Central Coast Community Energy (3CE) Operations Board
August 9, 2023

Operations Board of Directors
August 9, 2023
10:30 A.M.

Central Coast Community Energy
70 Garden Court, Suite 300
Monterey, CA 93940

REMOTE LOCATION VIA TELECONFERENCE
Any interested parties or community members may attend, and participate in, the meeting at the following addresses where Board members may also join the meeting from:

County of Santa Cruz
701 Ocean Street, Third Floor Training Room
Santa Cruz, CA 95060
City of San Luis Obispo
City Hall
990 Palm Street, Council Chambers
San Luis Obispo, CA 93401
City of Santa Maria
City Hall
110 East Cook Street, Council Chambers
Santa Maria, CA 93454
City of Goleta
City Hall
130 Cremona Drive, Conference Room 1
Goleta, CA 93117
Public may participate through ZOOM. For ZOOM participation please join by computer audio at:
https://us02web.zoom.us/s/82380649701
Or join by phone:
+1 669 900 6833 or +1 669 219 2599
Enter this Webinar ID Number: 823 8064 9701 when prompted. Please note there is no Participant Code, you will press # again after the recording prompts you.

You will be placed in the meeting as an attendee. To make a public comment:
 If joined by computer, please press the button to raise your hand  If joined by phone, please push *9 on your keypad
If you have anything that you wish to be distributed to the Board, please provide 15 copies to a member of 3CE staff or the Board Clerk, who will distribute the information to the Board members and staff.

The public may comment on the consent agenda and matters not listed on the agenda but within the Board's jurisdiction at the opening of the meeting. The Board may not take action at this meeting on any item not listed on the Agenda other than to refer the matter to staff or set it for a future meeting. The public may comment on a specific item listed on this agenda when the Board considers that item.

Speakers are limited to 3 minutes each.

In addition, members of the public may request and receive copies without undue delay of any documents that are distributed to the Board, unless there is a specific exemption under the Public Records Act that prevents the disclosure of the record. (Cal. Gov’t Code Section 54957.5) In compliance with Government Code Section 54957.5, non-exempt writings that are distributed to a majority or all of the Board in advance of a meeting and that relate to an agenda item will be made available at 3CE’s offices located at 70 Garden Court, Suite 300, Monterey, CA 93940 during normal business hours and are also available on the 3CE website located at: https://pub-3ce.escribemeetings.com/

AGENDA

Welcome & Roll Call
Pledge of Allegiance
Corrections or Additions
The Clerk will announce agenda corrections and proposed additions of emergency, urgency, or continued items, which will be acted on by the Board as provided in Sections 54954.2 of the California Government Code.

Public Comment on the Consent Agenda and Matters Not Listed on the Agenda.

The public may provide comments on any item within the Board's jurisdiction but not on the agenda. The Board may not take action at this meeting on any item not listed on the agenda other than to refer the matter to staff or set it for a future meeting. Speakers are limited to 3 minutes each.

CONSENT CALENDAR

1. Approve Minutes from the May 10, 2023 meeting of the Operations Board of Directors

2. Approve and authorize the CEO to execute a broker agreement to enable procurement of Resource Adequacy (RA) Products with a transaction fee not to exceed 1.0% of the notional value of the RA transaction ICAP Energy LLC Inc finds for 3CE

3. Approve and authorize the CEO to execute broker agreement to enable procurement of Resource Adequacy (RA) Products with a transaction fee not to exceed 1.0% of the notional of the RA transaction Karbone Inc finds for 3CE

4. Receive update on recent changes to the Energy Risk Management Policy approved by the Risk Management Committee in July 2023

5. Approve and authorize the CEO to execute Amendment No. 1 to the agreement with TRC Engineers Inc. to provide technical assistance services in support of Member Agency reach code adoption to increase the total not to exceed amount to $321,935 and extend
the term to September 30, 2025

6. Approve and authorize the CEO to execute Amendment No. 2 to the agreement with Cohen Ventures Inc. doing business as (DBA) Energy Solutions to provide implementation services in support if the Electrify Your Home Program, extending term of the
agreement by one (1) year to September 30, 2024, and reflecting adjustments to incentives

7. Approve and authorize CEO to execute Amendment No. 1 to the agreement with Bruan, Blaising & Wynne, P.C. to increase contractual not to exceed amount from $130,000 to $145,000 for additional regulatory services support for the 2022-2023 fiscal year

8. Approve an amendment to the Agreement with Hall Energy Law, PC (“Hall Energy”) for specialized legal services to add $60,000, increasing the not to exceed from $150,000 to $210,000 for the 2022-23 Fiscal Year

9. Receive FY 2022-23 Energy Programs update

10. Receive Regulatory update

11. Treasurer's Report

REGULAR AGENDA

12. CAC Report

13. CEO Report
a. Staffing Updates
b. Policy Board Approves Project Selection Criteria
c. Market Outlook
d. Yellow Pine Energy Center Begins Operations
e. Resource Adequacy Rule Changes and CCA Expansion
f. Demand Response
g. Budget Update

14. Approve and authorize CEO to execute the small generator interconnection agreement between Pacific Gas and Electric Company and Central Coast Community Energy in an amount not to exceed $120,000 for the interconnection cost associated with the
installation of an energy storage facility at the Emeline project site

15. Approve and authorize CEO to execute the small generator interconnection agreement between Pacific Gas and Electric Company and Central Coast Community Energy in an amount not to exceed $120,000 for the interconnection cost associated with the
installation of an energy storage facility at the Roy Wilson Project site

16. It is recommended that the Operations Board of Directors review, approve, and adopt a revised Central Coast Community Energy (3CE) Purchasing Policy - Financial Policy 8 (FP8) with an effective date of September 1, 2023

17. It is recommended that the Operations Board of Directors review, approve, and adopt an updated Central Coast Community Energy (3CE) Purchase Card Policy - Financial Policy 6 (FP6) with an effective date of September 1, 2023

18. It is recommended that the Operations Board of Directors review, approve, and adopt an updated Central Coast Community Energy (3CE) Travel Policy- Financial Policy 9 (FP9) with an effective date of September 1, 2023
Board Member Reports & Comments (Information Only)
Adjournment
Operations Board of Directors
May 10, 2023, 10:30 am
Central Coast Community Energy
70 Garden Court, Suite 300
Monterey, CA 93940
County of Santa Cruz
701 Ocean Street, Third Floor Training Room
Santa Cruz, CA 95060
City of San Luis Obispo
City Hall
990 Palm Street, Council
Chambers San Luis Obispo, CA
93401
City of Santa Maria
City Hall
110 East Cook Street, Council Chambers Santa
Maria, CA 93454
County of Santa Barbara
County Administration Building
105 East Anapamu Street,
Board of Supervisors Conference Room
Santa Barbara, CA 93101

MINUTES
The meeting was called to order at 10:30 AM with 11 members attending in 5 locations and a quorum established.

Directors Present: County of Santa Cruz: Palacios, Vice Chair Goldstein 3CE Headquarters: Espinosa, Guertin, Harvey, Pia, Wood
City of San Luis Obispo: Chair Johnson
City of Santa Maria: Stilwell
City of Santa Barbara: Chapjian, Imhof
Directors Absent: De La Rosa, Huffaker, Lewis, J. Lewis, T., Mendez (arrived at 10:45am- 3CE HQ), Murphy (arrived at 10:57am – Santa Maria), Reynolds (arrived at 10:37am – 3CE HQ)
Corrections or Additions
Clerk announced that * Approve and Authorize the CEO to Execute a Resource Adequacy Confirmation for Capacity with Long Beach Generation LLC, with a Term of 7 Years in an Amount Not to Exceed $55,146,000, Inclusive of Any Associated Broker Fees, and in a Form Substantially Similar to Exhibit A. Was added to the agenda within the compliance of the Brown Act and made available to the public on Friday, May 5, 2023.

The Chair opened the public comment period for the consent agenda and items not listed on the agenda.

No public comments received.

The Chair closed public comment period.

1. CONSENT AGENDA
MOTION: Moved by Director Chapjian, seconded by Director Pia to approve the Consent Agenda.

ACTION: The Motion Carried with a roll call vote: 12/0/6 AYES: Espinosa, Guertin, Harvey, Imhof, Chapjian, Palacios, Pia, Reynolds, Stilwell, Wood, Vice Chair Goldstein, Chair Johnson
NOES: None
ABSENT: De La Rosa, Huffaker, Lewis, J., Lewis, T. Mendez, Murphy

1. Approved Minutes from the April 12, 2023 Meeting of the Operations Board of Directors as submitted

2. Approved the CEO to Submit an Interim Load Management Standards Compliance Plan that Extends Deadlines for Loading Rate Information into the California Energy Commission’s Market Informed Demand Automation Server as Permitted Under CCR Title 20, Section 1623.1(a)(2).

3. Authorized the CEO to Execute Amendment No. 2 to the Standard Services Agreement with AIQUEOUS, LLC to Add$39,000 For a Total Not to Exceed Amount of $503,250 and No Additional Time.

4. Received Energy Programs Update

5. Received Treasurer Report

REGULAR AGENDA

1. Community Advisory Council Report
The Chair opened the public comment period.

No Public Comments Received.

The Chair closed public comment period.

ACTION: Discussion Item; no action required

2. CEO Report
a. Staffing Update
b. Front of the Meter Energy Storage Update
c. CAISO Interconnection Enhancements Initiative
d. Real-time Pricing Pilots
e. CARB Rule for Truck Fleets Approved
f. 9th Circuit Rules City of Berkeley Gas Ban Preempted by Energy Policy Conservation Act The Chair opened the public comment period.

No Public Comments Received.

The Chair closed public comment period.

ACTION: Discussion Item; no action required

3. Received an Update on a Prepay Financing Transaction and Recommends the Policy Board's Approval and Authorization of the CEO to Execute a Clean Energy Purchase Contract with California Community Choice Financing Authority and Ancillary Documents and Agreements to Affect the Prepay Financing Transaction.

The Chair opened the public comment period.

No Public Comments Received.

The Chair closed public comment period.

MOTION: Moved by Director Mendez, seconded by Vice Chair Goldstein to approve.

ACTION: The Motion Carried with a roll call vote: 12/1/4/1 AYES: Espinosa, Guertin, Harvey, Imhof, Mendez, Chapjian. Palacios, Pia, Reynolds, Wood, Vice Chair Goldstein, Chair Johnson
NOES: Stilwell
ABSENT: De La Rosa, Huffaker, Lewis, J., Lewis, T.

ABSTAIN: Murphy

4. Received an Update of the Fiscal Year 2022-23 Mid-Year Budget Re-forecast and Supports Seeking Policy Board Approval to Increase Appropriations.

The Chair opened the public comment period.

No public comments received.

The Chair closed public comment period.

MOTION: Moved by Director Stilwell, seconded by Director Imhof to approve.

ACTION: The Motion Carried with a roll call vote: 13/0/4/1 AYES: Espinosa, Guertin, Harvey, Imhof, Mendez, Chapjian, Palacios, Pia, Reynolds, Stilwell, Wood, Vice Chair Goldstein, Chair Johnson
NOES: None
ABSENT: De La Rosa, Huffaker, Lewis, J., Lewis, T.

ABSTAIN: Murphy
* Approve and Authorize the CEO to Execute a Resource Adequacy Confirmation for Capacity with Long Beach Generation LLC, with a Term of 7 Years in an Amount Not to Exceed $55,146,000, Inclusive of Any Associated Broker Fees, and in a Form Substantially Similar to Exhibit A
The Chair opened the public comment period.

No public comments received.

The Chair closed public comment period.

MOTION: Moved by Director Stilwell, seconded by Vice Chair Goldstein to approve.

ACTION: The Motion Carried with a roll call vote: 13/0/4/1 AYES: Espinosa, Guertin, Harvey, Imhof, Mendez, Chapjian, Palacios, Pia, Reynolds, Stilwell, Wood, Vice Chair Goldstein, Chair Johnson
NOES: None
ABSENT: De La Rosa, Huffaker, Lewis, J., Lewis, T.

ABSTAIN: Murphy

CLOSED SESSION
Council announced that no reportable action would be taken during closed session.

The Chair opened the public comment period on closed session items.

No Public Comments Received.

The Chair closed public comment period.

Recessed into closed session at 11:57am
Closed session under Government Code § 54956.9(1)(d) relating one item of existing litigation:

1. East Bay Community Energy et al. v. California Public Utilities Commission (A167425) Adjourned at 12:17pm
Staff Report Item 2
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
Prepared By: Jeremy Clark, Manager of Energy Trading
SUBJECT: Approve and authorize the CEO to execute a broker agreement to enable procurement of Resource Adequacy (RA) Products with a transaction fee not to exceed 1.0% of the notional value of the RA transaction ICAP Energy LLC Inc finds for 3CE DATE: August 9, 2023
RECOMMENDATION:

This recommends the Board approve and authorize the CEO to execute a Broker Agreement to enable procurement of Resource Adequacy Products (“RA”) with a transaction fee not to exceed 1.0% of the notional value of any RA transaction ICAP Energy LLC Inc facilitates for 3CE.

BACKGROUND:

ICAP Energy LLC provides third-party brokerage services to market participants nationwide. They leverage a deep network of industry relationships to provide anonymous bid/ask RA products to the market, while charging a nominal fee for the matching of an anonymous Seller with anonymous Buyer.

In recent years, the Resource Adequacy market has transitioned from a bilateral market to a brokered market. Since 2018, 3CE has been running competitive solicitations to buy RA or taking part in investor-owned-utility (“IOUs”) RA solicitations.

DISCUSSION/ANALYSIS:

Being enabled with multiple nationwide brokers enables 3CE to remain competitive in the RA market, where lack of transparency, revolving regulatory requirements, and increasing numbers of load serving entities have each pushed the market away from bilateral transactions and toward brokered transactions.

RA Sellers are participating less in CCA solicitations, as there are over 40 load serving entities seeking to buy RA and running solicitations. Over the past year, the active participation by RA Sellers has been dwindling dramatically and 3CE has been unable to receive adequate awards of RA from IOUs. This impacts our ability to procure sufficient RA to meet our compliance obligations. Entering into this enabling agreement with ICAP will increase liquidity by adding another tool for 3CE to be successful in its RA procurement efforts. Non-compliance of 3CE’s RA obligations will result in financial penalties and potentially non-financial adverse actions by the regulatory entity. Brokers have become the preference for RA Sellers because the suppliers only need to offer their excess RA to one party, who disperses the information to many RA Buyers. The RA Seller also remains anonymous to any potential Buyers until a deal has been agreed to.
3CE currently has authority to transact with two brokers, Tullet Prebon and Equus, and is seeking to get enabled with ICAP. Transacting with the use of Brokers has been limited in the past, given 3CE’s past preference to avoid having to pay a fee to a middleman. However, 3CE has recognized the need to do more transacting with Brokers, given our need to be RA compliant and the fact RA Seller are almost solely using Brokers now.

FISCAL IMPACT:

None. Individual confirmations would be subject to negotiation and execution pursuant to the terms of the approved Energy Risk Management Policy.

CONCLUSION:

Staff recommends the Operations Board approve and authorize the CEO to execute the Broker Agreement with ICAP Energy LLC to enable finding sufficient RA to be compliant. The transaction fee will not exceed 1.0% of the notional value of any RA transaction the Broker finds for 3CE. There are no specific transactions associated with this request.

ATTACHMENT(S):

1. ICAP Energy BSA

BROKERAGE SERVICES AGREEMENT

BETWEEN

ICAP ENERGY LLC
AND

CENTRAL COAST COMMUNITY ENERGY
BROKERAGE SERVICES AGREEMENT, made and entered into as of the 10th day of July, 2023, by and between ICAP Energy LLC, a Delaware corporation with its principal office at 200 Vesey Street, New York, NY 10281 (the “Broker”), and Central Coast Community Energy, a California Joint Powers Authority, with its principal place of business at 70 Garden Court, Suite 300, Monterey CA93940 (the “Customer”) (individually referred to as a “Party” and collectively referred to as the “Parties”).

WITNESSETH:

WHEREAS, Customer desires to engage the services of Broker to provide energy and/or other financial product brokering services; and
WHEREAS, Broker desires to provide such services to Customer.

NOW, THEREFORE, Customer and Broker, in consideration of the mutual covenants set forth herein, agree as follows:

1. SCOPE OF SERVICES

1.1 Services. During the term of this Agreement, and subject to the covenants and conditions herein set forth, Broker shall provide Resource Adequacy product brokering services (the “Services”) from time to time and as may be requested by Customer. When such services are requested by Customer, Customer shall advise Broker that it is seeking to purchase or sell a Resource Adequacy product (each such purchase or sale being referred to herein as a “Transaction”). Customer shall notify Broker of such terms and conditions of purchase and/or sale of the applicable product as Customer may determine, including but not limited to, terms and conditions relating to the type of product and the proposed purchase/sale price, quantity, source, term and delivery in respect of a Transaction. In response to Customer’s notification of a proposed Transaction, Broker shall use commercially reasonable efforts to locate a seller or purchaser of such Resource Adequacy product which is willing to perform in accordance with the terms and conditions set forth by Customer. In addition to responding to requests by Customer, Broker may also notify Customer of unsolicited offers for a Transaction. Customer in its sole discretion shall be free to reject any offer for a Transaction that Broker shall present. In the event of such rejection by Customer, Broker shall not be entitled to payment hereunder with respect to such offer for a Transaction. Except with respect to the payment to Broker of Fees under Paragraph 3.1 below or the payment of any amounts under Paragraph 4.4 below, Customer shall not be responsible for any of Broker’s internal operating costs associated with its efforts hereunder.

1.2 Transactions. Broker shall have no authority to bind Customer with respect to any Transaction. However, it is expressly contemplated by the Parties that Customer, during the course of dealing with Broker, may accept or reject offers hereunder in writing only, and that an offer for a Transaction, once accepted by Customer inwriting, will constitute a Transaction binding on Customer. Customer understands that its telephone conversations with Broker may be recorded. Transactions shall be subject to all applicable federal, state and local laws and regulations.

1.3 Non-Exclusive Engagement. The Parties acknowledge that this Agreement does not grant Broker exclusive rights to provide any brokerage services to Customer and that Broker is not guaranteed any minimum level of Fees (as defined in Paragraph 3.1below) under this Agreement. Further, Customer shall not be obligated to refer to Broker any inquiries for the sale or purchase of any product that it obtains directly, nor shall Broker be entitled to any compensation with respect to such inquiries.

1.4 Broker Acting as Limited Agent Only. The Parties acknowledge that Broker does not take title to any product and cannot guarantee delivery or the quality of any product which is the subject of a Transaction. It is further agreed, acknowledged and understood that Broker will be acting only as a limited agent with respect to any Transaction, not as principal, and, as such, shall have no beneficial interest in any Transaction, and, therefore, shall not receive any of the benefits, or be responsible for any of the obligations, of Customer or any other principal with respect to any Transaction brokered under this Agreement.

1.5 No Representations. Broker does not make, and shall not be deemed to make, any representations or warranties to Customer regarding (i) any counterparty to any Transaction or proposed Transaction hereunder, including without limitation, with respect to the reputation, financial stability, creditworthiness, ability to perform, experience, or any other qualification of any such counterparty, (ii) the suitability of any Transaction or proposed Transaction with respect to the needs and requirements of Customer, or (iii) the underlying product. In addition, the brokerage services to be performed by Broker do not include any legal or tax advice which Customer may desire or need in connection with any Transaction. Customer acknowledges that it is responsible for obtaining any legal or tax advice it deems appropriate.

2. TERM
This Agreement shall become effective when executed by both Parties and shall remain in full force and effect for a five year term set to expire July 31, 2028 or until terminated by either Party for any reason upon thirty (30) days’ advance written notice to the other Party; provided, however, that no such termination shall affect any existing Transaction(s) hereunder, unless otherwise agreed in writing by the Parties. Notwithstanding the above, the applicable provisions of this Agreement shall remain in effect after any such termination to the extent necessary to provide for final billing, billing adjustments and payments and to give effect to those provisions of this Agreement, if any, which explicitly survive termination.

3. SERVICE FEE

3.1 Fee. With respect to each Transaction accepted hereunder, Customer agrees to pay a fee to Broker (a “Fee”) as full compensation and consideration for the performance of the Services hereunder by Broker on behalf of Customer with respect to such Transaction. The Fee for any Transaction shall be agreed upon between the parties at the time such Transaction is executed.

In the absence of such agreement, the Fee shall be determined based on the applicable rate set forth in Schedule A hereof.
a. The Parties acknowledge that, to the extent agreed in writing by Broker (such agreement shall not be unreasonably withheld), Customer’s obligation to pay Broker’s Fee may be paid and satisfied by the counterparty of any Transaction.

3.2 Fee Earned. The Fee for any Transaction shall be deemed to be earned upon the acceptance by Customer of an offer for such Transaction. Accordingly, unless agreed upon in writing as set forth in Section 3.1(a), Customer shall be responsible for the payment of the entire Fee with respect to any Transaction with respect to which an offer has been accepted by Customer, including, without limitation, any Transaction that is (i) for any or no reason, not fully performed by the parties thereto or (ii) subsequently voided or rescinded.

3.3 Payment Not Through Broker. Payment for the product purchased or sold by Customer hereunder shall be made directly between the parties to the Transaction and shall not be made by, to or through Broker

3.4 Fee From Other Parties. It is acknowledged that Broker may be paid a fee from both parties (purchaser and seller) with respect to any Transaction. Customer acknowledges that the acceptance of a fee by Broker from both parties is customary practice in the industry and does not represent a conflict of interest or a breach of any duty owed or deemed to be owed by Broker to Customer.

4. TERMS OF PAYMENT AND INVOICING

4.1 Billing. The accounting period for Transactions hereunder shall be one (1) calendar month (the “Billing Period”). Broker shall invoice Customer, in writing and in U.S. dollars, promptly following the end of each Billing Period for Services occurring in the prior Billing Period. Customer shall make payment to Broker for the invoice by wire or electronic funds transfer upon its receipt of the invoice.

4.2 Customer’s Billing Address. Unless other billing procedures shall have been agreed to in writing by the Parties, all invoices to Customer shall be sent to: [email protected] and physically to 70 Garden Court, Suite 300, Monterey, CA 93940, Attention: AP, Power Supply.

4.3 Acceptance of Invoices. Invoice statements shall be deemed to be accepted by Customer if Broker has not received written objection by Customer within ten (10) days after Customer’s receipt thereof. In case any portion of any invoice is the subject of a bona fide dispute, the undisputed amount shall be payable when due as described in Section 4.1, and any disputed amount subsequently determined to be owed shall be paid promptly after such determination.

4.4 Late Fees; Suspension or Termination of Services. If Customer fails timely to pay the undisputed amount of Broker’s invoice or promptly to pay a disputed amount subsequently determined to be owed, Customer shall have five (5) days following receipt from Broker of written notice of such failure in which to make such payment, failing which Broker may, in its sole discretion, immediately suspend further performance under any Services until Customer makes such payment in full. If Customer fails to make such payment in full within 15 days following receipt of Broker’s notice of such failure, Broker may in its discretion terminate this Agreement and all Services. Customer shall remain liable for any earned Fees earned by Broker prior to such termination.

5. LIMITATION OF LIABILITY
Broker shall not be liable for any consequential, incidental, punitive, indirect or other special damages relating to the performance or nonperformance of this Agreement or any Transaction hereunder.

6. ENTIRE AGREEMENT
This Agreement constitutes the entire agreement between the Parties relating to the subject matter hereof and supersedes any other agreements, written or oral, between the Parties concerning such subject matter.

7. CHOICE OF LAW
The formation, validity, interpretation, execution, amendment and termination of this Agreement shall be governed by the laws of the State of California, without giving effect to principles of conflicts of law.

8. NON-WAIVER OF DEFAULTS
No waiver by either Party of any default of the other Party under this Agreement shall operate as a waiver of a future default, whether of a like or different character.

9. WRITTEN AMENDMENTS
No modification of the terms and provisions of this Agreement shall be or become effective except by written amendment executed by the Parties.

10. SEVERABILITY
Should any provision of this Agreement for any reason be declared invalid or unenforceable by final and non-appealable order of any court or regulatory body having jurisdiction, such decision shall not affect the validity of the remaining portions, and the remaining portions shall remain in full force and effect as if this Agreement had been executed without the invalid portion.

11. NON-DISCLOSURE AND PUBLICATION RESTRICTIONS
Any confidential or proprietary information, which is specifically and conspicuously marked as confidential (by stamp, legend or otherwise) before it is transmitted to the receiving party, or which is otherwise known by the receiving party to be a trade secret or confidential information, shall not be disclosed to a third party without (1) the prior written consent of the transmitting party, and (2) fulfilling such conditions as the transmitting party may prescribe, except as prescribed by law or legal process.

11.1 Notwithstanding any other provision herein, Broker and Customer acknowledge and agree that this Agreement and any proposed Transaction entered into in connection herewith are subject to the requirements of the California Public Records Act (Government Code Section 6250 et seq.). Upon request or demand of any third person or entity not a party hereto to Customer pursuant to the California Public Records Act for production, inspection and/or copying of confidential information (“Requested Confidential Information”):
a. Within two (2) business days of such request or demand, or sooner if practical, Customer shall notify Broker in writing via email that such request has been made.
b. Customer shall reasonably cooperate with Broker to evaluate the request or demand to determine whether any records or documents otherwise responsive to the third-party request are exempt under the California Public Records Act.

Customer has sole discretion in making the final determination regarding the scope of responsive information and the application of any exemptions, including the decision to withhold or redact otherwise responsive information in accordance with the California Public Records Act.
c. If Broker disagrees with Customer’s determination regarding the application of the California Public Records Act, including the scope of redactions necessary to protect exempt information from disclosure, Broker shall have the right to take, at its sole expense, whatever legal steps it determines are necessary to prevent release of the Requested Confidential Information to the third party by Customer. • If Broker takes or attempts to take such action, Customer shall provide timely and reasonable cooperation to Broker, if requested by Broker. • If Broker secures an order preventing Customer’s disclosure of requested confidential or proprietary information, Broker agrees to indemnify and defend Customer, officers, employees, and agents ("Customer Indemnified Parties"), from any claims, liability, award of attorneys' fees, or damages and to defend any action, claim or lawsuit arising from Customer’s compliance with such order.
• If Broker takes no such action after receiving notice from Customer, Customer shall, at its discretion, be permitted to comply with the third party's request or demand and is not required to defend against it Consistent with the California Public Records Act, Customer shall take commercially reasonable efforts to withhold or redact any information exempt from disclosure, including but not limited to trade secret information, market sensitive information, or other information protected under law.

12. NOTICES
All notices provided for or permitted hereunder shall be made in writing and by hand delivery, overnight courier, certified or registered mail (postage prepaid and return receipt requested), or by facsimile transmission:

If to Broker to:

ICAP Energy LLC
9931 Corporate Campus Drive
Suite 3000
Louisville, KY 40223
Attention: Operations
If to Customer to:

Central Coast Community Energy
70 Garden Court, Suite 300
Monterey, CA 93940
Attention: Robert M Shaw, COO and General Counsel
or to such other address or facsimile number as either party may specify in writing to the other.

All such notices shall be deemed to have been duly given, when delivered by hand, if personally delivered; the next day after being sent by overnight courier, if sent with guaranteed next day delivery; when received, if mailed; and when receipt is confirmed, if facsimile transmission is used.

13. ARBITRATION
Any dispute, controversy or claim between Broker and Customer based on, arising out of or relating to this Agreement shall be settled by final and binding arbitration in California, administered by the American Arbitration Association (“AAA”) and pursuant to the applicable rules thereof. Judgment upon any resulting arbitration award may be entered in any court of competent jurisdiction.

14. ASSIGNMENT
This Agreement shall be binding upon and inure to the benefit of the Parties and their respective permitted successors and assigns; but neither this Agreement nor any of the rights, benefits or obligations hereunder shall be assigned, by operation of law or otherwise, by an Party without the prior written consent of the other party; provided, however, that such consent shall not be unreasonably withheld.

15. COUNTERPARTS
This Agreement may be executed in one or more counterparts, each of which shall be deemed an original. It is the intention of each of the undersigned Parties that the other Party may rely on a PDF or facsimile copy of the signature of its duly authorized officer in proceeding in connection with the matters set forth herein and that upon the exchange of such PDF or facsimile signatures, electronically or otherwise, this Agreement shall be binding between the Parties, whether or not hard copies of this Agreement are ever exchanged between them.

16. NO RECOURSE AGAINST CUSTOMER’S MEMBER AGENCIES
Broker acknowledges and agrees that Customer is a Joint Powers Authority, which is a public agency sperate and distinct from its member agencies. All debts, liabilities, or obligations undertaken by Customer in connection with this Agreement are undertaken solely by Customer and are not the debts, liabilities, or obligations of its member agencies. Broker waives any recourse against Customer’s member agencies.

IN WITNESS WHEREOF, the Parties have caused their duly authorized representatives to enter into this Agreement as of the date first above written.

ICAP ENERGY LLC
By:

Name: Darren Hayes
Title: CEO Energy & Commodities, Americas

CENTRAL COAST COMMUNITY ENERGY
By:

Name:

Title:

SCHEDULE A
The commission rate is:

PRODUCT FEE
Resource Adequacy Products 1.0% of the Transaction Value Staff Report Item 3
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
Prepared By: Jeremy Clark, Manager of Energy Trading
SUBJECT: Approve and authorize the CEO to execute broker agreement to enable procurement of Resource Adequacy (RA) Products with a transaction fee not to exceed 1.0% of the notional of the RA transaction Karbone Inc finds for 3CE DATE: August 9, 2023
RECOMMENDATION:

This recommends the Board approve and authorize the CEO to execute a Broker Agreement to enable procurement of Resource Adequacy Products (“RA”) with a transaction fee not to exceed 1.0% of the notional value of any RA transaction Karbone Inc facilitates for 3CE.

BACKGROUND:

Karbone Inc provides third-party brokerage services to market participants nationwide. They leverage a deep network of industry relationships to provide anonymous bid/ask RA products to the market, while charging a nominal fee for the matching of an anonymous Seller with anonymous Buyer.

DISCUSSION/ANALYSIS:

Enabling with another nationwide RA broker enables 3CE to more efficient and cost effectively participate in the Resource Adequacy market which has transitioned from a bilateral market to a brokered market.

Since 2018, 3CE has been running competitive solicitations to buy RA or taking part in investor-owned-utilities (“IOUs”) RA solicitations. Over the past year, the active participation by RA sellers has been dwindling dramatically and 3CE has been unable to receive adequate awards of RA from IOUs. This impacts our ability to procure sufficient RA to meet our compliance obligations. Entering into this enabling agreement with Karbone will increase liquidity by adding another tool for 3CE to be successful in its RA procurement efforts. Non-compliance of 3CE’s RA obligations will result in financial penalties and potentially non-financial adverse actions by the regulatory entity.

RA Sellers are participating less in CCA solicitations, as there are over 40 load serving entities seeking to buy RA and running solicitations. Brokers have become the preference for RA Sellers because the suppliers only need to offer their excess RA to one party, who disperses the information to many RA Buyers. The RA Seller also remains anonymous to any potential Buyers until a deal has been agreed to.
3CE currently has authority to transact with two brokers, Tullet Prebon and Equus, and is seeking to get enabled with Karbone. Transacting with the use of Brokers has been limited in the past, given 3CE’s past preference to avoid having to pay a fee to a middleman. However, 3CE has recognized the need to do more transacting with Brokers, given our need to be RA compliant and the fact RA Seller are almost solely using Brokers now.

FISCAL IMPACT:

None. Individual agreements would be subject to negotiation and execution pursuant to the terms of the approved Energy Risk Management Policy.

CONCLUSION:

Staff recommends the Operations Board approve and authorize the CEO to execute the Broker Agreement with Karbone Inc to enable finding sufficient RA to be compliant. The transaction fee will not exceed 1.0% of the notional value of any RA transaction the Broker finds for 3CE.

There are no specific transactions associated with this request.

ATTACHMENTS:

1. Karbone BSA
©KARBONE 2014 1/5
Strictly confidential
July 14th, 2023

BROKERAGE AGREEMENT

CONFIDENTIAL
We are pleased to set forth in this letter of agreement (the “Agreement”) the terms of the engagement, of Karbone Inc., a Delaware corporation, or affiliates under common control of Karbone Inc. (collectively, “Karbone”), by Central Coast Community Energy, a California joint powers authority (the “Company”).

1. Scope of Engagement. Karbone is engaged by the Company to identify and introduce certain contacts (“Candidates”) that have interest to purchase or sell Resource Adequacy (“RA”) from related projects from time to time as requested by Company. When such services are requested by Company, Company shall advise Karbone that it is seeking to purchase or sell a Resource Adequacy product (each such purchase or sale being referred to herein as a “Transaction”). Company shall notify Karbone of such terms and conditions of purchase and/or sale of the applicable product as Company may determine, including but not limited to, terms and conditions relating to the type of product and the proposed purchase/sale price, quantity, source, term and delivery in respect of a Transaction. In response to Company’s notification of a proposed Transaction, Karbone shall use commercially reasonable efforts to locate a seller or purchaser of such Resource Adequacy product which is willing to perform in accordance with the terms and conditions set forth by Company. In addition to responding to requests by Company, Karbone may also notify Company of unsolicited offers for a Transaction. Company in its sole discretion shall be free to reject any offer for a Transaction that Karbone shall present. In the event of such rejection by Company, Karbone shall not be entitled to payment hereunder with respect to such offer for a Transaction. Except with respect to the payment to Karbone of Fees under Schedule A in accordance with Section 2 below, Company shall not be responsible for any of Karbone’s internal operating costs associated with its efforts hereunder.

2. Compensation; Billing; Payment. Karbone shall have no authority to bind Company with respect to any Transaction. However, it is expressly contemplated by the parties that Company, during the course of dealing with Karbone, may accept offers for a Transaction hereunder in writing only, and that an offer for a Transaction, once accepted by Company in writing, will constitute a Transaction that may be subject to a Brokerage Fee hereunder. The Company agrees to pay Karbone a fee (the “Brokerage Fee”) in the event of the successful completion and execution of a purchase and/or sale agreement for any Transaction introduced to the Company by Karbone and accepted by Company in writing. Schedule A outlines the Brokerage Fee payable to Karbone upon successful execution of financial close of such Transaction. The accounting period for Transactions hereunder shall be one (1) calendar month (the “Billing Period”). Karbone shall invoice Company, in writing and in U.S. dollars, promptly following the end of each Billing Period for Brokerage Fees incurred in the prior Billing Period.

Company shall make payment to Broker for the invoice by wire or electronic funds transfer upon its receipt of the invoice.

©KARBONE 2014 2/5

3. Indemnification. Karbone shall indemnify, defend and hold the Company and its directors, officers, employees, members, partners, agents, affiliates and controlling persons (each such person being a “Company Indemnified Party”) harmless from and against any and all losses, claims, damages and liabilities to which such Company Indemnified Party may become subject, under any applicable federal, state or foreign law or otherwise, related to or arising out of Karbone’s bad faith, gross negligence, willful misconduct or the breach of any representation, warranty or covenant contained herein by Karbone, and shall reimburse each Company Indemnified Party for all reasonable costs and expenses (including court costs and reasonable attorneys’ fees) incurred in connection with the investigation of, preparation for, or defense of any pending or threatened claim or any action or proceeding arising therefrom, whether or not such Company Indemnified Party is a party to such action or proceeding.

The Company shall indemnify, defend and hold Karbone and its directors, officers, employees, members, partners, agents, affiliates and controlling persons (each such person being a “Karbone Indemnified Party”) harmless from and against any and all losses, claims, damages and liabilities to which such Karbone Indemnified Party may become subject, under any applicable federal, state or foreign law or otherwise, related to or arising out of the Company’s bad faith, gross negligence, willful misconduct or the breach of any representation, warranty or covenant contained herein by the Company, and shall reimburse each Karbone Indemnified Party for all reasonable costs and expenses (including court costs and reasonable attorneys’ fees) incurred in connection with the investigation of, preparation for, or defense of any pending or threatened claim or any action or proceeding arising there from, whether or not such Karbone Indemnified Party is a party to such action or proceeding.

4. Terms and Termination. This Agreement shall commence on the date on which the Agreement is executed by both parties hereto and, unless earlier terminated by either party hereto, continue for twenty-four (24) months. The Company or Karbone may terminate this Agreement for any reason on thirty (30) days’ written notice to the other party or immediately for cause or following a material breach of any material representation, warranty or covenant of the other party contained in this Agreement.

5. Tail Period. It is expressly understood that the provisions in this Agreement relating to the payment of Brokerage Fees to Karbone will survive any termination of this Agreement by the Company or Karbone pursuant to Section 4 of this Agreement. Subject to the foregoing, the Company shall be obligated to pay Karbone a Brokerage Fee if, during the term of this Agreement, or until the sixth (6th) month anniversary of the termination of this Agreement, Company executes a purchase and/or sale agreement with a Candidate for any Transaction introduced to the Company by Karbone and that was accepted by Company in writing prior to the termination of this Agreement.

6. Representations, Warranties and Covenants of Karbone. Karbone represents, warrants and covenants to the Company as follows:

A. Karbone is duly organized, validly existing and in good standing under the laws of the State of Delaware and in each other jurisdiction in which the nature or conduct of its business requires such qualification.

B. This Agreement has been duly authorized, executed and delivered and constitutes a valid and binding agreement of Karbone, enforceable against Karbone in accordance with its terms. The execution and delivery of this Agreement, the incurrence of the obligations set forth

©KARBONE 2014 3/5
in this Agreement and the consummation of the transactions contemplated herein will not constitute a breach of, or default under, any instrument or agreement by which Karbone is bound or any order, rule or regulation applicable to Karbone of any court or any governmental body or administrative agency having jurisdiction over.

7. Representations, Warranties and Covenants of The Company. The Company represents, warrants and covenants to Karbone as follows:

A. The Company is duly organized, validly existing and in good standing under the laws of California and in each other jurisdiction in which the nature or conduct of its business requires such qualification.

B. This Agreement has been duly authorized, executed and delivered and constitutes a valid and binding agreement of the Company, enforceable against the Company in accordance with its terms. The execution and delivery of this Agreement, the incurrence of the obligations set forth in this Agreement and the consummation of the transactions contemplated herein will not constitute a breach of, or default under, any instrument or agreement by which the Company is bound or any order, rule or regulation applicable to the Company of any court or any governmental body or administrative agency having jurisdiction over.

8. Arbitration. Any claim or dispute arising out of this Agreement or the alleged breach thereof shall be submitted by the parties to binding and non-appealable arbitration to be administered by the American Arbitration Association in accordance with its commercial arbitration rules, to be held in the English language in California or such other location agreed to between the parties. Judgment on the award rendered by the arbitrator may be entered in any court having jurisdiction thereof. Both parties shall attempt to resolve any dispute by good faith negotiation or mediation before submitting to arbitration.

9. [Reserved].

10. No Recourse Against Customer’s Member Agencies. Karbone acknowledges and agrees that Customer is a Joint Powers Authority, which is a public agency sperate and distinct from its member agencies. All debts, liabilities, or obligations undertaken by Customer in connection with this Agreement are undertaken solely by Customer and are not the debts, liabilities, or obligations of its member agencies. Broker waives any recourse against Customer’s member agencies.

11. Miscellaneous.

A. Successors and Assigns. This Agreement shall be binding on and inure to the benefit of each party's successors and assigns, but may not be assigned without the prior written consent of the other party.

B. Governing Law. This Agreement shall be governed by and construed in accordance with the internal laws of the State of California, without regard to conflicts of laws or principles thereof.

C. Amendment. This Agreement may not be modified or amended except in writing signed by the parties hereto.

©KARBONE 2014 4/5
D. Independent Contractor. The parties agree that the services to be performed by Karbone under this Agreement shall be exclusively in the capacity of an independent contractor.

Unless otherwise expressly provided herein, neither the Company, on the one hand, nor Karbone, on the other hand, shall have authority to act for or represent the other in any way and shall not otherwise be deemed to be an agent of the other. Nothing contained herein shall create or constitute the Company, on the one hand, or Karbone, on the other hand, as members of any partnership, joint venture, association, syndicate, unincorporated business, other separate entity or any employer-employee relationship.

If the foregoing correctly sets forth your understanding and intentions, please so indicate by signing and returning to us a copy of this Agreement.

Sincerely,
By: _________________________________
Name: Jonathan C. Burnston
Company: Karbone Inc.

Title: Managing Partner
Date: July 14th 2023
Accepted and agreed to:

By: ________________________________
Name:

Company:

Title:

Date:

©KARBONE 2014 5/5
Schedule A - Brokerage Fees
Fees payable in cash at closing, which is defined as the signing of final purchase and/or sales agreements regarding the Transaction.

Karbone will use the following fee table to calculate its compensation:

Transaction Fees
Resource Adequacy 1.00% of total notional value of
transaction
Staff Report Item 4
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Jeremy Clark, Manager of Energy Trading
SUBJECT: Receive update on recent amendment to the Energy Risk Management Policy approved by the Risk Management Committee in July 2023
DATE: August 9, 2023
RECOMMENDATION:

Update 3CE’s Operations Board on recent amendment to the Energy Risk Management (ERM) Policy and Approved by the Risk Management Committee (RMC) in July 2023.

BACKGROUND:

The ERM Policy establishes 3CE’s risk management functions and procedures to identify, quantify, and manage the risks associated with power procurement activities. The ERM Policy establishes management responsibilities, organizational structures, risk management standards, and operating controls and limits necessary to properly identify and manage 3CE’s risk to support meeting its procurement goals.

The ERM Policy was first approved in March 2018, revised in September 2018, November 2020, and June 2022.

DISCUSSION/ANALYSIS:

As part of 3CE’s regular review of the ERM Policy and its recently adopted policy of ensuring Resource Adequacy (RA) compliance by procuring longer-term RA transactions to enable cost certainty, some changes have been identified.

Section 1.4 of the ERM Policy permits amendments to appendixes by a vote of the RMC and later notice to the Operations Board.

At its July 27, 2023, meeting, the RMC approved amendments to Appendix A (adding an additional transaction type) and Appendix D (minor change to duration Limits in Delegation Financial Authority).

The first change in Appendix A adds Broker Fees as an approved transaction type. Broker Fees are commissions paid to an entity that matches an anonymous Buyer and anonymous Seller. The Broker earns a fee when an actual match occurs, and a transaction is entered.

While 3CE has used Brokers sparingly in the past, there has been a major shift in how the RA market is functioning. The majority of RA Sellers are only offering their available RA supply through Brokers. In the past, RA Sellers would respond to RA Buyers who have issued solicitations. Given the large number of RA Buyers, RA Sellers has transitioned to using Brokers for the ease of transacting, and anonymity it gives them. 3CE does learn the identity of the RA Sellers, when we commit to entering into a deal. However, using Brokers requires you to be able to commit to entering into a transaction very quickly.

The second change is to the Delegation of Financial Authority matrix in Appendix D as follows:

The current matrix limits the CEO’s ability to transact deals with Term Limits longer than 36 months (3 years). The current RA market is actively trading from next month through 2030. To secure the necessary RA volumes, the RMC approved increasing the Term Limit of the CEO to 60 months (5 years) to be more successful at becoming RA compliant in a fast-paced environment.

Furthermore, the current matrix limits the CEO’s & RMC’s ability to transact any deals with Maturity Limits longer than 48 months & 72 months, respectively. Maturity relates to the date you enter into a transaction and the start of the Delivery Term. E.g., A transaction with a Delivery Term of January 2026 through December 2030 would have a Term of 5 years (60 Months) and a Maturity of 7.5 years (90 Months), if executed in July 2023. The RMC approved increasing this threshold to 96 months (8 years) to better align with the market and allow the CEO or the RMC to enter into longer term agreements, with delivery term start dates farther out in the future.

Given the scarcity of RA and speed with which offers from Brokers to sell RA are no longer available, the CEO and RMC need these expanded Term and Maturity Limits to secure RA compliance at cost-effective prices.

There is no change to the Value Limits of any individual transaction, sourced from a solicitation or via a Broker, and each transaction will still be subject to terms within the Energy Risk Management Policy.

FISCAL IMPACT:

None.

CONCLUSION:

This is an information only item. The updated, RMC-approved, ERM Policy has been attached to this report.

ATTACHMENT(S):

1. Revised ERM Policy
1 Energy Risk
Management Policy
Initial Version March 2018 –Policy Board of Directors Approved First Revision September 2018 –Operations Board of Directors Approved Second Revision November 2020 –Operations Board of Directors Approved Third Revision August 2022 – Operations Board of Directors Approved 2 Table of Contents
Table of Contents
SECTION 1: POLICY OVERVIEW.................................................................................................................4 1:1 Background and Purpose ...............................................................................................................4

1.2 Scope.............................................................................................................................................5

1.3 Energy Risk Management Objective...............................................................................................5

1.4 Policy Administration.....................................................................................................................5 SECTION 2: STRATEGY/GOALS AND RISK EXPOSURES...............................................................................6

2.1 Policy Goals ...................................................................................................................................6

2.2 Risk Catalog ...................................................................................................................................7

2.2.1 Attrition: Customer Opt-Out Risk ............................................................................................7

2.2.2 Market Risk.............................................................................................................................7

2.2.3 Liquidity Risk ...........................................................................................................................7

2.2.4 Regulatory Risk .......................................................................................................................8

2.2.5 Volumetric Risk .......................................................................................................................8

2.2.6 Model Risk ..............................................................................................................................8

2.2.7 Operational Risk......................................................................................................................8

2.2.8 Counterparty & Generalized Credit Risk ..................................................................................8 SECTION 3: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIESSECTION............................................9

3.1 Risk Management Organizational Structure ...................................................................................9

3.2 Risk Management Committee (RMC) .............................................................................................9

3.3 Segregation of Duties................................................................................................................... 10

3.3.1 Front Office........................................................................................................................... 10

3.3.2 Middle Office ........................................................................................................................ 11

3.3.3 Back Office............................................................................................................................ 11 SECTION 4: BUSINESS PRACTICES........................................................................................................... 12

4.1 General Conduct.......................................................................................................................... 12

4.2 Hedging & Trading Activities; Prohibition on Speculation ............................................................. 12

4.3 Trading for Personal Accounts...................................................................................................... 12

4.4 Conflict of Interest....................................................................................................................... 12

4.5 Adherence to Statutory Requirements......................................................................................... 13 3 4.6 Authorized Products, Markets & Terms........................................................................................ 13

4.7 System of Record......................................................................................................................... 14

4.8 Transaction Valuation .................................................................................................................. 14

4.9 Policy Compliance........................................................................................................................ 14 SECTION 5: TOLERANCES ....................................................................................................................... 15

5.1 Hedging Tolerances.................................................................................................................... 15

5.1.1 Energy Procurement Tolerances............................................................................................ 15

5.1.2 Renewable Energy Procurement Tolerances.......................................................................... 15

5.1.3 Capacity Procurement Tolerances ....................................................................................... 15

5.2 Monitoring, Reporting and Instances of Exceeding Risk Limits...................................................... 16 SECTION 6: CREDIT POLICY .................................................................................................................... 17 SECTION 7: POSITION TRACKING AND MANAGEMENT REPORTING........................................................ 18 SECTION 8: POLICY REVISION PROCESS.................................................................................................. 19

8.1 Acknowledgement of Policy......................................................................................................... 19

8.2 Policy Interpretations................................................................................................................... 19 Appendix A: AUTHORIZED TRANSACTION TYPES, REGIONS, AND MARKETS ........................................... 20 Appendix B: NEW TRANSACTION APPROVAL FORM............................................................................... 21 Appendix C: DEFINITIONS ...................................................................................................................... 22 Appendix D: DELEGATION OF FINANCIAL AUTHORITY............................................................................ 24 4 SECTION 1: POLICY OVERVIEW
1:1 Background and Purpose
Central Coast Community Energy (“CCCE”), formerly Monterey Bay Community Power Authority, is a public joint powers agency located within the geographic boundaries of Monterey, Santa Cruz San Benito, San Luis Obispo, and Santa Barbara Counties. Member agencies of CCCE include the Counties of Monterey, Santa Cruz, San Benito, and Santa Barbara, as well as certain incorporated cities located within the member counties and San Luis Obispo County. Presently, CCCE’s CCA Members include the following local government entities:

County of
Santa Cruz
County of
Monterey
County of
San
Benito
City of
San Luis
Obispo
County of
Santa
Barbara
City of
Santa Cruz
City of
Salinas
City
Hollister
Morro
Bay
Santa Maria
City of
Watsonville
City of
Monterey
City of
San Juan
Bautista
Paso
Robles
Solvang
City of
Capitola
City of
Pacific
Grove
Pismo Beach Goleta
City of
Scotts
Valley
City of
Carmel
Grover Beach Carpinteria
City of
Seaside
Arroyo Grande Guadalupe
City of
Marina
Buellton
Sand City
Soledad
Greenfield
Gonzales
Del Rey
Oaks
5 CCCE members elected to implement and administer a community choice aggregation (“CCA”) program. The CCA program will give its members an opportunity to procure electricity supplies and implement local programs that meet the goals of the local communities. Electricity procured to serve customers will continue to be delivered over the Investor-Owned Utilities’ (PG&E & SCE) transmission and distribution systems.

Providing retail electric generation service to customers enrolled in the CCA program exposes CCCE to risks such as customer opt-out risk, market risk, regulatory risk, volumetric risk, model risk, operational risk, counterparty credit risk and reputation risk.

This Energy Risk Management Policy (“Policy”) establishes CCCE’s Energy Risk Management Program (“Program”) including risk management functions and procedures to manage the risks associated with power procurement activities.

The ultimate purpose of this Policy is to help CCCE manage its risks by specifying management responsibilities, organizational structures, risk management standards, and operating controls and limits necessary to properly identify and manage CCCE’s exposure to risk.

1.2 Scope
Unless otherwise explicitly stated in this Policy, or other policies approved by the Board, this Policy applies to all power procurement and related business activities that may impact the risk profile of CCCE. This Policy documents the framework by which management and staff will:
 Identify and quantify risk
 Develop and execute procurementstrategies
 Create a framework of controls and oversight
 Monitor, measure, and report on the effectiveness of the Program

1.3 Energy Risk Management Objective
The objective of the Energy Risk Management Policy is to provide a framework for conducting procurement activities that will manage risks to support CCCE meeting the goals.

Pursuant to this Policy, CCCE will identify and measure the magnitude of the risks and take the necessary steps to manage and reduce that risk to acceptable levels.

1.4 Policy Administration
This Policy document shall be routinely reviewed and approved by the CCCE Operations Board of Directors (“Board”). The Risk Management Committee (“RMC”) and Operations Board must approve amendments to this Policy, except for the appendices, which may be amended with approval of only the RMC. The RMC must give notice to the Board of any amendment it makes to an appendix or a reference policy or procedure document.
6 SECTION 2: STRATEGY/GOALS AND RISK EXPOSURES

2.1 Policy Goals
CCCE operates in a dynamic, volatile environment and market. Prices for energy and its underlying drivers, such as natural gas, are susceptible to unpredictable and sometimes significant changes in short intervals. Regulatory and legislative changes can structurally change markets, market price levels, and procurement requirements. Low liquidity and financial dislocations may lead to counterparty distress. CCCE’s Energy Risk Management Policy (ERM) is designed to address these challenges. Its overarching goals are the following:
 Preserving the financial health and stability of CCCE  Providing rate stability
 Ensuring the long-term viability of CCCE
In furtherance of these goals CCCE strives to:
 Maintain a credit rating of A- or equivalent, as defined by S&P Global Ratings or an equivalent ratings agency
 Limit power supply cost variance to the annual budget to 10%, barring extraordinary circumstances
 Fund its Rate Stabilization Fund at levels that buffer customers from rate shock and maintain a 3-year rate trajectory which is competitive with Investor-Owned Utilities (IOUs) The ERM Policy is a strategic document, not a prescriptive manual. The metrics, limits, and products used to measure and manage risk must continuously evolve to reflect industry best practices and ensure relevance and alignment with the policy’s goals. CCCE is responsible for designing and executing specific plans, metrics, limits, hedging plans, and processes in accordance with the ERM Policy CCCE will report regularly to the Risk Management Committee (RMC).

CCCE aims to achieve these goals by managing the key risks identified in the Risk Catalog at section 2.2 below. More specifically, the goals will be incorporated into the specific limits and metrics used to govern hedging activities and long-term procurement. It is important to note these goals are not intended to be a comprehensive list of CCCE’s goals.

To ensure CCCE is implementing best practices for an energy supplier of its size and scope, CCCE will engage an outside third-party energy risk management expert to conduct an annual audit and benchmark CCCE’s risk policy and internal processes. The results of audit will be presented to the RMC. 7 2.2 Risk Catalog
This Energy Risk Management Policy addresses the following key risks:
a) Attrition: Customer Opt-Out risk
b) Market risk
c) Liquidity Risk
d) Regulatory risk
e) Volumetric risk
f) Model risk
g) Operational risk
h) Counterparty & Generalized Credit risk

2.2.1 Attrition: Customer Opt-Out Risk
Customer opt-out risk includes any condition or event that creates the potential for significant reductions in the CCA’s customer base, leading to the potential on higher retail rates, uncompetitive position, and further loss of customer base. Customer opt-out risk remains a primary risk for the CCA industry. Managing Opt-out risk requires the establishment of, and adherence to, certain metrics to limit optout risks, such as:
 Retail rate competitiveness
 Rate Stability Reserves Fund

2.2.2 Market Risk
Market (Energy Price) volatility risk of losses due to the movements in power market prices, interest rates, and credit market prices. Power market price risk includes the risk of adverse price movements in energy, capacity, power basis, renewable attributes, and underlying drivers such as natural gas market prices. Interest rate and credit market price risks are considered when evaluating financing structures associated with long-term hedges or contracts. CCCE will deploy a range of metrics to measure market risk, such as forward-looking stress tests based on multiple factors and Value-at-Risk (VaR) over multiple time periods. Limits – such as those on position size, tenor, product type and VaR - will be set based on market conditions and alignment with this policy’s goals.

2.2.3 Liquidity Risk
Liquidity Risk is the risk of a lack of enough creditworthy buyers and sellers in a market to execute transactions at prices which reasonably reflect underlying fundamentals. This risk can make it difficult for CCCE to execute hedging transactions, such as exits, that reduce risk and maximize value. CCCE will monitor liquidity in markets and, where applicable, set limits on product types, tenor, and position size to reduce the risk of stranded positions. 8 2.2.4 Regulatory Risk
Legislative and regulatory policy decisions, including technical market rule changes can have far-reaching impacts on prices, procurement requirements, asset values, and cash flows. CCCE will actively monitor and, where possible, shape legislative and regulatory policy to mitigate risk. CCCE will also quantify and forecast the financial impacts of proposed regulatory actions through scenario analysis. CCCE will mitigate potential regulatory risk by structuring procurement strategies and contracting practices to minimize potential policy change related impacts.

2.2.5 Volumetric Risk
Volumetric risk is the risk of variance in the expected quantity of load served by CCCE. Volumetric risk may be driven by factors such as attrition, weather, and behind-the-meter generation.

Attrition risk is explicitly modeled under this policy. Weather is the biggest short-term driver of volumetric risk. CCCE will develop load distributions that account for a wide range of weather outcomes and size positions accordingly. CCCE may set limits on open positions by tenor, as appropriate, to reduce volumetric risk.

2.2.6 Model Risk
Model risk is variance from modeled or forecasted outcomes due to fundamental deficiencies in models and/or information systems. CCCE will validate models on an ongoing basis for robustness, update and/or patch models frequently, collaborate regularly with vendors, and exchange information & best practices with peers bilaterally or in trainings and conferences.

2.2.7 Operational Risk
Operational risk is variance in financial performance due to weaknesses or failures in the quality, scope, content, and/or execution of hedging, procurement, and risk management functions.

Operational risk also incorporates fraudulent actions by employees or third parties, particularly due to inadequate or ineffective controls. CCCE manages operational risk through a variety of methods, including regular reporting, segregation of functions, layered oversight, external audits, and staff training. Additional methods will be proposed to the RMC as appropriate.

2.2.8 Counterparty & Generalized Credit Risk
Counterparty risk is the risk that a counterparty will fail to perform or adequately remedy its obligations in accordance with contractual and transactional terms. Generalized credit risk is the risk of a generalized reduction in credit to a sector, a set of counterparties, or a specific counterparty that results in an increase in counterparty risk. The impact of counterparty failure on CCCE’s financials can be significant. CCCE will monitor counterparty risk based on a variety of metrics and analyses, including but not limited to an in-depth review of counterparty financials, exposure by credit rating, exposure by tenor and product type. 9 SECTION 3: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIESSECTION

3.1 Risk Management Organizational Structure
CCCE risk management is organizationally structured to ensure effective segregation of duties and multiple layers of oversight using a waterfall approach. Risk approval limits are contained in Exhibit D, the Risk Management Delegation of Financial Authority (DOFA).

The CCCE Operations Board of Directors (“Operations Board”) is responsible for approving the energy risk management policy. It reviews and approves this policy and approves risk exposures above those delegated to the RMC in the DOFA.

The Risk Management Committee (RMC) is responsible for overseeing strategic compliance with this policy and approving risk exposures above those delegated to the CEO.

The Front Office is responsible for energy short-term trading function and long-term negotiations of power supply contracts, mindful of the ERMP limits.

The Middle Office is responsible ensuring compliance with the policy and monthly reporting of risk exposure to RMC. This segregates the monitoring from trading functions ensure adherence to risk limits and provides an important check and balance.

The Back Office is responsible for processing payments ensuring adherence to contract terms and provide appropriate reporting regulatory agencies.

3.2 Risk Management Committee (RMC)
The CEO shall establish the RMC, set the agenda, and serve as its Chair. The RMC consists of the following voting members:
 Chief Executive Officer (CEO)
 Up to five (5) Members of CCCE’s Policy and/or Operations Board of Directors, selected by the CEO
 Chief Financial Officer
 Chief Operating Officer
 Director of Regulatory and Legislative Affairs
The RMC is responsible for overseeing strategic compliance with this policy and approving major risk exposures above those delegated to the CEO. This includes ensuring procurements and hedging are consistent with CCCE’s strategic goals.

Specifically, the RMC maintains the authority and responsibility to:
 Ensure that procurements are consistent with this policy and hedging plans based on CCCE’s 10 financial objectives and situation.
 Approve procurements and risk exposures above those delegated to the CEO and up to the limits specified in the DOFA, based on the strategic goals of this ERM Policy and CCCE’s financial situation
 Understand and approve the limits, metrics, and product types necessary to ensure compliance with this policy
 Review risk management reports as described in this Policy.  Review actual and projected risks and financial outcomes and review summaries of violations of this policy
 Refer to the Operations Board those exposures and risks above those delegated to the RMC in the DOFA

3.3 Segregation of Duties
CCCE shall maintain a segregation of duties, also referred to as "separation of function” to help manage and control the risks outlined in this Policy.

3.3.1 Front Office
The Front Office is responsible for the procurement and hedging activities necessary to manage CCCE’s wholesale power market positions and obligations. Specific responsibilities include:
 Develop long-term procurement strategies to reliably meet CCCE’s load-serving obligation using a least-cost best-fit approach
 Develop annual, quarterly, and monthly hedge plans to prudently meet CCCE’s load-serving obligation using a mix of market transactions and CCCE power assets, such as dispatchable generation
 Optimize CCCE’s load-supply balance and asset management strategies to prudently maximize value for CCCE customers while adhering to all risk management processes and limits
 Develop and use fundamental and probabilistic analysis – such as power market supply-demand balances and transmission outages – to guide optimization, procurement, and hedging decisions
 Accurately record all transactions in the system of record  Accurately track open positions and hedge performance across tenors  Execute transactions and negotiate or amend contracts as needed to meet the above goals in accordance with the limits set out in the DOFA. Restructure previously approved transactions and contracts as needed in accordance with the DOFA limitations 11 3.3.2 Middle Office
The Middle Office is responsible for implementing, administering, and monitoring compliance with this policy. Specific responsibilities include:
 Developing market and transaction analytics that inform risk analyses of CCCE’s hedging and procurement activities; providing Front Office with an independent view as needed  Developing metrics and risk management processes for the risks identified in the Risk Catalog in this policy
 Designing and setting hedging and procurement limits, including but not limited to product types, tenors, delivery points, counterparties, and markets.  Monitoring risk exposures and policy compliance on an ongoing basis, with monthly reporting to the RMC
 Developing limits with exchanges, brokers, and trading venues  Analyzing risk of the hedging and procurement plans developed by the Front Office.  Developing and maintaining demand forecasts
 Independently maintaining forward price curves for use in valuation, pricing, and monitoring. Developing internal estimates of forward prices where credible liquid data is not available
 Valuing CCCE positions and contracts
 Validating settlements
 Reporting limit violations to the CEO and the RMC
 Calculating and maintaining the net forward power positions of CCCE  Assist Back Office in calculating Counterparty Credit Exposure

3.3.3 Back Office
The Back Office is responsible for the administrative activities necessary to execute and settle transactions and contracts and to support the Middle Office where necessary to monitor compliance with this Policy.

Specific responsibilities include:
 Confirming all transaction details (physical and financial) and reconciling differences with the trading counterparties
 Reviewing transaction confirmations for adherence to approved limits  Validating trade entry and flow through the system of record  Validating and reconciling physical and financial transaction flows  Settling trades and calculating revenues and profit & loss  Providing settlement, credit, and other data as needed to the Middle Office and Finance to support monitoring of risk exposures and budget processes 12 SECTION 4: BUSINESS PRACTICES

4.1 General Conduct
All personnel, including Members of the Operational and Policy Board of Directors, staff, and agents, adhere to standards of integrity, ethics, conflicts of interest, compliance with statutory law and regulations and with applicable CCCE standards of personal conduct while employed by, contracted by, or affiliated with CCCE.

4.2 Hedging & Trading Activities; Prohibition on Speculation CCCE contracts and trades in energy markets to hedge positions, reduce risk, and, in compliance with this policy, prudently optimize the value of its portfolio of assets and market positions. Speculative trading is explicitly prohibited under this policy. Examples of speculative trading include trading a commodity where CCCE does not have an underlying position or risk, trading a product based solely on personal judgement about market direction, taking positions in volumes that deviate significantly from CCCE’s underlying need etc. Should a question arise about speculative trading activities, CCCE’s Middle Office will make an initial finding based on an analysis of the situation and present a written report to the CEO and the RMC. The RMC will make a final determination based on the situation.

4.3 Trading for Personal Accounts
All CCCE staff and agents are prohibited from trading the power and environmental products traded by CCCE.

4.4 Conflict of Interest
CCCE staff are expected to meet the highest standards for ethical conduct, beyond just the specific matters discussed in this section.

CCCE staff responsible for negotiating, reviewing, and/or approving hedging activities and procurements are obligated to provide written notice to CCCE of any real or potential conflict of interest in the matter.

An example of such a conflict of interest may be negotiating with a counterparty while seeking employment for oneself or a relative with that counterparty.

CCCE staff are prohibited from trading on information gained during hedging and procurement activities. An example of such an activity would be a CCCE employee directly or indirectly purchasing stock in a developer prior to the announcement of CCCE awarding that developer a significant contract.

Purchases of pooled vehicles such as broadly diversified mutual funds and ETFs are exempted from this policy.

CCCE Front Office staff are expected to seek best execution and least-cost best-fit from counterparties and intermediaries. Steering trades and contracts to counterparties based on potential financial gain or personal relationships is prohibited.

Additionally, Conflicts of Interest shall be identified and defined as set forth in the CCCE Conflict of Interest Code, as amended from time to time by the Policy Board, which incorporates the Political Reform Act requirements for all employees advising CCCE. 13 If there is any doubt as to whether a prohibited condition exists, then it is the employee’s responsibility to discuss the possible prohibited condition with her/his manager or supervisor. Employees may seek an advisory position from the California Fair Political Practices Commission.

4.5 Adherence to Statutory Requirements
Compliance is required with rules promulgated by the state of California, California Public Utilities Commission, California Energy Commission, Federal Energy Regulatory Commission (FERC), Commodity Futures Trading Commission (CFTC), and other regulatory agencies.

Congress, FERC, and CFTC have enacted laws, regulations and rules that prohibit, among other things, any action or course of conduct that actually or potentially operates as a fraud or deceit upon any person in connection with the purchase or sale of electric energy or transmission services. These laws also prohibit any person or entity from making any untrue statement of fact or omitting to state a material fact where the omission would make a statement misleading. Violation of these laws can lead to both civil and criminal actions against the individual involved, as well as CCCE. This Policy is intended to comply with these laws, regulations, and rules and to avoid improper conduct on the part of anyone employed by CCCE. These procedures may be modified from time to time by legal requirements, auditor recommendations, RMC requests and other considerations.

In the event of an investigation or inquiry by a regulatory agency, CCCE may provide legal counsel to employees. However, CCCE, with the consent of the Operations Board, will not appoint legal counsel to an employee if CCCE determine that representation of the employee will create an actual conflict between the employee and CCCE, or that the employee was not acting in good faith within the scope of employment.

4.6 Authorized Products, Markets & Terms
Transactions are conducted bilaterally, using standard contracts such as the EEI or WSPP, or through exchanges such as the InterContinental Exchange (ICE). CCCE CEO or their designee must authorize all transactions.

New products, tenors, markets, delivery points, and transaction types can be authorized by the RMC.

When seeking such approval, a New Product Approval Form, as shown in Appendix C, should be drafted describing all significant elements of the proposed product. This should include, at a minimum:
 A description of the benefit to CCCE, such as decreasing costs, managing volatility etc  The role of the new product in CCCE’s overall portfolio and risk management strategies  Risk analysis that identifies the specific risks mitigated by the new product and illustrates its application
 Transaction process, initial risk limits and settlement process  Proposed valuation methodology (including pricing model, where appropriate)  Proposed accounting methodology
14 CCCE’s CEO or their designee is responsible for requesting the RMC’s approval. If approved, Appendix A to the Policy will be updated to reflect the new transaction type.

4.7 System of Record
CCCE will maintain a set of records for all transactions executed in association with CCCE procurement activities. The records will be maintained in US dollars and transactions will be separately recorded and categorized by type of transaction. This system of record shall be auditable

4.8 Transaction Valuation
Transaction valuation and reporting of positions shall be based on objective, market-observed prices.

Whenever possible, mark-to-market valuations should be based on independent, publicly available market information and data sources. The Middle Office will be responsible for independently validating and reporting marks, valuations, and settlements.

4.9 Policy Compliance
The Middle Office will provide a monthly report monitoring compliance with the limits established by this Policy.
15 SECTION 5: TOLERANCES

5.1 Hedging Tolerances
Hedging tolerances for Energy, renewable attributes, and capacity (Resource Adequacy) are shown below. From time to time, the middle office, in response to market conditions, may recommend adjustments to these ranges.

5.1.1 Energy Procurement Tolerances
Period Minimum Tolerance Maximum Tolerance Target
Year 1 (Current Year) 90% of Load 110% of Demand 100% of Demand Year 2 70% of Load 110% of Demand 85% of Demand
Year 3 50% of Load 90% of Demand 70% of Demand
Year 4 30% of Load 60% of Demand 50% of Demand
Year 5 20% of Load 50% of Demand 30% of Demand

5.1.2 Renewable Energy Procurement Tolerances
Period Minimum Tolerance Maximum Tolerance Target
Year 1 (Current Year) 90% of mandate 100% of demand 100% of mandate Year 2 70% of mandate 100% of demand 85% of mandate
Year 3 50% of mandate 90% of demand 70% of mandate
Year 4 50% of mandate 75% of CCCE demand 65% of mandate Year 5
50% of CCCE RPS Procurement
Strategy 75% of demand 65% of mandate

5.1.3 Capacity Procurement Tolerances
Period Minimum Tolerance Maximum Tolerance Target
Prompt Month 100% of required 100% of required 100% of required Prompt Quarter 90% of required 100% of required 100% of required Year 1 (Current Year) 90% of required 100% of required 100% of required Year 2 80% of required 100% of required 90% of required Year 3 50% of required 100% of required 70% of required Year 4 20% of required 70% of required 50% of required
Year 5 0% of required 50% of required 40% of required
16 5.2 Monitoring, Reporting and Instances of Exceeding Risk Limits The Middle Office is responsible for monitoring, and reporting compliance with, all limits within this Policy. If a limit or control is violated, the Middle Office will notify the CEO and the RMC. The RMC will discuss the cause and potential remediation of the exceedance to determine next steps for curing the exceedance.
17 SECTION 6: CREDIT POLICY
Counterparty and generalized credit risk are significant risks to CCCE’s financial operations. The Middle Office will conduct a thorough analysis of all candidate counterparties prior to approving them to transact. This analysis will include but not be limited to analyzing the proposed counterparty’s financial statements, credit rating, liquidity, hedge levels, market sensitivity, and business operations. The Middle Office will determine whether to extend an unsecured or secured credit line to the candidate counterparty, as appropriate. The maximum unsecured credit line that can be extended to any counterparty is $50 Million.

In addition to individual counterparty limits, the Middle Office will set limits by credit rating, tenor, product, and, where appropriate, transaction type and delivery type. For example, it may set an overall limit of $50 million for counterparties rated BB+ that supersedes the BB+ counterparties’ individual credit approvals of $100 million. This will limit concentration of credit risk.

Counterparty credit health and generalized credit conditions will be monitored on an ongoing basis.

Individual counterparty limits or aggregate credit limits by tenor/product/credit rating may be adjusted up or down to reflect current conditions. Counterparties who exceed limits must promptly post enough collateral to come into compliance or have their positions liquidated. 18 SECTION 7: POSITION TRACKING AND MANAGEMENT REPORTING Minimum reporting requirements are shown below. The reports outlined below will be made available to RMC members:
 Monthly Financial Model Forecast
Latest projected financial performance, marked to current market prices, and shown relative to financial goals
 Monthly Net Position Report
Prepare a forward net position report and report the results to the RMC  Monthly Counterparty Credit Exposure
This report will show credit exposures for transactions executed by CCCE  Monthly Risk Analysis
This will include a stress test of financial forecast relative to financial goals 19 SECTION 8: POLICY REVISION PROCESS
CCC’s Energy Risk Management Policy will evolve over time as market and business factors change. At least on an annual basis, the RMC will review this Policy and associated procedures to determine if they should be amended, supplemented, or updated to account for changing business and/or regulatory requirements. If an amendment is warranted, the Policy amendment will be submitted to the CCCE Board for approval. Changes to appendices to this Policy may be approved by the RMC.

8.1 Acknowledgement of Policy
Any CCCE employee participating in any activity or transaction within the scope of this Policy shall sign on an annual basis or upon any revision, a statement approved by the RMC that such employee:
 Read CCCE’s Energy Risk Management Policy
 Understands the terms of said Policy
 Will comply with said Policy
 Understands that any violation of said Policy shall be subject to employee discipline up to and including termination of employment.

8.2 Policy Interpretations
Questions about the interpretation of any matters of this Policy should be referred to the CEO. All legal matters stemming from this Policy will be referred to General Counsel. 20 Appendix A: AUTHORIZED TRANSACTION TYPES, REGIONS, AND MARKETS All transaction typeslisted belowmust be executed within the limitsset forth in this Policy. (The following transaction types can be ‘nonstandard’ at CCCE subject to RMC approval) Over the Counter Products
 CAISO Market Products
o Day-ahead and Real-time Energy
o Congestion Revenue Rights
o Convergence bids
o Inter Scheduling Coordinator Transactions
o Tagging into and out of CAISO
 Physical Power Products
o Power
o Physical Over-the-counter Options
o Physical Resource Adequacy Capacity
 Physical Transmission Products
o Physical WECC transmission
 Physical Environmental Products
o Renewable Energy Credits
o Specified Source Power
o Carbon Allowances and Obligations
 Financial Power Products
o Power
o Financial Over-the-counter Options
o Broker Fees
21 Appendix B: NEW TRANSACTION APPROVAL FORM
New or Non-Standard Transaction Approval Form
Prepared By: Date:

New or Non-Standard Transaction Name:

Business Rationale and Risk Assessment:
 A description of the benefit to CCCE, such as decreasing costs, managing volatility etc.  The role of the new product in CCCE’s overall portfolio and risk management strategies  Middle Office risk analysis that identifies the specific risks mitigated by the new product and illustrates its application
 Transaction process, initial risk limits and settlement process  An assessment of the legal, tax, and regulatory aspects of the product  Proposed valuation methodology (including pricing model, where appropriate)  Proposed reporting requirements, including any changes to existing procedures and system requirements necessary to support the new transaction type  Proposed accounting methodology
Reviewed by:

Chief Operating Officer Date
Chief Financial Officer Date
General Counsel Date
Chief Executive Officer Date
22 Appendix C: DEFINITIONS
Back Office: That part of a trading organization which handles transaction accounting, confirmations, management reporting, contract administration and working capital management, which reports to the Chief Operating Officer.

Bilateral Transaction: Any physical or financial transaction between two counterparties, neither of whom is an Exchange or market entity such as CAISO.

Cash Flow at Risk: A measure of the potential shortfall in cash flow from a specified level during a specified period of time at a specified confidence level.

CAISO: California Independent System Operator. CAISO operates a California bulk power transmission grid, administers the State’s wholesale electricity markets, and provides reliability planning and generation dispatch.

California Energy Commission (CEC): CEC is the primary energy policy and planning agency for California.

California Fair Political Practices Commission (FPPC): FPPC is a five-member independent, non-partisan commission that has primary responsibility for the impartial and effective administration of the Political Reform Act.

California Public Utilities Commission (CPUC): CPUC is a regulatory agency that regulates privately owned public utilities in the state of California, including electric power, telecommunications, natural gas and water companies.

Community Choice Aggregator (CCA): CCAs allow local government agencies such as cities and/or counties to purchase and/or develop generation supplies on behalf of their residents, businesses, and municipal accounts.

Commodity Futures Trading Commission (CFTC): The CFTC is a U.S. federal agency that is responsible for regulating commodity futures and swap markets. It goals include the promotion of competitive and efficient futures markets and the protection of investors against manipulation, abusive trade practices and fraud.

Clearing: Clearing is the process of reconciling purchases and sales of a commodity, as well as the direct transfer of funds from one financial institution to another. The process validates the availability of funds, records the transfer, and in the case of financial securities, ensure the delivery to the buyer.

Commodity: A basic good used in commerce that is interchangeable with other commodities of the same type. Commodities aremost often used asinputsin the production of other goods orservices. The quality of a given commodity may differ slightly, but it is essentially uniform across producers. When they are traded on an exchange, commoditiesmust alsomeetspecifiedminimum standards, also known as a basis grade.

Confirmation Letter: A letter agreement between two counterparties that details the specific commercial terms (e.g., price, quantity and point of delivery) of a transaction.

Congestion Revenue Right: A point-to-point financial instrument in the Day-Ahead Energy Market that entitles the holder to receive compensation for or requires the holder to pay certain congestion related transmission charges that arise when the transmission system is congested.

Counterparty Credit Risk: The risk of financial loss resulting from a counterparty to a transaction failing to fulfill its obligations.
23 Counterparty Credit Exposure: This measures the known exposures and is represented by the sum of both (a)Realized exposure and (b) Forward exposure, as those terms are defined below:

Realized exposure: payable or receivable amount owed between counterparties, is a measurement of cash flow for billed and unbilled transactions.

Forward exposure: measure of current unrealized exposure and includes the measure of a counterparty’s incentive to fulfill contractual obligations. Forward exposure measures the risk associated with having a payment default or the need to replace a transaction in the event of delivery default.

Edison Electric Institute (EEI): EEI is an association that represents all U.S. investor-owned electric companies.

Day-ahead Market: The short-term forward market for efficiently allocating transmission capacity and facilitating purchases and sales of energy and scheduled bilateral transactions; conducted by CAISO prior to the operating day.

Delivery point: the point at which a commodity will be delivered and received.

Federal Energy Regulatory Commission (FERC): FERC is a federal agency that regulates the interstate transmission of electricity, natural gas, and oil. FERC also reviews proposals to build liquefied natural gas terminals, interstate natural gas pipelines, as well as licenses hydroelectric generation projects.

Front Office: That part of a trading organization which solicits customer business, services existing customers, executes trades and ensures the physical delivery of commodities, which reports to the Chief Operating Officer.

Hedging products: Hedging products means capacity, energy, renewable energy credits or other products related to a specific transaction.

Hedging Transaction: A transaction designed to reduce the financial exposure of a specific outstanding position or portfolio; “fully hedged” equates to complete elimination of the targeted risk and “partially hedged” implies a risk reduction of less than 100%.

InterContinental Exchange (ICE): ICE s an American company formed in 2000 that operates global financial exchanges, clearing houses and provides mortgage technology, data and listing services.

Investor Owned Utility (IOU): An IOU is a business organization providing electrical and/or natural gas services to both retail and wholesale consumers and is managed as a private enterprise. Pacific Gas & Electric Company (PG&E) and Southern California Edison (SCE) are examples of IOUs.

Middle Office: That part of a trading organization that measures and reports on market risks, develops risk management policies and monitors compliance with those policies, manages credit, and keeps management and the Board informed on risk managementissues, which reports to the Chief Financial Officer.

Speculation: Speculation is the act of trading an asset with the expectation of realizing financial gain resulting from a change in price in the asset being transacted.

Value-at-Risk (VaR): VaR is a risk tolerance metric that quantifies the extent of possible financial losses within a firm, portfolio, or position over a specific time frame.

Western Systems Power Pool (WSPP): WSPP is an organization of electrical wholesale market entities that have developed and utilize a standardized agreement (WSPP Agreement) to execute trading opportunities, allowing WSPP members to manage power delivery and price risk. 24 Appendix D: DELEGATION OF FINANCIAL AUTHORITY
The Policy and Operations Boards of Directors (“Boards”) explicitly delegate approval of transactions to the CEO, RMC as outlined in the following table
Position Maturity Limit Term Limit Value Limit ($)21
Risk Management Committee 7296 Months 60 Months 110,000,000 Chief Executive Officer 4896 Months 3660 Months 65,000,000 1 “Value Limit” is the total notional value of the transaction, inclusive of any related procurement fees.

These delegated authorities may be further delegated and used to set hedging and procurement limits necessary to manage CCCE’s portfolio. For example, the CEO could authorize the Front Office to trade up to 250 MW of Next-Week Heavy Load Hour Day-Ahead Power at NP15 on ICE.

Additionally, to adapt to changing market conditions and to facilitate the daily operations of CCCE, the Boards are delegating authority to CEO (or designee) to execute administrative amendments to duly approved transactions where such amendment does not exceed the CEO’s delegated authority as set forth above (for clarity, amendments exceeding Maturity, Term or Value limits shall require Operations Board approval) and further reduces CCCE’s risk in furtherance of this Policy. Such administrative amendments must be reported during the next RMC meeting and Operations Board meeting.

These authorities will be applied to wholesale power activity executed outside of the California Independent System Operator (“CAISO”) markets. These limits provide CCCE needed authorities to manage risks as they arise. Transactions falling outside the delegations above require Board approval prior to execution. Activity with CAISO is excluded from thistable due to the nature of the market, where prices for activity may not be known until after transactions are committed.

All procurement executed under the delegation above, must align with the CCCE’s underlying risk exposure (locational, volume and temporal) that is being hedged consistent with the approved Procurement Strategy.

The point of delivery for all products must be at a location on the CAISO transmission grid.

Formatted: Superscript
Staff Report Item 5
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dan Bertoldi, Manager of Energy Programs
SUBJECT: Approve and authorize the CEO to execute Amendment No. 1 to the agreement with TRC Engineers Inc. to provide technical assistance services in support of Member Agency reach code adoption to add $200,000 increasing the total not to exceed amount to $321,935 and to extend the term an additional two years with a new expiration date of September 30, 2025
DATE: August 9, 2023
RECOMMENDATION:

This memorandum recommends the Operations Board authorize the CEO to execute Amendment No. 1 to the Standard Services Agreement with TRC Engineers, Inc. to add $200,000 for a total not to exceed amount of $321,935 and to extend the term of the Agreement to September 30, 2025.

BACKGROUND:

At its August 10, 2022 meeting, the Operations Board approved an agreement with TRC Engineers, Inc. for consulting services in support of Member Agency reach code adoption. The Agreement had a not to exceed amount of $121,935 with a term ending on September 30, 2023.

On October 3, 2022, 3CE staff launched a redesigned Reach Code Program with program implementation support from TRC Engineers. Since its launch, four Member Agencies have engaged in the program: the City of Watsonville, the City of San Luis Obispo, the County of Monterey, and the City of San Juan Bautista.

DISCUSSION/ANALYSIS:

The Reach Code Program offers stakeholder outreach support and provides no-cost technical assistance to help Member Agencies adopt and implement reach codes that advance new construction electrification, existing building electrification, and electric vehicle charging infrastructure. Support includes presenting to key stakeholders, answering technical questions, attending meetings, developing customized ordinances, reviewing staff presentations and reports, and developing implementation tools to help Member Agencies enforce their reach codes.

The proposed amendment to the Agreement with TRC Engineers will extend the term by two years - through FY 2024-25 – to enable continued support of Member Agencies to adopt and implement reach codes. Consistent with past years, the annual not to exceed amount will equal $100,000, for a total of $200,000 added to the Agreement.

FISCAL IMPACT:

If approved, and contingent on approval of each future fiscal year’s Operating Budget by the Policy Board, the total not to exceed amount of the Agreement with TRC Engineers will increase by $200,000, for a total of $321,935 over two additional years - a total of four fiscal years. The not to exceed amount for each fiscal year is as follows:
 FY 2021-22: $21,935
 FY 2022-23: $100,000
 FY 2023-24: $100,000
 FY 2024-25: $100,000
CONCLUSION:

The Board’s approval of this action will result in 3CE and TRC’s continued support for Member Agencies’ adoption of building and transportation electrification reach codes through FY 2024-25.

ATTACHMENTS:

1. Amendment No. 1 to TRC Engineers Agreement

2. Original TRC Engineers Agreement
Amendment No. 1 To Agreement Between TRC Engineers, Inc and CCCE for Consulting Services

AMENDMENT NO. 1
TO SERVICES AGREEMENT BETWEEN TRC ENGINEERS, INC. AND

CENTRAL COAST COMMUNITY ENERGY
This Amendment No. 1 to the Services Agreement (“Agreement”) which was effective on August 11, 2022 is entered into by and between CENTRAL COAST COMMUNITY ENERGY (“CCCE”) and TRC Engineers, Inc. (“CONTRACTOR”); (CCCE and CONTRACTOR are referred herein as “party,” or collectively, as the “Parties”), with respect to the following:

RECITALS
WHEREAS, CCCE and CONTRACTOR entered into the Agreement on August 11, 2022, to provide goods and/or services generally described as consulting services to support CCCE Member Agency reach code adoption; and
WHEREAS, CCCE seeks to add $200,000 from the Energy Programs Budget to the Agreement to continue consulting services in support of Member Agency reach code adoption; and

WHEREAS, CCCE seeks to extend the term of the Agreement to September 30, 2025;

AGREEMENT
NOW, THEREFORE, the Parties agree to amend the Agreement as follows:

The Agreement is hereby amended on the terms and conditions as set forth in the Agreement, except as specifically set forth below.

1. Amend the first sentence of Section 3.1 to read as follows:

The term of this Agreement is from the date of execution until September 30th, 2025, unless sooner terminated pursuant to the terms of this Agreement.

2. Amend Section 2.1 to read as follows:

2.1. CCCE shall pay the CONTRACTOR in accordance with the payment provisions set forth in Exhibit B, subject to the limitations set forth in this Agreement. The total amount payable by CCCE to CONTRACTOR under this Agreement shall not exceed (the “NTE”) the sum of $321,935 as follows:

2.1.1. The NTE in FY 2021-2022 shall not exceed $21,935.

2.1.2. The NTE in FY 2022-2023 shall not exceed $100,000

2.1.3 The NTE in FY 2023-2024 shall not exceed $100,000 or such amount consistent with the approved FY 2023-2024 Operating Budget.

2.1.4 The NTE in FY 2024-2025 shall not exceed $100,000 or such amount consistent with the approved FY 2024-2025 Operating Budget.

Amendment No. 1 To Agreement Between TRC Engineers, Inc and CCCE for Consulting Services

3. Replace Exhibit B with Exhibit B-1, attached and incorporated herein.

4. Except as provided herein, all remaining terms, conditions and provisions of the Agreement are unchanged and unaffected by this Amendment No. 1 and shall continue in full force and effect.

5. A copy of this Amendment No. 1 shall be attached to the Original Agreement.

6. This Amendment No. 1 shall be effective when signed by both parties.

Amendment No. 1 To Agreement Between TRC Engineers, Inc and CCCE for Consulting Services

Exhibit B-1: Payment Terms
CONTRACTOR will be paid on a time and materials basis to complete the tasks outlined in Exhibit A:

Scope of Work. The total not to exceed amount of this Agreement is $321,935.00. The budget is inclusive of travel costs and materials. It does not include printing and distribution of marketing materials or translation services. Without impacting the total not to exceed amount, task budgets may be reallocated between tasks without a contract amendment upon written approval by CCCE.

Table B-1
FY 2021 - 2022 &
FY 2022 - 2023 FY 2023 - 2024 FY 2024 - 2025
Task 1 - Administration $9,917 $8,000 $8,000

1.1 Monthly invoicing & reporting
Task 2 - Outreach and Stakeholder
Engagement $54,404 $30,000 $30,000

2.1 Website development &
maintenance

2.2 Distribution list development

2.3 Public events

2.4 Reporting and check-ins
Task 3 - Municipal Technical Assistance $57,614 $62,000 $62,000

3.1 Tool Development

3.2 Adoption Assistance

3.3 Implementation Assistance

3.4 Ad hoc research
Total - Per Fiscal Year $121,395 $100,000 $100,000
Grand Total $321,935
Rates for key staff are in the table below. Rates shall remain in effect for the term of this Agreement.

Adjustments to staff rates shall require written notice of the change at least 30 days prior to the date the change is to become effective and prior written approval by CCCE.

Title Hourly Rate Staff
Vice President $285 Abhijeet Pande
Director II $240 Gwelen Paliaga
Director $220 Marian Goebes
Associate Director $200 Farhad Farahmand
Senior Project Manager $190 Yun Wei, Mayra Vega, Rosie Kang Project Manager II $175 Rupam Singla
Project Manager $160 Avani Goyal, Jose Garcia
Associate Project Manager II $130 Kristen Bellows
Associate Project Manager $120 Cory Griffin, Rohan Gupta, Yolanda Beesemyer, Haley Lindsay Amendment No. 1 To Agreement Between TRC Engineers, Inc and CCCE for Consulting Services

IN WITNESS WHEREOF, the parties hereto have set their hands the day and year first above written.

Vendor Central Coast Community Energy
BY:__________________________________ BY:______________________________________ Title:_____________________________ Robert Shaw, CEO
Date: ____________________________ Date: ____________________________ Vendor Approved as to Form
BY:__________________________________ BY:___________________________________ Title:_____________________________ Charles Mckee, General Counsel Date: ____________________________ Date: ____________________________ Approved as to Financial Terms
BY:______________________________________
Dewayne Woods, Chief Financial Officer
Date: ____________________________
DocuSign Envelope ID: 085BEDE0-E8FB-4C5E-B008-513A84E157BE EP-2022-011 |

CENTRAL COAST COMMUNITY ENERGY

STANDARD SERVICES AGREEMENT
This Agreement is made by and between CENTRAL COAST COMMUNITY ENERGY (“CCCE”) and TRC Engineers, Inc. (hereinafter “CONTRACTOR”), a California corporation with its principal place of business located at 10680 White Rock Rd., Sacramento, CA 95827. CCCE and CONTRACTOR may be individually referred to herein as “Party” or collectively as “Parties.”
In consideration of the mutual covenants and conditions set forth in this Agreement, the Parties agree as follows:

1. GENERAL DESCRIPTION

1.1. CCCE hereby engages CONTRACTOR to perform, and CONTRACTOR hereby agrees to perform, the services described in Exhibit A in conformity with the terms of this Agreement. The goods and/or services are generally described as: Consulting services to support CCCE Member Agency reach code adoption.

2. PAYMENT PROVISIONS

2.1. CCCE shall pay the CONTRACTOR in accordance with the payment provisions set forth in Exhibit B, subject to the limitations set forth in this Agreement. The total amount payable by CCCE to CONTRACTOR under this Agreement shall not exceed (the “NTE”) the sum of $121,935 as follows:

2.1.1. The NTE in FY 2021-2022 shall not exceed $21,935.

2.1.2. The NTE in FY 2022-2023 shall not exceed $100,000 or such amount consistent with the approved FY 2022-2023 Operating Budget.

3. TERM OF AGREEMENT

3.1. The term of this Agreement is from the date of execution until September 30, 2023, unless sooner terminated pursuant to the terms of this Agreement. This Agreement is of no force or effect until signed by both the CONTRACTOR and CCCE, with CCCE’s execution to be last in time. CONTRACTOR may not commence work under this Agreement before CCCE signs this Agreement.

3.2. CCCE reserves the right to cancel this Agreement, or any extension of this Agreement, without cause with thirty (30) days written notice, or with cause immediately.

4. SCOPE OF SERVICES AND ADDITIONAL PROVISIONS

4.1. The following attached exhibits are incorporated herein by reference and constitute a part of this Agreement:

4.1.1. Exhibit A: Scope of Services

4.1.2. Exhibit B: Payment Terms

4.1.3. Exhibit C: Procedures for Unauthorized Release of Covered Information DocuSign Envelope ID: 963150D7-68C7-4D9E-9E1B-B2BAF0AF31DF DocuSign Envelope ID: 085BEDE0-E8FB-4C5E-B008-513A84E157BE EP-2022-011 |

5. PERFORMANCE STANDARDS

5.1. CONTRACTOR warrants that CONTRACTOR and CONTRACTOR’s agents, employees and subcontractors performing services under this Agreement are specially trained, experienced, competent, and appropriately licensed to perform the work and deliver the services required under this Agreement and are not employees of CCCE or immediate family of an employee of CCCE.

5.2. CONTRACTOR and CONTRACTOR’s agents, employees and subcontractors shall perform all work in a safe and skillful manner and in compliance with all applicable laws and regulations. All work performed under this Agreement that is required by law to be performed or supervised by licensed personnel shall be performed in accordance with such licensing requirements.

5.3. CONTRACTOR shall furnish, at its own expense, all materials, equipment, and personnel necessary to carry out the terms of this Agreement, except as otherwise specified in this Agreement.

CONTRACTOR shall not use CCCE premises, property (including equipment, instruments, or supplies) or personnel for any purpose other than in the performance of its obligations under this Agreement.

5.4. CONTRACTOR will perform the services consistent with the professional skill and care ordinarily provided by the same type of professional, for a project of similar size, scope, and complexity during the time which the Services are provided, and in a similar locality, under similar circumstances (“Standard of Care”). Such Standard of Care is not a warranty or guarantee, and CONTRACTOR has no such obligation, express or implied. Nothing in this Agreement will be interpreted to require CONTRACTOR to perform professional services to any higher standard or have any obligation in the performance of professional services in excess of what is required by the Standard of Care, and this paragraph will control over any contrary provision.

6. PAYMENT CONDITIONS

6.1. Prices shall remain firm for the initial term of the Agreement and, thereafter, may be adjusted annually as provided herein. CCCE does not guarantee any minimum or maximum amount of dollars to be spent under this Agreement.

6.2. Negotiations for rate changes shall be commenced, by CONTRACTOR, a minimum of ninety days (90) prior to the expiration of the Agreement. Rate changes are not binding unless mutually agreed upon in writing by CCCE and the CONTRACTOR.

6.3. Invoices shall be submitted monthly on a form acceptable to CCCE and provide sufficient detail, as determined by CCCE, of services rendered for the invoiced period.

6.4. CCCE shall certify the invoice for payment in either the amount requested, or in such other amount as CCCE determines is due in conformity with this Agreement. Invoices shall be certified and paid within 45 days of submission to CCCE.

6.5. If CCCE does not pay CONTRACTOR within forty-five (45) days of the date of an invoice, then CONTRACTOR may, upon seven (7) days’ written notice to CCCE, suspend performance of the Services until payment of the amount owing has been received.

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7. TERMINATION

7.1. During the term of this Agreement, CCCE may terminate the Agreement for any reason by giving written notice of termination to the CONTRACTOR at least thirty (30) days prior to the effective date of termination. Such notice shall set forth the effective date of termination. In the event of such termination, the amount payable under this Agreement shall be reduced in proportion to the services provided prior to the date of termination. Contractor shall be paid for any winddown expenses that are required for to the termination, upon CCCE request.

7.2. CCCE may cancel and terminate this Agreement for good cause effective immediately upon written notice to CONTRACTOR. “Good cause” includes the failure of CONTRACTOR to perform the required services at the time and in the manner provided under this Agreement. If CCCE terminates this Agreement for good cause, CCCE may be relieved of the payment of any consideration to CONTRACTOR, and CCCE may proceed with the work in any manner, which CCCE deems proper. The cost to CCCE shall be deducted from any sum due the CONTRACTOR under this Agreement.

CONTRACTOR shall be paid for all services performed through the date of Termination.

8. INDEMNIFICATION

8.1. CONTRACTOR shall indemnify, and hold harmless CCCE, its Directors, Board members, officers member agencies and employees (Indemnitees) from any third-party claim, loss, demand, damage arising out of, or in connection with, performance of this Agreement by CONTRACTOR and/or its agents, employees or sub-contractors to the extent such claims are caused by CONTRACTOR’s negligent acts, errors, or omissions in the performance under this Agreement. For all other claims, excepting to the extent of loss, injury or damage caused by the negligence or willful misconduct of personnel employed by CCCE, CONTRACTOR shall indemnify and defend and hold Indemnitees against all losses, demands, or damage, and will defend Indemnitees against any and all claims, arising out of third party bodily injury, disease, death, or property damage (excluding damages for loss of use) arising out of or relating to the services performed, but only to the extent such bodily injury, disease, death, or property damage is caused by the negligence or intentional misconduct of CONTRACTOR, its subcontractors, or any person or entity for whose acts or omissions any of them are responsible in the performance of this Agreement. It is the intent of the parties to this Agreement to provide the broadest possible coverage for CCCE. The Parties shall, to the extent of negligence, share in the proportionate costs, attorneys’ fees, expenses and liabilities incurred with respect to any litigation in which the CONTRACTOR is obligated to indemnify, defend and hold harmless CCCE under this Agreement.

8.1.1. The CONTRACTOR’s selection of counsel to satisfy CONTRACTOR’s defense and hold harmless obligation as set forth in section 8.1 above, shall be subject to review and approval by CCCE.

8.1.2. Notwithstanding any other provision of this Agreement, CCCE shall be entitled to participate fully in the defense of any claim or action the expense of any such participation to be borne by CCCE.

9. INSURANCE REQUIREMENTS

9.1. Prior to commencement of this Agreement, the CONTRACTOR shall provide a “Certificate of Insurance” certifying that coverage as required herein has been obtained. Individual endorsements executed by the insurance carrier shall accompany the certificate. This verification of coverage shall be sent to CCCE.

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9.2. Without limiting CONTRACTOR’s duty to defend and indemnify, CONTRACTOR shall maintain in effect throughout the term of this Agreement a policy or policies of insurance with the following minimum limits of liability:

9.2.1.1.Commercial General Liability Insurance, including but not limited to premises and operations, including coverage for Bodily Injury and Property Damage, Personal Injury, Contractual Liability, Broad form Property Damage, Independent Contractors, Products and Completed Operations, and cross-liability with a combined single limit for Bodily Injury and Property Damage of not less than $1,000,000 per occurrence, and $2,000,000 in the aggregate.

9.2.1.2.Business Automobile Liability Insurance, covering all motor vehicles, including owned, leased, non-owned, and hired vehicles, used in providing services under this Agreement, with a combined single limit for Bodily Injury and Property Damage of not less than $500,000 per occurrence.

9.2.1.3.Workers’ Compensation Insurance, if CONTRACTOR employs others in the performance of this Agreement, in accordance with California Labor Code section 3700 and with Employer’s Liability limits not less than $1,000,000 each person, $1,000,000 each accident and $1,000,000 each disease.

9.2.1.4.Professional Liability Insurance, if required for the professional services being provided, (e.g., those persons authorized by a license to engage in a business or profession regulated by the California Business and Professions Code), in the amount of not less than $1,000,000 per claim and $2,000,000 in the aggregate, to cover liability for malpractice or errors or omissions made in the course of rendering professional services.

If professional liability insurance is written on a “claims-made” basis rather than an occurrence basis, the CONTRACTOR shall, upon the expiration or earlier termination of this Agreement, obtain extended reporting coverage (“tail coverage”) with the same liability limits. Any such tail coverage shall continue for at least three years following the expiration or earlier termination of this Agreement.

9.3. Unless otherwise specified by this Agreement, all such insurance shall be written on an occurrence basis, or, if the policy is not written on an occurrence basis, such policy with the coverage required herein shall continue in effect for a period of three years following the date CONTRACTOR completes its performance of services under this Agreement.

9.4. Commercial general liability and automobile liability policies shall provide an endorsement naming CCCE, its Directors, Board members, officers, member agencies and employees as Additional Insureds with respect to liability arising out of the CONTRACTOR’S work, including ongoing and completed operations, and shall further provide that such insurance is primary insurance to any insurance or self-insurance maintained by CCCE and that the insurance of the Additional Insureds shall not be called upon to contribute to a loss covered by the CONTRACTOR’S insurance.

DocuSign Envelope ID: 963150D7-68C7-4D9E-9E1B-B2BAF0AF31DF DocuSign Envelope ID: 085BEDE0-E8FB-4C5E-B008-513A84E157BE EP-2022-011 |

10. RECORD AND CONFIDENTIALITY

10.1. CONTRACTOR and its officers, employees, agents, and subcontractors shall comply with any and all federal, state, and local laws, which provide for the confidentiality of records and other information. CONTRACTOR shall not disclose any confidential records or other confidential information received from CCCE or prepared in connection with the performance of this Agreement, unless CCCE specifically permits CONTRACTOR to disclose such records or information.

CONTRACTOR shall promptly transmit to CCCE any and all requests for disclosure of any such confidential records or information. CONTRACTOR shall not use any confidential information gained by CONTRACTOR in the performance of this Agreement except for the sole purpose of carrying out CONTRACTOR’s obligations under this Agreement.

10.1.1. Confidential Information specifically includes Covered Information (as defined in Exhibit C), including Protected Personal Information(“PPI”) that identifies, relates to, describes, or is capable of being associated with, or could reasonably be linked, directly or indirectly, with a consumer, household, or customer account. All such Covered Information and PPI must fully be protected from disclosure as set forth in California Public Utility Commission Decision D.12- 08-045. In the event of an unauthorized release of Covered Information and PPI, CONTRACTOR shall comply with Exhibit C, Procedures for Unauthorized Release of Covered Information.

10.2. Upon expiration or termination of this Agreement, CONTRACTOR shall return to CCCE any CCCE records which CONTRACTOR used or received from CCCE to perform services under this Agreement. Notwithstanding the forgoing, Contractorshall not be required to alter, modify, delete, or destroy computer back-up media made in the ordinary course of business, one archival copy of the Confidential Information, or information required by law to be maintained, provided that any such information is maintained in confidence pursuant to this Agreement.

10.3. CONTRACTOR shall prepare, maintain, and preserve all reports and records that may be required by federal, state, and local rules and regulations related to services performed under this Agreement. CONTRACTOR shall maintain such records for a period of at least three years after receipt of final payment under this Agreement. If any litigation, claim, negotiation, audit exception, or other action relating to this Agreement is pending at the end of the three-year period, then CONTRACTOR shall retain said records until such action is resolved.

10.4. CCCE shall have the right to examine, monitor and audit all records, documents, conditions, and activities of the CONTRACTOR and its subcontractors related to services provided under this Agreement. Pursuant to Government Code section 8546.7, if this Agreement involves the expenditure of public funds in excess of $10,000, the parties to this Agreement may be subject, at the request of CCCE or as part of any audit of CCCE, to the examination and audit of the State Auditor pertaining to matters connected with the performance of this Agreement for a period of three years after final payment under the Agreement.

10.5. CCCE shall have a royalty-free, exclusive and irrevocable license to reproduce, publish, and use, and authorize others to do so, all original computer programs, writings, sound recordings, pictorial reproductions, drawings, and other works of similar nature produced in the course of or under this Agreement. CONTRACTOR shall not publish any such material without the prior written approval of CCCE. In the event CCCE, its employees, permitted assigns, successors, consultants, member agencies, and other engineers (“CCCE Parties”), subsequently reproduces or otherwise uses DocuSign Envelope ID: 963150D7-68C7-4D9E-9E1B-B2BAF0AF31DF DocuSign Envelope ID: 085BEDE0-E8FB-4C5E-B008-513A84E157BE EP-2022-011 |
the deliverables or creates a derivative work based upon the deliverables, CCCE will, where authorized or permitted by law, remove or completely obliterate the original professional seals, trademarks, logos, and other indications on the deliverables of the identity of CONTRACTOR, its employees, and its sub-consultants. Additionally, such use by CCCE of the deliverables is at CCCE’s sole risk.

11. NON-DISCRIMINATION

11.1. During the performance of this Agreement, CONTRACTOR, and its subcontractors, shall not unlawfully discriminate against any person because of race, religious creed, color, sex, national origin, ancestry, physical disability, mental disability, medical condition, maritalstatus, age (over 40), or sexual orientation, either in CONTRACTOR’s employment practices or in the furnishing of services to recipients. CONTRACTOR shall ensure that the evaluation and treatment of its employees and applicants for employment and all persons receiving and requesting services are free of such discrimination. CONTRACTOR and any subcontractor shall, in the performance of this Agreement, fully comply with all federal, state, and local laws and regulations which prohibit discrimination. The provision of services primarily or exclusively to such target population as may be designated in this Agreement shall not be deemed to be prohibited discrimination.

12. INDEPENDENT CONTRACTOR

12.1. In the performance of work, duties, and obligations under this Agreement, CONTRACTOR is at all times acting and performing as an independent contractor and not as an employee of CCCE.

No offer or obligation of permanent employment with CCCE and CONTRACTOR shall not become entitled by virtue of this Agreement to receive from CCCE any form of employee benefits including but not limited to sick leave, vacation, retirement benefits, workers’ compensation coverage, insurance or disability benefits. CONTRACTOR shall be solely liable for and obligated to pay directly all applicable taxes, including federal and state income taxes and social security, arising out of CONTRACTOR’s performance of this Agreement. In connection therewith, CONTRACTOR shall defend, indemnify, and hold CCCE harmless from any and all liability which CCCE may incur because of CONTRACTOR’s failure to pay such taxes.

13. NOTICES

13.1. Notices required under this Agreement shall be delivered personally or by first-class, postage pre-paid mail to CCCE and CONTRACTOR’S contract administrators at the addresses listed below:

Central Coast Community Energy TRC Engineers, Inc.

Chief Financial & Technology Officer Abhijeet Pande, Vice President 70 Garden Court, Suite 300 17911 Von Karman Avenue, Suite 400 Monterey, Ca 93940 Irvine, CA 92614-6261

14. MISCELLANEOUS PROVISIONS

14.1. Conflict of Interest. CONTRACTOR represents that it presently has no interest and agrees not to acquire any interest during the term of this Agreement, which would directly, or indirectly conflict in any manner or to any degree with the full and complete performance of the services required to be rendered under this Agreement.

14.2. Amendment. This Agreement may be amended or modified only by an instrument in writing signed by CCCE and the CONTRACTOR.

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14.3. Waiver. Any waiver of any terms and conditions of this Agreement must be in writing and signed by CCCE and the CONTRACTOR. A waiver of any of the terms and conditions of this Agreement shall not be construed as a waiver of any other terms or conditions in this Agreement.

14.4. Contractor. The term “CONTRACTOR” as used in this Agreement includes CONTRACTOR’s officers, agents, and employees acting on CONTRACTOR’s behalf in the performance of this Agreement.

14.5. Disputes. CONTRACTOR shall continue to perform under this Agreement during any dispute.

14.6. Assignment and Subcontracting. The CONTRACTOR shall not assign, sell, or otherwise transfer its interest or obligations in this Agreement without the prior written consent of CCCE None of the services covered by this Agreement shall be subcontracted without the prior written approval of CCCE. Notwithstanding any such subcontract, CONTRACTOR shall continue to be liable for the performance of all requirements of this Agreement.

14.7. Successors and Assigns. This Agreement and the rights, privileges, duties, and obligations of CCCE and CONTRACTOR under this Agreement, to the extent assignable or delegable, shall be binding upon and inure to the benefit of the parties and their respective successors, permitted assigns, and heirs.

14.8. Compliance with Applicable Law. The parties shall comply with all applicable federal, state, and local laws and regulations in performing this Agreement.

14.9. Headings. The headings are for convenience only and shall not be used to interpret the terms of this Agreement.

14.10. Time is of the Essence. Time is of the essence in each and all of the provisions of this Agreement.

14.11. Governing Law. This Agreement shall be governed by and interpreted under the laws of the State of California.

14.12. Non-exclusive Agreement. This Agreement is non-exclusive and both CCCE and CONTRACTOR expressly reserve the right to contract with other entities for the same or similar services.

14.13. Construction of Agreement. CCCE and CONTRACTOR agree that each party has fully participated in the review and revision of this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting party shall not apply in the interpretation of this Agreement or any amendment to this Agreement.

14.14. Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same Agreement.

14.15. Authority. Any individual executing this Agreement on behalf of CCCE or the CONTRACTOR represents and warrants hereby that he or she has the requisite authority to enter into this Agreement on behalf of such party and bind the party to the terms and conditions of this Agreement.

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14.16. Integration. This Agreement, including the exhibits, represent the entire Agreement between CCCE and the CONTRACTOR with respect to the subject matter of this Agreement and shall supersede all prior negotiations, representations, or agreements, either written or oral, between CCCE and the CONTRACTOR as of the effective date of this Agreement, which is the date that CCCE signs the Agreement.

14.17. Interpretation of Conflicting Provisions. In the event of any conflict or inconsistency between the provisions of this Agreement and the Provisions of any exhibit or other attachment to this Agreement, the provisions of this Agreement shall prevail and control.

SIGNATURE OF THE PARTIES:

TRC Engineers, Inc. Central Coast Community Energy
BY:

Title: Francis X. Reilly
President, Advanced Energy
BY:

Tom Habashi, CEO
Date: 8/2/2022 Date:

Approved as to Form
BY:

Brian Kimball, General Counsel
Date:

Approved as to Financial Terms
BY:

Jaya Bajpai, Chief Financial Officer
Date:

DocuSign Envelope ID: 963150D7-68C7-4D9E-9E1B-B2BAF0AF31DF 8/11/2022
8/11/2022
8/11/2022
DocuSign Envelope ID: 085BEDE0-E8FB-4C5E-B008-513A84E157BE EP-2022-011 |
Exhibit A: Scope of Services
Emissions from transportation and building natural gas use comprise the largest sources of GHGs within the Central Coast Community Energy’s (CCCE) service area. CCCE’s Reach Code Program aims to develop and advance Building Electrification and Electric Vehicle (EV) Infrastructure “reach” codes with its Member Agencies to update local building codes for new residential and commercial construction and major remodels. These codes are to be developed in alignment with and build on the 2022 California statewide building code updates. Codes for new buildings and major modifications are the most cost-effective points at which to install EV charging infrastructure and electric appliances compared to retrofitting existing buildings.

TRC will leverage some of the resources developed for Peninsula Clean Energy (PCE), Silicon Valley Clean Energy (SVCE), and East Bay Community Energy (EBCE) to support decarbonization reach code adoption in Central Coast Community Energy (3CE) Member Agencies. This approach will increase efficiency and reduce redundant work.

TRC has assigned budgets by task. TRC will alert CCCE if budget can or needs to move across tasks, but TRC will not exceed a total budget across all tasks.

Task 1 – Administration
TRC will:

Task 1.1 - Setup a kickoff meeting with CCCE
Task 1.2 - Provide monthly invoices and status updates, including work accomplished and next steps, with hours billed by Member Agency and general tasks
Task 1 Deliverable(s): Kickoff meeting, monthly reports, check-ins Task 2 – Outreach and Stakeholder Engagement
Task 2.1 – Website development and maintenance.

TRC will create a new one-page website for CCCE similar to BayAreaReachCodes.org. The website will have CCCE branding and house the municipal tools and templates serving Adoption Support and Implementation Support.

Task 2.2 – Distribution list development.

TRC will lead stakeholder engagement with CCCE staff support. An early start and partnership with regional agencies like Tri-County Regional Energy Network (3C-REN) will ensure strong footing. TRC expects that CCCE will provide the following:
♦ Notice to Member Agency elected officials that reach code technical assistance is being made available, and recommend that Member Agencies prioritize reach code adoption for this year ♦ Email contacts for Member Agency staff anticipated to be reach code champions. This may be Community Development, Planning, Building, or Sustainability staff.

Task 2.3 – Public events. TRC will setup three 60-90-minute stakeholder meetings in CCCE territory to share information on reach code adoption and solicit feedback via discussion and polls. These meetings will introduce reach codes and supporting information, leveraging previously developed and re-branded content.

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Stakeholder meetings will be as follows, with contacts attained from CCCE, 3C-REN, and other regional collaborators:
♦ Member Agency staff – elected officials, municipal staff ♦ Building industry – architects, developers, affordable housing organizations, utilities, building trades, energy consultants, and contractors on the State Licensing Board ♦ General public – Advocates, environmental groups, and other members of the community as determined from the CCCE Communications and Outreach team.

Regional collaborators may include:
♦ County air pollution control districts (APCDs), including Monterey Bay Air Resources District (MBARD) ♦ Golden State Builder Exchanges, which has four local chapters in CCCE service area ♦ California Building Industry Association, which has two local chapters in CCCE service area ♦ CALBO
♦ Central Coast International Code Council
Task 2.4 – Reporting and check-ins. TRC will facilitate bi-weekly check-ins, including agenda and note-taking, to discuss Outreach and other program elements. TRC will also report on attendance, process and share event recordings, and update distribution lists as needed.

Task 2 Deliverable(s): Website, distribution lists, 3 stakeholder meetings, recordings, attendee lists, attendee feedback, bi-weekly check-ins
Task 3 – Municipal Technical Assistance
TRC will support adoption assistance and implementation assistance for Member Agencies that express interest after the stakeholder meetings.

Task 3.1 – Tool development.

TRC will share tool and studies developed and available on BayAreaReachCodes.org, AllElectricDesign.Org, LocalEnergyCodes.com, or other websites, rebranded to represent CCCE. These tools include:
♦ Model codes
o New construction electrification
 Municipal Ordinance
 Part 11 Building Code amendment
o Electric Vehicle Charging Infrastructure
 Zoning Ordinance
 Part 11 Building Code amendment
o Existing buildings
 Time of Permit Ordinance
 Adoption framework
♦ Slide deck library
♦ Staff report template
♦ Frequently Asked Questions
♦ If the Member Agency adopts Part 6 building code amendments governing efficiency or conservation, TRC will provide a template and support application for California Energy Commission approval.

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Task 3.2 – Adoption assistance.

This includes:
♦ Initial meeting to develop a timeline, strategy, and outline needs for technical assistance for each City.
♦ Review and comment staff presentations and staff reports ♦ Answer technical questionsreceived from elected officials or the public ♦ Alongside CCCE, present and/or attend at Council/Board Study Sessions and Readings to support technical questions
Task 3.3 – Implementation assistance.

TRC will develop and offer implementation tools to CCCE member agencies that have adopted reach codes.

Foremost, this will include a building plan checklist that can be housed on a city website and offered to the development community.

Implementation assistance will include supporting each Member Agency that adopts a reach code with a training for Member Agency Staff. TRC may deliver the trainings or collaborate with 3C-REN or other regional agencies to deliver the trainings to Member Agency Staff. The development of the training materials will occur in collaboration with the Bay Area Reach Codes Initiative, Statewide Utility Program, BayREN, and other agencies as well as 3C-REN and TRC.

Task 3.4 - TRC will be available for ad hoc requests from CCCE. Requests can be dependent on specific stakeholder questions and client priorities and may necessitate budget reallocations. Potential requests include but are not limited to:
♦ Targeted outreach efforts such as developer focus groups ♦ Marketing or infographic development
♦ Cost-effectiveness analysis using CCCE rates or custom prototype buildings Task 3 Deliverable(s): Adoption tools, municipal staff technical assistance, implementation tools, municipal staff implementation assistance.

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Exhibit B: Payment Terms
CONTRACTOR will be paid on a time and materials basis to complete the tasks outlined in Exhibit A: Scope of Work. The total not to exceed amount of this Agreement is $121,935.00. The budget is inclusive of travel costs and materials. It does not include printing and distribution of marketing materials or translation services. Without impacting the total not to exceed amount, task budgets may be reallocated between tasks without a contract amendment upon written approval by CCCE.

Hours Totals
Task 1 - Administration 70 $9,917.00

1.1 Kickoff

1.2 Monthly reporting
Task 2 - Outreach and Stakeholder Engagement 425 $54,404.00

2.1 Website development & maintenance

2.2 Distribution list development

2.3 Public events

2.4 Reporting and check-ins
Task 3 - Municipal Technical Assistance 380 $57,614.00

3.1 Tool Development

3.2 Adoption Assistance

3.3 Implementation Assistance

3.4 Ad hoc research
Totals 875 $121,935.00
Rates for key staff are in the table below. Rates shall remain in effect for the term of this Agreement.

Adjustments to staff rates shall require written notice of the change at least 30 days prior to the date the change is to become effective and prior written approval by CCCE.

Title Hourly Rate Staff
Vice President $285 Abhijeet Pande
Director II $240 Gwelen Paliaga
Director $220 Marian Goebes
Associate Director $200 Farhad Farahmand
Senior Project Manager $190 Yun Wei, Mayra Vega
Project Manager II $175 Rupam Singla
Project Manager $160 Avani Goyal, Jose Garcia
Associate Project ManagerII $130 Kristen Bellows
Associate Project Manager $120 Cory Griffin, Rohan Gupta, Yolanda Beesemyer, Haley Lindsay DocuSign Envelope ID: 963150D7-68C7-4D9E-9E1B-B2BAF0AF31DF DocuSign Envelope ID: 085BEDE0-E8FB-4C5E-B008-513A84E157BE EP-2022-011 |
Exhibit C: Procedures for Unauthorized Release of Covered Information SCOPE
CONTRACTOR hereby agrees to adhere to these Procedures for detecting and reporting the unauthorized release of Covered Information, including Protected Personal Information (“PPI”).

These Procedures apply to the following unauthorized release activities:

1. Unauthorized access

2. Unauthorized destruction

3. Unauthorized use

4. Unauthorized modification

5. Disclosure to third parties for Secondary Purposes (see below)

DEFINITIONS
Covered Entity – (1) any Community Choice Aggregator or Electrical Service Provider (when providing service to residential or small commercial customers), or any third party that provides services to a Community Choice Aggregator or Electrical Service Provider (when providing service to residential or small commercial customers) under contract, (2) any third party who accesses, collects, stores, uses or discloses covered information pursuant to an order of the Commission, unless specifically exempted, who obtains this information from an electrical corporation, a Community Choice Aggregator or an Electrical Service Provider (when providing service to residential or small commercial customers), or (3) any third party, when authorized by the customer, that accesses, collects, stores, uses, or discloses covered information relating to 11 or more customers who obtains this information from an electrical corporation, a Community Choice Aggregator or an Electrical Service Provider (when providing service to residential or small commercial customers).

Covered Information -- any usage information obtained through the use of the capabilities of Advanced Metering Infrastructure when associated with any information that can reasonably be used to identify an individual, family, household, residence, or non-residential customer, except that covered information does not include usage information from which identifying information has been removed such that an individual, family, household or residence, or non-residential customer cannot reasonably be identified or re-identified. Covered information, however, does not include information provided to the California Public Utilities Commission (the “Commission”) pursuant to its oversight responsibilities.

Primary Purposes – The “primary purposes” for the collection, storage, use, or disclosure of covered information, as outlined in Rule 1(c) of Attachment B, are to:

1. Provide or bill for electrical power or gas,

2. Provide for system, grid, or operational needs,

3. Provide services as required by state or federal law or as specifically authorized by an order of the Commission, or

4. Plan, implement, or evaluate demand response, energy management, or energy efficiency programs under contract with a Community Choice Aggregator or and Electrical Service Provider (when providing service to residential or small commercial customers), under contract with the 8/1/2022 13 Contract Number:

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Commission, or as part of a Commission authorized program conducted by a governmental entity under the supervision of the Commission.

Secondary Purposes – “Secondary purpose” means any purpose that is not a primary purpose.

Non-Covered Entity – “Non-Covered Entity” means any entity not defined as a Covered Entity.

Responsible Parties -- CCCE, CONTRACTOR, and any staff, employees, or sub consultants contracted by CCCE or CONTRACTOR.

PROCEDURE
Detecting and Reporting of Unauthorized Releases

1. All Responsible Parties are required to protect Covered Information from unauthorized release activities as set forth above.

2. Any request by any non-Covered Entities, for access to Covered Information must be reviewed and approved by an CCCE manager level employee to ensure no unauthorized or inadvertent release of Covered Information.

3. All authorized releases of Covered Information to Non-Covered Entities shall be logged and reported to CCCE on a quarterly basis.

4. Any discovery of any unauthorized release of Covered Information must be reported to CCCE within one week of detection.

Unauthorized Release Handling Procedure

1. The discovering party after detecting, or discovery of, the unauthorized release of Covered Information must contact CCCE’s Dir. of Finance and Administration (or another executive manager) immediately.

2. CONTRACTOR will quantify and validate the type and extent of unauthorized release and report that information to CCCE’s Dir. of Finance and Administration in writing with sufficient detail for CCCE to determine the extent and impact of the unauthorized release.

3. CONTRACTOR shall prepare a written annual report of all discoveries of unauthorized releases of Covered Information.

Review and Training

1. At least annually, CONTRACTOR will review these Procedures with its staff, employees, or sub consultants.

2. Any proposed changes to these Procedures shall be provided in writing to CCCE’s Dir. of Finance and Administration for their consideration.
8/1/2022 14 Contract Number:

DocuSign Envelope ID: 963150D7-68C7-4D9E-9E1B-B2BAF0AF31DF Staff Report Item 6
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dan Bertoldi, Manager of Energy Programs
SUBJECT: Approve and authorize the CEO to execute Amendment No. 2 to the agreement with Cohen Ventures Inc. DBA Energy Solutions to provide implementation services in support if the Electrify Your Home Program, extending term of the agreement by one (1) year to September 30, 2024, and reflecting adjustments to incentives DATE: August 9, 2023
RECOMMENDATION:

This memorandum recommends the Operations Board authorize the CEO to execute Amendment No. 2 to the Original Agreement with Cohen Ventures, Inc. DBA Energy Solutions, (the “Agreement”) extending term of the Agreement by one (1) year to September 30, 2024, and reflecting adjustments to incentives with no change to the Not to Exceed Amount.

BACKGROUND:

On March 9, 2022, the Operations Board authorized the CEO to execute an agreement with Energy Solutions in an amount not to exceed $1,760,000 and term ending September 30, 2022, to support residential electrification program implementation.

In May 2022, 3CE launched the Electrify Your Home Program (EYH). The Program provides incentives to enrolled contractors who recommend and switch out gas powered appliances in existing single and multi-family buildings with all-electric heat pump water heating and HVAC technologies. These incentives directly reduce the upfront cost for 3CE customers who make the switch to all-electric heat pump technology. This program partners with the TECH Clean California Initiative, a State-wide program, to increase available funds when applicable, and to leverage existing program contractor enrollment, training, and other initiatives undertaken by TECH Clean California.

On August 10, 2022, the Operations Board approved Amendment No. 1 to the Agreement with Energy Solutions to extend the term of the Agreement by one (1) year to September 30, 2023, and adjust fees and incentive levels with no change to the not to exceed amount.

DISCUSSION/ANALYSIS:

Staff are in the process of modifying the design of the EYH Program for FY 2023-24. Proposed modifications will provide increased incentives to replace damaged HVAC and water heaters with all electric technology for customers whose homes suffer damage as a result of declared natural disasters.

This change will allow customers impacted by flooding to receive an additional $1,000 - $3,000 for each unit that is replaced, depending on the equipment type and housing type (single family or multifamily).

Additionally, staff are proposing to reduce incentive levels for heat pump water heaters when program participants leverage program funds from the State’s Self-Generation Incentive Program (SGIP).

Customers who use both 3CE and SGIP funds to replace their gas water heater will receive $1,500 - $2,300 less from 3CE. When leveraging SGIP funds, customers will receive a higher overall incentive amount and potentially required to participate in a qualifying demand response (DR) program with their new water heater. This modification to the EYR Program is designed to motivate customers to take advantage of both the SGIP and EYH Programs, while providing our customers with the most options to receive incentives for electrifying their water heaters.

The proposed Amendment No. 2 modifies the Scope of Work to reflect the proposed EYH Program modifications outlined above and extends the term of the agreement for one year through FY 2023-24.

The not to exceed amount of the Agreement will not be impacted.

FISCAL IMPACT:

The proposed funding to support the Electrify Your Home Program for FY 2023-24 is subject to Policy Board adoption as part of the FY 2023-24 Operating Budget. There is no impact to the not to exceed amount of the Agreement.

CONCLUSION:

The Board’s approval of this action will result in Energy Solutions continuing to provide implementation services in support of 3CE’s Electrify Your Home program through September 30, 2024, and to better support 3CE’s customers to electrify their home’s HVAC and water heaters.

ATTACHMENTS:

1. Amendment No. 2 to Energy Solutions Agreement

2. Amendment No. 1 to Energy Solutions Agreement

3. Original Energy Solutions Agreement
Amendment No. 2 To Agreement Between Energy Solutions and 3CE 1 AMENDMENT NO. 2

TO SERVICES AGREEMENT BETWEEN ENERGY SOLUTIONS AND

CENTRAL COAST COMMUNITY ENERGY
This Amendment No.2 to the Services Agreement (“Agreement”) which was effective on March 11, 2022, is entered into by and between CENTRAL COAST COMMUNITY ENERGY (“3CE”) and Cohen Ventures, Inc. DBA Energy Solutions (hereinafter “CONTRACTOR”); (CCCE and CONTRACTOR are referred herein as “party,” or collectively, as the “Parties”), with respect to the following:

RECITALS
WHEREAS, 3CE and CONTRACTOR entered into an Agreement on March 11, 2022, to provide services for the implementation of a residential electrification program (“Program”); and
WHEREAS, 3CE sought to support and enhance the TECH Clean California Initiative, a statewide program to accelerate electrification, by combining CCCE incentive funds with state incentive funds; and
WHEREAS, 3CE and CONTRACTOR executed Amendment No. 1 to the Agreement on August 15, 2022; and
WHEREAS, without changing the Not to Exceed amount of the Agreement, 3CE and CONTRACTOR seek to extend the term of the Agreement to September 30, 2024; and WHEREAS, 3CE seeks to further support victims of declared natural disasters by providing enhanced incentives through the Electrify Your Home Program; and WHEREAS, 3CE seeks to leverage State funding available through the Self Generation Incentive Program to further support customers who choose to participate in Demand Response programs.

AGREEMENT
NOW, THEREFORE, the Parties agree to amend the Agreement as follows:

1. Amend the first sentence of Section 3.1 to read as follows:

The term of this Agreement is from the date of execution until September 30th, 2024, unless sooner terminated pursuant to the terms of this Agreement.

2. Replace Exhibit A-1 with Exhibit A-2, attached and incorporated herein.

3. Except as provided herein, all remaining terms, conditions and provisions of the Amendment No. 2 To Agreement Between Energy Solutions and 3CE 2 Agreement Amendment No. 1 are unchanged and unaffected by this Amendment No. 2 and shall continue in full force and effect.

4. The terms and conditions in this Amendment No. 2 shall control over any inconsistent terms and conditions in the original Agreement and Amendment No. 1.

5. A copy of this Amendment No. 2 shall be attached to the Original Agreement.

6. This Amendment No. 2 shall be effective when signed by both parties.

IN WITNESS WHEREOF, the parties hereto have set their hands the day and year first above written.

Energy Solutions Central Coast Community Energy
BY:__________________________________ BY:___________________________________ Title:_____________________________ Robert M. Shaw, CEO Date: ____________________________ Date: ____________________________ Vendor Approved as to Form
BY:__________________________________ BY:___________________________________ Title:_____________________________ Charles McKee, General Counsel Date: ____________________________ Date: ____________________________ Approved as to Financial Terms
BY:__________________________________
Dewayne Woods, Chief Financial Officer
Date: ____________________________
8/1/2023 3 Contract Number: ______________
Exhibit A-2: Scope of Services
Task 1 - Program Administration
CONTRACTOR will collaborate with CCCE to develop, implement, and manage the CCCE Electrify Your Home Program (“The Program”) with activities including, but not limited to processing applications, paying incentives, reporting, and representing CCCE’s interests with third parties and participating contractors. CONTRACTOR will host monthly calls to review the status of goals, participant performance, and discuss potential issues and recommendations for improvement.

Activities:
 Meetings hosted once per month
Task 2 - Data Reports
Task 2a – Monthly Data Report
CONTRACTOR will provide reports to CCCE in a manner that enables confident decision-making and alleviates audit risk. To enable real-time reporting, CONTRACTOR’S software platform, Iris, is designed to provide secure integrated data collection, and reports may be downloaded from Iris at any time. The fields included in these reports are flexible and will be configured to suit CCCE’s preferences.

CONTRACTOR will prepare a monthly report with a summary of current participation and performance indicators that are determined by CONTRACTOR and approved by CCCE. These reports will be accessible either through the online application system, delivered via a secure file sharing website, or delivered based on agreed upon terms between CCCE and CONTRACTOR.

Deliverables:
 Monthly Report delivered once per month
Task 2b - Full Data Reports
All sales data collected from participants in claims, as well as all data documenting completed validation checks, eligible equipment specifications, and payments to participants, will be saved in Iris and will be available for use in all automated and manual QA/QC processes. CONTRACTOR will report on this data Program-to-date, which will include application-level fields such as equipment, installation, customer, and savings data.

Deliverables:
 Raw data provided ad hoc.

Task 3 - Contractor Outreach
CONTRACTOR will leverage trade ally outreach efforts to build and maintain a network of contractors, distributors, and manufacturers to support the Program and ensure contractors in CCCE territory are aware of the higher incentives sponsored by CCCE. CONTRACTOR will work with contractors to create 8/1/2023 4 Contract Number: ______________
installs in CCCE territory and provide support on how to submit applications through the Incentive Clearinghouse. Contractors previously enrolled in the TECH Clean California Initiative will automatically be enrolled in the CCCE program through an amendment to the TECH Trade Partner Participation Agreement.

Activities:
 Support for contractors in CCCE
Task 4 - Incentive Clearinghouse and Incentive Payments The Incentive Clearinghouse will be the central processing platform for all Program incentives, including potential future incentives that may be integrated from other parties (e.g., TECH or other State incentives). The Incentive Clearinghouse will have the functionality to layer incentives across multiple program administrators. The goals of the Incentive Clearinghouse are to 1) simplify the participant experience by standardizing application requirements and the application submittal process, and 2) create a more comprehensive project data set for public reporting purposes.

CONTRACTOR will configure the incentive clearinghouse with Single Family and Multi-Family Incentives.

CONTRACTOR will process applications, conduct QA/QC, and pay incentives for CCCE on the Incentive Clearinghouse. If potential future incentives from third parties become available for program integration, payments to contractors will combine both CCCE and additional incentives into a single check paid to participants to simplify the payment process.

Activities:
 Configuration of Incentive Clearinghouse with CCCE incentives.  Processing and Payment of CCCE Incentive applications.

Table 1: Estimated Percentage of Time Per Task
Task Estimated Percent of Time
Task 1 – Program Administration 30%
Task 2 – Monthly Data Reports 20%
Task 3 – Contractor Outreach 20%
Task 4 – Incentive Clearinghouse 30%
Program Incentives and Implementation
Incentive Plan
The tables below show incentive values for Heat Pump Heating, Ventilation, and Air Conditioning (HPHVAC) and Heat Pump Water Heater (HPWH) measures under the Program. In all cases, the incentive is limited by the project cost, which will be a required application field. The incentives will be available throughout CCCE service area and are subject to change based on CCCE’s discretion. The CCCE funded incentives will be paid by the CONTRACTOR and dispersed through the Contractor’s Incentive Clearinghouse to provide a seamless experience to market actors. 8/1/2023 5 Contract Number: ______________
Single Family Incentives
Heat Pump Heating Ventilation and Air Conditioning (HVAC) Measures The Program will provide incentives for single family homeowner customers converting from a gas or propane HVAC to all-electric HPHVAC.

Table 2: Unitary/Split System Heat Pump HVAC Incentives Equipment
Type*
Size Category Sub-Category Tier
Seasonal/Part-Load Cooling
Efficiency
HSPF
CCCE
Incentive
per Unit
Unitary Split
System and
mini/multi-split
< 5.4 tons Ducted
Baseline HP Replacement $2,500
1 16.0 SEER 9.5 $3,000
2 18.0 SEER 10.0 $3,500
*Incentives available for installations providing full-home heating/cooling. Load calculations showing the installed mini-/multi-split serves full home will be required as part of the application.

The Program will provide an added incentive to income qualified applicants installing a HVAC measure.

The incentive is determined by active enrollment in the CARE or FERA programs. The incentive is a flat rate of $1,000/unit.

Table 3: Income Qualified Kicker - HPHVAC
Measure Qualifier
CCCE
Incentive
per Unit
Income Qualified Kicker CARE/FERA enrollment $1,000
The Program will provide added incentives for the installation of HPWH measures when (a) a customer certifies to Contractor they are located at a single-family home that was damaged by a Governor-proclaimed disaster occurring in or after February 2023, (b) Contractor passes this information on to 3CE and (c) 3CE thereafter notifies Contractor the customer is eligible for the added incentive. Contractor shall have no responsibility for determining eligibility for such added incentives and shall bear no costs or liabilities with respect to added incentives paid to customers subsequently determined to be ineligible.

Table 4: Equipment Replacement Disaster Kicker - HPHVAC Measure Qualifier
CCCE
Incentive
per Unit
Equipment Replacement
Disaster Kicker - HPHVAC
Damage to home resulting
from declared natural
disaster
$3,000
8/1/2023 6 Contract Number: ______________
Heat Pump Water Heater (HPWH) Measures
The Program will provide incentives for single family homeowner customers converting from a gas or propane water heater to all-electric HPWH. In all cases, the Program will require applicants to provide evidence of the previous unit’s fuel type to obtain the incentive. For projects that leverage incentive funding from the California Public Utility Commission’s Self Generation Incentive Program (SGIP) under CPUC Decision 22-04-036, 3CE will provide a reduced incentive amount that can be combined with SGIP funds.

Table 5: Heat Pump Water Heater Incentives
Previous WH Fuel Type HPWH Capacity
CCCE
Incentive per
Unit
CCCE
Incentive per
Unit for
Projects that
Leverage SGIP
funding
Natural Gas/Propane
< 55 Gallons $3,300 $1,500
> 55 Gallons $3,800 $1,500
The Program will provide added incentive for income qualified residential customers installing HPWH measures. The incentive is determined by active enrollment in the CARE or FERA programs. The incentive is a flat rate of $1,000/unit.

Table 6: Income Qualified Kicker - HPWH
Measure Qualifier
CCCE
Incentive
per Unit
Income Qualified Kicker CARE/FERA enrollment $1,000
The Program will provide added incentives for the installation of HPWH measures when (a) a customer certifies to 3CE or Contractor a project is located at a single-family home that was damaged by a Governor-proclaimed disaster occurring in February 2023 or later and (b) Contractor passes this information onto 3CE and (c) 3CE thereafter notifies Contractor the customer is eligible for the added incentive. Contractor shall have no responsibility for determining eligibility for such added incentives and shall bear no costs or liabilities with respect to added incentives paid to customers subsequently determined to be ineligible.

Table 7: Equipment Replacement Disaster Kicker - HPWH
Measure Qualifier
CCCE
Incentive
per Unit
8/1/2023 7 Contract Number: ______________
Equipment Replacement
Disaster Kicker - HPWH
Damage to home resulting
from declared natural
disaster
$1,000
Panel Replacement Measures
The Program will offer incentives for panel replacements or upgrades to single family homeowner customers that increase the effective panel capacity to support additional electrical load related to the installation of HPHVAC or HPWH measures. This includes materials and labor related to the panel replacement or upgrade and may include smart load center upgrades. Panel upgrade/replacement must be done in combination with a heat pump installation.

Table 8: Panel Upgrade and Replacement Incentives
Measure Category
CCCE
Incentive per
Unit
Panel upgrade $2,000
Multi-Family Incentives
Gas to Electric HPWH
The Program will provide incentives for multifamily building owner customers converting from a gas or propane water heater to all-electric HPWH.

Table 9: Multifamily Unit HPWH Incentives
Measure Market Rate
Incentives per Unit
Income
Qualified
Incentives per
Unit
Gas/propane to HPWH - unitary $2,100 $2,800
Upsizing kicker Gas/propane to
HPWH - unitary $1,050 $1,400
Non HPWH to HPWH - central $1,800 $2,400
Upsizing kicker non HPWH to
HPWH - central $900 $1,200
Panel/Electrical service
upgrade*
$2,000 $2,800
Disaster Replacement Kicker** $1,000 $1,000
*This includes materials and labor related to the panel replacement or upgrade and may include smart load center upgrades. Panel upgrade/replacement must be done in combination with a heat pump installation.
** The incentive is determined by a project located at a multi-family dwelling that was damaged by a Governor-proclaimed disaster occurring in February 2023 or later. 8/1/2023 8 Contract Number: ______________
Heat Pump Heating Ventilation and Air Conditioning (HVAC) Measures The Program will provide incentives for multifamily building owner customers converting from a gas or propane HVAC to all-electric HPHVAC.

Table 10: Multifamily Unit HP HVAC Incentives
Measure Market Rate Incentives
per Unit
Income
Qualified
Incentives per
Unit
Split or Rooftop HP - individual apt. $3,000 $4,000
PTHP, SPVHP, unitary through the
wall - individual apt. $750 $1,000
PTHP, SPVHP, unitary through the
wall - individual apt. (Variable
capacity/inverter driven (previous
heat source = all except PTHPs)
$1,500 $2,000
HP HVAC - multiple apts. $1,500 $2,000
Split or Rooftop HP - common area $2,700 $3,600
PTHP, SPVHP, unitary through the
wall - common area
$450 $600
PTHP, SPVHP, unitary through the
wall - common area (Variable
capacity/inverter driven, previous
heat source = non HP systems)
$1,200 $1,600
Panel/Electrical service upgrade $2,000 $2,800
Disaster Replacement Kicker** $2,000 $2,000
*This includes materials and labor related to the panel replacement or upgrade and may include smart load center upgrades. Panel upgrade/replacement must be done in combination with a heat pump installation.
** The incentive is determined by a project located at a multi-family dwelling that was damaged by a Governor-proclaimed disaster occurring in February 2023 or later.

TECH Clean California Data Sharing
CCCE acknowledges and agrees that over the course of CONTRACTOR carrying out its obligations under this agreement, customer program participation data may need to be disclosed to CONTRACTOR’S subcontractors and representatives carrying out their obligations under the TECH Clean California program. In its agreements with subcontractors and representatives, CONTRACTOR will require the same adherence to all confidentiality and data security measures described by this Agreement, including Section 10. Record and Confidentiality and Exhibit C: Procedures for Release of Covered Information.

CONTRACTOR is solely responsible for any breach or non-compliance of these terms by its TECH Clean California subcontractors or CONTRACTOR representatives in safeguarding confidential information in accordance with this Agreement.

DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 1 AMENDMENT NO. 1

TO SERVICES AGREEMENT BETWEEN ENERGY SOLUTIONS AND

CENTRAL COAST COMMUNITY ENERGY
This Amendment No.1 to the Services Agreement (“Agreement”) which was effective on March 11, 2022, is entered into by and between CENTRAL COAST COMMUNITY ENERGY (“CCCE”) and Cohen Ventures, Inc. DBA Energy Solutions (hereinafter “CONTRACTOR”); (CCCE and CONTRACTOR are referred herein as “party,” or collectively, as the “Parties”), with respect to the following:

RECITALS
WHEREAS, CCCE and CONTRACTOR entered into the Agreement on March 11, 2022, to provide goods and/or services generally described as services to implement a Residential Electrification Program (“Program”) for CCCE customers; and WHEREAS, CCCE sought to support and enhance the TECH Clean California Initiative, a statewide program to accelerate electrification, by combining CCCE incentive funds with state incentive funds; and
WHEREAS, due to high demand, in May 2022, TECH Clean California Initiative funds became either fully reserved or substantially reserved throughout CCCE’s service area, impacting the Program’s ability to provide CCCE customers with incentives at the desired levels to accelerate electrification; and
WHEREAS, CCCE seeks to extend the term of the Agreement to September 30, 2023; and
WHEREAS, without changing the Not to Exceed amount of the Agreement, CCCE seeks to supplement incentive funds that were offered under the TECH Clean California Initiative to allow building electrification incentives to remain unchanged for CCCE customers.

AGREEMENT
NOW, THEREFORE, the Parties agree to amend the Agreement as follows:

The Agreement is hereby amended on the terms and conditions as set forth in the Agreement, except as specifically set forth below.

1. Amend the first sentence of Section 3.1 to read as follows:

EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 2 The term of this Agreement is from the date of execution until September 30th, 2023, unless sooner terminated pursuant to the terms of this Agreement.

2. Replace Exhibit A with Exhibit A-1, attached and incorporated herein.

3. Replace Exhibit B with Exhibit B-1, attached and incorporated herein.

4. Except as provided herein, all remaining terms, conditions and provisions of the Agreement are unchanged and unaffected by this Amendment No. 1 and shall continue in full force and effect.

5. A copy of this Amendment No. 1 shall be attached to the Original Agreement.

6. This Amendment No. 1 shall be effective when signed by both parties.

IN WITNESS WHEREOF, the parties hereto have set their hands the day and year first above written.

Cohen Ventures, Inc. Central Coast Community Energy
BY:

Title: Associate Director
BY:

Tom Habashi, CEO
Date: 8/2/2022 | 8:19 AM PDT Date:

Approved as to Form
BY:

Brian Kimball, General Counsel
Date:

Approved as to Financial Terms
BY:

Jaya Bajpai, Chief Financial Officer
Date:

EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B 8/15/2022
8/15/2022
8/15/2022
DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 8/1/2022 3 Contract Number:

Exhibit A-1: Scope of Services
Task 1 - Program Administration
CONTRACTOR will collaborate with CCCE to develop, implement, and manage the CCCE Electrify Your Home Program (“The Program”) with activities including, but not limited to processing applications, paying incentives, reporting, and representing CCCE’s interests with third parties and participating contractors. CONTRACTOR will host monthly calls to review the status of goals, participant performance, and discuss potential issues and recommendations for improvement.

Activities:
• Meetings hosted once per month
Task 2 - Data Reports
Task 2a – Monthly Data Report
CONTRACTOR will provide reports to CCCE in a manner that enables confident decision-making and alleviates audit risk. To enable real-time reporting, CONTRACTOR’S software platform, Iris, is designed to provide secure integrated data collection, and reports may be downloaded from Iris at any time. The fields included in these reports are flexible and will be configured to suit CCCE’s preferences.

CONTRACTOR will prepare a monthly report with a summary of current participation and performance indicators that are determined by CONTRACTOR and approved by CCCE. These reports will be accessible either through the online application system, delivered via a secure file sharing website, or delivered based on agreed upon terms between CCCE and CONTRACTOR.

Deliverables:
• Monthly Report delivered once per month
Task 2b - Full Data Reports
All sales data collected from participants in claims, as well as all data documenting completed validation checks, eligible equipment specifications, and payments to participants, will be saved in Iris and will be available for use in all automated and manual QA/QC processes. CONTRACTOR will report on this data Program-to-date, which will include application-level fields such as equipment, installation, customer, and savings data.

Deliverables:
• Raw data provided ad hoc.

Task 3 - Contractor Outreach
CONTRACTOR will leverage trade ally outreach efforts to build and maintain a network of contractors, distributors, and manufacturers to support the Program and ensure contractors in CCCE territory are aware of the higher incentives sponsored by CCCE. CONTRACTOR will work with contractors to create EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 8/1/2022 4 Contract Number:
installs in CCCE territory and provide support on how to submit applications through the Incentive Clearinghouse. Contractors previously enrolled in the TECH Clean California Initiative will automatically be enrolled in the CCCE program through an amendment to the TECH Trade Partner Participation Agreement.

Activities:
• Support for contractors in CCCE
Task 4 - Incentive Clearinghouse and Incentive Payments The Incentive Clearinghouse will be the central processing platform for all Program incentives, including potential future incentives that may be integrated from other parties (e.g., TECH or other State incentives). The Incentive Clearinghouse will have the functionality to layer incentives across multiple program administrators. The goals of the Incentive Clearinghouse are to 1) simplify the participant experience by standardizing application requirements and the application submittal process, and 2) create a more comprehensive project data set for public reporting purposes.

CONTRACTOR will configure the incentive clearinghouse with Single Family and Multi-Family Incentives.

CONTRACTOR will process applications, conduct QA/QC, and pay incentives for CCCE on the Incentive Clearinghouse. If potential future incentives from third parties become available for program integration, payments to contractors will combine both CCCE and additional incentives into a single check paid to participants to simplify the payment process.

Activities:
• Configuration of Incentive Clearinghouse with CCCE incentives. • Processing and Payment of CCCE Incentive applications.

Table 1: Estimated Percentage of Time Per Task
Task Estimated Percent of Time
Task 1 – Program Administration 30%
Task 2 – Monthly Data Reports 20%
Task 3 – Contractor Outreach 20%
Task 4 – Incentive Clearinghouse 30%
Program Incentives and Implementation
Incentive Plan
The tables below show incentive values for Heat Pump Heating, Ventilation, and Air Conditioning (HPHVAC) and Heat Pump Water Heater (HPWH) measures under the Program. In all cases, the incentive is limited by the project cost, which will be a required application field. The incentives will be available throughout CCCE service area and are subject to change based on CCCE’s discretion. The CCCE funded incentives will be paid by the CONTRACTOR and dispersed through the Contractor’s Incentive Clearinghouse to provide a seamless experience to market actors.

EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 8/1/2022 5 Contract Number:

Single Family Incentives
Heat Pump Heating Ventilation and Air Conditioning (HVAC) Measures The Program will provide incentives for single family homeowner customers converting from a gas or propane HVAC to all-electric HPHVAC.

Table 2: Unitary/Split System Heat Pump HVAC Incentives Equipment
Type* Size Category Sub-Category Tier
Seasonal/Part-Load Cooling
Efficiency
HSPF
CCCE
Incentive
per Unit
Unitary Split Baseline HP Replacement $2,500
System and
mini/multi- < 5.4 tons Ducted 1 16.0 SEER 9.5 $3,000
split 2 18.0 SEER 10.0 $3,500
*Incentives available for installations providing full-home heating/cooling. Load calculations showing the installed mini-/multi-split serves full home will be required as part of the application.

The Program will provide an added incentive to income qualified applicants installing a HVAC measure.

The incentive is determined by active enrollment in the CARE or FERA programs. The incentive is a flat rate of $1,000/unit.

Table 3: Income Qualified Kicker - HPHVAC
Measure Qualifier
CCCE
Incentive
per Unit
Low-Income Kicker CARE/FERA enrollment $1,000
Heat Pump Water Heater (HPWH) Measures
The Program will provide incentives for single family homeowner customers converting from a gas or propane water heater to all-electric HPWH. In all cases, the Program will require applicants to provide evidence of the previous unit’s fuel type to obtain the incentive.

Table 4: Heat Pump Water Heater Incentives
Previous WH Fuel
Type HPWH Capacity
CCCE
Incentive
per Unit
Natural Gas/Propane < 55 Gallons $3,300
> 55 Gallons $3,800
The Program will provide an added incentive to income qualified applicants installing HPWH measure.

The incentive is determined by active enrollment in the CARE or FERA programs. The incentive is a flat rate of $1,000/unit.

EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 8/1/2022 6 Contract Number:

Table 5: Income Qualified Kicker - HPWH
Measure Qualifier
CCCE
Incentive
per Unit
Low-Income Kicker CARE/FERA enrollment $1,000
Panel Replacement Measures
The Program will offer incentives for panel replacements or upgrades to single family homeowner customers that increase the effective panel capacity to support additional electrical load related to the installation of HPHVAC or HPWH measures. This includes materials and labor related to the panel replacement or upgrade and may include smart load center upgrades. Panel upgrade/replacement must be done in combination with a heat pump installation.

Table 6: Panel Upgrade and Replacement Incentives
Measure Category
CCCE
Incentive per
Unit
Panel upgrade $2,000
Multi-Family Incentives
Gas to Electric HPWH
The Program will provide incentives for multifamily building owner customers converting from a gas or propane water heater to all-electric HPWH.

Table 7: Multifamily Unit HPWH Incentives
Measure Market Rate
Incentives per Unit
Low Income
Incentives per
Unit
Gas/propane to HPWH - unitary $2,100 $2,800
upsizing kicker Gas/propane to
HPWH - unitary $1,050 $1,400
non HPWH to HPWH - central $1,800 $2,400
upsizing kicker non HPWH to
HPWH - central $900 $1,200
Panel/Electricalservice
upgrade* $2,000 $2,800
*This includes materials and labor related to the panel replacement or upgrade and may include smart load center upgrades. Panel upgrade/replacement must be done in combination with a heat pump installation.

EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 8/1/2022 7 Contract Number:

Heat Pump Heating Ventilation and Air Conditioning (HVAC) Measures The Program will provide incentives for multifamily building owner customers converting from a gas or propane HVAC to all-electric HPHVAC.

Table 8: Multifamily Unit HP HVAC Incentives
Measure Market Rate Incentives
per Unit
Low Income
Incentives per
Unit
Split or Rooftop HP - individual apt. $3,000 $4,000
PTHP, SPVHP, unitary through the
wall - individual apt. $750 $1,000
PTHP, SPVHP, unitary through the
wall - individual apt. (Variable
capacity/inverter driven (previous
heat source = all except PTHPs)
$1,500 $2,000
HP HVAC - multiple apts. $1,500 $2,000
Split or Rooftop HP - common area $2,700 $3,600
PTHP, SPVHP, unitary through the
wall - common area $450 $600
PTHP, SPVHP, unitary through the
wall - common area (Variable
capacity/inverter driven, previous
heat source = non HP systems)
$1,200 $1,600
Panel/Electricalservice upgrade $2,000 $2,800
*This includes materials and labor related to the panel replacement or upgrade and may include smart load center upgrades. Panel upgrade/replacement must be done in combination with a heat pump installation.

TECH Clean California Data Sharing
CCCE acknowledges and agrees that over the course of CONTRACTOR carrying out its obligations under this agreement, customer program participation data may need to be disclosed to CONTRACTOR’S subcontractors and representatives carrying out their obligations under the TECH Clean California program. In its agreements with subcontractors and representatives, CONTRACTOR will require the same adherence to all confidentiality and data security measures described by this Agreement, including Section 10. Record and Confidentiality and Exhibit C: Procedures for Release of Covered Information. CONTRACTOR is solely responsible for any breach or non-compliance of these terms by its TECH Clean California subcontractors or CONTRACTOR representatives in safeguarding confidential information in accordance with this Agreement.

EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B DocuSign Envelope ID: 8EE70542-67A7-4684-A8D2-D5F1608CC7F6 8/1/2022 8 Contract Number:

Exhibit B-1: Payment Terms
Incentive Reimbursement
CONTRACTOR will pay incentives and be reimbursed by CCCE to simplify payment process.

CONTRACTOR will provide invoices with details of incentive payments as well as fixed price and performance payments in a format required by CCCE. Invoices will be submitted to CCCE by the 15th of each month.

Budget
CONTRACTOR will be compensated with an administration budget based on a fixed price (Fixed Price Start-Up Fee) and performance basis (Performance Payment). The Fixed Price Start-Up Fee and Performance Payment covers all the services in the Scope of Work. The Fixed Price Start-Up Fee covers costs associated with Program start-up, including 1) contractor outreach and enrollment across CCCE’s service area; 2) coordination with additional TECH Clean California Initiative activities, including but not limited to contractor outreach, contractor training, vendor engagement, data analysis, data reporting, marketing, and pilot activities; and 3) configuration of the Incentive Clearinghouse. The Program Implementation Fee covers ongoing services described in the Scope of Work. The Fixed Price Start-Up Fee shall be $50,000 and the Program Implementation Fee shall be 7% of all incentives paid out over $500,000. Associated with Program start-up, the Fixed Price Start-Up Fee will be invoiced upon receiving the Program’s first claim through the Incentive Clearinghouse and demonstration of completed activities 1 – 3 above, deemed satisfactory by CCCE. Tables 1 and 2 below provide a breakdown of the budget and budget thresholds for each building type.

Table 1: Budget Breakdown
Expense Type Total
Incentive Reimbursement $1,600,000
Administration Costs $160,000
Fixed Price Start-Up Fee $50,000
Program Implementation Fee $110,000
Total Costs $1,760,000
Table 2. Budget per Category
Category Minimum Budget Maximum Budget Per Project
Single Family (SF) $600,000 $100,000*
Multi-Family (MF) $400,000 $100,000
Low-Income (SF or MF) $200,000 $200,000
*Includes large group single family projects such as a military base.

These budgets per category are intended to promote geographic equity and diversity across the Program’s projects. Incentive caps per category may be changed at CCCE's discretion and documented in email.

EP-2022-013
DocuSign Envelope ID: A7C3C8D0-7DAF-423A-95E2-3A470663F71B 3/9/2022 1 Contract Number: ______________

CENTRAL COAST COMMUNITY ENERGY

STANDARD SERVICES AGREEMENT
This Agreement is made by and between CENTRAL COAST COMMUNITY ENERGY (“3CE”) and Cohen Ventures, Inc. DBA Energy Solutions (hereinafter “CONTRACTOR”), a California corporation with its principal place of business located at 449 15th Street, Suite 400, Oakland, CA . 3CE and CONTRACTOR may be individually referred to herein as “Party” or collectively as “Parties.” In consideration of the mutual covenants and conditions set forth in this Agreement, the Parties agree as follows:

1. GENERAL DESCRIPTION

1.1. 3CE hereby engages CONTRACTOR to perform, and CONTRACTOR hereby agrees to perform, the services described in Exhibits A in conformity with the terms of this Agreement. The goods and/or services are generally described as services to implement a Residential Electrification Program for CCCE customers.

2. PAYMENT PROVISIONS

2.1. 3CE shall pay the CONTRACTOR in accordance with the payment provisions set forth in Exhibit B, subject to the limitations set forth in this Agreement. The total amount payable by 3CE to CONTRACTOR under this Agreement shall not exceed the sum of $1,760,000.00.

3. TERM OF AGREEMENT

3.1. The term of this Agreement is from the date of execution until September 30th, 2022, unless sooner terminated pursuant to the terms of this Agreement. This Agreement is of no force or effect until signed by both the CONTRACTOR and 3CE, with 3CE’s execution to be last in time.

CONTRACTOR may not commence work under this Agreement before 3CE signs this Agreement.

3.2. 3CE reserves the right to cancel this Agreement, or any extension of this Agreement, without cause with thirty (30) days written notice, or with cause immediately.

4. SCOPE OF SERVICES AND ADDITIONAL PROVISIONS

4.1. The following attached exhibits are incorporated herein by reference and constitute a part of this Agreement:

4.1.1.Exhibit A: Scope of Services

4.1.2.Exhibit B: Payment Terms

4.1.3.Exhibit C: Procedures for Unauthorized Release of Covered Information DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 2 Contract Number: ______________

5. PERFORMANCE STANDARDS

5.1. CONTRACTOR warrants that CONTRACTOR and CONTRACTOR’s agents, employees and subcontractors performing services under this Agreement are specially trained, experienced, competent, and appropriately licensed to perform the work and deliver the services required under this Agreement and are not employees of 3CE or immediate family of an employee of 3CE.

5.2. CONTRACTOR and CONTRACTOR’s agents, employees and subcontractors shall perform all work in a safe and skillful manner and in compliance with all applicable laws and regulations. All work performed under this Agreement that is required by law to be performed or supervised by licensed personnel shall be performed in accordance with such licensing requirements.

5.3. CONTRACTOR shall furnish, at its own expense, all materials, equipment, and personnel necessary to carry out the terms of this Agreement, except as otherwise specified in this Agreement. CONTRACTOR shall not use 3CE premises, property (including equipment, instruments, or supplies) or personnel for any purpose other than in the performance of its obligations under this Agreement.

6. PAYMENT CONDITIONS

6.1. Prices shall remain firm for the initial term of the Agreement and, thereafter, may be adjusted annually as provided herein. 3CE does not guarantee any minimum or maximum amount of dollars to be spent under this Agreement.

6.2. Negotiations for rate changes shall be commenced, by CONTRACTOR, a minimum of ninety days (90) prior to the expiration of the Agreement. Rate changes are not binding unless mutually agreed upon in writing by 3CE and the CONTRACTOR.

6.3. Invoices shall be submitted monthly on a form acceptable to 3CE and provide sufficient detail, as determined by 3CE, of services rendered for the invoiced period.

6.4. 3CE shall certify the invoice for payment in either the amount requested, or in such other amount as 3CE determines is due in conformity with this Agreement. Invoices shall be certified and paid within 45 days of submission to 3CE.

7. TERMINATION

7.1. During the term of this Agreement, 3CE may terminate the Agreement for any reason by giving written notice of termination to the CONTRACTOR at least thirty (30) days prior to the effective date of termination. Such notice shall set forth the effective date of termination. In the event of such termination, the amount payable under this Agreement shall be reduced in proportion to the services provided prior to the date of termination.

7.2. Either Party may provide notice to the breaching Party of the non-breaching Party’s intent to cancel and terminate this Agreement for Good Cause (defined below). Termination shall occur DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 3 Contract Number: ______________
if the Parties fail to agree on a plan for the breaching Party to cure within fifteen (15) days of the breaching Party’s receipt of such notice. “Good Cause” includes the failure of CONTRACTOR to perform the required services at the time and in the manner provided under this Agreement, or failure for 3CE to render payment for completed services following CONTRACTOR’s written demand for payment, in accordance with Exhibit B – Payment Conditions. If either Party terminates this Agreement for Good Cause, 3CE may be relieved of payment for work not performed and 3CE may proceed with the work in any manner, which 3CE deems proper.

8. INDEMNIFICATION

8.1. CONTRACTOR shall indemnify, defend, and hold harmless 3CE, its Directors, Board members, officers, agents and employees from any claim, liability, loss, injury or damage arising out of, or in connection with, performance of this Agreement by CONTRACTOR and/or its agents, employees or sub-contractors, excepting only loss, injury or damage caused by the sole negligence or willful misconduct of personnel employed by 3CE. It is the intent of the parties to this Agreement to provide the broadest possible coverage for 3CE. The CONTRACTOR shall reimburse 3CE for all costs, attorneys’ fees, expenses and liabilities incurred with respect to any litigation in which the CONTRACTOR is obligated to indemnify, defend and hold harmless 3CE under this Agreement.

8.1.1.The CONTRACTOR’s selection of counsel to satisfy CONTRACTOR’s defense and hold harmless obligation as set forth in section 8.1 above, shall be subject to review and approval by 3CE.

8.1.2.Notwithstanding any other provision of this Agreement, 3CE shall be entitled to participate fully in the defense of any claim or action.

9. INSURANCE REQUIREMENTS

9.1. Prior to commencement of this Agreement, the CONTRACTOR shall provide a “Certificate of Insurance” certifying that coverage as required herein has been obtained. Individual endorsements executed by the insurance carrier shall accompany the certificate. In addition, the CONTRACTOR upon request shall provide a certified copy of the policy or policies. This verification of coverage shall be sent to 3CE.

9.2. Without limiting CONTRACTOR’s duty to defend and indemnify, CONTRACTOR shall maintain in effect throughout the term of this Agreement a policy or policies of insurance with the following minimum limits of liability:

9.2.1.1. Commercial General Liability Insurance, including but not limited to premises and operations, including coverage for Bodily Injury and Property Damage, Personal Injury, Contractual Liability, Broad form Property Damage, Independent Contractors, Products and Completed Operations, and cross-liability with a combined single limit for Bodily Injury and Property Damage of not less than $1,000,000 per occurrence, and $2,000,000 in the aggregate.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 4 Contract Number: ______________

9.2.1.2. Business Automobile Liability Insurance, covering all motor vehicles, including owned, leased, non-owned, and hired vehicles, used in providing services under this Agreement, with a combined single limit for Bodily Injury and Property Damage of not less than $500,000 per occurrence.

9.2.1.3. Workers’ Compensation Insurance, if CONTRACTOR employs others in the performance of this Agreement, in accordance with California Labor Code section 3700 and with Employer’s Liability limits not less than $1,000,000 each person, $1,000,000 each accident and $1,000,000 each disease.

9.2.1.4. Professional Liability Insurance, if required for the professional services being provided, (e.g., those persons authorized by a license to engage in a business or profession regulated by the California Business and Professions Code), in the amount of not less than $1,000,000 per claim and $2,000,000 in the aggregate, to cover liability for malpractice or errors or omissions made in the course of rendering professional services. If professional liability insurance is written on a “claims-made” basis rather than an occurrence basis, the CONTRACTOR shall, upon the expiration or earlier termination of this Agreement, obtain extended reporting coverage (“tail coverage”) with the same liability limits. Any such tail coverage shall continue for at least three years following the expiration or earlier termination of this Agreement.

9.3. Unless otherwise specified by this Agreement, all such insurance shall be written on an occurrence basis, or, if the policy is not written on an occurrence basis, such policy with the coverage required herein shall continue in effect for a period of three years following the date CONTRACTOR completes its performance of services under this Agreement.

9.4. Commercial general liability and automobile liability policies shall provide an endorsement naming 3CE, its Directors, Board members, officers, agents, and employees as Additional Insureds with respect to liability arising out of the CONTRACTOR’S work, including ongoing and completed operations, and shall further provide that such insurance is primary insurance to any insurance or self-insurance maintained by 3CE and that the insurance of the Additional Insureds shall not be called upon to contribute to a loss covered by the CONTRACTOR’S insurance.

10. RECORD AND CONFIDENTIALITY

10.1. “Confidential Information” is defined as certain confidential, secret and proprietary information, disclosed either orally or in writing or in printed, graphic or electronically recorded materials, records, data, specifications, formulas, technology, inventions, devices, products, methods, know-how, processes, financial data, specific client data and requirements, client and potential client lists, information concerning each Parties employees, agents or divisions, pricing information, and other trade secrets which have been or will be developed and owned by either of the Parties or their respective client(s).

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 5 Contract Number: ______________

10.1.1. Confidential Information specifically includes Covered Information (as defined in Exhibit C), including Protected Personal Information(“PPI”) that identifies, relates to, describes, or is capable of being associated with, or could reasonably be linked, directly or indirectly, with a consumer, household, or customer account. All such Covered Information and PPI must fully be protected from disclosure as set forth in California Public Utility Commission Decision D.12-08-045. In the event of an unauthorized release of Covered Information and PPI, CONTRACTOR shall comply with Exhibit C, Procedures for Unauthorized Release of Covered Information.

10.2. The Parties and their respective officers, employees, agents, and subcontractors shall comply with any and all federal, state, and local laws, which provide for the confidentiality of records and other information. A Party receiving Confidential Information (the “Receiving Party”) shall not disclose any confidential records or other Confidential Information received from the other Party (the “Disclosing Party”) or prepared in connection with the performance of this Agreement, unless the Disclosing Party specifically permits the Receiving Party to disclose such records or information. The Receiving Party shall promptly transmit to 3CE any and all requests for disclosure of any such confidential records or Confidential Information. The Receiving Party shall not use any Confidential Information gained by the Receiving Party in the performance of this Agreement except for the sole purpose of carrying out the Receiving Party’s obligations under this Agreement.

10.3. Upon expiration or termination of this Agreement, the Receiving Party shall return to the Disclosing Party any Disclosing Party records which the Receiving Party used or received from the Disclosing Party to perform services under this Agreement.

10.4. CONTRACTOR shall prepare, maintain, and preserve all reports and records that may be required by federal, state, and local rules and regulations related to services performed under this Agreement. CONTRACTOR shall maintain such records for a period of at least three years after receipt of final payment under this Agreement. If any litigation, claim, negotiation, audit exception, or other action relating to this Agreement is pending at the end of the three-year period, then CONTRACTOR shall retain said records until such action is resolved.

10.5. 3CE shall have the right to examine, monitor and audit all records, documents, conditions, and activities of the CONTRACTOR and its subcontractors related to services provided under this Agreement. Pursuant to Government Code section 8546.7, if this Agreement involves the expenditure of public funds in excess of $10,000, the parties to this Agreement may be subject, at the request of 3CE or as part of any audit of 3CE, to the examination and audit of the State Auditor pertaining to matters connected with the performance of this Agreement for a period of three years after final payment under the Agreement.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 6 Contract Number: ______________

10.6. CONTRACTOR shall not publish any and all original computer programs, writings, sound recordings, pictorial reproductions, drawings, and other works of similar nature without the prior written approval of 3CE.

11. INTELLECTUAL PROPERTY RIGHTS

11.1 “Iris Platform” is defined as the Iris online software and associated data, owned and maintained by CONTRACTOR and provided as a part of the services to 3CE under this Agreement, that functions as an incentive processing and program reporting platform for 3CE’s customers and other third parties.

11.2 Intellectual Property Rights to the Iris Platform. All right, title, and interest in and to the Iris Platform (including without limitation all intellectual property rights therein) and all modifications, improvements, extensions, customizations, scripts or other definitive works of the Iris Platform provided or developed by the CONTRACTOR, whether prior to or during the Term of this Agreement, are and shall remain at all times solely vested in the CONTRACTOR. The Iris Platform was developed in its entirety by CONTRACTOR prior to the term of this Agreement, is the sole and exclusive property of CONTRACTOR, and CONTRACTOR retains all intellectual property rights thereto, including but not limited to copyrights (including all registrations and applications therefor), trade secrets, service marks, trademarks, trade names, trade dress, trademark applications and registrations, internet domain names, and all other proprietary and intellectual property rights, including moral rights.

Use of the Iris Platform by 3CE, its customers or any third party as part of the services shall not convey any rights of ownership to the Iris Platform, express or implied, including any intellectual property rights thereto, to any such party. During the term of this Agreement, CONTRACTOR grants to 3CE a non-exclusive, non-assignable, royalty-free, worldwide limited right to access and use the Iris Platform in connection with the services. Except as expressly provided herein, Company agrees not to assign, sublicense, transfer, copy, reproduce, distribute, republish, display, post or transmit in any form or by any means, any part of the Iris Platform to any third party. 3CE agrees not to access the Iris Platform by any means other than through the interfaces that are provided by CONTRACTOR.

Notwithstanding any conflicting terms of this Agreement, the Iris Platform and any and all works, expressions, inventions, ideas, discoveries, improvements and developments made to the Iris Platform by any person during the term of this Agreement, are explicitly excluded as "work for hire" pursuant to this Agreement.

Any data provided by 3CE to CONTRACTOR on the Iris Platform remains the property of 3CE and, upon request, shall be exported and/or deleted from the Iris Platform.

11.3 Iris Platform Terms of Use. All users of the Iris Platform shall be required to comply with the Iris Platform's standard Terms of Use, including 3CE employees who accesses the Iris Platform in connection DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 7 Contract Number: ______________
with the services; provided, however, that if any Terms of Use applicable to 3CE employees conflict with any provisions of this Agreement, with respect to 3CE's use of the Iris Platform in connection with the services, the provision of this Agreement shall control.

12. NON-DISCRIMINATION

12.1. During the performance of this Agreement, CONTRACTOR, and its subcontractors, shall not unlawfully discriminate against any person because of race, religious creed, color, sex, national origin, ancestry, physical disability, mental disability, medical condition, marital status, age (over 40), or sexual orientation, either in CONTRACTOR’s employment practices or in the furnishing of services to recipients. CONTRACTOR shall ensure that the evaluation and treatment of its employees and applicants for employment and all persons receiving and requesting services are free of such discrimination. CONTRACTOR and any subcontractor shall, in the performance of this Agreement, fully comply with all federal, state, and local laws and regulations which prohibit discrimination. The provision of services primarily or exclusively to such target population as may be designated in this Agreement shall not be deemed to be prohibited discrimination.

13. INDEPENDENT CONTRACTOR

13.1. In the performance of work, duties, and obligations under this Agreement, CONTRACTOR is at all times acting and performing as an independent contractor and not as an employee of 3CE. No offer or obligation of permanent employment with 3CE and CONTRACTOR shall not become entitled by virtue of this Agreement to receive from 3CE any form of employee benefits including but not limited to sick leave, vacation, retirement benefits, workers’ compensation coverage, insurance or disability benefits. CONTRACTOR shall be solely liable for and obligated to pay directly all applicable taxes, including federal and state income taxes and social security, arising out of CONTRACTOR’s performance of this Agreement. In connection therewith, CONTRACTOR shall defend, indemnify, and hold 3CE harmless from any and all liability which 3CE may incur because of CONTRACTOR’s failure to pay such taxes.

14. NOTICES

14.1. Notices required under this Agreement shall be delivered personally, by email, or by first-class, postage pre-paid mail to 3CE and CONTRACTOR’S contract administrators at the addresses listed below. In the case of email, Notices are considered received upon the date of confirmation of receipt or read receipt:

Central Coast Community Energy CONTRACTOR
Chief Financial Officer Contract Services
70 Garden Court, Suite 300 449 15th Street, Suite 400
Monterey, Ca 93940 Oakland, CA 94612
Email: [email protected] Email: [email protected] DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 8 Contract Number: ______________

15. MISCELLANEOUS PROVISIONS

15.1. Conflict of Interest. CONTRACTOR represents that it presently has no interest and agrees not to acquire any interest during the term of this Agreement, which would directly, or indirectly conflict in any manner or to any degree with the full and complete performance of the services required to be rendered under this Agreement.

15.2. Amendment. This Agreement may be amended or modified only by an instrument in writing signed by CCCE and the CONTRACTOR.

15.3. Waiver. Any waiver of any terms and conditions of this Agreement must be in writing and signed by 3CE and the CONTRACTOR. A waiver of any of the terms and conditions of this Agreement shall not be construed as a waiver of any other terms or conditions in this Agreement.

15.4. Contractor. The term “CONTRACTOR” as used in this Agreement includes CONTRACTOR’s officers, agents, and employees acting on CONTRACTOR’s behalf in the performance of this Agreement.

15.5. Disputes. CONTRACTOR shall continue to perform under this Agreement during any dispute.

15.6. Assignment and Subcontracting. The CONTRACTOR shall not assign, sell, or otherwise transfer its interest or obligations in this Agreement without the prior written consent of 3CE None of the services covered by this Agreement shall be subcontracted without the prior written approval of 3CE. Notwithstanding any such subcontract, CONTRACTOR shall continue to be liable for the performance of all requirements of this Agreement.

15.7. Successors and Assigns. This Agreement and the rights, privileges, duties, and obligations of 3CE and CONTRACTOR under this Agreement, to the extent assignable or delegable, shall be binding upon and inure to the benefit of the parties and their respective successors, permitted assigns, and heirs.

15.8. Compliance with Applicable Law. The parties shall comply with all applicable federal, state, and local laws and regulations in performing this Agreement.

15.9. Headings. The headings are for convenience only and shall not be used to interpret the terms of this Agreement.

15.10. Time is of the Essence. Time is of the essence in each and all of the provisions of this Agreement.

15.11. Governing Law. This Agreement shall be governed by and interpreted under the laws of the State of California.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 9 Contract Number: ______________

15.12. Non-exclusive Agreement. This Agreement is non-exclusive and both 3CE and CONTRACTOR expressly reserve the right to contract with other entities for the same or similar services.

15.13. Construction of Agreement. 3CE and CONTRACTOR agree that each party has fully participated in the review and revision of this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting party shall not apply in the interpretation of this Agreement or any amendment to this Agreement.

15.14. Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same Agreement.

15.15. Authority. Any individual executing this Agreement on behalf of 3CE or the CONTRACTOR represents and warrants hereby that he or she has the requisite authority to enter into this Agreement on behalf of such party and bind the party to the terms and conditions of this Agreement.

15.16. Integration. This Agreement, including the exhibits, represent the entire Agreement between 3CE and the CONTRACTOR with respect to the subject matter of this Agreement and shall supersede all prior negotiations, representations, or agreements, either written or oral, between 3CE and the CONTRACTOR as of the effective date of this Agreement, which is the date that 3CE signs the Agreement.

15.17. Interpretation of Conflicting Provisions. In the event of any conflict or inconsistency between the provisions of this Agreement and the Provisions of any exhibit or other attachment to this Agreement, the provisions of this Agreement shall prevail and control.

Energy Solutions Central Coast Community Energy
BY:__________________________________ BY:______________________________________ Title:_____________________________ Tom Habashi, CEO
Date: ____________________________ Date: ____________________________ Approved as to Form
BY:______________________________________
Brian Kimball, General Counsel
Date: ____________________________
DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B Director, Energy Efficiency
3/9/2022
3/11/2022
3/11/2022
3/9/2022 10 Contract Number: ______________
Approved as to Financial Terms
BY:______________________________________
Jaya Bajpai, Chief Financial Officer
Date: ____________________________
DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/10/2022
3/9/2022 11 Contract Number: ______________
Exhibit A: Scope of Services
Task 1 - Program Administration
Consultant will collaborate with CCCE to develop, implement, and manage the Program with activities including, but not limited to program budget and tracking and representing CCCE’s interests with third parties and participating contractors. Consultant will host monthly calls to review the status of goals, participant performance, and discuss potential issues and recommendations for improvement.

Activities:
• In Person meetings hosted once per month
Task 2 - Data Reports
Task 2a – Monthly Data Report
Consultant will provide reports to CCCE in a manner that enables confident decision-making and alleviates audit risk. To enable real-time reporting, our software platform, Iris, is designed to provide secure integrated data collection, and reports may be downloaded from Iris at any time. The fields included in these reports are flexible and will be configured to suit CCCE’s preferences.

Consultant will prepare a monthly report with a summary of current participation and performance indicators that are determined by Consultant and approved by CCCE.

These reports will be accessible either through the online application system, delivered via a secure file sharing website, or delivered based on agreed upon terms between CCCE and Consultant.

Deliverables:
• Monthly Report delivered once per month
Task 2b - Full Data Reports
All sales data collected from participants in claims, as well as all data documenting completed validation checks, eligible equipment specifications, and payments to participants, will be saved in Iris and will be available for use in all automated and manual QA/QC processes. Consultant will report on this data Program-to-date, which will include application-level fields such as equipment, installation, customer, and savings data.

Deliverables:
• Raw data provided ad hoc.

Task 3 - Contractor Outreach
Consultant will leverage trade ally outreach efforts of TECH to build and maintain a network of contractors, distributors, and manufacturers to support the Program and ensure contractors in CCCE territory are aware of the higher incentives sponsored by CCCE. Consultant will work with contractors to create installs in CCCE territory and provide support on how to submit applications through the DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 12 Contract Number: ______________
Incentive Clearinghouse. Contractors enrolled in TECH will automatically be enrolled in the CCCE program through an amendment to the TECH Trade Partner Participation Agreement.

Activities:
• Support for contractors in CCCE
Task 4 - Incentive Clearinghouse and Incentive Payments The Incentive Clearinghouse will be the central processing platform for all TECH incentives. This feature will be used for statewide, pilot, and regional incentives offered by TECH, and will be essential to scale and integrate new initiatives as building electrification is more widely adopted. The Incentive Clearinghouse will have the functionality to layer incentives across multiple program administrators. The goals of the Incentive Clearinghouse is to 1) simplify the participant experience by standardizing application requirements and the application submittal process, and 2) create a more comprehensive project data set for public reporting purposes.

Consultant will configure the incentive clearinghouse with Single Family and Multi-Family Incentives.

Consultant will pay process, QA/QC and pay incentives for CCCE on the clearinghouse. Payments to contractors will combine both CCCE and TECH incentives into a single check paid to participants to simplify the payment process.

Activities:
• Configuration of Incentive Clearinghouse with CCCE incentives • Processing and Payment of CCCE Incentive applications.

Estimated Percentage of Time Per Task:

Task Estimated Percent of Time
Task 1 – Program Administration 30%
Task 2 – Monthly Data Reports 20%
Task 3 – Contractor Outreach 20%
Task 4 – Incentive Clearinghouse 30%
Program Duration
Program duration is at the discretion of CCCE, but the current proposal assumes the program will run from July 1, 2022, through July 1st, 2025, or until the budget is spent.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 13 Contract Number: ______________
Program Incentives and Implementation
Incentive Plan
The below tables show the incentive values for HP HVAC and HPWH measures. In all cases, the incentive is limited by the project cost, which will be a required application field. The incentives will be available throughout CCCE territory.

Single Family Incentives
Heat Pump HVAC Measures
TECH plans to offer baseline incentives of $3,000 per unit to all Gas IOU customers in California. TECH is seeking to partner with other program administrators that want to provide incentives to support quicker adoption by supporting an enhanced incentive structure that offers up to $3,600 in additional incentives. Consultant proposes that CCCE funds $1,500 per HP HVAC installation, which will allow the TECH to provide complementary incentives for the installation of higher efficiency equipment with higher installation quality. These CCCE funded incentives will be paid by the Consultant and dispersed through the Incentive Clearinghouse with the TECH funds to provide a seamless experience to market actors.

Table 1: Unitary/Split System Heat Pump HVAC Incentives *Incentives available for installations providing full-home heating/cooling. Load calculations showing the installed mini-/multi-split serves full home will be required as part of the application. **TECH incentives are shown for display purposes and are subject to change based on TECH Program decisions.

Energy Solutions will inform CCCE of any potential changes to TECH incentives.

Table 2: Heat Pump HVAC Quality Installation Bonuses
Quality Installation Measure* Qualifier
CCCE
Incentive
per Unit
TECH
Incentive per
Unit**
Total
Incentive per
Unit
Manual J Completed Provide Calculations $0 $600 $600
Duct Testing and Sealing 5% Total leakage or less $0 $600 $600 Equipment
Type
Size
Category
Sub-Category Tier
Seasonal/Part-Load Cooling
Efficiency
HSPF
CCCE
Incentive
per Unit
TECH
Incentive
per
Unit**
Total
Incentive
per Unit
Unitary Split
System and
mini/multi-split
< 5.4 tons Ducted
Baseline HP Replacement $1,500 $1,500 $3,000
1 16.0 SEER 9.5 $1,500 $2,400 $3,900
2 18.0 SEER 10.0 $1,500 $3,300 $4,800
DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 14 Contract Number: ______________
Field Measured Performance
(based on ASHRAE 221-2020)
Heating System Performance Ratio (HSPr)
or Cooling System Performance Ratio
(CSPr) = 80% or better
$0 $600 $600
*Incentives only available as add-on bonuses to heat pump installation. **TECH incentives are shown for display purposes and are subject to change based on TECH Program decisions.

Energy Solutions will inform CCCE of any potential changes to TECH incentives.

The HP HVAC measures are for gas to heat pump conversion scenarios only. In all cases, the applicant must show that the gas equipment has either been fully decommissioned or setup to run in emergency scenarios only. In addition, the HP HVAC incentives are based on heat pumps that provide full-home heating and cooling. The incentives are available in cases when the customer does not have previous cooling.

CCCE would also be funding a low-income adder, with a flat rate of $1,000/unit.

Measure Qualifier
CCCE
Incentive
per Unit
TECH
Incentive
per Unit
Total
Incentive
per Unit*
Low-Income Kicker CARE/FERA enrollment $1,000 $0 $1,000 Heat Pump Water Heater Measures
The Program will offer incentives for customers converting from a gas, propane, or electric resistance water heater to HPWH. In all cases, the Program will require applicants to provide evidence of the previous unit’s fuel type to obtain the incentive. Like the HP HVAC measures, TECH plans to offer baseline incentives for HPWH’s but will offer an enhanced incentive structure (up to a total of $6,600) for partners that want to provide incentives for these technologies. The enhanced incentive structure will support additional incentives for replacing electric resistance water heaters and for panel upgrades needed in conjunction with HPWH installations. Consultant proposes that CCCE offer $1,500 for gas to electric conversions. These incentives will be funded by CCCE and distributed by the Consultant with the complimentary TECH incentives. This contribution of funding enables TECH to offer complimentary incentives that are more attractive for replacing electric resistance replacement, and enable electric panel upgrades, overcoming a major barrier to many installations.

Table 3: Heat Pump Water Heater Incentives
Previous WH Fuel
Type HPWH Capacity
CCCE
Incentive
per Unit
TECH
Incentive
per Unit*
Total
Incentive
per Unit
Natural Gas/Propane
< 55 Gallons $1,500 $1,600 $3,100
> 55 Gallons $1,500 $2,300 $3,800
Electric resistance All $0 $1,500 $1,500
*TECH incentives are shown for display purposes and are subject to change based on TECH Program decisions.

Energy Solutions will inform CCCE of any potential changes to TECH incentives.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 15 Contract Number: ______________
Table 4: Panel Upgrade/Smart Load Center Incentives
Measure Category Qualifier
CCCE
Incentive
per Unit
TECH
Incentive
per Unit**
Total
Incentive
per Unit
Panel upgrade Up to 200 amps
$1,000 $1,800 $2,800
Smart Load Center* None
*Incentives only available as add-on bonuses to heat pump water heater installation **TECH incentives are shown for display purposes and are subject to change based on TECH Program decisions.

Energy Solutions will inform CCCE of any potential changes to TECH incentives.

The incentive rates for natural gas or propane to HPWH are differentiated to support upsizing HPWHs to ensure the units have capacity to run primarily in heat pump mode, while also having load available to shift out of peak demand periods.

TECH will offer panel upgrade incentives for customers sizing up to 200 amps or installing a smart load center if the smart load center increases the effective panel capacity to support the added electrical load from the HPWH.

CCCE would also be funding a low-income adder, with a flat rate of $1,000/unit Measure Qualifier
CCCE
Incentive
per Unit
TECH
Incentive
per Unit
Total
Incentive
per Unit
Low-Income Kicker CARE/FERA enrollment $1,000 $0 $1,000 Consultant will re-evaluate incentive levels and participation after the first year, 2022, to determine whether the incentive design should be updated to meet the needs of CCCE and TECH. The soon to be released 120-volt “plug-in” HPWHs will be eligible for the incentive amount associated with the previous water heater fuel type. Consultant may establish a future measure category specifically available for the 120-volt HPWHs once more data on unit install cost are collected.

Multi-Family Incentives
Multifamily incentives are proposed to be 50% of current TECH offering for market rate incentives and 100% of the TECH incentives for low income. These incentives reflect similar incentives offered by other Program Administrators in the state and can be layered directly with the TECH incentives. This format will ensure that there is little confusion with multifamily contractors.

Gas to Electric HPWH
DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 16 Contract Number: ______________
Measure CCCE Market Rate
Incentives
CCCE Low
Income
Incentives
TECH
Layered
Incentives*
Gas/propane to HPWH - unitary $700 $1,400 $1,400
upsizing kicker Gas/propane to
HPWH - unitary
$350 $700 $700
non HPWH to HPWH - central $600 $1,200 $1,200
upsizing kicker non HPWH to
HPWH - central
$300 $600 $600
Panel/Electrical service upgrade $700 $1,400 $1,400
*TECH incentives are shown for display purposes and are subject to change based on TECH Program decisions.

Energy Solutions will inform CCCE of any potential changes to TECH incentives.

Gas to Electric HP HVAC Incentives
Measure CCCE Market Rate
Incentives
CCCE Low
Income
Incentives
TECH Layered
Incentives*
Split or Rooftop HP - individual apt. $1,000 $2,000 $2,000 PTHP, SPVHP, unitary through the
wall - individual apt.
$250 $500 $500
PTHP, SPVHP, unitary through the
wall - individual apt. (Variable
capacity/inverter driven (previous
heat source = all except PTHPs)
$500 $1,000 $1,000
HP HVAC - multiple apts. $500 $1,000 $1,000
Split or Rooftop HP - common area $900 $1,800 $1,800
PTHP, SPVHP, unitary through the
wall - common area
$150 $300 $300
PTHP, SPVHP, unitary through the
wall - common area (Variable
capacity/inverter driven, previous
heat source = non HP systems)
$400 $800 $800
Panel/Electrical service upgrade $700 $1,400 $1,400
*TECH incentives are shown for display purposes and are subject to change based on TECH Program decisions.

Energy Solutions will inform CCCE of any potential changes to TECH incentives.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 17 Contract Number: ______________
Exhibit B: Payment Terms
Incentive Reimbursement
Consultant will pay incentives and be reimbursed by CCCE to simplify payment process. Consultant will provide invoices with details of incentive payments as well as fixed price and performance payments in an agreed upon between Consultant and CCCE. Invoices will be submitted to CCCE by the 15th of each month.

Budget
Consultant will be compensated with an administration budget based on a fixed price (Fixed Price Start-Up Fee) and performance basis (Performance Payment). The Fixed Price Start-Up Fee and Performance Payment covers all the services in the Scope of Work. The Fixed Price Start-Up Fee covers costs associated with Program start-up, including 1) contractor outreach and enrollment across CCCE’s service area, 2) coordination with additional TECH activities, and 3) configuration of the Incentive Clearinghouse. The Program Implementation Fee covers ongoing services described in the Scope of Work. The Fixed Price Start-Up Fee shall be $50,000 and the Program Implementation Fee shall be 10% of all incentives paid out over $500,000. Associated with Program start-up, the Fixed Price Start-Up Fee will be invoiced upon receiving the Program’s first claim through the Incentive Clearinghouse and satisfactory demonstration of completed activities 1 – 3 above. Table 6 below provides the key performance indicators and budget for the Program.

Table 5: Budget and Participation Estimates
Key Metric Total
Estimated HP HVAC Units 667
Estimated HPWH Units 400
Incentive Reimbursement $1,600,000
Total Administration Costs $160,000
Fixed Price Start-Up Fee $50,000
Program Implementation Fee $110,000
Total Costs $1,760,000
Table 6. Budget per Category
Category Minimum Budget Maximum Budget Per Project
Single Family (SF) $600,000 $100,000*
Multi-Family (MF) $400,000 $100,000
Low-Income (SF or MF) $200,000 $200,000
*Includes large group single family projects such as a military base.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 18 Contract Number: ______________
These budgets per category are intended to promote geographic equity and diversity across the Program’s projects. Incentive caps per category may be changed through agreement with both parties and documented in email.

Exhibit C: Procedures for Unauthorized Release of Covered Information SCOPE
CONTRACTOR hereby agrees to adhere to these Procedures for detecting and reporting the unauthorized release of Covered Information, including Protected Personal Information (“PPI”).

These Procedures apply to the following unauthorized release activities:

1. Unauthorized access

2. Unauthorized destruction

3. Unauthorized use

4. Unauthorized modification

5. Disclosure to third parties for Secondary Purposes (see below)

DEFINITIONS
Covered Entity – (1) any Community Choice Aggregator or Electrical Service Provider (when providing service to residential or small commercial customers), or any third party that provides services to a Community Choice Aggregator or Electrical Service Provider (when providing service to residential or small commercial customers) under contract, (2) any third party who accesses, collects, stores, uses or discloses covered information pursuant to an order of the Commission, unless specifically exempted, who obtains this information from an electrical corporation, a Community Choice Aggregator or an Electrical Service Provider (when providing service to residential or small commercial customers), or (3) any third party, when authorized by the customer, that accesses, collects, stores, uses, or discloses covered information relating to 11 or more customers who obtains this information from an electrical corporation, a Community Choice Aggregator or an Electrical Service Provider (when providing service to residential or small commercial customers).

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 19 Contract Number: ______________
Covered Information -- any usage information obtained through the use of the capabilities of Advanced Metering Infrastructure when associated with any information that can reasonably be used to identify an individual, family, household, residence, or non-residential customer, except that covered information does not include usage information from which identifying information has been removed such that an individual, family, household or residence, or non-residential customer cannot reasonably be identified or re-identified. Covered information, however, does not include information provided to the California Public Utilities Commission (the “Commission”) pursuant to its oversight responsibilities.

Primary Purposes – The “primary purposes” for the collection, storage, use, or disclosure of covered information, as outlined in Rule 1(c) of Attachment B, are to:

1. Provide or bill for electrical power or gas,

2. Provide for system, grid, or operational needs,

3. Provide services as required by state or federal law or as specifically authorized by an order of the Commission, or

4. Plan, implement, or evaluate demand response, energy management, or energy efficiency programs under contract with a Community Choice Aggregator or and Electrical Service Provider (when providing service to residential or small commercial customers), under contract with the Commission, or as part of a Commission authorized program conducted by a governmental entity under the supervision of the Commission.

Secondary Purposes – “Secondary purpose” means any purpose that is not a primary purpose.

Non-Covered Entity – “Non-Covered Entity” means any entity not defined as a Covered Entity.

Responsible Parties -- 3CE, CONTRACTOR, and any staff, employees, or sub consultants contracted by 3CE or CONTRACTOR.

PROCEDURE
Detecting and Reporting of Unauthorized Releases

1. All Responsible Parties are required to protect Covered Information from unauthorized release activities as set forth above.

2. Any request by any non-Covered Entities, for access to Covered Information must be reviewed and approved by an 3CE manager level employee to ensure no unauthorized or inadvertent release of Covered Information.

3. All authorized releases of Covered Information to Non-Covered Entities shall be logged and reported to 3CE on a quarterly basis.

4. Any discovery of any unauthorized release of Covered Information must be reported to 3CE within one week of detection.

Unauthorized Release Handling Procedure

1. The discovering party after detecting, or discovery of, the unauthorized release of Covered Information must contact 3CE’s Dir. of Finance and Administration (or another executive manager) immediately.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B 3/9/2022 20 Contract Number: ______________

2. CONTRACTOR will quantify and validate the type and extent of unauthorized release and report that information to 3CE’s Dir. of Finance and Administration in writing with sufficient detail for 3CE to determine the extent and impact of the unauthorized release.

3. CONTRACTOR shall prepare a written annual report of all discoveries of unauthorized releases of Covered Information.

Review and Training

1. At least annually, CONTRACTOR will review these Procedures with its staff, employees, or sub consultants.

2. Any proposed changes to these Procedures shall be provided in writing to 3CE’s Dir. of Finance and Administration for their consideration.

DocuSign Envelope ID: D2DC84CA-DDED-44EC-B04E-3C8EFC07B99B Staff Report Item 7
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Hilary Staver, Director of Regulatory Affairs and Compliance SUBJECT: Approve and authorize CEO to execute Amendment No. 1 to the agreement with Bruan, Blaising & Wynne, P.C. to increase contractual not to exceed amount from $130,000 to $145,000 for additional regulatory services support for the 2022-2023 fiscal year DATE: 8/9/2023
RECOMMENDATION:

Approve and authorize CEO to execute Amendment No. 1 to the agreement with Bruan, Blaising & Wynne, P.C. to increase contractual not to exceed amount from $130,000 to $145,000 for additional regulatory services support for the 2022-2023 fiscal year.

BACKGROUND:

Braun, Blaising & Wynne, P.C. (BB&W) provides external regulatory counsel services, including filing compliance filings, comments, and other documents for 3CE at state regulatory agencies; facilitating joint regulatory advocacy by groups of CCAs; monitoring and reporting on regulatory agency activities; and performing legal and regulatory research.
3CE’s current contract with BB&W is a two-year agreement ending September 30, 2024. The amendment before the Board increases the not-to-exceed amount of the contract in order to accommodate the unusually high amount of engagement required this year, especially around the changing rules and processes associated with the Resource Adequacy (RA) program.

DISCUSSION/ANALYSIS:

External regulatory counsel serves several important functions in 3CE’s policy work, and as 3CE’s primary external regulatory counsel BB&W performs all of them. Most importantly, regulatory counsel facilitates successful participation in state regulatory agency stakeholder proceedings. 3CE engages most often with the California Public Utilities Commission (CPUC) but also with the California Energy Commission (CEC) and the California Air Resources Board (CARB). Each agency has unique rules and procedures that must be followed in order to provide input on potential new regulations and demonstrate compliance with existing ones. BB&W’s attorneys assist 3CE in both the development and filing of compliance reports, comments, and other documents necessary to ensure that 3CE meets its compliance obligations and is represented in the policymaking conversation.

Second, external counsel plays an important role in inter-CCA advocacy collaboration. In areas where the statewide CCA trade organization is not active, the CCA community is often represented by a group of CCAs working together to develop positions and file comments and testimony supporting them.

External legal counsel representing these CCAs jointly serves as an organizing point for the group, providing space for discussion and drafting the filings based on the consensus of the group.

Finally, regulatory counsel serves an important monitoring and research function, drawing on the legal history of CCAs to help solve problems and answer new questions as they arise in the present. BB&W is one of the most experienced and active legal firms in California on CCA regulatory and policy issues, and 3CE benefits from access to their knowledge of CCA legal and regulatory history.

FISCAL IMPACT:

The Board’s approval will increase Braun, Blaising & Wynne, P.C.’s budgeted annual $130,000 not to exceed cap by an additional $15,000 for the Fiscal Year 2022-2023.

CONCLUSION:

The Board’s approval and direction enables CCCE to obtain continued regulatory support from Braun, Blaising & Wynne, P.C., by increasing the current annual not to exceed cap of $130,000 by an additional $15,000 for the Fiscal Year 2022-2023.

ATTCHMENT(S):

1. Third Legal Services Agreement

2. Amendment One to the Third Agreement
1 Third Legal Services Agreement
This Third Legal Services Agreement (Agreement), effective as of latest date set forth in the signature block, is entered into by and between Central Coast Community Energy (Client), and Braun Blaising & Wynne, P.C., a California professional corporation (Firm). The Firm and the Client shall be collectively referred to herein as the Parties.

A. The Firm provides regulatory and legal services related to, among other things, rates, rules, policies and regulations affecting Community Choice Aggregation (CCA) programs.

B. The Parties entered into legal services agreements, dated July 5, 2018 (First Agreement) and August 14, 2019, as amended on August 14, 2020, and November 5, 2021, (Second Agreement), by which the Firm has been providing legal and regulatory services in support of the Client’s CCA program, including the provision of certain joint services provided by the Firm to the Client and other CCA clients (CCA Group).

C. The Parties are interested in entering into this Agreement to replace the currently effective Second Agreement, as amended, and to set forth the terms and conditions, and budgetary limitation, associated with the Firm’s provision of legal and regulatory services.
- Agreement -

The Parties agree as follows:

1. Term and Termination. This Agreement shall be effective on October 1, 2022, and shall continue in effect through September 30, 2024, unless earlier terminated as described below. The Second Agreement, as amended, shall terminate on the effective date of this Agreement. For the avoidance of doubt, it is the intention of the Parties that this Agreement shall succeed and replace services provided under the Second Agreement, such that there is no lapse in services provided by the Firm to the Client. Either Party may terminate this Agreement by providing no less than 30 days written notice.

2. General Scope of Services. The Firm shall provide (a) regulatory and legal services, as directed and authorized by the Client, in support of the Client’s CCA program, as described further in Section 3(a), (b) joint representation of Client and other participants in the CCA Group on matters before California regulatory agencies, as described further in Section 3(b), and (c) joint reporting services provided by the Firm to the Client and to the CCA Group, as described further in Section 3(c).
/
DocuSign Envelope ID: D46CA6AA-BBE1-495A-9999-FE2E2DFDC658 2 3. Fees and Description of Services.
(a) Individual Client Services: For services provided under this Agreement directly to the Client, as requested and authorized by the Client, the Client shall pay the Firm in accordance with the following hourly rates for the following categories:

Senior Shareholders: $450
Junior Shareholders: $400
Senior Attorney: $370
Senior Associates: $345
Junior Associates: $300
Paralegal / Law Clerk: $170
Administrative Assistant: $65
(b) Joint Representation: As authorized by the Client and other clients in the Firm’s CCA Group, the Firm shall provide joint representation on various regulatory matters at the California Public Utilities Commission (CPUC). The Client’s share of such joint services shall generally be its pro-rata share, but in any event shall be described to and authorized by the Client. Costs associated with joint representation shall generally be setup as a separate matter in the Firm’s accounting system. Further information regarding joint representation is described in Section 8.
(c) Regulatory Reports and Summaries: The Firm provides a variety of regulatory reporting services. On a fixed-fee basis, the Firm shall continue to provide regulatory reports on the same basis as provided under the Second Agreement, namely (1) a bi-weekly, comprehensive regulatory report, (2) alternate week email regulatory bulletins (3) agenda summaries of energy-related items on the CPUC’s meeting agenda and (4) an email report on the outcome of energy-related items on the CPUC’s meeting agenda. The current monthly fee for this service is $1,750 but may be adjusted upward or downward based on mutual written agreement of the Parties. In addition to these regulatory reports, the Firm also provides regulatory summaries of issues and activities of interest to the CCA Group. The cost of this service will be shared on a pro-rata basis among participating clients. At any time, upon written notice from the Client, the Client may suspend or modify the scope of either the regulatory reports or the regulatory summaries.
(d) Hourly Rates: All office, research, and meeting time shall be billed at the hourly rates set forth above.
(e) Annual Adjustment: The hourly rates for services provided under this Agreement, including the hourly rate for any contract attorney(s), are reviewed annually by the Firm on or about June 1, and are subject to adjustment on no less than 30 days written notice. (f) Not to Exceed Budget: The total amount of charges under this Agreement shall not exceed $130,000 per contract year (or a total of $260,000) without the express written consent of the Client. The Firm will make reasonable efforts to inform the Client two months before the Firm believes that charges under this agreement will likely exceed $104,000 in a given year.

DocuSign Envelope ID: D46CA6AA-BBE1-495A-9999-FE2E2DFDC658 3 (g) Other Attorney(s): As needed and as authorized by the Client, the Firm may contract with other attorney(s) to provide services under the guidance and direction of the Firm’s assigned attorney (Scott Blaising). The Firm will provide advance notice to the Client of the hourly rates for attorneys with whom the Firm has contracted for services provided under this Agreement. The Client will be billed at the specified hourly rate for the contract attorney(s) regardless of the amount of charge to the Firm for services provided by the contract attorney(s). (h) Other Providers: As needed and as authorized by the Client, the Firm may contract with electric industry professionals (e.g., rate consultants, etc.) (Other Provider(s)) in order to perform Client-directed tasks. In the event that such tasks are authorized, and the Client wishes the Firm to pay Other Providers on the Client’s behalf, the Client and the Firm will agree on a reasonable administrative fee for consolidated billing, not to exceed 10%.

4. Costs and Expenses. In addition to the fees set forth above, the Client shall reimburse the Firm for all pre-approved out-of-pocket costs and expenses actually incurred by the Firm in connection with the legal services provided by the Firm. Out-of-pocket costs and expenses include, but are not necessarily limited to, travel expenses, and reproduction and postage costs associated with representation of the Client in regulatory or other legal proceedings. Reproduction and postage costs otherwise incurred in the normal course of business are considered Firm overhead and will not directly be charged to the Client.

5. Billing and Payment. The Firm shall provide monthly invoices to the Client for all fees and expenses. The invoice shall be itemized to include, at a minimum, the time spent by each service provider, the total time spent by each service provider, a description of services performed, and a description and itemization of costs and expenses. The Firm shall bill the Client in minimum increments of 1/10th of an hour. Invoices shall be considered due and payable upon receipt and shall be overdue after 30 days of receipt.

6. Notices. All notices, invoices, reports or other communication required herein shall be properly given if delivered via electronic mail, or other mutually acceptable means, to the following addresses:

Client: Central Coast Community Energy
Attention: Hilary Staver
[email protected]
Firm: Braun Blaising & Wynne, P.C.

Attention: Scott Blaising
[email protected]

7. Independent Contractor. The Firm is and shall be considered an independent contractor with respect to the performance of services under this Agreement.

8. Joint Representation and Conflict Waiver.

DocuSign Envelope ID: D46CA6AA-BBE1-495A-9999-FE2E2DFDC658 4 (a) The Firm currently represents several clients that have operational CCA programs. The Firm also represents the California Community Choice Association, an association of CCA programs. (See Exhibit A, which reflects the Firm’s current list of clients.) Together with the Client, these CCA clients shall be referred to below as “CCA Clients.” The Firm anticipates that it will from time to time provide joint representation of the CCA Clients before the CPUC, whether directly or indirectly through a coalition or other organizational structure. This section generally describes the contemplated joint representation and requests written consent to the Firm’s joint representation. This section also describes potential conflicts and requests written consent to the Firm’s continuing representation in such circumstances. (b) The Firm does not believe that the Firm’s joint representation of the CCA Clients presently involves any actual conflicts of interest. The Client should be aware, however, that such representation may involve potential conflicts and that the interests and objectives of each of the participants individually on certain issues may, at some time in the future, become inconsistent with the interests and objectives of the other participants. The Firm’s joint representation has implications, which the Client should consider. For example, rather than vigorously asserting a single participant's interest on an issue, it is likely that the Firm will balance interests between the participants represented. Because individual participants may have different talents, energy, personal goals, and financial resources, sole representation of one participant could result in more aggressive advocacy, and hence more favorable treatment, for that participant compared to the more even-handed approach the Firm may follow in representing multiple interests. Joint representation may also result in the loss of the attorney-client privilege for communications between you and members of the Firm, because anything disclosed by one participant on a matter of common interest could be disclosed to a jointly represented client in a civil proceeding between the two participants. (c) The Firm will make every effort during the course of joint representation to confirm that the participants continue to have a commonality of interest in connection with the positions asserted. If interests diverge during the course of joint representation, further disclosure and waiver of the conflict, or withdrawal from representation, could be necessary. (d) In addition to the joint representation described above, the Firm also represents numerous public agencies in California on diverse matters of energy law and regulation. Therefore, it is possible that, while the Firm is representing the Client, certain types of conflicts may arise in matters unrelated to the present engagement for which the Firm requests the Client’s consent and waiver now. Present or future clients, including clients who rely upon the Firm for general representation, may ask the Firm to represent them in transactions or litigation adverse to the Client. The Firm would decline the other representation if the Firm believes there is a risk of misuse of the Client’s confidential information. (e) By signing this Agreement, the Client confirms (i) that the Client has been informed as to the nature of potential conflicts that may arise as a result of the Firm’s joint representation and the Firm’s representation of other clients; (ii) that the Client has been provided a reasonable opportunity to seek the advice of independent counsel regarding potential conflicts and waiver thereof; (iii) that the Client understands an actual conflict may arise in the future that would require an additional disclosure and waiver, or, alternatively, withdrawal by the Firm; (iv) that the Client agrees that the Firm may represent other clients as described herein, DocuSign Envelope ID: D46CA6AA-BBE1-495A-9999-FE2E2DFDC658 5 including clients in unrelated matters adverse to the Client; and (v) that the Client hereby waives any claim of conflict of interest arising from such representation.

9. Insurance
(a) Malpractice Insurance. Without limiting the provisions of this Agreement relating to indemnification and defense, the Firm, at its expense, shall maintain in full force and effect during the period of performance of this Agreement and for three years thereafter, professional malpractice insurance that covers the services provided pursuant to this Agreement in the amount of not less than $1,000,000, with an insurance carrier authorized to do business in California.
(b) Other Insurance. The Firm, at its expense, shall also maintain during the period of performance of this Agreement and for three years thereafter, insurance as follows:
(1) General liability: (with coverage at least as broad as ISO form CG 00 01 10 01) coverage in an amount not less than $2,000,000 general aggregate and $1,000,000 per occurrence for general liability, bodily injury, personal injury, and property damage.
(2) Automobile liability: (with coverage at least as broad as ISO form CA 00 01 10 01, for “any auto”) coverage in an amount not less than $1,000,000 per accident for personal injury, including death, and property damage.
(3) Workers' compensation and employer's liability: coverage shall comply with the laws of the State of California.
(c) Primary. The Firm’s insurance is primary to any other insurance available to the Client with respect to any claim arising out of this Agreement. Any insurance maintained by the Client shall be excess of the Firm’s insurance and shall not contribute with it.

The Firm’s endorsement of insurance shall include a waiver of any rights of subrogation against the Client, and its directors, officers, employees and agents.

10. Miscellaneous.
(a) This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of California, exclusive of conflict of laws provisions. (b) This Agreement constitutes the entire agreement between the Parties concerning the subject matter hereof.
(c) This Agreement may not be modified or amended without the express written agreement of the Parties.
(d) This Agreement may be executed in any number of counterparts, including through facsimile signatures, and upon execution by the Parties, each executed counterpart shall have the same force and effect as an original document and as if the Firm and DocuSign Envelope ID: D46CA6AA-BBE1-495A-9999-FE2E2DFDC658 6 the Client had signed the same document. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form but having attached to it one or more signature pages. (e) This Agreement may be scanned and stored in electronic format. Neither Party shall object to the admissibility of an electronic version of this Agreement on the basis that such was not originated or maintained in documentary form.

11. Signature. In witness whereof, the Parties have caused this Agreement to be executed by their duly authorized representatives.

Client Firm
________________________
Scott Blaising
Title: Principal/Shareholder
__________________________
Tom Habashi
Title: CEO
Date: ________________ Date: ________________
Approved as to Form
__________________________
Brian Kimball, General Counsel
Approved as to Financial Terms
_____________________________
Jaya Bajpai, Chief Financial Officer
DocuSign Envelope ID: D46CA6AA-BBE1-495A-9999-FE2E2DFDC658 9/30/2022
Exhibit A
Representative List of Clients
Braun Blaising & Wynne, P.C.
(September 2022)

Balancing Authority of Northern California (BANC)
California Choice Energy Authority (CalChoice)
Cities of Lancaster, Pico Rivera, Pomona, Rancho Mirage, San Jacinto, and Santa Barbara California Community Choice Association (CalCCA)
California Community Power (CC Power)
California Municipal Utilities Association (CMUA)
Central Coast Community Energy
Clean Energy Alliance
Clean Power Alliance of Southern California
City of Cerritos
City of Colton
City of Corona
East Bay Community Energy
Eastside Power Authority
City of Escondido
Friant Power Authority
City of Indio
City of Industry
Kirkwood Meadows Public Utilities District
Lamb Energy (City of Coachella)
Lathrop Irrigation District
City of Los Angeles, Department of Water and Power
Marin Clean Energy
Merced Irrigation District
Minter Field Airport District
City of Moreno Valley
City of Needles
Orange Cove Irrigation District
City of Pasadena
City of Pittsburg (Pittsburg Power Company)
Peninsula Clean Energy Authority
Pioneer Community Energy
Port of Stockton
Power and Water Resources Pooling Authority (PWRPA)
City of Rancho Cucamonga
City of Redding
Redwood Coast Energy Authority
City of Roseville
Sacramento Municipal Utility District (SMUD)
Salt River Project
San Diego Community Power
San Luis and Delta-Mendota Water Authority
Seattle City Light
City of San Jose
City of Shasta Lake
Silicon Valley Clean Energy
Sonoma Clean Power Authority
Southern California Public Power Authority
Turlock Irrigation District
University of California (Office of the President)
City of Victorville
DocuSign Envelope ID: D46CA6AA-BBE1-495A-9999-FE2E2DFDC658 Amendment No. 1 To Third Legal Services Agreement Between Braun, Blaising, & Wynne, P.C. and Central Coast Community Energy Page 1 of 2
AMENDMENT NO. 1

TO THIRD LEGAL SERVICES AGREEMENT BETWEEN
BRAUN, BLAISING, & WYNNE, P.C. AND

CENTRAL COAST COMMUNITY ENERGY
This Amendment No. 1 to the Third Legal Services Agreement (“Agreement”) which was effective on September 30, 2022, is entered into by and between CENTRAL COAST COMMUNITY ENERGY (“3CE”) and BRAUN, BLAISING, & WYNNE, P.C. (hereinafter “CONTRACTOR” or “BB&W”), a California professional corporation with its principal place of business located at 555 Capitol Mall, Suite 570, Sacramento, California 95814. 3CE and CONTRACTOR are referred to individually herein as “Party,” or collectively, as the “Parties”, with respect to the following:

RECITALS
WHEREAS, 3CE and CONTRACTOR entered into the Third Legal Services Agreement (the “Original Agreement”) for provision of regulatory counsel services on September 30, 2022, with a two-year term to expire on September 30, 2024, and WHEREAS, the Original Agreement specified not-to-exceed amounts of $130,000 per contract year or a total of $260,000, and
WHEREAS, evolving regulatory conditions have increased 3CE’s need for regulatory counsel services.

AGREEMENT
NOW, THEREFORE, the Parties agree to amend the Agreement as follows:

1. Section 3.f is amended as follows:
3(f) Not to Exceed Budget:

For the Period October 1, 2022, through September 30,2023, the Not to Exceed Amount is $145,000 per contract year.

For the Period October 1, 2023, through September 30,2024, the Not to Exceed Amount is $130,000 per contract year.

The total amount of charges under this Agreement shall not exceed a total of $275,000 without the express written consent of the Client. The Firm will make reasonable efforts to inform the Client two months before the Firm believes that charges under this agreement will likely exceed $104,000 in a given year.

Amendment No. 1 To Third Legal Services Agreement Between Braun, Blaising, & Wynne, P.C. and Central Coast Community Energy Page 2 of 2

2. A copy of this Amendment No.1 shall be attached to the Original Agreement.

3. This Amendment No. 1 shall be effective when signed by both parties.

IN WITNESS WHEREOF, the parties hereto have set their hands the day and year first above written.

Vendor Central Coast Community Energy
BY:__________________________________ BY:______________________________________ Title:Scott Blaising, Principal/Shareholder Robert M. Shaw, Chief Executive Officer Date: ____________________________ Date: ____________________________ Vendor Approved as to Form
BY:__________________________________ BY:___________________________________ Title:_____________________________ Charles McKee, General Counsel Date: ____________________________ Date: ____________________________ Approved as to Financial Terms
BY:______________________________________
Dewayne Woods, Chief Financial Officer
Date: ____________________________
Staff Report Item 8
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dennis Dyc-O’Neal, Chief Operations Officer SUBJECT: Approve an amendment to the Agreement with Hall Energy Law, PC (“Hall Energy”) for specialized legal services to add $60,000, increasing the not to exceed from $150,000 to $210,000 for the 2022-23 Fiscal Year
DATE: August 9, 2023
RECOMMENDATION:

This recommends the Operations Board of Directors approve an amendment to the agreement with Hall Energy Law, PC (“Hall Energy”) for specialized legal services to add $60,000, increasing the not to exceed from $150,000 to $210,000 for the 2022-23 Fiscal Year.

BACKGROUND:
3CE engaged Hall Energy under various agreements since 2019 for specialized legal services to support the negotiation of power and related product negotiations, energy supply agreements, coordinated operations agreements, and the administration and implementation of 3CE’s long-term power purchase agreements.

At its September 2020 meeting, the Operations Board approved a new engagement with Hall Energy with a not to exceed cap of $150,000 per fiscal year (“Agreement”).

DISCUSSION/ANALYSIS:

During the current fiscal year 2022-2023, Hall Energy has supported several unplanned procurement contract re-negotiations fueled primarily by the impacts related to the global supply chain disruptions and permitting delays. Additionally, the legal services required for supporting our prepay activities has been more than anticipated.

The Agreement establishes a not to exceed cap of $150,000 per fiscal year, but also enables the parties to agree to additional services above the cap, should it be needed.

The current spending to date in fiscal year 2022-2023 has been higher than planned, and the anticipated legal support services needed from Hall Energy for the remaining months is expected to exceed the current cap by approximately $60,000.

FISCAL IMPACT:

The Board’s approval will increase Hall Energy Law’s budgeted annual $150,000 not to exceed cap by an additional $60,000 for the Fiscal Year 2022-2023.

CONCLUSION:

The Board’s approval and direction enables CCCE to obtain continued legal support from Hall Energy by increasing the current not to exceed cap of $150,000 by an additional $60,000 for the Fiscal Year 2022- 2023.

ATTACHMENT(S):

1. Hall Energy Law Engagement Agreement
Hall Energy Law PC | www.hallenergylaw.com | 3 Monroe Pkwy. Ste. P #406, Lake Oswego, OR 97035

HALL ENERGY LAW PC
Stephen Hall | 503-313-0755 | [email protected]
November 20, 2020

VIA EMAIL
Central Coast Community Energy
Attention: Tom Habashi
70 Garden Court #300
Monterey, CA 93940
Re: Representation of Central Coast Community Energy
Dear Tom:

We are pleased that you have requested Hall Energy Law PC (the “Firm”) to continue providing legal services to Central Coast Community Energy, (formerly, Monterey Bay Community Power Authority ) and we thank you for the opportunity to be of assistance.

This engagement letter (the “Agreement”) sets forth the scope of our engagement, the financial terms of our engagement, and all other aspects of this engagement, as follows:

1. Scope of Engagement. By means of this Agreement, 3CE is engaging the Firm to continue to provide legal services in connection with 3CE’s procurement of energy, renewable energy and related products, including but not limited to the review, drafting, revision, negotiation, and finalization of, or amendments to, (i) EEI Master Agreements and Cover Sheets, amendments to the WSPP agreement, confirmations and any supporting credit documentation such as parent guarantees and letters of credit (collectively, the “Energy Supply Agreements”), (ii) deposit account control agreements, intercreditor and collateral agency agreements, and security agreements entered into by 3CE (the “Lockbox Agreements”), (iii) development of a Coordinated Operations Agreement (“COA”) for administration and implementation of long-term power purchase and sale agreements (“PPAs”), and (iv) follow-on support in connection with the PPAs already acquired, and additional negotiations, if any, and (v) procurement of additional renewable energy and miscellaneous legal advice and analysis, including but not limited to, advice related to any potential bankruptcy by Pacific Gas & Electric, or services related to any of the foregoing (“Other Services”). The Firm and MBCP acknowledge and anticipate that 3CE may, from time to time, engage in Joint RFO proceedings with other CCAs. The legal services relating to the Energy Supply Agreements, the Lockbox Agreements, Additional Follow-Up, and the Other Services are collectively referred to below as the “Engagement.”

2. Term. The term of this Agreement shall commence as of October 1, 2020 and shall continue indefinitely and at least until the completion of the case(s) or matter(s) assigned by CCA to FIRM hereunder, unless earlier terminated as set forth herein (the “Term”), or until terminated DocuSign Envelope ID: CE35727D-C5ED-473E-9F3B-E84C0EFC81DF Monterey Bay Community Power Authority
November 20, 2020
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by either party by providing thirty (30) days’ written notice of its intent to terminate this Agreement, subject to payment of any amounts owed for services previously rendered and, if requested by 3CE, completion of any partially completed projects.

3. Fees and Hourly Rates. Our billing practice is to charge for our legal services, based primarily on the amount of time, including travel time, devoted to a matter at hourly rates for the particular professionals involved. These hourly rates are based upon these professionals’ experience, expertise, and standing. I will be the attorney responsible for the performance of the Engagement and my hourly rate for this work is $595/hr. Where appropriate, I may use junior attorneys on this Engagement and the hourly rates for their work would typically range from $375- $540/hr. These rates are modified by the Firm from time to time, and any new rates would be implemented on a prospective basis and would apply only to legal services rendered after the effective date of the new rates.

The Firm and 3CE agree that 3CE will be responsible for only a portion of the costs for legal services related to Joint RFO procurement efforts, the allocation of which will be determined and agreed to in writing before commencement of new work relating to the Joint RFO procurement efforts between the Joint RFO members. Notwithstanding the foregoing, existing arrangements between the Joint RFO members for allocation of costs for ongoing work that was commenced prior to, and which is still in progress as of, October 1, 2020 will remain in place, unless subsequently amended by the Joint RFO members in writing, and with notice to the Firm.

The total amount of legal services for the Engagement for the Term shall not exceed one hundred and fifty thousand dollars ($150,000.00) per fiscal year (the “NTE Cap”) without the written approval of 3CE, it being understood by 3CE that the NTE Cap does not necessarily represent the total fees to complete all of the matters in the Engagement because of the nature of such projects. 3CE will not be responsible for any fees incurred in excess of the NTE Cap unless expressly authorized by 3CE in writing. If additional legal services are required that extend beyond the NTE Cap, 3CE and the Firm shall agree in writing to the scope and cost of such additional services.

We believe that our hourly rates are comparable with the rates charged for the same kinds of work by lawyers and other professionals of similar experience, expertise and standing. We try to use associate and paralegal support on projects where appropriate, and we will be happy to discuss the staffing of 3CE’s project with you.

We will charge for all activities undertaken in providing legal services to 3CE under this Agreement, including but not limited to the following: conferences, including preparation and participation; preparation and review of correspondence and other documents; legal research; court and other appearances; including preparation and participation; and telephone calls, including calls with you, other attorneys or persons involved with this matter, and governmental agencies. The legal personnel assigned to 3CE’s matter will confer among themselves about the matter, as required. When they do confer, each person will charge for the time expended. Likewise, if more than one of our legal personnel attends a meeting, court hearing or other proceeding, each will charge for the time spent. We will charge for travel time, both local and out of town.

DocuSign Envelope ID: CE35727D-C5ED-473E-9F3B-E84C0EFC81DF Monterey Bay Community Power Authority
November 20, 2020
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4. Additional Services and Outside Expenditures. If our legal representation requires additional services provided by vendors, we will obtain your advance approval before incurring any such additional services on 3CE’s behalf. 3CE will be required either to pay for these outside additional services directly, or to reimburse us if we make payment for these services on 3CE’s behalf. We sometimes will make payment for, and then bill 3CE for reimbursement of smaller items such as filing fees, photocopying by outside copying services, electronic discovery services, recording fees, messenger services, service of process, and court fees. When there are substantial expenditures involving vendors (such as for discovery management, document production, depositions, expert witnesses, exhibit preparation, or air fare) or substantial out-of-pocket expenditures (such as extended field expenses, large outside copying jobs, or jury fees), we will require either that 3CE pay those sums to us before we expend them, that 3CE provide an advance deposit for such expenditures, or that 3CE directly contract with and pay the vendor. 3CE will not be billed for any internal Firm costs incurred on 3CE’s behalf, such as telephone (including long distance charges), telecopy charges, word processing, secretarial overtime, firm couriers, postage (including FedEx, UPS or similar overnight delivery services), printing and photocopying performed in-house.

5. Monthly Statements and Payment Terms. Our practice will be to send a monthly statement of our charges for legal services and for reimbursement of payments made on our client’s behalf for outside additional services. The detail in the monthly statement will inform 3CE of the nature and progress of our work and of the charges and expenditures being incurred.

Unless otherwise agreed, each monthly statement is fully due and payable upon receipt, but in no event later than thirty (30) days after its issuance date.

We specifically reserve the right to withdraw from representation of 3CE and to cease performing immediately all services if we do not receive full payment of any amounts owed to us within forty-five (45) days of any statement.

6. Withdrawal From Representation. The attorney-client relationship is one of mutual trust and confidence. If you have any questions at all about the provisions of this Agreement, we invite your inquiries. We encourage our clients to inquire about any matter relating to our engagement agreements or monthly statements which may be in any way unclear or appear unsatisfactory. If 3CE does not meet its obligation of timely payments or deposits under this Agreement, we reserve the right to withdraw from 3CE’s representation on that basis alone, subject of course to any required judicial, administrative, or other approvals.

This Agreement is also subject to termination by either party upon reasonable notice for any reason. If there were to be such a termination, however, 3CE would remain liable for all unpaid charges for services provided and expenditures advanced or incurred.

7. Duties Upon Termination of Active Representation. Upon termination of our active involvement in a particular matter for which we had previously been engaged, we will have no further duty to inform you of future developments or changes in law which may be relevant to such matter in which our representation has terminated. Further, unless 3CE and the Firm agree in writing to the contrary, we will have no obligation to monitor renewal or notice dates or similar deadlines which may arise from the matters for which we had been engaged. If 3CE’s matter DocuSign Envelope ID: CE35727D-C5ED-473E-9F3B-E84C0EFC81DF Monterey Bay Community Power Authority
November 20, 2020
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involves obtaining a judgment and such judgment is obtained, we will only be responsible for those post judgment services (such as recording abstracts, filing judgment liens, and calendaring renewals of judgments) as are expressly agreed to by 3CE and the Firm in writing and for which 3CE will be obligated to pay.

8. Document Storage Policies. The Firm’s policy with regard to documents and other materials at the conclusion of a matter is to maintain them in storage for a period of no more than ten (10) years. All documents and other materials in our file will then be destroyed or discarded without notice to 3CE. Accordingly, if there are any documents or other materials 3CE wish to have retrieved from 3CE’s file at the conclusion of a matter, it will be necessary for 3CE to advise us of that request to ensure that they are not destroyed.

9. Consent to Electronic Communications. In order to maximize efficiency in this matter, we intend to use state of the art communications devices to the fullest extent possible (e.g., Email, document transfer by computer, cellular telephones, and facsimile transfers). The use of such devices under current technology may place 3CE’s confidences and privileges at risk. However, we believe the effectiveness involved in use of these devices outweighs the risk of accidental disclosure. By signing this letter, you acknowledge your consent to the use of these devices.

10. Disclaimer of Guarantee. Nothing in this Agreement should be construed as a promise or guarantee about the outcome of any matter which we are handling on 3CE’s behalf. Our comments about the outcome of 3CE’s matter are expressions of opinion only.

If we should provide you with an estimate of the fees and costs which may be incurred in connection with our representation of 3CE, it is important that you understand and acknowledge that any such estimate is merely an estimate based on numerous assumptions which may or may not prove to be correct and that any estimate is not a guarantee or agreement of what the maximum amount of fees and/or costs will be.

11. Future Matters. Unless otherwise agreed in writing between us, all other matters referred to us for representation shall be governed by the terms of this Agreement.

12. Entire Agreement. This Agreement contains all terms of the agreement between us applicable to our representation of 3CE, and may not be modified except by a written agreement signed by both of us.

13. Future Conflict. Our undertaking to represent 3CE in the above matters will not act as a barso asto prevent usfrom representing any existing orfuture client with respect to a claim, litigation or transaction adverse to 3CE, so long as in the course of our representation of 3CE we have not obtained any information that would be adverse to 3CE’s interests with respect to such claim, litigation or transaction.

14. Client. The Firm’s clients for the purpose of our representation are only the persons and entities identified in this Agreement. Unless expressly agreed, we are not undertaking the representation of any related or affiliated person or entity, nor any of their shareholders, partners, officers, directors, agents, or employees.

DocuSign Envelope ID: CE35727D-C5ED-473E-9F3B-E84C0EFC81DF Monterey Bay Community Power Authority
November 20, 2020
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If this Agreement correctly sets forth your understanding of the scope of the services to be rendered to 3CE by the Firm and if all of the terms set forth in this Agreement are satisfactory, then please sign this Agreement and return it to me so that we will be engaged as 3CE’s legal counsel. If the scope of services described is incorrect, or if the terms set forth are not satisfactory to you, please let us know in order that we can discuss either aspect.

I look forward to continuing to work with you and thank you once again for the opportunity to be of service.

Sincerely,
Stephen Hall
Principal
I have read and understand the contents of this Agreement and consent to the Firm representing 3CE on the terms set forth in this Agreement.

CENTRAL COAST COMMUNITY
ENERGY (formerly, MONTEREY BAY
COMMUNITY POWER AUTHORITY), a
California joint powers authority
Dated: ________________, 2020 By:

Name: Tom Habashi
Title: CEO
Approve as to financial terms:

Dated: ________________, 2020 By:

Name: Tiffany Law
Title: CFTO
Approve as to form:

Dated: ________________, 2020 By:

Name: Robert M. Shaw
Title: COO/GC
DocuSign Envelope ID: CE35727D-C5ED-473E-9F3B-E84C0EFC81DF 11/21/2020
11/21/2020
11/21/2020
Staff Report Item 9
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dan Bertoldi, Manager of Energy Programs
SUBJECT: Receive Update on FY 2022-2023 Energy Programs DATE: August 9, 2023
RECOMMENDATION:

This memorandum recommends the Operations Board receive an update on FY 2022-23 Energy Programs.

BACKGROUND:

Staff provide regular updates on the performance and administration of the FY 2022-23 Energy Programs Portfolio.

DISCUSSION/ANALYSIS:

Staff are actively implementing 3CE’s FY 2022-23 suite of Energy Programs, serving a broad range of customers to advance building electrification, transportation electrification, and agricultural electrification. Provided as attachments to this report are updates on community energy programs and Member Agency Services implementation activities.

FISCAL IMPACT:

There is no fiscal impact associated with this update and report.

CONCLUSION:
3CE’s Energy Programs support local economic stimulation by providing the community and Member Agencies with funding and services to accelerate regional electrification as well as enhanced incentives for underserved customers to reduce GHG emissions throughout the 3CE service area.

ATTACHMENTS:

1. Update on 3CE Community Energy Programs

2. Update on 3CE Member Agency Services
FY 22-23 3CE Community Energy Programs
Provided in this report is an update on FY 22-23 Community Energy Programs implementation activities.

Electric Bus Program
On March 1, 2023, 3CE launched the Electric Bus Program. The Electric Bus Program provides 3CE customers with incentives for the purchase or lease of all-electric school buses and agricultural worker transport buses. The Electric Bus Program is intended to reduce GHG emissions from buses, as well as eliminate harmful pollutants emitted by traditional diesel buses in close proximity to people. To date, 3CE has received one application for a school bus. This program has an incentive budget of $1.4 million.

As of the writing of this report, 3CE has approved two application for a total of $400,000 for an electric school bus that will go towards Title 1 schools in Monterey and Santa Barbara counties.

Electrify Your Home Program
On October 3, 2022, 3CE staff launched the Electrify Your Home Program (EYH) with implementation support from third-party implementor, Energy Solutions. This residential electrification program provides incentives “midstream” to enrolled contractors who recommend and switch out gas powered appliances in existing single and multi-family buildings with all-electric heat pump water heating and HVAC technologies. These incentives directly reduce the upfront cost for 3CE customers who make the switch to all-electric heat pump technology. In FY 22/23, 3CE budgeted $1.6 million for EYH.

Contractors enrolled in the statewide TECH Clean California (TECH) program also have access to no-cost workforce education and training focused on electrification design and specification, heat pump installation, building science, and soft skills in sales and marketing. There are 75 licensed contractors enrolled in the TECH program that serve part of 3CE’s service area.

The following table summarizes program performance to date:

Approved & Paid Submitted Reserved Total Allocated
Single-family $481,400.00 $122,100.00 $100,400.00 $703,900.00 Multifamily $0 $0 $45,000.00 $45,000.00
Total $481,400.00 $122,100.00 $145,400.00 $748,900.00
New Construction Electrification Program
On October 3, 2022, 3CE staff launched the New Construction Electrification Program (NCEP). This year’s iteration of NCEP provides affordable and farmworker housing developers, and homeowners building Accessory Dwelling Units (ADU), with incentives to build all-electric housing. Housing projects must be built to all-electric standards for all energy utility needs including but not limited to water heating, space heating, and cooking appliances. Incentives will be provided on a per-unit basis and will be provided “downstream” to developers and homeowners upon successful completion of the project. In FY 22/23, 3CE has budgeted $1.5 million for NCEP.

As of the writing of this report, staff have received and approved six (6) multi-unit projects totaling $500,000 in funding reservations for a total of 200 affordable housing units. 3CE has also received and approved 17 applications for ADU projects for a total of $90,000. See Figure 1 below for total program funds reserved by county in FY 22/23. For a full list of all NCEP funds reserved since FY 19/20, please see Appendix A, attached to this document.

Figure 1 (above): Shows NCEP funds distributed by County in FY 22/23.

Electrify Your Ride Program
On November 1, 2022, 3CE staff launched the third iteration of the Electrify Your Ride (EYR) Program.

Building off last year’s program, the Electrify Your Ride Program provides rebates to 3CE customers who purchase or lease an electric vehicle (EV). This program also incorporates rebates for Level 2 EV Chargers, as well as related home electrical upgrades - such as panel upgrades and wiring – to support “EV Readiness”.

Residential, commercial/agricultural, and public agency customers are welcome to apply. Higher incentive amounts are available through this program for income-qualified customers to promote greater adoption of transportation electrification in disadvantaged and low-income communities.

The following figures summarize program performance based on over 700 approved applications received to date:

Figure 2 (above): Shows Electrify Your Ride funds distributed by County in FY 22/23.

Figure 3 (above): Shows Electrify Your Ride Program funds distributed by Measure type in FY 22/23.

Figure 4 (above): Shows a breakdown of funds distributed to income qualified applicants. Tier 1 = 201 - 400% of the Federal Poverty Level (“FPL”); Tier 2 = less than 200% of FPL; N/A = Non-Income Qualified applicants Ag Electrification Program
On December 8, 2022, staff launched the fourth iteration of the Agricultural Electrification Program (“Ag Program”). The Ag Program provides incentives to 3CE customers for replacement of fossil fuel powered agricultural equipment with new electric equipment including irrigation pumps, farm tools, tractors, utility vehicles, and other equipment. Incentives are provided “downstream” directly to the customer after proof of purchase and/or installation of equipment.

Like last year, applications for projects with the greatest estimated GHG emissions reduction as well as those submitted by small to medium sized businesses will be supported by the highest incentive levels.

The following figures summarize program performance based on approved applications received to date:

Figure 5 (above): Shows total funds reserved or distributed by County for the FY 22/23 AG Electrification Program.

Figure 6 (above): Shows Ag Electrification Program funds distributed by equipment type in FY 22/23.

Appendix A – NCEP Approved Housing Developments, by City Installation City Development Name
Estimated Project
Completion Date
Total Reserved
Funds
Total # of
Housing
Units
(Final) Status
Atascadero Paseo Paloma 11/1/2026 $180,000.00 72 Funds Reserved Buellton Village Senior Apartments 8/31/2024 $122,500.00 49 Funds Reserved Goleta Heritage Ridge 2/28/2025 $102,500.00 41 Funds Reserved Goleta Hollister Lofts 12/31/2023 $90,000.00 36 Funds Reserved Guadalupe Escalante Meadows 6/1/2023 $200,000.00 80 Funds Reserved Hollister Riverview Estates II 4/12/2023 $60,000.00 24 Project Complete Hollister Santana Ranch Apartments 3/1/2023 $139,250.00 56 Funds Reserved Hollister Phase 1 of Santana Ranch Apartments 3/1/2023 $37,500.00 16 Funds Reserved Hollister The Apartments at Santana Ranch, Phase 2 12/31/2023 $137,500.00 55 Funds Reserved Lompac (Unincorporated SB
County) Brisa Encina 7/31/2024 $122,500.00 49 Funds Reserved Lompoc Plaza de la Bandera 10/15/2025 $110,000.00 44 Funds Reserved New Cuyama Perkins Place 4/30/2025 $82,500.00 33 Funds Reserved Pismo Beach Shell Beach Senior Apartments 5/1/2024 $62,500.00 25 Funds Reserved Pismo Beach Pismo Terrace 7/31/2023 $125,000.00 50 Funds Reserved Salinas 467, 479 E. Market Street 1/31/2025 $156,750.00 84 Funds Reserved San Luis Obispo
Presidio WH SLR 80 Towns, LLC (Williams Homes)
Fig at the Orchard- Tract 3150 2/16/2022 $141,500.00 80 Funds Reserved San Luis Obispo
Presidio WH SLR 120 Lofts Efficiency Units at the
Orchard -Tract 3150 6/15/2022 $214,500.00 120 Funds Reserved San Luis Obispo Iron & Oak 12/31/2022 $29,750.00 17 Project Complete San Luis Obispo Vinifera 10/10/2022 $76,000.00 40 Project Complete San Luis Obispo Broad Street 10/24/2022 $100,000.00 40 Funds Reserved San Luis Obispo Tiburon Place 10/1/2024 $170,000.00 68 Funds Reserved San Luis Obispo Harvest Lofts 3/31/2023 $213,500.00 122 Funds Reserved San Luis Obispo Harvest Vistas 12/31/2024 $26,250.00 15 Funds Reserved San Luis Obispo Avila Ranch - $35,000.00 14 Funds Reserved Santa Babrara Patterson Point 5/15/2025 $60,000.00 24 Funds Reserved Santa Cruz 180 Permanent Supportive Housing Project 7/12/2023 $240,000.00 121 Funds Reserved Santa Cruz Pacific Station North 4/30/2025 $237,500.00 95 Funds Reserved Santa Cruz Jessie Street Apartments
- $123,500.00 50 Funds Reserved
Santa Cruz 1500 Capitola Road Family Housing 6/30/2023 $142,500.00 57 Funds Reserved Santa Cruz Downtown Library Apartments 3/31/2025 $240,000.00 105 Funds Reserved Santa Cruz Calypso 9/30/2024 $87,500.00 35 Funds Reserved Santa Cruz, CA Natural Bridges Apartments 1/5/2025 $50,000.00 20 Funds Reserved Santa Ynez Harry's House 5/26/2023 $150,000.00 60 Funds Reserved Seaside Lower Stilwell Privatized Military Housing 8/31/2022 $240,000.00 96 Project Complete Soledad San Vicente Rentals 6/30/2021 $20,000.008 Project Complete Unincorporated Monterey
County East Garrison Apartments 8/30/2023 $165,000.00 66 Funds Reserved Watsonville Miles Lane Family Housing 12/7/2023 $180,000.00 72 Funds Reserved Watsonville Pippin Phase II Apartments 7/9/2024 $200,000.00 80 Funds Reserved Watsonville 1482 Freedom Blvd 11/30/2023 $131,750.00 53 Funds Reserved FY 22-23 Member Agency Services
Provided in this report is an update on FY 22-23 Member Agency Services implementation activities.

Reach Code Program
On October 3, 2022, 3CE staff launched the Reach Code Program with program implementation support from a consultant, TRC Engineers. This redesigned program offers stakeholder outreach support and provides no-cost technical assistance to help Member Agencies adopt and implement reach codes.

Support includes presenting to key stakeholders, answering technical questions, attending meetings, developing customized ordinances, reviewing staff presentations and reports, and developing implementation tools to help Member Agencies enforce their reach codes. The Reach Code Program includes recommended model codes for new construction electrification, electric vehicle charging infrastructure, and existing building electrification.

Since launch, four Member Agencies have engaged in the program: City of Watsonville, City of San Luis Obispo, the County of Monterey, and the City of San Juan Bautista. 3CE is also supporting a regional reach code working group effort including the County of Santa Barbara and the Cities of Carpinteria and Goleta and being led by 3C-REN with support from Southern California Edison.

The following table summarizes program performance based on engagement and type of reach code being pursued:

Member Agency Type of Reach Code (NC, EB, EV)
County of Monterey New Construction and Electric Vehicle City of Watsonville New Construction and Electric Vehicle City of San Luis Obispo Existing Buildings
City of San Juan Bautista New Construction and Electric Vehicle On April 17, 2023, the US Court of Appeals for the Ninth Circuit overturned a District Court ruling allowing the City of Berkeley’s adoption of municipal codes that prohibit natural gas infrastructure in newly constructed buildings. Working closely with its partners, 3CE is investigating the implications of the Ninth Circuit Court’s ruling to determine what actions, if any, should be taken.

Electrify Your Fleet Program
On December 15, 2022, 3CE staff launched the Electrify Your Fleet (EYF) program. EYF provides incentives to Member Agencies to offset the cost of the purchase/lease of light duty, medium duty, and heavy-duty battery electric vehicles. These incentives are available as a post-purchase rebate or as a pre-purchase reservation.

The following figures summarize program performance based on applications received as of the writing of this report.

Figure 1 (above): Shows Electrify Your Fleet funds distributed by Organization in FY 22/23 Figure 2 (above): Shows Electrify Your Fleet Program funds distributed by Vehicle Class in FY 22/23.

Charge Your Fleet Program
On December 15, 2022, 3CE staff launched the Charge Your Fleet (CYF) program. CYF is the complement to EYF and provides incentives to Member Agencies to offset the cost of the purchase and construction/installation of electric vehicle charging infrastructure. Charging stations may be either public facing or “behind the fence” and include Level 2 and/or Level 3 chargers. These incentives are available as a post-purchase rebate or as a pre-purchase reservation.

The following figures summarize program performance based on applications received as of the writing of this report.

Figure 3 (above): Shows Charge Your Fleet funds distributed by Organization in FY 22/23 Figure 4 (above): Shows Charge Your Fleet Program funds distributed by equipment type in FY 22/23.

Member Agency Building and Transportation Electrification Working Groups 3CE has established and is facilitating working groups focused on building and transportation electrification to drive participation in existing programs and inform future program design; identify common needs, barriers, and scalable solutions for regional electrification; and identify and share resources between Member Agencies and 3CE.

The Transportation Electrification Working Group (TEWG) met on June 1, 2023, and received a presentation from Optony regarding 3CE’s Plan Your Fleet Program. Member Agencies were given an opportunity to hear directly from Optony about the services under Plan Your Fleet and ask questions regarding fleet transition and EV infrastructure planning.

The next Building Electrification Working Group (TEWG) meeting will be held on July 27, 2023, and will feature a presentation from TRC Engineers, 3CE’s third-party implementor for the Reach Code Program, where they will discuss “Electric Preferred 2.0” Reach Codes.

Below is the proposed schedule for future BEWG and TEWG meetings.

BEWG TEWG
July 27 August 24
October 26 November 16
Plan Your Fleet Program
On June 1, 2023, 3CE launched the Plan Your Fleet Program to provide no-cost planning, design, and engineering consultation to 3CE Member Agencies to accelerate fleet electrification and development of electric vehicle charging infrastructure across the 3CE service area. Since launching the Program, 3CE’s third-party implementor, Optony, has engaged with three (3) Member Agencies as of the writing of this report.

FY 22/23 Programs To-be-Launched
Broadband Access Initiative
Through the Broadband Access Initiative, 3CE is collaborating with Member Agencies, Regional Broadband Consortia, economic development agencies, and community-based organizations to support two regional broadband projects. 3CE will establish an agreement with Member Agencies via to support work that (1) addresses economic development, employment opportunities, and digital equity and (2) enhances 3CE customer engagement and enables customer participation in programs. Member Agencies will, in turn, coordinate with economic development agencies and community-based organizations to conduct projects working with underserved customers across 3CE’s service area, particularly in rural regions, disadvantaged communities, and areas impacted by flooding. 3CE staff are in the process of finalizing an agreement to be executed in Q4 of FY 22/23.

Staff Report Item 10
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
SUBJECT: Regulatory Update
DATE: August 9, 2023
DISCUSSION:

Please find attached 3CE’s Regulatory and Legislative Update, providing the latest information on the following:

Regulatory: Resource Adequacy (RA), Provider of Last Resort (POLR), Load Management Standards (LMS) and Real-Time Pricing, Demand Flexibility, and Bioenergy Market Adjustment Tariff (BioMAT).

Legislative: Energy Budget Trailer Bill
CONCLUSION:

This is an informational item only.

ATTACMENT(S):

1. Regulatory Update
Regulatory Update
August 9, 2023
2 Table of Contents
REGULATORY UPDATE......................................................................................................................................................... 3 Resource Adequacy (RA)................................................................................................................................................. 3 Provider of Last Resort (POLR) and Emergency Transition Planning ......................................................... 3 Load Management Standards (LMS) and Real-Time Pricing............................................................................ 4 Demand Flexibility............................................................................................................................................................. 4 Bioenergy Market Adjustment Tariff (BioMAT).................................................................................................... 4 LEGISLATIVE UPDATE.......................................................................................................................................................... 5 Energy Budget Trailer Bill............................................................................................................................................... 5 3 REGULATORY UPDATE
Resource Adequacy (RA)
Issue
The Resource Adequacy (RA) program is the California Public Utilities Commission’s (CPUC) main grid reliability planning program. All load serving entities (LSEs) under the CPUC’s jurisdiction, including CCAs, must demonstrate purchase of a specified amount of eligible RA capacity each month and year to comply with RA program requirements.

A combination of increasing demand and decreasing supply of eligible RA capacity over the past five years has resulted in sharply increased prices and unprecedented difficulty procuring sufficient RA to achieve compliance. Over the past year the CPUC has also sought to tie RA compliance to other, unrelated functions such as CCA expansion into new communities.

Status
On June 29, 2023 the CPUC voted unanimously to accept a redlined Proposed Decision that among other changes, tied RA deficiencies to future CCA expansions.

Next Steps
CalCCA anticipates challenging the approved Decision on numerous grounds.

Provider of Last Resort (POLR) and Emergency Transition Planning Issue
The Provider of Last Resort (POLR) is the backstop entity that provides electric service to customers of a load serving entity if that LSE fails suddenly. This role has historically been held by the investor owned utilities (IOUs, namely Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric), but this proceeding is establishing a process to allow CCAs and other non-IOU LSEs to become POLR in their service areas.

This proceeding is also considering rules designed to prevent LSE failures that have various implications for 3CE finances and operations, including changes to how much money CCAs must post as insurance against their own failure (called the Financial Security Requirement or FSR). 3CE’s FSR has been set at $147,000 since 2018, but that amount is likely to increase with the reforms being considered in this proceeding.

Status
On June 19, 2023 the CPUC issued an updated proceeding schedule restarting progress and accelerating the timeline to reach a Decision. We can now expect to receive a Proposed Decision with an updated FSR methodology by October 2023, meaning the new methodology will likely be approved in time to be used in the biannual FSR recalculation in November. Staff are following the proceeding closely to understand the likely impact to 3CE’s FSR as soon as possible.

Next Steps
Briefs were the last opportunity for stakeholder input before CPUC staff withdraw to write the Proposed Decision, so there is no further expected activity in this proceeding until the Proposed Decision is released in October 2023.
4 Load Management Standards (LMS) and Real-Time Pricing Issue
CEC updated the Load Management Standard (LMS) regulations now require IOUs, municipal utilities, and CCAs with load greater than 700 GWh/year to upload time-dependent rates to the CEC’s Market Informed Demand Automation Server (MIDAS) platform, develop an LMS Compliance Plan by March 2024, and present to their governing bodies, for approval by the CEC, at least one hourly marginal cost-based rate option (often referred to as a real-time rate) for their customers by 2025.

Status
As of July 28, 2023, 3CE’s MIDAS platform updates have been completed.

Next Steps
3CE staff are beginning development of 3CE’s LMS Compliance Plan while also evaluating the CEC regulatory authority to set CCA rate structures.

Demand Flexibility
Issue
This is a large proceeding opened in 2022 to promote demand flexibility in California for the purpose of improving grid reliability and reducing the cost of grid stress events. While this proceeding does not directly govern CCA ratemaking. 3CE is participating to ensure CCA ratemaking authority is preserved, monitor changes to IOU transmission and distribution rates, address data access issues between IOUs and CCAs that hinder time-dependent rate design, and advocate for rate structures that promote equity for bundled and unbundled customers.

Status
This proceeding is currently implementing one of the new statutory requirements created in 2022 by the passage of AB 205, which required the CPUC to design and approve an income-graduated fixed charge (IGFC) for all residential electric utility customers by July 1, 2024. The goal is to reduce energy costs for low-income Californians by creating a monthly fixed charge that increases with income, allowing the volumetric charge to be lower. While the fixed charge will be on the delivery side of the bill and not affect 3CE operations directly, 3CE staff are following the process to understand how customers’ experience will evolve around 3CE service.

Next Steps
3CE staff continues to follow the process and help develop CalCCA filings through the remainder of 2023. The CPUC is scheduled to release a Proposed Decision in Q1 2024 establishing an IGFC rate structure and pathway for implementation in advance of the July 1, 2024 legislative deadline. Following the Decision each investor-owned utility will need to file an Advice Letter applying the approved rate structure to their own ratemaking process. The earliest that any California electricity users could expect to see an IGFC on their bill is September 2026.

Bioenergy Market Adjustment Tariff (BioMAT)
Issue
BioMAT is a procurement program opened in 2015 to encourage the development of small bioenergy projects in California. The program is unique in that it allows load serving entities (LSEs) contracting with these projects to recover the costs from all California electricity users through the Public Purpose 5 Programs (PPP) charge. In 2021 3CE and other CCAs successfully lobbied legislators to reverse the exclusion of CCAs from BioMAT with the passage of AB 843. AB 843 was the first time CCAs gained access to PPP funding, setting a valuable policy precedent. The CPUC began implementation of AB 843 in October 2022 by opening of a new proceeding to work through the details of CCA participation.

Status
Major issues in the CPUC proceeding thus far include the approval process for CCA BioMAT contracts, the BioMAT cost recovery process, and management of the BioMAT contract queue to track procurement progress for participating CCAs.

Next Steps
A proposed Decision is scheduled to be released by the end of September 2023.

LEGISLATIVE UPDATE
Energy Budget Trailer Bill
Issue
The most significant issue for 3CE and CCAs this legislative session has been a package of energy policies introduced in Governor Newsom’s budget proposal. The energy budget trailer bill language included four concerning components: 1) increased CPUC authority over CCAs, 2) a new centralized resource procurement function at the Department of Water Resources, 3) a new financial penalty for Resource Adequacy (RA) deficiencies on top of the CPUC’s penalties, and 4) the potential exclusion of the Diablo Canyon Power Plant from the RA program, which would further exacerbate existing RA market challenges.

Status
3CE staff and leadership have been working with 3CE’s legislative delegation and other CCAs from around California to address these concerns.

Next Steps
The legislature is currently on summer recess until August 14, 2023 with the end of the session on September 14, 2023. Staff will be following the process closely and update the Board as necessary through the remainder of the legislative session.

Compiled Financial Statements 1
Compiled Budgetary Comparison Schedule 6
Budget Variance Commentary 10
Financial Dashboard 11
Investment Summary 12
Table of Contents

TREASURER REPORT
Fiscal Year to Date
As of May 31, 2023
1 ACCOUNTANTS’ COMPILATION REPORT
Board of Directors
Central Coast Community Energy
Management is responsible for the accompanying financial statements of Central Coast Community Energy (a California Joint Powers Authority) which comprise the statement of net position as of May 31, 2023, and the related statement of revenues, expenses, and changes in net position, and the statement of cash flows for the period then ended in accordance with accounting principles generally accepted in the United States of America. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statements nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, conclusion, nor provide any assurance on these financial statements.

Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.

Central Coast Community Energy’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.

We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.

Maher Accountancy
San Rafael, CA
June 22, 2023
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com Current assets
Cash and cash equivalents
Held for working capital reserves 38,400,000 $
Held for reserves - other 114,474,216
Held for program commitments 5,600,000
Cash and cash equivalents 158,474,216
Accounts receivable, net of allowance 32,530,177
Accrued revenue 22,065,433
Other receivables 1,063,671
Loan receivable 187,201
Prepaid expenses 8,188,286
Deposits 4,962,752
Restricted cash 294,000
Investments - held for reserves 74,969,789
Total current assets 302,735,525
Noncurrent assets
Deposits 23,182
Loan receivable 1,520,797
Lease asset, net of amortization 1,538,347
Capital assets, net of depreciation 227,610
Total noncurrent assets 3,309,936
Total assets 306,045,461
Current liabilities
Accrued cost of electricity 36,570,086
Accounts payable 1,781,233
Other accrued liabilities 1,415,076
User taxes and energy surcharges due to other governments 1,586,082 Lease liability 292,467
Security deposits - energy suppliers 6,501,030
Total current liabilities 48,145,974
Noncurrent liabilities
Security deposits - energy suppliers 9,131,250
Lease liability 1,269,484
Total noncurrent liabilities 10,400,734
Total liabilities 58,546,708
Investment in capital assets 204,006
Restricted for security collateral 294,000
Unrestricted 247,000,747
Total net position 247,498,753 $

NET POSITION
As of May 31, 2023

STATEMENT OF NET POSITION

CENTRAL COAST COMMUNITY ENERGY
ASSETS

LIABILITIES
See accountants' compilation report. 2

OPERATING REVENUES
Electricity sales, net 291,652,658 $
Other income 45,180
Total operating revenues 291,697,838

OPERATING EXPENSES
Cost of electricity 240,986,892
Contract services 6,636,320
Staff compensation 4,132,218
Other operating expenses 5,698,629
Depreciation 207,122
Total operating expenses 257,661,181
Operating income (loss) 34,036,657

NONOPERATING REVENUES (EXPENSES)
Interest and investment income 4,831,167
Grant revenue 1,450,969
Interest and related expense (30,598)
Nonoperating revenues (expenses) 6,251,538
CHANGE IN NET POSITION 40,288,195
Net position at beginning of period 207,210,558
Net position at end of period 247,498,753 $
Eight Months Ended May 31, 2023

AND CHANGES IN NET POSITION

STATEMENT OF REVENUES, EXPENSES

CENTRAL COAST COMMUNITY ENERGY
See accountants' compilation report. 3

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers 307,677,452 $
Receipts from liquidated damages 147,000
Receipts from suppliers 4,637,467
Other operating receipts 45,180
Payments to suppliers for electricity (246,242,435)
Payments for other goods and services (11,388,480)
Payments for staff compensation (4,346,755)
Payments of taxes and energy surcharges to other governments (5,863,196) Net cash provided by operating activities 44,666,233

CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Principal payments received on loan receivable 292,002
Receipts from grantor 1,450,969
Net cash provided by non-capital
financing activities 1,742,971

CASH FLOWS FROM CAPITAL AND RELATED

FINANCING ACTIVITIES
Payments of lease liability (146,843)
Payments to acquire capital assets (63,514)
(210,357)

CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 4,243,956
Proceeds from investment sales 71,017,464
Purchase of investments (113,082,920)
Net cash provided (used) by investing activities (37,821,500) Net change in cash and cash equivalents 8,377,347
Cash and cash equivalents at beginning of year 150,390,869 Cash and cash equivalents at end of period 158,768,216 $ Reconciliation to the Statement of Net Position
Cash and cash equivalents (unrestricted) 158,474,216 $
Restricted cash 294,000
Cash and cash equivalents 158,768,216 $
Eight Months Ended May 31, 2023

STATEMENT OF CASH FLOWS

CENTRAL COAST COMMUNITY ENERGY
See accountants' compilation report. 4
Operating income (loss) 34,036,657 $
Adjustments to reconcile operating income (loss) to net cash provided by operating activities
Depreciation expense 207,122
Provision for uncollectible accounts 2,990,442
(Increase) decrease in:

Accounts receivable, net 11,586,981
Accrued revenue (3,903,488)
Other receivables 1,097,531
Prepaid expenses (7,879,867)
Deposits 3,331,178
Increase (decrease) in:

Accrued cost of electricity (3,504,496)
Accounts payable 179,973
Other accrued liabilities 379,052
User taxes and energy surcharges due to other governments (355,882) Security deposits - energy suppliers 6,501,030
Net cash provided by operating activities 44,666,233 $

CENTRAL COAST COMMUNITY ENERGY
STATEMENT OF CASH FLOWS (continued)
Eight Months Ended May 31, 2023

RECONCILIATION OF OPERATING INCOME (LOSS) TO NET

CASH PROVIDED BY OPERATING ACTIVITIES
See accountants' compilation report. 5
1 ACCOUNTANTS’ COMPILATION REPORT
Board of Directors
Central Coast Community Energy
Management is responsible for the accompanying special purpose statements of Central Coast Community Energy (a California Joint Powers Authority) which comprise the budgetary comparison schedule and a supplemental budgetary comparison schedule for the period ended May 31, 2023, and for determining that the budgetary basis of accounting is an acceptable financial reporting framework. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statement nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, a conclusion, nor provide any assurance on this special purpose budgetary comparison statement.

The special purpose statement is prepared in accordance with the budgetary basis of accounting, which is a basis of accounting other than accounting principles generally accepted in the United States of America. This report is intended for the information of the Board of Directors of the Authority.

Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.

Central Coast Community Energy’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.

We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.

Maher Accountancy
San Rafael, CA
June 22, 2023
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com 2022/23 YTD
Budget
2022/23 YTD
Actual
2022/23 YTD
Budget Variance
(Under) Over
2022/23 YTD
Actual / Budget %
2022/23 Annual
Budget
2022/23 Budget
Less Actual
2022/23 Budget
Remaining /
Budget %

REVENUES AND OTHER SOURCES
Electricity sales 290,768,000 $ 297,545,038 $ 6,777,038 $ 102% 436,500,000 $ 138,954,962 $ 32% Less uncollectible accounts (5,000,000) (4,441,411) 558,589 89% (7,500,000) (3,058,589) 41% Net revenue - electricity 285,768,000 293,103,627 7,335,627 103% 429,000,000 135,896,373 32% Investment and miscellaneous income - 4,876,347 4,876,347 n/a - (4,876,347) n/a Total revenues and other sources 285,768,000 297,979,974 12,211,974 104% 429,000,000 131,020,026 31% EXPENDITURES AND OTHER USESCurrent Expenditures
Cost of energy 241,891,556 238,581,000 3,310,556 101% 377,919,000 136,027,444 36% Energy programs (incentives and grants) 10,661,000 4,755,024 (5,905,976) 45% 15,992,000 11,236,976 70% Data manager 1,643,823 1,473,000 170,823 112% 2,793,000 1,149,177 41% Utility service fees 1,400,000 1,186,181 (213,819) 85% 2,100,000 913,819 44% Staffing 6,161,000 4,132,218 (2,028,782) 67% 9,244,000 5,111,782 55% Professional services 2,536,000 1,426,716 (1,109,284) 56% 3,397,000 1,970,284 58% Legal services 1,310,000 831,642 (478,358) 63% 1,965,000 1,133,358 58% Marketing and customer enrollment 293,056 662,000 (368,944) 44% 994,000 700,944 71% Other general & administration 2,696,000 1,440,687 (1,255,313) 53% 3,746,000 2,305,313 62% Total current expenditures 265,480,000 257,600,903 (7,879,097) 97% 418,150,000 160,549,097 38% Other Uses
Capital outlay - 75,563 75,563 n/a - (75,563) n/a
Total other uses - 75,563 75,563 n/a - (75,563)
Total Expenditures and Other Uses 265,480,000 257,676,466 (7,803,534) 97% 418,150,000 160,473,534 38% Surplus (Deficit) 20,288,000 $ 40,303,508 $ 20,015,508 $ 10,850,000 $ (29,453,508) $ -271% Reserves at end of reporting period: Held for Working Capital 38,400,000 $ Held for Reserves - Cash and Cash Equivalents 114,474,216 Held for Reserves - Investments 74,969,789 Total 227,844,005 $

CENTRAL COAST COMMUNITY ENERGY

SUPPLEMENTAL BUDGETARY COMPARISON SCHEDULE
Eight Months Ended May 31, 2023
See accountants' compilation report. 3
Budget Item YTD Variance Comment
Electric Sales Revenue 2.3% Sales revenue includes revenues actually billed to customers as well as estimated customer usage during the reporting period that is not yet billed.

Cost of Energy 1.4% Variances in this category are typically due to (1) timing difference between projected and actual REC deliveries, (2) variance from actual to anticipated market prices, and (3) variance from actual to expected volume used by customers. Cost of energy includes scheduling coordinator fees for budget purposes only.

Staffing (32.9%) Staffing expenses are under budget due to the timing of new hires.

Professional Services (43.7%) This category includes accounting, IT, technical and other consultants.

Legal Costs (36.5%) This category includes outside legal costs for regulatory and energy procurement needs.

Marketing and customer enrollment (55.7%) Variance is mostly due to the lower than anticipated costs of recent customer enrollments.

Data Management Services 11.6% These fees non-discretionary and are charged on a per customer basis.

Utility Service Fees (15.3%) These are PG&E and SCE fees charged on a per customer basis.

Other General & Administrative (46.6%) This category includes occupancy costs, industry membership dues, and other general and administrative costs.

Energy and Related Programs (55.4%) Programs expenses have generally been delayed until future periods Budget Commentary for significant items

CENTRAL COAST COMMUNITY ENERGY
October 1, 2022 through May 31, 2023
$7.7
$0.6
Act
Bud
$51.1
$47.2
$51.1
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
$60.0
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Actual
Budget
$293.0
$285.77
$429.0
$0.0
$100.0
$200.0
$300.0
$400.0
$500.0
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Actual
Budget
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Actual (T48/T8) 415 407 429 406 370 383 357 388
Budget 453 425 424 431 393 418 424 426 450 474 481 444
0 100
200
300
400
500
600

CUSTOMERS

SALES VOLUME
388 GWh

STD MARGIN
$7.7M (22%)
Δ in NET ASSETS
$6.0M

REVENUE
$36.3M
Cumulative YTD Electricity Sales
Cumulative YTD Direct Margin
(Electricity Sales less Cost of Energy)
Data Definitions:

CUSTOMERS: Count of active customers from Calpine.

REPORTED / SALES VOLUME: Best available estimate of actual meter volume. Currently based on T+8 SQMD Report and T+48 when available.

REVENUE: Total Operating Revenue, net of uncollectible, (excludes Miscellaneous and Interest income).

NON-OP REV: Other uses, primarily Interest Income
ELECTRICITY SALES: Sales from electricity (net of uncollectible).

STD MARGIN: Electricity Sales less cost of energy (Forecasting & scheduling included in Cost of Energy to match budget) ACTUAL: Same as sales volume above
BUDGET: Volumes from FY22/23 budget
Monthly Sales Volume (GWh)
Financial Dashboard: May 2023
Margin %

CUSTOMERS
445,000
ACTIVE
May revenue of $36.3M accounts for 388
GWh in net retail consumption. This comes
in 38Gwh below budgeted volume.

Year-to-date electricity revenue is $293M
compared to a budget of $286M. YTD Direct
Margin (defined as Electricity Sales less Cost
of Energy) of $43.5M is ahead of budget by
$3.9M.

The chart to the right shows volume
comparison to budgeted volume.

The charts below display cumulative
revenue and margin $ vs budget.
34%
47%
20%
40%
47%
14%
Res
Com
Ag
YTD Month
38%
45%
17%
43%
45%
13%
Res
Com
Ag
YTD Month
Revenue $36.3
C.O.E. $27.3
OpEx $2.9
Net Income $6.0 22.0%

1.7%
Act
Bud
Margin $
10 Return of Investments YTD Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep CASH AND CASH EQUIVALENTSRiver City Bank - Money Market and other Interest Earning AccountsFunds Invested - Average Balance $ 70,230,463 68,793,882 $ 70,636,473 $ 68,570,477 $ 76,819,998 $ 92,274,506 $ 104,647,869 $ 105,080,118 $ - $ - $ - $ - $ Gains/Losses/Interest $ 85,008 1,263,408 $ 94,651 $ 119,286 $ 123,533 $ 137,627 $ 205,218 $ 240,392 $ 257,694 $ Average APY 1.48% 1.62% 2.03% 2.16% 2.15% 2.67% 2.76% 2.94%INVESTMENTSRiver City Bank - Treasury-indexed productsFunds Invested - Average Balance $ 45,259,882 40,162,814 $ 55,127,902 $ 47,699,367 $ 47,828,254 $ 42,893,075 $ 42,856,284 $ 42,594,899 $ - $ - $ - $ - $ Gains/Losses/Interest $ 67,213.37 1,322,984 146,549.22 207,805 214,163 186,551 167,504 148,003 185,195 - - Average APY 2.01% 3.89% 4.52% 5.39% 4.68% 4.69% 4.14% 5.22%RBC GAM / Principal Financal Funds Invested - Average Balance $ 75,641,706 75,380,564 $ 75,948,593 $ 76,212,285 $ 76,458,827 $ 76,851,697 $ 77,101,019 $ 77,341,109 $ - $ - $ - $ - $ Gains/Losses/Interest $ 143,733.97 2,110,075 261,142.30 306,886.17 266,301.86 246,542.46 392,869.54 252,509.11 240,089.34 - - Average APY 2.29% 4.14% 4.85% 4.19% 3.87% 6.13% 3.93% 3.73%

CENTRAL COAST COMMUNITY ENERGY
Investment Summary
October 1, 2022 through May 31, 2023
Staff Report Item 12
TO: 3CE Operations Board of Directors
FROM: Seth Capron, CAC Chair
SUBJECT: CAC Report
DATE: August 9, 2023
Community Advisory Council Report to Operations Board on the April 5, 2023 Meeting COO Report – Discussion Item
COO Shaw provided updates on:
 Staffing Updates
 San Luis Obispo County Supervisors’ vote to join CCCE!!  Energy Program Update
 Launch of consultant-supported program to provide technical assistance to jurisdictions to electrify fleets, with special emphasis on smaller jurisdictions that lack staff to carry out a program
 Working on future demand response program (FY23/24)
- Recommended by CAC for future programming
- Has significant potential to shave peak demand and lower energy costs  Bills Addressing Interconnection Delays – Both load and generation  Numerous bills in the legislature
 Critical need to address this issue to meet CCCE’s electrification goals  Staff will come back at future CAC meetings to keep us updated on which bills offer the greatest opportunity to address the grid connection delays Regional Transportation Electrification Action Plan Presentation and Panel Discussion – Electric Vehicle Infrastructure Trade Associations (Discussion Item) Representatives from EVgo, Environmental, and Energy Consulting, and the Electrification Coalition  Presentation on available federal incentives for EVs and EVSEs in IRA  Requirements for new EVSEs to qualify – size, maintenance/reliability, data capable, ADA compliance, open data standards
 Available for individuals and businesses
 Includes passenger vehicles, medium-duty and heavy-duty chargers, and vehicles  Review of CA state funding for EVs and EVSEs
 Over 70 bills proposed in the current legislative session  Plans for “Resources Bond” in 2024 to raise funds for EVs and EVSEs  Funding being proposed for EVSEs at multi-family projects, light-duty fleets, low-income and disadvantaged communities, and single-family homes
FY 21 – 22 Energy Programs Portfolio Evaluation and Report Valuable ongoing review of prior year program impacts and success  Criteria for evaluation
 Customer participation
 Equity
 GHG emissions reductions
 Detailed analysis of performance against criteria
 80% of budgeted incentives spent or reserved is good, but staff could look for opportunities to reallocate funding mid-year with the goal of utilizing all budgeted funds.

Energy Programs Update
Now offering a robust variety of electrification incentives  Community Programs
 Electric Bus Program
- Launched March 1, 2023
- Now includes ag worker transportation
 Ag electrification
 New Construction Electrification Program
- Now includes ADUs
 Electrify Your Ride Program
 Electrify Your Home Program
 Member Agency Services
 Reach Code Program
- Higher level of service provided through new contract with a consultant - Working with one county, four cities, and a regional working group in Santa Barbara
 Electrify Your Fleet Program
 Charge Your Fleet Program
 Plan Your Fleet Program
- With extensive agency support from consultant
- Launch Q2
 Broadband Access Initiative – Launch Q2
Annual Supplier Diversity Report
o Received report on CCCE’s continuing efforts to increase use of small and medium-sized local vendors.

Receive Update on Regional Transportation Electrification Action Plan (Discussion Item) Staff reviewed the overall steps being taken to create Regional Transportation Electrification Plan (RTEAP)
 Goal is to determine how and where CCCE should direct future transportation electrification program investments.
 CAC Work Study Sessions
 Member Agency Working Group meetings
 Medium-Duty/Heavy-Duty Zero Emission Vehicle Blueprint – led by CCCE and consultant – Build Momentum
 Central Coast Zero Emission Vehicle Strategy – led by Santa Barbara County Association of Governments
 Evaluation of FY 21-22 and current CCCE transportation electrification programs A comprehensive CCCE Transportation Electrification Plan will guide the deployment of CCCE resources.

CCCE will also need to work proactively with IOUs to make sure that front of the meter infrastructure is being upgraded on a schedule to provide for planned future EV charging capacity.

Receive Update on FY 22/23 Energy Programs Portfolio (Discussion Item) Staff provided a detailed update on the implementation of the FY 22-23 Community and Member Agency Energy Programs
 FY 22-23 CCCE Community Energy Programs
 Electrify Your Home Program
- Incentives for hot water and HVAC heat pump technology - Midstream incentives to enrolled contractors
- Supported by consultant - Energy Solutions
- $285,300 allocated to date with an annual budget of $1.6 Million  New Construction Electrification Program
- In addition to low-income housing, program now supports farmworker housing, ADUs and flood victims
- Incentives are for all-electric homes (no natural gas or propane) - $165,000 allocated to date with an annual budget of $1.5 Million  Electrify Your Ride Program
- Now accepting 1040 tax forms
- New no-cost technical assistance for multi-family housing and publicly accessible commercial EV charger installations
- Improved communication with applicants
- Plans to contract third-party implementer
- Plans for workforce development incentives for EVSE installation - $476,000 allocated to date with an annual budget of $4.6 Million  Ag Electrification Program
- Frontier Energy to provide new no-cost technical assistance to ag customers - $132,000 allocated to date with an annual budget of $2 Million  Upcoming Electric Bus Program launches Feb/March 2023 - New iteration will include transit and ag employee buses as well as school buses  FY 22-23 CCCE Member Agency Programs
 Reach Code Program
- Support by consultant, TRC Engineers
- Comprehensive support for Reach Code development and adoption - Three agencies have used program
 Electrify Your Fleet Program
- Incentives for light duty, medium duty and heavy duty EV’s  Charge Your Fleet Program
- Incentives for electrical vehicle charging infrastructure - Public-facing or dedicated to fleet charging only
 Member Agency Building and Transportation Electrification Working Groups - Working groups to encourage agency participation in incentive programs - Separate groups focused on Building Electrification and Transportation Electrification
 Upcoming programs to launch this spring
 Plan Your Fleet
- No-cost technical assistance (planning, design and engineering) provided by third party consultant (tbd)
- Facilitate member agency participation in fleet electrification  Broadband Access Initiative
- Funds for planning and interagency collaboration
- CAC Broadband Ad Hoc committee is assisting staff with program design Community Advisory Council Report to Operations Board on the June 7, 2023 Meeting Workshop
Regional Transportation Electrification Action Plan Presentation and Panel Discussion  Program Staff from Silicon Valley Clean Energy presentation on EV Digital Engagement  eHub - One-stop web presence for guiding customers on electrification journey - Inspiring customers to go electric: Awareness, Education, Action - Education on the why and how
- Concierge customer assistance
Connect customers to programs
Info on EV models, chargers, electric appliances
Purchasing portals for EV’s and other electrification products  Significant customer engagement through repeat web site visits  GridShift App
- Automates EV charging schedules to lower customer costs & support the grid - Works with many EVs and EV chargers
- Timing based on electric TOU rates and carbon intensity of the CA grid - App made available to customers
- Average savings = $100 per year per customer
- Significant SVCE savings on power purchases
- Significant reduction in greenhouse gas emissions due to shift to daytime electricity consumption of greener power
 Program Staff from East Bay Community Energy presentation on EV Fast Charging Program  Focus on fast charging access for renters, which is currently almost non-existent  DMV data shows nearly zero EV uptake by renters
 Comprehensive charger siting methodology using data
- EV ownership locations from DMV
- Utility capacity
- Renter density and underserved communities
 Goal – 800 to 1000 new fast chargers by 2030
 Each site typically includes ten dual port chargers (20 EVs)  Phase 1 is focused on rent-free sites on member agency property - Rent-free = lower charging costs to public
 Sites adjacent to amenities (retail, dining)
 Phase II will look to medium-duty chargers for goods movement fleets  Program based on CCA ownership of chargers
- Reduced cost to public – rates controlled by CCA
- Subcontracting financing, construction and maintenance with fixed contracts Subcontracts require 97% uptime
 EBCE Board has committed $30 million over ten years
 EBCE branded chargers
COO Report – Discussion Item
 Energy Market Outlook
 Grim
 Demand Side Management Initiative
 A major opportunity to manage RA through various Demand Response initiatives  Income Graduated Fixed Charges on the Delivery Side of the Bill (PG&E and SoCal Edison) Receive Update on FY 2022-23 Energy Programs
Staff provided their regular update on the ongoing review of existing programs Overall level of program uptake is excellent
Analysis of programs successes and shortfalls
Receive Presentation on Anticipated FY 2023-23 Energy Programs Portfolio  Proposing to move forward with current established programs  Existing program improvements based on FY 22/23 portfolio review and lessons learned  Incorporate input from community, CAC and Boards
 One new program proposal for Demand-Side Management (Demand Response)  Program to develop behavioral and automated approached to load modifications  Likely to be a focus for the CAC’s Workplan Study Sessions in FY23/24  New technologies provide many opportunities for shifting loads to lower carbon, less costly power
 Savings for both customers and 3C Energy
Staff Report Item 13
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
SUBJECT: CEO Report
DATE: August 9, 2023

STAFFING UPDATE
Dennis Dyc-O’Neal is stepping into the role of Chief Operating Officer, a promotion from his previous role as Director of Power Services where he oversaw the Power Resources Team and served as the Interim Chief Operating Officer from April 17, 2023, until July 30, 2023.

Dennis brings forth a total of twenty-five years of experience in the electric and natural gas markets, specializing in renewable energy, business development and contract administration. Dennis started his career in the energy industry as a researcher with the California Energy Commission.

Prior to joining 3CE, Dennis was the Director of Power Resources for Silicon Valley Clean Energy. Dennis worked for 13 years at PG&E in various management positions in energy procurement and contract management. His extensive experience also includes Vice President of Operations for Go-Green, an electric service provider in the late 1990’s, managing power procurement and customer services.

Dennis succeeds Robert M. Shaw, who currently serves as the Chief Executive Officer.

Dennis’s promotion took effect on July 31, 2023.

Emmanuel Gutierrez joined 3CE as the Director of Data and Analytics on June 26, 2023. Emmanuel is an accomplished professional with over 13 years of experience in utilities, predominantly within a major utility company in the Northeast. Additionally, he has contributed his expertise to a prominent technology firm, leading various data analytics and implementation projects. Emmanuel's extensive background encompasses a wide range of initiatives, including the development of dashboards, propensity models, segmentation strategies, and the implementation of AI solutions. With a proven track record in the utility space, Emmanuel has mastered the craft of driving impact out of data. His dedication, combined with his diverse experience, positions him as a great asset to the organization.

Tara Walling joined the 3CE team on July 17, 2023 as the Power Resources Markets Manager. Tara Walling brings over 20 years of experience working in Power and Natural Gas markets. Tara made her entry into the energy field when wind had just launched and solar was a dream of the future. She is now looking to deploy her experience, knowledge, and creativity toward using economically sensible renewable energy as the starting point for the sustainable path forward. Tara has worked for PacifiCorp as a project manager, Avangrid Renewables culminating as a senior trader and power scheduler amongst other agencies.

POLICY BOARD APPROVES PROJECT SELECTION CRITERIA
The Policy Board of Directors, at its June 21, 2023 meeting, adopted a new framework that formalizes an evaluation process for renewable energy and storage project solicitations. This new policy, called the Project Selection Criteria (PSC), will further 3CE’s core mission of delivering competitively priced clean and renewable energy to customers while committing to a skilled workforce, local and targeted hiring, and meaningful community engagement.

The adopted selection criteria evaluates projects based upon the following criteria: 1) ability to cost-effectively meet 3CE’s regulatory obligations and 100% clean and renewable energy goal; 2) commitment to workforce development; 3) potential for innovation; 4) location; 5) environmental impacts, and 6) benefits accruing to underserved communities.

As part of 3CE’s request for approval for a renewable energy or storage facility to the Operations Board, staff will report on how that project scored on each of these new evaluation criteria.

The selection criteria will be incorporated into future solicitations for renewable energy and/or storage facility.

MARKET OUTLOOK
In July, blistering heat drove up energy demand and prices across the West as residents sought relief from sweltering conditions. The California Independent System Operator (CAISO) grid demand peaked on July 20, when demand reached 42,256 MW. CAISO issued an Energy Emergency Alert 1 which indicated that all available generation is in use or “committed” and deficiencies in energy supply are anticipated. On July 25, CAISO issued an Energy Emergency Alert Watch, indicating all available generation is “committed” or forecasted to be in use. Average electricity prices in our area increased from the low $40/MWh range to mid- to high-$70/MWh, with more dramatic increases in Arizona due to the prolonged heat wave there. Temperatures are expected to remain hotter than normal throughout August in the West.

YELLOW PINE ENERGY CENTER BEGINS OPERATIONS
On July 26, 2023, 3CE’s third Solar PV and energy storage project began deliveries to our customers.

Yellow Pine Energy Center, a 75 MW solar PV plus 39 MW energy storage facility located in Clark County Nevada but fully integrated into the CAISO, will serve 5% of 3CE’s demand. It is the sixth clean and renewable project 3CE has brought online to date. Collectively, 27% of 3CE’s demand is being served by these projects.

RESOURCE ADEQUACY RULE CHANGES AND CCA EXPANSION
On June 29, 2023, the California Public Utilities Commission (CPUC) adopted changes to the Resource Adequacy (RA) program used for grid reliability planning. Among these is a new rule that a CCA may not expand its service to new communities if it has not met all RA compliance requirements for at least two calendar years. Application of the rule will begin with RA deficiencies in September 2023. Past RA deficiencies will not affect CCA expansions. Tying CCA expansion to RA program performance is outside the CPUC’s role in CCA expansion as defined in state statute, and the California Community Choice Association has filed an Application for Rehearing challenging the new rule on behalf of all California CCAs. In the meantime, 3CE staff are waiting for the CPUC to certify 3CE’s Implementation Plan to expand service to the County of San Luis Obispo in January 2025. The language of the RA Decision states that the new expansion limitation will not apply to implementation plans submitted before the decision was passed. 3CE submitted the San Luis Obispo County Implementation Plan on May 15, 2023, so the new rules should not apply to it. The CPUC has a statutory deadline of August 15, 2023, to certify the Implementation Plan. Staff will be monitoring the situation and will update the Board as appropriate.

DEMAND RESPONSE
3CE will be partnering with OhmConnect, the leading residential demand response provider in California. OhmConnect helps hundreds of thousands of customers manage their at-home electricity by rewarding them for smarter energy use. The company pays customers for saving electricity when the grid is stressed and likely to utilize dirty power, unlocking clean, affordable, and reliable energy. Through devices such as smart thermostats and smart plugs, the company is able to inform customers when electricity is most expensive and help them use less, leading to personal savings and the potential for region-wide reduction of energy use. The program is planned to roll out to 3CE customers this month in preparation for late summer coastal peak temperatures and earlier evening sunsets, which reduce solar power production when people are still using substantial amounts of electricity.

BUDGET UPDATE
Fiscal Year 2023-24 Recommended Budget is under development with the major challenge being a dramatic increase in the Cost of Energy (COE). While the budget is still under development early indications are that the costs of energy will increase by $116.9 million, due to Resource Adequacy compliance and volatile energy markets driving up the Cost of Energy (COE) procurement. Initial estimates indicate that even with this substantial increase in COE our rates will continue to be competitive with the Investor-Owned Utilities.

ATTACHAMENT(S):

1. 2023 June Customer Enrollment and Engagement Report

2. Contracts less than $100k
Customer Enrollment and Engagement Report
Central Coast Community Energy
Communications and Outreach
June 2023
I. Member Agency Services Meetings:
3CE staff presented before the Cities of Pacific Grove, Scotts Valley, Seaside, and Gonzales to share accomplishments, programs, and goals as well as agency-specific data about 3CE investment in each community.

II. Opt-Outs:

Total Opt-Out request for May 2023: 103
III. Enrollment:

IVR
24%
Phone Call
24%
Task
1%
Web
51%
Opt Outs by Activity Type
Decline to
Provide
19%
Dislike
being
automatica
lly enrolled
31%
Other
24%
Rate or
Cost
Concerns
26%
Opt Outs by Reason Given

94.0%

96.3%

93.7%

96.0%

94.7%

91.1%

94.9%

96.4%

80.6%

68.0%

97.5%

91.9%

94.3%

92.9%

96.1%

89.1%

96.6%

95.7%

93.6%

92.5%

93.2%

91.6%

99.1%

96.0%

94.9%

96.9%

85.4%

97.0%

95.3%

97.6%

97.8%

94.7%

93.3%

0.0% 20.0% 40.0% 60.0% 80.0% 100.0% 120.0%

WATSONVILLE

SOLEDAD

SCOTTS VALLEY

SANTA CRUZ CO

SANTA BARBARA CO

SAN LUIS OBISPO

SAN BENITO CO

PISMO BEACH

PACIFIC GROVE

MONTEREY CO
MARINA

GUADALUPE

GREENFIELD
GOLETA

CARPENTERIA

CAPITOLA

ARROYO GRANDE
PERCENT OF ELIGIBLE LOAD SERVCE AS JUNE 1, 2023

90.42%

96.85%

87.86%

94.09%

96.31%

98.11%

94.91%

96.43%

96.70%

92.92%

96.29%

90.89%

90.45%

89.47%

95.82%

92.43%

96.40%

96.88%

92.62%

95.66%

93.26%

88.66%

97.90%

95.65%

87.49%

86.93%

95.84%

96.09%

94.68%

97.75%

95.39%

97.15%

95.31%

80.00% 82.00% 84.00% 86.00% 88.00% 90.00% 92.00% 94.00% 96.00% 98.00% 100.00%

WATSONVILLE INC

SOLEDAD INC

SCOTTS VALLEY

SANTA CRUZ CO

SANTA BARBARA CO

SAN LUIS OBISPO

SAN BENITO CO

PISMO BEACH

PACIFIC GROVE

MONTEREY CO
MARINA

GUADALUPE

GREENFIELD
GOLETA

CARPINTERIA

CAPITOLA

ARROYO GRANDE
PERCENTAGE OF ELIGIBLE ENROLLMENT AS OF JUNE 1, 2023
III. Media Outreach
May 2023
Social media:

Facebook
Followers: 1,903
Post Reach: 2.5K
Post engagement: 175K
New page followers: 2
Link Clicks: 72
Top Performing Content: Bonny Doon electric school bus
Facebook En Espanol
Followers: 183
Post Reach: 2,307
Post engagement: 54
New page followers: 0
Link Clicks: 6
Top Performing Content: bilingual induction cooking
demonstration
Instagram
Followers: 959
Reach: 3.1K
Top Performing Content: CalCCA Conference photos
New Followers: 18
Twitter
Followers: 1.1K
Top Performing Content: New leadership appointments
LinkedIn
Followers: 1.8K
Top Performing Content: CalCCA Conference photos
Earned media:

POWER Magazine
May 16 · 12:31 PM
How Off-Grid Solar-Powered Electrification Can Drive More Revenue for Agriculture USTimeToday · Bobby Allyn
May 10 · 2:37 PM
Santa Barbara County on track to 100 percent renewable energy by 2030 Santa Cruz Sentinel · Nick Sestanovich
May 10 · 11:13 AM
Watsonville City Council receives update on climate goals CCCE Contracts < $100k
Vendor Total Engagement Amount From To Service Scope Remarks 1 MRW & Associates, LLC $9,000 10/5/2022 12/31/2023 Amendment No. 1 to extend the service term on the agreement dated October 5, 2022 for services providing support for the development of 3CE's 2022 Integrated Resource Plan. 2 Collaborating Learning, Inc. $35,000 5/31/2023 9/30/2023 Facilitation services in building collaboration across the organization in a culture that supports teamwork, open leadership, individual development, and organizational purpose and effectiveness.

Staff Report Item 14
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dennis Dyc-O’Neal, Chief Operating Officer SUBJECT: Approve and authorize CEO to execute the small generator interconnection agreement between Pacific Gas and Electric Company and Central Coast Community Energy in an amount not to exceed $120,000 for the interconnection cost associated with the installation of an energy storage facility at the Emeline project site DATE: August 9, 2023
RECOMMENDATION:

Authorize CEO to execute the Small Generator Interconnection Agreement (SGIA) between Pacific Gas and Electric Company (PG&E) and Central Coast Community Energy (3CE) in an amount not to exceed $120,000 for the interconnection cost associated with the installation of an energy storage facility at the Emeline Project site.

BACKGROUND:

In December 2021, 3CE launched the Front of the Meter Energy Storage (FMES) effort to build 1 to 5 MW sized energy storage systems throughout the 3CE service area. Energy storage provides firmer capacity in that it converts our planned portfolio of intermittent renewable generation resources into dispatchable, more reliable resources, and will allow us to cost-effectively achieve 3CE’s goal of 100% renewable power by 2030. Energy storage also provides grid-level flexibility with its ability to help keep the power system running despite outages during extreme weather.

In June 2022, the Policy Board approved developing, funding, owning, and operating these assets. Phase one of this effort has focused on identifying and using viable member-agency sites to install these batteries.

DISCUSSION/ANALYSIS:

The Emeline Project site, located at 1000 Emeline Ave, Santa Cruz in Santa Cruz County, was provided to 3CE by its member-agency and after conducting our own internal assessments was considered viable. It was then submitted into PG&E’s interconnection process for review by them as the local utility distribution company. It passed their initial screening as a viable site, and PG&E provided an expected cost of $120,000 required for interconnection of a 3 MW energy storage facility at the site.

The detailed expected cost for interconnection is as follows:
 A Pre-energization test, protection review and testing witnessing ($10,000)  PG&E Primary Revenue Metering ($15,000)
 Primary Service-OH (Per location not including Metering ($15,000)  PG&E SCADA Recloser at the POI ($80,000)
If approved, 3CE will then proceed with issuing an RFO to identify and select a qualified contractor to obtain the necessary permits and construct the facility. This will happen in the Fall of 2023.

FISCAL IMPACT:

The fiscal impact of signing this SGIA will have a not to exceed amount of $120,000.00.

CONCLUSION:

Staff recommends that 3CE’s Operations Board of Directors authorize CEO to execute the Small Generator Interconnection Agreement between Pacific Gas and Electric Company and Central Coast Community Energy in an amount not to exceed $120,000 for the interconnection cost associated with the installation of an energy storage facility at the Emeline Project site.

ATTACHMENTS:

1. Emeline SGIA
Internal

SMALL GENERATOR INTERCONNECTION

AGREEMENT (SGIA)
(For Generating Facilities No Larger Than 20 MW)

BETWEEN

PACIFIC GAS AND ELECTRIC COMPANY
AND

CENTRAL COAST COMMUNITY ENERGY
For Project:

Emeline
3243 - WD
Santa Cruz, CA 95060
Santa Cruz County
WDT GIP (2017) SGIA i
Internal

TABLE OF CONTENTS
Page No.

Article 1. Scope and Limitations of Agreement. ............................................................................. 1

1.5 Responsibilities of the Parties ................................................................................ 1

1.6 Parallel Operation Obligations................................................................................ 3

1.7 Metering .................................................................................................................. 3

1.8 Reactive Power....................................................................................................... 3

1.8.1 Power Factor Design Criteria ..................................................................... 3

1.8.2 Deleted ...................................................................................................... 4

1.8.3 Deleted ...................................................................................................... 4

1.8.4 Primary Frequency Response.................................................................... 4 Article 2. Inspection, Testing, Authorization, and Right of Access ................................................ 7

2.1 Equipment Testing and Inspection ......................................................................... 7

2.2 Authorization Required Prior to Parallel Operation................................................ 7

2.3 Right of Access ....................................................................................................... 7 Article 3. Effective Date, Term, Termination, and Disconnection .................................................. 8

3.1 Effective Date.......................................................................................................... 8

3.2 Term of Agreement................................................................................................. 8

3.3 Termination ............................................................................................................. 8

3.4 Temporary Disconnection....................................................................................... 9

3.4.1 Emergency Conditions ............................................................................ 9

3.4.2 Routine Maintenance, Construction, and Repair...................................... 9

3.4.3 Forced Outages....................................................................................... 9

3.4.4 Adverse Operating Effects......................................................................10

3.4.5 Modification of the Small Generating Facility ..........................................10

3.4.6 Reconnection .........................................................................................10 Article 4. Cost Responsibility for Interconnection Facilities and Distribution Upgrades.............. 10

4.1 Interconnection Facilities ...................................................................................... 10

4.2 Distribution Upgrades ........................................................................................... 10 Article 5. Cost Responsibility for Network Upgrades ................................................................... 11

5.1 Applicability ........................................................................................................... 11

5.2 Network Upgrades ................................................................................................ 11

5.2.1 Repayment of Amounts Advanced for Network Upgrades ......................11

5.3 Special Provisions for Affected Systems.............................................................. 12

5.4 Rights Under Other Agreements .......................................................................... 12 Article 6. Billing, Payment, Milestones, and Financial Security ................................................... 12

6.1 Billing and Payment Procedures and Final Accounting ....................................... 12

6.2 Milestones............................................................................................................. 13

6.3 Financial Security Arrangements.......................................................................... 13

6.4 Responsibility for any Outstanding Interconnection Study Costs........................ 14 WDT GIP (2017) SGIA ii
Internal
Article 7. Assignment, Liability, Indemnity, Force Majeure, Consequential Damages, and Default ........................................................................................................................................... 14

7.1 Assignment ........................................................................................................... 14

7.2 Limitation of Liability.............................................................................................. 14

7.3 Indemnity............................................................................................................... 14

7.4 Consequential Damages ...................................................................................... 15

7.5 Force Majeure....................................................................................................... 15

7.6 Default................................................................................................................... 16 Article 8. Insurance ....................................................................................................................... 16 Article 9. Confidentiality ................................................................................................................ 17 Article 10. Disputes....................................................................................................................... 18 Article 11. Taxes ........................................................................................................................... 18 Article 12. Miscellaneous.............................................................................................................. 18

12.1 Governing Law, Regulatory Authority, and Rules ................................................ 19

12.2 Amendment........................................................................................................... 19

12.3 No Third-Party Beneficiaries................................................................................. 19

12.4 Waiver................................................................................................................... 19

12.5 Entire Agreement.................................................................................................. 19

12.6 Multiple Counterparts............................................................................................ 19

12.7 No Partnership ...................................................................................................... 19

12.8 Severability............................................................................................................ 20

12.9 Security Arrangements ......................................................................................... 20

12.10 Environmental Releases....................................................................................... 20

12.11 Subcontractors...................................................................................................... 20

12.12 Reservation of Rights ........................................................................................... 21 Article 13. Notices......................................................................................................................... 21 Attachment 1 – Glossary of Terms
Attachment 2 – Description and Costs of the Small Generating Facility, Interconnection Facilities, and Metering Equipment
Attachment 3 – One-line Diagram Depicting the Small Generating Facility, Interconnection Facilities, Metering Equipment, and Upgrades
Attachment 4 – Milestones
Attachment 5 – Additional Operating Requirements for the Distribution Provider's Distribution and Transmission Systems and Affected Systems Needed to Support the Interconnection Customer’s Needs
Attachment 6 – Distribution Provider's Description of its Upgrades and Best Estimate of Upgrade Costs
WDT GIP (2017) SGIA iii
Internal
WDT GIP (2017) SGIA 1
Internal
This Interconnection Agreement ("Agreement") is made and entered into this ________ day of ________________, 20__ by PACIFIC GAS AND ELECTRIC COMPANY ("Distribution Provider"), and Central Coast Community Energy ("Interconnection Customer"), each hereinafter sometimes referred to individually as "Party" or both referred to collectively as the "Parties."
Distribution Provider Information
Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]
Interconnection Customer Information
Central Coast Community Energy
Attention: Dennis Dyc-O’neal
70 Garden Court, Ste 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
Interconnection Customer Application No: PG&E Project ID # 50O755950, Queue # 3243- WD.

In consideration of the mutual covenants set forth herein, the Parties agree as follows:

Article 1. Scope and Limitations of Agreement

1.1 This Agreement shall be used for all Small Generating Facility Interconnection Requests submitted under the Small Generator Interconnection Procedures (SGIP) or Generator Interconnection Procedures (GIP) except for those submitted under the 10 kW Inverter Process contained in SGIP Attachment 5.

1.2 This Agreement governs the terms and conditions under which the Interconnection Customer’s Small Generating Facility will interconnect with, and operate in parallel with, the Distribution Provider's Distribution System.

1.3 This Agreement does not constitute an agreement to purchase or deliver the Interconnection Customer's power. The purchase or delivery of power and other services that the Interconnection Customer may require will be covered under separate agreements. The Interconnection Customer will be responsible for separately making all necessary arrangements (including scheduling) for delivery of electricity.

1.4 Nothing in this Agreement is intended to affect any other agreement between the Distribution Provider and the Interconnection Customer.

1.5 Responsibilities of the Parties

1.5.1 The Parties shall perform all obligations of this Agreement in accordance with all Applicable Laws and Regulations, Operating Requirements, and Good Utility WDT GIP (2017) SGIA 2
Internal
Practice.

1.5.2 The Interconnection Customer shall construct, interconnect, operate and maintain its Small Generating Facility and construct, operate, and maintain its Interconnection Facilities in accordance with the applicable manufacturer’s recommended maintenance schedule, in accordance with this Agreement, and with Good Utility Practice.

1.5.3 The Distribution Provider shall construct, operate, and maintain its Distribution System, Transmission System and Interconnection Facilities in accordance with this Agreement, and with Good Utility Practice.

1.5.4 The Interconnection Customer agrees to construct its facilities or systems in accordance with applicable specifications that meet or exceed those provided by the National Electrical Safety Code, the American National Standards Institute, IEEE, Underwriter's Laboratory, and Operating Requirements in effect at the time of construction and other applicable national and state codes and standards. The Interconnection Customer agrees to design, install, maintain, and operate its Small Generating Facility so as to reasonably minimize the likelihood of a disturbance adversely affecting or impairing the system or equipment of the Distribution Provider or Affected Systems. The Interconnection Customer shall comply with the Distribution Provider’s Interconnection Handbook. In the event of a conflict between the terms of this SGIA and the terms of the Distribution Provider’s Interconnection Handbook, the terms in this SGIA shall govern.

1.5.5 Each Party shall operate, maintain, repair, and inspect, and shall be fully responsible for the facilities that it now or subsequently may own unless otherwise specified in the Attachments to this Agreement. Each Party shall be responsible for the safe installation, maintenance, repair and condition of their respective lines and appurtenances on their respective sides of the point of change of ownership. The Distribution Provider and the Interconnection Customer, as appropriate, shall provide Interconnection Facilities that adequately protect the Distribution Provider's Distribution and Transmission Systems, personnel, and other persons from damage and injury. The allocation of responsibility for the design, installation, operation, maintenance and ownership of Interconnection Facilities shall be delineated in the Attachments to this Agreement.

1.5.6 The Distribution Provider shall coordinate with all Affected Systems to support the interconnection.

1.5.7 The Interconnection Customer shall ensure “frequency ride through” capability and “voltage ride through” capability of its Small Generating Facility in accordance with the standards and requirements described in the PG&E Transmission Interconnection Handbook (TIH) and the Distribution Interconnection Handbook (DIH). The Interconnection Customer shall enable these capabilities such that its Small Generating Facility shall not disconnect automatically or instantaneously from the system or equipment of the Distribution Provider and any Affected Systems for a defined under-frequency or over-frequency condition, or an under-voltage or over-voltage condition, as tested pursuant to Article 2.1 of this Agreement. The defined conditions shall be in accordance with Good Utility Practice and consistent with any standards and guidelines WDT GIP (2017) SGIA 3
Internal
that are applied to other generating facilities in the Balancing Authority Area on a comparable basis. The Small Generating Facility’s protective equipment settings shall comply with the Distribution Provider’s automatic load-shed program. The Distribution Provider shall review the protective equipment settings to confirm compliance with the automatic load-shed program. The term “ride through” as used herein shall mean the ability of a Small Generating Facility to stay connected to and synchronized with the system or equipment of the Distribution Provider and any Affected Systems during system disturbances within a range of conditions, in accordance with Good Utility Practice and consistent with any standards and guidelines that are applied to other generating facilities in the Balancing Authority on a comparable basis. The term “frequency ride through” as used herein shall mean the ability of a Small Generating Facility to stay connected to and synchronized with the system or equipment of the Distribution Provider and any Affected Systems during system disturbances within a range of under-frequency and over-frequency conditions, in accordance with Good Utility Practice and consistent with any standards and guidelines that are applied to other generating facilities in the Balancing Authority Area on a comparable basis. The term “voltage ride through” as used herein shall mean the ability of a Small Generating Facility to stay connected to and synchronized with the system or equipment of the Distribution Provider and any Affected Systems during system disturbances within a range of under-voltage and over-voltage conditions, in accordance with Good Utility Practice and consistent with any standards and guidelines that are applied to other generating facilities in the Balancing Authority Area on a comparable basis.

1.6 Parallel Operation Obligations
Once the Small Generating Facility has been authorized by the Distribution Provider to commence parallel operation, the Interconnection Customer shall abide by all rules and procedures pertaining to the parallel operation of the Small Generating Facility in the applicable control area, including, but not limited to; 1) the rules and procedures concerning the operation of generation set forth in the Tariff or by the applicable system operator(s) for the Distribution Provider's Distribution and Transmission Systems and; 2) the Operating Requirements set forth in Attachment 5 of this Agreement.

1.7 Metering
The Interconnection Customer shall be responsible for the Distribution Provider's reasonable and necessary cost for the purchase, installation, operation, maintenance, testing, repair, and replacement of metering and data acquisition equipment specified in Attachments 2 and 3 of this Agreement. The Interconnection Customer's metering (and data acquisition, as required) equipment shall conform to applicable industry rules and Operating Requirements.

1.8 Reactive Power

1.8.1 Power Factor Design Criteria

1.8.1.1 Synchronous Generation The Interconnection Customer shall design its Small Generating Facility to maintain a composite power delivery at continuous rated power output at the Point of Interconnection at a power factor within the range of 0.95 leading to 0.95 lagging, unless the Distribution Provider has established different requirements that apply to all similarly situated synchronous generators in the control area on a comparable basis.

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1.8.1.2 Non-Synchronous Generation The Interconnection Customer shall design its Small Generating Facility to maintain a composite power delivery at continuous rated power output at the high-side of the generator substation at a power factor within the range of 0.95 leading to 0.95 lagging, unless the Distribution Provider has established a different power factor range that applies to all similarly situated non-synchronous generators in the control area on a comparable basis. This power factor range standard shall be dynamic and can be met using, for example, power electronics designed to supply this level of reactive capability (taking into account any limitations due to voltage level, real power output, etc.) or fixed and switched capacitors, or a combination of the two. This requirement shall only apply to newly interconnecting nonsynchronous generators that have not yet executed a Facilities Study Agreement as of the effective date of the Final Rule establishing this requirement (Order No. 827).

1.8.2 This Section deleted in FERC Docket No. ER13-494-000..

1.8.3 This Section deleted in FERC Docket No. ER13-494-000.

1.8.4 Primary Frequency Response.

Interconnection Customer shall ensure the primary frequency response capability of its Small Generating Facility by installing, maintaining, and operating a functioning governor or equivalent controls. The term “functioning governor or equivalent controls” as used herein shall mean the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the Small Generating Facility’s real power output in accordance with the droop and deadband parameters and in the direction needed to correct frequency deviations. Interconnection Customer is required to install a governor or equivalent controls with the capability of operating: (1) with a maximum 5 percent droop and ±0.036 Hz deadband; or (2) in accordance with the relevant droop, deadband, and timely and sustained response settings from an approved NERC Reliability Standard providing for equivalent or more stringent parameters. The droop characteristic shall be: (1) based on the nameplate capacity of the Small Generating Facility, and shall be linear in the range of frequencies between 59 to 61 Hz that are outside of the deadband parameter; or (2) based an approved NERC Reliability Standard providing for an equivalent or more stringent parameter. The deadband parameter shall be: the range of frequencies above and below nominal (60 Hz) in which the governor or equivalent controls is not expected to adjust the Small Generating Facility’s real power output in response to frequency deviations. The deadband shall be implemented: (1) without a step to the droop curve, that is, once the frequency deviation exceeds the deadband parameter, the expected change in the Small Generating Facility’s real power output in response to frequency deviations shall start from zero and then increase (for under-frequency deviations) or decrease (for over-frequency deviations) linearly in proportion to the magnitude of the frequency deviation; or (2) in accordance with an approved NERC Reliability Standard providing for an equivalent or more stringent parameter. Interconnection Customer shall notify Transmission Provider that the primary frequency response capability of the WDT GIP (2017) SGIA 5
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Small Generating Facility has been tested and confirmed during commissioning.

Once Interconnection Customer has synchronized the Small Generating Facility with the Transmission System, Interconnection Customer shall operate the Small Generating Facility consistent with the provisions specified in Sections 1.8.4.1 and 1.8.4.2 of this Agreement. The primary frequency response requirements contained herein shall apply to both synchronous and non-synchronous Small Generating Facilities.

1.8.4.1 Governor or Equivalent Controls. Whenever the Small Generating Facility is operated in parallel with the Transmission System, Interconnection Customer shall operate the Small Generating Facility with its governor or equivalent controls in service and responsive to frequency. Interconnection Customer shall: (1) in coordination with Transmission Provider and/or the relevant balancing authority, set the deadband parameter to: (1) a maximum of ±0.036 Hz and set the droop parameter to a maximum of 5 percent; or (2) implement the relevant droop and deadband settings from an approved NERC Reliability Standard that provides for equivalent or more stringent parameters.

Interconnection Customer shall be required to provide the status and settings of the governor or equivalent controls to Transmission Provider and/or the relevant balancing authority upon request. If Interconnection Customer needs to operate the Small Generating Facility with its governor or equivalent controls not in service, Interconnection Customer shall immediately notify Transmission Provider and the relevant balancing authority, and provide both with the following information: (1) the operating status of the governor or equivalent controls (i.e., whether it is currently out of service or when it will be taken out of service); (2) the reasons for removing the governor or equivalent controls from service; and (3) a reasonable estimate of when the governor or equivalent controls will be returned to service. Interconnection Customer shall make Reasonable Efforts to return its governor or equivalent controls into service as soon as practicable. Interconnection Customer shall make Reasonable Efforts to keep outages of the Small Generating Facility’s governor or equivalent controls to a minimum whenever the Small Generating Facility is operated in parallel with the Transmission System.

1.8.4.2 Timely and Sustained Response. Interconnection Customer shall ensure that the Small Generating Facility’s real power response to sustained frequency deviations outside of the deadband setting is automatically provided and shall begin immediately after frequency deviates outside of the deadband, and to the extent the Small Generating Facility has operating capability in the direction needed to correct the frequency deviation. Interconnection Customer shall not block or otherwise inhibit the ability of the governor or equivalent controls to respond and shall ensure that the response is not inhibited, except under certain operational constraints including, but not limited to, ambient temperature limitations, physical energy limitations, outages of mechanical equipment, or regulatory requirements. The Small Generating Facility shall sustain the real power response at least until system frequency returns to a value within the deadband setting of the WDT GIP (2017) SGIA 6
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governor or equivalent controls. A Commission-approved Reliability Standard with equivalent or more stringent requirements shall supersede the above requirements.

1.8.4.3 Exemptions. Small Generating Facilities that are regulated by the United States Nuclear Regulatory Commission shall be exempt from Sections 1.8.4, 1.8.4.1, and 1.8.4.2 of this Agreement. Small Generating Facilities that are behind the meter generation that is sized-to-load (i.e., the thermal load and the generation are near-balanced in real-time operation and the generation is primarily controlled to maintain the unique thermal, chemical, or mechanical output necessary for the operating requirements of its host facility) shall be required to install primary frequency response capability in accordance with the droop and deadband capability requirements specified in Section 1.8.4, but shall be otherwise exempt from the operating requirements in Sections 1.8.4,

1.8.4.1, 1.8.4.2, and 1.8.4.4 of this Agreement.

1.8.4.4 Electric Storage Resources. Interconnection Customer interconnecting an electric storage resource shall establish an operating range in Attachment 5 of its SGIA that specifies a minimum state of charge and a maximum state of charge between which the electric storage resource will be required to provide primary frequency response consistent with the conditions set forth in Sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 of this Agreement. Attachment 5 shall specify whether the operating range is static or dynamic, and shall consider: (1) the expected magnitude of frequency deviations in the interconnection; (2) the expected duration that system frequency will remain outside of the deadband parameter in the interconnection; (3) the expected incidence of frequency deviations outside of the deadband parameter in the interconnection; (4) the physical capabilities of the electric storage resource; (5) operational limitations of the electric storage resource due to manufacturer specifications; and (6) any other relevant factors agreed to by Transmission Provider and Interconnection Customer, and in consultation with the relevant transmission owner or balancing authority as appropriate. If the operating range is dynamic, then Attachment 5 must establish how frequently the operating range will be reevaluated and the factors that may be considered during its reevaluation.

Interconnection Customer’s electric storage resource is required to provide timely and sustained primary frequency response consistent with Section 1.8.4.2 of this Agreement when it is online and dispatched to inject electricity to the Transmission System and/or receive electricity from the Transmission System. This excludes circumstances when the electric storage resource is not dispatched to inject electricity to the Transmission System and/or dispatched to receive electricity from the Transmission System. If Interconnection Customer’s electric storage resource is charging at the time of a frequency deviation outside of its deadband parameter, it is to increase (for over-frequency deviations) or decrease (for under-frequency deviations) the rate at which it is charging in accordance with its droop parameter. Interconnection Customer’s electric storage resource is not required to change from WDT GIP (2017) SGIA 7
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charging to discharging, or vice versa, unless the response necessitated by the droop and deadband settings requires it to do so and it is technically capable of making such a transition.

1.9 Capitalized terms used herein shall have the meanings specified in the Glossary of Terms in Attachment 1 or the body of this Agreement.

Article 2. Inspection, Testing, Authorization, and Right of Access

2.1 Equipment Testing and Inspection

2.1.1 The Interconnection Customer shall test and inspect its Small Generating Facility and Interconnection Facilities prior to interconnection. The Interconnection Customer shall notify the Distribution Provider of such activities no fewer than five Business Days (or as may be agreed to by the Parties) prior to such testing and inspection. Testing and inspection shall occur on a Business Day. The Distribution Provider may, at its own expense, send qualified personnel to the Small Generating Facility site to inspect the interconnection and observe the testing. The Interconnection Customer shall provide the Distribution Provider a written test report when such testing and inspection is completed.

2.1.2 The Distribution Provider shall provide the Interconnection Customer written acknowledgment that it has received the Interconnection Customer's written test report. Such written acknowledgment shall not be deemed to be or construed as any representation, assurance, guarantee, or warranty by the Distribution Provider of the safety, durability, suitability, or reliability of the Small Generating Facility or any associated control, protective, and safety devices owned or controlled by the Interconnection Customer or the quality of power produced by the Small Generating Facility.

2.2 Authorization Required Prior to Parallel Operation

2.2.1 The Distribution Provider shall use Reasonable Efforts to list applicable parallel operation requirements in Attachment 5 of this Agreement. Additionally, the Distribution Provider shall notify the Interconnection Customer of any changes to these requirements as soon as they are known. The Distribution Provider shall make Reasonable Efforts to cooperate with the Interconnection Customer in meeting requirements necessary for the Interconnection Customer to commence parallel operations by the in-service date.

2.2.2 The Interconnection Customer shall not operate its Small Generating Facility in parallel with the Distribution Provider's Distribution System without prior written authorization of the Distribution Provider. The Distribution Provider will provide such authorization once the Distribution Provider receives notification that the Interconnection Customer has complied with all applicable parallel operation requirements. Such authorization shall not be unreasonably withheld, conditioned, or delayed.

2.3 Right of Access
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2.3.1 Upon reasonable notice, the Distribution Provider may send a qualified person to the premises of the Interconnection Customer at or immediately before the time the Small Generating Facility first produces energy to inspect the interconnection, and observe the commissioning of the Small Generating Facility (including any required testing), startup, and operation for a period of up to three Business Days after initial start-up of the unit. In addition, the Interconnection Customer shall notify the Distribution Provider at least five Business Days prior to conducting any on-site verification testing of the Small Generating Facility.

2.3.2 Following the initial inspection process described above, at reasonable hours, and upon reasonable notice, or at any time without notice in the event of an emergency or hazardous condition, the Distribution Provider shall have access to the Interconnection Customer's premises for any reasonable purpose in connection with the performance of the obligations imposed on it by this Agreement or if necessary to meet its legal obligation to provide service to its customers.

2.3.3 Each Party shall be responsible for its own costs associated with following this article.

Article 3. Effective Date, Term, Termination, and Disconnection

3.1 Effective Date
This Agreement shall become effective upon execution by the Parties subject to acceptance by FERC (if applicable), or if filed unexecuted, upon the date specified by the FERC. The Distribution Provider shall promptly file this Agreement with the FERC upon execution, if required.

3.2 Term of Agreement
This Agreement shall become effective on the Effective Date and shall remain in effect for a period of ten years from the Effective Date or such other longer period as the Interconnection Customer may request and shall be automatically renewed for each successive one-year period thereafter, unless terminated earlier in accordance with article 3.3 of this Agreement.

3.3 Termination
No termination shall become effective until the Parties have complied with all Applicable Laws and Regulations applicable to such termination, including the filing with FERC of a notice of termination of this Agreement (if required), which notice has been accepted for filing by FERC.

3.3.1 The Interconnection Customer may terminate this Agreement at any time by giving the Distribution Provider 20 Business Days written notice.

3.3.2 Either Party may terminate this Agreement after Default pursuant to article 7.6.

3.3.3 Upon termination of this Agreement, the Small Generating Facility will be disconnected from the Distribution Provider's Distribution System. The termination of this Agreement shall not relieve either Party of its liabilities and WDT GIP (2017) SGIA 9
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obligations, owed or continuing at the time of the termination.

3.3.4 The provisions of this article shall survive termination or expiration of this Agreement.

3.4 Temporary Disconnection
Temporary disconnection shall continue only for so long as reasonably necessary under Good Utility Practice.

3.4.1 Emergency Conditions -- "Emergency Condition" shall mean a condition or situation: (1) that in the judgment of the Party making the claim is imminently likely to endanger life or property; or (2) that, in the case of the Distribution Provider, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to the Distribution System, the Distribution Provider's Interconnection Facilities any Affected Systems; or (3) that, in the case of the Interconnection Customer, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to, the Small Generating Facility or the Interconnection Customer's Interconnection Facilities. Under Emergency Conditions, the Distribution Provider may immediately suspend interconnection service and temporarily disconnect the Small Generating Facility. The Distribution Provider shall notify the Interconnection Customer promptly when it becomes aware of an Emergency Condition that may reasonably be expected to affect the Interconnection Customer's operation of the Small Generating Facility.

The Interconnection Customer shall notify the Distribution Provider promptly when it becomes aware of an Emergency Condition that may reasonably be expected to affect the Distribution Provider's Distribution System or other Affected Systems. To the extent information is known, the notification shall describe the Emergency Condition, the extent of the damage or deficiency, the expected effect on the operation of both Parties' facilities and operations, its anticipated duration, and the necessary corrective action.

3.4.2 Routine Maintenance, Construction, and Repair
The Distribution Provider may interrupt interconnection service or curtail the output of the Small Generating Facility and temporarily disconnect the Small Generating Facility from the Distribution Provider's Distribution System when necessary for routine maintenance, construction, and repairs on the Distribution Provider's Distribution System and/or Transmission System. The Distribution Provider shall provide the Interconnection Customer with five Business Days notice prior to such interruption. The Distribution Provider shall use Reasonable Efforts to coordinate such reduction or temporary disconnection with the Interconnection Customer.

3.4.3 Forced Outages
During any forced outage, the Distribution Provider may suspend interconnection service to effect immediate repairs on the Distribution Provider's Distribution System and/or Transmission System. The Distribution Provider shall use Reasonable Efforts to provide the Interconnection Customer with prior notice. If prior notice is not given, the Distribution Provider shall, upon request, provide the Interconnection Customer written documentation after the fact explaining the circumstances of the disconnection.

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3.4.4 Adverse Operating Effects
The Distribution Provider shall notify the Interconnection Customer as soon as practicable if, based on Good Utility Practice, operation of the Small Generating Facility may cause disruption or deterioration of service to other customers served from the same electric system, or if operating the Small Generating Facility could cause damage to the Distribution Provider's Distribution System or Affected Systems. Supporting documentation used to reach the decision to disconnect shall be provided to the Interconnection Customer upon request. If, after notice, the Interconnection Customer fails to remedy the adverse operating effect within a reasonable time, the Distribution Provider may disconnect the Small Generating Facility. The Distribution Provider shall provide the Interconnection Customer with five Business Day notice of such disconnection, unless the provisions of article 3.4.1 apply.

3.4.5 Modification of the Small Generating Facility
The Interconnection Customer must receive written authorization from the Distribution Provider before making any change to the Small Generating Facility that may have a material impact on the safety or reliability of the Distribution System and/or Transmission System. Such authorization shall not be unreasonably withheld. Modifications shall be done in accordance with Good Utility Practice. If the Interconnection Customer makes such modification without the Distribution Provider's prior written authorization, the latter shall have the right to temporarily disconnect the Small Generating Facility.

3.4.6 Reconnection
The Parties shall cooperate with each other to restore the Small Generating Facility, Interconnection Facilities, and/or the Distribution Provider's Distribution System or Transmission System to their normal operating state as soon as reasonably practicable following a temporary disconnection.

Article 4. Cost Responsibility for Interconnection Facilities and Distribution Upgrades

4.1 Interconnection Facilities

4.1.1 The Interconnection Customer shall pay for the cost of the Interconnection Facilities itemized in Attachment 2 of this Agreement. The Distribution Provider shall provide a best estimate cost, including overheads, for the purchase and construction of its Interconnection Facilities and provide a detailed itemization of such costs. Costs associated with Interconnection Facilities may be shared with other entities that may benefit from such facilities by agreement of the Interconnection Customer, such other entities, and the Distribution Provider.

4.1.2 The Interconnection Customer shall be responsible for its share of all reasonable expenses, including overheads, associated with (1) owning, operating, maintaining, repairing, and replacing its own Interconnection Facilities, and (2) operating, maintaining, repairing, and replacing the Distribution Provider's Interconnection Facilities.

4.2 Distribution Upgrades
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The Distribution Provider shall design, procure, construct, install, and own the Distribution Upgrades described in Attachment 6 of this Agreement. If the Distribution Provider and the Interconnection Customer agree, the Interconnection Customer may construct Distribution Upgrades that are located on land owned by the Interconnection Customer. The actual cost of the Distribution Upgrades, including overheads, as well as costs associated with operating, maintaining, repairing, and replacing Distribution Provider’s Distribution Upgrades shall be directly assigned to the Interconnection Customer.

Article 5. Cost Responsibility for Network Upgrades

5.1 Applicability
No portion of this Article 5 shall apply unless the interconnection of the Small Generating Facility requires Network Upgrades.

5.2 Network Upgrades
The Distribution Provider or the Transmission Owner shall design, procure, construct, install, and own the Network Upgrades described in Attachment 6 of this Agreement. If the Distribution Provider and the Interconnection Customer agree, the Interconnection Customer may construct Network Upgrades that are located on land owned by the Interconnection Customer. Unless the Distribution Provider elects to pay for Network Upgrades, the actual cost of the Network Upgrades, including overheads, shall be borne by the Interconnection Customer unless Article 5.2.1 directs otherwise.

5.2.1 Repayment of Amounts Advanced for Network Upgrades To the extent the CAISO Tariff, Section 12.3.2 of Appendix Y and Section 14.3.2 of Appendix DD, and successor tariffs provides for cash repayment or Congestion Revenue Rights to the Interconnection Customer for contribution to the cost of Network Upgrades, the Interconnection Customer shall be entitled to a cash repayment of Congestion Revenue Rights, equal to the total amount paid to the Distribution Provider and Affected System operator, if any, for Network Upgrades, including any tax gross-up or other tax-related payments associated with the Network Upgrades, and not otherwise refunded to the Interconnection Customer.

Any repayment shall include interest calculated in accordance with the methodology set forth in FERC’s regulations at 18 C.F.R. 35.19a(a)(2)(iii) from the date of any payment for Network Upgrades through the date on which the Interconnection Customer receives a repayment of such payment pursuant to this subparagraph. The Interconnection Customer may assign such repayment rights to any person.

5.2.1.1 If the Interconnection Customer is entitled to a cash repayment pursuant to Article 5.2.1, the Interconnection Customer, the Distribution Provider, and Affected System operator may adopt any alternative payment schedule that is mutually agreeable so long as the Distribution Provider and Affected System operator take one of the following actions no later than five years from the Commercial Operation Date: (1) return to the Interconnection Customer any amounts advanced for Network Upgrades not previously repaid, or (2) declare in writing that the WDT GIP (2017) SGIA 12
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Distribution Provider or Affected System operator(s) will continue to provide payments to the Interconnection Customer on a dollar-for-dollar basis for the non-usage sensitive portion of transmission charges, or develop an alternative schedule that is mutually agreeable and provides for the return of all amounts advanced for Network Upgrades not previously repaid; however, full reimbursement shall not extend beyond twenty (20) years from the commercial operation date.

5.2.1.2 If the Small Generating Facility fails to achieve commercial operation, but it or another generating facility is later constructed and requires use of the Network Upgrades, the Distribution Provider and Affected System operator shall at that time reimburse the Interconnection Customer for the amounts advanced for the Network Upgrades if the Interconnection Customer is entitled to a cash repayment pursuant to Article 5.2.1.

Before any such reimbursement can occur, the Interconnection Customer, or the entity that ultimately constructs the generating facility, if different, is responsible for identifying the entity to which reimbursement must be made.

5.3 Special Provisions for Affected Systems
Unless the Distribution Provider provides, under this Agreement, for the repayment of amounts advanced to Affected System operator(s) for Network Upgrades, the Interconnection Customer and Affected System operator shall enter into an agreement that provides for such repayment. The agreement shall specify the terms governing payments to be made by the Interconnection Customer to Affected System operator as well as the repayment by Affected System operator.

5.4 Rights Under Other Agreements
Notwithstanding any other provision of this Agreement, nothing herein shall be construed as relinquishing or foreclosing any rights, including but not limited to firm transmission rights, capacity rights, transmission congestion rights, or transmission credits, that the Interconnection Customer shall be entitled to, now or in the future, under any other agreement or tariff as a result of, or otherwise associated with, the transmission capacity, if any, created by the Network Upgrades, including the right to obtain cash reimbursements or transmission credits for transmission service that is not associated with the Small Generating Facility.

Article 6. Billing, Payment, Milestones, and Financial Security

6.1 Billing and Payment Procedures and Final Accounting

6.1.1 The Distribution Provider shall bill the Interconnection Customer for the design, engineering, construction, and procurement costs of Interconnection Facilities and Upgrades contemplated by this Agreement on a monthly basis, or as otherwise agreed by the Parties. The Interconnection Customer shall pay each bill within 30 calendar days of receipt, or as otherwise agreed to by the Parties.

6.1.2 Within six months of completing the construction and installation of the Distribution Provider's Interconnection Facilities and/or Upgrades described in the Attachments to this Agreement, the Distribution Provider shall provide the WDT GIP (2017) SGIA 13
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Interconnection Customer with a final accounting report of any difference between (1) the Interconnection Customer's cost responsibility for the actual cost of such facilities or Upgrades, and (2) the Interconnection Customer's previous aggregate payments to the Distribution Provider for such facilities or Upgrades. If the Interconnection Customer's cost responsibility exceeds its previous aggregate payments, the Distribution Provider shall invoice the Interconnection Customer for the amount due and the Interconnection Customer shall make payment to the Distribution Provider within 30 calendar days. If the Interconnection Customer's previous aggregate payments exceed its cost responsibility under this Agreement, the Distribution Provider shall refund to the Interconnection Customer an amount equal to the difference within 30 calendar days of the final accounting report.

6.2 Milestones
The Parties shall agree on milestones for which each Party is responsible and list them in Attachment 4 of this Agreement. A Party's obligations under this provision may be extended by agreement. If a Party anticipates that it will be unable to meet a milestone for any reason other than an Uncontrollable Force Event, it shall immediately notify the other Party of the reason(s) for not meeting the milestone and (1) propose the earliest reasonable alternate date by which it can attain this and future milestones, and (2) requesting appropriate amendments to Attachment 4. The Party affected by the failure to meet a milestone shall not unreasonably withhold agreement to such an amendment unless (1) it will suffer significant uncompensated economic or operational harm from the delay, (2) attainment of the same milestone has previously been delayed, or (3) it has reason to believe that the delay in meeting the milestone is intentional or unwarranted notwithstanding the circumstances explained by the Party proposing the amendment.

6.3 Financial Security Arrangements
The Interconnection Customer shall provide the Distribution Provider an Interconnection Financial Security by the earliest date of either (i) no later than the financial security posting milestone date negotiated in Attachment 4 of this Agreement, (ii) no later than 180 Calendar Days after the effective date of this agreement, or (iii) at least twenty (20) Business Days prior to the commencement of the design, procurement, installation, or construction of a discrete portion of the Distribution Provider's Interconnection Facilities and Upgrades. The Interconnection Customer shall provide the Distribution Provider, at the Interconnection Customer's option, a guarantee, letter of credit, escrow agreement or other form of security that is reasonably acceptable to the Distribution Provider and is consistent with the Uniform Commercial Code of the jurisdiction where the Point of Interconnection is located. Such security for payment shall be in an amount sufficient to cover the costs for constructing, designing, procuring, and installing the applicable portion of the Distribution Provider's Interconnection Facilities and Upgrades and shall be reduced on a dollar-for-dollar basis for payments made to the Distribution Provider under this Agreement during its term. In addition:

6.3.1 The guarantee must be made by an entity that meets the creditworthiness requirements of the Distribution Provider, and contain terms and conditions that guarantee payment of any amount that may be due from the Interconnection Customer, up to an agreed-to maximum amount.

6.3.2 The letter of credit or escrow agreement must be issued by a financial institution or insured reasonably acceptable to the Distribution Provider and must specify a WDT GIP (2017) SGIA 14
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reasonable expiration date.

6.4 Responsibility for any Outstanding Interconnection Study Costs The Interconnection Customer must complete payment on all outstanding invoiced interconnection study costs no later than the financial security posting milestone date negotiated in Attachment 4 of this Agreement. Study costs not yet invoiced within thirty (30) Calendar Days of that financial security posting deadline must be paid by the Interconnection Customer within thirty (30) Calendar Days of the date of the invoice once they are invoiced to the Interconnection Customer.

Failure to complete payment on these interconnection study invoices by these deadlines will constitute Default on this Agreement by the Interconnection Customer, subject to the terms of Article 7.6 “Default”.

Article 7. Assignment, Liability, Indemnity, Uncontrollable Force, Consequential Damages, and Default

7.1 Assignment
This Agreement may be assigned by either Party upon fifteen (15) Business Days prior written notice and opportunity to object by the other Party; provided that:

7.1.1 Either Party may assign this Agreement without the consent of the other Party to any affiliate of the assigning Party with an equal or greater credit rating and with the legal authority and operational ability to satisfy the obligations of the assigning Party under this Agreement;

7.1.2 The Interconnection Customer shall have the right to assign this Agreement, without the consent of the Distribution Provider, for collateral security purposes to aid in providing financing for the Small Generating Facility, provided that the Interconnection Customer will promptly notify the Distribution Provider of any such assignment.

7.1.3 Any attempted assignment that violates this article is void and ineffective.

Assignment shall not relieve a Party of its obligations, nor shall a Party's obligations be enlarged, in whole or in part, by reason thereof. An assignee is responsible for meeting the same financial, credit, and insurance obligations as the Interconnection Customer. Where required, consent to assignment will not be unreasonably withheld, conditioned or delayed.

7.2 Limitation of Liability
Each Party's liability to the other Party for any loss, cost, claim, injury, liability, or expense, including reasonable attorney's fees, relating to or arising from any act or omission in its performance of this Agreement, shall be limited to the amount of direct damage actually incurred. In no event shall either Party be liable to the other Party for any indirect, special, consequential, or punitive damages, except as authorized by this Agreement.

7.3 Indemnity
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7.3.1 This provision protects each Party from liability incurred to third parties as a result of carrying out the provisions of this Agreement. Liability under this provision is exempt from the general limitations on liability found in article 7.2.

7.3.2 The Parties shall at all times indemnify, defend, and hold the other Party harmless from, any and all damages, losses, claims, including claims and actions relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the other Party's action or failure to meet its obligations under this Agreement on behalf of the indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the indemnified Party.

7.3.3 If an indemnified person is entitled to indemnification under this article as a result of a claim by a third party, and the indemnifying Party fails, after notice and reasonable opportunity to proceed under this article, to assume the defense of such claim, such indemnified person may at the expense of the indemnifying Party contest, settle or consent to the entry of any judgment with respect to, or pay in full, such claim.

7.3.4 If an indemnifying party is obligated to indemnify and hold any indemnified person harmless under this article, the amount owing to the indemnified person shall be the amount of such indemnified person's actual loss, net of any insurance or other recovery.

7.3.5 Promptly after receipt by an indemnified person of any claim or notice of the commencement of any action or administrative or legal proceeding or investigation as to which the indemnity provided for in this article may apply, the indemnified person shall notify the indemnifying party of such fact. Any failure of or delay in such notification shall not affect a Party's indemnification obligation unless such failure or delay is materially prejudicial to the indemnifying party.

7.4 Consequential Damages
Other than as expressly provided for in this Agreement, neither Party shall be liable under any provision of this Agreement for any losses, damages, costs or expenses for any special, indirect, incidental, consequential, or punitive damages, including but not limited to loss of profit or revenue, loss of the use of equipment, cost of capital, cost of temporary equipment or services, whether based in whole or in part in contract, in tort, including negligence, strict liability, or any other theory of liability; provided, however, that damages for which a Party may be liable to the other Party under another agreement will not be considered to be special, indirect, incidental, or consequential damages hereunder.

7.5 Uncontrollable Force

7.5.1 As used in this article, an Uncontrollable Force shall mean "any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm, flood, earthquake, explosion, breakage or accident to machinery or equipment, any curtailment, order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or any other cause beyond the WDT GIP (2017) SGIA 16
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reasonable control of the Distribution Provider or Interconnection Customer which could not be avoided through the exercise of Good Utility Practice. An Uncontrollable Force Event does not include an act of negligence or intentional wrongdoing by the Party claiming Uncontrollable Force."

7.5.2 If an Uncontrollable Force Event prevents a Party from fulfilling any obligations under this Agreement, the Party affected by the Uncontrollable Force Event (Affected Party) shall promptly notify the other Party, either in writing or via the telephone, of the existence of the Uncontrollable Force Event. The notification must specify in reasonable detail the circumstances of the Uncontrollable Force Event, its expected duration, and the steps that the Affected Party is taking to mitigate the effects of the event on its performance. The Affected Party shall keep the other Party informed on a continuing basis of developments relating to the Uncontrollable Force Event until the event ends. The Affected Party will be entitled to suspend or modify its performance of obligations under this Agreement (other than the obligation to make payments) only to the extent that the effect of the Uncontrollable Force Event cannot be mitigated by the use of Reasonable Efforts. The Affected Party will use Reasonable Efforts to resume its performance as soon as possible.

7.6 Default

7.6.1 No Default shall exist where such failure to discharge an obligation (other than the payment of money) is the result of an Uncontrollable Force Event as defined in this Agreement or the result of an act or omission of the other Party. Upon a Default, the non-defaulting Party shall give written notice of such Default to the defaulting Party. Except as provided in article 7.6.2, the defaulting Party shall have 60 calendar days from receipt of the Default notice within which to cure such Default; provided however, if such Default is not capable of cure within 60 calendar days, the defaulting Party shall commence such cure within 20 calendar days after notice and continuously and diligently complete such cure within six months from receipt of the Default notice; and, if cured within such time, the Default specified in such notice shall cease to exist.

7.6.2 If a Default is not cured as provided in this article, or if a Default is not capable of being cured within the period provided for herein, the non-defaulting Party shall have the right to terminate this Agreement by written notice at any time until cure occurs, and be relieved of any further obligation hereunder and, whether or not that Party terminates this Agreement, to recover from the defaulting Party all amounts due hereunder, plus all other damages and remedies to which it is entitled at law or in equity. The provisions of this article will survive termination of this Agreement.

Article 8. Insurance

8.1 The Interconnection Customer shall, at its own expense, maintain in force general liability insurance without any exclusion for liabilities related to the interconnection undertaken pursuant to this Agreement. The amount of such insurance shall be sufficient to insure against all reasonably foreseeable direct liabilities given the size and nature of the generating equipment being interconnected, the interconnection itself, and the WDT GIP (2017) SGIA 17
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characteristics of the system to which the interconnection is made. The Interconnection Customer shall obtain additional insurance only if necessary as a function of owning and operating a generating facility. Such insurance shall be obtained from an insurance provider authorized to do business in the State where the interconnection is located.

Certification that such insurance is in effect shall be provided upon request of the Distribution Provider, except that the Interconnection Customer shall show proof of insurance to the Distribution Provider no later than ten Business Days prior to the anticipated commercial operation date. An Interconnection Customer of sufficient credit-worthiness may propose to self-insure for such liabilities, and such a proposal shall not be unreasonably rejected.

8.2 The Distribution Provider agrees to maintain general liability insurance or self-insurance consistent with the Distribution Provider’s commercial practice. Such insurance or self-insurance shall not exclude coverage for the Distribution Provider's liabilities undertaken pursuant to this Agreement.

8.3 The Parties further agree to notify each other whenever an accident or incident occurs resulting in any injuries or damages that are included within the scope of coverage of such insurance, whether or not such coverage is sought.

Article 9. Confidentiality

9.1 Confidential Information shall mean any confidential and/or proprietary information provided by one Party to the other Party that is clearly marked or otherwise designated "Confidential." For purposes of this Agreement all design, operating specifications, and metering data provided by the Interconnection Customer shall be deemed Confidential Information regardless of whether it is clearly marked or otherwise designated as such.

9.2 Confidential Information does not include information previously in the public domain, required to be publicly submitted or divulged by Governmental Authorities (after notice to the other Party and after exhausting any opportunity to oppose such publication or release), or necessary to be divulged in an action to enforce this Agreement. Each Party receiving Confidential Information shall hold such information in confidence and shall not disclose it to any third party nor to the public without the prior written authorization from the Party providing that information, except to fulfill obligations under this Agreement, or to fulfill legal or regulatory requirements.

9.2.1 Each Party shall employ at least the same standard of care to protect Confidential Information obtained from the other Party as it employs to protect its own Confidential Information.

9.2.2 Each Party is entitled to equitable relief, by injunction or otherwise, to enforce its rights under this provision to prevent the release of Confidential Information without bond or proof of damages, and may seek other remedies available at law or in equity for breach of this provision.

9.3 Notwithstanding anything in this article to the contrary, and pursuant to 18 CFR § 1 b.20, if FERC, during the course of an investigation or otherwise, requests information from one of the Parties that is otherwise required to be maintained in confidence pursuant to this Agreement, the Party shall provide the requested information to FERC, within the WDT GIP (2017) SGIA 18
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time provided for in the request for information. In providing the information to FERC, the Party may, consistent with 18 CFR § 388.112, request that the information be treated as confidential and non-public by FERC and that the information be withheld from public disclosure. Parties are prohibited from notifying the other Party to this Agreement prior to the release of the Confidential Information to FERC. The Party shall notify the other Party to this Agreement when it is notified by FERC that a request to release Confidential Information has been received by FERC, at which time either of the Parties may respond before such information would be made public, pursuant to 18 CFR § 388.112. Requests from a state regulatory body conducting a confidential investigation shall be treated in a similar manner if consistent with the applicable state rules and regulations.

Article 10. Disputes

10.1 The Parties agree to attempt to resolve all disputes arising out of the interconnection process according to the provisions of this article.

10.2 In the event of a dispute, either Party shall provide the other Party with a written Notice of Dispute. Such Notice shall describe in detail the nature of the dispute.

10.3 If the dispute has not been resolved within two Business Days after receipt of the Notice, either Party may contact FERC's Dispute Resolution Service (DRS) for assistance in resolving the dispute.

10.4 The DRS will assist the Parties in either resolving their dispute or in selecting an appropriate dispute resolution venue (e.g., mediation, settlement judge, early neutral evaluation, or technical expert) to assist the Parties in resolving their dispute. DRS can be reached at 1-877-337-2237 or via the internet at http://www.ferc.gov/legal/adr.asp.

10.5 Each Party agrees to conduct all negotiations in good faith and will be responsible for one-half of any costs paid to neutral third-parties.

10.6 If neither Party elects to seek assistance from the DRS, or if the attempted dispute resolution fails, then either Party may exercise whatever rights and remedies it may have in equity or law consistent with the terms of this Agreement.

Article 11. Taxes

11.1 The Parties agree to follow all applicable tax laws and regulations, consistent with FERC policy and Internal Revenue Service requirements.

11.2 Each Party shall cooperate with the other to maintain the other Party's tax status.

Nothing in this Agreement is intended to adversely affect the Distribution Provider's tax exempt status with respect to the issuance of bonds including, but not limited to, local furnishing bonds.

Article 12. Miscellaneous
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12.1 Governing Law, Regulatory Authority, and Rules
The validity, interpretation and enforcement of this Agreement and each of its provisions shall be governed by the laws of the state of California (where the Point of Interconnection is located), without regard to its conflicts of law principles. This Agreement is subject to all Applicable Laws and Regulations. Each Party expressly reserves the right to seek changes in, appeal, or otherwise contest any laws, orders, or regulations of a Governmental Authority.

12.2 Amendment
The Parties may amend this Agreement by a written instrument duly executed by both Parties.

12.3 No Third-Party Beneficiaries
This Agreement is not intended to and does not create rights, remedies, or benefits of any character whatsoever in favor of any persons, corporations, associations, or entities other than the Parties, and the obligations herein assumed are solely for the use and benefit of the Parties, their successors in interest and where permitted, their assigns.

12.4 Waiver

12.4.1 The failure of a Party to this Agreement to insist, on any occasion, upon strict performance of any provision of this Agreement will not be considered a waiver of any obligation, right, or duty of, or imposed upon, such Party.

12.4.2 Any waiver at any time by either Party of its rights with respect to this Agreement shall not be deemed a continuing waiver or a waiver with respect to any other failure to comply with any other obligation, right, duty of this Agreement.

Termination or default of this Agreement for any reason by Interconnection Customer shall not constitute a waiver of the Interconnection Customer's legal rights to obtain an interconnection from the Distribution Provider. Any waiver of this Agreement shall, if requested, be provided in writing.

12.5 Entire Agreement
This Agreement, including all Attachments, constitutes the entire agreement between the Parties with reference to the subject matter hereof, and supersedes all prior and contemporaneous understandings or agreements, oral or written, between the Parties with respect to the subject matter of this Agreement. There are no other agreements, representations, warranties, or covenants which constitute any part of the consideration for, or any condition to, either Party's compliance with its obligations under this Agreement.

12.6 Multiple Counterparts
This Agreement may be executed in two or more counterparts, each of which is deemed an original but all constitute one and the same instrument.

12.7 No Partnership
This Agreement shall not be interpreted or construed to create an association, joint venture, agency relationship, or partnership between the Parties or to impose any partnership obligation or partnership liability upon either Party. Neither Party shall have any right, power or authority to enter into any agreement or undertaking for, or act on WDT GIP (2017) SGIA 20
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behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other Party.

12.8 Severability
If any provision or portion of this Agreement shall for any reason be held or adjudged to be invalid or illegal or unenforceable by any court of competent jurisdiction or other Governmental Authority, (1) such portion or provision shall be deemed separate and independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable the benefits to each Party that were affected by such ruling, and (3) the remainder of this Agreement shall remain in full force and effect.

12.9 Security Arrangements
Infrastructure security of electric system equipment and operations and control hardware and software is essential to ensure day-to-day reliability and operational security. FERC expects all transmission providers, market participants, and interconnection customers interconnected to electric systems to comply with the recommendations offered by the President's Critical Infrastructure Protection Board and, eventually, best practice recommendations from the electric reliability authority. All public utilities are expected to meet basic standards for system infrastructure and operational security, including physical, operational, and cyber-security practices.

12.10 Environmental Releases
Each Party shall notify the other Party, first orally and then in writing, of the release of any hazardous substances, any asbestos or lead abatement activities, or any type of remediation activities related to the Small Generating Facility or the Interconnection Facilities, each of which may reasonably be expected to affect the other Party. The notifying Party shall (1) provide the notice as soon as practicable, provided such Party makes a good faith effort to provide the notice no later than 24 hours after such Party becomes aware of the occurrence, and (2) promptly furnish to the other Party copies of any publicly available reports filed with any governmental authorities addressing such events.

12.11 Subcontractors
Nothing in this Agreement shall prevent a Party from utilizing the services of any subcontractor as it deems appropriate to perform its obligations under this Agreement; provided, however, that each Party shall require its subcontractors to comply with all applicable terms and conditions of this Agreement in providing such services and each Party shall remain primarily liable to the other Party for the performance of such subcontractor.

12.11.1 The creation of any subcontract relationship shall not relieve the hiring Party of any of its obligations under this Agreement. The hiring Party shall be fully responsible to the other Party for the acts or omissions of any subcontractor the hiring Party hires as if no subcontract had been made; provided, however, that in no event shall the Distribution Provider be liable for the actions or inactions of the Interconnection Customer or its subcontractors with respect to obligations of the Interconnection Customer under this Agreement. Any applicable obligation imposed by this Agreement upon the hiring Party shall be equally binding upon, and shall be construed as having application to, any subcontractor of such Party.

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of subcontractor’s insurance.

12.12 Reservation of Rights
The Distribution Provider shall have the right to make a unilateral filing with FERC to modify this Agreement with respect to any rates, terms and conditions, charges, classifications of service, rule or regulation under section 205 or any other applicable provision of the Federal Power Act and FERC's rules and regulations thereunder, and the Interconnection Customer shall have the right to make a unilateral filing with FERC to modify this Agreement under any applicable provision of the Federal Power Act and FERC's rules and regulations; provided that each Party shall have the right to protest any such filing by the other Party and to participate fully in any proceeding before FERC in which such modifications may be considered. Nothing in this Agreement shall limit the rights of the Parties or of FERC under sections 205 or 206 of the Federal Power Act and FERC's rules and regulations, except to the extent that the Parties otherwise agree as provided herein.

Article 13. Notices

13.1 General
Unless otherwise provided in this Agreement, any written notice, demand, or request required or authorized in connection with this Agreement ("Notice") shall be deemed properly given if delivered in person, delivered by recognized national courier service, or sent by first class mail, postage prepaid, to the person specified below:

If to the Interconnection Customer:

Central Coast Community Energy
Attention: Dennis Dyc-O’neal
70 Garden Court, Ste 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
If to the Distribution Provider:

Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]

13.2 Billing and Payment
Billings and payments shall be sent to the addresses below:

Interconnection Customer:

Central Coast Community Energy
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Attention: Dewayne Woods
70 Garden Court, Ste 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
Distribution Provider:

Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]

13.3 Alternative Forms of Notice
Any notice or request required or permitted to be given by either Party to the other and not required by this Agreement to be given in writing may be so given by telephone, facsimile or e-mail to the telephone numbers and e-mail addresses set out below:

If to the Interconnection Customer:

Central Coast Community Energy
Attention: Dennis Dyc-O’neal
70 Garden Court, Ste 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
If to the Distribution Provider:

Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]

13.4 Designated Operating Representative
The Parties may also designate operating representatives to conduct the communications which may be necessary or convenient for the administration of this Agreement. This person will also serve as the point of contact with respect to operations and maintenance of the Party’s facilities.

Interconnection Customer’s Operating Representative:

Central Coast Community Energy
Attention: Dennis Dyc-O’neal
70 Garden Court, Ste 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
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Distribution Provider’s Operating Representative:

Pacific Gas and Electric Company
Concord Distribution Control Center
1020 Detroit Ave., Concord, CA 94518
Work Management Desk (Planned Clearance Requests)
Attention: Santa Cruz District (AOR 6- Central Coast Division) Phone: 844-743-2100
Real Time Operator Desk (Real Time Operational Issues)
Attention: Santa Cruz District (AOR 6- Central Coast Division) Phone: 844-743-3322

13.5 Changes to the Notice Information
Either Party may change this information by giving five Business Days written notice prior to the effective date of the change.

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Article 14. Signatures
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their respective duly authorized representatives.

For the Distribution Provider: Pacific Gas and Electric Company Signature:

Name: Michael Porter
Title: Manager, EGI Wholesale Operations
Date:

For the Interconnection Customer: Full Company/Customer Name Signature:

Name: Robert Shaw
Title: CEO
Date:

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Attachment 1
Glossary of Terms
Adverse System Impact -- A potential or actual negative effect due to technical or operational limits on conductors or equipment being exceeded that may compromise the safety and reliability of the electric system.

Affected System – An electric system other than the Distribution Provider's Distribution System that may be affected by the proposed interconnection, including but not limited to the Transmission System.

Affected System Operator -- The entity that operates an Affected System.

Affiliate -- With respect to a corporation, partnership or other entity, each such other corporation, partnership or other entity that directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with, such corporation, partnership or other entity.

Applicable Laws and Regulations -- All duly promulgated applicable federal, state and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders, permits and other duly authorized actions of any Governmental Authority.

Applicable Reliability Council -- The reliability council applicable to the Distribution System to which the Generating Facility is directly interconnected.

Applicable Reliability Standards -- The requirements and guidelines of NERC, the Applicable Reliability Council, and the Control Area of the Distribution System to which the Generating Facility is directly interconnected, including the requirements pursuant to Section 215 of the Federal Power Act.

Area Deliverability Constraint -- A transmission system operating limit, that would constrain the deliverability of a substantial number of generators if the CAISO were to assign full capacity or partial capacity deliverability status to additional generating facilities in one or more specified geographic or electrical areas of the CAISO Controlled Grid in a total amount that is greater than the TP Deliverability for those areas. May also be a transmission system operating limit that constrains a quantity of generation in a local area of the grid that is larger than the generation amount identified in the applicable Transmission Planning Process (TPP) portfolio for the entire portfolio area. May also be a transmission system operating limit that constrains all or most of the same generation already constrained by a previously identified Area Deliverability Constraint.

Area Delivery Network Upgrade (ADNU) -- A transmission upgrade or addition identified by the CAISO to relieve an Area Deliverability Constraint.

Base Case – The data including, but not limited to, base power flow, short circuit and stability data bases, underlying load, generation, and transmission facility assumptions, contingency lists, including relevant special protection systems, and transmission diagrams used to perform the Interconnection Studies. The Base Case may include Critical Energy Infrastructure Information (as that term is defined by FERC). The Base Case shall include transmission facilities as approved by the Distribution Provider or CAISO, as applicable, and Distribution Upgrades and Network Upgrades associated with generating facilities in (iv) below and generating facilities that (i) are directly interconnected to the Distribution System or CAISO Grid; (ii) are interconnected to Affected Systems and may have an impact on the Interconnection Request; (iii) have a pending request to interconnect to the Distribution System or an Affected System; or (iv) are not interconnected to the Distribution System or CAISO Grid, but are subject to a fully executed generator interconnection agreement (or its equivalent predecessor agreement) or for which an WDT GIP (2017) SGIA 26
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unexecuted generator interconnection agreement (or its equivalent predecessor agreement) has been requested to be filed with FERC.

Breach -- The failure of a Party to perform or observe any material term or condition of the GIA.

Breaching Party – A Party that is in Breach of the GIA.

Business Day – Monday through Friday, excluding Federal Holidays and the Friday after Thanksgiving.

Calendar Day -- Any day including Saturday, Sunday or a Federal Holiday.

CAISO – California Independent System Operator Corporation. See also ISO.

Clustering -- The process whereby a group of Interconnection Requests is studied together, instead of serially, for the purpose of conducting the Interconnection System Impact Study.

Commercial Operation -- The status of a Generating Facility that has commenced generating electricity for sale, excluding electricity generated during Trial Operation.

Commercial Operation Date – The date on which an Electric Generating Unit at a Generating Facility has received final written Permission to Operate from the Distribution Provider for operation of the generation facilities in parallel with the utility.

Confidential Information -- Any confidential, proprietary or trade secret information of a plan, specification, pattern, procedure, design, device, list, concept, policy or compilation relating to the present or planned business of a Party, which is designated as confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection, or otherwise.

Construction Activities -- Actions by the Distribution Provider that result in irrevocable financial commitments for the purchase of major electrical equipment or land for Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades assigned to the Interconnection Customer that occur after receipt of all appropriate governmental approvals needed for the Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades.

Control Area -- An electrical system or systems bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other Control Areas and contributing to frequency regulation of the interconnection. A Control Area must be certified by an Applicable Reliability Council.

CPUC -- California Public Utilities Commission.

Default – The failure of a breaching Party to cure its Breach under the Small Generator Interconnection Agreement.

Deliverability -- (1) The annual Net Qualifying Capacity of a Generating Facility, as verified through a Deliverability assessment and measured in MW, which specifies the amount of resource adequacy capacity the Generating Facility is eligible to provide. (2) The annual Maximum Import Capability of an intertie, which specifies the amount of resource adequacy capacity, measured in MW, that Load-serving Entities collectively can procure from imports at that intertie to meet their resource adequacy requirements.

Deliverability Assessment -- An evaluation of the On-Peak Deliverability Assessment set forth in GIP Section 5.8.3, and the Off-Peak Deliverability Assessment set forth in GIP Section 5.8.3 to determine if a Generating Facility or a group of Generating Facilities could provide Energy to the CAISO Controlled Grid WDT GIP (2017) SGIA 27
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and be delivered to the aggregate of Load on the CAISO Controlled Grid at Peak Load, under a variety of severely stressed conditions.

Deliverability Status -- An attribute of a Generating Facility that is requested by an Interconnection Customer for the Generating Facility, assigned by the CAISO to the Generating Facility through the GIP, GIDAP, or other process specified in the CAISO tariff, and that affects the maximum Net Qualifying Capacity to which the Generating Facility could be entitled.

Delivery Network Upgrades -- The transmission facilities at or beyond the point where the Distribution Provider’s Distribution System interconnects to the ISO Grid, other than Reliability Network Upgrades, identified in the Interconnection Studies to relieve constraints on the ISO Grid. Delivery Network Upgrades may be further classified as Local Delivery Network Upgrades or Area Delivery Network Upgrades.

Dispute Resolution -- The procedure for resolution of a dispute between the Parties in which they will first attempt to resolve the dispute on an informal basis.

Distribution Owner – The entity that owns, leases, or otherwise possesses an interest in the portion of the Distribution System at the Point of Interconnection and may be a Party to the Small Generator Interconnection Agreement to the extent necessary.

Distribution Provider – The public utility (or its designated agent) that owns, controls, or operates transmission or distribution facilities used for the transmission of electricity in interstate commerce and provides transmission or wholesale distribution service under the Tariff. The term Distribution Provider should be read to include the Distribution Owner when the Distribution Owner is separate from the Distribution Provider.

Distribution Provider's Interconnection Facilities -- All facilities and equipment owned, controlled, or operated by the Distribution Provider from the Point of Change of Ownership to the Point of Interconnection as identified in the GIA, including any modifications, additions or upgrades to such facilities and equipment. Distribution Provider's Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Stand Alone Network Upgrades or Network Upgrades.

Distribution Service -- The wholesale distribution service provided under the Tariff.

Distribution System – Those non-ISO transmission and distribution facilities owned, controlled and operated by the Distribution Provider that are used to provide distribution service under the Tariff, which facilities and equipment are used to transmit electricity to ultimate usage points such as homes and industries directly from nearby generators or from interchanges with higher voltage transmission networks which transport bulk power over longer distances. The voltage levels at which Distribution Systems operate differ among areas.

Distribution Upgrades – The additions, modifications, and upgrades to the Distribution Provider's Distribution System at or beyond the Point of Interconnection to facilitate interconnection of the Small Generating Facility and render the service necessary to effect the Interconnection Customer's wholesale sale of electricity in interstate commerce. Distribution Upgrades do not include Interconnection Facilities.

Effective Date -- The date on which the GIA becomes effective upon execution by the Parties subject to acceptance by FERC, or if filed unexecuted, upon the date specified by FERC.

Electric Generating Unit -- An individual electric generator and its associated plant and apparatus whose electrical output is capable of being separately identified and metered.

Emergency Condition -- A condition or situation: (1) that in the judgment of the Party making the claim is imminently likely to endanger life or property; or (2) that, in the case of a Distribution Provider, is WDT GIP (2017) SGIA 28
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imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to Distribution Provider's Distribution System, Distribution Provider's Interconnection Facilities or the electric systems of others to which the Distribution Provider's Distribution System is directly connected; or (3) that, in the case of Interconnection Customer, is imminently likely (as determined in a nondiscriminatory manner) to cause a material adverse effect on the security of, or damage to, the Generating Facility or Interconnection Customer's Interconnection Facilities. System restoration and black start shall be considered Emergency Conditions; provided that Interconnection Customer is not obligated by the GIA to possess black start capability.

Energy-Only Deliverability Status -- A condition elected by an Interconnection Customer for a Generating Facility interconnected to Distribution System, the result of which is that the Interconnection Customer is responsible only for the costs of Reliability Network Upgrades and is not responsible for the costs of Delivery Network Upgrades, but the Generating Facility will be deemed to have a Net Qualifying Capacity (as defined in the ISO Tariff) of zero and, therefore, cannot be considered to be a Resource Adequacy Resource (as defined in the ISO Tariff).

Engineering & Procurement (E&P) Agreement -- An agreement that authorizes the Distribution Provider to begin engineering and procurement of long lead-time items necessary for the establishment of the interconnection in order to advance the implementation of the Interconnection Request.

Environmental Law – The applicable Laws or Regulations relating to pollution or protection of the environment or natural resources.

Federal Power Act -- The Federal Power Act, as amended, 16 U.S.C. §§ 791a et seq.

FERC -- The Federal Energy Regulatory Commission (Commission) or its successor.

Full Capacity Deliverability Status (FCDS) – The condition whereby a Generating Facility interconnected with the Distribution System, under coincident ISO Control Area peak demand and a variety of severely stressed system conditions, can deliver the Generating Facility’s full output to the aggregate of load on the ISO Grid, consistent with the ISO’s reliability criteria and procedures and the ISO’s On-Peak Deliverability Assessment.

Generating Facility – The Interconnection Customer's device for the production and/or storage for later injection of electricity identified in the Interconnection Request, but shall not include the Interconnection Customer's Interconnection Facilities. A Small Generating Facility is one that has maximum capacity of 20 MW or less. A Large Generating Facility is one that has a maximum capacity of more than 20 MW.

Generating Facility Capacity -- The net capacity of the Generating Facility and the aggregate net capacity of the Generating Facility where it includes multiple Electric Generating Units.

Generator Interconnection Agreement (GIA) – Either the Small Generator Interconnection Agreement (SGIA), which is Attachment F to the Wholesale Distribution Tariff, unless the proposed interconnection is for a generating facility larger than 20 MW, in which case references to interconnection agreement are to the Large Generator Interconnection Agreement (LGIA), which is Attachment H to the Wholesale Distribution Tariff.

Generator Interconnection and Deliverability Allocation Procedures (GIDAP) – See ISO’s Generator Interconnection and Deliverability Allocation Procedures (ISO Tariff GIDAP) Generator Interconnection Procedures (GIP) – See the definition for either ISO’s Tariff Generator Interconnection Procedures (ISO Tariff GIP), or Wholesale Distribution Tariff Generator Interconnection Procedures (WDT GIP).

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Good Utility Practice – Any of the practices, methods and acts engaged in or approved by a significant portion of the electric industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region.

Governmental Authority – Any federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the Parties, their respective facilities, or the respective services they provide, and exercising or entitled to exercise any administrative, executive, police, or taxing authority or power; provided, however, that such term does not include the Interconnection Customer, the Interconnection Provider, or any Affiliate thereof.

Initial Synchronization Date -- The date upon which the Generating Facility is initially synchronized and upon which Trial Operation begins.

In-Service Date -- The date upon which the Interconnection Customer reasonably expects it will be ready to begin use of the Distribution Provider's Interconnection Facilities to obtain back feed power.

Interconnection Customer – Any entity, including the Distribution Provider, the Distribution Owner, the Transmission Owner or any of the affiliates or subsidiaries of either, that proposes to interconnect its Small Generating Facility with the Distribution Provider's Distribution System.

Interconnection Customer's Interconnection Facilities – All facilities and equipment, as identified in the GIA, that are located between the Generating Facility and the Point of Change of Ownership, including any modification, addition, or upgrades to such facilities and equipment necessary to physically and electrically interconnect the Generating Facility to the Distribution Provider's Distribution System.

Interconnection Customer's Interconnection Facilities are sole use facilities.

Interconnection Facilities – The Distribution Provider's Interconnection Facilities and the Interconnection Customer's Interconnection Facilities. Collectively, Interconnection Facilities include all facilities and equipment between the Small Generating Facility and the Point of Interconnection, including any modification, additions or upgrades that are necessary to physically and electrically interconnect the Small Generating Facility to the Distribution Provider's Distribution System. Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades or Network Upgrades.

Interconnection Financial Security -- The financial instrument(s) submitted by the Interconnection Customer to the Distribution Provider prior to the start of any Construction Activities as a security for the Distribution Provider against the estimated costs of the Construction Activities described in the Generator Interconnection Agreement. The Interconnection Customer may post the Interconnection Financial Security using any of the financial instruments listed in the WDT GIP.

Interconnection Handbook - A handbook, developed by the Distribution Provider and posted on the Distribution Provider’s website or otherwise made available by the Distribution Provider, describing the technical and operational requirements for wholesale generators and loads connected to the Distribution System, as such handbook may be modified or superseded from time to time. In the event of a conflict between the terms of this SGIA and the terms of the Distribution Provider’s Interconnection Handbook, the terms in this SGIA shall govern.

Interconnection Request – The Interconnection Customer's request, in accordance with the Tariff, to interconnect a new Small Generating Facility, or to increase the capacity of, or make a Material Modification to the operating characteristics of, an existing Small Generating Facility that is interconnected with the Distribution Provider’s Distribution System.

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Interconnection Service -- The service provided by the Distribution Provider associated with interconnecting the Interconnection Customer's Generating Facility to the Distribution Provider's Distribution System and enabling it to receive electric energy and capacity from the Generating Facility at the Point of Interconnection, pursuant to the terms of the GIA and, if applicable, the Distribution Provider's Tariff.

IRS -- The Internal Revenue Service.

ISO -- The California Independent System Operator Corporation, a state chartered, nonprofit, corporation that controls certain transmission facilities of all Participating Transmission Owners and dispatches certain generating units and loads. See also CAISO.

ISO Grid -- The system of transmission lines and associated facilities of the Participating Transmission Owners that have been placed under the ISO’s Operational Control.

ISO’s Generator Interconnection and Deliverability Allocation Procedures (ISO Tariff GIDAP) -- The procedures included in the ISO Tariff to interconnect a Generating Facility directly to the ISO Grid, as such procedures may be modified from time to time, and accepted by the Commission. See also GIDAP.

ISO’s Generator Interconnection Procedures (ISO Tariff GIP) -- The procedures included in the ISO Tariff to interconnect a Generating Facility directly to the ISO Grid, as such procedures may be modified from time to time, and accepted by the Commission. See also GIP.

Large Generating Facility -- A Generating Facility having a Generating Facility Capacity of more than 20 MW.

Local Deliverability Constraint -- A transmission system operating limit modeled in the GIDAP study process that would be exceeded if the CAISO were to assign Full Capacity Deliverability Status or Partial Capacity Deliverability Status to one or more additional Generating Facilities interconnecting to the CAISO Controlled Grid in a specific local area, and that is not an Area Deliverability Constraint.

Local Delivery Network Upgrade (LDNU) -- A transmission upgrade or addition identified by the CAISO in the GIDAP Interconnection Study Process to relieve a Local Deliverability Constraint.

Loss -- Any and all losses relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the other Party's performance, or non-performance of its obligations under the GIA on behalf of the indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the indemnifying Party.

Material Modification – A modification that has a material impact on the cost or timing of any Interconnection Request, or any other valid interconnection request to the Distribution Provider or the ISO with a later queue priority date.

Metering Equipment -- All metering equipment installed or to be installed at the Generating Facility pursuant to the GIA at the metering points, including but not limited to instrument transformers, MWh-meters, data acquisition equipment, transducers, remote terminal unit, communications equipment, phone lines, and fiber optics.

NERC -- The North American Electric Reliability Council or its successor organization.

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Network Upgrades – Additions, modifications, and upgrades to the Distribution Provider's Transmission System required at or beyond the point at which the Distribution System connects to the Distribution Provider’s Transmission System to accommodate the interconnection of the Small Generating Facility to the Distribution Provider’s Distribution System. Network Upgrades do not include Distribution Upgrades.

See also: Area Delivery Network Upgrades; Delivery Network Upgrades; Local Delivery Network Upgrades; and Reliability Network Upgrades.

Notice of Dispute -- A written notice of a dispute or claim that arises out of or in connection with the GIA or its performance.

Operating Requirements – Any operating and technical requirements that may be applicable due to Regional Transmission Organization, California Independent System Operator, control area, or the Distribution Provider's requirements, including those set forth in the Small Generator Interconnection Agreement.

Participating Transmission Owner -- An entity which (i) owns, operates, and maintains transmission lines and associated facilities and/or has entitlements to use certain transmission lines and associated facilities; and (ii) has transferred to the ISO operational control of such facilities and/or entitlements to be made part of the ISO Grid.

Party or Parties – The Distribution Provider, Distribution Owner, Transmission Owner, Interconnection Customer or any combination of the above.

Point of Change of Ownership -- The point set forth in the GIA where the Interconnection Customer's Interconnection Facilities connect to the Distribution Provider’s Interconnection Facilities.

Point of Interconnection – The point set forth in the GIA where the Interconnection Facilities connect with the Distribution Provider's Distribution System.

Pre-Construction Activities -- The actions by the Distribution Provider, other than those required by an Engineering and Procurement Agreement under Section 8 of the GIP, undertaken prior to Construction Activities in order to prepare for the construction of the Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades assigned to the Interconnection Customer, including, but not limited to, preliminary engineering, permitting activities, environmental analysis, or other activities specifically needed to obtain governmental approvals for the Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades.

Qualifying Capacity -- The maximum Resource Adequacy Capacity that a Resource Adequacy Resource may be eligible to provide. The criteria and methodology for calculating the Qualifying Capacity of resources may be established by the CPUC or other applicable Local Regulatory Authority and provided to the CAISO. A resource’s eligibility to provide Resource Adequacy Capacity may be reduced below its Qualifying Capacity through the CAISO’s assessment of Net Qualifying Capacity.

Queue Position – The order of a valid Interconnection Request, relative to all other pending valid Interconnection Requests, that is established based upon the date and time of receipt of the valid Interconnection Request by the Distribution Provider and is represented by a unique identifying code assigned to each Interconnection Request that is deemed complete.

Reasonable Efforts – With respect to an action required to be attempted or taken by a Party under the Small Generator Interconnection Agreement, efforts that are timely and consistent with Good Utility Practice and are otherwise substantially equivalent to those a Party would use to protect its own interests.

Reliability Network Upgrades -- The transmission facilities at or beyond the point where the Distribution Provider’s Distribution System interconnects to the ISO Grid, necessary to interconnect one or more Generating Facility(ies) safely and reliably to the ISO Grid, which would not have been necessary but for WDT GIP (2017) SGIA 32
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the interconnection of one or more Generating Facility(ies), including Network Upgrades necessary to remedy short circuit or stability problems, or thermal overloads. Reliability Network Upgrades shall only be deemed necessary for thermal overloads, occurring under any system condition, where such thermal overloads cannot be adequately mitigated through the ISO’s congestion management, operating procedures, or special protection systems based on the characteristics of the Generating Facilities included in the Interconnection Studies, limitations on market models, systems, or information, or other factors specifically identified in the Interconnection Studies. Reliability Network Upgrades also include, consistent with the Applicable Reliability Council’s practice and Applicable Reliability Standards, the facilities necessary to mitigate any adverse impact the Generating Facility’s interconnection may have on a path’s Applicable Reliability Council rating.

Resource Adequacy (RA) -- A mandatory planning and procurement process to ensure adequate resources to serve all customers in real time. The program requires that Load Serving Entities (LSEs) meet a Planning Reserve Margin for their obligations. The program provides deliverability criteria that each LSE must meet, as well as system and local capacity requirements. Rules are provided for "counting" resources towards meeting resource adequacy obligations. The resources that are counted for RA purposes must make themselves available to the California ISO for the capacity for which they were counted. The ISO's Interim Reliability Requirements Program and the resource adequacy under MRTU tariff provisions are intended to complement the State of California's efforts to implement resource adequacy programs.

Site Control -- Documentation reasonably demonstrating: (1) ownership of, a leasehold interest in, or a right to develop a site for the purpose of constructing the Generating Facility; (2) an option to purchase or acquire a leasehold site for such purpose; or (3) an exclusivity or other business relationship between Interconnection Customer and the entity having the right to sell, lease or grant Interconnection Customer the right to possess or occupy a site for such purpose (see also: Site Exclusivity).

Site Exclusivity -- The third option to prove Site Control and applies only in instances when the Interconnection Customer has a business (private) or government agency (public) relationship with the project site’s deed holder.
(1) For private land, Site Exclusivity shall mean documentation reasonably demonstrating legal authorization from the land owner showing the Interconnection Customer has either (a) Ownership of, a leasehold interest in, or a right to develop property upon which the Generating Facility will be located consisting of a minimum of 50% of the acreage reasonably necessary to accommodate the Generating Facility; or (b) an option to purchase or acquire a leasehold interest in property upon which the Generating Facility will be located consisting of a minimum of 50% of the acreage reasonably necessary to accommodate the Generating Facility. (2) For public land, including that controlled or managed by any federal, state or local agency, Site Exclusivity shall mean documentation from the governing public agency providing a final, non-appealable permit, license, or other exclusive legal right to use the property for the purpose of generating electric power and in acreage reasonably necessary to accommodate the Generating Facility. Such documentation showing exclusive right to use public land under the management of a Local, State, or Federal agency shall be in a form specified by that agency.

Smart Inverter —A Generating Facility’s inverter that performs functions that when activated can autonomously contribute to grid support during excursions from normal operating voltage and frequency system conditions by providing dynamic reactive/real power support, voltage and frequency ride-through, ramp rate controls, communication systems with ability to accept external commands and other functions.

Small Generating Facility – An Interconnection Customer's device for the production and/or storage for later injection of electricity identified in the Interconnection Request, but shall not include the Interconnection Customer's Interconnection Facilities, that has a generating capacity of 20 megawatts (MW) or less.

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Stand Alone Network Upgrades -- Network Upgrades that an Interconnection Customer may construct without affecting day-to-day operations of the Transmission System during their construction. Both the Distribution Provider and the Interconnection Customer must agree as to what constitutes Stand Alone Network Upgrades and identify them in an Appendix to the GIA.

System Protection Facilities -- The equipment, including necessary protection signal communications equipment, required to protect (1) the Distribution Provider's Distribution System, the ISO Controlled Grid, and Affected Systems from faults or other electrical disturbances occurring at the Generating Facility and (2) the Generating Facility from faults or other electrical system disturbances occurring on the Distribution Provider's Distribution System, the ISO Controlled Grid or on other delivery systems or other generating systems to which the Distribution Provider's Distribution System and Transmission System is directly connected.

Tariff – The Distribution Provider’s Wholesale Distribution Tariff through which open access distribution service and Interconnection Service are offered, as filed with the FERC, and as amended or supplemented from time to time, or any successor tariff.

Transmission System – Those facilities owned by the Distribution Provider that have been placed under the ISO’s operational control and are part of the ISO Grid.

Trial Operation -- The period during which Interconnection Customer is engaged in on-site test operations and commissioning of the Generating Facility prior to Commercial Operation. Also known as Permission to Parallel for Test Purposes.

Uncontrollable Force -- Any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm, flood, earthquake, explosion, breakage or accident to machinery or equipment, any curtailment, order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or any other cause beyond the reasonable control of the Distribution Provider or Interconnection Customer which could not be avoided through the exercise of Good Utility Practice. An Uncontrollable Force event does not include acts of negligence or intentional wrongdoing by the Party claiming Uncontrollable Force.

Upgrades – The required additions and modifications to the Distribution Provider's Distribution System, at or beyond the Point of Interconnection. Upgrades may be Network Upgrades or Distribution Upgrades.

Upgrades do not include Interconnection Facilities.

Wholesale Distribution Tariff Generator Interconnection Procedures (WDT GIP) – The procedures included in the Distribution Provider’s Wholesale Distribution Tariff (WDT) to interconnect a Generating Facility directly to the Distribution Provider’s Distribution System, as such procedures may be modified from time to time, and accepted by the Commission.

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Attachment 2
Description and Costs of the Small Generating Facility, Interconnection Facilities and Metering Equipment
Central Coast Community Energy, an Interconnection Customer (IC), has requested a Generating Facility (GF) interconnection for Emeline (Project) to the Pacific Gas and Electric Company (PG&E)’s distribution system for a 3000 kW BESS generating facility to be located at 1000 Emeline Ave, SANTA CRUZ, CA 95060. The Generating Facility will be connected to PG&E’s Paul Sweet 2105 distribution circuit.

Interconnection will be in accordance with FERC’s Generator Interconnection Procedures. The requested operating date for the Project is 30 April 2024. This Project has been assigned the reference number of 3243-WD.

Equipment, including the Small Generating Facility, Interconnection Facilities, and metering equipment shall be itemized and identified as being owned by the Interconnection Customer, the Distribution Provider, Distribution Owner or the Transmission Owner. The Distribution Provider will provide a best estimate itemized cost, including overheads, of its Interconnection Facilities and metering equipment, and a best estimate itemized cost of the annual operation and maintenance expenses associated with its Interconnection Facilities and metering equipment.

Actual costs incurred by the Interconnection Customer to install these Interconnection Facilities will be trued up with the Interconnection Customer once this project has achieved commercial operation, per Article 6.1 of this agreement. The Interconnection Customer will be responsible for payment of all actual costs incurred to install these facilities, and any additional facilities identified as necessary during the engineering, design, or construction phases. Should additional facilities be deemed necessary for the interconnection of this facility, Distribution Provider will identify these additional facilities as soon as possible in the construction phase, and will coordinate with the Interconnection Customer on the additional costs and timing needed to implement them. As needed, the costs of ownership for these Interconnection Facilities also will be updated once this project has achieved commercial operation.

Project Information
Project Name: Emeline
Number of Generators: 4 BESS
Manufacturer Model Name & Number: SolBank S1K5650A01 or similar battery energy storage container
Number of Inverters: 2
Manufacturer Model Name & Number: EPC Power CAB1000
Total Output: 3000 kVA (3000kW @ 1.0 power factor)
Transformer Data: 3000 kVA @ Z = 5.75% 21kV / 600V Delta / Wye-Grounded
PG&E Grid Voltage at Interconnection: 21 kV
Substation / Feeder Paul Sweet Bank 2 115kV / 21.6kV Paul Sweet 2105
Primary Line Configuration at POI 3-phase, 4-wire distribution circuit Description of Operation Wholesale export to Paul Sweet 2105 Energy Storage Load Study Option Firm Service
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Interconnection Facilities
The estimated costs associated with the Interconnection Facilities required to interconnect the project to Distribution Provider’s Distribution System.

Interconnection Facilities (Subject to Cost-of-Ownership) Costs Pre-energization test, protection review and testing witnessing $10,000 PG&E Primary Revenue Metering $15,000
Primary Service-OH (Per location not including Metering) $15,000 PG&E SCADA Recloser at POI $80,000
Total -- Interconnection Facility Costs (Subject to Cost-of-Ownership) $ 120,000 ITCC Tax1 TBD
1 Not subject to ITCC (Income Tax Calculation Component) on contribution. ITCC is exempt for wholesale generators that meet the IRS Safe Harbor Provisions. PG&E currently does not require the Interconnection Customer to provide security to cover the potential tax liability on the Interconnection Facilities, Distribution Upgrades, and Network Upgrades per the IRS Safe Harbor Provisions (IRS Notice 88-129). PG&E reserves the right to require, on a nondiscriminatory basis, the Interconnection Customer to provide such security, in a form reasonably acceptable to PG&E as indicated in Article 11 of the SGIA, an amount up to the cost consequences of any current tax liability. Upon request and within sixty (60) Calendar Days’ notice, the Interconnection Customer shall provide PG&E such ITCC security or ITCC payment in the event that Safe Harbor Provisions have not been met, in the form requested by PG&E.

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Attachment 3
One-line Diagram Depicting the Small Generating Facility, Interconnection Facilities, Metering Equipment, and Upgrades
Figure 3-1 One-Line Conceptual Diagram of Project Name
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Figure 3-2 Vicinity Map of Project Name
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Attachment 4
Milestones
In-Service Date: February 5, 2025
Critical milestones and responsibility as agreed to by the Parties:

Milestone Date Responsible Party
1 Financial Security Posting Due Date January 22, 2024 Interconnection Customer 2 Submit electronic initial design package
(including but not limited to equipment list,
70% final SLD, site map and site plan)
January 29, 2024 Interconnection Customer
3 On-site project kick-off meeting February 19, 2024 Distribution Provider & Interconnection Customer
4 Completion of the Interconnection Facilities,
Distribution Upgrades, and Network Upgrade
facilities
January 22, 2025 Distribution Provider &
Interconnection Customer
5 In-Service Date (back-feed power) February 5, 2025 Distribution Provider & Interconnection Customer
6 Pre-parallel Inspection and Testing March 5, 2025 Distribution Provider & Interconnection Customer
7 Initial Synchronization March 19, 2025 Interconnection Customer 8 Provide written approval to Interconnection
Customer for the operation of the facilities
(PTO) and Commercial Operation Date
(COD)
March 26, 2025 Distribution Provider
9 Completion of Reliability and Deliverability
Network Upgrades (RNU, DNU) identified in
Attachment 5 as part of implementing FCDS
N/A Distribution Provider
Note 1 – Ability to Meet Milestone Dates
The ability to meet these Milestone dates requires that all tasks, including tasks preceding the milestones listed above, to be completed in a timely fashion and does not account for unanticipated delays, including but not limited to delays caused by: emergency response due to wildfires or storms; time to complete environmental studies; availability of needed resources (e.g., materials or crews); difficulties securing necessary permits, easements, right of ways, licenses or other approvals; construction additional information needed to complete the project implementation process; or delays scheduling clearances to complete the interconnection of this project to the PG&E system.

Note 2 -- Supplemental Billing and Payment Provisions:

In accordance with Article 6.3 of this project’s SGIA, the financial security posting(s) must be completed by the Interconnection Customer before the Distribution Provider may begin any capital work. The Interconnection Customer may negotiate a milestone date to post the financial security(-ies) up to 180 Calendar Days (CD) after the execution of this SGIA. This negotiated date is shown in the milestones table above. If the financial security posting(s) is/are not completed by the date shown in the table above, a notice of default will be issued to the Interconnection Customer in accordance with Article 7.6 of this SGIA.

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Note 3 -- Billing Procedures for Actual Costs:

Per Section 6.1.1 of this project’s SGIA, PG&E will bill the Interconnection Customer on a monthly basis for actual labor and/or material costs incurred during the prior month.

Agreed to by:

For the Distribution Provider Date:

For the Interconnection Customer Date:

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Attachment 5
Additional Operating Requirements for the Distribution Provider's Distribution System, Transmission System and Affected Systems Needed to Support the Interconnection Customer's Needs

5.1 General Operating Requirements
The Distribution Provider shall also provide requirements that must be met by the Interconnection Customer prior to initiating parallel operation with the Distribution Provider's Distribution System.

At a minimum, the Interconnection Customer agrees to construct and interconnect the facility described in this agreement with the PG&E system in accordance with the standards and requirements described in the PG&E Transmission Interconnection Handbook (TIH) and the Distribution Interconnection Handbook (DIH), as well as any specific operating requirements identified and described in the final interconnection study completed by the Distribution Provider for this facility.

5.2 Deliverability Status
The Interconnection Customer has elected for this Small Generating Facility to have Energy Only Deliverability Status, as defined in the CAISO Tariff. As a result, this Small Generating Facility was studied for Energy Only Deliverability Status by the Distribution Provider, and the results of those studies have been incorporated into this SGIA. The Interconnection Customer and the Distribution Provider acknowledge and understand that this Small Generating Facility will have Energy Only Deliverability Status.

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Attachment 6
Distribution Provider's Description of its Upgrades
and Best Estimate of Upgrade Costs
The Distribution Provider shall describe Upgrades and provide an itemized best estimate of the cost, including overheads, of the Upgrades and annual operation and maintenance expenses associated with such Upgrades. The Distribution Provider shall functionalize Upgrade costs and annual expenses as either transmission or distribution related.

Actual costs incurred by the Interconnection Customer to install these Distribution Upgrades and Network Upgrades will be trued up with the Interconnection Customer once this project has achieved commercial operation, per Article 6.1 of this agreement. The Interconnection Customer will be responsible for payment of all actual costs incurred to install these facilities, and any additional facilities identified as necessary during the engineering, design, or construction phases. Should additional upgrades be deemed necessary for the interconnection of this facility, Distribution Provider will identify these additional upgrades as soon as possible in the construction phase, and will coordinate with the Interconnection Customer on the additional costs and timing needed to implement them. As needed, the costs of ownership for these Interconnection Facilities also will be updated once this project has achieved commercial operation.

Distribution Upgrades
The estimated costs associated with the system upgrades required to interconnect the project to the Distribution Provider’s Distribution System.

Distribution Upgrades: None
Reliability Network Upgrades
The estimated costs associated with the system upgrades required to interconnect the project to the Distribution Provider’s Transmission System. In accordance with Article 5.2.1 of this Agreement, Reliability Network Upgrades reimbursement is capped at a maximum of $TBD per MW of generating capacity. To the extent that such reimbursement does not cover all costs of the RNUs, the IC shall receive Congestion Revenue Rights (“CRRs”) for the portion of the RNUs that are not covered by the above reimbursement.

Reliability Network Upgrades: None
Total Project Costs
Cost Category
Amount Subject to
COO ($)
Amount NOT
Subject to COO ($)
Total Cost
Category Amount
($)
Interconnection Facilities
Costs (Attachment 2) $120,000 N/A $120,000
Distribution Upgrade Costs
(Attachment 6) $0 N/A $0
Network Upgrade Costs
Reliability Network $ $
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Upgrade Costs
(Attachment 6)
Deliverability-related RNU
(Attachment 5) N/A $ $
Delivery Network Upgrades
(Attachment 5) N/A $ $
Total Project Costs ($) $120,000 $ $120,000
Total Cost-of-Ownership Charges for Project:

The Interconnection Customer has elected the following by placing a check mark against it for Cost-of-Ownership for the applicable Interconnection Facilities and/or Distribution Upgrades. The Cost-of-Ownership will commence upon the In-Service Date per Article 4.1.2.

A. Monthly Cost-of-Ownership Charge
$ Total Project Costs Subject to COO x 0.89%2 (current percentage rate) = $ Monthly COO Amt Total Monthly Cost-of-Ownership Charge $ 1,068 / month
B. Equivalent One-Time Charge (in lieu of recurring Monthly Cost-of-Ownership Charge) $ Monthly COO Amt / month x 12 months x 14.73 (present worth factor3) = $ One time COO Amt Total Equivalent One-Time Charge $ 188,779.68
2 The COST-OF-OWNERSHIP Charge for Interconnections provided under this Agreement is determined in accordance with PG&E’s applicable percentage rates calculated using PG&E’s most recent distribution owner revenue requirement on file with and accepted by FERC. PG&E currently charges the following COST-OF-OWNERSHIP rates for distribution facilities: Customer financed, Distribution-level Rate of 0.89% monthly.
3 The Present Worth Factor (PWF), which is also known as the perpetuity factor, is used under this agreement to determine the equivalent One-Time Payment. This financial factor is the reciprocal of the after-tax Rate of Return on Rate Base (ROR). The after-tax ROR is calculated by the Economic and Project Analysis Department and is based on CPUC decisions, which establish the Return on Rate Base.

Staff Report Item 15
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Dennis Dyc-O’Neal, Chief Operating Officer SUBJECT: Approve and authorize CEO to execute the small generator interconnection agreement between Pacific Gas and Electric Company and Central Coast Community Energy in an amount not to exceed $120,000 for the interconnection cost associated with the installation of an energy storage facility at the Roy Wilson Project site DATE: August 9, 2023
RECOMMENDATION:

Authorize CEO to execute the Small Generator Interconnection Agreement (SGIA) between Pacific Gas and Electric Company (PG&E) and Central Coast Community Energy (3CE) in an amount not to exceed $120,000 for the interconnection cost associated with the installation of an energy storage facility at the Roy Wilson Project site.

BACKGROUND:

In December 2021, 3CE launched the Front of the Meter Energy Storage (FMES) effort to build 1 to 5 MW sized energy storage systems throughout the 3CE service area. Energy storage provides firmer capacity in that it converts our planned portfolio of intermittent renewable generation resources into dispatchable, more reliable resources, and will allow us to cost-effectively achieve 3CE’s goal of 100% renewable power by 2030. Energy storage also provides grid-level flexibility with its ability to help keep the power system running despite outages during extreme weather.

In June 2022, the Policy Board approved developing, funding, owning, and operating these assets. Phase one of this effort has focused on identifying and using viable member-agency sites to install these batteries.

DISCUSSION/ANALYSIS:

The Roy Wilson Project site, located at 202 Grimmer Road, Watsonville in Santa Cruz County, was provided to 3CE by its member-agency and after conducting our own internal assessments was considered viable. It was then submitted into PG&E’s interconnection process for review by them as the local utility distribution company. It passed their initial screening as a viable site, and PG&E provided an expected cost of $120,000 required for interconnection of a 3 MW 4.5 MW energy storage facility at the site.

The detailed expected cost for interconnection is as follows:
 A Pre-energization test, protection review and testing witnessing ($10,000)  PG&E Primary Revenue Metering ($15,000)
 Primary Service-OH (Per location not including Metering ($15,000)  PG&E SCADA Recloser at the POI ($80,000)
If approved, 3CE will then proceed with issuing an RFO to identify and select a qualified contractor to obtain the necessary permits and construct the facility. This will happen in the Fall of 2023.

FISCAL IMPACT:

The fiscal impact of signing this SGIA will have a not to exceed amount of $120,000.00.

CONCLUSION:

Staff recommends that 3CE’s Operations Board of Directors authorize CEO to execute the Small Generator Interconnection Agreement between Pacific Gas and Electric Company and Central Coast Community Energy in an amount not to exceed $120,000 for the interconnection cost associated with the installation of an energy storage facility at the Roy Wilson Project site.

ATTACHMENTS:

1. Roy Wilson Yard SGIA
Internal

SMALL GENERATOR INTERCONNECTION

AGREEMENT (SGIA)
(For Generating Facilities No Larger Than 20 MW)

BETWEEN

PACIFIC GAS AND ELECTRIC COMPANY
AND

CENTRAL COAST COMMUNITY ENERGY
For Project:

Roy Wilson Yard
3266 - WD
Watsonville, CA 95076
Santa Cruz County
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TABLE OF CONTENTS
Page No.

Article 1. Scope and Limitations of Agreement........................................................................... 1

1.5 Responsibilities of the Parties ............................................................................. 1

1.6 Parallel Operation Obligations............................................................................. 3

1.7 Metering.............................................................................................................. 3

1.8 Reactive Power................................................................................................... 3

1.8.1 Power Factor Design Criteria ..................................................................... 3

1.8.2 Deleted ...................................................................................................... 4

1.8.3 Deleted ...................................................................................................... 4

1.8.4 Primary Frequency Response.................................................................... 4 Article 2. Inspection, Testing, Authorization, and Right of Access .............................................. 7

2.1 Equipment Testing and Inspection ...................................................................... 7

2.2 Authorization Required Prior to Parallel Operation.............................................. 7

2.3 Right of Access................................................................................................... 7 Article 3. Effective Date, Term, Termination, and Disconnection ................................................ 8

3.1 Effective Date ..................................................................................................... 8

3.2 Term of Agreement............................................................................................. 8

3.3 Termination......................................................................................................... 8

3.4 Temporary Disconnection ................................................................................... 9

3.4.1 Emergency Conditions ............................................................................ 9

3.4.2 Routine Maintenance, Construction, and Repair...................................... 9

3.4.3 Forced Outages....................................................................................... 9

3.4.4 Adverse Operating Effects......................................................................10

3.4.5 Modification of the Small Generating Facility ..........................................10

3.4.6 Reconnection .........................................................................................10 Article 4. Cost Responsibility for Interconnection Facilities and Distribution Upgrades ..............10

4.1 Interconnection Facilities....................................................................................10

4.2 Distribution Upgrades ........................................................................................10 Article 5. Cost Responsibility for Network Upgrades .................................................................11

5.1 Applicability........................................................................................................11

5.2 Network Upgrades .............................................................................................11

5.2.1 Repayment of Amounts Advanced for Network Upgrades ......................11

5.3 Special Provisions for Affected Systems ............................................................12

5.4 Rights Under Other Agreements........................................................................12 Article 6. Billing, Payment, Milestones, and Financial Security ..................................................12

6.1 Billing and Payment Procedures and Final Accounting ......................................12

6.2 Milestones..........................................................................................................13

6.3 Financial Security Arrangements .......................................................................13

6.4 Responsibility for any Outstanding Interconnection Study Costs........................14 Article 7. Assignment, Liability, Indemnity, Force Majeure, Consequential Damages, and Default ......................................................................................................................................14

7.1 Assignment........................................................................................................14 WDT GIP (2017) SGIA ii
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7.2 Limitation of Liability...........................................................................................14

7.3 Indemnity ...........................................................................................................14

7.4 Consequential Damages....................................................................................15

7.5 Force Majeure....................................................................................................15

7.6 Default ...............................................................................................................16 Article 8. Insurance ...................................................................................................................16 Article 9. Confidentiality.............................................................................................................17 Article 10. Disputes ...................................................................................................................18 Article 11. Taxes .......................................................................................................................18 Article 12. Miscellaneous ..........................................................................................................18

12.1 Governing Law, Regulatory Authority, and Rules...............................................19

12.2 Amendment .......................................................................................................19

12.3 No Third-Party Beneficiaries ..............................................................................19

12.4 Waiver ...............................................................................................................19

12.5 Entire Agreement...............................................................................................19

12.6 Multiple Counterparts.........................................................................................19

12.7 No Partnership...................................................................................................19

12.8 Severability ........................................................................................................20

12.9 Security Arrangements.......................................................................................20

12.10 Environmental Releases ....................................................................................20

12.11 Subcontractors...................................................................................................20

12.12 Reservation of Rights.........................................................................................21 Article 13. Notices .....................................................................................................................21 Attachment 1 – Glossary of Terms
Attachment 2 – Description and Costs of the Small Generating Facility, Interconnection Facilities, and Metering Equipment
Attachment 3 – One-line Diagram Depicting the Small Generating Facility, Interconnection Facilities, Metering Equipment, and Upgrades
Attachment 4 – Milestones
Attachment 5 – Additional Operating Requirements for the Distribution Provider's Distribution and Transmission Systems and Affected Systems Needed to Support the Interconnection Customer’s Needs
Attachment 6 – Distribution Provider's Description of its Upgrades and Best Estimate of Upgrade Costs
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This Interconnection Agreement ("Agreement") is made and entered into this ________ day of ________________, 20__ by PACIFIC GAS AND ELECTRIC COMPANY ("Distribution Provider"), and CENTRAL COAST COMMUNITY ENERGY ("Interconnection Customer"), each hereinafter sometimes referred to individually as "Party" or both referred to collectively as the "Parties."
Distribution Provider Information
Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]
Interconnection Customer Information
Central Coast Community Energy
Attention: Robert Shaw
70 Garden Court, Suite 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
Interconnection Customer Application No: PG&E Project ID # 50O765767, Queue # 3266- WD.

In consideration of the mutual covenants set forth herein, the Parties agree as follows:

Article 1. Scope and Limitations of Agreement

1.1 This Agreement shall be used for all Small Generating Facility Interconnection Requests submitted under the Small Generator Interconnection Procedures (SGIP) or Generator Interconnection Procedures (GIP) except for those submitted under the 10 kW Inverter Process contained in SGIP Attachment 5.

1.2 This Agreement governs the terms and conditions under which the Interconnection Customer’s Small Generating Facility will interconnect with, and operate in parallel with, the Distribution Provider's Distribution System.

1.3 This Agreement does not constitute an agreement to purchase or deliver the Interconnection Customer's power. The purchase or delivery of power and other services that the Interconnection Customer may require will be covered under separate agreements. The Interconnection Customer will be responsible for separately making all necessary arrangements (including scheduling) for delivery of electricity.

1.4 Nothing in this Agreement is intended to affect any other agreement between the Distribution Provider and the Interconnection Customer.

1.5 Responsibilities of the Parties

1.5.1 The Parties shall perform all obligations of this Agreement in accordance with all Applicable Laws and Regulations, Operating Requirements, and Good Utility WDT GIP (2017) SGIA 2
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Practice.

1.5.2 The Interconnection Customer shall construct, interconnect, operate and maintain its Small Generating Facility and construct, operate, and maintain its Interconnection Facilities in accordance with the applicable manufacturer’s recommended maintenance schedule, in accordance with this Agreement, and with Good Utility Practice.

1.5.3 The Distribution Provider shall construct, operate, and maintain its Distribution System, Transmission System and Interconnection Facilities in accordance with this Agreement, and with Good Utility Practice.

1.5.4 The Interconnection Customer agrees to construct its facilities or systems in accordance with applicable specifications that meet or exceed those provided by the National Electrical Safety Code, the American National Standards Institute, IEEE, Underwriter's Laboratory, and Operating Requirements in effect at the time of construction and other applicable national and state codes and standards. The Interconnection Customer agrees to design, install, maintain, and operate its Small Generating Facility so as to reasonably minimize the likelihood of a disturbance adversely affecting or impairing the system or equipment of the Distribution Provider or Affected Systems. The Interconnection Customer shall comply with the Distribution Provider’s Interconnection Handbook. In the event of a conflict between the terms of this SGIA and the terms of the Distribution Provider’s Interconnection Handbook, the terms in this SGIA shall govern.

1.5.5 Each Party shall operate, maintain, repair, and inspect, and shall be fully responsible for the facilities that it now or subsequently may own unless otherwise specified in the Attachments to this Agreement. Each Party shall be responsible for the safe installation, maintenance, repair and condition of their respective lines and appurtenances on their respective sides of the point of change of ownership. The Distribution Provider and the Interconnection Customer, as appropriate, shall provide Interconnection Facilities that adequately protect the Distribution Provider's Distribution and Transmission Systems, personnel, and other persons from damage and injury. The allocation of responsibility for the design, installation, operation, maintenance and ownership of Interconnection Facilities shall be delineated in the Attachments to this Agreement.

1.5.6 The Distribution Provider shall coordinate with all Affected Systems to support the interconnection.

1.5.7 The Interconnection Customer shall ensure “frequency ride through” capability and “voltage ride through” capability of its Small Generating Facility in accordance with the standards and requirements described in the PG&E Transmission Interconnection Handbook (TIH) and the Distribution Interconnection Handbook (DIH). The Interconnection Customer shall enable these capabilities such that its Small Generating Facility shall not disconnect automatically or instantaneously from the system or equipment of the Distribution Provider and any Affected Systems for a defined under-frequency or over-frequency condition, or an under-voltage or over-voltage condition, as tested pursuant to Article 2.1 of this Agreement. The defined conditions shall be in accordance with Good Utility Practice and consistent with any standards and guidelines WDT GIP (2017) SGIA 3
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that are applied to other generating facilities in the Balancing Authority Area on a comparable basis. The Small Generating Facility’s protective equipment settings shall comply with the Distribution Provider’s automatic load-shed program. The Distribution Provider shall review the protective equipment settings to confirm compliance with the automatic load-shed program. The term “ride through” as used herein shall mean the ability of a Small Generating Facility to stay connected to and synchronized with the system or equipment of the Distribution Provider and any Affected Systems during system disturbances within a range of conditions, in accordance with Good Utility Practice and consistent with any standards and guidelines that are applied to other generating facilities in the Balancing Authority on a comparable basis. The term “frequency ride through” as used herein shall mean the ability of a Small Generating Facility to stay connected to and synchronized with the system or equipment of the Distribution Provider and any Affected Systems during system disturbances within a range of under-frequency and over-frequency conditions, in accordance with Good Utility Practice and consistent with any standards and guidelines that are applied to other generating facilities in the Balancing Authority Area on a comparable basis. The term “voltage ride through” as used herein shall mean the ability of a Small Generating Facility to stay connected to and synchronized with the system or equipment of the Distribution Provider and any Affected Systems during system disturbances within a range of under-voltage and over-voltage conditions, in accordance with Good Utility Practice and consistent with any standards and guidelines that are applied to other generating facilities in the Balancing Authority Area on a comparable basis.

1.6 Parallel Operation Obligations
Once the Small Generating Facility has been authorized by the Distribution Provider to commence parallel operation, the Interconnection Customer shall abide by all rules and procedures pertaining to the parallel operation of the Small Generating Facility in the applicable control area, including, but not limited to; 1) the rules and procedures concerning the operation of generation set forth in the Tariff or by the applicable system operator(s) for the Distribution Provider's Distribution and Transmission Systems and; 2) the Operating Requirements set forth in Attachment 5 of this Agreement.

1.7 Metering
The Interconnection Customer shall be responsible for the Distribution Provider's reasonable and necessary cost for the purchase, installation, operation, maintenance, testing, repair, and replacement of metering and data acquisition equipment specified in Attachments 2 and 3 of this Agreement. The Interconnection Customer's metering (and data acquisition, as required) equipment shall conform to applicable industry rules and Operating Requirements.

1.8 Reactive Power

1.8.1 Power Factor Design Criteria

1.8.1.1 Synchronous Generation The Interconnection Customer shall design its Small Generating Facility to maintain a composite power delivery at continuous rated power output at the Point of Interconnection at a power factor within the range of 0.95 leading to 0.95 lagging, unless the Distribution Provider has established different requirements that apply to all similarly situated synchronous generators in the control area on a comparable basis.

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1.8.1.2 Non-Synchronous Generation The Interconnection Customer shall design its Small Generating Facility to maintain a composite power delivery at continuous rated power output at the high-side of the generator substation at a power factor within the range of 0.95 leading to 0.95 lagging, unless the Distribution Provider has established a different power factor range that applies to all similarly situated non-synchronous generators in the control area on a comparable basis. This power factor range standard shall be dynamic and can be met using, for example, power electronics designed to supply this level of reactive capability (taking into account any limitations due to voltage level, real power output, etc.) or fixed and switched capacitors, or a combination of the two. This requirement shall only apply to newly interconnecting nonsynchronous generators that have not yet executed a Facilities Study Agreement as of the effective date of the Final Rule establishing this requirement (Order No. 827).

1.8.2 This Section deleted in FERC Docket No. ER13-494-000..

1.8.3 This Section deleted in FERC Docket No. ER13-494-000.

1.8.4 Primary Frequency Response.

Interconnection Customer shall ensure the primary frequency response capability of its Small Generating Facility by installing, maintaining, and operating a functioning governor or equivalent controls. The term “functioning governor or equivalent controls” as used herein shall mean the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the Small Generating Facility’s real power output in accordance with the droop and deadband parameters and in the direction needed to correct frequency deviations. Interconnection Customer is required to install a governor or equivalent controls with the capability of operating: (1) with a maximum 5 percent droop and ±0.036 Hz deadband; or (2) in accordance with the relevant droop, deadband, and timely and sustained response settings from an approved NERC Reliability Standard providing for equivalent or more stringent parameters. The droop characteristic shall be: (1) based on the nameplate capacity of the Small Generating Facility, and shall be linear in the range of frequencies between 59 to 61 Hz that are outside of the deadband parameter; or (2) based an approved NERC Reliability Standard providing for an equivalent or more stringent parameter. The deadband parameter shall be: the range of frequencies above and below nominal (60 Hz) in which the governor or equivalent controls is not expected to adjust the Small Generating Facility’s real power output in response to frequency deviations. The deadband shall be implemented: (1) without a step to the droop curve, that is, once the frequency deviation exceeds the deadband parameter, the expected change in the Small Generating Facility’s real power output in response to frequency deviations shall start from zero and then increase (for under-frequency deviations) or decrease (for over-frequency deviations) linearly in proportion to the magnitude of the frequency deviation; or (2) in accordance with an approved NERC Reliability Standard providing for an equivalent or more stringent parameter. Interconnection Customer shall notify Transmission Provider that the primary frequency response capability of the WDT GIP (2017) SGIA 5
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Small Generating Facility has been tested and confirmed during commissioning.

Once Interconnection Customer has synchronized the Small Generating Facility with the Transmission System, Interconnection Customer shall operate the Small Generating Facility consistent with the provisions specified in Sections 1.8.4.1 and 1.8.4.2 of this Agreement. The primary frequency response requirements contained herein shall apply to both synchronous and non-synchronous Small Generating Facilities.

1.8.4.1 Governor or Equivalent Controls. Whenever the Small Generating Facility is operated in parallel with the Transmission System, Interconnection Customer shall operate the Small Generating Facility with its governor or equivalent controls in service and responsive to frequency. Interconnection Customer shall: (1) in coordination with Transmission Provider and/or the relevant balancing authority, set the deadband parameter to: (1) a maximum of ±0.036 Hz and set the droop parameter to a maximum of 5 percent; or (2) implement the relevant droop and deadband settings from an approved NERC Reliability Standard that provides for equivalent or more stringent parameters.

Interconnection Customer shall be required to provide the status and settings of the governor or equivalent controls to Transmission Provider and/or the relevant balancing authority upon request. If Interconnection Customer needs to operate the Small Generating Facility with its governor or equivalent controls not in service, Interconnection Customer shall immediately notify Transmission Provider and the relevant balancing authority, and provide both with the following information: (1) the operating status of the governor or equivalent controls (i.e., whether it is currently out of service or when it will be taken out of service); (2) the reasons for removing the governor or equivalent controls from service; and (3) a reasonable estimate of when the governor or equivalent controls will be returned to service. Interconnection Customer shall make Reasonable Efforts to return its governor or equivalent controls into service as soon as practicable. Interconnection Customer shall make Reasonable Efforts to keep outages of the Small Generating Facility’s governor or equivalent controls to a minimum whenever the Small Generating Facility is operated in parallel with the Transmission System.

1.8.4.2 Timely and Sustained Response. Interconnection Customer shall ensure that the Small Generating Facility’s real power response to sustained frequency deviations outside of the deadband setting is automatically provided and shall begin immediately after frequency deviates outside of the deadband, and to the extent the Small Generating Facility has operating capability in the direction needed to correct the frequency deviation. Interconnection Customer shall not block or otherwise inhibit the ability of the governor or equivalent controls to respond and shall ensure that the response is not inhibited, except under certain operational constraints including, but not limited to, ambient temperature limitations, physical energy limitations, outages of mechanical equipment, or regulatory requirements. The Small Generating Facility shall sustain the real power response at least until system frequency returns to a value within the deadband setting of the WDT GIP (2017) SGIA 6
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governor or equivalent controls. A Commission-approved Reliability Standard with equivalent or more stringent requirements shall supersede the above requirements.

1.8.4.3 Exemptions. Small Generating Facilities that are regulated by the United States Nuclear Regulatory Commission shall be exempt from Sections 1.8.4, 1.8.4.1, and 1.8.4.2 of this Agreement. Small Generating Facilities that are behind the meter generation that is sized-to-load (i.e., the thermal load and the generation are near-balanced in real-time operation and the generation is primarily controlled to maintain the unique thermal, chemical, or mechanical output necessary for the operating requirements of its host facility) shall be required to install primary frequency response capability in accordance with the droop and deadband capability requirements specified in Section 1.8.4, but shall be otherwise exempt from the operating requirements in Sections 1.8.4,

1.8.4.1, 1.8.4.2, and 1.8.4.4 of this Agreement.

1.8.4.4 Electric Storage Resources. Interconnection Customer interconnecting an electric storage resource shall establish an operating range in Attachment 5 of its SGIA that specifies a minimum state of charge and a maximum state of charge between which the electric storage resource will be required to provide primary frequency response consistent with the conditions set forth in Sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 of this Agreement. Attachment 5 shall specify whether the operating range is static or dynamic, and shall consider: (1) the expected magnitude of frequency deviations in the interconnection; (2) the expected duration that system frequency will remain outside of the deadband parameter in the interconnection; (3) the expected incidence of frequency deviations outside of the deadband parameter in the interconnection; (4) the physical capabilities of the electric storage resource; (5) operational limitations of the electric storage resource due to manufacturer specifications; and (6) any other relevant factors agreed to by Transmission Provider and Interconnection Customer, and in consultation with the relevant transmission owner or balancing authority as appropriate. If the operating range is dynamic, then Attachment 5 must establish how frequently the operating range will be reevaluated and the factors that may be considered during its reevaluation.

Interconnection Customer’s electric storage resource is required to provide timely and sustained primary frequency response consistent with Section 1.8.4.2 of this Agreement when it is online and dispatched to inject electricity to the Transmission System and/or receive electricity from the Transmission System. This excludes circumstances when the electric storage resource is not dispatched to inject electricity to the Transmission System and/or dispatched to receive electricity from the Transmission System. If Interconnection Customer’s electric storage resource is charging at the time of a frequency deviation outside of its deadband parameter, it is to increase (for over-frequency deviations) or decrease (for under-frequency deviations) the rate at which it is charging in accordance with its droop parameter. Interconnection Customer’s electric storage resource is not required to change from WDT GIP (2017) SGIA 7
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charging to discharging, or vice versa, unless the response necessitated by the droop and deadband settings requires it to do so and it is technically capable of making such a transition.

1.9 Capitalized terms used herein shall have the meanings specified in the Glossary of Terms in Attachment 1 or the body of this Agreement.

Article 2. Inspection, Testing, Authorization, and Right of Access

2.1 Equipment Testing and Inspection

2.1.1 The Interconnection Customer shall test and inspect its Small Generating Facility and Interconnection Facilities prior to interconnection. The Interconnection Customer shall notify the Distribution Provider of such activities no fewer than five Business Days (or as may be agreed to by the Parties) prior to such testing and inspection. Testing and inspection shall occur on a Business Day. The Distribution Provider may, at its own expense, send qualified personnel to the Small Generating Facility site to inspect the interconnection and observe the testing. The Interconnection Customer shall provide the Distribution Provider a written test report when such testing and inspection is completed.

2.1.2 The Distribution Provider shall provide the Interconnection Customer written acknowledgment that it has received the Interconnection Customer's written test report. Such written acknowledgment shall not be deemed to be or construed as any representation, assurance, guarantee, or warranty by the Distribution Provider of the safety, durability, suitability, or reliability of the Small Generating Facility or any associated control, protective, and safety devices owned or controlled by the Interconnection Customer or the quality of power produced by the Small Generating Facility.

2.2 Authorization Required Prior to Parallel Operation

2.2.1 The Distribution Provider shall use Reasonable Efforts to list applicable parallel operation requirements in Attachment 5 of this Agreement. Additionally, the Distribution Provider shall notify the Interconnection Customer of any changes to these requirements as soon as they are known. The Distribution Provider shall make Reasonable Efforts to cooperate with the Interconnection Customer in meeting requirements necessary for the Interconnection Customer to commence parallel operations by the in-service date.

2.2.2 The Interconnection Customer shall not operate its Small Generating Facility in parallel with the Distribution Provider's Distribution System without prior written authorization of the Distribution Provider. The Distribution Provider will provide such authorization once the Distribution Provider receives notification that the Interconnection Customer has complied with all applicable parallel operation requirements. Such authorization shall not be unreasonably withheld, conditioned, or delayed.

2.3 Right of Access
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2.3.1 Upon reasonable notice, the Distribution Provider may send a qualified person to the premises of the Interconnection Customer at or immediately before the time the Small Generating Facility first produces energy to inspect the interconnection, and observe the commissioning of the Small Generating Facility (including any required testing), startup, and operation for a period of up to three Business Days after initial start-up of the unit. In addition, the Interconnection Customer shall notify the Distribution Provider at least five Business Days prior to conducting any on-site verification testing of the Small Generating Facility.

2.3.2 Following the initial inspection process described above, at reasonable hours, and upon reasonable notice, or at any time without notice in the event of an emergency or hazardous condition, the Distribution Provider shall have access to the Interconnection Customer's premises for any reasonable purpose in connection with the performance of the obligations imposed on it by this Agreement or if necessary to meet its legal obligation to provide service to its customers.

2.3.3 Each Party shall be responsible for its own costs associated with following this article.

Article 3. Effective Date, Term, Termination, and Disconnection

3.1 Effective Date
This Agreement shall become effective upon execution by the Parties subject to acceptance by FERC (if applicable), or if filed unexecuted, upon the date specified by the FERC. The Distribution Provider shall promptly file this Agreement with the FERC upon execution, if required.

3.2 Term of Agreement
This Agreement shall become effective on the Effective Date and shall remain in effect for a period of ten years from the Effective Date or such other longer period as the Interconnection Customer may request and shall be automatically renewed for each successive one-year period thereafter, unless terminated earlier in accordance with article 3.3 of this Agreement.

3.3 Termination
No termination shall become effective until the Parties have complied with all Applicable Laws and Regulations applicable to such termination, including the filing with FERC of a notice of termination of this Agreement (if required), which notice has been accepted for filing by FERC.

3.3.1 The Interconnection Customer may terminate this Agreement at any time by giving the Distribution Provider 20 Business Days written notice.

3.3.2 Either Party may terminate this Agreement after Default pursuant to article 7.6.

3.3.3 Upon termination of this Agreement, the Small Generating Facility will be disconnected from the Distribution Provider's Distribution System. The termination of this Agreement shall not relieve either Party of its liabilities and WDT GIP (2017) SGIA 9
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obligations, owed or continuing at the time of the termination.

3.3.4 The provisions of this article shall survive termination or expiration of this Agreement.

3.4 Temporary Disconnection
Temporary disconnection shall continue only for so long as reasonably necessary under Good Utility Practice.

3.4.1 Emergency Conditions -- "Emergency Condition" shall mean a condition or situation: (1) that in the judgment of the Party making the claim is imminently likely to endanger life or property; or (2) that, in the case of the Distribution Provider, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to the Distribution System, the Distribution Provider's Interconnection Facilities any Affected Systems; or (3) that, in the case of the Interconnection Customer, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to, the Small Generating Facility or the Interconnection Customer's Interconnection Facilities. Under Emergency Conditions, the Distribution Provider may immediately suspend interconnection service and temporarily disconnect the Small Generating Facility. The Distribution Provider shall notify the Interconnection Customer promptly when it becomes aware of an Emergency Condition that may reasonably be expected to affect the Interconnection Customer's operation of the Small Generating Facility.

The Interconnection Customer shall notify the Distribution Provider promptly when it becomes aware of an Emergency Condition that may reasonably be expected to affect the Distribution Provider's Distribution System or other Affected Systems. To the extent information is known, the notification shall describe the Emergency Condition, the extent of the damage or deficiency, the expected effect on the operation of both Parties' facilities and operations, its anticipated duration, and the necessary corrective action.

3.4.2 Routine Maintenance, Construction, and Repair
The Distribution Provider may interrupt interconnection service or curtail the output of the Small Generating Facility and temporarily disconnect the Small Generating Facility from the Distribution Provider's Distribution System when necessary for routine maintenance, construction, and repairs on the Distribution Provider's Distribution System and/or Transmission System. The Distribution Provider shall provide the Interconnection Customer with five Business Days notice prior to such interruption. The Distribution Provider shall use Reasonable Efforts to coordinate such reduction or temporary disconnection with the Interconnection Customer.

3.4.3 Forced Outages
During any forced outage, the Distribution Provider may suspend interconnection service to effect immediate repairs on the Distribution Provider's Distribution System and/or Transmission System. The Distribution Provider shall use Reasonable Efforts to provide the Interconnection Customer with prior notice. If prior notice is not given, the Distribution Provider shall, upon request, provide the Interconnection Customer written documentation after the fact explaining the circumstances of the disconnection.

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3.4.4 Adverse Operating Effects
The Distribution Provider shall notify the Interconnection Customer as soon as practicable if, based on Good Utility Practice, operation of the Small Generating Facility may cause disruption or deterioration of service to other customers served from the same electric system, or if operating the Small Generating Facility could cause damage to the Distribution Provider's Distribution System or Affected Systems. Supporting documentation used to reach the decision to disconnect shall be provided to the Interconnection Customer upon request. If, after notice, the Interconnection Customer fails to remedy the adverse operating effect within a reasonable time, the Distribution Provider may disconnect the Small Generating Facility. The Distribution Provider shall provide the Interconnection Customer with five Business Day notice of such disconnection, unless the provisions of article 3.4.1 apply.

3.4.5 Modification of the Small Generating Facility
The Interconnection Customer must receive written authorization from the Distribution Provider before making any change to the Small Generating Facility that may have a material impact on the safety or reliability of the Distribution System and/or Transmission System. Such authorization shall not be unreasonably withheld. Modifications shall be done in accordance with Good Utility Practice. If the Interconnection Customer makes such modification without the Distribution Provider's prior written authorization, the latter shall have the right to temporarily disconnect the Small Generating Facility.

3.4.6 Reconnection
The Parties shall cooperate with each other to restore the Small Generating Facility, Interconnection Facilities, and/or the Distribution Provider's Distribution System or Transmission System to their normal operating state as soon as reasonably practicable following a temporary disconnection.

Article 4. Cost Responsibility for Interconnection Facilities and Distribution Upgrades

4.1 Interconnection Facilities

4.1.1 The Interconnection Customer shall pay for the cost of the Interconnection Facilities itemized in Attachment 2 of this Agreement. The Distribution Provider shall provide a best estimate cost, including overheads, for the purchase and construction of its Interconnection Facilities and provide a detailed itemization of such costs. Costs associated with Interconnection Facilities may be shared with other entities that may benefit from such facilities by agreement of the Interconnection Customer, such other entities, and the Distribution Provider.

4.1.2 The Interconnection Customer shall be responsible for its share of all reasonable expenses, including overheads, associated with (1) owning, operating, maintaining, repairing, and replacing its own Interconnection Facilities, and (2) operating, maintaining, repairing, and replacing the Distribution Provider's Interconnection Facilities.

4.2 Distribution Upgrades
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The Distribution Provider shall design, procure, construct, install, and own the Distribution Upgrades described in Attachment 6 of this Agreement. If the Distribution Provider and the Interconnection Customer agree, the Interconnection Customer may construct Distribution Upgrades that are located on land owned by the Interconnection Customer. The actual cost of the Distribution Upgrades, including overheads, as well as costs associated with operating, maintaining, repairing, and replacing Distribution Provider’s Distribution Upgrades shall be directly assigned to the Interconnection Customer.

Article 5. Cost Responsibility for Network Upgrades

5.1 Applicability
No portion of this Article 5 shall apply unless the interconnection of the Small Generating Facility requires Network Upgrades.

5.2 Network Upgrades
The Distribution Provider or the Transmission Owner shall design, procure, construct, install, and own the Network Upgrades described in Attachment 6 of this Agreement. If the Distribution Provider and the Interconnection Customer agree, the Interconnection Customer may construct Network Upgrades that are located on land owned by the Interconnection Customer. Unless the Distribution Provider elects to pay for Network Upgrades, the actual cost of the Network Upgrades, including overheads, shall be borne by the Interconnection Customer unless Article 5.2.1 directs otherwise.

5.2.1 Repayment of Amounts Advanced for Network Upgrades To the extent the CAISO Tariff, Section 12.3.2 of Appendix Y and Section 14.3.2 of Appendix DD, and successor tariffs provides for cash repayment or Congestion Revenue Rights to the Interconnection Customer for contribution to the cost of Network Upgrades, the Interconnection Customer shall be entitled to a cash repayment of Congestion Revenue Rights, equal to the total amount paid to the Distribution Provider and Affected System operator, if any, for Network Upgrades, including any tax gross-up or other tax-related payments associated with the Network Upgrades, and not otherwise refunded to the Interconnection Customer.

Any repayment shall include interest calculated in accordance with the methodology set forth in FERC’s regulations at 18 C.F.R. 35.19a(a)(2)(iii) from the date of any payment for Network Upgrades through the date on which the Interconnection Customer receives a repayment of such payment pursuant to this subparagraph. The Interconnection Customer may assign such repayment rights to any person.

5.2.1.1 If the Interconnection Customer is entitled to a cash repayment pursuant to Article 5.2.1, the Interconnection Customer, the Distribution Provider, and Affected System operator may adopt any alternative payment schedule that is mutually agreeable so long as the Distribution Provider and Affected System operator take one of the following actions no later than five years from the Commercial Operation Date: (1) return to the Interconnection Customer any amounts advanced for Network Upgrades not previously repaid, or (2) declare in writing that the WDT GIP (2017) SGIA 12
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Distribution Provider or Affected System operator(s) will continue to provide payments to the Interconnection Customer on a dollar-for-dollar basis for the non-usage sensitive portion of transmission charges, or develop an alternative schedule that is mutually agreeable and provides for the return of all amounts advanced for Network Upgrades not previously repaid; however, full reimbursement shall not extend beyond twenty (20) years from the commercial operation date.

5.2.1.2 If the Small Generating Facility fails to achieve commercial operation, but it or another generating facility is later constructed and requires use of the Network Upgrades, the Distribution Provider and Affected System operator shall at that time reimburse the Interconnection Customer for the amounts advanced for the Network Upgrades if the Interconnection Customer is entitled to a cash repayment pursuant to Article 5.2.1.

Before any such reimbursement can occur, the Interconnection Customer, or the entity that ultimately constructs the generating facility, if different, is responsible for identifying the entity to which reimbursement must be made.

5.3 Special Provisions for Affected Systems
Unless the Distribution Provider provides, under this Agreement, for the repayment of amounts advanced to Affected System operator(s) for Network Upgrades, the Interconnection Customer and Affected System operator shall enter into an agreement that provides for such repayment. The agreement shall specify the terms governing payments to be made by the Interconnection Customer to Affected System operator as well as the repayment by Affected System operator.

5.4 Rights Under Other Agreements
Notwithstanding any other provision of this Agreement, nothing herein shall be construed as relinquishing or foreclosing any rights, including but not limited to firm transmission rights, capacity rights, transmission congestion rights, or transmission credits, that the Interconnection Customer shall be entitled to, now or in the future, under any other agreement or tariff as a result of, or otherwise associated with, the transmission capacity, if any, created by the Network Upgrades, including the right to obtain cash reimbursements or transmission credits for transmission service that is not associated with the Small Generating Facility.

Article 6. Billing, Payment, Milestones, and Financial Security

6.1 Billing and Payment Procedures and Final Accounting

6.1.1 The Distribution Provider shall bill the Interconnection Customer for the design, engineering, construction, and procurement costs of Interconnection Facilities and Upgrades contemplated by this Agreement on a monthly basis, or as otherwise agreed by the Parties. The Interconnection Customer shall pay each bill within 30 calendar days of receipt, or as otherwise agreed to by the Parties.

6.1.2 Within six months of completing the construction and installation of the Distribution Provider's Interconnection Facilities and/or Upgrades described in the Attachments to this Agreement, the Distribution Provider shall provide the WDT GIP (2017) SGIA 13
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Interconnection Customer with a final accounting report of any difference between (1) the Interconnection Customer's cost responsibility for the actual cost of such facilities or Upgrades, and (2) the Interconnection Customer's previous aggregate payments to the Distribution Provider for such facilities or Upgrades. If the Interconnection Customer's cost responsibility exceeds its previous aggregate payments, the Distribution Provider shall invoice the Interconnection Customer for the amount due and the Interconnection Customer shall make payment to the Distribution Provider within 30 calendar days. If the Interconnection Customer's previous aggregate payments exceed its cost responsibility under this Agreement, the Distribution Provider shall refund to the Interconnection Customer an amount equal to the difference within 30 calendar days of the final accounting report.

6.2 Milestones
The Parties shall agree on milestones for which each Party is responsible and list them in Attachment 4 of this Agreement. A Party's obligations under this provision may be extended by agreement. If a Party anticipates that it will be unable to meet a milestone for any reason other than an Uncontrollable Force Event, it shall immediately notify the other Party of the reason(s) for not meeting the milestone and (1) propose the earliest reasonable alternate date by which it can attain this and future milestones, and (2) requesting appropriate amendments to Attachment 4. The Party affected by the failure to meet a milestone shall not unreasonably withhold agreement to such an amendment unless (1) it will suffer significant uncompensated economic or operational harm from the delay, (2) attainment of the same milestone has previously been delayed, or (3) it has reason to believe that the delay in meeting the milestone is intentional or unwarranted notwithstanding the circumstances explained by the Party proposing the amendment.

6.3 Financial Security Arrangements
The Interconnection Customer shall provide the Distribution Provider an Interconnection Financial Security by the earliest date of either (i) no later than the financial security posting milestone date negotiated in Attachment 4 of this Agreement, (ii) no later than 180 Calendar Days after the effective date of this agreement, or (iii) at least twenty (20) Business Days prior to the commencement of the design, procurement, installation, or construction of a discrete portion of the Distribution Provider's Interconnection Facilities and Upgrades. The Interconnection Customer shall provide the Distribution Provider, at the Interconnection Customer's option, a guarantee, letter of credit, escrow agreement or other form of security that is reasonably acceptable to the Distribution Provider and is consistent with the Uniform Commercial Code of the jurisdiction where the Point of Interconnection is located. Such security for payment shall be in an amount sufficient to cover the costs for constructing, designing, procuring, and installing the applicable portion of the Distribution Provider's Interconnection Facilities and Upgrades and shall be reduced on a dollar-for-dollar basis for payments made to the Distribution Provider under this Agreement during its term. In addition:

6.3.1 The guarantee must be made by an entity that meets the creditworthiness requirements of the Distribution Provider, and contain terms and conditions that guarantee payment of any amount that may be due from the Interconnection Customer, up to an agreed-to maximum amount.

6.3.2 The letter of credit or escrow agreement must be issued by a financial institution or insured reasonably acceptable to the Distribution Provider and must specify a WDT GIP (2017) SGIA 14
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reasonable expiration date.

6.4 Responsibility for any Outstanding Interconnection Study Costs The Interconnection Customer must complete payment on all outstanding invoiced interconnection study costs no later than the financial security posting milestone date negotiated in Attachment 4 of this Agreement. Study costs not yet invoiced within thirty (30) Calendar Days of that financial security posting deadline must be paid by the Interconnection Customer within thirty (30) Calendar Days of the date of the invoice once they are invoiced to the Interconnection Customer.

Failure to complete payment on these interconnection study invoices by these deadlines will constitute Default on this Agreement by the Interconnection Customer, subject to the terms of Article 7.6 “Default”.

Article 7. Assignment, Liability, Indemnity, Uncontrollable Force, Consequential Damages, and Default

7.1 Assignment
This Agreement may be assigned by either Party upon fifteen (15) Business Days prior written notice and opportunity to object by the other Party; provided that:

7.1.1 Either Party may assign this Agreement without the consent of the other Party to any affiliate of the assigning Party with an equal or greater credit rating and with the legal authority and operational ability to satisfy the obligations of the assigning Party under this Agreement;

7.1.2 The Interconnection Customer shall have the right to assign this Agreement, without the consent of the Distribution Provider, for collateral security purposes to aid in providing financing for the Small Generating Facility, provided that the Interconnection Customer will promptly notify the Distribution Provider of any such assignment.

7.1.3 Any attempted assignment that violates this article is void and ineffective.

Assignment shall not relieve a Party of its obligations, nor shall a Party's obligations be enlarged, in whole or in part, by reason thereof. An assignee is responsible for meeting the same financial, credit, and insurance obligations as the Interconnection Customer. Where required, consent to assignment will not be unreasonably withheld, conditioned or delayed.

7.2 Limitation of Liability
Each Party's liability to the other Party for any loss, cost, claim, injury, liability, or expense, including reasonable attorney's fees, relating to or arising from any act or omission in its performance of this Agreement, shall be limited to the amount of direct damage actually incurred. In no event shall either Party be liable to the other Party for any indirect, special, consequential, or punitive damages, except as authorized by this Agreement.

7.3 Indemnity
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7.3.1 This provision protects each Party from liability incurred to third parties as a result of carrying out the provisions of this Agreement. Liability under this provision is exempt from the general limitations on liability found in article 7.2.

7.3.2 The Parties shall at all times indemnify, defend, and hold the other Party harmless from, any and all damages, losses, claims, including claims and actions relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the other Party's action or failure to meet its obligations under this Agreement on behalf of the indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the indemnified Party.

7.3.3 If an indemnified person is entitled to indemnification under this article as a result of a claim by a third party, and the indemnifying Party fails, after notice and reasonable opportunity to proceed under this article, to assume the defense of such claim, such indemnified person may at the expense of the indemnifying Party contest, settle or consent to the entry of any judgment with respect to, or pay in full, such claim.

7.3.4 If an indemnifying party is obligated to indemnify and hold any indemnified person harmless under this article, the amount owing to the indemnified person shall be the amount of such indemnified person's actual loss, net of any insurance or other recovery.

7.3.5 Promptly after receipt by an indemnified person of any claim or notice of the commencement of any action or administrative or legal proceeding or investigation as to which the indemnity provided for in this article may apply, the indemnified person shall notify the indemnifying party of such fact. Any failure of or delay in such notification shall not affect a Party's indemnification obligation unless such failure or delay is materially prejudicial to the indemnifying party.

7.4 Consequential Damages
Other than as expressly provided for in this Agreement, neither Party shall be liable under any provision of this Agreement for any losses, damages, costs or expenses for any special, indirect, incidental, consequential, or punitive damages, including but not limited to loss of profit or revenue, loss of the use of equipment, cost of capital, cost of temporary equipment or services, whether based in whole or in part in contract, in tort, including negligence, strict liability, or any other theory of liability; provided, however, that damages for which a Party may be liable to the other Party under another agreement will not be considered to be special, indirect, incidental, or consequential damages hereunder.

7.5 Uncontrollable Force

7.5.1 As used in this article, an Uncontrollable Force shall mean "any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm, flood, earthquake, explosion, breakage or accident to machinery or equipment, any curtailment, order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or any other cause beyond the WDT GIP (2017) SGIA 16
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reasonable control of the Distribution Provider or Interconnection Customer which could not be avoided through the exercise of Good Utility Practice. An Uncontrollable Force Event does not include an act of negligence or intentional wrongdoing by the Party claiming Uncontrollable Force."

7.5.2 If an Uncontrollable Force Event prevents a Party from fulfilling any obligations under this Agreement, the Party affected by the Uncontrollable Force Event (Affected Party) shall promptly notify the other Party, either in writing or via the telephone, of the existence of the Uncontrollable Force Event. The notification must specify in reasonable detail the circumstances of the Uncontrollable Force Event, its expected duration, and the steps that the Affected Party is taking to mitigate the effects of the event on its performance. The Affected Party shall keep the other Party informed on a continuing basis of developments relating to the Uncontrollable Force Event until the event ends. The Affected Party will be entitled to suspend or modify its performance of obligations under this Agreement (other than the obligation to make payments) only to the extent that the effect of the Uncontrollable Force Event cannot be mitigated by the use of Reasonable Efforts. The Affected Party will use Reasonable Efforts to resume its performance as soon as possible.

7.6 Default

7.6.1 No Default shall exist where such failure to discharge an obligation (other than the payment of money) is the result of an Uncontrollable Force Event as defined in this Agreement or the result of an act or omission of the other Party. Upon a Default, the non-defaulting Party shall give written notice of such Default to the defaulting Party. Except as provided in article 7.6.2, the defaulting Party shall have 60 calendar days from receipt of the Default notice within which to cure such Default; provided however, if such Default is not capable of cure within 60 calendar days, the defaulting Party shall commence such cure within 20 calendar days after notice and continuously and diligently complete such cure within six months from receipt of the Default notice; and, if cured within such time, the Default specified in such notice shall cease to exist.

7.6.2 If a Default is not cured as provided in this article, or if a Default is not capable of being cured within the period provided for herein, the non-defaulting Party shall have the right to terminate this Agreement by written notice at any time until cure occurs, and be relieved of any further obligation hereunder and, whether or not that Party terminates this Agreement, to recover from the defaulting Party all amounts due hereunder, plus all other damages and remedies to which it is entitled at law or in equity. The provisions of this article will survive termination of this Agreement.

Article 8. Insurance

8.1 The Interconnection Customer shall, at its own expense, maintain in force general liability insurance without any exclusion for liabilities related to the interconnection undertaken pursuant to this Agreement. The amount of such insurance shall be sufficient to insure against all reasonably foreseeable direct liabilities given the size and nature of the generating equipment being interconnected, the interconnection itself, and the WDT GIP (2017) SGIA 17
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characteristics of the system to which the interconnection is made. The Interconnection Customer shall obtain additional insurance only if necessary as a function of owning and operating a generating facility. Such insurance shall be obtained from an insurance provider authorized to do business in the State where the interconnection is located.

Certification that such insurance is in effect shall be provided upon request of the Distribution Provider, except that the Interconnection Customer shall show proof of insurance to the Distribution Provider no later than ten Business Days prior to the anticipated commercial operation date. An Interconnection Customer of sufficient credit-worthiness may propose to self-insure for such liabilities, and such a proposal shall not be unreasonably rejected.

8.2 The Distribution Provider agrees to maintain general liability insurance or self-insurance consistent with the Distribution Provider’s commercial practice. Such insurance or self-insurance shall not exclude coverage for the Distribution Provider's liabilities undertaken pursuant to this Agreement.

8.3 The Parties further agree to notify each other whenever an accident or incident occurs resulting in any injuries or damages that are included within the scope of coverage of such insurance, whether or not such coverage is sought.

Article 9. Confidentiality

9.1 Confidential Information shall mean any confidential and/or proprietary information provided by one Party to the other Party that is clearly marked or otherwise designated "Confidential." For purposes of this Agreement all design, operating specifications, and metering data provided by the Interconnection Customer shall be deemed Confidential Information regardless of whether it is clearly marked or otherwise designated as such.

9.2 Confidential Information does not include information previously in the public domain, required to be publicly submitted or divulged by Governmental Authorities (after notice to the other Party and after exhausting any opportunity to oppose such publication or release), or necessary to be divulged in an action to enforce this Agreement. Each Party receiving Confidential Information shall hold such information in confidence and shall not disclose it to any third party nor to the public without the prior written authorization from the Party providing that information, except to fulfill obligations under this Agreement, or to fulfill legal or regulatory requirements.

9.2.1 Each Party shall employ at least the same standard of care to protect Confidential Information obtained from the other Party as it employs to protect its own Confidential Information.

9.2.2 Each Party is entitled to equitable relief, by injunction or otherwise, to enforce its rights under this provision to prevent the release of Confidential Information without bond or proof of damages, and may seek other remedies available at law or in equity for breach of this provision.

9.3 Notwithstanding anything in this article to the contrary, and pursuant to 18 CFR § 1 b.20, if FERC, during the course of an investigation or otherwise, requests information from one of the Parties that is otherwise required to be maintained in confidence pursuant to this Agreement, the Party shall provide the requested information to FERC, within the WDT GIP (2017) SGIA 18
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time provided for in the request for information. In providing the information to FERC, the Party may, consistent with 18 CFR § 388.112, request that the information be treated as confidential and non-public by FERC and that the information be withheld from public disclosure. Parties are prohibited from notifying the other Party to this Agreement prior to the release of the Confidential Information to FERC. The Party shall notify the other Party to this Agreement when it is notified by FERC that a request to release Confidential Information has been received by FERC, at which time either of the Parties may respond before such information would be made public, pursuant to 18 CFR § 388.112. Requests from a state regulatory body conducting a confidential investigation shall be treated in a similar manner if consistent with the applicable state rules and regulations.

Article 10. Disputes

10.1 The Parties agree to attempt to resolve all disputes arising out of the interconnection process according to the provisions of this article.

10.2 In the event of a dispute, either Party shall provide the other Party with a written Notice of Dispute. Such Notice shall describe in detail the nature of the dispute.

10.3 If the dispute has not been resolved within two Business Days after receipt of the Notice, either Party may contact FERC's Dispute Resolution Service (DRS) for assistance in resolving the dispute.

10.4 The DRS will assist the Parties in either resolving their dispute or in selecting an appropriate dispute resolution venue (e.g., mediation, settlement judge, early neutral evaluation, or technical expert) to assist the Parties in resolving their dispute. DRS can be reached at 1-877-337-2237 or via the internet at http://www.ferc.gov/legal/adr.asp.

10.5 Each Party agrees to conduct all negotiations in good faith and will be responsible for one-half of any costs paid to neutral third-parties.

10.6 If neither Party elects to seek assistance from the DRS, or if the attempted dispute resolution fails, then either Party may exercise whatever rights and remedies it may have in equity or law consistent with the terms of this Agreement.

Article 11. Taxes

11.1 The Parties agree to follow all applicable tax laws and regulations, consistent with FERC policy and Internal Revenue Service requirements.

11.2 Each Party shall cooperate with the other to maintain the other Party's tax status.

Nothing in this Agreement is intended to adversely affect the Distribution Provider's tax exempt status with respect to the issuance of bonds including, but not limited to, local furnishing bonds.

Article 12. Miscellaneous
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12.1 Governing Law, Regulatory Authority, and Rules
The validity, interpretation and enforcement of this Agreement and each of its provisions shall be governed by the laws of the state of California (where the Point of Interconnection is located), without regard to its conflicts of law principles. This Agreement is subject to all Applicable Laws and Regulations. Each Party expressly reserves the right to seek changes in, appeal, or otherwise contest any laws, orders, or regulations of a Governmental Authority.

12.2 Amendment
The Parties may amend this Agreement by a written instrument duly executed by both Parties.

12.3 No Third-Party Beneficiaries
This Agreement is not intended to and does not create rights, remedies, or benefits of any character whatsoever in favor of any persons, corporations, associations, or entities other than the Parties, and the obligations herein assumed are solely for the use and benefit of the Parties, their successors in interest and where permitted, their assigns.

12.4 Waiver

12.4.1 The failure of a Party to this Agreement to insist, on any occasion, upon strict performance of any provision of this Agreement will not be considered a waiver of any obligation, right, or duty of, or imposed upon, such Party.

12.4.2 Any waiver at any time by either Party of its rights with respect to this Agreement shall not be deemed a continuing waiver or a waiver with respect to any other failure to comply with any other obligation, right, duty of this Agreement.

Termination or default of this Agreement for any reason by Interconnection Customer shall not constitute a waiver of the Interconnection Customer's legal rights to obtain an interconnection from the Distribution Provider. Any waiver of this Agreement shall, if requested, be provided in writing.

12.5 Entire Agreement
This Agreement, including all Attachments, constitutes the entire agreement between the Parties with reference to the subject matter hereof, and supersedes all prior and contemporaneous understandings or agreements, oral or written, between the Parties with respect to the subject matter of this Agreement. There are no other agreements, representations, warranties, or covenants which constitute any part of the consideration for, or any condition to, either Party's compliance with its obligations under this Agreement.

12.6 Multiple Counterparts
This Agreement may be executed in two or more counterparts, each of which is deemed an original but all constitute one and the same instrument.

12.7 No Partnership
This Agreement shall not be interpreted or construed to create an association, joint venture, agency relationship, or partnership between the Parties or to impose any partnership obligation or partnership liability upon either Party. Neither Party shall have any right, power or authority to enter into any agreement or undertaking for, or act on WDT GIP (2017) SGIA 20
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behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other Party.

12.8 Severability
If any provision or portion of this Agreement shall for any reason be held or adjudged to be invalid or illegal or unenforceable by any court of competent jurisdiction or other Governmental Authority, (1) such portion or provision shall be deemed separate and independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable the benefits to each Party that were affected by such ruling, and (3) the remainder of this Agreement shall remain in full force and effect.

12.9 Security Arrangements
Infrastructure security of electric system equipment and operations and control hardware and software is essential to ensure day-to-day reliability and operational security. FERC expects all transmission providers, market participants, and interconnection customers interconnected to electric systems to comply with the recommendations offered by the President's Critical Infrastructure Protection Board and, eventually, best practice recommendations from the electric reliability authority. All public utilities are expected to meet basic standards for system infrastructure and operational security, including physical, operational, and cyber-security practices.

12.10 Environmental Releases
Each Party shall notify the other Party, first orally and then in writing, of the release of any hazardous substances, any asbestos or lead abatement activities, or any type of remediation activities related to the Small Generating Facility or the Interconnection Facilities, each of which may reasonably be expected to affect the other Party. The notifying Party shall (1) provide the notice as soon as practicable, provided such Party makes a good faith effort to provide the notice no later than 24 hours after such Party becomes aware of the occurrence, and (2) promptly furnish to the other Party copies of any publicly available reports filed with any governmental authorities addressing such events.

12.11 Subcontractors
Nothing in this Agreement shall prevent a Party from utilizing the services of any subcontractor as it deems appropriate to perform its obligations under this Agreement; provided, however, that each Party shall require its subcontractors to comply with all applicable terms and conditions of this Agreement in providing such services and each Party shall remain primarily liable to the other Party for the performance of such subcontractor.

12.11.1 The creation of any subcontract relationship shall not relieve the hiring Party of any of its obligations under this Agreement. The hiring Party shall be fully responsible to the other Party for the acts or omissions of any subcontractor the hiring Party hires as if no subcontract had been made; provided, however, that in no event shall the Distribution Provider be liable for the actions or inactions of the Interconnection Customer or its subcontractors with respect to obligations of the Interconnection Customer under this Agreement. Any applicable obligation imposed by this Agreement upon the hiring Party shall be equally binding upon, and shall be construed as having application to, any subcontractor of such Party.

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of subcontractor’s insurance.

12.12 Reservation of Rights
The Distribution Provider shall have the right to make a unilateral filing with FERC to modify this Agreement with respect to any rates, terms and conditions, charges, classifications of service, rule or regulation under section 205 or any other applicable provision of the Federal Power Act and FERC's rules and regulations thereunder, and the Interconnection Customer shall have the right to make a unilateral filing with FERC to modify this Agreement under any applicable provision of the Federal Power Act and FERC's rules and regulations; provided that each Party shall have the right to protest any such filing by the other Party and to participate fully in any proceeding before FERC in which such modifications may be considered. Nothing in this Agreement shall limit the rights of the Parties or of FERC under sections 205 or 206 of the Federal Power Act and FERC's rules and regulations, except to the extent that the Parties otherwise agree as provided herein.

Article 13. Notices

13.1 General
Unless otherwise provided in this Agreement, any written notice, demand, or request required or authorized in connection with this Agreement ("Notice") shall be deemed properly given if delivered in person, delivered by recognized national courier service, or sent by first class mail, postage prepaid, to the person specified below:

If to the Interconnection Customer:

Central Coast Community Energy
Attention: Robert Shaw
70 Garden Court, Suite 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
If to the Distribution Provider:

Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]

13.2 Billing and Payment
Billings and payments shall be sent to the addresses below:

Interconnection Customer:

Company Name
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Attention: Primary BILLING Contact Name
Street Address
City, State Zip Code
Phone: phone number
Email: email address
Distribution Provider:

Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]

13.3 Alternative Forms of Notice
Any notice or request required or permitted to be given by either Party to the other and not required by this Agreement to be given in writing may be so given by telephone, facsimile or e-mail to the telephone numbers and e-mail addresses set out below:

If to the Interconnection Customer:

Central Coast Community Energy
Attention: Robert Shaw
70 Garden Court, Suite 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
If to the Distribution Provider:

Pacific Gas and Electric Company
Attention: Electric Grid Interconnection - Contract Management 300 Lakeside Drive
Oakland, CA 94612-3534
Email: [email protected]

13.4 Designated Operating Representative
The Parties may also designate operating representatives to conduct the communications which may be necessary or convenient for the administration of this Agreement. This person will also serve as the point of contact with respect to operations and maintenance of the Party’s facilities.

Interconnection Customer’s Operating Representative:

Central Coast Community Energy
Attention: Robert Shaw
70 Garden Court, Suite 300
Monterey, CA 93940
Phone: 877-455-2223
Email: [email protected]
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Distribution Provider’s Operating Representative:

Pacific Gas and Electric Company
Concord Distribution Control Center
1020 Detroit Ave., Concord, CA 94518
Work Management Desk (Planned Clearance Requests)
Attention: Santa Cruz District (AOR 6- Central Coast Division) Phone: 844-743-2100
Real Time Operator Desk (Real Time Operational Issues)
Attention: Santa Cruz District (AOR 6- Central Coast Division) Phone: 844-743-3322

13.5 Changes to the Notice Information
Either Party may change this information by giving five Business Days written notice prior to the effective date of the change.

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Article 14. Signatures
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their respective duly authorized representatives.

For the Distribution Provider: Pacific Gas and Electric Company Signature:

Name: Michael Porter
Title: Manager, EGI Wholesale Operations
Date:

For the Interconnection Customer: Full Company/Customer Name Signature:

Name: Robert Shaw
Title: Customer Signatory Title
Date:

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Attachment 1
Glossary of Terms
Adverse System Impact -- A potential or actual negative effect due to technical or operational limits on conductors or equipment being exceeded that may compromise the safety and reliability of the electric system.

Affected System – An electric system other than the Distribution Provider's Distribution System that may be affected by the proposed interconnection, including but not limited to the Transmission System.

Affected System Operator -- The entity that operates an Affected System.

Affiliate -- With respect to a corporation, partnership or other entity, each such other corporation, partnership or other entity that directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with, such corporation, partnership or other entity.

Applicable Laws and Regulations -- All duly promulgated applicable federal, state and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders, permits and other duly authorized actions of any Governmental Authority.

Applicable Reliability Council -- The reliability council applicable to the Distribution System to which the Generating Facility is directly interconnected.

Applicable Reliability Standards -- The requirements and guidelines of NERC, the Applicable Reliability Council, and the Control Area of the Distribution System to which the Generating Facility is directly interconnected, including the requirements pursuant to Section 215 of the Federal Power Act.

Area Deliverability Constraint -- A transmission system operating limit, that would constrain the deliverability of a substantial number of generators if the CAISO were to assign full capacity or partial capacity deliverability status to additional generating facilities in one or more specified geographic or electrical areas of the CAISO Controlled Grid in a total amount that is greater than the TP Deliverability for those areas. May also be a transmission system operating limit that constrains a quantity of generation in a local area of the grid that is larger than the generation amount identified in the applicable Transmission Planning Process (TPP) portfolio for the entire portfolio area. May also be a transmission system operating limit that constrains all or most of the same generation already constrained by a previously identified Area Deliverability Constraint.

Area Delivery Network Upgrade (ADNU) -- A transmission upgrade or addition identified by the CAISO to relieve an Area Deliverability Constraint.

Base Case – The data including, but not limited to, base power flow, short circuit and stability data bases, underlying load, generation, and transmission facility assumptions, contingency lists, including relevant special protection systems, and transmission diagrams used to perform the Interconnection Studies. The Base Case may include Critical Energy Infrastructure Information (as that term is defined by FERC). The Base Case shall include transmission facilities as approved by the Distribution Provider or CAISO, as applicable, and Distribution Upgrades and Network Upgrades associated with generating facilities in (iv) below and generating facilities that (i) are directly interconnected to the Distribution System or CAISO Grid; (ii) are interconnected to Affected Systems and may have an impact on the Interconnection Request; (iii) have a pending request to interconnect to the Distribution System or an Affected System; or (iv) are not interconnected to the Distribution System or CAISO Grid, but are subject to a fully executed generator interconnection agreement (or its equivalent predecessor agreement) or for which an WDT GIP (2017) SGIA 26
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unexecuted generator interconnection agreement (or its equivalent predecessor agreement) has been requested to be filed with FERC.

Breach -- The failure of a Party to perform or observe any material term or condition of the GIA.

Breaching Party – A Party that is in Breach of the GIA.

Business Day – Monday through Friday, excluding Federal Holidays and the Friday after Thanksgiving.

Calendar Day -- Any day including Saturday, Sunday or a Federal Holiday.

CAISO – California Independent System Operator Corporation. See also ISO.

Clustering -- The process whereby a group of Interconnection Requests is studied together, instead of serially, for the purpose of conducting the Interconnection System Impact Study.

Commercial Operation -- The status of a Generating Facility that has commenced generating electricity for sale, excluding electricity generated during Trial Operation.

Commercial Operation Date – The date on which an Electric Generating Unit at a Generating Facility has received final written Permission to Operate from the Distribution Provider for operation of the generation facilities in parallel with the utility.

Confidential Information -- Any confidential, proprietary or trade secret information of a plan, specification, pattern, procedure, design, device, list, concept, policy or compilation relating to the present or planned business of a Party, which is designated as confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection, or otherwise.

Construction Activities -- Actions by the Distribution Provider that result in irrevocable financial commitments for the purchase of major electrical equipment or land for Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades assigned to the Interconnection Customer that occur after receipt of all appropriate governmental approvals needed for the Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades.

Control Area -- An electrical system or systems bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other Control Areas and contributing to frequency regulation of the interconnection. A Control Area must be certified by an Applicable Reliability Council.

CPUC -- California Public Utilities Commission.

Default – The failure of a breaching Party to cure its Breach under the Small Generator Interconnection Agreement.

Deliverability -- (1) The annual Net Qualifying Capacity of a Generating Facility, as verified through a Deliverability assessment and measured in MW, which specifies the amount of resource adequacy capacity the Generating Facility is eligible to provide. (2) The annual Maximum Import Capability of an intertie, which specifies the amount of resource adequacy capacity, measured in MW, that Load-serving Entities collectively can procure from imports at that intertie to meet their resource adequacy requirements.

Deliverability Assessment -- An evaluation of the On-Peak Deliverability Assessment set forth in GIP Section 5.8.3, and the Off-Peak Deliverability Assessment set forth in GIP Section 5.8.3 to determine if a Generating Facility or a group of Generating Facilities could provide Energy to the CAISO Controlled Grid WDT GIP (2017) SGIA 27
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and be delivered to the aggregate of Load on the CAISO Controlled Grid at Peak Load, under a variety of severely stressed conditions.

Deliverability Status -- An attribute of a Generating Facility that is requested by an Interconnection Customer for the Generating Facility, assigned by the CAISO to the Generating Facility through the GIP, GIDAP, or other process specified in the CAISO tariff, and that affects the maximum Net Qualifying Capacity to which the Generating Facility could be entitled.

Delivery Network Upgrades -- The transmission facilities at or beyond the point where the Distribution Provider’s Distribution System interconnects to the ISO Grid, other than Reliability Network Upgrades, identified in the Interconnection Studies to relieve constraints on the ISO Grid. Delivery Network Upgrades may be further classified as Local Delivery Network Upgrades or Area Delivery Network Upgrades.

Dispute Resolution -- The procedure for resolution of a dispute between the Parties in which they will first attempt to resolve the dispute on an informal basis.

Distribution Owner – The entity that owns, leases, or otherwise possesses an interest in the portion of the Distribution System at the Point of Interconnection and may be a Party to the Small Generator Interconnection Agreement to the extent necessary.

Distribution Provider – The public utility (or its designated agent) that owns, controls, or operates transmission or distribution facilities used for the transmission of electricity in interstate commerce and provides transmission or wholesale distribution service under the Tariff. The term Distribution Provider should be read to include the Distribution Owner when the Distribution Owner is separate from the Distribution Provider.

Distribution Provider's Interconnection Facilities -- All facilities and equipment owned, controlled, or operated by the Distribution Provider from the Point of Change of Ownership to the Point of Interconnection as identified in the GIA, including any modifications, additions or upgrades to such facilities and equipment. Distribution Provider's Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Stand Alone Network Upgrades or Network Upgrades.

Distribution Service -- The wholesale distribution service provided under the Tariff.

Distribution System – Those non-ISO transmission and distribution facilities owned, controlled and operated by the Distribution Provider that are used to provide distribution service under the Tariff, which facilities and equipment are used to transmit electricity to ultimate usage points such as homes and industries directly from nearby generators or from interchanges with higher voltage transmission networks which transport bulk power over longer distances. The voltage levels at which Distribution Systems operate differ among areas.

Distribution Upgrades – The additions, modifications, and upgrades to the Distribution Provider's Distribution System at or beyond the Point of Interconnection to facilitate interconnection of the Small Generating Facility and render the service necessary to effect the Interconnection Customer's wholesale sale of electricity in interstate commerce. Distribution Upgrades do not include Interconnection Facilities.

Effective Date -- The date on which the GIA becomes effective upon execution by the Parties subject to acceptance by FERC, or if filed unexecuted, upon the date specified by FERC.

Electric Generating Unit -- An individual electric generator and its associated plant and apparatus whose electrical output is capable of being separately identified and metered.

Emergency Condition -- A condition or situation: (1) that in the judgment of the Party making the claim is imminently likely to endanger life or property; or (2) that, in the case of a Distribution Provider, is WDT GIP (2017) SGIA 28
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imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to Distribution Provider's Distribution System, Distribution Provider's Interconnection Facilities or the electric systems of others to which the Distribution Provider's Distribution System is directly connected; or (3) that, in the case of Interconnection Customer, is imminently likely (as determined in a nondiscriminatory manner) to cause a material adverse effect on the security of, or damage to, the Generating Facility or Interconnection Customer's Interconnection Facilities. System restoration and black start shall be considered Emergency Conditions; provided that Interconnection Customer is not obligated by the GIA to possess black start capability.

Energy-Only Deliverability Status -- A condition elected by an Interconnection Customer for a Generating Facility interconnected to Distribution System, the result of which is that the Interconnection Customer is responsible only for the costs of Reliability Network Upgrades and is not responsible for the costs of Delivery Network Upgrades, but the Generating Facility will be deemed to have a Net Qualifying Capacity (as defined in the ISO Tariff) of zero and, therefore, cannot be considered to be a Resource Adequacy Resource (as defined in the ISO Tariff).

Engineering & Procurement (E&P) Agreement -- An agreement that authorizes the Distribution Provider to begin engineering and procurement of long lead-time items necessary for the establishment of the interconnection in order to advance the implementation of the Interconnection Request.

Environmental Law – The applicable Laws or Regulations relating to pollution or protection of the environment or natural resources.

Federal Power Act -- The Federal Power Act, as amended, 16 U.S.C. §§ 791a et seq.

FERC -- The Federal Energy Regulatory Commission (Commission) or its successor.

Full Capacity Deliverability Status (FCDS) – The condition whereby a Generating Facility interconnected with the Distribution System, under coincident ISO Control Area peak demand and a variety of severely stressed system conditions, can deliver the Generating Facility’s full output to the aggregate of load on the ISO Grid, consistent with the ISO’s reliability criteria and procedures and the ISO’s On-Peak Deliverability Assessment.

Generating Facility – The Interconnection Customer's device for the production and/or storage for later injection of electricity identified in the Interconnection Request, but shall not include the Interconnection Customer's Interconnection Facilities. A Small Generating Facility is one that has maximum capacity of 20 MW or less. A Large Generating Facility is one that has a maximum capacity of more than 20 MW.

Generating Facility Capacity -- The net capacity of the Generating Facility and the aggregate net capacity of the Generating Facility where it includes multiple Electric Generating Units.

Generator Interconnection Agreement (GIA) – Either the Small Generator Interconnection Agreement (SGIA), which is Attachment F to the Wholesale Distribution Tariff, unless the proposed interconnection is for a generating facility larger than 20 MW, in which case references to interconnection agreement are to the Large Generator Interconnection Agreement (LGIA), which is Attachment H to the Wholesale Distribution Tariff.

Generator Interconnection and Deliverability Allocation Procedures (GIDAP) – See ISO’s Generator Interconnection and Deliverability Allocation Procedures (ISO Tariff GIDAP) Generator Interconnection Procedures (GIP) – See the definition for either ISO’s Tariff Generator Interconnection Procedures (ISO Tariff GIP), or Wholesale Distribution Tariff Generator Interconnection Procedures (WDT GIP).

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Good Utility Practice – Any of the practices, methods and acts engaged in or approved by a significant portion of the electric industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region.

Governmental Authority – Any federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the Parties, their respective facilities, or the respective services they provide, and exercising or entitled to exercise any administrative, executive, police, or taxing authority or power; provided, however, that such term does not include the Interconnection Customer, the Interconnection Provider, or any Affiliate thereof.

Initial Synchronization Date -- The date upon which the Generating Facility is initially synchronized and upon which Trial Operation begins.

In-Service Date -- The date upon which the Interconnection Customer reasonably expects it will be ready to begin use of the Distribution Provider's Interconnection Facilities to obtain back feed power.

Interconnection Customer – Any entity, including the Distribution Provider, the Distribution Owner, the Transmission Owner or any of the affiliates or subsidiaries of either, that proposes to interconnect its Small Generating Facility with the Distribution Provider's Distribution System.

Interconnection Customer's Interconnection Facilities – All facilities and equipment, as identified in the GIA, that are located between the Generating Facility and the Point of Change of Ownership, including any modification, addition, or upgrades to such facilities and equipment necessary to physically and electrically interconnect the Generating Facility to the Distribution Provider's Distribution System.

Interconnection Customer's Interconnection Facilities are sole use facilities.

Interconnection Facilities – The Distribution Provider's Interconnection Facilities and the Interconnection Customer's Interconnection Facilities. Collectively, Interconnection Facilities include all facilities and equipment between the Small Generating Facility and the Point of Interconnection, including any modification, additions or upgrades that are necessary to physically and electrically interconnect the Small Generating Facility to the Distribution Provider's Distribution System. Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades or Network Upgrades.

Interconnection Financial Security -- The financial instrument(s) submitted by the Interconnection Customer to the Distribution Provider prior to the start of any Construction Activities as a security for the Distribution Provider against the estimated costs of the Construction Activities described in the Generator Interconnection Agreement. The Interconnection Customer may post the Interconnection Financial Security using any of the financial instruments listed in the WDT GIP.

Interconnection Handbook - A handbook, developed by the Distribution Provider and posted on the Distribution Provider’s website or otherwise made available by the Distribution Provider, describing the technical and operational requirements for wholesale generators and loads connected to the Distribution System, as such handbook may be modified or superseded from time to time. In the event of a conflict between the terms of this SGIA and the terms of the Distribution Provider’s Interconnection Handbook, the terms in this SGIA shall govern.

Interconnection Request – The Interconnection Customer's request, in accordance with the Tariff, to interconnect a new Small Generating Facility, or to increase the capacity of, or make a Material Modification to the operating characteristics of, an existing Small Generating Facility that is interconnected with the Distribution Provider’s Distribution System.

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Interconnection Service -- The service provided by the Distribution Provider associated with interconnecting the Interconnection Customer's Generating Facility to the Distribution Provider's Distribution System and enabling it to receive electric energy and capacity from the Generating Facility at the Point of Interconnection, pursuant to the terms of the GIA and, if applicable, the Distribution Provider's Tariff.

IRS -- The Internal Revenue Service.

ISO -- The California Independent System Operator Corporation, a state chartered, nonprofit, corporation that controls certain transmission facilities of all Participating Transmission Owners and dispatches certain generating units and loads. See also CAISO.

ISO Grid -- The system of transmission lines and associated facilities of the Participating Transmission Owners that have been placed under the ISO’s Operational Control.

ISO’s Generator Interconnection and Deliverability Allocation Procedures (ISO Tariff GIDAP) -- The procedures included in the ISO Tariff to interconnect a Generating Facility directly to the ISO Grid, as such procedures may be modified from time to time, and accepted by the Commission. See also GIDAP.

ISO’s Generator Interconnection Procedures (ISO Tariff GIP) -- The procedures included in the ISO Tariff to interconnect a Generating Facility directly to the ISO Grid, as such procedures may be modified from time to time, and accepted by the Commission. See also GIP.

Large Generating Facility -- A Generating Facility having a Generating Facility Capacity of more than 20 MW.

Local Deliverability Constraint -- A transmission system operating limit modeled in the GIDAP study process that would be exceeded if the CAISO were to assign Full Capacity Deliverability Status or Partial Capacity Deliverability Status to one or more additional Generating Facilities interconnecting to the CAISO Controlled Grid in a specific local area, and that is not an Area Deliverability Constraint.

Local Delivery Network Upgrade (LDNU) -- A transmission upgrade or addition identified by the CAISO in the GIDAP Interconnection Study Process to relieve a Local Deliverability Constraint.

Loss -- Any and all losses relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the other Party's performance, or non-performance of its obligations under the GIA on behalf of the indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the indemnifying Party.

Material Modification – A modification that has a material impact on the cost or timing of any Interconnection Request, or any other valid interconnection request to the Distribution Provider or the ISO with a later queue priority date.

Metering Equipment -- All metering equipment installed or to be installed at the Generating Facility pursuant to the GIA at the metering points, including but not limited to instrument transformers, MWh-meters, data acquisition equipment, transducers, remote terminal unit, communications equipment, phone lines, and fiber optics.

NERC -- The North American Electric Reliability Council or its successor organization.

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Network Upgrades – Additions, modifications, and upgrades to the Distribution Provider's Transmission System required at or beyond the point at which the Distribution System connects to the Distribution Provider’s Transmission System to accommodate the interconnection of the Small Generating Facility to the Distribution Provider’s Distribution System. Network Upgrades do not include Distribution Upgrades.

See also: Area Delivery Network Upgrades; Delivery Network Upgrades; Local Delivery Network Upgrades; and Reliability Network Upgrades.

Notice of Dispute -- A written notice of a dispute or claim that arises out of or in connection with the GIA or its performance.

Operating Requirements – Any operating and technical requirements that may be applicable due to Regional Transmission Organization, California Independent System Operator, control area, or the Distribution Provider's requirements, including those set forth in the Small Generator Interconnection Agreement.

Participating Transmission Owner -- An entity which (i) owns, operates, and maintains transmission lines and associated facilities and/or has entitlements to use certain transmission lines and associated facilities; and (ii) has transferred to the ISO operational control of such facilities and/or entitlements to be made part of the ISO Grid.

Party or Parties – The Distribution Provider, Distribution Owner, Transmission Owner, Interconnection Customer or any combination of the above.

Point of Change of Ownership -- The point set forth in the GIA where the Interconnection Customer's Interconnection Facilities connect to the Distribution Provider’s Interconnection Facilities.

Point of Interconnection – The point set forth in the GIA where the Interconnection Facilities connect with the Distribution Provider's Distribution System.

Pre-Construction Activities -- The actions by the Distribution Provider, other than those required by an Engineering and Procurement Agreement under Section 8 of the GIP, undertaken prior to Construction Activities in order to prepare for the construction of the Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades assigned to the Interconnection Customer, including, but not limited to, preliminary engineering, permitting activities, environmental analysis, or other activities specifically needed to obtain governmental approvals for the Distribution Provider’s Interconnection Facilities, Distribution Upgrades, or Network Upgrades.

Qualifying Capacity -- The maximum Resource Adequacy Capacity that a Resource Adequacy Resource may be eligible to provide. The criteria and methodology for calculating the Qualifying Capacity of resources may be established by the CPUC or other applicable Local Regulatory Authority and provided to the CAISO. A resource’s eligibility to provide Resource Adequacy Capacity may be reduced below its Qualifying Capacity through the CAISO’s assessment of Net Qualifying Capacity.

Queue Position – The order of a valid Interconnection Request, relative to all other pending valid Interconnection Requests, that is established based upon the date and time of receipt of the valid Interconnection Request by the Distribution Provider and is represented by a unique identifying code assigned to each Interconnection Request that is deemed complete.

Reasonable Efforts – With respect to an action required to be attempted or taken by a Party under the Small Generator Interconnection Agreement, efforts that are timely and consistent with Good Utility Practice and are otherwise substantially equivalent to those a Party would use to protect its own interests.

Reliability Network Upgrades -- The transmission facilities at or beyond the point where the Distribution Provider’s Distribution System interconnects to the ISO Grid, necessary to interconnect one or more Generating Facility(ies) safely and reliably to the ISO Grid, which would not have been necessary but for WDT GIP (2017) SGIA 32
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the interconnection of one or more Generating Facility(ies), including Network Upgrades necessary to remedy short circuit or stability problems, or thermal overloads. Reliability Network Upgrades shall only be deemed necessary for thermal overloads, occurring under any system condition, where such thermal overloads cannot be adequately mitigated through the ISO’s congestion management, operating procedures, or special protection systems based on the characteristics of the Generating Facilities included in the Interconnection Studies, limitations on market models, systems, or information, or other factors specifically identified in the Interconnection Studies. Reliability Network Upgrades also include, consistent with the Applicable Reliability Council’s practice and Applicable Reliability Standards, the facilities necessary to mitigate any adverse impact the Generating Facility’s interconnection may have on a path’s Applicable Reliability Council rating.

Resource Adequacy (RA) -- A mandatory planning and procurement process to ensure adequate resources to serve all customers in real time. The program requires that Load Serving Entities (LSEs) meet a Planning Reserve Margin for their obligations. The program provides deliverability criteria that each LSE must meet, as well as system and local capacity requirements. Rules are provided for "counting" resources towards meeting resource adequacy obligations. The resources that are counted for RA purposes must make themselves available to the California ISO for the capacity for which they were counted. The ISO's Interim Reliability Requirements Program and the resource adequacy under MRTU tariff provisions are intended to complement the State of California's efforts to implement resource adequacy programs.

Site Control -- Documentation reasonably demonstrating: (1) ownership of, a leasehold interest in, or a right to develop a site for the purpose of constructing the Generating Facility; (2) an option to purchase or acquire a leasehold site for such purpose; or (3) an exclusivity or other business relationship between Interconnection Customer and the entity having the right to sell, lease or grant Interconnection Customer the right to possess or occupy a site for such purpose (see also: Site Exclusivity).

Site Exclusivity -- The third option to prove Site Control and applies only in instances when the Interconnection Customer has a business (private) or government agency (public) relationship with the project site’s deed holder.
(1) For private land, Site Exclusivity shall mean documentation reasonably demonstrating legal authorization from the land owner showing the Interconnection Customer has either (a) Ownership of, a leasehold interest in, or a right to develop property upon which the Generating Facility will be located consisting of a minimum of 50% of the acreage reasonably necessary to accommodate the Generating Facility; or (b) an option to purchase or acquire a leasehold interest in property upon which the Generating Facility will be located consisting of a minimum of 50% of the acreage reasonably necessary to accommodate the Generating Facility. (2) For public land, including that controlled or managed by any federal, state or local agency, Site Exclusivity shall mean documentation from the governing public agency providing a final, non-appealable permit, license, or other exclusive legal right to use the property for the purpose of generating electric power and in acreage reasonably necessary to accommodate the Generating Facility. Such documentation showing exclusive right to use public land under the management of a Local, State, or Federal agency shall be in a form specified by that agency.

Smart Inverter —A Generating Facility’s inverter that performs functions that when activated can autonomously contribute to grid support during excursions from normal operating voltage and frequency system conditions by providing dynamic reactive/real power support, voltage and frequency ride-through, ramp rate controls, communication systems with ability to accept external commands and other functions.

Small Generating Facility – An Interconnection Customer's device for the production and/or storage for later injection of electricity identified in the Interconnection Request, but shall not include the Interconnection Customer's Interconnection Facilities, that has a generating capacity of 20 megawatts (MW) or less.

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Stand Alone Network Upgrades -- Network Upgrades that an Interconnection Customer may construct without affecting day-to-day operations of the Transmission System during their construction. Both the Distribution Provider and the Interconnection Customer must agree as to what constitutes Stand Alone Network Upgrades and identify them in an Appendix to the GIA.

System Protection Facilities -- The equipment, including necessary protection signal communications equipment, required to protect (1) the Distribution Provider's Distribution System, the ISO Controlled Grid, and Affected Systems from faults or other electrical disturbances occurring at the Generating Facility and (2) the Generating Facility from faults or other electrical system disturbances occurring on the Distribution Provider's Distribution System, the ISO Controlled Grid or on other delivery systems or other generating systems to which the Distribution Provider's Distribution System and Transmission System is directly connected.

Tariff – The Distribution Provider’s Wholesale Distribution Tariff through which open access distribution service and Interconnection Service are offered, as filed with the FERC, and as amended or supplemented from time to time, or any successor tariff.

Transmission System – Those facilities owned by the Distribution Provider that have been placed under the ISO’s operational control and are part of the ISO Grid.

Trial Operation -- The period during which Interconnection Customer is engaged in on-site test operations and commissioning of the Generating Facility prior to Commercial Operation. Also known as Permission to Parallel for Test Purposes.

Uncontrollable Force -- Any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm, flood, earthquake, explosion, breakage or accident to machinery or equipment, any curtailment, order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or any other cause beyond the reasonable control of the Distribution Provider or Interconnection Customer which could not be avoided through the exercise of Good Utility Practice. An Uncontrollable Force event does not include acts of negligence or intentional wrongdoing by the Party claiming Uncontrollable Force.

Upgrades – The required additions and modifications to the Distribution Provider's Distribution System, at or beyond the Point of Interconnection. Upgrades may be Network Upgrades or Distribution Upgrades.

Upgrades do not include Interconnection Facilities.

Wholesale Distribution Tariff Generator Interconnection Procedures (WDT GIP) – The procedures included in the Distribution Provider’s Wholesale Distribution Tariff (WDT) to interconnect a Generating Facility directly to the Distribution Provider’s Distribution System, as such procedures may be modified from time to time, and accepted by the Commission.

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Attachment 2
Description and Costs of the Small Generating Facility, Interconnection Facilities and Metering Equipment
Central Coast Community Energy, an Interconnection Customer (IC), has requested a Generating Facility (GF) interconnection for Roy Wilson Yard (Project) to the Pacific Gas and Electric Company (PG&E)’s distribution system for a 4,500 kW BESS generating facility to be located at 202 Grimmer Road, WATSONVILLE SANTA CRUZ CA 95076. The Generating Facility will be connected to PG&E’s Green Valley 2104 distribution circuit. Interconnection will be in accordance with FERC’s Generator Interconnection Procedures. The requested operating date for the Project is 30 April 2024. This Project has been assigned the reference number of 3266-WD.

Equipment, including the Small Generating Facility, Interconnection Facilities, and metering equipment shall be itemized and identified as being owned by the Interconnection Customer, the Distribution Provider, Distribution Owner or the Transmission Owner. The Distribution Provider will provide a best estimate itemized cost, including overheads, of its Interconnection Facilities and metering equipment, and a best estimate itemized cost of the annual operation and maintenance expenses associated with its Interconnection Facilities and metering equipment.

Actual costs incurred by the Interconnection Customer to install these Interconnection Facilities will be trued up with the Interconnection Customer once this project has achieved commercial operation, per Article 6.1 of this agreement. The Interconnection Customer will be responsible for payment of all actual costs incurred to install these facilities, and any additional facilities identified as necessary during the engineering, design, or construction phases. Should additional facilities be deemed necessary for the interconnection of this facility, Distribution Provider will identify these additional facilities as soon as possible in the construction phase, and will coordinate with the Interconnection Customer on the additional costs and timing needed to implement them. As needed, the costs of ownership for these Interconnection Facilities also will be updated once this project has achieved commercial operation.

Project Information
Project Name: Roy Wilson Yard
Number of Generators: 6 BESS
Manufacturer Model Name & Number: SolBank S1K5650A01
Number of Inverters: 3
Manufacturer Model Name & Number: CPS-1500 Gen4 [600V]
Total Output: 4736.84 kVA (4,500kW @ 0.95 power factor) Transformer Data: 4400 kVA @ Z = 5.75% 21kV / 600V Delta / Wye-Grounded
PG&E Grid Voltage at Interconnection: 21 kV
Substation / Feeder Green Valley Bank 3 115 kV / 21.6 kV Green Valley 2104
Primary Line Configuration at POI 3-phase, 4-wire distribution circuit Description of Operation Wholesale Export to Green Valley 2104 WDT GIP (2017) SGIA 35
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Interconnection Facilities
The estimated costs associated with the Interconnection Facilities required to interconnect the project to Distribution Provider’s Distribution System.

Interconnection Facilities (Subject to Cost-of-Ownership) Costs Pre-energization test, protection review and testing witnessing $10,000 PG&E Primary Revenue Metering $15,000
Primary Service-OH (Per location not including Metering) $15,000 PG&E SCADA Recloser at POI $80,000
Total -- Interconnection Facility Costs (Subject to Cost-of-Ownership) $ 120,000 ITCC Tax1 TBD
1 Not subject to ITCC (Income Tax Calculation Component) on contribution. ITCC is exempt for wholesale generators that meet the IRS Safe Harbor Provisions. PG&E currently does not require the Interconnection Customer to provide security to cover the potential tax liability on the Interconnection Facilities, Distribution Upgrades, and Network Upgrades per the IRS Safe Harbor Provisions (IRS Notice 88-129). PG&E reserves the right to require, on a nondiscriminatory basis, the Interconnection Customer to provide such security, in a form reasonably acceptable to PG&E as indicated in Article 11 of the SGIA, an amount up to the cost consequences of any current tax liability. Upon request and within sixty (60) Calendar Days’ notice, the Interconnection Customer shall provide PG&E such ITCC security or ITCC payment in the event that Safe Harbor Provisions have not been met, in the form requested by PG&E.

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Attachment 3
One-line Diagram Depicting the Small Generating Facility, Interconnection Facilities, Metering Equipment, and Upgrades
Figure 3-1 One-Line Conceptual Diagram of Project Name
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Figure 3-2 Vicinity Map of Project Name
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Attachment 4
Milestones
In-Service Date: Month xx, 20xx
Critical milestones and responsibility as agreed to by the Parties:

Milestone Date Responsible Party
1 Financial Security Posting Due Date January 26, 2024 Interconnection Customer 2 Submit electronic initial design package
(including but not limited to equipment list,
70% final SLD, site map and site plan)
Month xx, 20xx Interconnection Customer
3 On-site project kick-off meeting Month xx, 20xx Distribution Provider & Interconnection Customer
4 Completion of the Interconnection Facilities,
Distribution Upgrades, and Network Upgrade
facilities
Month xx, 20xx Distribution Provider &
Interconnection Customer
5 In-Service Date (back-feed power) Month xx, 20xx Distribution Provider & Interconnection Customer
6 Pre-parallel Inspection and Testing Month xx, 20xx Distribution Provider & Interconnection Customer
7 Initial Synchronization Month xx, 20xx Interconnection Customer 8 Provide written approval to Interconnection
Customer for the operation of the facilities
(PTO) and Commercial Operation Date
(COD)
Month xx, 20xx Distribution Provider
9 Completion of Reliability and Deliverability
Network Upgrades (RNU, DNU) identified in
Attachment 5 as part of implementing FCDS
Month xx, 20xx OR
N/A Distribution Provider
Note 1 – Ability to Meet Milestone Dates
The ability to meet these Milestone dates requires that all tasks, including tasks preceding the milestones listed above, to be completed in a timely fashion and does not account for unanticipated delays, including but not limited to delays caused by: emergency response due to wildfires or storms; time to complete environmental studies; availability of needed resources (e.g., materials or crews); difficulties securing necessary permits, easements, right of ways, licenses or other approvals; construction additional information needed to complete the project implementation process; or delays scheduling clearances to complete the interconnection of this project to the PG&E system.

Note 2 -- Supplemental Billing and Payment Provisions:

In accordance with Article 6.3 of this project’s SGIA, the financial security posting(s) must be completed by the Interconnection Customer before the Distribution Provider may begin any capital work. The Interconnection Customer may negotiate a milestone date to post the financial security(-ies) up to 180 Calendar Days (CD) after the execution of this SGIA. This negotiated date is shown in the milestones table above. If the financial security posting(s) is/are not completed by the date shown in the table above, a notice of default will be issued to the Interconnection Customer in accordance with Article 7.6 of this SGIA.

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Note 3 -- Billing Procedures for Actual Costs:

Per Section 6.1.1 of this project’s SGIA, PG&E will bill the Interconnection Customer on a monthly basis for actual labor and/or material costs incurred during the prior month.

Agreed to by:

For the Distribution Provider Date:

For the Interconnection Customer Date:

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Attachment 5
Additional Operating Requirements for the Distribution Provider's Distribution System, Transmission System and Affected Systems Needed to Support the Interconnection Customer's Needs

5.1 General Operating Requirements
The Distribution Provider shall also provide requirements that must be met by the Interconnection Customer prior to initiating parallel operation with the Distribution Provider's Distribution System.

At a minimum, the Interconnection Customer agrees to construct and interconnect the facility described in this agreement with the PG&E system in accordance with the standards and requirements described in the PG&E Transmission Interconnection Handbook (TIH) and the Distribution Interconnection Handbook (DIH), as well as any specific operating requirements identified and described in the final interconnection study completed by the Distribution Provider for this facility.

5.2 Deliverability Status
The Interconnection Customer has elected for this Small Generating Facility to have Energy Only Deliverability Status, as defined in the CAISO Tariff. As a result, this Small Generating Facility was studied for Energy Only Deliverability Status by the Distribution Provider, and the results of those studies have been incorporated into this SGIA. The Interconnection Customer and the Distribution Provider acknowledge and understand that this Small Generating Facility will have Energy Only Deliverability Status.

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Attachment 6
Distribution Provider's Description of its Upgrades
and Best Estimate of Upgrade Costs
The Distribution Provider shall describe Upgrades and provide an itemized best estimate of the cost, including overheads, of the Upgrades and annual operation and maintenance expenses associated with such Upgrades. The Distribution Provider shall functionalize Upgrade costs and annual expenses as either transmission or distribution related.

Actual costs incurred by the Interconnection Customer to install these Distribution Upgrades and Network Upgrades will be trued up with the Interconnection Customer once this project has achieved commercial operation, per Article 6.1 of this agreement. The Interconnection Customer will be responsible for payment of all actual costs incurred to install these facilities, and any additional facilities identified as necessary during the engineering, design, or construction phases. Should additional upgrades be deemed necessary for the interconnection of this facility, Distribution Provider will identify these additional upgrades as soon as possible in the construction phase, and will coordinate with the Interconnection Customer on the additional costs and timing needed to implement them. As needed, the costs of ownership for these Interconnection Facilities also will be updated once this project has achieved commercial operation.