On the agenda: Glendora Board of Directors Meeting Agenda 09-17-26 — data center (Sep 17)

Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

NOTICE OF REGULAR MEETING
Board of Directors
NOTICE IS HEREBY GIVEN by the undersigned, as the Executive Director of the Southern California
Public Power Authority, that a regular meeting of the Board of Directors is to be held as follows:

Thursday, September 17, 2026
10:00 AM
Southern California Public Power Authority
1160 Nicole Court
Glendora, CA 91740

Any writings or documents provided to the Board of Directors
regarding any item on this agenda subsequent to distribution of the
agenda packet will be made available for public inspection at
SCPPA’s Office set forth above, during normal business hours.
Members of the public may participate in the meeting in person or via
teleconferencing and may also view any documents made available
during the meeting, using the following information:
Call
Call-In Number: 888-788-0099
Meeting ID: 923 7238 1802
Passcode: 914368

Meeting
Zoom: Join Meeting
Meeting Materials: Access Here

SCPPA, upon request, will provide reasonable accommodation to the disabled to ensure equal access
to its meetings. To ensure availability, such request should be made 72 hours in advance of the Meeting
by contacting the Authority at (626) 793-9364 or [email protected] during business hours.
The following matters are the business to be transacted and considered by the Board of Directors:
1. NOTICE / AGENDA AND OPPORTUNITY FOR THE PUBLIC TO ADDRESS THE BOARD
Members of the public may address the Board at this time on any item on today’s agenda or any
other item that is within the subject matter jurisdiction of the Board. Comments from members
of the public shall be limited to three (3) minutes unless additional time is approved by the Board.
Any member of the Board may request that items on the agenda be taken out of order, or that
items be added to the agenda pursuant to the provisions of Section 54954.2(b) of the California
Government Code.
BOARD AGENDA COVER
Page 1 of 3

Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

2. EXECUTIVE DIRECTOR REPORT
The Executive Director will report on the activities of the Authority since the last Board Meeting.
3. CONSENT CALENDAR
All matters listed under the Consent Calendar are considered to be routine and will all be enacted
by one motion. There will be no separate discussion of these items prior to the time the Board
votes on the motion, unless one or more Board members, staff, or a member of the public
requests that specific items be discussed and/or removed for separate discussion or action.
A. Minutes of the Board of Directors Meeting
o Regular Meeting Minutes: August 20, 2026
B. Receive and File:
1. Finance Committee Meeting Minutes: August 3, 2026
2. Monthly Investment Report: July 2026
3. SCPPA A&G Budget Comparison Report: July 2026
4. Quarterly Renewables Report
5. Working Group Update: September 2026
6. Magnolia Power Project Operations Report: August 2026
7. Palo Verde Nuclear Generating Station Status Report: July 2026
8. Federal Legislative Report: August 2026
C. Resolution 2026-095
Approve Amendment No. 5 to Master Professional Services Agreement for Energy Efficiency
Audits and Direct Installation Services with Eagle Systems International, Inc. DBA Synergy
Companies, to Extend the Term of the Agreement to January 21, 2027
4. CHIEF FINANCIAL & ADMINISTRATIVE OFFICER
A. Resolution 2026-096
Authorizing Preparation of All Documents Necessary or Appropriate to Sell and Issue
Renewable Energy Prepayment Bonds, Proceeds of which will be used to Finance
Prepayments for the Purchase of Supplies of Renewable Energy for the Benefit of the City
of Pasadena; and Authorizing Related Actions
B. Presentation Regarding SCPPA Training Program
5. ASSET MANAGEMENT REPORT
A. Resolution 2026-097
Authorizing Execution of a WSPP Confirmation Agreement with Tenaska Power Services,
Co. for the Sale of Certain Environmental Attributes Associated with Geothermal Projects
Located in the State of Nevada
6. PROGRAM DEVELOPMENT REPORT
A. Resolution 2026-098
Award and Authorize Execution of a Master Professional Services Agreement to The
Cadmus Group LLC for Consulting Services Related to Energy Efficiency and Demand
Response Programs and Electric Utility Fleet Electrification; Providing for Additional
Contributions to the Authority’s Revolving General Fund, and Authorizing Certain Related
Action

BOARD AGENDA COVER
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Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

7. GOVERNMENT AFFAIRS REPORT
The Director of Government Affairs will report on regional, state, and/or federal legislative and
regulatory activities affecting Southern California public power utilities, including climate
change, air quality, wildfire mitigation, renewable energy and traditional energy resources,
transportation and building electrification, alternative energy supplies, resource planning,
market and utility operations, and joint powers agreements.
A. State Legislative Update Including Wildfire Reform and Other End of Session Actions
B. August California Energy Commission Tour Recap

8. BOARD MEMBER COMMENTS
A. Opportunity for Board Members to bring up informational items or request that an
item be added to a future Board Agenda.

9. ADJOURNMENT

Daniel E Garcia
Executive Director
Southern California Public Power Authority

BOARD AGENDA COVER
Page 3 of 3

MINUTES OF THE REGULAR MEETING OF THE BOARD OF DIRECTORS
OF THE SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

A regular meeting of the Board of Directors was held on August 20, 2026, at Southern California
Public Power Authority, 1160 Nicole Court, Glendora, CA 91740.
The meeting was called to order at 10:00 AM by the Board President, Mandip Samra. Daniel E
Garcia, Executive Director, went through the emergency safety protocols for the in-person meeting
participants. Ms. Samra went through the web conference protocol. Salpi Ortiz took attendance.
The following Board Members
(B) or Alternates (A) were
present:

Anaheim: Brian Beelner (B)
Azusa: Tikan Singh (B)
Banning: Fred Lyn (B)
Burbank: Mandip Samra (B)
Cerritos: Sergio Huizar (A)
Colton: Thomas Miller (B)
IID: Sabrina Barber (A)
Glendale: Scott Mellon (B)
LADWP: Ashkan Nassiri (A)
Pasadena: David Reyes (B), Kelly Nguyen (A)
Riverside: Scott Lesch (A)
Vernon: Todd Dusenberry (B)

1. NOTICE/AGENDA AND OPPORTUNITY FOR THE PUBLIC TO ADDRESS THE BOARD
Ms. Samra noted that the meeting was noticed and posted as required under the Brown Act.
He invited public comment on any items on the agenda. There were no public comments.
2. EXECUTIVE DIRECTOR REPORT
Mr. Garcia announced that registration is now open for the two-day Annual Conference. He
noted that Salpi Ortiz sent an email to the Board with information to assist with the registration
process. Early registration is encouraged to support conference planning efforts. The goal is to
have 300 attendees.
3. CONSENT CALENDAR
A. Minutes of the Board of Directors Meeting
o Regular Meeting Minutes: July 16, 2026
B. Receive and File:
1. Finance Committee Meeting Minutes: July 13, 2026
2. Monthly Investment Report: June 2026
MINUTES OF THE BOARD OF DIRECTORS

Meeting Date: 08-20-2026

Page 1 of 6

3. Quarterly Investment Report: June 2026
4. SCPPA A&G Budget Comparison Report: Preliminary June 2026
5. Working Group Update: July 2026
6. Magnolia Power Project Operations Report: July 2026
7. Palo Verde Nuclear Generating Station Status Report: June 2026
8. Federal Legislative Report: July 2026
C. Resolution 2026-091
Providing Authorization to Executive Director to Execute Agreements to Implement Southern
California Public Power Authority’s Annual Conferences and Authorizing Certain Related
Action
Moved by: Tom Miller, Colton Electric Utility
Seconded: Ashkan Nassiri, Los Angeles Department of Water & Power
Ms. Ortiz took a Roll Call vote:
Yes
Anaheim

X

Azusa

X

Banning

X

Burbank

X

Cerritos

X

Colton

X

Glendale

X

IID

X

LADWP

X

Pasadena

X

Riverside

X

Vernon

X

No

Present, Not
Voting

Absent

Kelly Nguyen, Alternate, voted for Pasadena Water & Power on this item.
4. ASSET MANAGEMENT REPORT
A. Resolution 2026-092
Amendment No. 1 to Tieton Hydropower Project Budget

MINUTES OF THE BOARD OF DIRECTORS

Meeting Date: 08-20-2026

Page 2 of 6

Charles Guss, Senior Asset Manager, presented Resolution 2026-092 to the Board for
consideration and approval.
Moved by: Mandip Samra, Burbank Water & Power
Seconded: Sabrina Barber, Imperial Irrigation District
Ms. Ortiz took a Roll Call vote:
Yes
Anaheim

X

Azusa

X

Banning

X

Burbank

X

Cerritos

X

Colton

X

Glendale

X

IID

X

LADWP

X

Pasadena

X

Riverside

X

Vernon

X

No

Present, Not
Voting

Absent

Kelly Nguyen, Alternate, voted for Pasadena Water & Power on this item. David Reyes, Board
Member for Pasadena Water & Power, arrived after this item and voted on remainder of
Agenda items on behalf of Pasadena.
B. Resolution 2026-093
Authorizing a Pseudo-Tie Arrangement Relating to the Authority’s share of the Arizona Nuclear
Power Project Generation through a Dynamic Transfer Balancing Authority Operating
Agreement between Arizona Public Service Company and the City of Los Angeles by and
through the Los Angeles Department of Water & Power; Authorizing Certain Related Action;
Finding Such Action Exempt from California Environmental Quality Act.
Mr. Guss presented Resolution 2026-093 to the Board for consideration and approval and
responded to questions from the Board.
Moved by: Ashkan Nassiri, Los Angeles Department of Water & Power
MINUTES OF THE BOARD OF DIRECTORS

Meeting Date: 08-20-2026

Page 3 of 6

Seconded: Margie Otto, Vernon Public Utilities
Ms. Ortiz took a Roll Call vote:
Yes
Anaheim

X

Azusa

X

Banning

X

No

Burbank

Present, Not
Voting

Absent

Abstained

Cerritos

X

Colton

X

Glendale

X

IID

X

LADWP

X

Pasadena

X

Riverside

X

Vernon

X

5. PROGRAM DEVELOPMENT REPORT
A. Resolution 2026-094
Authorizing the Executive Director to Execute Amendment No. 2 to the Master Goods and
Services Agreement with Resource Innovations, Inc. for Energy Efficiency-Related Services and
Products and Authorizing Certain Related Action
Brandon Czworniak, Senior Utility Analyst presented Resolution 2026-094 to the Board for
consideration and approval.
Moved by: Tikan Singh, Azusa Light & Water
Seconded: Mandip Samra, Burbank Water & Power
Ms. Ortiz took a Roll Call vote:
Yes
Anaheim

No

Present, Not
Voting

Absent

X

MINUTES OF THE BOARD OF DIRECTORS

Meeting Date: 08-20-2026

Page 4 of 6

Azusa

X

Banning

X

Burbank

X

Cerritos

X

Colton

X

Glendale

X

IID

X

LADWP

X

Pasadena

X

Riverside

X

Vernon

X

David Reyes, Board Member, Pasadena Water & Power voted on this item.
6. PROJECT DEVELOPMENT REPORT
A. Project Development Update Regarding Requests for Proposals for Renewable
Energy and Storage Projects
John Quan, Principal Utility Analyst, presented an update on Request for Proposals for
Renewable Energy and Storage Projects. Mr. Quan answered questions from the Board of
Directors.
7. GOVERNMENT AFFAIRS REPORT
A. State Regulatory Update Including Advanced Clean Fleets
Elisabeth de Jong, Government Affairs Manager, provided a state regulatory update on
Advanced Clean Fleets and responded to comments from the Board.
B. State Legislative Update Including Wildfire Reform and Other End of Session Actions
Natalie Seitzman presented a State Legislative Update including Wildfire Reform and other
End of Session Actions, including a balcony solar bill, and responded to questions and
comments from the Board.
C. Federal Update Including Nuclear Waste Policy
Mario De Bernardo, Government Affairs Director, presented a federal issues update
including Nuclear Waste Policy.
D. SCPPA Advocacy Events, Including the 2026 SCPPA Policy Staff Tour Recap and
August California Energy Commission Tour
Mr. De Bernardo provided an update on SCPPA advocacy events, including the 2026
Policy Staff Tour and the August California Energy Commission Tour. Mr. De Bernardo
MINUTES OF THE BOARD OF DIRECTORS

Meeting Date: 08-20-2026

Page 5 of 6

thanked the Board for its support of the Policy Staff Tour and noted that the tour was a
success. He shared positive feedback from participating staff members, who commended
SCPPA for providing an informative and educational experience. Mr. De Bernardo also
reminded the Board of the upcoming California Energy Commission Tour scheduled for
August 27.
7. BOARD MEMBER COMMENTS
A. Opportunity for Board Members to bring up informational items or request that an
item be added to a future Board Agenda.
Ms. Samra, Board President shared that on September 8th and 9th the Department of
Energy will be visiting Burbank and invited SCPPA members to join. Ms. Samra also
offered to serve as an extra utility stakeholder for SCPPA members, if desired, as part of
their Integrated Resource Planning processes. Margie Otto, Alternate, Vernon Public
Utilities, commended the SCPPA team for a very productive Policy Tour.
8. ADJOURNMENT
The meeting was adjourned at 11:31 a.m.
Respectfully Submitted,
___________________
Daniel E Garcia
Executive Director

MINUTES OF THE BOARD OF DIRECTORS

Meeting Date: 08-20-2026

Page 6 of 6

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
1160 NICOLE COURT
GLENDORA, CA 91740
(626) 793-9364 – FAX: (626) 793-9461
WWW.SCPPA.ORG

MINUTES OF THE REGULAR MEETING OF THE FINANCE COMMITTEE OF
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
The meeting of the Finance Committee was held on August 3, 2026, at the SCPPA Glendora office and by
teleconference from Imperial Irrigation District. The meeting commenced at 10:30 A.M. and adjourned at 11:00 A.M.
Mr. Lillio (Committee Chair) took attendance. Committee members/Alternate Committee members
present for the Finance Committee Meeting were: Daniel Smith (Azusa); Jim Steffens (Banning); Joseph
Lillio (Burbank); Kinda Salloum (Colton); Adrine Isayan (Glendale); Belen Valenzuela (IID-Teleconference);
John Equina (LADWP); Lynne Chaimowitz (Pasadena); and Brian Seinturier (Riverside).
Others attendees were: Victor Hsu (Norton Rose Fulbright); Mike Berwanger, Louise Houghton and Jim
Carbone (PFM Financial Advisors-Teleconference); Grace Mao and Francisco Olivares-Ortiz
(LADWP/SCPPA-LA); Houbert Yousef and Leriza Flores (LADWP/SCPPA-LA-Teleconference); Daniel
Garcia, Aileen Ma, Charles Guss, Christine Godinez and Anna Mendoza (SCPPA); Arsineh Aghasian, Brian
Leung and Luis Castaneda (SCPPA-Teleconference); Herman Leung (Pasadena-Teleconference); Claudia
Huerta (Riverside-Teleconference).
1. Opportunity for the Public to Address the Committee
Mr. Lillio invited any members of the public to provide comments. No public comments were made.
2. Consent Calendar
Mr. Lillio presented the Consent Calendar to the Committee for consideration. The Committee
recommended forwarding the following reports to the Board of Directors (Board) for receipt and filing.
A. Minutes of the July 13, 2026 Finance Committee meeting
Moved By:
Seconded By:

Lynne Chaimowitz
Jim Steffens

Page 1 of 4

The following roll call vote was taken:
Yes
Anaheim
Azusa
Banning
Burbank
Colton
Glendale
IID
LADWP
Pasadena
Riverside
Vernon

No

Present,
Not Voting

Absent
X

X
X
X
X
X
X
X
X
X
X

3. Investment Reports
Grace Mao, LADWP/SCPPA-LA Manager of Finance, presented the Monthly and Quarterly Investment
Reports for the period ended June 30, 2026, to the Committee for review and consideration. The
Committee recommended forwarding the reports to the Board for receipt and filing.
Moved By:
Seconded By:

Lynne Chaimowitz
Adrine Isayan
The following roll call vote was taken:
Yes
Anaheim
Azusa
Banning
Burbank
Colton
Glendale
IID
LADWP
Pasadena
Riverside
Vernon

No

Present,
Not Voting

Absent
X

X
X
X
X
X
X
X
X
X
X

Page 2 of 4

4. Administrative & General Expense Budget Comparison Report
Anna Mendoza, SCPPA Senior Utility Analyst, presented the preliminary A&G Budget Comparison
Report for the fiscal year ended June 30, 2026, to the Committee for review and consideration. The
Committee recommended forwarding the report to the Board for receipt and filing.
Moved By:
Seconded By:

Daniel Smith
Brian Seinturier
The following roll call vote was taken:
Yes
Anaheim
Azusa
Banning
Burbank
Colton
Glendale
IID
LADWP
Pasadena
Riverside
Vernon

No

Present,
Not Voting

Absent
X

X
X
X
X
X
X
X
X
X
X

5. Tieton Hydropower Project Fiscal Year 2026-27 Budget Revision
Charles Guss, SCPPA Senior Asset Manager, presented the revised project budget for the Tieton
Hydropower Project for fiscal year 2026-27 to the Committee for review and consideration. The
Committee recommended forwarding the project budget to the Board for approval. Project Vote with
Burbank and Glendale as the project participants.
Moved By:
Seconded By:

Adrine Isayan
Joseph Lillio
The following roll call vote was taken:
Yes
Anaheim
Azusa
Banning
Burbank

No

Present,
Not Voting

X
X
X

Page 3 of 4

Absent
X

Colton
Glendale
IID
LADWP
Pasadena
Riverside
Vernon

X
X
X
X
X
X
X

6. Mead-Adelanto Project Right-of-Way Fee
Mr. Guss provided the Committee with information regarding an increase in the Right-of-Way (ROW) fee
assessed by the Bureau of Land Management (BLM) for the Mead-Adelanto Project and responded to
questions from the Committee.
7. Geothermal and/other Renewable Energy Prepayment
Ms. Ma provided the Committee with an update on the proposed financing of the new geothermal and/or
other renewable energy prepayment on behalf of LADWP. The transaction documents are continued to
be worked on by the financing team.
8. Market and Variable Rate Demand Obligation (VRDO) Update
Mike Berwanger, PFM, provided the Committee with a market update and VRDO status report.
9. Unsolicited Proposals
Mr. Berwanger provided a brief summary of the unsolicited proposals received.
10. Committee Member and Staff Comments
Mr. Lillio opened the item for comments and announced that, in observance of the Labor Day holiday on
September 7, 2026, there will be no Committee meeting on that day. The Committee supported
rescheduling the next meeting to Monday, September 14, 2026. Ms. Ma informed the Committee of the
upcoming SCPPA Annual Conference scheduled for on October 21-22, 2026.
_____________________________________________________________________

THE NEXT FINANCE COMMITTEE MEETING
WILL BE SEPTEMBER 14, 2026.

Page 4 of 4

ANAHEIM • AZUSA • BANNING • BURBANK • CERRITOS • COLTON • GLENDALE • IID• LOS ANGELES • PASADENA • RIVERSIDE • VERNON

Southern California Public Power Authority
1160 Nicole Court
Glendora, CA 91740
(626) 793-9364
August 31, 2026
Mr. Daniel E Garcia
Executive Director
Southern California Public Power Authority
1160 Nicole Court
Glendora, California 91740
Dear Mr. Garcia:
Enclosed is the July 2026 Investment Report for the Palo Verde, Southern Transmission System (STS),
Southern Transmission System Renewal, San Juan, Magnolia Power, Natural Gas, Natural Gas Prepaid, MeadAdelanto, Mead-Phoenix, Don A. Campbell/Wild Rose Geothermal, Don A. Campbell 2 Geothermal, Canyon
Power, Pebble Springs Wind, Tieton Hydropower, Linden Wind, Clean Energy, Clean Energy II, Milford Wind
I, Milford Wind II, Windy Point/Flats, Ameresco, Apex Power, Copper Mountain Solar 3, Columbia 2 Solar,
Eland 1, Eland 2, Heber 1 Geothermal, Ormat No. Nevada Geothermal, Ormesa Geothermal, Springbok 1 Solar,
Springbok 2 Solar, Springbok 3 Solar, Kingbird Solar, Summer Solar, Astoria 2 Solar, Antelope Big Sky Ranch,
Antelope DSR 1, Antelope DSR 2, Puente Hills Landfill Gas, Whitegrass No. 1 Geothermal, Star Peak
Geothermal, Desert Harvest II, Roseburg Biomass, Red Cloud Wind, Coso Geothermal, Mammoth Casa Diablo
IV, and Daggett Solar Power 2 Projects; and for the Project Stabilization, San Juan Mine Reclamation Trust, San
Juan Decommissioning Trust, and the SCPPA Decommissioning Trust Funds. The Portfolios for the Projects
and Funds included in the Investment Report are in compliance with the SCPPA Investment Policy.
During the month of July, the Investment Group coordinated variable debt service payments of $397,613 for the
Magnolia Power, Linden Wind and Canyon Power Projects. Net swap payments of $266,138 were received in
accordance with the Interest Swap agreements for Canyon Power, Magnolia Power, and Natural Gas Prepaid
Projects. The net commodity swap receipt for the Natural Gas Prepaid Project was $1,468,635. On July 1,
principal payments of $120.2 million and fixed interest payments of $63.8 million were made on various bond
issues for Southern Transmission System, Magnolia, Mead-Adelanto, Mead-Phoenix, Natural Gas, Canyon
Power, Tieton Hydropower, Windy Point/Flats, Milford Wind I, Milford Wind II, Southern Transmission
System Renewal and Apex Power Projects.
$166.3 million cash and maturities were invested in the various SCPPA project trust funds. Assets managed by
the Investment Group for these funds had a market value of $1.89 billion as of July 31, 2026, with an average
yield of 3.8%. Total interest earned on the project funds for the month and year to date was $7.3 million.
Based upon anticipated expenditures for each Project and required receipts from each Participant, SCPPA
believes that it will be able to meet all its expenditure requirements for the next six months.
Sincerely,

GRACE MAO
Manager of Finance
Los Angeles Department of Water & Power

The Members of Southern California Public Power Authority work together to power sustainable communities.

Monthly Investment Report
July 31, 2026
Projects

Portfolio Yield Investment Cost Carrying Value

Market Value

Portfolio Life2 Cost of Capital3

Palo Verde

4.02%

22,843,029

22,844,200

22,537,966

2.08

N/A

San Juan

3.52%

454,100

454,100

454,100

0.00

N/A

Magnolia

3.83%

58,768,361

58,968,425

58,784,337

0.35

2.97%

STS

3.76%

9,217,241

9,217,241

9,171,406

1.08

4.70%

STS Renewal

3.82%

1,026,840,076

1,031,403,954

1,031,248,485

0.33

4.01%

Mead-Phoenix

3.75%

5,399,217

5,410,760

5,383,795

0.04

2.53%

Mead-Adelanto

3.69%

3,833,276

3,838,355

3,824,878

0.04

2.53%

Natural Gas
1
Natural Gas Prepaid

3.84%

49,044,306

49,057,509

48,406,982

1.12

6.06%

4.67%

26,060,775

26,060,775

26,017,675

8.12

5.09%

Canyon Power

2.76%

11,587,437

11,629,991

11,629,210

0.03

2.74%

Apex Power

3.91%

35,928,718

35,994,424

35,687,369

2.15

4.32%

SCPPA Decomm Trust Fund

3.42%

208,284,934

208,378,875

205,458,314

1.77

N/A

Project Stabilization Fund

3.87%

181,513,131

181,592,745

178,957,810

1.79

N/A

Tieton
Clean Energy1

3.97%

3,221,827

3,221,827

3,185,455

2.77

2.67%

4.74%

27,947,951

27,947,951

27,947,951

3.64

N/A

4.59%

47,704,256

47,704,256

47,704,256

2.15

N/A

Linden Wind

4.09%

21,691,582

21,702,911

21,456,391

3.47

3.15%

Milford Wind 1

3.64%

4,582,254

4,594,352

4,594,269

0.05

5.08%

Milford Wind 2

3.56%

3,345,332

3,347,306

3,347,265

0.01

1.05%

Windy Point Flats

3.66%

13,388,914

13,427,770

13,428,915

0.02

3.55%

Pwr Purchase Agreements Combined

3.43%

119,572,997

119,915,065

119,908,088

0.10

N/A

San Juan Reclaim Trust Fund

3.27%

12,910,609

12,914,339

12,814,811

1.62

N/A

San Juan Decomm Trust Fund

4.14%

535,892

535,892

527,162

4.11

N/A

Clean Energy II1

1

Weighted average remaining portfolio life for NG Prepaid and Clean Energy Projects include Guaranteed Investment Contracts (GICs).
In years
3
Cost of capital as of January 31, 2024 as provided by PFM.
2

U.S. Treasury

Tenor
1M
2M
3M
6M
1Y
2Y
3Y
5Y

I25 Ask YTM US
Treasury Actives
Curve 07/31/26
3.669
3.743
3.753
3.942
4.033
4.291
4.352
4.449

I25 Ask YTM US
Treasury Actives
Curve 07/31/25
4.355
4.357
4.337
4.268
4.092
3.957
3.900
3.972

I25 Ask YTM
(Change) 07/31/2607/31/25
(68.60)
(61.40)
(58.40)
(32.60)
(5.90)
33.40
45.20
47.70

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
1160 NICOLE COURT
GLENDORA, CA 91740
(626) 793-9364 – FAX: (626) 793-9461

MEMO

WWW.SCPPA.ORG

To:

SCPPA Finance Committee

From: Aileen Ma, Chief Financial & Administrative Officer
Date:

September 14, 2026

Re:

FY 2026-27 Administrative & General (A&G) Expense Budget to Actual Comparison Report – July 2026

As of July 31, 2026, total A&G expenditures were $1,042,038 which was $173,092 or 14.2% under the year-to-date
budget.
Total Indirect A&G expenditures were $697,246, which was $134,276 or 16.1.% under budget. The under budget was
primarily due to the timing of expenditures and invoices from vendors and consultants. The under budget was partially
offset by slightly higher salaries due to the timing of the biweekly payroll schedule, creating a three-paycheck month for
July. It is anticipated that salaries will trend back toward budget in the next few months. In addition, SCPPA elected to
prepay the entire annual required contribution of $220,790 for CalPERS Miscellaneous Plans' Unfunded Accrued
Liability in July, saving $7,383 in interest for FY 2026-27.
Total Direct A&G expenditures were $344,792, which was $38,816 or 10.1% under budget. The under budget was
primarily due to the timing of expenditures for legal and consulting services. The under budget was partially offset by
higher trustee fees because of the timing of invoices paid for annual trustee fees on various project fund accounts. Agent
billable costs were also over budget primarily due to overtime costs incurred during year-end closing and the preparation
of the year-end financial statements. It is anticipated that trustee fees will trend back toward budget as the fiscal year
progresses and agent billable costs will trend back toward budget after the year-end audit is completed.

Southern California Public Power Authority
FY 2026-27 Adminstrative & General (A&G) Expense Budget to Actual
July 31, 2026

ANNUAL
BUDGET
FY 2026-2027

YTD
BUDGET
7/31/2026

YTD
ACTUAL
7/31/2026

Under /
(Over)
Budget

%
Variance

Salaries
Employee Benefits
Office Building Costs
Office IT and Equipment/Furniture
Office Expenses
Insurance
Meeting Expense
Travel and Conferences
Staff Training/Development
Memberships and Dues
Subscriptions
Gov't Affairs (Sacramento Office)
Legislative Advocacy
Regulatory Advocacy
General Legal Services
Auditing Services
Consulting & Other Services
Financial Advisor
Glendora Project Accounting - Direct A&G

$

3,424,400
1,137,600
245,050
156,700
54,540
181,690
44,300
79,000
62,000
29,790
19,995
237,960
406,000
220,000
150,000
5,075
187,000
129,000
(58,560)

$

368,270 $
298,775
16,256
18,494
4,321
4,451
3,688
6,576
5,163
333
1,669
19,819
30,913
18,337
12,500
500
15,587
10,750
(4,880)

378,505 $
243,086
7,042
15,447
1,413
2,733
276
135
6,532
29,418
17,500
850
(5,691)

(10,235)
55,689
9,214
3,047
2,908
1,718
3,412
6,441
5,163
333
1,669
13,287
1,495
837
12,500
500
14,737
10,750
811

-2.8%
18.6%
56.7%
16.5%
67.3%
38.6%
92.5%
97.9%
100.0%
100.0%
100.0%
67.0%
4.8%
4.6%
100.0%
100.0%
94.5%
100.0%
-16.6%

Subtotal

$

6,711,540

$

831,522 $

697,246 $

134,276

16.1%

-

-

-

0.0%

Budget Contingency

169,250

TOTAL INDIRECT A&G

$

6,880,790

$

831,522 $

697,246 $

134,276

16.1%

Outside Counsels
Auditing Services
Consulting & Other Services
Project Travel Costs
WREGIS Fees
Agent Billable Costs
Trustee Fees
Rating Agency Fees
Glendora Project Accounting

$

445,200
380,985
271,600
8,500
16,705
3,182,350
320,300
170,000
58,560

$

37,100 $
20,000
22,637
712
1,393
265,195
26,692
5,000
4,880

8,560 $
3,571
287,000
39,971
5,691

28,540
20,000
19,067
712
1,393
(21,805)
(13,279)
5,000
(811)

76.9%
100.0%
84.2%
100.0%
100.0%
-8.2%
-49.8%
100.0%
-16.6%

TOTAL DIRECT A&G

$

4,854,200

$

383,609 $

344,792 $

38,816

10.1%

TOTAL A&G EXPENSES

$

11,734,990

$

173,092

14.2%

1,215,131

$

1,042,038

$

Renewable Project Q2
Performance Report
Prepared by:
Brian Leung, Nicholas Nolasco,
Luis Castaneda & Liam Reilly
August 18, 2026

For The Period Beginning
April 2026 - June 2026

Table of Contents

Page

2
Hydro Tieton ……………………………………………………..
Landfill Gas Chiquita Canyon…...…………………………3
Puente Hills…………………………………….......
4
5
Geothermal Casa Diablo IV…........................................
Coso….......................................... 6
Heber-I………………………………………………
7
Don A. Campbell I …………………………….
8
Don A. Campbell II …………………………….
9
NNGP……………………………………………………
10
Ormesa…...........................................11
Star Peak…………………………........
12
Whitegrass No. 1….................................
13
14
Wind Pebble Springs…………………………………….
Windy Flats……………………………………….
15
Linden……………………………………………….
16
Milford I ……………………………………………
17
Milford II……………………………………………
18
Red Cloud…...................................... 19
20
Solar Antelope Big Sky Ranch………………………….
Antelope DSR I & II………………………........
21
Astoria 2………………………………………........
22
Columbia Two…………………………………….
23
Copper Mountain 3………………………………..
24
Daggett Solar 2…........................
25
Desert Harvest II…..................................
26
Eland I ….....................................
27
Eland II …..................................... 28
Kingbird B………………………………………......
29
Springbok I-III……………………………………………………..
30-32
Summer………………………………………………………………
33
Biomass Roseburg…........................................34

TIETON SMALL HYDRO
Location: 40 miles west of Yakima, WA
Type: Hydro
Acquisition: 30-Nov-09
Capacity (MWs): 13.6
Term: Permanent Ownership
Participants:
%
MWs
Burbank
50%
6.8
Glendale
50%
6.8
100%
13.6
Operations Notes:
April 2026: Tieton Hydropower Project generated 5,526 MWh in April, bringing year-to-date generation to
14,526 MWh. Production was affected by changing river flow requirements and a Unit-2 trip early in the
month, though operational adjustments and corrective actions minimized long-term impacts to generation.
May 2026: The project generated 6,446 MWh, increasing year-to-date generation to 20,898 MWh. Operations
were driven by river flow management requirements and transmission scheduling constraints, including
periods where generation was limited to 14 MW, resulting in some available flow being diverted away from
generation.
June 2026: Tieton generated 3,429 MWh, bringing cumulative 2026 generation to 24,233 MWh. Reduced
water flows limited generation opportunities during much of the month, while maintenance associated with
turbine guide bearing contamination required Unit-2 to be taken offline at the end of June for repairs.
YTD NCF closed at 41%.

Generation (MWhs)

YTD Capacity Factor

10,000

50%

8,000

40%

6,000

30%

4,000

20%

2,000

10%

0

0%

2024

2025

2026

2024

-2-

2025

2026

8/18/2026

CHIQUITA CANYON
Location: Valencia, CA
Type: Landfill Gas
COD: 1-Nov-10
Capacity (MWs): 7.8
(net)
Term: 20 years
Participants:
%
MWs
Burbank
17%
1.3
Pasadena
83%
6.5
100%
7.8
Operations Notes:
SCPPA received a Force Majeure notice from Ameresco, the project operator, on February 22, 2024. In the
notice, the shutdown was attributed to a subsurface chemical reaction within the existing landfill. This
reaction has reduced the availability of methane, increased water vapor in the landfill gas, and altered the
composition of sulfur compounds—from hydrogen sulfide to dimethyl sulfide. The facility is not designed to
treat or remove dimethyl sulfide; consequently, this compound passes through the system and is emitted
into the atmosphere, resulting in non-compliance with the facility’s current air permit.
Based on discussions among SCPPA, the Project Participants, and Ameresco, PPA payments for FY 2025–2026
have been reduced to zero. As a result of the shutdown and the Force Majeure event, generation has been
significantly impacted.
During the second period, state agencies overseeing Waste Connections’ response to the reaction
determined that the affected area has doubled or tripled in size. This expansion has rendered the current
containment strategy ineffective, necessitating immediate action to prevent further growth of the reaction
and to mitigate risks to the environment and public health and safety.

Generation (MWhs)

YTD Capacity Factor

2,500

40%

2,000

30%

1,500

20%

1,000
500

10%

0

0%
2024

2025

2026

2024

-3-

2025

2026

8/18/2026

PUENTE HILLS
Location: City of Industry, CA
Type: Landfill Gas
COD: 1-Jan-17
(start of SCPPA deliveries)
Capacity (MWs): 41.5
Term: 10 years
Participants:
%
MWs
Banning 23.2558%
9.65
Colton 23.2558%
9.65
Pasadena 30.2326%
12.55
Vernon 23.2558%
9.65
100%
41.5
Operations Notes:
April 2026: PERG completed a planned maintenance outage on April 28 that resulted in 33 hours of
downtime. During the outage, the facility attempted a DCS software upgrade, completed repairs to critical
valves and actuators, performed boiler feedwater control valve replacements, and conducted maintenance
on the continuous emissions monitoring system before returning the plant to service.
May 2026: PERG operated reliably during May following the April maintenance activities. Upgraded and
repaired control equipment remained in service, contributing to stable operations and supporting the plant's
strong quarterly availability performance.
June 2026: PERG continued stable operations through June, helping the facility achieve 98.1% availability for
the second quarter with an average net output of 16,039 kW. Total downtime for the quarter was limited to
42 hours, demonstrating strong overall plant performance and reliability.

Generation (MWhs)

YTD Capacity Factor

15,000

50%
40%

10,000

30%

5,000

20%

0

0%

10%

2024

2025

2026

2024

-4-

2025

2026

8/18/2026

CASA DIABLO IV
Location: Mono County, CA
Type: Geothermal
COD: 14-Jul-22
Capacity (MWs): 16
Term: 25 years
Participants:
%
MWs
Colton 100%
16
100%
16
Operations Notes:
Casa Diablo IV is a 30 MW net capacity
geothermal facility located in Mono County,
California. SCPPA, on behalf of the City of
Colton, entered into a 25-year Power
Purchase Agreement for a 16 MW share of
the facility.
April 2026: Casa Diablo IV generated 15,740 MWh, finishing 26% below forecast despite maintaining 97%
availability. Production was reduced by NDAMP/CAISO negative market pricing and ADS DOT restrictions, resulting
in partial generation throughout the month.
May 2026: The plant produced 15,206 MWh, or 15% below forecast, while maintaining 100% availability.
Generation continued to be constrained by NDAMP/CAISO negative market pricing and ADS DOT restrictions,
although overall plant operations remained stable.
June 2026: Casa Diablo IV generated 8,707 MWh, finishing 47% below forecast with availability declining to 89%.
Continued market-related restrictions and reduced operating levels significantly impacted production during the
month.
Casa Diablo IV has curtailed generation due elevated CAISO locational marginal prices (LMPs) have made it
untenable to dispatch energy to the grid, hence the drop in NCF for the year 2026.
YTD NCF at the facility closed at 65%, a 32% dip from the same period in 2025.

YTD Capacity Factor

Generation (MWhs)
120%

14,000
12,000
10,000
8,000
6,000
4,000
2,000
0

100%
80%
60%
40%
20%
0%

2024

2025

2024

2026

-5-

2025

2026

8/18/2026

COSO
Location: Inyo County, CA
Type: Geothermal
DCD 1-Jan-22
Capacity (MWs): 17.8
Term: 20 years
Participants:
%
MWs
Banning
45%
8.01
Riverside
55%
9.79
Pasadena
0%
0.00
100%
17.8
Operations Notes:
April 2026: Coso generated 66,681 MWh in April with 88.3% availability and a 74.9% capacity factor.
Production was impacted by planned outages and turbine overhauls at Navy 1 and BLM East, along with SCE
and CAISO transmission curtailments that affected operations for portions of four days during the month.
May 2026: The facility generated 78,008 MWh, achieving 98.7% availability and an 84.8% capacity factor.
Performance remained strong, with only a brief outage of Navy 1 Unit 3 at the end of the month due to a
main oil pump issue.
June 2026: Coso generated 73,714 MWh in June with 98.3% availability and an 82.8% capacity factor.
Production was slightly reduced by a four-day outage of Navy 1 Unit 3 related to a main oil pump issue, but
overall plant performance remained strong throughout the month.
YTD NCF at the facility closed at 86%, a 1% increase from the same period in 2025.

Generation (MWhs)

YTD Capacity Factor

15,000

150%

10,000

100%

5,000

50%

0

0%

2024

2025

2026

2024

-6-

2025

2026

8/18/2026

HEBER-1
Location: Heber, CA
Type: Geothermal
COD: 2-Feb-16 (SCPPA deliveries began)
Capacity (MWs): 62.5
Term: 10 years
Participants:
%
MWs
IID
22%
13.75
LADWP
78%
48.75
100%
62.5
Operations Notes:
April 2026: Heber 1 generated 33,776 MWh, slightly
exceeding forecast by 1% while maintaining 99%
availability. Plant operations remained stable, although
HGU 252 was offline throughout the month due to a
casing leak.
May 2026: The plant produced 32,446 MWh, finishing 3% below forecast with 100% availability. Generation
was reduced by ongoing issues with HGU 252 and a failure of VFD capacitors on HGU 10.
June 2026: Heber 1 generated 28,573 MWh, approximately 1% below forecast, while maintaining 99%
availability. Production was impacted by the continued outage of HGU 252 and a production pump replacement
on HGU 16, though overall plant operations remained stable.
Year-to-date net capacity factor (NCF) was 62%, representing a 10% decrease compared to performance during
the same period last year.

Generation (MWhs)

YTD Capacity Factor

50,000
40,000
30,000
20,000
10,000
0

100%
80%
60%
40%
20%
0%

2024

2025

2026

2024

-7-

2025

2026

8/18/2026

DON A. CAMPBELL 1
Location: Mineral County, NV
Type: Geothermal
COD: 1-Jan-14
Capacity (MWs): 25
Term: 20 years
Participants:
%
MWs
Burbank
15%
3.8
LADWP
85%
21.2
100%
25
Operations Notes:
April 2026: Don A. Campbell 1 generated 9,508 MWh, finishing just 1% below forecast with 98.4% availability.
The facility operated under normal conditions and delivered stable performance throughout the month.
May 2026: The plant produced 8,369 MWh, approximately 1% below forecast, while maintaining 99.6%
availability. Aside from a brief four-hour NERC maintenance outage, operations remained stable during the
month.
June 2026: Don A. Campbell 1 generated 6,495 MWh, exceeding forecast by 2% and maintaining 99%
availability. Despite an offline production well, the facility continued to operate reliably and achieved stable
monthly performance.
Year-to-date net capacity factor (NCF) closed at 53%, representing a 4% decrease compared to the same
period in 2025.
Generation (MWhs)

YTD Capacity Factor

15,000

80%
60%

10,000

40%

5,000

20%

0

0%

2024

2025

2026

2024

-8-

2025

2026

8/18/2026

DON A. CAMPBELL 2
Location: Mineral County, NV
Type: Geothermal
COD: 17-Sep-15
Capacity (MWs): 25
Term: 20 years
Participants:
%
MWs
LADWP
100%
25
100%
25
Operations Notes:
April 2026: Don A. Campbell 2 generated 8,529
MWh, slightly exceeding forecast by 1% while
maintaining 100% availability. Overall plant
performance was stable with no significant
operational impacts during the month.
May 2026: The plant produced 4,639 MWh, essentially in line with forecast, but availability declined to 66% due to
a planned outage for a generator swap and silencer replacements. The maintenance work was completed by
month end and the plant returned to service on May 31.
June 2026: Don A. Campbell 2 generated 4,659 MWh, finishing 8% below forecast with 97% availability. Production
was impacted by several short-duration outages related to a speed sensor failure, transmission line constraints,
and lube oil system maintenance, though overall plant performance remained stable.
YTD NCF at the facility closed at 43%, a 8% dip from the same period in 2025.

Generation (MWhs)

YTD Capacity Factor

15,000

80%

10,000

60%
40%

5,000

20%

0

0%

2024

2025

2026

2024

-9-

2025

2026

8/18/2026

Northern Nevada
Geothermal Portfolio
Location: Churchill & Washoe County, NV
Type: Geothermal
COD: 1-Dec-17
Capacity (MWs)*: 168.65
Term: 25 years
Participants:
%
MWs
LADWP 100%
168.65
100%
168.65
Operations Notes:
Brady: Brady generated 21,428 MWh in Q2 and maintained 99-100% availability. Production was below forecast in April and
May due to equipment failures but rebounded to 10% above forecast in June, resulting in stable overall performance.
Galena 2: Galena 2 generated 9,157 MWh and underperformed forecast throughout the quarter. Strong availability was offset
by recurring solar tracking issues and several outage events that continued to limit production.
McGinness Hills 3: McGinness Hills 3 delivered a strong quarter, generating 125,416 MWh and outperforming forecast in all
three months. Availability remained near 100%, and the project ended June 5% above year-to-date forecast generation.
Steamboat Hills Repower: Steamboat Hills Repower generated 58,809 MWh and performed largely in line with expectations.
Availability remained above 99%, with only minor equipment issues affecting production during the quarter.
Steamboat 2/3: Steamboat 2/3 produced 36,413 MWh during Q2, outperforming forecast in April and May before finishing
below forecast in June. Solar tracking and inverter issues reduced output, though availability remained strong throughout the
quarter.
Tungsten Mountain: Tungsten Mountain generated 67,710 MWh while maintaining approximately 100% availability. Inverterrelated issues contributed to below-forecast production during the quarter, though overall plant performance remained
stable.

YTD Capacity Factor

Generation (MWhs)
150,000

150%

100,000

100%

50,000

50%

0

0%

2024

2025

2026

2024

2025

* Capacity increases with each development period. Max capacity is capped at 185 MW.
-10-

2026

8/18/2026

ORMESA
Location: Imperial County, CA
Type: Geothermal
COD: 1-Jan-18
Capacity (MWs): 35
Term: 25 years
Participants:
%
MWs
IID
14%
5
LADWP
86%
30
100%
35
Operations Notes:
April 2026: Ormesa generated 25,074 MWh in
April, finishing 8% below forecast with a 48.4%
net capacity factor. Despite several planned
maintenance activities and short-duration
equipment outages, the facility maintained 100%
turbine and commercial availability throughout
the month.
May 2026: The plant produced 25,104 MWh, which was 6% below forecast, while maintaining 100% turbine
and commercial availability. Generation was impacted by a PLC communication fault at Ormesa 1 and a
complex-wide outage caused by a fire under a transmission line.
June 2026: Ormesa generated 23,019 MWh, finishing 3% below forecast and achieving a 44.4% net capacity
factor. The facility continued to maintain 100% turbine and commercial availability, with only minor wellrelated outages affecting overall production.
YTD NCF is 96%, a 3% increase compared to the same period last year in 2025.

Generation (MWhs)

YTD Capacity Factor

30,000

150%

20,000

100%

10,000

50%

0

0%

2024

2025

2026

2024

-11-

2025

2026

8/18/2026

STAR PEAK
Location: Pershing County, NV
Type: Geothermal
COD: 28-Sep-22
Capacity (MWs): 12.5
Term: 25 years
Participants:
%
MWs
Glendale
100%
12.5
100%
12.5
Operations Notes:
Star Peak is a 12.5 MW geothermal power
plant located in Pershing County, Nevada.
The facility reached commercial operation
status on September 28th, 2022.
April 2026: Star Peak generated 2,613 MWh, achieving 49.3% of guaranteed production. Plant availability
remained strong at 99.6%, but generation was significantly impacted by a lightning-related outage,
maintenance on R1, extended downtime on R3, and continued steam resource limitations that kept S1 offline.
May 2026: The plant produced 2,967 MWh, improving to 57.0% of guaranteed production. Plant availability
reached 100%, and unit availability across the ORC units remained near perfect, with production primarily
constrained by ongoing wellfield and steam resource limitations rather than equipment availability.
June 2026: Star Peak generated 2,484 MWh, achieving 53.8% of guaranteed production while maintaining
100% plant availability. Minor maintenance activities and weather-related unit trips had limited impact on
operations, with overall performance continuing to be constrained by resource limitations and the continued
unavailability of the steam unit.
YTD NCF is 34%, representing a 10% decrease from the same period last year in 2025.

Generation (MWhs)

YTD Capacity Factor

5,000

60%

4,000

50%
40%

3,000

30%

2,000

20%

1,000

10%

0

0%

2024

2025

2026

2024

-12-

2025

2026
8/18/2026

WHITEGRASS No. 1
Location: Lyon County, NV
Type: Geothermal
COD: 1-Apr-20
Capacity (MWs): 3
Term: 25 years
Participants:
%
MWs
Glendale 100%
3
100%
3
Operations Notes:
April 2026: Whitegrass generated 1,433 MWh,
achieving 86.2% of target generation and slightly
below the guaranteed level (99.3% of guarantee).
Plant availability remained strong at 98.9%, and
performance was consistent with expected
operating conditions despite ongoing geothermal
resource temperature and flow rate shortfalls
May 2026: The plant produced 1,321 MWh, reaching 81.6% of target generation while exceeding the
guaranteed level at 100.1% of guarantee. Whitegrass maintained 100% availability during the month, with
performance continuing to be constrained by resource temperature and flow rate limitations.
June 2026: Whitegrass generated 1,077 MWh, achieving 73.3% of target generation and 97.7% of the
guaranteed level. Plant availability remained high at 98.2%, though ongoing resource temperature and flow
rate shortfalls continued to limit overall generation performance.
YTD NCF at the facility closed at 65%, a 3% dip from the same period in 2025.

Generation (MWhs)

YTD Capacity Factor

2,000

100%

1,500

80%
60%

1,000

40%

500

20%

0

0%

2024

2025

2026

2024

-13-

2025

2026

8/18/2026

PEBBLE SPRINGS
Location: Gilliam County, OR
Type: Wind
COD: 31-Jan-09
Capacity (MWs): 98.7
Term: 18 years
Participants:
%
MWs
Burbank
10%
10.0
Glendale
20%
20.0
LADWP
70%
68.7
100%
98.7
Operations Notes:
April generation closed at 20,955 MWh.
May generation closed at 24,753 MWh.
June generation closed at 26,799 MWh.
YTD Production in the second quarter reached 72,508 MWh and YTD NCF closed at 25%, representing a
1% increase from the same period in 2025.
The SCPPA team is currently renegotiating an extension ahead of the agreement’s expiration in February
2027 and will present an amended PPA and PSA to the Board in the coming months.

Generation (MWhs)

YTD Capacity Factor

40,000

40%

30,000

30%

20,000

20%
10%

10,000

0%

0
2024

2025

2026

2024

-14-

2025

2026

8/18/2026

WINDY FLATS
Location: Klickitat County, WA
Type: Wind
COD: 25-Jan-10
Capacity (MWs): 262.2
Term: 20 years
Participants:
%
MWs
LADWP
92%
242.19
Glendale*
8%
20.01
100%
262.2
Operations Notes:
April 2026: Windy Flats generated 63,612 MWh, exceeding the P50 budget by 3% and the P99 budget
by 29%, with a 34% capacity factor. Strong wind conditions and 95.0% runtime availability supported
solid performance, while progress on annual maintenance and lift installations helped maintain
reliable operations.
May 2026: The project produced 80,984 MWh, outperforming the P50 budget by 15% and the P99
budget by 44%, achieving a 42% capacity factor. Above-average wind conditions and 96.6% runtime
availability drove strong generation despite ongoing generator replacements and maintenance
activities.
June 2026: Windy Flats generated 86,615 MWh, exceeding the P50 budget by 16% and the P99
budget by 45%, with a 46% capacity factor, marking the strongest month of the quarter. Strong wind
resource conditions and 96.0% runtime availability supported exceptional production while the site
completed its annual service campaign and several major maintenance projects.
YTD NCF at the facility closed at 31%, a 2% increase from the same period in 2025.

Generation (MWhs)
100,000

40%

80,000

30%

60,000

20%

40,000

YTD Capacity Factor

10%

20,000

0%

0
2024

2025

2026

2024

2025

2026

*Through a separate layoff agreement, the City of Glendale sold 100% of its entitlement to capacity and energy to LADWP.

-15-

8/18/2026

LINDEN
Location: Klickitat County, WA
Type: Wind
COD: 30-Jun-10
Capacity (MWs): 50
Term: Permanent Ownership
Participants:
%
MWs
LADWP
90%
45
Glendale*
10%
5
100%
50
Operations Notes:
April 2026: Linden generated 10,471 MWh during April, exceeding the P99 budget by 21% but finishing 15%
below the P50 budget. Commercial availability remained strong at 96.0%, and production reflected average
wind conditions, while ongoing turbine outages and major component repairs limited the site's ability to
achieve P50 generation levels.
May 2026: The project produced 12,636 MWh, outperforming the P99 budget by 17% but remaining 18% below
the P50 budget. Commercial availability held at 96.0%, and solid wind conditions supported stronger
production, though several long-term turbine outages continued to constrain overall performance.
June 2026: Linden generated 12,208 MWh, exceeding the P99 budget by 21% while finishing 15% below the P50
budget. Wind speeds were above average and commercial availability remained at 95.3%, but ongoing turbine
outages and a BPA curtailment event reduced overall generation despite otherwise favorable resource
conditions.
YTD NCF closed at 27%, a 4% increase from the same period in 2025.

Generation (MWhs)

YTD Capacity Factor

20,000

40%

15,000

30%

10,000

20%

5,000

10%
0%

0
2024

2025

2024

2026

2025

2026

*Through a separate layoff agreement, the City of Glendale sold 100% of its entitlement to capacity and energy to LADWP.

-16-

8/18/2026

MILFORD I
Location: Milford, UT
Type: Wind
COD: 16-Nov-09
Capacity (MWs): 203.5
Term: 20 years
Participants:
%
Burbank
5.00%
LADWP 92.50%
Pasadena
2.50%
100%
Operations Notes:

MWs
10.18
188.24
5.09
203.5

April 2026: Milford 1 generated 21,154 MWh, which was 49.0%
below budget, primarily due to below-budget wind speeds (6.0 m/s
vs. 6.6 m/s budgeted) and prolonged LADWP and Fervo outage
events. Despite the production shortfall, the project maintained
96.0% availability throughout the month.
May 2026: The project produced 30,823 MWh, improving significantly from April but still finishing 21.4% below
budget. Availability declined to 90.8%, while below-budget wind resource conditions and equipment-related losses
continued to impact overall generation.
June 2026: Milford 1 generated 39,204 MWh, its strongest month of the quarter, reducing the production variance
to 9.1% below budget. Strong wind conditions (7.6 m/s versus 6.8 m/s budgeted) and improved turbine availability
(97.4%) drove significantly better performance, although outage-related losses continued to affect production.
YTD NCF at the facility closed at 20%, a 2% decrease when compared to the same period in 2025.

Generation (MWhs)

YTD Capacity Factor

60,000

30%

40,000

20%

20,000

10%

0

0%
2024

2025

2026

2024

-17-

2025

2026

8/18/2026

MILFORD II
Location: Milford, UT
Type: Wind
COD: 2-May-11
Capacity (MWs): 102
Term: 20 years
Participants:
%
MWs
Glendale*
5%
5.1
LADWP
95%
96.9
100%
102
Operations Notes:
April 2026: Milford 2 generated 6,145 MWh, which was
68.9% below budgeted production despite strong turbine
mechanical availability of 99.3%. Performance was
primarily impacted by below-budget wind speeds and
extended LADWP/Fervo-related outage and curtailment
events during the month.
May 2026: The project produced 13,828 MWh, reducing the production shortfall to 25.5% below budget while
maintaining 97.0% turbine availability. Performance improved significantly from April, although lower-thanbudget wind conditions and curtailment events continued to impact generation.
June 2026: Milford 2 generated 18,030 MWh, finishing 12.4% below budget while benefiting from strong wind
resources of 6.8 m/s, well above the budgeted 6.1 m/s. Turbine availability remained solid at 97.2%, and the
project delivered its strongest production month of the quarter despite outage and performance-related
losses.
YTD NCF at the facility closed at 19%, a 5% decrease from the same period in 2025.

25,000

Generation (MWhs)
30%

YTD Capacity Factor

20,000
20%

15,000
10,000

10%

5,000
0%

0
2024

2025

2026

2024

2025

2026

*Through a separate layoff agreement, the City of Glendale sold 100% of its entitlement to capacity and energy
to LADWP.

-18-

8/18/2026

RED CLOUD
Location: Lincoln, Guadalupe, Torrance Counties, NM
Type: Wind
COD: 22-Dec-21
Capacity (MWs): 331
Term: 20 years
Participants:
%
MWs
LADWP
100%
331
100%
331

Operations Notes:
April 2026: Red Cloud generated 131,104 MWh, exceeding budget by 4.0%, driven by stronger-thanexpected wind resource conditions (102.7% of budget). Plant energy availability reached 92.1%, slightly
above budget, enabling the project to outperform production targets despite ongoing turbine
maintenance, curtailments, and transmission outages during the month.
May 2026: The project produced 96,598 MWh, which was 11.0% below budget, primarily due to reduced
turbine availability. Wind resource conditions were near plan at 98.8% of budget, but availability declined
to 82.6% as major component repairs, blade replacements, and turbine maintenance activities significantly
impacted generation.
June 2026: Red Cloud generated 82,244 MWh, remaining below budget as plant availability fell to 70.9%
despite exceptionally strong wind resource conditions (122.4% of budget). Performance was heavily
affected by turbine outages, blade repair campaigns, major component work, and the late-June turbine
collapse event that resulted in a large number of turbines being taken offline pending investigation.
YTD NCF closed at 47%, a 3% increase from the same time last year in 2025.

200,000

Generation (MWhs)

60%

150,000

YTD Capacity Factor

40%

100,000

20%

50,000

0%

0
2024

2025

2024

2026

-19-

2025

2026

8/18/2026

ANTELOPE BIG SKY RANCH
Location: Lancaster, CA
Type: Solar
COD: 19-Aug-16
Capacity (MWs): 20
Term: 25 years
Participants:
%
MWs
Azusa
17.5%
3.5
Pasadena
32.5%
6.5
Riverside
50%
10.0
100%
20
Operations Notes:
April 2026: Antelope Big Sky Ranch generated 4,283 MWh,
finishing 9.1% below expected production, while maintaining
97.1% availability. Performance was impacted by belowaverage resource conditions (87.4% resource index) and
additional site underperformance losses during the month.
May 2026: The project produced 4,930 MWh, which was 23.6% below expected production despite aboveaverage resource conditions (104.7% resource index). Availability declined to 89.5%, and outage-related and
performance losses significantly reduced monthly generation.
June 2026: Antelope Big Sky Ranch generated 4,971 MWh, finishing 25.6% below expected production while
benefiting from strong resource conditions (106.1% resource index). Although availability improved to 98.0%,
performance losses continued to materially impact overall production.
YTD NCF at the facility closed at 27%, a 4% dip from the same period in 2025.

Generation (MWhs)

YTD Capacity Factor

8,000

40%

6,000

30%

4,000

20%

2,000

10%

0

0%
2024

2025

2026

2024

-20-

2025

2026

8/18/2026

ANTELOPE DSR 1 & 2
Location: Lancaster, CA
Type: Solar
COD: 20-Dec-2016 & 6-Dec-2016
Capacity (MWs): 55
(50 MWs DSR1 & 5 MWs DSR2)
Term: 20 years
Participants:
%
MWs
Riverside 45.5%
25
Vernon 45.5%
25
Azusa
9.1%
5
100%
55
Operations Notes:
April 2026: Antelope DSR 1 and DSR 2 generated a
combined 13,214 MWh and maintained excellent
availability above 99%. Both projects underperformed
expectations, with production finishing 6.4% below
expected at DSR 1 and 11.6% below expected at DSR 2,
largely due to performance-related losses.
May 2026: The projects produced a combined 15,041 MWh, supported by near-perfect availability. DSR 1
finished only 2.4% below expected production, while DSR 2 was 11.6% below expected, resulting in mixed
overall performance for the month.
June 2026: Antelope DSR 1 and DSR 2 generated a combined 14,537 MWh. Favorable resource conditions were
offset by performance losses, with DSR 1 and DSR 2 finishing 15.9% and 14.1% below expected production,
respectively, while lower availability at DSR 1 further impacted results.
YTD NCF closed at 28%, a 2% decrease from the same period in 2025.

20,000

Combined
Generation (MWhs)

40%

15,000

30%

10,000

20%

5,000

10%

0

0%
2024

2025

Combined
YTD Capacity Factor

2024

2026

-21-

2025

2026

8/18/2026

ASTORIA 2
Location: Kern County, CA
Type: Solar
COD: 9-Dec-16
Capacity (MWs): 45
Term: 20 years
Participants:
%
MWs
Banning
17.78%
8
Colton 15.56%
7
Vernon 66.67%
30
100%
45
Operations Notes:
April 2026: Astoria 2 generated 20,371 MWh in April, which
was 4.7% below expected production, despite solar irradiance
finishing 3.5% above modeled levels. The project achieved
95.0% effective availability and an OPI of 95.3%, indicating
performance was primarily impacted by operational factors
rather than resource conditions.
May 2026: The project produced 23,255 MWh in May, significantly outperforming expectations with
an OPI of 137.7% despite irradiance being 28.5% below modeled conditions. Astoria 2 achieved 96.3%
effective availability, demonstrating exceptionally strong energy production relative to the available
solar resource.
June 2026: Astoria 2 generated 23,817 MWh during June, finishing 4.3% below expected production
while irradiance was 1.1% below modeled levels. The project maintained 94.0% effective availability
and an OPI of 95.7%, with performance remaining relatively close to expectations despite several
outage events during the month.

YTD Capacity Factor

Generation (MWhs)
20,000

40%

15,000

30%

10,000

20%

5,000

10%

0

0%
2024

2025

2024

2026

-22-

2025

2026

8/18/2026

COLUMBIA TWO
Location: Kern County, CA
Type: Solar
COD: 31-Dec-14
Capacity (MWs): 15
Term: 20 years
Participants:
%
MWs
Azusa
9%
1.35
Pasadena
17%
2.55
Riverside
74%
11.10
100%
15
Operations Notes:
April 2026: Columbia II delivered 3,729 MWh during
April, achieving a 34.5% capacity factor and 95.6%
availability. Minor inverter fault events were resolved
quickly, limiting operational impacts and supporting
stable overall performance for the month.
May 2026: The project generated 4,941 MWh in May, with a 44.3% capacity factor and 100%
availability. Strong solar resource conditions and minimal curtailment supported improved production,
while inverter startup trips were resolved through standard recovery procedures.
June 2026: Columbia II produced 4,911 MWh in June, achieving a 45.0% capacity factor and 99.2%
availability. Strong irradiance levels, no curtailment, and rapid resolution of temporary inverter outages
contributed to another month of strong operational performance.
NCF closed at 26%, a 4% decrease from 2025.

YTD Capacity Factor

Generation (MWhs)
40%

6,000

30%

4,000

20%

2,000

10%
0%

0
2024

2025

2026

2024

-23-

2025

2026

8/18/2026

COPPER MOUNTAIN 3
Location: Boulder City, NV
Type: Solar
COD: 9-Apr-15
Capacity (MWs): 250
Term: 20 years
Participants:
%
MWs
Burbank
16%
40
LADWP
84%
210
100%
250
Operations Notes:
Copper Mountain Solar 3 generated 184,786 MWh during the
second quarter, finishing 2% above plan despite solar resource
conditions that were 1% below planned insolation. This
performance highlights the project's ability to exceed production
expectations even under less favorable resource conditions.
The plant remained online throughout the quarter except for limited downtime events and achieved 98.74%
commercial availability, slightly below the planned level of 99.5%. Scheduled and corrective maintenance
activities were completed as needed to support reliable operations, and overall plant performance remained
strong, resulting in generation that exceeded quarterly production targets.
YTD generation was above historical averages by approximately 1435 MWh with YTD NCF closing the period at
29%; equal to last year's period.

YTD Capacity Factor

Generation (MWhs)
80,000

40%

60,000

30%

40,000

20%

20,000

10%

0

0%
2024

2025

2026

2024

-24-

2025

2026

8/18/2026

DAGGETT SOLAR 2
Location: Daggett, CA
Type: Solar
COD: 12-Dec-23
Capacity (MWs): 65
Term: 20 years
Participants:
%
Cerritos
8%
Vernon
92%
100%
Operations Notes:

MWs
5.30
59.70
65

April 2026: Daggett 2b generated 15,657 MWh with strong PV availability of 99.0%. The BESS discharged 3,668
MWh, completed 30 effective cycles, and maintained 97.8% availability, supporting reliable site performance
throughout the month.
May 2026: The project generated 18,418 MWh while achieving 99.5% PV availability. The BESS discharged 3,896
MWh with 99.8% availability and 89.4% round-trip efficiency, contributing to strong overall solar-plus-storage
performance.
June 2026: Daggett 2b produced 19,863 MWh, its highest output of the quarter, while maintaining 99.0% PV
availability. The BESS discharged 3,654 MWh, achieved 99.8% availability, and improved round-trip efficiency to
91.0%, delivering strong and consistent storage performance.
YTD NCF for the period closed at 33%, a 3% dip compared to the same period in 2025.

YTD Capacity Factor

Generation (MWhs)
25,000

40%

20,000

30%

15,000

20%

10,000

10%

5,000

0%

0
2024

2025

2024

2026

-25-

2025

2026

8/18/2026

Desert Harvest II
Location: Riverside County, CA
Type: Solar
COD: 17-Dec-20
Capacity (MWs): 70
Term: 25 years
Participants:
%
MWs
Anaheim 51.43%
36
Burbank 31.43%
22
Vernon 17.14%
12
100%
70
Operations Notes:
April 2026: Desert Harvest II generated 18,842 MWh, exceeding budgeted production by 13.8% despite solar
resource conditions coming in 18.1% below budget. The project achieved a 37.4% net capacity factor,
demonstrating strong operational performance and effective conversion of available solar resource.
May 2026: The project generated 20,906 MWh, essentially matching budget with 0.0% variance, and achieved a
40.1% net capacity factor. Although insolation was 11.9% below budget, Desert Harvest II maintained expected
production levels through strong plant performance.
June 2026: Desert Harvest II continued strong performance through June, maintaining year-to-date generation
of 79,156 MWh, which was 13.2% above budget, while operating without any reported outages. Limited
curtailment of 27 MWh and stable plant operations supported continued outperformance against annual
production targets.
The facility reached a YTD NCF of 34%, which represents a 5% increase from 2025.

30,000

Desert Harvest II
Generation (MWhs)

40%

Desert Harvest II
YTD Capacity Factor

30%

20,000

20%
10,000

10%

0

0%
2024

2025

2024

2026

-26-

2025

2026

8/18/2026

ELAND I SOLAR & STORAGE
Location: Mojave, CA
Type: Solar
COD: 18-Nov-24
Capacity (MWs): 200
Term: 25 years
Participants:
%
Glendale 12.50%
LADWP 87.50%
100%
Operations Notes:

MWs
25
175
200

April 2026: Eland 1 generated 55,486 MWh, which was 14.1%
below modeled production and 93.5% of PVUSA expected
energy. The BESS exported 13,593 MWh and maintained
99.6% availability, providing strong storage performance
May 2026: The project produced 76,730 MWh, exceeding modeled production by 6.2% and achieving
100.8% of PVUSA expected energy. The BESS exported 14,034 MWh with 100% availability, supporting
excellent overall site performance.
June 2026: Eland 1 generated 85,417 MWh, outperforming modeled production by 15.9% and achieving
102.1% of PVUSA expected energy. The BESS exported 14,338 MWh and maintained 100% availability,
contributing to the strongest combined performance month of the quarter.
The facility reached a YTD NCF of 40%, a 3% increase from last year during the same period. MWh
reported for the quarter approximately totaled 225,403 MWh.

YTD Capacity Factor

Generation (MWhs)
100,000

50%

80,000

40%

60,000

30%

40,000

20%

20,000

10%

0

0%
2024

2025

2024

2026

-27-

2025

2026

8/18/2026

ELAND II SOLAR & STORAGE
Location: Mojave, CA
Type: Solar
COD: 31-Jul-25
Capacity (MWs): 200
Term: 25 years
Participants:
%
MWs
LADWP 100.00%
200
5370100% 1.1E+07
Operations Notes:
Eland II Solar & Storage is a 200 MW solar power plant
located in Mojave, California. The facility reached commercial
operation status on July 31st, 2025.
April 2026: Eland 2 solar generation totaled 55,774 MWh, which was 15.3% below modeled production,
while the BESS exported 13,824 MWh and maintained 99.7% availability. Solar performance was impacted
by outages and curtailment events, while the storage system delivered strong reliability and energy
throughput.
May 2026: The solar facility generated 78,671 MWh, exceeding modeled production by 7.8%, while the
BESS exported 15,419 MWh with 100% availability. Strong solar resource conditions and highly reliable
storage operations resulted in excellent overall site performance.
June 2026: Eland 2 produced 86,363 MWh, outperforming modeled production by 17.3%, while the BESS
exported 13,989 MWh and achieved 100% availability. Strong solar production and consistent storage
performance drove the project's best combined performance month of the quarter.
The facility reached a YTD NCF of 40%, MWh reported for the quarter approximately total 215,366 MWh.

Generation (MWhs)

YTD Capacity Factor

100,000

50%

80,000

40%

60,000

30%

40,000

20%

20,000

10%

0

0%
2024

2025

2026

2024

-28-

2025

2026

8/18/2026

KINGBIRD B
Location: Rosamond, CA
Type: Solar
COD: 30-Apr-16
Capacity (MWs): 20
Term: 20 years
Participants:
%
MWs
Azusa
15%
3
Colton
15%
3
Riverside
70%
14
100%
20
Operations Notes:
April 2026: Kingbird B generated 5,641 MWh, exceeding
the energy budget by 4.5%. Higher-than-budgeted solar
resource conditions (+5.3% POA irradiance) and a 97.4%
performance index helped offset minor equipment-related
losses, resulting in strong overall performance.
May 2026: The project produced 6,556 MWh, outperforming the energy budget by 5.6%. Strong solar
resource conditions and 100% technical availability supported solid generation, while performance
remained strong with a 97.3% performance index.
June 2026: Kingbird B generated 6,811 MWh, exceeding budgeted production by 9.6%, making it the
strongest month of the quarter. Above-budget irradiance (+8.2%), a 99.3% performance index, and
99.8% technical availability drove exceptional production results.
YTD NCF at the facility closed at 35%, a 3% increase from the same period in 2025.

Generation (MWhs)

YTD Capacity Factor

8,000

40%

6,000

30%

4,000

20%

2,000

10%

0

0%
2024

2025

2026

2024

-29-

2025

2026

8/18/2026

SPRINGBOK I
Location: Kern County, CA
Type: Solar
COD: 11-Jul-16
Capacity (MWs): 105
Term: 25 years
Participants:
%
MWs
LADWP 100%
105
100%
105
Operations Notes:
Springbok I's YTD NCF finished at 33%, the
same as last years period.
April 2026: Springbok 1 generated 29,490 MWh, exceeding expected production by 3,207 MWh and
guaranteed production by 9,778 MWh. Strong solar resource conditions and 96% availability supported
excellent monthly performance.
May 2026: The plant produced 31,889 MWh, outperforming expected production by 1,542 MWh and
guaranteed production by 9,129 MWh. Despite availability declining to 94%, Springbok 1 continued to
deliver strong generation during the month.
June 2026:Springbok 1 generated 32,531 MWh, exceeding expected production by 1,100 MWh and
guaranteed production by 8,958 MWh. Increased solar irradiance drove the highest monthly
production of the year through June, though availability declined to 92%.

40,000

Springbok I
Generation (MWhs)

40%

30,000

30%

20,000

20%

10,000

10%

0

0%
2024

2025

2026

Springbok I
YTD Capacity Factor

2024

-30-

2025

2026

8/18/2026

SPRINGBOK II
Location: Kern County, CA
Type: Solar
COD: 6-Sep-16
Capacity (MWs): 150
Term: 27 years
Participants:
%
MWs
LADWP 100%
150
100%
150
Operations Notes:
Springbok II YTD NCF finished at 32%, roughly
a 1% dip from same period last year.
April 2026: Springbok 2 generated 41,791 MWh, exceeding expected production by 2,367 MWh and
guaranteed production by 12,223 MWh. Strong solar resource conditions and 100% availability
contributed to one of the site's best-performing months of the year.
May 2026: The plant produced 45,244 MWh, finishing just 277 MWh below expected production while
exceeding the guaranteed level by 11,104 MWh. Performance remained strong with 99% availability
and increased solar irradiance compared to April.
June 2026: Springbok 2 generated 46,396 MWh, exceeding guaranteed production by 11,037 MWh and
falling only 750 MWh below expected production. The project maintained 99% availability and
delivered its highest monthly production of the year through June.

60,000

Springbok II
Generation (MWhs)

40%

Springbok II
YTD Capacity Factor

30%

40,000

20%
20,000

10%

0

0%
2024

2025

2026

2024

-31-

2025

2026

8/18/2026

SPRINGBOK III
Location: Kern County, CA
Type: Solar
COD: 19-Jul-19
Capacity (MWs): 90
Term: 27 years
Participants:
%
MWs
LADWP 100%
90
100%
90
Operations Notes:
April 2026: Springbok 3 generated 24,783 MWh,
exceeding expected production by 794 MWh and
guaranteed production by 6,791 MWh, with strong
availability of 95.6%. The plant delivered one of its
strongest performance months year-to-date,
benefiting from favorable operating conditions.
May 2026: The plant generated 23,974 MWh, falling 3,725 MWh below expected production but remaining
3,200 MWh above the guaranteed level. Lower availability (81.3%) impacted production despite strong solar
resource conditions during the month.
June 2026: Springbok 3 produced 22,042 MWh, exceeding guaranteed production by 526 MWh but
underperforming the expected target. Although solar irradiance reached the highest level of the year to date,
reduced availability (75.1%) constrained overall output.
YTD NCF finished at 29% which represents a 5% decrease from the same period last year.

40,000

Springbok III
Generation (MWhs)

0

30,000

0

20,000

0

10,000

0

0

0
2024

2025

Springbok III
Generation (MWhs)

2024

2026

-32-

2025

2026

8/18/2026

SUMMER
Location: Lancaster, CA
Type: Solar
COD: 25-Jul-16
Capacity (MWs): 20
Term: 25 years
Participants:
%
MWs
Azusa 17.5%
3.5
Pasadena 32.5%
6.5
Riverside 50.0%
10.0
100%
20
Operations Notes:
April 2026: Summer Solar generated 5,365 MWh, which was
3.4% below expected production and 1.3% below budget.
Despite excellent availability (100%) and above-average solar
resource conditions, the project experienced minor
performance losses that reduced output.
May 2026: Summer Solar produced 6,377 MWh, exceeding budget by 3.0% but finishing 4.5% below expected
production. Strong solar resource conditions and 100% availability supported solid overall performance during
the month.
June 2026: Summer Solar generated 6,294 MWh, finishing 0.9% below budget and 8.0% below expected
production. Resource conditions remained favorable and availability was high (99.6%), but performance losses
prevented the project from fully capturing the available solar resource.
The YTD NCF closed at 34%, the same when compared to the same period last year.

Generation (MWhs)

YTD Capacity Factor

8,000

40%

6,000

30%

4,000

20%

2,000

10%

0

0%
2024

2025

2026

2024

-33-

2025

2026

8/18/2026

Roseburg
Location: Weed, CA
Type: Biomass
COD: 16-Feb-21 (start of SCPPA deliveries)
Capacity (MWs): 11
(SCPPA Capacity)
Term: 5 years
Participants:
%
MWs
Anaheim
4%
0.49
IID
8%
0.91
LADWP
49%
5.42
SMUD
23%
2.58
MID
6%
0.61
Riverside
4%
0.49
TID
4%
0.49
100%
11

Operations Notes:
The Roseburg contract expired in February 2026 and was not extended for the remainder of the year, hence no
operation is noted.

Generation (MWhs)

YTD Capacity Factor

6,000

80%
60%

4,000

40%
2,000

20%

0

0%
2024

2025

2026

2024

-34-

2025

2026

8/18/2026

Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

ANAHEIM • AZUSA • BANNING • BURBANK • CERRITOS • COLTON • GLENDALE • IID • LOS ANGELES • PASADENA • RIVERSIDE • VERNON

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
1160 NICOLE COURT
GLENDORA, CA 91740

MEMO

(626) 793-9364
WWW.SCPPA.ORG

TO: SCPPA Board of Directors
FROM: Daniel E Garcia, Executive Director
DATE: September 10, 2026
RE: Working Group Updates

WORKING GROUP SUMMARY
ASSET MANAGEMENT
The next Asset Management Working Group meeting will be held on October 29, 2026. We
plan to hear about Project Development activities and discuss existing Project issues.

ASSISTANT GENERAL MANAGER (AGM)
The next Assistant General Manager Working Group meeting will be held on October 28,
2026. We plan to hear about Legislative and Regulatory updates, Project Development
activities, and discuss existing Project issues.

CUSTOMER PROGRAMS
The Customer Programs Working Group (CPWG) met on August 18, 2026. The meeting
opened with general updates, including an overview of upcoming Program Development
Division's expiring contracts and the current status of the related RFPs.

Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

Brandon Czworniak provided a reminder for Members to submit their votes regarding the
proposed enhancements to the SB 1037 reporting platform.
Brandon also provided a recap of the California Energy Commission’s (CEC) July 15th Frontof-the-Meter Distributed Energy Resources (FTM DER) Workshop, highlighting key discussion
topics and takeaways related to the development and deployment of FTM DERs. (SCPPA, in
coordination, with several SCPPA Members, testified at this workshop.)
Renew Home joined the meeting to present on its Energy Shift program, which
incrementally adjusts customer heating and cooling during peak demand periods to help
reduce electricity usage and support grid reliability. The presentation included an overview
of the program and how it can support customer energy management.
The meeting concluded with discussion among Members on the presentations, and industry
and regulatory updates.
The next CPWG meeting will be held on September 15, 2026.

CYBERSECURITY
The Cybersecurity Working Group (CWG) met on August 26, 2026. The Group discussed
challenges and risks in the Cybersecurity space for this year. The CWG will reach out to the
Cybersecurity and Infrastructure Security Agency (CISA) for a future presentation on the
services they offer in the Utility space.
The CWG decided to meet on a quarterly basis. The next CWG meeting is planned for
December 9, 2026.

FINANCIAL INCENTIVES and RATES
The Financial Incentive Programs Working Group (FIPWG) met on August 25, 2026. The
meeting opened with general updates and discussion among members regarding upcoming
industry events and other related activities.

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Palo Alto Utilities joined the meeting to provide a presentation on its recently implemented
Time-of-Use (TOU) rates. The presentation covered Palo Alto’s approach to implementing
the new rates, customer considerations, and lessons learned from the implementation.
Mario De Bernardo provided Government Affairs updates, including the current status of
wildfire liability legislation and other relevant legislative and regulatory developments
affecting publicly owned utilities.
The meeting concluded with discussion among members on the presentation, legislative
and regulatory updates.
The next FIPWG meeting will be held on September 22, 2026.

HYDROGEN & OTHER EMERGING TECHNOLOGIES
This working group meets on an ad hoc basis. No meeting is currently scheduled.

KEY ACCOUNTS
This group meets on an ad hoc basis. No meeting is currently scheduled.

LEGAL
The next Legal Working Group meeting is scheduled for September 24, 2026.

LEGISLATIVE
The Legislative Working Group (LWG) met on August 19th and September 3rd.
The working group discussed matters related to the end of the legislative session including
results of the Appropriations Suspense File and eleventh hour bill negotiations. The LWG

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closely followed and provided input to the development of the Governor’s proposal to
address wildfire liability. SCPPA’s upcoming annual conference was also discussed.
Members of the LWG also met on September 8th at an ad hoc meeting organized by the
SCPPA Government Affairs Division to discuss next steps regarding Advanced Clean Fleets
policy now that CARB has finalized the latest rulemaking.
The next LWG meeting will be held on September 16th

MUTUAL ASSISTANCE
The Mutual Assistance Sub-Working Group (MASG) met on September 1, 2026. There were
no Mutual Assistance requests in July and August. We received a presentation from the
California Utilities Emergency Association (CUEA) during the meeting. There will be a
tabletop exercise CUEA will be conducting along with Southern California Edison later this
month. The Mutual Assistance Playbook has been fully reviewed and will be updated
accordingly.
The next MAWG meeting will be held on October 6, 2026.

NATURAL GAS
The next Natural Gas Working Group (NGWG) will be held on October 27, 2026. We plan to
receive operations updates from PureWest, SCPPA’s operator in Wyoming, and BKV, one of
SCPPA’s operators in Texas. In addition, this working group will also review Net Operating
Revenue reports for both Barnett and Pinedale projects.

PREPAY
General Prepay Working Group meetings will be scheduled in the future on an as needed
basis.

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REGULATORY
The Regulatory Working Group (RWG) met on August 19th.
The RWG discussed several regulatory and stakeholder developments. These included the
California Air Resources Board's (CARB) Advanced Clean Fleets (ACF) rule SF6 Rule
engagement opportunities; the California Energy Commission's (CEC) Integrated Resource
Planning (IRP) Guidelines updates and the Integrated Energy Policy Report (IEPR) updates;
State Water Resources Control Board (SWRCB) Utility Wildfire General Order; updates from
the California Electric Transportation Coalition (CalETC) board meeting; and SCPPA’s
upcoming annual conference.
Members of the RWG also met on September 8th at an ad hoc meeting organized by the
SCPPA Government Affairs Division to discuss next steps regarding Advanced Clean Fleets
policy now that CARB has finalized the latest rulemaking.
The next RWG meeting will be held on September 16, 2026.

RENEWABLES
The Renewables Working Group (ReWG) met on August 18, 2026. The Group discussed all
10 current projects in development and their statuses in the meeting. The ReWG discussed
all new proposals received at the end of July and Members will discuss internally to
determine which proposals to move forward with for future negotiations.
The next ReWG meeting will be held on September 15, 2026.

RESOURCE PLANNING
The Resource Planning Working Group (RPWG) met on September 3, 2026. The RPWG
discussed future procurement concerns in regards to potential increased tariffs and supply
chain delays. Balcony Solar was discussed regarding its potential safety impacts to utilities

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around back feed concerns and potential fire risks. The RPWG also discussed the latest CEC
guidelines for the IRs and felt the guidelines were less restrictive on certain energy
resources now.
The next RPWG meeting will be held on October 1, 2026.

RISK MANAGEMENT
The Risk Management Working Group (RMWG) met on September 2, 2026. The Group
received a presentation from Mei Pan with Anaheim Public Utilities and Huitzilo Arriaga with
Pasadena Water and Power on the history of wildfire liabilities and as they relate to utility
risk management. Following the presentation, the Group held a roundtable discussion.
The next RMWG meeting is scheduled for October 7, 2026.

SAFETY
The Safety Working Group (SWG) will meet on September 22, 2026. The Group plans to
discuss fleet safety consultants and any other pressing safety related issues for the end of
the year.

TRANSPORTATION ELECTRIFICATION
The Transportation Electrification Working Group (TEWG) met on August 18, 2026. The
meeting opened with general updates, including an overview of upcoming Program
Development Division's expiring contracts and the current status of the related RFPs.
Brandon Czworniak provided a summary of the UC Davis research paper, If You Build It,
They May Not Come: Willingness to Participate in Managed EV Charging. Brandon highlighted
the paper’s key findings regarding customer participation in managed charging programs
and the potential implications for utility program design.

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Emily Lemei with the Northern California Power Agency (NCPA) joined the meeting to
provide updates on the Clean Fuel Reward program, Low Carbon Fuel Standard (LCFS), and
new NCPA contracts.
Optony also joined the meeting to provide a presentation on its transportation
electrification advisory services, including potential opportunities to support SCPPA
Members with transportation electrification planning and implementation.
The meeting concluded with discussion among members on the presentations and industry
and regulatory updates.
The next TEWG meeting will be held on September 15, 2026.

TRANSMISSION & DISTRIBUTION ENGINEERING & OPERATIONS (TD
E&O)
The Transmission Distribution Engineering & Operation (TDE&O) Working Group (TDE&O
WG) met on September 1, 2026. The TDE&O WG received a presentation from Pasadena
on their EV Charging facilities throughout their city and their plans to expand in the next 5
years. The group discussed this year’s T&D Annual Conference scheduled for December 2,
2026. The plan is to host the event at the SCPPA Training Center.
The next TDE&O WG meeting will be held on October 6, 2026.

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RECURRING/ROLLING SOLICITATIONS:

NAME:

Request for Proposals: 2026 Stand-Alone Energy Storage Systems

WORKING GROUP:
ISSUE DATE:

Resource Planning

April 28, 2026

CLOSE DATE:

November 25, 2026

DESCRIPTION:
SCPPA Members seek an annual rolling Standalone Energy Storage Systems
(ESS) RFP to support Members’ procurement of renewable resources in
meeting their Renewable Portfolio Standards (RPS) and procurement targets
regarding Assembly Bill (AB) 2514. This RFP seeks proposals for stand-alone
ESS in areas relevant to SCPPA Members’ territories (CAISO Balancing
Authority (BA), IID BA, and at specific locations within the LADWP BA
system).

NAME:

Request for Proposals: 2026 Q3/Q4 SCPPA
Renewable Energy Resources and Energy Storage
Solutions

WORKING GROUP:

Renewables

ISSUE DATE:

July 16, 2026

CLOSE
DATE:

December 30, 2026

DESCRIPTION:
SCPPA’s semi-annual rolling RFP to solicit proposals from developers for
renewable resources with or without energy storage (Solar, Wind, Geothermal,
Biomass, and Small Hydro) to meet Members’ IRP, Clean Energy, and RPS goals.

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UPCOMING/RECENT SOLICITATIONS (NEW/CONTINUED SERVICES):

NAME:

Request for Proposals: 2026 Q3/Q4 SCPPA
Renewable Energy Resources and Energy Storage
Solutions

WORKING GROUP:

Renewables

ISSUE DATE:

July 16, 2026

CLOSE
DATE:

December 30, 2026

DESCRIPTION:
SCPPA’s semi-annual rolling RFP to solicit proposals from developers for
renewable resources with or without energy storage (Solar, Wind, Geothermal,
Biomass, and Small Hydro) to meet Members’ IRP, Clean Energy, and RPS goals.

NAME:

Request for Proposals: New Resources and Transmission

WORKING GROUP:
ISSUE DATE:

Renewables

February 5, 2026

CLOSE DATE:

October 16, 2026

DESCRIPTION:
Proposal from developers on Carbon-Free projects and related Transmission for
Members in particular areas where the Members can receive the energy.

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NAME:

Energy Efficiency Audits and Direct Installation Services

DEPARTMENT:
ISSUE DATE:

Program Development
October 1, 2026

CLOSE DATE:

November 1, 2026

DESCRIPTION:
SCPPA issued an RFP for Energy Efficiency Audits and Direct Installation
Services to provide integrated support for identifying, evaluating, and
implementing energy efficiency opportunities for residential, commercial,
industrial, and institutional customers of SCPPA members.

NAME:

Distributed Energy Resource Management Systems and Programs
Support Tools

DEPARTMENT:
ISSUE DATE:

Program Development
August 20, 2026

CLOSE DATE:

September 18, 2026

DESCRIPTION:
SCPPA issued an RFP for Distributed Energy Resource Management Systems
and Programs Support Tools to provide forecasting of distributed energy
resource adoption and output, quantify load flexibility, and improve
distribution grid planning.

NON-BOARD APPROVED CONTRACT EXTENSIONS:
None

Daniel E Garcia, Executive Director
Southern California Public Power Authority

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Matt VanPuyvelde
(818) 238-1859
September 17, 2026

MAGNOLIA POWER PLANT
OPERATIONS REPORT
August 2026
Reporting Period
August 1-31, 2026
Workforce Safety Statistics


There were zero (0) lost time accidents this month and zero (0) year-to-date (YTD).



There were zero (0) reportable incidents in August and zero (0) YTD.

Plant Performance Information


Availability: 100.0% in August, 98.8% fiscal year-to-date (FYTD), and 87.4% YTD.
(A table showing monthly plant availability for the past twenty months is attached.)



Unit Capacity Factor (240 MW): 85.2% in August, 77.9% FYTD, and 52.6% YTD.



Fired Factored Hours: 744.0 hours in August 2026.



Plant Starts (5 starts/month allowed): Zero (0) starts used in August 2026.



Plant Operating Hours (8,322 hours/year allowed): 5,084.2 hours YTD.



Statistics: Details are provided on the attached monthly production report entitled “Yearto-Date Summary of Statistics “CY2026 & FY2026-27”.

Plant Outage Summary and Other Information


There were no outages at MPP during the month of August 2026. A table entitled “Outage
Summary” is attached which shows all the outages that have occurred over the past
twelve (12) months. The “2026-2030 Scheduled Inspection Plan” is also attached
showing the calendar for future planned outages at MPP.



There were no instances of stranded energy in August 2026. A table showing stranded
energy by month is attached.



The duct burner system was shut off at 22:00 on Thursday, August 27, 2026 to prevent
exceeding the South Coast Air Quality Management District (SCAQMD) permit limit for
daily duct burner fuel consumption.



MPP is scheduled to undergo annual HRSG Safety Valve testing on Thursday,
September 17, 2026.



Preparations are underway for the upcoming planned outage. MPP will be shut down on
September 18, 2026, to perform an offline water wash of the combustion turbine
compressor and balance of plant maintenance. MPP is scheduled to be restarted on
September 21, 2026.

MAGNOLIA MONTHLY PRODUCTION REPORT
Year-to-Date Summary of Statistics
CY2026 & FY2026-27
2026

2026

2026

2026

2026

2026

2026

2026

2026

2026

2026

2026

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

FYTD

YTD

96,375
61,544
157,919

175,426
113,991
289,417

432,276
339,148
771,424

5,389
199
126,109
70.6%

5,727
6
152,192
85.2%

11,116
205
278,301
77.9%

34,709
2,543
736,715
52.6%

14,578
7,888
8,278

12,074
7,300
7,612

11,439
7,191
7,461

11,725
7,240
7,529

13,567
7,662
8,023

744.0
683.3
0.0
91.8%
0.0
60.8
0.0
0.0%
60.8
0.0
0.0
683.3
23,309

720.0
634.7
0.0
90.0%
13.4
72.0
0.0
0.0%
85.3
0.0
0.0
634.7
22,674

744.0
726.7
31.4
97.7%
0.0
0.0
17.3
2.3%
17.3
0.0
0.0
726.7
21,947

744.0
744.0
133.0
100.0%
0.0
0.0
0.0
0.0%
0.0
0.0
0.0
744.0
21,203

1,488.0
1,470.7
164.4
98.8%
0.0
0.0
17.3
1.2%
17.3
0.0
0.0
1,470.7
Feb 2029

5,831.0
5,084.2
187.5
87.4%
13.4
264.7
468.7
8.0%
746.8
0.0
0.0
5,084.2
-

657
674,944
0.0
0
544.2
674,944
1,028

668
692,281
0.0
2
544.2
692,283
1,036

919
954,437
5.3
5,474
538.9
959,911
1,038

1,050
1,102,440
31.5
33,088
507.4
1,135,528
1,050

1,969
5,679
2,056,877 5,864,832
37
43.7
38,562
45,611
2,095,439 5,910,444
1,044
1,031

ENERGY
Combustion Turbine (Gross)
Steam Turbine
Plant Generation (Gross)

MWh
MWh
MWh

43,154
35,017
78,171

22,044
17,752
39,796

52,872
46,336
99,208

49,074
45,032
94,106

42,218
40,740
82,958

47,488
40,280
87,768

79,051
52,447
131,498

Plant Auxiliaries (Unit Aux.)
Plant Auxiliaries (Reserve)
Plant Generation (Net)
Capacity Factor (240 MW Net)

MWh
MWh
MWh
%

3,729
392
74,442
41.7%

1,748
1,241
38,048
23.6%

4,908
7
94,300
52.9%

4,724
6
89,382
51.7%

4,344
304
78,614
44.0%

4,140
388
83,628
48.4%

THERMAL EFFICIENCY
Combustion Turbine (Gross)
Total Plant (Gross)
Total Plant (Net)

Btu/kWh
Btu/kWh
Btu/kWh

14,173
7,824
8,216

14,082
7,800
8,159

14,714
7,865
8,274

15,095
7,922
8,340

15,987
8,136
8,586

AVAILABILITY
Hours in the Month
Hours
Plant Operating Hours
Hours
Duct Burner Operating Hours
Hours
Plant Availability
%
Offline yet Available Hours
Hours
Planned Outage Hours
Hours
Forced Outage Hours
Hours
Forced Outage
%
Total Hours Offline
Hours
Forced Derated Hours
Hours
(FFH) From Peak Power
Hours
Total Factored Fired Hours
Hours
(FFH) Before Next Inspection
Hours
Estimated Date of Next Major Outage

744.0
546.0
0.0
73.4%
0.0
132.0
66.0
8.9%
198.0
0.0
0.0
546.0
25,741

672.0
286.6
0.0
42.7%
0.0
0.0
385.4
57.3%
385.4
0.0
0.0
286.6
25,455

743.0
743.0
10.8
100.0%
0.0
0.0
0.0
0.0%
0.0
0.0
0.0
743.0
24,712

720.0
720.0
12.3
100.0%
0.0
0.0
0.0
0.0%
0.0
0.0
0.0
720.0
23,992

FUEL USAGE AND QUALITY
Combustion Turbine
Combustion Turbine
Duct Burner
Duct Burner
Duct Burner Fuel Remaining
Total Plant Usage
Gas Btu (HHV)*
*1,050 assumed pending bill

601
611,604
0.0
5
551.1
611,609
1,018

301
310,422
0.0
0
551.1
310,422
1,032

757
777,955
2.2
2,306
548.8
780,261
1,028

726
740,749
4.6
4,737
544.2
745,485
1,020

MMSCF
DTH
MMSCF
DTH
MMSCF
DTH
Btu/SCF

Magnolia Power Plant - Outage Summary
Outages During the Reporting Period August 1-31, 2026
Outage Type

Start Date/Time

End Date/Time

Comments

Hours

N/A

Summary of Outages During the Past Twelve Months
Outage Type

Start Date

End Date

Hours

FO
PO
PO
FO
FO
PO
PO
RS
FO
FO

September 30, 2025
October 17, 2025
January 23, 2026
January 29, 2026
February 16, 2026
May 1, 2026
June 26, 2026
June 29, 2026
July 1, 2026
July 1, 2026

September 30, 2025
October 20, 2025
January 29, 2026
February 16, 2026
February 17, 2026
May 4, 2026
June 29, 2026
June 29, 2026
July 1, 2026
July 2, 2026

12.20
72.82
131.97
432.55
18.82
60.8
72.0
13.38
2.1
15.23

Outage Type Legend
RS - Reserve Shutdown
PO - Planned Outage
FO - Forced Outage
OMC - Outside of Management Control

Cause

Fuel gas compressor "A" suction valve repair
CT water wash
CT borescope/boiler inspection
HRSG/boiler desuperheater spray liner repairs
ST bearing vibration
CT water wash
SoCalGas pipeline maintenance, CT water wash
Off-line but available
FGC VFD fault
ST bearing #1 vibration

Magnolia Power Plant - Availability Summary Table
Monthly

Quarterly

Semi-Annually

Annually

Jan-25

100.0%
Feb-25

Q1 '25

99.1%

65.3%

Mar-25

0.0%

H1 '25

Apr-25

66.2%

16.5%
May-25

Q2 '25

93.5%

67.1%

Jun-25

90.4%

Yr '25

Jul-25

81.6%

91.9%
Aug-25

Q3 '25

100.0%

96.7%

Sep-25

98.3%

H2 '25

Oct-25

96.7%

90.2%
Nov-25

Q4 '25

100.0%

96.7%

Dec-25

100.0%
Jan-26

73.4%
Feb-26

Q1 '26

42.7%

73.0%

Mar-26

100.0%

H1 '26

Apr-26

83.5%

100.0%
May-26

Q2 '26

91.8%

93.9%

Jun-26

90.0%
Jul-26

97.7%
Aug-26

100.0%

2026-2030

Offline Water Wash
Hot Gas Path / Minor Inspection

Scheduled Inspection Plan
with 32K Hardware

Magnolia Power Project

Major Inspection

As of Aug. 31st, 2026
Total Fired Hours
PROJECTED ANNUALLY
INSPECTIONS

76

2026
(7,938 Hours)
151,104 Hrs
January 2026

2027
(6,096 Hours)

2028
(8,472 Hours)

81

85

Total Fired Time

155,635 Hours

2029
(8,448 Hours)

2030
(8,448 Hours)

89

93

January 2027

February 2028

February 2029

February 2030

Water Wash

Offline 6:00 PM 1/23/2026

Offline 6:00 PM 1/18/2027

Offline 6:00 PM 2/4/2028

Offline 6:00 PM 2/2/2029

Offline 6:00 PM 1/25/20230

90 Day Intervals
Every 2,160 Hours

Online 6:00 AM 1/29/2026

Online 6:00 AM 1/22/2027

Online 6:00 AM 2/10/2028

Online 6:00 AM 2/8/2029

Online 6:00 AM 1/31/2030

January 2027

CT Borescope/Boiler
Inspection
86
May 2028

CT Borescope/Boiler
Inspection
90
May 2029

CT Borescope/Boiler
Inspection
94
May 2030

Offline 6:00 PM 1/28/2027

Offline 6:00 PM 5/5/2028

Offline 6:00 PM 5/11/2029

Offline 6:00 PM 5/3/2030

Online 6:00 AM 5/12/2027

Online 6:00 AM 5/8/2028

Online 6:00 AM 5/14/2029

Online 6:00 AM 5/6/2030

87

91

95

Hot Gas Path / Minor
Inspection

CT Borescope/Boiler
Inspection
152,879 Hrs
77
May 2026

Every 32,000 Hours

Offline 6:00 PM 5/1/2026

Last HGP @ 144,837 Hrs

Online 6:00 AM 5/04/2026

Major Inspection

154,144 Hrs
June 2026

Every 64,000 Hours

Offline 6:00 AM 06/26/2026

Last Major @ 112,229 Hrs

Online 6:00 PM 06/29/2026

78

Upcoming Inspections
CT Enhancement
Boiler Inspection
01/28/2027-05/12/2027

SoCal Gas
Curtailment

CT Enhancement / Boiler
Inspection
82
83
August 2027

August 2028

August 2029

August 2030

Offline 6:00 PM 8/13/2027

Offline 6:00 PM 8/4/2028

Offline 6:00 PM 8/10/2029

Offline 6:00 PM 8/2/2030

Online 6:00 AM 8/16/2027

Online 6:00 AM 8/7/2028

Online 6:00 AM 8/13/2029

Online 6:00 AM 8/5/2030

84

88

92

96

79
September 2026
Offline 6:00 PM 9/18/2026
Online 6:00 AM 9/21/2026

All Future Dates are estimates
based on run hours and are
subject to change

4

81
82

80
79
December 2026

November 2027

November 2028

November 2029

November 2030

Offline 6:00 PM 11/5/2027

Offline 6:00 PM 11/3/2028

Offline 6:00 PM 11/2/2029

Offline 6:00 PM 11/1/2030

Online 6:00 AM 11/8/2027

Online 6:00 AM 11/6/2028

Online 6:00 AM 11/5/2029

Online 6:00 AM 11/4/2030

164,567 Hours

173,039 Hours

181,487 Hours

189,935 Hours

Offline 6:00 PM 12/11/2026
Online 6:00 AM 12/14/2026

End Of Year Totals

158,471 Hours

Stranded Energy Monthly Report
Month
Sep-25
Oct-25
Nov-25
Dec-25
Jan-26
Feb-26
Mar-26
Apr-26
May-26
Jun-26
Jul-26
Aug-26

Participant
Glendale
Anaheim
-

Energy (MWh)
47
34
-

SCPPA BOARD MEETING
PALO VERDE NUCLEAR GENERATING STATION (PVNGS)
STATUS REPORT
Plant Operations - Following is the status of the plant as of August 1st, 2026:

• Unit 1 is at full power in its 448th day of continuous operation.
• Unit 2 is at full power in its 87th day of continuous operation.
• Unit 3 is at full power in its 241th day of continuous operation.
July 2026, the year-to-date maximum dependable capacity factor is as follows:

Unit 1
Unit 2
Unit 3
Station

Capacity Factor
97.6%
98.3%
97.4%
97.8%
Budget:

July 2026, the cost report is summarized as follows:
(In $millions)
YTD-Budget

YTD-Actual

YTD-Variance

426.30
182.74
146.88
755.92

435.91
207.61
125.68
769.20

9.61
24.86
(21.20)
13.28

O&M
Capital
Fuel
Total

Year-End
Budget
800.00
377.00
205.24
1,382.24

July 2026 Developments:
•

•

Nuclear Production Tax Credit: APS will complete the CY 2025 prevailing wage
evaluation by 8/15/2026 and vendor correction payments by 8/31/2026, with new
reporting requirements under IRS Form 7220. All PVNGS co-owners are using
cost-of-service/regulated revenue-requirement data to determine nuclear gross
receipts.
ADVANCE Act / NRC Implications: APS outlined that the ADVANCE Act
repositions the NRC toward efficient, predictable, and risk-informed licensing and
oversight. In the area of licensing efficiency, Congress expects NRC review
decisions to be timely, predictable, and risk-informed. Major changes include: More

disciplined review schedules for Licensing Amendment Requests (LARs), Improved
Subsequent License Renewal (SLR) review processes. Reduction of unnecessary or
repetitive Requests for Additional Information (RAIs), and Support for digital
modernization across licensing activities.

Memo
TO:
FROM:
RE:
DATE:

Southern California Public Power Authority
TFG
Federal Legislative Report
September 8, 2026

August 2026 Federal Report
This legislative report covers activities related to appropriations, energy, and environment, as well as
telecommunications and cybersecurity issues from August 1, through September 1, 2026.

Executive Summary
Congressional Calendar. The House was out for most of August, returning for a few days at the end of
the month. The Senate was in session for the first two weeks.
FY 2027 Appropriations. In one of the few actions they took while they were briefly in session, the
House passed the Senate version of the FY 2026 Continuing Resolution, which will allow the
government to continue fully operating until at least December 11th.
Energy and Environment. Federal executive branch actions on a wide array of relevant issues
continued apace, including NERC and FERC actions related to large load demand; NRC licensing-related
actions, as well as efforts to assess data center impacts on the grid.
Telecommunications and Cybersecurity. As usual, much is going on in this space, though of particular
notice is action by the FCC, in which the Build America wireline deployment NPRM (WC Docket No. 25253) was published in the Federal Register on August 7, 2026, opening the formal comment period.
Comments are due by September 21. The proposed regulation would create a rebuttable presumption
that state and local governments effectively prohibit service when they fail to act on rights-of-way
authorization requests within federal deadlines -- in this case, within 60 days -- and would set costbased limits on fees. Municipal utilities owning poles and conduit in the rights-of-way would be
impacted. On the cybersecurity front, the President has issued an executive order declaring a national
emergency regarding foreign-produced bulk-power system electric equipment, invoking the
International Emergency Economic Powers Act and the National Emergencies Act.

FY 2026/2027 Budget/Appropriations
In their only action while they were briefly in session, the House took up, and passed by a vote of 37048 (19 Republicans and 29 Democrats voted no), the Senate version of the FY 2026 Continuing

August 2026 Federal Legislative Report

Resolution, which will allow the government to continue fully operating until at least December 11. In
addition to the effective date of December 11, the Senate version includes an extension of the major
programs in the current Surface Transportation bill (aka the Highway Bill) that expires September 30th, a
freeze on implementation of the Trump Administration’s proposed rule on grants management that
dramatically increases the role of political appointees in the decision-making process, and a freeze on
additional Customs and Border Patrol funding.
A refresher on where we stand relative to bills of interest: The House Committee on Appropriations has
completed action on all 12 appropriations bills that would fund the “discretionary” federal
departments and agencies through September 30, 2026 (entitlements are considered mandatory
funding and outside the traditional appropriations process), including the Energy and Water
Appropriations bill, which includes the budgets of the Department of Energy and the Bureau of
Reclamation. Detailed documents include: H.R. 9022; Report; List of approved FY27 Community Project
Funding requests; and the Summary, as well as the Interior-Environment bill, which includes the
Interior Department and EPA. Detailed documents include: H.R. 9171;Report; List of approved

FY27 Community Project Funding requests and a bill Summary.

Energy and Environment
Congressional Developments: Data Centers and Grid Infrastructure
Before the House broke for Summer Recess, the House Energy and Commerce Committee reported out
of committee several electricity, transmission, forecasting, and ratepayer protection measures. The bill
viewed as having the strongest political appeal that moved was HR 9340, the Ratepayer Protection Act,
designed to prevent cost shifts to existing customers as it relates to data centers.
It's notable that Congress is shifting its focus from general oversight of data centers toward specific
legislative frameworks that could influence an array of aspects of utility operations, including
transmission cost allocation – a hot topic in DC. An emerging bipartisan principle is that hyperscale
customers should bear the incremental costs they impose on utility systems while preserving
affordability for existing customers.
The debate on these and related issues is expected to continue later this year, during the “Lame Duck”

Session (post–election) and into the next Congress.

Action at FERC and NERC on Large Load Reliability
The Federal Energy Regulatory Commission (FERC) continued implementation of its June large-load
initiative, requiring regional grid operators to justify or reform tariffs governing the interconnection and
service of data centers and other major energy users. Areas under review include speculative requests,
study timelines, cost allocation, co-located generation, and reliability protections.

2

August 2026 Federal Legislative Report

The North American Electric Reliability Corporation (NERC) continued implementation of its largeload action plan following reliability concerns involving rapidly changing computational loads. It also
advanced proposals creating computational load owner and computational load operator registration
categories.
Together, these developments appear to reflect a shifting trend from treating data centers as ordinary
customers toward viewing them as grid-impacting facilities that may carry direct reliability obligations.
The eventual outcome could influence -- among other matters -- utility contracts, operational
coordination requirements, and transmission planning assumptions across the West.

DOE Action on Transmission Planning
DOE released its draft National Transmission Needs Study, identifying transmission constraints,
congestion, and future needs associated with load growth, changing generation patterns, and reliability
requirements.
Given Congress has also advanced legislation promoting advanced conductors, grid-enhancing
technologies, load forecasting improvements, and transmission modernization, it appears federal
policymakers are increasingly view transmission availability as a factor for economic growth and
resource development.
To that end, the ongoing issue -- part of federal permitting reform legislative discussions -- is how to
ensure that future federal transmission policies recognize Western grid conditions and support costeffective combinations of new transmission, advanced technologies, storage solutions, and regional
coordination, among other considerations.

Latest on Nuclear at NRC And Elsewhere
The Nuclear Regulatory Commission (NRC) has continued efforts to accelerate advanced nuclear
deployment in August. The NRC proposals could provide additional flexibility for advanced reactor
applicants through revised licensing approaches and streamlined review procedures. These actions are
intended to reduce development timelines and improve regulatory certainty.
A significant development has emerged: increased federal attention to nuclear fuel supply. In a new
publication, GAO reported continuing concerns regarding future availability of HALEU fuel required by
some advanced reactor designs. The report noted that fuel-cycle capacity may become an important
constraint on commercial deployment even if licensing reforms prove successful.

Telecommunications and Cybersecurity
Telecommunications
FCC Nomination Would Restore a Working Quorum: On August 7, President Trump nominated Danielle
Thumann Severs, senior counsel to Chairman Brendan Carr, to fill one of the Commission’s two vacant

3

August 2026 Federal Legislative Report

seats. If confirmed by the Senate, she would serve a five-year term retroactive to July 1, 2024,
establishing a three-member Republican quorum — the minimum the agency needs to fully exercise its
functions and powers. Confirmation would clear the way for contested items, including the pending
rights-of-way preemption proceedings, to move to a vote.
Build America Wireline NPRM: The FCC’s Build America wireline deployment NPRM (WC Docket No.
25-253) was published in the Federal Register on August 7, 2026, opening the formal comment cycle.
Comments are due September 21, and reply comments are due November 5. The item proposes a
rebuttable presumption that state and local governments effectively prohibit service when they fail to
act on rights-of-way authorization requests within federal deadlines, and would set cost-based limits on
fees. Municipal utilities owning poles and conduit in the rights-of-way face direct exposure.
This proceeding warrants close monitoring because future FCC action could affect how utility-owned
infrastructure, rights-of-way, poles, conduit, and related facilities are managed when
telecommunications providers seek access.
Of particular concern is that federal preemption could interfere with local infrastructure management,
utility safety practices, engineering reviews, and cost-recovery mechanisms.
Pole Attachment Reverse-Preemption Review Remains Pending: The FCC Wireline Competition
Bureau’s public notice asked whether the 23 states and the District of Columbia that certified under
Section 224(c) genuinely regulate pole attachment rates, terms, and conditions and maintain access
complaint procedures, and whether deficient certifications should be treated as invalid so the
Commission can assert federal jurisdiction. The record closed in late July; Bureau action is pending.
Although Section 224 exempts municipal utilities, the proceeding signals the Commission’s appetite for
expanding federal pole jurisdiction.
NTIA Completes Approval of All BEAD Final Proposals: NTIA announced on August 25 that it had
approved the last outstanding BEAD Final Proposal, completing approval of all 56 state and territorial
proposals. Assistant Secretary Arielle Roth marked the milestone by touring fiber and satellite projects
in Virginia. Most eligible entities have also cleared NIST review and executed award agreements. The
program now shifts from planning into construction, moving attention to permitting throughput, pole
access, and make-ready timelines in participating communities.
NTIA Seeks Comment on Application Forms for the Reopened Competitive Grant Program: On August
25, NTIA published a Federal Register notice seeking public comment on the application forms for its
reopened Competitive Grant Program — the first concrete procedural step toward deploying the
roughly $21 billion in savings generated by the BEAD restructuring. Comments on the associated
information collection are due October 26. The forms will shape eligibility and application burden for
any subsequent round targeting locations that remain unserved after the primary deployment phase.
FCC Section 706 Broadband Deployment Report: The FCC adopted its annual Section 706 report on
August 13 and released it on August 14, concluding that advanced telecommunications capability is
being deployed to all Americans in a reasonable and timely fashion. The report draws on Broadband
Data Collection filings current through June 30, 2025. An affirmative finding narrows the Commission’s

4

August 2026 Federal Legislative Report

statutory obligation to take immediate action removing deployment barriers, even as the agency
continues citing deployment concerns to justify its preemption rulemakings.
FCC Narrows Covered List Prohibition on Foreign-Produced Power Inverters: On August 20, the FCC
narrowed the class of foreign-produced power inverters it had added to the Covered List in July. The
prohibition now reaches inverters intended for use in parallel with an electric utility to supply common
loads and, at times, deliver power back to the utility. The Commission exempted inverters qualifying for
the Section 45X Advanced Manufacturing Tax Credit and clarified that inverters with either wired or
wireless communications components are covered. Distributed generation and storage procurement is
directly affected.

Cybersecurity
.Executive Order Declares a National Emergency Over Bulk-Power System Equipment: On August 26,
the President issued an executive order declaring a national emergency regarding foreign-produced
bulk-power system electric equipment, invoking the International Emergency Economic Powers Act and
the National Emergencies Act. The order generally prohibits or conditions the purchase and installation
of covered equipment, associated critical software, and digital capabilities tied to covered foreign
entities, and does not apply to facilities used for local distribution. The Department of Energy must
issue implementing rules within 120 days.
Cybersecurity Information Sharing Act of 2015 Approaches Another Sunset: CISA 2015 was extended
only through September 30, 2026, in the FY2026 Consolidated Appropriations Act, following two lapses
in the preceding year. The statute supplies liability protections, FOIA exemptions, and privilege
safeguards for the voluntary sharing of cyber threat indicators and defensive measures. Public power
utilities rely on those protections when participating in the E-ISAC and MS-ISAC. Long-term
reauthorization bills remain stalled, and August brought renewed industry pressure for action before
the deadline.
CISA Ends Six Free Assessments as the CIRCIA Final Rule Nears: CISA notified staff on August 25 that it
is ending six free assessments for critical infrastructure operators, including Cyber Resilience Reviews,
Ransomware Readiness Assessments, Incident Management Reviews, and Cyber Infrastructure Surveys,
directing organizations instead to its Cross-Sector Cybersecurity Performance Goals. The reduction
follows substantial budget and workforce cuts. It arrives as CISA prepares the CIRCIA final rule, expected
in September, requiring covered entities to report significant incidents within 72 hours and ransom
payments within 24 hours.

5

August 2026 Federal Legislative Report

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AGENDA ITEM STAFF REPORT

MEETING DATE:

SUBJECT:

09/17/2026

RESOLUTION NUMBER:

2026-095

Amendment No. 5 to Master Professional Services Agreement for Energy
Efficiency Audits and Direct Installation Services with Eagle Systems International
Inc. doing business as (DBA) Synergy Companies to Extend the Term of the
Agreement to January 21, 2027

DISCUSSION:

☐

OR

CONSENT:

☒

Select the appropriate box(es):
FROM:
Finance
Project Development
Program Development
Regulatory/Legislative
Project Administration
Legal
Executive Director

METHOD OF SELECTION:

☐
☐
☒
☐
☐
☐
☐

☒
☐
☐
☐

Competitive
Cooperative Purchase
Sole Source
Other
Other (Please describe):

MEMBER PARTICIPATION:
Sponsoring Member: Azusa, Colton, Banning, Burbank, Glendale, Imperial Irrigation District
Other Members Potentially Participating: N/A

Approved by Executive Director: ___________________________________

RECOMMENDATION:
Approve Amendment No. 5 to a Master Professional Services Agreement (Agreement) with Eagle
Systems International Inc. doing business as (DBA) Synergy Companies (Synergy) to extend the
term of the Agreement until January 21, 2027. Under the Agreement, Synergy provides residential
and commercial energy efficiency audits and direct installation of energy efficiency measures. The
additional months of service provided by Amendment No. 5 to the Agreement would allow SCPPA to
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provide continuity of services to its members pending release and completion of SCPPA’s competitive
request for proposals (RFP) process.
BACKGROUND:
Synergy is a full-service energy management organization founded in 1982 and headquartered in the
San Francisco Bay Area. Synergy has worked with major California and western states utilities, such
as Pacific Gas and Electric Company, Southern California Edison, Southern California Gas Company,
San Diego Gas & Electric, PacifiCorp, Rocky Mountain Power, and Nevada Energy, to bring energy
efficiency and environmental services to the utilities’ end-use customers.
In 2020, following a competitive solicitation process, the Board adopted Resolution No. 2020-107
authorizing SCPPA to enter into a master professional services agreement with Synergy for energy
efficiency audits and direct installations services. The initial term of the Agreement was three years with
an option for SCPPA to extend for an additional three-year term.
In 2021, the Board adopted Resolution No. 2021-102 approving Amendment No. 1 to the Agreement
to increase the not-to-exceed to $10,250,000 and to update the insurance and standard of care
provisions in the Agreement.
In 2023, the Board adopted Resolution No. 2023-100 approving Amendment No. 2 to the Agreement
to extend the term for the final 3 years, to increase the not-to-exceed amount to $18,550,000, to add
new energy efficiency measures, and to update product pricing as a result of rising costs of labor and
materials.
In 2025, the Board adopted Resolution No. 2025-012 approving Amendment No. 3 to the Agreement
to increase the not-to-exceed amount to $22,550,000, to add new energy efficiency measures, and to
update product pricing as a result of rising costs of labor and materials. The Board also adopted
Resolution No. 2025-094 approving Amendment No. 4 to the Agreement to increase the not-to-exceed
amount to $27,550,000 to allow for additional SCPPA Member participation in the Agreement.
The purpose of proposed Amendment No. 5 to the Agreement is to extend the Agreement with Synergy
for three additional months, until January 21, 2027, to avoid a disruption in services, pending the release
and completion of an RFP for energy efficiency audits and direct installation services
Six SCPPA Members – Azusa, Banning, Burbank, Colton, Glendale and Imperial Irrigation District –
have entered into task orders with Synergy under the Agreement. The Agreement is currently set to
expire on October 15, 2026. Through the Customer Programs Working Group, five Members, Azusa,
Burbank, Colton, Glendale, and Imperial Irrigation District expressed a desire to continue utilizing
Synergy’s services at this time.

DISCUSSION:
SCPPA staff recommends that SCPPA extend the current Agreement with Synergy by three months to
allow sufficient time to release and complete the competitive RFP process. The proposed extension
will help ensure continuity of service and avoid any potential lapse in critical support provided to SCPPA
Members during the transition period until SCPPA presents is recommendations for award of contract
to the Board for its consideration.
•

Scope of Contract Services:

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SCPPA Members have a need for energy efficiency audits and direct installation services for
their multi-family, hospitality, small business, municipal, and residential sectors.
Synergy’s services provide Members with an increased ability to identify and implement energy
efficiency measures tied to energy efficiency improvements.
Synergy’s scope of work includes the following core services:
1. Energy efficiency audits
2. Direct installation of energy efficiency measures
•

Selection Method:
SCPPA issued a competitive solicitation for energy efficiency audits and direct installation
services on July 7, 2020. The submittal deadline for the RFP was August 4, 2020.
A total of 20 responses were received and evaluated by Burbank, Colton, and the Imperial
Irrigation District based on the respondents’ qualifications, experience, skills required to provide
the required services, demonstration of project management abilities, references, and costcompetitiveness. Synergy was selected as the most qualified and cost-effective firm out of the
top six respondents to SCPPA’s competitive solicitation.

•

SCPPA’s Authority:
SCPPA has the authority to execute this Amendment No. 5 to the Agreement under the
California Joint Exercise of Powers Act, the SCPPA Joint Powers Agreement and the provisions
of Section 9615 of the California Public Utilities Code ("Section 9615”). The SCPPA Joint Powers
Agreement provides SCPPA with the authority to develop, finance, construct, operate and
maintain electric energy generation and transmission projects. SCPPA's ability to exercise this
right is supplemented by the requirements of Section 9615 which requires that each local publicly
owned electric utility, in procuring energy, “shall first acquire all available energy efficiency and
demand reduction resources that are cost effective, reliable and feasible." As a local publicly
owned utility, as that term is defined by the California Public Utilities Code, SCPPA and its
Members are subject to the requirements of Section 9615. Amendment No. 5 to the Agreement
will extend for three months the term of a contract to provide residential and commercial energy
efficiency audits and direct installation of energy efficiency measures to help SCPPA Members
satisfy the energy efficiency and demand reduction requirements of Section 9615 by delivering
cost-effective programs to residents, reducing demand through energy efficiency measures,
ensuring equitable access across all customer classes, and providing measurable, reportable
savings in alignment with industry best practices.

FISCAL IMPACT:
The Agreement has a not-to-exceed amount of $27,550,000. No additional funding will be required for
this Amendment.
Participating Members have committed in writing to paying for any, and all, services procured from
Synergy under the Agreement pursuant to separate task orders signed by each SCPPA Member that
elects to receive such services from Synergy.

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ATTACHMENTS:
1. Resolution No. 2026-095
2. MPSA Amendment No. 5

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RESOLUTION NO. 2026-095
RESOLUTION OF THE BOARD OF DIRECTORS OF THE
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
AUTHORIZING THE EXECUTIVE DIRECTOR TO
EXECUTE AMENDMENT NO. 5 TO THE MASTER
PROFESSIONAL SERVICES AGREEMENT BETWEEN
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
AND EAGLE SYSTEMS INTERNATIONAL, INC. DBA
SYNERGY COMPANIES EXTENDING THE TERM OF THE
AGREEMENT FOR THREE MONTHS
WHEREAS, the Southern California Public Power Authority (“SCPPA” or “the
Authority”) owns interests in various generation and transmission projects, the output or services
of which has been sold to Members of the Authority (“Members”); and its Members are engaged
in the generation, transmission, and distribution of electrical energy to retail customers, including
assisting such customers with the efficient use of said energy; and
WHEREAS, after a competitive solicitation, the SCPPA Board adopted Resolution
2020-107, pursuant to which SCPPA executed a Master Professional Services Agreement (the
“Agreement”) with Eagle Systems International, Inc. DBA Synergy Companies to provide energy
efficiency services (the “Services”) for participating Members; and
WHEREAS, on May 18, 2023, the SCPPA Board adopted Resolution 2021-102,
pursuant to which SCPPA executed Amendment No. 1 to the Agreement to increase the contract
not to exceed amount and to update the insurance and standard of care provisions included in the
Agreement; and
WHEREAS, on July 20, 2023, the SCPPA Board adopted Resolution 2023-100,
pursuant to which SCPPA executed Amendment No. 2 to the Agreement to increase the contract
not to exceed amount, extend the term of the amount, and update the list of products and services
provided in the Agreement; and
WHEREAS, on April 17, 2025, the SCPPA Board adopted Resolution 2025-012
pursuant to which SCPPA executed Amendment No. 3 to the Agreement to increase the contract
not to exceed amount to $22,550,000, to add new energy efficiency measures, and to update
product pricing as a result of rising costs of labor and materials; and
WHEREAS, on November 20, 2025, SCPPA adopted Resolution No. 2025-094
pursuant to which SCPPA executed Amendment NO. 4 to the Agreement to increase the not-toexceed amount from $22,550,000 to $27,550,000 due to increased Member utilization of the
Agreement; and
WHEREAS, the term of the Agreement will expire on October 15, 2026, and the
Parties desire to enter into Amendment No. 5 to extend the term for an additional three-month
period, through January 21, 2026, in order to provide for continued Services for participating
SCPPA Members while the Authority to undertake a competitive solicitation process for the
Services.

NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of the
Authority as follows:
1.

The Executive Director is authorized to execute Amendment No. 5 to the Agreement.

2.

The President, Vice President, Secretary, any Assistant Secretary, Executive Director and
any other officer of the Authority are each hereby authorized to execute and deliver any
and all documents and instruments and to do and cause to be done any and all acts and
things necessary or proper for carrying out the transactions contemplated by this
Resolution.

3.

This Resolution shall become effective immediately.

THE FOREGOING RESOLUTION is approved and adopted by the Authority this
17th day of September 2026.

PRESIDENT
MANDIP SAMRA
Southern California Public
Power Authority
ATTEST:

ASSISTANT SECRETARY
DANIEL E GARCIA
Southern California Public
Power Authority

AMENDMENT NO. 5
TO THE MASTER PROFESSIONAL SERVICES AGREEMENT BETWEEN
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
AND
EAGLE SYSTEMS INTERNATIONAL, INC. DBA SYNERGY COMPANIES
This Amendment No. 5 to the Master Professional Services Agreement (the “Agreement”) between the
Southern California Public Power Authority (“SCPPA”) and the Eagle Systems International, Inc. DBA
Synergy Companies (“Contractor”) (collectively, the “Parties”) is made and entered into on this 17th day
of September 2026.
WHEREAS, on October 15, 2020, the Parties entered into the Agreement, which Agreement has
been previously amended by Amendment No. 1 dated December 16, 2021; Amendment No. 2 dated July
20, 2023, Amendment No. 3 dated April 17, 2025; and Amendment No. 4 dated November 20, 2025; and
WHEREAS, the term of the Agreement will expire on October 15, 2026; and
WHEREAS, the Parties desire to extend the term of the Agreement through January 21, 2027.
NOW, THEREFORE, in consideration of the premises herein, and for good and valuable consideration,
the Parties agree as follows:
1. The term of the Agreement shall be extended up to and including January 21, 2027.
2. Except as provided herein, all other terms and conditions of the Agreement shall remain in full
force and effect.
IN WITNESS WHEREOF, each signatory hereto represents that he or she has been properly authorized to
execute and deliver this Amendment No. 5 on behalf of the party for which he or she signs.
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
By:
DANIEL E GARCIA
Executive Director
Approved as to Legal Form:
CHRISTINE GODINEZ
General Counsel
and;
EAGLE SYSTEMS INTERNATIONAL, INC. DBA SYNERGY COMPANIES
By:
MATTHEW CLARK
Vice President of Business Development

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AGENDA ITEM STAFF REPORT

MEETING DATE:

SUBJECT:

September 17, 2026

RESOLUTION NUMBER:

2026-096

Renewable Energy Prepayment – Initial Authorizing Resolution

DISCUSSION:

☒

OR

CONSENT:

☐

Select the appropriate box(es):
FROM:
Finance
Project Development
Program Development
Regulatory/Legislative
Project Administration
Legal
Executive Director

METHOD OF SELECTION:

☒
☐
☐
☐
☐
☐
☐

Competitive
Cooperative Purchase
Sole Source
Other

☐
☐
☐
☒

Other (Please describe):
In accordance with SCPPA Policy for
Financing and Selection of Financing
Team

MEMBER PARTICIPATION:
Sponsoring Member: Pasadena
Other Members Potentially Participating: N/A

Approved by Executive Director: ___________________________________

RECOMMENDATION:
Adopt a Resolution authorizing the preparation of all documents necessary for the issuance of bonds
to finance a proposed prepayment of supplies of renewable energy for the benefit of the City of
Pasadena.

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BACKGROUND:
The use of tax-exempt financing to prepay a long-term supply of natural gas and/or electricity is allowed
under the U.S. Tax Law and can provide significant cost savings to SCPPA members. Prepayments
can be applied in several ways, including for new energy purchases, utilizing existing power purchase
agreements (PPAs), natural gas purchases, and natural gas purchases converting to energy at a later
date.
SCPPA has previously financed prepayments of natural gas and renewable energy supplies with taxexempt bonds and currently has several prepay projects for the benefit of participating SCPPA
Members. These projects include the 2007 Prepaid Natural Gas Project for natural gas purchases, the
2024 Clean Energy Project (Prepaid PPA) utilizing existing PPAs, and the 2026 Clean Energy II Project
also utilizing existing PPAs.
DISCUSSION:
A SCPPA Member, the City of Pasadena (Pasadena), desires SCPPA to finance a prepayment of
supplies of renewable energy for Pasadena utilizing existing power purchase agreements. The
proposed Resolution will authorize a working group consisting of SCPPA staff and SCPPA’s municipal
advisor, bond counsel, and tax counsel, and support staff, to work with Pasadena staff and to
commence the preparation of documents for the proposed financing and to negotiate with
counterparties for the transaction.
On September 14, 2026, the Finance Committee will discuss the proposed financing of a new
renewable energy prepayment and consider recommending the attached Resolution to the Board of
Directors (Board) for approval to authorize the preparation of all necessary documents for the issuance
of bonds for the prepayment. If the Finance Committee recommends bringing the Resolution to the
Board for approval, staff requests that the Board consider this item at the September 17, 2026 Board
meeting.
SCPPA will incur costs in connection with its municipal advisor, bond counsel, and tax counsel services
for the preparation of the documents and related activities. These costs will be included in the total
amount of bonds issued as bond issuance costs. The payment of its municipal advisor, bond counsel,
and tax counsel fees will be contingent on the successful closing of the transaction. Once the draft
documents have been prepared, they will be brought to the Board for consideration and approval at a
future Board meeting.
•

Selection Method:
The Finance Committee will select the underwriting firms(s) in accordance with SCPPA’s Policy for
Financing and Selection of the Financing Team (Policy) and will consider the criteria as provided in
the Policy to determine the firm(s) that will deliver the overall best value for the transaction.

•

SCPPA’s Authority:
The financing of the proposed renewable energy prepayment is in accordance with the California
Joint Exercise of Powers Act and the SCPPA Joint Powers Agreement. The SCPPA Joint Powers
Agreement provides the authority for SCPPA to finance generation and transmission projects.

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FISCAL IMPACT:
There is no fiscal impact at this time.

ATTACHMENT:
1. Resolution 2026-096

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RESOLUTION NO. 2026-096
RESOLUTION OF THE BOARD OF DIRECTORS OF THE
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY (I)
AUTHORIZING THE PREPARATION OF ALL DOCUMENTS
NECESSARY OR APPROPRIATE TO SELL AND ISSUE
RENEWABLE ENERGY PREPAYMENT BONDS, PROCEEDS OF
WHICH WILL BE USED TO FINANCE PREPAYMENTS FOR THE
PURCHASE OF SUPPLIES OF RENEWABLE ENERGY FOR THE
BENEFIT OF THE CITY OF PASADENA AND (II) AUTHORIZING
OFFICERS OF THE AUTHORITY TO DO ALL THINGS DEEMED
NECESSARY OR APPROPRIATE IN CONNECTION THEREWITH
WHEREAS, the Finance Committee of the Southern California Public Power
Authority (the "Authority") has determined that it is in the best interest of the Authority to
proceed with preparing all documents necessary or appropriate to sell and issue bonds, notes
or other obligations (the "Bonds"), the proceeds of which will be used to finance
prepayments for the purchase of supplies of renewable energy for the benefit of the City of
Pasadena; and
WHEREAS, once prepared, drafts of the contracts proposed to be entered into by the
Authority in connection with the issuance of the Bonds for such purpose will be presented
for the Board's consideration.
NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of the Authority
as follows:
1.
The Authority's staff and the Authority's team of financing professionals
(including the personnel at the Los Angeles Department of Water and Power who work on
Authority matters, Norton Rose Fulbright US LLP, the Authority's Bond Counsel (“Bond
Counsel”), Nixon Peabody LLP, the Authority's Special Tax Counsel (“Special Tax
Counsel”) and PFM Financial Products LLC, the Authority's Municipal Advisor (the
“Municipal Advisor”)) are hereby authorized (i) to prepare all documents necessary or
appropriate for the sale and issuance of the Bonds, as and to the extent directed by the
Executive Director, and (ii) to consider proposal(s) from certain underwriter(s) with respect
to the sale and issuance of the Bonds for such purpose.
2.
The fees of Bond Counsel, Special Tax Counsel and the Municipal Advisor in
this transaction shall be contingent upon the successful issuance and sale of the Bonds and
shall be paid from the proceeds of the Bonds.
3.
Each of the President, any Vice President, Executive Director, Chief Financial
and Administrative Officer, Secretary, any Assistant Secretary, and any designee of the
foregoing, is hereby authorized and directed to do and cause to be done any and all acts and
things deemed necessary or appropriate for carrying out the transactions contemplated by
this Resolution.
306881213.2 1001408582
(Initial Resolution - SCPPA/Pasadena 2026 Clean Energy Prepay)

-1-

4.

This Resolution No. 2026- shall become effective immediately.

THE FOREGOING RESOLUTION is approved and adopted by the Authority this 17th
day of September, 2026.
By:

ATTEST:
By: ______________________________________
DANIEL E GARCIA
ASSISTANT SECRETARY
Southern California
Power Authority

306881213.2

-2-

MANDIP SAMRA
PRESIDENT
Southern California
Public Power Authority

Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

AGENDA ITEM STAFF REPORT

MEETING DATE:

SUBJECT:

September 17, 2026

RESOLUTION NUMBER:

2026-097

Environmental Attribute Sales Agreement with Tenaska Power Services Co. for
Sale of Nevada Portfolio Energy Credits

☒

DISCUSSION:

OR

CONSENT:

☐

Select the appropriate box(es):
FROM:

METHOD OF SELECTION:

☐
☐
☐
☐
☒
☐
☐

Finance
Project Development
Program Development
Regulatory/Legislative
Project Administration
Legal
Executive Director

☒
☐
☐

Competitive
Cooperative Purchase
Sole Source

Other (Please describe):
N/A

MEMBER PARTICIPATION:
Sponsoring Member:

Los Angeles Department of Water & Power (“LADWP”) and the City of
Burbank

Other Members Potentially Participating: None
Approved by Executive Director: ___________________________________
Daniel E Garcia

RECOMMENDATION:
Approve an Environmental Attribute Sales Agreement with Tenaska Power Services Co. (“Tenaska”)
for the sale of Nevada Portfolio Energy Credits.

AGENDA STAFF REPORT TEMPLATE

Page 1 of 3

v.8/6/2019

Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

BACKGROUND:
On behalf of LADWP and the City of Burbank, SCPPA has executed Purchase Power Agreements
(“PPAs”) with Ormat for several geothermal projects within the State of Nevada. LADWP is the sole
participant in SCPPA’s Northern Nevada Geothermal Portfolio and Don Campbell Phase 2 projects.
Burbank and LADWP both participate in the Don Campbell Phase 1 project, with shares of 15.38% for
Burbank and 84.62% for LADWP.
The PPAs include the purchase by SCPPA of all energy and environmental attributes. Renewable
Portfolio Standard (“RPS”) rules in Nevada vary from those of California by allowing for the creation of
renewable Portfolio Energy Credits (“PECs”) from station service or facility auxiliary load. As these
PECs originate from station service energy, they are not eligible for California RPS compliance use by
any SCPPA member. As a result, SCPPA estimates that it has over one million MWhs of PECs
available for sale from the PPAs from vintage year 2016 through March 31, 2026. The agreement with
Tenaska will allow for the sale of existing PECs for eventual use by Nevada load serving entities for
their Nevada RPS compliance.
DISCUSSION:
The LADWP Forward Marketing Group, on behalf of SCPPA and project participants LADWP and
Burbank, requested bids for the sale of SCPPA’s existing PECs from all counterparties with whom
LADWP has previously traded environmental attributes. LADWP received a total of one (1) bid at
$8/MWh of PECs.
The agreement with Tenaska allows the SCPPA project participants to obtain value from the PECs,
while minimizing the transactional risk to SCPPA and its Members. Within the agreement, Tenaska
agrees to purchase 1,895,505 MWh of PECs from vintage year 2016 through March 31, 2026 for a
price of $8.00/MWh, for a total of $15,164,040.42. Additionally, Tenaska agrees to transfer all funds to
SCPPA prior to the receipt of PECs, thereby eliminating the risk of non-payment.
ENVIRONMENTAL REVIEW:
This action is exempt from the California Environmental Quality Act (“CEQA”) pursuant to Section
15061(b)(3) of the CEQA guidelines (the “common sense” exemption) as it can be seen with certainty
that there is no possibility that the sale of the Portfolio Energy Credits associated with the existing PPAs
may have a significant effect on the environment.
SCPPA’S AUTHORITY:
The proposed Agreement is in accordance with the California Joint Exercise of Powers Act and the
SCPPA Joint Powers Agreement. The SCPPA Joint Powers Agreement provides SCPPA with the
authority to develop, finance, construct, operate and maintain electric energy generation and
transmission projects and to enter into contracts in connection therewith, including this proposed
contract for the sale of SCPPA’s PECs associated with SCPPA’s Nevada geothermal projects.
FISCAL IMPACT:
Pursuant to Section 5.1 of the Power Sales Agreements between SCPPA and each of the Participants
that are associated with the PPAs, SCPPA will provide to Participants all product, rights, and benefits
AGENDA STAFF REPORT TEMPLATE

Page 2 of 3

v.8/6/2019

Docusign Envelope ID: E8C2D46E-08EF-8811-8300-1817C189D20E

from the Project, and Participants will be responsible to pay for all costs, liabilities and obligations
associated with the acquisition of such product rights, and benefits from the Project. All net revenue
from the sale of the PECs will be paid to Participants in accordance with their respective project
participation shares under the Power Sales Agreements.
ATTACHMENTS:
1. Resolution 2026-097
2. Tenaska WSPP Confirmation Agreement
3. WSPP Agreement effective October 31, 2025

AGENDA STAFF REPORT TEMPLATE

Page 3 of 3

v.8/6/2019

Project Vote
RESOLUTION NO. 2026-097
RESOLUTION OF THE BOARD OF DIRECTORS OF THE
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
APPROVING AND AUTHORIZING EXECUTION OF A
CONFIRMATION AGREEMENT WITH TENASKA POWER
SERVICES, CO. FOR THE SALE OF CERTAIN ENVIRONMENTAL
ATTRIBUTES ASSOCIATED WITH GEOTHERMAL PROJECTS
LOCATED IN THE STATE OF NEVADA
WHEREAS, the Southern California Public Power Authority (“SCPPA”) was
created pursuant to the Joint Exercise of Powers Act found in Chapter 5 of Division 7 of Title 1 of
the Government Code of California, as amended from time to time (the “Act”), by its members
(“Members”), which are municipalities and an irrigation district that supply, among other things,
electrical energy, in the State of California, for the purpose of jointly and cooperatively undertaking
the planning, financing, development, acquisition, construction, operation, maintenance and
repair of projects for the generation or transmission of electric energy and all rights, properties
and improvements necessary therefor, including fuel; and
WHEREAS, among the many projects from which SCPPA procures energy on
behalf of its Members are three geothermal energy projects located in the state of Nevada, to wit:
the Don A. Campbell Phase I Geothermal Energy Project (“Don Campbell I”), the Don A. Campbell
Phase II Geothermal Energy Project (“Don Campbell II”), and the Northern Nevada Geothermal
Portfolio Project (“NNGPP”) (collectively, “Projects”); and
WHEREAS, pursuant to the Power Purchase Agreements between SCPPA and
the owners of the Projects, SCPPA is entitled 100% of the energy and all associated
environmental attributes (including renewable energy credits) produced by the Projects; and
WHEREAS, SCPPA sells the energy and associated environmental attributes
procured from the Projects pursuant to Power Sales Agreements with two Members (“Project
Participants”), namely, the City of Los Angeles acting by and through the Department of Water
and Power (“LADWP”), which has an 84.62% entitlement share in Don Campbell I and 100%
entitlement shares in Don Campbell II and NNGPP, and the City of Burbank which has a 15.38%
entitlement share In Don Campbell I; and
WHEREAS, pursuant to the Power Sales Agreements entered into by each of the
Project Participants, SCPPA has undertaken administration of these project, and to provide by
agreement for the performance and carrying out of such activities; and
WHEREAS, due to differences in the laws of California and Nevada respecting the
use of renewable energy credits derived from geothermal energy plants, a portion of such credits
(herein “Portfolio Energy Credits” or “PECs”) are valueless in California but have value in Nevada,
and consequently the Project Participants desire to sell the PECs as a way of offsetting the cost
of their participation in the Projects: and
WHEREAS, LADWP sought and obtained bids from industry firms interested in
purchasing PECs generated by the Projects, and obtained one bid, from Tenaska Power Services
Co. (“Tenaska”), which the Project Participants have determined is fair and reasonable and which
they desire to accept; and

WHEREAS, SCPPA and the Projects Participants have negotiated a proposed
Confirmation Agreement with Tenaska under the Western System Power Pool (WSPP)
Agreement for the sale of the PECs for vintage year 2016 through March 31, 2026 and
recommend its approval by the Board.
NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of the Southern
California Public Power Authority as follows:
1.

The Confirmation Agreement between the Southern California Public Power
Authority and Tenaska Power Services Co., a form of which has been presented
to the Board substantially in final form, is hereby approved.

2.

The Executive Director or his designee is hereby authorized and directed to
execute and deliver the Confirmation Agreement with such changes, insertions
and omissions as shall be approved by the Executive Director or his designee.

3.

The Executive Director and other officers of the Authority are hereby authorized
and directed to execute and deliver any and all other documents and instruments
and to do and cause to be done any and all acts and things necessary or proper
for carrying out the transactions contemplated by this resolution.

4.

This resolution shall become effective immediately.

THE FOREGOING RESOLUTION is approved and adopted by the Authority this
17th day of September 2026.

MANDIP SAMRA
PRESIDENT
Southern California Public
Power Authority

ATTEST:

DANIEL E GARCIA
ASSISTANT SECRETARY
Southern California Public
Power Authority

2

Confirmation Agreement
This confirmation (“Confirmation”) confirms this transaction (“Transaction”) and is entered into
this __ day of September, 2026 (“Effective Date”), by and between the Southern California Public
Power Authority (“Seller”) and Tenaska Power Services Co. (“Purchaser” or “Buyer”), each referred
to herein individually as a “Party” and collectively as the “Parties”, regarding the purchase and sale
of the Product (as defined below) under the terms and conditions below. This Transaction is governed
by the WSPP Agreement effective as of October 31, 2025, as amended from time to time, hereby
incorporated by this reference (the “Master Agreement”). The Master Agreement and this
Confirmation contain the entire agreement of the Parties with respect to the Transaction, and no
agreement, statement or promise made by either Party which is not contained herein, shall be valid or
binding. The Master Agreement and this Confirmation shall be collectively referred to herein as the
“Agreement”. Capitalized terms used but not otherwise defined in this Confirmation are defined in
the Master Agreement.
Product:

Product means PECs generated pursuant to this Confirmation. All PECs shall
meet the requirements of applicable Nevada statutes and regulations and shall
qualify as geothermal related portfolio energy credits.

PEC Transfer:

Commencing from the Effective Date, Seller shall, at its sole expense, take all
actions and execute all documents or instruments necessary to ensure that all
PECs associated with the Product Quantity are issued and tracked for purposes
of satisfying the requirements of the Public Utility Commission of Nevada
(“PUCN”). Seller shall comply with all Applicable Laws, including, without
limitation, the PUCN Operating Rules, regarding the certification and transfer
of such PECs to Buyer and Buyer shall be given sole title to all such PECs.
Seller shall transfer, or shall cause the transfer of, such PECs to Buyer for
Buyer's sole benefit no later than five (5) Business Days immediately following
Buyer’s payment of the Total Contract Price to Seller. Upon receiving written
or electronic confirmation from NVTREC that a transfer order has been
initiated by Seller, Buyer shall confirm such transfer order in NVTREC within
five (5) Business Days. Upon either Party's receipt of notice from NVTREC
that a transfer of PECs was not recognized, that Party will immediately notify
the other Party, providing a copy of such notice, and both Parties will cooperate
in taking such actions as are necessary for NVTREC to recognize the transfer
of PECs, except that Seller shall be fully responsible for all such costs and
expenses if the failure of a PEC transfer arises from Seller's failure to comply
with Applicable Laws. Each Party agrees to provide copies of its records to
the extent reasonably necessary for NVTREC to verify the accuracy of any
fact, statement, charge or computation made pursuant hereto if requested by
the other Party. This Confirmation shall terminate on the date on which both
Parties have completed the performance of their obligations hereunder.

Product Quantity:

1,895,505.053 kPECs of Product generated by the geothermal resources
specified in Exhibit A attached hereto.
Page 1

Contract Price:

$8.00 per kPEC of Product

Total Contract Price: $15,164,040.42
Payment Terms:

Buyer will pay the Seller an amount equal to the Contract Price multiplied by
the Product Quantity transferred from Seller to Buyer through NVTREC
(“Total Contract Price”).
Buyer shall pay the Total Contract Price to Seller on or before the later of (i)
three (3) Business Days immediately following the Effective Date hereof, or
(ii) one (1) Business Day immediately following Buyer’s receipt of the Product
Attestation.

Contact
Information:

Seller
For Contract Notices:
Southern California Public Power Authority
1160 Nicole Court
Glendora, CA 91740
Contact: Executive Director
Tel: (626) 793-9364
Email: [email protected]
Fax: (626) 793-9461
For Billing Matters :
Southern California Public Power Authority
1160 Nicole Court
Glendora, CA 91740
Contact: Finance and Accounting
Tel: (626) 793-9364
Email: [email protected]; [email protected]
Fax: (626) 793-9461
Buyer
Tenaska Power Services Co.
300 East John Carpenter Freeway
Suite 1100
Irving, TX 75062
Contact: Director, Contract Administration
Tel: (817) 303-1860
Email: [email protected]

Seller’s
Representations
and Warranties:

Seller, and, if applicable, its successors, represents and warrants that: (i) Seller
conveys title to the Product to Buyer and Seller holds all rights to such Product
Page 2

for conveyance of such title to Buyer; (ii) Seller has not sold the Product to any
other entity and PECs to be purchased and sold pursuant to this Confirmation
are not in practice committed to another party; and (iii) all rights, title and
interest in and to the Product are free and clear of any taxes or security interests
except for any right or interest by any entity claiming through Buyer. In
addition, as an express condition to Buyer’s obligation to pay for and take
delivery of the Product Quantity of PECs hereunder, Seller shall deliver (or
cause to be delivered) an attestation regarding the Product Quantity of PECs in
a form reasonably acceptable to Buyer and executed by the generator(s) of such
PECs (the “Product Attestation”).
Credit Support:

None required for either party in respect of this Transaction.

Definitions:
In addition to terms defined elsewhere in this Confirmation, the following definitions shall have the
meanings set forth below:
“Applicable Laws” means any statute, law, treaty, rule, tariff, regulation, ordinance, code, permit,
enactment, injunction, order, writ, decision, authorization, judgment, decree or other legal or
regulatory determination or restriction by a court or Governmental Authority of competent
jurisdiction, or any binding interpretation of the foregoing, as any of them is amended or
supplemented from time to time, that apply to either or both of the Parties, the Product, or the terms
of the Confirmation.
“Business Day(s)” means any day other than a Saturday or Sunday or a United States national holiday.
United States holidays shall be holidays observed by Federal Reserve member banks in New York
City.
“Governmental Authority” means any federal, state, local or municipal government, governmental
department, commission, board, bureau, agency, or instrumentality, or any judicial, regulatory or
administrative body, or the WECC or any other transmission authority, having or asserting
jurisdiction over a Party or the Agreement.
“kPEC” means 1,000 PECs.
“NVTREC” means the Nevada Tracks Renewable Energy Credits system.
“PEC” means a portfolio energy credit, as defined in NRS 704.7803 et seq., and the Nevada Public
Utility Commission regulations implementing such statute.
“PUCN Operating Rules” means the operating rules and requirements adopted by the PUCN.
“WECC” means the Western Electricity Coordinating Council.

Page 3

[Signature page to follow]

Page 4

SOUTHERN CALIFORNIA PUBLIC
POWER AUTHORITY

TENASKA POWER SERVICES CO.

By: ____________________________

By: ____________________________

Name: ___________________________

Name: ___________________________

Title: ____________________________

Title: ____________________________

Date: ____________________________

Date: ____________________________

Signature Page to Confirmation Agreement

Exhibit A
PC Certificate No.

Facility Name

Energy Type

Credit Type

Certified PCs

202209GEGPS0000810760

Brady

Geothermal

Station Usage Credit

6,565,500

202212GEGPS0000813799

Brady

Geothermal

Station Usage Credit

13,799,200

202303GEGPS0000811244

Brady

Geothermal

Station Usage Credit

11,243,710

202306GEGPS000088254

Brady

Geothermal

Station Usage Credit

8,253,508

202309GEGPS000087366

Brady

Geothermal

Station Usage Credit

7,366,493

202312GEGPS000089442

Brady

Geothermal

Station Usage Credit

9,441,720

202403GEGPS000089884

Brady

Geothermal

Station Usage Credit

9,883,537

202406GEGPS000087074

Brady

Geothermal

Station Usage Credit

7,073,903

202409GEGPS000086979

Brady

Geothermal

Station Usage Credit

6,979,249

202412GEGPS000089205

Brady

Geothermal

Station Usage Credit

9,205,300

202503GEGPS000088847

Brady

Geothermal

Station Usage Credit

8,847,070

202506GEGPS000087340

Brady

Geothermal

Station Usage Credit

7,339,944

202509GEGPS000088380

Brady

Geothermal

Station Usage Credit

8,380,421

202512GEGPS0000810979

Brady

Geothermal

Station Usage Credit

10,978,602

202603GEGPS0000810553

Brady

Geothermal

Station Usage Credit

10,553,328

201903GEGNS000207040

Galena 2

Geothermal

Station Usage Credit

2,309,000

201906GEGNS000205346

Galena 2

Geothermal

Station Usage Credit

5,346,000

201909GEGNS000205521

Galena 2

Geothermal

Station Usage Credit

5,521,000

201912GEGNS000207427

Galena 2

Geothermal

Station Usage Credit

7,427,000

202003GEGNS000206177

Galena 2

Geothermal

Station Usage Credit

6,177,000

202006GEGNS000207009

Galena 2

Geothermal

Station Usage Credit

7,009,000

202009GEGNS000207008

Galena 2

Geothermal

Station Usage Credit

7,008,000

202012GEGNS0002011879

Galena 2

Geothermal

Station Usage Credit

11,879,000

202103GEGNS0002011916

Galena 2

Geothermal

Station Usage Credit

11,916,000

202106GEGNS000207731

Galena 2

Geothermal

Station Usage Credit

7,731,000

202109GEGNS0002012133

Galena 2

Geothermal

Station Usage Credit

12,133,000

202112GEGNS0002012309

Galena 2

Geothermal

Station Usage Credit

12,309,000

202203GEGNS0002011323

Galena 2

Geothermal

Station Usage Credit

11,323,000

202206GEGNS000208003

Galena 2

Geothermal

Station Usage Credit

8,003,000

202209GEGNS000207860

Galena 2

Geothermal

Station Usage Credit

7,860,000

202212GEGNS0002015816

Galena 2

Geothermal

Station Usage Credit

15,816,000

202303GEGNS0002010573

Galena 2

Geothermal

Station Usage Credit

10,573,441

202306GEGNS000209001

Galena 2

Geothermal

Station Usage Credit

9,000,675

202309GEGNS000209590

Galena 2

Geothermal

Station Usage Credit

9,589,975

202312GEGNS0002012195

Galena 2

Geothermal

Station Usage Credit

12,194,974

202403GEGNS0002010753

Galena 2

Geothermal

Station Usage Credit

10,753,141

202406GEGNS000208925

Galena 2

Geothermal

Station Usage Credit

8,925,110

202409GEGNS000209225

Galena 2

Geothermal

Station Usage Credit

9,224,992

Exhibit A

202412GEGNS0002011419

Galena 2

Geothermal

Station Usage Credit

11,418,730

202503GEGNS0002014376

Galena 2

Geothermal

Station Usage Credit

14,375,672

202506GEGNS0002013267

Galena 2

Geothermal

Station Usage Credit

13,266,821

202509GEGNS0002010653

Galena 2

Geothermal

Station Usage Credit

10,653,223

202512GEGNS0002013445

Galena 2

Geothermal

Station Usage Credit

13,444,970

202603GEGNS0002011684

Galena 2

Geothermal

Station Usage Credit

11,684,266

201609GEGNS0004110715

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,122,700

201612GEGNS0004110639

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,639,000

201703GEGNS0004110158

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,158,100

201706GEGNS000419718

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

9,717,600

201709GEGNS000419796

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

9,796,000

201712GEGNS0004110551

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,551,000

201803GEGNS0004110224

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,224,000

201806GEGNS000418783

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

8,783,000

201809GEGNS000417715

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

7,715,000

201812GEGNS000417182

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

7,181,600

201903GEGNS000419825

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

9,824,800

201906GEGNS000419807

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

9,806,700

201909GEGNS000418719

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

8,718,700

201912GEGNS0004110447

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,447,200

202003GEGNS0004110722

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,722,000

202006GEGNS0004110796

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,796,400

202009GEGNS0004110990

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,989,600

202012GEGNS0004110999

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,998,700

202103GEGNS0004111034

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

11,033,900

202106GEGNS0004110193

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,193,100

202109GEGNS0004111022

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

11,021,500

202112GEGNS0004110025

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,025,100

202203GEGNS0004110293

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,293,100

202206GEGNS000417068

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

7,067,500

202209GEGNS000417047

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

7,046,600

202212GEGNS0004116028

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

16,028,000

202303GEGNS0004110127

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,126,557

202306GEGNS0004110063

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,062,659

202309GEGNS0004110130

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,130,054

202312GEGNS0004110222

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,222,049

202403GEGNS0004110238

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,238,145

202406GEGNS0004110693

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,693,006

202409GEGNS0004110588

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,587,753

202412GEGNS0004111091

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

11,090,777

202503GEGNS0004110788

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,788,243

Exhibit A

202506GEGNS0004110664

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,664,280

202509GEGNS0004110751

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,751,272

202512GEGNS0004111294

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

11,294,113

202603GEGNS0004110736

ORNI 37 Don A Campbell 2

Geothermal

Station Usage Credit

10,736,230

201812GEGNS000492332

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

2,279,007

201903GEGNS000497749

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

7,748,728

201906GEGNS000496996

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

6,995,850

201912GEGNS000497414

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

7,414,218

202003GEGNS000496620

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

6,619,546

202006GEGNS000496806

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

6,805,629

202009GEGNS000496928

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

6,928,168

202012GEGNS000496971

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

6,970,884

202103GEGNS000495771

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

5,771,182

202106GEGNS000499527

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

9,527,127

202109GEGNS0004911460

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

11,459,531

202112GEGNS0004913643

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

13,643,166

202203GEGNS0004914197

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

14,196,523

202206GEGNS0004911802

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

11,802,112

202209GEGNS000498398

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

8,397,707

202212GEGNS0004913212

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

13,212,314

202303GEGNS0004910444

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

10,444,118

202306GEGNS000499749

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

9,748,918

202309GEGNS0004911040

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

11,039,991

202312GEGNS0004911507

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

11,506,562

202403GEGNS0004913167

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

13,166,837

202406GEGNS0004911865

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

11,864,712

202409GEGNS0004913828

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

13,827,772

202412GEGNS000499349

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

9,348,559

202503GEGNS0004913269

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

13,269,301

202506GEGNS0004911013

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

11,012,933

202509GEGNS0004913456

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

13,456,207

202512GEGNS0004912751

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

12,751,227

202603GEGNS0004913741

ORNI 41 McGinness Hills 3

Geothermal

Station Usage Credit

13,740,805

201712GEGNS000473595

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

3,595,200

201803GEGNS000477292

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,291,500

201806GEGNS000474051

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

4,051,000

201809GEGNS000476553

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

6,553,000

201812GEGNS000475978

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

5,978,050

201903GEGNS000477592

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,592,400

201906GEGNS000476644

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

6,644,400

201909GEGNS000477666

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,665,895

Exhibit A

201912GEGNS000477325

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,324,730

202003GEGNS000477164

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,163,517

202006GEGNS000477918

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,918,400

202009GEGNS000478586

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

8,586,008

202012GEGNS000477933

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,932,742

202103GEGNS000478408

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

8,408,214

202106GEGNS000478954

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

8,954,379

202109GEGNS000478237

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

8,236,583

202112GEGNS000478445

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

8,445,000

202203GEGNS000477486

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,485,800

202206GEGNS000479862

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

9,861,850

202209GEGNS000478509

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

8,509,128

202212GEGNS0004714831

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

14,830,950

202303GEGNS0004712190

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

12,189,755

202306GEGNS0004711332

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

11,332,195

202309GEGNS0004710779

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

10,778,902

202312GEGNS0004711532

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

11,531,779

202403GEGNS000479020

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

9,019,951

202406GEGNS000478685

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

8,684,775

202409GEGNS000477572

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,571,630

202412GEGNS000477995

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,995,173

202503GEGNS000477838

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,837,913

202506GEGNS000476135

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

6,135,326

202509GEGNS000476833

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

6,832,844

202512GEGNS000477321

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,320,574

202603GEGNS000477013

ORNI 43 LLC-Tungsten

Geothermal

Station Usage Credit

7,013,374

202212GEGPS000128226

Steamboat 2

Geothermal

Station Usage Credit

1,090,435

202303GEGPS000125896

Steamboat 2

Geothermal

Station Usage Credit

5,896,075

202306GEGPS000121562

Steamboat 2

Geothermal

Station Usage Credit

1,561,553

202309GEGPS000127100

Steamboat 2

Geothermal

Station Usage Credit

7,099,620

202312GEGPS000127951

Steamboat 2

Geothermal

Station Usage Credit

7,950,957

202403GEGPS000126707

Steamboat 2

Geothermal

Station Usage Credit

6,707,003

202406GEGPS000124159

Steamboat 2

Geothermal

Station Usage Credit

4,158,939

202409GEGPS000124499

Steamboat 2

Geothermal

Station Usage Credit

4,498,532

202412GEGPS000126473

Steamboat 2

Geothermal

Station Usage Credit

6,472,500

202503GEGPS000125697

Steamboat 2

Geothermal

Station Usage Credit

5,696,593

202506GEGPS000124758

Steamboat 2

Geothermal

Station Usage Credit

4,757,978

202509GEGPS000124757

Steamboat 2

Geothermal

Station Usage Credit

4,756,865

202512GEGPS000126347

Steamboat 2

Geothermal

Station Usage Credit

6,346,969

202603GEGPS000125976

Steamboat 2

Geothermal

Station Usage Credit

5,976,245

202212GEGPS000136622

Steamboat 3

Geothermal

Station Usage Credit

1,198,145

Exhibit A

202303GEGPS000134274

Steamboat 3

Geothermal

Station Usage Credit

4,273,568

202306GEGPS000131911

Steamboat 3

Geothermal

Station Usage Credit

1,910,641

202309GEGPS000139521

Steamboat 3

Geothermal

Station Usage Credit

9,521,032

202312GEGPS000138766

Steamboat 3

Geothermal

Station Usage Credit

8,766,207

202403GEGPS000137401

Steamboat 3

Geothermal

Station Usage Credit

7,400,718

202406GEGPS000135239

Steamboat 3

Geothermal

Station Usage Credit

5,239,073

202409GEGPS000135876

Steamboat 3

Geothermal

Station Usage Credit

5,876,269

202412GEGPS000137414

Steamboat 3

Geothermal

Station Usage Credit

7,414,289

202503GEGPS000136717

Steamboat 3

Geothermal

Station Usage Credit

6,717,173

202506GEGPS000135825

Steamboat 3

Geothermal

Station Usage Credit

5,824,640

202509GEGPS000136871

Steamboat 3

Geothermal

Station Usage Credit

6,871,492

202512GEGPS000138524

Steamboat 3

Geothermal

Station Usage Credit

8,524,274

202603GEGPS000137715

Steamboat 3

Geothermal

Station Usage Credit

7,714,995

201606GEGPS0000723199

Steamboat Hills

Geothermal

Station Usage Credit

23,198,896

201606GEGPS000074199

Steamboat Hills

Geothermal

Station Usage Credit

4,199,104

201803GEGPS000072707

Steamboat Hills

Geothermal

Station Usage Credit

775,430

201806GEGPS000071514

Steamboat Hills

Geothermal

Station Usage Credit

1,514,000

201809GEGPS000071855

Steamboat Hills

Geothermal

Station Usage Credit

1,855,000

201812GEGPS000073301

Steamboat Hills

Geothermal

Station Usage Credit

3,301,000

201903GEGPS000073700

Steamboat Hills

Geothermal

Station Usage Credit

3,700,000

201906GEGPS000075468

Steamboat Hills

Geothermal

Station Usage Credit

5,468,000

201909GEGPS000075304

Steamboat Hills

Geothermal

Station Usage Credit

5,304,000

201912GEGPS000073345

Steamboat Hills

Geothermal

Station Usage Credit

3,345,000

202003GEGPS000073458

Steamboat Hills

Geothermal

Station Usage Credit

3,458,000

202006GEGPS000074881

Steamboat Hills

Geothermal

Station Usage Credit

4,881,100

202009GEGPS000079107

Steamboat Hills

Geothermal

Station Usage Credit

9,106,800

202012GEGPS0000710135

Steamboat Hills

Geothermal

Station Usage Credit

10,134,600

202103GEGPS000079568

Steamboat Hills

Geothermal

Station Usage Credit

9,567,600

202106GEGPS000074740

Steamboat Hills

Geothermal

Station Usage Credit

4,739,600

202109GEGPS000076418

Steamboat Hills

Geothermal

Station Usage Credit

6,418,200

202112GEGPS000076293

Steamboat Hills

Geothermal

Station Usage Credit

6,292,573

202203GEGPS000076080

Steamboat Hills

Geothermal

Station Usage Credit

6,079,700

202206GEGPS000073926

Steamboat Hills

Geothermal

Station Usage Credit

3,925,800

202209GEGPS000071995

Steamboat Hills

Geothermal

Station Usage Credit

1,994,500

202212GEGPS000073601

Steamboat Hills

Geothermal

Station Usage Credit

3,601,000

202303GEGPS000075430

Steamboat Hills

Geothermal

Station Usage Credit

5,429,847

202306GEGPS000074342

Steamboat Hills

Geothermal

Station Usage Credit

4,342,249

202309GEGPS000074967

Steamboat Hills

Geothermal

Station Usage Credit

4,966,930

202312GEGPS000076076

Steamboat Hills

Geothermal

Station Usage Credit

6,075,931

202403GEGPS000075672

Steamboat Hills

Geothermal

Station Usage Credit

5,672,475

202406GEGPS000074667

Steamboat Hills

Geothermal

Station Usage Credit

4,667,341

Exhibit A

202409GEGPS000074640

Steamboat Hills

Geothermal

Station Usage Credit

4,639,801

202412GEGPS000075560

Steamboat Hills

Geothermal

Station Usage Credit

5,559,721

202503GEGPS000075595

Steamboat Hills

Geothermal

Station Usage Credit

5,594,747

202506GEGPS000074769

Steamboat Hills

Geothermal

Station Usage Credit

4,768,778

202509GEGPS000074903

Steamboat Hills

Geothermal

Station Usage Credit

4,902,545

202512GEGPS000075622

Steamboat Hills

Geothermal

Station Usage Credit

5,621,602

202603GEGPS000075244

Steamboat Hills

Geothermal

Station Usage Credit

5,244,429

202203GEGNS000339509

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

9,508,600

202206GEGNS000336098

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

6,097,700

202209GEGNS000336639

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

6,639,300

202212GEGNS0003314961

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

14,960,500

202303GEGNS000339570

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

9,569,564

202306GEGNS000339505

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

9,505,206

202309GEGNS000339223

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

9,222,604

202312GEGNS000339781

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

9,780,812

202403GEGNS000339249

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

9,248,696

202406GEGNS000338937

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

8,936,632

202409GEGNS000338723

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

8,723,026

202412GEGNS000339109

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

9,108,639

202503GEGNS000338942

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

8,942,265

202506GEGNS000338874

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

8,873,918

202509GEGNS000338701

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

8,701,477

202512GEGNS0003316824

Wild Rose/Don Campbell

Geothermal

Station Usage Credit

16,823,951

Total PECs

1,895,505,053

Exhibit A

WSPP Agreement
Changes Effective October 31, 2025
This version includes all revisions approved by the Federal Energy Regulatory Commission
(FERC) in orders issued through January 9, 2026. The most recent revisions are to update the the
List of Members within the Agreement, per the FERC’s unpublished letter order dated January 9,
2026 (Docket No. ER26-512-000). The FERC accepted the revisions effective October 31, 2025
for the metadata and, for each change in the Member List, on the applicable date of the change as
stated in its order.
This version of the WSPP Agreement is prepared for the convenience of WSPP Members. The
WSPP Agreement as filed with the FERC is available at www.FERC.gov and specifically
http://etariff.ferc.gov/TariffList.aspx.
This explanatory page is not part of the WSPP Agreement and is not filed with the FERC.

WSPP AGREEMENT
WSPP INC.
FIRST REVISED RATE SCHEDULE FERC NO. 6
Superseding
Rate Schedule FERC No. 6

© WSPP Inc. 2003
All rights reserved

TABLE OF CONTENTS
1.

PARTIES

2.

RECITALS

3.

AGREEMENT

4.

DEFINITIONS

5.

TERM, TERMINATION AND WITHDRAWAL

6.

SERVICE SCHEDULES AND WSPP DEFAULT TRANSMISSION TARIFF

7.

ADMINISTRATION

8.

EXECUTIVE AND OPERATING COMMITTEES

9.

PAYMENTS

10.

UNCONTROLLABLE FORCES

11.

WAIVERS

12.

NOTICES

13.

APPROVALS AND EFFECTIVENESS

14.

TRANSFER OF INTEREST IN AGREEMENT

15.

SEVERABILITY

16.

MEMBERSHIP

17.

RELATIONSHIP OF PARTIES

18.

NO DEDICATION OF FACILITIES

19.

NO RETAIL SERVICES

20.

THIRD PARTY BENEFICIARIES

21.

LIABILITY AND DAMAGES

22.

DEFAULT OF TRANSACTIONS UNDER THIS AGREEMENT AND
CONFIRMATIONS

22A.

DEFAULT IN PAYMENT OF WSPP OPERATING COSTS

23.

OTHER AGREEMENTS

24.

GOVERNING LAW

25.

JUDGMENTS AND DETERMINATIONS

26.

COMPLETE AGREEMENT

27.

CREDITWORTHINESS

28.

NETTING

29.

TAXES

30.

CONFIDENTIALITY

31.

TRANSMISSION TARIFF

32.

TRANSACTION SPECIFIC TERMS AND ORAL AGREEMENTS

33.

PERFORMANCE, TITLE, AND WARRANTIES FOR TRANSACTIONS
UNDER SERVICE SCHEDULES

34.

DISPUTE RESOLUTION

35.

FORWARD CONTRACTS

36.

TRADE OPTION EXEMPTION

37.

ADDITIONAL REPRESENTATIONS AND WARRANTIES

38.

FLOATING PRICES

39.

AMENDMENT

40.

EXECUTION BY COUNTERPARTS

41.

WITNESS

EXHIBIT A: NETTING
EXHIBIT B: FORM OF COUNTERPARTY GUARANTEE AGREEMENT

EXHIBIT C: SAMPLE FORM FOR CONFIRMATION
EXHIBIT D: WSPP MEDIATION AND ARBITRATION PROCEDURES
SERVICE SCHEDULES
A.

ECONOMY ENERGY SERVICE

B.

UNIT COMMITMENT SERVICE

C.

FIRM CAPACITY/ENERGY SALE OR EXCHANGE SERVICE

D.

OPERATING RESERVE – SPINNING AND OPERATING RESERVE –
SUPPLEMENTAL

E.

ENERGY IMBALANCE AND GENERATOR IMBALANCE POWER

R.

RENEWABLE ENERGY CERTIFICATE TRANSACTIONS WITH AND
WITHOUT ENERGY

SCHEDULE Q: FERC ACCEPTED SELLER-SPECIFIC COST-BASED RATE SCHEDULES
LIST OF MEMBERS

1.

PARTIES:
The Parties to this WSPP Agreement (hereinafter referred to as "Agreement") are
those entities that have executed this Agreement, hereinafter sometimes referred to
individually as "Party" and collectively as "Parties," but excluding any such entity
that withdraws its participation in the Agreement. An entity shall become a Party
on the date specified in Section 16.6.

2.

RECITALS
2.1

Through this Agreement, the WSPP administers a multi-lateral, standardized
agreement applicable to capacity and/or energy transactions between members and
is available to entities (which qualify for membership under Section 16) throughout
the entire continental United States, Canada, and Mexico.

2.2

This Agreement serves two functions. First, it sets out the rules applicable to the
operation of the WSPP. Second, it sets out the terms for the standardized agreement
used for capacity and/or energy transactions between members.

2.3

This Agreement facilitates physical transactions in capacity and/or energy under a
FERC accepted or approved rate schedule (this Rate Schedule FERC No. 6).

2.4

Through the standardization of terms for transactions in capacity and/or energy
which facilitates such transactions, the public interest has been and will continue to
be served.

3.

AGREEMENT:
In consideration of the mutual covenants and promises herein set forth, the Parties
agree as follows:

4.

DEFINITIONS:
The following terms, when used herein with initial capitalization, whether in the singular
or in the plural, shall have the meanings specified:
Agreement:

This WSPP Agreement, including the Service Schedules and Exhibits

attached hereto, as amended; provided, however, that Confirmation(s) are not
included within this definition.
Administrative Committee: A sub-committee of the Executive Committee in accordance
with Section 8.1.2.
Broker: An entity or person that arranges trades or brings together Purchasers and Sellers
without taking title to the power.
Business Day(s): Any day other than a Saturday or Sunday or a national (United States or
Canadian, whichever is applicable) holiday. United States holidays shall be
holidays observed by Federal Reserve member banks in New York City. Where
both the Seller and the Purchaser have their principal place of business in the United
States, Canadian holidays shall not apply. Similarly, where both the Seller and the
Purchaser have their principal places of business in Canada, Canadian holidays
shall apply and United States holidays shall not apply. In situations where one
Party has its principal place of business within the United States and the other
Party's principal place of business is within Canada, both United States and
Canadian holidays shall apply.
California ISO: The California Independent System Operator Corporation or any successor
organization.

Confirmation(s): The confirmations for transactions developed and made effective in
accordance with Section 32 or Electronic Platform Confirmations.
Contract Price: The price agreed to between the Seller and the Purchaser for a transaction
under the Agreement and Confirmation.
Contract Quantity: The amount of capacity and/or energy to be supplied for a transaction
under the Agreement.
Control Area: An electric system capable of regulating its generation in order to maintain
its interchange schedule with other electric systems and to contribute its frequency
bias obligation to the interconnection as specified in the North American Electric
Reliability Council (NERC) Operating Guidelines.
Costs: As defined in Section 22.3 of this Agreement.
Damages Settlement Transaction: A transaction where, after non-performance under a
Confirmation, the Parties enter into a second transaction for the purpose of finally
settling damages incurred by the Performing Party due to non-performance of such
Confirmation.
Dealer: An entity or person that buys or sells power and takes title to the power at some
point.
Demand Response: A reduction in the consumption of electric energy by customers from
their expected consumption in response to an increase in the price of electric energy
or to incentive payments designed to induce lower consumption of electric energy.
Demand Response Entity: An entity or lawful association which is not an Electric Utility,
Qualifying Facility, or Retail Entity, which sells or otherwise provides Demand
Response through wholesale transactions.

Defaulting Party: As defined in Section 22.1 of this Agreement.
Determination Period: As defined in Section 38.2 of this Agreement.
Documentary Writing: A document which is physically delivered by courier or U.S. mail,
or a copy of which is transmitted by telefacsimile or other electronic means.
Economy Energy Service: Non-firm energy transaction whereby the Seller has agreed to
sell or exchange and the Purchaser has agreed to buy or exchange energy that is
subject to immediate interruption upon notification, in accordance with the
Agreement, including Service Schedule A, and any applicable Confirmation.
Electric Utility: An entity or lawful association which (i) is a public utility, Independent
Power Producer, or Power Marketer regulated under applicable state law or the
Federal Power Act, or (ii) is exempted from such regulation under the Federal
Power Act because it is the United States, a State or any political subdivision
thereof or an agency of any of the foregoing, or a Rural Utilities Service
cooperative, or (iii) is a public utility, Independent Power Producer, or Power
Marketer located in Canada or Mexico that is similarly regulated.
Electronic Platform Confirmation: agreed terms and conditions of a transaction, which
agreement (a) was made through electronic entry of information and terms on, and
in a manner that complies with the procedures of, the applicable electronic trading
platform or exchange, (b) includes, at a minimum, the Standard Confirmation
Provisions, and (c) is available to either Party for retrieval from the applicable
electronic trading platform or exchange in printable or electronic form.
Electronic Writing:
(1)

Recorded oral conversation; or

(2)

electronic communications, including but not limited to e-mail, if the Parties
to the transaction use such method to create an electronic writing for the
Confirmation for such transaction and, except with respect to e-mail,
specifically agree to the method of electronic communication.
Electronic Writings shall not include the transmittal of a copy of a document
by electronic means, which is considered a Documentary Writing.

ERCOT: Electric Reliability Council of Texas, Inc., and any successor organization.
Event of Default: As defined in Section 22.1 of this Agreement.
Executive Committee: The committee established pursuant to Section 8 of this Agreement.
FERC: The Federal Energy Regulatory Commission or its regulatory successor.
Firm Capacity/Energy Sale or Exchange Service: Firm capacity and/or energy transaction
whereby the Seller has agreed to sell or exchange and the Purchaser has agreed to
buy or exchange for a specified period available capacity with or without associated
energy which may include a Physically-Settled Option and a capacity transaction
in accordance with the Agreement, including Service Schedule C, and any
applicable Confirmation.
First Party: As defined in Section 27 of this Agreement.
Floating Price: As defined in Section 38.1 of this Agreement.
Gains: As defined in Section 22.3 of this Agreement.
Guarantee Agreement: An agreement providing a guarantee issued by a parent company
or another entity guaranteeing responsibility for obligations arising under this
Agreement and Confirmation. A sample form of Guarantee Agreement is provided
in Exhibit B.

Guarantor: The entity providing a guarantee pursuant to a Guarantee Agreement.
Hub: An electronic communication center that functions as a central point to electronically
receive and assemble data for offers to buy or sell power or transmission service
from each Party and make that data electronically available concurrently to all
Parties.
Incremental Cost: The forecasted expense incurred by the Seller in providing an additional
increment of energy or capacity during a given hour.
Independent Power Producer: An entity which is a non-traditional public utility that
produces and sells electricity but which does not have a retail service franchise.
Letter of Credit: An irrevocable, transferable, standby letter of credit, issued by an issuer
acceptable to the Party requiring the Letter of Credit.
Losses: As defined in Section 22.3 of this Agreement.
Market Disruption Event: As defined in Section 38.2 of this Agreement.
NERC: North American Electric Reliability Council or any successor organization.
Non-Defaulting Party: As defined in Section 22.1(a) of this Agreement.
Non-Performing Party: As defined in Section 21.3(a) of this Agreement.
Non-Standard Confirmation Provisions: Provisions other than Standard Confirmation
Provisions.
NYMEX: New York Mercantile Exchange and any successor organization.
Operating Agent:

An agent of the WSPP as may be designated by the Executive

Committee from time to time.
Operating Committee:
Agreement.

That committee established pursuant to Section 8 of this

Party or Parties: As defined in Section 1 of this Agreement.
Performing Party: As defined in Section 21.3(a) of this Agreement.
Power Marketer:

An entity which buys, sells, and takes title to electric energy,

transmission and/or other services from traditional utilities and other suppliers.
Physically-Settled Option: Includes (i) a call option which is the right, but not the
obligation, to buy an underlying power product as defined under Service Schedules
B or C according to the price and exercise terms set forth in the Confirmation; and
(ii) a put option which is the right, but not the obligation, to sell an underlying
power product as defined under Service Schedules B or C according to the price
and exercise terms set forth in the Confirmation.
Premium: The amount paid by the Purchaser of a Physically-Settled Option to the Seller
of such option by the date agreed to by the Parties in the Confirmation.
Present Value Rate: As defined in Section 22.3(b) of this Agreement.
Purchaser: Any Party which agrees to buy or receive from one or more of the other Parties
any service pursuant to the Agreement and any applicable Confirmation.
Qualifying Facility: A facility which is a qualifying small power production facility or a
qualifying cogeneration facility as these terms are defined in Federal Power Act
Sections 3(17)(A), 3(17)(C), 3(18)(A), and 3(18)(B); which meets the requirements
set forth in 18 C.F.R. §§ 292.203-292.209; or a facility in Canada or Mexico that
complies with similar requirements.
Replacement Price: The price at which the Purchaser, acting in a commercially reasonable
manner, effects a purchase of substitute capacity and/or energy in place of the
capacity and/or energy not delivered (for energy) or made available (for capacity

only) by the Seller or, absent such a purchase, the market price for such quantity of
capacity and/or energy, as determined by the Purchaser in a commercially
reasonable manner, at the delivery point specified for the transaction in the
Confirmation.
Resale Price: The price at which the Seller, acting in a commercially reasonable manner,
effects a resale of the capacity and/or energy not received by the Purchaser or,
absent such a resale, the market price for such quantity of capacity and/or energy,
as determined by the Seller in a commercially reasonable manner at the delivery
point specified for the transaction in a Confirmation.
Retail Entity: A retail aggregator or supplier or retail customer; provided, however, only
those Retail Entities eligible for transmission service under the FERC’s pro forma
open access transmission tariff are eligible to become members of the WSPP.
Second Party: As defined in Section 27 of this Agreement.
Seller: Any Party which agrees to sell or provide to one or more of the other Parties any
service pursuant to the Agreement and the applicable Confirmation.
Service Schedule: A schedule of services established pursuant to Section 6 of this
Agreement on file with FERC as part of this Agreement.
Standard Confirmation Provisions: Provisions setting forth: Seller, Purchaser, period of
delivery, schedule, delivery rate, delivery points, type of service (e.g. Service
Schedule A, B, C or other), contract quantity, price, transmission path (if any), date,
and certain additional information for physically settled options (option type,
option style, exercise date or period, premium, premium payout date, and method
for providing notice of exercise).

Successor in Operation: The successor entity which takes over the wholesale electric
trading operations of the first entity either through a merger or restructuring. A
Successor in Operation shall not include an entity which merely acquires power
sales contracts from the first entity either through a purchase or other means without
taking over the wholesale electric trading operations of the first entity.
Terminated Transaction: As defined in Section 22.2 of this Agreement.
Termination Payment: As defined in Section 22.2 of this Agreement.
Trading Day: As defined in Section 38.2 of this Agreement.
Uncontrollable Forces: As defined in Section 10 of this Agreement or in a Confirmation.
Unit Commitment Service: A capacity and/or associated scheduled energy transaction or a
Physically-Settled Option under which the Seller has agreed to sell and the
Purchaser has agreed to buy from a specified unit(s) for a specified period, in
accordance with the Agreement, including Service Schedule B, and any applicable
Confirmation.
WSPP: WSPP Inc., a corporation organized in 1995 and duly existing under the Utah
Revised Nonprofit Corporation Act.
WSPP Default Transmission Tariff: The transmission tariff filed on behalf of WSPP
members with FERC as it may be amended from time to time.
WSPP Homepage: WSPP’s internet web site, www.wspp.org.

5.

TERM, TERMINATION AND WITHDRAWAL:
5.1

This Agreement shall remain in effect until the Executive Committee, consistent
with the voting provisions of Section 8.3, votes to terminate this Agreement and
FERC accepts that termination, or FERC otherwise terminates the Agreement.

5.2

Any Party may withdraw its participation as a member of the WSPP and as a Party
to this Agreement by providing thirty (30) days prior written notice to the Operating
Agent and to the WSPP Homepage, and to all of its counterparties to outstanding
transactions. As of the effective date of any withdrawal, the withdrawing Party
shall have no further rights or obligations under this Agreement or as a member of
the WSPP, except with respect to each outstanding Confirmation, all outstanding
rights and obligations arising under any such Confirmation and this Agreement
shall remain in full force and effect as if the withdrawal had not occurred. No Party
shall oppose, before any court or regulatory agencies having jurisdiction, any other
Party's withdrawal as provided in this Section.

5.3

Except as provided for in Section 5.2, after termination, or withdrawal with respect
to the withdrawing Party, all rights to services provided under this Agreement shall
cease, and no Party shall claim or assert any continuing right to such services
thereunder. Except as provided in Section 5.2, no Party shall be required to provide
services based in whole or in part on the existence of this Agreement or on the
provision of services under this Agreement beyond the termination date, or date of
withdrawal with respect to the withdrawing Party. If the Parties have entered into
a master confirmation agreement only for WSPP transactions as that term is defined
in Section 32.10, the withdrawing Party shall have no further rights under that

master confirmation agreement except for transactions that were outstanding at the
time of the withdrawal.
5.4

The Parties subject to FERC jurisdiction under the Federal Power Act shall have
the right to terminate their participation as a Member of the WSPP and as Party to
this Agreement and any Confirmation without the necessity of filing with or
approval by FERC, provided that such Parties comply with the requirements of
Section 5.2.

6.

SERVICE SCHEDULES AND WSPP DEFAULT TRANSMISSION TARIFF:
6.1

The Parties contemplate that they may, from time to time, add or remove Service
Schedules under this Agreement. The attached Service Schedules A through E for
Economy Energy Service, Unit Commitment Service, Firm Capacity/Energy Sale
or Exchange Service, Operating Reserve – Spinning and Operating Reserve –
Supplemental, and Energy Imbalance and Generator Imbalance Power, and Service
Schedule R for Renewable Energy Certificate Transactions With And Without
Energy, are incorporated into and made a part of this Agreement.

Nothing

contained herein shall be construed as affecting in any way the right of the Parties
to jointly make application to FERC for a change in the rates and charges,
classification, service, terms, or conditions affecting WSPP transactions under
Section 205 of the Federal Power Act and pursuant to FERC rules and regulations
promulgated thereunder. Additional Service Schedules or amendments to existing
Service Schedules, if any, shall be adopted only by amendment of this Agreement
approved by the Executive Committee pursuant to Section 8.3 and shall become
effective on the effective date allowed or accepted by FERC consistent with Section
39.
6.2

[RESERVED]

6.3

When the WSPP Default Transmission Tariff applies as specified in the preamble
to such Default Transmission Tariff, Transmission Service under it shall be
available both to Parties and non-Parties under this Agreement; provided, however,
each Party or non-Party must be an eligible customer under the WSPP Default
Transmission Tariff in order to receive service.

7.

ADMINISTRATION:
7.1

The WSPP shall perform the administrative tasks necessary and appropriate to
implement this Agreement. All authority to direct, manage and administer the
WSPP shall reside in the Executive Committee. All duties assigned under this
Agreement, or otherwise, to the Operating Committee, sub-committees, officers,
Administrative Committee, or Operating Agent, are delegated powers of the
Executive Committee and are subject to the Executive Committee’s direction and
control. The WSPP may engage the services of an Operating Agent, from time to
time, to perform tasks in furtherance of this Agreement.

7.2

At least sixty (60) days prior to each calendar year that this Agreement is in effect,
the Administrative Committee shall submit a budget for said year of operation to
the Operating Committee for review. The proposed budget shall then be submitted,
with the Operating Committee’s recommendations, to the Executive Committee.
The Executive Committee may approve the budget as submitted or with revisions.
The Administrative Committee, Operating Committee, and Executive Committee
shall address any appropriate revisions of the budget in the same manner.

7.3

The WSPP shall, as necessary, bill the Parties for costs incurred under this
Agreement on an estimated basis reasonably in advance of when due, and such
billings shall be paid by the Parties when due. Such billings shall be adjusted in
the following month(s) to reflect recorded costs. Billing and payment of WSPP
costs shall otherwise be implemented in accordance with the provisions of Section
9.

7.4

The WSPP shall maintain the WSPP Homepage and, as it deems appropriate, may
engage a contractor for this purpose.

7.5

Each Party shall maintain a link to the WSPP Homepage and shall be responsible
for expenses related thereto.

7.6

The WSPP, at reasonable times and places, shall make available its books of
account, and records and documentation supporting expenditures under this
Agreement, for the inspection of any Party for a period of time not to exceed two
(2) years from the time such expenditures were incurred. A Party requesting review
of the WSPP’s records shall give the WSPP sufficient notice of its intent, but in no
event less than thirty (30) days. The requesting Party may perform this review
using personnel from its own staff or designate a certified public accounting firm
for the purpose of this review. All costs incurred to perform this review shall be at
the requesting Party's own expense. The Party performing the review shall not
voluntarily release the WSPP’s records or disclose any information contained
therein to any third party unless the written consent of the WSPP and the Executive
Committee has been obtained, except as required by law.

7.7

Upon the termination of this Agreement, in accordance with applicable law, the
WSPP shall dispose of any and all of its assets and wind up its affairs as the
Executive Committee may direct.

8.

EXECUTIVE AND OPERATING COMMITTEES:
As a means of securing effective and timely cooperation within the activities
hereunder and as a means of dealing on a prompt and orderly basis with various problems
which may arise in connection with system coordination and operation under changing
conditions, the Parties hereby establish an Executive Committee and an Operating
Committee.
8.1

Executive Committee:
The Executive Committee shall consist of one representative and an
alternate from each Party designated pursuant to Section 8.5 herein.

The

responsibilities of the Executive Committee are as follows:
8.1.1

To establish and amend bylaws of the WSPP consistent with this
Agreement and to serve as the Board of Directors of the WSPP in
accordance with applicable law.

8.1.2

To establish standing or ad hoc sub-committees as it may from time to time
deem necessary or appropriate and appoint or elect members thereto. Such
sub-committees shall include an Administrative Committee, as a standing
committee, to administer the affairs of the WSPP as the Executive
Committee may direct or approve. The Administrative Committee shall be
comprised of the Chairman, Vice-Chairman, Secretary and Treasurer of the
WSPP and the Chairman, and Vice-Chairman, and Secretary of the
Operating Committee.

8.1.3

To review at least annually the service activities hereunder to ensure that
such activities are consistent with the spirit and intent of this Agreement.

8.1.4

To review any unresolved issues which may arise hereunder and endeavor
to resolve the issues.

8.1.5

To review and approve the WSPP’s annual budget under this Agreement,
and any revision thereto, in accordance with Section 7.2 of this Agreement
or otherwise as the Executive Committee deems necessary or appropriate.

8.1.6

To amend this Agreement, from time to time, provided that no such
amendment or restatement shall be effective unless approved or accepted
by the FERC and subject to terms and conditions of such approval or
acceptance. The effectiveness of any amendment also shall be consistent
with Section 39.

8.1.7

To review and act on the application of an entity to become a Party to this
Agreement, or to delegate such authority as the Executive Committee
deems appropriate.

8.1.8

To do such other things and carry out such duties as specifically required
or authorized by this Agreement.

8.1.9

To notify any Party of the rescission of its interest in this Agreement due
to its failure to continue to meet the requirements of Section 16.1, or to
delegate such authority to the Chairman of the Executive Committee, the
Chairman of the Operating Committee, or the Administrative Committee.

8.1.10 To arrange for legal representation of the WSPP.
8.2

Operating Committee:
The Operating Committee shall consist of one representative and an
alternate from each Party designated pursuant to Section 8.5. The responsibilities
of the Operating Committee are as follows:

8.2.1

To establish, review, approve, or modify procedures and standard practices,
consistent with the provisions hereof, for the guidance of operating
employees in the Parties' electric systems as to matters affecting
transactions under this Agreement.

8.2.2

To submit to the Executive Committee any proposed revisions to the
Service Schedules or proposed additional Service Schedules.

8.2.3

To submit to the Executive Committee proposed amendments to this
Agreement, provided that the Operating Committee shall have no authority
to amend this Agreement, and further provided that the Executive
Committee may amend this Agreement under Section 8.1.6 without having
first received recommendations from the Operating Committee.

8.2.4

To establish, review, approve, or modify any scheduling or operating
procedures required in connection with transactions under this Agreement.

8.2.5

To review and make recommendations to the Executive Committee for
approval of the annual budget of the WSPP under this Agreement, including
any proposed revisions thereto.

8.2.6

To review and recommend as necessary the types and arrangement of
equipment for intersystem communication facilities to enhance transactions
and benefits under this Agreement.

8.2.7

To monitor the administration and costs of the WSPP Homepage.

8.2.8

If the Executive Committee so directs, to review new member applications
for membership in the WSPP under this Agreement and make

recommendations on said applications to the Executive Committee, or to
delegate such authority as the Operating Committee deems appropriate.
8.2.9

To establish standing or ad hoc sub-committees and appoint or elect
members of the Operating Committee thereto, provided that such subcommittees shall make recommendations to the Operating Committee and
shall not be authorized to take any action or exercise any power reserved to
the Operating Committee. Each sub-committee may elect a chairman, vice
chairman, and secretary as it deems appropriate.

8.2.10 To do such other things and carry out such duties as specifically required or
authorized by this Agreement or as directed by the Executive Committee;
provided, however, that the Operating Committee shall have no authority to
amend this Agreement.
8.3

All matters which require Operating Committee or Executive Committee approval
as provided in this Agreement shall be by no less than ninety percent (90%)
affirmative agreement of the committee members present or voting by proxy.

8.4

Unless otherwise agreed by all committee members of the Executive Committee or
Operating Committee, as applicable, the Chairman of the Executive Committee and
the Chairman of the Operating Committee shall cause all members of the applicable
committee to receive notice of a committee meeting at least ten (10) Business Days
prior to the date of the meeting. Such notice shall include an agenda of matters to
be discussed and voted on at the meeting. All material issues to be submitted to a
vote of the committee shall appear on the agenda.

8.5

In accordance with Section 16.5.1, each Party shall give notice to the WSPP of the
name of its designated representative and alternate representative (to act in the
absence of the designated representative) on each of the Executive Committee and
Operating Committee, and of any changes thereto, and WSPP shall publish a listing
of all such representatives on the WSPP Homepage. Each Party's designated
representatives shall be authorized to act on its behalf with respect to votes taken
of members of each committee and other activities of the committee.

8.6

The Executive Committee shall meet no less than once annually and otherwise as
determined by its Chairman in his discretion. The Operating Committee shall meet
as necessary, as determined by its Chairman in his discretion. A Chairman shall
call a meeting of such committee upon the written request of not less than ten (10)
members of the applicable committee.

8.7

The Executive Committee shall elect a Chairman, Vice-Chairman, Secretary and
Treasurer. The Operating Committee shall elect a Chairman, Vice-Chairman, and
Secretary. These officers shall serve terms of two-years duration, which terms shall
commence on January 1 of the year following the election and expire on December
31 of the subsequent year, provided, that despite the expiration of an officer's term,
the officer shall continue to serve until the officer's successor is elected and
commences to serve, and further provided that with or without cause, the Executive
Committee or Operating Committee, as applicable, may elect a substitute officer prior
to the expiration of a term.
8.7.1

The Chairman of the Executive Committee shall be the Chairman of the
WSPP.

The Chairman shall preside over meetings of the Executive

Committee and, when the Executive Committee is not in session, exercise day
to day management and control of the business and affairs of the WSPP,
subject at all times to this Agreement and the direction of the Executive
Committee.
8.7.2

The Vice-Chairman of the Executive Committee shall be the Vice-Chairman
of the WSPP. The Vice-Chairman, in the absence or disability of the
Chairman, shall exercise the powers and perform the duties of the Chairman
and such other duties as the Executive Committee or the Chairman may
prescribe, subject at all times to this Agreement and the direction of the
Executive Committee.

8.7.3

The Secretary of the Executve Committee shall be the Secretary of the WSPP.
The Secretary, or his designee, shall record minutes of meetings and actions
of the Executive Committee, perform the customary duties of a secretary of a
non-profit corporation, and attend to the giving and serving of all notices
required by law or under this Agreement as the Chairman may direct.

8.7.4

The Treasurer of the Executive Committee shall be the Treasurer of the
WSPP.

The Treasurer shall have custody of all funds, securities, and

evidences of indebtedness of the Corporation. The Treasurer shall receive and
give receipts for moneys paid in on account of the Corporation and shall pay
out of the funds on hand any bills, payrolls and other just debts of the
Corporation of whatever nature upon maturity. The Treasurer shall maintain
full and accurate accounts of all moneys received and paid out on account of
the Corporation. The Treasurer shall deposit all moneys and other valuables

in the name and to the credit of the Corporation in such depositories as may
be designated by the Executive Committee. The Treasurer shall adhere to
budgets determined by the Executive Committee, including the annual budget
under section 8.1.4 of this Agreement, and shall perform such other duties as
are customary for a treasurer of a non-profit corporation.
8.7.5. The Chairman of the Operating Committee shall preside over Operating
Committee meetings. The Vice Chairman of the Operating Committee shall
serve in the absence of the Chairman and perform such other duties as the
Operating Committee may assign. The Secretary of the Operating Committee,
or his designee, shall record minutes of meetings and actions of the Operating
Committee, and shall give notice of meetings as the Chairman may direct.

9.

PAYMENTS:
9.1

The accounting and billing period for transactions under this Agreement shall be
one (1) calendar month. Bills sent to any Party shall be sent to the appropriate
billing address as set forth on the WSPP homepage or as otherwise specified by
such Party.

9.2

Payments for amounts billed under this Agreement and any Confirmation shall be
received by the Party to be paid on the 20th day of the month in which the invoice
was received or the tenth (10) day after receipt of the bill, whichever is later.
Notwithstanding the foregoing, Premiums shall be paid within three (3) Business
Days of receipt of the invoice. Payment shall be made at the location designated
by the Party to which payment is due. Payment shall be considered received when
payment is received by the Party to which Payment is due at the location designated
by that Party. If the due date falls on a non-Business Day of either Party, then the
payment shall be due on the next following Business Day.

9.3

Amounts not paid on or before the due date shall be payable with interest calculated
daily, at a rate equal to 200 basis points above the per annum Prime Rate reported
daily in the Wall Street Journal for the period beginning on the day after the due
date and ending on the day of payment, provided that such interest shall not exceed
the amount permitted by law.

9.4

In order to dispute a bill in whole or in part, a Party must provide written notice of
the dispute to the other Party to the transaction. Such written notice shall specify
the amount in dispute and state the basis for the dispute. In case any portion of any
bill is in dispute, the entire bill shall be paid when due. Any excess amount of bills

which, through inadvertent errors or as a result of a dispute, may have been
overpaid shall be returned by the owing Party upon determination of the correct
amount, with interest calculated in the manner set forth in Section 9.3. A Party
shall have the right to dispute the accuracy of any bill or payment only for a period
of two (2) years from the date on which the bill was initially delivered.
9.5

If a Party’s records reveal that a bill was not delivered, then the Party may deliver
to the appropriate Party a bill within two (2) years from the date on which the bill
would have been delivered under Section 9.1 of this Agreement. The right to
payment is waived with respect to any amounts not billed within such two (2) year
period.

9.6

Each Party, or any third party representative of a Party, shall keep complete and
accurate records, and shall maintain such data as may be necessary for the purpose
of ascertaining the accuracy of all relevant data, estimates, or statements of charges
submitted hereunder for a period of two (2) years from the date the bill was
delivered under this Agreement and/or Confirmation.
Within a two (2) year period from the date on which the bill was initially delivered,
any Party to the applicable transaction may request in writing copies of the records
of the other Party for that transaction to the extent reasonably necessary to verify
the accuracy of any statement or charge. The Party from which documents or data
has been requested shall provide all reasonably requested documents and data
within a reasonable time period.

10.

UNCONTROLLABLE FORCES:
No Party shall be considered to be in breach of this Agreement or any applicable
Confirmation to the extent that a failure to perform its obligations under this Agreement or
any such Confirmation is due to an Uncontrollable Force. The term "Uncontrollable Force"
means an event or circumstance which prevents one Party from performing its obligations
under one or more transactions, which event or circumstance is not within the reasonable
control of, or the result of the negligence of, the claiming Party, and which by the exercise
of due diligence the claiming Party is unable to avoid, cause to be avoided, or overcome.
So long as the requirements of the preceding sentence are met, an “Uncontrollable Force”
may include and is not restricted to flood, drought, earthquake, storm, fire, lightning,
epidemic, war, riot, act of terrorism, civil disturbance or disobedience, labor dispute, labor
or material shortage, sabotage, restraint by court order or public authority, and action or
nonaction by, or failure to obtain the necessary authorizations or approvals from, any
governmental agency or authority.
The following shall not be considered “Uncontrollable Forces”: (i) Seller’s cost of
obtaining capacity and/or energy; or (ii) Purchaser’s inability due to the price of the
capacity and/or energy, to use or resell such capacity and/or energy. No Party shall,
however, be relieved of liability for failure of performance to the extent that such failure is
due to causes arising out of its own negligence or due to removable or remediable causes
which it fails to remove or remedy within a reasonable time period. Nothing contained
herein shall be construed to require a Party to settle any strike or labor dispute in which it
may be involved. Any Party rendered unable to fulfill any of its obligations by reason of
an Uncontrollable Force shall give prompt notice of such fact and shall exercise due

diligence, as provided above, to remove such inability within a reasonable time period. If
oral notice is provided, it shall be promptly followed by written notice.
Where the entity providing transmission services for transactions under this
Agreement and Confirmation interrupts such transmission service, the interruption in
transmission service shall be considered an Uncontrollable Force under this Section 10
only in the following two sets of circumstances:
(1)

An interruption in transmission service shall be considered an Uncontrollable Force
if (a) the Parties agreed on a transmission path for that transaction in the
Confirmation (b) firm transmission involving that transmission path was obtained
pursuant to a transmission tariff or contract to effectuate the transaction under this
Agreement and Confirmation, and (c) the entity providing transmission service
curtailed or interrupted such firm transmission pursuant to the applicable
transmission tariff or contract.

There shall be no due diligence obligation

associated with interruptions under this subparagraph (1).
(2)

If the Parties did not agree on the transmission path for a transaction in the
Confirmation, an interruption in transmission service shall be considered an
Uncontrollable Force only if (a) the Party contracting for transmission services shall
have made arrangements with the entity providing transmission service for firm
transmission to effectuate the transaction under the Agreement and Confirmation,
(b) the entity providing transmission service curtailed or interrupted such
transmission service, and (c) the Party which contracted for such firm transmission
services could not obtain alternate energy at the delivery point, alternate

transmission services, or alternate means of delivering energy after exercising due
diligence.
No Party shall be relieved by operation of this Section 10 of any liability to
pay for power delivered to the Purchaser or to make payments then due or which
the Party is obligated to make with respect to performance which occurred prior to
the Uncontrollable Force.

11.

WAIVERS:
Any waiver at any time by any Party of its rights with respect to a default under this
Agreement or any Confirmation, or any other matter under this Agreement, shall not be
deemed a waiver with respect to any subsequent default of the same or any other matter.

12.

NOTICES:
12.1

Except for the oral notice provided for in Section 10 of this Agreement, any formal
notice, demand or request provided for in this Agreement shall be in writing and
shall be deemed properly served, given or made if delivered in person, or sent by
either registered or certified mail (postage prepaid), prepaid telegram, fax, or
overnight delivery (with record of receipt).

12.2

Notices and requests of a routine nature applicable to delivery or receipt of capacity
and/or energy shall be given in such manner as the Parties to a transaction shall
prescribe in a Confirmation or otherwise; provided, however, if the Parties have not
prescribed a method of providing such routine notices, then the procedures in
Section 12.1 shall apply.

13.

EFFECT OF APPROVALS:
13.1

This Agreement and all Confirmations are subject to valid laws, orders, rules and
regulations of duly constituted authorities having jurisdiction. Nothing contained
in this Agreement or any Confirmation shall give FERC jurisdiction over those
Parties not otherwise subject to such jurisdiction or be construed as a grant of
jurisdiction over any Party by any state or federal agency not otherwise having
jurisdiction by law.

13.2

Nothing in this Agreement or any Confirmation is intended to restrict the authority
of the Bonneville Power Administration (BPA) pursuant to applicable statutory
authority to use its existing wholesale power and transmission rates or to adopt new
rates, rate schedules, or general rate schedule provisions for application under this
Agreement and obtain interim or final approval of those rates from FERC pursuant
to Section 7 of the Pacific Northwest Electric Power Planning and Conservation
Act, 16 U.S.C. Sec. 839e, provided such rates do not exceed the maximum rates in
the applicable Service Schedule and are consistent with the terms and conditions of
said Service Schedule.

13.3

Nothing contained in this Agreement or any Confirmation shall be construed to
establish any precedent for any other agreement or to grant any rights to or impose
any obligations on any Party beyond the scope and term of this Agreement or any
Confirmation.

14.

TRANSFER OF INTEREST IN AGREEMENT:
No Party shall voluntarily transfer its membership in the WSPP under this
Agreement without the written consent and approval of all other Parties except to a
Successor in Operation of such Party. With regard to the transfer of the rights and
obligations of any Party associated with transactions under this Agreement and
Confirmation(s), neither Party to such transactions may assign such rights or obligations
unless (a) the other Party provides its prior written consent which shall not be unreasonably
withheld; or (b) the assignment is to a Successor in Operation which provides reasonable
creditworthiness assurances (see Section 27 for examples of such assurances) if required
by the non-assigning Party based upon its reasonably exercised discretion. Any successor
or assignee of the rights of any Party, whether by voluntary transfer, judicial or foreclosure
sale or otherwise, shall be subject to all the provisions and conditions of this Agreement
and Confirmation(s) (where applicable) to the same extent as though such successor or
assignee were the original Party under this Agreement or the Confirmation(s), and no
assignment or transfer of any rights under this Agreement or any Confirmation(s) shall be
effective unless and until the assignee or transferee agrees in writing to assume all of the
obligations of the assignor or transferor and to be bound by all of the provisions and
conditions of this Agreement and any Confirmation(s) (where applicable). The execution
of a mortgage or trust deed or a judicial or foreclosure sale made thereunder shall not be
deemed a voluntary transfer within the meaning of this Section 14.

15.

SEVERABILITY:
In the event that any of the terms, covenants or conditions of this Agreement or any
Confirmation, or the application of any such term, covenant or condition, shall be held
invalid as to any person or circumstance by any court, regulatory agency, or other
regulatory body having jurisdiction, all other terms, covenants or conditions of this
Agreement and the Confirmation and their application shall not be affected thereby, but
shall remain in force and effect unless a court, regulatory agency, or other regulatory body
holds that the provisions are not separable from all other provisions of this Agreement or
such Confirmation(s).

16.

MEMBERSHIP:
16.1

Any Electric Utility, Retail Entity, Qualifying Facility, or Demand Response Entity
may become a Party to this Agreement. The Executive Committee shall notify such
Electric Utility, Retail Entity, Qualifying Facility, or Demand Response Entity of
its decision within sixty (60) days of a request to become a Party to this Agreement,
and any acceptable entity shall become a Party hereto by the execution of this
Agreement or a counterpart hereof, payment of costs pursuant to Section 16.4, and
concluding any necessary acceptance or approval referred to in Section 13. Any
such Party, if it is subject to the ratemaking jurisdiction of FERC, shall be
responsible for any FERC filing necessary for it to implement its performance
under this Agreement.

16.2

Each Party shall continue to meet the requirements of Section 16.1 in order to
remain a Party to this Agreement

16.3

Being a Party to this Agreement shall not serve as a substitute for contractual
arrangements that may be needed between any Party which operates a Control Area
and any other Party which operates within that Control Area.

16.4

Any entity that becomes a Party to this Agreement which was not a party to the
experimental Western Systems Power Pool Agreement shall pay a one time fee of
$25,000 under this Agreement in recognition of prior efforts and costs incurred by
the parties to the experimental Western Systems Power Pool Agreement, which
efforts greatly facilitated development of this Agreement. Such fee shall be
credited to future costs of the WSPP incurred hereunder.

16.5

In addition to requirements set forth elsewhere in this Agreement imposed on
Parties as part of their membership in the WSPP, each Party shall abide by the
following requirements:
16.5.1 Each Party shall maintain updated information regarding its Executive
Committee and Operating Committee representatives on the WSPP
Homepage and shall submit changes within a reasonable time period.
16.5.2 With regard to disputes involving transactions under this Agreement or
other agreements, no Party shall seek to conduct discovery of the WSPP or
issue or seek to obtain the issuance of any subpoena to the WSPP or WSPP
officers acting in their capacities as officers of the WSPP or of the WSPP’s
attorneys or consultants with regard to their work for the WSPP or their
opinions regarding the construction or interpretation of any clause of the
Agreement, provided that the foregoing prohibition shall not apply in
proceedings brought against the WSPP. In the event a Party seeks to compel
discovery or testimony in violation of this Section, that Party shall be
deemed to have consented to the quashing of the subpoena or other process
providing therefor. Notwithstanding any other provision in this Agreement,
a Party that seeks to conduct discovery or issue or seek to obtain the
issuance of any subpoena in breach of this provision shall compensate the
WSPP and its officers, attorneys, and consultants, as applicable, for all outof-pocket costs incurred.

16.6

An entity shall become a Party to this Agreement and a member of the WSPP upon
satisfaction of the requirements in this Section 16 and on the date allowed by FERC

if it is a FERC public utility or upon the date of satisfaction of the requirements in
this Section 16 if it is not a FERC public utility.

17.

RELATIONSHIP OF PARTIES:
17.1

Nothing contained in this Agreement or in any Confirmation shall be construed to
create an association, joint venture, trust, or partnership, or agency relationship
between or among the Parties, or to impose a trust or partnership covenant,
obligation, or liability on or with regard to any of the Parties. Each Party shall be
individually responsible for its own covenants, obligations, and liabilities under this
Agreement and under any applicable Confirmation.

17.2

All rights and obligations of the Parties under this Agreement are several and are
not joint.

18.

NO DEDICATION OF FACILITIES:
Any undertaking by one Party to another Party under any provision of this
Agreement shall not constitute the dedication of the electric system or any portion thereof
of the undertaking Party to the public or to the other Party, and it is understood and agreed
that any such undertaking under any provision of this Agreement by a Party shall cease
upon the termination of such Party's obligations under this Agreement.

19.

NO RETAIL SERVICES:
Nothing contained in this Agreement shall grant any rights to or obligate any Party
to provide any services hereunder directly to or for retail customers of any Party.

20.

THIRD PARTY BENEFICIARIES:
This Agreement shall not be construed to create rights, in, or to grant remedies to,
any third party as a beneficiary of this Agreement or of any duty, obligation or undertaking
established herein except as provided for in Section 14.

21.

LIABILITY AND DAMAGES:
21.1

This Agreement contains express remedies and measures of damages in Sections
21.3 and 22 for non-performance or default.

This Agreement also contains

additional remedies to enforce payment of monies due and to enforce terms of the
Agreement and applicable Confirmations in Section 21.2.
ALL OTHER DAMAGES OR REMEDIES ARE HEREBY WAIVED.
Therefore, except as provided in Sections 21.3 and 22, no Party or its directors,
members of its governing bodies, officers or employees shall be liable to any other
Party or Parties for any loss or damage to property, loss of earnings, or revenues,
personal injury, or any other direct, indirect, or consequential damages or injury, or
punitive damages, which may occur or result from the performance or nonperformance of this Agreement (including any applicable Confirmation), including
any negligence arising hereunder. Any liability or damages incurred by an officer
or employee of a Federal agency or by that agency that would result from the
operation of this provision shall not be inconsistent with Federal law.
21.2

Any Party due monies under this Agreement, the amounts of which are not in
dispute or if disputed have been the subject of a decision awarding monies, (i) shall
have the right to seek payment of such monies in any forum having competent
jurisdiction and (ii) shall possess the right to seek relief directly from that forum
without first utilizing the mediation or arbitration provisions of this Agreement and
without exercising termination and liquidation rights under Section 22.
In addition, each Party shall possess the right to seek specific performance
(injunctive relief) of the non-delivery related terms of this Agreement and any

Confirmation in any forum having competent jurisdiction. In seeking to enforce
the terms of this Agreement, however, consistent with Section 21.1, no Party is
entitled to receive or recover monetary damages except as provided in Sections 21.3
and 22.
21.3

The following damages provision shall apply to all transactions under this
Agreement. For transactions under Service Schedule A, however, this damages
provision or some other damages provision will apply only if such a damages
provision is agreed to through a Confirmation. The damages under this Section
21.3 apply to a Party's failure to deliver or receive (or make available in the case of
capacity) capacity and/or energy in violation of the terms of the Agreement and any
Confirmation. The Contract Quantity and Contract Price referred to in this Section
21.3 are part of the agreement between the Parties for which damages are being
calculated under this Section.
(a)

If either Party fails to deliver or receive (or make available in the case of
capacity), as the case may be, the quantities of capacity and/or energy due
under the Agreement and any Confirmation (thereby becoming a "NonPerforming Party" for the purposes of this Section 21.3), the other party (the
"Performing Party") shall be entitled to receive from the Non-Performing
Party an amount calculated as follows (unless performance is excused by
Uncontrollable Forces as provided in Section 10, the applicable Service
Schedule, or by the Performing Party):
(1)

If the amount the Purchaser scheduled or received in any hour is less
than the applicable hourly Contract Quantity, then the Purchaser

shall be liable for (a) the product of the amount (whether positive or
negative), if any, by which the Contract Price differed from the
Resale Price (Contract Price - Resale Price) and the amount by
which the quantity provided to the Purchaser was less than the
hourly Contract Quantity; plus (b) the amount of transmission
charge(s), if any, for firm transmission service upstream of the
delivery point, which the Seller incurred to achieve the Resale Price,
less the reduction, if any, in transmission charge(s) achieved as a
result of the reduction in the Purchaser's schedule or receipt of
electric energy (based on Seller's reasonable commercial efforts to
achieve such reduction). If the total amounts for all hours calculated
under this paragraph (1) are negative, then neither the Purchaser nor
the Seller shall pay any amount under this Section 21.3(a)(1).
(2)

If the amount the Seller scheduled or delivered (or made available
in the case of capacity) in any hour is less than the applicable hourly
Contract Quantity, then the Seller shall be liable for (a) the product
of the amount (whether positive or negative), if any, by which the
Replacement Price differed from the Contract Price (Replacement
Price - Contract Price) and the amount by which the quantity
provided by the Seller was less than the hourly Contract Quantity;
plus (b) the amount of transmission charge(s), if any, for firm
transmission service downstream of the delivery point, which the
Purchaser incurred to achieve the Replacement Price, less the

reduction, if any, in transmission charge(s) achieved as a result of
the reduction in the Seller's schedule or delivery (based on
Purchaser's reasonable commercial effort to achieve such
reduction). If the total amounts for all hours calculated under this
paragraph (2) are negative, then neither the Purchaser nor the Seller
shall pay any amount under this Section 21.3(a)(2).
(3)

The Non-Performing Party also shall reimburse the Performing
Party for any charges imposed on the Performing Party under open
access transmission or FERC accepted or approved tariffs for
regional organizations due to the non-performance.

(4)

The Non-Performing Party shall pay any amount due from it under
this section within the billing period as specified in Section 9 of this
Agreement or agreed to in the applicable Confirmation if the Parties
agreed to revise the billing period in Section 9.

(5)

In the event (a) two Parties entered into two or more Confirmations
in which the same Party is the Purchaser and the other Party is the
Seller, (b) deliveries under two or more of such Confirmations are
to occur, in whole or in part, on the same date and hour, and at the
same delivery point, and (c) as to such date, hour, and delivery point,
and with respect to one or more of such Confirmations, a Party is a
Non-Performing Party (for purposes of this Section 21.3(a)(5), each
such instance of non-performance, a “non-performed transaction”),
then, as set out in this Section 21.3(a)(5), each non-performed

transaction shall be identified to a Confirmation, and the Contract
Price of the Confirmation to which the non-performed transaction is
identified, and the Contract Quantity of the non-performed
transaction, shall be applied to the calculation of amounts due under
Section 21.3(a)(1) through (3), as applicable.
The Parties in good faith shall seek to agree to the
identification of each non-performed transaction to a Confirmation.
Each non-performed transaction not identified to a
Confirmation by agreement, and any megawatt hours that are not
fully accounted for by such identification, shall be identified to
Confirmation(s) as follows:
(i)

The Performing Party in good faith shall determine whether

each Confirmation is real-time, day-ahead, or forward; all
Confirmations that are not real-time or day-ahead shall be deemed
forward Confirmations.
(ii)

The Performing Party in good faith shall determine whether

each non-performed transaction is real-time, day-ahead, or forward;
all non-performed transactions that are not real-time or day-ahead
shall be deemed forward non-performed transactions.
(iii)

The Performing Party shall:
(x)

identify real-time non-performed transactions to

real-time Confirmations, provided, that if the megawatt hours
of real-time non-performed transactions exceed the

megawatt hours of real-time Confirmations, then such excess
megawatt

hours

shall

be

identified

to

day-ahead

Confirmations and any excess megawatt hours remaining
after such identification to day-ahead Confirmations shall be
identified to forward Confirmations.
(y)

identify day-ahead non-performed transactions to

day-ahead Confirmations, provided, that if the megawatt
hours of day-ahead non-performed transactions exceed the
megawatt hours of day-ahead Confirmations, then such
excess megawatt hours shall be identified to forward
Confirmations.
(z)

identify all remaining non-performed transactions to

forward Confirmations.
The Performing Party, in its billing for amounts due under Section
21.3(a)(1) through (3), shall set out a detailed explanation of each
applicable determination under parts (i), (ii), and (iii) of this Section
21.3(a)(5), and state the resulting Contract Quantity and Contract
Price, and any amounts associated with each such determination
under Section 21.3(a)(3).
(b)

The Parties agree that the amounts recoverable under this Section 21.3 are
a reasonable estimate of loss and not a penalty, and represent the sole and
exclusive remedy for the Performing Party. Such amounts are payable for
the loss of bargain and the loss of protection against future risks.

(c)

Each Party agrees that it has a duty to mitigate damages in a commercially
reasonable manner to minimize any damages it may incur as a result of the
other Party's performance or non-performance of this Agreement.

(d)

In the event the Non-Performing Party disputes the calculation of the
damages under this Section 21.3, the Non-Performing Party shall pay the
full amount of the damages as required by Section 9 of this Agreement to
the Performing Party. After informal dispute resolution as required by
Section 34.1, any remaining dispute involving the calculation of the
damages shall be referred to binding dispute resolution as provided by
Section 34.2 of this Agreement. If resolution or agreement results in
refunds or the need for refunds to the Non-Performing Party, such refunds
shall be calculated in accordance with Section 9.4 of this Agreement.

(e)

In the event non-performance of a transaction is accounted for by means of
a Damages Settlement Transaction and the Damages Settlement
Transaction is performed, then no damages shall be calculated or due under
§ 21.3(a) with respect to the non-performed transaction. Neither Party shall
be required to enter into a Damages Settlement Transaction.

22.

DEFAULT OF TRANSACTIONS UNDER THIS AGREEMENT AND

CONFIRMATIONS:
22.1

EVENTS OF DEFAULT
An "Event of Default" shall mean with respect to a Party ("Defaulting Party"):
(a)

the failure by the Defaulting Party to make, when due, any payment required
pursuant to this Agreement or Confirmation if such failure is not remedied
within two (2) Business Days after written notice of such failure is given to
the Defaulting Party by the other Party ("the Non-Defaulting Party"). The
Non-Defaulting Party shall provide the notice by facsimile to the designated
contact person for the Defaulting Party and also shall send the notice by
overnight delivery to such contact person; or

(b)

the failure by the Defaulting Party to provide clear and good title as required
by Section 33.3, or to have made accurate representations and warranties as
required by Section 37 and such failure is not cured within five (5) Business
Days after written notice thereof to the Defaulting Party; or

(c)

The institution, with respect to the Defaulting Party, by the Defaulting Party
or by another person or entity of a bankruptcy, reorganization, moratorium,
liquidation or similar insolvency proceeding or other relief under any
bankruptcy or insolvency law affecting creditor's rights or a petition is
presented or instituted for its winding-up or liquidation; or

(d)

The failure by the Defaulting Party to provide adequate assurances of its
ability to perform all of its outstanding material obligations to the NonDefaulting Party under the Agreement or any Confirmation pursuant to

Section 27 of this Agreement or any substitute or modified provision in any
Confirmation.
(e)

With respect to its Guarantor, if any:
(i)

if a material representation or warranty made by a Guarantor in
connection with this Agreement, or any transaction entered into
hereunder, is false or misleading in any material respect when made
or when deemed made or repeated; or

(ii)

the failure of a Guarantor to make any payment required or to
perform any other material covenant or obligation in any guarantee
made in connection with this Agreement, including any transaction
entered into hereunder, and such failure shall not be remedied within
three (3) Business Days after written notice; or

(iii)

the institution, with respect to the Guarantor, by the Guarantor or by
another person or entity of a bankruptcy, reorganization,
moratorium, liquidation or similar insolvency proceeding or other
relief under any bankruptcy or insolvency law affecting creditor’s
rights or a petition is presented or instituted for its winding-up or
liquidation; or

(iv)

the failure, without written consent of the other Party, of a
Guarantor’s guarantee to be in full force and effect for purposes of
this Agreement (other than in accordance with its terms) prior to the
satisfaction of all obligations of such Party under each transaction
to which such guarantee shall relate; or

(v)

a Guarantor shall repudiate, disaffirm, disclaim, or reject, in whole
or in part, or challenge the validity of, any guarantee.

22.2

REMEDIES FOR EVENTS OF DEFAULT
22.2(a) If an Event of Default shall have occurred and be continuing, the NonDefaulting Party, upon written notice to the Defaulting Party, shall have the
right (i) to suspend performance of transactions under this Agreement;
provided, however, (i) in no event shall any such suspension continue for
longer than ten (10) Business Days; (ii) such suspension must include all
transactions under this Agreement in effect as of the date of the suspension
between the Defaulting Party and the Non-Defaulting Party; and (iii) such
suspension is available only once for each default. This ten (10) day
suspension period shall not affect in any way the thirty (30) day period for
exercising a right of termination under Section 22.2(b).

The Non-

Defaulting Party shall have the unilateral right to exercise its rights under
this Agreement including its termination rights at any time within the
suspension period. The Defaulting Party shall have no suspension rights.
In no event shall the suspension continue beyond the cure of or waiver by
the Non-Defaulting Party of the applicable Event of Default. If the NonDefaulting Party seeks to terminate the suspension period such that the
suspension shall be terminated prior to the end of the ten (10) Business Day
period specified above, it may do so only by providing at least twenty-four
(24) hours written notice to the Defaulting Party before the suspension may
be terminated.

22.2(b) If an Event of Default occurs, the Non-Defaulting Party shall possess the
right to terminate all transactions between the Parties under this Agreement
upon written notice (by facsimile or other reasonable means) to the
Defaulting Party, such notice of termination to be effective immediately
upon receipt. If the Non-Defaulting Party fails to exercise this right of
termination within thirty (30) days following the time when the Event of
Default becomes known (or more than thirty days if the Non-Defaulting and
Defaulting Parties agree to an extension), then such right of termination
shall no longer be available to the Non-Defaulting Party as a remedy for the
Event(s) of Default; provided, however, this thirty day requirement for
exercising termination rights shall not apply to defaults pursuant to Sections
22.1(c) and 22.1(e)(iii).

The Non-Defaulting Party terminating

transaction(s) under this Section 22.2 may do so without making a filing at
FERC.
If the Non-Defaulting Party elects to terminate under this Section, it
shall be required to terminate all transactions between the Parties under the
Agreement at the same time. Upon termination, the Non-Defaulting Party
shall liquidate all transactions as soon as practicable, provided that in no
event will the Non-Defaulting Party be allowed to liquidate Service
Schedule A transactions.

The payment associated with termination

("Termination Payment") shall be calculated in accordance with this Section
22.2 and Section 22.3. The Termination Payment shall be the sole and
exclusive remedy for the Non-Defaulting Party for each terminated

transaction ("Terminated Transaction") for the time period beginning at the
time notice of termination under this Section 22 is received. Prior to receipt
of such notice of termination by the Defaulting Party, the Non-Defaulting
Party may exercise any remedies available to it under Section 21.3 of this
Agreement or Confirmation(s), and any other remedies available to it at law
or otherwise.
Upon termination, the Non-Defaulting Party may withhold any payments it
owes the Defaulting Party for any obligations incurred prior to termination under
this Agreement or Confirmation(s) until the Defaulting Party pays the Termination
Payment to the Non-Defaulting Party. The Non-Defaulting Party shall possess the
right to set-off the amount due it under this Section 22 by any such payments due
the Defaulting Party as provided in Section 22.3(d).
22.3

LIQUIDATION CALCULATION OPTIONS
The Non-Defaulting Party shall calculate the Termination Payment as
follows:
(a)

The Gains and Losses shall be determined by comparing the value of the
remaining term, transaction quantities, and transaction prices under each
Terminated Transaction had it not been terminated to the equivalent
quantities and relevant market prices for the remaining term either quoted
by a bona fide third-party offer or which are reasonably expected to be
available in the market under a replacement contract for each Terminated
Transaction. To ascertain the market prices of a replacement contract, the
Non-Defaulting Party may consider, among other valuations, quotations

from Dealers in energy contracts, any or all of the settlement prices of the
NYMEX power futures contracts (or NYMEX power options contracts in
the case of Physically-Settled Options) and other bona fide third party
offers, all adjusted for the length of the remaining term and differences in
transmission. It is expressly agreed that the Non-Defaulting Party shall not
be required to enter into replacement transactions in order to determine the
Termination Payment.
(b)

The Gains and Losses calculated under paragraph (a) shall be discounted to
present value using the Present Value Rate as of the time of termination (to
take account to the period between the time notice of termination was
effective and when such amount would have otherwise been due pursuant
to the relevant transaction). The "Present Value Rate" shall mean the sum
of 0.50% plus the yield reported on page "USD" of the Bloomberg Financial
Markets Services Screen (or, if not available, any other nationally
recognized trading screen reporting on-line intraday trading in United States
government securities) at 11:00 a.m. (New York City, New York time) for
the United States government securities having a maturity that matches the
average remaining term of the Terminated Transactions; and

(c)

The Non-Defaulting Party shall set off or aggregate, as appropriate, the
Gains and Losses (as calculated in Section 22.3(a)) and Costs and notify the
Defaulting Party. If the Non-Defaulting Party's aggregate Losses and Costs
exceed its aggregate Gains, the Defaulting Party shall, within three (3)
Business Days of receipt of such notice, pay the Termination Payment to

the Non-Defaulting Party, which amount shall bear interest at the Present
Value rate from the time notice of termination was received until paid. If
the Non-Defaulting Party's aggregate Gains exceed its aggregate Losses and
Costs, the Non-Defaulting Party, after any set-off as provided in paragraph
(d), shall pay the remaining amount to the Defaulting Party within three (3)
Business Days of the date notice of termination was received including
interest at the Present Value from the time notice of termination was
received until the Defaulting Party receives payment.
(d)

The Non-Defaulting Party shall aggregate or set off, as appropriate, at its
election, any or all other amounts owing between the Parties (discounted at
the Present Value Rate) under this Agreement and any Confirmation against
the Termination Payment so that all such amounts are aggregated and/or
netted to a single liquidated amount. The net amount due from any such
liquidation shall be paid within three (3) Business Days following the date
notice of termination is received.

(e)

(i)

If the Non-Defaulting Party owes the Defaulting Party monies under
this Section 22.3, then notwithstanding the three Business Day
payment requirement detailed above, the Non-Defaulting Party may
elect to pay the Defaulting Party the monies owed under this Section
22.3 over the remaining life of the contract(s) being terminated. The
Non-Defaulting Party may make this election by providing written
notice to the Defaulting Party within three Business Days of the
notice being provided to terminate and liquidate under this Section

22.3. The Non-Defaulting Party shall provide the Defaulting Party
with the details on the method for recovering the monies owed over
the remaining life of the contract(s). That method shall ensure that
the Defaulting Party receives a payment each month through the end
of the term of each contract which allows it to receive the monies
which would have been due it under Sections 22.3(c) and (d) in total
(to be recovered over the term of the contract(s) to replicate as
closely as possible the payment streams under such contract(s))
provided that the discounting using the Present Value Rate
referenced in Section 22.3 (b) shall not be reflected in determining
the amounts to be recovered under this provision. Any disputes as
to the methodology shall be resolved pursuant to the dispute
resolution procedures in Section 34, with binding arbitration
pursuant to Section 34.2 required for disputes as to the methodology
if mediation is unsuccessful.
(ii)

This Section 22.3(e) and the rights and obligations under it shall
survive termination of any applicable transactions or agreements.

(iii)

The Party owed monies under this Section 22.3(e) shall have the
right to request credit assurances consistent with Section 27 even
after termination of any contract or transaction.

(iv)

If the Party owing money defaults on its payment obligations
consistent with Section 22.1(a) or defaults with regard to providing
credit assurances consistent with Section 22.1(d), then the other

Party shall have the right (by written notice) at any time after the
Party owing money defaults to require that Party to pay all monies
owed under all of the contracts subject to this Section 22.3(e) within
three Business Days of receipt of the written notice. The monies to
be paid under this accelerated payment provision shall be the
remaining amounts to be paid under the contract(s) reflecting a
discount using the Present Value Rate from the date of the written
notice.
(f)

If the Defaulting Party disagrees with the calculation of the Termination
Payment and the Parties cannot otherwise resolve their differences, the
calculation issue shall be submitted to informal dispute resolution as
provided in Section 34.1 of this Agreement and thereafter binding dispute
resolution pursuant to Section 34.2 if the informal dispute resolution does
not succeed in resolving the dispute. Pending resolution of the dispute, the
Defaulting Party shall pay the full amount of the Termination Payment
calculated by the Non-Defaulting Party within three (3) Business Days
(except if the option under 22.3(e) has been invoked in which case the
payment times in that provision would apply) of receipt of notice as set forth
in Sections 22.3(c) and (d) subject to the Non-Defaulting Party refunding,
with interest, pursuant to Section 9.4, any amounts determined to have been
overpaid.

(g)

For purposes of this Section 22.3:

(i)

"Gains" means the economic benefit (exclusive of Costs), if any,
resulting from the termination of the Terminated Transactions,
determined in a commercially reasonable manner as calculated in
accordance with this Section 22.3;

(ii)

"Losses" means the economic loss (exclusive of Costs), if any,
resulting from the termination of the Terminated Transactions,
determined in a commercially reasonable manner as calculated in
accordance with this Section 22.3;

(iii)

"Costs" means brokerage fees, commissions and other similar
transaction costs and expenses reasonably incurred in terminating
any specifically related arrangements which replace a Terminated
Transaction, transmission and ancillary service costs associated with
Terminated Transactions, and reasonable attorneys' fees, if any,
incurred in connection with the Non-Defaulting Party enforcing its
rights with regard to the Terminated Transactions.

The Non-

Defaulting Party shall use reasonable efforts to mitigate or eliminate
these Costs.
(iv)

In no event, however, shall a Party's Gains, Losses or Costs include
any penalties or similar charges imposed by the Non-Defaulting
Party.

22A.

DEFAULT IN PAYMENT OF WSPP OPERATING COSTS:
22A.1 A Party shall be deemed to be in default in payment of its share of WSPP operating
costs pursuant to Section 7 of this Agreement, if any, when payment is not received
within ten (10) days after receipt of written notice. A default by any Party in such
payment obligations shall be cured by payment of all overdue amounts together
with interest accrued at the rate of one percent (1%) per month, or the maximum
interest rate permitted by law, if any, whichever is less, prorated by days from the
due date to the date the payment curing the default is made unless and until the
Executive Committee shall determine another rate.
22A.2 A defaulting Party, which is in default under Section 22.A1, shall be liable for all
costs, including costs of collection and reasonable attorney fees, plus interest as
provided in Section 22.A1 hereof.
22A.3 The rights under this Agreement of a Party which is in default of its obligation to
pay operating costs under this Agreement for a period of three (3) months or more
may be revoked by a vote of the non-defaulting Parties' representatives on the
Executive Committee consistent with Section 8.3. The defaulting Party's rights
shall not be revoked, however, unless said Party has received at least thirty (30)
days written notice of the non-defaulting Parties' intent to revoke such rights. Said
notice shall state the date on which the revocation of rights shall become effective
if the default is not cured and shall state all actions which must be taken or amounts
which must be paid to cure the default. This provision allowing the non-defaulting
Parties to revoke such rights is in addition to any other remedies provided in this
Agreement or at law and shall in no way limit the non-defaulting Parties' ability to

seek judicial enforcement of the defaulting Party's obligations to pay its share of
the operating costs under this Agreement.

Upon the effective date of such

revocation of rights, the defaulting party shall not be allowed to enter into any new
transactions under this Agreement. The defaulting party under the Agreement and
Confirmation(s) shall be required to carry out all obligations that existed prior to
the effective date of such revocation. If a defaulting Party's rights under this
Agreement have been revoked, the Executive Committee may restore that Party's
rights upon the defaulting Party paying all amounts due and owing under this
Agreement.
22A.4 Upon revocation of the rights of a defaulting Party under this Agreement, costs of
the WSPP hereunder shall be equally shared among the remaining Parties. Cost
allocation adjustments shall be retroactive to the date of the default.

23.

OTHER AGREEMENTS:
No provision of this Agreement shall preclude any Party from entering into other
agreements or conducting transactions under existing agreements with other Parties or third
parties. This Agreement shall not be deemed to modify or change any rights or obligations
under any prior contracts or agreements between or among any of the Parties.

24.

GOVERNING LAW:
This Agreement and any Confirmation shall be governed by and construed in
accordance with the laws of the State of Utah, without regard to the conflicts of laws rules
thereof. The foregoing notwithstanding, (1) if both the Seller and Purchaser are organized
under the laws of Canada, then the laws of the province of the Seller shall govern, or (2) if
the Seller or Purchaser is an agency of or part of the United States Government, then the
laws of the United States of America shall govern.

25.

JUDGMENTS AND DETERMINATIONS:
Whenever it is provided in this Agreement that a Party shall be the sole judge of
whether, to what extent, or under what conditions it will provide a given service, its
exercise of its judgment shall be final and not subject to challenge. Whenever it is provided
that (i) a service under a given transaction may be curtailed under certain conditions or
circumstances, the existence of which are determined by or in the judgment of a Party, or
(ii) the existence of qualifications for membership shall be determined by the Executive
Committee pursuant to Section 16, that Party's or the Executive Committee's determination
or exercise of judgment shall be final and not subject to challenge if it is made in good faith
and not made arbitrarily or capriciously.

26.

COMPLETE AGREEMENT:
This Agreement and the Confirmation(s), shall constitute the full and complete
agreement of the Parties with respect to a transaction, except as provided under Section
32.4.

27.

CREDITWORTHINESS:
Should a Party's creditworthiness, financial responsibility, or performance viability
become unsatisfactory to the other Party in such other Party's reasonably exercised
discretion with regard to any transaction pursuant to this Agreement and any Confirmation,
the dissatisfied Party (the "First Party") may require the other Party (the "Second Party")
to provide, at the Second Party's option (but subject to the First Party's acceptance based
upon reasonably exercised discretion), either (1) the posting of a Letter of Credit, (2) a cash
prepayment, (3) the posting of other acceptable collateral or security by the Second Party,
(4) a Guarantee Agreement executed by a creditworthy entity; or (5) some other mutually
agreeable method of satisfying the First Party. The Second Party’s obligations under this
Section 27 shall be limited to a reasonable estimate of the damages to the First Party
(consistent with Section 22.3 of this Agreement) if the Second Party were to fail to perform
its obligations. Events which may trigger the First Party questioning the Second Party's
creditworthiness, financial responsibility, or performance viability include, but are not
limited to, the following:
(1)

The First Party has knowledge that the Second Party (or its Guarantor if applicable)
are failing to perform or defaulting under other contracts.

(2)

The Second Party has exceeded any credit or trading limit set out in any
Confirmation or other agreement between the Parties.

(3)

The Second Party or its Guarantor has debt which is rated as investment grade and
that debt falls below the investment grade rating by at least one rating agency or is
below investment grade and the rating of that debt is downgraded further by at least
one rating agency.

(4)

Other material adverse changes in the Second Party's financial condition occur.

(5)

Substantial changes in market prices which materially and adversely impact the
Second Party's ability to perform under this Agreement or any Confirmation occur.
If the Second Party fails to provide such reasonably satisfactory assurances of its

ability to perform a transaction hereunder within three (3) Business Days of demand
therefore, that will be considered an Event of Default under Section 22 of this Agreement
and the First Party shall have the right to exercise any of the remedies provided for under
that Section 22. Nothing contained in this Section 27 shall affect any credit agreement or
arrangement, if any, between the Parties.

28.

NETTING:
28.1

Parties shall net payments (associated with transactions under this Agreement and
Confirmation(s)) in accordance with Exhibit A, if such Parties have executed the
form attached as Exhibit A. The Parties’ obligations to net shall include the netting
of all payments received by the Parties in the same calendar month. Parties that
have executed Exhibit A shall provide a signed copy of Exhibit A to a
representative of the WSPP and to any Party that requests a copy and indicate on
the WSPP Homepage that they have executed Exhibit A. If a Party indicated its
election to net payments on the WSPP Homepage and that Party desires to withdraw
its agreement to net, that Party shall provide at least 30 days notice on the WSPP
Homepage of the change in its election to net and also shall provide, concurrent
with its withdrawal notice, written notice to all Parties with which it has ongoing
transactions or with which it has committed to future transactions under the
Agreement at the time of the notice. Any such changes in netting status shall apply
beginning at least 30 days after notice required by this Section 28.2 is provided and
only shall apply to transactions agreed to beginning on or after the date the change
in netting status becomes effective.

28.2

The Parties may by separate agreement either through a Confirmation or some other
agreement set out specific terms relating to the implementation of the netting in
addition to or in lieu of Exhibit A.

28.3

Each Party reserves to itself all rights, set offs, counterclaims, and other remedies
and defenses (to the extent not expressly herein waived or denied) which such Party

has or may be entitled to arising from or out of this Agreement and any applicable
Confirmation.

29.

TAXES:
The Contract Price for all transactions under this Agreement shall include full
reimbursement for, and the Seller is liable for and shall pay, or cause to be paid, or
reimburse the Purchaser for if the Purchaser has paid, all taxes applicable to a transaction
that arise prior to the delivery point. If the Purchaser is required to remit such tax, the
amount shall be deducted from any sums due to the Seller. The Seller shall indemnify,
defend, and hold harmless the Purchaser from any claims for such taxes. The Contract
Price does not include reimbursement for, and the Purchaser is liable for and shall pay,
cause to be paid, or reimburse the Seller for if the Seller has paid, all taxes applicable to a
transaction arising at and from the delivery point, including any taxes imposed or collected
by a taxing authority with jurisdiction over the Purchaser. The Purchaser shall indemnify,
defend, and hold harmless the Seller from any claims for such taxes. Either Party, upon
written request of the other Party, shall provide a certificate of exemption or other
reasonably satisfactory evidence of exemption if either Party is exempt from taxes, and
shall use reasonable efforts to obtain and cooperate with the other Party in obtaining any
exemption from or reduction of any tax. Taxes are any amounts imposed by a taxing
authority associated with the transaction.

30.

CONFIDENTIALITY:
30.1

The terms of any transaction under this Agreement or any other information
exchanged by the Purchaser and Seller relating to the transaction shall not be
disclosed to any person not employed or retained by the Purchaser or the Seller or
their affiliates, except to the extent disclosure is (1) required by law, (2) reasonably
deemed by the disclosing Party to be required to be disclosed in connection with a
dispute between or among the Parties, or the defense of any litigation or dispute,
(3) otherwise permitted by consent of the other Party, which consent shall not be
unreasonably withheld, (4) required to be made in connection with regulatory
proceedings (including proceedings relating to FERC, the United States Securities
and Exchange Commission or any other federal, state or provincial regulatory
agency); (5) required to comply with North American Electric Reliability
Organization, regional reliability council, or successor organization requirements;
(6) necessary to obtain transmission service; or (7) to a developer of an index of
electric power prices in accordance with Section 30.2. In the event disclosure is
made pursuant to this provision, the Parties shall use reasonable efforts to minimize
the scope of any disclosure and have the recipients maintain the confidentiality of
any documents or confidential information covered by this provision, including, if
appropriate, seeking a protective order or similar mechanism in connection with
any disclosure. This provision shall not apply to any information that was or is
hereafter in the public domain (except as a result of a breach of this provision).

30.2

A Party may disclose the terms of transactions under this Agreement, excluding the
identities of parties, to any developer of any index of electric power prices without

violation of the confidentiality obligations under Section 30.1 if: (1) the disclosing
Party and the index developer have entered into a written agreement, prior to the
disclosure, under which the developer has agreed to use the information solely for
the development of an index of electric power prices for publication and not for any
other purpose; and (2) the index with respect to which disclosure is made is an
aggregation of terms of transactions and does not identify terms of single
transactions or the identities of parties to transactions.

31.

TRANSMISSION TARIFF:
Pursuant to FERC Order No. 888, issued on April 24, 1996, and FERC orders where
applicable, the WSPP Default Transmission Tariff has been filed and has become effective.
The Parties agree to be bound by the terms of that Tariff for so long as they are WSPP
members.

32.

TRANSACTION SPECIFIC TERMS AND ORAL AGREEMENTS:
32.1

General
32.1.1 A Confirmation shall include, at a minimum, the Standard Confirmation
Provisions. (See Exhibit C for a sample). Subject to the limitations in
Section 32.2 (Standard Confirmation Provisions) and Section 32.3 (NonStandard Confirmation Provisions), the Confirmation shall be made in
writing by a Documentary Writing or an Electronic Writing, or shall be an
Electronic Platform Confirmation.
32.1.2 Pursuant to the provisions of this Section 32, the Parties to a transaction
under this Agreement may agree to modify any term of this Agreement
(other than provisions regarding the operation of the WSPP as an
organization including Sections 7 and 8) which applies to such transaction,
such agreement to be stated in a Confirmation or Confirmations.
32.1.3 Sections 32.2 and 32.3 shall not apply to an Electronic Platform
Confirmation. Parties may amend an Electronic Platform Confirmation in
accordance with the procedures, if any, of the applicable platform or
exchange or in any other manner this Agreement permits. Each Electronic
Platform Confirmation between WSPP members shall be subject to this
Agreement, unless the transaction specified in the Electronic Platform
Confirmation is subject to another agreement between the Parties other than
a master Confirmation applicable to the Parties’ WSPP Confirmations.

32.2

Process For Confirming Standard Confirmation Provisions.

32.2.1 Confirmation of Standard Confirmation Provisions For Transactions of
Less Than One Week in Duration.
Confirmation for Standard Confirmation Provisions applicable to
transactions of less than one week in duration may be through:
(i)

a Documentary Writing (including a Confirmation which is not
executed by both Parties but which is binding under Section 32.2.3)
or

(ii)

an Electronic Writing.

Notwithstanding the foregoing sentence, with respect to a transaction of less
than one week in duration as agreed in an Electronic Writing and that is to
commence within one week of that agreement, a subsequent proposed
confirming Documentary Writing under Section 32.2.3 shall not vary the
terms of the Electronic Writing unless the Documentary Writing is executed
by both Parties.
32.2.2 Standard Confirmation Provisions For Transactions of One Week or More
in Duration.
Written confirmation shall be required for all Standard Confirmation
Provisions for transactions of one week or more in duration. Such written
confirmation may be made by a Documentary Writing executed by both
Parties or a Documentary Writing not executed by both Parties but which is
binding under Section 32.2.3.
32.2.3 Written Confirmation Process for Standard Confirmation Provisions.

The Seller shall provide a proposed Documentary Writing containing the
proposed Standard Confirmation Provisions which must be received by the
Purchaser within five Business Days of the date of the agreement to the
transaction. The Purchaser shall have five Business Days from date of
receipt to accept or propose modifications to the proposed Documentary
Writing. If the Purchaser does not respond within that time period, the
Seller’s proposed Documentary Writing shall be considered as accepted and
shall be the final Confirmation. If the Seller fails to provide a proposed
Documentary Writing within the five Business Days period, then, within
the immediately subsequent five Business Days, the Purchaser may submit
a proposed Documentary Writing to the Seller. The Seller shall then have
five Business Days from date of receipt to accept or propose modifications
to the proposed Documentary Writing. If the Seller does not respond within
that time period, the Purchaser’s proposed Documentary Writing shall be
considered as accepted and shall be the final Confirmation.
32.3

Process for Confirming Non-Standard Confirmation Provisions.
32.3.1 Non-Standard Confirmation Provisions for Transactions of Less Than One
Week in Duration.

Confirmation for Non-Standard Confirmation

Provisions for a transaction of less than one week in duration only may be
through: (i) an Electronic Writing; or (ii) in a Documentary Writing
executed by both Parties.
32.3.2 Non-Standard Confirmation Provisions for Transactions of One Week or
More in Duration.

Confirmation for Non-Standard Confirmation

Provisions for transactions of one week or more only shall be through a
Documentary Writing executed by both Parties.
32.3.3 WSPP Agreement is a Default Agreement.
If the Parties to a transaction (i) do not reach agreement on any proposed
Non-Standard Confirmation Provision and (ii) do not confirm it under
Section 32.3.1 or 32.3.2, as applicable, then the term or terms of the
Agreement, which the Parties could not reach agreement to modify or
change or which are not considered modified pursuant to this Section 32.3,
shall apply to the transaction.
32.4

Prior Discussions And Statements
32.4.1 A Confirmation under Section 32.2 and/or 32.3, shall, together with this
Agreement, be an integrated contract with respect to the transaction, shall
supersede all discussions and negotiations with respect thereto, and are
intended by the Parties as a final expression of their agreement with respect
to such terms as are included therein and may not be contradicted by
evidence of any prior agreement unless there is clear and convincing
evidence of a mutual mistake in the Confirmation.
32.4.2 Notwithstanding any provision in this Agreement (including Sections
32.3.2 and 32.4.1), until the Confirmation has become final in accordance
with Sections 32.2 and/or 32.3 for a transaction, any oral agreement or
electronic communication establishing agreement of the Parties relating to
such transaction shall remain valid and binding.

32.5

The Parties agree not to contest, or assert any defense with respect to, the validity
or enforceability of any agreement to the terms concerning a specific transaction,
on the basis that documentation of such terms fails to comply with the requirements
of any statute that agreements be written or signed. Each Party consents to the
recording by the other Party, without any further notice, of telephone conversations
between representatives of the Parties, which contain agreements to or discussion
concerning the terms of a specific transaction.

All such recordings may be

introduced and admitted into evidence for the purpose of proving agreements to
terms, and any objection to such introduction or admission for such purpose is
hereby expressly waived.
32.6

In the event of a conflict between a binding and effective Confirmation and this
Agreement, the Confirmation shall govern.

32.7

The Seller shall not be required to file any Confirmation with FERC except as
provided in the Service Schedules.

32.8

Other Products and Service Levels: The Parties may apply this Agreement and
make a Confirmation with respect to a product/service level defined under any other
document or form of agreement (e.g., the California ISO tariff, the ERCOT
agreement or the EEI agreement). The confirmation process set forth in Section
32.3 shall apply to any such Confirmation. Unless the Parties expressly state and
agree that all the terms and conditions of such other agreement will apply to any
such transaction consistent with Section 32.3, the transaction shall be subject to all
the terms of this Agreement, except that (1) all service level/product definitions, (2)
force majeure/uncontrollable force definitions, and (3) other terms as mutually

agreed shall have the meaning ascribed to them in the different agreement or in the
applicable Confirmation.
32.9

Reserved.

32.10 The Parties may agree to modify terms of this Agreement for more than one
transaction pursuant to a separate written agreement (a “master confirmation
agreement”), which agreement shall be considered part of each Confirmation
between the Parties and shall apply to all transactions entered into between the two
Parties unless the Parties specifically agree to override such changes for a particular
transaction consistent with the procedure in Section 32.2 or 32.3, whichever is
applicable.

33.

PERFORMANCE, TITLE, AND WARRANTIES FOR TRANSACTIONS UNDER

SERVICE SCHEDULES:
33.1

Performance
33.1.1 The Seller shall deliver to the delivery point(s) as agreed to in the applicable
Confirmation and sell to the Purchaser in accordance with the terms of the
Agreement and such Confirmation.
33.1.2 The Purchaser shall receive and purchase the Contract Quantity, as agreed
to by the Parties in the applicable Confirmation, at the delivery point(s) and
purchase from the Seller in accordance with the terms of the Agreement and
such Confirmation.

33.2

Title and Risk of Loss
Title to and risk of loss of the electric energy shall pass from the Seller to
the Purchaser at the delivery point agreed to in the Confirmation; provided,
however, with regard to federal agencies or parts of the United States Government,
title to and risk of loss shall pass to Purchaser to the extent permitted by and
consistent with applicable law.

33.3

Warranties
The Seller warrants that it will transfer to the Purchaser good title to the
electric energy sold under the Agreement and any Confirmation, free and clear of
all liens, claims, and encumbrances arising or attaching prior to the delivery point
and that Seller's sale is in compliance with all applicable laws and regulations.
THE SELLER HEREBY DISCLAIMS ALL OTHER WARRANTIES,

EXPRESS

OR

IMPLIED,

INCLUDING

ANY

WARRANTY

OF

MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE.

34.

DISPUTE RESOLUTION:
34.1

INFORMAL DISPUTE RESOLUTION
Before binding dispute resolution or any other form of litigation may
proceed, any dispute between the Parties to a transaction under this Agreement first
shall be referred to nonbinding mediation except for actions taken pursuant to
Section 21.2. The Parties shall attempt to agree upon a mediator from a list of ten
(10) candidates provided by the Chairman of the WSPP Operating Committee or
his or her designee. If the Parties are unable to agree, then the Chairman or the
designee shall appoint a mediator for the dispute. Neither the mediator nor the
person involved on behalf of the WSPP in developing a list of mediators for the
Parties to choose from or in selecting the mediator (if the Parties are unable to do
so) shall possess a direct or indirect interest in either Party or the subject matter of
the mediation. The WSPP shall establish procedures for the appointment of
mediators and the conduct of mediation and those procedures shall apply to the
mediation.

34.2

BINDING DISPUTE RESOLUTION
The Parties to a dispute may elect binding dispute resolution using the
following process unless binding arbitration of certain disputes is required under
this Agreement in which event the Parties shall use the process set forth in this
Section 34.2 to resolve such disputes, unless the Parties otherwise agree:
(a)

WSPP Dispute Resolution:

A Party to a dispute (if binding dispute

resolution is required) or all Parties to a dispute (if agreement of the Parties
is required for binding dispute resolution) may initiate binding dispute

resolution under WSPP procedures by notifying the Chairman of the WSPP
Operating Committee or his or her designee. The Chairman or his or her
designee shall provide the Parties with a list of ten (10) eligible arbitrators.
Within ten (10) days of receiving the list, the Parties shall agree on a single
arbitrator from the list to conduct the arbitration, or notify the Chairman of
the Operating Committee or the designee of their inability to reach
agreement. If notified of the Parties inability to reach agreement, then the
Chairman or the designee shall choose the arbitrator from the list within five
(5) days. Neither the arbitrator nor the person involved on behalf of the
WSPP in developing a list of arbitrators for the Parties to choose from or in
selecting the arbitrator (if the Parties are unable to do so) shall possess a
direct or indirect interest in either Party or the subject matter of the
arbitration. The Procedures to be used for this arbitration shall follow the
arbitration procedures which shall be developed and maintained by the
WSPP and the procedures will be generally consistent with the commercial
arbitration rules of the American Arbitration Association though not
involving the Association.
If the Parties agree to binding dispute resolution under this Section 34.2,
each Party understands that it will not be able to bring a lawsuit concerning any
dispute that may arise which is covered by this arbitration provision.
Notwithstanding the foregoing, nothing herein is intended to waive any provision
of the Federal Arbitration Act, 9 U.S.C. § 1, et. seq., or any right under state statute

or common law to challenge an arbitration award or to prevent any action to enforce
any arbitration award.
A Party's liability and damages under any arbitration award resulting from
the process set forth in this Section 34.2 shall be limited as provided in this
Agreement or in any Confirmation.
34.3

COSTS
Each Party shall be responsible for its own costs and those of its counsel
and representatives. The Parties shall equally divide the costs of the arbitrator or
mediator and the hearing.

34.4

CONFIDENTIALITY
Any arbitration or mediation under this Section 34 shall be conducted on a
confidential basis and not disclosed, including any documents or results which shall
be considered confidential, unless the Parties otherwise agree or such disclosure is
required by law.

35.

FORWARD CONTRACTS:
The Parties acknowledge and agree that all transactions under the Agreement and
Confirmation(s) are forward contracts and that the Parties are forward contract merchants,
as those terms are used in the United States Bankruptcy Code. The Parties acknowledge
and agree that all of their transactions, together with this Agreement and the related
Confirmation(s) form a single, integrated agreement, and agreements and transactions are
entered into in reliance on the fact that the agreements and each transaction form a single
agreement between the Parties.

36.

TRADE OPTION EXEMPTION
The Parties intend that any Physically Settled Option under this Agreement shall
qualify under the trade option exemption, 17 C.F.R. § 32.3. Accordingly, each Party
buying or selling a Physically Settled Option agrees and warrants that any such option shall
be offered only to a provider, user, or merchant and that the entities entering into the options
are doing so solely for purposes related to their business.

37.

ADDITIONAL REPRESENTATIONS AND WARRANTIES:
Each Party warrants and represents to the other(s) that it possesses the necessary
corporate, governmental and legal authority, right and power to enter into and agree to the
applicable Confirmation for a transaction or transactions and to perform each and every
duty imposed, and that the Parties' agreement to buy and sell power under this Agreement
and the Confirmation represents a contract. Each Party also warrants and represents to the
other(s) that each of its representatives executing or agreeing through a Confirmation to a
transaction under this Agreement is authorized to act on its behalf.
Each Party further warrants and represents that entering into this Agreement and
any applicable Confirmation does not violate or conflict with its Charter, By-laws or
comparable constituent document, any law applicable to it, any order or judgment of any
court or other agency of government applicable to it or any agreement to which it is a party
and that this Agreement and applicable Confirmation, constitute a legal, valid and binding
obligation enforceable against such Party in accordance with the terms of such agreements.
Each Party also represents that it is solvent and that on each delivery this
representation shall be deemed renewed unless notice to the contrary is given in writing by
the Purchaser to the Seller before delivery.

38.

FLOATING PRICES:
38.1

In the event the Parties intend that the price for a transaction is to be based on an
index, exchange or any other kind of variable reference price (such price being a
“Floating Price”), the Parties shall specify the “Floating Price” to be used to
calculate the amounts in a Confirmation due Seller for that transaction.

38.2

Market Disruption. If a Market Disruption Event has occurred and is continuing
during the Determination Period, the Floating Price for the affected Trading Day
shall be determined as follows. The Parties shall negotiate in good faith to agree
on a Floating Price (or a method for determining a Floating Price) for the affected
Trading Day. If the Parties have not so agreed on or before the twelfth Business
Day following the first Trading Day on which the Market Disruption Event
occurred or existed, then the Floating Price shall be determined in good faith by the
Parties based upon (1) quotes from Dealers in energy contracts; and/or (2) quotes
from Brokers in energy contracts. Each Party may obtain up to a maximum of four
quotes which must be provided to the other Party no later than twenty-two Business
Days following the first Business Day on which the Market Disruption Event
occurred or existed. These quotes shall reflect transacted prices. The Floating Price
for the affected Trading Day shall equal a simple average of the quotes obtained
and provided by the Parties consistent with the provisions of this Section 38. Each
Party providing quote(s) to the other Party also shall identify to that other Party the
Dealer(s) and/or the Broker(s) who provided each of the quotes to allow
verification.

“Determination Period” means each calendar month during the term of the relevant
transaction; provided that if the term of the transaction is less than one calendar
month the Determination Period shall be the term of the transaction.
“Market Disruption Event” means, with respect to an index, any of the following
events (the existence of which shall be determined in good faith by the Parties): (a)
the failure of the index to announce or publish information necessary for
determining the Floating Price; (b) the failure of trading to commence or the
permanent discontinuation or material suspension of trading in the relevant options
contract or commodity on the exchange or market acting as the index; (c) the
temporary or permanent discontinuance or unavailability of the index; (d) the
temporary or permanent closing of any exchange acting as the index; or (e) a
material change in the formula for or the method of determining the Floating Price.
“Trading Day” means a day in respect of which the relevant price source published
the relevant price or would have published the relevant price but for the Market
Disruption Event.
38.3

Calculation of Floating Price. For the purposes of the calculation of a Floating
Price, all numbers shall be rounded to three (3) decimal places. If the fourth (4th)
decimal number is five (5) or greater, then the third (3rd) decimal number shall be
increased by one (1), and if the fourth (4th) decimal number is less than five (5),
then the third (3rd) decimal number shall remain unchanged.

38.4

Corrections. For the purposes of determining the relevant prices for any day, if the
price published or announced on a given day and used or to be used to determine
the relevant price is subsequently corrected and the correction is published or
announced by the person responsible for that publication or announcement, either

Party may notify the other Party of (i) that correction and (ii) the amount (if any)
that is payable as a result of that correction. If a Party gives notice that an amount
is so payable, the Party that originally either received or retained such amount will
pay such amount consistent with the provisions of this Section 38.4. The amount
that is payable as a result of the correction shall be included in the billing cycle in
which the notice of the correction is provided.

39.

AMENDMENT:
39.1

This Agreement may be amended upon the submission to FERC and acceptance by
FERC of that amendment. The effective date of the amendment shall be the date
on which FERC allows the amendment to become effective; provided, however, if
the FERC orders a hearing on a filing under Section 205 of the Federal Power Act
proposing an amendment to this Agreement, the amendment as it may be revised
by the FERC shall not become effective until the FERC issues its final order (i.e.
its order on rehearing before any judicial review) on the amendment. The Parties
through the Executive Committee shall direct the filing of any amendments. The
Parties to this Agreement agree to bound by this Agreement as it may be amended,
provided that the Parties possess the right to challenge any amendments at FERC
and to exercise any applicable withdrawal rights under this Agreement.

39.2

Unless otherwise stated in the amendment, all amendments shall apply only to new
transactions entered into or agreed to on or after the effective date of the
amendment. Preexisting agreements and transactions shall operate under the
version of the WSPP Agreement effective at the time of the agreement for the
transaction unless the Parties to a transaction or transactions mutually agree
otherwise.

39.3

An agreement modifying this Agreement or a Confirmation for a transaction needs
no consideration to be binding.

40.

EXECUTION BY COUNTERPARTS:
This Agreement may be executed in any number of counterparts, and upon
execution by all Parties, each executed counterpart shall have the same force and effect as
an original instrument and as if all Parties had signed the same instrument. 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 hereto but having attached to it one or more
signature pages.

41.

WITNESS:
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed
by their duly authorized representative as of the 27th day of July, 1991 (or as of the date of
execution of this Agreement by each Party's duly authorized representation, in the case of
any Party that becomes a signatory to this Agreement subsequent to July 27, 1991).

By:________________________________
Name of signing official:
Title:
Name of Member:
Date:

EXHIBIT A
NETTING
Each Party that executes this Exhibit A to the Agreement agrees to net payments for
transactions under the WSPP Agreement and the applicable Confirmation(s) with any other Party
or Parties which also have agreed to net payments by executing a copy of this Exhibit A. The
Party executing this Exhibit A shall indicate below when it desires that its agreement to net
becomes effective. A Party agreeing to net under this Exhibit A shall comply with the provisions
of Section 28.2 of the Agreement. Defined terms used herein are as defined in the WSPP
Agreement. Netting shall be done in accordance with the following provision:
If the Purchaser and Seller are each required to pay an amount on
the payment due date in the same month for transactions under the
Agreement and Confirmation(s), then such amounts with respect to
each Party will be aggregated and the Parties will discharge their
obligations to pay through netting, in which case the Party owing
the greater aggregate amount will pay to the other party the
difference between the amounts owed consistent with the payment
times in Section 9.2 of the Agreement, unless the Parties have
otherwise agreed to a different payment time as allowed by the
Agreement. Each Party reserves to itself all rights, set-offs,
counterclaims and other remedies and/or defenses to which it is or
may be entitled, arising from or out of the Agreement. All
outstanding payments between the Parties which are to be netted
pursuant to this Exhibit A for transactions under WSPP Agreement
and the applicable Confirmation(s) shall be offset against each other
or set off or recouped therefrom.
__________________________________
Name of Authorized Representative

__________________________
Effective Date for Netting

__________________________________
Name of WSPP Member
__________________________________
Signature of Authorized
Representative

__________________________
Date of Execution

[WSPP SAMPLE FORM – PARTIES ARE FREE TO USE THIS OR DISREGARD IT.]
EXHIBIT B
FORM OF COUNTERPARTY GUARANTEE AGREEMENT
This Guarantee Agreement (this “Guarantee”), dated, as of [__________], 199[__], is
made and entered into by [_____________], a [__________] corporation (“Guarantor”).
WITNESSETH:
WHEREAS, [___________________] (the “Company”) may enter into transactions
involving power sales under the WSPP Agreement (“WSPP Agreement”) and related
Confirmation(s)1 (collectively “Agreements”) with [Company Name] (“Guaranteed Party”); and
WHEREAS, Guarantor will directly or indirectly benefit from the Agreements.
NOW THEREFORE, in consideration of the Guaranteed Party agreeing to conduct
business with Company, Guarantor hereby covenants and agrees as follows:
1.
GUARANTY. Subject to the provisions hereof, Guarantor hereby irrevocably and
unconditionally guarantees the timely payment when due of the obligations of Company (the
“Obligations”) to the Guaranteed Party in accordance with the Agreements. If Company fails to
pay any Obligations, Guarantor shall promptly pay to the Guaranteed Party no later than the next
Business Day (as defined in the WSPP Agreement), after notification, the amount due in the same
currency and manner provided for in the Agreements. This Guarantee shall constitute a guarantee
of payment and not of collection. Guarantor shall have no right of subrogation with respect to any
payments it makes under this Guarantee until all of the Obligations of Company to the Guaranteed
Party are paid in full. The liability of Guarantor under the Guarantee shall be subject to the
following:
(a)
Guarantor’s liability hereunder shall be and is specifically limited to
payments expressly required to be made in accordance with the Agreements (even if such
payments are deemed to be damages) and, except to the extent specifically provided in the
Agreements, in no event shall Guarantor be subject hereunder to consequential, exemplary,
equitable, loss of profits, punitive, tort, or any other even if such fees together with the payments
exceed the cap in Section 1(b), damages, costs, except that Guarantor shall be required to pay
reasonable attorney fees.
(b)
The aggregate liability of the Guarantor shall not exceed [_____] Million
U.S. Dollars [___________].
2.
DEMANDS AND NOTICE. If Company fails or refuses to pay any Obligations,
the Guaranteed Party may make a demand upon Guarantor (hereinafter referred to as a “Payment
1

Demand”). A Payment Demand shall be in writing and shall reasonably and briefly specify in
what manner and what amount Company has failed to pay and an explanation of why such payment
is due, with a specific statement that the Guaranteed Party is calling upon Guarantor to pay under
this Guarantee. A Payment Demand satisfying the foregoing requirements shall be deemed
sufficient notice to Guarantor that it must pay the Obligations. A single written Payment Demand
shall be effective as to any specific default during the continuance of such default, until Company
or Guarantor has cured such default, and additional Payment Demands concerning such default
shall not be required until such default is cured.
3.

REPRESENTATIONS AND WARRANTIES. Guarantor represents and warrants

that:
(a)
it is a corporation duly organized and validly existing under the laws of the
State of [_____________] and has the corporate power and authority to execute, deliver and carry
out the terms and provisions of this Guarantee;
(b)
no authorization, approval, consent or order of, or registration or filing with,
any court or other governmental body having jurisdiction over Guarantor is required on the part of
Guarantor for the execution and delivery of this Guarantee; and
(c)
this Guarantee constitutes a valid and legally binding agreement of
Guarantor enforceable against Guarantor in accordance with its terms, except as the enforceability
of this Guarantee may be limited by the effect of any applicable bankruptcy, insolvency,
reorganization, moratorium or similar laws affecting creditors’ rights generally and by general
principles of equity.
4.
EFFECT OF BANKRUPTCY BY COMPANY. The Guarantor’s obligation to
pay under this Guarantee shall not be affected in any way by the institution with respect to the
Company of a bankruptcy, reorganization, moratorium or similar insolvency proceeding or other
relief under any bankruptcy or insolvency law affecting creditor’s rights or a petition for the
Company’s winding-up or liquidation.
5.
AMENDMENT. No term or provision of this Guarantee shall be amended,
modified, altered, waived, or supplemented except in a writing signed by the Guarantor and
Guaranteed Party hereto.
6.
WAIVERS. Guarantor hereby waives (a) notice of acceptance of this Guarantee;
(b) presentment and demand concerning the liabilities of Guarantor, except as expressly
hereinabove set forth; and (c) any right to require that any action or proceeding be brought against
Company or any other person, or except as expressly hereinabove set forth, to require that the
Guaranteed Party seek enforcement of any performance against Company or any other person,
prior to any action against Guarantor under the terms hereof.
Except as to applicable statutes of limitation, no delay of the Guaranteed Party in the
exercise of, or failure to exercise, any rights hereunder shall operate as a waiver of such rights, a
waiver of any other rights or a release of Guarantor from any obligations hereunder.

Guarantor consents to the renewal, compromise, extension, acceleration or other changes
in the time of payment of or other changes in the terms of the Obligations, or any part thereof or
any changes or modifications to the terms of the Agreements.
Guarantor may terminate this Guarantee by providing written notice of such termination to
the Guaranteed Party and upon the effectiveness of such termination, Guarantor shall have no
further liability hereunder, except as provided in the last sentence of this paragraph. No such
termination shall be effective until fifteen (15) Business Days after receipt by the Guaranteed Party
of such termination notice. No such termination shall affect Guarantor’s liability with respect to
any obligations arising under any transaction entered into prior to the time the termination is
effective, which transaction shall remain guaranteed pursuant to the terms of this Guarantee.
7.
ASSIGNMENT. The Guarantor shall not assign this Guarantee without the express
written consent of the Guaranteed Party. The Guaranteed Party shall be entitled to assign its rights
under this Agreement in its sole discretion.

8.
NOTICE. Any Payment Demand, to the Guaranteed Party or the Guarantor notice,
request, instruction, correspondence or other document to be given hereunder by any party to
another (herein collectively called “Notice”) shall be in writing and delivered personally or mailed
by certified mail, postage prepaid and return receipt requested, or by telegram or telecopier, as
follows:
To [Name of Guaranteed Party]
____________________________
____________________________
____________________________
Attn: _______________________
Fax No.: (___) ________________
To Guarantor:

____________________________
____________________________
____________________________
Attn: _______________________
Fax No.: (___) ________________

Notice given by personal delivery or mail shall be effective upon actual receipt. Notice
given by telegram or telecopier shall be effective upon actual receipt if received during the
recipient’s normal business hours, or at the beginning of the recipient’s next business day after
receipt if not received during the recipient’s normal business hours. All Notices by telegram or
telecopier shall be confirmed promptly after transmission in writing by certified mail or personal
delivery. Any party may change any address to which Notice is to be given to it by giving notice
as provided above of such change of address.
8.
MISCELLANEOUS. THIS GUARANTEE SHALL IN ALL RESPECTS BE
GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE
STATE OF [State], WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. This
Guarantee shall be binding upon Guarantor, its successors and assigns and inure to the benefit of
and be enforceable by the Guaranteed Party, its successors and assigns. The Guarantee embodies
the entire agreement and understanding between Guarantor and the Guaranteed Party and
supersedes all prior agreements and understandings relating to the subject matter hereof. The
headings in this Guarantee are for purposes of reference only, and shall not affect the meaning
hereof. This Guarantee may be executed in any number of counterparts, each of which shall be an
original, but all of which together shall constitute one instrument.
EXECUTED as of the day and year first above written.
[___________________________]
By: ________________________
Name: ______________________
Title: _______________________

EXHIBIT C
SAMPLE FORM FOR CONFIRMATION
1.

Transaction Specific Agreements
The undersigned Parties agree to sell and purchase electric energy, or a PhysicallySettled Option, pursuant to the WSPP Agreement as it is supplemented and modified
below:
(a)
(b)
(c)
(d)
(e)
(f)
(g)

(h)
(i)
(j)
(k)
(l)

(m)

Seller: __________________________________
Purchaser: __________________________________
Period of Delivery: From __\__\__ To __\__\__
Schedule (Days and Hours): __________________
Delivery Rate:________________________________
Delivery Point(s): __________________________
Type of Service (Check as Applicable)
Service Schedule A _________
Service Schedule B _________
Service Schedule C _________
Physically-Settled Option Service Schedule B ______
Physically-Settled Option Service Schedule C ______
Other products per Section 32.6 _________________ [Describe Product]
Contract Quantity: ________ Total MWhrs.
Contract or Strike Price: _____________________
Transmission Path for the Transaction (If Applicable):
Date of Agreement if different: _____________
Additional Information for Physically-Settled Options
(i)
Option Type: Put __________
Call______________
(ii)
Option Style: __________
(iii)
Exercise Date or Period: __________
(iv)
Premium:
__________
(v)
Premium Payment Date: _________
(vi)
Method for providing notice of exercise ________________________
Special Terms and Exceptions:
See Attachment A

[Special Terms and Exceptions shall be shown on an Attachment to this Confirmation.]
___________________________
Name of Trader for Purchaser

___________________________
Name of Trader for Seller

___________________________
Authorized Signature
for Purchaser

___________________________
Authorized Signature
for Seller

___________________________
Date

___________________________
Date

EXHIBIT D
WSPP MEDIATION AND ARBITRATION PROCEDURES
I.

MEDIATION
A.

Informal Mediation. WSPP members with a dispute or a potential dispute
involving transactions under the WSPP Agreement may request non-binding,
informal mediation by contacting the WSPP’s General Counsel and by providing a
brief explanation in writing of the dispute and the remedy being sought. All parties
to the dispute must request this Informal Mediation for it to become effective. After
this contact, a telephonic conference call will be arranged among the affected
WSPP members and the WSPP’s General Counsel, the Chairman of the Operating
Committee, and/or some other independent and knowledgeable person requested
by the Chairman of the Operating Committee to participate. The purpose of the
conference call will be to discuss the issues and to have an independent person or
persons state their views. Best efforts will be made to set up this conference call
within five Business Days after the WSPP’s General Counsel is contacted subject
to accommodating the schedules of all involved. This Informal Mediation shall be
considered as satisfying the Mediation requirements of Section 34.1 of the WSPP
Agreement.

B.

Initiating Formal Mediation. A WSPP member which believes that it possesses
a claim against another WSPP member relating to a WSPP transaction, which is
unable to resolve the dispute through agreement with the other member to the
transaction, and which desires to pursue that claim shall initiate non-binding formal
mediation pursuant to Section 34.1 of the WSPP Agreement.

The member

initiating such mediation shall do so by Serving written notice to the Chairman of
the WSPP Operating Committee, the WSPP’s General Counsel, and the other
members against which the claim is directed. Such notice shall state the nature of
the dispute, the remedy sought, and support the claim.
C.

Response to Document Initiating Formal Mediation. Within eight days, the
member or members against which the claim is directed may provide a response to
the notice which shall be Served on the member which initiated the Mediation, the
Chairman of the WSPP’s Operating Committee, and the WSPP’s General Counsel.

D.

Choosing the Mediator. The Mediator shall be chosen in accordance with the
procedures set forth in Section 34.1 of the WSPP Agreement. Each Party may
suggest persons to be included on the list of Mediators to be presented to the Parties
provided that these suggested persons shall be provided to the WSPP
Representative together with relevant personal histories within two Business Days
of the date by which time the list of Mediators is to be sent out. The WSPP
Representative shall allow at least one person suggested by each Party to be added
to the list of Mediators. A brief personal history of each person on the list of
potential mediators shall be provided to the Parties, with that history showing the
person’s employment over the last five years and any other relevant facts. The
WSPP Representative shall provide the Parties with the list of Mediators within
five days of receipt of notice of the dispute. The Parties then shall have five days
in which to reach agreement on a Mediator or inform the WSPP Representative that
they were unable to reach agreement in which event the WSPP Representative shall
appoint the Mediator consistent with Section 34.1 of the WSPP Agreement. Upon

request of the Parties for expedition, the WSPP Representative shall use best efforts
to expedite this process.
E.

Location for the Formal Mediation. The Parties shall agree on a location for the
Mediation. If the Parties fail to reach agreement, then the WSPP Representative
shall set the location which shall be convenient for the Parties and the Mediator.

F.

Time for the Formal Mediation. The Parties shall agree on the time for the
Mediation after consultation with the Mediator if one has been appointed. If the
Parties fail to reach agreement, then the WSPP Representative shall set the time
which shall not be more than twenty-one days after the notice initiating the
Mediation is received after consultation with the Parties and any Mediator.

G.

Conduct of the Formal Mediation. The Mediator shall have the ability to conduct
the Mediation in any manner which the Mediator believes is appropriate to facilitate
resolution of the dispute. Each Party shall have at least one representative with the
authority to settle the dispute present at the Mediation. The Mediation shall be
private and confidential and the Mediator shall have the authority to exclude any
person not directly involved unless the Parties agree otherwise in writing. At the
Mediation, each Party shall have the right to make a brief presentation of its case
and to question the other Party. Each Party also may be represented by counsel.

H.

Replacement of the Mediator. If the Mediator resigns, withdraws or is no longer
able to serve, then the Parties shall have two Business Days in which to agree on a
new Mediator. If the Parties are unable to agree within such time, the WSPP
Representative shall appoint a replacement Mediator from the list used to select the
first Mediator within two Business Days after being notified that the Parties are

unable to agree. The dates and deadlines in this section may require modification
if the mediator is replaced. Any extensions shall be as limited as possible.
II.

ARBITRATION
A.

Initiating Arbitration. A WSPP member which initiates Arbitration pursuant to
Section 34.2 of the WSPP Agreement shall do so by Serving the Chairman of the
WSPP Operating Committee, the WSPP General Counsel and the members against
which the claim is directed with written notice of its demand for arbitration. Such
notice shall state the nature of the dispute, the remedy sought, and support the claim.

B.

Response. Within ten days of receipt of the notice, any member or members
against which the claim is directed may provide a response to the notice. Such
response must include any counterclaims which the member believes are
appropriate. If a counterclaim is submitted, then the member which submitted the
notice may respond to the counterclaim within ten days of receipt. All such
responses shall be Served on the Parties, the Chairman of the WSPP Operating
Committee, and the WSPP General Counsel.

C.

Choosing the Arbitrator. The Arbitrator shall be chosen in accordance with the
procedures set forth in Section 34.2 of the WSPP Agreement. Each Party may
suggest persons to be included on the list of Arbitrators to be presented to the Parties
provided that these suggested persons are provided to the WSPP Representative
together with relevant personal histories within two business days of the date by
which time the list of Arbitrators is to be sent out. The WSPP Representative shall
allow at least one person suggested by each Party to be added to the list of potential
Arbitrators. A brief personal history of each person on the list of potential

Arbitrators shall be provided to the Parties, with that history showing the person’s
employment over the last five years and any other relevant facts. The WSPP
Representative shall provide the Parties with the list of Arbitrators within seven
days of receipt of notice of the request for Arbitration. The Parties then shall have
ten days in which to reach agreement on the Arbitrator or to inform the WSPP
Representative that they were unable to reach agreement in which event the WSPP
Representative shall appoint the Arbitrator consistent with Section 34.2 of the
Agreement. Upon request of the Parties for expedition, the WSPP Representative
shall use best efforts to cause this process to be expedited.
D.

Location for the Arbitration. The Parties shall agree on a location for the
Arbitration. If the Parties fail to reach agreement, then the WSPP Representative
shall set the location which shall be convenient for the Parties and the Arbitrator.

E.

Time for the Arbitration. The Parties shall agree on the time for the Arbitration
and coordinate that time with the Arbitrator if one has been agreed to or appointed.
If the Parties fail to reach agreement, then the WSPP Representative shall set the
time which shall not be more than 60 days after the notice is received. The WSPP
Representative shall set a time after consultation with the Parties and the Arbitrator
to check their schedules.

F.

Discovery. After appointment of the Arbitrator, each Party shall be entitled to
obtain relevant documents from the other Parties and to take depositions. Each
Party shall respond to such a document request within seven days of receipt of the
request and make its employees or consultants available for depositions to the
extent that the employee or consultant possesses knowledge and information

relevant to the dispute. Each Party shall disclose documents that are confidential
or commercially sensitive subject to a reasonable protective order. Any disputes
concerning discovery shall be promptly referred to the Arbitrator who shall have
authority to resolve such disputes, including the authority to require attendance of
witnesses at depositions. The Federal Rules of Civil Procedure shall apply to
discovery under these procedures.
G.

Conduct of Arbitration if the Parties Agree to Waive an Oral Hearing. If the
Parties agree to waive an oral hearing, then the Parties shall Serve Initial Briefs no
later than 35 days after the notice is received or notify the Arbitrator that they do
not wish to submit any additional documents. Parties shall Serve any Reply Briefs
no later than ten days after the date for Service of Initial Briefs.

H.

Conduct of the Arbitration Hearing. No later than fifteen days before any
hearing, any Party may Serve an Initial Brief or notify the Arbitrator that they do
not wish to submit any additional documents. A Party shall Serve any Reply Brief
no later than five Business Days before any hearing. The Arbitrator shall preside
over any hearing and rule on all objections including objections as to the
admissibility of evidence or whether the questioning is proper. All testimony shall
be submitted under oath. The Arbitrator is not bound to follow any particular rules
governing the conduct of the proceeding. The Arbitrator may rely on legal advice
provided through the WSPP. The Arbitrator may require any person employed by
a Party to attend and testify at the hearing. Each Party shall possess the right to
present evidence, including witnesses, and to cross-examine other Parties’
witnesses. The Arbitration shall be private and the Arbitrator shall have the

authority to exclude any person not directly involved unless the Parties otherwise
agree. Each Party may be represented by counsel. A stenographic record of the
Arbitration shall be kept.
I.

Decision. Within ten Business Days after the end of the Arbitration hearing, the
Arbitrator shall issue his award in writing. If the Parties waived the right to an oral
hearing, then the Arbitrator shall issue the award within ten Business Days of the
last date Briefs were to be submitted. The Arbitrator is not limited in the remedies
he may order so long as any arbitration award is consistent with the provisions and
limitations of the WSPP Agreement and any applicable Confirmation with respect
to the liability and damages of any Party; provided, however, upon agreement of
the Parties to the dispute, the Arbitrator’s choice of remedies may be limited.

J.

Replacement of the Arbitrator. If the Arbitrator resigns, withdraws, or is no
longer able to serve then the Parties shall have two Business Days in which to agree
on a new Arbitrator. If the Parties are unable to agree within such time, the WSPP
Representative shall appoint a replacement Arbitrator from the list used to select
the first Arbitrator within two Business Days after being notified that the Parties
are unable to agree.

The dates and deadlines in this section may require

modification if the mediator is replaced. Any extensions shall be as limited as
possible.
III.

MISCELLANEOUS
A.

Confidentiality. Any Arbitration or Mediation shall be confidential as provided in
Section 34.4 of the WSPP Agreement.

B.

Costs. Costs shall be borne by Parties as provided in Section 34.3 of the WSPP
Agreement.

C.

Restrictions on Lawsuits. Each Party shall be subject to the restrictions provided
in Section 34.2 of the WSPP Agreement.

D.

Attorney-Client/Attorney Workproduct. The Arbitrator or Mediator shall not
take any action which would result in disclosure of information in violation of the
attorney-client privilege or attorney workproduct doctrine.

IV.

DEFINITIONS
A.

Arbitrator or Arbitration. The Arbitrator appointed pursuant to these procedures
and Section 34.2 of the WSPP Agreement and the Arbitration pursuant to these
procedures and the WSPP Agreement.

B.

Initial or Reply Briefs. Written documents submitted by the Parties to support
their positions and respond to each others positions. Such documents shall be
limited to 25 pages.

C.

Business Days. Defined as in the WSPP Agreement.

D.

Mediator or Mediation. The Mediator appointed pursuant to these procedures
and Section 34.1 of the WSPP Agreement and the Mediation pursuant to these
procedures and the WSPP Agreement.

E.

Parties. The WSPP members involved in the Mediation or Arbitration which have
a direct interest in the dispute.

F.

Service, Serving, or Served. The method of service shall be by fax, unless
impracticable because of the size of the document. In all events, the document
should be delivered to the Party by overnight mail. Parties also should attempt to

send the document out by email if possible. Service will be accomplished to a Party
if sent to the Party’s contact person for the disputed transaction. If there are
multiple contact persons for one Party, service to one such person shall suffice.
Service shall be to those individuals or entities specified in this procedures, but
must include service to the Parties, the Mediator or Arbitrator (if either has been
appointed), and to the WSPP General Counsel.
G.

WSPP Representative. The Chairman of the WSPP Operating Committee or his
or her designee for the purposes of the Arbitration or Mediation.

SERVICE SCHEDULE A
ECONOMY ENERGY SERVICE
A-1

PARTIES:
This Service Schedule is agreed upon as a part of this Agreement by the Parties.

A-2

PURPOSE:
The purpose of this Service Schedule is to define additional specific procedures, terms and
conditions for requesting and providing Economy Energy Service.

A-3

TERMS:
A-3.1 A Party may schedule Economy Energy Service from another Party by mutual
agreement; provided, however, that each Party shall be the sole judge as to the
extent to and the conditions under which it is willing to provide or receive such
service hereunder consistent with statutory requirements and contractual
commitments including the Agreement and any applicable Confirmation.
A-3.2 Scheduling of Economy Energy Service hereunder shall be a responsibility of the
Parties involved.
A-3.3 Each Seller/Purchaser may prepare a daily estimate of the amount of Economy Energy
Service that it is willing and able to sell/buy each hour and the associated hourly
sale/purchase price for the next Business Day, plus the weekend and holidays, and
communicate this information to all other Parties via the Hub.
A-3.4 Purchasers shall arrange purchases directly with Sellers, and shall be responsible for
transmission arrangements.
A-3.5 Unless otherwise mutually agreed between the Purchaser and the Seller, all Economy
Energy Service transactions shall be pre-scheduled, and billings shall be based on

amounts and prices agreed to in advance by schedulers, subject to Paragraphs A-3.6
and 3.7 and subject to change by mutual agreement between dispatchers or schedulers
due to system changes.
A-3.6 The price for Economy Energy Service shall be mutually agreed to in advance
between Seller and Purchaser and shall not be subject to the rate caps specified in
Section A-3.7 in either of the following two circumstances:
(1)

where the Seller is a FERC regulated public utility and that Seller has been
authorized to sell power like that provided for under this Service Schedule at
market-based rates; or

(2)

where the Seller is not a FERC regulated public utility.
A Party is a FERC regulated public utility if it is a "public utility" as defined
in Section 201(e) of the Federal Power Act, 16 U.S.C. § 824(e).

A-3.7 Except as provided for in Section A-3.6, the price shall not exceed the Seller's
forecasted Incremental Cost plus up to:

$7.32/kW/ month; $1.68/kW/week;

33.78¢/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16)
hours or less per day. The hourly rate is capped at the Seller's forecasted Incremental
Cost plus 33.78¢/kW/ day. The total demand charge revenues in any consecutive
seven-day period shall not exceed the product of the weekly rate and the highest
demand experienced on any day in the seven-day period. In lieu of payment, such
Parties may mutually agree to exchange economy energy at a ratio not to exceed that
ratio provided for in Section C-3.6 of Service Schedule C. The Seller's forecasted
Incremental Cost discussed above also may include any transmission and/or ancillary
service costs associated with the sale, including the cost of any transmission and/or

ancillary services that the Seller must take on its own system. Any such transmission
and/or ancillary services charges shall be separately identified by the Seller to the
Purchaser for transactions under this Schedule including the exchange of economy
energy. The transmission and ancillary service rate ceilings shall be available through
the WSPP's Hub or homepage. Any such transmission services (and ancillary service
provided in conjunction with such transmission service) by Seller shall be provided
pursuant to any applicable transmission tariff or agreement, and the rates therefore
shall be consistent with such tariff or agreement. The foregoing hourly rate caps (i)
are subject to the submission of cost justification by the applicable Seller to the FERC,
and acceptance by FERC thereof, under Western Systems Power Pool, 122 FERC ¶
61,139 (2008), or (ii) are inapplicable, in the event that the Seller has filed with FERC,
and FERC has accepted, a rate schedule applicable solely to such Seller, which rate
schedule has been, upon the request of the applicable Seller, incorporated into this
Agreement at Schedule “Q” hereof (such incorporation to occur upon Seller’s request
without approval of the WSPP Executive Committee).
A-3.8 Unless otherwise agreed, the Purchaser shall be responsible for maintaining operating
reserve requirements as back-up for Economy Energy Service purchased and the
Seller shall not be required to maintain such operating reserve.
A-3.9 Each Party that is a FERC regulated public utility as defined in A-3.6 shall file the
Confirmation with FERC for each transaction under this Service Schedule with a term
in excess of one year no later than 30 days after service begins if that Party would
have been required to file such Confirmation or similar agreements with FERC under
an applicable FERC accepted market based rate schedule.

SERVICE SCHEDULE B
UNIT COMMITMENT SERVICE
B-1

PARTIES:
This Service Schedule is agreed upon as part of this Agreement by the Parties.

B-2

PURPOSE:
The purpose of this Service Schedule is to define additional specific procedures, terms, and
conditions for requesting and providing Unit Commitment Service.

B-3

TERMS:
B-3.1 A Party may schedule Unit Commitment Service from another Party by mutual
agreement; provided, however, that each Party shall be the sole judge as to the
extent to and the conditions under which it is willing to provide or receive such
service hereunder consistent with statutory requirements and contractual
commitments including the Agreement and any applicable Confirmation. Once an
agreement is reached, then the obligation for Unit Commitment Service becomes a
firm commitment, for both Parties, for the agreed capacity and terms.
B-3.2 Unless otherwise mutually agreed by the Parties involved in a Unit Commitment
Service transaction, the terms set forth in this Service Schedule B shall govern such
transaction.
B-3.3 Unless otherwise agreed between the Purchaser and the Seller, all transactions shall
be prescheduled, subject to any conditions agreed to by schedulers, for a specified unit
for a specified period of time.
B-3.4 Purchasers shall arrange purchases directly with Sellers.
B-3.5 The price for Unit Commitment Service shall be mutually agreed to in advance
between Seller and Purchaser and shall not be subject to the rate caps specified in

Section B-3.6 in either of the following two circumstances:
(1)

where the Seller is a FERC regulated public utility and that Seller has been
authorized to sell power like that provided for under this Service Schedule at
market-based rates; or

(2)

where the Seller is not a FERC regulated public utility.

A Party is a FERC regulated public utility if it is a "public utility" as defined in
Section 201(e) of the Federal Power Act, 16 U.S.C. § 824(e).
B-3.6 Except as provided for in Section B-3.5, the price shall not exceed the Seller's
forecasted Incremental Cost plus up to:

$7.32/kW/month; $1.68/kW/week;

33.78¢/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16)
hours or less per day. The hourly rate is capped at the Seller's forecasted Incremental
Cost plus 33.78¢/kW/day. The total demand charge revenues in any consecutive
seven-day period shall not exceed the product of the weekly rate and the highest
demand experienced on any day in the seven-day period. The Seller's forecasted
Incremental Cost discussed above also may include any transmission and/or ancillary
service costs associated with the sale, including the cost of any transmission and/or
ancillary services that the Seller must take on its own system. Any such transmission
and/or ancillary service charges shall be separately identified by the Seller to the
Purchaser. The transmission and ancillary service rate ceilings shall be available
through the WSPP's Hub or homepage. The foregoing hourly rate caps (i) are subject
to the submission of cost justification by the applicable Seller to the FERC, and
acceptance by FERC thereof, under Western Systems Power Pool, 122 FERC ¶
61,139 (2008), or (ii) are inapplicable, in the event that the Seller has filed with FERC,

and FERC has accepted, a rate schedule applicable solely to such Seller, which rate
schedule has been, upon the request of the applicable Seller, incorporated into this
Agreement at Schedule “Q” hereof (such incorporation to occur upon Seller’s request
without approval of the WSPP Executive Committee).
B-3.7 Start-up costs and no-load costs if included by the Seller shall be stated separately in
the price.
B-3.8 Energy schedules for the Purchaser's share of a unit may be modified by the Purchaser
with not less than a thirty (30) minute notice before the hour in which the change is to
take place, unless otherwise mutually agreed or unforeseen system operating
conditions occur.
B-3.9 Unit Commitment Service is intended to have assured availability; however,
scheduled energy deliveries may be interrupted or curtailed as follows:
(a)

By the Seller by giving proper recall notice to the Purchaser if the Seller and
the Purchaser have mutually agreed to recall provisions,

(b)

By the Seller when all or a portion of the output of the unit is unavailable, by
an amount in proportion to the amount of the reduction in the output of the
unit, unless otherwise agreed by the schedulers,

(c)

By the Seller to prevent system separation during an emergency, provided the
Seller has exercised all prudent operating alternatives prior to the interruption
or curtailment,

(d)

Where applicable, by the Seller to meet its public utility or statutory
obligations to its customers, or

(e)

By either the Seller or the Purchaser due to the unavailability of transmission

capacity necessary for the delivery of scheduled energy.
B-3.10 Each Party that is a FERC regulated public utility as defined above in B-3.5 shall file
the Confirmation with FERC for each transaction under this Service Schedule with a
term in excess of one year no later than 30 days after service begins if that Party would
have been required to file such Confirmation or similar agreements with FERC under
an applicable FERC accepted market based rate schedule.
B-4

BILLING AND PAYMENT PROVISIONS:
B-4.1 Except as provided in Sections B-4.2 and B-5, billing for Unit Commitment Service
shall be computed based upon the agreed upon prices.
B-4.2 In the event the Seller requests recall of Unit Commitment Service in a shorter time
frame than was mutually agreed pursuant to Section B-3.9(a) and the Purchaser
agrees to allow such recall, the Purchaser shall be relieved of any obligation to pay
start-up costs.

B-5

TERMINATION PROVISION:
In the event Unit Commitment Service is curtailed or interrupted except as provided in
Section B-3.9(a), the Purchaser shall have the option to cancel the Unit Commitment
Service at any time by paying the Seller for (i) all energy deliveries scheduled up to the
notice of termination and (ii) all separately stated start-up and no-load costs.

SERVICE SCHEDULE C
FIRM CAPACITY/ENERGY SALE OR EXCHANGE SERVICE
C-1

PARTIES:
This Service Schedule is agreed upon as a part of this Agreement by the Parties.

C-2

PURPOSE:
The purpose of this Service Schedule is to define additional specific procedures, terms, and
conditions for requesting and providing Firm Capacity/Energy Sale or Exchange Service.

C-3

TERMS:
C-3.1 A Party may schedule Firm Capacity/Energy Sale or Exchange Service from another
Party by mutual agreement; provided, however, that each Party shall be the sole judge
as to the extent to and the conditions under which it is willing to provide or receive
such service hereunder consistent with statutory requirements and contractual
commitments including the Agreement and any applicable Confirmation. Once an
agreement is reached, then the obligation for Firm Capacity/Energy Sale or Exchange
Service becomes a firm commitment, for both Parties, for the agreed service and
terms.
C-3.2 Unless otherwise agreed between the Purchaser and the Seller, all transactions shall
be prescheduled, subject to any conditions agreed to by schedulers.
C-3.3 Firm capacity transactions shall include buying, selling, or exchanging capacity
between Parties with or without associated energy. A firm capacity sale or exchange
is a commitment, in accordance with the terms and conditions specified in the
Confirmation, of capacity resources.
C-3.4 Firm energy transactions shall include buying, selling, or exchanging firm energy

between Parties in accordance with the terms and conditions specified in the
Confirmation.
C-3.5 The price for Firm Capacity/Energy Sale or Exchange Service shall be mutually
agreed to in advance between Seller and Purchaser and shall not be subject to the rate
caps specified in Section C-3.6 in either of the following two circumstances:
(1)

where the Seller is a FERC regulated public utility and that Seller has been
authorized to sell power like that provided for under this Service Schedule at
market-based rates; or

(2)

where the Seller is not a FERC regulated public utility.

A Party is a FERC regulated public utility if it is a "public utility" as defined in Section
201(e) of the Federal Power Act, 16 U.S.C. § 824(e).
C-3.6 Except as provided for in Section C-3.5, the price shall not exceed the Seller's
forecasted Incremental Cost plus up to: $7.32/kW/month; $1.68/kW/week;
33.78¢/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16)
hours or less per day. The hourly rate is capped at the Seller's forecasted Incremental
Cost plus 33.78¢/kW/day. The total demand charge revenues in any consecutive
seven-day period shall not exceed the product of the weekly rate and the highest
demand experienced on any day in the seven-day period. Exchange ratios among such
Parties shall be as mutually agreed between the Purchaser and the Seller, but shall not
exceed the ratio of 1.5 to 1.0. The Seller's forecasted Incremental Cost discussed
above also may include any transmission and/or ancillary service costs associated with
the sale, including the cost of any transmission and/or ancillary services that the Seller
must take on its own system. Any such transmission and/or ancillary service charges

shall be separately identified by the Seller to the Purchaser for transactions under this
Schedule including exchanges. The transmission and ancillary service rate ceiling
shall be available through the WSPP's Hub or homepage. Any such transmission
service (and ancillary services provided in conjunction with such transmission
service) by Seller shall be provided pursuant to any applicable transmission tariff or
agreement, and the rates therefore shall be consistent with such tariff or agreement.
The foregoing hourly rate caps (i) are subject to the submission of cost justification
by the applicable Seller to the FERC, and acceptance by FERC thereof, under Western
Systems Power Pool, 122 FERC ¶ 61,139 (2008), or (ii) are inapplicable, in the event
that the Seller has filed with FERC, and FERC has accepted, a rate schedule applicable
solely to such Seller, which rate schedule has been, upon the request of the applicable
Seller, incorporated into this Agreement at Schedule “Q” hereof (such incorporation
to occur upon Seller’s request without approval of the WSPP Executive Committee).
C-3.7 Firm Capacity/Energy Sale or Exchange Service shall be interruptible only if the
interruption is: (a) within any recall time or allowed by other applicable provisions
governing interruptions of service under this Service Schedule, as may be mutually
agreed to by the Seller and the Purchaser, (b) due to an Uncontrollable Force as
provided in Section 10 of this Agreement; or (c) where applicable, to meet Seller’s
public utility or statutory obligations to its customers; provided, however, this
paragraph (c) shall not be used to allow interruptions for reasons other than
reliability of service to native load. If service under this Service Schedule is
interrupted under Section C-3.7(a) or (b), neither Seller nor Purchaser shall be
obligated to pay any damages under this Agreement or Confirmation. If service under

this Service Schedule is interrupted for any reason other than pursuant to Section C3.7(a) or (b), the Non-Performing Party shall be responsible for payment of damages
as provided in Section 21.3 of this Agreement or in any Confirmation.
C-3.8 Each Party that is a FERC regulated public utility as defined in Section C-3.5 shall
file the Confirmation with FERC for each transaction under this Service Schedule
with a term in excess of one year no later than 30 days after service begins if that Party
would have been required to file such Confirmation or similar agreements with FERC
under an applicable FERC accepted market based rate schedule.
C-3.9 Seller shall be responsible for ensuring that Service Schedule C transactions are
scheduled as firm power consistent with the most recent rules adopted by the
applicable NERC regional reliability council.

SERVICE SCHEDULE D
OPERATING RESERVE – SPINNING
AND
OPERATING RESERVE –SUPPLEMENTAL
D-1 PURPOSE
This Service Schedule specifies procedures, terms and conditions pursuant to which the Seller
provides Operating Reserve – Spinning and/or Operating Reserve – Supplemental, as specified in
the Confirmation, to enable the Designated Authority to meet a reserve obligation or to resell as
ancillary services under an OATT.
D-2 DEFINITIONS AND RULES ABOUT THIS SERVICE SCHEDULE
D-2.1 Terms used in this Service Schedule with initial capitalization which are not defined in the
Agreement or this Service Schedule shall have the meanings given to them in the NERC
Glossary and Applicable Standards. In addition to the definitions specified in Section 4 of
the Agreement, the following definitions apply to this Service Schedule.
D-2.1.1 “Applicable Standards” means the NERC Reliability Standards and the respective
reliability standards and criteria of NERC, and of any Regional Reliability
Organization, Balancing Authority, and Reserve Sharing Group applicable to the
Seller’s provision and the Designated Authority’s use of Operating Reserve –
Spinning or Operating Reserve – Supplemental, in force as of the date of the
Confirmation.
D-2.1.2 “Demand Response Resource(s)” has the meaning given in 18 C.F.R. §35.28(b)(5).
D-2.1.3 “Designated Authority” means the Regional Reliability Organization, Balancing
Authority, Reserve Sharing Group or other entity designated in the Confirmation,

which shall have a right to apply the applicable Reserve to the quantity of Reserve
it is required to maintain, and to use such Reserve in accordance with the
Applicable Standards. The Designated Authority and the Purchaser may be the
same entity or two different entities. If the Designated Authority and the Purchaser
are the same entity, then the Designated Authority shall also be the Purchaser for
all purposes under the Agreement.
D-2.1.4 “Good Utility Practice” means any of the practices, methods, and acts engaged in
or approved by a significant portion of the electric utility industry during the
applicable time period in the applicable region, 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 in question was made, could have been expected to
accomplish the desired result in a manner that: (a) is consistent with the Applicable
Standards; (b) gives due consideration to reliability, safety and protection of
equipment and the public welfare; and (c) is 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, or the exclusion of all other
practices, but rather to be a range of acceptable practices, methods, or acts
generally accepted in the region.
D-2.1.5 “NERC Glossary” means the NERC Glossary of Terms Used in Reliability
Standards.
D-2.1.6 “Non-Performance” with respect to Seller shall have the meaning given in Section
D-4.1, and with respect to Purchaser, the meaning given in Section D-4.2.
D-2.1.7 “OATT” refers to the Open Access Transmission Tariff of the Designated

Authority or, if the Designated Authority has no OATT, the pro forma Open
Access Transmission Tariff of the FERC.
D-2.1.8 “OATT Schedule” refers to schedule 5 or 6 of the OATT for sale of ancillary
services, or any other schedule under an OATT for sale of Operating Reserve –
Spinning or Operating Reserve – Supplemental.
D-2.1.9 “Operating Reserve – Spinning” shall have the meaning given in the NERC
Glossary of Terms and the Applicable Standards, and is the product transacted
under schedule 5 or similar schedule under an OATT.
D-2.1.10 “Operating Reserve – Supplemental” shall have the meaning given in the NERC
Glossary of Terms and the Applicable Standards, and is the product transacted
under schedule 6 or similar schedule under an OATT.
D-2.2 The following rules apply to this Service Schedule.
D-2.2.1 In the event of inconsistency between the definition in the NERC Glossary of
Terms and the Applicable Standards, the Applicable Standards shall control.
D-2.2.2 No product sold or transferred under this Service Schedule D shall include reactive
supply and voltage control service, or Regulation and Frequency Response
service.
D-2.2.3 The OATT, OATT Schedules, regulations of the FERC, the NERC Glossary, and
Applicable Standards shall be applied in their forms as of the date of the
Confirmation.
D-3 TERMS OF SERVICE
D-3.1 Each Confirmation entered into under this Service Schedule shall contain the following
information, and may contain other terms and conditions to which the Parties agree:

(a)

A prominent designation of the service, Operating Reserve – Spinning and/or
Operating Reserve – Supplemental, to which the Confirmation applies;

(b) Identification of the Designated Authority and if the Designated Authority is not a
Regional Reliability Organization, the Regional Reliability Organization within which
the Designated Authority is electrically located;
(c) The Standard Confirmation Provisions, as applicable;
(d) Any additional attributes of the Operating Reserve – Spinning or Operating Reserve –
Supplemental, as the Parties may agree;
(e) The means by which requests for energy required to be delivered under the Service
Schedule shall be communicated; and
(f) Any conditions to the effectiveness of the Confirmation, including, for example, the
completion of any arrangements or agreements between the Seller and the Designated
Authority or among the Seller, Designated Authority, and Purchaser.
D-3.2 Contract Price. The Contract Price may include separately stated charges for capacity and
energy, and any agreements concerning transmission arrangements and payment
obligations.
D-3.3 Seller shall provide Operating Reserve – Spinning or Operating Reserve – Supplemental,
as applicable, to the Designated Authority in conformity with the Applicable Standards and
any additional attributes specified in the Confirmation as are consistent with the Applicable
Standards. Seller shall provide such service from one or more generation resources or
Demand Response Resources. Such resources must be physically and operationally
available to respond within the time periods, and in conformance with other technical and
operational criteria, prescribed by, the Applicable Standards for the applicable service, and

as required to conform to any additional attributes stated in the Confirmation.
D-3.4 Obligations Concerning Capacity and Requests for and Delivery of Energy
D-3.4.1 Seller shall provide capacity and deliver energy associated with Operating Reserve
– Spinning or Operating Reserve – Supplemental, in quantities up to the applicable
capacity(ies) specified in the Confirmation for the applicable hour(s), as and when
the Designated Authority requests such delivery in the manner of request specified
in the Confirmation and in accordance with Section D-3.4.2.
D-3.4.2 The Designated Authority shall use the capacity and energy provided by Seller
under this Service Schedule for the sole purpose of satisfying the Designated
Authority’s own obligations pertaining to Operating Reserve – Spinning and
Operating Reserve – Supplemental, as specified in the Applicable Standards or the
Confirmation. Purchaser shall ensure that the Designated Authority shall not
require Seller to deliver energy under this Service Schedule except as and when
the Designated Authority determines, in its good faith discretion reasonably
exercised in accordance with Good Utility Practice or such other criteria as may
be stated in the Confirmation, that such energy is required to enable it to respond
to a contingency or other event for which the service specified in the Confirmation
is permitted to be utilized under the Applicable Standards or as otherwise stated in
the Confirmation.
D-3.5 Inspection and Audit. The Purchaser and Designated Authority shall have the right, to
conduct such inspections and audits of Seller’s records as are reasonable to assure that the
Seller’s provision of services under this Service Schedule and Confirmation conforms to
the Applicable Standards and the Confirmation. The Seller shall have the right to conduct

inspections and audits of the Designated Authority’s records as reasonably required to
assure that any use by the Designated Authority of the services under this Service Schedule
and Confirmation conformed to Section D-3.4.2 and the Confirmation. The Parties may
state further details and conditions in the Confirmation concerning these rights, including,
for example, provisions concerning confidentiality or limiting inspection to an agreed
third-party auditor.
D-3.6 Regulatory Matters – Rate Caps
D-3.6.1 The price for Operating Reserve – Spinning or Operating Reserve – Supplemental
shall not be subject to the rate caps specified in Section D-3.6.2 in either of the
following two circumstances:
(1) where the Seller is a FERC regulated public utility and that Seller has been
authorized to sell power like that provided for under this Service Schedule at
market-based rates; or
(2) where the Seller is not a FERC regulated public utility.
A Party is a FERC regulated public utility if it is a "public utility" as defined in
Section 201(e) of the Federal Power Act, 16 U.S.C. § 824(e).
D-3.6.2 Except as provided for in Section D-3.6.1, the price shall not exceed the Seller's
forecasted Incremental Cost plus up to: $7.32/kW/month; $1.68/kW/week;
33.78¢/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16)
hours or less per day. The hourly rate is capped at the Seller's forecasted
Incremental Cost plus 33.78¢/kW/day. The total demand charge revenues in any
consecutive seven-day period shall not exceed the product of the weekly rate and
the highest demand experienced on any day in the seven-day period. Exchange

ratios among such Parties shall be as mutually agreed between the Purchaser and
the Seller, but shall not exceed the ratio of 1.5 to 1.0. The Seller's forecasted
Incremental Cost discussed above also may include any transmission and/or
ancillary service costs associated with the sale, including the cost of any
transmission and/or ancillary services that the Seller must take on its own system.
Any such transmission and/or ancillary service charges shall be separately
identified by the Seller to the Purchaser for transactions under this Schedule
including exchanges. The transmission and ancillary service rate ceiling shall be
available through the WSPP's Hub or homepage. Any such transmission service
(and ancillary services provided in conjunction with such transmission service) by
Seller shall be provided pursuant to any applicable transmission tariff or
agreement, and the rates therefore shall be consistent with such tariff or agreement.
The foregoing hourly rate caps (i) are subject to the submission of cost justification
by the applicable Seller to the FERC, and acceptance by FERC thereof, under
Western Systems Power Pool, 122 FERC ¶ 61,139 (2008), or (ii) are inapplicable,
in the event that the Seller has filed with FERC, and FERC has accepted, a rate
schedule applicable solely to such Seller, which rate schedule has been, upon the
request of the applicable Seller, incorporated into this Agreement at Schedule “Q”
hereof (such incorporation to occur upon Seller’s request without approval of the
WSPP Executive Committee).
D-4 NON-PERFORMANCE, DAMAGES AND TERMINATION
D-4.1 Seller Non-Performance. “Non-Performance” with respect to Seller means Seller’s failure
to provide capacity or deliver energy to the Designated Authority as this Service Schedule

and the Confirmation require.
D-4.1.1 Purchaser Entitlement to Damages. In the event of Non-Performance by Seller,
Seller shall pay damages to Purchaser calculated in accordance with Section 21.3
of the Agreement.
D-4.1.2 Purchaser Option to Terminate. Purchaser shall have an option to declare any
instance of Seller’s Non-Performance under Section D-4.2 an Event of Default
under the Agreement and the remedies for an Event of Default under Section
22.2(b) of the Agreement shall apply (excluding Section 22.2(a)), provided, that
the right to terminate transactions for such Non-Performance shall be limited to
transactions under this Service Schedule D. Exercise of the termination option
under this Section D-4.1.2 shall not diminish the performing Party’s rights to
collect damages for such Non-Performance under Section D-4.1.1, or to avail itself
of remedies for other Events of Default.
D-4.2 Purchaser Non-Performance. “Non-Performance” with respect to the Purchaser means the
Designated Authority’s failure to receive capacity and/or energy, or the Designated
Authority’s use of capacity and/or energy under this Service Schedule which use does not
conform to Section D-3.4.2 (such capacity and/or energy, the “unauthorized energy”).
D-4.2.1 Seller Entitlement to Damages. In the event of Non-Performance by Purchaser,
Purchaser shall compensate Seller in an amount equal to the quantity of
unauthorized energy Seller was required to deliver during each hour, multiplied
by the energy charge for the applicable hour.
D-4.2.2 Seller Option to Terminate. Seller shall have an option to declare any instance of
Purchaser’s Non-Performance under Section D-4.2 an Event of Default under the

Agreement and the remedies for an Event of Default under Section 22.2(b) of the
Agreement shall apply (but not Section 22.2(a)), provided that the right to
terminate all transactions for such Non-Performance shall be limited to
transactions under this Service Schedule D. Exercise of the termination option
under this Section D-4.2.2 shall not diminish the performing Party’s rights to
collect damages for such Non-Performance under Section D-4.2.1, or to avail itself
of remedies for other Events of Default under the Agreement.
D-4.3 Termination under Section D-4.1.2 or D-4.4.2 shall become effective immediately upon
receipt by the non-performing Party of the Performing Party’s written notice thereof, which
notice shall specify the Non-Performance. If the Performing Party fails to exercise its
termination option arising from an instance of Non-Performance under Section D-4.1.2 or
D-4.2.2 within thirty (30) days following the date the option to terminate arose, then solely
with respect to that instance of Non-Performance, the termination option shall cease to be
available to the Performing Party.
D-4.4 Nothing in this Service Schedule shall restrict the right of either Party to avail itself of other
remedies provided in the Agreement.

SERVICE SCHEDULE E
ENERGY IMBALANCE AND GENERATOR IMBALANCE POWER
E-1 PURPOSE
This Service Schedule states procedures, terms and conditions pursuant to which the Seller
provides Energy Imbalance Power and Generation Imbalance Power to the Purchaser, as specified
in the Confirmation, and the Purchaser receives such service to meet a reliability obligation or to
resell as ancillary services under an OATT.
E-2 DEFINITIONS AND RULES ABOUT THIS SERVICE SCHEDULE
E-2.1

In addition to the definitions specified in Section 4 of the Agreement, the following
definitions apply to this Service Schedule E.
E-2.1.1 “Balancing Power” means a service or product that can be resold as Energy
Imbalance Power or Generator Imbalance Power under Schedules 4 and 9,
respectively, of the OATT or other schedule under an OATT for sale of imbalance
power.
E-2.1.2 “Demand Response Resource(s)” has the meaning given in 18 C.F.R. §35.28(b)(5).
E-2.1.3 “Non-Performance” with respect to Seller shall have the meaning given in Section
E-4.1 and with respect to Purchaser the meaning given in Section E-4.2.
E-2.1.4 “OATT” refers to the Purchaser’s Open Access Transmission Tariff approved by
the FERC or, if the Purchaser has no OATT, the pro forma Open Access
Transmission Tariff of the FERC.
E-2.1.5 “OATT Schedule” refers to schedule 4 or 9 of the OATT for sale of ancillary
services, or any other schedule for sale of imbalance power under an OATT.

E-2.2 The following rules apply to this Service Schedule.

E-2.2.1 No product sold or transferred under this Service Schedule E shall include reactive
supply and voltage control service, or Regulation and Frequency Response
service.
E-2.2.2 The OATT and OATT Schedules shall be applied in their forms as of the date of
the Confirmation.
E-3 TERMS OF SERVICE
E-3.1 Each Confirmation entered into under this Service Schedule shall contain the following
information, and may contain other terms and conditions to which the Parties agree:
(a) A prominent designation of the service, Energy Imbalance and Generator Imbalance
Power, to which the Confirmation applies;
(b) The Standard Confirmation Provisions, as applicable;
(c) Any additional attributes of the Balancing Power, as the Parties may agree;
(d) The means by which requests for energy required to be delivered under the Service
Schedule shall be communicated; and
(e) Any conditions to the effectiveness of the Confirmation.
E-3.2 Contract Price. The Contract Price may include separately stated charges for capacity and
energy, and any agreements concerning transmission arrangements and payment
obligations.
E-3.3 Seller shall provide Balancing Power from one or more generation resources or Demand
Response Resources. Such resources must be physically and operationally available to
respond within the time periods, and in conformance with other technical and operational
criteria, as may be stated in the Confirmation.
E-3.4 Obligations Concerning Capacity and Requests for and Delivery of Energy

E-3.4.1 Upon the requests of the Purchaser, Seller shall provide capacity and deliver
energy associated with Balancing Power to the Purchaser at any rate of flow up to
and including the applicable capacity(ies) and at such intervals as are specified in
the Confirmation for the applicable hour(s).
E-3.4.2 Transmission must be available intra-hour, and may be arranged and scheduled in
any manner that meets the requirements of the Parties.
E-3.5 Regulatory Matters – Rate Caps
E-3.5.1 The price for Balancing Power shall not be subject to the rate caps specified in
Section E-3.5.2 in either of the following two circumstances:
(1) where the Seller is a FERC regulated public utility and that Seller has been
authorized to sell power like that provided for under this Service Schedule at
market-based rates; or
(2) where the Seller is not a FERC regulated public utility.
A Party is a FERC regulated public utility if it is a "public utility" as defined in
Section 201(e) of the Federal Power Act, 16 U.S.C. § 824(e).
E-3.5.2 Except as provided for in Section E-3.5.1, the price shall not exceed the Seller's
forecasted Incremental Cost plus up to: $7.32/kW/month; $1.68/kW/week;
33.78¢/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16)
hours or less per day. The hourly rate is capped at the Seller's forecasted
Incremental Cost plus 33.78¢/kW/day. The total demand charge revenues in any
consecutive seven-day period shall not exceed the product of the weekly rate and
the highest demand experienced on any day in the seven-day period. Exchange
ratios among such Parties shall be as mutually agreed between the Purchaser and

the Seller, but shall not exceed the ratio of 1.5 to 1.0. The Seller's forecasted
Incremental Cost discussed above also may include any transmission and/or
ancillary service costs associated with the sale, including the cost of any
transmission and/or ancillary services that the Seller must take on its own system.
Any such transmission and/or ancillary service charges shall be separately
identified by the Seller to the Purchaser for transactions under this Schedule
including exchanges. The transmission and ancillary service rate ceiling shall be
available through the WSPP's Hub or homepage. Any such transmission service
(and ancillary services provided in conjunction with such transmission service) by
Seller shall be provided pursuant to any applicable transmission tariff or
agreement, and the rates therefore shall be consistent with such tariff or agreement.
The foregoing hourly rate caps (i) are subject to the submission of cost justification
by the applicable Seller to the FERC, and acceptance by FERC thereof, under
Western Systems Power Pool, 122 FERC ¶ 61,139 (2008), or (ii) are inapplicable,
in the event that the Seller has filed with FERC, and FERC has accepted, a rate
schedule applicable solely to such Seller, which rate schedule has been, upon the
request of the applicable Seller, incorporated into this Agreement at Schedule “Q”
hereof (such incorporation to occur upon Seller’s request without approval of the
WSPP Executive Committee).
E-4 NON-PERFORMANCE, DAMAGES AND TERMINATION
E-4.1 Seller Non-Performance. “Non-Performance” with respect to Seller means Seller’s failure
to provide capacity or deliver energy to the Purchaser as this Service Schedule and the
Confirmation require.

E-4.1.1 Purchaser Entitlement to Damages. In the event of Non- Performance by Seller,
Seller shall pay damages to Purchaser calculated in accordance with Section 21.3
of the Agreement.
E-4.1.2 Purchaser Option to Terminate. Purchaser shall have an option to declare any
instance of Seller’s Non-Performance under Section E-4.1 an Event of Default
under the Agreement and the remedies for an Event of Default under Section
22.2(b) of the Agreement shall apply (excluding Section 22.2(a)), provided that
the right to terminate transactions for such Non-Performance shall be limited to
transactions under this Service Schedule E. Exercise of the termination option
under this Section E-4.1.2 shall not diminish the performing Party’s rights to
collect damages for such Non-Performance under Section E-4.1.1, or to avail itself
of remedies for other Events of Default.
E-4.2 Purchaser Non-Performance.

“Non-Performance” with respect to Purchaser means

Purchaser’s failure to receive energy that it had scheduled for receipt under this Service
Schedule and the Confirmation.
E-4.2.1 Seller Entitlement to Damages. In the event of Non-Performance by Purchaser,
Purchaser shall pay damages to Purchaser calculated in accordance with Section
21.3 of the Agreement.
E-4.2.2 Seller Option to Terminate. Seller shall have an option to declare any instance of
Purchaser’s Non-Performance under Section E-4.2 an Event of Default under the
Agreement and the remedies for an Event of Default under Section 22.2(b) of the
Agreement shall apply (excluding Section 22.2(a)), provided that the right to
terminate transactions for such Non-Performance shall be limited to transactions

under this Service Schedule E. Exercise of the termination option under this
Section E-4.2.2 shall not diminish the performing Party’s rights to collect damages
for such Non-Performance under Section E-4.2.1, or to avail itself of remedies for
other Events of Default.
E-4.3 Termination under Section E-4.1.2 or E-4.2.2 shall become effective immediately upon
receipt by the non-performing Party of the Performing Party’s written notice thereof, which
notice shall specify the Non-Performance. If the Performing Party fails to exercise its
termination option arising from an instance of Non-Performance under Section E-4.1.2 or
E-4.2.2 within thirty (30) days following the date the option to terminate arose, then solely
with respect to that instance of Non-Performance, the termination option shall cease to be
available to the Performing Party.
E-4.4 Nothing in this Service Schedule shall restrict the right of either Party to avail itself of other
remedies provided in the Agreement.

SERVICE SCHEDULE R
RENEWABLE ENERGY CERTIFICATE TRANSACTIONS
WITH AND WITHOUT ENERGY
R-1

Introduction; Transaction Documentation; and Rules of Construction. This Service
Schedule R states terms and conditions applicable to REC Transactions entered into by
Parties under the Agreement.
R-1.1 Documentation. Each REC Transaction shall be documented in a Confirmation.
Annex 2 is a Confirmation template, which the Parties may modify and make
subject to any other agreement between them.

A Confirmation for a REC

Transaction will be given legal effect only if a Documentary Writing.
R-1.2 Contract Documents. The Agreement, Service Schedule R, and the fully executed
Confirmation comprise a contract for a REC Transaction. Any conflicts between
or among the Agreement, Service Schedule R, and the Confirmation shall be
resolved in the following order of control: first, the Confirmation; second, Service
Schedule R; and third, the Agreement.
R-1.3 Definitions. Definitions contained in the Agreement and Annex 1 apply to this
Service Schedule R. Any conflicts among definitions contained in these documents
shall be resolved in accordance with Section R-1.2.
R-1.4 Rules of Construction.
R-1.4.1

The Annexes of Service Schedule R are incorporated into and made a
part of this Service Schedule R, as though set forth fully herein.

R-1.4.2

The word “including” shall mean “including but not limited to.” Unless
otherwise specified, the word “Section” refers to a section of this
Service Schedule R and includes all subparts of the specified section.

R-1.4.3

Subject to any legal restrictions applicable to a Party, the Parties to a
REC Transaction may vary any term or condition of this Service
Schedule R for that REC Transaction.

Provisions in this Service

Schedule R concerning such variance of terms, such as “unless
otherwise agreed,” shall not prejudice the generality of the preceding
sentence, provided, that the Parties shall not vary Section C-3.6 of
Service Schedule C, Section B-3.6 of Service Schedule B, and Section
A-3.7 of Service Schedule A.
R-1.4.4

An Applicable Program shall be applicable to a REC Transaction only
if designated expressly in the Confirmation.

No rule of contract

construction or interpretation, and no inference or implication, shall
cause an Applicable Program that is not designated expressly in the
Confirmation to be applicable to a REC Transaction.
R-2

Confirmations; REC Products.
R-2.1 REC Transaction. A “REC Transaction” is a purchase and sale of a REC
separately from or bundled with Energy. A REC Transaction may be for the
purchase and sale of any REC Product defined in Section R-2.3 or another REC
Product the Parties may define.
R-2.2 Confirmations. In addition to other terms and conditions to which the Parties may
agree, the Confirmation:
R-2.2.1

must include the following terms: REC Product, Contract Quantity,
Contract Price, Vintage, and Transfer Date, and whether the
Environmental Attributes covered by the REC are All Attributes,
Program Attributes, or other coverage the Parties may specify;

R-2.2.2

for a bundled REC Transaction (Firm Bundled REC, Resource
Contingent Bundled REC, or Facility As-Run Bundled REC), may
include a single Contract Price which may be allocated between the
REC and the Energy;

R-2.2.3

must identify the Renewable Energy Facility or Renewable Energy
Source if the REC Transaction is All Attributes (Section R-2.4.1) or
Program Attributes (Section R-2.4.2), if a designated Applicable
Program requires such identification, or if the REC Product is Resource
Contingent Bundled REC or Facility As-Run Bundled REC;

R-2.2.4

must designate an Applicable Program if the REC Transaction is
Program Attributes, the Seller is to assure compliance with an
Applicable Program (Sections R-5.2.1, 6.3, and 6.4), or to recover
penalties and alternative compliance payments (Section R-9.1), and if
the REC Transaction is All Attributes, may designate an Applicable
Program (Section 2.4.1).

R-2.3 REC Products. A “REC Product” is any of the following defined products or other
product specified in the Confirmation.
R-2.3.1

Firm REC. A “Firm REC” is a REC purchased and sold in a transaction
that does not include the sale or purchase of energy. The Seller has a
firm obligation to Deliver the REC pursuant to the Confirmation. A
remedy for non-performance is available under Section R-9, except in
the event and to the extent of Uncontrollable Force.

R-2.3.2

Firm Bundled REC. A “Firm Bundled REC” is a REC purchased and
sold in a transaction that includes the purchase and sale of Energy. The

Seller has a firm obligation to Deliver the REC and Energy pursuant to
the Confirmation. A remedy for non-performance is available under
Section R-9, except in the event and to the extent of Uncontrollable
Force. The terms and conditions of Service Schedule C apply to the
purchase and sale of Energy associated with a Firm Bundled REC as the
Parties may modify such terms and conditions in the Confirmation,
subject to the proviso stated in Section R-1.4.3. The hourly rate caps
identified in Section C-3.6 of Service Schedule C shall apply, except (1)
where the Seller is a FERC regulated “public utility” as defined in
Section 201(e) of the Federal Power Act, 16 U.S.C. § 824(e), and that
Seller has been authorized to sell power like that provided for in Service
Schedule C at market-based rates; or (2) where the Seller is not such a
FERC regulated “public utility.” When such hourly rate caps apply, (a)
if the Contract Price is allocated between the REC and the Energy, the
hourly rate caps shall apply to the Contract Price for the Energy and not
the REC; and (b) if the Contract Price is not allocated between the REC
and the Energy, the hourly rate caps shall apply to the bundled Contract
Price.
R-2.3.3

Resource Contingent REC. A “Resource Contingent REC” is a REC
purchased and sold in a transaction that does not include the sale or
purchase of Energy. The Seller has a resource contingent obligation to
Deliver the REC pursuant to the Confirmation. A remedy for nonperformance is available under Section R-9, except in the event and to
the extent: (i) of Uncontrollable Force; (ii) the Renewable Energy

Facility identified in the Confirmation was not on line to produce energy
required for the REC due to Forced Outage, Scheduled Maintenance, or
Fuel Impediment; or (iii) of the occurrence of such other circumstances
to which the Parties may have agreed in the Confirmation, resulting in
a reduction of output or unavailability to produce energy required for
the REC. In the event and to the extent of an outage under (ii) or, if
applicable, (iii), the resulting reduction in output for the applicable hour
shall be allocated among all purchasers of RECs from the Renewable
Energy Facility who are identified in the Confirmation (including
purchasers identified under any provisions in the Confirmation allowing
for subsequent identification) in accordance with any priorities or shares
stated in the Confirmation, and if no priorities or shares are stated in the
Confirmation, then proportionately in accordance with such purchasers’
contract quantities under contracts with Seller.
R-2.3.4

Resource Contingent Bundled REC.
(a)

A “Resource Contingent Bundled REC” is a REC purchased and
sold in a transaction that includes the purchase and sale of
Energy. The Seller has a resource contingent obligation to
Deliver the REC and Energy pursuant to the Confirmation. A
remedy for non-performance is available under Section R-9,
except in the event and to the extent: (i) of Uncontrollable Force;
(ii) the Renewable Energy Facility identified in the
Confirmation was not on line to produce energy required for the
REC or Delivery, due to Forced Outage, Scheduled

Maintenance, or Fuel Impediment; or (iii) of the occurrence of
such other circumstances to which the Parties agreed in the
Confirmation, resulting in a reduction of output or unavailability
to produce energy required for the REC or Delivery. In the event
and to the extent of an outage under (ii) or, if applicable, (iii),
the resulting reduction in output for the applicable hour shall be
allocated among all purchasers of RECs and energy from the
Renewable Energy Facility who are identified in the
Confirmation (including purchasers identified under any
provisions in the Confirmation allowing for subsequent
identification) in accordance with any priorities or shares stated
in the Confirmation, and if no priorities or shares are stated in
the Confirmation, then proportionately in accordance with such
purchasers’ contract quantities under contracts with Seller.
(b)

The terms and conditions of Service Schedule B apply to the
purchase and sale of Energy associated with a Resource
Contingent Bundled REC as modified herein and as may be
modified in the Confirmation, subject to the proviso stated in
Section R-1.4.3. The hourly rate caps identified in Section B3.6 of Service Schedule B shall apply, except (1) where the
Seller is a FERC regulated “public utility” as defined in Section
201(e) of the Federal Power Act, 16 U.S.C. § 824(e), and that
Seller has been authorized to sell power like that provided for in
Service Schedule B at market-based rates; or (2) where the Seller

is not such a FERC regulated “public utility.” When such hourly
rate caps apply, (a) if the Contract Price is allocated between the
REC and the Energy, the hourly rate caps shall apply to the
Contract Price for the Energy and not the REC; and (b) if the
Contract Price is not allocated between the REC and the Energy,
the hourly rate caps shall apply to the bundled Contract Price.
Service Schedule B Section B-3.8 is modified to state the
following:
Energy schedules for the Purchaser's share of a
Renewable Energy Facility may be modified by the
Purchaser with not less than a thirty (30) minute notice
before the hour in which the modification is to occur,
unless otherwise agreed or unforeseen system operating
conditions occur, or as otherwise required by, or
pursuant to customary practice in, the applicable regional
reliability council. A reduction in the energy schedule
shall be made commensurately for the REC requirement
for the applicable hour. Seller shall notify Purchaser of
volumes to be delivered no later than thirty (30) minutes
before the hour in which delivery is to occur unless
otherwise agreed or such notification is infeasible due to
unforeseen system operating conditions. Seller shall
timely notify the Purchaser of Scheduled Maintenance.
The following is added at the end of Section B-3.9:

(f) By the Seller when all or a portion of the unit is
unavailable due to Fuel Impediment, unless otherwise
agreed by the schedulers.
R-2.3.5

Facility As-Run REC. A “Facility As-Run REC” is a REC purchased
and sold in a transaction that does not include the sale or purchase of
Energy. The Seller is obligated to Deliver the REC pursuant to the
Confirmation.

A remedy for non-performance is available under

Section R-9, except in the event and to the extent that, for any reason or
no reason, the Renewable Energy Facility identified in the Confirmation
was not on line to produce energy required for the REC.

If the

Renewable Energy Facility designated in the Confirmation is not
operated, the resulting reduction in output for the applicable hour shall
be allocated among all purchasers of RECs from the Renewable Energy
Facility who are identified in the Confirmation (including purchasers
identified under any provisions in the Confirmation allowing for
subsequent identification) in accordance with any priorities or shares
stated in the Confirmation, and if no priorities or shares are stated in the
Confirmation, then proportionately in accordance with such purchasers’
contract quantities under contracts with Seller.
R-2.3.6

Facility As-Run Bundled REC.
(a)

A “Facility As-Run Bundled REC” is a REC purchased and sold
in a transaction that includes the purchase and sale of Energy.
The Seller has an obligation to Deliver the REC and Energy
pursuant to the Confirmation. A remedy for non-performance is

available under Section R-9, except in the event and to the extent
that, for any reason or no reason, the Renewable Energy Facility
identified in the Confirmation was not on line to produce energy
required for the REC or Delivery. If the Renewable Energy
Facility designated in the Confirmation is not operated, the
resulting reduction in output for the applicable hour shall be
allocated among all purchasers of RECs and energy from the
Renewable Energy Facility who are identified in the
Confirmation (including purchasers identified under any
provisions in the Confirmation allowing for subsequent
identification) in accordance with any priorities or shares stated
in the Confirmation, and if no priorities or shares are stated in
the Confirmation, then proportionately in accordance with such
purchasers’ contract quantities under contracts with Seller.
(b)

The terms and conditions of Service Schedule A apply to the
purchase and sale of Energy associated with a Facility As-Run
Bundled REC as modified herein and as may be modified in the
Confirmation, subject to the proviso stated in Section R-1.4.3.
The hourly rate caps identified in Section A-3.7 of Service
Schedule A shall apply, except (1) where the Seller is a FERC
regulated “public utility” as defined in Section 201(e) of the
Federal Power Act, 16 U.S.C. § 824(e), and that Seller has been
authorized to sell power like that provided for in Service
Schedule A at market-based rates; or (2) where the Seller is not

such a FERC regulated “public utility.” When such hourly rate
caps apply, (a) if the Contract Price is allocated between the
REC and the Energy, the hourly rate caps shall apply to the
Contract Price for the Energy and not the REC; and (b) if the
Contract Price is not allocated between the REC and the Energy,
the hourly rate caps shall apply to the bundled Contract Price.
Service Schedule A Section A-3.3 is modified to state the
following:
Energy schedules may be modified by the Purchaser or
Seller with not less than a thirty (30) minute notice
before the hour in which the modification is to occur,
unless otherwise agreed or unforeseen system operating
conditions occur, or as otherwise required by, or
pursuant to customary practice in, the applicable regional
reliability council. A reduction in the energy schedule
shall be made commensurately for the REC requirement
for the applicable hour. Seller shall notify Purchaser of
volumes to be delivered no later than thirty (30) minutes
before the hour in which delivery is to occur unless
otherwise agreed or such notification is infeasible due to
unforeseen system operating conditions.
R-2.4 Environmental Attributes Contained In The REC. The Confirmation may
describe the Environmental Attributes covered by the REC as All Attributes,
Program Attributes, or as the Parties otherwise may agree. If the Confirmation does

not designate a REC Transaction as Program Attributes or otherwise limit the
Environmental Attributes conveyed, and if a Renewable Energy Facility or
Renewable Energy Source is specified, the REC Transaction shall be All Attributes.
A designation of All Attributes will not be effective unless a Renewable Energy
Facility or Renewable Energy Source is designated in the Confirmation.
R-2.4.1

All Attributes.

An “All Attributes” REC conveys all of the

Environmental Attributes the Renewable Energy Facility or Renewable
Energy Source designated in the Confirmation is capable of producing,
whether known or unknown on the Effective Date, including, at a
minimum, all Environmental Attributes required by any Applicable
Program designated in the Confirmation. Seller disclaims any warranty
that Environmental Attributes other than those required by an
Applicable Program designated in the Confirmation fulfill the
requirements of any other Applicable Program.

To establish the

Environmental Attributes conveyed, the Confirmation may include a
specification thereof.
R-2.4.2

Program Attributes.

A “Program Attributes” REC conveys the

Environmental Attributes required by an Applicable Program
designated in the Confirmation. It conveys no other Environmental
Attributes, the rights to which are retained by the Seller. The Parties
should verify that a designated Tracking System will recognize a
Program Attributes REC. (Note, WREGIS does not recognize a
Program

Attributes

Attributes.)

limitation

upon

conveyed

Environmental

R-3

Delivery and Title.
R-3.1 Unbundled REC Transactions. This Section R-3.1 applies if the REC Product is
a Firm REC, Resource Contingent REC, or Facility As-Run REC.
R-3.1.1

Delivery. “Deliver(y)(ed)” occurs upon completion of Seller’s transfer
of the Contract Quantity to Purchaser.

If a Tracking System is

designated in the Confirmation, Seller shall cause transfer in accordance
with the rules and procedures of the Tracking System. If the Tracking
System does not state such rules or procedures, then Delivery shall
occur upon the Tracking System’s transfer of the REC into Purchaser’s
account. If a Tracking System is not designated in the Confirmation,
Delivery is completed upon Seller’s delivery to Purchaser of an
Attestation.
R-3.1.2

Acceptance.

“Accept(ance)(ed)” means Purchaser’s receipt of

Delivery of the REC from Seller, without Purchaser’s rejection. If a
Tracking System is designated in the Confirmation, Purchaser shall
receive a transfer in accordance with the rules and procedures of the
Tracking System, and Acceptance (or rejection) shall be made within
five (5) Business Days following the date the Tracking System gives
electronic notice to Purchaser that it has initiated transfer (this deadline
applies regardless of any different period stated in the Tracking
System’s rules and procedures) and if timely rejection is not made, then
the Delivery is Accepted. If a Tracking System is not designated in the
Confirmation, Acceptance occurs upon Purchaser’s Acceptance,

without rejection within five (5) Business Days of delivery, of the
Attestation delivered by Seller.
R-3.1.3

Passage of Title. Title to the REC shall pass from Seller to Purchaser
upon Delivery and Acceptance.

R-3.2 Bundled REC Transactions. This Section R-3.2 applies if the REC Product is a
Firm Bundled REC, Resource Contingent Bundled REC, or Facility As-Run
Bundled REC.
R-3.2.1

Delivery.

“Delivery(y)(ed)” occurs upon completion of Seller’s

transfer to Purchaser of the Contract Quantity of the REC and the
Contract Quantity of the Energy.

Delivery of the REC shall be

completed in accordance with Section R-3.1.1. Delivery of Energy shall
be completed in accordance with the terms and conditions of the
Confirmation and the Agreement.
R-3.2.2

Acceptance. “Acceptance” of the REC occurs in the manner specified
in Section R-3.1.2, and of the Energy upon receipt at the delivery point
in accordance with the Confirmation.

R-3.2.3

Passage of Title. If the Vintage of the REC is prior to the Effective
Date, title to the REC passes from Seller to Purchaser on the Effective
Date or other date to which the Parties agree. If the REC is to be
generated on or after the Effective Date, title to the REC passes upon
the generation of each megawatt hour of energy required for production
of the REC, and Seller shall hold the REC in trust for Purchaser until
Delivery. Passage of title to Energy occurs pursuant to the Agreement.

R-3.3 Actions Required of Parties to Assure Delivery.

R-3.3.1

Provision of Generation Information; Required Actions. No less
than monthly, Seller shall provide Purchaser with a written statement
setting forth for applicable periods the quantities of Seller’s generation
of energy for production of the REC. Seller shall promptly take all
actions and do all things necessary and appropriate to cause the
designated Tracking System, if any, to transfer the REC to Purchaser,
including promptly providing all required information and documents
in the required forms, and paying any and all fees the Tracking System
imposes on Seller.

If the Confirmation provides for a designated

Tracking System to expedite issuance of certificates (for example,
forward transfer certificates in WREGIS), Seller shall promptly take all
actions required to cause such expedition. If no Tracking System is
designated in the Confirmation, then upon creation of the REC Seller
shall promptly deliver the Attestation to Purchaser.
R-3.3.2

Failure to Issue REC. Seller is responsible for transfer and issuance
of RECs by the Tracking System; Purchaser’s sole responsibilities are
maintenance of an account with the Tracking System and Acceptance
of conforming RECs pursuant to Section R-3.1.2. Without prejudice to
the immediately preceding sentence, in the event a Tracking System
designated in the Confirmation declines to issue an electronic credit or
physical certificate to document the attempted transfer, Delivery, or
Acceptance of a REC, each Party will provide the other Party with all
documents, communications, and information sent to or received from
the Tracking System that pertain thereto. The Parties will cooperate,

and each Party will complete any uncompleted items for which it is
responsible, each at its own expense. If following such efforts, and due
to no failure of Seller to take all required actions, the Tracking System
does not issue the electronic credit or physical certificate to document
the attempted transfer, Delivery, or Acceptance of the REC, Seller may,
upon Purchaser’s agreement (which Purchaser may decline in its
discretion), provide an Attestation to Purchaser to effect Delivery. The
obligations under this Section R-3.3.2 shall not be construed to diminish
the Seller or the Purchaser’s respective rights and obligations under the
Agreement, Service Schedule R, and the Confirmation.
R-3.4 Conveyance and Transfer. As of both Delivery and passage of title, Seller shall
transfer and convey to Purchaser all right, title, and interest in and to the REC and
all Environmental Attributes underlying the REC pursuant to the Confirmation, and
the exclusive right to any and all Reporting Rights Seller may have in or to the REC
and the Environmental Attributes, free and clear of any liens, security interests, or
other encumbrances.
R-4

Charges; Credit. The charge shall be an amount equal to the Contract Price multiplied by
the Delivered and Accepted quantity, without prejudice to the right to recover damages
owed in accordance with Section R-9. The Parties may state any credit terms and
conditions to which they agree in the Confirmation; Section 27 of the Agreement applies
unless otherwise agreed.

R-5

Governing Law; Change in Law.
R-5.1 Governing Law. Section 24 of the Agreement applies except as follows. If an
Applicable Program is designated in the Confirmation, all performance obligations

pursuant to the REC Transaction concerning the creation, issuance, transfer,
tracking and retirement of the REC shall be governed as follows:
R-5.1.1

If the Applicable Program was created by the laws of a Governmental
Authority, then by the laws, rules, regulations, orders, and judicial
precedent of such Governmental Authority;

R-5.1.2

If the Applicable Program was not created by the laws of a
Governmental Authority, but is a voluntary program, then Section 24 of
the Agreement applies without modification, and the Parties shall be
bound contractually to comply with the standards and criteria of the
voluntary Applicable Program.

R-5.2 Change in Law.
R-5.2.1

Applicability. Section R-5.2 applies only to REC Transactions for
which an Applicable Program is designated in the Confirmation. In a
REC Transaction for which no Applicable Program is designated, Seller
makes no representation or warranty concerning compliance with any
particular Applicable Program and any such representation or warranty
is expressly disclaimed.

R-5.2.2

Definitions.
(a)

“Change in Law” means any addition or amendment, by a
Governmental Authority, to any laws, rules, regulations, orders,
or judicial precedent, that applies to an Applicable Program
designated in the Confirmation, that is enacted or issued after the
Effective Date and nullifies compliance of the REC with the
Applicable Program. An addition or amendment that is enacted

or issued before the Effective Date but effective on or after the
Effective Date is not a Change in Law.
(b)

“Regulatorily Continuing” means a REC Transaction in which
the REC and Environmental Attributes conform to the
requirements of an Applicable Program designated in the
Confirmation as such requirements exist on the Effective Date
and the Transfer Date, including requirements modified or
added by a Change in Law.

(c)

“Not Regulatorily Continuing” means a REC Transaction in
which the REC and Environmental Attributes conform to the
requirements of an Applicable Program designated in the
Confirmation as such requirements exist on the Effective Date
only, and the REC and Environmental Attributes are not
required to conform to requirements modified or added by a
Change in Law.

R-5.2.3

Default Designation as Regulatorily Continuing. A REC Transaction
as to which an Applicable Program is designated in the Confirmation
shall be Regulatorily Continuing unless the Parties specify in the
Confirmation that the REC Transaction is Not Regulatorily Continuing.

R-5.2.4

Effect of Change In Law in Regulatorily Continuing REC
Transaction.
(a)

If a Change in Law occurs in a Regulatorily Continuing REC
Transaction, Seller shall be obligated to make reasonable efforts
to attain compliance with the designated Applicable Program,

the costs of which shall not be required to exceed any cost cap
specified in the Confirmation. If despite such efforts to attain
compliance, including reasonable expenditures, Seller cannot
obtain compliance and Purchaser refuses to accept Delivery of
the REC due to the Change in Law, Seller shall not be liable for
damages under Section R-9.
(b)

In the event Purchaser refuses to accept Delivery of the REC
under Section 5.2.4(a), and Seller has Delivered energy to
Purchaser in the REC Transaction, Purchaser shall not be
relieved of its obligation to pay for such energy, which payment
shall be either at the price allocated to energy in the
Confirmation, if any, and if no allocation is made, then at an
amount equal to the Replacement Price.

R-5.2.5

Amendment to Address Change In Law. Nothing in this Section R5.2 shall be construed to preclude the Parties from agreeing to amend
the Confirmation to permit a Seller to perform its obligations in a REC
Transaction as to which a Change in Law has occurred.

R-6

Seller Representations and Warranties. In each REC Transaction, Seller represents and
warrants to Purchaser the following:
R-6.1 As of both Delivery and passage of title, Seller has and conveys to Purchaser all
right, title, interest in and to the REC and all Environmental Attributes underlying
the REC as required by the Confirmation, and the exclusive right to any and all
Reporting Rights Seller may have in or to the REC and Environmental Attributes,
free and clear of any liens, security interests, or other encumbrances.

R-6.2 As of both Delivery and passage of title, the REC and Environmental Attributes
conform to the requirements of the REC Transaction.
R-6.3 If the REC Transaction is Regulatorily Continuing (and an Applicable Program is
designated in the Confirmation), subject to any limits upon Seller’s obligations
under Section R-5.2.4, as of both Delivery and passage of title, that the REC and
Environmental Attributes conform to the requirements of the designated Applicable
Program as such requirements exist on the Effective Date and the Transfer Date.
R-6.4 If the REC Transaction is Not Regulatorily Continuing (and an Applicable Program
is designated in the Confirmation), as of both Delivery and passage of title, that the
REC and Environmental Attributes conform to the requirements of the designated
Applicable Program as such requirements exist on the Effective Date.
R-6.5 With respect to deliveries of Energy in REC Transactions for Firm Bundled REC,
Contingent Resource Bundled REC, and Facility As-Run Bundled REC, that Seller
has complied with the representations and warranties stated in Section 33 of the
Agreement.
SELLER DISCLAIMS ALL OTHER WARRANTIES, EXPRESS OR IMPLIED,
INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A
PARTICULAR PURPOSE.
R-7

Records; Confidentiality
R-7.1 Correction of Records. If any statement, charge or computation concerning a
REC Transaction is inaccurate, the Parties promptly shall make any adjustments to
records as reasonably necessary to correct such inaccuracy, and make any
adjustment of payments required to correspond to the corrected records, provided,

that Purchaser shall not be required to pay a higher Contract Price or accept a lower
Contract Quantity than the Confirmation requires.
R-7.2 Exception to Confidentiality.

Purchaser has the right to disclose to any

Governmental Authority having jurisdiction over Purchaser, or to any voluntary
Applicable Program and the person or entity specified by the rules of procedures of
the voluntary Applicable Program to perform certification, any information
necessary to demonstrate Purchaser’s compliance with an Applicable Program
(whether or not designated in the Confirmation); provided, however, that Purchaser
shall use reasonable efforts to minimize the scope of any such disclosure and shall
require, as may be feasible, that the recipient maintain the confidentiality of any
documents or confidential information governed by the provisions of Section 30.1
of the Agreement, including, if permitted under applicable procedures of the
Governmental Authority or such administrator, and subject to any applicable public
records laws, seeking a protective order or similar protective mechanism in
connection with any disclosure. With respect to a REC, Purchaser also has the right
to disclose the following to any customer or affiliate of Purchaser that is
participating in any voluntary or mandatory Applicable Program: the Renewable
Energy Source, the location of any Renewable Energy Facility designated in the
Confirmation, and monthly generation quantities of energy underlying the REC.
R-8

Uncontrollable Force. The following is substituted for the first sentence of the second
paragraph of Section 10 of the Agreement:
The following shall not be considered “Uncontrollable Forces”: (i) Seller’s cost of
producing or obtaining the REC or energy (or ability to sell the REC or energy at a
price exceeding the Contract Price); (ii) the loss or failure of Seller’s supply,

including materials or equipment; or (iii) Purchaser’s inability economically to use
or resell the REC or energy.
The following is added at the end of the second paragraph of Section 10 of the Agreement:
If production of energy at a Renewable Energy Facility designated in the
Confirmation is curtailed due to an Uncontrollable Force, any production during
the period of such curtailment shall be allocated as follows: first, among all
purchasers of Firm RECs, Firm Bundled RECs, Resource Contingent RECs,
Resource Contingent Bundled RECs, and energy purchased under Service
Schedules B and C, proportionately to such purchasers’ contract quantities under
contracts with Seller during such period and subject to any priorities or shares stated
in the Confirmation, and second, to all purchasers of Facility As-Run RECs,
Facility As-Run Bundled RECs and energy purchased under Service Schedule A,
proportionately to such purchasers’ contract quantities under contracts with Seller
during such period and subject to any priorities or shares stated in the Confirmation.
R-9

Remedies for Non-Performance.
R-9.1 Damages. Section 21.3 of the Agreement, as modified in this Section 9, applies to
REC Transactions.
R-9.1.1

Failure to Receive or Deliver in Unbundled REC Transactions. This
Section R-9.1.1 applies to REC Transactions for Firm REC, Resource
Contingent REC, and Facility As-Run REC. Section 21.3(a)(3) and (5)
of the Agreement are inapplicable. Section 21.3(a)(1) of the Agreement
is modified as follows:
If Purchaser refuses to Accept Delivery of RECs Delivered by
Seller in accordance with the Confirmation, then Purchaser shall

be liable to Seller for the product of (i) and (ii) where (i) is the
amount, if any, by which the Contract Price exceeded the Resale
Price and (ii) is the amount by which the quantity of RECs
Purchaser refused to Accept was less than the Contract Quantity,
subject to any limitations stated in the Confirmation.
21.3(a)(2) is modified as follows:
If Seller fails to Deliver RECs to Purchaser in accordance with
the Confirmation, then Seller shall be liable to Purchaser for: (a)
the product of (i) and (ii) where (i) is the amount, if any, by
which the Replacement Price exceeded the Contract Price and
(ii) is the amount by which the quantity of RECs Seller
Delivered was less than the Contract Quantity; plus (b) if an
Applicable Program is specified, the amount, if any, of penalties
and alternative compliance payments a Governmental Authority
required Purchaser to pay due to Seller’s non-performance, and
which penalties or alternative compliance payments are no
longer subject to judicial review, subject to any limitations stated
in the Confirmation.
R-9.1.2

Failure to Receive or Deliver in Bundled REC Transactions.
(a)

Price Not Allocated between REC and Energy. This Section
R-9.1.2(a) applies to REC Transactions for Firm Bundled REC,
Resource Contingent Bundled REC, and Facility As-Run
Bundled REC, and in which the Confirmation does not allocate

the Contract Price between the REC and Energy.

Section

21.3(a)(1) of the Agreement is modified as follows:
If Purchaser refuses to Accept Delivery from Seller in
accordance with the Confirmation, then Purchaser shall be
liable to Seller for: (a) the product of (i) and (ii) where (i) is
the amount, if any, by which the Contract Price exceeded the
Resale Price, and (ii) is the amount by which the quantity of
RECs and Energy Purchaser refused to Accept was less than
the Contract Quantity, plus (b) the amount of transmission
charge(s), if any, for firm transmission service upstream of
the delivery point, which Seller incurred to achieve the
Resale Price, less the reduction, if any, in transmission
charge(s) achieved as a result of the reduction in Purchaser’s
schedule or receipt of Energy (based on Seller’s
commercially reasonable efforts to achieve such reduction),
subject to any limitations stated in the Confirmation. If the
Purchaser refused to Accept Delivery of RECs but Accepted
Delivery of Energy, then Purchaser shall pay Seller for such
received Energy at the Resale Price of the Energy; if the
Purchaser refused to Accept Delivery of Energy but
Accepted Delivery of RECs, the Purchaser shall pay Seller
for Accepted RECs at an amount equal to the Contract Price
less the Resale Price of the Energy.
Section 21.3(a)(2) of the Agreement is modified as follows:

If Seller fails to Deliver to Purchaser in accordance with the
Confirmation, then Seller shall be liable to the Purchaser for:
(a) the product of (i) and (ii) where (i) is the amount, if any,
by which the Replacement Price exceeded the Contract
Price, and (ii) is the amount by which the quantity of RECs
and Energy Delivered was less than the Contract Quantity;
plus (b) the amount of transmission charge(s), if any, for firm
transmission service downstream of the delivery point,
which Purchaser incurred to achieve the Replacement Price,
less the reduction, if any, in transmission charge(s) achieved
as a result of the reduction in Seller’s schedule or delivery of
Energy (based on Purchaser’s commercially reasonable
efforts to achieve such reduction), plus (c) if an Applicable
Program is specified, the amount, if any, of penalties and
alternative compliance payments a Governmental Authority
required Purchaser to pay due to Seller’s non-performance,
and which penalties or alternative compliance payments are
no longer subject to judicial review, subject to any
limitations on such amounts stated in the Confirmation. In
the event Seller Delivers Energy but not RECs, and
regardless of Purchaser’s receipt of Energy, Purchaser shall
not be required to pay Seller for such Energy.
(b)

Price Allocated between REC and Energy. This Section R9.1.2(b) applies to REC Transactions for Firm Bundled REC,

Resource Contingent Bundled REC, and Facility As-Run
Bundled REC, in which the Confirmation sets forth an allocation
of the Contract Price between the REC and energy.
(i)

If Purchaser refuses to Accept Delivery of RECs in
accordance with the Confirmation, then Purchaser shall
be liable to Seller as set forth in Section R-9.1.1.

(ii)

Subject to part (v) of this Section, if Seller fails to
Deliver RECs in accordance with the Confirmation, then
the Seller shall be liable to Purchaser as set forth in
Section R-9.1.1.

(iii)

If Purchaser refuses to receive Delivery of Energy in
accordance with the Confirmation, then Section 21.3(a)
of the Agreement shall apply as set forth in the
Agreement without modification by this Service
Schedule R.

(iv)

If Seller fails to Deliver Energy in accordance with the
Confirmation, then Section 21.3(a) of the Agreement
shall apply as set forth in the Agreement without
modification by this Service Schedule R.

(v)

In the event Seller Delivers Energy but fails to Deliver
RECs, and regardless of Purchaser’s receipt of Energy,
Purchaser shall not be required to pay Seller for such
Energy.

R-10 Other Modifications of the Agreement for REC Transactions.

R-10.1 Revised Agreement Definitions.

For purposes of REC Transactions, the

following revisions to definitions contained in Section 4 of the Agreement shall
apply:
R-10.1.1 Contract Quantity: The amount of RECs and, if applicable, Energy, to
be supplied for a transaction under the Agreement.
R-10.1.2 Power Marketer: An entity which buys, sells, and takes title to RECS,
electric energy, transmission and/or other services from traditional
utilities and other suppliers.
R-10.1.3 Physically Settled Option: Includes (i) a call option which is the right,
but not the obligation, to buy an underlying REC and/or power product
as defined under Service Schedule R according to the price and exercise
terms set forth in the Confirmation; and (ii) a put option which is the
right, but not the obligation, to sell an underlying REC or power product
as defined under Service Schedule R according to the price and exercise
terms set forth in the Confirmation.
R-10.1.4 Replacement Price: The price at which the Purchaser, acting in a
commercially reasonable manner, effects a purchase of substitute
REC(s), capacity and/or energy in place of the REC(s), capacity and/or
energy not Delivered (for REC(s) and/or energy) or made available (for
capacity only) by the Seller or, absent such a purchase, the market price
for such quantity of REC(s), capacity and/or energy, as determined by
the Purchaser in a commercially reasonable manner, for Energy at the
delivery point specified in the Confirmation. Substitute REC(s) must

be similar in all material respects to the REC(s) specified in the
Confirmation.
R-10.1.5 Resale Price: The price at which the Seller, acting in a commercially
reasonable manner, effects a resale of the REC(s), capacity and/or
energy not received by the Purchaser or, absent such a resale, the market
price for such quantity of REC(s), capacity and/or energy, as determined
by the Seller in a commercially reasonable manner, for Energy at the
delivery point specified for the transaction in a Confirmation.
R-10.2 Notices. Section 12.2 of the Agreement is revised by inserting “RECs or” before
the phrase “capacity and/or energy.”

SERVICE SCHEDULE R
ANNEX 1 - DEFINITIONS
“Acceptance” has the meaning given in Sections R-3.1.2 or R-3.2.2, as applicable.
“All Attributes” has the meaning given in Section R-2.4.1.
“Applicable Program” means (a) a program adopted by a Governmental Authority that requires
the sale, purchase, or use of energy generated or produced by a facility that converts renewable
natural resources such as wind, sunlight, rain, tides, geothermal heat, hydro, or biomass into
electric energy, including any Renewable Portfolio Standard (RPS) adopted by a Governmental
Authority and all Governing Law that pertains thereto, or (b) a voluntary program for reporting,
crediting or attributing RECs and all rules, standards and procedures adopted by the administering
organization that pertain thereto.
“Attestation” means (a) the Seller’s written statement, certified as true and correct by an authorized
officer of Seller, that the REC is Delivered and title to the REC has been transferred to the
Purchaser, and that the Seller has taken all steps to effect transfer of the REC required by any
Tracking System designated in the Confirmation, and (b) that satisfies the requirements of any
Applicable Program designated in the Confirmation or is a generation information system record
of ownership transfer. Annex 2 Exhibit 1 is a template for use of the Parties; an agreed form of
Attestation should be included as a part of the Confirmation, and the agreed form will suffice as
an Attestation regardless of whether or not it meets the criteria of this definition.
“Change in Law” has the meaning given in Section R-5.2.2(a).
“Deliver” has the meaning given in Sections R-3.1.1 or 3.2.1, as applicable.
“Effective Date” means the date both Parties have executed the Confirmation, or which the Parties
otherwise specify in the Confirmation.
“Environmental Attribute” means the following, unless a Tracking System is designated in the
Confirmation, and such Tracking System defines “Environmental Attribute,” in which case the
Tracking System’s definition of “Environmental Attribute” shall control: a characteristic
concerning or affecting the environment created by or resulting from the generation of electric
energy by a Renewable Energy Source, and which capable of measurement, verification, or
calculation. The term does not include tax credits or other tax benefits under any law or other
direct third-party subsidies for generation of electric energy by a Renewable Energy Source. The
term includes “non-energy attributes” under Oregon law and “non-power attributes” under
Washington law. By way of example, the term may include the following: avoided emissions of
CO2 or other gases, or avoided water use (but not water or other rights or credits required under an
Applicable Program to site and develop the Renewable Energy Facility itself).
“Facility As-Run REC” has the meaning given in Section R-2.3.5.
“Facility As-Run Bundled REC” has the meaning given in Section R-2.3.6(a).

“Firm Bundled REC” has the meaning given in Section R-2.3.2.
“Energy” in the case of a Firm Bundled REC refers to Firm Capacity/Energy Sale or Exchange
Service under Service Schedule C as may be modified by Service Schedule R, in the case of a
Resource Contingent Bundled REC refers to Unit Commitment Service under Service Schedule B
as may be modified by Service Schedule R, and in the case of Facility As-Run Bundled REC refers
to Economy Energy Service under Service Schedule A as may be modified by Service Schedule
R.
“Firm REC” has the meaning given in Section R-2.3.1.
“Fuel Impediment” means the reduction or lack of wind or sunlight, excessive wind, or other
insufficiency or excess of a Renewable Energy Source (excluding biomass), that causes a reduction
or cessation of generation of electric energy by a Renewable Energy Facility.
“Forced Outage” means the removal from service availability of a generating unit, transmission
line, or other facility for emergency reasons, or the condition in which the equipment is unavailable
due to unanticipated failure (such unanticipated failure does not include a Fuel Impediment).
“Governing Law” has the meaning given in Section 24 of the Agreement as that Section may be
modified by Section R-5.1.
“Governmental Authority” means the United States, a State thereof, any political subdivision or
governmental body thereof, including any department or agency, with jurisdiction over a Party or
an Applicable Program.
“Not Regulatorily Continuing” has the meaning given in Section R-5.2.2(b).
“Program Attributes” has the meaning given in Section R-2.4.2.
“Regulatorily Continuing” has the meaning given in Section R-5.2.2(a).
“REC” refers to a renewable energy certificate and means a credit or certificate representing
Environmental Attributes created by or resulting from the generation of one (1) megawatt hour of
electric energy by a Renewable Energy Source, subject to the terms and conditions stated in the
Confirmation.
“REC Product” has the meaning given in Section R-2.2.
“REC Transaction” has the meaning given in Section R-2.1.
“Resource Contingent REC” has the meaning given in Section R-2.3.3.
“Resource Contingent Bundled REC” has the meaning given in Section R-2.3.4(a).

“Renewable Energy Facility” means an electric generation unit or other facility or installation
capable of producing or emitting electric energy using a Renewable Energy Source.
“Renewable Energy Source” means (a) a resource that is recognized as a renewable energy source
under an Applicable Program designated in the Confirmation, or (b) if no Applicable Program is
designated in the Confirmation, a natural resource from or through which electric energy can be
generated, including wind, solar, geothermal, landfill gas, wave, tidal, thermal ocean technologies,
and hydroelectric power, and excluding fossil carbon-based, non-renewable, or radioactive fuel.
“Reporting Rights” means the right to report and register the exclusive ownership of the REC or
Environmental Attributes under Governing Law or any other laws, regulations, orders or judicial
precedents of the government of the United States of America or any department or agency thereof,
or any State or political subdivision thereof, including mandatory and voluntary reporting, and
including reporting under section 1605(b) of the Energy Policy Act of 1992 and any foreign or
international emissions trading or reporting program.
“Scheduled Maintenance” means an outage or partial outage scheduled to perform the necessary
normal maintenance on a generating unit, transmission line, or other facility to preserve the
reliability of the unit or overall system reliability, including scheduled outages for such
maintenance.
“Tracking System” means the entity, if any, the Parties designated in the Confirmation that will
perform REC tracking and accounting functions, including receiving evidence of generation of the
REC and crediting the resulting REC to the Purchaser’s account.
“Transfer Date” means the date specified in the Confirmation, no later than which Seller must
make Delivery as defined in Sections R-3.1.1 or R-3.2.1, as applicable.
“Vintage” means the period in which the REC was or will be created.

SERVICE SCHEDULE R ANNEX 2
FORM OF
REC TRANSACTION CONFIRMATION
IDENTIFICATION OF PARTIES
Name of Seller:
_______________________________

Name of Purchaser:
____________________________________

Seller Information:
_______________________________
Contact

Purchaser Information:
_______________________________
Contact

Tel (O):

Tel (O):

___________________

Tel (Cell): _____________________

Tel (Cell):

___________________

E-mail: ________________________

E-mail: ________________________

Fax:

Fax:

_____________________

________________________

________________________

Contact information is subject to change by notice.
ADDRESSES FOR FORMAL NOTCES:
Purchaser:

Seller

_____________________________

_____________________________

_____________________________

_____________________________

_____________________________

_____________________________

_____________________________

_____________________________

INCORPORATED DOCUMENTATION (any “long form” or other bilateral agreements
between the Parties applicable to this Confirmation and incorporated herein)
________________________________________________________________
REC TRANSACTION TERMS
REC Product (e.g., Firm REC, Firm Bundled REC, etc.) (see Section R-2.3):
__________________________________________________________

Vintage of REC already created or period of generation for REC to be created (mm/yyyy)
__________________________________________________________
Contract Quantity (stated either on a megawatt hour basis or percentage of output of a
designated Renewable Energy Facility)
____________________
Transfer Date (generally the Effective Date of this Confirmation for REC that already
exists, and future date for REC to be generated after Effective Date)
____________________
Contract Price:
___________________
Allocation, if agreed:
REC:
_________________________
Energy:
_________________________
Environmental Attributes (Check One)
□ All Attributes (this designation is effective only if a Renewable Energy Source
or Renewable Energy Facility is designated below)
□ Program Attributes (this designation is effective only if an Applicable Program
is identified below) (Note: WREGIS and possibly other Tracking Systems will not
recognize a Program Attributes REC, or may treat it as an All Attributes REC)
Applicable Program (required for Program Attributes; not required for All Attributes, but
designation establishes the minimum Environmental Attributes required by a designated
Applicable Program). Also required for recovery of penalties and alternative compliance
payments (Section R-9.1). Designation should include detailed information, including any
applicable legal citations, to assure adequate description of the program.
______________________________________________________________
Designation of Renewable Energy Source or Renewable Energy Facility (required for All
Attributes).

Renewable Energy Source: ___________________________________________
Renewable Energy Facility
Name: _______________________
Location: ___________________________________
Generation Information System number: _________________
Tracking System number: ________________________
Fuel (wind, solar, etc.: __________________
Change in Law Provisions (Check One)
□ Regulatorily Continuing (Section R-5.2.2(b), requiring that Seller make
commercial reasonable efforts to obtain compliance with Changes in Law in the
designated Applicable Program. If checked, state any agreed maximum costs of
such efforts (if no maximum is stated, then no maximum applies):
$______________
□ Not Regulatorily Continuing (Section R-5.2.2(c)).
Tracking System(s) if any: (if none specified, then Delivery occurs by Attestation and not
by Tracking System crediting)
Damages. Damages include reimbursement for penalties and alternative compliance
payments, subject to any agreed cap on this damages component, which can be zero
(Section R-9.1):
$ __________________
Any agreements concerning forward certificates in WREGIS or other Tracking System
Expedition ) (Section R-3.3.1):
_______________________________________________________________
TERMS APPLICABLE TO ENERGY IF INCLUDED IN REC PRODUCT
Period (Schedule) of Delivery: From __\__\__ To __\__\__
Schedule (Days and Hours): __________________
Delivery Rate:________________________________
Delivery Point(s): __________________________
Contract Quantity (specify all details): _______________

Transmission Path for the Transaction (If Applicable):__________________
EFFECTIVE DATE AND OTHER PROVISIONS
Effective Date (no earlier than mutual execution of this Confirmation)
______________________________
Other provisions: ________________________________________________ [generally
stated in attachment to the Confirmation]
The Parties agree to the REC Transaction set forth herein as of the Effective Date
Seller

Purchaser

Signed: __________________________
Signed: ____________________________
Name: ___________________________
Name: ____________________________
Date: _______________________ Date: _____________________

ANNEX 2, Exhibit 1
Form of Attestation To Be Included As Exhibit To Confirmation
Attestation Of [Seller] (“REC Generator”)
Of Sale, Transfer, and Delivery Of Renewable Energy Certificate to
[Purchaser] “Purchaser”
Party and Contact Information:
[Insert names and addresses of Parties, address, and contact information]
Attestation:
I, [name of attesting officer], the [title] of Seller, declare and certify that Seller sold and delivered
Elect one:
___

Environmental Attributes Only

___

Bundled with electricity

to Purchaser, and further, that
1.
2.

Was generated by the Renewable Energy Facility (“REF”) designated below and
sold, transferred and delivered, subject to receipt of payment, to Purchaser.
Is associated with electricity delivered into the [insert delivery area] in compliance
with applicable energy delivery rules.

REF
Technology
Generator
Type
Name
and
Number

Fuel Type Generation
(Renewable Period
Energy
(mm/yy)
Source)

Generator
First
Day of Operation

The above statements are true and correct to the best of my knowledge, and based on my duly
diligent inquiry. This Attestation may serve as a Bill of Sale to document, in accordance with the
Confirmation, the transfer from Generator to Purchaser of all of Seller’s right, title and interest in
and to the REC and environmental attributes it represents, as set forth above.
Either Party may disclose this Attestation to others, including a Tracking System, public utility
commissions and other regulatory bodies having jurisdiction over Purchaser, and administrators
of voluntary green ener