Brian K. Cherry 

Vice President 

Regulatory Relations

Pacific Gas and Electric Company 

77 Beale St., Mail Code B10C 

P.O. Box 770000 

San Francisco, CA 94177 

 

Fax: 415-973-7226 

September 7, 2012 

Advice 4102-E 

(Pacific Gas and Electric Company ID U39 E) 

Public Utilities Commission of the State of California 

Subject: Power Purchase Agreement for the Procurement of Eligible 

Renewable Energy Resources Between Sierra Pacific Industries 

and Pacific Gas and Electric Company

I. Introduction 

A. Purpose of the advice letter 

Pacific Gas and Electric Company (“PG&E”) seeks California Public Utilities 

Commission (“Commission” or “CPUC”) approval of a Power Purchase 

Agreement (“PPA”) between PG&E and Sierra Pacific Industries (“SPI”) to 

purchase Renewables Portfolio Standard (“RPS”)-eligible energy from five 

biomass facilities located in California. The PPA has a term of 20 years for a 

combined 58 Megawatts (“MW”) of renewable power. The PPA price is below 

the applicable 2011 Market Price Referent (“MPR”). 

There are currently five existing Qualifying Facilities (“QFs”) owned and operated 

by SPI that are delivering power to PG&E under standard offer QF contracts, each 

of which will individually expire in 2016 and 2017. Immediately prior to the 

commencement of deliveries under the new PPA, all existing SPI QF contracts 

will terminate. The PPA will transition four of the QF facilities currently 

delivering power to PG&E to a RPS contract, and the fifth facility currently 

delivering power to PG&E will be decommissioned. The PPA will also include a 

new facility for a total of five facilities (collectively the “Project”) under a RPS 

contract. 

Deliveries under the PPA are expected to commence in April 2014. Prior to 2017, 

the PPA limits deliveries from the Project to an amount approximately equal to the 

average volume PG&E forecasts to procure under the existing QF contracts.1

 In 

 

1

 As further described in Section 1.F of the Advice Letter, the anticipated deliveries in 2014-2016 

are effectively equal to PG&E’s forecasted deliveries from the five existing QFs. 
Advice 4102-E September 7, 2012 

2 

2017, deliveries from the Project will increase. Therefore, incremental volumes 

from SPI to PG&E's RPS portfolio will begin in 2017.

PG&E requests that the Commission issue a resolution no later than early March, 

2013, approving the PPA in its entirety and containing the findings as set forth in 

Section V below. 

B. Subject of the advice letter 

1. Project name 

The Project consists of five facilities: Anderson II, Burney, Lincoln, Quincy and 

Sonora (each, an “Aggregated Generation Facility” or “AGF”). 

The Project is comprised of four existing (Burney, Lincoln, Quincy, and Sonora) 

and one new facility (Anderson II) for a total of 58 MW. All five AGFs are or 

will be co-located with saw mills also owned and operated by SPI. The power 

sold to PG&E under the PPA is electricity generated in excess of that used onsite 

for saw mill operations. 

2. Technology (including level of maturity) 

The AGFs are biomass-fed boiler and steam turbine generation facilities. The 

technology is mature.

3. General Location and Interconnection Point 

The AGFs are located throughout northern California in the cities of Anderson, 

Burney, Lincoln, Quincy, and Sonora. The existing AGFs have first points of 

interconnection within the boundaries of the California Independent System 

Operator (“CAISO”), a California balancing authority. The new AGF, Anderson 

II, is expected to have its first point of interconnection within the boundaries of the 

CAISO.

4. Owner(s) / Developer(s) 

a. Name(s) 

b. Type of entity(ies) (e.g. LLC, partnership) 

c. Business Relationship (if applicable, between 

seller/owner/developer)

Sierra Pacific Industries, a California Corporation, is the owner and operator of the 

four existing AGFs. SPI will also develop, own and operate the new Anderson II 

facility. 
Advice 4102-E September 7, 2012 

3 

5. Project background, e.g., expiring QF contract, phased 

project, previous power purchase agreement, contract 

amendment 

The Burney, Lincoln, Quincy and Sonora facilities, as well as a fifth facility, 

Anderson I, are existing QFs (all five together, “Existing QFs”) and are currently 

delivering power to PG&E under standard offer agreements. Absent the PPA, the 

Existing QF agreements would terminate in 2016 and 2017. The impact of the 

early termination of the Existing QFs is addressed in Confidential Appendices A 

& D. A sixth SPI QF facility, Susanville, delivered power to PG&E under a 

standard offer QF agreement until it was decommissioned in 2004. The Susanville 

QF agreement was not terminated at the time. 

The Anderson II facility is a new, yet-to-be-built facility, with commercial 

operation expected on April 1, 2014. The Anderson II facility is being built 

immediately adjacent to Anderson I. Anderson I will be decommissioned once the 

Anderson II facility is commercially operational. On the day immediately prior to 

Anderson II’s Initial Energy Delivery Date, any and all existing, effective 

agreements between PG&E and the Existing QFs and the Susanville PPA will 

terminate as well.

6. Source of agreement, i.e., RPS solicitation year or 

bilateral negotiation 

The PPA resulted from PG&E’s 2011 RPS Solicitation.

PG&E requests that the Commission issue a resolution no later than early March 

2013 approving the PPA in its entirety, all payments to be made by PG&E under 

the PPA, and containing the findings required by the definition of CPUC Approval 

adopted by Decision (“D.”) 07-11-025 and D.08-04-009.2

 

C. General Project Description 

The following table summarizes the substantive features of the 

Project:

Project Names Anderson II, Burney, Lincoln, 

Quincy, and Sonora 

Technology Biomass 

 

2 As provided by D.07-11-025 and D.08-04-009, the Commission must approve the PPA and 

payments to be made thereunder, and find that the procurement will count toward PG&E’s RPS 

procurement obligations.
Advice 4102-E September 7, 2012 

4 

Capacity (MW) 58 MW 

Capacity Factor 80% 

Expected Generation 

(GWh/Year) 

Contract Years 1&2: 294 gigawatt 

hours (“GWh”)/year 

Contract Year 3: 322 GWh/year 

Contract Years 4-20: 406 

GWh/year 

Contract Years 1-20: 390 

GWh/year on average 

Initial Commercial 

Operational Date 

4/1/2014 

Date contract Delivery Term 

begins 

4/1/2014 

Delivery Term (Years) 20 years 

Vintage (New / Existing / 

Repower) 

4 Existing facilities 

1 New facility 

Location (city and state) 

Anderson, CA; Burney, CA; 

Lincoln, CA; Quincy, CA; Sonora, 

CA 

Control Area (e.g., CAISO, 

BPA) 

CAISO 

Nearest Competitive 

Renewable Energy Zone 

(CREZ) as identified by the 

Renewable Energy 

Transmission Initiative 

(RETI)3

Anderson II: Round Mountain B 

Burney: Round Mountain B 

Lincoln: Solano 

Quincy: Lassen South 

Sonora: Solano

Type of cooling, if applicable Water 

D. Project location 

 

3

 Information about RETI is available at: http://www.energy.ca.gov/reti/
Advice 4102-E September 7, 2012 

5 

1. Provide a general map of the generation facility’s location 

2. For new projects describe facility’s current land use type 

(private, agricultural, county, state lands (agency), federal 

lands (agency), etc.) 

Anderson II is a new, yet-to-be-built facility, with commercial operation expected 

on April 1, 2014. 

The Anderson II facility will be built immediately adjacent to SPI’s 

existing Anderson facility and is located in Anderson, California. The land 

is owned by SPI.

The Burney facility is an existing facility located in Burney, California: 
Advice 4102-E September 7, 2012 

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The Lincoln facility is and existing facility located in Lincoln, California: 
Advice 4102-E September 7, 2012 

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The Quincy facility is an existing facility located in Quincy, California: 
Advice 4102-E September 7, 2012 

8 

The Sonora facility is an existing facilty located in Sonora, California: 
Advice 4102-E September 7, 2012 

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Each of the five AGFs is located on private land owned by SPI adjacent to SPI’s 

saw mill operations. 

E. General Deal Structure 

Describe general characteristics of contract, for example: 

1. Required or expected Portfolio Content Category of the 

proposed contract 

2. Partial/full generation output of facility 

3. Any additional products, e.g. capacity 

4. Generation delivery point (e.g. busbar, hub, etc.) 

5. Energy management (e.g. firm/shape, scheduling, selling, 

etc.) 

6. Diagram and explanation of delivery structure 

The Project is comprised of four existing in-state RPS-eligible renewable energy 

resources that have their first points of interconnection with the CAISO controlled 

transmission system, and new facility that also anticipates interconnection with the 
Advice 4102-E September 7, 2012 

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CAISO. Procurement from the Project satisfies the criteria for the portfolio 

content category specified in Public Utilities Code Section 399.16(b)(1)(A) 

(hereinafter “Portfolio Content Category One”) because each AGF is a RPSeligible generator that has or expects to have its first point of interconnection with 

the Western Electric Coordinating Council (“WECC”) transmission system within 

the boundaries of a California balancing authority. 

PG&E will receive partial output from the Project starting April 1, 2014, which is 

the expected commercial operation date of the new Anderson II facility. Each of 

the AGFs also provides electricity for SPI’s onsite saw mill use; PG&E is buying 

the energy generated in excess of SPI’s onsite load. Despite the ability to deliver 

higher levels of output as of the commercial operation date of Anderson II, annual 

deliveries under the PPA through the end of 2016 are contractually limited to the 

approximate quantity currently delivered to PG&E under the Existing QF 

agreements. Therefore, incremental RPS-eligible energy deliveries, relative to 

deliveries currently procured under the Existing QF agreements, begin in 2017. 

The PPA is for the purchase of a baseload Product. This includes the energy, 

capacity and all ancillary products, services or attributes similar to the foregoing 

which are or can be produced by or associated with the Project, including, without 

limitation, renewable attributes, Renewable Energy Credits, Capacity Attributes 

and Green Attributes associated with the volumes PG&E procures. 

The Anderson II facility may meet the criteria established for a New Combined 

Heat and Power Facility (“New CHP Facility”) pursuant to the Qualifying Facility 

and Combined Heat and Power Settlement Agreement (“Settlement Agreement”).4

 

To the extent that the Anderson II facility receives the necessary approvals to be 

designated as a New CHP Facility, PG&E requests that the Anderson II facility be 

counted as a greenhouse gas (“GHG”) credit from a New CHP Facility. 5 PG&E 

will calculate the appropriate GHG credit as the operational details for Anderson II 

are finalized and supplied to PG&E.6

 To the extent that the Anderson II facility is 

designated as a New CHP Facility, Anderson II will not count toward the MW 

targets adopted by the Settlement Agreement due to its fuel type. 7

 

4

 See Section 17 of the Qualifying Facility (QF)/CHP Settlement Term Sheet (“Term Sheet”) 

approved by the Commission in D.10-12-035. 

5

 See Section 7.3.1.1 of the Term Sheet. 6 This credit will be applied toward PG&E’s GHG Emissions Reduction Target, pursuant to 

Section 6 of the Term Sheet. PG&E will report this value in a CHP Program Semi-Annual 

Report, as required by Section 8 of the Term Sheet.

7

 New CHP facilities eligible for the MW targets are limited to certain gas fired facilities under 

Section 5.2.5 of the Term Sheet.
Advice 4102-E September 7, 2012 

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The Project’s energy will be delivered to the first point of interconnection to the 

CAISO Grid for each of the AGFs. The interconnection point for each AGF is 

summarized in the following table: 

Aggregated Generation 

Facility 

Interconnection Point 

Anderson II See Confidential Appendices A and D 

Burney Existing tap off the Pit#3 – Pit#1 230 kV line 

Lincoln Existing tap off the Lincoln – Pleasant Grove 115 kV 

line 

Quincy Existing tap off Caribou – Plumas Jct 60 kV line 

Sonora Existing tap off the Donnells – Curtis 115 kV line 

There is no firming or shaping associated with this PPA. PG&E or its agent will 

serve as scheduling coordinator for the Project.

Figure 1: Delivery Structure of the PPA 

F. RPS Statutory Goals & Requirements 

1. Briefly describe the Project’s consistency with and 

contribution towards the RPS program’s statutory goals 

set forth in Public Utilities Code §399.11. These goals 

include displacing fossil fuel consumption within the state; 

adding new electrical generating facilities within WECC; 

reducing air pollution in the state; meeting the state’s 

climate change goals by reducing emissions of greenhouse 

RPS Seller: SPI 

5 facilities throughout CA 

Expected to produce a total of 390 GWh 

average per year over contract term 

PG&E 

Purchases RPS-eligible energy 
Advice 4102-E September 7, 2012 

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gases associated with electrical generation; promoting 

stable retail rates for electric service; a diversified and 

balanced energy generation portfolio; meeting the state’s 

resource adequacy requirements; safe and reliable 

operation of the electrical grid; and implementing state’s 

transmission and land use planning activities. 

2. Describe how procurement pursuant to the contract will 

meet IOU’s specific RPS compliance period needs

Public Utilities Code §399.11 states that increasing California’s reliance on 

eligible renewable energy resources is intended to displace fossil fuel 

consumption within the state, promote stable electricity prices, reduce GHG 

emissions, improve environmental quality and promote the goal of a diversified 

and balanced energy generation portfolio. The Project is consistent with these 

goals because it will generate clean energy with minimal fossil fuel costs. The 

Project will also contribute to maintaining a diversified and balanced energy 

generation portfolio. 

Senate Bill (“SB”) 1078 established the California RPS Program, requiring an 

electrical corporation to increase its use of eligible renewable energy resources to 

20 percent of total retail sales no later than December 31, 2017. The legislature 

subsequently accelerated the RPS goal to reach 20 percent by the end of 2010. In 

April 2011, Governor Brown signed into law SB 2 1X. As implemented by D.11-

12-020, SB 2 1X requires retail sellers of electricity to meet the following RPS 

procurement quantity requirements beginning on January 1, 2011: 

• An average of twenty percent of the combined bundled retail sales during 

the first compliance period (2011-2013). 

• Sufficient procurement during the second compliance period (2014-2016) 

that is consistent with the following formula: (.217 * 2014 retail sales) + 

(.233 * 2015 retail sales) + (.25 * 2016 retail sales). 

• Sufficient procurement during the third compliance period (2017-2020) that 

is consistent with the following formula: (.27 * 2017 retail sales) + (.29 * 

2018 retail sales) + (.31 * 2019 retail sales) + (.33 * 2020 retail sales). 

• 33 percent of bundled retail sales in 2021 and all years thereafter. 
Advice 4102-E September 7, 2012 

13 

Consistent with the Energy Division Staff methodology for calculating the 

renewable net short8

, PG&E calculated an assessment of its current expected RPS 

need as of August 2012. The public portion of this assessment is provided in the 

following table, and is further described in Confidential Appendix A. 

 

8 See Administrative Law Judge’s Ruling in R. 11-05-005 (1) Adopting Renewable Net Short 

Calculation Methodology (2) Incorporating the Attached Methodology into the Record, and (3) 

Extending the Date for Filing Updates to 2012 Procurement Plans issued on August 2, 2012. 
14 

RPS Net Short Calculation as of August 2012

Current Expected Need Scenario (Annual)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 

RPS Target 20.0% 20.0% 20.0% 21.7% 23.3% 25.0% 27% 29% 31% 33% 33% 33% 33% 33% 33% 33% 33% 33% Voluntary Margin of Over-Procurement (GWh) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Aggregate Volumes (GWh) 14,473 14,773 18,737 22,267 24,680 24,812 24,176 22,193 21,465 20,653 20,221 17,896 17,594 17,345 17,231 16,625 16,264 16,17Annual RPS Position (%) 19.3% 32.1% 31.5% 29.0% 28.0% 26.8% 26.2% 23.2% 22.7% 22.4% 22.2% 21.3% 20.8% 20.7% Gross Surplus/(Deficit) compared to Annual Targets* (GWh) (500) 5,473 3,474 (22) (2,309) (4,743) (5,226) (7,602) (7,954) (8,255) (8,421) (9,078) (9,490) (9,629

Volumes (Banked) or Withdrawn from Bank 0 (5,473) (3,474) 22 2,309 4,743 5,226 7,602 4,696 0 0 0 0 0 

Net Surplus/(Deficit) (GWh) (500) 0000000 (3,258) (8,255) (8,421) (9,078) (9,490) (9,629

Net Annual RPS Positions (%) with Use of Bank 19.3% 25.0% 27.0% 29.0% 31.0% 33.0% 33.0% 33.0% 28.8% 22.4% 22.2% 21.3% 20.8% 20.7% Cumulative Banked Volumes (GWh) 0 15,651 21,125 24,599 24,577 22,268 17,525 12,299 4,696 0 0 0 0 0 0 

Forecast Failure Rate (%) for New Projects not yet online 0% 0.0% 1.8% 1.2% 3.7% 12.6% 20.5% 22.0% 22.1% 22.1% 22.2% 22.3% 22.3% 22.4% 22.4% 22.5% 22.6% 22.7% Forecast Failure Rate (%) for Existing Generation 0% 2.1% 2.6% 1.9% 1.0% 0.8% 0.7% 0.6% 0.4% 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% 

Current Expected Need Scenario (Compliance Period)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 

Compliance Period Requirement 33% 33% 33% 33% 33% 33% 33% 33% Voluntary Margin of Over-Procurement (GWh) 00000000Aggregate Volumes (GWh) 20,221 17,896 17,594 17,345 17,231 16,625 16,264 16,17RPS Position (%) 26.2% 23.2% 22.7% 22.4% 22.2% 21.3% 20.8% 20.7% Gross Surplus/(Deficit) (GWh) (5,226) (7,602) (7,954) (8,255) (8,421) (9,078) (9,490) (9,629Volumes (Banked) or Withdrawn from Bank (GWh) 5,226 7,602 4,696 0 0 0 0 0 Net Surplus/(Deficit) (GWh) 0 0 (3,258) (8,255) (8,421) (9,078) (9,490) (9,629

Net RPS Positions (%) 33.0% 33.0% 28.8% 22.4% 22.2% 21.3% 20.8% 20.7% 

Cumulative Banked Volumes (GWh) 12,299 4,696 0 0 0 0 0 0 

Forecast Failure Rate (%) for New Projects not yet online 22.2% 22.3% 22.3% 22.4% 22.4% 22.5% 22.6% 22.7% Forecast Failure Rate (%) for Existing Generation 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% Total RPS Risk Adjusted Net Short (2011-2030) (GWh) (73,690)*Assumed annual targets are: 2011-2013 (20% annually), 2014 (21.17%), 2015 (23.3%), 2016 (25%), 2017 (27%), 2018 (29%), 2019 (31%), and 2020 (33%). These targets are illustrative only and not enforceable.

20.0% 23.3% 30.0%

00 0

47,983 71,759 88,487

28.8%

(3,600)

3,600

0

30.0%

1.5% 1.2% 0.5%

21,125 17,525

0.6% 5.8% 21.7%
Advice 4102-E September 7, 2012 

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As illustrated by the results of its Current Expected Need Scenario, PG&E’s 

existing RPS portfolio is expected to provide sufficient RPS-eligible deliveries to 

meet PG&E’s RPS compliance requirements in the first compliance period. 

Additionally, PG&E expects to significantly exceed the RPS procurement targets 

set for the second compliance period.9

Notwithstanding its forecast of limited near-term need, PG&E has incremental 

need over the third compliance period, prior to applying any excess procurement 

from earlier compliance periods, and thereafter in order to maintain a 33% RPS 

level. PG&E estimates that it will need approximately 3,600 GWh of cumulative 

RPS-eligible volumes prior to applying excess procurement to satisfy third 

compliance period targets. After 2020, when compliance will be measured 

annually, PG&E’s Current Expected Need Scenario indicates a 5,200 GWh 

shortfall in 2021, increasing to an annual shortfall greater than 8,000 GWh per 

year in all years after 2023 prior to applying any future excess procurement. This 

significantly increased need in the early part of the next decade is driven by a 

large volume of expiring contracts in that time frame. 

As described in Section I.B. above, PG&E is currently purchasing RPS-eligible 

power from SPI under standard offer QF agreements, which individually expire in 

the latter half of 2016 and early 2017. In the assessment of need that PG&E has 

provided in the above table and Confidential Appendix A, it has accounted for the 

deliveries from the Existing QFs until the dates upon which the existing standard 

offer QF agreements expire. PG&E does not assume in its need analysis that 

expiring volumes are retained after individual contract expiration dates. 

The amount of deliveries from the Existing QFs included in this assessment of 

need is approximately equal to the Project’s anticipated deliveries prior to 2017.10 

Therefore, the termination of the Existing QFs and commencement of the PPA 

has no material impact on PG&E’s RPS need through 2016 due to the 

continuation of those historical volumes in this PPA. Beginning in 2017, the 

AGFs are expected to deliver approximately 406 GWh per year when PG&E has 

 

9

 See Section 6, notes to Appendix 1, and Appendix 3 of PG&E’s 2012 Renewable Energy 

Procurement Plan (Draft Version) filed on August 15, 2012 in R.11-05-005. Section 6 provides a 

description of PG&E’s deterministic approach to developing a risk-adjusted forecast, and the 

notes to Appendix 1 list the bundled retail sales assumptions used in PG&E’s net short 

calculations. 

10 PG&E’s forecast of deliveries from the Existing QFs is equal to approximately 300 GWh/year 

in 2014 – 2016.
Advice 4102-E September 7, 2012 

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a need for new incremental deliveries of RPS-eligible volumes (i.e., in the third 

compliance period and all years thereafter). 

G. Confidentiality 

Explain if confidential treatment of specific material is 

requested. Describe the information and reason(s) for 

confidential treatment consistent with the showing required by 

D.06-06-066, as modified by D.08-04-023. 

In support of this Advice Letter, PG&E has provided the confidential information 

listed below. This information includes the PPA and other information that more 

specifically describes the rights and obligations of the parties. This information is 

being submitted in the manner directed by D.08-04-023 and the August 22, 2006, 

Administrative Law Judge’s Ruling Clarifying Interim Procedures for Complying 

with D.06-06-066 to demonstrate the confidentiality of the material and to invoke 

the protection of confidential utility information provided under either the terms 

of the IOU Matrix, Appendix 1 of D.06-06-066 and Appendix C of D.08-04-023, 

or General Order 66-C. A separate Declaration Seeking Confidential Treatment 

is being filed concurrently with this Advice Letter. 

Confidential Attachments: 

Appendix A – Consistency with Commission Decisions and Rules and Project 

Development Status 

Appendix B – 2011 Solicitation Overview 

Appendix C1 – Independent Evaluator Report (Confidential) 

Appendix D – Contract Summary: SPI 

Appendix E – Comparison of the PPA to PG&E’s 2011 Pro Forma Power 

Purchase Agreement 

Appendix F – SPI Power Purchase Agreement 

Appendix G – Projects’ Contributions Toward RPS Goals 

Public Attachment 

Appendix C2 – Independent Evaluator Report (Public) 
Advice 4102-E September 7, 2012 

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II. Consistency with Commission Decisions 

A. RPS Procurement Plan 

1. Identify the Commission decision that approved the 

utility’s RPS Procurement Plan. Did the utility adhere to 

Commission guidelines for filing and revisions? 

2. Describe the Procurement Plan’s assessment of portfolio 

needs. 

3. Discuss how the Project is consistent with the utility’s 

Procurement Plan and meets utility procurement and 

portfolio needs (e.g. capacity, electrical energy, resource 

adequacy, or any other product resulting from the 

project). 

4. Describe the project characteristics set forth in the 

solicitation, including the required deliverability 

characteristics, online dates, locational preferences, etc. 

and how the Project meets those requirements. 

5. For Sales contracts, provide an analysis that evaluates 

selling the proposed contracted amount vs. banking the 

RECs towards future RPS compliance requirements (or 

any reasonable other options)

PG&E’s 2011 renewable procurement plan (“2011 RPS Plan”) was conditionally 

approved in D.11-04-030 on April 14, 2011. PG&E submitted a final version of 

the 2011 RPS Plan on May 4, 2011. The goal of PG&E’s 2011 RPS Plan is to 

procure approximately one to two percent of PG&E’s annual retail sales, or 800 

to 1,600 GWh per year. This goal intended to address both the near-term 

compliance mandate established in SB 2 1X and the longer term goal of serving 

33% of its retail sales with renewable resources by 2020. 

The Project is consistent with PG&E’s goal to procure 800 to 1,600 GWh per 

year in the 2011 RPS Solicitation. The Project’s incremental volumes commence 

in 2017 and will satisfy PG&E’s renewable energy portfolio needs which are 

projected in the third compliance period and beyond. Furthermore, because the 

PPA is long term, and the Project satisfies the criteria of Portfolio Content 

Category One, any deliveries in excess of PG&E’s RPS compliance obligation 
Advice 4102-E September 7, 2012 

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will be bankable and available for use to satisfy future compliance period or year 

needs. 

The Project is also consistent with PG&E’s preferred project characteristics set 

forth in the solicitation. PG&E’s 2011 RPS Solicitation Protocol expressed a 

preference for bundled in-state resources delivering energy and capacity at a 

delivery point assigned by CAISO inside PG&E’s service territory. Each AGF is 

consistent with these preferences because the facilities will directly interconnect 

to the CAISO within PG&E’s service territory. Furthermore, PG&E is entitled to 

all of the Project’s Contract Capacity, including Capacity Attributes, to enable 

PG&E to meet its Resource Adequacy or successor program requirements, as the 

CPUC, CAISO or other regional entity may prescribe. 

Because incremental deliveries begin in 2017, the Project is expected to 

contribute materially to PG&E’s RPS portfolio need in the third compliance 

period. The PPA conforms to PG&E’s Commission-approved 2011 RPS Plan by 

delivering an average of 406 GWh per year in the third compliance period to fill a 

portion of PG&E’s projected RPS net short position. The transaction complies 

with RPS program requirements, meets the portfolio needs outlined by the 2011 

RPS Plan and is competitive when compared to the other bids submitted in the 

2011 RFO and final shortlisted offers.

B. Bilateral contracting – if applicable 

1. Discuss compliance with D.06-10-019 and D.09-06-050. 

2. Specify the procurement and/or portfolio needs 

necessitating the utility to procure bilaterally as opposed 

to a solicitation. 

3. Describe why the Project did not participate in the 

solicitation and why the benefits of the Project cannot be 

procured through a subsequent solicitation.

This section is not applicable because the PPA resulted from PG&E’s 2011 RPS 

Solicitation. 

C. Least-Cost, Best-Fit (LCBF) Methodology and Evaluation 

1. Briefly describe IOU’s LCBF Methodology 

2. Indicate when the IOU’s Shortlist Report was approved 

by Energy Division
Advice 4102-E September 7, 2012 

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PG&E’s filed its 2011 RPS Shortlist Report on November 11, 2011 in Advice 

Letter 3938-E and a Supplement to the 2011 RPS Shortlist Report on February 8, 

2012 in Advice Letter 3938-E-A. The 2011 Shortlist Report has, at the date of 

this filing, not formally been approved by the Commission. 

The RPS statute requires PG&E to procure the “least-cost best-fit” (“LCBF”) 

eligible renewable resources.11 The LCBF decision directs the utilities to use 

certain criteria in their bid ranking12 and offers guidance regarding the process by 

which the utility ranks bids in order to select or “shortlist” the bids with which it 

will commence negotiations. PG&E’s approved process for identifying the LCBF 

renewable resources focuses on five primary areas: 

1) Market Valuation; 

2) Portfolio Fit; 

3) Project Viability 

4) RPS Goals; and 

5) Transmission Adder. 

PG&E examined the reasonableness of the PPA using the LCBF evaluation 

criteria from the 2011 RPS Solicitation. The general finding is that the PPA 

ranked favorably compared to the other projects received in PG&E’s 2011 RPS 

Solicitation. A more detailed discussion of PG&E’s evaluation of the PPA is 

provided in Confidential Appendix A. 

1. Market Valuation 

In a “mark-to-market analysis,” the present value of the bidder’s payment stream 

is compared with the present value of the product’s market value to determine the 

benefit (positive or negative) from the procurement of the resource, irrespective 

of PG&E’s portfolio. This analysis is based on an evaluation of the contract 

prices in the PPAs. PG&E’s analysis of the market value is confidential and 

addressed in Confidential Appendix A. 

2. Portfolio Fit 

Portfolio fit considers how well an offer’s firmness and energy delivery patterns 

match PG&E’s portfolio needs. PG&E evaluated the offer’s consistency with 

 

11 Pub. Util. Code § 399.14(a)(2)(B).

12 D.04-07-029.
Advice 4102-E September 7, 2012 

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portfolio fit as described in the 2011 RPS Plan and Protocol and filed its initial 

2011 RPS Shortlist Report on November 11, 2011. 

In a subsequent supplemental filing dated February 8, 2012 in Advice Letter 

3938-E-A,13 PG&E submitted an updated Shortlist Report that enhances the 

valuation methodology to calculate a portfolio-adjusted value (“PAV”). The 

PAV intends to more accurately reflect the value of renewable resources to PG&E 

customers. Specifically, the PAV methodology starts with net market value 

results, which reflect the value of a transaction relative to market forward curves, 

as an initial quantitative valuation. Additional quantitative adjustments are then 

made for aspects of market valuation, transmission adder, and portfolio fit 

described herein and for other factors that impact the value of a transaction with 

respect to PG&E’s portfolio. Using PG&E’s PAV methodology for the 2011 

RPS Solicitation, the offer compared favorably to the other 2011 RPS shortlisted 

offers. Additional information about the 2011 RPS Solicitation PAV 

methodology is provided in Confidential Appendix A and Advice Letter 3938-EA. 

3. Project Viability 

Project viability is based on three categories: 1) Company / Development Team, 

2) Technology, and 3) Development Milestones. It is assessed by the CPUCdeveloped Project Viability Calculator (“PVC”). The PVC is a tool for utilities to 

evaluate the viability of a renewable energy project, relative to all other projects 

that bid into the California utilities’ RPS solicitations. The PVC uses 

standardized categories and criteria to quantify a project's strengths and 

weaknesses in key areas of renewable project development. 

PG&E’s analysis of Project Viability and PVC score are confidential and can be 

found in Confidential Appendix A.

4. RPS Goals 

PG&E assesses the Offer’s consistency with and contribution to California’s 

goals for the RPS program and the Offer’s support of PG&E’s supplier diversity 

goals (collectively “RPS Goals”). The RPS Goals assessment considers nonquantitative factors, legislative findings and declarations that increase California’s 

reliance on renewable energy, consistency with the CPUC’s Water Action Plan, 

 

13 PG&E subsequently filed substitute sheets for Advice Letter 3938 E-A on February 15, 2012. 
Advice 4102-E September 7, 2012 

21 

Executive Order S-06-06 which established a goal the state would meet 20% of 

its renewable energy needs with electricity produced from biomass, and supplier 

diversity. 

5. Transmission Adder 

The transmission adder adjusts Offer prices to include the cost, if any, of bringing 

the power from the generating facility to PG&E’s network. Once Offers have 

been ranked on all evaluation criteria except transmission, the means by which 

the generation will be delivered to PG&E’s customers is examined. Each bid is 

associated with a transmission cluster based upon the location of the facility. If a 

CAISO interconnection study has been completed for the project, the costs in that 

report are used for bid evaluation. If no study has been completed, the project’s 

transmission costs are based upon either the ability to affect deliveries to PG&E’s 

load through exchanges, or other commercially-recognized means, or 

transmission costs are assigned using the transmission ranking cost report 

methodology. PG&E uses the lesser of the transmission adder or alternative 

commercial arrangements in determining the market value of bids and selecting 

the shortlist. 

PG&E’s determination of any transmission adder is confidential and can be found 

in Confidential Appendix A. 

D. Compliance with Standard Terms and Conditions (STCs) 

1. Does the proposed contract comply with D.08-04-009, 

D.08-08-028, and D.10-03-021, as modified by D.11-01-

025? 

2. Using the tabular format, provide the specific page and 

section number where the RPS non-modifiable STCs 

are located in the contract. 

3. Provide a redline of the contract against the utility’s 

Commission-approved pro forma RPS contract as 

Confidential Appendix E to the filed advice letter. 

Highlight modifiable terms in one color and nonmodifiable terms in another. 

The Commission set forth standard terms and conditions to be incorporated into 

contracts for the purchase of electricity from eligible renewable energy resources 

in D.04-06-014 and D.07-02-011, as modified by D.07-05-057 and D.07-11-025. 
Advice 4102-E September 7, 2012 

22 

These terms and conditions were compiled and published in D.08-04-009. 

Additionally, the non-modifiable term related to Green Attributes was finalized in 

D.08-08-028 and the non-modifiable terms related to Tradable Renewable Energy 

Credits (“TRECs”) were finalized in D.10-03-021, as modified by D.11-01-025. 

The non-modifiable standard terms and conditions in the PPA conform exactly to 

the “non-modifiable” terms set forth in Attachment A of D.08-04-009, as 

modified by D.08-08-028 and by Appendix C of D.10-03-021, as modified by 

D.11-01-025. These terms may be found on the following pages of the PPA: 

Non-Modifiable Term PPA Section No. PPA Page No. 

STC 1: CPUC Approval 1.60 6 

STC 2: RECs and Green Attributes 

• Definition of Green Attributes 1.138 14 - 15 

• Conveyance of Green Attributes 3.2 34 

STC 6: Eligibility 10.2(b) 63 

STC 17: Applicable Law 10.12 72 

STC REC-1: Transfer of renewable energy 

credits 

10.2(b) 63 

STC REC-2: Tracking of RECs in WREGIS 3.1(k)(viii) 32 

A redline comparison of the PPA with PG&E’s 2011 Pro Forma PPA is provided 

in Confidential Appendix E. 

E. Portfolio Content Category Claim and Upfront Showing (D.11-

12-052, Ordering Paragraph 9) 

1. Describe the contract’s claimed portfolio content category 

2. Explain how the procurement pursuant to the contract is 

consistent with the criteria of the claimed portfolio 

content category as adopted in D.11-12-052 

3. Describe the risks that the procurement will not be 

classified in the claimed portfolio content category 

4. Describe the value of the contract to ratepayers if: 

a. Contract is classified as claimed 
Advice 4102-E September 7, 2012 

23 

b. Contract is not classified as claimed

As described in Section I.E. and in further detail below, the PPA satisfies the 

upfront showing required for Portfolio Content Category One. SB 2 1X, which is 

codified at Public Utilities Code Sections 399.11, and following, established three 

portfolio content categories that apply to RPS-eligible generation associated with 

RPS procurement contracts signed after June 1, 2010. 

Decision 11-12-052 requires that IOUs make an upfront showing related to the 

categorization of each proposed RPS procurement transaction. Specifically, for 

approval of contracts meeting the criteria of section 399.16 (b)(1)(A) (i.e., 

“Portfolio Content Category One”), an IOU may show that the RPS-eligible 

generator has its first point of interconnection with the WECC transmission 

system within the boundaries of a California balancing authority area.14

The Project meets the upfront showing required for Portfolio Content Category 

One because the AGFs are in-state RPS-eligible renewable energy resources that 

have or expect to have first points of interconnection with WECC transmission 

system with the CAISO, a California balancing authority. Therefore, the RPSeligible procurement from the Project satisfies the criteria for the Portfolio 

Content Category One adopted in D.11-12-052. 

There is no known risk that the procurement would not be classified as Portfolio 

Content Category One. 

The value of the PPA as described and assessed in this Advice Letter is based on 

the assumption that the procurement meets the criteria of Portfolio Content 

Category One. If the PPA is not classified as Portfolio Content Category One, the 

value of the procurement to PG&E and its customers could be lower under certain 

limited scenarios. For example, if PG&E (i) exceeds the applicable portfolio 

balance requirements set forth in Section 399.16(c)(2); and (ii) has excess 

procurement in that compliance period, D.12-06-038 would require RECs 

exceeding the portfolio balance requirements to be deducted from the excess 

procurement. 

 

F. Minimum Quantity 

 

14 See D.11-12-052 at 40-41; See also id. at 37 (explaining that the upfront showing required of 

IOUs for procurement projected to meet Portfolio Content Category One based on the relevant 

point of interconnection would be “straightforwardly based on showing that the RPS-eligible 

generator has the applicable first point of interconnection.”) 
Advice 4102-E September 7, 2012 

24 

Minimum contracting requirements apply to short term 

contracts less than 10 years in length 

1. Explain whether or not the proposed contract triggers the 

minimum quantity requirement 

2. If the minimum quantity requirement applies, provide a 

detailed calculation that shows the extent to which the 

utility has satisfied the minimum quantity requirement. If 

the requirement has not yet been satisfied for the current 

year, explain how the utility expects to satisfy the quantity 

by the end of the year to count the proposed contract for 

compliance. 

In D.12-06-038, the Commission determined that in order to count energy 

deliveries from short-term contracts toward RPS goals, RPS-obligated loadserving entities must contract for deliveries equal to at least 0.25 percent of total 

retail sales in 2010 if the contract is signed during the first compliance period 

from 2011-2013. The proposed PPA is a long-term 20-year contract that does not 

trigger the minimum quantity requirement set forth in D.12-06-038. PG&E 

expects to be in compliance with the long-term contracting requirement for the 

first compliance period. 

G. Tier 2 Short-term Contract “Fast Track” Process – if applicable 

Complete this section if requesting approval via Tier 2 and the “fast 

track” process set forth in D.09-06-050. 

1. Is the facility in commercial operation? If not in 

commercial operation, explain the IOU’s basis for their 

determination that commercial operation will be achieved 

within the required six months. 

2. Describe and explain any contract modifications to the 

Commission-approved short-term pro forma contract.

This section is not applicable, as this is a long-term contact and thus not eligible 

for the “Fast Track” process. 

H. Market Price Referent (“MPR”) 

The actual price under the PPA is confidential, market-sensitive information. 

However, the PPA price is below the 20-year 2011 MPR for projects with a 2014 
Advice 4102-E September 7, 2012 

25 

commercial online date (“COD”) adopted in Resolution E-4442 on December 1, 

2011. Total cost information is discussed in Confidential Appendix D. 

I. Interim Emissions Performance Standard 

In D.07-01-039, the Commission adopted a greenhouse gas 

Emissions Performance Standard (EPS) which is applicable to 

electricity contract for baseload generation, as defined, having a 

delivery term of five years or more. 

1. Explain whether or not the contract is subject to the EPS.

2. If the contract is subject to the EPS, discuss how the 

contract is in compliance with D.07-01-039. 

3. If the contract is not subject to EPS, but delivery will be 

firmed/shaped with specified baseload generation for a 

term of five or more years, explain how the energy used to 

firm/shape meets EPS requirements. 

4. If the contract term is five or more years and will be 

firmed/shaped with unspecified power, provide a showing 

that the utility will ensure that the amount of substitute 

energy purchases from unspecified resources is limited 

such that total purchases under the contract (renewable 

and non-renewable) will not exceed the total expected 

output from the renewable energy source over the term of 

the contract. 

5. If substitute system energy from unspecified sources will 

be used, provide a showing that: 

a. the unspecified energy is only to be used on a 

short-term basis; and 

b. the unspecified energy is only used for operational 

or efficiency reasons; and 

c. the unspecified energy is only used when the 

renewable energy source is unavailable due to a 

forced outage, scheduled maintenance, or other 

temporary unavailability for operational or 

efficiency reasons; or 
Advice 4102-E September 7, 2012 

26 

d. the unspecified energy is only used to meet 

operating conditions required under the contract, 

such as provisions for number of start-ups, ramp 

rates, minimum number of operating hours 

A greenhouse gas Emissions Performance Standard (“EPS”) was established by 

Senate Bill 1368 (“SB 1368”), which requires that the Commission consider 

emissions costs associated with new long-term (five years or greater) power 

contracts procured on behalf of California ratepayers. 

To implement SB 1368, in D.07-01-039, the Commission adopted an EPS that 

applies to contracts for a term of five or more years for baseload generation with 

an annualized plant capacity factor of at least 60 percent. D.07-01-039 

determined that certain renewable resources and technologies are pre-approved as 

EPS-compliant. 

“Based on the record in this proceeding, it is reasonable to make an upfront 

determination that the following renewable resources and technologies are 

EPS-compliant: 

(a) Solar Thermal Electric (with up to 25% gas heat input) 

(b) Wind 

(c) Geothermal, with or without reinjection 

(d) Generating facilities (e.g., agricultural and wood waste, 

landfill gas) using biomass that would otherwise be disposed of 

utilizing open burning, forest accumulation, landfill (uncontrolled, 

gas collection with flare, gas collection with engine), spreading or 

composting.”15

The Project consists of five AGFs, each of which is a biomass generating facility 

as identified in (d) and as such is pre-approved and EPS-compliant. Notification 

of compliance with D.07-01-039 is provided through this Advice Letter, which 

has been served on the service list in the RPS rulemaking, R.11-05-005. 

J. Procurement Review Group (PRG) Participation 

1. List PRG participants (by organization/company). 

2. Describe the utility’s consultation with the PRG, including 

when information about the contract was provided to the 

 

15 See D.07-01-039 at 18 and Conclusions of Law 35(c). 
Advice 4102-E September 7, 2012 

27 

PRG, whether the information was provided in meetings 

or other correspondence, and the steps of the 

procurement process where the PRG was consulted. 

3. For short term contracts, if the PRG was not able to be 

informed prior to filing, explain why the PRG could not 

be informed.

The Procurement Review Group (“PRG”) for PG&E includes the Commission’s 

Energy Division and Division of Ratepayer Advocates, Department of Water 

Resources, Union of Concerned Scientists, The Utility Reform Network, the 

California Utility Employees, and Jan Reid, as a PG&E ratepayer. The PPA was 

presented to the PRG as part of PG&E’s proposed shortlist on August 12, 2011.16 

On December 23, 2012, PG&E presented the PAV methodology to the PRG and 

explained how the methodology would apply to the 2011 RPS RFO. The SPI 

transaction was subsequently presented to the PRG as a potential contract for 

execution on June 19, 2012. Additional information is provided in Confidential 

Appendix A. 

K. Independent Evaluator (IE) 

The use of an IE is required by D.04-12-048, D.06-05-039, 07-12-

052, and D.09-06-050 

1. Name of IE 

2. Describe the oversight provided by the IE. 

3. List when the IE made any findings to the Procurement 

Review Group regarding the applicable solicitation, the 

project/bid, and/or contract negotiations. 

4. Insert the public version of the project-specific IE Report.

The IE, Arroyo Seco Consulting, reviewed and assessed PG&E’s RPS evaluation 

and selection process, and observed the negotiations of the PPA to ensure that 

they were conducted fairly. The IE provided insights and findings to the PRG 

during the PRG meetings noted in Section J above. Based on the valuation and 

project viability of the Project, the IE supports that the PPA merits CPUC 

approval. The detailed findings of the IE regarding the PPA are contained in 

Confidential Appendix C1 and Public Appendix C2. 

 

16 As described above in Section II. C., PG&E filed a Supplement to the 2011 RPS Shortlist 

Report on February 8, 2012 in Advice Letter 3938-E-A reflecting the final 2011 RPS RFO 

shortlist. The final 2011 RPS shortlist was provided to the PRG on January 19, 2012.
Advice 4102-E September 7, 2012 

28 

III.Project Development Status 

A. Company / Development Team 

1. Describe the Project development team and/or company 

principals and describe how many years of experience 

they have had on the development side of the electric 

industry. 

SPI has extensive experience building and maintaining biomass co-generation 

facilities. In the last thirty years SPI has constructed several biomass-fired boilers 

and steam turbine generation facilities onsite of its saw mills in California and 

Washington. The facilities are also maintained and repaired by SPI. SPI expects 

to build the Anderson II facility and not rely on an external Engineering, 

Procurement and Construction contractor. 

2. List any successful projects (renewable and conventional) 

the Project development team and/or company principals 

have owned, constructed, and/or operated. 

SPI constructed, owns and operates the following biomass generators in 

California and Washington: 

Facility Name Location 

Facility Size 

(MW) 

Anderson 1 CA 5.0 

Burney CA 20.0 

Lincoln CA 19.2 

Loyalton CA 20.0 

Quincy CA 27.5 

Sonora CA 7.5 

Aberdeen WA 18.0 

Burlington WA 28.0 

Total: 145.2 
Advice 4102-E September 7, 2012 

29 

B. Technology 

1. Technology Type and Level of Technology Maturity 

a. Discuss the type and stage of the Project’s proposed 

technology (e.g. concept state, testing stage, 

commercially operating, utility-scale operation, 

ample history of operation). 

b. If the technology has not been commercially 

demonstrated, identify whether the developer has 

or plans to have a demonstration project. Describe 

the project (MW, hours run), its results (e.g., 

temperature, GWh, or other appropriate metric) 

and its ability to perform on a commercial scale. 

c. If hybrid technology will be deployed, describe the 

configuration and potential issues and/or benefits 

created by the hybrid technology.

All five of the AGFs use or will use biomass-fed boilers with a steam turbine and 

generator to generate electricity. This technology has been in use for decades and 

is mature. 

2. Quality of Renewable Resource 

a. Explain the quality of the renewable resource that 

the Project will rely upon. Provide supporting 

documentation, such as project-specific resource 

studies, reports from RETI or the National 

Renewable Energy Lab (NREL) that supports 

resource quality claims and ability for the facility to 

provide expected generation. 

b. For biomass projects, please provide a fuel resource 

analysis and the developer’s fuel supply plan. 

Identify: 

i. From whom/where is the fuel being secured; 

and 

ii. Where the fuel is being stored 

c. Explain whether the utility believes that the Project 

will be able meet the terms of the contract given its 
Advice 4102-E September 7, 2012 

30 

independent understanding of the quality of the 

renewable resource. If necessary, reference 

successful nearby projects, completed studies, 

and/or other information. 

SPI owns 1.6 million acres of timberland in California from which it harvests 

timber for processing at its saw mills in California. The wood waste from these 

saw mills will supply nearly 100% of the fuel used at the five AGFs to generate 

electricity. SPI occasionally acquires fuel resulting from forest fuel reduction 

projects and orchard thinning and pruning. These outside fuel acquisitions are 

infrequent, thus SPI is immune from fuel supply issues and price volatility. The 

fuel for each AGF is stored onsite at each facility. 

SPI has delivered power to PG&E from the Existing QFs under standard offer QF 

agreements since the 1980s and 1990s using its own wood waste fuel. Based on 

SPI’s unique ability to self-provide nearly 100% of the fuel required for the 

AGFs, as well as its proven track record of delivering under its current standard 

offer contracts, PG&E believes that SPI will be able meet the terms of the PPA. 

3. Other Resources Required 

a. Identify any other fuel supply (other than the 

renewable fuel supply discussed above) necessary to 

the Project and the anticipated source of that 

supply; 

b. Explain whether the developer has secured the 

necessary rights for water, fuel(s), and any other 

required inputs to run the Project. 

c. Provide the estimated annual water consumption of 

the facility (gallons of water/year) 

d. Explain whether the utility believes that the Project 

will be able meet the terms of the contract given its 

independent understanding of the adequacy of the 

additional fuel or any other necessary resource 

supply. If necessary, reference successful nearby 

projects, completed studies, and/or other 

information. 

Four of the AGFs (Anderson II, Burney, Lincoln and Sonora) use a small amount 

of natural gas during start-up of the facility. The Quincy facility uses a low sulfur 
Advice 4102-E September 7, 2012 

31 

diesel during start up. The AGFs are expected to run baseload, thus the amount 

of natural gas or diesel used in start-ups during a year is expected to be small. 

SPI currently purchases natural gas from PG&E when required for start-up and 

expects to maintain this practice for the Anderson II facility. Diesel for the 

Quincy facility is purchased from local diesel suppliers. 

Saw mill operations require a substantial amount of water and SPI has secured the 

necessary rights to water and fuel for all five AGFs. SPI has wells at all of its 

facilities with the exception of Lincoln, where SPI purchases water for the boiler 

from the City of Lincoln. The Anderson II facility is being built on the same site 

as the existing Anderson facility and will have access to the wells located there. 

The estimated water consumption associated with the total generation from each 

AGF is summarized in the following table: 

AGF 1000’s of Gallons/year 

Anderson II 150,000 

Burney 93,000 

Lincoln 91,000 

Quincy 87,000 

Sonora 79,000 

Based on SPI’s unique ability to self-provide 100% of the fuel and water required 

for the AGFs, as well as its proven track record of delivering under its current 

standard offer contracts, PG&E believes that SPI will be able meet the terms of 

the PPA. 

C. Development Milestones 

Four of the Project’s AGF’s are existing facilities. The following development 

milestones apply only to the Anderson II Facility.

1. Site Control 

Explain the status of Project site control, including: 

a. Site control type (e.g. ownership, lease, BLM Rightof-Way grant, etc.) 

i. If lease, describe duration of site control and 

any exercisable extension options 
Advice 4102-E September 7, 2012 

32 

ii. Level or percent of site control attained – if 

less than 100%, discuss seller’s plan for 

obtaining full site control 

SPI has full site control by ownership of the land on which the Anderson II 

facility will be built. Anderson II will be built immediately adjacent to SPI’s 

existing Anderson I facility. 

2. Equipment Procurement 

Explain the status of equipment procurement for the 

Project, including: 

a. The status of the procurement of major equipment 

(e.g. equipment in-hand, contracts executed and 

equipment in delivery, negotiating contracts with 

supplier(s), etc.). For equipment not yet procured, 

explain any contingencies and overall timing. 

b. The developer’s history of ability to procure 

equipment. 

c. Any identified equipment procurement issues, such 

as lead time, and their effect on the Project’s date 

of operability. 

The turbine for Anderson II has been ordered and substantial deposits have been 

made. The turbine is scheduled to be delivered to the site in Anderson in 

November, 2012. The boiler has been ordered, substantial deposits have been 

made and its components are being constructed. Initial deliveries of boiler 

components are scheduled to commence in September, 2012. A Purchase Order 

(“PO”) has been issued for the transformer and it is being built. POs have been 

issued for all other major components (electrostatic precipitator, cooling tower, 

etc.). 

In the last thirty years SPI has constructed several biomass-fired boilers and steam 

turbine generation facilities onsite of its saw mills in California and Washington. 

The facilities are also maintained and repaired by SPI. Based on this experience, 

SPI has a strong track record of procuring equipment. 

3. Permitting / Certifications Status 
Advice 4102-E September 7, 2012 

33 

a. Describe the status of the Project’s RPS-eligibility 

certification from the CEC. Explain if there is any 

uncertainty regarding the Project’s eligibility. 

b. Use the following table to describe the status of all 

major permits or authorizations necessary for 

development and operation of the Project, 

including, without limitation, CEC authorizations, 

air permits, certificates of public convenience and 

necessity (CPCN) or permits to construct (PTC) for 

transmission, distribution, or substation 

construction/ expansion, land use permits, building 

permits, water use or discharge authorizations, 

Federal Aviation Administration authorizations, 

military authorizations, and Federal 

Communication Commission authorizations. If 

necessary, table may be split between public and 

confidential sections – permits requests with public 

agencies should be included in the public portion. 

The Anderson II Facility has been pre-certified as RPS-eligible by the CEC. 

There is no uncertainty regarding its eligibility. 

The following table summarizes the status of all major permits or authorizations 

necessary for development and operation of the Anderson II facility: 

Name of Permit 

or Lease 

required 

Grantor Description of 

Permit or Lease 

Current 

Status 

(to be filed, 

pending 

approval, 

approved) 

Projected 

timeframe 

for 

approval 

 Air permits U.S. EPA 

Prevention of 

Significant 

Deterioration 

Filed, 

pending 

approval 

October 

2012 

Land use 

permits 

 Shasta 

County 

 Shasta County has 

approved the EIR 

and has issued a 

grading permit. 

CUP has been Approved Approved 
Advice 4102-E September 7, 2012 

34 

issued. 

 Building 

permits 

 Shasta 

County 

 Authorization to 

proceed with the 

construction 

 To be filed 

 The 

building 

permit is 

expected 

once the 

PSD 

permit is 

obtained. 

Water use or 

discharge 

authorizations 

Water use and 

discharge permits 

for Anderson II. Approved Approved 

4. Production Tax Credit (PTC) / Investment Tax Credit 

(ITC) / Other government funding– if applicable 

a. Explain the Project’s potential eligibility for tax 

credits or other government funding based on the 

technology of the Project and contract operation 

date. 

b. If the developer is pursuing PTCs/ITCs/Other, 

explain the criteria that must be met and the 

developer’s plans for obtaining the 

PTCs/ITCs/Other. 

c. Explain whether the utility or the seller bears the 

risk if the anticipated tax credits/funding are not 

obtained. 

SPI plans to claim a Grant in Lieu of Credits as authorized in Section 1603 of the 

American Recovery and Reinvestment Act of 2009. It requires that the Anderson 

II facility start up and produce electricity by 12/31/2013. SPI bears the risk if it is 

unable to obtain the cash grant. 

5. Transmission 

a. Discuss the status of the Project’s interconnection 

application, whether the Project is in the CAISO or 

any other interconnection queue, and which 
Advice 4102-E September 7, 2012 

35 

transmission studies are complete and/or in 

progress. 

b. Discuss the status of the Interconnection 

Agreement with the interconnecting utility (e.g., 

draft issued, executed and at FERC, fully 

approved) 

c. Describe the required network and gen-tie 

upgrades and the capacity to be available to the 

Project upon completion, including any proposed 

curtailment schemes. 

d. Describe any required substation upgrades or 

construction. 

e. Discuss the timing and process for all transmissionrelated upgrades. Identify critical path items and 

potential contingencies in the event of delays 

f. Explain any issues relating to other generating 

facility projects in the transmission queue as they 

may affect the Project. 

g. If the Project is dependent on transmission that is 

likely to be congested at times, leading to a product 

that is less than 100% deliverable for at least 

several years, explain how the utility factored the 

congestion into the LCBF bid analysis. 

h. Describe any alternative transmission 

arrangements available and/or considered to 

facilitate delivery of the Project’s output. 

PG&E describes the transmission arrangements for Anderson II in more detail in 

Confidential Appendix A and Confidential Appendix D. 

D. Financing Plan 

1. Explain developer’s manner of financing (e.g. project 

financing, balance sheet financing, utility tax equity 

investment, etc.). 

2. Describe the developer’s general project financing status. 
Advice 4102-E September 7, 2012 

36 

3. To what extent (%) has the developer received firm 

commitments from financers (both debt and equity), and 

how much financing is expected to be needed to bring the 

Project online? 

4. List any government funding or awards received by the 

Project. 

5. Explain the creditworthiness of all relevant financiers 

6. Describe developer’s history of ability to procure 

financing. 

7. Describe any plans for obtaining subsidies, grants, or any 

other third party monetary awards (other than 

Production Tax Credits and Investment Tax Credits) and 

discuss how the lack of any of this funding will affect the 

Project.

SPI expects to use tax exempt pollution control financing from the California 

Pollution Control Finance Authority (“CPCFA”) for 50 to 60 percent of the 

Anderson II cost and will carry the cost of construction on its balance sheet. SPI 

has used CPCFA financing in the past for other projects similar to the Anderson II 

project. 

SPI has not received any government funding or awards. SPI has a track record of 

balance sheet financing the construction of its previous projects, so procuring 

financing has not been an issue. SPI plans to claim a Grant in Lieu of Credits as 

authorized in Section 1603 of the American Recovery and Reinvestment Act of 

2009. SPI bears the risk if it is unable to obtain the cash grant. 

Additional financing information is provided in Confidential Appendix A. 

IV. Contingencies and/or Milestones 

Describe major performance criteria and guaranteed milestones, 

including those outside the control of the parties, including 

transmission upgrades, financing, and permitting issues. 

The PPA includes certain performance criteria and milestones that PG&E 

includes in its form RPS PPA contracts. These and other contingencies and 

milestones are addressed in Confidential Appendices A and D. 
Advice 4102-E September 7, 2012 

37 

V. Request for Commission Approval 

PG&E requests that the Commission issue a resolution no later than early March 

2013 that: 

1. Approves the PPA in its entirety, including payments to be made by 

PG&E pursuant to the PPA, subject to the Commission’s review of 

PG&E’s administration of the PPA. 

2. Finds that any procurement pursuant to the PPA is procurement from 

eligible renewable energy resources for purposes of determining 

PG&E’s compliance with any obligation that it may have to procure 

eligible renewable energy resources pursuant to the California RPS 

(Public Utilities Code Section 399.11 et seq.), D. 11-12-020 and D.11-

12-052, or other applicable law. 

3. Finds that all procurement and administrative costs, as provided by 

Public Utilities Code section 399.13(g), associated with the PPA shall 

be recovered in rates. 

4. Adopts the following finding of fact and conclusion of law in support of 

CPUC Approval: 

a. The PPA is consistent with PG&E’s 2011 RPS procurement plan. 

b. The terms of the PPA, including the price of delivered energy, is 

reasonable. 

5. Adopts the following finding of fact and conclusion of law in support of 

cost recovery for the PPA: 

a. The utility’s costs under the PPA shall be recovered through 

PG&E’s Energy Resource Recovery Account. 

 b. Any stranded cost that may arise from the PPA is subject to the 

provisions of D.04-12-048 that authorize recovery of stranded 

renewables procurement costs over the life of the contract. The 

implementation of the D.04-12-048 stranded cost recovery 

mechanism is addressed in D.08-09-012. 
Advice 4102-E September 7, 2012 

38 

6. Adopts the following findings with respect to resource compliance with 

the EPS adopted in R.06-04-009: 

a. The PPA is pre-approved as meeting the EPS because it is for an 

existing biomass facility covered by Conclusion of Law 35(d) of 

D.07-01-039. 

b. PG&E has provided the notice of procurement required by D.06-01-

038 in its Advice Letter filing. 

7. Adopts a finding of fact and conclusion of law that deliveries from the 

PPA shall be categorized as procurement under the portfolio content 

category specified in Section 399.16(b)(1)(A), subject to the 

Commission’s after-the-fact verification that all applicable criteria have 

been met. 

8. Adopts a finding of fact and conclusion of law that, to the extent the 

Anderson II facility receives all necessary approvals to be designated as 

a CHP Facility defined by the QF/CHP Settlement adopted by D.10-12-

035: 

a. Anderson II will be counted as a GHG Credit from a New CHP 

Facility pursuant to section 7.3.1.1 of the QF/CHP Settlement 

Agreement Term Sheet. 

b. Anderson II will not be counted toward the MW targets pursuant to 

section 5.2.5 of the QF/CHP Settlement Agreement Term Sheet. 

Protests: 

Anyone wishing to protest this filing may do so by sending a letter by September 

27, 2012, which is 20 days from the date of this filing. The protest must state the 

grounds upon which it is based, including such items as financial and service 

impact, and should be submitted expeditiously. Protests should be mailed to: 

CPUC Energy Division 

Attention: Tariff Unit, 4th Floor 

505 Van Ness Avenue 

San Francisco, California 94102 
Advice 4102-E September 7, 2012 

39 

Facsimile: (415) 703-2200 

E-mail: EDTariffUnit@cpuc.ca.gov 

Copies should also be mailed to the attention of the Director, Energy Division, 

Room 4004, at the address shown above. 

The protest also should be sent via U.S. mail (and by facsimile and electronically, 

if possible) to PG&E at the address shown below on the same date it is mailed or 

delivered to the Commission: 

 Pacific Gas and Electric Company 

 Attention: Brian K. Cherry 

 Vice President, Regulatory Relations 

 77 Beale Street, Mail Code B10C 

 P.O. Box 770000 

 San Francisco, California 94177 

 Facsimile: (415) 973-7226 

 E-Mail: PGETariffs@pge.com 

Effective Date: 

PG&E requests that the Commission issue a resolution approving this advice 

filing no later than early March, 2013.

Notice: 

In accordance with General Order 96-B, Section IV, a copy of this Advice Letter 

excluding the confidential appendices is being sent electronically and via U.S. 

mail to parties shown on the attached list and the service lists for R.11-05-005, 

and R.12-03-014. Non-market participants who are members of PG&E’s 

Procurement Review Group and have signed appropriate Non-Disclosure 

Certificates will also receive the Advice Letter and accompanying confidential 

attachments by overnight mail. Address changes to the General Order 96-B 

service list should be directed to PGETariffs@pge.com. For changes to any other 
Advice 4102-E September 7, 2012 

40 

service list, please contact the Commission’s Process Office at (415) 703-2021 or 

at Process_Office@cpuc.ca.gov. Advice letter filings can also be accessed 

electronically at http://www.pge.com/tariffs. 

Vice President – Regulatory Relations 

cc: Service List for R.11-05-005 

 Service List for R.12-03-014 

 Paul Douglas – Energy Division 

Jason Simon – Energy Division 

Adam Schultz – Energy Division 

Joseph Abhulimen – DRA 

Cynthia Walker – DRA 

Attachments 

Limited Access to Confidential Material: 

The portions of this Advice Letter marked Confidential Protected Material are 

submitted under the confidentiality protection of Section 583 and 454.5(g) of the 

Public Utilities Code and General Order 66-C. This material is protected from 

public disclosure because it consists of, among other items, the Amendment itself, 

price information, and analysis of the proposed RPS Amendment, which are 

protected pursuant to D.06-06-066 and D.08-04-023. A separate Declaration 

Seeking Confidential Treatment regarding the confidential information is filed 

concurrently herewith. 

Confidential Attachments: 

Appendix A – Consistency with Commission Decisions and Rules and Project 

Development Status 

Appendix B – 2011 Solicitation Overview 

Appendix C1 – Independent Evaluator Report (Confidential) 

Appendix D – Contract Summary: SPI 

Appendix E – Comparison of the PPA to PG&E’s 2011 Pro Forma Power 

Purchase Agreement 

Appendix F – SPI Power Purchase Agreement 

Appendix G – Projects’ Contributions Toward RPS Goals 
Advice 4102-E September 7, 2012 

41 

Public Attachment

Appendix C2 – Independent Evaluator Report (Public) 
CALIFORNIA PUBLIC UTILITIES COMMISSION 

ADVICE LETTER FILING SUMMARY 

ENERGY UTILITY 

MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) 

Company name/CPUC Utility No. Pacific Gas and Electric Company (ID U39 E)

Utility type: Contact Person: Meredith Allen / Greg Backens 

 ELC  GAS Phone #: 415-973-2868 / 415-973-4390 

 PLC  HEAT  WATER E-mail: MEAe@pge.com / gab4@pge.com 

EXPLANATION OF UTILITY TYPE 

ELC = Electric GAS = Gas 

PLC = Pipeline HEAT = Heat WATER = Water 

(Date Filed/ Received Stamp by CPUC)

Advice Letter (AL) #: 4102-E Tier: 3

Subject of AL: Power Purchase Agreement for the Procurement of Eligible Renewable Energy Resources 

Between Sierra Pacific Industries and Pacific Gas and Electric Company

Keywords (choose from CPUC listing): Agreements, Procurement

AL filing type:  Monthly  Quarterly  Annual  One-Time  Other _____________________________ 

If AL filed in compliance with a Commission order, indicate relevant Decision/Resolution #: N/A 

Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: N/A 

Summarize differences between the AL and the prior withdrawn or rejected AL: N/A 

Is AL requesting confidential treatment? Yes.

See the attached matrix that identifies all of the confidential information. 

If so, what information is the utility seeking confidential treatment for: The attached matrix identifies the confidential 

information. 

Confidential information will be made available to those who have executed a nondisclosure agreement: Non-market 

participants who are members of PG&E’s Procurement Review Group who have signed nondisclosure agreements will 

receive the confidential information. 

Name(s) and contact information of the person(s) who will provide the nondisclosure agreement and access to the 

confidential information: Gillian Clegg, (415) 973-1332 

Resolution Required?  Yes No 

Requested effective date: Early March 2013 No. of tariff sheets: N/A 

Estimated system annual revenue effect (%): N/A

Estimated system average rate effect (%): N/A

When rates are affected by AL, include attachment in AL showing average rate effects on customer classes 

(residential, small commercial, large C/I, agricultural, lighting).

Tariff schedules affected: N/A 

Service affected and changes proposed: N/A

Protests, dispositions, and all other correspondence regarding this AL are due no later than 20 days after the date of 

this filing, unless otherwise authorized by the Commission, and shall be sent to: 

CPUC, Energy Division Pacific Gas and Electric Company 

Tariff Files, Room 4005 

DMS Branch 

505 Van Ness Ave., San Francisco, CA 94102 

EDTariffUnit@cpuc.ca.gov 

Attn: Brian K. Cherry, Vice President, Regulatory Relations 

77 Beale Street, Mail Code B10C 

P.O. Box 770000 

San Francisco, CA 94177 

E-mail: PGETariffs@pge.com 







Public Appendix C2

Independent Evaluator Report
PACIFIC GAS AND 

ELECTRIC COMPANY 

2011 RENEWABLE 

POWER SOLICITATION

REPORT OF THE INDEPENDENT 

EVALUATOR ON A CONTRACT WITH SIERRA 

PACIFIC INDUSTRIES

S E P T E M B E R 5 , 2012

A R R O Y O S E C O C O N S U L T I N G
2

TA B L E O F C O N T E N T S

EXECUTIVE SUMMARY.............................................................................................................3

1. ROLE OF THE INDEPENDENT EVALUATOR............................................................4

2. ADEQUACY OF OUTREACH TO PARTICIPANTS AND ROBUSTNESS OF 

SOLICITATION.......................................................................................................................8

3. FAIRNESS OF OFFER EVALUATION AND SELECTION METHODOLOGY.15

4. FAIRNESS OF HOW PG&E ADMINISTERED THE OFFER EVALUATION 

AND SELECTION PROCESS............................................................................................36

5. FAIRNESS OF PROJECT-SPECIFIC NEGOTIATIONS .............................................49

6. MERIT FOR CPUC APPROVAL.........................................................................................63
3

E X E C U T I V E S U M M A RY

This report provides an independent evaluation of the process by which the Pacific Gas 

and Electric Company (“PG&E”) negotiated and executed a Power Purchase Agreement 

(PPA) with Sierra Pacific Industries (“SPI”) for the output of five generation projects fueled 

with woody waste biomass. The PPA covers delivery from four existing projects (Burney, 

Lincoln, Quincy, Sonora) that have long been contracted with PG&E as Qualifying Facilities 

(QFs), and one new project, the Anderson II facility, which will replace the existing 

Anderson power plant. In aggregate the portfolio will provide 58 MW of contract capacity.

PG&E and SPI initiated bilateral discussions about a new aggregated RPS contract to 

replace the existing QF contracts in late 2010. In June 2011 PG&E terminated those 

discussions, asking SPI to offer its projects into the utility’s 2011 Renewable Portfolio 

Standard (RPS) Request for Offers (RFO). SPI’s Offer to contract its portfolio in a single 

contract was shortlisted by PG&E. Negotiations resulted in a PPA executed on August 9,

2012. An independent evaluator (IE), Arroyo Seco Consulting (Arroyo), reviewed PG&E’s 

processes as PG&E conducted its solicitation and the parties negotiated a new PPA. 

The structure of this report follows the 2011 RPS Shortlist Report Template provided by 

the Energy Division of the CPUC. Topics covered include:

 The role of the IE;

 Adequacy of outreach for and robustness of the prior competitive solicitation;

 The fairness of the design of PG&E’s least-cost, best-fit (LCBF) methodology;

 The fairness of PG&E’s administration of its LCBF methodology;1

 Fairness of project-specific negotiations; and

 Merit of the PPA for CPUC approval.

Arroyo’s opinion is that the negotiations between PG&E and SPI were, overall,

conducted in a manner that was fair to ratepayers. The utility granted SPI a unique 

concession not provided to competing sellers in the 2011 solicitation; the circumstances of 

how and why this concession was granted mitigate Arroyo’s concerns about its fairness to 

competitors. Arroyo agrees with PG&E that the contract merits CPUC approval, based on 

an independently developed opinion that the contract ranks high in net valuation and low in

contract price; Arroyo regards the portfolio fit of the SPI projects with PG&E's supply

needs as moderate, and the project viability of the four existing powerhouses as high. 

Arroyo ranks the project viability of the new Anderson II facility as high as well. 
4

1 . RO L E O F T H E I N D E P E N D E N T 

E VA L UAT O R

Pacific Gas and Electric Company issued a Request for Offers (RFO) on May 11, 2011, a

competitive solicitation for power generation that qualifies as eligible renewable energy 

resources (ERRs) under the California Renewables Portfolio Standard Program.

2

 The RPS 

Program was established by state law to ensure that retail sellers of electricity meet targets 

for procurement from ERRs as a percentage of annual retail sales. 

The CPUC had conditionally approved PG&E’s 2011 RPS procurement plan in its 

Decision 11-04-030 issued on April 14, 2011. This chapter elaborates on the prior CPUC 

decisions that form the basis for an Independent Evaluator’s participation in the 2011 RPS 

RFO and in bilaterally negotiated contracts for RPS-eligible energy, describes key roles of 

the IE, details activities undertaken by the IE in this solicitation to fulfill those roles, and 

identifies the treatment of confidential information.

A. CPUC DECISIONS REQUIRING INDEPEND ENT EVALUATOR PARTICIPATION

The CPUC first mandated a requirement for an independent, third-party evaluator to 

participate in competitive solicitations for utility power procurement in Decision 04-12-048

on December 16, 2004 (Findings of Fact 94-95, Ordering Paragraph 28). The CPUC 

required use of an IE when Participants in a competitive procurement solicitation include 

affiliates of investor-owned utilities (IOUs), IOU-built projects, or IOU-turnkey projects. 

The Decision envisaged that establishing an IE role would serve as a safeguard against anticompetitive conduct in the process of evaluating IOU-built or IOU-affiliated projects 

competing against Power Purchase Agreements (PPAs) with independent power developers.

In approving the IOUs’ 2006 RPS procurement plans, the CPUC issued Decision 06-05-

039 on May 25, 2006. This Decision expanded the CPUC’s requirements, ordering that each 

IOU use an IE to evaluate and report on the entire solicitation, evaluation, and selection 

process, for the 2006 RPS RFO and future competitive solicitations. This requirement now 

applies whether or not IOU-owned or IOU-affiliate generation participates in the solicitation

(Finding of Fact 20, Conclusion of Law 3, and Ordering Paragraph 8). This was intended by 

the CPUC to increase the fairness and transparency of the Offer selection process.

Decision 06-05-039 required the IE to report separately from the utility on the bid

solicitation, evaluation, and selection process. Based on that Decision, the IE should 

 

1 The first four chapters are taken from the IE report prepared in October 2011 that accompanied 

PG&E’s short list; since then PG&E has sought to address the concerns expressed about 

methodology and administration in its 2012 RPS Plan, and has revised its LCBF methodology.

2 The solicitation protocol was amended slightly on June 7, 2011 to alter the schedule for the RFO.
5

provide a preliminary report along with the IOU submitting its short list, and a final report 

with the advice letter or letters for approval of contracts with the selected Offers.

B. KEY INDEPENDENT EVALUATOR ROLES

To comply with the requirements ordered by the CPUC, PG&E retained Arroyo Seco 

Consulting to serve as IE for the 2011 competitive solicitation for renewable resources, 

providing an independent evaluation of the utility’s Offer evaluation and selection process.

The CPUC stated its intent for participation of an IE in competitive procurement 

solicitations to “separately evaluate and report on the IOU’s entire solicitation, evaluation 

and selection process”, in order to “serve as an independent check on the process and final 

selections.”3 More specifically, the Energy Division of the CPUC has provided a template to 

guide how IEs should report on the 2011 RPS competitive procurement process, outlining 

four specific issues that should be addressed:

 Describe the IE’s role;

 Did the IOU do adequate outreach to potential bidders, and was the solicitation 

robust? 

 Was the IOU’s LCBF methodology designed such that bids were fairly evaluated?

 Was the LCBF bid evaluation process fairly administered?

The structure of this report, setting out detailed findings for each of these issues, is 

organized around the template provided by the ED. 

C. IE ACTIVITIES

To fulfill the role of evaluating PG&E’s 2011 solicitation, several tasks were undertaken, 

both prior to Offer Opening and subsequently. Prior to Offer Opening on June 22, 2011, 

Arroyo performed several tasks to assess PG&E’s methodology for evaluating Offers:

 Reviewed the solicitation and its attachments including PG&E’s 2011 Form 

Agreements and description of the LCBF methodology and criteria.

 Examined the utility’s nonpublic protocols detailing how PG&E would evaluate 

Offers against various criteria.

 Attended PG&E’s Bidders’ Conference on May 19, 2011 to evaluate the information 

provided to potential Participants, and how that information was distributed.

 Reviewed the list of registered attendees of the Bidders’ Conference against PG&E’s 

master list of RFO contacts (used for outreach to potential Participants). 

 

3 CPUC Decision 06-05-039, May 25, 2006, “Opinion Conditionally Approving Procurement Plans 

for 2006 RPS Solicitations, Addressing TOD Benchmarking Methodology”, page 46.
6

 Reviewed the posting of questions and answers from the Bidders’ Conference on 

PG&E’s public website to check whether information that was made available inperson to conference attendees was also provided to other potential Participants.

 Examined PG&E’s 2011 RFO master contact list; performed an analysis of contacts 

with respect to industry and technology representation.

 Interviewed members of PG&E’s evaluation committee regarding details of the 2011 

version of the utility’s LCBF methodology and its inputs.

During the period between Offer Opening and PG&E’s development of a final short list

for submittal to the CPUC, Arroyo’s activities included:

 Participating in opening Offers. Arroyo observed the opening of each Offer and 

observed the PG&E team logging in each Offer. The IE took an electronic copy of 

each Offer package, and independently built a database for tracking Offers.

 Reading portions of each Offer. Arroyo particularly scrutinized Offers for utility 

purchase. For PPA Offers, Arroyo focused on pricing, collateral, interconnection, 

permitting, technology, resource assessment, site control, and development and 

ownership experience descriptions in detail.

 Building an independent valuation model and using it to value Offers. This served as 

a cross-check against PG&E’s LCBF model. The IE model used independent inputs 

and a different methodology than PG&E’s. It was much simpler and lacked detail 

and granularity used in the PG&E model. However, the independent valuation was 

useful for testing the PG&E team’s ranking of Offers using alternate assumptions.

 Attending PG&E’s evaluation team discussions of Offers, criteria, issues, etc. 

 Scoring Offers independently for viability, using the ED’s 2011 version of the 

Project Viability Calculator. The independently developed Offer valuations and 

viability scores provided part of the basis for developing an independent view of the 

relative merit of Offers that the PG&E team selected or rejected.

 Reviewing PG&E’s scoring of Offers for the criteria other than market valuation and 

project viability, testing for consistency and fairness in the treatment of projects. 

 Attending meetings of PG&E’s steering committee, as it made decisions about the 

logic for selecting a short list and approved proposed selections for the short list.

 Attending meetings of PG&E’s Procurement Review Group (PRG), including

answering questions about the solicitation and the Offers, and presenting an 

independent commentary and observations about the RFO. 
7

 Offering PG&E’s evaluation team and steering committee commentary based on 

independent opinion. In a few cases Arroyo provided specific suggestions on 

particular topics such as the feasibility of specific out-of-state transmission proposals.

Additionally, in order to prepare this report on the contract with Sierra Pacific 

Industries, Arroyo pursued project-specific activities:

 Observed (telephonically) several negotiation sessions between utility staff and SPI’s 

commercial team;

 Reviewed draft term sheets, draft contracts, and other documents passed between 

the parties;

 Performed an independent valuation of the SPI contract and evaluation of the 

project viability of the Anderson II facility;

 Compared the net value and pricing of the SPI contract to peer groups consisting of 

alternative proposals available to PG&E.

D. TREATMENT OF CONFID ENTIAL INFORMATION

The CPUC’s Decision 06-06-066 detailed guidelines for treating confidential information

in IOU power procurement and related activities, including competitive solicitations. The 

Decision provides for confidential treatment of “Score sheets, analyses, evaluations of 

proposed RPS projects”, vs. public treatment (after submittal of final contracts) of the total 

number of projects and megawatts bid by resource type. Where the IE’s reporting on the 

fairness of PG&E’s selection of Offers requires explicit discussion of such analyses, scores, 

and evaluations, these are redacted from the public report.
8

2 . A D E QUAC Y O F O U T R EAC H T O 

PA RT I C I PA N T S A N D RO BU ST N E S S 

O F T H E S O L I C I TAT I O N

In its 2011 RPS solicitation, PG&E sought to meet a goal of procuring 1 to 2% of retail 

load by selecting Offers that will lead to negotiated contracts and commercially operating 

generating facilities. This section assesses the degree to which PG&E adequately conducted 

outreach activities to drum up sufficient participation in the RFO process, and the degree to 

which the resulting solicitation may be judged robust enough to be competitive.

A. CLARITY AND CONCISION OF SOLICITATION MATERIALS

While not really concise (it totals 53 pages excluding attachments, vs. Edison’s 46 pages 

and SDG&E’s 24 pages), Arroyo believes that the contents of PG&E’s 2011 RPS RFO 

solicitation protocol generally provided clear and comprehensible direction to Participants 

on how to prepare and submit complete Offer packages that could be accepted and 

evaluated. Arroyo has a few observations about the clarity of the guidance provided in the 

protocol and issues created when Participants failed to understand or follow that guidance:

 Most Offers were submitted as complete and conforming packages. Common 

deficiencies in other Offers included:

1. Failure to submit the offer form (Attachment D) for all Offer variants or phases; 

2. Errors in filling in the offer form, such as missing data, incomplete project 

description, or incomplete self-scored Project Viability Calculator;

3. Use of a earlier draft version of Attachment D from the original posting of the 

RFO documents, rather than the one finalized on June 2, 2011 and posted on 

PG&E’s public web site then;

4. Failure to provide the text and data of the Offer in the requested Microsoft 

Word 2003 and Excel 2003 formats (as opposed to later versions or to Acrobat 

.pdf files);

5. Corrupted data files;

6. Failure to submit the hardcopies of the Offer as clearly requested in the protocol;

7. Failure to submit a copy of a completed CAISO or PTO interconnection study 

in cases where the project had progressed to the point where such a study had 

been obtained. This requirement was explicitly stated in the solicitation protocol 

but widely ignored by Participants; and
9

8. In the case of projects outside California and not directly interconnecting to the

CAISO, failure to specify how power would be delivered to a CAISO intertie 

point with a firm schedule, or what arrangements would be made to deliver to 

the CAISO. 

Since requirements for the offer form were addressed in the solicitation protocol, in

the instruction sheet for the offer form, and in the bidders’ workshop presentation, 

Arroyo can only surmise that many Participants neglected to pay attention to these 

small but important details. Sending deficiency letters to Participants who failed to 

provide required information and obtaining corrections was time-consuming for all 

involved, but in most cases corrected documents were provided by the Participants 

and were accepted by PG&E. Arroyo cannot identify any specific improvements to 

the clarity of the RFO materials that might have reduced the incidence of such 

Participant errors, other than editing the instructions for attachment D (e.g. restating 

in the offer form instructions the need to Enable Macros in MS Excel) or walking 

through the form step by step in a section of the bidders’ conference.

 The 2011 solicitation protocol stated at least four preferences of the utility that are 

not specifically among the evaluation criteria, including preferences for:

1. Projects considered bundled, in-state resources, over projects whose output will 

be considered renewable energy credits (RECs) for RPS compliance purposes;

2. Projects that deliver to CAISO nodes within the PG&E service territory, as 

opposed to the territories of other utilities (CAISO or otherwise) or to an 

interface point at the boundary of the CAISO;

3. Projects that contribute to PG&E’s Resource Adequacy (RA) requirements, such 

as CAISO-interconnected projects with full deliverability, as opposed to energyonly projects in the CAISO or projects in other balancing area authorities for 

which deliverability or import capability of RA capacity throughout the contract 

term to PG&E has not yet been established.

4. Projects that offer flexibility in on-line date, given regulatory uncertainty 

affecting PG&E’s need for RPS-eligible energy in 2014 and 2015.

4

 

Based on comments provided in feedback sessions after the RFO, it appeared that 

several Participants were not aware of these stated preferences, perhaps because the 

description of the preference fell outside the chapter of the solicitation protocol that 

describes how Offers were to be evaluated. Arroyo recommends that in the future 

PG&E should edit the protocol to clarify that these specific preferences can play an 

important role in selection, even though they are not among the evaluation criteria. 

This would improve the transparency of the selection process to Participants.

 

4 In PG&E’s presentation at the bidders’ conference, PG&E also expressed a preference that was not 

included in the solicitation protocol: “PG&E expects to focus on the latter part of the second (2014-

2016) compliance period.” It would have been helpful to state this preference clearly within the text 

of the protocol.
10

 The discussions that took place while debriefing non-shortlisted Participants after 

the RFO suggest that several developers did not understand the role of the Project 

Viability Calculator as a tool for assessing the likelihood that a proposed project 

could attain commercial operation and for screening proposals. Also, it is clear from 

how some Participants self-scored their projects that the Calculator’s scoring 

guidelines provided by the ED are broadly misunderstood or misinterpreted. 

Several Participants did not or chose not to understand that the Calculator was 

designed such that the highest score for “project development experience” or 

“ownership/O&M experience” is assigned only if the development team has 

previously brought into operation at least two projects of the same technology and

similar or larger MW capacity than that proposed. Some Participants could have 

improved their scores if they had read the guidelines more carefully and chosen to 

propose projects that could score higher based on those details. However, guidelines 

were provided in plain sight in the offer form. It is unclear how PG&E could have 

provided better guidance on how it uses the Calculator, beyond spending more time 

in the bidders’ workshop walking through each criterion in the Calculator in detail.

Given the bulk of material that PG&E needs to provide in its protocol, it is not 

surprising that it exceeds fifty pages. Arroyo cannot identify any straightforward way to 

make the protocol more concise; the material provided is generally needed to provide 

Participants with a full and transparent view of how the solicitation will function and with 

full disclosure about obligations and constraints that govern Participants if they choose to 

proceed. One possibility would be to reduce the information required in Offers to focus 

more narrowly on data needed to establish eligibility and to perform the evaluation.

When the utility solicited feedback from non-shortlisted Participants after closing the 

solicitation, the sense of the feedback provided by developers was that PG&E’s “solicitation 

was well organized” and “the most user-friendly of the three IOUs”, that “the instructions 

were pretty clear”, that in particular “the bidders’ conference was very informative” and that 

the utility team’s handling of questions and answers was responsive and helpful. Criticisms 

of the solicitation tended to focus on technical problems and burdensome nature of filling 

out the offer form, the priorities embedded in the Project Viability Calculator, the lack of 

transparency on what sort of projects were short-listed at what prices, the large volume and 

possible redundancy of information requested in the Offers, and that hardcopies of the 

Offer packages should not be required as opposed to electronic copies.

Overall, Arroyo believes that PG&E’s solicitation materials were clear, if not particularly 

concise, and that improvement opportunities to help ensure that more complete Offer 

packages are submitted in the future are minor. Improvements could be helpful in 

streamlining the process and increasing Participants’ satisfaction. Arroyo has some specific 

critiques regarding the solicitation protocol’s lack of transparency about Offers for sites for 

development, described in the next chapter.
11

B. ADEQUACY OF OUTREACH

Here are some considerations used to evaluate whether PG&E performed successfully in 

reaching out to the community of renewable power developers:

 How many individuals were contacted? To what extent were these contacts in 

companies that develop renewable power?

 Was a diverse set of renewable technologies covered in the contacts, or was the 

outreach excessively focused on one or two technologies?

 How widely was information about the solicitation disseminated? Was information 

about the solicitation readily available to the public?

 To what extent did Participants appear well-informed about the details of the 

solicitation?

By May 2011, PG&E had compiled a general contact list for use in publicizing its RFOs, 

totaling more than 1,600 individuals; this is a significant increase from the version of the list 

used in the 2009 RPS solicitation, with closer to 1,100 contacts. PG&E appears to have 

been actively compiling contacts for outreach, including a contact list for the biogas industry.

When analyzed to attempt to assess which industries the contacts represented, the largest 

segment was made up of individuals active in the solar power sector, followed by wind 

power and biomass-based generation. Figure 1 displays the estimated shares by industry 

sector of these contacts. Note that this contact list is employed not just for renewable 

solicitations but for all-source RFOs as well.

Inspection of the contact list reveals that many of the major developers of renewable 

energy in North America are included, particularly among solar, wind, and geothermal 

developers. About 60% of the individual contracts represented organizations that could 

develop renewable generation or sell from existing facilities. Other contacts were with 

entities that provide services to renewable energy developers, such as attorneys, financing 

providers, consultants, equipment vendors, and wholesale marketers; it is unclear whether 

these providers sought to be on PG&E’s RFO contact list in order to keep abreast of the 

solicitation or to develop business with renewable energy developers.

PG&E did not issue a press release to announce the issuance of the 2011 RPS RFO. 

However, news of the solicitation was picked up and reported in the electric power trade 

press, including publications such as Global Power Report, Megawatt Daily, Power, Finance, 

and Risk, and ReCharge. In addition, the detailed solicitation protocol and its attachments, 

the schedule, and other informational items were posted on PG&E’s public website.

Figure 1. Breakdown of contact list by sector
12 33%

14%

12%

12%

6%

5%

3%

3%

3%

2%

2% 2%1%1%1%

Solar

Vendor

Wind

Other

Fossil

Biomass

Biogas

Real estate

Finance

Geothermal

Marketing

Attorney

Hydro

DSM

Wave/tidal

Arroyo notes that news of PG&E’s RPS RFO was publicized not only in the trade press 

but also on the public websites of several law firms whose practices include a focus on 

renewable energy contract law, such as Allen Matkins, Davis Wright Tremaine, Stoel Rives,

and Wilson Sonsini. The news of the RFO was also disseminated by the Geothermal 

Resources Council and the National Renewable Energy Laboratory.

Another indicator of the adequacy of outreach for the RFO was the response of 

attendees for the bidders’ conference. Figure 2 counts individuals, by sector, who registered 

for the conference (there is no means to check who actually attended). A turnout of more 

than 400 individuals represents a very strong response and expression of industry interest, 

and is an increase of about 70% over the registration for the 2009 RPS RFO bidders’ 

conference. The largest share of attendees represented the solar and wind sectors. 

Arroyo estimates that out of the attendees at the 2011 bidders’ conference, about 55% 

were with firms that submitted Offers. This was a higher portion than in the 2009 bidders’ 

conference. This is an indication of successful outreach, in that the audience that registered 

for the conference was made up mostly of the staffs of developers, owners, or traders that 

were positioned to submit Offers, as opposed to vendors, attorneys, or consultants to 

developers, or to small entities that were not really prepared to propose projects.

Arroyo’s conclusion is that PG&E conducted substantial outreach to renewable power 

developers in North America. The number of individuals contacted, the distribution of the 

news of the solicitation in the electric power trade press, and the strikingly large attendance 

at the bidders’ conference and the decent yield of Offers submitted by conference attendees 

all suggest that PG&E’s overall outreach effort was strong and effective. 
13

Figure 2. Breakdown of registration for bidders’ conference 

48%

19%

8%

6%

4%

3%

3%

2%

2%2%1%1%

1%

Solar

Wind

Vendor

Other

Biogas

Marketing

Finance

Fossil

Geothermal

Real estate

Biomass

Attorney

Wave/Tidal

Hydro

DSM

100%= 418 registered attendees

C . ROBUSTNESS OF THE SOLICITATION

Here are some considerations used to evaluate whether PG&E performed successfully in 

conducting a robust solicitation:

 Was the response to the solicitation large enough for PG&E to expect to achieve its 

goal of procuring 1 – 2% of retail load, given the likely attrition of Offers between 

short list and commercial operation, without having to accept a majority of Offers?

 Was the response to the solicitation diverse with respect to technologies?

 Was the distribution of responses broadly represented by projects that were assessed 

as moderately or highly viable, or was there an excess of less viable Offers?

The Offers PG&E received totaled an immense volume of projected generation. If all 

the Offers were contracted they would total more than PG&E’s entire retail load. Such a 

massive response to the RFO should provide plenty of opportunity for PG&E to negotiate, 

contract for, and procure the stated objective for the RFO of 1 to 2% of retail load. Total 

GWh/year volume elicited in Offers exceeded the 2009 RFO’s response by more than 80%. 

This ratio of offered volume to targeted procurement volume reflects a remarkably healthy 

and robust response. More than 300 in-state projects were proposed for contracts, often 

with several variants (e.g. varying on-line dates, pricing packages, delivery terms, etc.).

The Offers submitted to the 2011 RPS RFO provided more technology diversity than 

those submitted to the 2009 RFO. There was a greater volume of 2011 proposals for 
14

projects using technologies or resources that were weakly represented in the last solicitation. 

While it is difficult to attribute this to specific outreach activities by the utility, Arroyo is 

aware that PG&E staff had actively reached out in order to make potential Participants using 

these weakly represented technologies aware of the availability of the RPS RFO as a means 

to obtain long-term PPAs. Given the large number of Offers submitted in 2011 using the 

well-represented technologies such as solar and wind, Arroyo does not believe that the 

outreach activities of the utility were in any way unfair to those developer communities.

D. ADEQUACY OF FEEDBACK FROM PARTICIPANTS

After receiving notification that their Offers had been rejected, several of the nonshortlisted Participants expressed an interest in follow-up discussions to be debriefed on 

reasons for the decision. Arroyo participated in many of these sessions. Based on the 

number of debriefing sessions that took place (about fifty) and the extent to which the utility 

team obtained actionable commentary about the RFO from Participants, Arroyo believes 

that PG&E sought adequate feedback about the bidding and evaluation process. 

In general these feedback sessions were welcomed by Participants. They created an 

opportunity for Participants to obtain a somewhat clearer view of how PG&E’s evaluation 

criteria and preferences applied to their specific Offers, and of what factors played a role in 

the failure to select the Offers. Many Participants, when prompted to offer feedback on 

PG&E’s solicitation materials and process, had generally positive commentary, including 

positive ratings for the format of the Offer (such as for the verification checks built into the 

spreadsheet), for the process and its fairness, for the helpfulness of the bidders’ conference,

and for the opportunity to debrief on the outcome of PG&E’s selection. A variety of 

specific criticisms were offered, including some constructive suggestions that are 

summarized later in this report. Some major themes of the criticisms included:

 Data requirements for the written Offers were onerous;

 More transparency in characterizing the price of short-listed Offers would be 

preferred (often by Participants whose Offers were not short-listed and who 

aspire to submit their projects to future solicitations with improved pricing);

 The requirement for hardcopies of the Offers should be dropped in favor of 

electronic-only submittals; and

 More clarity on how the Project Viability Calculator guidelines are applied would 

be helpful; many Participants disagreed with the Calculator’s design because they 

felt their Offers were unfairly disadvantaged by how scoring criteria are specified.

Arroyo’s opinion is that PG&E’s efforts to give and receive feedback after the close of 

the solicitation were adequate and quite helpful both to the utility and to those Participants 

who were willing to take part in a debriefing session. 
15

3 . FA I R N E S S O F OFFER

EVA L UAT I O N A N D SE L E C T I O N 

M E T H O D O L O G Y

The key finding of this chapter is that PG&E’s evaluation and selection methodology for 

identifying a short list for the 2011 RPS RFO was designed fairly, overall. Arroyo has some 

disagreements with the utility’s approach.

The following discussion identifies principles for evaluating the methodology, describes 

it, evaluates its strengths and weaknesses, and identifies some specific issues with the 

methodology and its inputs that Arroyo recommends be addressed in future solicitations.

A. PRINCIPLES FOR EVALUATING THE METHOD OLOGY

The Energy Division of the CPUC has usefully suggested a set of principles for 

evaluating the process used by IOUs for selecting Offers in competitive renewable 

solicitations, within the template intended for use by IEs in reporting. These include:

 The IOU bid evaluation should be based only on information submitted in bid 

proposal documents. 

 There should be no consideration of any information that might indicate whether the 

bidder is an affiliate.

 Procurement targets and objectives were clearly defined in the IOU’s solicitation 

materials.

 The IOU’s methodology should identify quantitative and qualitative criteria and 

describe how they will be used to rank bids. These criteria should be applied 

consistently to all bids. 

 The LCBF methodology should evaluate bids in a technology-neutral manner.

 The LCBF methodology should allow for consistent evaluation and comparison of 

bids of different sizes, in-service dates, and contract length.

Some additional considerations appear relevant to PG&E’s specific situation. Unlike 

some utilities, PG&E does not rely on weighted-average calculations of scores for evaluation 

criteria to arrive at a total aggregate score. Instead, the team ranks Offers by net market 

value, after which, “[u]sing the information and scores in each of the other evaluation 

criteria, PG&E will decide which Offers to include and which ones not to include on the 

Shortlist.”5 The application of judgment in bringing the non-valuation criteria to bear on 

 

5Pacific Gas and Electric Company, “Renewables Portfolio Standard, 2011 Solicitation Protocol, May 

11, 2011 (Updated June 7, 2011)”, page 40.
16

decision-making, rather than a mechanical, quantitative means of doing so, implies an 

opportunity to test the fairness and consistency of the method using additional principles:

 The methodology should identify how non-valuation measures will be considered; 

non-valuation criteria used in selecting Offers should be transparent to Participants.

 The logic of how non-valuation criteria or preferences are used to reject higher-value 

Offers and select lower-value Offers should be applied consistently and without bias.

 The valuation methodology should be reasonably consistent with industry practices.

B. PG&E’S LEAST-COST BEST-FIT METHOD OLOGY

The California legislation that mandated the RPS program required that the procurement 

process use criteria for selection of least-cost and best-fit renewable resources; in Decisions 

D.03-06-071 and D.04-07-029 the CPUC issued detailed guidelines for the IOUs to select 

LCBF renewable resources. PG&E adopted Offer selection and evaluation processes and 

criteria for its 2011 RPS RFO. These are summarized in Section XI of PG&E’s 2011

Solicitation Protocol for its renewable solicitation, and detailed in its Attachment K.

Additionally, PG&E developed non-public documents for internal use that detail the 

protocols for each individual criterion used in the evaluation process. These include:

 Market valuation

 Portfolio fit

 Project viability

 RPS goals

 Adjustment for transmission cost adders

 Ownership eligibility

 Sites for development

The first five of these are listed as evaluation criteria in the 2011 RPS RFO solicitation 

protocol (in contrast to prior years, PG&E did not score Offers on Credit). Additionally, 

the protocol states two other criteria: the materiality and cost impact of Participants’ 

proposed modifications to the RFO’s requirements and to the PPA, and the total volume of 

offers submitted by a single counterparty (considering the volume of energy already under 

contract as well). In other words, PG&E stated that it will take into account the degree to 

which Participants have proposed changes to its 2011 RPS Form Agreement for contracting, 

and the degree of supplier concentration in contracts with individual counterparties.

This section summarizes PG&E’s methodology briefly and at a high level; readers are 

referred to PG&E’s 2011 RPS Solicitation Protocol and its Attachment K for a fuller

treatment of the detailed methodology.
17

MARKET VALUATION

PG&E measures market value as benefits minus costs. Benefits include energy value 

and capacity value (Resource Adequacy); ancillary services value is assumed zero. Costs are 

PG&E’s payments to the Participant, adjusted by Time-of-Delivery (TOD) factors as

specified in the solicitation protocol. TOD factors serve as multipliers to the contract price 

per megawatt-hours (MWh) based on the time of day and season of the delivery, and are 

intended to reflect the relative value of the energy and capacity delivered in those time 

periods. Also, costs are adjusted to reflect transmission adders. The costs of integrating an 

intermittent resource into the electric system, such as load-following, providing imbalance 

services, operational reserves, and regulation, are assumed zero. Both benefits and costs are 

discounted from the entire contract period to 2011 dollars per MWh in the methodology.

PG&E measures energy value by projecting a forward energy curve (in hourly 

granularity) out to the time horizon of the contract period, and multiplying projected hourly 

energy price by the projected hourly generation specified by the Offer’s generation profile. 

For dispatchable Offers, the protocol uses a real-option pricing model to measure energy 

benefit. 

PG&E develops an outlook for the value of Resource Adequacy capacity as a time series 

of nominal dollar per kilowatt-year estimates. The CPUC established specific guidelines for 

estimating RA capacity.

6

 Also, the CPUC decided to base Net Qualifying Capacity on a 70% 

exceedance level for solar and wind resources whose output is stochastic in nature, in a 

calculation that takes into account diversity benefits of multiple individual generators with 

different profiles. In 2011, the PG&E team has adapted its methodology for estimating the 

RA capacity of as-yet-unbuilt projects to match the CPUC guidance more closely. Capacity 

benefit is calculated as the product of capacity value and quantity, and discounted to 2011

nominal dollars.

PORTFOLIO FIT

For the 2011 renewable solicitation, PG&E employed a quantitative scoring system to 

assess the portfolio fit of an Offer into its overall set of energy resources and obligations. 

The team calculated one score for the firmness of delivery of the offered resource and 

another score for the time of delivery of the resource (relative to PG&E’s portfolio needs). 

The overall score for portfolio fit is the numerical average of the two.

PROJECT VIABILITY

PG&E employed the Energy Division’s final 2011 version of the Project Viability 

Calculator to assess the likelihood that a proposed generation facility will be completed and 

enter full commercial operation by the proposed on-line date. The CPUC suggested that the 

Calculator is intended for use as a screening tool rather than a dispositive means of making 

 

6 California Public Utilities Commission, Decision 09-06-028, “Decision Adopting Local 

Procurement Obligations for 2010 and Further Refining the Resource Adequacy Program”, June 18, 

2009.
18

selection decisions.7 PG&E was also willing to use its business judgment in assessing the 

relative viability of projects rather than relying solely on Calculator scores to make selections.

The viability score is developed through an assessment of several attributes of the 

project provided in the detailed Offer, including

 Project development experience,

 Ownership and operating and maintenance experience,

 Technical feasibility,

 Resource quality,

 Manufacturing supply chain (e.g. constraints upon availability of key components),

 Site control,

 Permitting status,

 Project financing status,

 Interconnection progress,

 Transmission requirements, and

 Reasonableness of Commercial Operation Date (COD).

The Energy Division provided a set of scoring guidelines for each of these criteria, in a 

helpful effort to standardize how a project would be assigned a score between zero and ten 

for each. The guidelines support the pursuit of consistency and fairness in rating the 

viability of proposed projects room for judgment; the combination of the Calculator and its 

guidelines should serve as a guide to developers on how projects will be assessed by IOUs. 

More discussion about the utility of the Calculator as a standardized tool as it was 

applied in PG&E’s 2011 RPS RFO is provided below in the section about the administration 

of the methodology.

RPS GOALS

PG&E assesses the degree to which the Offer is consistent with and will contribute to 

the state of California’s goals for the RPS Program, and the degree to which the Offer will 

 

7 California Public Utilities Commission, Decision 09-06-018, “Decision Conditionally Accepting 

2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan 

Supplements”, June 8, 2009, page 20. Arroyo agrees that it is imprudent to rely excessively on the 

numerical score to make a judgment about the likelihood a project will come on-line on schedule.
19

contribute to PG&E’s goals for supplier diversity. The CPUC has articulated specific 

attributes of renewable generation projects which can be considered in utility procurement 

evaluations, such as benefits to low-income or minority communities, environmental 

stewardship, and resource diversity, that do not clearly fall within the other evaluation 

criteria. Similarly, the CPUC has issued a Water Action Plan, and to the extent a renewable 

energy project makes use of water on site, its proposed use of water is evaluated for 

consistency or inconsistency with the CPUC’s recommended water conservation practices. 

Additionally, the state Legislature articulated benefits anticipated for the RPS program in 

the Legislative Findings and Declarations associated with the laws passed to create the 

program, and PG&E assesses the degree to which Offers would promote these benefits. 

The Governor of California issued Executive Order S-06-06 that, among other things, 

established a goal that the state will meet 20% of its renewable energy needs with electricity 

generated from biomass. PG&E assesses the extent to which an Offer supports that goal.

PG&E has well-defined corporate objectives for supplier diversity, and evaluates 

whether the Participant is, or will make a good faith effort to subcontract with, Women-, 

Minority-, and Disabled Veteran-owned Business Enterprises (WMDVBEs). In the 2011 

RPS RFO PG&E asked Participants to submit a completed Supplier Diversity Questionnaire

with information on the Participant’s WMDVBE status, its intent to subcontract with 

diverse entities, and its own supplier diversity program. The PG&E team scored these 

questionnaires as part of evaluating Offers against the overall RPS Goals criterion. A change 

in the 2011 RFO is that PG&E stated that it will include in resulting PPAs a contractual 

requirement to make good-faith efforts towards a contracted supplier diversity target, and to 

report annual payments to diverse subcontractors. In Attachment L it requested Participants 

to specify the percentage of subcontracting spending would be to WMDVBEs.

TRANSMISSION COST ADDERS

The cost of transmission to move power from a project offered in the solicitation to 

PG&E retail customers is considered in valuation. The methodology takes into account the 

need to upgrade the transmission network in order to accommodate the increment of new 

renewable generation in locations (clusters) that may require significant capital outlay, either 

by PG&E or by other IOUs. Each California IOU publishes a Transmission Ranking Cost 

Report (TRCR) which identifies clusters that require network upgrades to accommodate new 

generation, and estimates a proxy for the cost of upgrades and the amount of new 

generation that would trigger the need for upgrades. If a CAISO interconnection study has 

been completed, the team generally uses the more project-specific estimate of transmission 

network upgrade costs identified in the study rather than the TRCR-based proxy (assuming 

that the Participant has included the study as part of its Offer package, as was required). 

PG&E takes into account both the cost of upgrades required to achieve a reliable 

interconnection as well as the cost required to achieve a fully deliverable interconnection, for 

Offers that propose to obtain a full capacity interconnection. While PG&E did not require 

Participants to achieve full capacity interconnections in the RFO, Offers that proposed 

energy-only interconnections were not credited with any Resource Adequacy value.
20

The Solicitation Protocol and its Attachment K lay out the analysis required to allocate 

network upgrade costs to individual Offers. This includes the use of a model to calculate the 

present value of the impact of the network upgrade capital cost on revenue requirement, 

estimating in 2011 dollars per MWh the impact on customers of the upgrade. 

This year, PG&E required Offers to specify a CAISO delivery point and a price at that 

point, rather than allowing them to propose delivery outside the CAISO. Alternatively, 

these Participants could propose to use a pseudo-tie arrangement or dynamic scheduling 

arrangement for the CAISO to manage delivery, despite a project’s interconnection in a nonCAISO balancing authority area.

UTILITY OWNERSHIP ALTERNATIVES AND SITES FOR DEVELOPMENT

PG&E developed protocols for evaluating Offers proposing to sell the utility a site for 

development of renewable generation or to build a facility and transfer it to PG&E 

ownership. The evaluation of turnkey Offers includes an analysis of the project’s value 

under PG&E ownership and a consideration of the extent to which ownership of such a 

project is compatible with the utility’s core competencies.

There is little specific guidance about how PG&E evaluates the tradeoff between a PPA 

Offer variant and a Purchase and Sale Agreement (PSA) Offer variant (e.g. build and transfer

to utility ownership) for the same project. Nor is there much guidance regarding how the 

utility evaluates compatibility of owning a project with PG&E’s core competencies. 

Similarly, both the public solicitation protocol and the non-public protocol give very 

little specific guidance about how PG&E evaluates Offers for sites for development, and 

Attachment K is silent on the subject. The protocol does not reveal what technologies 

PG&E would consider for such an Offer, what term is required, whether site sale or site 

lease is preferred, or any other requirements or preferences the utility applies when it 

evaluates proposed sites for development. In the actual event these Offers were evaluated 

based on criteria that were absent from both the public and non-public protocols, which 

Arroyo regards as less than fair to Participants. This lack of transparency detracts from the 

clarity of the RFO materials and contributed to wasted effort on the part of Participants. 

COUNTERPARTY CONCENTRATION

In the 2011 RPS solicitation protocol, PG&E stated explicitly that it will consider its 

total exposure to volume of contracted deliveries from any individual counterparty and the 

volume already contracted with that party in making selection decisions. Arroyo regards 

supplier concentration as a legitimate business concern for the utility and its customers, both 

for credit risk for the utility’s supply portfolio as well as risk of development failure. 

This year, PG&E made an effort to avoid the prior practices of one or two individual 

developers that submitted excessively large numbers of Offers, by limiting the total number 

of Offers per Participant to five, with an exception for small Offers (up to ten Offers per 

Participant if the total capacity of Offers does not exceed 200 MW). Some developers still 

submitted more than five large Offers, and others circumvented the restriction by bringing 

in different part-owners for different groups of projects. Other developers submitted 

multiple Offers for projects owned by different subsidiaries or initially owned by other 
21

developers while retaining an option to purchase the project if successful. Overall, these

tactics used to avoid PG&E’s stated limitation do not appear to have benefited those 

developers at all, but it created excess effort for the utility team; PG&E chose to evaluate all 

Offers (absent a screening evaluation it would impossible to know which projects to reject).

8

 

PG&E’S PREFERENCES REGARDING OFFERS

 In addition to the various evaluation criteria, PG&E’s solicitation protocol states two 

preferences regarding selection of Offers. In section III regarding Solicitation Goals, the 

section on contract term refers to regulatory uncertainty regarding implementation rules on 

annual compliance goals and states that “PG&E will encourage bids that recognize that 

uncertainty and offer flexibility toward meeting a range of possible targets (e.g., varied online 

dates)”. Arroyo views this as a reasonable preference to take into account when making a 

short list given the status of PG&E’s RPS compliance position for the next several years.

PG&E also states in its solicitation protocol a preference for projects that deliver power 

to “a nodal delivery point...within PG&E’s service territory” over projects that deliver to 

CAISO interface points (e.g. the California-Oregon Border, Mead, Palo Verde, or Four 

Corners substations) or to “California locations outside of the CAISO’s control area” (e.g. 

points within the grids of the Western Area Power Administration, or WAPA, Imperial 

Irrigation District, or IID, non-CAISO municipal utilities such as the Los Angeles 

Department of Water and Power, or LADWP, or non-CAISO rural electric cooperatives 

such as the Plumas-Sierra Rural Electric Cooperative), or to out-of-state locations. 

Arroyo regards this as a reasonable preference, and appropriate to state in the protocol. 

Most of the operators of control areas external to the CAISO have in the past chosen not to 

provide imbalance service or operating reserves that would be required to enable an

intermittent generator in their territory to schedule firm deliveries to a CAISO intertie. Also, 

contracting with projects that interconnect into PG&E’s grid can have other benefits to the 

utility and its ratepayers, such as enhancing local voltage support. In situations where 

PG&E is cut off from other service territories (as for example the catastrophic collapse of 

SDG&E’s and IID’s systems in September 2011) the robustness of PG&E’s system is 

enhanced by having renewable generation on line in its own territory rather than in other 

utilities’ grids. Consequently Arroyo views PG&E’s lower preference for out-of-state power 

or power delivered into non-CAISO control areas as based on legitimate business concerns.

A third area where PG&E’s solicitation protocol does not quite express a preference or 

an evaluation criterion is in contract language modifications. The protocol states that the 

utility will assess the materiality and cost impact of the Participant’s proposed modifications 

to PG&E’s Form Agreement or standard term sheet. The inference is that the utility will 

generally prefer Offers where the Participant submits revisions and comments to the Form 

Agreement with modest or nil proposed changes to PG&E’s standard terms and conditions

 

8 Some developers believed that the five-Offer limitation was too constraining in the situation where 

the company has a large “pipeline” of potential projects of multiple technologies. Other developers 

praised the five-Offer limitation, observing that “it was very intelligent to limit the size to five 

projects” because it avoided an even larger proposal response without affecting the short list, under 

the belief that the limit focuses developers’ attention on their lowest-priced and most viable projects.
22

over Offers whose mark-ups demand unfair concessions, such as projects that propose to 

post Delivery Term Security that is far less than PG&E’s standard requirement.

While Arroyo views these preferences as legitimate business concerns and as factors that 

are reasonable for PG&E to consider in deciding which Offers to select or reject for its 

short list, Arroyo is concerned that the transparency of how such preferences affect Offer 

selection could be improved. In the debriefing sessions for non-shortlisted Participants it

seemed that some were unaware of the expressed preference for projects interconnecting 

within PG&E’s grid, or for projects interconnecting within the CAISO, vs. projects 

delivering at a CAISO intertie point. Arroyo recommends that in future solicitations PG&E 

edit the solicitation protocol to help clarify that preference. 

Also, it would have improved the clarity of the solicitation protocol if it had explicitly 

stated that PG&E’s preference would “focus on the latter part of the 2014-2016 compliance 

period” as stated in the bidders’ conference presentation. It appears, based on debriefings 

after the RFO’s close, that several Participants missed that point and assumed that Offers 

with earlier on-line dates were preferred, as had previously been the case in PG&E’s 2009 

RPS RFO. Arroyo speculates that some Participants could have improved the attractiveness 

of their Offers had they been aware of this subtly stated preference and acted upon it.

SELECTION OF A SHORT LIST

Having ranked Offers by market valuation, including the impact of transmission adders, 

and having scored the Offers against the non-valuation criteria, the PG&E team decides 

which Offers to include on the short list. As stated in the solicitation protocol, the team 

ranks all conforming offers based on net value, then uses scores and information from the 

non-valuation criteria to decide which Offers to include on the list, and which to exclude.

In conditionally accepting the 3 California IOUs’ procurement plans for 2011 RPS 

solicitations, the CPUC noted that “each utility may apply its own reasonable business 

judgment in running its solicitation, within the parameters” and guidance provided by the 

CPUC. This affords PG&E a certain degree of latitude in making decisions about how to 

use information about criteria such as Project Viability and RPS Goals and preferences such 

as service territory and on-line date in selecting Offers. Unlike other utilities that employ a 

weighted average of scores for all criteria as a determinative measure to make selection and 

rejection decisions, PG&E can, up to a point, use its judgment to select lower-valued Offers 

or less-viable Offers that have special attributes in meeting RPS Goals, for example. 

C. STRENGTHS AND WEAKNESSES OF PG&E’S METHOD OLOGY

PG&E’s evaluation methodology for renewable energy solicitations has been revised

over the course of several years, and its evolution has benefitted from input from IEs, the 

utility’s PRG, and internal review. It has thus achieved a certain degree of refinement that 

has strengthened the process from the perspective of fairness and reasonableness.

1. MARKET VALUATION
23

General strengths and weaknesses. PG&E’s valuation methodology has several 

advantages over methods used by other utilities:

 It is rooted in a comparison to market price forwards rather than to model outputs 

for hypothetical future market price based on inputs such as forecast demand, 

modeled supply increases, and fuel price scenarios.

 It is relatively rapid to turn around several valuations at once, in contrast to the 

burdensome nature of running multiple cases of traditional utility production cost 

models with dozens of cases for each generating unit assumed built vs. assumed not 

built to calculate system cost differences between scenarios with each unit in vs. out.

 It uses a valuation concept that is generally accepted in the electric power industry.

 It provides an intuitive valuation based on the degree to which a generating unit is 

“in the money” with respect to market price

There are some drawbacks with this approach, some of which are common to any 

valuation methodology for long-term PPAs:

 Because western power forward markets are not liquid and transparent beyond a 

limited time horizon, PPAs that last for up to 25 years must rely on extrapolation of 

market forward curves for valuation rather than on direct observation of traded 

prices for power two decades hence.

 A certain degree of interpolation or projection is required to achieve hourly 

granularity in price assumptions.

 In the absence of functioning, liquid, transparent markets in California for Resource 

Adequacy, the valuation must rely on fundamental forecasts for the value of capacity 

rather than on traded forward curves.

 There are challenges in estimating what Net Qualifying Capacity will be assigned by 

the CAISO to a project that does not yet exist. To a large extent PG&E must rely 

on the generation profiles provided by Participants, some of which appear to be of 

dubious quality.

 The methodology, given its inputs from forward curves, RA value assumptions, and 

discount rate, sometimes gives results that might appear counterintuitive, such as 

preferring higher-priced but longer-term contracts to lower-priced but shorter-term 

contracts, or preferring PPAs with later on-line dates to earlier on-line dates, all else 

being equal. Such outcomes can be explained by inspection of the data and input 

parameters and are consistent with the methodology. If the results run counter to 

the utility’s or ratepayer’s preferences, issues can be addressed through PG&E’s 

flexibility to apply business judgment to its decisions.

 In the 2011 RPS solicitation, PG&E has used historical information about locational 

marginal price (LMP) to adjust the valuation of Offers based on the historical record. 
24

Attachment K to the solicitation protocol displayed the aggregation multipliers used 

to adjust for LMPs in various zones within the CAISO. Unfortunately, analogous 

multipliers had not been prepared for delivery points at intertie points of the CAISO; 

Arroyo recommends that prior to the next RFO the PG&E team investigate how 

best to make LMP adjustments for Offers that propose to deliver at such points.

Price vs. Value. PG&E’s LCBF methodology takes into account both proposed price 

and estimated net value of each Offer, in the sense that price is a key input to the utility’s 

valuation model. However, PG&E ranks Offers and Offer variants by calculated net value 

to make a primary screening for selection purposes, and does not construct or review a 

separate ranking by contract price. The valuation ranking takes into account the total cost to 

ratepayers of a PPA by including the contract payments (or purchase price) for a project and 

the transmission rate impact of required network upgrades and the effect of differing market 

prices across zones on the attractiveness of a project’s output. When reviewing Offers to 

make a short list, PG&E does include information on LCBF-based net value and pricing, but 

the focus is on net value including transmission cost impacts rather than on contract price. 

Financial Benefits and Costs. Overall, PG&E’s LCBF methodology adequately takes 

into account nearly all financial benefits and costs of proposed Offers (see below for one 

exception). There are some areas that would be challenging for the evaluation team to 

quantify in financial terms. For example:

 Environmental externalities relating to the impact of new projects on wildlife or 

scarce water supplies are difficult to quantify as financial costs. A sub-team of 

PG&E’s evaluation team reviews such aspects of proposed projects as their 

potential impact on threatened and endangered species. While these concerns 

are not translated into estimates of financial costs, PG&E’s selection of a short 

list is informed by these data.

 Some local areas of PG&E’s grid could suffer from deficiencies in local capacity 

resources compared to requirements identified to maintain local reliability. For 

example, the CAISO has identified a deficiency of 36 MW of resources in the 

Sierra local area within PG&E’s territory.

9

 It is difficult to quantify as financial 

benefits the extra benefit to grid reliability that would be provided by contracting 

with new resources in local areas with deficiencies.

 The California IOUs assume that the cost of integrating new resources into the 

electric system is zero, consistent with current CPUC policy. Utilities in other 

jurisdictions apply estimated costs of integration for intermittent resources when 

ranking the value of potential new projects, based on estimates of such 

components as obtaining sufficient load-following resources and 

voltage/frequency regulation. One might anticipate that at some point as load 

grows and as intermittent resources make up a greater proportion of the resource 

mix within the CAISO the price of increasingly scarce but required load-

 

9 California Independent System Operator, “2012 Local Capacity Technical Analysis: Final Report 

and Study Results”, April 29, 2011, page 2. 
25

following and regulation may increase. This potential effect is not included in 

PG&E’s valuation; there is no CEC-approved methodology for such an estimate.

Arroyo acknowledges the challenges of quantifying benefits and costs such as these in 

monetary terms, and opines that the PG&E LCBF methodology incorporates most financial 

benefits and costs that reasonably can be estimated at this point in time, with the following 

two exceptions.

Transmission upgrade costs. As described above, PG&E’s LCBF methodology includes 

the costs of transmission upgrades in its value calculations of all Offers involving projects 

that propose to interconnect directly to the CAISO, using proxy costs from TRCRs or 

estimates of network upgrade costs from interconnection studies or executed 

interconnection agreements. However, the methodology does not take into account these 

costs in situations where the project proposes to interconnect outside the CAISO balancing 

authority area and the network costs are ultimately borne by transmission customers of that 

other balancing authority area. Arroyo believes that valuing projects in these areas without 

applying transmission adders while valuing projects within the CAISO with adders is less 

than fully fair to developers of projects within the territories of the three IOUs. 

Arroyo recommends that PG&E incorporate estimates of transmission upgrade costs for 

Offers where projects propose to interconnect within California to non-CAISO balancing 

authority areas that are entirely or partially located within California. While Arroyo 

acknowledges that PG&E’s ratepayers will not directly bear the costs of network upgrades in 

these other BAAs, the California ratepayers served directly by these balancing authorities 

will. Additionally, to the extent that PG&E procures energy from projects within such 

BAAs, taking delivery at a CAISO intertie point, PG&E’s customers will pay a contract price 

for that power which recovers the cost of transmitting the project’s output to the intertie, 

and those transmission tariffs will eventually reflect the cost of required network upgrades. 

However, in the 2011 RFO, Arroyo can identify at most one proposal whose selection or 

rejection might have differed if non-CAISO network upgrade costs had been counted.

Congestion charges. As described previously, the current implementation of the LCBF 

methodology does not count the congestion charges between certain distant CAISO delivery 

points and the EZ hubs internal to CAISO service territories. Arroyo recommends that the 

PG&E team develop estimates of LMP multipliers appropriate for these delivery points as it 

has done for zones within the main body of the CAISO grid.

2. EVALUATION OF PORTFOLIO FIT

The approach PG&E employed in the 2011 RPS RFO to score Offers on portfolio fit 

differed from that used in prior years. The current approach has specific advantages:

 The numerical score is based on quantitative calculations or on technology-specific 

attributes, and is objective in its development with little discretion or judgment 

involved in applying scoring guidelines.
26

 The scoring for time of delivery is closely related to how PG&E currently perceives 

its greatest needs for new RPS procurement, an important consideration for 

compliance strategy.

There are a few drawbacks to this approach:

 The current scoring approach is somewhat black and white; it tends to provide either 

a high score or a low score with few steps in between.

 In the greater scheme of things, the portfolio fit criterion does not appear to have as 

much impact as others such as market valuation, project viability, and RPS goals. To 

Arroyo’s awareness there has not yet been a situation where a renewable Offer’s 

superior portfolio fit score has enabled it to be shortlisted by PG&E despite inferior 

value or viability; nor has there been a situation where an inferior portfolio fit score 

has led an Offer to be rejected from a short list. 

PG&E’s revised portfolio fit criterion for the 2011 RPS solicitation is consistent with the 

utility’s current understanding of its generation need for each compliance period under SBX

2. Arroyo has almost no visibility into how PG&E calculates its net short position of RPSeligible energy procurement vs. RPS goals in the three compliance periods and can therefore 

have no opinion about whether that calculation was reasonable. To the extent information 

was made available to the utility’s Procurement Review Group, it appears that the portfolio 

fit methodology aligns well with times when PG&E expects more procurement is needed. 

The utility’s estimates have considerable potential for error, both because of uncertainty 

about how the CPUC’s implementation rules will set targets for intermediate years like 2014 

and 2015, and because of uncertainty about the likelihood that contracted projects will come 

on-line and the extent to which projects whose PPAs are expiring will be recontracted.

3. EVALUATION OF BIDS WITH VARYING SIZES, IN-SERVICE DATES, AND 

CONTRACT LENGTH

Offer Size. PG&E’s LCBF valuation methodology is essentially neutral to project size; it 

does not consider extrinsic variables such as MW capacity or GWh volume as positive or 

negative factors but rather reduces the value of the Offer to a normalized $/MWh metric. 

To the extent project size has an impact on valuation, it reveals itself in the proposed 

contract price if the technology is one that provides economies of scale and enables 

developers to propose lower prices for larger projects. 

The viability scoring system, however, is not neutral to project size. The larger the 

proposed project, the less likely it is that the developer has succeeded in the past in 

developing similar or larger sized projects, owned and operated similar or larger sized 

projects, or financed similar or larger sized projects. So the Offer is likelier to score lower 

on Project Development Experience, Ownership/O&M Experience, and Project Financing 

Status if the project is larger. 

From the debriefings after the conclusion of the RFO, it became evident that many 

developers failed to appreciate that proposing new projects much larger than any they had 
27

previously brought into operation will lower their viability score using the Energy Division’s 

Project Viability Calculator. Other developers with deep experience in developing large 

projects in conventional technologies were unaware that the design of the Calculator did not 

fully take that experience into account in scoring when they proposed to construct large 

projects using a renewable technology with which they had no prior experience.

This left some non-selected Participants with a sense that the design of the Project 

Viability Calculator was unfair to them, arguing that it has a “rich get richer” aspect in which 

only those developers who have previously brought into operation large renewable energy 

projects can achieve the highest scores for developer and ownership experience for 

proposed new large renewable energy projects. 

The fact that PG&E’s objective for the 2011 solicitation is to procure 1 to 2% of retail 

load, combined with the RFO Goals non-quantitative factor of resource diversity, makes it 

difficult for the utility to select the very largest-volume proposals offered. An extreme 

hypothetical scenario in which the utility selects one Offer only of several TWh/year would 

be the opposite of pursuing resource diversity. The RFO Goals criterion gives PG&E the 

basis for preferring to select multiple smaller Offers rather than a very few large projects, in 

pursuit of greater resource diversity. This tradeoff between the criteria of highest valuation 

vs. resource diversity requires the utility to exercise business judgment about its priorities.

On-Line Date. PG&E’s LCBF valuation methodology, using current inputs, exhibits a 

propensity to favor projects that start later rather than earlier, all else being equal (this is 

related to inputs about forward prices, capacity value, and discount rate). It is a modest 

effect, and is roughly consistent with the stated preference of the utility to focus on the latter 

part of the 2014-2016 compliance period rather than on the first compliance period.

Because of the focus of PG&E’s methodology on selecting projects ranked high for net 

value and project viability, the process is not designed to provide a short list that fits best 

with PG&E’s net short position for RPS compliance. That would require the most valued 

and most viable proposals to have offered in-service dates that closely match the compliance 

periods when the utility has the largest net short position, which would be coincidental if it 

occurred. Instead, because there are more than three evaluation criteria to pursue, the 

methodology is designed to construct a short list composed primarily of high-valued and 

highly viable proposals of which some have on-line dates that fall close to compliance 

periods with short positions, but of which others have substantially earlier or far later inservice dates and don’t necessarily fit well with compliance periods of the greatest need.

Similarly, PG&E’s methodology is not designed to construct a short list with the highest 

value to ratepayers while meeting the utility’s RPS compliance needs. Such an alternative 

approach would necessarily disregard the project viability criterion by selecting the highest 

valued Offers with in-service dates matching RPS compliance periods of greatest need, 

regardless of whether those low-priced and well-timed projects have progressed at all in 

permitting, interconnection, and site control processes, and whether or not their technology 

is well-commercialized or never before demonstrated at utility scale. The IOUs have had 

bitter experience with low-priced projects that proposed attractive on-line dates but failed to 

achieve timely commercial operation because of viability issues. PG&E’s methodology is 

designed to screen out high-valued projects that fit well with compliance period needs if they 
28

rank low on project viability. If the PG&E had an alternative approach that disregards 

viability in pursuit of highest value and fit with compliance needs, then one would expect a 

short list with a significantly higher likelihood of contract failure than the current approach.

Contract Duration. The valuation methodology similarly tends to favor contracts with 

longer duration to those with shorter terms, all else being equal. Since few Participants ever 

seem to propose both a longer and shorter duration contract at the same contract price, this 

is a very minor effect, typically swamped by price differences between Offer variants. 

4. EVALUATION OF BIDS’ TRANSMISSION COSTS

The valuation methodology assigns estimated transmission costs to the contract price of 

generation in order to compare Offers fairly, taking into account the full cost of generating 

power including upgrades required to achieve reliable deliverability for new generation.

Many features of the transmission cost methodology are specified by regulatory decisions.

The methodology has a few strengths:

 It provides a means to level the playing field between Offers that deliver directly into 

PG&E’s service territory at uncongested locations and those whose proposed 

facilities will require expensive new transmission upgrades and new substation 

facilities to maintain grid reliability. 

 It provides a view of full costs of the project rather than only the energy 

procurement cost.

The transmission cost methodology also has some drawbacks:

 The process of estimating transmission adders is analytically burdensome. It requires 

checking of Participant’s information by transmission experts and consumes a 

considerable portion of the total time for valuation analysis.

 TRCR adders are a generalized, regional proxy for the actual cost of a particularsized project at a particular interconnection point. There can be rather large 

deviations between the final cost of network upgrades written into an 

interconnection agreement and an early TRCR estimate. 

 In those cases where the TRCR adder turns out to be an underestimate of actual 

network upgrade cost, PG&E’s prior practice of only performing the full LCBF 

valuation including transmission adders during solicitations impedes the transparency 

of decision-making. 

 TRCR adders are available only for California IOUs, and only for specific 

transmission clusters that the IOUs have analyzed. They are not available for other 

balancing authorities in California or outside the state. It would be challenging for 

the PG&E team to estimate a proxy for network upgrade cost for projects 

interconnecting, for example, in the Sacramento Municipal Utility District’s or IID’s 

grid unless the project had obtained a system impact study or facilities study or 
29

interconnection agreement from that balancing area authority. Given the focus on 

new renewables in Imperial Valley, this shortage of information is inconvenient.

 CAISO Phase I studies have been known to provide gross early overestimates of the 

actual network upgrade costs. In some transmission clusters, excessive numbers of 

new projects have applied for interconnections; their aggregate new capacity is so 

large that Phase I estimates of work required to accommodate such a large new build 

are massive. When posed with the obligation to finance hundreds of millions of 

dollars of network upgrades for their projects, many developers choose to drop out 

of the CAISO queue, leaving sufficiently fewer new projects moving through the 

Phase II study to result in much smaller estimates of network upgrade costs. In 

these situations, the methodology disadvantages projects that have received a Phase I 

study but not yet a Phase II study, even though the analysis in hand is the best 

currently available estimate of project-specific upgrade requirements. This seems less 

than fully fair to some projects caught in that early stage of analysis.

Whether the transmission adder methodology relies more on TRCR proxy adders or on 

interconnection studies or interconnection agreement data depends entirely on what projects 

Participants submit. In the case of PG&E’s 2011 RPS solicitation, roughly half the Offers 

had not applied for an interconnection or had not yet completed a Phase I study or system 

impact study. This illustrates how reliant the methodology is on the accuracy of the IOUs’ 

Transmission Ranking Cost Reports.

Most Phase I and Phase II interconnection studies provide estimates of both reliability 

network upgrades and deliverability network upgrades. In situations in which the project has 

not yet been studied as a full capacity resource, the studies lack an analysis of required 

deliverability upgrades. In many cases projects apply for an energy-only resource and later 

request a deliverability assessment (such as for projects that initiated their application under 

the Small Generator Interconnection Process). PG&E’s methodology is designed to be 

internally consistent; either it treats a project as energy-only and takes into account the 

estimated reliability network upgrades only and doesn’t attribute Resource Adequacy value to 

the facility, or it treats it as full-capacity, takes into account costs of both reliability and 

deliverability network upgrades, and attributes RA value. In some cases projects were 

analyzed both ways and the approach that provided the higher valuation was selected, giving 

the project the benefit of the doubt that of the two the higher-valued approach would be 

chosen. This would be consistent with the logic of PG&E choosing to contract with a new 

project as an energy-only resource if the deliverability network upgrade costs would exceed 

the value of Resource Adequacy the project can provide.

Conformance checks of transmission study results were performed. Arroyo notes that 

some Offers misstated the estimated network upgrade costs provided by CAISO or PTO 

studies. Arroyo believes that PG&E did a thorough job of checking the original source 

materials when conducting its analysis of transmission adders. Part of the challenge was that 

many Participants omitted the requested copy of the latest interconnection study, requiring 

the utility team to seek this information for deficient Offer packages.

5. EVALUATION OF BIDS’ PROJECT VIABILITY
30

The implementation of the Project Viability Calculator as a screening tool for use in the 

evaluation of Offers has brought several advantages:

 The Calculator is a step in the direction of more standardized evaluation of viability 

across all three IOUs.

 The Calculator provides a broader set of criteria by which projects are assessed than 

was the case with PG&E’s prior approach to scoring viability.

 The range of scores from zero to 100 gives more visibility to differences between 

projects than methods that use single-digit scores.

 The methodology allows PG&E to use both the more standardized tool as well as 

business judgment in taking project characteristics into account when making short 

list decisions.

There are still opportunities to improve the use of the Calculator.

 Some of the scoring guidelines for the Calculator are sufficiently ambiguous that 

reasonable individuals scoring the same project can arrive at different results. When 

the scores rated by Arroyo and the PG&E team were compared, the variance 

between scores had a standard deviation of 12 points. Even among individual 

members of the PG&E team there was a need to review and standardize scoring to 

reduce discrepancies between individuals’ practices. This suggests that the Calculator 

is still a crude screening tool with a lot of noise in the scoring process, and that 

differences of only two or three points between projects should not be regarded as 

determinative in selecting one and rejecting the other, because the difference falls 

within the error of the analysis.

 As evidenced by feedback from Participants, developers in general have a poor 

understanding of how the utility interprets the scoring guidelines. Many developers, 

for example, claimed not understand that their project cannot obtain a score of 10 

out of 10 for project development experience if their team has never brought at least 

two projects of equal or larger size with similar technology into operation...even 

though that is explicitly what the scoring guidelines in the Calculator state.

 Some scoring criteria would be difficult for a layperson to interpret, such as the 

Transmission System Upgrade Requirements criterion that requires some basic 

knowledge of what components of an upgrade require or don’t require a CPUC 

Permit to Construct of Notice of Construction. Many or most developers lack onstaff experts in the regulatory landscape for new transmission build in California.

 Some of the Offers were scored low simply because the Participants omitted basic 

information about their projects, even though upon debriefing it became clear that 

full disclosure would have resulted in a higher viability score. It is unclear to Arroyo 

how this could be improved in the future, since the solicitation materials clearly 

stated what information was required.
31

In Arroyo’s opinion, PG&E reasonably measured the viability of every project that 

submitted a conforming proposal for bundled energy, out-of-state power attached to 

renewable energy credits, or biogas. The evaluation team did not use the Calculator to 

evaluate Offers for RECs only or sites for development; some Participants for the former

did not submit data needed to evaluate their viability, and proposals of land sales or leases 

are not amenable for scoring as power projects with the information requested or supplied.

The Participants’ self-scoring was uneven in quality. While the PG&E team agreed with 

the self-scored Calculator scores for about a quarter of Offers, on average PG&E gave the 

Participant-estimated scores a “haircut” of eleven points. This is somewhat distorted by a 

few developers who scored their own projects by more than 40 points higher than the 

PG&E team; Arroyo agreed with PG&E that these projects had been assigned grossly 

inflated scores by any objective standard.

PG&E conducted conformance checks of viability assessments for Offers, in part to 

ensure quality control and consistency in how multiple scorers applied the scoring guidelines. 

Particular attention was paid to Offers that were considered for short listing in early drafts, 

in order to confirm the quality and consistency of the assessments.

In some cases factors not assessed by the Calculator were taken into consideration when 

the PG&E team made selections; this is consistent with the direction provided by the CPUC 

about the use of the Calculator as a screening tool.

6. OTHER STRENGTHS AND WEAKNESSES

Evaluation of different technologies. PG&E’s protocol tends to avert selecting Offers 

for utility ownership for which the utility lacks particular core competencies, so there is a 

bias against purchasing projects that the company is less well-suited to own and operate. 

This seems reasonable and appropriate, since it is not in ratepayers’ interest for the utility to 

own generating facilities that require specific skills PG&E lacks.

The Project Viability Calculator was designed to be technology-neutral as well. 

However, the Calculator will return a lower score for a project that relies on a technology 

that is not well-commercialized, or that the developer lacks prior experience developing, 

owning, operating, or financing, all else being equal. The methodology will tend to discount 

projects based on emerging technologies or on those that have not been implemented 

broadly at utility scale, and will tend to promote projects that rely on technologies with

widespread market acceptance and many examples of operating 100+ MW installations. It 

became evident from debriefing Participants that some developers were unaware that the 

Calculator’s design tends to disfavor emerging technologies, and that other competitive 

venues than the IOUs’ RPS RFOs that do not require the use of the Calculator might be 

more appropriate for projects that employ poorly-commercialized technologies.

PG&E’s protocol for RFO Goals includes a provision allowing the utility to consider the 

non-quantitative factor of resource diversity benefits in the selection process; this is stated in 

Attachment K and supported by regulatory decisions. This feature allows the utility to 

consider such things as its resource need for baseload vs. peaking or intermittent generation 

in selecting Offers. To the extent some technologies are operated as baseload in the 
32

California market and there is a resource need for baseload resources this may tilt Offer 

selection towards those projects over technologies that provide intermittent or peaking 

generation. Similarly, the RFO Goals criterion accommodates the non-quantitative factor of 

continuing to meet the goal stated by Executive Order S-06-06 for biomass-fueled renewable 

energy, which could tilt Offer selection towards biomass or biogas-fueled generation.

Out-of-state projects. One issue regarding both value and viability concerns Offers for 

out-of-state projects that propose not to actually deliver power to the CAISO but instead 

intend to be managed through a pseudo-tie or dynamic scheduling. There are only a very 

few projects to date where these have been implemented by the CAISO. Because such 

approaches require the assent of both the CAISO and the foreign balancing area authority to 

which the project will interconnect (and PTOs in between), it is difficult for PG&E to judge 

the likelihood of whether such arrangements will actually be achieved. It was evident from 

reviewing out-of-state Offers that several Participants do not comprehend how their projects 

will be treated by the CPUC for RPS compliance purposes, with several assuming that their 

PPAs will be treated as bundled in-state delivery of power, despite failing to specify how 

they will obtain dynamic scheduling by the CAISO. One hopes that more experience with 

dynamic scheduling will make it clearer what can and cannot be achieved with these 

arrangements and that future solicitation protocols can clarify how PG&E will assess them.

Similarly, Arroyo considers it risky for the utility to value out-of-state projects that 

assume that the import of their power at a CAISO intertie will provide full Resource 

Adequacy value to PG&E ratepayers. The process for allocation of RA import capability at 

intertie points does not currently accommodate long-term dedication of that capability to 

IOUs, putting at risk the delivery of RA value. Simply assuming that full RA benefits of the 

capacity of these out-of-state projects will be realized for the entire delivery term of a PPA 

may overstate the value of these projects. However, in the actual selection of projects 

Arroyo can identify at most one Offer whose selection or rejection might have differed if 

PG&E had taken a different approach in evaluating pseudo-ties or RA import capability.

Participants’ viewpoints on strengths and weaknesses. Feedback from Participants 

provided some insight into other strengths of PG&E’s approach compared to other utilities’.

 The bidders’ conference was cited as being “very helpful” by several Participants, in 

clarifying objectives, evaluation process, and requirements. The ability to ask 

questions and to obtain answers quickly and spontaneously was cited as useful.

 The solicitation materials were regarded as clear, straightforward, and “userfriendly”, with the exception of the Attachment D offer form, with which some 

Participants had technical difficulties. (Others found the verification process built 

into this year’s Attachment D to be quite helpful and fully functional.) Participants 

who submitted less commonly pursued approaches (e.g. projects outside the CAISO 

or sites for development) tended to be more frustrated with their perception that the 

solicitation materials lacked clarity about their Offers would be evaluated.

 While some Participants clearly did not understand how the scoring guidelines in the 

Project Viability Calculator were intended to be used and were frustrated that their 
33

early-stage projects were disfavored by the design of the Calculator, others expressed 

opinions that the Calculator was “fair and relevant” and straightforward.

 While frustrated by PG&E’s policy of not disclosing detailed information about the 

nature of the short list, and the utility’s unwillingness to provide second chances to 

improve rejected Offers, Participants appreciated the opportunity to be debriefed 

about the reasons why their Offers were rejected because they could gather useful 

information on how to make their projects more competitive in future solicitations. 

Some Participants particularly appreciated that PG&E provided timely responses 

about whether their Offers were selected or rejected, in contrast to another IOU.

 Some Participants felt disadvantaged compared to rivals who, they feared, could 

propose unreasonably low pricing, obtain a PPA, then sell the project. They 

suggested that PG&E erect higher barriers to participation by “non-serious” parties, 

such as higher offer deposits (as required in other jurisdictions). Arroyo views this 

theme as a form of confirmation that PG&E’s approach to outreach was successful 

in obtaining broad and robust competition from the developer community.

D. FUTURE LCBF METHOD OLOGY IMPROVEMENTS

The methodology employed by PG&E has undergone repeated refinement, motivated 

both by internal choices within the utility and external impetus by the regulator. This 

process has provided incremental improvements to the methodology over time. Arroyo can 

at this point only suggest a few modest changes that may further improve the means by 

which PG&E evaluates Offers or the transparency with which Participants can view the 

evaluation process, some of which were suggested in feedback sessions by Participants.

ENHANCING TRANSPARENCY

One set of suggestions would seek to address the sense that comprehension of how 

PG&E evaluates and selects Offers among the developer community could be improved. 

This could help reduce wasted effort on the part of developers in promoting projects that 

are unlikely to be selected, and reduce the amount of wasted effort within the utility as it 

attempts to analyze Offers with poor viability and low value. Some ideas could include:

 Reviewing the scoring guidelines for the Project Viability Calculator in the bidders’ 

conference, to explain what is required to obtain top scores in each criterion;

 Including scoring guidelines for all 11 criteria used in the Calculator in Attachment

K, with commentary on what it takes to obtain top scores in each category; 

 Editing the solicitation materials to further emphasize the need for out-of-state 

projects to provide a full price at a CAISO delivery point that the developer would 

be willing to write into a PPA, rather than a busbar price outside the CAISO;
34

 Modifying solicitation materials to clarify that the developer must provide a copy of 

the most recent interconnection study or executed interconnection agreement that 

will serve as the basis for estimating a transmission adder for network upgrades;

 Revising the solicitation materials to clarify that, in addition to the various evaluation 

criteria, PG&E will use its preferences regarding delivery point and commercial 

operation date to make selection decisions. In particular, it would be key to make as 

clear as possible within the solicitation protocol itself what PG&E’s preferences for 

on-line date are, seeing that many Participants completely failed to notice this;

 Editing the both the public and non-public solicitation protocols to provide a fuller 

description of how Offers for sites for development will be evaluated, what the basic 

requirements for eligibility are, what specific evaluation criteria will be used, and 

what characteristics of offered sites would render them attractive or unattractive to 

the utility as candidates for ownership. The ownership team should provide clearer 

internal documentation of how it made its selection and rejection decisions.

STREAMLINING THE PROCESS

At least one other IOU has chosen to drop the requirement for hardcopies of the Offer 

package; to Arroyo this now seems an appropriate step for PG&E to take, going forward. 

Arroyo has some lingering concern about the Participants who fail to put all the information 

present in their hardcopy Offers into readable electronic form using the required format, but 

this may be dispelled if Offers are submitted entirely in electronic form. Arroyo agrees that 

it is still best to submit electronic Offer packages by flash drive rather than by e-mail.

Some Participants have objected to the volume of information that PG&E requires for a 

complete Offer. Arroyo agrees that there are some opportunities to delete some required 

information that has little or no impact on a short-listing decision (such as project block 

diagrams and resumes of managers) in favor of seeking such information after short-listing. 

IMPROVING VALUATION INPUTS 

Arroyo has suggestions for improving the methodology for assessing the value of Offers:

 Use a discount rate based on an estimate of the cost of capital for power developers, 

rather than PG&E’s authorized cost of capital. Arroyo believes that given the risks 

that face renewable project development (permitting, site control, interconnection, 

equipment procurement, financing, etc.) it is more appropriate to discount future 

benefits and costs of the projects using a higher discount rate representative of the 

riskier independent power industry, rather than that of a regulated monopoly. 

 Restudy the inputs to the model that set the basis for Resource Adequacy valuation. 

For example, it appears that PG&E’s current assumption for new entrant capital 

costs is materially higher than that embedded in the currently applicable Market Price 

Referent. Arroyo believes that current assumptions (including the use of a regulated 

utility’s cost of capital as discount rate) cause the PG&E team to overstate the value 
35

of RA capacity, and that this tends to create distortions and biases in project 

valuation rankings. 

 Clarify that the most recent CAISO or PTO interconnection study (or 

interconnection agreement if available) is required in the Offer package. Without this 

non-public information it is difficult to assess an appropriate transmission adder 

other than using TRCR information, and data from either a Phase I or Phase II study 

report is more specific to a given resource than TRCR proxy estimates.

 Develop LMP multipliers for CAISO interconnection points at the periphery of the 

balancing authority area, such as Four Corners, Moenkopi, Mead, and the 

Hassayampa-North Gila line, so that energy from projects that propose such nodes

as delivery points can be valued taking congestion into account. These are CAISO 

delivery points that are external to the body of the IOUs’ service territories and tend 

to record higher congestion differentials than points within the territories.

 Discuss with the CAISO its plans and policies for establishing pseudo-ties or 

dynamic scheduling arrangements for new projects outside the balancing authority 

area, in order to establish a view about which projects realistically can expect to 

obtain such treatment and which not. For example, Arroyo perceives it as unlikely

that the CAISO could or would set up dynamic scheduling arrangements with 

projects that interconnect in WECC balancing authority areas that would require 

wheeling through three service territories to get to a CAISO intertie. 

 Offers claiming that a project will be managed as a pseudo-tie should be required to 

state the specific CAISO intertie with which it will be permanently associated as 

required by CAISO rules; this would clarify how best to value the proposal.

 Include in the LCBF valuation the costs of network upgrades for projects that 

interconnect within California but outside the CAISO grid. The practice of 

evaluating full costs for some projects but PPA costs only (omitting the impact on 

transmission rates) for other California projects seems inconsistent and less than 

fully fair to developers who choose to build their generation within the CAISO grid. 

It also seems less than fully fair to California customers in non-CAISO balancing 

authority areas who will bear the primary burden for those upgrades.
36

4 . FA I RN E S S O F H OW P G & E 

A D M I N I S T E R E D T H E O F F E R

E VA L UAT I O N A N D S E L E C T I O N 

P RO C E S S

This section describes the extent to which PG&E’s administration of its protocols for 

Offer evaluation and selection in the 2011 RPS solicitation was conducted fairly. Arroyo’s

overall conclusion is that the process was conducted in a fair and generally consistent 

manner. Arroyo disagreed with PG&E about the length of its short list. This chapter 

discusses how PG&E developed a final short list to submit to the CPUC.

A. PRINCIPLES USED TO DETERMINE FAIRNES S OF PROCESS

The Energy Division has suggested a set of principles proposed to guide IEs in 

determining if an IOU’s administration of its evaluation and selection process was fair:

 Were all bids treated the same regardless of the identity of the bidder?

 Were bidder questions answered fairly and consistently and the answers made 

available to all bidders?

 Did the utility ask for “clarifications” that provided one bidder an advantage over 

others?

 Was the economic evaluation of the bids fair and consistent?

 Was there a reasonable justification for any fixed parameters that were a part of the 

IOU’s LCBF methodology (e.g., RMR values; debt equivalence parameters)? 

 What qualitative and quantitative factors were used to evaluate bids?

Some other considerations appear relevant to reviewing PG&E’s administration of its 

methodology. The use of business judgment in bringing multiple non-valuation criteria to 

bear on decision-making, rather than a mathematical, objective means of doing so, implies 

an opportunity to test the fairness of administration using additional principles:

 Were the decisions to reject higher-valued Offers from the short list because of low 

scores in criteria other than valuation or PG&E’s preferences applied consistently

across all Offers?

 If PG&E did not select the projects for the short list that provide the best overall 

value while meeting the needs of PG&E’s three compliance periods, what factors 

prevented those projects from being selected? Was their rejection based on factors 

that were communicated transparently to Participants in the solicitation protocol?
37

 Does the resulting short list conform to the needs of PG&E’s portfolio?

 Were the judgments used to create the short list based on evaluation criteria and

preferences that were publicly made available in the solicitation protocol to 

Participants prior to Offer submittal?

B. REVIEWING PG&E’S ADMINISTRATION OF ITS EVALUATION AND SELECTION 

PROCESS

PG&E provided Arroyo Seco Consulting with many detailed inputs to its valuation 

model and with results of market valuation at several steps during the evaluation process, 

including detailed information about transmission adders applied to Offers. Arroyo also had 

copies of all Offers and of correspondence between PG&E and Participants during this 

period, and was able to make independent opinions about the strengths and weakness of 

individual Offers against the evaluation criteria laid out in PG&E’s protocols.

Arroyo was present at evaluation team and steering committee meetings in which draft 

proposals for the short list of Offers were developed, reviewed, questioned, modified, 

argued, and finalized. The logic and priorities underlying why specific Offers were rejected 

and accepted to the short list were made evident in these sessions. Arroyo had access to 

members of the evaluation team responsible for scoring the Offers against each of the 

evaluation criteria. Arroyo was able to question decisions that appeared unfair or 

inconsistent from an independent perspective.

Additional elements of Arroyo’s approach for evaluating the fairness of the evaluation 

and selection process include:

 Building an independent valuation model that directly used detailed Offer 

information, to construct an independent ranking of Offers by net market value;

 Independently scoring Offers using the 2011 Project Viability Calculator; 

 Developing a separate and independent point of view about which Offers most 

merited selection for a short list;

 Comparing PG&E’s valuation ranking to the IE model’s ranking, identifying outliers

(e.g. where the utility ranked an Offer much higher than the IE or vice versa), 

identifying the root cause for variances, and determining whether variances were 

justified by different inputs and methodology or stemmed from errors by either 

PG&E or Arroyo;

 Auditing communications between PG&E and Participants to check whether any 

individual Participant was advantaged by requests posed or information provided;

 Reviewing in detail and discussing PG&E’s decisions to reject Offers for 

nonconformance with the requirements of the solicitation protocol;
38

 Reviewing PG&E’s decisions to reject Offers for low scores in non-valuation

criteria, or based on the utility’s stated preferences, and independently reviewing 

whether those rejections were fair and reasonable;

 Testing these rejection and acceptance decisions for consistency; reviewing whether 

the logic for rejection and acceptance was consistently applied to all Offers.

C . FAIRNESS OF REJECTION OF OFFERS FOR NONCONFORMANCE TO 

REQUIREMENTS OF THE SOLICITATION

After Offers were received, PG&E performed a detailed review of the packages in order 

to identify deficiencies that needed to be addressed by requesting additional information 

from Participants and to assess which Offers deviated from the requirements of the 

solicitation protocol. Most Participants whose Offers were identified as deficient were able 

and willing to address the missing information. A few did not. 

Fifteen Offers were rejected by PG&E for nonconformance with the requirements of 

the Solicitation Protocol. Also, a few variants of Offers were rejected though other variants 

of the same Offer were accepted as conforming. PG&E rejected some Offers and variants

because they violated the requirement stated in the solicitation protocol that projects for a 

Purchase and Sale Agreement (e.g. for transfer to utility ownership) must be sited within the 

state of California. PG&E is not at this point in time considering the purchase of out-ofstate power plants through RPS solicitations.

Other offers for PPAs were rejected as nonconforming because they specified a price for 

delivery at a project busbar in a balancing authority area outside California rather than to a 

CAISO delivery point. Or they proposed an out-of-state project as a PPA for bundled 

product delivery, rather than a REC sale or a CAISO-approved pseudo-tie or dynamic 

scheduling arrangement. Some out-of-state Offers failed to provide a detailed or credible

plan about how to deliver power to the CAISO, particularly for intermittent resources, or 

failed to name a specific point of interconnection to the CAISO where the power will be 

delivered. The solicitation protocol had cited CPUC Decision 11-01-025 regarding bundled 

transactions requiring interconnections inside California or using dynamic scheduling. It 

appeared that some Participants do not understand current requirements for a project to be 

considered an in-state bundled resource for purposes of RPS compliance.

Similarly, some variants were rejected because they failed to conform to another 

requirement stated in the protocol for PSAs: “The Project and transmission interconnection 

must be designed and constructed in conformance with California Independent System 

Operator’s (CAISO) various reliability agreements, procedures, protocols, tariffs, and 

standards.”10 While this eligibility requirement does not says so in so many words, Arroyo 

interprets it to disqualify PSAs for in-state generation whose interconnection is outside the 

CAISO’s balancing authority area. Such projects would not operate under the CAISO tariff. 

PG&E is not considering purchasing generation outside the CAISO through RFOs.

 

10 Pacific Gas and Electric Company, “Renewables Portfolio Standard: 2011 Solicitation Protocol, 

May 11, 2011 (Updated June 7, 2011)”, page 9.
39

One Offer submitted for a PSA was rejected for non-compliance with the requirement 

stated in the solicitation protocol that the “Project should utilize a commercially proven, 

non-solar technology.” PG&E is not currently considering solar generation proposals from 

the RPS RFO for transfer to utility ownership (as opposed to other competitive solicitations 

focused on pursuing turnkey approaches to utility-owned solar generation).

PG&E rejected another set of Offers that failed to provide basic information required by 

the solicitation protocol, such as project location, and which explicitly were offered as 

indicative, non-binding proposals as opposed to the binding and exclusive requirement for 

participation in the RFO as stated in the protocol. Other Offers were deemed 

nonconforming to the requirements of the protocol because they proposed new 

transmission or new shaping-and-firming service arrangements rather than new PPAs, PSAs, 

unbundled RECs, or biogas sales as requested in the protocol.

In the days immediately following Offer Opening, some Participants sent PG&E 

corrections and changes to their previously submitted Offers. Arroyo notes that some of 

these were prompted by deficiency notices e-mailed to the Participants by PG&E, while 

others were unprompted voluntary efforts of the Participants to address errors they 

recognized only after shipping the original Offers. Arroyo does not consider the changes, 

even improvements, in these Offers to have been prompted by “signaling” by PG&E or by 

an unfair request for “clarifications” by the utility. 

Overall, Arroyo’s opinion is that PG&E’s decisions about which Offers or Offer 

variants to classify as nonconforming were fair to Participants. There were Offers that were 

very clearly nonconforming based on explicit deficiencies from the requirements clearly 

stated in the solicitation protocol; most Offers were clearly conforming. There was also a 

gray area in between, in which reasonable people could disagree about whether an Offer 

should be rejected for nonconformance or not; in general the PG&E team gave Participants 

whose Offers fell into this gray zone the benefit of the doubt and evaluated the proposals. 

In many of these cases Arroyo would have rejected the proposals. However, none of these 

accepted Offers from the gray area were selected given their rankings for value and viability.

Another gray area that troubles Arroyo is the failure of several Participants to submit the 

required Attachment L, PG&E’s supplier diversity questionnaire. As described below, it 

appears that some Participants did not take the supplier diversity evaluation criterion of the 

RFO and the requirements of the protocol relating to diversity seriously. In future Arroyo 

would suggest that Offers lacking a completed Attachment L be rejected as non-conforming 

if PG&E contacts the Participant to correct the deficiency but the Participant fails to do so.

D. REASONABLENESS AND FAIRNESS OF PARAMETERS AND INPUTS

The vast majority of the many parameters and inputs that PG&E used in its evaluation 

of the 2011 RPS RFO Offers were reasonably and fairly chosen, in Arroyo’s opinion. 

Arroyo identified only one issue regarding the choices PG&E made about parameters and 

inputs that merits discussion.
40

PG&E used a discount rate of 7.6% to bring future Offer costs and benefits to a 2011

present value. This value is based on PG&E’s approved cost of capital. It represents the 

approved weighted average cost of capital (WACC) for PG&E, on an after-tax basis. 

Arroyo doubts it is appropriate to use a regulated utility’s authorized cost of capital as 

the discount rate for net revenues from PPAs with renewable generation developers. These 

developers are generally not regulated utilities but are rather private or public companies in 

the independent power producer (IPP) sector. The cost of equity and cost of debt for the 

riskier IPP sector are both higher than for regulated utilities. For example, the cost of debt 

assumed into the Energy Division’s 2009 analysis of the Market Price Referent (MPR), an 

analysis that represents the risks of an IPP developer building a proxy plant under a longterm PPA, was 7.67% compared to PG&E’s authorized 6.05%, and the assumed cost of 

equity underlying the proxy developer was 11.96% vs. PG&E’s authorized 11.35%. 

Arroyo asserts that the flow of net benefits of power deliveries from independent power 

companies contracting in long-term PPAs has more risk associated with it than PG&E’s risk

(e.g. higher credit risk, bankruptcy risk, liquidity risk, development risk) that merits 

discounting the net benefits at the higher WACC associated with the IPP industry. That 

suggests that the appropriate WACC to be used when evaluating Offers in this solicitation 

should be closer to the 8.25% after-tax WACC for the proxy plant used in the 2009 MPR 

model than to the regulated utility’s 7.6%. PG&E disagrees, and believes that cash flows in a 

PPA secured by a regulated utility’s credit should be discounted at a regulated WACC.

Arroyo’s opinion is that use of a low discount rate results in valuations that overstate the 

importance of the most distant years of contract term, when the methodology depends on 

extrapolated market forward prices. Arroyo views this as a distortion that skews PG&E’s 

value rankings towards preferring long-dated PPAs, and projects with later on-line dates. In 

particular, the lower discount rate tends to overemphasize the value of Resource Adequacy.

PG&E has a variety of internal controls in place to ensure that selection of inputs is

reasonable and fair. The Energy Supply organization relies on a separate and independent 

risk management function for oversight on power market assumptions used in valuation, 

and on a financial function for oversight on financial assumptions. The choice of 

parameters is described in internal protocols. Also, the IE has the opportunity to review the 

inputs to the valuation model in detail and to raise questions with the team as appropriate. 

E. THIRD-PARTY ANALY SIS

In its 2011 solicitation, PG&E outsourced a portion of the analysis of transmission 

adders to an external consultant. An internal PG&E transmission expert oversaw the work

and performed quality control on the product; also, Arroyo had an opportunity to review the 

third-party work product and compare it to the IE’s independent analysis as a check. 

F. TRANSMISSION COST ADDERS AND INTEGRATION COSTS

PG&E generally followed its transmission analysis protocols in administering its 

procedures for market valuation. The team used TRCR proxy costs from the three 
41

California IOUs or data from Phase I or Phase II interconnection studies or interconnection 

agreements to estimate the cost of network upgrades for new projects interconnecting in 

congested locations. This is a great deal of transmission information to process in a short 

period of time and the team should be commended for its success in having developed, 

acquired, and applied a full set of this data within the deadline for creating a short list.

The team followed the public and non-public protocols for analysis of transmission 

adders. As stated in the discussion of PG&E’s LCBF methodology, there are two areas in 

which Arroyo disagrees with how this was performed. Both fall within lacunae in the 

protocols, so PG&E’s practice was entirely consistent with its protocols.

 Arroyo believes that transmission cost adders should be estimated for projects 

that interconnect within California but outside the CAISO’s balancing authority 

area, using the estimates of network upgrade costs provided in those other 

PTO’s interconnection studies. Arroyo considers the valuations of these PPAs 

to understate the full cost of power from the projects, and the analytic approach 

to be less than fully fair to projects that interconnect to the CAISO grid.

 In Arroyo’s opinion, the lack of estimated LMP multipliers for CAISO intertie 

points that fall outside the main body of the BAA presents a gap in data inputs. 

Projects that propose to interconnect to these points are unfairly advantaged vs.

projects assigned to recognized LMP zones. Arroyo’s opinion is that projects 

interconnecting to far-flung outposts of the CAISO grid in other states should 

be evaluated with a recognition that nodal prices there are on average materially

lower than those within the core of CAISO service territories due to congestion.

G. AFFILIATE PROPOSALS AND TURNKEY OFFERS

PG&E has more stringent eligibility requirements for renewable energy projects 

intended for utility ownership through turnkey development and transfer (the utility does 

not have unregulated affiliates that participated in the RPS RFO). For example, PG&E does 

not accept proposals for utility-owned generation that is sited outside California or outside 

the CAISO balancing authority area. In the RPS solicitation PG&E did not accept PSA 

proposals for solar generation; it separately conducts a competitive solicitation seeking solar 

photovoltaic generation for utility ownership.

Analytically, PG&E has an extra step in applying the same LCBF methodology to 

projects proposed for PSAs; it estimates a stream of revenue requirements for the project 

and the estimated operating and maintenance costs to replace PPA payments as the cost of 

the PSA. Otherwise the evaluation of turnkey proposals is quite similar to that of PPAs.

H. PG&E’S USE OF ADDITIONAL CRITERIA AND ANALY SIS IN CREATING A 

SHORT LIST

PG&E’s overall approach to creating a short list was to rank PPA Offers for bundled 

delivery to a CAISO node by net value and to screen out (as a first cut) all Offers that scored 

below a chosen threshold for project viability. Then the PG&E team went down the list 
42

ranked by value, selecting Offers primarily based on highest valuation and higher than 

threshold viability. These selections were modified by criteria and preferences other than 

value and viability, described in this section. 

PG&E stopped adding highly valued projects to its short list when the total volume of 

the selections totaled several times the RFO’s target of 1% to 2% of PG&E’s retail load. 

The team made a business judgment of how much more than the target would be needed to 

achieve the goals for the RFO, given a likelihood that Participants would choose exclusive 

negotiations with other utilities or that Offers would drop out of negotiations at some point. 

The team applied different value cutoffs to different classes of projects based on the 

utility’s stated preferences; for example, the valuation cutoff was lower for projects sited 

within PG&E’s service territory than for those interconnecting to other utility’s grids. 

Similarly, the valuation cutoff for Offers of unbundled RECs or RECs plus firm energy was 

set higher than the cutoff for Offers proposing bundled delivery of energy to a CAISO 

point. Other situations where the cutoff varied are described below.

1. SERIOUS ENVIRONMENTAL CONCERNS

Appendix K to PG&E’s 2011 solicitation protocol states specific subcomponents of the 

RPS Goals evaluation criterion. Among these is “environmental stewardship”, which is 

identified in the CPUC’s Decision 04-07-029 as one of a few designated “qualitative 

attributes” that the Decision allowed the IOUs to use as the basis for including Offers on a 

short list, subject to (1) the Offer being within reasonable price proximity to others selected 

and (2) support from the utility’s PRG prior to elevation.

In the 2011 RFO, PG&E’s evaluation team screened Offers to identify higher-valued 

projects with potentially serious environmental impacts; this is the contrapositive of the logic 

stated in Decision 04-09-027, in that PG&E is using a qualitative attribute to reject Offers 

from its short list. The team identified only a few Offers as posing sufficiently egregious 

threats to consider rejection on the basis of the most serious environmental concerns. These 

typically related to concerns regarding impact to endangered or threatened species from 

construction of a generating facility in close proximity to critical habitat.

In administrating its methodology, PG&E only rejected one 2011 Offer based solely on 

serious environmental concerns; it was adjacent to known occurrences of both endangered 

and fully protected species. Other projects that were identified as posing such concerns 

were rejected anyway based on inadequate value or viability scores.

2. RESOURCE DIVERSITY

Another component of the RFO Goals evaluation criterion is resource diversity. 

Attachment K of PG&E’s 2011 solicitation protocol cited “Resource Diversity benefits” as a 

non-quantitative factor identified in CPUC Decision 04-07-029 that could be considered in 

Offer selection.
43

PG&E made an effort to increase the resource diversity of its energy mix by altering the 

value cutoff point below which it rejected Offers. For example, the PG&E team chose to 

accept baseload generation Offers that were valued below proposals for intermittent 

generation that were rejected. In a sense, the team chose to create a short list that is quite

diverse in resource type (rather than, say, one technology) by applying the valuation criterion 

differently for different resources, rather than selecting only the highest-valued proposals 

that had acceptable viability. This will likely result in PG&E contracting with a diverse mix 

of baseload and peaking, and firm and intermittent resources, at a higher cost to ratepayers 

than only contracting disproportionately with one type of resource at lower cost.

3. SUPPLIER CONCENTRATION

In this year’s solicitation, PG&E stated in its protocol that averting excess supplier 

concentration would be an evaluation criterion. During the selection process this criterion 

played a role: the PG&E team limited the volume of selected Offers from any individual 

counterparty. In some cases where a Participant had its most attractive Offers selected, the 

PG&E team chose to reject remaining Offers from that Participant even though they were 

higher valued than Offers from other Participants that were also selected. PG&E also chose 

to reject some rather large proposals from a developer with whom the utility has already 

contracted large-volume projects that have not yet achieved commercial operation. 

One way that PG&E avoided excess supplier concentration was to reject some rather 

high-volume Offers with high valuations in favor of smaller Offers with lower valuations 

from the same developer. This enabled the short list to include a larger number of 

Participants whose smaller Offers were selected, instead of fewer Participants with only large 

Offers. The result is a more robust solicitation in the sense that more companies are likely 

to complete contracts and that PG&E’s counterparty credit risk will be diversified. It also 

means that total ratepayer cost will be higher than an alternative scenario in which only the 

very highest-valued, viable Offers were selected regardless of volume.

In future years the transparency of solicitations would be improved if this aspect or 

consequence of the supplier concentration criterion were communicated more clearly in the 

bidders’ conference and in the protocol. Arroyo believes that it is unlikely that most

Participants were aware that submitting large projects could disadvantage those proposals.

4. DELIVERY POINT

PG&E stated in its 2011 solicitation protocol a preference for projects that deliver at 

nodal points within PG&E’s service territory, over projects that deliver to other nodal points 

within the CAISO, to interface points of the CAISO, and to points outside the CAISO.

In the 2011 RPS solicitation, PG&E translated this stated preference into a higher 

valuation cutoff for in-state projects outside its service territory and a lower valuation cutoff 

for projects inside. In other words, some projects interconnecting in the SP-15 zone were 

rejected, whereas if the project with the same resource type, valuation, and viability had 

proposed to interconnect in NP-15 or ZP-26 it would likely have been selected.
44

5. COMMERCIAL OPERATION DATE

The solicitation protocol clearly stated PG&E’s preference to select Offers that 

demonstrated flexibility in on-line date. PG&E’s bidders’ conference presentation stated 

that the utility would focus on the latter part of the 2014-2016 compliance period. This 

preference aligns with the utility’s current view of its RPS portfolio needs. 

It is difficult to separate the application of this preference in Offer selection from an 

independent effect: that the LCBF valuation methodology assigns a higher value, all else 

being equal, to projects with later on-line dates than to projects with earlier on-line dates. 

Arroyo is not aware of any individual Offer that selected solely because of the timing of its 

COD, as opposed to a better valuation for later on-line date. Nor is Arroyo aware of any 

Offer that was rejected solely because its proposed on-line date was far from the latter part 

of the 2014-2016 compliance period. It was clear that fit of projects’ timing with the utility’s 

compliance needs was on the mind of the PG&E team as it constructed the short list. 

In future RPS solicitations, PG&E should improve the transparency of its selection 

process by stating its timing preference directly in the protocol. It was evident from 

debriefings that many Participants were operating under the mistaken belief that PG&E 

preferred projects with the earliest on-line dates, as was the case in its 2009 RPS RFO. 

7. SUPPLIER DIVERSITY

One of the components of the RPS Goals evaluation criterion is whether an Offer will 

contribute towards PG&E’s supplier diversity goals. The solicitation protocol states that 

“It is the policy of PG&E that Women-, Minority-, and Disabled Veteran-owned 

Business Enterprises (WMDVBE) shall have the maximum practicable opportunity to 

participate in the performance of Agreements resulting from this Solicitation. PG&E 

encourages Participants to carry out PG&E’s policy and contribute to PG&E’s goal by 

reaching greater than 30% of all procurement with WMDVBEs...The Supplier Diversity 

evaluation will take into account the Participant’s status as a WMDVBE, intent to 

subcontract with WMDVBEs, and the Participant’s own Supplier Diversity Program.”

PG&E’s evaluation committee scored Offers based on the submittal of Attachment L, a

Supplier Diversity Questionnaire.

Historically, only a tiny proportion of IOUs’ short-listed Offers or executed PPAs have 

been executed with WMDVBEs, and PG&E’s policy of scoring Offers against this 

subcriterion is no doubt intended to help address the shortfall between actual procurement 

of renewable power from WMDVBE’s (or from prime contractors that use diverse suppliers 

as subcontractors) and PG&E’s overall supplier diversity goal.

Among developers submitting to the 2011 RPS RFO, only three Participants were

WMDVBEs that have been certified by the CPUC Clearinghouse. None of the Offers 

submitted by certified WMDVBEs scored above the valuation cutoff. Other Participants 

claimed to be WMDVBEs that had not yet obtained CPUC certification, but review of their 

ownership suggested that this claim was inaccurate for at least one entity.
45

Not only were few Participants actual WMDVBEs, but only a subset of Participants 

agreed to pursue PG&E’s stated WMDVBE subcontracting goal (30% of spend). Some 

Participants whose Offer was shortlisted stated an intent to meet this goal in their proposals 

but others did not. Arroyo views the overall response from the renewable energy developer 

community towards PG&E’s diversity goals as rather weak. It appears that many 

Participants failed to take the supplier diversity criterion seriously. In future solicitations 

there may be opportunities to explain or communicate the diversity goal more clearly, and to 

more explicitly link Offer selection to a Participant’s willingness to commit to some 

subcontracting goal. 

I. ANALYSIS OF PG&E’ S SHORT LIST RESULTS

This section provides a review of instances in which Arroyo Seco Consulting disagreed 

with PG&E’s decisions in the administration of its evaluation and selection methodology, 

and a discussion of the fairness of the decisions.

1. SOURCES OF DISAGREEMENT

Arroyo disagreed with some minor aspects of the PG&E analysis and selection, but 

these pertained to micro-level issues that did not affect overall selection of a short list. For 

example, Arroyo and the PG&E team scored Offers using the same Project Viability 

Calculator; in nearly all cases the scores differed, but relative rankings of Offers were similar 

overall. Other examples of minor disagreement with no impact on selection include:

 Arroyo disagreed with the estimates of LMP multipliers applied to CAISO

delivery points outside California which had not been assigned to an LMP zone;

 Arroyo would have rejected as non-compliant more out-of-state Offers with 

weak cases for achieving regulatory treatment as bundled in-state resources;

 Arroyo would not have assigned full Resource Adequacy value to some of the 

out-of-state Offers that proposed to deliver power at CAISO intertie points 

where PG&E’s ability to secure RA import capability is limited.

Arroyo’s primary critique of PG&E’s short list is that it is too large. Total volume is a 

multiple of the target for procurement of contracts from the 2011 RFO. By choosing to 

accommodate a large short list, PG&E has selected some Offers that Arroyo considers 

marginally attractive, rather than focusing on the highest valued, most viable proposals:

 Because PG&E chose a different cutoff for valuation for different types or 

locations of resources, it selected several Offers that Arroyo ranked as mediocre 

in net value. Arroyo would have shortened the short list by rejecting these 

lower-valued proposals.

 PG&E used a cutoff for viability score to screen out many Offers. However, the 

team selected a very few Offers that it had scored below this threshold, because 

of other attributes that PG&E considered sufficiently attractive to outweigh the 
46

projects’ weaker viability assessments. Arroyo would have rejected those 

proposals based on the projects’ mediocre viability.

 Arroyo’s input assumptions to the independent valuation place a lower value on

Resource Adequacy capacity than PG&E’s do. As a result, Arroyo would have 

ranked some solar projects lower than PG&E did, and some wind generation 

projects higher; Arroyo would have considered selecting more wind generation.

Although Arroyo disagreed with the resulting short list that PG&E selected, the basis for 

these disagreements largely centers on differences in business judgments about relative 

priorities and choices of numerical inputs. Arroyo believes that the choices the PG&E team 

made were reasonable and justifiable. For example, PG&E’s choice to lower the valuation 

cutoff for certain resource types and locations was fully consistent with placing a relatively 

high priority on the non-quantitative sub-criterion of resource diversity and on the stated 

preference for projects within PG&E’s service territory. While Arroyo’s relative preferences 

differ, Arroyo believes that PG&E’s relative priorities, based on its business judgment, are 

reasonable.

Similarly, Arroyo disagrees with PG&E’s selection of inputs for its valuation of capacity, 

but acknowledges that the underlying sources of the inputs which generate the RA value 

estimates come directly from the CPUC and the California Energy Commission. It seems 

reasonable for a regulated utility to select parameters in a way that they are consistent with 

guidance from regulators, though Arroyo believes that better choices are available for inputs.

Separately, Arroyo can offer only a qualified opinion about whether the selection of 

Offers for sites for development was made fairly. The group within PG&E that analyzes 

these Offers provided incomplete documentation of the basis for selection decisions. 

Arroyo disagrees with the shortlisting decisions about these Offers. The CPUC will have a 

better opportunity to review these if PG&E executes contracts for these in the future.

2. INDEPENDENT OFFER ANALYSES

Arroyo conducted its own rather simplified valuation analysis. PG&E’s and Arroyo’s

valuations generally correlated well for many Offers, but with a fair amount of noise in the 

comparison, as shown in Figure 3 that compares the two sets of valuations. Some of the 

differences between valuations include:

 Less value assigned to Resource Adequacy in the independent assessment, which 

tends to lower the value ranking of projects with the most estimated Net 

Qualifying Capacity such as solar generation;

 Less value assigned to projects interconnecting in non-CAISO balancing 

authority areas;

 Less of a premium assigned to projects with later CODs or longer delivery terms.

This comparison was useful in quality control to identify errors in PG&E’s or the IE’s 

input parameters. Also, the comparison helped identify what factors caused specific Offers 
47

to be ranked high or low in PG&E’s short-listing process, such as the impact of the discount 

rate assumption, the on-line date, and the size of transmission adder.

Arroyo also scored each Offer for viability independently of PG&E’s analysis. This was 

useful to get an estimate of what the standard error of the Calculator is, and a sense of 

whether differences in score reflect significant differences in viability or are within the noise 

of the method. Arroyo emerged from the comparison (shown in Figure 4) with a view that 

differences of a dozen or fewer points in viability score may not reflect significant 

differences in the likelihood that project will succeed in attaining commercial operation on 

schedule, given the modest precision of the tool and the subjectivity of its use.

Figure 3

Comparison of PG&E and IE valuations

IE valuations, $/MWh PG&E valuations, $/MWh

Some of the differences between viability scores include:

 Lower IE scores for projects proposing very large solar photovoltaic facilities;

 Lower IE scores for projects from developers with experience only in distributed 

generation (e.g. beyond the meter) projects rather than wholesale generation;

 Lower IE scores for projects for which specific network upgrades are as yet 

poorly characterized.

3. RECTIFYING DEFICIENCIES OF REJECTED OFFERS

PG&E communicated early to several Participants about basic deficiencies in their Offer 

packages and provided them with an opportunity to correct these deficiencies by completing 
48

or correcting their original submissions. None of these original deficiencies caused rejection 

from the short list, as far as Arroyo can discern. Many of the issues related to failure to 

complete an Attachment D offer form fully, using the final version of that form, or omission 

of the most recent CAISO or PTO interconnection study.

Figure 4

IE viability score

PG&E viability score

Given the robustness of the solicitation and the large number of Offer variants, PG&E 

did not collect every piece of information required by the protocol from every Participant. 

Some Participants had obtained interconnection studies for their project but did not submit 

copies with their proposals. Arroyo observes that in these cases the missing information 

would not have made a difference to the selection decision. PG&E made a concerted effort 

to obtain copies of these studies for most of these projects. By this point it was evident 

which Offers had proposed uncompetitive, high prices and were unlikely to be short-listed.

4. OVERALL FAIRNESS OF ADMINISTRATION

Despite a variety of minor disagreements, Arroyo Seco Consulting’s overall judgment is 

that PG&E’s administration of its protocols to arrive at a short list for the 2011 RPS RFO 

was fair, unbiased, consistent, and reasonable. 

Most disagreements between Arroyo and the PG&E team fall into the category of 

choices that Arroyo would have not made if it were administering the solicitation, but that 

Arroyo agrees are choices a reasonable person could make if that person had different 

priorities or emphases regarding the weights assigned to evaluation criteria. Arroyo believes 

that PG&E’s preferences and its choices are within the realm of “reasonable business 

judgment” that the CPUC allows IOUs to exercise in energy procurement. 
49

5 . FA I R N E S S O F P RO J EC TS P E C I F I C N E G O T I AT I O N S

This chapter gives an independent review of the extent to which PG&E’s negotiations 

with Sierra Pacific Industries for a new contract for delivery of RPS-eligible energy were 

conducted fairly.

Arroyo observed several negotiation sessions between PG&E's and SPI’s

representatives. Arroyo was also able to review draft term sheets and contracts in order to 

identify specific proposals and counterproposals the parties made regarding contract terms 

in the course of discussions.

Based on this review, Arroyo did not identify any situations in which PG&E provided 

SPI with concessions in contract terms that the IE considered to be materially unfair to 

ratepayers. Nor did PG&E provide SPI with information that might have unfairly 

advantaged the seller compared to its competitors; however, PG&E gave SPI a unique and 

valuable concession that was not provided to competing sellers in the 2011 RPS solicitation.

However, the circumstances about how and why this concession was granted mitigate 

Arroyo’s concerns about whether negotiations were fair to SPI’s competitors. The starting 

point for negotiations was PG&E’s 2011 RPS Form Agreement; PG&E requested updates 

to the 2012 Form Agreement when that became available in May 2012. Only a few variances 

to the utility’s standard form language were requested by SPI and accepted by PG&E.

Arroyo’s opinion is that the negotiations between PG&E and SPI were conducted in a 

manner that was fair to ratepayers; the resulting contract retains the ratepayer protections 

afforded by PG&E’s Form Agreement. While there could be a perception that negotiations 

were less than fully fair to SPI’s competitors, Arroyo does not regard this as sufficient a 

concern to cause the PPA to merit rejection. 

A. BACKGROUND INFORMATION

Sierra Pacific Industries is an integrated forest products company headquartered in 

Anderson, California, with numerous operations in forestry, sawmills, and product 

manufacturing; it is the second largest lumber producer in the U.S. SPI currently owns and 

operates six generation plants in California, fueled by woody waste biomass, four of whose 

output will continue to be provided to PG&E under the new PPA. Four of these projects 

have been under contract with PG&E as Qualifying Facilities since they commenced 

operations:

 Anderson, 5.0 MW contract capacity as a QF, commenced operation in 1998;
50

 Burney, 20 MW as a QF11, 1986; 

 Lincoln, 7.5 MW, 1986; 

 Quincy, 20.0 MW, 1986; and 

 Sonora, 7.5 MW. SPI and PG&E agreed in 2008 to substitute the Sonora facility 

(which SPI purchased in 1995) for SPI’s defunct Susanville plant in the existing 

QF contract between the parties.12

All of these generating projects are located at SPI lumber mills on SPI-owned land, and 

serve as co-generators with lumber operations where steam from the unit is used to dry 

lumber in kilns. In addition to the existing facilities, SPI has been planning to replace the 

Anderson project with a new 30.15-MW Anderson II facility to be constructed in the same 

site as the existing generator. The new PPA will cover sales from Anderson II, Burney, 

Lincoln, Quincy, and Sonora. 

One element of the transaction with SPI is that the QF agreement with the five existing 

projects will be terminated by the parties rather than allowing PG&E ratepayers to continue 

to benefit from the pricing of that agreement through the original delivery term. The 

valuation analysis described in the next chapter addresses the loss of benefits from that early 

termination. 

The parties negotiated terms for several months. In July 2012, PG&E selected the most 

competitive of the remaining shortlisted Offers from its 2011 RPS RFO for execution, 

including the SPI portfolio PPA, based on current market conditions and using the 

portfolio-adjusted valuation approach described in the next chapter rather than the version 

of the LCBF methodology that was used to make shortlisting decisions in the summer of 

2011 as described in Chapter 3.13

 

11

 

12 For 2012 the CAISO counted average Net Qualifying Capacity for the five existing projects of 0.71 

MW, 10.93 MW, 9.36 MW, 14.45 MW and 1.25 MW respectively. 

13 Chapters 1 through 4 of this report restate the October 2011 public version of the IE report that 

accompanied the filing of PG&E’s short list; PG&E’s methods have been altered since then.
51

B. PRINCIPLES FOR EVALUATING THE FAIRNESS OF NEGOTIATIONS

Arroyo took into account several principles to evaluate the degree of fairness with which 

SPI was treated in negotiations. 

 Were sellers treated fairly and consistently by PG&E during negotiations? Were 

all sellers given equitable opportunities to advance their Offers towards final 

PPAs? Were individual sellers given unique opportunities to move their 

proposals forward or concessions to improve their contracts’ commercial value, 

opportunities not provided to others? 

 Was the distribution of risk between seller and buyer in the PPAs distributed 

equitably across PPAs? Did PG&E’s ratepayers take on a materially 

disproportionate share of risks in some contracts and not others? Were 

individual sellers given opportunities to shift their commercial risks towards 

ratepayers, opportunities that were not provided to others? 

 Was non-public information provided by PG&E shared fairly with all sellers? 

Were individual sellers uniquely given information that advantaged them in 

securing contracts or realizing commercial value from those contracts? 

 If any individual seller was given preferential treatment by PG&E in the course 

of negotiations, is there evidence that other sellers were disadvantaged by that 

treatment? Were other proposals of comparable value to ratepayers assigned 

materially worse outcomes? 

C. NEGOTIATIONS BETWEEN SIERRA PACIFIC INDUSTRIES AND PG&E

In November 2010, SPI and PG&E began bilateral discussions about how to convert the 

existing QF contracts into a new RPS agreement. Discussions continued for several months 

and considerable progress was made drafting a new RPS contract structure and pricing. 

However, in May 2011 PG&E notified SPI that it would terminate these bilateral 

negotiations. At that time PG&E asked SPI to propose its projects into the 2011 RPS RFO 

in order that the SPI offer would compete directly with other available proposals and be 

evaluated directly against competitors. 

SPI prepared and submitted 

 Following the selection, 

the parties began active negotiations in December 2011, which culminated in execution of an 

RPS contract on August 9, 2012. Some of the issues addressed in the negotiation included: 


52

 

 
53

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14
54

 

 

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o

 

 

15
55

 



 

16

17
56

 

 
57



 



 



 
58



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59

 



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60

 Use-limited resource. PG&E asked, and SPI agreed, that the seller be obligated 

to take commercially reasonable steps to obtain a CAISO designation as a uselimited resource for its generators. If successful, this would help PG&E avoid 

actions by the CAISO to override the utility’s planned schedules in making 

dispatch decisions. 

D. DEGREE OF FAIRNESS OF PROJECT-SPECIFIC NEGOTIATIONS

The starting point for drafting the PPA with SPI was PG&E’s 2011 RPS Form 

Agreement, which serves as the basis for contracting with other sellers; in June 2012 PG&E 

updated the draft PPA to include features of its draft 2012 RPS Form Agreement. There are 

only a few modifications to the Form Agreement that would raise issues about whether 

ratepayers or competing generators were treated unfairly. 

One possible issue is the fairness to ratepayers and competitors of PG&E allowing SPI 

Arroyo notes that there are precedents for PG&E 

There are a few mitigating factors that partially alleviate Arroyo’s concern about the 
61

Another mitigating factor is that PG&E chose to 

On that basis, Arroyo views the trade-off as 

reasonable if not ideal. 

 

Overall, Arroyo’s opinion is that the negotiations with SPI were handled in a manner fair 

to ratepayers: 

 Most other sellers with proposals of comparable valuation and viability have 

been given comparable opportunities to move their contracts forward. 

 The distribution of risk between PG&E and SPI is comparable to that in other 

RPS contracts with baseload generators. 

 Arroyo does not believe that at any time PG&E provided any information to SPI 

that may have advantaged the seller compared to its competitors. 

 PG&E provided a concession to SPI that is unique within this RPS solicitation. 

 appears to Arroyo to be a reasonable tradeoff 

for ratepayers

However, in Arroyo’s opinion, granting this unique 

concession to SPI creates an appearance of less than fully fair treatment of SPI’s 

competitors.
62

6 . M E R I T F O R C P U C A P P ROVA L

This chapter provides an independent review of the merits of the contract between 

PG&E and Sierra Pacific Industries against criteria identified in the Energy Division’s 2011 

RPS IE template.

A. CONTRACT SUMMARY

On August 9, 2012, PG&E and SPI executed a contract for delivery of RPS-eligible 

energy from SPI’s new Anderson II facility and four existing projects at Burney, Lincoln, 

Quincy, and Sonora; all are biomass-fueled projects using woody waste, primarily from SPI 

operations, located on SPI-owned premises with saw mills.

 Anderson II, a new cogeneration plant with 17 MW of contract capacity18 out of 

the PPA’s total 58 MW, will be constructed at the site of an existing cogeneration 

plant on the premises of SPI’s lumber mill north of the city of Anderson, 

southern Shasta County.

 Burney is an existing facility which will have 12 MW of contract capacity, located 

west of the community of Burney, in eastern Shasta County.

 Lincoln is an existing facility which will have 11 MW of contract capacity, located 

within the city of Lincoln, in western Placer County.

 Quincy is an existing facility which will have 16 MW of contract capacity, located 

in the community of Quincy, in central Plumas County.

 Sonora is an existing facility which will have 2 MW of contract capacity, located 

east of the city of Sonora, in western Tuolumne County.

The delivery term for the contract would begin upon commercial operation of the new 

Anderson II project and extend for 20 years (Anderson II’s guaranteed commercial 

operation date is April 1, 2014).

 

18 Note that the contract specifies 58 MW of contract capacity from SPI’s overall portfolio of power 

plants, and does not assign “contract capacity” to any specific facility. The numbers shown here 

correspond to what SPI offered for each project on an individual basis and what is listed in Appendix 

XVI of the PPA as “Nominal Portfolio Contribution” to the 58 MW.
63

B. NARRATIVE OF EVALUATION CRITERIA AND RANKING

The 2011 RPS template for IEs provided by the Energy Division calls for a narrative of 

the merits of the proposed project on the criteria of contract price, portfolio fit, and project 

viability. 

CONTRACT PRICE AND MARKET VALUATION 

Arroyo has compared the net value of the SPI contract to relevant peer groups of 

previously and currently offered competing sources of RPS-eligible energy, using the results 

of both PG&E’s analysis and a simpler but independent model. Based on those 

comparisons, Arroyo opines that the market valuation of the SPI contract ranks as high 

compared to relevant peer groups of competing proposals, and the contract price ranks as 

low. 

Contract Price. 

 

On that basis, Arroyo’s opinion is that the SPI contract’s price ranks low among 

competing alternatives. 

Market Valuation. Using its least-cost, best-fit methodology PG&E estimated the value 

of SPI’s deliveries under the PPA, taking as inputs for market forward price observations 

from July 11, 2012. The proposed contract’s estimated net market value ranks 

PG&E also estimated the “portfolio-adjusted value” of the SPI PPA using an alternative 

methodology that explicitly discounts the benefit to ratepayers of the renewable attributes of 

delivered energy in the first and second compliance periods. This method counts the value 

 

19
64

of green attributes in delivery years when PG&E is expected to be short of its compliance 

goals. PG&E’s current expectation is that it will meet RPS targets in the first and second 

periods with contracts already in place, so the thought in applying this version of the 

portfolio-adjusted value metric was that incremental RPS-eligible energy delivered through at 

least 2018 does not provide additional value to ratepayers.20 Also, this method discounts the 

value of Resource Adequacy delivered from projects that are outside PG&E’s service 

territory, under the theory that at some point in time the utility’s ability to benefit from 

capacity attributes of generation located in SP-15 will be limited by import constraints. The 

effect of such adjustments is to reduce the attractiveness of contracts with earlier on-line 

dates or with sites in southern California. 

Using the portfolio-adjusted value metric, the SPI PPA ranks 

Arroyo independently estimated the value of the SPI PPA. This estimate places the PPA 

in 

On the basis of these comparisons, Arroyo’s opinion is that the SPI contract ranks high 

in net value compared to relevant competing alternatives. 

PORTFOLIO FIT 

Arroyo ranks the SPI contract’s fit with PG&E’s supply portfolio needs as moderate.

PG&E based its evaluation of Offers in the 2011 RPS solicitation on the fit of proposed 

deliveries with and on the firmness of delivery. 

 

 

 

20
65

The SPI powerhouses operate as baseload units; SPI runs the boilers primarily for its 

steam needs at its saw mills rather than as standalone electric generators. 

 

SPI’s Lincoln cogenerator is sited in the CAISO’s Sierra area, which was identified in 

both 2011 and 2012 Local Capacity Technical Analysis studies as deficient in local capacity 

resources. More specifically, the South of Palermo sub-area was identified as deficient by 

313 MW for 2011 and by 36 MW for 2012 under “Category B”21: at summer peak, load 

would need to be shed immediately after the first contingency. Lincoln is in the South of 

Palermo sub-area. It appears that SPI’s Lincoln power plant currently plays a role in 

maintaining grid reliability in the Sierra area. The CAISO anticipates that the deficiency 

could be remedied by major network upgrades to PG&E’s grid including line voltage 

upratings in the vicinity of Vaca-Dixon and Davis, which could be in place by 2015. 

Similarly, SPI’s Sonora generator is sited in the Tesla-Bellota sub-area of the CAISO’s 

Stockton area, which the 2012 Local Capacity Technical Analysis identified as deficient by 

114 MW in local capacity resources using “Category C”, a more demanding criterion. No 

deficiency was identified under “Category B”. So SPI Sonora plays a role in maintaining grid 

reliability in the Stockton area. The CAISO does not anticipate this deficiency being relieved 

by 2016. 

Arroyo considers the portfolio fit of SPI’s production with the utility’s needs to be 

moderate. 

PROJECT VIABILITY 

In Arroyo’s opinion, the physical project viability of the four existing, operating SPI 

facilities that are being recontracted in this PPA is quite high. These powerhouses have 

operated for decades and have been maintained by SPI for use in its saw mill production 

processes. An existing, currently operating project is more viable, in a physical rather than 

economic sense, than any proposed as-yet-unbuilt generator. 

The new Anderson II facility will resemble SPI’s existing generators in many respects.

 

21 The CAISO’s 2013 study identified no local deficiency in the Sierra area under Category B, which 

considers a scenario with an n-1 contingency of a single transmission failure, though there is still a 

deficiency using Category C that employs an n-2 contingency, or double line failures. 
66

Project development experience. SPI developed the existing powerhouses at its 

Anderson, Burney, Lincoln, and Quincy saw mills; the Sonora powerhouse was purchased 

along with that lumber operation from a prior owner. Anderson II, at 30.15 MW, will be 

larger in turbine-rated capacity than any of those individual existing powerhouses. 

Ownership/O&M experience. SPI has owned and operated the powerhouses since they 

were constructed or, in the case of Sonora, purchased in 1995 from Fibreboard Inc. out of 

bankruptcy. 

Technical feasibility. 

 This is a well-commercialized and stable 

technology. 

 

Resource quality. SPI’s existing facilities use the company’s mill waste as the primary 

source of fuel; this is augmented by in-forest waste from the extensive private forestry 

holdings of the company as well as other sources. 

Manufacturing supply chain. The existing powerhouses do not rely on new sources of 

hardware. For Anderson II, one would not expect manufacturing supply constraints for 

hardware given the lead time available to SPI. 

Site control. SPI owns the sites of all five mills and their cogenerators. The new 

Anderson II power plant will be constructed on the grounds of SPI’s Anderson mill 

property, near the existing boiler and fuel house. 

Permitting. SPI holds all required permits for continued operation of the four existing 

power plants, including air permits and wastewater discharge permits. The Shasta County 

Planning Commission recently approved a final environmental impact report for the 

Anderson II facility in June 2012.22 The Shasta County Board of Supervisors approved the 

facility’s use permit in July 2012 after an appeal by the Center for Biological Diversity of 

approval by the Planning Commission. 

 

22 The CEQA process for Anderson II was contentious and prolonged; reportedly, three versions of 

a draft environmental impact statement were prepared. Much of the debate appears to have focused 

on the impact of a woody biomass-fueled generator on greenhouse gas emissions, whether beneficial 

or harmful in the short term. 
67

SPI applied in March 2010 for an Authority to Construct and Prevention of Significant 

Deterioration permit from the U.S. EPA for the new Anderson cogenerator; 

Project financing status

Interconnection progress. The existing powerhouses are already interconnected to the 

CAISO grid, 

SPI applied for a Large Generator Interconnection Agreement for Anderson II 

Transmission requirements. 

 the grid infrastructure for delivery of power from the existing power plants 

is already in place.

 This 

suggests that grid upgrade work will not impede SPI’s ability to achieve its guaranteed online date for Anderson II of April 2014. 

Reasonableness of COD. As existing generators, there are no physical impediments to 

continued operation of the four operating SPI facilities over the contract term, barring 

catastrophic failure. One anticipates the need for major maintenance overhauls in the course 

of the delivery term. 
68

The new Anderson II project has full site control, has obtained its use permit, and 

should be able to interconnect reliably to the grid 

 It appears likely to Arroyo that Anderson II can achieve commercial 

operation by its GCOD of April 2014. 

Summary. The viability of the already operating SPI facilities is quite high. Arroyo has 

scored the Anderson II project using the Energy Division’s Project Viability Calculator. 

Based on this, the SPI contract ranks among the highest-viability proposals submitted to 

PG&E in the 2011 RPS RFO. 

RPS GOALS 

SPI’s RPS-eligible generation is likely not needed for PG&E to meet its RPS compliance 

goals in the second compliance periods, but should contribute to compliance in the third 

period and beyond. 

 

Entering into this transaction advances PG&E and the state towards the 20% biomass goal 

set by Executive Order S-06-06 by virtue of the increased production from the new 

Anderson II plant and the continued operation of the existing plants for more than a decade. 

C. DISCUSSION OF MERIT FOR APPROVAL

In Arroyo’s opinion, PG&E’s contract with Sierra Pacific Industries merits CPUC 

approval. 

Arroyo’s independent but simpler valuation ranks the SPI contract as high in net value 

compared to other Offers submitted to PG&E in the 2011 RPS RFO. PG&E’s LCBF 

analysis suggests that the contract ranks as high in net market value and high in portfolioadjusted value when compared to competing alternatives. PG&E now relies on the 

portfolio-adjusted value metric, which discounts the attractiveness of projects outside its 

service territory, for decision-making. The contract price ranks low compared to competing 

alternatives available to PG&E. 

The project viability of four of SPI’s powerhouses is quite high because they are existing, 

operating facilities. Arroyo has scored the new Anderson II power plant as high in project 

viability given SPI’s experience with developing and operating biomass-fueled generators, its 

success in moving the project through the local permitting process, and the modest cost and 

work scope of required network upgrades. Further progress needs to be made in federal air 

permitting, execution of an interconnection agreement, and completion of network 

upgrades. 
69

Arroyo regards the SPI contract as ranking as moderate in portfolio fit. 

 The SPI Lincoln 

powerhouse currently contributes to grid reliability in the CAISO’s resource-deficient Sierra 

area. 

Arroyo believes that PG&E’s project-specific negotiations with SPI were conducted in a 

manner that was fair to ratepayers. The concession that PG&E granted to SPI 

 appears less than fully fair to competing 

developers when viewed in isolation. 

 Based on its high 

valuation, low contract price, high viability, and moderate portfolio fit, Arroyo’s opinion is 

that this contract merits CPUC approval. 
PG&E Gas and Electric 

Advice Filing List 

General Order 96-B, Section IV 

AT&T Department of Water Resources North America Power Partners 

Alcantar & Kahl LLP Dept of General Services North Coast SolarResources 

Ameresco Douglass & Liddell Northern California Power Association 

Anderson & Poole Downey & Brand Occidental Energy Marketing, Inc. 

BART Duke Energy OnGrid Solar 

Barkovich & Yap, Inc. Economic Sciences Corporation PG&E 

Bartle Wells Associates Ellison Schneider & Harris LLP Praxair 

Bloomberg Foster Farms R. W. Beck & Associates 

Bloomberg New Energy Finance G. A. Krause & Assoc. RCS, Inc. 

Boston Properties GLJ Publications SCD Energy Solutions 

Braun Blaising McLaughlin, P.C. GenOn Energy Inc. SCE 

Brookfield Renewable Power GenOn Energy, Inc. SMUD 

CA Bldg Industry Association Goodin, MacBride, Squeri, Schlotz & 

Ritchie 

SPURR 

CENERGY POWER Green Power Institute San Francisco Public Utilities Commission 

CLECA Law Office Hanna & Morton Seattle City Light 

California Cotton Ginners & Growers Assn Hitachi Sempra Utilities 

California Energy Commission In House Energy Sierra Pacific Power Company 

California League of Food Processors International Power Technology Silicon Valley Power 

California Public Utilities Commission Intestate Gas Services, Inc. Silo Energy LLC 

Calpine Lawrence Berkeley National Lab Southern California Edison Company 

Cardinal Cogen Los Angeles County Office of Education Spark Energy, L.P. 

Casner, Steve Los Angeles Dept of Water & Power Sun Light & Power 

Center for Biological Diversity Luce, Forward, Hamilton & Scripps LLP Sunrun Inc. 

Chris, King MAC Lighting Consulting Sunshine Design 

City of Palo Alto MBMC, Inc. Sutherland, Asbill & Brennan 

City of Palo Alto Utilities MRW & Associates Tecogen, Inc. 

City of San Jose Manatt Phelps Phillips Tiger Natural Gas, Inc. 

City of Santa Rosa Marin Energy Authority TransCanada 

Clean Energy Fuels McKenzie & Associates Turlock Irrigation District 

Clean Power Merced Irrigation District United Cogen 

Coast Economic Consulting Modesto Irrigation District Utility Cost Management 

Commercial Energy Morgan Stanley Utility Specialists 

Consumer Federation of California Morrison & Foerster Verizon 

Crossborder Energy Morrison & Foerster LLP Wellhead Electric Company 

Davis Wright Tremaine LLP NLine Energy, Inc. Western Manufactured Housing 

Communities Association (WMA) 

Day Carter Murphy NRG West eMeter Corporation 

Defense Energy Support Center NaturEner 

Department of General Services Norris & Wong Associates