable eventualities, rather than a single deterministic prediction (which can result in major stranded costs or mismatches should that single prediction be wrong), these robust planning methods should realize major savings for Californians .
IV. Action Plan
a. Proposed Procurement Activities and Potential Barriers WestLight’s mission is to provide affordable, clean electricity and advance local solutions that lower costs, reduce pollution, and strengthen community resilience. The Preferred Portfolio identifies the most cost-effective way to achieve WestLight’s mission, internal targets, and the assigned reliability and GHG emissions targets of the IRP process and includes a significant amount of new resources including wind, geothermal, solar, and energy storage resources.
424
89 WestLight takes a multi-pronged approach to implementing its annual and long-term clean energy goals for RPS and carbon-free non-RPS eligible resources. This implementation includes issuing Requests for Proposals (RFPs) or RFOs, participating in jointly issued RFPs / RFOs, engaging in bilateral negotiations and exploring partnerships to develop clean energy resources. WestLight varies the timing of its clean energy procurement activities to ensure a diversification of counterparties, prices, and term and to meet short-term needs based on actual load.
As described in Section II.a, WestLight’s procurement activities are guided by Board-adopted policies, including its Energy Risk Policy, renewable energy and procurement policies, and workforce and sustainability objectives. Together, these policies establish a framework for balancing affordability, reliability, emissions reductions, and risk management in its procurement decisions. Consistent with this framework, WestLight seeks to maintain a diverse portfolio of resources. Procurement decisions consider a range of factors, including technology type, generation profile, project location, contract term, and market risk. WestLight’s procurement strategy is designed to support achievement of its reliability and clean energy objectives while maintaining flexibility to adapt to evolving market, financial, and regulatory conditions.
WestLight intends to implement its Preferred Portfolio through a combination of bilateral procurement, competitive solicitations, and joint procurement activities. Consistent with the procurement policies and risk management framework described in Section II.a, WestLight will continue to evaluate opportunities to procure resources that support its reliability, affordability, and clean energy objectives.
WestLight evaluates resources on a least-cost best-fit basis to determine the most cost-effective way to meet its renewable energy goals with the resources available.
In evaluating bids, WestLight considers quantitative criteria such as:
• Project economic value, including energy, attributes, and capacity (net of curtailment and degradation),
• Contract cost
• Forecasted congestion, curtailment, and market revenue risks • Contract term
• Contribution to meeting WestLight’s time-coincident goals • Contribution to meeting WestLight’s procurement requirements under IRP procurement orders, including D.19-11-016, D.21-06-035,D.23-02-040, and D.26-02-057. • Alignment with WestLight’s risk management strategies, including spatial diversification of its supply portfolio
WestLight also considers qualitative criteria such as:
• Project viability and development risk:
Project status regarding interconnection, site control, permits Technology viability
Financial stability of project owner/developer
Approach/discussion on EPC contracting
• Project team experience
• Project location
• Environmental impacts and related mitigation requirements 425
90 o Whether projects deliver multiple benefits for air, water, and nature and avoid impacts to important lands, species, and waters
o Whether projects are in areas zoned for renewable energy development or in high-conflict areas
o Whether projects have recycling and decommissioning plans for project technology
• Disadvantaged Communities
Whether projects are located within DACs, can demonstrate DAC workforce and community development benefits, and have conducted outreach to DAC communities.
Whether projects are located within California, particularly projects located within or close to San Mateo County and the City of Los Banos • Workforce Development
Potential workforce impacts of proposed projects with the goal of promoting fair compensation, fair worker treatment, multi-trade collaboration, and support of the existing wage base in local communities where contracted projects will be located
• Community Benefits
Efforts by the developer to incorporate community feedback in the planning and development process, commitment to community sponsorships, community benefits plans, and community benefits agreements in areas surrounding the project site.
WestLight issues regular procurements to manage exposure to market risk. In alignment with WestLight’s evaluation criteria described above and its procurement strategies described in Section II.a, WestLight targets a diversity of contract term lengths, resource additionality, and resource technologies to develop a diverse, cost-effective, and low-risk power portfolio. WestLight values short-term contracts (less than 5 years in length) to help manage future uncertainty in load, supplies, and regulatory requirements.
WestLight see a valuable role for existing renewable resources in its portfolio, which may be more feasible to contract under short-term contracts than new resources.
A key component of WestLight’s procurement strategy is participation in CC Power joint procurement.
Through CC Power, member agencies are able to jointly procure large-scale and emerging clean energy resources, diversify development and commercial risks, and achieve economies of scale that may not be available through individual procurements. WestLight has utilized CC Power as a primary procurement vehicle for compliance with the long lead-time resource requirements established under D.21-06-035 and D.23-02-040, specifically for long-duration energy storage and firm clean resources. Consistent with the results of its Preferred Portfolio modeling, WestLight anticipates that joint procurement efforts through CC Power will continue to be an important pathway for securing firm clean resources, including geothermal and emerging geothermal technologies.
In addition to its participation in CC Power, WestLight continues to conduct its own competitive solicitations to meet its procurement objectives. Recent examples include a 2024 solicitation for renewable energy and storage resources to support WestLight’s goal of serving customer load with 100 percent renewable energy by 2030, and a solicitation to allocate Commercial Interest points in CAISO’s Queue Cluster 15 process, consistent with Interconnection Process Enhancements. 426
91 WestLight plans to continue similar procurement activities on an approximately annual basis to fulfill the procurement of new resources identified in its Preferred Portfolio, and anticipates releasing its next RFO in Q4 of 2026 or Q1 of 2027.
Any contracts with a term longer than five years must be approved by WestLight’s Board. These approvals take place during public Board meetings which provide opportunity for members of the public to comment on the proposed contract.
Additional details on WestLight’s action plans regarding specific areas are detailed in the sections below. i. The LSE should provide responses for each of the following resource categories:
Resources to meet IRP mandated procurement requirements, including D.21-06-035 and D.23-02-040:
In June 2021, the CPUC issued D. 21-06-035, establishing procurement requirements for load-serving entities, including WestLight, to procure specified resources on prescribed timelines. The CPUC subsequently adopted additional procurement requirements through Decision 23-02-040. WestLight’s procurement obligations under Decisions 21-06-035 and 23-02-040 are identified in Table 37 below.
Table 37: WestLight’s D.21-06-035 and D.23-02-040 Procurement Requirements Compliance Date Capacity
08/01/2023 38 MW
06/01/2024 117 MW
06/01/2025 51.4 MW32
06/01/2025
(Zero-emitting generation, generation
paired with storage, or demand
response)
47 MW*
(subset of 2023, 2024, and 2025
capacity, not additive)
06/01/2026 35 MW
06/01/2027 35 MW
06/01/2028
(Long Duration Storage) 19 MW
06/01/2028
(Firm Clean Resources) 19 MW
WestLight has procured sufficient resources to meet its requirements under D.21-06-035 and D.23-02- 040, including generic, zero-emitting generation/generation paired with storage, firm clean resources, 32 WestLight's original 2025 requirement under D.21-06-035 was 28 MW. WestLight submitted AL-031-E for a baseline swap to count two resources on the baseline toward its 2023 requirements, and added a commensurate amount to its 2025 requirements.
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92 and long-duration storage. A portion of these resources have achieved commercial operation and the remainder are in various stages of development.
1,000 MW of firm zero-emitting resource requirements
WestLight has contracted for 26 MW of repowered geothermal capacity from Heber 2 Geothermal, 14 MW of which is incremental and qualifies as firm zero-emitting resource under D.21-06-035. WestLight contracted this resource following participation in Ormat’s Request for Bids in 2021. This project has achieved commercial operation. WestLight has secured import allocation at the delivery point for this resource.
Additionally, WestLight has contracted for up to 24 MW of new geothermal capacity through its share of two executed contracts, Fish Lake geothermal and Ormat portfolio, from CC Power. These resources were identified through a solicitation completed in early 2022. WestLight also contracted with a 6 MW geothermal project, Whitegrass No.2, in 2022. These projects all face development challenges. These include federal policy risks regarding Foreign Entity of Concern (FEOC) requirements, permitting and environmental risks, and commercial risks associated with a limited supply of geothermal development opportunities, all of which increase cost and uncertainty surrounding project viability. Despite these challenges, WestLight still expects to be able to meet its firm clean resource requirements under D.21-06- 035 and D.23-02-040.
1,000 MW of long-duration storage resource requirements WestLight has contracted for approximately 15 MW of new long duration storage capacity through its share of an executed contract from CC Power with Tumbleweed Storage. This resource was identified through a solicitation completed in 2021. Tumbleweed Storage achieved commercial operation on June 1, 2026.
WestLight has contracted for 10 MW of new long duration storage capacity with the San Gabriel Project II. The project is expected to achieve commercial operation by June 1, 2027, and will fulfill the remainder of WestLight’s long-duration storage requirements under D.21-06-035. WestLight receives regular progress reports from the developer on project development status, and no significant risks have been identified.
2,500 MW of zero-emissions generation, generation paired with storage, or demand response resource requirements. All other procurement requirements WestLight is required to procure 47 MW of zero-emissions generation, generation paired with storage, or demand response resources. WestLight has met these procurement requirements with the Arica Solar plus Storage and Chaparral Solar plus Storage resources, both of which are now online. ii. Plans for resourcesthat are currently non-candidate in CPUC’s IRPs not described above
WestLight's Preferred Portfolio includes an 8-hour Advanced Compressed Air Energy Storage (A-CAES) resource that is not currently represented as a candidate resource in the CPUC's IRP modeling framework, which only considers 8-hr litihium ion storage technologies, or 12-hr location constrained storage.
Because WestLight has already executed a contract for this resource, it was included as an existing portfolio input to the modeling and included as part of the Preferred Portfolio. WestLight will continue to 428
93 support development of this project and monitor progress toward commercial operation. Additional information on this resource is provided below in Section iv. Other Energy Storage.
In addition, WestLight intends to continue pursuing BTM distributed energy resource initiatives, including customer-sited solar and storage, and virtual power plants. While these resources are not reflected as selectable candidate resources in the current IRP framework, they remain an important component of WestLight's broader strategy to improve resilience and grid flexibility. iii. Other renewable and/or zero carbon resources not described above WestLight’s plans for procuring renewable and zero carbon resources are described in Section IV.a above. iv. Other energy storage not described above
WestLight’s plans for procuring energy storage are described in Section IV.a above. v. Other demand response not described above
Currently WestLight has approximately 550 residential systems actively dispatching daily for a total of
1.6MW / 3.1MWh. This program is with a residential solar and storage provider that has been providing daily load modification to WestLight since 2022.
WestLight’s strategic plan includes launching at least one 10 MW virtual power plant (VPP) that delivers value to customers, communities, and the grid by 2030. WestLight has contracted with Lunar Energy, a Distributed Energy Resource Management System (DERMS) to coordinate the VPP service. At this time integration work is proceeding to integrate residential storage systems being deployed under WestLight’s income-qualified residential solar and storage program. The VPP system will allow for more dynamic dispatch of assets for grid needs. Other dispatchable asset classes will be explored and ultimately integrated if deemed viable.
DERMS integrations for distributed energy resources are not yet standardized. As a consequence, integration is done differently by each manufacturer, though some integrators are seeking to create common interfaces and processes. Due to the heterogeneity, costs are high and timelines are unpredictable. Certain asset classes such as water heaters are largely unproven or have low yield, or recruitment of relevant participants is prohibitively challenging (EVs). Fixed storage and thermostats for HVAC (commercial and residential) are likely the most viable near term reliable distributed dispatchable assets.
The effects of Demand Response programs that have already been developed are included in WestLight’s IRP analysis via their impacts to WestLight’s overall load shape. However, additional Demand Response programs were not evaluated in WestLight’s IRP analysis due to lack of available inputs and assumptions for additional program deployment. WestLight plans to pursue additional Demand Response going forward and will incorporate the effects of this in the next IRP cycle. 429
94 vi. Other energy efficiency not described above
WestLight is applying to the CPUC to become a full “apply-to-administer” Energy Efficiency (EE) provider.
CCAs have a statutory right to administer such EE programs and approval is expected in 2027 for programs to launch beginning in 2028. Consistent with the 2024-2027 IRP Filing Requirements, WestLight assumed the Energy Efficiency load modifier volumes assigned to WestLight by the CPUC in its IRP analysis.
WestLight includes a description of its planned EE programs in this section even though different levels of EE could not be assumed when modeling its Preferred Portfolio.
The portfolio of EE programs planned include:
• Multifamily Strategic Energy Management (SEM) - Works with multifamily property owners and managers to build long-term energy management practices. Through energy coaching, building energy data tools, and peer learning, participants identify operational improvements, low- and no-cost savings opportunities, and ways to improve comfort for residents. The program also helps properties identify electrification readiness and load flexibility opportunities. By supporting ongoing energy management and providing performance-based incentives for verified savings, the program helps reduce energy costs and emissions while improving building performance for residents and owners. From 2028–2031, the program is expected to deliver 1.5 million net first-year kWh, and engage approximately 60–75 multifamily buildings in multi-year SEM cohorts. • Non-Residential SEM - Engages commercial, agricultural, public sector, and industrial customers through a dedicated energy coaching model that builds long-term capacity for operational and behavioral energy management. The program offers a six-year curriculum with energy coaching, cohort learning, and real-time energy data tools to help participants identify operational improvements, load flexibility opportunities, and electrification readiness. Through performance-based incentives and continuous improvement practices, the program supports sustained energy savings, reduced GHG emissions, and long-term decarbonization outcomes. From 2028–2031, the program is expected to deliver 19.6 million net first-year kWh in savings while serving approximately 40–60 large-load customers.
• Commercial Direct Install (DI) - Provides a turnkey, no or low-cost solution for commercial customers, delivering onsite energy and electrification readiness assessments and direct installation of energy-saving measures. From years 2028-2031, the program expects to deliver 419,675 first year net kWh and serve approximately 300 customers. • Residential DI - Provides no-cost in-home energy assessments and installation of energy-saving measures that improve comfort, health, and safety for residents. Energy Advisors and trusted community partners help households understand energy use, identify electrification opportunities, and connect to other programs and incentives. The program focuses on underserved and hard-to-reach customers while building long-term energy awareness and engagement. From 2028–2031, the program is expected to deliver 18,658 net first-year kWh and complete approximately 2,000 in-home assessments and direct installs. • Renter Marketplace - Provides Equity customers, renters, and small and micro businesses with easy access to discounted energy-efficient and clean energy products through an online platform that simplifies incentives and purchasing. The marketplace offers curated product recommendations, multilingual support, and concierge assistance to help underserved customers adopt renter-friendly technologies like plug-in induction stoves, window heat pumps, and 430
95 efficient appliances. From 2028–2031, the program is expected to deliver 2.9 million net first-year kWh and reach approximately 2,600 equity customer purchases. • FLEXMarket (expanded) - Offers measure-agnostic incentives that encourage aggregators to submit projects that reduce peak load and deliver verified energy savings. Using a pay-for-performance structure, the program rewards projects based on measured results while supporting load flexibility and electrification solutions. From 2028–2031, the program is expected to deliver 7.8 million net first-year kWh savings across approximately 140 buildings. • Refrigerant Workforce, Education, and Training (WE&T) - Builds local contractor capacity to support refrigerant recovery, recycling, and the transition to low-global warming potential (low-GWP) refrigerants. The program provides small and independent HVAC contractors with no-cost training, equipment starter kits, certification support, and connections to refrigerant buyback markets that create new revenue opportunities. By partnering with workforce organizations and community colleges, the program expands access to training while supporting compliance with California refrigerant regulations and reducing Hydrofluorocarbon (HFC) emissions. The goal is to reduce GHG emissions from improperly handled refrigerant and through the transition to low-GWP refrigerant. By 2031, the program aims to recruit and train 75+ local small and independent contractors.
• Integrated Demand Side Management (IDSM)- Encourages load shifting by coordinating behind-the-meter battery systems through WestLight’s Distributed Energy Resource Management System (DERMS). Residential and municipal participants receive performance-based incentives for discharging batteries during peak demand periods, helping reduce grid stress and improve local resilience. The program uses automated measurement and verification to track energy shifted from peak to off-peak hours while providing guidance on battery optimization and energy management. The program aims to enroll 522 customers (496 residential, 26 municipal) with battery systems by 2031.
Once the application is approved, WestLight will run competitive solicitations for partners to execute these programs. WestLight expects a ramp up period as the programs are put into place with increasing impact of these programs coming in the latter part of the four year term (2028-2031). vii. Other distributed generation not described above
WestLight’s service territory includes approximately 25,000 NEM accounts with an estimated 260MWac of solar power capacity. In addition, the service territory has approximately 8,000 accounts with battery storage systems with approximately 80MWac of power capacity.
WestLight’s strategic plan includes a target of accelerating distributed energy resource adoption by adding at least 15 MW of local solar and 35 MWh of storage at customer sites. These goals will be achieved primarily through its residential and local government solar and storage programs with storage systems integrated into a WestLight VPP.
DAC-GT
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96 The Disadvantaged Communities Green Tariff (DAC-GT)33 program enables income-qualified residential customers living in DACs who may be unable or unwilling to install solar on their roof to access 100% renewable energy through a community solar (or community solar and storage) project. Participating customers also receive a 20% discount on their electric bill. The program is overseen by the California Public Utilities Commission (CPUC) and modeled after the existing Green Tariff portion of the Green Tariff/Shared Renewables Programs. It is available to customers who meet the income eligibility requirements for the California Alternate Rates for Energy (CARE) and Family Electric Rate Assistance (FERA) programs and live in Disadvantaged Communities (DAC).34 WestLight currently administers 6.008 MW of DAC-GT program capacity, providing approximately 2,600 customers with a flat 20% monthly bill discount compared to their otherwise applicable tariff. Since 2022, WestLight’s DAC-GT program has provided over $2.5 million in bill discounts to eligible participants.
WestLight’s DAC-GT capacity is met through a 3 MW solar interim resource35 and a 3 MW solar dedicated resource called Dos Palos Clean Power, which came online in 2025. These resources are included in WestLight’s IRP analysis. Dos Palos Clean Power received significant support from local community leaders and elected officials, including the office of State Senator Caballero and the City of Los Banos Mayor Amabile.36 The ongoing support from City of Los Banos and Merced County leaders demonstratesthat Dos Palos Clean Power directly strengthens the economic conditions of local communities through customer bill savings, productive use of fallowed farmland, and local-hiring preferences to improve rural economic development opportunities, in addition to the environmental benefits that the project provides.
Community Microgrids
WestLight submitted two applications under PG&E’s Microgrid Incentive Program (MIP) in December 2025 to request funding for multi-customer, community-based microgrids (Community Microgrids) in its service area. Community Microgrids are energy systems that power multiple customers and critical facilities within a defined boundary through a solar and battery energy storage system that is directly connected to the utility’s distribution grid. The microgrid operates in parallel with the distribution grid during normal conditions (also called “Blue Sky Mode”) but can disconnect from the larger grid and operate in “Island Mode” during times when the larger grid experiences an outage.
WestLight proposed two microgrids along the coast of San Mateo County, an area that is considered a Disadvantaged and Vulnerable Community (DVC) and experiences frequent and sustained power outages.
The most likely application to receive funding is the Pescadero Community Microgrid. The Pescadero Community Microgrid covers the entire town of Pescadero, including several critical facilities (a fire station, 3 schools, a local community NGO) as well as over 100 residences and businesses. The Pescadero Community Microgrid will be anchored around a ~1.5 MW solar and 8 MWh storage system which will provide more than 72 hours of backup power.
33 WestLight Green Access Program, https://www.westlightenergy.org/residential/rates-billing/green-access-program/ 34 https://oehha.ca.gov/calenviroscreen/sb535
35 WestLight launched an RFO in November 2025 to replace the interim resource with a new dedicated resource. 36 See https://losbanosenterprise.com/local-news/2025/los-banos-leaders-celebrate-wastewater-treatment-plant-solar-project/, https://thewestsideexpress.com/2025/05/11/joint-peninsula-clean-energy-renewable-america-dos-palos-solar-project-comes-online/, https://www.westlightenergy.org/news-releases/joint-peninsula-clean-energy-renewable-america-dos-palos-solar-project-comes-online/ 432
97 If awarded funding, WestLight will collaborate with PG&E and community partners on the development of the Community Microgrid which would come online in 2029 at the earliest. The project would be funded through the MIP and supported by contributions from WestLight, San Mateo County, and potentially other sources. Because of the pending status of the MIP application at the time of conducting the IRP analysis, any potential community microgrids were not included in this IRP analysis. viii. Transportation electrification, including any investments that correspond to different levels than what is included in Integrated Energy Policy Report (IEPR) In this IRP, WestLight utilized the assigned annual volume of electric vehicle load but applied its own internal electric vehicle load shape. The IEPR and WestLight forecast similar volumes of EV load in the near term through 2030, but the IEPR forecasts higher demand in the later forecast years.
WestLight’s service territory is a region of high electric vehicle adoption. An estimated 70,000+ personal plug-in electric vehicles are in operation out of roughly 550,000 total personal vehicles as of Q4 2025. The region also includes an additional 60,000 commercial vehicles across light-, medium-, and heavy-duty classes. In 2024, 40% of new personal vehicle sales were plug-ins, outpacing the state average. It is anticipated that new private vehicles sales will be nearly entirely plug-in electric in advance of the state’s 2035 target. However, internal forecasts suggest that existing private gasoline-powered vehicles will still account for approximately 45% to 65% of vehicles on the road during that timeframe, or roughly 250,000 to 350,000 vehicles.
Fleet conversions have been very modest, but local governments are increasingly preparing to meet Air Resource Board Advanced Clean Fleets requirements. Nearly all local municipal fleets are receiving EV transition assistance from WestLight or other providers at this time.
EV charging to support the growing number of electric vehicles is primarily in residential single-family homes. Data is limited on chargers installed in other locations, but industry data indicates an estimated 8,000 chargers across public, workplace and multifamily segments. The overall charge port gap, the difference between chargers expected to be installed by 2035 and the projected need by the California Energy Commission, is projected at roughly 35,000 chargers, with a particularly acute gap in multifamily.
In other words, current deployment trajectories fall well short of the infrastructure needed to support the all-electric vehicle fleet envisioned by the CEC, requiring a substantial acceleration in charger deployment.
WestLight's programs seek to close this gap by accelerating charger deployment, with a particular emphasis on expanding charging access for multifamily residents and other underserved customer segments. Finally, e-bikes have generated substantial interest. While widespread data on alternative mobility electrification is unavailable, WestLight’s programs have provided incentives for 3,000+ e-bikes to-date.
WestLight’s strategy in transportation focuses on private vehicle electrification with an emphasis on the low-income community. Transportation electrification delivers significant economic benefits to EV adopters.
Specific programs are as follows:
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98 1. Reach Codes: WestLight has had an extremely successful program supporting local governments in adopting code enhancements which support EV readiness. To date approximately 20 local cities adopted local codes that accelerated widescale EV readiness for new multifamily and expanded EV readiness in commercial construction ahead of the most recent state code. By 2035, the reach codes and state code are anticipated to result in 19,000 new charge ports, assuming development continues consistent with historical trends.
2. EV Charging Incentives and Technical Assistance: This program supports EV charging in multi-family, workplace and public segments. It includes a special emphasis on multi-family charging through advanced design assistance that “right-sizes” infrastructure through power management and low-power charging to maximize cost-effective port installations. Notably, several state programs, including the CEC’s Communities in Charge Program (CIC) now incentivize the installation of Level 1 chargers in assigned parking at multifamily properties, a core component of WestLight’s program.
3. Used EV Rebate: This program provides incentives for the purchase of used electric vehicles for income-qualified customers and a “hotline” for income-qualified individuals.
4. E-Bikes: WestLight provides incentives to income-qualified residents for the purchase of e-bikes with point-of-sale rebates.
5. Fleets: The fleets program is focused on local government fleets providing technical assistance for developing an infrastructure plan for local agencies. The program will provide incentives and bridge agencies towards meeting state requirements.
WestLight has developed an in-depth analysis characterizing the transportation sector in the service territory and defining a strategy for maximizing decarbonization by 2035. The plan includes complementing state and federal funding and incentives with an additional $30M to $40M in direct investment in transportation electrification through 2035, assuming projected budget capacity. In addition to the above investments, WestLight is planning an aggressive EV load shaping program which can generate an estimated additional $40M to $50M in CPUC-directed and/or wholesale market funds over the same period of time for further investment in electrification. The plan calls for continued scaling of the above programs particularly to advance EV charging in multi-family and ensure that low-income residents have access to EVs, e-bikes and other modes of electric transportation. ix. Building electrification, including any investments that correspond to different levels than what is included in Integrated Energy Policy Report (IEPR) Consistent with the 2024-2027 IRP Filing Requirements, WestLight assumed the Building Electrification (BE) load modifier volumes assigned to WestLight by the CPUC in its IRP analysis. WestLight includes a description of its BE programs in this section even though different levels of BE could not be assumed when modeling its Preferred Portfolio.
WestLight has approximately 300,000 residential units and 8,046 commercial buildings with 194 million square feet of space. 60% of housing units are over 50 years old and 40% of units are rentals, with a heavy concentration of rentals in the multi-family segment (85%). 62% of building methane gas use is in the residential sector with the majority for space and water heating. Electrification of the built environment 434
99 is in the earliest stages. Over 50,000 residential accounts in the service territory are electric-only, though this includes multifamily buildings which have central gas water heating systems and homes that may receive propane or other portable fuels. Water and space heating are predominantly gas combustion, 97% and 67% respectively in the residential sector. Through WestLight’s incentive programs begun in 2021, over 5,000 gas-to-electric appliance replacements have been installed WestLight’s strategy in building electrification focuses on advancing local codes covering all building types as well as offering incentive programs that focus on small residential (single-family and small multifamily) with self-contained home systems.
Specific programs are as follows:
1. Reach Codes: WestLight has had an extremely successful program supporting local governments in adopting code enhancements for all-electric new construction. Nearly all cities adopted local codes that strongly encouraged all-electric construction in most segments ahead of the state code. In addition, the program has begun working with local governments on existing building reach codes with 4 cities adopting such codes to-date.
2. Developer Technical Assistance: This program provides no-cost technical assistance to builders, developers, and designers primarily for new construction. To date over 100 firms have been provided with substantive assistance with a portfolio of sector specific experts.
3. Home Upgrade: Provides incentives, on-bill finance and technical assistance for single-family home electrification. Program includes “self-serve” option, turnkey “full-service”, including no-cost upgrades for income-qualified customers, and emergency water heater replacements.
Emphasizes right-sizing to avoid unnecessary service upgrades.
4. Commercial Electrification: Expected to launch in early 2027, this program will provide incentives for commercial electrification of off-the-shelf HVAC, water heating and cooking systems.
WestLight has developed an in-depth analysis characterizing the building sector in the service territory and defining a strategy for maximizing decarbonization by 2035. The plan includes complementing state and federal funding and incentives with an additional $180M or more in direct investment in building electrification through 2035, assuming projected budget capacity. In addition to the above investments, WestLight is planning to aggressively leverage conventional and innovative finance strategies to aid customers in making the conversion. The plan calls for larger incentives for residents with less capacity to bear costs in addition to higher initial incentives which are expected to decline as the market matures and costs decline.
x. Potential Centralized Procurement, pursuant to AB-1373 WestLight believes load-serving entities should remain the primary entities responsible for procuring resources to serve their customers, given their direct accountability for cost, reliability, and portfolio 435
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design. CCA procurement teams also have significant and sophisticated contracting expertise that would be difficult to replicate at a CPE that would have to build this expertise from scratch. CCAs and other LSEs have already demonstrated the ability to contract for geothermal, long-duration storage, and other long lead-time resources through bilateral procurement, joint powers authority structures, and competitive solicitations.
To the extent centralized procurement is pursued under AB 1373, it should be targeted to circumstances where it provides clear market-development, logistical, or cost advantages that cannot be efficiently achieved through individual LSE procurement, as demonstrated by substantial evidence. In addition, any centralized procurement framework should provide transparency regarding costs and benefits, avoid shifting development or timing risk onto LSEs, and preserve flexibility for existing procurement strategies.
Many of the principal barriers facing long lead-time resources relate not to lack of procurement authority or willingness, but to transmission availability, interconnection timelines, permitting complexity, and commercial readiness. Addressing the barriers facing long-lead-time resources will remain critical regardless of procurement structure.
As part of the 2024-2027 Filing Requirements, WestLight was allocated its load share of proposed centrally procured resources pursuant to AB 1373. These allocations, expressed as nameplate capacity, included 19 MW of 12-hour long duration energy storage (LDES), 19 MW of multiday storage LDES, 165 MW of offshore wind, and 22 MW of geothermal resources. WestLight evaluated how inclusion of these resources would affect its Preferred Portfolio if they were procured by DWR and allocated to WestLight’s portfolio.
Because the geothermal and storage resources are assumed to come online during the first half of the 2030s, their impacts to WestLight’s portfolio would first appear in the 2035 model year. In 2035, the centrally procured geothermal resources displace 67 MW of onshore wind resources in WestLight's Preferred Portfolio. In 2040, the 67 MW of onshore wind are added back into the portfolio, and the mix of additional geothermal and solar + storage resources are tweaked, with 59 MW fewer strategic geothermal resources and 100 additional MW of solar and 4hr storage resources.
The impacts are more significant in 2045, when the 165 MW offshore wind allocation reduces the need for approximately 129 MW each of solar PV and hybrid storage resources, 51 MW of onshore wind, and 37 MW of geothermal. As discussed in Section III.l, offshore wind provides a generation profile that is complementary to solar resources and can contribute meaningfully to portfolio diversity and emissions reductions. However, the overall costs of the portfolio with the centrally procured resources were higher than WestLight’s Preferred Portfolio.
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Figure 28: Cumulative Change in WestLight Energy’s Preferred Portfolio with AB 1373 Resources xi. Other
WestLight does not have other plans in addition to what has already been discussed in the above sections of the Action Plan.
Potential Barriers
Each of the resource types discussed above faces significant potential barriers and risks. Market, regulatory, financial, resource viability and operational barriers can affect WestLight’s ability to achieve the Preferred Portfolio described in this IRP. WestLight does not expect to fully realize this Preferred Portfolio; instead, it expectsto adapt to the real-world conditions as they change, and continue to procure and operate the least-cost least-risk portfolio in pursuit of its mission to provide affordable, clean electricity and advance local solutions that lower costs, reduce pollution, and strengthen community resilience. Below, WestLight discusses potential barriers and risks to achieving its Preferred Portfolio. • Resource availability
o One of the most fundamental barriers that LSEs in California face is a lack of diverse resources, specifically, a lack of any potential new resources other than solar and storage.
WestLight’s Preferred Portfolio contains significant quantities of capacity from new wind and geothermal resources which, despite their high desirability, may not actually be available in the market. These resources could theoretically be developed due to the existence of favorable natural conditions and resource potential and are presented to LSEs as potential selections for their portfolios. However, WestLight has observed that these resources are challenging to develop, facing permitting and local opposition, as well as development costs that exceed planning assumptions. WestLight has selected these resources to signal to the state and to the market that these are the best-fit resources for WestLight’s portfolio, if these resources can be developed at reasonable costs. -400
-300
-200
-100
0 100
200
300
2035 2040 2045
Capacity (MW)
CPE Offshore Wind CPE 12 hr LDES CPE MDS CPE Geothermal Onshore Wind Solar Storage Geothermal
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o Without diverse resources, California will be forced to achieve the policy goals of SB100 with solar plus storage. This would require substantial solar overbuild to meet winter energy needs and would lead to over-generation of solar energy during summer months, resulting in increased curtailment, higher costs, and higher risk than a portfolio with a more diverse resource mix.
• PCIA and Financial Security Requirements (FSR)
o California CCAs face a unique challenge in implementing local clean energy and customer affordability objectives due to the financial impacts and uncertainty associated with the Power Charge Indifference Adjustment (PCIA). WestLight supports the underlying principle of preventing cost shifting between customer groups; however, the PCIA framework has resulted in significant cost and risk shifting from bundled customers to CCA customers. The magnitude and trajectory of PCIA charges can affect customer rates, procurement decisions, and the financial resources available to support local programs and clean energy investments.
o One area of particular concern is the treatment of utility-owned generation resources within the PCIA framework. Under current implementation, costs of utility-owned generation assets can continue to be recovered through the PCIA even after their original costs have been recovered or when the resources are repowered. WestLight believes that cost recovery mechanisms should appropriately align resource costs with the customers receiving the benefits of those resources. Where such resources could be decommissioned, these costs can be avoided, and so are no longer appropriate for inclusion for recovery in the PCIA. Similarly, where resources are retained or procured to meet broader system reliability needs, cost allocation mechanisms should recognize the system-wide benefits provided by those resources.
o The PCIA also presents portfolio management challenges for CCAs because it functions as a fixed-price contract associated with procurement decisions made by the IOUs prior to customer departure. As a result, CCAs must manage their own procurement activities in conjunction with an existing portfolio of resources and financial obligations over which they have limited visibility and control. This can complicate efforts to align procurement strategies with local policy objectives and evolving market conditions. o WestLight estimates that PG&E’s 2016 vintage PCIA functions as a fixed-price hedge of approximately 30% to 40% of its annual load, and will eventually stabilize at approximately 15% of its annual load given the current treatment of utility-owned generation resources. As a result, if WestLight pursues a portfolio, such as its Preferred Portfolio described in this IRP using bundled PPA contracts to serve 100% of its annual load, it will effectively be operating a portfolio that supplies 115% - 140% of its annual load needs. This oversupply is not optimal from a risk management perspective and increases exposure to market conditions and reduces procurement flexibility. In effect, CCAs must manage customer load using both the resources they procure and a legacy portfolio embedded in the PCIA, regardless of whether those resources align with the CCA’s procurement objectives or continue to represent the most cost-effective means of serving customer load. A more risk-aware portfolio composition would limit long-term contracts to 60% to 85% of total annual load and fill in the remainder of supply needs with short- and medium-term contracts. This diversity of contract terms would allow LSEs to manage technology, market, and load migration risks by providing some flexibility in near-term years. Instead, the current implementation of the PCIA forces CCA customers to be over-hedged with long-term contracts from the PCIA, while simultaneously “erasing” these contracts from the IOUs’ portfolios, and providing IOUs with short-term market 438
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positions that reduce risks to bundled customers while increasing risks to departed customers. That is, the PCIA allows IOUs to operate their portfolios with an optimal blend of short and long-term contract positions, while forcing CCAs to operate their portfolios with a high-risk over-exposure to long-term contracts.
o Furthermore, the Commission’s recent actions that shift greater costs onto CCA customers will have a dampening effect on the major contribution of reliability and decarbonization resources that CCAs have procured. These CCA resources have at times been necessary to keep California on target to meet its goals as other entities have fallen short, but the ability of CCAs to continue to be a vigorous engine of the renewable energy transition is undermined when the Commission shifts additional costs onto CCA customers.
o A similar dynamic has operated with Commission decisions to increase CCA financial security requirements, which serve to divert CCA financial capacities away from resource procurement and toward providing excessive levels of insurance that provide no benefit to California ratepayers.
• Supply Chain
o The development of the new resources in WestLight’s Preferred Portfolio is dependent on international supply chains to procure key equipment and materials. These supply chains have been strained in recent years and are expected to continue to struggle to meet the needs of California’s explosive growth in new resources. For example, high voltage transformers, which are required to step up facility generation to transmission-level voltages, have a current lead-time of 2 to 3 years. Steel, aluminum, solar panels, wind turbines, and lithium cells also have faced longer and longer lead times and higher prices as demand outpaces the global supply chain. The supply chain issues are further exacerbated by recent trade war tariffs and new Foreign Entity of Concern (FEOC) restrictions that disincentivize imports from critical global manufacturing regions. • Interconnection
o Even projects that successfully navigate development, permitting, financing, and supply chain challenges may experience significant delays to commercial operation due to delays in the construction of required interconnection facilities by Transmission Owners.
Because these facilities are often outside the control of project developers and load-serving entities, such delays create uncertainty regarding project schedules, online dates, and compliance with procurement requirements.
o WestLight has observed that the incentives and accountability mechanisms associated with Transmission Ownerinterconnection work are not always aligned with timely project completion. In some cases, developers have expressed interest in self-performing portions of the required interconnection work to accelerate project schedules but are limited by Transmission Owners in doing so. As a result, interconnection-related delays remain a significant risk to resource development and can impede the timely deployment of clean energy resources.
• Federal Opposition
o The current federal administration has opposed clean energy development through several avenues, with the overall effect of reducing the pool of resources that are available for contracting. The reduction in supply creates additional upward pressure on long-term contract prices. Federal opposition could also lead to the failure of contracted projects, a risk which WestLight is closely monitoring. • Tax Credit Availability
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o Renewable and clean energy development has been supported by tax credits for the past two decades that are now poised to expire. Resources with later CODs are priced without the benefits of tax credits, which increases long-term contract prices by around 30%.
Despite the hopes that economies of scale would reduce the costs for these technologies over time, recent tightening of supply due to federal policy coupled with increasing demand has seen upward price pressure, which is only exacerbated by the expiration of the tax credits.
• Tariffs
o Recent imposition of tariffs on certain imported materials and equipment has further increased the cost of developing new clean resources. Although the courts have overturned certain tariffs, it is unclear if projects will be able to recover tariff payments from the federal government, further complicating the ability for tariff invalidation to help reduce resource development costs and ultimately, costs borne by rate payers. • Permitting
o Permitting challenges continue to provide headwinds for clean energy projects. Federal permitting processes are openly hostile to clean energy development, but even clean-energy- neutral or supportive state and local jurisdictions can still challenge and delay resource development through long and uncertain bureaucratic processes. • Developer market power
o Dynamics in the long-term contract market have shifted in recent years towards favoring developers. CPUC procurement mandates, combined with the limited availability of preferred resource types such as wind and geothermal, create market conditions that increase developers’ leverage over load-serving entities in contract negotiations. Market power allows developers of these desirable technologies to increase long-term contract prices beyond the objective cost of developing these projects, leading to unnecessary cost burden on rate payers.
• LSE procurement autonomy
o CCAs were formed to provide local control over procurement decisions to serve local load.
Procurement mandates, cost allocation mechanisms, and more recent centralized procurement initiatives have reduced the degree of autonomy CCAs have over their procurement decisions. CCAs are proactive and sophisticated procurement entities that are committed to achieving SB100 goals while protecting ratepayers from unnecessarily high costs. Consequently, CCAs have used their autonomy to advance statewide goals largely on a faster timeline than state planners have envisioned. Undermining that autonomy risks undermining statewide goals. The primary challenge associated with certain long-lead time resources, including offshore wind and geothermal, has not been a lack of buyer interest, but rather the limited availability of commercially mature projects capable of entering into long-term offtake agreements. CCAs that have already procured resources consistent with reliability and SB 100 objectives should not be required to bear higher costs associated with centrally procured resources that are duplicative of procurement they have already completed.
• TPD availability
o A critical factor in whether a resource will be economic to develop is the ability of the resource to be allocated deliverability, which allows the resource to provide resource adequacy. CAISO administers the deliverability studies and allocations, which are highly complex and difficult to predict. Deliverability in CAISO is scarce in the regions where resource development is more achievable, and highly linked to the approval and completion of transmission upgrades. While CAISO has released the Point of 440
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Interconnection Heat Map, which helps stakeholders understand the current available deliverability at interconnection points throughout the CAISO system, there is currently no easy-to-use tool to evaluate when future deliverability will become available at a given node, given completion of previously approved transmission upgrades. The lack of easy-to-use information on future deliverability makes it difficult to predict whether projects with future CODs will be able to secure deliverability and thus provide resource adequacy, which increases contracting risk for load-serving entities. • Large Loads, Data centers
o The rapid emergence of large data center load introduces significant uncertainty into long-term resource planning and procurement. Uncertainty regarding the timing, location, and magnitude of data center development complicates load forecasting and can result in procurement decisions based on speculative demand. Planning processes should clearly distinguish forecast load associated with committed development from speculative demand to avoid unnecessary procurement and cost burdens on ratepayers.
Data center load forecasts should be assigned to the load-serving entities expected to serve those customers, rather than allocated proportionally across all LSEs. Pro rata allocation of speculative data center load may result in unnecessary procurement and increased costs for customers who will never receive service from those facilities. o Increased electricity demand from data centers may drive higher costs for critical electrical equipment, and clean energy resources. It is difficult for load-serving entities, which have an obligation to limit costs to ratepayers, to compete for scarce geothermal resources against large commercial customers with fewer capital or affordability constraints. New geothermal development that may be facilitated by the state should serve California's existing electricity load and statutory reliability and emissions reduction requirements before supporting discretionary new loads, and the CPUC should recognize this dynamic of competitive imbalance when designing procurement programs and issuing procurement orders that rely on firm clean resources. • Regulatory uncertainty
o The ability to achieve WestLight’s Preferred Portfolio could be inhibited by regulatory intervention in the procurement process. The Reliable and Clean Power Procurement Programs (RCPPP) will likely play a large role in determining how procurement is done over the next twenty years but is currently still in the development stage. Depending on how the RCPPP is structured, WestLight may be more or less likely to achieve its portfolio goals. Uncertainty surrounding what procurement may or may not be ordered forces caution in moving ahead with aggressive procurement that may end up being uncredited or duplicated by procurement orders.
o WestLight notes that increasing overlap among multiple regulatory frameworks can create conflicting planning signals and reduce procurement efficiency. Examples include evolving ELCC methodologies, Slice-of-Day and 24-hour Resource Adequacy constructs, changing central procurement structures, new reliability procurement orders, and cost allocation proceedings such as PCIA. While each proceeding may address legitimate policy objectives, overlapping changes implemented on differing timelines can increase customer costs and risks, complicate contracting decisions, and make long-term portfolio planning more difficult. Greater coordination, transparency, and implementation stability across proceedings would improve the ability of load-serving entities to make timely and cost-effective clean energy investments.
o Regulatory changes are often implemented on timelines that do not align with project development cycles, contract terms, or transmission buildout schedules, which can create 441
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avoidable execution risk. WestLight encourages greater long-term policy stability so that customer dollars and staff resources can be focused on actual clean energy procurement and implementation rather than adapting to shifting compliance frameworks. • Operational risks
o Once a resource comes online, it faces a distinctly different set of risks than a resource in development. Owner/operator solvency, climate/meteorological variability, and maintenance risks could all affect WestLight’s portfolio. However, WestLight sees the largest operational risk to its portfolio as stemming from congestion and curtailment in the wholesale market. Because of the lack of diversity in the CAISO supply stack, solar generation has proliferated and wholesale market prices during solar hours tend to be very low and often negative. WestLight predicts that periods of negative prices will increase and the magnitude of the negative prices will increase over time. These dynamics will lead WestLight and other resource schedulers to curtail generation to avoid negative prices. Curtailment and negative pricing will impact future costs as well as the ability to achieve future clean energy targets, because facilities will likely under-generate relative to “standard” solar and wind capacity factors – but due to market dynamics, not meteorological variation.
b. Disadvantaged Communities (DACs)
LSE Activities & Programs Impacting DACs
WestLight’s ECOplus customers historically received a 5% discount relative to PG&E’s electric service rate, providing immediate bill savings to customers seeking to reduce their monthly electricity costs. In addition, WestLight provided customers with a 10% discount relative to PG&E’s generation rates for most of 2025 and a portion of 2026. On average, WestLight customers save at least $5 per month on electric generation costs compared to PG&E customers. Since its inception in 2016, WestLight has delivered more than $226 million in cumulative customer bill savings, including a $300 bill credit distributed in 2023 to approximately 40,000 CARE and FERA customers, including customers residing in DACs.
WestLight also supports customer participation in bill management and arrearage relief programs administered in coordination with PG&E. Customers experiencing financial hardship may be eligible for programs such as the Arrearage Management Plan (AMP). In recent years, WestLight has increased outreach to AMP-eligible customers to encourage enrollment and reduce outstanding arrearages.
WestLight additionally prioritizes AMP participants when selecting customers for enrollment in its DAC-GT program, described further in Sections III.b and III.d. WestLight also worked with PG&E to expand Budget Billing to include the WestLight generation portion of customer bills, allowing customers to smooth monthly electricity payments and reduce seasonal bill volatility, particularly during summer months in warmer climate zones.
In addition to direct bill savings and bill management support, WestLight administers a variety of customer programs focused on transportation electrification, building decarbonization, and energy resilience. These programs help reduce criteria air pollutants by supporting the adoption of clean electric technologies and reducing reliance on fossil fuel combustion in the transportation and building sectors. WestLight does not currently procure and does not plan to procure electricity directly from fossil-fueled generation resources.
Consistent with its Preferred Portfolio results, WestLight plans to continue procuring a diverse mix of renewable and storage resources, increasing the share of customer load served by dedicated contracted 442
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resources and further reducing air pollutant emissions associated with system power purchases. As discussed in Section III.d.ii, WestLight's Green Transit Tariff represents an innovative approach to reducing greenhouse gas and criteria air pollutant emissions through coordinated renewable energy procurement and transportation electrification. By supplying Caltrain's electrified rail system with 100% renewable electricity and pioneering a first-of-its-kind tariff that also compensates regenerative braking exports, WestLight has demonstrated how electricity procurement can directly support cleaner transportation and improved air quality in disadvantaged communities. WestLight will continue expanding innovative procurement strategies that achieve both decarbonization and local public health benefits. While the Green Transit Tariff represents one example of WestLight's innovative approach to reducing emissions, WestLight also advances these objectives through a broad portfolio of customer programs targeted toward disadvantaged and underserved communities. Many of WestLight’s programs are income-qualified or designed to serve underserved customer segments, including low-income customers, customers residing in DACs, and multifamily residents. Table 38 below provides a description of these programs.
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Table 38: Overview of WestLight Programs Available to all customers, including those located within a DAC
Program Description Status
Community Solar Green
Tariff (CSGT) and
Disadvantaged
Community Green Tariff
(DAC-GT)
Pursuant to D.18-06-027, CCAs have
developed and implemented their own
DAC-GT and CS-GT programs to promote
the installation of renewable generation
among residential customers in
disadvantaged communities
(CalEnviroScreen DACs)
Approximately 2,600
customers are currently
enrolled and receiving a
20% bill discount from
participation.
Distributed Generation:
GovPV Solar + storage for
public buildings
Local government solar and storage
program that facilitates and finances
deployment of solar and storage on local
government sites. Launched in 2020.
To date, 36 sites have 5
MW of solar installed with
storage being developed for
approximately half the
sites.
Distributed Generation:
Residential solar +
storage
Facilitates installation of solar and storage
systems on single-family homes. The
program is currently focused on income-qualified customers being provided no-cost system with SGIP funds. The program is intended to broaden to all customers
later this year.
Installations at over 200
low-income customers is in-progress. Nearly 600
additional homes are
currently being dispatched
for grid services under a
prior version of the
program. New battery
systems will be integrated
into a virtual power plant
system.
Transportation: Used EV
Rebate
This program provides incentives for the
purchase of used electric vehicles for
income-qualified customers. The program
also provides an “EV advisor” hotline for
questions related to EVs. Launched in
2019.
Over 1,300 income-qualified rebates have been
provided since inception in
2019. Nearly 500 rebates
were provided for new EVs
in a prior version of the
program.
Transportation: E-Bikes This program provides incentives to income-qualified residents for the
purchase of e-bikes with point-of-sale
rebates. Launched in 2021.
To date over 2,100 rebates
to low-income customers.
Transportation: “EV
Ready”37 - EV Charging
Incentives and Technical
Assistance
This program provides incentives and
technical assistance for the installation of
EV charging at multi-family, workplace
and public locations. It includes a special
emphasis on multi-family charging
through advanced design assistance that
“right-sizes” infrastructure through power
To date the program has
installed nearly 2,400 ports,
two-thirds of which are at
multi-family buildings.
37 https://www.westlightenergy.org/business/rebates-offers-business/ev-ready-program/ 444
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management and low-power charging to
maximize cost-effective port installations.
Launched in 2020.
Buildings: Home Upgrade Provides incentives, on-bill finance and technical assistance for single-family
home electrification. Program includes
“self-serve” option, turnkey “full-service”,
including no-cost upgrades for income-qualified customers, and emergency water heater replacements. Emphasizes
right-sizing to avoid unnecessary service
upgrades.
Nearly 6,200 measures
supported including over
350 income-qualified
homes. Nearly 50 all-electric homes have been
completed in “full service”
offering.
FLEXmarket This is a pay-for-performance program
aimed at load shaping energy efficiency in
the commercial sector. The program pays
out incentives based on metered
performance using the Avoided Cost
Calculator as the basis of incentive value.
Launched 2022.
11 commercial projects
were completed in the first
iteration of the program.
Second iteration launching
shortly.
Buildings: Developer
Technical Assistance
This program provides no-cost technical
assistance to builders, developers and
designers primarily for new construction.
Launched 2020.
To date over 100 firms have
been provided with
assistance.
Buildings: Public Building
electrification
Provides grants and financing for
electrification of local government
buildings. Launched in 2024.
To date projects in 5 local
agencies have been
awarded and are in
progress. 2 projects have
been completed, including
a municipal pool
electrification project.
Transportation: Public
Fleets
Provides technical assistance to local
government fleets for developing a
vehicle replacement and infrastructure
plan. Program includes load shaping
assistance in a partnership with The
Mobility House. Launched in 2022.
To date, 15 agencies are
enrolled with projects in-progress and 2 projects
already completed
Building electrification
Reach Codes
Program supporting local governments in
adopting code enhancements for all-electric existing construction. Initiated in 2019 with a focus on new construction,
now the program focuses on existing
construction.
To date 4 cities have
adopted local codes that
encourage electrification of
space and water heating in
existing construction.
Since disadvantaged communities based on the CalEnviroScreen definition make up a relatively small portion of WestLight’s customer base, WestLight often expands the definition of eligible customers for the purposes of its programs to include eligibility based on income, customers on specific rates, and by using locally tailored wealth qualifications criteria. WestLight currently serves 445
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37,664 accounts enrolled in the California Alternate Rates for Energy (CARE) program and 1,993 accounts enrolled in the Family Electric Rate Assistance (FERA) program. Eligibility criteria vary by program based on administrative considerations, program design, and target outcomes. In general, WestLight utilizes a combination of income-based screening, such as CARE/FERA or area median income thresholds, and, for certain high-benefit programs, additional wealth-based criteria, such as liquid assets, property ownership, and housing characteristics to better target resources to customers with the greatest need. This approach allows WestLight to balance equitable program access with effective allocation of resources, particularly in cases where geographic definitions of DAC may not fully capture local socioeconomic conditions.
Outreach Activities in DACs
Community Outreach Grant Program
WestLight provides annual grants to community-based organizations to expand its engagement with hard-to-reach customers, including low-income, non-English-speaking, and other households from disadvantaged communities. These trusted local organizations provide information to customers about WestLight and its offerings in multiple languages. Grantees also help customers enroll in energy discount programs (e.g., CARE and LIHEAP) and adopt e-bikes, electric vehicles, and electric appliances.
Additionally, these partners facilitate workshops, focus groups, and other opportunities to solicit feedback directly from its customers to improve WestLight’s services. In 2026, WestLight awarded $550K in grants to 16 community-based organizations. Since 2018, WestLight has awarded $2.8 million in grants to 25 nonprofits.
In 2025, outreach grantees provided information about WestLight to 13,000+ customers in person and directed 21,000+ visits to its website. These partners helped enroll 1,110+ households in energy programs, including bill discounts and rebates for electric transportation and electric appliances.
Additional Outreach Initiatives
In 2026, WestLight has launched a new model of customer engagement through the Community Feedback Forum - a series of meetings designed to gather meaningful input from residents, nonprofit leaders, and other WestLight customers about its programs and services. An objective of the Community Feedback Forum is to provide interactive, flexible, and accessible forums for community listening. Meetings are offered in English and Spanish in a hybrid format.
c. LSEs’ Tribal Customers
There are no federally recognized tribal governments or tribal lands located within WestLight’s service territory in San Mateo County or the City of Los Banos, and WestLight does not currently serve any tribal government customers. While WestLight has not conducted tribal-specific outreach related to this IRP filing, WestLight’s resource solicitation processes include qualitative evaluation criteria related to tribal and cultural resource considerations, including whether project developers have consulted local Native American tribes regarding potential impacts to lands that may contain cultural resources. 446
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d. Procurement Products
WestLight may utilize the following procurement products, consistent with its Energy Risk Policy, to procure resources, serve customer load, and manage risks associated with its Preferred Portfolio.
Table 39: WestLight Procurement Products
Product Description of Product
Power Purchase
Agreements (PPA)
A contractual agreement for the purchase of energy from a generating resource that bundles physical electricity, RECs, and Resource Adequacy Capacity.
Financial Electricity
(Inter-SC Trade or IST)
Contractual or market-based transactions related to electricity that involve financial settlement but do not require the physical delivery of power, submitted to and cleared by the CAISO
Tolling Agreements A contract in which one party (the toller) pays the project owner for the right to control dispatch or charging and discharging of the facility.
The toller receives the energy, environmental attributes, and market revenues, while the owner operates and maintains the project in exchange for a fixed and/or variable tolling payment.
Resource Adequacy
Capacity
Capacity (in MWs) that is eligible to be counted toward compliance with the California Public Utilities Commission (CPUC) and the California Independent System Operator’s (CAISO’s) Resource Adequacy Program, which ensures sufficient reliable resources are available to meet peak electricity demand and maintain grid reliability.
Load-Serving Entities (LSEs) are required to meet System and Flexible Resource Adequacy obligations, which may be satisfied with capacity from electric power generation or demand-side resources.
Mid-Term Reliability
Capacity
Capacity that is eligible to be counted toward compliance with the California Public Utilities Commission’s Mid-Term Reliability procurement requirements, as established in Decisions D.21-06-035, D.23-02-040, and any subsequent decisions requiring the procurement of incremental capacity.
Maximum Import
Capability (MIC) or
Import Allocation Rights
(IAR)
The maximum amount of electricity capacity (in MWs) that can be reliably imported into California from outside the CAISO balancing authority area over the transmission system during peak demand conditions, and that is eligible to be counted toward Resource Adequacy compliance.
Specified Source Power Electricity and associated attributes that are traceable to specific generating facilities through an auditable contract trail or equivalent verification mechanism, such as a tradable commodity or tracking system, that provides commercial verification that the attributes claimed have been sold once and only once. Specified Source Power may be from facilities owned or controlled by WestLight or supported by executed contractual documentation. Examples of Specified Source Power that WestLight transacts are Renewable Energy Certificates (RECs) and Green House Gas (GHG) Free attributes.
Renewable Energy
Credits (RECs)
Credits that represent the renewable energy attributes associated with the generation of one megawatt-hour (MWh) of electricity from 447
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an eligible renewable energy resource that qualifies for the California Renewables Portfolio Standard (RPS).
Green House Gas (GHG)
Free attributes
Attributes associated with the generation of one megawatt-hour (MWh) of electricity from a zero-emissions resource (e.g. large hydro, nuclear) that otherwise does not qualify for the California Renewables Portfolio Standard (RPS)
Ancillary Services Energy products contracted to help maintain grid stability and reliability in CAISO. There are four types of ancillary services products:
regulation up, regulation down, spinning reserve, and non-spinning reserve.
Convergence Bids The purchase or sale of energy in the day-ahead market with the explicit requirement to buy or sell it back in the real-time market using convergence bidding, also called virtual bidding.
Congestion Revenue
Rights (CRRs)
Financial instruments used to offset congestion costs that occur in the day-ahead market process. CRRs are made available through allocations and may be transacted through auctions and bilateral trades.
The utilization of these products may evolve over the planning horizon based on market conditions, portfolio composition, and operational needs.
e. Commission Direction of Actions
WestLight Energy’s Board of Director’s oversees and governs WestLight’s planning and procurement activities. This IRP was approved by WestLight’s Board of Directors on July 23, 2026, and the resolution documenting this approval is attached as Appendix D.
WestLight requests that the Commission certify the completeness of WestLight Energy’s IRP detailing WestLight’s Preferred Portfolio, as summarized above and detailed in the completed Resource Data Template and Clean System Power Calculator.
WestLight encourages the Commission to provide a clear, durable, and coordinated long-term procurement framework through the Reliable and Clean Power Procurement Program (RCPPP) and related procurement proceedings. As procurement requirements evolve, continued alignment among Integrated Resource Planning, Resource Adequacy requirements, and the RCPPP will be important to avoid conflicting planning signals and unnecessary customer costs. Any programmatic approach should be responsive to changes in demand that are driven by electrification, climate-induced load changes, as well as load migration. Moreover, any programmatic approach should allow LSEs to manage their portfolio risk by allowing a variety of resource types and contract lengths, according to an LSE’s adopted risk policy.
The programmatic approach should support the maintenance of contracts with existing resources, as well as contracts with new resources, especially by supporting a mix of long-term and short-term contract structures. Short-term contracts preserve procurement flexibility, allowing LSEs to incorporate new technologies and take advantage of future cost declines as resources mature and market conditions evolve. Moreover, a programmatic approach should not penalize LSEs that have already developed a robust clean portfolio that provides the reliability and emissions reductions benefits required to serve that LSE’s customers. A failure to account for these early actors risks introducing serious cost shifts when early 448
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moving LSEs that have filled their portfolios are then called on to procure additional resources that will be actually used to meet the load of other LSEs.
WestLight further believes load-serving entities should remain the primary entities responsible for serving their customers’ resource needs, with centralized procurement used selectively where it provides clear market development, logistical, or cost advantages. Future procurement direction, including under the RCPPP, should reflect commercial readiness, transmission availability, interconnection timelines, customer affordability, and early procurement actions already taken by load-serving entities.
V. Lessons Learned
WestLight Energy appreciates staff’s time and efforts implementing the 2024-2027 Integrated Resource Planning process. California has aggressive goals that are challenging to implement, which currently appear to strain the already tenuous affordability of electricity in California. WestLight applauds the CPUC's solicitation of feedback for ways to potentially improve the IRP process to ensure that the Commission and LSEs can achieve state policy goals in the most prudent way possible.
The state policy goals pursued by the CPUC are often summarized as safety, reliability, and decarbonization, implemented in a cost-effective manner (emphasis added). Inspection of this statement shows that affordability is not a co-equal goal with the first three; but rather a consideration for implementation.
Expensive electricity rates prevent natural electrification because customers know they will pay more to use electric appliances than gas appliances. High electric rates also put economic strain on low-income customers and build resentment towards government policy objectives that are driving up rates.
WestLight encourages the CPUC to consider affordability as a co-equal objective alongside safety, reliability, and decarbonization. Maintaining customer affordability is critical not only for ratepayer protection, but also for sustaining public support for the investments necessary to achieve California's long-term climate and reliability objectives. To that end, WestLight offers the following suggestions:
Acknowledge uncertainty in load forecasting
Recent iterations of the IEPR load forecast have shown high fluctuations in projections related to data center speculation. Low quality data was submitted by stakeholders and used in published load forecasts and was subsequently revised. For example, in WestLight’s service territory, the published IEPR load forecast shows data center load in WestLight’s service territory associated with interconnection applications that, upon inspection, are either 1) not in WestLight’s service territory, or 2) associated with multi-family housing projects, not data centers. Because IEPR demand forecasts are used to inform CPUC IRP planning and procurement requirements, forecast uncertainty has direct implications for customer costs. The CEC should continue refining its treatment of large new loads and other uncertain sources of demand growth by distinguishing between verified and speculative load projections and working closely with CCAs and other LSEs to validate project status and expected energization timelines. Forecasts should transparently reflect uncertainty rather than relying solely on deterministic assumptions, helping ensure that procurement and infrastructure decisions are aligned with realistic load growth expectations.
IRP Procurement Mandates and the Reliable and Clean Power Procurement Program Recent procurement orders have demonstrated the risks associated with adding resource-specific procurement constraints late in the planning process without sufficient opportunity for analysis of 449
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potential market and reliability impacts. In the most recent procurement order, the addition of a long lead-time resource requirement effectively functioned as a long-duration storage mandate due to the limited availability of commercially mature geothermal resources. WestLight's own reliability analysis demonstrates that portfolios can contain substantial battery capacity that is unable to fully contribute to reliability needs due to insufficient generating resources that provide charging energy. Procurement requirements that further increase storage deployment without considering charging sufficiency will exacerbate this issue and lead to unintended reliability and affordability consequences.
WestLight encourages the CPUC to keep future procurement requirements as simple and technology-neutral as possible. Procurement requirements that focus on reliability, emissions reductions, and other planning objectives, rather than prescribing specific resource types, allow load-serving entities to identify the most cost-effective portfolio solutions while reducing the risk of developer market power and unintended resource concentration.
WestLight also supports the CPUC's continued development of the Reliable and Clean Power Procurement Program (RCPPP). A durable long-term procurement framework has the potential to reduce reliance on ad hoc procurement orders, provide greater certainty to market participants, and better align resource development with California's long-term reliability, affordability, and decarbonization objectives.
Align Reliability Planning with the Resource Adequacy Proceeding.
Since the prior filing cycle, California’s reliability planning framework has continued to evolve through Effective Load Carrying Capability (ELCC) methodologies, Slice-of-Day constructs, Resource Adequacy reforms, and the development of the Reliable and Clean Power Procurement Program (RCPPP). WestLight encourages continued alignment across these frameworks so that load-serving entities receive consistent and actionable planning signals. Since having two independent planning standards can only increase costs (if the two standards align, there is no change to procurement, but if they differ, additional procurement will be needed to meet both standards), and given that ELCC-denominated procurement orders appear to have induced procurement that has been misaligned with statewide needs, WestLight strongly encourages moving the IRP program to a Slice-of-Day methodology that better captures grid dynamics and does not trigger over procurement or cost shifting amongst LSEs. Greater coordination would improve procurement efficiency, reduce unnecessary complexity, and better support timely investment in reliable clean resources.
Fully incorporate and plan for responsiveness to possible outcomes of CPE procurement.
The current portfolio described in the Inputs and Assumptions assumes that no procurement is achieved by the CPE for long-lead time resources. Thus, if the CPE does indeed procure long-lead time resources, the portfolio described in the Inputs and Assumptions will be larger than needed to cost-effectively meet SB100 goals. The CPUC should carefully monitor CPE procurement activity and adjust procurement goals in the IRP and RCPPP proceedings such that SB100 goals are achieved in the most cost-effective way, avoiding unnecessary capacity over-build.
Plan for multiple scenarios – Build the least-regrets solution.
Current IRP modeling is done using deterministic modeling techniques, which assume a single future scenario and attempt to determine the optimal resource mix under that single future. While deterministic modeling is computationally simpler, it does not fully capture the uncertainty inherent in long-term resource planning since actual future conditions will inevitably differ from a single scenario. 450
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In order to achieve SB 100 goals, California is about to make large investments in both supply-side resources and distribution and transmission infrastructure, which will ultimately be financed by end-use customers. Using deterministic planning to make decisions about which investments are “optimal” will lead to stranded investments if the future does not proceed exactly according to the deterministic scenario, especially considering the large uncertainties faced by planners. Uncertainties in the magnitude of future load, the availability and costs of different resources, and the effects of changing weather patterns on resource generation mean that the stakes for making the best investment decisions are high, and deterministic modeling alone is not an appropriate basis for making long-term resource planning decisions.
Recent advances in modeling theory and computational abilities have given rise to a more sophisticated modeling approach known as “decision making under uncertainty”, or “DMUU”. This modeling approach considers a range of uncertainties in the modeled inputs and finds the lowest cost solution considering all the uncertainties. Recent demonstrations of these techniques show that the cost of the “DMUU” solution is marginally higher than the deterministic solution, but reduces future costs by orders of magnitude by selecting infrastructure investments that are adaptive and flexible to future uncertainty, avoiding stranded investments in infrastructure that are only necessary in one possible future that never materializes.38
WestLight encourages the CPUC to support and adopt DMUU techniques into the IRP process. First, the CPUC should delineate the range of uncertainty in the input and assumptions used in the IRP modeling.
The CPUC should then use DMUU techniques to select a resource portfolio that is robust to future uncertainty and avoids stranded investment costs by being adaptable, flexible, and realistic. The CPUC should also coordinate with and support the CAISO in adopting DMUU techniques within the Transmission Planning Process to support the approval of transmission upgrades that will be the most cost-effective investment across a range of uncertainties. Finally, the CPUC should require IOUs to use DMUU techniques when evaluating and requesting approval of distribution system investments.
Align imports and import capacity (MIC) planning.
The current portfolio developed by the CPUC for the Inputs and Assumptions shows reliance on out-of-state resources to achieve the state’s SB100 goals. However, the CPUC instructed CAISO in the 2025-2026 TPP to not plan for imported resources, despite their inclusion in the portfolio39.
This creates a disconnect between resource planning and transmission planning. If CAISO does not plan for imported resources, it will not identify or approve transmission upgrades needed to increase import capability at intertie locations. WestLight is already observing limitations in available import capacity for out-of-CAISO resources, and these constraints will become more pronounced over time if transmission planning assumptions surrounding imports do not align with resource planning assumptions. Imported resources tend to be more diverse than in-state resources and will likely play a critical role in cost-effectively achieving the state’s SB100 goals. 38 Mantegna, G., Dimanchev, E., Pecci, F., Patankar, N., & Jenkins, J. (2026). Uncertainty-aware grid planning in the real world: A method enabling large-scale, two-stage adaptive robust optimization for capacity expansion planning (arXiv:2603.00394). arXiv. https://doi.org/10.48550/arXiv.2603.00394 39 D.25-02-026 at 62
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LSEs would also appreciate an easy-to-use resource that shows existing and planned imports and MIC availability by year and transmission upgrade completion. The import capacity available at each intertie will increase as certain in-CAISO transmission upgrades come online, however, it is very difficult to track how that capacity will grow over time, and thus it is difficult to contract with out-of-CAISO resources with future delivery dates.
Ground busbar mapping in CAISO interconnection queue realities.
There are resources in the CAISO interconnection queue that cannot get deliverability because there is no mechanism to trigger certain transmission upgrades that will relieve constraints. LSEs provide resource preferences to CPUC in the IRP process, which CPUC uses as an input to busbar mapping in the TPP.
However, LSE preferences are only one side of the commercial process that leads to successful resource development. LSEs are not developers, and they do not know where the most viable sites are located for development. The CPUC’s over-reliance on broad geographic preferences stated by LSEs in the IRP causes the busbar mapping process and subsequently, the TPP, to be overfit to LSEs preferences, ignoring the other side of the resource development process, represented by resources in the CAISO interconnection queue. The CPUC should find a way to incorporate the presence of resources in the interconnection queue and requests for deliverability into the busbar mapping process and allow that commercial interest to influence the transmission planning process and create deliverability.
Incorporate demand-side resources in the Integrating Resource Planning process: demand management, distributed energy resources, and distribution connected resources.
WestLight is limited in its ability to develop DCRs because of current market conditions and regulatory treatment leading to a divergence between how resource costs and benefits are measured.
On resource costs, WestLight acknowledges that DCRs typically have higher development cost because smaller (1MW – 20MW) systems do not benefit from economies of scale like 200MW – 1GW+ utility-scale procurement does. This is particularly relevant when it comes to interconnection costs and costs associated with achieving Full Capacity Deliverability Status (FCDS). It is essential that DCRs achieve FCDS or an equivalent capacity accreditation so that LSEs can receive resource adequacy (RA) credit for the resource. However, the current deliverability allocation process is an ill fit for projects of this size and type (i.e., it is typically cost prohibitive for DCRs to achieve FCDS).
On the benefit side, however, DCR electricity generation is compensated based on wholesale market prices following the same rules and compensation mechanisms as large-scale FTM projects even though these projects often have additional benefits that are not valued under the traditional least-cost best-fit procurement methodology. More specifically, DCRs can offset proximate load, thus mitigating the need for costly upgrades to the transmission and distribution grid, and moreover can provide positive non-energy impacts (NEIs) such as improving local air quality and assisting the workforce development goals of communities. However, none of these benefits are currently being valued under the existing market mechanisms and regulatory frameworks.
WestLightsupports the following specific policy recommendations to appropriately value these resources:
Count DCRs as Load Modifiers in the Year-Ahead RA Forecast Each year, CPUC-jurisdictional LSEs are required to submit year-ahead load forecasting data to the CEC and CPUC. The Year-Ahead load forecast form requires LSEs to forecast retails sales of 452
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electricity and peak demand for the upcoming calendar year. The form also asks LSEs to document forecasted capacity values of each type of load modifier (e.g. BTM PV, Battery Storage, Energy Efficiency, Light-Duty and Medium-Duty EV, etc.) which the CEC and CPUC account for when setting the LSE’s year ahead Resource Adequacy (RA) obligation. In other words, load modifier values can reduce the capacity an LSE needs to procure from the bulk transmission system. As RA prices have been relatively volatile in recent years40, and since increasing load forecasted in the IEPR may add upward pressure to RA prices, load-modifiers provide an alternative to supply side costs, assist the reliability of the bulk transmission system, and enhance distribution systems.
WestLight supports initiatives to expand the resource types that qualify as load modifiers41 because of the numerous local and system benefits mentioned above. Specifically, WestLight supports the initiative to study how DCR generation could be measured and recorded as a load modifier in the IEPR and YARA forecast template. When DCRs are sited close to load, they can offset the need for LSEs to procure electricity from the bulk-transmission system thereby producing the same effect as BTM load modifiers. Hence, DCRs should be able to receive the same treatment as BTM load modifiers under the CEC’s Peak Demand Forecasting process.
Consider NEIs in Electricity Supply Modeling
The Production Cost Model (PCM) and the Capacity Expansion Model (CEM) frameworks represent the state’s most robust and transparent resource modeling processes and form the basis of the IRP. However, these electricity supply models were designed for centralized, fossil fuel, dispatch-oriented generation42 which makes them incapable of including many essential non-energy impacts (NEIs) that DERs or DCRs could provide (e.g., local air quality, resilience, household energy cost, water and workforce impacts)43. The current versions of PCM and CEM models used by the state in the IRP proceeding do not attempt to model the ways that larger deployment rates of DERs and DCRs could both impact supply-side costs and local economic development, environmental benefits, and resilience. Instead, the models rely on static input assumptions of DERs based on forecasts, rate design, and existing program adoption rates which constrain their benefits in statewide resource planning.
On May 19, 2026, the CEC hosted a Staff Webinar on Integrating NEI Metrics in Supply Modeling44 where CEC staff explained that the current models miss negative impacts of generation resources on local communities such as higher rates of diesel particulate matter and/or the negative impacts that nitrogen oxide pollution bears on people living near fossil-fuel power plants. 40 https://cal-cca.org/resource-adequacy/
41 Joint Comments on 2026 IEPR Update,
https://efiling.energy.ca.gov/GetDocument.aspx?tn=269324&DocumentContentId=106404 42 Staff Webinar on Integrating NEI Metrics in Supply Modeling, Slide 17 & 18 43 Staff Webinar on Integrating NEI Metrics in Supply Modeling, Slide 19 44 Staff Webinar on Integrating NEI Metrics in Supply Modeling available here, https://efiling.energy.ca.gov/GetDocument.aspx?tn=270022&DocumentContentId=107174 453
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WestLight concurs with the initial findings of the CEC and recommends that the existing electricity supply model analysis be updated (e.g. improved modeling constraints and objectives)45 to incorporate the holistic impacts of electricity generation, including both costs and NEIs. This would enable the State to better evaluate how BTM DERs and DCRs can strengthen the electricity system while also helping solve localized concerns such as pollution, economic development and resilience.
Evaluate and Credit Transmission and Distribution Grid Benefits to DCRs As mentioned above, DCRs are often located closer to load than large-scale FTM generation resources. They can often directly serve load within the same distribution and transmission constraints, which has two benefits for the grid infrastructure. First, DCRs help avoid the need for transmission line build-out and alleviate potential transmission congestion costs by siting generation closer to load. Second, DCRs can have specific locational benefits by deferring or mitigating upgrades to the distribution grid that otherwise would have to occur in the area.
Ordered by D.21-02-006, the IOUs offered the Distribution Investment Deferral Framework (DIDF) Partnership Pilots (“Pilots”) until D.24-10-030 suspended the Pilots.46 The Pilots were initially designed to procure BTM DERs to avoid or defer utility distribution investments but they also incorporated FTM DCRs to solve the same issues.47 Despite its many shortcomings, the DIDF Pilots demonstrated that DERs and DCRs can indeed mitigate distribution investments, leading to specific and quantifiable costs savings for the utility. Unfortunately, the DIDF Partnership Pilots were suspended in D.24-10-003 and despite ongoing discussions under the Commission’s High DER Proceeding (R.21-06-017), no new mechanism has been created to date to value the grid upgrade deferral value that DERs and DCRs can provide. The Commission should establish a mechanism that appropriately values the transmission and distribution benefits provided by DCRs and DERs so that their benefits can be reflected in resource procurement and planning decisions.
Allow for a firm timeline for portfolio development.
WestLight is strongly interested in providing the Commission with robust and extremely well-analyzed portfolios to support the Commission in its efforts but needs sufficient time in which to perform that analysis and needs to be able to plan when the work will be able to occur. Uncommunicated delays affect LSEs’ ability to manage their work schedules to ensure the modeling is both up-to-date and completed on time. While WestLight certainly understands the challenges in foreseeing every possible issue that arises while several dozen LSEs engage in the IRP process, WestLight recommends increasing staffing or other resources or reconsidering the timelines and structures for the IRP process. In general, the critical requirements and major parameters, such as load forecasts, required data inputs including available resources, costs, and reliability targets, required targets, and required portfolios must be finalized at least 8 to 10 months in advance to allow for robust portfolio development. WestLight believes this will be in the best interest of the overall process so that LSE IRPs can be of the highest quality and usefulness to the Commission.
45 NEI Integration Approaches – Supplemental Information, https://efiling.energy.ca.gov/GetDocument.aspx?tn=270338&DocumentContentId=107530 46 D.24-10-030, Finding of Fact 17
47 Read more at https://www.latitudemedia.com/news/inside-the-battery-projects-redefining-pges-grid-upgrade-playbook/?shem=rimspwouoe 454
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WestLight also encourages increased transparency regarding core planning assumptions, including load growth forecasts, electrification impacts, large new loads, resource development expectations, and transmission availability. As planning outcomes increasingly depend on uncertain future conditions, transparent assumptions and scenario analysis will improve stakeholder confidence and produce more durable planning outcomes.
Develop a centralized project database to minimize repetitive data collection.
Many of the data points required to be input in the RDT are redundant with data that should already have been collected and recorded by the CPUC. Specifically, for online resources with CAISO resource IDs, the CPUC should have access to the nameplate capacity, technology type, capacity area, location, commercial operation date, and contract term. Asking LSEs to continuously re-input the same data for the same resource across various filings invites data input errors and is an inefficient use of staff time. The CPUC should develop a centralized project database that contains quality-assured and quality-controlled data for each project. LSEs should be able to provide CPUC with a resource ID, and then CPUC can use the database to look up the relevant project information.
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Glossary of Terms
Alternative Portfolio: LSEs are permitted to submit “Alternative Portfolios” developed from scenarios using different assumptions from those used in the Preferred System Plan with updates. Any deviations from the “Conforming Portfolio” must be explained and justified.
Approve (Plan): the CPUC’s obligation to approve an LSE’s integrated resource plan derives from Public Utilities Code Section 454.52(b)(2) and the procurement planning process described in Public Utilities Code Section 454.5, in addition to the CPUC obligation to ensure safe and reliable service at just and reasonable rates under Public Utilities Code Section 451.
Balancing Authority Area (CAISO): the collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area.
Baseline resources: Those resources assumed to be fixed as a capacity expansion model input, as opposed to Candidate resources, which are selected by the model and are incremental to the Baseline.
Baseline resources are existing (already online) or owned or contracted to come online within the planning horizon. Existing resources with announced retirements are excluded from the Baseline for the applicable years. Being “contracted” refers to a resource holding signed contract/s with an LSE/s for much of its energy and capacity, as applicable, for a significant portion of its useful life. The contracts refer to those approved by the CPUC and/or the LSE’s governing board, as applicable. These criteria indicate the resource is relatively certain to come online. Baseline resources that are not online at the time of modeling may have a failure rate applied to their nameplate capacity to allow for the risk of them failing to come online.
Candidate resource: those resources, such as renewables, energy storage, natural gas generation, and demand response, available for selection in IRP capacity expansion modeling, incremental to the Baseline resources.
Capacity Expansion Model: a capacity expansion model is a computer model that simulates generation and transmission investment to meet forecasted electric load over many years, usually with the objective of minimizing the total cost of owning and operating the electrical system. Capacity expansion models can also be configured to only allow solutions that meet specific requirements, such as providing a minimum amount of capacity to ensure the reliability of the system or maintaining greenhouse gas emissions below an established level.
Certify (a Community Choice Aggregator Plan): Public Utilities Code 454.52(b)(3) requires the CPUC to certify the integrated resource plans of CCAs. “Certify” requires a formal act of the Commission to determine that the CCA’s Plan complies with the requirements of the statute and the process established via Public Utilities Code 454.51(a). In addition, the Commission must review the CCA Plans to determine any potential impacts on public utility bundled customers under Public Utilities Code Sections 451 and 454, among others.
Clean System Power (CSP) methodology: the methodology used to estimate GHG and criteria pollutant emissions associated with an LSE’s Portfolio based on how the LSE will expect to rely on system power on an hourly basis.
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Community Choice Aggregator: a governmental entity formed by a city or county to procure electricity for its residents, businesses, and municipal facilities.
Conforming Portfolio: the LSE portfolio that conforms to IRP Planning Standards, the 2045 LSE-specific GHG Emissions Benchmark, use of the LSE’s assigned load forecast, use of inputs and assumptions matching those used in developing the Reference System Portfolio, as well as other IRP requirements including the filing of a complete Narrative Template, a Resource Data Template and Clean System Power Calculator.
Effective Load Carrying Capacity: a percentage that expresses how well a resource is able avoid loss-of-load events (considering availability and use limitations). The percentage is relative to a reference resource, for example a resource that is always available with no use limitations. It is calculated via probabilistic reliability modeling, and yields a single percentage value for a given resource or grouping of resources.
Effective Megawatts (MW): perfect capacity equivalent MW, such as the MW calculated by applying an ELCC % multiplier to nameplate MW.
Electric Service Provider: an entity that offers electric service to a retail or end-use customer, but which does not fall within the definition of an electrical corporation under Public Utilities Code Section 218.
Filing Entity: an entity required by statute to file an integrated resource plan with CPUC.
Future: a set of assumptions about future conditions, such as load or gas prices.
GHG Benchmark (or LSE-specific 2045 GHG Benchmark): the mass-based GHG emission planning targets calculated by staff for each LSE based on the methodology established by the California Air Resources Board and required for use in LSE Portfolio development in IRP.
GHG Planning Price: the systemwide marginal GHG abatement cost associated with achieving a specific electric sector GHG planning target.
Integrated Resources Planning Standards (Planning Standards): the set of CPUC IRP rules, guidelines, formulas and metrics that LSEs must include in their LSE Plans.
Integrated Resource Planning (IRP) process: integrated resource planning process; the repeating cycle through which integrated resource plans are prepared, submitted, and reviewed by the CPUC Long term: more than 5 years unless otherwise specified.
Load Serving Entity: an electrical corporation, electric service provider, community choice aggregator, or electric cooperative.
Load Serving Entity (LSE) Plan: an LSE’s integrated resource plan; the full set of documents and information submitted by an LSE to the CPUC as part of the IRP process.
Load Serving Entity (LSE) Portfolio: a set of supply- and/or demand-side resources with certain attributes that together serve the LSE’s assigned load over the IRP planning horizon.
Loss of Load Expectation (LOLE): a metric that quantifies the expected frequency of loss-of-load events per year. Loss-of-load is any instance where available generating capacity is insufficient to serve electric demand. If one or more instances of loss-of-load occurring within the same day regardless of duration 457
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are counted as one loss-of-load event, then the LOLE metric can be compared to a reference point such as the industry probabilistic reliability standard of “one expected day in 10 years,” i.e. an LOLE of 0.1.
Maximum Import Capability: a California ISO metric that represents a quantity in MWs of imports determined by the CAISO to be simultaneously deliverable to the aggregate of load in the ISO’s Balancing Authority (BAA) Area and thus eligible for use in the Resource Adequacy process. The California ISO assess a MIC MW value for each intertie into the ISO’s BAA and allocated yearly to the LSEs. A LSE’s RA import showings are limited to its share of the MIC at each intertie.
Net Qualifying Capacity (NQC): Qualifying Capacity reduced, as applicable, based on: (1) testing and verification; (2) application of performance criteria; and (3) deliverability restrictions. The Net Qualifying Capacity determination shall be made by the California ISO pursuant to the provisions of this California ISO Tariff and the applicable Business Practice Manual.
Non-modeled costs: embedded fixed costs in today’s energy system (e.g., existing distribution revenue requirement, existing transmission revenue requirement, and energy efficiency program cost).
Nonstandard LSE Plan: type of integrated resource plan that an LSE may be eligible to file if it serves load outside the CAISO balancing authority area.
Optimization: an exercise undertaken in the CPUC’s Integrated Resource Planning (IRP) process using a capacity expansion model to identify a least-cost portfolio of electricity resources for meeting specific policy constraints, such as GHG reduction or RPS targets, while maintaining reliability given a set of assumptions about the future. Optimization in IRP considers resources assumed to be online over the planning horizon (baseline resources), some of which the model may choose not to retain, and additional resources (candidate resources) that the model is able to select to meet future grid needs.
Planned resource: any resource included in an LSE portfolio, whether already online or not, that is yet to be procured. Relating this to capacity expansion modeling terms, planned resources can be baseline resources (needing contract renewal, or currently owned/contracted by another LSE), candidate resources, or possibly resources that were not considered by the modeling, e.g., due to the passage of time between the modeling taking place and LSEs developing their plans. Planned resources can be specific (e.g., with a CAISO ID) or generic, with only the type, size and some geographic information identified.
Qualifying capacity: the maximum amount of Resource Adequacy Benefits a generating facility could provide before an assessment of its net qualifying capacity.
Preferred Conforming Portfolio: the conforming portfolio preferred by an LSE as the most suitable to its own needs; submitted to CPUC for review as one element of the LSE’s overall IRP plan.
Preferred System Plan: the Commission’s integrated resource plan composed of both the aggregation of LSE portfolios (i.e., Preferred System Portfolio) and the set of actions necessary to implement that portfolio (i.e., Preferred System Action Plan).
Preferred System Portfolio: the combined portfolios of individual LSEs within the CAISO, aggregated, reviewed and possibly modified by Commission staff as a proposal to the Commission, and adopted by the Commission as most responsive to statutory requirements per Pub. Util. Code 454.51; part of the Preferred System Plan.
Short term: 1 to 3 years (unless otherwise specified).
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Staff: CPUC Energy Division staff (unless otherwise specified).
Standard LSE Plan: type of integrated resource plan that an LSE is required to file if it serves load within the CAISO balancing authority area (unless the LSE demonstrates exemption from the IRP process).
Transmission Planning Process (TPP): process conducted by the California Independent System Operator (CAISO) to identify potential transmission system limitations and areas that need reinforcements over 10- year and 15-year horizons.
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DATE: July 10, 2026
MEETING DATE: July 23, 2026
VOTE REQUIRED: Majority Vote
TO: Honorable WestLight Energy Board of Directors
FROM: Kirsten Andrews-Schwind, Associate Director of Community Relations and Climate Equity
SUBJECT: Approval of Recommendation to Award the 2026 Dave Pine Community Energy Award to Community Outreach Workers (Promotoras) (Action) Item No. 8
WestLight Energy
JPA Board Correspondence
RECOMMENDATION
Approve awarding the first annual Dave Pine Community Energy Award at the September 30, 2026 Impact Summit hosted by WestLight Energy.
BACKGROUND
Established in May 2026, the Dave Pine Community Energy Award is an annual award to recognize local organizations or community members who have demonstrated exceptional commitment to advancing WestLight Energy’s mission and goals. The award is named in honor of former Supervisor and founding Board Chair, Dave Pine, for his longstanding leadership on climate action and vision in creating Peninsula Clean Energy, now WestLight Energy.
The Dave Pine Community Energy Award honors an organization or individual per year.
Award recipients are selected based on the following criteria:
1. Impactful work that advances WestLight Energy’s mission
2. Demonstration of potential to achieve significant greenhouse gas (GHG) reductions
3. Advancement of community equity goals
4. Projects or initiatives are conducted within WestLight Energy’s service area Awardees receive public recognition and the inclusion of honorees’ names on a commemorative plaque displayed in the Board room at WestLight Energy’s new office.
WestLight Energy Board members and Staff were invited to submit nominations for the Dave Pine Community Energy Award, and seven nominations were received. Each nominee was evaluated by an ad hoc working committee comprised of former Supervisor Dave Pine, Director Noelia Corzo, Director Coleen Mackin, Director Elmer Martinez Saballos, Director Marty Medina, and Director Betsy Nash.
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DISCUSSION
For the inaugural Dave Pine Community Energy Award, the ad hoc working committee recommends recognition of community outreach workers in WestLight Energy’s service area.
Community outreach workers (Promotoras in Spanish) have been key to WestLight Energy’s success in reaching our low-income, immigrant customers. They are most often well-connected women in immigrant communities who serve as a trusted bridge between government institutions and their immigrant neighbors. They educate themselves on topics of concern to their communities, such as social service and health programs, and conduct in-depth on-the-ground outreach about them in their native languages.
WestLight Energy has worked with various community-based organizations with Promotora networks over the years, primarily in Spanish but also in Tagalog. These dedicated outreach workers are the frontline communicators for the following concepts:
How WestLight Energy benefits customers and why they should not opt-out (and maintaining WestLight Energy’s ability to reduce greenhouse gas emissions by serving a large customer base with our procurement)
How bill discounts make energy more affordable for our most economically challenged customers, and how to enroll
The public health links between air quality and greenhouse gas emissions How to enroll in low-income programs such as e-bikes and used electric vehicles The first Dave Pine Community Energy Award will be presented by Dave Pine himself at WestLight Energy's Impact Summit on September 30, 2026. The committee recommends inviting community outreach workers who have partnered with WestLight Energy over the years to attend the event.
FISCAL IMPACT
None, the proposed award does not include a monetary component.
STRATEGIC PLAN
The Dave Pine Community Energy Award supports the guiding principle of Environmental Impact by recognizing efforts that reduce greenhouse gas emissions in our service area.
Through serving as trusted communicators, Community outreach workers also help WestLight Energy advance the guiding principal of Customer-Focused Approach. 461
RESOLUTION NO. _____________
WESTLIGHT ENERGY, COUNTY OF SAN MATEO, AND THE CITY OF LOS BANOS,
STATE OF CALIFORNIA
APPROVAL OF RECOMMENDATION TO AWARD THE 2026 DAVE PINE COMMUNITY
ENERGY AWARD TO COMMUNITY OUTREACH WORKERS (PROMOTORAS) (ACTION) RESOLVED, by Westlight Energy of the County of San Mateo, and the City of Los Banos, State of California, (“Westlight”) that:
WHEREAS, WestLight Energy was formed as Peninsula Clean Energy on February 29, 2016, and adopted the name WestLight Energy on May 28, 2026; and WHEREAS, as a County Supervisor, Dave Pine led the formation of Peninsula Clean Energy, now WestLight Energy, bringing together the County, cities, and major stakeholders. He then led the agency as the first Chair of the Board of Directors; and WHEREAS, in May 2026, WestLight Energy established the Dave Pine Community Energy Award in honor of former Supervisor and founding Board Chair Dave Pine and his longstanding leadership on climate action and vision in creating WestLight Energy; and WHEREAS, the Dave Pine Community Energy Award recognizes organizations and community members who have demonstrated exceptional commitment to advancing WestLight Energy’s mission and goals; and
WHEREAS, awardees are selected with the following criteria: 1) work that advances WestLight Energy’s mission; 2) demonstration of potential to achieve significant greenhouse gas (GHG) reduction; 3) advancement of community equity goals; 4) projects or initiatives are conducted within WestLight Energy’s service area; and
WHEREAS, WestLight Energy Board members and Staff were invited to submit nominations for the 2026 Dave Pine Community Energy Award; and
WHEREAS, an ad hoc working committee comprised of Board members and former Supervisor Pine evaluated nominees; and
WHEREAS, the ad hoc working committee recommended awarding community outreach workers in 2026 for their contributions to reaching WestLight Energy’s low-income immigrant communities; and
NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board recognize community outreach workers/Promotoras with the 2026 Dave Pine Community Energy Award.
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DATE: July 13, 2026
MEETING DATE: July 23, 2026
VOTE REQUIRED: Majority Vote
TO: Honorable WestLight Energy Board of Directors
FROM: Jennifer Stalzer, General Counsel
SUBJECT: Approval of an Agreement with Shawn E. Marshall, Chief Executive Officer, for the Term of July 1, 2026 to June 30, 2029 (Action)
Item No. 9
WestLight Energy
JPA Board Correspondence
RECOMMENDATION
The Board’s Ad Hoc Committee, consisting of Board Chair Marty Medina, Board Vice Chair Leslie Ragsdale, and former Board Chair Donna Colson, recommends that the Board approve a renewal Agreement with Shawn E. Marshall, Chief Executive Officer of WestLight Energy (the Agreement). The Agreement commenced on July 1, 2026 and concludes on June 30, 2029 with the possibility of an extension. Based on the Committee’s comprehensive review of Ms. Marshall’s performance and goal progress it recommends Board approval of an Amendment increasing Ms. Marshall’s annual base salary to $440,300. This represents a three and a half percent (3.5) percent increase from Ms. Marshall's current salary of $425,000.
The Ad Hoc Committee further recommends that the Executive Committee award Ms.
Marshall a discretionary bonus of $42,500 for the service year of 2025-2026.
BACKGROUND
Shawn E. Marshall was appointed as the Chief Executive Officer of WestLight Energy effective July 1, 2023 under an initial three-year contract that expired June 30, 2026. Following a comprehensive performance review process the attached Agreement has been drafted. This Agreement extends Ms. Marshall's tenure as CEO for an additional three-years through June 30, 2029 subject to the terms of the Agreement and sets salary at $440,300.
DISCUSSION
The Board’s Ad Hoc CEO Review Committee in conjunction with WestLight's Director of People and Culture, Leilani Johnson, managed a comprehensive performance review process and evaluated Ms. Marshall's performance in a number of categories over her third year as CEO. The Ad Hoc Committee concluded that during her third year of service, Ms. Marshall met or exceeded expectations in all performance categories. The Ad Hoc Committee also reviewed Ms. Marshall’s goals as reviewed and approved by the Committee following her 2025 performance review. The goals are completed or in progress to the Committee’s satisfaction. Finally, the Ad Hoc committee reviewed current CEO salary data from other 464
northern California CCAs to benchmark current CEO salary ranges.
Based on her performance and goal progression in the service of WestLight Energy, the Ad Hoc Committee recommends that Ms. Marshall’s contract be renewed and that her salary be increased three and a half percent (3.5%) to an amount not to exceed $440,300 and that this amount shall be effective July 1, 2026. Further, there is a recommendation to the Executive Committee that it award a bonus of ten percent (10%) of the Chief Executive Officer’s 2025- 2026 base salary ($42,500) given Ms. Marshall's performance. The performance of such bonus is at awarded at the sole discretion of the Executive Committee.
In conclusion and based on the above-described reviews and analysis, the Ad Hoc Committee recommends approval of the agreement with Shawn E. Marshall inclusive of the pay increase as described herein. The Committee also thanks Shawn E. Marshall for her three years of excellent service as Chief Executive Officer of WestLight Energy. Ms. Marshall’s performance will be reevaluated on or before June 30, 2027.
FISCAL IMPACT
Funding for the Chief Executive Officer’s compensation, including the approved salary adjustment and any discretionary bonus awarded by the Executive Committee, was included in the Fiscal Year 2026–27 budget approved by the Board.
ATTACHMENTS:
Shawn Contract Contract II July 2026.pdf
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RESOLUTION NO. _____________
WESTLIGHT ENERGY, COUNTY OF SAN MATEO, AND THE CITY OF LOS BANOS,
STATE OF CALIFORNIA
APPROVAL OF AN AGREEMENT WITH SHAWN E. MARSHALL, CHIEF EXECUTIVE OFFICER, FOR THE TERM OF JULY 1, 2026 TO JUNE 30, 2029 (ACTION) RESOLVED, by Westlight Energy of the County of San Mateo, and the City of Los Banos, State of California, (“Westlight”) that:
WHEREAS, WestLight Energy was formed as Peninsula Clean Energy on February 29, 2016, and adopted the name WestLight Energy on May 28, 2026; and WHEREAS, Shawn E. Marshall was appointed to the position of Chief Executive Officer of WestLight Energy on July 1, 2023; and
WHEREAS, the WestLight Board of Directors conducts yearly reviews of Ms. Marshall's performance; and
WHEREAS, consistent with this practice, the WestLight Board of Directors initiated a third year review of Ms. Marshall’s performance and goals through an Ad Hoc Committee of the WestLight Board consisting of Board Chair Marty Medina, Board Vice Chair Leslie Ragsdale, and former Board Chair Donna Colson; and
WHEREAS, the Board’s Ad Hoc Committee concluded that during her third year of service, Ms. Marshall either met or exceeded expectations in all evaluated performance categories; and
WHEREAS, the Ad Hoc Committee also assessed Ms. Marshall’s progress on her 2025-2026 goals that were previously reviewed and approved by the Committee; and WHEREAS, the Ad Hoc Committee determined that Ms. Marshall’s evaluated goals are either appropriately in progress or completed to its satisfaction; and WHEREAS, based on her excellent performance and progress on critical goals, the Ad Hoc Committee recommends that Ms. Marshall’s contract be renewed for the term July 1, 2026 through June 30, 2029; and
WHEREAS, that Ms. Marshall's salary be increased by three and half percent (3.5%) to an amount not to exceed $440,300 and that this salary amount shall be effective July 1, 2026; and
WHEREAS, the Board further recommends to the Executive Committee that Ms. Marshall 466
receive the $42,500 discretionary annual bonus allowed by the June 26, 2025 Amendment based on her excellent performance in the position of CEO; and WHEREAS, this Board has been presented with a form of such Agreement and has examined and approved as to both form and content and desires to enter into the same.
NOW THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Chair of WestLight Energy be, and hereby is authorized and directed to execute an Agreement Between WestLight Energy and Shawn E. Marshall for Service as Chief Executive Officer for and on behalf of WestLight Energy, and the General Counsel may attest the Chair’s signature thereto.
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AGREEMENT BETWEEN WESTLIGHT ENERGY AND
SHAWN E. MARSHALL FOR SERVICE AS CHIEF EXECUTIVE
OFFICER
THIS AGREEMENT is entered into this 1st day of July 2026, between WESTLIGHT ENERGY (“WESTLIGHT”), a joint powers agency established by the County of San Mateo and the Cities and Towns within the County as well as the City of Los Banos, and SHAWN E.
MARSHALL (“CEO”).
W I T N E S S E T H
WHEREAS, in 2023, WESTLIGHT conducted a recruitment for the Chief Executive Officer and selected SHAWN E. MARSHALL as the CEO of WESTLIGHT; WHEREAS, SHAWN E. MARSHALL has served ably as Chief Executive Officer of WESTLIGHT since 2023;
WHEREAS, the Board of Directors of WESTLIGHT desires to enter into an additional three year contract with the CEO for the years 2026-2029; NOW, THEREFORE, in consideration of the mutual covenants, terms and conditions as hereinafter set forth, the parties agree as follows:
1. SHAWN E. MARSHALL is hereby employed as CEO of WESTLIGHT pursuant to this Agreement. This Agreement, and CEO’s term of employment, commences on July 1, 2026 and ends on June 30, 2029. The specification of a term indicates only the maximum length of this Agreement and is not a guarantee of employment for any period of time. CEO is an at-will employee and shall serve at the pleasure of the WESTLIGHT Board of Directors (“WESTLIGHT Board”). WESTLIGHT may terminate this Agreement, without cause, at any time for any reason effective immediately upon written notice. CEO may terminate this agreement, without cause, at any time for any reason upon sixty (60) days written notice. 1468
2. CEO shall be responsible for the day-to-day administration of WESTLIGHT under the direction of the WESTLIGHT Board. CEO shall seek advice and assistance from the Executive Committee and any other committee constituted by WESTLIGHT for that purpose.
CEO shall devote her full-time efforts to the performance of the duties of CEO of WESTLIGHT.
Beginning July 1, 2026, CEO shall receive an annual salary of FOUR HUNDRED AND FORTY FOUR THOUSAND THREE HUNDRED DOLLARS ($440,300.00) in 24 bimonthly installments of $18,345.83. This salary will remain in effect until at least June 30, 2029.
4. Any further salary increase will be made in conjunction with CEO’s annual performance reviews, which will generally take place on or about June 30th of each succeeding year. The determination of whether any salary adjustments are merited and the amount of the adjustments are within the sole discretion of the WESTLIGHT Board, whose decision shall be final. Further, CEO shall be eligible for an annual bonus of up to TEN PERCENT (10%) of the CEO's current salary to the extent that the Executive Committee of the WESTLIGHT Board (or an ad hoc committee appointed by the Executive Committee) determines that the CEO has met or exceeded the goals and objectives established by Executive Committee (or an ad hoc committee appointed by the Executive Committee). The determination of whether any bonus is merited and the amount are within the sole discretion of the WESTLIGHT Executive Committee (or an ad hoc committee appointed by the Executive Committee), whose decision shall be final.
5. WESTLIGHT shall provide CEO with a Defined Contribution Plan or Plans. The Plan(s) will provide for a matching contribution from WESTLIGHT in the same manner and amount as that currently provided to other WESTLIGHT employees. The matching contribution from WESTLIGHT will vest in accordance with the vesting terms established for other WESTLIGHT employees set forth in the Plan(s) but in no event will the vesting period exceed four years.
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6. CEO shall accrue paid leave and such paid leave shall be accrued and capped in a manner consistent with that of other WESTLIGHT management employees. In addition, CEO shall accrue one (1) additional day of Paid Time for each year of service (e.g., after three (3) years of CEO's total service they shall accrue three (3) additional days of PTO).
7. CEO shall be provided with paid holidays in conformance with the paid holidays established for other WESTLIGHT employees.
8. CEO is eligible for health, vision, dental and other benefits in the same manner and cost as other WESTLIGHT employees.
9. During the employment term WESTLIGHT shall reimburse CEO for budgeted and reasonable out-of-pocket expenses incurred in connection with WESTLIGHT’s business, including reasonable expenses for mileage, travel, conferences, and membership dues in professional organizations that are appropriate to WESTLIGHT’s goals, as approved by the Chair of the Board.
10. WESTLIGHT shall pay CEO for all services through the effective date of termination. CEO shall have no right to any additional compensation or payment, except as provided below and except for any accrued and vested benefits. a. If WESTLIGHT terminates this Agreement (thereby terminating CEO’s employment) without cause, WESTLIGHT shall pay CEO a lump sum severance benefit equal to four (4) months of her then applicable base salary thereafter. b. If WESTLIGHT terminates this Agreement (thereby terminating CEO’s employment) with cause, CEO shall not be entitled to any severance. As used in this Agreement, cause shall mean termination due to:
(1) A judgment or adverse determination by any court, the State Attorney General, a grand jury, or the California Fair Political Practices 3470
Commission involving any misconduct in the course and scope of duties, including but not limited to: intentional tort or violation of any statute or law constituting misconduct in office, misuse of public funds or conflict of interest; (2) Conviction of a felony;
(3) Conviction of a misdemeanor arising out of CEO’s duties under this Agreement and involving a willful or intentional violation of law or any crime of moral turpitude;
(4) Willful abandonment of duties;
(5) A pattern of repeated, willful and intentional failures to carry out materially significant and legally constituted policy decisions of the WESTLIGHT Board made by the WESTLIGHT Board as a body or persistent and willful violation of properly established rules and procedures; and
(6) Any other action or inaction by CEO that materially and substantially harms WESTLIGHT’s interests, materially and substantially impedes or disrupts the performance of WESTLIGHT, or that is detrimental to employee safety or public safety.
c. If CEO terminates this Agreement (thereby terminating CEO’s employment), CEO shall not be entitled to any severance. d. Any other term of this Agreement notwithstanding, the maximum severance that CEO may receive under this Agreement shall not exceed the limitations provided in Government Code Sections 53260 – 53264, or other applicable law. Further, in the event CEO is convicted of a crime involving an abuse of office or position, CEO 4471
shall reimburse the WESTLIGHT for any paid leave or cash settlement (including severance), as provided by Government Code Sections 53243 – 53243.4.
11. This Agreement represents the entire agreement between the parties with respect to the subject matter addressed herein, and any previous agreements between the parties, whether written or oral, with respect to the subject matter of this agreement are of no further force and effect. All subsequent modifications of this agreement shall not be effective unless set forth in writing and executed by CEO and by Resolution of the WESTLIGHT Board.
IN WITNESS WHEREOF, the parties have executed this Agreement on the day and year written below.
Dated____________________ WESTLIGHT ENERGY
By______________________________________
Marty Medina
Chair, WESTLIGHT Board of
Directors
ATTEST:
_________________________
General Counsel
Dated_____________________ By____________________________________ Shawn E. Marshall
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DATE: July 10, 2026
MEETING DATE: July 23, 2026
VOTE REQUIRED: None
TO: Honorable WestLight Energy Board of Directors
FROM: Rafael Reyes, Senior Director of Energy Programs
SUBJECT: Community Energy Programs Quarterly Report
Item No. 11
WestLight Energy
JPA Board Correspondence
BACKGROUND
The following programs are in progress, key metrics are provided in the table here and detailed information is provided below.
Buildings
Home Upgrade Rebates
(Appliance Rebates)
6,733 measures rebated (+343 M/M); 1,359 loans issued (+19 M/M)
Home Upgrade Full-Service &
Emergency Water Heater
2024- phase (new): 95 homes completed
Emergency Water Heater Installations: 16
2021-2014 phase (old): 305 homes completed. Closed.
Home Upgrade Personalized
Support
358 support calls completed (66 in Q2 ‘26)
GovBE 5 GovBE projects, 7 schools projects
Reach Codes
4 cities adopted existing building codes: Menlo Park, San Mateo, Portola Valley, East Palo Alto.
Commercial Electrification BOD approved June 2026, est. launch Jan 2027 Distributed Resources
Residential Solar + Storage
Low-income: 160 complete, 59 pending
General market: 555 installs under prior program.
FLEXmarket
First round: 11 commercial and 13 residential projects
CPUC approved round two for 2026-2029, to open in Q3
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GovPV
Completed: 32 of 39 sites, 4.57 MW
Operational: 26 sites, 3MW
Energy Efficiency CPUC application submitted in March, approval late ‘27 Virtual Power Plants
Targeting dispatch of 1.2MWh of battery energy capacity from approximately 100 customers by summer.
Transportation
EV Charging Ports to date: 2,831 (+257 in Q2 26)
Used EV 1,570 EVs since 2021. (+80 M/M)
E-Bikes 3,650 rebates since 2021 (n/a, paused)
GovEV (fleets) 19 enrolled, 4 TA completed, ~4 installs expected in 2026 Other
Member Agency Energy
Grants
Proposals received from all cities. Projects in-progress.
DISCUSSION
1. Building and EV Reach Codes
Background: In 2018 the Board approved a building “reach code” initiative to support local governments in adopting enhancements to the building code for low-carbon and EV ready buildings. The initiative is a joint project with Silicon Valley Clean Energy (SVCE). May 2026 the Board approved the new contract with TRC to continue the program through December 2029.
The program includes no-cost technical assistance, model codes and other tools. The tools and model code language are available on the project website (www.BayAreaReachCodes.org). Program has received multiple extensions and expanded to provide technical assistance to builders and facilities managers. The program has had a major influence on state code. The most recent state code (effective January 1st) built on the local reach codes implementing an EV charger or outlet for every new multi-family residence with an assigned parking space. Code also requires heat pump water and space heating in the proscriptive path for new construction, the most common choice of builders. The new phase of the project largely focuses on retrofit and other existing building reach code development, as well as options for more complex multi-family housing codes and Building Performance Standards. Additional partners have been brought on to assist with equity analysis and Building Performance Standard development.
Status
2026 Reach Codes: Menlo Park, San Mateo, Portola Valley, and East Palo Alto have adopted existing building reach codes targeting: major renovations, air conditioning replacements, pre-wiring at opportune times. A number of additional cities are exploring adoption, including Burlingame which held a study session on July 6 th.
Several cities have been experiencing significant delays in code approval with the Building Standards Commission (BSC). Local legislative officials have been engaged in outreach to BSC to learn more.
For more information, please visit https://bayareareachcodes.org/ 474
2. Buildings Programs
2.1 Home Upgrade Rebates and Zero Percent Loans
Background: Approved by the Board in May 2020, WestLight launched the heat pump water heater (HPWH) rebates in January 2021. Additionally, in August 2021, the Board approved an On-Bill Financing program (referred to as the Zero Percent Loan) and expansion of the program to include heat pump heating and cooling systems. The program offers qualified residential customers a 0% interest loan up to $10,000 to fund the cost of eligible electrification upgrades. The Zero Percent Loan program launched in October 2022.
Status: A limited time offer campaign to further incentivize heat pump water heater projects launched on April 1 and ran through May 31. Customers received an additional $500 (total of $4,000 rebate) during this time. The loan has experienced no defaults to date.
For more information, please visit https://www.westlightenergy.org/residential/home-upgrade-services/ Customer Satisfaction
Scores 1-5, 5=High
Metric Q1 26 Lifetime
Program Satisfaction 4.8 4.8
Satisfaction with Water Heater 4.4 4.5
Satisfaction with HVAC 4.7 4.7
2.2 Home Upgrade “Full-Service Installation” (includes Low-Income Direct-Install and Emergency Water Heater Service)
Background: In May 2020, the Board approved implementing a direct-install low-income home upgrade program to offer minor home repair, energy efficiency, and electrification measures to income-qualified homeowners at no cost to them. The measures implemented in each home varied depending on the home’s needs but included at least one electrification measure. The program launched on September 2021. The Board extended the program through June 30, 2024. The program served 305 homes, including 9 homes who received whole home electrification as part of a pilot within the program.
Following a competitive selection process, the Board approved the $26M contract with Franklin Energy on February 22, 2024 to provide whole home electrification upgrades at no-cost to low-income residents, full-service electrification installation services to non-income qualified residents at a low cost, and an emergency heat pump water heater replacement service. Silicon Valley Clean Energy (SVCE) also contracted with Franklin for the joint program.
The program experienced operational performance challenges and was restructured to improve performance in the second half of 2025, removing Franklin Energy as third-party implementor. WestLight selected 3 contractors (Fuse Electric, Villquin, and Super Brothers), following a competitive bid process, to work with directly in this program and WestLight transitioned to manage the program directly. The Board approved 3 contracts for these newly 475
selected contractors for total of $18M in November 2025.
Status: The program relaunched in December and has already received over 200 applications. Outreach campaigns were conducted in partnership with the City of Menlo Park, canvassing with our program partner, CRC, and community workshops focusing in Belle Haven. Other outreach is planned for summer 2026.
For more information, please https://www.westlightenergy.org/residential/home-upgrade-services/full-service-home-electrification/
2.3 Local Government Building Electrification Program (GovBE) Background: In August 2023, the Board approved a local government building electrification program to help fund building electrification at local government facilities. The program will offer roughly $1 million per year in incentives and creates a $10 million dollar revolving loan fund. Incentives are based on therms saved at a given facility. Incentives and loan are capped at $600k per jurisdiction per year, each. The program requires a 25% cost-share from non- WestLight funds, and will have a streamlined, annual application process.
Status: GovBE’s 2025 funding round was opened in early June 2025, and applications remain open ongoing. There is $1 million in incentives available through a competitive application process. At this time, no cities have yet applied for the new round. The team is considering new options to provide to cities which might be more attractive. City staff has indicated staff bandwidth is the primary barrier to taking advantage of these funds.
A separate $5 million from the surplus funds were allocated for schools, which is open for applications on a rolling basis until funds are exhausted. WestLight is coordinating closely with the San Mateo County Sustainability Department and the San Mateo County Office of Education (SMCOE.) We hold monthly coordination meetings, and WestLight has a small contract with SMCOE to help provide funding for staff dedicated to school decarbonization.
SMCOE coordinates with local districts to promote decarbonization and increase awareness of WestLight programs
San Mateo County leads a program performing inventories of fossil-fuel fired equipment to aid in decarbonization assessments and planning. The County also provides this service for member agencies, which is a first-of-its-kind program in California.
Four school districts have been approved for funding, and three additional have applied. All contracts signed to-date have been HVAC electrification projects, with many districts performing portfolio-wide heating system electrification while improving air conditioning for classrooms. The most recent applications have been focused on heat pump water heater installations.
For more information, please visit https://www.westlightenergy.org/public-organization/govbe-program-electrification-for-public-buildings/
2.4 Personalized Support Services (Concierge)
Background: In March 2023, the Programs Team presented the Building Electrification Strategy to the BOD as a discussion item. The Building Electrification Strategy included a “hotline” provided electrification planning and technical support. In July 2024, WestLight hired 476
a new building electrification expert to provide customized support to WestLight customers.
Status: The service launched in 2025. 350+ support calls have been conducted. Callers information requests vary, many seeking high level information on approach and options for electrification. A new post-call personalized electrification planner is now provided to customers.
More info at https://www.westlightenergy.org/residential/home-upgrade-services/personalized-support/ Customer Satisfaction
Scores 1-5, 5=High
Metric Q2 26 Lifetime
Program Satisfaction 4.8 4.7
2.5 Commercial Electrification
Background: In August 2023, the Board approved commercial electrification program to help fund building electrification for Westlight Energy’s business customers. The program will offer roughly $1 million per year in incentives. Incentives will be offered as a $/widget, menu style, appliance rebates for commercial HVAC, water heating and cooking equipment. Incentives and loan will be capped at $50k per customer.
Status: Pre-Launch Planning
3. Distributed Energy Programs
WestLight Energy is advancing the distributed energy efforts below to reduce customer electricity bills, provide backup power, enable decarbonization, and to shape customer demand in a way that complements our renewable supply portfolio.
3.1 Solar and Storage for Public Buildings (“GovPV”)
Background: The Solar and Storage for Public Buildings / GovPV Program aggregates local government facilities into a group procurement of solar and optionally battery storage systems. WestLight Energy provides no-cost site assessments, preliminary designs, financial analysis, contracting support, public approval management, equipment procurement, and other project development support. Participating sites have systems installed as part of Power Purchase Agreements (“PPAs”) directly with WestLight Energy, which enable customers to get solar and battery storage at their facilities with no upfront investment. This model enables significant cost savings for participating agencies.
Initial site scoping and up to $8 million in capital was approved by the Board in October 2020 for the first round, known as “GovPV1”. At the January 2023 Board Meeting, the Board of Directors approved the installation contract and power purchase agreements with 10 jurisdictions in the first round for a total of 12 sites yielding 1.7 MW solar. Battery storage systems are planned for at least three of these facilities.
Round 2 – or “GovPV2” – was approved by the Board in January 2024, with a budget of $23 477
million. This portfolio includes 24 sites and 3.5MW solar. McMillan Electric, a local union firm, is providing construction services on round 2 and most of round 1. In February 2025, the Board approved an expanded scope with McMillan to build battery storage and EV chargers at GovPV sites, with an incremental budget increase of $7 million.
Round 3 – or GovPV3 – was approved by the Board in March 2026, with an increased budget of $5. This portfolio consists of three solar and battery energy storage projects.
Status: All 12 GovPV1 systems, totaling 1.7MW, were commissioned as of 2025. Of the 24 GovPV2 systems, fourteen are operational, seven are fully finish and awaiting utility approvals. The remaining three systems are expected to mostly be construction complete by the end of the summer. All eligible systems have been grandfathered into the more favorable NEM 2 tariff. Based on the most current modeling with updated rates, the projects collectively are projected to save participants approximately $40 million over 25 years. Staff is now developing and analyzing battery energy storage retrofits for this portfolio.
For future rounds, staff is working on early development processes for three solar + battery energy storage projects. Staff has developed and is now utilizing tools to estimate the amount of backup power that these systems can provide, prices that WestLight can offer program participants, and the associated cost-benefit analyses for customers. Staff is exploring approaches for continuing the program with less reliance on WestLight capital. Initial focus has been on California IBank, however the terms appear challenging so other options are now being explored.
For more information, please visit https://www.westlightenergy.org/public-organization/govpv-solar-battery-for-public-buildings/
3.2 Residential Solar + Battery Backup
Background: WestLight Energy’s programs for residential solar are split up into two customer segments: general market and low income. WestLight’s first general market program through a partnership with Sunrun is no longer accepting enrollments but is currently dispatching batteries and providing backup power to each home. These batteries are discharged daily to reduce WestLight’s peak load. WestLight receives >1.5MW of daily peak load reduction through 2032 from these resources. WestLight is developing a successor general market program.
Separately, WestLight implemented a program to help low-income single-family homeowners access the State of California’s Self-Generation Incentive Program (SGIP), called the Solar Battery Savings Program. SGIP provides behind-the-meter (BTM) storage or solar + storage systems to eligible low-income single-family homeowners to deliver bill savings and resilience benefits. The Solar Battery Savings Program leverages state SGIP incentives for low or no-cost system installation for income qualified customers. Reaching WestLight’s target of 200 installations would result in approximately 1MW of solar and 2.5MWh of battery storage. In October 2024, the Board approved WestLight’s contract with Haven Energy to manage the installation of these systems.
Status: Haven received 219 approvals for SGIP incentives and has completed 160 installations of battery-only, and solar and battery systems. Among those installations, 100 systems are now operational. In total, Haven has applied for over $5.8 million in state incentives to fund these solar and storage installations for low-income customers. 478
In 2025, WestLight ran a competitive solicitation to find the provider for the general market residential solar and storage program that will be geared towards our broader customer base.
The new program had been intended to launch in 2026 however, negotiations with a prospective partner were not successful and will result in timing delays. This program is now expected to launch late 2026 or early 2027.
3.3 FLEXmarket
Background: In November 2021 the Board approved a program plan for the establishment of an innovative meter efficiency and load-shaping program using what is known as FLEXmarket. FLEXmarket is a market-based program structure that provides incentives to program “aggregators” to implement programs for energy efficiency and load shaping. The novel elements of the structure include a “pay-for-performance” approach which only provides incentives on confirmed performance using meter data. This novel structure was innovated by MCE. In addition, the program plan was developed for submission to the CPUC to allow WestLight Energy to run the program with fully reimbursed funding through the CPUC. WestLight Energy’s billing data services provider Calpine has entered into a strategic partnership with the firm Recurve to provide FLEXmarket services through a streamlined structure. Providers of energy efficiency and building electrification equipment can apply for incentives through this program.
Staff developed the commercial version of the program and launched the market in July 2023.
Like the residential version, providers of commercial energy efficiency and building electrification equipment, as well as aggregators of these projects, can pursue incentives through the Commercial FLEXmarket. This iteration of the program closed in May 2025 as the funding cycle ended. In May of 2025, WestLight applied to renew funding for a commercial-only program for another 3 years. WestLight received CPUC for this funding in January 2026.
Status: The FLEXMarket Program has delivered approximately $1.8 million in combined energy and grid benefits, helping lower overall system costs for customers.
The program has paused new enrollments due to the closure of the current funding cycle as of May 2025. Project savings for enrolled projects concluded in Q4, and final payments for round one projects were issued in Q2 2026. Launch activities have initiated for the round two funding. WestLight has been engaging with Calpine to recontract dervices for the FLEXMarket platform through Recurve. This process has taken longer than anticipated, but it is in the finalization stages and should have a signd contract for July 2026. However, due to this delay we missed our targeted relaunch date of Q2, but we anticipate the program reopening for enrollment in Q3 2026.
For more information, please visit https://www.westlightenergy.org/business/rebates-offers-business/flexmarket-program
3.4 Energy Efficiency
Background: As part of WestLight Energy’s strategy to diversify revenue and leverage external funding for customer programs, we are preparing to submit our first Application for Third-Party Administration (ATA) to the California Public Utilities Commission (CPUC). This application aims to secure a third-party portfolio under the CPUC’s energy efficiency framework. In alignment with CPUC priorities, the portfolio will emphasize greenhouse gas (GHG) reductions and decarbonization, to the extent permitted within CPUC cost-479 effectiveness and policy constraints. This is WestLight’s first ATA submission; currently, only one other Community Choice Aggregator (CCA) holds an approved third-party portfolio, making this a strategic and precedent-setting effort.
Status: WestLight submitted its Energy Efficiency application in March 2026. The application proposes eight new programs to be fully funded by the CPUC for the years 2028-2031.
Totaling $36 million over the term, the programs focus on customer segments in WestLight service territory not fully served by current programs including commercial sectors, multifamily buildings and additional support for underserved residential households.
The next immediate steps in the process include responding to stakeholder comments on the application, addressing data requests over the coming months, and participating in other CPUC procedural activities. Approval is currently expected in late 2027.
To learn more about our Energy Efficiency application, please visit:
https://www.westlightenergy.org/public-information/regulatory-filings and navigate to the Energy Efficiency Business Plan Application section.
3.5 Virtual Power Plants
Background: As part of the 2026-2030 Strategic Plan, WestLight established a 5-year goal to launch a 10 MW Virtual Power Plant (VPP) by 2030. WestLight will aggregate behind-the-meter DERs under this VPP, using a Distributed Energy Resource Management System (DERMS), a centralized software system that helps entities monitor, control, and optimize behind-the-meter DERs. In May 2025, the Board approved a 5-year, $3.1 million contract with Lunar Energy for their DERMS, Lunar Gridshare.
Status: WestLight and Lunar have executed a contract and have progressed with designing the dispatch plans and integrations for residential battery storage. This summer, WestLight will enroll the first solar and storage systems into this VPP using systems installed under WestLight’s Solar Battery Savings Program. WestLight is targeting approximately 100 customers representing 1.2 MWh of battery energy capacity to begin participating in the VPP by Summer 2026. Communications and customer education materials are being drafted that will explain the VPP to customers and support them if they have any questions or concerns.
4. Transportation Programs
4.1 Used Electric Vehicle (EV)
Background: Originally launched in March 2019, the Used EV Rebate Program currently provides a $2,000 rebate to income-qualified residents. Customers have been able to receive the WestLight rebate at the point of sale with participating dealerships.
Status: The program made moderate changes effective July 1, including requiring that all rebates be redeemed at participating dealerships only, updating income requirements to match CARE/FERA, and limiting one rebate per customer per lifetime.
Staff are monitoring the possible implementation of a new California EV point of sale rebate in FY 27 and possible implications for the WestLight rebate offering. 480
For more information, please visit https://www.westlightenergy.org/residential/rebates-offers/ev-rebate-program/ Customer Satisfaction
Scores 1-5, 5=High
Metric Q1 26 Lifetime
Program Satisfaction 4.4 4.9
4.2 “EV Ready” Charging Design Assistance & Incentives
Background: In December 2018, the Board approved the EV Ready program, consisting of EV charging infrastructure incentives and technical assistance. The program is open and available to multi-family housing, affordable housing, workplace charging, and general public-access sites, through there is a general focus on multi-family housing, which has been a historically underserved population in state EV charging programs.
WestLight offers free project design assistance, facilitated through Ecology Action (previously through CLEAResult). There are currently 300+ active projects receiving this assistance and, on average, projects receiving assistance more than double the overall size of their EV charging projects.
Status: The program has helped the community install nearly 3,500 chargers (70%+ at multi-family housing) with more than 3,000 additional chargers in progress. Key elements of the program are being replicated by a number of other state and regional programs, including the CEC “Communities in Charge” program.
Some of the largest multi-family EV charging projects in the nation are occurring currently in the EV Ready program. This includes the installation of over 200 chargers in South San Francisco, the single largest retrofit multi-family EV charging project in the state, which is hosting a ribbon cutting ceremony on July 29 featuring CEC Commissioner Skinner and CPUC Commissioner Baker. Local news report: https://www.youtube.com/watch?v=jdTpDQSz6Ys&t After a competitive bid in the summer of 2025, Ecology Action was selected as the new technical assistance provider and started working with customers in December 2025. After marketing efforts throughout the first half of 2026, the program is receiving an average of ~10 project applications per month, a similar application rate to before the switch to Ecology Action in 2025. Additional marketing activities, such as emails, blog posts, and webinars are underway. The EV Ready program is actively recruiting and seeking referrals to property owners and housing organizations.
Program staff participated in several events during Affordable Housing Month to advocate for EV charging at affordable housing properties. This included attending the grand opening of Middlefield Junction, where 90+ outlets and chargers were installed with WestLight Energy technical support and funding, one of the largest affordable housing EV charging projects of its kind.
To address EV charging affordability issues, WestLight is also currently leading an innovation grant opportunity. This will develop new EV charging systems that can be submetered to a multi-family residential unit, even though the charger is connected to a separate meter, 481
reducing or eliminating price markups experienced by EV drivers. Orange Charger has been awarded this innovation grant and work has begun. Major regulatory hurdles exist and staff are now engaging with the CPUC on submetering regulation improvements.
For more information, please visit https://www.westlightenergy.org/business/rebates-offers-business/ev-ready-program
4.3 E-Bike Rebate Program
Background: The Board originally approved the income-qualified E-Bikes Rebate program in July 2020 and has run in annual cycles to provide rebates to residents with low to moderate incomes. The program has provided over 3,500 rebates since 2021. Customers can use the rebate at qualifying bike shops for a point-of-sale discount. with 20+ participating bike shops in San Mateo County and Merced County (for Los Banos-based customers).
Status: The program transitioned to a year-round offering and relaunched on May 6, 2025.
The program was very popular with an average of about over 300 rebates provided per month.
The program is particularly popular in Los Banos, which is now receiving the majority of rebates. However, the program was exceeding budget and operating capacity requiring reassessment.
As of late May, the program has been paused while undertaking backend systems updates.
The program is expected to relaunch in Q4 of 2026 with several program modifications, including a monthly limit of 150 rebates with a first-come, first-served application process opening around the 1
st of every month. Community-based organizations are available to assist customers with applications.
For more information, please visit https://www.westlightenergy.org/residential/rebates-offers/e-bikes Customer Satisfaction
Scores 1-5, 5=High
Metric Q1 26 Lifetime
Program Satisfaction 4.6 4.8
Satisfaction with E-Bike 4.7 4.8
4.4 Public EV Fleet Program (GovEV)
Background: The Board approved the GovEV Fleet Program in November 2020. This program is comprised of three components to help local agencies begin their fleet electrification efforts: hands-on technical assistance, gap funding, and a vehicle to building resiliency demonstration that will assess the costs and benefits of utilizing fleet EVs as backup power resources for agencies in grid failures and other emergencies. In August 2022, the Board of Directors approved a contract with Optony to provide technical assistance in this program and further approved an extension with Optony in March 2024. An additional two-year extension with Optony is proposed for the April Board meeting.
Status: 19 local municipal fleets have enrolled, including: Bay Area Air District, Brisbane, Burlingame, Caltrain (non-revenue fleet), Cabrillo USD, Central Coast Water Authority, Daly 482
City, East Palo Alto, Foster City, Half Moon Bay, Menlo Park, Millbrae, Redwood City Elementary School District, Rethink Waste San Bruno, San Carlos, San Mateo, San Mateo Community College District, and South San Francisco.
East Palo Alto recently installed 4 fleet EV chargers after receiving assistance through GovEV.
San Bruno, Burlingame, and Menlo Park are expected to begin construction shortly.
For more information, please visit https://www.westlightenergy.org/public-organization/govev-program-public-fleet-electrification
5. Other Programs
5.1 Member Agency Energy Grants
Background: In December 2023 the Board directed WestLight to implement a set of initiatives utilizing a one-time allocation from surplus funds. One of the programs is the Member Agency Energy Grants with up to $11.5 million for grants to member agencies as flexible funding for a range of clean energy projects. Funding is provided by formula in a non-competitive allocation for qualifying projects required to execute within two years.
Status: Proposals have been received from all member agencies with 17 grant agreements and projects underway.
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DATE: July 10, 2026
MEETING DATE: July 23, 2026
VOTE REQUIRED: None
TO: Honorable WestLight Energy Board of Directors
FROM: Gwen Rose, Director of Marketing and Community Relations SUBJECT: Marketing, Outreach Activities, and Media Relations Quarterly Report Item No. 12
WestLight Energy
JPA Board Correspondence
BACKGROUND
The Marketing & Community Relations teams continued to enhance WestLight Energy’s (formerly PCE) reputation, educate and engage customers, and strengthen community partnerships in support of electrification, affordability, and long-term decarbonization goals.
During Q2, the department successfully completed implementation of the WestLight Energy rebrand, expanded customer outreach and community engagement, advanced the agency's 10-year impact campaign, and increased WestLight Energy's visibility through strategic media relations and thought leadership.
DISCUSSION
Brand
Q2 marked the successful implementation of the WestLight Energy brand. Following Board approval of the visual identity in April, staff completed brand guidelines and worked in coordination with other departments to transition to business operations as WestLight Energy on June 26. The new website launched on June 29, with customer-facing communications beginning in June ahead of the July 1 public launch.
Staff also completed the first WestLight Energy brand video, refreshed hundreds of marketing assets and collateral pieces, transitioned social media channels to the new brand, and coordinated communications with customers, member agencies, vendors, and community partners throughout the transition.
Program Marketing
Program marketing continued to support customer affordability and electrification through coordinated campaigns for Home Upgrade Services, EV Ready, heat pump water heater incentives, and Solar + Battery Savings.
Marketing collaborated closely with Programs and implementation partners to support customer education, while developing a department-wide marketing dashboard that will improve measurement and optimization of future campaigns. 484
Events
Community engagement remained strong throughout Q2.
• Community events attended: 24
• Customers reached: approximately 2,600
Staff participated in Earth Day celebrations throughout San Mateo County, Youth Climate Ambassadors events, the Middlefield Junction Affordable Housing grand opening, the Multi-Family Building Electrification Summit, Brisbane Community Pool ribbon cutting, and Binational Workshops in Los Banos. These engagements strengthened relationships with customers, member agencies, schools, and community organizations while increasing awareness of WestLight Energy programs and services.
Outreach Grants
Outreach Grant partners continued expanding WestLight Energy's reach into priority communities through culturally relevant education and engagement. During Q2, outreach grantees participated in message testing for the WestLight Energy campaign, supported Community Feedback Forums, and provided valuable customer insights to strengthen future communications and outreach efforts.
These partnerships continue to strengthen equitable access to WestLight Energy programs while building trusted relationships with community organizations throughout the service territory.
School and Youth Programs
Education remained a priority throughout Q2. Staff evaluated proposals for the 2026–2028 School Engagement Program and continued working to connect students with clean energy education and career opportunities. School districts continue to receive tailored support with decarbonizing their facilities. Additional outreach included Youth Climate Ambassadors programming, the GovPV Ribbon-Cutting at the SMC Office of Education, and support for community education initiatives during Earth Month.
Voice of Customer
Voice of Customer (VoC) efforts continued to expand through Community Feedback Forums, customer research, and message testing that informed both programs and the WestLight Energy transition.
During Q2, staff hosted a Community Feedback Forum focused on local climate action, completed analysis of customer feedback related to residential battery programs, tested WestLight Energy messaging with outreach grantees and community participants, and implemented a standardized tagging system for customer communications to improve long-term analysis and reporting. Findings confirmed that while the agency gathers substantial customer input, there is an opportunity to better align insights across departments and strengthen how they inform programs and communications.
News and Media
Media Relations focuses on enhancing WestLight Energy’s reputation and leadership position by garnering earned media attention. Highlights from the quarter include:
1. WestLight Energy Rebrand. Staff executed a coordinated communications strategy 485
supporting the transition to WestLight Energy, including outreach to customers, member agencies, community organizations, and partners in advance of the public launch.
2. Building Electrification and Local Partnerships. Media outreach surrounding building electrification projects generated coverage of the San Mateo County Office of Education solar installation, Atherton Town Hall solar project, Menlo Park City Hall solar project, and Brisbane Community Pool electrification. Coverage appeared in outlets including Redwood City Pulse, InMenlo, KTSF Channel 26, and regional community publications.
3. Affordable Housing and EV Charging. Affordable Housing Month communications highlighted WestLight Energy's installation of EV charging infrastructure at Middlefield Junction in Redwood City. The story generated coverage in CleanTechnica, Charged EVs, and other electric vehicle trade publications, helping position WestLight Energy as a leader in equitable transportation electrification.
4. Thought Leadership. Staff strengthened relationships with national energy reporters through outreach during San Francisco Climate Week and participation in industry events. Engagement included KQED, Canary Media, Heatmap News, Bay Area News Group, and San Jose Mercury News, expanding WestLight Energy's visibility on building electrification and clean energy innovation.
STRATEGIC PLAN
STRATEGIC PLAN
The Marketing & Community Relations activities described in this report support WestLight Energy's 2026–2030 Strategic Plan by advancing customer engagement, environmental leadership, equity, innovation, and organizational excellence.
Customer-Focused Approach
Program marketing, community events, and Voice of Customer initiatives strengthened customer participation, engagement, and satisfaction. Marketing campaigns increased awareness of customer programs, community events provided opportunities for direct engagement, and Voice of Customer activities helped ensure customer feedback continues to inform communications and program development.
Environmental Impact
Marketing and outreach efforts promoted electrification, energy efficiency, and clean energy solutions through customer campaigns, educational events, and partnerships, helping customers reduce greenhouse gas emissions while supporting the agency's decarbonization goals.
Economic Development
Communications highlighted WestLight Energy's affordability and customer value by promoting rebates, incentives, and competitive rates. Partnerships with community organizations also expanded equitable access to programs that provide financial benefits to customers.
Innovation
Brand implementation, thought leadership, and earned media positioned WestLight Energy as a leader in community choice energy and clean energy innovation. Staff participation in 486
conferences, strategic communications, and media outreach increased awareness of the agency's leadership and impact.
Equity
Community-based outreach, multilingual engagement, school partnerships, and the Outreach Grant Program expanded access to WestLight Energy's programs for historically underserved communities while ensuring community perspectives continue to shape outreach and communications.
Distributed Energy Resources
Marketing campaigns and customer education increased awareness of home electrification, electric vehicles, battery storage, and other distributed energy resources that help customers reduce emissions and improve energy resilience.
Organizational Excellence
Implementation of the WestLight Energy brand, marketing technology improvements, cross-department coordination, and expanded Voice of Customer capabilities strengthened organizational effectiveness and supported data-informed decision-making. 487
DATE: July 13, 2026
MEETING DATE: July 23, 2026
VOTE REQUIRED: None
TO: Honorable WestLight Energy Board of Directors
FROM: Mike Mielke, Senior Manager, Legislative Policy
SUBJECT: July 2026 Legislative Policy and Political Update Item No. 13
WestLight Energy
JPA Board Correspondence
BACKGROUND
This memorandum provides an overview of major political, legislative, and regulatory developments in Sacramento and Washington, D.C. that are most relevant to WestLight Energy as the California Legislature pauses for its Summer Recess and policymakers in California and Washington increasingly focus on affordability, reliability, transmission infrastructure, and growing electricity demand.
DISCUSSION
Sacramento Update: Energy Policy and Political Landscape As the California Legislature enters its Summer Recess, lawmakers leave behind an energy policy agenda that continues to be defined by one overarching challenge: how to maintain California's ambitious clean energy and climate goals while addressing growing concerns regarding affordability, electric reliability, and rapidly increasing electricity demand.
Although legislative committee activity has paused until August, significant negotiations continue behind the scenes on budget trailer bills, major energy legislation, and several high-profile policy issues expected to shape the final weeks of the legislative session.
Affordability remains the dominant political issue in Sacramento. Legislators across the political spectrum continue to express concern regarding rising electricity rates, the cumulative cost of climate and infrastructure investments, and the long-term affordability implications of transportation electrification, building electrification, and rapidly growing electricity demand.
Increasingly, policymakers are seeking solutions that improve affordability, maintain reliability, and preserve California's long-term clean energy trajectory.
Load growth has become one of the defining energy policy issues of 2026. Demand associated with artificial intelligence, data centers, advanced manufacturing, transportation electrification, and building electrification is forcing policymakers to reconsider longstanding assumptions regarding resource planning, transmission expansion, interconnection timelines, and infrastructure investment. As a result, many of the legislature's most significant energy 488
bills this year focus not only on climate objectives, but also on ensuring the electric system can reliably and affordably accommodate future demand.
Another noteworthy development is the legislature's increasingly critical view of the California Public Utilities Commission (CPUC). While lawmakers continue to recognize the Commission's important role in regulating California's energy sector, frustration has grown over rising electricity rates, implementation timelines, and the perception that legislative priorities are not always being carried out as intended. Although the most significant CPUC reform proposal stalled this year, legislative interest in Commission reform appears likely to continue into the next legislative session, particularly as affordability concerns remain at the forefront of energy policy discussions.
State Budget Update
Governor Newsom recently signed California's 2026-27 State Budget, providing greater certainty regarding the state's near-term fiscal outlook while leaving several significant energy and climate policy questions unresolved. Although the budget addresses the state's immediate fiscal challenges, California continues to face an underlying structural deficit, and policymakers remain cautious given ongoing uncertainty surrounding federal funding, economic conditions, and future revenues from the state's cap-and-invest program.
One of the most significant outstanding issues is the future allocation of Greenhouse Gas Reduction Fund (GGRF) revenues. While the budget provides an overall fiscal framework, lawmakers continue negotiating how future cap-and-invest revenues should be allocated among competing priorities, including public transit, climate programs, wildfire resilience, affordability initiatives, and other energy investments. Additional budget trailer bills are expected later this summer to address several of these issues.
Several major energy policy discussions also remain unresolved heading into August. These include potential legislation related to the future of Diablo Canyon Nuclear Power Plant, continued discussions regarding wildfire liability and cost recovery, and ongoing negotiations over several high-profile energy and environmental bills that remain active following policy committee deadlines. As a result, although the legislature is officially in recess, significant policy development will continue throughout July in preparation for the legislature's return in August.
2026 Governor's Race
The race to succeed Governor Gavin Newsom is influencing policy discussions in Sacramento. Following the June primary, former U.S. Secretary of Health and Human Services Xavier Becerra and Republican businessman Steve Hilton advanced to the November general election. While the candidates differ significantly on climate and energy policy, both campaigns are reinforcing a broader political trend already visible in the Legislature: growing emphasis on affordability, cost containment, and the practical implementation of California's climate goals.
Rather than debating how quickly California should pursue clean energy and decarbonization, policymakers are increasingly focused on how the transition can occur, how it should be paid for, and how affordability and reliability concerns should be balanced against climate objectives. Regardless of the election outcome, the governor's race is reinforcing legislative focus on electricity affordability, reliability, permitting, infrastructure development, and the pace of the clean energy transition—issues that are likely to remain central through the remainder 489
of the 2026 legislative session and beyond.
Top Issues Driving California Energy Policy
1. Energy Affordability: Affordability remains the dominant issue in Sacramento, with policymakers increasingly evaluating energy, climate, and infrastructure policies through the lens of customer electricity rates and overall cost impacts.
2. Load Growth: Rapid growth in electricity demand driven by artificial intelligence, data centers, transportation electrification, and advanced manufacturing continues to reshape discussions regarding long-term resource planning and grid investment.
3. Transmission Modernization: Policymakers continue to prioritize transmission expansion and modernization as essential to improving reliability, reducing congestion, and supporting California's evolving electricity needs.
4. Reliability: Maintaining electric system reliability while advancing California's clean energy goals remains a central focus of legislative and regulatory decision-making.
5. Local Governance and Regulatory Accountability: Community Choice Aggregator autonomy, local procurement flexibility, and effective implementation of legislative priorities by state agencies continue to be important themes in energy policy discussions.
Key Legislative Developments
While WestLight continues to monitor a broad range of legislation affecting California's energy sector, the following four bills remain the organization's highest legislative priorities because of their potential impacts on affordability, reliability, customer choice, and long-term electric system planning.
1. Transmission Planning Reform (AB 2111 – Papan)
AB 2111, jointly sponsored by WestLight Energy, Sonoma Clean Power, and the Abundance Network, remains WestLight's highest legislative priority this year. The bill would modernize California's transmission planning process by requiring planning agencies to evaluate multiple plausible future scenarios, improve coordination among the CPUC, CEC, and CAISO, and better align transmission planning with future electricity demand, infrastructure needs, and resource development. As California experiences rapid load growth driven by artificial intelligence, data centers, transportation electrification, and advanced manufacturing, the bill seeks to ensure that transmission planning better anticipates future needs while supporting affordability, reliability, and access to lower-cost clean energy resources. WestLight Energy Position: Co-Sponsor Status / Location: Senate Appropriations.
2. Power Charge Indifference Adjustment Transparency (AB 1761 – Rogers) AB 1761, sponsored by CalCCA, would improve transparency regarding the calculation of the Power Charge Indifference Adjustment (PCIA) by requiring additional disclosure regarding the assumptions and methodologies used to establish PCIA charges. Greater transparency would improve customer understanding, strengthen regulatory accountability, and enhance long-term procurement planning for Community Choice Aggregators. The bill reflects ongoing legislative interest in improving oversight of costs that directly affect customer electricity rates.
Position: Support
490
Status / Location: Senate Appropriations.
3. Slice-of-Day Resource Adequacy Flexibility (SB 1138 – Padilla) SB 1138, also sponsored by CalCCA, would provide additional flexibility within California's Slice-of-Day Resource Adequacy framework by allowing greater hourly transactability of resource adequacy obligations. The bill can help reduce unnecessary procurement costs, improve market efficiency, and maintain reliability while providing load-serving entities with greater operational flexibility. WestLight Energy Position: Support Status / Location: Assembly Appropriations.
4. Data Centers and Large Load Cost Responsibility (SB 886 – Padilla) SB 886 has emerged as one of the most significant energy policy bills in response to rapidly growing electricity demand from data centers and other large electrical loads. Recent amendments negotiated by CalCCA significantly improved the bill by protecting existing customers from procurement cost shifts, preserving local CCA governance, and explicitly clarifying that nothing in the bill authorizes the CPUC to regulate CCA rates or terms of service. The bill is increasingly viewed as a potential model for how California allocates the costs of serving large new electrical loads while protecting existing ratepayers and preserving local authority. WestLight Energy Position: Neutral
Status / Location: Assembly Appropriations.
Washington, D.C. Update: Energy Policy and Political Landscape Federal energy policy continues to evolve as policymakers respond to growing electricity demand, affordability concerns, and increasing pressure to modernize the nation's electric grid. While the Trump Administration remains focused on reducing regulatory burdens, expanding domestic energy production, and reassessing certain clean energy programs, bipartisan interest continues to grow around transmission expansion, permitting reform, grid reliability, and the infrastructure needed to support artificial intelligence, data centers, advanced manufacturing, and electrification.
Congress also continues to grapple with broader fiscal and energy policy priorities following enactment of the Administration's second reconciliation package. Discussions have already begun regarding a potential third reconciliation measure, although prospects remain uncertain.
Meanwhile, several significant regulatory and judicial developments—including FERC action on large-load interconnection, updated Department of Energy rebate guidance, and ongoing litigation affecting renewable energy tax credits—continue to reshape the federal energy policy landscape.
Top Issues Driving Federal Energy Policy
1. Electricity Demand Growth: Artificial intelligence, data centers, advanced manufacturing, and electrification continue to drive bipartisan interest in expanding generation, transmission, and grid infrastructure while ensuring that large new customers bear an appropriate share of associated costs.
2. Transmission and Permitting Reform: Congress continues to explore reforms intended to accelerate transmission development, modernize interconnection processes, and streamline permitting while balancing federal, state, and local authority. 491
3. Energy Affordability: Policymakers remain focused on reducing energy costs for consumers while ensuring sufficient investment in infrastructure needed to support long-term reliability and economic growth.
4. Federal Program Changes: Federal agencies continue to revise clean energy, electrification, and rebate programs, creating uncertainty for states, utilities, and project developers while new implementation guidance continues to emerge.
5. Grid Security: Cybersecurity and protection of critical energy infrastructure remain growing priorities as artificial intelligence and digital technologies become increasingly integrated into electric system operations.
Federal Energy: Legislative and Regulatory Policy Updates
1. Large Load Interconnection and Data Centers: One of the month's most significant developments came from the Federal Energy Regulatory Commission (FERC), which initiated action requiring regional transmission organizations and independent system operators to establish clearer rules governing the interconnection of large electrical loads, including data centers. Rather than asserting direct federal jurisdiction over co-located loads, FERC directed grid operators to establish more transparent processes for cost allocation, network upgrades, reliability, and large-load flexibility.
2. Transmission and Permitting Reform: Transmission and permitting reform remain among Congress's highest energy priorities. Lawmakers continue negotiating legislation to accelerate transmission development, improve interregional planning, modernize generator interconnection, and streamline permitting for critical energy infrastructure. While disagreements remain over federal siting authority and cost allocation, there is growing bipartisan recognition that transmission expansion is essential to meeting future electricity demand and maintaining grid reliability.
3. Federal Rebate Programs: The Department of Energy continues implementing revised guidance for the HOMES and High-Efficiency Electric Home Rebate (HEEHR) programs.
Under the updated guidance, HEEHR funds may no longer be used to remove existing fossil-fuel equipment, although heat pump installations remain eligible under certain circumstances.
California and other participating states are evaluating implementation options while awaiting additional DOE guidance.
4. California's Clean Air Act Waivers: The U.S. Environmental Protection Agency recently transmitted four additional California Clean Air Act waiver actions to Congress under the Congressional Review Act, including actions related to the state's remaining Advanced Clean Cars I requirements. These actions reflect continuing federal-state differences regarding California's authority to establish vehicle emissions standards and may influence future transportation electrification policy.
5. Geothermal: Congress recently advanced a bipartisan package of geothermal energy legislation intended to accelerate permitting and deployment of geothermal resources, reflecting growing interest in firm, carbon-free resources that can support grid reliability and meet increasing electricity demand.
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Strategic Takeaways for WestLight
1. Transmission policy is increasingly being driven by affordability, reliability, and load growth, not solely clean energy objectives.
2. Artificial intelligence and data centers continue to reshape energy policy at both the state and federal levels, with growing emphasis on infrastructure planning and cost responsibility.
3. Federal energy policy remains in flux as agencies continue revising regulations, incentive programs, and permitting processes that could affect California's clean energy transition.
4. As the California legislature returns in August, negotiations will intensify on several of WestLight's highest-priority bills and outstanding budget and energy policy issues.
ATTACHMENTS:
July 2026 Bill Matrix - Updated.pdf
493
Status of 2026 Legislative Session Bills
As of July 13, 2026
With WestLight Energy and CalCCA Adopted Positions
1 Bill Summary Status WestLight
Energy
Position
CalCCA
Position
Comments
AB 1761 (Rogers)
PCIA Data
Transparency
This bill would require the PUC to ensure that all
data relied on in any decision or ruling, or in any
proposal or analysis provided by an IOU, the
PUC’s staff, or any other party, for the
determination or application of a calculation
methodology for the PCIA is made available to
load-serving entities and ratepayer advocates
on behalf of customers.
Scheduled for
August 3 hearing
in Senate
Appropriations
Support Sponsor This is CalCCA’s
sponsored
legislation to
increase data
transparency on
PCIA inputs.
AB 1787 (Schultz)
Option Dynamic
Rate Tariff
Existing law requires that the rate component
be a nonbypassable element of the local
distribution service. This bill would require the
PUC to require an IOU, if the PUC approves the
IOU’s request to upgrade its smart meter
infrastructure, to offer all its customers at least
one dynamic rate option no later than one year
after the upgraded smart meter is anticipated to
be placed into service.
Awaiting hearing
in Senate
Appropriations
Oppose CalCCA had
concerns with this
bill but was able to
work with the
author on
amendments that
prevented an
oppose position
being needed.
AB 1849 (Papan)
Decarbonized
Gaseous Fuels
Current law regulates the emission of air
contaminants, including the oxides of nitrogen,
into the atmosphere. Current law generally
vests regulatory jurisdiction over stationary
sources of air pollution to the air pollution
control districts and air quality management
districts and regulatory jurisdiction over mobile
sources of air pollution to the California Air
Dead - Held in
Assembly
Appropriations
and
494
Status of 2026 Legislative Session Bills
As of July 13, 2026
With WestLight Energy and CalCCA Adopted Positions
2 Bill Summary Status WestLight
Energy
Position
CalCCA
Position
Comments
Resources Board (CARB). This bill would require,
on or before December 31, 2027, CARB to
conduct an assessment of the amount of
decarbonized gaseous fuels that will be needed
to decarbonize hard-to-electrify sectors and
maintain reliability in the electricity sector. The
bill would require the assessment to include an
assessment of the need for decarbonized
gaseous fuels in each hard-to-electrify sector.
AB 2111 (Papan)
Transmission
Planning
Existing law requires the PUC, in consultation
with the CEC, to provide transmission-focused
guidance to the Independent System Operator
(ISO) about resource portfolios of expected
future renewable energy resources and zero-carbon resources, including by region, to allow the ISO to identify and approve transmission
facilities needed to interconnect resources. This
bill would require the PUC, CEC, and ISO on or
before January 1, 2028, to incorporate
uncertainty into their planning efforts.
Scheduled for
August 3 hearing
in Senate
Appropriations
Co-SponsorSupport WestLight Energy
is co-sponsoring
the bill along with
Sonoma Clean
Power and the
Abundance
Network
AB 2234 (Papan)
CEQA: Geothermal
Exploratory
Projects
The California Environmental Quality Act (CEQA)
requires a lead agency, to prepare, or cause to
be prepared, and certify the completion of an
environmental impact report on a project that it
proposes to carry out or approve that may have
a significant effect on the environment. Existing
Scheduled for
August 3 hearing
in Senate
Appropriations
This bill is
sponsored by
Sonoma Clean
Power.
495
Status of 2026 Legislative Session Bills
As of July 13, 2026
With WestLight Energy and CalCCA Adopted Positions
3 Bill Summary Status WestLight
Energy
Position
CalCCA
Position
Comments
law establishes the Geologic Energy
Management Division in the Department of
Conservation. Existing law requires the division
to be the lead agency for all geothermal
exploratory projects for purposes of CEQA. This
bill would expressly include as part of a
geothermal exploratory project, among other
things, equipment and activities necessary to
establish interconnectivity between wells and
reservoirs, for purposes of CEQA.
A similar version
of this bill was
vetoed by the
Governor in 2025.
AB 2266 (Schultz)
Resource Adequacy
and Procurement
Planning
This bill would streamline certain CPUC
reporting requirements related to resource
adequacy (RA), integrated resource planning
(IRP), and renewable procurement programs. It
would also require the CPUC to use a single
capacity valuation methodology when setting
resource adequacy and procurement
requirements beginning in 2030.
Scheduled for
August 3 hearing
in Senate
Appropriations
Support
if
Amended
CalCCA, WestLight
Energy and other
CCAs have
proposed/submitt
ed amendments
to help prevent
cost shifts among
loadserving
entities, ensure
the capacity
valuation
methodology does
not favor or
disadvantage
particular
resource types,
496
Status of 2026 Legislative Session Bills
As of July 13, 2026
With WestLight Energy and CalCCA Adopted Positions
4 Bill Summary Status WestLight
Energy
Position
CalCCA
Position
Comments
and improve the
bill's reporting and
implementation
provisions.
AB 2313 (Berman)
Home Energy
Choice Act
This bill, the Home Energy Choice Act, would
require the PUC to require each gas IOU to offer
a Gas Distribution Service Line Replacement
Alternatives Program, on or before January 1,
2028, to provide gas customers served by a gas
distribution service line, planned or forecasted
for replacement over the next 5 years, or
prioritized for replacement by the PUC, with a
monetary incentive to deploy gas distribution
service line replacement alternatives, such as
heat pumps or induction stoves, and cease gas
service to avoid the gas distribution service line
replacement.
Scheduled for
August 3 hearing
in Senate
Appropriations
Support Support Co-sponsored by
Earthjustice and
NRDC
AB 2369 (Rogers)
Resource
Adequacy: Energy-Only Resources
This bill would require the CPUC's Resource
Adequacy framework to ensure that load-serving entities procure sufficient energy storage and other energy-only resources to
maintain electric system reliability.
Scheduled for
August 3 hearing
in Senate
Appropriations
Support Sponsored by
Sonoma Clean
Power
AB 2383 (Zbur) This bill would require the PUC, on or before January 1, 2028, in a new or existing
proceeding, to provide for a classification of
Scheduled for
August 3 hearing
Neutral CalCCA was in an
Oppose Unless
Amended position
497
Status of 2026 Legislative Session Bills
As of July 13, 2026
With WestLight Energy and CalCCA Adopted Positions
5 Bill Summary Status WestLight
Energy
Position
CalCCA
Position
Comments
Large Energy Use
Facilities
retail electricity consumers that are large energy
use facilities (data centers) that is separate and
distinct from classifications of service for other
commercial or industrial retail electricity
consumers and has its own rate schedule, as
specified.
in Senate
Appropriations
but successfully
negotiated
amendments to
move to neutral
AB 2493 (Petrie-Norris)Existing law requires the PUC, if it determines that the rules, practices, equipment, appliances,
facilities, or service of a public utility, or the
methods of manufacture, distribution,
transmission, storage, or supply used by an IOU
are unjust, unreasonable, unsafe, improper,
inadequate, or insufficient, to determine and fix
the rules, practices, equipment, appliances,
facilities, service, or methods to be observed,
furnished, constructed, enforced, or employed.
This bill would require the PUC to require each
IOU to retain an independent third-party
auditor to review certain transmission- and
interconnection-related submissions made by
the IOU.
Scheduled for
August 3 hearing
in Senate
Appropriations
AB 2508 (Hoover)
Public Utilities
Public Purpose
Programs Fund
Existing law vests the Public Utilities
Commission with regulatory authority over
public utilities, including electrical corporations.
Under existing law, the commission administers,
or otherwise oversees, various public purpose
Dead – Held in
Assembly
Appropriations
Oppose Also opposed by
MCE and San
Diego Clean Power
498
Status of 2026 Legislative Session Bills
As of July 13, 2026
With WestLight Energy and CalCCA Adopted Positions
6 Bill Summary Status WestLight
Energy
Position
CalCCA
Position
Comments
programs, including energy efficiency and
conservation programs, cost-effective energy
efficiency programs, rate assistance programs
for eligible food banks, and home insulation
financial assistance programs. This bill would
establish the Public Utilities Public Purpose
Programs Fund. The bill would require the
commission, no later than January 1 of each
year, commencing January 1, 2027, to
determine and publish the amount necessary to
fund certain public purpose programs and
programs administered by electrical regional
energy networks for the following fiscal year, as
provided.