BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA Application of Pacific Gas and Electric Company (U 39-E) for Approval of 2008 Long-Term Request for Offer Results and for Adoption of Cost Recovery and Ratesetting Mechanisms

Application 09-09-021

(Filed September 30, 2009)

PACIFIC ENVIRONMENT’S OPENING BRIEF DEBORAH BEHLES LUCAS WILLIAMS SHANNA FOLEY, PTLS No. 23621 CHAD PRADMORE, PTLS No. 24574 JAMES UPP, PTLS No. 24467 ERIC KAPLAN, PTLS No. 23717 Environmental Law and Justice Clinic Golden Gate University School of Law 536 Mission Street San Francisco, CA 94105-2968 Telephone: (415) 442-6647 Facsimile: (415) 896-2450 dbehles@ggu.edu Dated: April 14, 2010 Attorneys for Pacific Environment

F I L E D04-14-1004:59 PM

TABLE OF CONTENTS

I. INTRODUCTION AND SUMMARY ............................................................1

II. FACTUAL BACKGROUND………………………………………………...2

III. ARGUMENT……………………………………………………………….....4

A. PG&E Is Seeking Authorization Of Other Projects and Contracts In Other Proceedings Pursuant to the Authorization Granted in D.07-12-052……………………………...4

B. PG&E Should Not be Allowed to Procure Any of the 800 to 1,200 Megawatts Authorized by D.07-12-052 in this Proceeding Because PG&E’s Actual Need is Zero; the New LTPP Proceeding Is the

Proper Venue for Determining Whether PG&E Should Be Allowed to Procure Megawatts in the Future……………………….....................7 1. The Megawatts Previously Authorized in the 2006 LTPP Are No Longer Needed………………………………………………………..7

a. The 2009 Peak Reserve Margin in PG&E’s NP26 Territory

Fluctuated Between 44 and 46 Percent Demonstrating that PG&E Does Not Need Any New MW……………………………...7

b. The Commission Should Rely on the 2009 Demand Forecast Instead of the Outdated 2007 Draft Forecast Relied on in the 2006 LTPP…………………………………………………………8

c. The Overestimated Export Assumption Contained in the LTPP Would Reduce Future Demand by 1,900 MW………………….....9

d. Energy Efficiency Has Had a Larger Impact on Consumption Than Anticipated in the 2006 LTPP and that Impact Continues To Increase…………………………………………………….......10

e. Retirement Assumptions Relied Upon in the 2006 LTPP Have Changed, Further Reducing PG&E’s Need……………………...11

f. Recent Population Statistics Show That DemandIis Lower……...12

2. Additional Fossil-Fuel Facilities Are Not Needed to Back-Up Renewable Energy.................................................................................13

3. PG&E Should Be Required to Demonstrate Actual Need Before It Is Allowed to Procure Any Megawatts Due to a Contingent Risk; This Analysis Can Be Conducted in the 2010 LTPP................15

C. The Marsh Landing PPA and Oakley Generating Station PSA Are Not Reasonable Or in the Best Interest of PG&E’s Customers…..…..16

D. PG&E Should Not Be Authorized to Recover Costs Incurred Pursuant to the PPA’s in the Energy Recovery Account, Nor to Recover Any Stranded Costs Associated with the Agreements………………………………………………………………..19 E. PG&E’s Rate Recovery and Initial Annual Revenue

Requirement Proposals for the Contra Cost Project, as Modified By the Partial Settlement Agreement Dated February 17, 2010, Should Not Be Approved……………………………………………….…..20 F. PG&E’s Conduct Regarding the 2008 LTRFO Was

Neither Reasonable Nor Consistent with Commission Directives………………………………………….…………21

1. PG&E Was Required to Consider The Environmental Impacts of The Proposed Plants…………………………………………..…...21

2. PG&E Failed to Follow Its Environmental Leadership Protocol

and Consider the Environmental Impacts of the Plants....................22

3. If PG&E Had Analyzed the Environmental Impacts of the Facilities, It Should Not Have Chosen Them……………………......24

IV. CONCLUSION………………………………………………………………………..27

TABLE OF AUTHORITIES CALIFORNIA STATUTES Cal. Health & Safety Code § 38500, et. seq. (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . .17 Cal. Pub. Util. Code § 399.11 (Westlaw 2010). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 17 Cal. Pub. Util. Code § 399.13 (Westlaw 2010) . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . .18 Cal. Pub. Util. Code § 399.14(e) (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .18 Cal. Pub. Util. Code § 399.15(a) (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Cal. Pub. Util. Code § 399.15(b)(4) (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19 Cal. Pub. Util. Code § 451 (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 Cal. Pub. Util. Code § 454.5 (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Cal. Pub. Util. Code § 454.8 (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Cal. Pub. Util. Code § 701 (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17 Cal. Pub. Util. Code § 701.1(c) (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Cal. Pub. Util. Code § 701.3 (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Cal. Pub. Util. Code § 701.4 (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Cal. Pub. Util. Code § 727.5(e) (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Cal. Pub. Util. Code § 790(b) (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 Cal. Pub. Util. Code § 790(e) (Westlaw 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 CALIFORNIA CASES Toward Utility Rate Normalization v. Public Utilities Com. 44 Cal.3d 870 (Cal. 1988) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 CALIFORNIA EXECUTIVE ORDERS Executive Orders S-14-08 (11/17/2008) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17

CALIFORNIA PUBLIC UTILITY COMMISSION DECISIONS D. 95-12-063. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17 D. 04-01-050 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 D.04-12-048. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 D.05-12-020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 D.07-12-052. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .passim D. 08-10-037. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,18 D.09-06-049 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 D.09-10-017. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 4 D.09-12-041. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 D.10.02.032. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 CALIFORNIA PUBLIC UTILITY COMMISSION RULINGS R.08-08-009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18

R.08-02-007. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14, 16, 19

CALIFORNIA PUBLIC UTILITY COMMISSION RESOLUTIONS

R. E-4240. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 OTHER PUBLIC UTILITY COMMISSION DOCUMENTS Jan. 26, 2010 Proposed Alternate Decision of Peevey and Proposed Decision of ALJ in A.09-02-019. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . …5

1

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of Pacific Gas and Electric Company (U 39-E) for Approval of 2008 Long-Term Request for Offer Results and for Adoption of Cost Recovery and Ratesetting Mechanisms

Application 09-09-021

(Filed September 30, 2009)

PACIFIC ENVIRONMENT’S OPENING BRIEF

Pacific Environment respectfully submits this Opening Brief in response to the

February 1, 2010 Assigned Commissioner’s Ruling and Scoping Memo in Applications

09-10-021. The Ruling set forth several issues including how much of the 800-1,200

megawatts PG&E should be allowed to procure in this proceeding, whether the

transactions are just and reasonable, and whether PG&E’s conduct in its long term

request for offers was reasonable and consistent with the Public Utilities Commission’s

directives.

I. INTRODUCTION AND SUMMARY OF ARGUMENT

Many things have changed since the Commission’s 2006 Long-Term

Procurement Plan (LTPP) decision. As California emerges from an economic recession,

the energy landscape has changed. Pacific Gas and Electric Company (PG&E) now has

access to more electricity generation than it needs. Last summer, PG&E’s territory

operated with a 44% reserve margin during summer peak. This extraordinarily high

margin is in part due to the Commission’s success at increasing energy efficiency and the

demand decrease from the recession. These factors, along with delayed facility

retirements and inflated population and energy export assumptions demonstrate that the

800-1,200 MW demand from the 2006 LTPP is no longer needed. Even PG&E has

forecasted a decrease in need.

2

Despite all this evidence, PG&E continues its push for procurement, requesting

over 1,500 MW of new natural gas-fired facilities in this and other proceedings by

relying on outdated predictions. In this proceeding, PG&E is requesting permission to

procure energy from two proposed fossil fuel power plants in an area that already houses

the majority of the Bay Area’s power generation, whose air quality is in the worst ten

percentile in the nation, and that has higher than average rates of cancer and asthma, as

well as other adverse health effects commonly associated with poor air quality. The

potential impacts of new facilities are especially unacceptable when the new capacity is

not needed.

To support the procurement of this unneeded energy, PG&E has argued that an

increased number of natural gas facilities are necessary to integrate renewable energy into

the grid. This argument lacks merit because California Energy Commission (CEC) data

shows no new natural gas facilities are currently needed to integrate renewable energy,1

and even if new backup was needed, energy storage and upgrades to existing facilities

could back up renewables.

PG&E’s attempt to procure unneeded energy by relying on outdated and

inaccurate predictions should be rejected. The Commission should not allow PG&E to

increase its already extraordinarily high reserve margin at the ratepayers’ and local

communities’ expense.

I. BACKGROUND

Pursuant to Section 454.5 of the Public Utilities Code, the Commission conducts a

biannual long term procurement proceeding to determine a utility’s, such as PG&E’s,

1 See Ex. 501 (Test. of R. Cox) at p. 7 (citing California Energy Commission, Impact of Assembly Bill 32 Scoping Plan Electricity Resource Goals on New Natural Gas-Fired Generation, CEC-200-2009-011 (June 2009), available at http://www.energy.ca.gov/2009publications/CEC-200-2009-011/CEC-200-2009-011.PDF.)

3

procurement needs. In 2006, the Commission opened a LTPP proceeding and

determined PG&E’s future procurement need by relying on a draft 2007 CEC forecast

and a series of assumptions, including potential retirement dates for older facilities, and

proposed energy exports from PG&E’s system.2 In D.07-12-052 (LTPP decision), the

Commission found that PG&E’s procurement need was 800 to 1,200 megawatts (MW)

by 2015 based on these inputs and assumptions.3

After the 2006 LTPP decision, several events occurred that raise serious questions

about the assumptions made in the decision, including the CEC’s development of a more

recent demand forecast that shows reduced demand due to increased energy efficiency

savings and decreased economic growth.4 In addition, the CEC published a report after

the decision calling into question the export assumption relied on in the 2006 LTPP.5

PG&E has filed a series of applications asking for approval of energy contracts

from new fossil fuel capacity since the 2006 LTPP decision.6 Last fall, the Commission

approved one of these applications, which authorized 184 MW at the Mariposa facility.7

In this Proceeding, PG&E has requested authority to procure over 1,300 MW of new

fossil fuel capacity from two proposed natural gas-fired plants in Contra Costa County, to

delay the retirement of an old inefficient facility, and to approve a contract with a

cogeneration facility.8

2 See D.07-12-052 at pp. 86,116. 3 Id. at pp. 105, 227, 291. 4 See Ex. 403 at p. 2; see also California Energy Commission, May 21, 2009 Presentation on Current Forecast, available at http://www.energy.ca.gov/2009_energypolicy/documents/2009-05-21_workshop/presentations/03_CEC_Marshall_May_21_Peak_Demand.pdf. 5 See Ex. 405 at pp. 1, 7, 3 (“LTPP final decision over estimated the amount of capacity flowing North to South . . . by at least 1,900 MW.”); see also infra at Section III.B.1 (discussing the changed export assumption). 6 See infra at Section III.A. (discussing PG&E’s recent applications which include A.09-04-001; A.09-09-021; A.09-10-022; A.09-10-034). 7 D.09-10-017. 8 See A.09-09-021 at pp. 2-3.

4

Pacific Environment along with Sierra Club California, Communities for a Better

Environment, Californians for Renewable Energy, Inc., The Utility Reform Network, and

the Division of Ratepayer Advocates filed protests in this application. Pacific

Environment protested PG&E’s application because PG&E’s request to add two

unneeded new facilities to an area that already has over ten polluting power plants and to

extend the retirement of an old, inefficient once-through cooling facility is inconsistent

with this Commission’s decisions, the State’s focus on renewable energy, environmental

justice considerations, and PG&E’s own environmental leadership protocol.9

After a prehearing conference on December 2, 2009, the Commission issued an

Assigned Commissioner’s Ruling and Scoping Memo on February 1, 2010. Pursuant to

the schedule set forth in the Scoping Memo, the intervening parties filed opening

testimony on February 22, 2010, and all the parties filed reply testimony on March 10,

2010. Following the briefing, the parties filed a joint motion to admit the testimony and

certain data requests into the record on April 7, 2010.

III. ARGUMENT

A. PG&E Is Seeking Authorization of Other Projects and Contracts In Other Proceedings Pursuant to the Authorization Granted in D.07-12-052.

Decision D.07-12-052 authorized PG&E to procure 800-1200 MW by 2015.10

PG&E is seeking authorization for MW above and beyond the authority that was granted

in the 2006 LTPP.

PG&E has sought approval of fossil fuel energy contracts from new capacity in

other proceedings. On April 1, 2009, PG&E sought approval of a 184 MW contract with

9 See Pacific Environment’s Protest, A.09-09-021 at p. 1 (Oct. 30, 2009). 10 See D.07-12-052 at p.116.

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Mariposa Energy, which the Commission approved in D.09-10-017.11 Last fall, PG&E

also filed applications seeking approval to take over California Department of Water

Resources (DWR) contracts and to obtain an additional 254 MW via contract upgrades

with the Tracy facility and the Los Esteros Critical Energy Facility.12 All of these new

438 MW should count towards the 2006 LTPP authorized capacity.13

PG&E has also sought approval of new capacity from renewable energy contracts

in other proceedings that are above the MW from new renewable energy contracts that

was assumed in the LTPP. The 2006 LTPP authorization is intended to be “a backstop

authorization that results from additional identified net short after all preferred loading

order resources are exhausted.”14 Therefore, PG&E’s procurement of additional

preferred resources should be counted as part of PG&E’s need.

Last February, PG&E applied to the Commission for approval of a 500 MWdc

PG&E distributed Solar Photovoltaic Program.15 This program is likely to be approved

as both the Commission’s ALJ proposed decision and the Assigned Commisioner’s

proposed alternative decision approved the project.16 In addition to these solar projects,

under the California Solar Initiative program a total of 921 MWac are forecast to be

11 See A.09-04-001, D.09-10-017. 12 See A. 09-10-022, A.09-10-034. 13 PG&E does not dispute that the Mariposa contract should count towards the 800-1200 MW. See Ex. 1 (PG&E Test.) at p. 1. The additional 254 MW from the DWR contract novations should count as well. See D.08-11-056, at p. 81 (“contracts must be reviewed by the Commission for consistency with long-term procurement planning criteria.”). 14 D.07-12-052 at p. 100. 15 See A.09-02-019. 16 See Jan. 26, 2010 Proposed Alternate Decision of Peevey and Proposed Decision of ALJ in A.09-02-019.

6

installed in PG&E territory by 2017.17 Just from these two programs 600 MWac of peak

generation are unaccounted for in D.07-12-052.18

In addition, PG&E is developing and constructing far more solar energy capacity

than the 2006 LTPP assumed. Solar projects under development or construction are

listed in Appendix A attached hereto with a total capacity of 3,617 MW.19 In addition to

these contracts, other projects have recently been constructed and are now operational.

For example, PG&E has been operating a 10 MW solar photovoltaic facility operated by

El Dorado Energy since January 1, 2009.20 PG&E has also secured 175 MW of wind

power from the Klondike III project and 103 MW from the Rattlesnake Road wind

project.21 Further, on December 3, 2009 PG&E filed an application with the Commission

to acquire, develop, and construct the Manzana Wind Project (Manzana).22 The Manzana

facility has an expected capacity of 246 MW with an expected operational date of

December 2011.23 The MW generated from these projects should be considered when

addressing PG&E’s need because PG&E has procured more capacity than assumed in the

2006 LTPP.

In addition to the newly procured projects discussed above, PG&E recently began

construction and/or operation of fossil fuel facilities. These facilities can meet any

17 See Ex. No. 500 (Test. of B. Powers) at pp 9-12 (citing Itron, Impacts of Distributed Generation- Final Report, prepared for California Public Utilities Commission Energy Division Staff, January 2010, at pp.3-8). 18 See Ex. No. 500 (Test. of B. Powers), at pp. 9-12 (citing Itron report). 19 Id. The Commission recently stated, after the California Solar Initiative, achieved over 50 MW that it was “an amount of capacity equivalent to a typical peaking power plant.” See CPUC Press Release, April 13, 2010, available at http://docs.cpuc.ca.gov/PUBLISHED/NEWS_RELEASE/116211.htm. 20 See Resolution E-4240. 21 The Oregonian. Power Hungry California is Hot For the Northwest’s Clean Energy. August 24, 2008. http://www.oregonlive.com/environment/index.ssf/2008/08/california_utilities_look_to_o.html 22 A.09-12-002. 23 Id; see also New Release: PG&E Agrees to Purchase and Operate Major California Wind Energy Project (Dec. 3, 2009), available at http://www.pge.com/about/newsroom/newsreleases/20091203/pge_agrees_to_purchase_and_operate_major_california_wind_energy_project.shtml

7

perceived need that PG&E has for new fossil fuel generation instead of preferred

resources. The Gateway Generating Station, which is a PG&E owned and operated 530

MW peaking facility, began commercial operation in January 2009.24 In addition, the

Colusa Generating Station, at 660 MW, and the Humboldt Bay Repowering Project, at

163 MW, are now under development and/or construction.25

In sum, PG&E is either seeking authorization or has received authorization for

MW that are far beyond what was approved and considered in D.07-12-052. Therefore,

the above projects should be considered when determining PG&E’s need.

B. PG&E Should Not be Allowed to Procure Any of the 800 to 1,200 Megawatts Authorized by D.07-12-052 in this Proceeding Because PG&E’s Actual Need Is Zero; The New LTPP Proceeding Is the Proper Venue for Determining Whether PG&E Should Be Allowed to Procure Megawatts in the Future.

1. The Megawatts Previously Authorized in the 2006 LTPP Are No Longer Needed. In D.07-12-052, the Commission relied on certain assumptions that are no longer

justified, including inaccurate estimates of the amount of MW that would be exported and

retired. Additionally, conditions have changed since the 2006 LTPP, including decreased

population growth and energy consumption, and the increase in energy efficiency and use

of renewable sources. While some of these factors alone would be sufficient to support

the conclusion that PG&E no longer needs to procure the additional MW authorized by

the 2006 LTPP, all of these factors combined undoubtedly demonstrate that PG&E’s

request to procure additional MW should be rejected.

24 See California Energy Commission, Commission Order, Proposed Decision of the Siting Committee, Docket No. 00-AFC-1C, available at http://www.energy.ca.gov/sitingcases/gateway/. 25 See California Energy Commission information on Colusa and Humboldt, available at http://www.energy.ca.gov/sitingcases/colusa/index.html; and http://www.energy.ca.gov/sitingcases/humboldt/index.html.

8

a. The 2009 Peak Reserve Margin in PG&E’s NP26 Territory Fluctuated Between 44 and 46 Percent Demonstrating That PG&E Does Not Need Any New MW.

PG&E is required to operate with a 15-17 percent reserve margin.26 In 2009,

California ISO (CAISO) forecasted that PG&E’s NP26 territory would have a 30 percent

reserve margin for the summer peak of 2009.27 Even at that level, PG&E would have a

reserve margin double what is required.28 However, the actual numbers for the summer

demonstrate that PG&E’s NP26 territory actually had reserves margins that never fell

below 44 percent (as shown below in Table 1).29

Table 1. Actual Peak Summer Reserve Margins for PG&E NP26 Territory.30

Month CAISO forecast reserves available in

NP26 in summer 2009 (MW)

Peak 1-hour load in NP26a

(MW)

Date and time of peak

Actual reserve marginb

(%)

June 2009 27,899 19,392 6/29/09, 4-5 pm

44

July 2009 27,899 19,419 7/17/09, 4-5 pm

44

August 2009

27,899 19,215 8/10/09, 4-5 pm

45

September 2009

27,899 19,131 9/3/09, 3-4 pm

46

a) http://oasis.caiso.com/mrtuoasis/?doframe=true&serverurl=http%3a%2f%2ffrptp09. oa.caiso.com%3a8000&volume=OASIS

b) (CAISO forecast 1-in-2 reserves-actual peak)/actual peak = reserve margin. Reserve margins of this magnitude mean that there was an excess of at least 5,527

MW above the required 15 percent reserve margin.31 These excesses show that PG&E

already has access to far more generation than is needed, especially when considering the

26 See D.07-12-052 at p. 104. 27 See Ex. 500 (Test. of B. Powers) at p.7 (citing California Independent System Operator, 2009 Summer Loads and Resources Operations Preparedness Assessment, May 7, 2009, at pp. 3-4) . 28 Ex. 502 (Reply Test. of B. Powers and R. Cox) at p. 2(citing California Independent System Operator, 2009 Summer Loads and Resources Operations Preparedness Assessment, May 7, 2009, Table 1, p. 4.). 29 Ex. 502 (Reply Test. of B. Powers and R. Cox) at p. 3. 30 This table is excerpted from Ex. 502 at p. 3. Percents are rounded to the nearest percent. 31 Id. (“19,419 MW x 1.15 = 22,332 MW. This is the actual minimum reserves requirement for NP26 in the summer of 2009. 27,899 MW – 22,332 MW = 5,567 MW. These are the additional reserves that were available in the summer of 2009 in NP26 beyond the 15 percent minimum reserve margin requirement”).

9

future additions covered in the previous section. Therefore, PG&E does not need to

procure any new MW.

b. The Commission Should Rely on the 2009 Demand Forecast Instead of the Outdated 2007 Draft Forecast Relied on in the 2006 LTPP.

The Commission based its 2006 LTPP decision in large part on the CEC’s

2007 California Energy Demand (CED) 2008-2018 Staff Draft Forecast.32 The

Commission relied on the 2007 draft forecast because it was the “most current

public information available” and therefore it provided “a better ‘snapshot’ of the

current needs of the system” than the older demand forecasts.33

Similarly, the 2009 Demand Forecast provides a more accurate snapshot

of the current needs of the system.34 Importantly, the CEC found that the 2007

CED’s need determination is “markedly” higher than actual need.35 This is the

result of changed circumstances, which in combination with other significant

changes, now negate the need for the allocation of any additional MW to PG&E.

While PG&E admits that the current demand forecast is lower than the demand

forecast relied on in the LTPP decision,36 it still takes the position that the procurement of

these additional MW is needed regardless of new data to the contrary. PG&E’s

assertions should be rejected. PG&E has not offered any evidence showing that it does

indeed need to procure more MW. Rather, PG&E has continued to rely solely on

32 D.07-12-052 at p. 29. 33 See D.07-12-052 at pp. 29-30 n. 38. 34 Feb. 1, 2010 Assigned Commissioner’s Ruling and Scoping Memo, A.09-09-021, at pp. 6-7 (discussing changes in economic conditions, load forecasts, etc., since the LTPP.) There was a change between the Draft and the Adopted forecast. See Ex. 500 (Test. of B. Powers) at p. 2. It is not clear that there was any substantive reason for the change. See id. 35 See CEC, 2009 Integrated Energy Policy Report at p. 51, available at http://www.energy.ca.gov/2009publications/CEC-100-2009-003/CEC-100-2009-003-CMF.PDF; see also Ex. 403 (CED 2010-2020 Adopted Forecast, Dec. 2009); Ex. 500 (Test. of B. Powers) at p. 3 (comparing 2007 Draft Forecast with 2009 Adopted Forecast). 36 See Ex. 5 (PG&E’s Reply Test.) at pp. 4-5, 7 (admitting that the 2009 CEC forecast is lower than the forecast relied on in the 2006 LTPP).

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outdated projections of need from the draft 2007 CED rather than actual numbers from

recent years.37

c. The Overestimated Export Assumption Contained in the LTPP Would Reduce Future Demand by 1,900 MW.

In the 2006 LTPP, the Commission assumed that PG&E would export 3,000 MW

of electricity to Southern California.38 This assumption was supplied to the Commission

by the CEC.39 After the release of the 2006 LTPP, however, the CEC found that exports

were overestimated by “at least 1,900 MW.”40 This overestimation resulted in an export

figure nearly 300 percent higher than the actual exported amount and was “clearly not

correct.”41

Notably, PG&E has not disputed the CEC’s overestimation findings, which is not

surprising since PG&E claims it does not know how much energy it exports.42 PG&E

instead states that the export assumption was already calculated in the 2006 LTPP.43 This

error, however, is significant and should be considered. If this error is fixed, the demand

predicted in the 2006 LTPP would have been 1,900 MW lower, and PG&E’s need would

be eliminated.44 Based on this overestimated export assumption alone, the Commission

should not allow PG&E to procure any additional unneeded MW in this proceeding.

37 See e.g., Ex. 5 (PG&E’s Reply Test.) at pp. 3, 6-15 (PG&E only relies on projections of its need, not actual numbers). 38 See Ex. 501 (Test. of R. Cox) at p. 5 (citing D.07-12-052 at Table PGE-1). 39 See D.07-12-052 at p. 12. 40 See Ex. 501 (Test. of R.Cox) at p. 5 (citing California Energy Commission, Revisiting Path 26 Power Flow Assumptions (Staff Paper, October 2008) at p. 3, available at http://www.energy.ca.gov/2008publications/CEC-200-2008-006/CEC-200-2008-006.pdf.). 41 See id. (citing Revisiting Path 26 Power Flow Assumptions). 42 See Ex. 17 (“PG&E does not know the actual exports across Path 26 . . .”); Ex. 073 (“PG&E does not know the actual exports across Path 26 for 2007, 2008 and 2009.”); Ex. 5 at p. 12-13 (acknowledging that the CEC found the LTPP export assumptions “no longer valid”). In fact, no party question CEC findings. See, e.g., Ex. 301 (failing to address the CEC’s Path 26 Power Flow Assumptions report). 43 See Ex. 1 (PG&E Test.) at p. 12. 44 See Ex. 501 (Test. of R. Cox) at p. 5 (citing California Energy Commission, Revisiting Path 26 Power Flow Assumptions (Staff Paper, October 2008) at p. 3, available at http://www.energy.ca.gov/2008publications/CEC-200-2008-006/CEC-200-2008-006.pdf.); see also Ex. 200

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d. Energy Efficiency Has Had a Larger Impact on Consumption than Anticipated in the 2006 LTPP and That Impact Continues to Increase.

Due to the success of initiatives promoting efficient electricity use and new

energy-saving technology, in addition to the efficiency gains considered in the 2009

CED, need in PG&E’s territory has been reduced by approximately an additional 2,600

GWh from the 2009 CED forecast levels due to additional incremental energy efficiency

(EE) impacts.45 This is no small reduction. The efficiency policies set forth by the

Commission have had the equivalent effect of eliminating the need for a 350 MW

combined cycle power plant running at 85 percent capacity.46

In its reply testimony, PG&E argues that the incremental EE impacts are not firm

and therefore should not be counted.47 However, in the 2006 LTPP, the Commission

took incremental EE impacts of the same type into account, and the predicted incremental

EE subsequently occurred and reduced demand.48 Similarly, here, the new data should be

incorporated to establish reliable estimates of actual need determination.

e. Retirement Assumptions Relied Upon in the 2006 LTPP Have Changed, Further Reducing PG&E’s Need.

In the 2006 LTPP decision, the Commission assumed that 4,200 MW from aging

and inefficient facilities would be retired by 2015 and that new MW would need to be

(Test. of K. Woodruff) at p. 19 (“if the error identified by CEC staff were to be corrected, PG&E’s need determination would be reduced by at least 1,900 MW, or effectively to zero!”); Ex. 100 (Test. of DRA) at p. 9 (“If PG&E’s need determination was amended to correct for only this mistake, its current authority to procure new generation under D.07-12-052 would be wiped out all together.”); Ex. 400 (Test. of R. Sarvey) at p. 4 (same). 45 See Ex. 500 (Test. of B. Powers) at p. 3 (comparing 2007 Draft Forecast with 2009 Adopted Forecast); See Ex. 403 (CEC, California Energy Demand 2010-2020 Adopted Forecast, December 2009) at p. 25. 46 See Ex. 500 (Test. of B. Powers) at p. 3; Ex. 501 (Test. of R. Cox) at p. 4 (same); Ex. 501 (Test. of R. Cox) at p. 4 (“through what PG&E calls its “demand-reduction programs,” PG&E estimates that “its electricity sales would grow at an average rate of just 1 percent per year between 2009 and 2018.”) (quoting from PG&E, 2008 Corporate Responsibility Report at p. 56, available at http://www.pgecorp.com/corp_responsibility/reports/2008/img/pge_crr_2008.pdf.). 47 Ex. 5 (PG&E Reply Test.) at pp. 11-12. 48 Compare D.07-12-052 at pp. 48, 116 with Ex. 500 (Test. of B. Powers) at p. 3 (quoting from Ex. 404 (CEC, Incremental Impacts of Energy Efficiency Policy Initiatives Relative to the 2009 Integrated Energy Policy Adopted Demand Forecast) at pg. 5).

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procured to replace them.49 This assumption has since proven inaccurate. For example,

1,311 MW from the Pittsburg Generating Station and 1,500 MW from the Moss Landing

facility are no longer expected to be retired until December 2017.50

Even if the retirement assumptions had proven accurate, no additional MW need

to be allocated. Many existing once-through cooling (OTC) facilities are currently

running far below capacity..51 Furthermore, a recent report found that several OTC

facilities could retire by 2015 with no need for additional replacement capacity; the report

concluded that a more than adequate reserve margin would still exist “with as little as

$135 million in in-state transmission upgrades.”52

In response, PG&E argues that it would be below the required priority reserve

margin (PRM) of 15 percent if these plants retire without procuring new capacity.53 This

claim is unfounded because PG&E relies on the 2006 LTPP decision forecast

assumptions, which have been shown to be inaccurate. In addition, the reserve margin at

44 percent is currently so large that “[u]ncertainties in the need for additional generation

in PG&E territory in the 2010-2020 timeframe, including OTC boiler plant retirements,

can readily be absorbed.”54

49 D.07-12-052 at 104, 116 Table PGE-1. 50 See Ex. 501 (Test. of R. Cox) at p. 6 (comparing D.07-12-052 at p. 116 with Draft Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (November 23, 2009) at p. 10, available at http://www.swrcb.ca.gov/water_issues/programs/npdes/docs/cwa316/otcpolicy112309_clean.pdf). PG&E has not questioned these new assumptions. Rather, it states that retirement is uncertain. See Ex. 5 (PG&E Reply Test.) at p. 13-14. 51 See Ex. 501 (Test. of R. Cox) at p. 6 (referring to CEC, Comments to State Water Resources Control Board Concerning Its Coastal Power Plant Preliminary Draft Policy and Related Scoping Document (May 2008) at p. 18-19, available at http://www.energy.ca.gov/siting/documents/2008-05-20_CHAIRMAN_SWRCB.PDF. 52 Id. (quoting California Ocean Protection Council & State Water Resources Control Board, Electric Grid Reliability Impacts from Regulation of Once-Through Cooling in California (ICF Jones & Stokes, April 2008) at p. 3, available at http://www.swrcb.ca.gov/water_issues/programs/tmdl/docs/power_plant_cooling/reliability_study.pdf). 53 See Ex. 5 (PG&E Reply Test.) at p. 14. 54 See Ex. 500 (Test. of B. Powers) at p. 9; see also Ex. 501 (Test. of R. Cox) at p. 7.

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f. Recent Population Statistics Show That Demand Is Lower.

Even though the 2009 CEC forecast predicts a lower demand, the demand would

have been lower still if the CEC had used more reliable, current population statistics. 55

According to the CEC, there is no expected increase in per capita electricity consumption

or peak demand over the 2010-2020 period,56 which means that population growth will

be the primary driver for residential and commercial energy demand growth.57

Considering that population growth will be the only source of new demand, the best

forecast should use the most current and reliable growth statistics available.58 The CEC

relied on three sources for population growth statistics in the CED 2007 that have since

lowered their predictions.59 Despite this, the CED 2009 Adopted uses those same

population growth statistics, which are now too high.60 Therefore, the use of this

outdated data has significantly inflated predicted demand.61 This is yet another reason

that PG&E’s demand is lower than predicted in the 2006 LTPP decision.

2. Additional Fossil-Fuel Facilities Are Not Needed to Back-Up Renewable Energy.

Even though PG&E does not need any additional MW, PG&E claims that its

requested contracts are necessary to integrate renewable energy sources into the grid.62

This argument fails. The CEC has found that new natural gas facilities are not currently

needed to integrate renewable energy and meet RPS goals.63 This is true even

55 Id. at p. 5 (Figure 1). 56 Ex. 500 (Test. of B. Powers) at p. 4 (citing CEC, California Energy Demand 2010-2020 Adopted Forecast) at p. 24. 57 Id. (citing CEC, California Energy Demand 2010-2020 Adopted Forecast, at p. 24 Figure 2). 58 Id. 59 Id. 60 Id. 61 See id. at pp. 4-6. 62 See Ex. 1 (PG&E Test.) p. 1-1. 63 See CEC’s Impact of Assembly Bill 32 Scoping Plan Electricity Resource Goals on New Natural Gas-Fired Generation (2009); see also Ex. 501 (Test. of R. Cox) at p. 7 (“the study found that no new natural

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considering the eventual phase-out and retirement of several OTC facilities.64 It is

especially hard to see why new facilities are needed when PG&E’s existing facilities are

running at extremely low annual capacity factors.65 Moreover, since PG&E is unaware

of the actual capacity of its own facilities,66 it is difficult to understand how it can argue

that there is additional need.

PG&E has responded to the CEC Report by arguing that the report found that

renewable integration could only be achieved by adding 7,758 of new natural-gas fired

capacity.67 This 7,758 figure actually comes from one scenario examined in the Report

(in which multiple scenarios were examined) where only 19%, or 1474 MW, is estimated

to be added in Northern California by 2020.68 Other scenarios in the report assume that

some of the replacement of OTC units could come from other preferred resources, such

as wind or solar, which would result in “significant benefits.”69 Regardless, PG&E has

procured above 1474 MW capacity in recent proceedings.70 Furthermore, because the

MW are not actually needed until 2020 and PG&E has already procured over the amount

recommended for Northern California, any remaining issues can be fully addressed in the

next LTPP proceeding.71

gas plants are needed in the San Francisco Bay Area to meet local reliability needs in light of the push to meet the 33% renewable portfolio standard.”). 64 See id. 65 See Ex. 501 (Test. of R. Cox) at p. 6 (citing California Energy Commission, Comments to State Water Resources Control Board Concerning Its Coastal Power Plant Preliminary Draft Policy and Related Scoping Document (May 2008) at p. 19, available at http://www.energy.ca.gov/siting/documents/2008-05- 20_CHAIRMAN_SWRCB.PDF.) 66 Ex. 78 (PG&E Data Request Response). 67 See Ex. 5 (PG&E Reply Test.) at p. 20. 68 See June 2009 CEC Staff Report on AB32 Implementation, available at http://www.energy.ca.gov/reti/documents/phase2A/comments/Joan_Taylor_Ca-Nevada_Desert_Energy_Committee_Attachment.PDF at p. 2. 69 Id. at pp. 20-21. 70 See supra at Section III (A). 71 See June 2009 CEC Staff Report on AB32 Implementation at p. 2; see also Assigned Commissioner’s Ruling Addressing Future Commission Activities Related to Procurement Planning, R.08-02-007 at p. 3 (Dec. 3, 2009), available at http://docs.cpuc.ca.gov/efile/RULINGS/110674.pdf (next LTPP proceeding will examine the OTC retirement issues and integrate 33% RPS goal).

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Even if more backup was needed for renewable energy, energy storage and

upgraded existing facilities can meet this need. Importantly, wind and solar PV energy

can be stored at a commercial level.72 Existing battery storage technology and other

types of storage technology already provide a way to store renewable energy,73 and

PG&E itself has currently existing technology that can back up renewable energy. For

instance, the Helms Pump Storage Facility in PG&E’s system currently provides 600

MW of backup power for renewable energy.74 Indeed, the CEC has further found that

existing storage technology is sufficient to back up renewable energy,75 a conclusion also

reached by CAISO.76

Furthermore, to the extent that backup fossil fuel energy for intermittent

renewable generation is needed, the most environmentally beneficial way to accomplish

this is not to build additional unneeded fossil fuel facilities, but to install existing

technology such as OpFlex, a relatively simple way to upgrade existing natural gas

facilities that allows for faster, more efficient startup times.77

3. PG&E Should Be Required to Demonstrate Actual Need Before It Is Allowed To Procure Any Megawatts Due to a Contingent Risk; This Analysis Can Be Conducted in the 2010 LTPP.

The Commission should not approve the new facilities in this proceeding based on

the “contingent risk” that other power projects in PG&E’s service area may ultimately 72 See Ex. 501 (Test. of Rory Cox) at p. 8 (discussing 2009 IERP that concluded that commercial battery storage technology for renewable energy is available); see id. at p. 9 (discussing commercial availability of renewable energy storage technology, including PG&E’s Helms Pump Storage Facility); Ex. 500 (Test. of B. Powers) at p. 11 (discussing “utility-scale battery storage projects in California.”). 73 See Ex. 501 (Test of R. Cox) at p. 8 (quoting CEC report in finding that increased natural gas facilities are not needed in light of existing battery storage technology); see also id. at p. 9 (CAISO has found the same). 74 See Ex. 501 (Test. of R. Cox) at p. 9 (citing California ISO, Integration of Renewable Resources at p. 94). 75 See Ex. 501 (Test. of R. Cox) at p. 8 (citing 2009 IEPR at pp. 86, 192). 76 See Ex. 501 (Test. of R. Cox) at p. 8 (citing California ISO, Integration of Renewable Resources at p. 21 (November 2007), available at http://www.caiso.com/1ca5/1ca5a7a026270.pdf). 77 See Ex. 501 (Test. of R. Cox) at pp. 10-11 (citing various documents from other facilities discussing the benefits of OpFlex).

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fail to be built.78 Importantly, a recent Commission decision counsels against allowing

utilities to recover rates in anticipation of potential cost overruns, holding instead that

recovery based on contingent risk should be deferred until an after-the-fact

reasonableness review is conducted “to ensure just and reasonable rates.”79 Accordingly,

potential cost overruns due to unrealized contingencies are not recoverable unless and

until the utility proves that they are reasonable and necessary.80

Here, PG&E’s procurement of excess capacity in anticipation of project failure is

unreasonable and unnecessary. Last year, NP26 had a 44% reserve margin at the summer

peak.81 In conjunction with the factors discussed above, PG&E does not need any new

MW in its territory. PG&E should be required to show why additional MW would be

reasonable and necessary given this extraordinarily high reserve margin. This analysis

can be completed in the 2010 LTPP.82

C. The Marsh Landing PPA and Oakley Generating Station PSA Are Not Reasonable or in the Best Interest of PG&E’s Customers.

The Public Utilities Code contains several provisions designed to protect

ratepayers. In particular, transactions must be used and useful to receive rate base

treatment.83 Public Utilities Code Section 451 further requires that charges to ratepayers

78 PG&E and CUE/CURE make this argument in their testimony. See, e.g., Ex. 300 (CUE/CURE Testimony) at pp. 8-11. 79 D.10.02.032 (February 25, 2010) at p. 128. 80 Id. 81 See Ex. 502 (B. Powers & R. Cox Reply Test.) at pp. 2-3 82 See Assigned Commissioner’s Ruling Addressing Future Commission Activities Related to Procurement Planning, R.08-02-007 at p. 3 (Dec. 3, 2009), available at http://docs.cpuc.ca.gov/efile/RULINGS/110674.pdf (next LTPP proceeding will examine the OTC retirement issues and integrate 33% RPS goal). 83 See Pub. Util. Code §§ 454.8, 701.10(a), 727.5(e), 790(b) & (e); see Toward Utility Rate Normalization v. Public Utilities Com., 44 Cal.3d 870, 877 (Section 454.8 codifies the “key principle that costs borne by ratepayers should closely match benefits they receive”) (internal quotation marks omitted); accord D.09-06-049 (“the Commission has an ongoing duty to ensure that utility investments result in infrastructure that is used and useful”).

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are “[j]ust and reasonable rates . . . based on the cost to serve.”84 Over-procuring fossil

fuel energy by allowing PG&E to procure energy from the two unneeded proposed

facilities would not be useful, just, or reasonable for the ratepayers.

Foremost, over-procurement is not needed.85 To determine whether a transaction

is used and useful, a utility must show a “reasonable need.”86 PG&E does not have a

reasonable need,87 and therefore procurement of additional fossil fuel MW is not useful,

just, or reasonable.

Moreover, PG&E’s request to over-procure unneeded fossil fuel energy is not just

or reasonable considering its failure to meet California’s Renewable Portfolio Standards

(RPS).88 Achieving the RPS is a central goal of the Commission and the State.89 AB 32

also requires a reduction in greenhouse gas emissions to 1990 levels by 2020.90 The

cornerstone of the State’s plan for meeting AB 32 is the RPS.91 The RPS Program

requires utilities to increase procurement from renewable energy resources by at least 1%

of their retail sales annually, until they reach 20% by 2010.92

84 Cal. Pub. Util. Code § 451; see also D.04-12-048. 85 See supra at Section III.B. 86 Cf. D.05-12-020 at 20 (finding equipment was “used and useful” because utility had established its “reasonable need”). 87 See supra at Section III.B. 88 See supra at Section III.C. 89 Cal. Pub. Util. Code § 701; see also Cal. Pub. Util. Code § 701.3; (D.) 95-12-063 (“The Commission's recent policy of encouraging resource diversity through the development of new renewable resources is derived from 701.1 and 701.3.”), Cal. Pub. Util. Code § 701.4 (“It is the policy of the state and the intent of the Legislature that state and municipal electric resource acquisition programs recognize and include a value for the resource diversity provided by renewable resources.”); see also D.07-12-052 at pp. 42, 74 (recognizing the importance of achieving the renewable standards). 90 Cal. Health & Safety Code § 38500, et. seq.; see also Press Release from Office of the Governor: Gov. Schwarzenegger Signs Executive Order to Advance State’s Renewable Energy Portfolio Standard to 33 Percent by 2020 (September 15, 2009). 91 Id. at ES-3 (Dec. 2008); see also Re Integration of Greenhouse Gas Emissions Standards into Procurement Policies, D. 08-10-037 at p. 3 (Oct. 16, 2008) (“We emphasize that the foundation for success to reduce GHG emissions in the electricity sector is more energy efficiency and further development of renewable energy sources such as wind, solar, geothermal, and biomass.”), at p. 4 (“Renewable resources are essential for reducing GHG emissions and reaching AB 32 goals, and are a crucial aspect of the future low-carbon economy that will be required to meet California’s 2050 climate goals.”). 92 Cal. Pub. Util. Code § 399.11.

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Since PG&E’s LTPP was approved by the Commission in 2007, Executive Order

S-14-08 accelerated RPS goals. Executive Order S-14-08 now requires that utilities serve

their load based with 33% renewable energy by 2020.93 As the Commission recently

recognized, “[p]ursuing a 33% target is a policy goal of the Commission and one that

should be pursued by the IOUs at this time.”94 The Commission has authority to take all

“appropriate action” to ensure that utilities meet this goal.95

Concerns about the reliability and price fluxuation of natural gas have also driven

the need for increased renewable procurement.96 The CEC has recommended that the

Commission should “mitigate the risk of relying heavily on natural gas by reducing

demand for natural gas for power generation through greater reliance on renewable

generation.”97 Similarly, the Commission has recognized that “[a] higher renewables

mandate would mitigate consumer’ exposure to natural gas price risk likely to come as

demand for natural gas intensifies and supply diminishes.”98

Recent estimates show that only 14.4 percent of PG&E’s electricity comes from

renewable sources.99 PG&E has consistently failed to meet its RPS goals, and it’s likely

that PG&E will not have the required 20% by 2010.100 Despite this, PG&E continues to

93 Executive Order S-14-08 (11/17/2008), available at http://gov.ca.gov/executive-order/11072. 94 R.08-08-009 (Dec. 17, 2009); D.09-12-041(Dec. 17, 2009); see also Final Opinion on Greenhouse Gas Regulatory Strategies, D. 08-10-037 at p. 92 (Oct. 16, 2008), available at http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/92591.pdf (“We pledge to use our best efforts and to support the efforts of others to achieve 33% renewables by 2020.”). 95 See Cal. Pub. Util. Code § 399.14(e); Cal. Pub. Util. Code § 399.13; § 399.15(a). 96 Re Integration of Greenhouse Gas Emissions Standards into Procurement Policies, D. 08-10-037 at p. 3 (Oct. 16, 2008). 97 Re Policies and Cost Recovery Mechanism for Generation Procurement and Renewable Resource Development Respondents: Pacific Gas and Electric Company, et. al., D. 04-01-050 at p. 65 (Jan. 22, 2004). 98 Re Integration of Greenhouse Gas Emissions Standards into Procurement Policies, D. 08-10-037 at p. 42 (Oct. 16, 2008); see also Ex. 501 (Test of R. Cox) at pp. 8-9 (reliability of wind and solar energy increases with amount and geographic extent of renewable projects). 99 California Public Utility Commission Website, California Renewables Portfolio Standards, available at http://www.cpuc.ca.gov/PUC/energy/Renewables/index.htm. 100 See Ex. 501 (Test. of R. Cox) at p. 11 (citing Commission RPS Quarterly Report (July

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add new MW from natural gas generation.101 In the event that a utility fails to meet its

RPS mandates, that utility “shall procure additional eligible renewable energy resources

in subsequent years to compensate for the shortfall.”102 PG&E has not yet met, let alone

exceeded, its RPS goals. Thus, allowing PG&E to procure an additional 1,305 fossil-fuel

MW makes little sense when seeking to pursue RPS goals. Moreover, allowing

additional, and unneeded, procurement of fossil fuel energy is inconsistent with the

loading order of California’s Energy Action Plan, which prioritizes energy efficiency and

renewable energy over fossil fuel generation.103

Finally, allowing PG&E to procure unneeded fossil fuel energy would likely

crowd out renewable projects. The LTPP decision reiterated that PG&E should not

“crowd out preferred resources and/or systematically overprocure.”104 As the

Commission stated, “AB 32 and Senate Bill (SB) 1368, California's Climate Change

laws, provid[e that] . . . procurement must now consider carbon risk when filling net short

positions with fossil resources, so as not to ‘crowd out’ preferred resources.”105 Thus, the

Commission should not approve PG&E’s request to procure unneeded fossil fuel energy.

2008) at p. 11, available at http://docs.cpuc.ca.gov/word_pdf/REPORT/85936.pdf).; see also See California Energy Commission, Report On Progress Of Publicly Owned Utilities In Implementing Renewable Portfolio Standards (Consultant Report, Dec. 2008) at pp. 30, 33, available at http://www.energy.ca.gov/2008publications/CEC-300-2008-005/CEC-300-2008-005.PDF.). 101 See Ex. 501 (Test. of R. Cox) at p.11; Ex. 200 (Test. of TURN) at p. 17 (procuring additional gas resources is inconsistent with 33% renewable RPS goal). 102 Cal. Pub. Util. Code § 399.15(b)(4). 103 Integrate and Refine Procurement Policies Underlying Long-Term Procurement Plans, R. 08-02-007 (Feb. 14, 2008). 104 D.07-12-052 at p. 42; see also Ex. 502 (Reply Test. of R. Cox and B. Powers) at p. 2 (Lawrence Berkeley National Laboratory study found that California would need to reduce natural gas plant capacity to meet the 33 percent renewable energy requirement.). 105 R.08-02-007 at p. 1 (Feb. 14, 2008).

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D. PG&E Should Not Be Authorized to Recover Costs Incurred Pursuant to the PPAs in the Energy Revenue Recovery Account and to Recover Any Stranded Costs Associated with the Agreements.

PG&E should not be allowed to recover costs incurred pursuant to the PPAs in the

ERRA and to recover stranded costs associated with the agreements. Neither of these

two facilities are needed, just, reasonable, used, or useful.106

E. PG&E’s Rate Recovery and Initial Annual Revenue Requirement Proposals for the Contra Costa Project, as Modified by the Partial Settlement Agreement Dated February 17, 2010, Should Not Be Approved.

PG&E should not be allowed to recover rates and initial annual revenue

requirements under the Proposed Partial Settlement agreement unless the MW are

needed, the proposed facilities are just and reasonable, and PG&E’s conduct of the 2008

LTRFO was reasonable and consistent with Commission directives. None of these

prerequisites have been satisfied.107

In addition, the Oakley Generating Station costs appear to be unreasonable in

comparison to the lower costs at the Colusa Generating Station.108 The Colusa PSA

comparison is relevant and valuable, and PG&E’s failure to explain in any detail why

market conditions might have changed is insufficient to demonstrate why costs above the

Colusa PSA are reasonable. 109 PG&E’s failure is especially glaring since PG&E took

over the Colusa PSA around April 2008,110 which was the same month that PG&E

requested offers in response to the 2006 LTPP.111

106 See supra at Sections III.B and III.C. 107 See supra at Section III.B and infra at Section III.F (discussions above and below which demonstrate that the facilities are not needed and PG&E’s conduct of the LTRFO was not reasonable and consistent with Commission directives). 108 See Ex. 7 (Settling Parties’ Reply Comments, filed March 24, 2010 in A.09-09-021) at p. 5. 109 See id. at p. 5 (PG&E argues that Colusa costs are irrelevant because “market conditions have changed and unfortunately the Colusa PSA price no longer reflects current market conditions.”). 110 http://www.pge.com/about/news/mediarelations/newsreleases/q2_2008/080423.shtml 111 See Ex. 1 (PG&E Direct Test., A.09-09-021, Long Term Request for Offers).

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PG&E should not be allowed to recover rates under the Proposed Partial

Settlement because the two proposed facilities do not meet operational flexibility

requirements. In particular, PG&E states that it needs facilities to be able to start in 10

minutes.112 Yet, according to the documents before the CEC, the Marsh Landing owner

has requested a start time longer than 12 minutes113 and the Oakley Generating Project

documents assume a start time of 30 minutes.114

Moreover, PG&E has failed to demonstrate why the Proposed Partial Settlement

is reasonable when the operating profile assumed in the settlement is different than the

profile in the PSA.115 In particular, PG&E states that “[t]he operating profile referenced .

. . that included 333 starts and 4,329 hours of operation was for purposes of developing

the O&M forecast only and does not reflect PSA requirements.”116 PG&E’s assurance

that it will terminate the agreements with the proposed facilities at issue here if the

permits do not meet or exceed the permitted requirements does not explain why it used

numbers for the Proposed Partial Settlement that do not reflect the requirements in the

PSA agreement.

112 See Ex. 5 (PG&E Reply Test.) at p.18, nn. 53, 54. 113 See Marsh Landing Data Request 7, available at http://www.energy.ca.gov/sitingcases/marshlanding/documents/applicant/data_request_responses_1-54/01_MLGS%20Response%20to%20Data%20Requests%201-54.pdf. 114 See Oakley Generating Station Application for Certification, Data Request Responses 1-43 (Docket # 09-AFC-4) at p. 5, available at http://www.energy.ca.gov/sitingcases/contracosta/documents/index.html. 115 Notably, PG&E did not produce the operating scenarios in its initial testimony until after the Proposed Partial Settlement was filed. See Proposed Exhibit List, A.09-09-021, filed April 7, 2010 (Ex. 82-C is dated 4/1/10). PG&E also failed to explain how it took the operating constraint for Marsh Landing into consideration by only citing its own unsupported reply testimony. See Ex. 7 (Settling Parties’ Reply Comments) at p. 12. 116 See Ex. 7 (Settling Parties’ Reply Comments) at p.14.

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F. PG&E’s Conduct of the 2008 LTRFO Was Neither Reasonable Nor Consistent with Commission Directives.

1. PG&E Was Required to Consider Environmental Impacts of the Proposed

Plants. In assessing reasonableness, the Commission considers environmental impacts,

“including air quality.”117 In addition, section 453 of the Public Utility Code provides

that “[n]o public utility shall, as to rates, charges, service, facilities, or in any other

respect, make or grant any preference or advantage to any corporation or person or

subject any corporation or person to any prejudice or disadvantage.”118 Consistent with

these requirements, in D.07-12-052, the Commission directed utilities to “provide greater

weight [to issues such as] disproportionate resource sitings in low income and minority

communities and environmental impacts/benefits.”119

To consider environmental impacts in the 2008 LTRFO, PG&E committed to

“assess the potential cumulative pollution exposure of the community to criteria

pollutants in air, water, and soil within 1 mile and within 6 miles of Participants proposed

facility.”120 As part of this process, PG&E stated that it would include “among other

things . . . local community outreach plans.”121 PG&E further states on its website that it

“will conduct its operations in a manner that is consistent with and promotes

environmental justice principles.”122 As part of this environmental leadership analysis,

PG&E ranked the offers for “how well they reflected California’s and PG&E’s energy

and environmental policies and goals.”123

117 Cal. Pub. Util. Code § 701.1(c). 118 Cal. Pub. Util. Code Section 453. 119 D.07-12-052 at p.157; see also D.07-12-052 at Finding 35 and 103. 120

See Ex. 1 at PG&E’s Long Term Request for Offers Protocol at p. 15, available at http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitation/allsourcerfo/. 121 See Ex. 5 at p. 24. 122 http://www.pge.com/includes/docs/pdfs/about/environment/pge_ej_policy.pdf. 123 Ex. 1 at 3-7; see Ex. 31-C (showing environmental leadership rankings of offers).

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2. PG&E Failed to Follow Its Environmental Leadership Protocol and Consider the Environmental Impacts from the Plants.

PG&E did no analysis of how these two polluting facilities would impact the

already overburdened area.124 In fact, PG&E did not even make the effort to obtain and

examine the facilities’ air permits.125 Moreover, PG&E did not present any evidence of

any community outreach that it conducted in the community. 126

Despite these failures, PG&E, in its reply testimony, claims that it, “fully

followed its Environmental Leadership Protocol which provided for, among other things,

assessments of cumulative impacts.”127 Yet when asked, PG&E admitted that the only

environmental considerations it made related to these facilities was that it was extending

the retirement of Contra Costa 6 and 7 and that the facilities would use efficient

equipment.128 This does not suffice as the environmental analysis required by PG&E’s

environmental leadership protocol and Commission directives.

In fact, PG&E’s environmental considerations could actually result in worsening

air quality in the County. PG&E proposes extending the retirement of Contra Costa units

6 and 7 to the end of 2017 from its proposed earlier retirement date.129 This negates the

point that PG&E tries to make in its testimony that this application will reduce the

concentration of generating facilities in the County.130 Moreover, in 2008, Unit 6 ran

124 See Exs. 54, 56, 57, 62, 63, 70 and 75 (PG&E answers to data requests asking for its environmental analysis). 125 See Ex. 61 (replying that PG&E does not have draft air permits). 126 See Ex. 70. 127 See Ex. 5 at p. 24; see also Ex. 56 (objecting to request asking for any cumulative impacts analysis conducted and presenting no evidence that such an analysis was conducted); Ex. 62 (same). 128 See Exs. 57, 63, 70 (not providing an analysis that would demonstrate how the proposed plants would, or would not, contribute to environmental health issues in the community). 129 Compare D.07-12-052 at p. 116 with Draft Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plaint Cooling (November 23, 2009), available at http://www.swrcb.ca.gov/water_issues/programs/npdes/docs/cwa316/otcpolicy112309_clean.pdf. 130 See Ex. 1 (PG&E Test.) at p. 4-8,.

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only 1 percent of the time, while Unit 7 ran only 4 percent of the time.131 Switching low

capacity units with high capacity units (even allowing for the low end 20% capacity

estimate of the Marsh Landing facility) creates more pollution.132

Furthermore, as discussed below, the use of the General Electric (GE) 7FA.05

combustion turbine will not likely improve air quality in the County since the turbines

will still emit significant emissions. In fact, the more efficient turbines may cause the

facilities to be operated more often, as the higher efficiency could easily allow for higher

usage, which would result in worse air quality.

3. If PG&E Had Analyzed the Environmental Impacts of the Facilities, It Should Not Have Chosen Them.

PG&E’s proposal to build these plants in an area with a low-income community

already disproportionately impacted by air pollution is contrary to PG&E’s

environmental leadership requirements and Commission directives.

The proposed Oakley Generating Station and Marsh Landing Generating Station

are located in an area with a high minority133 and low-income134 population that is

already heavily impacted by pollution. In fact, over half of all the power generated in the

Bay Area is generated from power plants located in Contra Costa County.135 There are

131 See Ex. 501 (Test. of R. Cox) at p. 6 (citing California Energy Commission, Comments to State Water Resources Control Board Concerning Its Coastal Power Plant Preliminary Draft Policy and Related Scoping Document (May 2008) at p. 19, available at http://www.energy.ca.gov/siting/documents/2008-05- 20_CHAIRMAN_SWRCB.PDF). 132 See Mirant Responses to Data Request Set 3, CEC Docket 08-AFC-3, at p. 72-1 (February 11, 2010) available at http://www.energy.ca.gov/sitingcases/marshlanding/documents/index.html#applicant. 133 See Ex. 501 (Test. of R. Cox) at p. 18 (citing Bay Area Census, City of Antioch, available at http://www.bayareacensus.ca.gov/cities/Antioch.htm; see also Contra Costa Health Services, Chronic Disease Prevention: A Framework for Contra Costa County, available at http://cchealth.org/groups/chronic_disease/framework.php (describing how West Contra Costa County is composed of significant percentage of minorities)). 134 See id. at p. 18 (citing Contra Costa Health Services, Health Indicators for Selected Cities and Places in Contra Costa County, available at http://cchealth.org/health_data/hospital_council/pdf/poverty.pdf). 135 See Ex. 501 (Test. of R. Cox) at p.17 (citing http://energyalmanac.ca.gov/powerplants/POWER_PLANTS.XLS); see also Ex. 301 (Reply Test. of

25

also numerous oil refineries and chemical plants located in the County.136 Altogether, the

County has five times the number of facilities that emit criteria air pollutants per square

mile than the California average.137

Not surprisingly, the area where the proposed Oakley Generating Station and

Marsh Landing Generating Station are located has high levels of air pollution.138

According to the Bay Area Quality Management District (BAAQMD), the county’s air

quality currently does not meet federal air quality standards intended to protect public

health for ozone and fine particulate matter.139 In particular, the Pittsburg and Bethel

Island ambient air monitors – the monitors nearest to the proposed power plants – have

shown higher than allowable levels of the state ozone standard.140

The proposed Marsh Landing and Oakley power plants will emit substantial

amounts of ozone, particulate matter, and other pollutants. For example, according to the

information submitted to the CEC, the Oakley Generating Station is expected to annually

emit 98.8 tons of NOx, 50.8 tons of CO, 76.3 tons of PM10, and 12.6 tons of SO2.141 The

Marsh Landing Generating Station is expected to annually emit 97 tons of NOx, 187.4

CUE/CURE) at p. 6, n.24 (not disputing that over half of the MW generated in the Bay Area is generated in Contra Costa County). 136 See Ex. 501 (Test. of R. Cox) at pp. 17-18 (citing Air Resources Board, Facility Search Engine, available at http://www.arb.ca.gov/ei/disclaim.htm); see also id. at Attachment 3 (listing facilities approximately within 6 miles of proposed facilities). 137 Id. 138 Id. (“the part of the County where these proposed plants are to be sited is in the top ten percentile in the nation for criteria pollutant emissions.”) (citing Scorecard: The Pollution Information Website, Criteria Air Pollutant Report for Contra Costa County, available at http://www.scorecard.org/env-releases/cap/county.tcl?fips_county_code=06013.). 139 See Bay Area Air Quality Management District, Attainment Status, available at http://hank.baaqmd.gov/pln/air_quality/ambient_air_quality.htm. 140 See Ex. 501 (Test. of R. Cox) at p. 19 (citing Bay Area Air Quality Management District, Air Quality Monitoring Data, PM 2.5 Continuous, available at http://gate1.baaqmd.gov/aqmet/AQYearly.aspx). 141 http://www.energy.ca.gov/sitingcases/contracosta/documents/applicant/2010-02-11_Applicant_Response_to_Data_Requests_Set_1_1-43_TN-55333.pdf (This document was submitted to the CEC on 3/10/10 and so was unavailable at time of R. Cox’s testimony, which cited previous data submitted by applicant).

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tons of CO, 35.02 tons of VOC, 12.64 tons of SO2, and 47.24 tons of PM10.142 These

numbers will be higher if the facility goes over its proposed permitted operation.143

As the U.S. Environmental Protection Agency (EPA) has found, these pollutants

increase the likelihood of adverse cardiovascular and respiratory impacts such as

asthma.144 For example, EPA has stated that exposure to fine particulate matter likely

causes adverse cardiovascular and respiratory responses (including increases in asthma)

as well as higher levels of mortality.145

Health problems such as asthma are already disproportionately high in Contra

Costa County. According to the Contra Costa Asthma Coalition, the prevalence of

asthma for 5-17 year olds, which is about fourteen percent nationwide, is almost twenty

four percent in Contra Costa County,.146 Moreover, asthma disproportionately impacts

minority children. According to Contra Costa Health Services, the hospitalization rate

for asthma for African American children in Contra Costa County is four times higher

than that for Caucasian children in the County.147 There are other significant health

142 Id. 143 See Mirant Response to Data Request Set 3, CEC Docket 08-AFC-3 (Feb. 11, 2010) at p. 72-1 144 See, e.g., U.S. Environmental Protection Agency, Cleaning Up Common Pollutants, available at http://www.epa.gov/air/caa/peg/cleanup.html; California Air Resources Board, Asthma and Air Pollution, available at http://www.arb.ca.gov/research/asthma/asthma.htm. The ARB-funded Children’s Health Study found that children who lived in communities with high ozone levels and participated in several sports were more likely to develop asthma than the same active children living in areas with less ozone pollution. In another ARB-funded study, researchers found a positive association between some volatile organic compounds and symptoms in asthmatic children from Huntington Park, a predominantly Latino suburb of Los Angeles. 145 See Ex. 501 (Test. of R. Cox) at p. 20 (citing U.S. Environmental Protection Agency, Integrated Science Assessment for Particulate Matter, National Center for Environmental Assessment, Office of Research and Development (December 2009) at p. 2-31, available at http://www.epa.gov/ncea/pdfs/partmatt/Dec2009/PM_ISA_full.pdf. 146 See Ex. 501 (Test. of R. Cox) at p. 21 (citing Contra Costa Asthma Coalition, available at http://www.calendow.org/uploadedFiles/CAFA3_CCscreen.pdf (Contra Costa County asthma rate in children is 23.7%, whereas national rate is 14.2%). 147 See Ex. 501 (Test. of R. Cox) at p. 21 (citing Contra Costa Health Services, Health Disparities in Contra Costa, available at http://cchealth.org/groups/rhdi/pdf/health_disparities_in_cc.pdf.).

27

issues in the County that could be impacted by the proposed facilities, especially since

43% of the low income residents in the County do not have health insurance.148

In light of the disproportionate burden of pollution and health impacts this area

already experiences, it is unlikely that PG&E would have chosen the Marsh Landing and

Oakley proposals had it actually followed its own LTRFO environmental commitments

and environmental justice policy.149

IV. CONCLUSION

The Commission should reject PG&E’s attempt to procure unneeded energy from

an area already overburdened by pollution, which would not be used, useful, just or

reasonable for the ratepayers.

Respectfully submitted,

April 14, 2010 _/s/ Deborah Behles__________________ DEBORAH BEHLES LUCAS WILLIAMS

Environmental Law and Justice Clinic Golden Gate University School of Law 536 Mission Street San Francisco, CA 94105-2968 Telephone: (415) 442-6647 dbehles@ggu.edu

Attorneys for Pacific Environment

148 See Ex. 501 (Test. of R. Cox) at pp. 21-22 (citing data from Contra Health Services that shows a higher incidence of cancer and stroke in the County). 149 See PG&E’s Environmental Justice Policy at http://www.pge.com/includes/docs/pdfs/about/environment/pge_ej_policy.pdf.

APPENDIX A

Utility-Scale Solar Projects Contracted With PG&E150 Developer Project Name Electricity

Purchaser Location Capacity

(MW) Projects Under Construction: GreenVolts, Inc. GV1 PG&E Byron, CA 2 Cleantech America, Inc. CalRENEW-1 PG&E Mendota, CA 5 Projects Under Development: Abengoa Solar Mojave Solar PG&E San Bernardino County,

CA 250

BrightSource Energy Ivanpah Solar Electricity Generating System (SEGS) I

PG&E Barstow, CA 126

BrightSource Energy Ivanpah Solar Electricity Generating System (SEGS) III

PG&E Barstow, CA 133

BrightSource Energy Coyote Springs 1 PG&E Coyote Springs, NV 200 BrightSource Energy Coyote Springs 2 PG&E Coyote Springs, NV 200 eSolar Apline SunTower PG&E Lancaster, CA 92 NextEra Energy Resources Genesis Solar

Energy Project PG&E Riverside County, CA 250

San Joaquin Solar, LLC San Joaquin Solar 1

PG&E Coalinga, CA 53

San Joaquin Solar, LLC San Joaquin Solar 2

PG&E Coalinga, CA 53

Solar Reserve Rice Solar Energy Project

PG&E Riverside County, CA 150

Solel Mojave Solar Park PG&E Mojave Desert, CA 553 First Solar Topaz Solar Farm PG&E Carrisa Plains, CA 550 First Solar Desert Sunlight PG&E Desert Center, CA 300 First Solar/Sempra Generation

Copper Mountain Solar Project

PG&E Boulder City, NV 48

Nextlight Renewable Power

Aqua Caliente PG&E Yuma County, AZ 290

Nextlight Renewable Power

AV Solar Ranch One

PG&E Antelope Valley, NV 230

Solar Project Solutions PG&E Tulane County, CA 20 Solar Project Solutions PG&E Tulane County, CA 20 Solar Project Solutions PG&E Tulane County, CA 20 Solar Project Solutions PG&E Kings County, CA 20 Solar Project Solutions PG&E Tulane County, CA 50 Solon Corporation PG&E CA 2 Total MW 3617

150 Information taken from tables created by Solar Energy Industries Association (SEIA) available at http://www.seia.org/galleries/pdf/Major%20Solar%20Projects.pdf.

CERTIFICATE OF SERVICE

I, Deborah Behles, am over the age of 18 years and employed in the City and County

of San Francisco. My business address is 536 Mission Street, San Francisco, California

94105.

On April 14, 2010, I served the within document PACIFIC ENVIRONMENT’S

OPENING BRIEF, in A.09-09-021, pursuant to the Commission’s Rules of Practice and

Procedure, with separate and additional delivery of hard-copies by U.S. Mail to Assigned

Commissioner Peevey and Assigned ALJ Farrar, at San Francisco, California.

Executed on April 14, 2010, at San Francisco, California. /s/ Deborah Behles Deborah Behles

Electronic Service List, A.09-09-021

JPacheco@sempra.com mdjoseph@adamsbroadwell.com nao@cpuc.ca.gov mflorio@turn.org dbehles@ggu.edu magq@pge.com bcragg@goodinmacbride.com crmd@pge.com l_brown369@yahoo.com slazerow@cbecal.org ed.mainland@sierraclub.org martinhomec@gmail.com blaising@braunlegal.com anne.cleary@mirant.com liddell@energyattorney.com wkeilani@semprautilities.com eklebaner@adamsbroadwell.com AGL9@pge.com filings@a-klaw.com Kcj5@pge.com nes@a-klaw.com will.mitchell@cpv.com sscb@pge.com taj8@pge.com lcottle@winston.com william.kissinger@bingham.com todd.edmister@bingham.com jeffgray@dwt.com vidhyaprabhakaran@dwt.com cem@newsdata.com CPUCCases@pge.com RegRelCPUCCases@pge.com john.chillemi@mirant.com sean.beatty@mirant.com mrw@mrwassoc.com dmarcus2@sbcglobal.net michaelboyd@sbcglobal.net brbarkovich@earthlink.net wynne@braunlegal.com kdw@woodruff-expert-services.com steven@iepa.com abb@eslawfirm.com wmc@a-klaw.com edf@cpuc.ca.gov dbp@cpuc.ca.gov kkm@cpuc.ca.gov mwt@cpuc.ca.gov shi@cpuc.ca.gov ys2@cpuc.ca.gov