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 rene wable power. The PP A price is below the applicable 2011 Market Price Referent (“MPR”). There are currently five existing Qualif ying Facilities (“QFs”) owned and operated by SPI that are delivering powe r 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 ne w PPA, all existing SPI QF contracts will terminate. The PPA will transiti on four of the QF facilities currently delivering power to PG&E to a RPS cont ract, and the fifth facility currently delivering power to PG&E will be decommi ssioned. 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 A dvice 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 Proj ect 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 Ge neration Facility” or “AGF”). The Project is comprised of four existi ng (Burney, Lincoln, Quincy, and Sonora) and one new facility (Anderson II) for a to tal of 58 MW. All five AGFs are or will be co-located with sa w mills also owned and ope rated 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 st eam turbine generation facilities. The technology is mature.

3. General Location and Interconnection Point

The AGFs are located throu ghout northern California in the cities of Anderson, Burney, Lincoln, Quincy, and Sonora. The existing AGFs have first points of interconnection within th e boundaries of the California Independent System Operator (“CAISO”), a California balancin g authority. The new AGF, Anderson II, is expected to have its first point of interconnection within th e boundaries of the CAISO.

4. Owner(s) / Developer(s)

a. Name(s)

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

c. Business Relationship (i f applicable, between seller/owner/developer) Sierra Pacific Industries, a California Corp oration, is the owne r and operator of the four existing AGFs. SPI will also develo p, own and operate the new Anderson II facility.Advice 4102-E September 7, 2012

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### 5. Project background, e.g., expi ring QF contract, phased project, previous power purc hase agreement, contract amendment The Burney, Lincoln, Quin cy and Sonora facilities, as well as a fifth facility, Anderson I, are existing QFs (all five toge ther, “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 Ex isting QFs is addressed in Confidential Appendices A & D. A sixth SPI QF facility, Susanv ille, delivered power to PG&E under a standard offer QF agreem ent until it was decommissioned in 2004. The Susanville QF agreement was not te rminated at the time.

The Anderson II facility is a new, ye t-to-be-built facility , with commercial operation expected on April 1, 2014. The Anderson II facility is being built immediately adjacent to Anderson I. Ande rson I will be decommissioned once the Anderson II facility is comme rcially 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 Ex isting 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 requir ed 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

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### 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

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### 1. Provide a general map of the ge neration facility’s location

2. For new projects describe fac ility’s current land use type (private, agricultural, county, state lands (agency), federal lands (agency), etc.) Anderson II is a new, yet-to-be-built fa cility, with commercial operation expected on April 1, 2014.

The Anderson II facility will be bu ilt 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 a nd existing facility located in Lincoln, California:Advice 4102-E September 7, 2012

7 

### The Quincy facility is an existing facility loca ted 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 priv ate 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 produc ts, 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 existi ng in-state RPS-eligib le renewable energy resources that have their first points of interconnection with the CAISO controlled transmission system, and new facility that also anticipates inte rconnection with theAdvice 4102-E September 7, 2012

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### CAISO. Procurement from the Project sa tisfies the criteria for the portfolio content category specified in Public Utilities Code Section 399.16(b)(1)(A) (hereinafter “Portfolio Content Cate gory One”) because each AGF is a RPSeligible generator that has or expects to ha ve 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 Pr oject 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 SP I’s onsite saw mill use; PG&E is buying the energy generated in exce ss of SPI’s onsite load. De spite the ability to deliver higher levels of output as of the comme rcial operation date of Anderson II, annual deliveries under the PPA through the end of 2016 are contractually limited to the approximate quantity currently deliver ed to PG&E under the Existing QF agreements. Therefore, incremental RPS- eligible energy deliveries, relative to deliveries currently procured under the Existing QF agre ements, begin in 2017. The PPA is for the purchase of a baselo ad 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 associ ated with the Projec t, including, without limitation, renewable attributes, Renewabl e Energy Credits, Capacity Attributes and Green Attributes associated with the volumes PG&E procures. The Anderson II facility may meet the cr iteria 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 Ande rson II facility receives th e necessary approvals to be designated as a New CHP Facility, PG&E requ ests 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, Ande rson 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)/C HP 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 re port 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 target s 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 th e first point of interconnection to the CAISO Grid for each of th e 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 Li ncoln – Pleasant Grove 115 kV line Quincy Existing tap off Cari bou – Plumas Jct 60 kV line Sonora Existing tap off the Do nnells – 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 RP S 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 genera ting 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 energyAdvice 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 requiremen ts; safe and reliable operation of the electrical grid; and implementing state’s transmission and land us e planning activities.

2. Describe how procurement pur suant to the contract will meet IOU’s specific RPS compliance period needs
Public Utilities Code §399.11 states th at increasing California’s reliance on eligible renewable energy resources is intended to displace fossil fuel consumption within the state, promot e stable electricity prices, reduce GHG emissions, improve environmental quality an d 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 maintain ing a diversified and balanced energy generation portfolio.

Senate Bill (“SB”) 1078 established th e 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 th an December 31, 2017. The legislature subsequently accelerated the RPS goal to re ach 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 pe rcent of the combined bu ndled 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: (.2 17 * 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 formul a: (.27 * 2017 retail sales) + (.29 * 2018 retail sales) + (.31 * 2019 reta il sales) + (.33 * 2020 retail sales).

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

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### Consistent with the Energy Division Staff methodology for calculating the renewable net short 8 

### , PG&E calculated an assessmen t 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 descri bed 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 A ttached Methodology into the Record, and (3) Extending the Date for Filing Updates to 2012 Procurement Plans issued on August 2, 2012.Advice 4102-E September 7, 2012

14RPS Net Short Calculation as of August 2012Current Expected Need Scenario (Annual)2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030RPS 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% 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 0 0Aggregate 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 16,176 15,605 15,536Annual 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% 19.9% 19.8%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) (10,252) (10,373)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 0 0Net Surplus/(Deficit) (GWh)(500)0000000(3,258) (8,255) (8,421) (9,078) (9,490) (9,629) (10,252) (10,373)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% 19.9% 19.8%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 0 0Forecast 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% 22.7% 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% 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 2029 2030Compliance Period Requirement33% 33% 33% 33% 33% 33% 33% 33% 33% 33%Voluntary Margin of Over-Procurement (GWh)0000000000Aggregate Volumes (GWh)20,221 17,896 17,594 17,345 17,231 16,625 16,264 16,176 15,605 15,536RPS Position (%)26.2% 23.2% 22.7% 22.4% 22.2% 21.3% 20.8% 20.7% 19.9% 19.8%Gross Surplus/(Deficit) (GWh)(5,226) (7,602) (7,954) (8,255) (8,421) (9,078) (9,490) (9,629) (10,252) (10,373)Volumes (Banked) or Withdrawn from Bank (GWh)5,226 7,602 4,696 0 0 0 0 0 0 0Net Surplus/(Deficit) (GWh)0 0(3,258) (8,255) (8,421) (9,078) (9,490) (9,629) (10,252) (10,373)Net RPS Positions (%)33.0% 33.0%28.8% 22.4% 22.2% 21.3% 20.8% 20.7% 19.9% 19.8%Cumulative Banked Volumes (GWh)12,299 4,696 0 0 0 0 0 0 0 0Forecast Failure Rate (%) for New Projects not yet online22.2% 22.3% 22.3% 22.4% 22.4% 22.5% 22.6% 22.7% 22.7% 22.7%Forecast Failure Rate (%) for Existing Generation0.1% 0.1% 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%00 047,983 71,759 88,48728.8%(3,600)3,600030.0%1.5% 1.2% 0.5%21,125 17,5250.6% 5.8% 21.7%Advice 4102-E September 7, 2012

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### As illustrated by the results of its Cu rrent Expected Need Scenario, PG&E’s existing RPS portfolio is exp ected to provide sufficient RPS-eligible deliveries to meet PG&E’s RPS compliance requirement s in the first compliance period. Additionally, PG&E expects to significan tly 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, pr ior to applying any excess procurement from earlier compliance periods, and thereaf ter 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, increasi ng 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 pa rt 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 purcha sing RPS-eligible power from SPI under standard offer QF ag reements, 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 Confiden tial Appendix A, it ha s 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 Existin g QFs included in this assessment of need is approximately equal to the Projec t’s anticipated deliver ies prior to 2017. 10 

### Therefore, the termination of the Ex isting QFs and commencement of the PPA has no material impact on PG&E’s RP S need through 20 16 due to the continuation of those historical volumes in this PPA. Begi nning in 2017, the AGFs are expected to deliver approxima tely 406 GWh per year when PG&E has

9 See Section 6, notes to Appendix 1, and A ppendix 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 Existi ng QFs is equal to appr oximately 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 treatm ent 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 modifi ed by D.08-04-023. In support of this Advice Letter, PG&E has provided th e 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 th e August 22, 2006, Administrative Law Judge’s Ruling Clarifyi ng Interim Procedur es for Complying with D.06-06-066 to de monstrate the confidentiality of the material and to invoke the protection of confidentia l 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 De claration Seeking Co nfidential Treatment is being filed concurrently with this Advice Letter.

Confidential Attachments :

Appendix A – Consistency with Commission Decision s and Rules and Project Development Status Appendix B – 2011 Solicitation Overview Appendix C1 – Independent Eval uator Report (Confidential) Appendix D – Contra ct Summary: SPI Appendix E – Comparison of the PPA to PG&E’s 2011 Pro Forma Power Purchase Agreement Appendix F – SPI Pow er Purchase Agreement Appendix G – Projects’ Contri butions Toward RPS Goals

Public Attachment

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

17 II. 

### Consistency with Commission Decisions

A. 

### RPS Procurement Plan

1. Identify the Commission d ecision 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 meet s utility procurement and portfolio needs (e.g. capacity, electrical energy, resource adequacy, or any other pr oduct resulting from the project).

4. Describe the project characteristics set forth in the solicitation, including th e 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 contract ed 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 in tended 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 re newable 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 Solic itation. The Project’s in cremental volumes commence in 2017 and will satisfy PG&E’s rene wable energy portfolio needs which are projected in the third compliance period and beyond. Furthermore, because the PPA is long term, and the Project satis fies the criteria of Portfolio Content Category One, any deliveries in excess of PG&E’s RPS compliance obligationAdvice 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 consiste nt 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-sta te resources delivering energy and capacity at a delivery point assigned by CAISO inside PG &E’s service territo ry. Each AGF is consistent with these preferences because the facilities will directly interconnect to the CAISO within PG&E’s service territory. Furt hermore, PG&E is entitled to all of the Project’s Contract Capacity, including Capacity Attr ibutes, to enable PG&E to meet its Resource Adequacy or successor program requirements, as the CPUC, CAISO or other regi onal 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 4 06 GWh per year in the thir d compliance period to fill a portion of PG&E’s projecte d 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 compar ed to the other bids submitted in the 2011 RFO and final shortlisted offers.

B. 

### Bilateral contractin g – 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 pr ocure 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 su bsequent solicitation. This section is not applicable becaus e the PPA resulted from PG&E’s 2011 RPS Solicitation.

C. 

### Least-Cost, Best-Fit (LCBF) Me thodology and Evaluation

1. Briefly describe IOU’s LCBF Methodology

2. Indicate when the IOU’s Shor tlist Report was approved by Energy DivisionAdvice 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 20 11 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 procur e the “least-cost best-fit” (“LCBF”) eligible renewable resources. 11 

### The LCBF decision directs the utilities to use certain criteria in their bid ranking 12 

### and offers guidance regarding the process by which the utility ranks bids in order to select or “shortlis t” the bids with which it will commence negotiations. PG&E’s approv ed process for iden tifying 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 Confid ential Appendix A.

1. Market Valuation

In a “mark-to-market analysis,” the presen t value of the bidder’s payment stream is compared with the presen t value of the product’s mark et value to determine the benefit (positive or negative) from the pr ocurement 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 offe r’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 Pr otocol and filed its initial 2011 RPS Shortlist Report on November 11, 2011.

In a subsequent supplemental filing da ted February 8, 2012 in Advice Letter 3938-E-A, 13 

### PG&E submitted an updated Shortlis t Report that enhances the valuation methodology to calculate a portfolio-adjusted value (“PAV”). The PAV intends to more accurately reflect th e value of renewable resources to PG&E customers. Specifically, the PAV method ology starts with net market value results, which reflect the value of a transa ction relative to market forward curves, as an initial quantitative valuation. Ad ditional 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 favor ably 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 cate gories: 1) Company / Development Team, 2) Technology, and 3) Development Mile stones. It is assessed by the CPUCdeveloped Project Viability Ca lculator (“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 rene wable project development.

PG&E’s analysis of Project Viability a nd 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”). Th e RPS Goals assessment considers nonquantitative factors, legislative findings an d declarations that increase California’s reliance on renewable energy, consistenc y with the CPUC’s Water Action Plan,

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

21 

### Executive Order S-06-06 which establishe d 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 deliver ed to PG&E’s customers is examined. Each bid is associated with a transmission cluster ba sed upon the location of the facility. If a CAISO interconnection study has been comple ted 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 th e 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 th e 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, pr ovide the specific page and section number where the RPS non-modifiable STCs are located in the contract.

3. Provide a redline of the co ntract 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 an d 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 modi fied by D.07-05-057 and D.07-11-025.Advice 4102-E September 7, 2012

22 

### These terms and conditions were comp iled and published in D.08-04-009. Additionally, the non-modifiable term relate d to Green Attributes was finalized in D.08-08-028 and the non-modifiable term s 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 co nditions 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 an d 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: Tracki ng of RECs in WREG IS 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 Cate gory Claim and Upfront Showing (D.11- 12-052, Ordering Paragraph 9)

1. Describe the contract’s clai med portfolio content category

2. Explain how the procurement pu rsuant 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 claimedAdvice 4102-E September 7, 2012

23 

### b. Contract is not classified as claimed

As described in Section I.E. and in furt her detail below, the PPA satisfies the upfront showing required for Portfolio Co ntent 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 ma ke an upfront showing related to the categorization of each propose d RPS procurement transac tion. Specifically, for approval of contracts meeting the criteri a 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 interc onnection with the WECC transmission system within the boundaries of a California balancing authority area. 14



### The Project meets the upfr ont showing required for Portfolio Content Category One because the AGFs are in-s tate RPS-eligible renewa ble energy resources that have or expect to have first points of interconnection with WECC transmission system with the CAISO, a California ba lancing authority. Therefore, the RPSeligible procurement from the Project sa tisfies the criteria for the Portfolio Content Category One adopted in D.11-12-052.

There is no known risk that the procurem ent would not be classified as Portfolio Content Category One.

The value of the PPA as described and a ssessed in this Advice Letter is based on the assumption that the procurement me ets 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 a pplicable portfolio balance requirements set fort h in Section 399.16(c)(2); and (ii) has excess procurement in that compliance peri od, D.12-06-038 would require RECs exceeding the portfolio balance requireme nts 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 Portfo lio Content Category One based on the relevant point of interconnection would be “straightforw ardly based on showing that the RPS-eligible generator has the applicable first point of interconnection.”)Advice 4102-E September 7, 2012

24 

### Minimum contracting requireme nts apply to short term contracts less than 10 years in length

1. Explain whether or not the prop osed 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 minimu m quantity requirement. If the requirement has not yet b een satisfied for the current year, explain how the utility expe cts to satisfy the quantity by the end of the year to co unt the proposed contract for compliance

. In D.12-06-038, the Commission determin ed that in order to count energy deliveries from short-term contracts to ward 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 requirem ent set forth in D.12-06-038. PG&E expects to be in complian ce with the long-term cont racting 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 fo rth 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-te rm pro forma contract.

This section is not applicable , as this is a long-term co ntact and thus not eligible for the “Fast Track” process.

H. 

### Market Price Referent (“MPR”) The actual price under the PPA is confid ential, market-sensitive information. However, the PPA price is below the 20-ye ar 2011 MPR for projects with a 2014Advice 4102-E September 7, 2012

25 

### commercial online date (“C OD”) adopted in Resolution E-4442 on December 1, 2011. Total cost information is di scussed in Confiden tial Appendix D.

I. 

### Interim Emissions Performance Standard

In D.07-01-039, the Commissi on 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 cont ract is subject to the EPS.

2. If the contract is subject to the EPS, discuss how the contract is in complia nce 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 th at the amount of substitute energy purchases from unspeci fied resources is limited such that total purchases und er 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 on ly 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 unavailabilit y for operational or efficiency reasons; orAdvice 4102-E September 7, 2012

26 

### d. the unspecified energy is only used to meet operating conditions requ ired 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 adop ted 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 resour ces and technologies are pre-approved as EPS-compliant.

“Based on the record in this proceeding, it is reas onable to make an upfront determination that the following renewa ble 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., ag ricultural and wood waste, landfill gas) using biomass that w ould otherwise be disposed of utilizing open burning, forest ac cumulation, landfill (uncontrolled, gas collection with flare, gas colle ction 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 provi ded through this Advice Letter, which has been served on the se rvice 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 co ntract 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, ex plain 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 Concer ned 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 meth odology to the PRG and explained how the methodology would a pply 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 in formation 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 ap plicable solicitation, the project/bid, and/or contract negotiations.

4. 

### Insert the public version of the project-specific IE Report. The IE, Arroyo Seco Consulting, review ed 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 find ings of the IE regarding the PPA are contained in Confidential Appendix C1 a nd 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 Lette r 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 develo pment 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 an d maintaining biomass co-generation facilities. In the last thir ty years SPI has constructed several biomass-fired boilers and steam turbine generation facilities ons ite of its saw mills in California and Washington. The facilities ar e also maintained and repa ired by SPI. SPI expects to build the Anderson II facility and no t 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: 145.2Advice 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 wh ether the developer has or plans to have a demons tration 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 hy brid technology.

All five of the AGFs use or will use biom ass-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 R ETI or the National Renewable Energy Lab (NREL) that supports resource quality claims and ab ility 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 itsAdvice 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 timberla nd 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 fu el resulting from fo rest 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 th e Existing QFs under standard offer QF agreements since the 1980s and 1990s us ing its own wood waste fuel. Based on SPI’s unique ability to self-provide ne arly 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 disc ussed above) necessary to the Project and the anticipated source of that supply;

b. Explain whether the developer has secured the necessary rights for wate r, fuel(s), and any other required inputs to run the Project.

c. Provide the estimated annu al 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 sulfurAdvice 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 du ring a year is expected to be small. SPI currently purchases natural gas fro m 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 am ount 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 exceptio n of Lincoln, where SPI pu rchases water for the boiler from the City of Lincoln. The Anderson II facility is being built on the same site as the existing Anderson f acility and will have access to the wells located there. The estimated water consumption associat ed 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-provi de 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 th at SPI will be able meet the terms of the PPA.

C. Development Milestones Four of the Project’s AGF’s are existi ng facilities. The fo llowing 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. ow nership, lease, BLM Rightof-Way grant, etc.)

i. If lease, describe duration of site control and any exercisable extension optionsAdvice 4102-E September 7, 2012

32 

### ii. Level or percent of site control attained – if less than 100%, discu ss seller’s plan for obtaining full site control SPI has full site control by ownershi p 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 orde red 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 or dered, substantial deposits have been made and its components are being cons tructed. Initial deliveries of boiler components are scheduled to commence in September, 2012. A Purchase Order (“PO”) has been issued for the transforme r and it is being built. POs have been issued for all other major components (e lectrostatic precipitator, cooling tower, etc.).

In the last thirty years SPI has construc ted several biomass-fired boilers and steam turbine generation facilities onsite of its sa w mills in California and Washington. The facilities are also maintained and repair ed by SPI. Based on this experience, SPI has a strong track record of procuring equipment.

3. Permitting / Certifications StatusAdvice 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 de scribe the status of all major permits or authorizations necessary for development and operation of the Project, including, without limitat ion, CEC authorizations, air permits, certificates of public convenience and necessity (CPCN) or permit s to construct (PTC) for transmission, distribution, or substation construction/ expansion, la nd use permits, building permits, water use or di scharge authorizations, Federal Aviation Administ ration authorizations, military authorizat ions, 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-cer tified 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 oper ation 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 ApprovedAdvice 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 purs uing 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 ta x credits/funding are not obtained.

SPI plans to claim a Grant in Lieu of Cred its 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 Pr oject is in the CAISO or any other interconnect ion queue, and whichAdvice 4102-E September 7, 2012

35 

### transmission studies are complete and/or in
progress.
b. Discuss the status of the Interconnection Agreement with the inte rconnecting 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 pro cess for all transmissionrelated upgrades. Identify critical path items and potential contingencies in the event of delays

f. Explain any issues relati ng to other generating facility projects in the tran smission queue as they may affect the Project.

g. If the Project is dependent on transmission that is likely to be congested at ti mes, leading to a product that is less than 100% deliverable for at least several years, explain ho w 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 arrange ments 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 fi nancing, 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 (b oth 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 hist ory of ability to procure financing.

7. Describe any plans for obtainin g subsidies, grants, or any other third party monetary awards (other than Production Tax Credits and In vestment Tax Credits) and discuss how the lack of any of this funding will affect the Project.

SPI expects to use tax exempt pollutio n control financing from the California Pollution Control Finance Authority (“CP CFA”) 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 ot her projects similar to the Anderson II project.

SPI has not received any gover nment funding or awards. SP I 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 ob tain the cash grant.

Additional financing inform ation is provided in Co nfidential Appendix A.

IV. 

### Contingencies and/or Milestones Describe major performance criter ia and guaranteed milestones, including those outside the cont rol of the parties, including transmission upgrades, financin g, 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 C onfidential 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 pursu ant to the PPA is procurement from eligible renewable energy resour ces for purposes of determining PG&E’s compliance with any obliga tion that it may have to procure eligible renewable energy resour ces 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 ad ministrative costs, as provided by Public Utilities Code s ection 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 PP A 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 au thorize 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 me eting 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 Lette r filing.

7. Adopts a finding of fact and conc lusion of law that deliveries from the PPA shall be categorized as procur ement under the po rtfolio 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 conclu sion of law that, to the extent the Anderson II facility receives all nece ssary 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 counte d 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 fro m the date of this filing. The protest must state the grounds upon which it is ba sed, including such items as financial and service impact, and should be subm itted expeditiously. Protes ts should be mailed to:

CPUC Energy Division Attention: Tariff Unit, 4 th 

### Floor 505 Van Ness Avenue San Francisco, California 94102Advice 4102-E September 7, 2012

39 

### Facsimile: (415) 703-2200 E-mail: EDTariffUnit@cpuc.ca.gov

Copies should also be maile d to the attention of the Director, Energy Division, Room 4004, at the address shown above.

The protest also should be se nt 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 i ssue a resolution approving this advice filing no later than early March, 2013.

Notice :

In accordance with General Order 96-B, Sec tion 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 lis t and the service lists for R.11-05-005, and R.12-03-014. Non-ma rket participants who are members of PG&E’s Procurement Review Group and have signed appropriate Non-Disclosure Certificates will also receive the Ad vice Letter and accompanying confidential attachments by overnight mail. Addre ss changes to the General Order 96-B service list should be directed to PGETariffs@pge.com . For changes to any otherAdvice 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 mark ed Confidential Protected Material are submitted under the confidentia lity 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 o f, among other items, the Amendment itself, price information, and analysis of th e 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 Decision s and Rules and Project Development Status Appendix B – 2011 Solicitation Overview Appendix C1 – Independent Eval uator Report (Confidential) Appendix D – Contra ct Summary: SPI Appendix E – Comparison of the PPA to PG&E’s 2011 Pro Forma Power Purchase Agreement Appendix F – SPI Pow er Purchase Agreement Appendix G – Projects’ Contri butions Toward RPS GoalsAdvice 4102-E September 7, 2012

41 

### Public Attachment

Appendix C2 – Independent Ev aluator 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 an d Pacific Gas and Electric Company Keywords (choose from CPUC lis ting): Agreements, Procurement AL filing type:  Monthly  Quarterly  Annual  One-Time  Other _____________________________ If AL filed in compliance with a Commission order, indicate relevant Deci sion/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 trea tment 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 Revi ew Group who have signed nondisclosure agreements will receive the confidential information. Name(s) and contact information of the person(s) who w ill 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 re venue 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

# PACIF IC GAS AND ELECTRIC COMPANY 2011 RENEWABLE POWER SOLICITATION

REPORT OF THE INDEPE NDENT 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 G2



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

EXECUTIVE SUMMARY

................................ ................................ ................................ ............. 3 1. ROLE OF THE IN DEPENDENT EVALUATOR

................................ ............................ 4 2

. ADEQUACY OF OUTREACH TO PARTICIPANTS AND ROBUSTNESS OF SOLICITATION

................................ ................................ ................................ ....................... 8 3

. FAIRNESS OF OFFER EV ALUATION AND SELECTI ON METHODOLOGY

. 1 5 4

. FAIRNESS OF HOW PG&E ADMINISTERED THE OFF ER EVALUATION AND SELECTIO N PROCESS

................................ ................................ ............................ 36 5. FAIRNESS OF PROJ ECT

- SPECIFIC NEGOTIATION S

................................ ............. 49 6. MERIT FOR CPUC A PPROVAL

................................ ................................ ......................... 633



# 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 execu ted a Power Purchase Agreement (PPA) wit h Sierra Pacific Industries (“SPI ”) for the output of five generation projects fueled with woody waste biomass

. The PPA covers delivery fro m 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 portf olio will provide 58 MW of contract capacity.

PG&E and SPI initiated bilateral discussions about a new aggregate d RPS contract to replace the existing QF contracts in late 2010 . In June 2011 PG &E terminated those discussions, asking SPI to offer its proje cts 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

. N egotiations resulted in a PPA executed on August 9, 2012. An independent evalua tor (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 t he 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 . T he 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 CPU C approval, based on an independently developed opinion that the contract ranks high in net valuation and low in contract p rice; Arroyo regards the portfolio fit of the SPI projects with PG&E's supply needs as moderate , and the project viability of the fou r 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 Offer s (RFO) on May 11, 2011 , a competitive solicitation for power generation that qualifies as eligible renewable energy resources (ERR s ) under the California Renewable s Portfoli o 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

. Thi s chapter elaborate s on the prior CPUC decisions that form the basis fo r an Independent Evaluator’s participation in the 2011 RPS RFO and in bilaterally negotiated contracts for RPS

- eligible energy

, describes key role s of the IE, details activities underta ken by the IE in this solicitation to fulfill those roles , and identifies the treatment of confidential information.

A

. C PUC D ECISIONS R EQUIRING I NDEPEND ENT E VALUATOR P ARTICIPATION

The CPUC first mandat ed a requirement for an independent, third

- party eval uator to participate in competitive solicitations for u tility power procurement in Decision 04

- 12

- 048 on December 16, 2004 (Findings of Fact 94

- 95, Ordering Paragraph 28)

. T he CPUC requir ed use of an IE when P articipants in a competitive procurement solic itation 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 anti

competitive conduct in the process of evaluating IOU

- bu ilt or IOU

- affiliate d 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, 2 006. This Decision expanded the CPUC’s r equirement s , ordering that each IOU use an IE to evaluate and report on the entire solicitation, evaluation, and selection
proces s, for the 2006 RPS RFO and future competitive solicitations. This requirement now applies whether or not IOU

- owned or IOU

- aff iliate 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.

Decisi on 06

- 05

- 039 required th e IE to report separat ely from the utility on the bid solicitation, evaluation, and selection process. Based on that Decision, t he 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 t hen 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 lett er or letters for approval of contracts with the selected Offers.

B

. KEY I N DEPENDENT EVALUATOR R OLES

To comply with the requirements ordered by the CPUC, PG&E retained Arroyo Seco Consulting to serve as IE for the 2011 competitive solicit ation for renewab le resources

, providing an independent evaluation of the utility’s O ffer 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 specif

ically, the Energy Division of the CPUC has provided a template to guide how IEs should report on the 2011 RPS c ompetitive pro curement process, outlining f our 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 ?

 Wa s the IOU’s LCBF methodology designed such that bid s were fairly evaluated ?

 Wa s the LCBF bid ev a luation 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 A CTIVITIES

To ful fill 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

.

 Examin ed the utility’s nonpublic proto cols detailing how PG&E would evaluate Offers against various criter ia

.

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

, and how that information was distributed.

 R eviewed the list of registered attendees of the Bidders’ Conference against PG&E’ s
master list of RFO contacts ( u sed for outreach to potential P articipants).

3 CPU C 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 in

person to conference attendees was al so provided to other potential P articipants.

 Examin ed PG&E’s 2011 RFO maste r contact list; performed an analysis of co ntacts with respect to industry and technology representation

.

 Interviewed members of PG&E’s evaluation committee regarding details of the 2011 version o f the utility’s LCBF methodology and its inputs

. During the period be tween 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 bu ilt a database for tracking Offers.

 Read ing 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 inde pendent 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. I t was much simpler and lacked detail and granularity used in the PG&E model. However, the indepe ndent valuation was useful for testing the PG&E team’s ra nking of Offers using alternat e assumptions.

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

.

 Scoring O ffer s independently for viability , using the ED’s 2011 version o f 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 s coring of Offer s 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 c ommittee , as it made decisions about the logic for selecting a short lis t and approved proposed selection s 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 a n independent commentary and observations abou t the RFO

.7

 Offer ing 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 sessio ns between utility staff and SPI ’s commercial team ;

 Reviewed draft term sheets, draft contract s, and other documents passed between the parties;

 Performed an independ ent 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 contrac t to peer groups consisting of alternative proposals available to PG&E.

D

. T REATMENT OF C ONFID ENTIAL I NFORMATION

The CPUC’s Decision 06

- 06

- 066 detailed guidelines for treating confidential information in IOU power procurement and related activitie s , inclu ding c ompetitive solicitations

. T he 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 project s 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 E AC H T O PA RT I C I PA N T S A N D RO B U S T 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 g oal of procuring 1 to 2% of retail load by selecting Offers that will lead to nego tiated 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 solici tation may be judged robust enough to be competitive.

A. CLARITY AND CONCISION OF SOLICITATION MATE RIALS

While not real ly 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 provide d clear and comprehensible direction to P articipants on how to prepare and submit complete O ffer packages that could be accepted and evaluated. Arroyo has a few observations about the clarity of t he gu idance provided in the
pr otocol and issues created when P articipants failed to understand or follow that guidance:

 Most Offers were submitted as complete and conforming packages. C ommo n deficiencies in other O ffers included:

1. F ailure to submit the of f er form (Attachment D) for all O ffer variants or phases ;

2. E rror s in filling in the offer form

, such as missing data , incomplete project description, or incomplete self

- scored Project Viability Calculator ;

3. U se of a earlier draft version of Attachment D fr om 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. F ailure to provide the text and d ata of the Offer in the requested Microsoft Word 2003 and Excel 2003 formats (as opposed to later versions or to Acrobat .pdf files);

5. C orrupted data files;

6. F ailure 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 h ad 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; and9 8. In the case of projects outside California and not directly i nterconnecting to the CAISO , failure to specify how power would be delivered to a CAISO intertie point with a firm schedule , or what arrangem ents 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 P articipants neglected to pay attention to thes e small but important details. S endin g deficiency letters to P articipants who failed to provi de required infor mation 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 th e RFO materials th at might have reduced the incidence of such P articip ant 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 resource s , over projects whos e output will be considered renewable energy credits ( RECs) for RPS compliance purposes ;

2. P rojects that deliver to CAISO nodes within the PG&E service territ ory, as opposed to the territories of other utilities (CAISO or otherwise) or t o an inter face point at the boundary of the CAISO;

3. P rojects that contribute to PG&E’s Resource Adequacy (RA) requirements, such as CAISO

- interconnected projects with full deliverability, as opposed to energy

only 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 f

or RPS

- eligible energy in 2014 and 2015

. 4

Based on comments provided in feedback sessions after the RFO, i t appe ared 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 recomme nds that in the future PG&E should edit the protocol to clarify that these specific preferences can play a n important role in selection, even though they ar e not among the evaluation criteria. This would improve the transparency of the selection process to P articipants.

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 P articipants after the RFO suggest that sev eral developers did not understa nd 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 prov

ided by the ED are broadly misunderstood or misinterpreted

. Several Participants did not or chose not to understand that th e Calculator wa s 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 projec ts of the same technology and similar or la rger MW capacity than that proposed. Some Participants coul d have improved their scores if they had read the guidelines more carefully and chos en 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 o n 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 materi al that PG&E need s to provide in its protocol, it is not surprising that it exceeds fifty p ages. Arroyo cannot identify any straightforward way to make the protocol more concise; the material provided is generally neede d to provide P articipants with a full and transparent view of how the solicitation will function and with full disclosure about obligatio ns and constraints that govern P articipants 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 u tility solicited feedback from non

- shortlisted P articipants 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 instruc tions 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 reques ted 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 solic itation materials were clear, if not particularly concise , and that improvement opportunities to help ensure that more complete O ffer 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 protoc ol’s lack of transparency about Offers for sites for development, described in the next chapter.11 B. ADEQUACY OF OUTR EACH

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 techn ologies?

 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 publicizin g 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 b een actively compi ling 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 ren ewable 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 whet her 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, new s 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 attachm ents, the schedule, and other informational items were posted on PG&E’s public website.

Figure 1 . Breakdown of contact list by sector12

Arroyo notes that news of P G&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 th e Geothermal Resources Council and the Nation al R enewable Energy Laboratory.

Another indicator of the adequacy of outreach for the RFO was the response of attendees for th e 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 represent s a very strong response and expression of industry interest, and is an increase of about 70% over the registration for the 20 09 RPS RFO bidders’ conference

. The largest share of attende es 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 indicatio n 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 t o 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 s olicitation 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 Figur e 2. Breakdown of re gistration for bidders’ conference

C . ROBUSTNESS OF TH E 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 e n ough 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 w ith respect to technologies?

 Was the distr

ibution 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 total ed an immense volume of p rojected 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 resp onse by more than 80%. This ratio of offered volume to targeted procurement volume reflects a remarkably healthy and robust response. M ore 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 for14

projects using technolog

ies 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 s taff 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

we ll

- 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 PARTIC IPANTS

After receiving notification that thei r Offers had been rejected, s everal of the non

shortlisted Participants expressed an interest in follow

- up discussion s 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 w hich 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 the ir 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 t he 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 suggestion s 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 P roject Viability Ca lculator guidelines are applied would be helpful; many Participants disagreed with the Calculator ’s design because they felt their Offers were u nfairly 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

. F A I R N E S S O F O FFER E VA L UAT I O N A N D S E L E C T I O N

M E T H O D O L O G Y

The key f inding of this chapter is that PG&E’s evaluation and selection methodology for ident ifying 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 weak nesses , and identifies some specific issues with the

m ethodology and its inputs that Arroyo recommends be addressed in future solicitations.

A. P RINCIPLES F OR E VALUATING T HE M ETHOD OLOGY

The Energy Division o f the CPUC has usefully suggested a set of principles for evaluating the process used by IOUs for selecting Offers in compet itive renewable solicitations, within the template intended for use by IEs in reporting. The se include:

 The IOU bid evaluation should be based only on information submitted in bid proposal documents.

 There should be no consideration of any information t hat 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 us ed 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, i n

- service dates, and contract length.

Some additional consi derations appear relevant to PG&E’s specific situation

. Unlike some utilities, PG&E does not rely on weighted

- average ca lculations of scores for evaluation criteria to arrive at a total aggregate score

. Instead, the t eam ranks Offers by net ma rket 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 applicat ion of judgment in bringing the non

- valuation criteria to bear on

5 Pacific 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 methodol ogy 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 high er

- value Offers and sele ct low er

- value Offers should be applied consistently and without bias.

 The valuation methodology should be reasonably consistent with industry practices

.

B . PG&E’S L EAST

- C OST B EST

- F IT M ETHOD OLOGY

The California legislation that mandated the RPS program re quired that the procurem ent 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 ren ewable resources. PG&E adopted Offer selection and evaluation process es and criteria for its 2011 RPS RFO. These are summari zed in Section XI of PG&E’s 2011 Solicitation Protocol for its renewable solicitation, and d etailed in its Attachment K

. Additionally, PG&E developed non

- public docume nts for internal use that detail the protocols for each individual criterion used in the evaluation process. These include :

 Market valuation

 Portfolio fit

 Project viabil ity

 RPS goals

 Adjustment for t ransmission 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 proto col states two other criteria: the materiality and c ost 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 t hat 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 method ology briefly and at a high lev el; readers are referred to PG&E’s 2011 RPS Solicitation Protocol and its Attachment K for a full er 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 A dequacy); 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 p rotoc ol. TOD factors serve as multi plier s 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 trans mission adders. The cost s of integrating a n 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 th e entir e 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 proje cted hourly generation specified by the Offer’s generation profile. For dispatchable Offer s, the protocol uses a real

- option pricing model to measure energy bene fit.

PG&E develops an outlook for the value of Resource Adequacy capacity as a time series

o f nominal dollar per kilowatt

- year estimate s

. The CPUC established specific guidelines for estimating RA capacity

. 6 Al so, the CPUC decided to base Net Qualifying Capacity on a 70% exceedance level for solar and wind resources whose output is stochastic i n nature, in a calculation that takes into account diversity benefits of multiple individual generators with different profiles. In 2011, t he 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 empl oyed a quantitative scoring system to assess the port folio 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 nee ds). 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

en ter full commercial operation by the proposed on

- line date. The CPUC suggested that the Calculator i s 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 Refinin g the Resource Adequacy Program”, June 18, 2009.18

selection decisions. 7 PG&E w as also willing to use its b usiness judgment in assessing the relative viability of projects rather than relying solely on Calc ulator 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,

 Manufacturi ng supply chain (e.g. constraints upon availability of key components),

 Site control,

 Permitting status,

 Proj ect financing status,

 Interconnection progress,

 Transmission requirements, and

 Reasonableness of Commercial Operation Date (COD).

The Energy Division provided a set of scoring guidelines f or 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 ser

ve as a g uide to developers on how projects will be assessed by IOU s

.

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 admin istration of the met hodology

.

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, p age 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 CP UC 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 clear ly 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 CPU C’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 t he 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 bioma ss. 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 Di sabled Veteran

- owned Business Enterprises (WMDVBEs)

. In the 2011 RPS RFO PG&E asked Participants t o submit a completed Supplier Diversity Questionnaire with information on the Participant’s WMDVBE status, its intent to subcontract with diverse entities, a nd 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 PP As a contractual requi rement to make good

- faith efforts towards a contracted supplier diversity ta rget , and to report annual pay ments to diverse subcontractors. In Attachment L it requested Participants to specify the percentage of sub contracting 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. T he methodology takes into account the need to upgrade the transmission network in order to acc ommodate 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 h as been completed, the team generally use s 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 i ts Offer package, as was requir ed).

PG&E takes into accou nt 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 Particip ants to achieve full capacity inter connections in the RFO, Off ers that proposed
energy

- only interconnections were not credited with any Resource Adequacy value.20

The Solicitation Protocol and its A ttachment K lay out the analysis requi red to allocate

networ k 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.

Th is 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 scheduli ng arrangement for the CAISO to manage delivery

, despite a project’s interconnection in a non

CAISO balancing authority area.

UTILITY OWNERSHIP ALTERNATIVES AND SITES FOR DEVELOPMENT

PG&E develo ped protocols for evaluating Offers proposing to sell the util ity a site for deve lopment of renewable generation or to build a facility and transfer it t o 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 owner ship 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 v ery 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 sa le or site lease is preferred, or any other requirements or preferences the utility applies when it evaluate s proposed sites for development. In the actual event these Offers were evaluated based on criteria that were absent from both the public and non

- p ublic 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 so licitation protocol, PG&E stated explicitly that it will consider its total exposure to volume of contracted deliveries from any individual counterparty and the volume alr eady contracted with that party in making selection decisions. Arroyo regards suppli er 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 developmen t failure.

This year, PG&E made an effort to avoid the prior practice s 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 i n different part

- owners for different groups of projects. Other developers submitted multiple Offers for projects owned by differen t subsidiaries or initially owned by other21

developers while retaining an option to purchase the project if successful. Overall, these tactic s used to avoid PG&E’s stated limitation do not appear to have benefited those developers at all, but it created ex c ess 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 solici tation 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 statu s 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 inter face points (e.g. the Ca lifornia

- 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 Irriga tion 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 reg ards this as a reasonable preference, and appropriat e 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 tha t interconnect into PG&E’s grid can have other benefits to the utility and its ratepayers, such as enhancing local voltage suppo rt. 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 te rritory rather than i n 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 concern s

. A third area where PG&E’s solicitation prot ocol does not quite express a preference or

a n 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 Agreemen t 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 si tuation 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 lar ger 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 who se 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 f

or PG&E to consider in deciding which Offers to select or reject for its short list, Arroyo is concern ed 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 inte rconnecting 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
per iod ” as stated in the bidders’ conference presentation. It appears, based on debriefings aft er the RFO’s close , that several Participants missed that point and assumed that Offers with earlier on

- line dates were p referred, as had previously been the case in PG&E’s 2009 RPS RFO

. Arroyo speculat es that some Participants could have improved the attrac tiveness 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 valuat ion, 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 offer s 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 informa tion 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

. S TRENGTHS AND W EAKNESSES OF PG&E ’S M ETHOD OLOGY

PG&E’s ev aluation 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. I t has thus achieved a certain degree of refinement th at has strengthened the process from the perspective of fairness and reasonableness.

1. MARKET VALUATION23

General strengths and weaknesses. PG&E’s valuation methodology has several advantages over methods used by other utilities:

 It is rooted in a compari son 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 utili ty 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 un it 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 market s are not liquid and transparent beyond a limited time horiz on, PPAs that last for up to 25 years must rely on extrapolation o f mark et 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 function ing, 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 a ssigned 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, s ometimes 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

- li ne 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 f lexibility 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 multiplier s 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 estimat ed net value of each Offer, in t he 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 ratepa yers 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 pri ces 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 c ontract 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 review s 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 area s 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 terri tory

. 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 component s 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 t he price of increas ingly 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 . T his 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 cost s 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 CAIS O, using proxy costs from TRCRs or estimates of network upgrade costs fr om 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 ar e ultimately borne by transmis sion 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 th an fully fair to d evelopers 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 tha t are entirely or partially located within California

. While Arroyo acknowledges that PG&E’s ratepayers will not directly bear the costs of network upgrade s in these other BAAs, the California ratepay ers served directly by these balancing authoritie s 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 transmit ting the project’s output to th e 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 cost s 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 ap proach 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

- spe cific attributes, and is objective in its development wit h 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 greates t needs for new RPS procurement, an important consideration for compliance strategy.

The re 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 appea r to have as much impact as others such as market valuation, project viability, and R PS 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 cu rrent understanding of its generation need for ea ch compliance period under SB X 2. Arroyo has almost no visibility into how PG&E calculates its net short position of RPS

eligible energy procurement vs. RPS goals i n the three compliance periods and can ther efore have no opinion about whether that calculation was reasonable. T o the extent informat ion was made available to the utility’s Procurement Review Group, it appea rs that the portfolio fit methodology aligns well with times when PG&E expects more procur ement 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 likelih ood 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 projec t size; it does not consider extrinsic variables such as MW capacity or GWh volume as positive or negative factor s but rather reduces the value of the Offer to a normalized $/MWh metric. To the extent project size has an impa ct on valuation , it reveals it self in the proposed contract price if the technology is one that provides economies of scale and enable s developers to propose lower prices for larger projects.

The viability scoring system, however, is not neutral to proje ct size. T he 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 fai led to appreciate that proposing new projects much larger than any they had27

previously brought into operation will lower their viability score using the Energy Division’s Project Viability Calculator. Other developers with deep experience in developing la rge 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 exp erience.

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, combine d 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 wo uld be the opposite of pursu ing resource diversity. The RFO Goals criterion gives PG&E the basis for pref

erring to select multiple smaller Offe rs rather than a very few large projects , in pursuit of greater resource diversity

. This tradeoff between the c riteria 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 cu rrent inputs, exhibits a propensity to favor projects that start later ra ther than earlier, all else being equal (this is related to inputs about forward prices, capacity value, and discount rate). It is a mod est 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 ran ked high for net value and project viability, the process is not designed to p rovide 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 off ered in

- service dates that close ly match the compliance periods when the utility has the largest net short position, which would be coincid ental if it occurred. Ins tead, 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 other s have substantially earlier or far later in

service dates and don’t necessarily fit well with compliance periods of the greatest need.

Similarly, PG&E’s methodology is not designed to con struct a short list with the highest value to ratepayers while meeting the utility’s RPS compliance needs. Such an alternative approach would necessarily disregard th e project viability criterion by select ing the highest valued Offers with in

- service date s 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 tha t proposed attractive on

- line dates but failed to achieve timely commercial operati on because of viability issues . PG&E’s methodology is desig ned to scre en out high

- valued projects that fit well with compliance period needs if they28

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 bein g 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 cost s 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 deliverabilit y for new generation

. Many features of the transmission cost methodology are specified by regulatory decision s

. 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 te rritory 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 m ethodology also has some drawbacks:

 The process of estimating transmission adders is analytically burdensome. It requires checking of Participant’s info rmation by transmission experts and consumes a considerable po rtion of the total time for valuation analysis.

 TRCR adders are a generalized, regional proxy for the actual cost of a particular

sized project at a particular interconnection point. There can be rather large deviations between the final cost of network u pgrades written into an in terconnection agreement and an early T RCR 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 ava ilable 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 proj ect had obtained a system impact study or facilities study or29 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 h ave 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 n ew capacity is so large that Phase I estimates of work re quired 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 few er n ew projects moving through the Phase II study to result in much smaller estimates of network upgrade costs. In these situ ations, the methodology disadvantage s projects that have received a Phase I study but not yet a Phase II study, even though the analys is in hand is the best currently available estimate of project

- specific upgrade requirements. This see ms less than fully fair to some projects caught in that early stage of analysis.

Whether the transmission adder methodology relies more on TRCR proxy add ers 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 upgrad es and deliverability network upgrades. In sit uations 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 an d 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 an d 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 attr ibutes 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 consis tent 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 pro vided 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 transmis sion 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 VIABILITY30

The i mplementation of the Project Viability Calculator as a screening tool for use in the evalu ation 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 Calc ulator 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 sin gle

- 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 Calcu lator.

 Some of t he scoring guidelines for the Calculator are sufficiently ambiguous that reasonable individuals scoring the same project can ar rive at different results. When the scores rated by Arroyo and the PG&E team were compare d, 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 di screpancies between individuals’ practices. This suggests that the Calculator is still a crude sc reening 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 select ing one and rejecting the other

, because the difference falls within the error of th e 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 sc oring 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 on

staff 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 t hough 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 C alculator to evalu ate Offers for REC s 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 i s 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 conform ance 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 o rder to confirm the qua lity and consistency of the assessments

.

I n some cases factors not assessed by the Calculato r 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 b ias 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.

T he 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 develo ping, 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 widesp read 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 util ity 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 bas eload vs. peaking or intermittent g eneration in selecting Offers. T o the extent some technologies are operated as baseload in the32

California market and there is a resource need for baseload resources this may tilt Offer selection towards those projects ov er 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 b e managed through a pseudo

- tie or dynamic scheduling. There are only a very few projects to date where th ese have been implemented by the CAISO . Because such approaches require the assent of both the CAISO and the foreign balancing area authority to whic h 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 h ow 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 ho pes that more experience with dynamic scheduling will make it clearer what can and cannot be achieved with these

ar rangements 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 accommoda te long

- term dedication of that capability to IOUs, putting at risk the delivery of RA value . S imply 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 val ue 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.

Participant s’ v

iewpoints on strengths and weak nesses. Feedback from Participants provided some insight into other strengths of PG&E’s approach compared to other utilities ’

.

 The bidders’ con ference was cited as being “very helpful ” by several Participants, in clarify ing objectives, evaluation process, and requirements. The ability to ask questions and to obtain answers quickly and spontaneously was cited as useful.

 The solicitation mater ials were regarded as clear, straightforward

, and “user

friendly”, with the excep tion 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 p ursued appr oaches (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 un derstand how the scoring guidelines in the Project Viability Calculator were intended to be used and were frustrated that their33 early

- stage projects were disfavored by the design of the Calculator , others expressed opinion s that the Calculator was “fair an d 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 provide d 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. The y suggested that PG&E erect higher barriers to participati on by “non

- serious” parties

, such a s 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 P articipants 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 w ith 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 score s 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 CAI SO 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 exe cuted interconnection agreement that will serve as the basis for estimating a transmission adder for network upgrades;

 Revisi ng the solicitation materials to clarify that, in addition to the various evaluation criteria, PG&E will use its preferences regarding d elivery 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 comple tely failed to notice this ;

 Editing the both the public and non

- public solicitation protocol s to prov ide a fuller description of h ow Offers for sites for development will be evaluated, what the basic requirements for eligibility are, what specific evaluati on criteria will be used, and what cha racteristics 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 ab out 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 stil l 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 req uires 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 o f seeking such information after short

- listing.

IMPROVING VALUATION INPUTS

Arroyo has suggestions for improving the m ethodology 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 th at 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 t he 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

cost s is materially higher than that embedded in the cu rrently 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 value35 of RA capacity, and that this tends to create disto rtions 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 a n 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 estimate s.

 Develop LMP multipliers for CAISO interconnection points at the peri phery of the balancing authority area, such as Four Corners, Moenkopi, Mead, and the Hassayampa

- North Gila line , so that energy from p rojects 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, A rroyo perceives it as unlikely that the CAISO could or wo uld 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 pse udo

- 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 proj ects that interconnect within California but outside the CAISO grid. T he practice of evaluating full costs for some projects but PPA costs only (omitting the impact on transmission rates) for other California pro jects seems inconsistent and less than full y 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 R N 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 admin istration of its protocols for O ffer evalu ation and selection in the 2011 RPS solicitation was conducted fairly. Arroyo’s overall conclusion is that the process was conducted in a f air and generally consistent

manner

. Arroyo disagreed with PG&E about the length of its short list

. This chapter d iscusses 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 IE s in determining if an IOU’s administration of its evaluati on 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 para meters)?

 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 be ar on decision

- making, rather than a mathematical, objective means of doing so, implies an opportun ity to test the fairness of administration using additional principles:

 We re 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, wha t factors prevented those pr ojects from being selected? W as 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?

 We re th e 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 s ubmittal?

B. REVIEW ING PG&E’S ADMINISTR ATION OF ITS EVALUAT ION AND SELECT ION
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 Offer s

. Ar royo also had copies of all Offers and of c orrespondence between PG&E and P articipants during this period, and was able to mak e independent opinion s about the strengths and weakness of individual Offers against the evaluation criteri a laid out in PG& E’s protocols

. Arroyo was present at evaluation team and steering committee meetings in which draft
p roposals for the short list of O ffers were developed, reviewed, questioned, modified, argued, and finalized. The logic and priorities underlying why speci fic O ffers were rejected and accepted to the short list were made evident in these sessions. Arroyo had access to

m embers of the evaluation team responsible for scoring the O ffers against each of the evaluatio n criteria. Arroyo was able to question decis ions that appeared unfair or inconsistent from an independent perspective

.

Additional elements of Arro yo ’s approach for evaluating the fairness of the evaluation and selection process include:

 Building an independent valuation model that directly used det a iled 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 selec tion 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 ), ide ntifying the root cause for variances, and determining whether vari ances were justified by different inputs and methodology or s temmed from errors by either PG&E or Arroyo ;

 Auditing communications between P G&E and Participants to check whether any individual Participant was advantaged by requests posed or information prov ided;

 Reviewing in detail and discussing PG&E’s decisions to reject Offers for nonconformanc e with the requirements of the solicitation p rotocol;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 review ing 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 REJE CTION OF OFFERS FOR NONCONFOR MANCE 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 addi tional information from Participants and to assess which Offers deviated from the requirem ents of the solicitation protocol. Most Participants whose Offers were identified as deficient were able and willing to address the missing information. A few did n ot.

Fif teen Offers were rejec ted 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 s ome Offers and varian ts 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

- of

state 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 t ha n 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

- 0 1

- 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 purpos es of RPS compliance.

Similarly, some variants were rejected because they failed to c onform to another requirement stated in the protocol for PSAs : “ The Project and transmission interconnection must be designed and constructed in conformance with Californ ia 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 n on

- 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 own ership (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 pro ject 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. Ot her 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.

I n the days immediately following Offer Opening, some Participant s 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 addre ss 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 nonconf orming were fair to Participants . There were Offers that were very clearly nonconforming based on explicit deficiencies from the requirements clearly

st ated 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 Par ticipants 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 t he proposals

. However, none of these accepted Offers from the gray are a were selected given their ran kings for value and viability

. Another gray area that troubl es Arroyo is the failure of several Participants to submit the required Attachment L, PG&E’s supplier diversity questionnaire. As descr ibed below, it appears that some Participants did not take t he 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 Part icipant to correct the deficiency but the Participant fails to do so.

D. REASONABLENESS AND FAIRNESS OF PARAMETERS AND IN PUTS

The vast majority of the many para meters and inputs that PG&E used in its evaluation of the 2011 RPS RFO Offers were reasonably a nd fairly chosen , in Arroyo’s opinion

. Arroyo identified only one issue regarding the choices PG&E made about parameters and inputs that merit s discussion.40

PG&E used a discount rate of 7.6% to bring future Offer costs and benefits to a 20 11 present value. This value is based on PG&E’s app roved 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 d iscount rate for net revenues from PPAs with renewable generation developers

. The se 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 d ebt for the riskier IPP sector are both higher than for regulated utilities. F or example

, the cost of d ebt assumed into the Energy Division’s 2009 analysis of the Market Price Referent (MPR)

, an analysis that represents the risks of an IPP developer bui lding a proxy plant under a long

term PPA

, was 7.67 % compared to PG&E’s authorized 6.05%, and the assumed c ost of
eq uity underlying the proxy developer was 11.96 % vs. PG&E’s authorized 11.35%.

Arroyo asserts that the flow of net benefits of power deliver ies from independent power companie s 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 as sociated with the IPP industry . That suggests that the appropriate W ACC to be used when evaluating O ffers 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 tha t overstate the importance of the most d istant years of contract term , when the methodology depends on extrapolated market forward prices. Arroyo views thi s as a distortion that skews PG&E’s value rankings to wards preferring long

- dated PPAs, and project s with later on

- line dates

. In particular , the low er discount rate tends to overemphasize the value of Resource Adequacy.

PG&E has a variety of internal contr ols in place to ensure that se lection of inputs is reasonable and fair. The Energy Supply organization relies on a separate and independen t 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 r eview 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 outsource d a portion of the analysis of transmission adders to an external consultant. A n inte rnal PG&E transmiss ion expert oversaw the work and perfor med 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 A ND INTEGRATION COSTS

PG&E generally followed its transmission analysis protocols in administering its procedures for marke t valuation. The team used TRCR proxy costs from the three41

California IOUs or data from Phase I or Phase II interconnection studies o r 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 s uccess 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 w as performed. B oth 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 estim ated for projects that interconnect within California but outside the CAISO’s balancing authority area, using the estimates of network upgrade c osts provided in those other PTO ’s interconnection studies. Arroyo considers the valuations of these PPAs

to un derstate 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 out side the main body of the BAA presents a gap in data inputs. P rojects that propose to interconnect to these po ints are unfairly advantaged vs. projects assigned to recognized LMP zones. Arroyo’s opinion is that projects interconnecting to far

- flung outposts o f th e 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 m ore 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 ac cept 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 s eeking 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. Otherwi se the evaluation of turnkey proposals is quite similar to that of PPAs.

H. PG&E’S USE OF AD DITIONAL CRITERIA AN D ANALY SIS IN CREATI NG A
SHORT LIST

PG&E’s overall approach to cr eating a sh ort 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 list42

ranked by value, s electing Offers primarily based on high est 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 l oad. 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 pre ferences; 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 ENVIRONME NTAL CONCERNS
Appendix K to PG&E’s 2011 solic itation protocol states specific subc omponents of the RPS Goals evaluation criterion . Among these is “ environmental s tewardship”, 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 fo r 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 screen ed Offers to identify higher

- va lued project s 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 ide ntified only a few Offers a s 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 c lose proximity to critical habitat.

In admin istrating 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 th at were identified as posing such concerns were rejected anyway based on inadequate value or viability scores

.

2. RESOURCE DIVERSI TY
Another component of the RFO Goals evaluation criterion is resource diversity. Attachment K of PG&E’s 2011 solicitation p rotocol 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 cutof

f 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 co ntracting with a diverse mix of baseload and peaking, and firm and intermi ttent resources , at a higher cost to ratepa yers than only contracting disproportionately with one type of resource at lower cost

.

3 . SUPPLIER CONCENTRA TION
In this year’s solicitatio n, 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 hi gher valued than Offers from other Participants that were also selected. PG&E also cho se 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 rathe r 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 wi th 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 th e 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 com municated more clearly in the bidders’ conference and in the protocol. A rroyo believes that it is unlikely that most Participants were aware that submitting large projects c ould disadvantage those proposals.

4. DELIVERY POINT

PG&E stated in its 2011 soli citation protocol a preference f or 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 preferen ce 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 o f its RPS portfolio needs.

It is difficult to separate the application of this prefe rence 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 dat es 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.

I n 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 Go als 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 (WMD VBE ) shall have the maximum practicable opportunity to participate in the performance of Agreements resulting from thi s 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 WMDVB E, 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 WMDVBE s, and PG&E’s policy of scoring Offers against this subcriterion is no doubt intended to help address the shortfall between actual procurement of renew able power from WMDVBE’s (or from pr ime 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 certif ied 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 th at 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 proposal s 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 s olicitations there may be opportunities to explain or communicate the diversity goal more clearly, and to more explicitly link Offer selection to a Participant’s willingne ss 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 methodolo gy, and a discussion of the fairness of the decisions

.

1. SOURCES OF DISAGREEMENT

A rroyo 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 Viabili ty Calculator; in nearly all cases the scores differed , but relative rankings of Offers were similar overall . Ot her 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 treatmen t as bundled in

- state resources;

 Arroyo woul d not have ass igned 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 l arge. 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 v alued, most viable proposals:

 Because PG&E chose a different cutoff for valuation for different types or locations of resources, it selected sev eral Offers that Arroyo ranked as mediocre in net value . Arroyo would have shortened the short list by rejecti n g 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 attr ibutes that PG&E considered sufficiently attractiv e to outweigh the46 projects’ weaker viability assessments . Arroyo would have rejecte d 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 P G&E selected, the basis for these disagreements largely centers on dif ferences 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 examp le, PG&E’s choice to lower the valuation cutoff for certain r esource types and locations was fully consistent with p lacing a relatively high priority on the non

- quantitative sub

- criterion of resource diversity and on the stated preference for projects with in PG&E’s service territory

. While Arroyo’s relative preferences differ, Arroyo b elieves that PG&E’s relative priorities, based on its business judgment, are reasonable.

Similarly, Arroyo disagrees with PG&E’s selection of inpu ts for its valuation of capa city

, but acknowledges that the underlying sources of t he 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 ar e consistent with guidance from regulators, though Arroyo believes th at 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 gro up within PG&E that ana lyzes these Offers provided incomplete documentation of th e basis for selection decisions. Arroyo disagrees with the shortlisting decisions about these Offers. The CPUC will have a better opp ortunity to review these if PG&E execute s contracts for these in the future.

2. INDEPENDENT OFFER ANALYSES

Arroyo conducted its own rather simpl ified 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 Fi gure 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 es timated Net Qualifying Capacity such as solar generation;

 Less value assigned to projects interconnecting in non

- CAISO balancing authority areas;

 Less of a premium a ssigned 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 Offers47

to be ranked high or low in PG&E’s short

- listing process, such as the impact of the discount rate assumpti on, 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 diff erences 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

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 corre ct these deficiencies by completing48

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

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 d ifference 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. OV ERALL 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 arri ve at a short list for the 2011 RPS RFO was fair , unbiased, consistent, and reasonabl e.

Most disagreements between Arroyo and the PG&E team fall in to 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 d ifferent priorities or emphases regarding the weight s 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 procureme nt.49



# 5 . FA I R N E S S O F P RO J E C T

S 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 session s between PG&E's and SPI ’ s representatives . Arroyo was also able to review draft term sheets and contracts in order to ide ntify specific proposals and counterproposals the parties made regarding contract terms in the course of discussion s

. Based on this review, Arroyo did n ot identify any situations in which PG&E provided SPI with concessions in contract terms that the IE con sidered to be materially unfair to ratep ayers. 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 P G&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 be tween 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 c ompetitors, Arroyo does not regard this as sufficient a concern to cause the PPA to merit rejection.

A. BACKGROUND INFORMATI ON

Sierra Pacific Industries is an integrat ed 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 plant s in California

, fueled by woody waste biomass

, four of whose output will continue to be provided t o PG&E under the new PPA . Four of t hese projects have been under contract with PG&E as Qualifying Facilities since they commenced operations :

 Anderson , 5.0 MW contract capac ity as a QF , commenced operation in 1998 ;50  Burney, 20 MW as a QF 11 , 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

s erve 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 A nderson 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,
L incoln, 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 EVALU ATING THE FAIRNESS O F 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 selle rs given equitable opportunities to advance their Offers towards final PP As? Were individual sellers given unique opportunities to move their proposal s forward or concessions to improve their contracts’ commercial value, opportunities not provided to others?

 Was th e 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 neg otiations, is there evidence that other sellers were disadvantaged by tha t treatment? Were other proposals of comparable value to ratepayers assigned materially worse outcomes?

C. NEGOTIATIONS BETWEEN SIERRA PACIFIC INDUS TRIES AND PG&E

In Nov ember 2010, SPI and PG&E began bilateral discussions about how to convert the

ex isting 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 pa rties 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:

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60  Use -limited resource. PG&E asked, and SPI agreed, that the seller be obligatedto 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 O F PROJECT

- SPECIFIC NEGOTIATION S

The starting point for drafting the PPA with SPI was PG&E’s 2011 RPS Form Agreement, w hich 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

Arr oyo notes that there are precedents for PG&E

T here are a few mitigating factors that partially alleviate Arroy o’s concern about the61

Another mitigating factor is that PG&E chose to

On that basis, Arroyo views the trade-off as reasonable if not idea l.

Overall, Arr oyo’s opinion is that the negotiati ons 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 advant aged the seller compared to its competitors.

 PG&E provided a concession to SPI that is unique within this RPS solicitation.

appea rs to Arroyo to be a reasonable tradeoff for r atepayers 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 revie w 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 Ander son 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 capacity 18 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 c apacity, located within the city of Lincoln, in western Placer County.

 Quincy is an exist ing 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 guara nteed 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 EVALUAT ION CRITERIA AND RAN KING

The 2011 RP S 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
prev iously 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 comparis ons, Arroyo opines that the market valuation of the SPI contract ranks as high compared to r elevant 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, tak ing 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 de livered energy in the first and second compliance periods. This method counts the value

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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 i t 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 utili ty’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 inde pendently estimated the value of the SPI PPA . This estimate places the PPA in

On the bas is 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 ba sed its evaluation of Offers in the 2011 RPS solicitation on the fit of proposed deliveries with and on the firmness of delivery.

2065

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 mai ntaining 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. The se powerhouses have operated for decades and have been maintained by SPI for use in its saw mill production
pr ocesses. An existing, currently operating project is more viable, in a physical rather than economic sense, than any proposed as- yet -unbuilt generator.

T he new Anderson II facility will resemble SPI’s existing generators in many respects.

21 The CAI SO’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.

Per mitting. 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 I I 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 th e 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 wor k will not impede SPI’s ability to achieve its guaranteed on

line 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 GC OD 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. Ba sed on this, the SPI contract ranks among the highest-viability proposals submitted to PG&E in the 2 011 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 be yond.

Entering into this tr ansaction advances PG&E and the state towards the 20% biomass goal set by E xecutive 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 Industri es merits CPUC approval.

Arroyo’s independent but simpler valuation rank s 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 analy sis suggests that the contract ranks as high in net market value and high in portfolioadjusted va lue 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 pri ce 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 via bility 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 permitt ing, execution of an interconnection agreement, and completion of network upgrades.69

Arroyo regards the SPI contract as ranking as moderate in portfolio fit.

T he SPI Lincoln powerhouse currently contributes to grid reliability in the CAISO’s resource -de ficient Sierra

area.
Arroyo believes that PG&E’s projec t-specific negotiations with SPI were conducted in a

manner t hat was fair to ratepayers. The concession that PG&E granted to SPI appears less than fully fair to competing deve lopers when viewed in isolation.

Based on its high valua tion, 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 Resour ces 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 Occi dental 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 Goodi n, MacBride, Squeri, Schlotz & Ritchie SPURR

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