BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

In the Matter of the Application of San Diego Gas & Electric Company (U 902-E) for a Certificate of Public Convenience and Necessity for the Sunrise Powerlink Transmission Project

Application No. 06-08-010

(Filed August 4, 2006)

COMMENTS OF SAN DIEGO GAS & ELECTRIC COMPANY ON ALTERNATE PROPOSED DECISION OF COMMISSIONER GRUENEICH

E. Gregory Barnes James F. Walsh SAN DIEGO GAS & ELECTRIC COMPANY 101 Ash Street San Diego, CA 92101 Telephone: 619/699-5019 Facsimile: 619/699-5027 E-mail: gbarnes@sempra.com Attorneys for SAN DIEGO GAS & ELECTRIC COMPANY

November 20, 2008

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TABLE OF CONTENTS Page

SUBJECT INDEX .......................................................................................................................... ii TABLE OF AUTHORITIES ......................................................................................................... iv LIST OF ACRONYMS/CITATION FORM...................................................................................v COMMENTS ON ALTERNATE PROPOSED DECISION ..........................................................1 APPENDIX

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SUBJECT INDEX (Rule 14.3(b))

I. INTRODUCTION .................................................................................................................... 1

II. THE AD ERRS BY NOT FINDING A RELIABILITY NEED FOR SUNRISE.................................................................................................................................. 2

A. The AD’s load and resource baseline violates Commission-adopted CAISO planning guidelines. ............................................................................................... 3

B. It is imprudent to rely on the South Bay plant after 2009 for purposes of reliability planning. ............................................................................................................. 5

C. SDG&E’s recently-adopted LTPP confirms a 2010 reliability need for Sunrise................................................................................................................................. 6

D. The AD’s assumed 2014 reliability need provides a reliability basis for issuing a CPCN authorizing commencement of construction now. ................................... 7

III. ADOPTING THE AD’S COMPLIANCE PHASE WILL DELAY SUNRISE AND CHILL THE DEVELOPMENT OF RENEWABLES................................................... 8

A. The Sunrise compliance phase would substantially delay Sunrise..................................... 9

B. The Sunrise Compliance Plan is, in effect, a “poison pill” for Sunrise .............................. 9

1. The math in the AD is infeasible. ................................................................................. 10

2. Under open access, the SDG&E compliance plan cannot assure that any PPAs will get the rights required to transmit power on Sunrise, making any commitment less than binding. ............................................................................ 11

3. “Chicken & Egg” – Development cannot move forward based upon a contingent transmission line. ...................................................................................... 11

4. The economic showing required by the compliance plan carries the seeds of its own destruction. ....................................................................................... 12

C. The Minnesota case is not useful precedent here.............................................................. 12

D. The Sunrise Compliance Plan is unnecessary because the record contains ample assurances that that Sunrise will deliver “substantial amounts of Imperial Valley renewable energy.” ................................................................................. 13

E. The Sunrise Compliance Plan is bad policy and unduly discriminatory .......................... 14

F. SDG&E offers commitments that will achieve the AD’s goal to ensure that Sunrise will deliver “substantial amounts of Imperial Valley renewable energy.” ........................................................................................................... 14

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1. The “No Conventional Coal” Commitment. SDG&E will not enter into contracts for supply from a conventional coal generator that would deliver across the Sunrise Powerlink. ......................................................................... 15

2. The Renewables Replacement Commitment. SDG&E will commit that if a renewable resource that is deliverable by Sunrise and currently under contract to SDG&E fails, SDG&E will contract to replace that energy with another renewable resource from the same region. ................................ 16

3. The 33% Renewables Target by 2020 Commitment. SDG&E will contract towards a voluntary 33 percent RPS procurement target by 2020............................................................................................................................. 16

IV. THE COST CAP MUST BE ADJUSTED BASED ON CERTAIN RECORD FACTS AND ASSUMPTIONS OVERLOOKED BY THE AD.......................................... 17

A. The initial total construction costs for the FESSR should be increased by $4 million .......................................................................................................................... 17

B. The AD did not account for the expense of undergrounding through Alpine Boulevard, which will increase initial construction costs by $91 million ............................................................................................................................... 18

C. When adjusting for the Coastal Link Alternative, the AD utilizes an erroneous cost estimate for the Coastal Link.................................................................... 19

D. The AD’s adoption of $154 million in mitigation costs is incorrect ................................ 20

E. For the cost cap, the AD should adopt a 10-15% adder to the project cost estimate as a contingency against unforeseen circumstances ........................................... 21

F. The AD’s command that the Commission will re-assess the cost-effectiveness and need for Sunrise if SDG&E exercises its right to increase the cost cap is unduly burdensome and without precedent................................. 21

V. THE AD ERRS BY FINDING THAT P.U. CODE § 399.25 DOES NOT SUPPORT ISSUING A CPCN FOR SUNRISE NOW.......................................................... 22

VI. CONCLUSION...................................................................................................................... 23

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TABLE OF AUTHORITIES

STATUTES & LEGISLATION Cal. Pub. Res. Code § 2106.1 (2008).................................................................................24 Cal. Pub. Util. Code §363 (2008) ........................................................................................5 Cal. Pub. Util. Code § 399.25 (2008) ........................................................................ passim Cal. Pub. Util. Code §1005.5 (2008) ...........................................................................16, 21 Assembly Bill 32, Ch. 488, Stats. 2005-2006 (Cal 2006)..........................................1, 6, 15 Senate Bill 1368, Ch. 598, Stats. 2005-2006 (Cal 2006)...................................................15 Executive Order S-14-08 (Cal, Nov. 17, 2008) .................................................................16 CALIFORNIA PUBLIC UTILITIES COMMISSION DECISIONS Order Modifying LTPP Decision D.07-12-052, D.08-11-008.............................................7 Long Term Procurement Plan Decision, D.07-12-052.............................................. passim In re Antelope-Vincent/Antelope-Techachapi, D.07-03-045 .............................................14 In re Antelope-Pardee, D.07-03-012 ...........................................................................14, 22 Economic Methodology Decision, D.06-11-018..................................................................6 In re Silvergate Substation, D.06-09-022 ..........................................................................20 EMF Decision, D.06-01-042..............................................................................................22 In re SONGS Steam Generator Replacement Project, D.05-12-040 .................................21 Electric Resource Planning OIR, D.04-12-048 .................................................................11 In re Jefferson-Martin, D.04-08-046 ......................................................................... passim In re Valley Rainbow, D.02-12-066........................................................................... passim Transmission OII, D.01-03-077.........................................................................................11

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OTHER PUBLIC UTILITIES COMMISSION DECISIONS Order Granting Certificates of Need Subject to Conditions, Minn. Public Utilities Commission, Docket No. E-002/CN-01-1958 (March 11, 2003)..................................9, 12 Order Clarifying and Amending Order of March 11, 2003, Minn. Public Utilities Commission, Docket No. E-002/CN-01-1958 (May 16, 2003)...................................12, 13 Order Approving Design Change, Encouraging Technical Discussions and Requiring Update, Minn. Public Utilities Commission, Docket No. E-002/CN-01-1958 (July 13, 2004) ..............................................................................12,13 OTHER AUTHORITIES Cal. Pub. Util. Comm. Rule of Practice and Procedure 14.3...............................................1 Energy Division Resolution E-4189 (September 4, 2008) ..................................................3

LIST OF COMMONLY USED ACRONYMS/ABBREVIATIONS

AB Assembly Bill ABDSP Anza Borrego Desert State Park AD Alternate Decision AFUDC Allowance for Funds Used During Construction ALJ Administrative Law Judge BLM Bureau of Land Management CCGT Combined Cycle Gas Turbine CEC California Energy Commission CEO Chief Executive Officer CEQA California Environmental Quality Act CPCN Certificate of Public Convenience and Necessity CPUC California Public Utilities Commission DEIR Draft Environmental Impact Report EMF Electric and Magnetic Field FEIR Final Environmental Impact Report FERC Federal Energy Regulatory Commission FESSR Final Environmentally Superior Southern Route GHG Green House Gas GWH Gigawatt Hour IEPR CEC’s Integrated Energy Policy Report kV Kilovolt LTPP Long-term Procurement Plan MNPUC Minnesota Public Utilities Commission MW Megawatt OIR Order Instituting Rulemaking

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PD Proposed Decision PEA Proponent’s Environmental Assessment PG&E Pacific Gas & Electric Company PPA Power Purchase Agreement PV Photovoltaic P.U. Code California Public Utilities Code RDEIR Redistributed Draft Environmental Impact Statement RETI California Renewable Energy Transmission Initiative RFO Request for Offers RMR Reliability Must Run RPS Renewable Portfolio Standard SCE Southern California Edison WECC Western Electricity Coordinating Council

RECORD CITATION FORM

Record exhibits are cited “[witness surname, if applicable], Ex. [number] at [chapter. page(s):line(s) [to the extent applicable].” The record transcript is cited “[witness surname, if applicable], T.[page(s):line(s)].” Where a citation appears in a heading or at the end of a paragraph, the citation is to evidence or authority for the entire section or paragraph.

SHORT FORM PARTY DESIGNATIONS

CAISO California Independent System Operator CBD Center for Biological Diversity Conservation Groups CBD and the San Diego Chapter of the Sierra Club DRA Division of Ratepayer Advocates IID Imperial Irrigation District MGRA Mussey Grade Road Alliance Powers Mr. Bill Powers SDG&E San Diego Gas & Electric Company State Parks California State Parks Foundation TNHC The Nevada Hydro Company UCAN Utility Consumers’ Action Network

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

In the Matter of the Application of San Diego Gas & Electric Company (U 902-E) for a Certificate of Public Convenience and Necessity for the Sunrise Powerlink Transmission Project

Application No. 06-08-010

(Filed August 4, 2006)

COMMENTS OF SAN DIEGO GAS & ELECTRIC COMPANY ON ALTERNATE PROPOSED DECISION OF COMMISSIONER GRUENEICH

Pursuant to Rule 14.3 of the Commission’s Rules of Practice and Procedure, applicant

San Diego Gas & Electric Company (“SDG&E”) submits these comments on the Alternate

Proposed Decision of Commissioner Grueneich (“AD”).1

I. INTRODUCTION

As stated by Debra Reed, SDG&E’s CEO, at the November 7, 2008 en banc oral

argument in this matter (T.6238:13-18), SDG&E supports substantial elements of the AD as a

means of moving forward with this important project. But, after three years of litigating this

application, SDG&E is focused on how the Commission can use the AD as a basis for granting a

CPCN with full authority to commence construction now. Specifically, SDG&E agrees with the

AD’s finding that the Sunrise Powerlink is an economic project needed to meet AB 32

requirements and a 33 percent renewable goal. We also support the selection of the southern

route that avoids the Anza-Borrego Desert State Park. And we agree with the AD’s objective to

use Sunrise to deliver newly-developed renewables from the Imperial Valley region2 into the

1 The AD, issued Oct. 31, 2008, is entitled Decision Granting as Conditioned a Certificate of Public

Convenience and Necessity for the Sunrise Powerlink Transmission Project. SDG&E will respond separately to Commissioner Grueneich’s Ruling Requesting Comments on Revised Section 19 (Nov. 18, 2008).

2 The “Imperial Valley area” means the area east of the Miguel substation (including east San Diego County where renewables seek to interconnect to the South West Power Link) to the Imperial Valley Substation, Northern Baja, and the Imperial Valley in which areas Sunrise facilitates the development of renewables by addressing the CAISO’s existing 1150 MW dispatch limit. Woldemariam, Ex. SD-35 at 6.28. It has been generally understood in discourse in this proceeding that references to renewable development in the Imperial Valley includes these nearby areas in Mexico and San Diego County.

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California energy market. However, the AD contains three major legal and factual errors that

must be corrected in the Commission’s final decision in this matter.

First, the Commission must correct the AD’s finding that Sunrise is not needed for

reliability because San Diego does not have a reliability deficiency until 2014 (AD at 104).

Second, the Commission should substitute the Company’s voluntary commitments for the

renewable compliance plan, eliminating yet another phase of litigation that would have been

required before final approval and commencement of construction (AD at 262). Third, the basis

for the cost cap must be corrected to conform to the record and to Commission precedent.

In addition, we seek correction of some other aspects of the AD that are easily cured,

completely devoid of support in the record, set a bad precedent, or are contrary to state policies

such as its findings on EMF and that P.U. CODE § 399.25 ”is inapplicable to Sunrise.” In sum, to

facilitate quick Commission resolution, the changes recommended below are limited to those

few areas where correction is necessary for the project to proceed, or for other important public

interest objectives. To this end, SDG&E does not attempt here to address each and every legal

or factual error in the AD. We detail below how the law, the record and the pubic interest

support these crucial modifications of the AD.

II. THE AD ERRS BY NOT FINDING A RELIABILITY NEED FOR SUNRISE

The AD finds that Sunrise is not needed for reliability until 2014 (AD at 104), and

declines to find any need for Sunrise based on reliability. It further orders the litigation of a

compliance phase before construction can start – a phase that contemplates yet another round of

prepared testimony, economic modeling, hearings, and briefs, which would likely postpone final

approval of Sunrise for at least a year. See section III.A, infra. Even if one accepts the AD’s

2014 date as the first year Sunrise is needed for reliability, common sense and prudent planning

suggest that this finding provides a reliability basis for a CPCN permitting construction to begin

now. Moreover, the AD bases this finding on an analytical baseline that is contrary to the

evidence and represents a flawed understanding of prudent planning principles. As shown

below, this baseline includes assumptions about in-basin generation that violate CAISO planning

guidelines adopted by this Commission, contradict the record evidence, and contradict SDG&E’s

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long-term procurement plan (“LTPP”) recently approved by the Commission.3 And, reliance on

a single scenario to determine reliability need is contrary to prudent planning principles.

For the reasons set forth in the following sections, SDG&E requests that the Commission

confirm that Sunrise is needed for reliability and issue a CPCN immediately on that basis.

A. The AD’s load and resource baseline violates Commission-adopted CAISO planning guidelines.

The AD assumes that 540 MW from the Carlsbad Energy Center will come online in the

summer of 2013, resulting in a net increase of 222 MW. AD at 36. It further assumes that the

existing South Bay Power Plant will operate until the end of 2012. AD at 35. Neither

assumption provides a prudent basis for reliability planning. While SDG&E disagrees with other

load and resource assumptions used by the AD, changing just these two generation assumptions

to conform with CAISO grid planning criteria and standard industry practice shows that Sunrise

is needed as soon as 2010 to resolve the reliability need in SDG&E’s service territory.

With respect to the Carlsbad Energy Center, this project does not have approval from the

CEC for its Application for Certification, and does not have a PPA.4

Under CAISO Grid Planning Committee Guidelines, the Commission’s Valley Rainbow

and Jefferson-Martin decisions,5 and prudent transmission planning principles for a five year

planning horizon, it is reasonable to assume for planning forecasts only generation that is under

construction and has a planned in-service date within that planning horizon should be considered

as in-service for reliability analysis. In ten-year planning cases, only generation under

construction or that has received regulatory approval should be assumed in a reliability analysis.6

3 D.07-12-052 and Resolution E-4189 (September 4, 2008). If, as in the LTPP, the Carlsbad Energy

Center and South Bay are removed form the baseline, without other adjustments, the analysis shows a reliability need beginning in 2010.

4 CEC Docket No. 07-AFC-06. http://www.energy.ca.gov/sitingcases/carlsbad/ 5 D.02-12-066 (2002); D.04-08-046 (2004). 6 Brown, Ex. SD-36 at 12.2, citing CAISO Approach on the Modeling of New Generation in Power Flow

Cases, at p. 1 (April 16, 2004)). Available at the following link http://www.caiso.com/docs/2001/06/25/20010625134406100.pdf and also at Ex. SD-36, Attachment 12-1. According to this CAISO Committee, in five-year planning cases (emphasis added), “only generation that is under construction and has a planned in-service date within the time frame of the study should be modeled in the initial power flow case.” In ten-year planning cases, “only generation that is under construction or has received regulatory approval should be modeled in the area of interest in the initial power flow case.

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The Commission has recognized that the CAISO Planning Guidelines reflect standard

industry practice and that they are prudent for planning purposes. The Commission’s Valley

Rainbow decision considered what assumptions about new generation were reasonable in

assessing the need for a transmission line project. It concluded that “[s]tandard industry practice

indicates that we should include proposed generating units that are under construction or have

received regulatory permits in the resource mix for transmission planning purposes unless there

is compelling evidence that the future of such plants is in question.” D.02-12-066 at 33.

In Jefferson-Martin, the Commission confirmed this standard in assessing the need for a

transmission line in light of claims that new generation would be available at some point in the

future. The Commission found (D.04-08-046 at 43):

Inclusion of the four CCSF turbines in the resource mix used to assess need for the Jefferson-Martin project would not be consistent with the ISO’s guidelines for either five-year or ten-year planning cases, since they have not received regulatory permits. We take official notice of information on the CEC’s website indicating that an Application for Certification was filed … for three of the four turbines. In light of the on-going controversy about the turbines and the early stage of their certification process, we do not have sufficient confidence that the three CCSF combustion turbines subject to that application will be constructed in a timely fashion to warrant deviation from standard industry practice and include them in the resource mix used to evaluate need for the Jefferson-Martin project.7

SDG&E has an obligation to reliably serve its customers. Consistent with CAISO grid planning

criteria, which help to ensure reliable electric service, we do not presume that generation projects

that neither have regulatory approval nor are under construction will be available by 2010 – or by

2014. See, e.g., Brown Ex. SD-36 at 12.3. Therefore, based on the foregoing authority, the 222

MW attributable to the Carlsbad Energy Center should be removed from the AD’s analytical

baseline, at least for purposes of determining reliability need.8

7 The Commission further noted that no party in that proceeding ever suggested that the Commission

should include in the resource mix used to assess the need for the Jefferson-Martin transmission line a “previously planned Potrero Unit 7 since Mirant has withdrawn its Application for Certification at the CEC.” Id. at 25.

8 The AD also ignores Commission precedent suggesting that, even if an RFO is held today, the development cycle for a CCGT power plant (such as the Carlsbad project) is approximately seven years. The Commission has recognized this development timing in D.07-12-052 at 21:

[r]ecent experience suggest[s] that the time required to develop and carry-out competitive long term RFOs, then finance, permit and construct new generation resources – including a cushion to account for unanticipated delays – requires that these procurement decisions be made up to seven years in advance of when the resources are needed.

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B. It is imprudent to rely on the South Bay plant after 2009 for purposes of reliability planning.

The AD’s treatment of the existing South Bay Power Plant is premised on circular logic –

or a self-fulfilling prophesy – that maintaining South Bay in the baseline ensures that there is no

reliability deficiency, and South Bay will not be shut down until Sunrise is in service. Moreover,

while the AD assumes that South Bay will retire by December 31, 2012 or the end of the year in

which Sunrise comes online, whichever is earlier (see, e.g., AD at 35), it fails to acknowledge

that the continued operation of this old and inefficient plant utilizing once through cooling

carries substantial risk, given that this plant is critical to SDG&E’s current reliability needs yet

there presently is no viable alternative available. Further, operating this plant past 2009 will

necessitate the expenditure of approximately $45 million annually in additional maintenance

costs, additional compliance costs likely triggered by a needed water discharge permit renewal

(Strack, Ex. SD-27 at 20) and substantial capital costs. Kruger, Ex. SD-36 at 11.23-11.25. The

AD also ignores the statutory recognition that closure of the plant is in the public interest.9

Indeed, the Commission’s final LTPP recognized that SDG&E’s assumed retirement of the

South Bay units by the end of 2009 is appropriate. D.07-12-052 at 86. The Commission did

acknowledge that the retirement of these units depends on other contingencies that will replace

the electricity from the facility, such as from the Otay Mesa Generating Plant and Sunrise being

approved and built, and certain new peaking facilities being in-service. For the reasons

described in SDG&E’s Phase 1 testimony (Avery, Ex. SD-5 at I-13 – 17) and during Phase 2

(Held, Ex. SD-35 at 4.6), keeping these old units running with expensive, non-competitive

This precedent reinforces the prudence of excluding the Carlsbad project from the baseline reliability assumptions, given that the assumed 2013 in-service date is unlikely even if the other project milestones are eventually achieved.

9 P. U. CODE § 363(c) provides that, for certain “bayside fossil-fueled electric generation” (i.e., South Bay) (emphasis supplied):

…where the local governmental entity and electrical corporation have engaged in significant negotiations with the purpose of shutting down the power plant, and where there is an agreement between the electrical corporation and the local governmental entity for closure of the facilities or for the local governmental entity to acquire the facilities, the commission shall approve the closure of these facilities or the transfer of these electric generation and associated transmission facilities to the local governmental entity and shall consider the utility transactions with the community to be just and reasonable for its ratepayers.

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reliability-must-run (“RMR”) payments frustrates existing state policy preferences. These

preferences are expressed in the state’s Energy Action Plan, the Commission’s preferred

“loading order,” the 2010 RPS goals, and the AB 32 GHG emission reduction requirement.

Finally, the AD fails to acknowledge that delay of the Sunrise in-service date carries a

substantial present value cost to CAISO customers, e.g., a one or a two year deferral into past

2010 carries respectively a $128 million or $248 million (nominal) cost to CAISO customers.

Strack, Ex. SD-27 at 20.10 For these reasons, it would be a far better solution, in terms of

reliability, if Sunrise replaces the reliability benefits currently provided by South Bay.

C. SDG&E’s recently-adopted LTPP confirms a 2010 reliability need for Sunrise.

The AD relies on Commission’s December 2007 decision in the Long Term Procurement

Plan proceeding (“LTPP”) in establishing the analytical baseline.11 Pursuant to this decision, the

Commission recently approved SDG&E’s LTPP, which is based on nearly identical assumptions

to those in the analytical baseline.12 But SDG&E’s approved LTPP assumes that neither South

10 Moreover, the AD’s reliance on the fact that SDG&E included South Bay in some post-2009 scenarios

(at 50-52) is not a basis for adding this old unit to the baseline. The parties, including SDG&E, modeled a wide range of assumptions, and the fact that SDG&E concedes that continued South Bay operation is one plausible future scenario is not an admission that such an assumption is likely or prudent for planning purposes.

11 The AD, at section 6.2.2, p. 39, finds (footnotes omitted):

The Scoping Memo [at 13] ordered parties to use, to the degree possible, “the most recent Commission-adopted assumptions, goals, policies and levels of effort in its base case forecasts of loads and resources.” The Economic Methodology Decision sets forth this requirement also [D.06-11-018, Attachment A at 5-6]. The Commission’s December 2007 decision in the Long Term Procurement Plan proceeding … uses the Energy Commission’s November 2007 Forecast [D.07-12-052 at 39]. While the LTPP Decision relies on a 1-in-2 peak demand forecast for determining procurement authorization, the November 2007 Forecast also includes a 1-in-10 peak demand forecast. For consistency with the LTPP Decision, we adopt the November 2007 Forecast of 1-in-10 peak demand.

12 The AD (at 151) lists the exceptions in its analytical baseline to the assumptions in SDG&E’s approved LTPP.

Note that the AD relies solely on an “Update” to a compliance exhibit required by the presiding ALJ. Although these comments take the AD’s Update as given in order to work with as much of the AD as possible, it would be reversible error for the Commission to rely on the Update to the extent it differs from the fully-litigated LTPP. The Update, disclosed for the first time in the AD and PD, was apparently prepared by the ALJ after the record closed, based on post-record economic modeling of an unspecified extent by the ALJ’s consultant (see AD at 150-151), and on assumptions that were not disclosed in the AD nor provided in any workpapers to the parties. The Commission cannot properly ground a decision on an ALJ-manufactured analysis that has not been fully disclosed to the parties,

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Bay nor Carlsbad Energy Center are in service, and it identifies a grid reliability need of up to

322 MW in 2010, growing to up 628 MW by 2014 prior to the addition of the Wellhead

Margartia and the JPower Pala Peaker. The Commission recently confirmed a need for new

generation prior to Sunrise in D.08-11-008 where it stated in Ordering Paragraph 1d that:

We authorize … [SDG&E] to procure a total of up to 530 megawatts (MW) of new local capacity that was conditionally authorized in D.07-12-052 and require that applications for this procurement be supported by updates of the status and projected on-line date of … Sunrise ….

By itself, SDG&E’s recently-adopted LTPP provides a sound basis for a Sunrise CPCN

based on a reliability need, with authorization to commence construction now. It is the AD’s

baseline assumptions that are outliers in the context of the Commission’s fully-litigated

procurement process. The Commission cannot properly decline to find that Sunrise is needed for

reliability based on such outliers, especially given the robust record that Sunrise is needed as

soon as 2010.13

D. The AD’s assumed 2014 reliability need provides a reliability basis for issuing a CPCN authorizing commencement of construction now.

Yakout Mansour, the CAISO’s CEO, in his recent oral argument in this case, presented

this Commission with the proper perspective for viewing this proceeding’s reliability issues.

Fundamentally, Mr. Mansour points out that it is unproductive to …”try… to nail down the exact

date…and the cost to the dollar” for an asset with a life of 40 to 50 years.14 Mr. Mansour urged

the Commission to start this project “as soon as you can…. time is of the essence. The case is

urgent” T.6248:28; 6249:7-8.

much less without the parties having the opportunity for discovery, cross-examination or briefing on such evidence.

13 Sparks, Ex. I-6 at 39 (Table 5); Avery, Ex. SD-5 at I-1-3, 8, 12, 15, Appendix I-1 – CAISO South Regional Transmission Plan for 2006; Brown, Ex. SD-5 at Tables II-1 through II-10, II-12-13, 16; Strack, Ex. SD-6 at IV-47-48, Table IV-22.

14 Mr. Mansour, a system planner for 40 years, observed (T.6248:4-14)

What do we do in planning? … [W]e’ll make assumptions based on the best we can see. We determine the needs, and as best we can, a date. Now, if we say 2012 there is a reliability issue, is there a clock that will tick form midnight in the year 2011 December 31 and then it becomes problematic in this? No. What it shows is that within that time frame, we’re hanging by the teeth. So whether it’s 2012, 2013 or 2014 … is really very unproductive argument.

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Mr. Mansour’s point concerning the folly of deciding need for a large project based on a

precise date in a single scenario is reinforced by other evidence in the record. SDG&E submitted

unrebutted evidence that in each of 2007 and 2008, its peak load shattered the then-current CEC

forecasts, suggesting that such forecasts are conservative, if not materially low, for grid

reliability planning.15 Such evidence of uncertainty surrounding forecasts (especially the one

used for the AD’s baseline), and Mr. Mansour’s rationale, suggest one or both of two

modifications to the AD. The Commission could simply find that a reliability need in 2014 (the

date found in the AD) is sufficient to support a CPCN to start construction now. And, the

Commission could cite the range of forecasts in evidence, including those of SDG&E and the

CAISO that find a reliability need as early as 2010,16 and hold that, given the range of forecasts,

it is prudent to find a reliability need for Sunrise supporting the immediate start of construction.

III. ADOPTING THE AD’S COMPLIANCE PHASE WILL DELAY SUNRISE AND CHILL THE DEVELOPMENT OF RENEWABLES

The AD (at 286, ordering ¶ 5) provides that construction of Sunrise may not begin until

the Commission approves a “Sunrise Compliance Plan” to be submitted by SDG&E in the “form

of an application,” in order to (id. at 284, ordering ¶ 2):

… provide assurance that Sunrise will realize projected greenhouse gas emission reductions and economic benefit estimates … [and describe] how SDG&E will ensure that Sunrise will be used to deliver substantial amounts of Imperial Valley renewable generation to the California market.

15 Within months after the adoption of CEC’s Integrated Energy Policy Report (“IEPR”) forecast in late-

2005, the CEC revised the year 2007 outlook for San Diego by +80 MW, a 2% increase, which roughly equals a year's worth of peak growth. More importantly, actual peaks reached the last two years confirm that the CEC forecasts have been low. On Saturday, July 22, 2006, SDG&E’s customer demand recorded an all-time peak of 4502 MW – overtaking the previous record 4065 MW established in 2004. If the weather conditions that Saturday had occurred on a weekday, and if substantial load had not been forced out of service at time of peak, SDG&E could have recorded approximately 4800 to 4900 MW of demand. Avery, Ex. SD-5 at I-7 n. 13; Brown, Ex. SD-5 at II-2. And, on Labor Day, September 3, 2007, SDG&E’s customer demand recorded an all-time peak of 4636 MW. If the weather conditions that Labor Day had occurred the following day (i.e., on a workday), SDG&E would have exceeded 5100 MW of demand. Accord, Strack, T.1605:17-25, T.1606:1-9. Even on an adverse weather peak condition, such a peak demand was not expected to occur until the 2015 timeframe. The weather events of the past two years demonstrate how nature can easily exceed even adverse planning assumptions.

16 Brown, Ex. SD-5, Tables II-1 through II-10; Sparks, Ex. I-6, Table 5.

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The AD explicitly grounds this requirement on a Minnesota commission decision

authorizing a transmission project conditioned on the import of wind generation in circumstances

purportedly similar to those before the Commission in this proceeding.17 Relying on this

decision, the compliance plan requires detailed proof that Sunrise is completely dedicated to

renewable generation. But, it is ironic that the Minnesota decision authorizes the proponent to

commence construction, yet the AD cites this decision to prevent construction until further

litigation is resolved. Moreover, as shown below, the compliance plan will not only delay the

project, but it is infeasible in its current form, it will chill renewable development, and the

assurances it purportedly seeks are already provided by the Sunrise record and by contracts

approved by the Commission in other proceedings.

A. The Sunrise compliance phase would substantially delay Sunrise.

On its face, by requiring an application and prior Commission approval, the AD would

set in place a process requiring a scoping memo and evidentiary hearings. And, the compliance

phase requires SDG&E to prove up GHG estimates, economic benefits, and

… renewable development objectives consistent with of [sic] the projected levels by the …[CAISO] of Sunrise-related renewable development in this proceeding, as represented in Table 2 of Section 6.10 of the decision.

In other words, the AD would require yet another round of economic modeling, with all

of the accompanying discovery and disputes over assumptions. Based on past experience in this

proceeding, this will require at least another year of litigation before the matter is submitted to

the Commission. And, as shown in the next section, the AD requires SDG&E to meet an

infeasible burden of proof in the compliance phase.

B. The Sunrise Compliance Plan is, in effect, a “poison pill” for Sunrise

The AD’s compliance application (ordering ¶ 2) requires SDG&E to show “binding

commitments” that “substantial amounts of Imperial Valley renewable generation will be

developed and delivered via Sunrise to the California market.” And the plan must contain

“renewable development objectives consistent with” the AD’s depiction of CAISO projections

17 AD at 167, 169-70, finding of fact 20 at 277, citing Order Granting Certificates of Need Subject to

Conditions, Minn. Public Utilities Commission, Docket No. E-002/CN-01-1958 (March 11, 2003), found at: https://www.edockets.state.mn.us/EFiling/ShowFile.do?DocNumber=1473345

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(at 68, Table 2). Given the requirement that projects in the plan must deliver on the day that

Sunrise is placed into service, it is evident that the detail sought by the plan can only be supplied

by projects very far into development – put differently, much more mature – than is reasonable

to expect – prior to start of construction for Sunrise. Moreover, the plan would require SDG&E

to submit detailed data on projects which are under contract with other entities. SDG&E does not

have data – let alone a binding commitment – for every potential solar, wind and geothermal

project in the Imperial Valley region that may connect, or use transfer capability made available

by, to the open-access Sunrise transmission line. Below we present additional examples showing

how the compliance plan is stacked against making the showings required to start construction.

1. The math in the AD is infeasible.

The AD’s understanding of “substantial … binding commitments” appears to require

contracts in excess of the additional transfer capability provided by Sunrise. The total energy in

Table 2 is 22,000 GWH. A 1000 MW line at 100% capacity factor would carry 8,760 GWH. A

binding commitment by SDG&E for the 22,000 GWH identified in Table 2 would represent over

100% of SDG&E’s 2010 total retail sales, and ~6 times SDG&E’s 20% RPS goal and almost 4

times SDG&E’s 33% RPS goal. Viewed in terms of capacity, the compliance plan requires

SDG&E to demonstrate binding commitments for as much as 1600 megawatts of geothermal

additions from 2011 to 2015. It is unrealistic for SDG&E to demonstrate binding commitments

for this level of new geothermal base load resource when its off-peak load is often below 1,700

megawatts, especially when one consider that SDG&E has roughly 500 MW of nuclear and other

renewable base load resources available.18

18 Although, in the spirit minimizing suggested changes to the AD, we do not challenge here the

AD’s findings (e.g., finding of fact 19) concerning the GHG emissions from Sunrise construction and operation, we note here that these findings too suffer from bad arithmetic. Construction and operation emissions are attributed to Sunrise, but neither construction nor operations emissions are attributed to alternatives. And the record shows that Sunrise emissions are offset with de minimus renewable delivery. For example, a 22 MW geothermal power plant operating at 90% capacity factor for one year would provide about 1% of SDG&E’s forecast 2010 RPS requirement, which would offset Sunrise emissions. Anderson, Ex. SD-37 at 2.2; McClenahan, Ex. SD-37 at 2.5-2.6.

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2. Under open access, the SDG&E compliance plan cannot assure that any PPAs will get the rights required to transmit power on Sunrise, making any commitment less than binding.

SDG&E does not have the ability to make “binding commitments” to this enormous

amount of power, due to the fact that any new contracts which SDG&E negotiates that

contemplate interconnection within the CAISO control area must apply to the CAISO for

interconnection. Other parties will also be competing for space on this highly desirable new

path; SDG&E has no exclusive right to use the path and therefore “filling” the capacity of the

line must be accomplished by a number of parties. SDG&E has no means to include these other

parties in its compliance plan, nor can it exclude any party.

3. “Chicken & Egg” – Development cannot move forward based upon a contingent transmission line.

As Mr. Mansour, the CAISO’s CEO, suggested (T.6249:15-19), if the AD’s compliance

plan is adopted, it will be impossible for SDG&E to commit to having renewables show-up as

the line is energized due to "chicken-and-egg" nature of the transmission-developer dynamic and

the resultant uncertainty in the Sunrise development schedule (or whether Sunrise will be

approved at all). Not only is it within the Commission’s expertise to officially notice what past

experience in California suggests, but the record in this proceeding,19 and in other Commission

and agency proceedings,20 confirms that uncertainty regarding new transmission will chill and/or

delay renewable project development. Moreover, the contingent nature of the AD’s “approval”

will make it impossible to meet the compliance plan’s detailed showings. For example, it will be

difficult for the ISO to insert a contingent transmission line into LGIA studies. And it is doubtful

that other agencies will commit time to processing permit applications for generators where the

line has not been constructed, much less approved. As discussed further below, it may also

hinder the CPUC’s RETI process.

19 Kemp, Ex. SD-15 at 3-4; Cowman, T.6304:23 – 305:22. 20 See, Electric Resource Planning OIR, R.04-04-003, D.04-12-048 at 228. Accord, 2006 LTPP OIR,

R.06-02-013, D.07-12-052, Transmission OII, I.00-11-001, D.01-03-077.

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4. The economic showing required by the compliance plan carries the seeds of its own destruction.

Under the compliance plan, it appears that SDG&E must demonstrate that the renewables

with “binding commitments” will be economic. It appears that the intended benchmark for the

economic comparison is the CAISO’s CRS renewable costs as adopted by the ALJ’s “Update” to

the post-hearing Compliance Ex. 1. See AD, findings of fact 12, 14. First, it is self-evident that

the compliance plan would force SDG&E to make drastic concessions, in terms of price and risk

allocation (such as credit), to get the “binding commitments” within the 90 days required by the

AD (ordering ¶ 2(a)). Such desperate acquisition will ensure the resulting commitments are not

economic.

Second, the record establishes that the renewable cost forecasts from 2007 as adopted by

the AD as a benchmark are too low. Unrebutted testimony (ignored by the AD) that the

CAISO’s renewable resource supply curve utilized by the AD’s economic evaluation bears no

relationship to the results of SDG&E’s request for offers (“RFOs”) beginning in 2004, showing

that it has received far more bids and entered into more contracts at competitive prices and

amounts from the Imperial Valley area than from the San Diego area and areas to the north of

SONGS. See McClenahan, Ex. SD-134; T.5628:1-5, 5654:1-24.

C. The Minnesota case is not useful precedent here.

On March 11, 2003, the Minnesota Public Utilities Commission (“MNPUC”) granted a

Certificate of Need to Xcel Energy to construct four transmission lines, ranging from 115-kV to

345-kV across 168 miles in southwestern Minnesota. The certificate required Xcel to acquire the

825 MW of wind generation that it expected the lines to carry before the lines became

operational (not as with the AD, prior to starting construction).21 Because Xcel filed its

application based solely on importing wind energy, the MNPUC held Xcel to its request:

[Given] Xcel’s ... request to build transmission lines for the explicit purpose of carrying renewable energy, and the significant risk that these lines might not be

21 Xcel predicated the need solely on the import of 825 MW of wind generation. Xcel never claimed that

the transmission lines were needed for reliability - "it does not claim that they are needed to meet increased demand for electricity." Order Granting Certificates of Need Subject to Conditions at 3, MNPUC docket no. E-002/CN-01-1958 (March 11, 2003) https://www.edockets.state.mn.us/EFiling/ShowFile.do?DocNumber=1473345.

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used for that purpose, it makes little sense not to require Xcel to acquire the 825 megawatts of wind generation that it expects those lines to carry.

MNPUC Order at 18. Note that the MNPUC did not require consummation of the acquisitions

prior to start of construction. The fact that Xcel specifically requested the CPCN based solely on

moving 825 MW of wind electricity also distinguishes this case from Sunrise. And, Xcel never

presented a reliability or an economic need justification. There is nothing in the available

records or subsequent orders22 suggesting that Xcel ever objected to the requirement to import

825 MW of wind energy.23 In sum, the Minnesota decision is simply not useful guidance here,

and it does not support the AD’s compliance plan.

D. The Sunrise Compliance Plan is unnecessary because the record contains ample assurances that Sunrise will deliver “substantial amounts of Imperial Valley renewable energy.”

The record (McClenahan, Ex. SD-35 at 2.6) shows SDG&E already has in place

purchased power agreements (“binding commitments”) for the bulk of the additional transfer

capability provided by Sunrise:

CapacityMW

EnergyGWH

Under Contract Stirling I & II 600 1298MMR I & II 100 472Esmeralda I & II 60 485SCE-Sempra 250 722

Total 1010 3075

22 The later MNPUC amended its order by clarifying that its "825-megawatt purchase requirement

imposed in this case is not intended to influence the criteria that Xcel will apply in selecting vendors in its ongoing, all-source bidding process." Order Clarifying and Amending Order of March 11, 2003 (May 16, 2003) at 2. https://www.edockets.state.mn.us/EFiling/ShowFile.do?DocNumber=1506105. On July 13, 2004, the MNPUC approved a design change to the project, the last issuance in this docket. Order Approving Design Change, Encouraging Technical Discussions and Requiring Update, https://www.edockets.state.mn.us/EFiling/ShowFile.do?DocNumber=1865388

23 Indeed, it appears that Xcel’s transmission line will assist the development of Xcel-owned wind generation. Xcel recently announced (Oct. 31, 2008) that it will invest almost $1 billion in wind farms over the next three years. Xcel plans to build its first-ever North Dakota facility, as well as a new wind farm in Nobles County in southwest Minnesota. Xcel Energy Plans Wind Power Expansion, http://minnesota.publicradio.org/display/web/2008/10/31/xcel_wind/?refid=0

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All of the foregoing contracts with the exception of the second phase for Stirling24 have been

approved by the Commission, except for the SCE contract, which has been submitted to the

Commission.25 McClenahan, Ex. SD-139.

E. The Sunrise Compliance Plan is bad policy and unduly discriminatory

The Commission is promoting the California Renewable Energy Transmission Initiative

(“RETI”) to encourage transmission development to Competitive Renewable Energy Zones

(“CREZ”). The recent RETI report includes the Imperial Valley region as one of several

identified CREZ.26 And in fact ranks one of the identified IV CREZs as one of its two highest

ranked CREZs.27 But the AD would promulgate, in the middle of this worthy policy initiative, a

pre-licensing compliance scheme that would competitively disadvantage the Imperial Valley

region vis-à-vis other regions – a scheme that would require binding commitments over-

subscribing the line’s transfer capability prior to the start of the line’s construction. The only

thing more destructive from a policy perspective would be to cure the discrimination by adopting

the Sunrise Compliance Plan as development-chilling precedent for future transmission-for-

renewables. In this regard, it is noteworthy that the Commission approved two Tehachapi

transmission projects under P.U. CODE § 399.25 on a “build it and they will come” basis – i.e.,

not requiring any demonstration of such commitments. See, D.07-03-012 and D.07-03-045.

F. SDG&E offers commitments that will achieve the AD’s goal to ensure that Sunrise will deliver “substantial amounts of Imperial Valley renewable energy.”

If the Commission eliminates the AD’s Sunrise Compliance Plan requirement, and grants

the Sunrise CPCN with an appropriate cost cap and without further delay, SDG&E will make the

24 . The Stirling contract provides for a second phase at 300 MW, which is included in the 600 MW total, although this phase must be submitted for Commission approval. 25 Other sources in the record reinforce these assurances. There are over 7000 MW of renewable energy

projects in the Imperial Valley in the CAISO Interconnection queue. Ex. SD-37 at 2.4-2.5. In addition, IID testifies to more than 1800 MW of interconnection requests in its queue (Montano, Ex. I-3 at 2 and T.3446:24-25) that could be assisted by Sunrise. Accord, Brady at T.6254:16-17; 27-28 and 6255:1-3.

26 See, RETI, Phase 1B, Draft Report, November 2008 at: http://energy.ca.gov/reti/documents/2008-11-05_RETI_Phase_1B_Draft_Report.pdf

27 Id. at Table ES-2, page ES-7.

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following commitments that will ensure that Sunrise “will be used to deliver substantial amounts

of Imperial Valley renewable generation to the California market” (AD at 284):

1. The “No Conventional Coal” Commitment. SDG&E will not enter into contracts for supply from a conventional coal generator that would deliver across the Sunrise Powerlink.

The Commission’s existing mechanisms for review and approval of procurement transactions will provide significant regulatory oversight of SDG&E’s “no conventional coal” commitment on Sunrise. These mechanisms include:

• Applications for Commission approval of individual procurement contracts of five years or longer;

• Advice Letter filings of Quarterly Procurement Transactions Reports that provide substantial detail on SDG&E’s procurement transactions;

• Regular consultations with SDG&E’s Procurement Review Group (PRG), which includes members of Commission staff as well as other non-market participant consumer advocate interests; and

• Renewables and Long-Term Procurement Plans that are filed for Commission review and approval on an annual and biennial basis, respectively.

SDG&E will still have the ability to purchase system power, which is power purchased from an unspecified source.28 In the WECC, the supply source for system power transactions is not identified until after the contracting is concluded, and ultimately such arrangements could include a coal component. Because the supply source for system power transactions cannot be known at the time of contracting, however, such transactions are consistent with SDG&E’s “no conventional coal” contracting commitment.29

SDG&E may in the future seek the Commission’s prior approval to consider specific clean coal technologies or carbon sequestration projects that could present attractive opportunities for customers and that satisfy the Commission’s rules regarding emissions, such as those adopted to implement AB 32 and SB 1368.

28 This type of power is predominantly purchased on a “day ahead” basis to satisfy short term reliability

needs or economic opportunities. 29 One concern raised by the AD and PD is that a new interconnection to the WECC grid could induce the

operation of more conventional coal generation. By committing not to contract with coal generators, SDG&E is eliminating that prospect to the extent it is within its control in an open-access regime. In any event, this concern would apply to any such new interconnection, including, for example, Palo Verde-Devers No. 2.

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2. The Renewables Replacement Commitment. SDG&E will commit that if a renewable resource that is deliverable by Sunrise and currently under contract to SDG&E fails, SDG&E will contract to replace that energy with another renewable resource from the same region.

SDG&E’s renewables replacement commitment applies to SDG&E’s currently executed and approved renewables contracts that would use Sunrise for delivery. For any of these current contracts that become subject to replacement, SDG&E will contract for replacements from the same region.

Generators that will benefit from the capacity that is made available by the Sunrise Powerlink are generally located in East County San Diego, the Imperial Valley, Northern Mexico, and southwestern Arizona.

SDG&E’s renewables replacement commitment will be subject to (1) SDG&E’s least cost, best fit analysis as described in SDG&E’s Commission-approved Renewables Procurement Plan and (2) the existence and availability of Sunrise capacity.

SDG&E will demonstrate compliance with this requirement in its Semi-Annual RPS Compliance Report, annual Renewables Procurement Plan, and biennial Long-Term Procurement Plan. SDG&E also consults regularly with its PRG and will inform its PRG of a failed contract within 60 days of official notice of termination. SDG&E will also continue consultations with its PRG as the replacement efforts are underway.

3. The 33% Renewables Target by 2020 Commitment. SDG&E will contract towards a voluntary 33 percent RPS procurement target by 2020.

SDG&E will contract towards a voluntary goal of achieving 33 percent of retail sales from renewables by 2020.30 SDG&E will continue to work with the Commission, Legislature, and other stakeholders to develop a fair set of rules that will apply to all load serving entities.

SDG&E’s voluntary, increased renewables contracting target will be superseded by any subsequent State law that adopts a renewables requirement that replaces the current mandate of 20 percent renewables by 2010.

SDG&E will continue to use least cost, best fit analysis as it contracts towards its 33 percent voluntary goal.

30 On November 17, 2008, Governor Schwarzenegger signed Executive Order S-14-08, effective

immediately, to streamline California's renewable energy project approval process and to increase the state's RPS to 33 percent (emphasis supplied):

…. the following Renewable Portfolio Standard target is hereby established for California: All retail sellers of electricity shall serve 33 percent of their load with renewable energy by 2020. State government agencies are hereby directed to take all appropriate actions to implement this target in all regulatory proceedings, including siting, permitting, and procurement for renewable energy power plants and transmission lines. http://gov.ca.gov/index.php?/press-release/11073/

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SDG&E will demonstrate that it is on a trajectory to achieve the 33 percent by 2020 renewables target in its Semi-Annual RPS Compliance Report and Project Development Status Report, on an annual basis in its Renewables Procurement Plan, and on a biennial basis in its Long-Term Procurement Plan.

IV. THE COST CAP MUST BE ADJUSTED BASED ON CERTAIN RECORD FACTS AND ASSUMPTIONS OVERLOOKED BY THE AD

The AD adopted “a maximum cost for the Final Environmentally Superior Southern

Route pursuant to § 1005.5(a) of $1.719 billion ($2012).” AD at 270. The AD calculated the

cost cap based solely on estimated project costs, by starting (id. n.706):

… with construction costs and AFUDC of $1.670 billion ($2012) and added mitigation costs of $154 million ($2012), for a total of $1.824 billion, which includes SDG&E’s proposed Coastal Link. To adjust for the adopted Coastal Link Alternative, [the AD] deduct[ed] $189 million ($2012), which is SDG&E’s assumed cost of its proposed Coastal Link, and add[ed] in the estimated cost of the adopted Coastal Link Alternative of $84 million ($2012).

Review of the AD’s cost cap calculations demonstrates that these project cost values must be

adjusted for consistency with the final record.

As demonstrated below, reference to the record shows that the AD’s cost estimate is

understated by approximately $164 million.31 This number includes corrections to the values

used by the AD in its calculation of the cost cap quoted above, plus additional costs of the

FESSR’s new plan of service that were not part of the SDG&E estimate relied on by the AD.

SDG&E seeks a revised project cost estimate of $1.883 billion, and, consistent with Commission

precedent for large and risky projects, requests a 10-15% adder to this estimate as a contingency

against project risks, including well-documented recent price increases in important project

inputs.32

A. The initial total construction costs for the FESSR should be increased by $4 million

The AD used a total construction cost, including AFUDC, of $1.670 billion for the

FESSR. This number was based on SDG&E’s cost estimates of its own Modified Southern

31 Unless otherwise noted in this section, all values are expressed in 2012 dollars. 32 Note that this total project cost estimate is very close to the $1.864 billion that was the estimate

submitted at the direction of the ALJ, and was the basis for the economic analysis showing that Sunrise creates $110 million per year in net benefits. Ex. SD-142.

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Route (including the Coastal Link), which is similar to the FESSR. Cf. AD at 101 (“We find that

SDG&E has offered the best developed capital cost estimates for the Proposed Project and the

other transmission alternatives. We adopt these capital cost estimates as Analytical Baseline

assumptions.”) (footnote omitted). The total construction cost estimate for the Modified

Southern Route provided in SDG&E’s Phase 2 testimony was $1.67 billion. See Ex. SD-36 at

8.1. However, SDG&E rounded its cost estimate to the second decimal point. The actual cost of

the Modified Southern Route is $1.674 billion.33 Since the Commission used cost figures

rounded to the third decimal point, SDG&E should not be punished for rounding to the second

decimal point in its testimony. Thus, the total estimated construction costs of the FESSR (i.e.,

the Commission’s starting point for calculating a cost cap) should be increased by $4 million to

$1.674 billion, which would be consistent with the cost figures in the AD.

B. The AD did not account for the expense of undergrounding through Alpine Boulevard, which will increase initial construction costs by $91 million

The AD did not take into consideration a major cost difference between the FESSR’s

plan of service and the Modified Southern Route’s plan of service when adopting a cost estimate

for the FESSR. The FESSR includes 2 miles of additional underground double circuit 230 kV

transmission line across the eastern portion of Alpine Boulevard. This modification replaces the

Star Valley Option alternative that was included in the Modified Southern Route’s plan of

service. Thus, the additional 2 miles of undergrounding was not included in the Modified

Southern Route’s cost estimates.

As stated in SDG&E’s Phase 2 testimony, the undergrounding costs are substantial. See

Ex. SD-35 at 3.6-3.8; Attachment 3-4. The additional 2 miles of undergrounding may be

calculated using cost estimate data already contained in the record. Using SDG&E’s detailed

cost estimates in Attachment 3-4 for the ESSR as identified in the DEIR, the Commission may

calculate the average cost per mile of undergrounding through Alpine Boulevard. See Ex. SD-

35, Attachment 3-4. The total estimated cost of the additional 2 miles of undergrounding

through Alpine Boulevard would be $91 million.34

33 See Workpapers in Support of Phase 2 Direct Testimony Regarding Cost Estimates for the Modified

Southern Route and Submitted to Interested Parties. 34 To arrive at this estimate, SDG&E started with total construction costs of the approximately 6 miles of

underground transmission line through Alpine Boulevard, which totaled $175.2 million without

19

For purposes of the AD’s cost cap calculation, $91 million should be added to the total

construction costs of the FESSR because the $1.674 billion initial figure fails to account for the

additional undergrounding change to the Modified Southern Route’s plan of service. With this

addition, the total construction cost of the FESSR is $1.765 billion [$1.674 billion (initial

construction costs based on Modified Southern Route) + $91 million (additional 2 miles of

undergrounding)].

C. When adjusting for the Coastal Link Alternative, the AD utilizes an erroneous cost estimate for the Coastal Link

As stated above, the total construction cost of the FESSR is $1.765 billion, which

includes the cost of building the Coastal Link. In order to adjust for the Coastal Link’s

elimination in the FESSR’s plan of service, the AD reduced the total construction cost by $189

million. This cost estimate for the Coastal Link is incorrect.

SDG&E’s cost estimate for the Coastal Link is $156.2 million. See Ex. U-101 at 39

n.181 (citing SDG&E’s 3/19/08 Response to UCAN Data Request #37-4a). The AD erroneously

included $29 million ($2011) in support costs in its $189 million estimate for the Coastal Link.

The $29 million ($2011) in support costs does not reflect the actual level of support directly

associated with the Coastal Link that may be reduced with its elimination.35 A significant

portion of support costs have already been spent in support of licensing, engineering and public

outreach. In fact, the support costs associated with the Coastal Link Alternative (which has been

proposed to replace the Coastal Link’s plan of service) would be similar, if not more than the

support costs for the Coastal Link. Thus, the Commission should not eliminate any support costs

contingency, AFUDC and escalation to a 2012 in-service date. See Ex. SD-35, Attachment 3-4. SDG&E then needed to determine the amount of contingency, AFUDC and escalation to add to the total construction costs. Based on the figures in Attachment 3-4, SDG&E calculated that contingency equaled 13.0% ($124,036/$955,064), AFUDC equaled 15.5% ($167,230/$1,079,100) and escalation equaled 18.9% ($235,960/$1,246,330). Thus, the total Alpine Boulevard underground costs including contingency, AFUDC and escalation is $271.9 million ($175.2 million x 1.13 (contingency) x 1.155 (AFUDC) x 1.189 (escalation)). The additional costs of adding 2 miles of undergrounding at the east end of Alpine Boulevard is $91 million ($271.9 million x (2 miles/6 miles)).

35 The $29 million ($2011) in support costs reflects a ratio of the overall support costs based on the total dollar figure of the Coastal Link facilities compared to the overall project cost estimate. In response to a RPCC data request, SDG&E provided this support cost figure in Phase 2 so RPCC could make an apples-to-apples comparison with SDG&E’s Phase 1 cost estimates for the Coastal Link.

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from the total project cost estimate when replacing the Coastal Link with the Coastal Link

Alternative.

Accordingly, the Commission should only reduce the total construction costs of the

FESSR by $156.2 million (SDG&E’s estimate) instead of $189 million (the AD’s estimate).

After removing the Coastal Link from the FESSR’s plan of service and adding the estimated

costs of the Coastal Link Alternative, the total construction cost for the FESSR’s plan of service

is $1.693 billion [$1.674 billion (initial construction costs based on Modified Southern Route) +

$91 million (additional 2 miles of undergrounding) - $156.2 million (removal of Coastal Link) +

$84 million (addition of Coastal Link Alternative)].

D. The AD’s adoption of $154 million in mitigation costs is incorrect

The AD adopts $154 million in mitigation costs for the FESSR. AD at 270 n.706.

However, it is unclear how the AD’s mitigation costs were calculated. SDG&E proposes a total

mitigation cost of $190 million for the FESSR based on its calculation of mitigation costs for the

Modified Southern Route provided during Phase 2 evidentiary hearings. See Ex. SD-142, Table

11-5. Pursuant to ALJ Weissman’s direction, SDG&E provided in Table 11-5, a total cost

estimate of $1.864 billion (construction plus mitigation costs) for the Modified Southern Route.

After subtracting $1.674 billion in total construction costs identified above, the mitigation cost

for the Modified Southern Route is $190 million ($1.864 billion - $1.674 billion). SDG&E’s

$190 million mitigation cost estimate for the Modified Southern Route is based on essentially the

same line mileage as the FESSR, which is why the Commission should adopt this figure.36

After adding the total mitigation costs to the total construction costs of the FESSR, the

total cost estimate for the project is $1.883 billion ($1,693 million + 190 million). Based on the

foregoing, the project cost estimate for purposes of establishing the cost cap should be set at

$1.883 billion.

36 In SDG&E’s Phase 2 testimony, SDG&E estimated that the mitigation costs for the 111-mile ESSR

identified in the DEIR would be $162 million. See Ex. SD-35 at 3.19. The ESSR’s $162 million mitigation cost estimate did not account for the additional 11 miles of transmission line that the Modified Southern Route (i.e., the FESSR) traverses. The $28 million mitigation cost estimate increase for the Modified Southern Route is consistent with the route’s increased mileage that needs to be mitigated.

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E. For the cost cap, the AD should adopt a 10% adder to the project cost estimate as a contingency against unforeseen circumstances

For one of the largest and most complicated transmission projects in California’s history,

the AD should adopt a 10% adder to its proposed cost cap as a contingency against unforeseen

circumstances. The AD’s cost cap does not allow for adjustments based on, among other things,

changes in SDG&E’s authorized cost of capital, additional mitigation costs, actual field

conditions and adjustments for inflation and AFUDC if the in-service date is delayed for reasons

beyond SDG&E’s control. In the unlikely event these adjustments are needed, the 10% adder

will cover the above contingencies without burdening the Commission with additional process.

The Commission has previously authorized an adder over the utility’s estimate as part of

the cost cap to specifically account for these uncertainties. For example, the Commission set a

cost cap with a similar adder for SDG&E’s Silvergate Substation, adding 10% to SDG&E’s cost

estimate. See D.06-09-022 at 17, Ordering Paragraph 3. This adder was in addition to any

contingency amounts typically included within SDG&E’s estimate. Furthermore, in the San

Onofre Nuclear Generating Station Steam Generator Replacement Proceeding, the Commission

adopted a cost cap for Southern California Edison Company (“SCE”) that was 15% above SCE’s

estimated project costs. See D.05-12-040, Finding of Fact 14 (“[The Commission] find[s] it

reasonable to allow SCE to incur costs subject to reasonableness review 15-percent in excess of

[SCE’s] cost estimate.”). Once again, this adder was in addition to SCE’s 26% contingency

amount already included within its cost estimates.

Thus, as a contingency against unforeseen circumstances facing such a significant and

complex project, the AD should adopt a 10% adder to SDG&E’s total cost estimate of $1.883

billion when adopting its cost cap for the FESSR, consistent with Commission precedent.

F. The AD’s command that the Commission will re-assess the cost-effectiveness and need for Sunrise if SDG&E exercises its right to increase the cost cap is unduly burdensome and without precedent

The AD requires SDG&E to re-litigate the cost-effectiveness and need for Sunrise if

SDG&E’s final costs exceed the adopted cost cap. The Commission should reconsider this

condition. SDG&E has searched the Commission’s prior decisions in ratemaking cases and has

found no cases where such an unduly burdensome requirement was adopted. In fact, California

22

law does not require that the Commission re-assess the project’s cost-effectiveness and need if an

applicant seeks to increase the cost cap. See P.U. CODE § 1005.5(b).

Pursuant to § 1005.5(b), SDG&E must only show “that the cost [of the project] has in

fact increased and that the present or future public convenience and necessity require

construction of the project at the increased cost.” If SDG&E applies to the Commission to

increase the cost cap, SDG&E should only have to comply with these two requirements detailed

above. Therefore, the AD should remove the “cost-effectiveness and need” language in its

ordering paragraph 8(b) regarding the cost cap adjustment. See AD at 288.

V. THE AD ERRS BY FINDING THAT P.U. CODE § 399.25 DOES NOT SUPPORT ISSUING A CPCN FOR SUNRISE NOW

The AD (at 282, conclusion of law 4) declines to find that Sunrise is needed under P. U.

CODE § 399.25, “[s]ince Sunrise is not necessary for SDG&E to meet its 2010 renewable power

goals of 20% ...” (emphasis added). This statute “directs the Commission to deem necessary

those transmission facilities identified in applications if the proposed facilities are necessary to

facilitate achievement of the State’s renewable power goals.” In re Antelope-Pardee, D.06-06-

34 at 2. The AD’s conclusory determination that § 399.25 does not apply is directly contradicted

by the AD’s own finding (at 70) that “without a secure transmission path, no significant amount

of new renewable generation will be constructed in the Imperial Valley.” The holding also

ignores substantial evidence that SDG&E, and other California utilities, need Sunrise to meet the

20% goal.37 The AD implies that if a utility could meet its 20% in any other plausible way, then

the project flunks the statutory test.

The AD provides no coherent rationale for its construction of § 399.25, and it errs by

ignoring the plain statutory text “necessary to facilitate” and not merely “necessary,” as the AD

suggests. Moreover, the AD offers absolutely no reasoning contrary to SDG&E’s showing that

Sunrise would indeed “facilitate” meeting the State RPS at any level. Thus, the AD errs as a

matter of law in its construction of the statute by disregarding its plain language and by reading

out of the statute the term “facilitate. The Commission should reverse the AD on this point and

find that Sunrise in fact needed under § 399.25.

37 Avery, Ex. SD-5 at I-18, Appendix I-I, CAISO CSRTP July 2006 Report at 66-67; McClenahan, Ex.

SD-5 at III-9 – III-12; McClenahan, Ex. SD-37 at 2.2, 2.5; Oatman, Ex. SD-37 at 13.36.

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VI. IT WOULD BE ERROR TO ADOPT THE AD’S EMF MITIGATION

The AD (ordering ¶ 5) would require, as an EMF mitigation measure:

(a) Where such design modifications are consistent with low-cost policy set forth, for example, in Decision (D.) 07-03-012, SDG&E shall increase tower and conductor heights by 20 feet along any portions of the overhead transmission corridor where there are residences within 50 feet of the side of the right of way closest to the new 500 kV transmission lines.

(b) The mitigation described in subsection (a), above, shall apply where there are existing residential properties and also where development of new residences is underway at the time that SDG&E undertakes final project design, consistent with D.06-01-042.

But no party requested such a measure, the FEIR recommended no such measure, and, in

spite of the citations, no EMF policy requires such a measure. There is no evidence in the record

that this measure would reduce EMF exposure as contemplated by the Commission’s EMF

policy. And, no consideration was given to the fact that the measure could produce visual

impacts such that the property owners might actually prefer the normal tower and conductor

heights. It would be error to adopt the measure in such circumstances. SDG&E will submit the

amended EMF mitigation plan required by the AD and will adopt appropriate low-cost measures,

including, if warranted, adjustments to tower and conductor height. But there is simply no basis

in the Commission’s EMF policy or in the record for the AD’s arbitrary measure, including

distance values.

VII. THE COMMISSION SHOULD ENSURE FLEXIBLE MITIGATION

The FEIR for Sunrise includes mitigation measures for the Final Environmentally

Superior Southern Route, which are unprecedented in scope and complexity. Those mitigation

measures are set forth in a proposed Mitigation Monitoring, Compliance, and Reporting Program

(“MMCRP”). FEIR Section I. SDG&E commented extensively during the public comment

period on the DEIR and RDEIR, detailing its substantial concerns that many of the mitigation

measures, either individually or collectively, are disproportionate to the impacts, infeasible, or

both, and that they would unnecessarily increase the cost of the project and delay its in-service

date.38 Most of SDG&E’s concerns were not addressed in the FEIR.

38 The Commission recognized the challenges that “problematic mitigation measures” place on the development of transmission infrastructure to provide access to renewable energy resources for California

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The FEIR contemplates that “[i]f and when a project has been approved by the

Commission and BLM, the CPUC and BLM will compile the Final Plan from the Mitigation

Monitoring Program in the … [FEIR], as adopted” and describes the required content of that

Final Plan. FEIR Section I.2. The Final Plan should include, among other things, a “variance

process” and a procedure for SDG&E to notify the CPUC and the BLM if any of the mitigation

measures “are not or cannot be successfully implemented” and for the CPUC and BLM to

“assess whether alternative mitigation is appropriate and specify to SDG&E the subsequent

actions required.” FEIR Sections I.3 and I.4.

AD Ordering ¶ 7 provides: “The Mitigation Monitoring Program for the Final

Environmentally Superior Southern Route in the … [FEIR] is adopted and all feasible mitigation

measures indentified in the Final EIR/EIS are imposed upon construction of the Final

Environmentally Superior Southern Route” (emphasis added). SDG&E does not object to the

Commission adopting the MMCRP and imposing all feasible mitigation measures on the project,

as described. SDG&E requests, however, that the Commission provide the following guidance

to Commission staff (“staff”) in connection with development of the Final Plan.

1. The Final Plan must implement all feasible mitigation measures indentified in the Final EIR/EIS for the Final Environmentally Superior Southern Route to reduce or avoid the project’s significant environmental impacts consistent with CEQA.

2. For purposes of the Final Plan, “feasible” is defined by CEQA as “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, social, and technological factors.” See CAL. PUB. RES. CODE § 21061.1.

3. To the extent that implementation and enforcement of any mitigation measure is within the discretion of staff, staff may modify such mitigation measure in the Final Plan, provided that no new significant impacts are created by the modification and any existing impacts intended to be addressed by the mitigation measure continue to be avoided or reduced consistent with CEQA.

4. Throughout the Final Plan, to the extent that review and approval periods are within the discretion of staff, such review and approval periods should be as expedited as reasonably possible.

5. The Final Plan’s variance process shall provide for a clear process and timely decisions, and to the extent consistent with CEQA and all other applicable laws, reasonable flexibility in implementing the required mitigation measures.

and is seeking “potential improvements intended to both enhance protection of the environment and minimize the burden of compliance.” Workshop Notice for September 3, 2008 (I.08-03-010/R.08-03-009).

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6. The Final Plan shall provide for a clear process and timely decisions in connection with mitigation measures that are not or cannot be successfully implemented, assessment of alternative mitigation, and specification of subsequent actions required.

VIII. CONCLUSION

SDG&E requests that Commissioner Grueneich’s AD be modified and approved by the

Commission as described above, and as set forth in the appended proposed findings of fact and

conclusions of law.

Respectfully submitted,

/s/ E. GREGORY BARNES E. Gregory Barnes James F. Walsh SAN DIEGO GAS & ELECTRIC COMPANY 101 Ash Street San Diego, CA 92101 Telephone: 619/699-5019 Facsimile: 619/699-5027 E-mail: gbarnes@sempra.com Attorneys for SAN DIEGO GAS & ELECTRIC COMPANY

November 20, 2008

APPENDIX (Rule 14.3 (b))

PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW AND ORDERING PARAGRAPHS to PROPOSED ALTERNATE DECISION OF COMMISSIONER

GRUENEICH

Findings of Fact 1. At the time the Commission’s Economic Methodology Decision issued, SDG&E’s

2005 Application had been pending for almost one year and CAISO’s Board already had

approved CAISO’s economic evaluation of the Proposed Project. The assigned

Commissioner never issued a ruling that elected to apply the rebuttable presumption in

the Economic Methodology Decision to the economic analysis approved by CAISO’s

Board.

2. In the CPCN review at the Commission, at the direction of the Assigned

Commissioner and the ALJ in the Scoping Memo and later rulings, CAISO has presented

additional economic analyses, which it developed during Phase 1 and 2 hearings. The

assigned Commissioner never issued a ruling that elected to apply the rebuttable

presumption in the Economic Methodology Decision to this new economic analysis by

CAISO.

3. For purposes of developing an Analytical Baseline for determining the energy

benefits, reliability benefits, and RPS compliance savings estimates generated by all of

the Sunrise alternatives, the ALJ adopted CAISO’s modeling approach to quantifying

energy benefits, reliability benefits, and RPS compliance savings and to use CAISO’s

final Phase 2 modeling assumptions with the following deviations:

(a) use the Energy Commission staff’s November 2007 Forecast of 1-in-10 peak demand, including its embedded assumptions for the California Solar Initiative, energy efficiency, and other distributed generation;

(b) adjust the November 2007 Forecast by including the demand response savings we approved in SDG&E’s most recent Long Term Procurement Plan;

(c) assume that the existing South Bay Power Plant will retire by December 31, 2012 or the end of the year in which Sunrise comes online, whichever is earlier;

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(d) assume only 25% of the new coal fired generation identified in the SSG-WI database will come online and that combined cycle resources will be used to replace the canceled coal plants;

(e) assume that at least 50% of the out-of-state renewables identified by CAISO for its RPS Cost Savings modeling will be available to California;

(f) adopt CAISO’s initial renewable cost estimates;

(g) assume the implementation of UCAN’s Miguel Import Limit Upgrade;

(h) assume Imperial Irrigation District’s Path 42 increased rating and upgrades (reflecting a transfer capability of 1,200 MW) and its Dixieland-Imperial Valley line;

(i) assume Rancho Peñasquitos’ proposed Coastal Link Alternative; and

(j) assume SDG&E’s estimated capital costs for all of the Sunrise alternatives, and SDG&E’s 58-year amortization period for the Sunrise transmission alternatives, but assume UCAN’s projected operating and maintenance costs of $26.3 million per year, which will add $22.4 million per year to SDG&E’s projected costs for the various Sunrise routes.

4. The CAISO’s analysis concludes that the Environmentally Superior Southern

Route provides net annual levelized benefits over 58 years of between $155 million under

its RPS Base Case and $320 million annually. SDG&E’s analysis concludes that Sunrise

provides net annual levelized benefits over 58 years of between $145 million and $268

million in comparison to the In-Area All Source and In-Area Renewable alternatives.

These conclusions are a reasonable representation of the range of benefits that could be

realized with Sunrise.

5. It is not reasonable to rely solely on the ALJ’s Analytical Baseline Assumptions to

determine project need, because these assumptions represent a single scenario in

circumstances where other reasonable scenarios have been presented by CAISO and

SDG&E.

6. Given its relative low cost and apparent feasibility, SDG&E should implement

UCAN’s Miguel Import Limit Upgrade proposal and accordingly, UCAN’s motion

should be granted as specified herein.

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7. A review of Path 44’s rating is warranted given the passage of time since the last

review and given UCAN’s credible evidence that an increase in Path 44’s rating may be

possible.

8. Table 5 in Section 7.1.2 of the AD projects, based on the Analytical Baseline

assumptions, the “reliability need” for SDG&E’s service area.

9. Based upon this Analytical Baseline assumptions, SDG&E’s service area has no

reliability need for new resources before 2014 and has a surplus of capacity of 773 MW

in 2010, 698 MW in 2011, 624 MW in 2012, and 55 MW in 2013. SDG&E’s service

area shows a reliability need for new resources starting at 22 MW in 2014 and 95 MW in

2015, with a total of 456 MW by 2020.

10. Using reasonable assumptions based on Commission findings, SDG&E’s

updated Phase 2 analysis shows a 2010 reliability deficiency of 103 MW without Sunrise

growing over time.

11. The CAISO analysis shows 133 MW reliability deficiency in 2010. Taken with

the Analytical Baseline and SDG&E’s analysis, it is reasonable to find that a reliability

deficiency that Sunrise could address will arise as early as 2010.

12. Without Sunrise, this deficiency must be met with new generation sited within

the constrained San Diego basin.

13. Even if one assumes that there will be no reliability deficiency until 2014, given

the uncertainties of forecasting and the prospect of unforeseen delays in construction, it

would be reasonable to start construction of Sunrise as soon as possible in order to

address the reliability deficit.

14. SDG&E has placed more than enough in-state, north of SONGs projects on the

short list to fulfill its entire RPS obligation through 2010.

15. The Compliance Exhibit energy benefits estimates of $5 million per year under

20% RPS and $18 million per year under 33% RPS are within the range of reasonable

estimates in the record.

16. We find that the combustion turbine costs assumed by CAISO are reasonable; we

adopt CAISO’s modeling methodology for reliability benefits and the results of that

modeling, which show reliability benefits of $237 million per year, because CAISO’s

assumptions are consistent with our adopted Analytical Baseline assumptions.

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17. Construction of Sunrise will generate $90 million in RPS compliance costs under

20% RPS, based on the following reasonable inputs and modeling adjustments: using

CAISO’s CRS Renewable Costs in our adopted Analytical Baseline; assuming 50% of

out-of-state renewable resources will be available to California; and removing a modeling

limitation in the Compliance Exhibit that did not allow calculation of RPS compliance

costs, only RPS compliance savings. Under 33% RPS, Sunrise generates significant RPS

savings.

18. Our Update to the Compliance Exhibit makes adjustments in response to

comments by parties in order to reasonably analyze the Compliance Exhibit’s 4 cases

against the Analytical Baseline assumptions. The Update was prepared after the record

closed, based on post-record modeling. No workpapers documenting assumptions and

calculations have been provided, and no party has had the opportunity for discovery,

cross-examination or briefing on the Update, The Update makes the following

adjustments to the Compliance Exhibit:

(a) Assumes CAISO’s Phase 2 combustions turbine costs for all cases;

(b) adjusts the amount of in-area renewables in the All-Source Generation Alternative, thereby changing the distribution of renewables throughout the WECC, consistent with CAISO’s assumed supply curves;

(c) subtracts $367 million per year from the assumed capital cost of the All-Source Generation Alternatives in each scenario to address the 37 MW of solar PV already paid for in the California Solar Initiative program;

(d) adds $22.4 million per year to the assumed costs of SDG&E’s “Enhanced” Northern Route and the Draft EIR/EIS Environmentally Superior Southern Route to raise the CAISO’s assumed operating and maintenance costs of $3.9 million to our adopted Analytical Baseline assumption of $26.3 million per year; and

(e) adjusts the modeling of the 20% RPS cases to calculate negative RPS compliance savings (or costs).

19. Assuming 20% RPS, the All-Source Generation Alternative is a superior option to

Sunrise, regardless of renewable cost assumptions.

20. Assuming 33% RPS and CAISO Phase 2 combustion turbine costs, Sunrise will

generate over $100 million per year in net benefits, which significantly exceeds the $74

5

million per year of net benefits estimated for the All-Source Generation Alternative,

assuming CAISO’s CRS Renewable Costs.

21. Without a secure transmission path, no significant amount of new renewable

generation will be constructed in the Imperial Valley region. Developers will not risk

their capital investment without certainty that their projects’ generation will be

deliverable to loads. We agree with CAISO and SDG&E that the construction of Sunrise

would encourage the development of renewable resources in the Imperial Valley region,

thereby facilitating achievement of the state’s RPS goals.

22. There is a tremendous amount of uncertainty regarding conclusions reached by

the models used in this case.

23. The potentially significant construction-related GHG impacts from Sunrise can

only be justified if there is assurance that the line will deliver significant amounts of

renewables, rather than fossil fired resources.

24. This Commission has an obligation to ensure that cost-effective renewables flow

over Sunrise to meet our GHG goals and to realize the RPS cost savings projected for the

line under 33% RPS.

25. 60% of the energy currently under contract that SDG&E needs to comply with the

20% RPS mandate, or approximately 2,000 GWh, is located in Imperial Valley and

contingent upon Sunrise.

26. Imperial Valley supports an unparalleled diversity of potential renewable

generation technologies that would be facilitated by Sunrise, including 2,300 MW of base

load geothermal.

27. Since the Sunrise project was announced, there have been over 5,000 MW of new

renewable generator interconnect requests in the CAISO queue that would be facilitated

by Sunrise.

28. Without the Sunrise Powerlink there is a substantial likelihood that only a fraction

of the potential generating capacity in Imperial Valley will come online.

29. The Commission has already approved 4 RPS PPAs in the Imperial Valley that

would be facilitated by Sunrise.

30. The “Minnesota approach” referenced by Conservation Groups would require

assurances that substantial renewable energy is contracted for delivery over the proposed

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line before the line becomes operational, and does not require proof of the contracts

before construction can begin.

31. The new energy projects from the Imperial Valley region under contract to

SDG&E or to other utilities such as SCE, the delivery of which Sunrise would facilitate,

together with such projects in the CAISO and IID interconnection queue, taken provide

the assurances sought by the “Minnesota approach.”

32. Reinforcing the assurances from executed contracts in the record, SDG&E has

made commitments to the effect that, if the Commission approves Sunrise without a

compliance plan subject to prior Commission approval and with an appropriate cost cap

(1) SDG&E will commit to not contract with coal generators for the delivery of energy

across the Sunrise Powerlink; (2) SDG&E will commit that in event that a renewable

resource that is deliverable by Sunrise and currently under contract to SDG&E fails, it

will seek to replace that energy with another renewable resource from the same region;

and (3) SDG&E will voluntarily commit to raise its RPS target to 33 percent by 2020,

and to work with the Commission, Legislature and other stakeholders to develop a fair set

of rules that will apply to all load serving entities. Theses commitments were detailed in

SDG&E’s comments on the Alternate Decision of Assigned Commissioner Grueneich.

33. Anza-Borrego’s General Plan, which governs State Parks’ management of the

Anza-Borrego, does not provide an exemption from its mandate for construction and

maintenance of a major transmission line like the Proposed Project.

34. If State Parks determined that any Northern Route through Anza-Borrego was

inconsistent with the existing Anza-Borrego General Plan, the State Parks and Recreation

Commission would have to exercise its discretionary authority to adopt revisions to the

General Plan to allow the siting and construction of this kind of project before State Parks

could issue any permits, which would cause substantial delay.

35. The Proposed Project’s Anza-Borrego Link will require de-designation of 50.2

acres of state wilderness; other Northern Routes would have a lesser, direct impact on

wilderness but still might require de-designation of some wilderness land.

36. Because SDG&E, BLM, Imperial Irrigation District and State Parks contest the

width and continuity of the existing easement through Anza-Borrego, any approval of a

Northern Route likely would lead, at minimum, to a complex and significant debate over

7

the legal status and rights associated with easements through Anza-Borrego, and would

cause substantial delay.

37. Any Northern Route would have massive significant and unmitigable

environmental impacts on Anza-Borrego; be contrary to community values – both those

of the people who visit Anza-Borrego, as well as the values embodied in our state laws

protecting areas like Anza-Borrego; be permanently detrimental to recreational and park

areas within Anza-Borrego; and have permanent and negative impacts on historical and

aesthetic resources in Anza-Borrego.

38. Based on the fire history reviewed herein, 230 kV and 500 kV lines placed on

steel towers are highly unlikely to ignite fires. However, given the fire risks associated

with any transmission line route in San Diego County, approval of the Final

Environmentally Superior Southern Route must be conditioned upon the most rigorous,

reasonable mitigation available to reduce the risk of fire ignition; therefore, this

Commission should impose all feasible mitigation measures specified in the ordering

paragraphs.

39. While the fire history reviewed herein suggests a concurrent outage involving the

Southwest Powerlink and the Environmentally Superior Southern Route is more likely

than one involving the Environmentally Superior Northern Route, a dual line outage

could occur whether or not a new transmission line is collocated with the Southwest

Powerlink, since special proximity is not the only indicator of a concurrent outage.

Moreover, the 230 kV segments of the Environmentally Superior Northern Route put

more assets at risk of fire.

40. The All-Source Generation Alternative, the In-Area Renewable Alternative, and

the LEAPS Transmission-Only Alternative – the three alternatives that the Final EIR/EIS

determines to be environmentally superior to the Final Environmentally Superior

Southern Route, are not feasible when the Commission factors in certain other

considerations, including meeting California’s broader policy goals.

41. The Final Environmentally Superior Southern Route is the highest ranked

Alternative that will facilitate Commission policy to achieve GHG reductions through

renewable procurement in the shortest time possible with the greatest economic benefits;

8

therefore, the Final Environmentally Superior Southern Route is necessary to meet

California’s GHG goals by facilitating increased levels of renewable development.

42. Approval of Sunrise should be conditioned as specified in the ordering paragraphs

to address community values concerns raised by Mussey Grade and others.

43. The EIR/EIS has adequately considered the concerns of the affected agricultural

communities in siting the Final Environmentally Superior Southern Route; moreover,

approval of the Final Environmentally Superior Southern Route rather than a Northern

Route significantly mitigates impacts on agricultural lands.

44. SDG&E should notify the Commission of any changes in the final project

development schedule for the Final Environmentally Superior Southern Route.

45. The Final EIR/EIS was presented to the Commission, and the Commission has

received, reviewed, and considered the information contained in the Final EIR/EIS.

46. The Final EIR/EIS reflects the Commission’s independent judgment and analysis.

47. Significant and unavoidable environmental impacts will result from construction

and operation of the Final Environmentally Superior Southern Route; however, the

Commission has adopted all feasible mitigation measures; adopted certain alternatives

that reduce the impacts of the Final Environmentally Superior Southern Route; rejected

as infeasible alternatives to the Final Environmentally Superior Southern Route;

recognized all significant, unavoidable impacts; and balanced the benefits of the Final

Environmentally Superior Southern Route against its significant and unavoidable

impacts.

48. The benefits of the Final Environmentally Superior Southern Route outweigh and

override its significant and unavoidable impacts, for the reasons set forth in the statement

of overriding considerations in Section 20.3 of today’s decision.

49. The proposed Mitigation Monitoring, Compliance, and Reporting Program

(Mitigation Monitoring Program) in the Final EIR/EIS is designed to ensure compliance

with the changes in the project and mitigation measures imposed on the authorized

project during implementation and recommends a framework for implementation of the

Mitigation Monitoring Program by this Commission as the CEQA lead agency.

50. SDG&E should amend its EMF Management Plan as needed to apply its no-cost

EMF management techniques to the Final Environmentally Superior Southern Route.

9

51. The reasonable maximum cost for the Final Environmentally Superior Southern

Route pursuant to § 1005.5(a) is $1.883 billion ($2012), based on estimates as calculated

in Section 22 of today’s decision. Given the magnitude of the uncertainty and risk

attendant to project completion, it is reasonable, consistent with other Commission

decisions approving large projects, to add 10% to this maximum cost to establish the

project’s cost cap.

52. SDG&E should take the necessary steps to institute a review of Path 44’s rating,

should report within 90 days of the effective date of this decision on the status of the

review and should serve the report on the assigned Commissioner, other four

Commissioners, the Director of the Commission’s Energy Division, and the service list

for A.06-08-010. The Energy Division’s Director should require additional reports as

deemed necessary.

53. The exhibits specified in the ordering paragraphs were identified at hearing but

inadvertently, were not received in evidence. The CAISO Workpapers specified in the

ordering paragraphs should be identified and received in evidence as CAISO Exhibit I-

15. To ensure the completeness of the record, the complete EIR/EIS should be made a

reference exhibit as indicated in the ordering paragraphs.

Conclusions of Law 1. The Commission has jurisdiction over the proposed transmission project pursuant

to § 1001 et seq.

2. The preponderance of the evidence standard, the default standard in civil and

administrative law cases, is the applicable standard of review here.

3. Neither the CAISO Board-approved economic evaluation nor the subsequent

CAISO economic evaluation should be granted a rebuttable presumption under the

Commission’s Economic Methodology Decision.

4. Consistent with the Commission’s Valley Rainbow and Jefferson-Martin decisions

and the CAISO Grid Planning Committee Guidelines, and prudent transmission planning

principles for a five year planning horizon, it is reasonable to assume for planning

forecasts only generation that is under construction and has a planned in-service date

within that planning horizon should be considered as in-service for reliability analysis. In

10

ten-year planning cases, only generation under construction or that has received

regulatory approval should be assumed in a reliability analysis.

5. The range of reasonable scenarios presented shows Sunrise is needed to fill a

reliability deficit beginning as early as 2010.

6. Sunrise is necessary to facilitate California’s achievement of its 2010 RPS goal of

20%, and therefore the Sunrise application is approved pursuant to P.U. Code § 399.25.

7. SDG&E will be held to the commitments it made in its comments to

Commissioner Grueneich’s Alternate Proposed Decision to provide additional assurance

that renewable resources are delivered by Sunrise in order to meet the Commission’s

GHG goals and to realize the RPS cost savings projected for the line under 33% RPS.

8. Anza-Borrego is subject to the California Wilderness Act.

9. The Final EIR/EIS has been completed in compliance with CEQA and should be

certified.

10. The Mitigation Monitoring Program in the Final EIR/EIS should be adopted,

and, to the extent consistent with CEQA, the Final Plan under that program should

provide a clear and timely variance process for mitigation measures.

11. Consistent with our interpretation of § 625 in D.01-10-029, the appropriate

standard of notice for Sunrise is that prescribed by § 625(a)(1)(B), which only requires

notice to the Commission Calendar.

12. The Commission has jurisdiction and responsibility pursuant to § 1005.5(a) to

specify a “maximum cost determined to be reasonable and prudent” for the Sunrise

project. If, as specified in the ordering paragraphs, the cost estimates for the Final

Environmental Superior Southern Route should prove be materially lower than or higher

than the adopted cost cap, SDG&E shall request an adjustment to the cost cap.

13. Since no party will be prejudiced thereby, the exhibits specified in the ordering

paragraphs should be received in evidence and the complete EIR/EIS should be made a

reference exhibit.

14. UCAN’s motion regarding its Miguel Import Limit Upgrade proposal should be

granted as specified in the ordering paragraphs. Since no party will be prejudiced

thereby, these motions should be granted: all pending motions of the CAISO for leave to

file late and leave to submit additional testimony; all pending motions to adopt transcript

11

corrections; the motion of Powers Engineering Requesting Permission for Late Filing of

Brief and Reply Brief. Today’s decision on the merits of Sunrise renders all other

pending motions moot.

ORDER

IT IS ORDERED that:

1. The request of San Diego Gas & Electric Company (SDG&E) for a certificate of

public convenience and necessity to construct the proposed Sunrise Powerlink

Transmission Project (Sunrise) is granted for the routing alternative identified in the Final

Environmental Impact Report/Final Environmental Impact Statement (Final EIR/EIS) as

the Final Environmental Superior Southern Route, subject to the additional requirements

in Ordering Paragraphs 4 through 8, 12(c), and 13.

2. The Final EIR prepared for Sunrise is certified.

3. SDG&E shall notify the Commission of any changes in the final project

development schedule for the Final Environmentally Superior Southern Route.

4. The Mitigation Monitoring Program for the Final Environmentally Superior

Southern Route in the Final EIR/EIS is adopted and all feasible mitigation measures

identified in the Final EIR/EIS are imposed upon construction of the Final

Environmentally Superior Southern Route, including:

(a) requiring fire-safe construction practices to reduce the risk of wildfire ignitions during construction;

(b) prohibiting construction during extreme weather conditions to reduce the risk of potentially catastrophic wildfire ignitions during construction;

(c) ensuring adequate coordination for emergency fire suppression to avoid project personnel and equipment interference with firefighting operations;

(d) ensuring adequate removal of hazardous vegetation;

(e) requiring annual contributions to a Defensible Space Grants Fund that will assist in the maintenance of defensible space requirements and in the implementation of other fire-safe measures at the private residences most at risk of a project-related wildfire;

(f) requiring the replacement of existing 69 kV wood poles that are within 100 feet of the project with steel poles to mitigate the

12

potential fire hazard of a wood pole being knocked into the adjacent conductors;

(g) requiring annual contributions to a Firefighting Mitigation Fund that will improve fire prevention measures and help improve fire protection equipment and services;

(h) requiring a Memorandum of Understanding between SDG&E, Cal Fire, and Cleveland National Forest to coordinate effective fire plans and emergency procedures;

(i) requiring weed abatement and controls for invasive weeds to prevent establishment of non-native plants that have a high ignition potential and carry fires at a high rate of spread; and

(j) requiring climbing inspections on 10% of the project structures annually to improve detection of imminent component failures that could result in wildfire ignitions.

5. In connection with development of the Final Plan under the adopted Mitigation

Monitoring Program, Commission staff (“staff”) is directed as follows”

(a) The Final Plan must implement all feasible mitigation measures indentified in the Final EIR/EIS for the Final Environmentally Superior Southern Route to reduce or avoid the project’s significant environmental impacts consistent with CEQA.

(b) For purposes of the Final Plan, “feasible” is defined by CEQA as “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, social, and technological factors.” See CAL. PUB. RES. CODE § 21061.1.

(c) To the extent that implementation and enforcement of any mitigation measure is within the discretion of staff, staff may modify such mitigation measure in the Final Plan, provided that no new significant impacts are created by the modification and any existing impacts intended to be addressed by the mitigation measure continue to be avoided or reduced consistent with CEQA.

(d) Throughout the Final Plan, to the extent that review and approval periods are within the discretion of staff, such review and approval periods should be as expedited as reasonably possible.

(e) The Final Plan’s variance process shall provide for a clear process and timely decisions, and to the extent consistent with CEQA and all other applicable laws, reasonable flexibility in implementing the required mitigation measures.

(f) The Final Plan shall provide for a clear process and timely decisions in connection with mitigation measures that are not or

13

cannot be successfully implemented, assessment of alternative mitigation, and specification of subsequent actions required.

6. SDG&E shall amend its Electro Magnetic Field (EMF) Management Plan as

needed to apply its no-cost EMF management techniques to the Final Environmentally

Superior Southern Route.

7. The reasonable total project cost of $1.89 billion ($2012) plus a 10% adder for

contingency is adopted for the Final Environmentally Superior Southern Route. SDG&E

shall apply to the Commission for an adjustment of the cost cap in the following

instances:

(a) If upon completion of the final, detailed engineering design-based

construction estimates for the Final Environmental Superior Southern Route,

SDG&E concludes that the cost will be materially (i.e., 1% or more) lower

than the adopted maximum, SDG&E shall submit an updated cost estimate

with an explanation of why the cost cap should not be revised downward to

reflect the new estimate.

(b) If SDG&E’s final estimate exceeds the approved cost cap, SDG&E shall seek

an increase in the cost cap pursuant to Public Utilities Code Section 1005.5(b).

8. The documents that constitute the Final Environmental Impact

Report/Environmental Impact Statement (Final EIR/EIS) are received as Reference

Exhibits on the effective date of this decision, as follows:

(a) Draft EIR/EIS – Reference Exhibit A;

(b) Recirculated Draft EIR/Supplemental Draft EIS – Reference Exhibit B;

(c) Final EIR/EIS – Reference Exhibit C; and

(d) Revisions to the Final EIR/EIS – Reference Exhibit D.

9. The following exhibits are received in evidence on the effective date of

this decision: Conservation Groups Exhibit C-15; Imperial Irrigation District Exhibit ID-

4; Mussey Grade Exhibit MG-32; Powers Engineering Exhibit Powers-1; and Rancho

Peñasquitos Exhibits R-9, R-10, R-11, R-12, R-13, and R-14.

10. CAISO Workpapers with the file names CAISO3 SD&LA v5.xls, CAISO3

SD&LA v5 less LCR case.xls, and CAISO3 SD&LA v4.xls are identified as CAISO

Exhibit I-15 and received in evidence on the effective date of this decision.

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11. Pending motions are resolved as follows:

(a) All pending motions of the CAISO for leave to file late and leave to submit additional testimony are granted;

(b) All pending motions to adopt transcript corrections are granted;

(c) The June 5, 2007 Motion to Compel SDG&E to Upgrade its Import Capability at Miguel Substation filed by Utility Consumer’s Action Network (UCAN) is granted as specified herein and within 30 days of the effective date of this decision SDG&E shall serve (but not file) a status report on assigned Commissioner Dian M. Grueneich, the other four Commissioners, the Director of the Commission’s Energy Division, and the service list for Application (A.) 06-08-010;

(d) The September 24, 2008 motion of Powers Engineering Requesting Permission for Late Filing of Brief and Reply Brief is granted;

(e) UCAN’s June 5, 2007 Motion to Enjoin SDG&E from Entering Into a Permanent Cross-Trip Arrangement with CFE is denied as moot; and

(f) All motions or portions of motions that have not otherwise been resolved are denied as moot.

12. SDG&E shall take the necessary steps to institute a review of Path 44’s rating

and, within 90 days of the effective date of this decision, shall report on the status of that

review and shall serve (but not file) the report on the assigned Commissioner and the

service list for A.06-08-010, the other four Commissioners, and the Director of the

Commission’s Energy Division. The Energy Division’s Director will require additional

reports as deemed necessary.

13. The issues in the Assigned Commissioner and Administrative Law Judge’s

Scoping Memo and Ruling, November 1, 2007, and Revised Scoping Memo and Ruling of

the Assigned Commissioner and Administrative Law Judge, June 20, 2008, have been

addressed and this proceeding is resolved for the purpose of compliance with Public

Utilities Code Section 1705.1. However, the proceeding remains open to address, as an

adjudication, the issues raised by the Assigned Commissioner’s Revised Scoping Memo

and Ruling Regarding Possible Rule 1.1 and Rule 8.3 Violations; Order to Show Cause,

August 1, 2008.

This order is effective today.

CERTIFICATE OF SERVICE

I hereby certify that I have this day served a copy of the foregoing COMMENTS OF

SAN DIEGO GAS & ELECTRIC COMPANY ON ALTERNATE PROPOSED

DECISION OF COMMISSIONER GRUENEICH on all parties identified in Docket No.

A.06-08-010 by U.S. mail and electronic mail, and by Federal Express to the assigned

Commissioner(s) and Administrative Law Judge(s).

Dated at San Diego, California, this 20TH day of November, 2008.

/s/ JOEL DELLOSA Joel Dellosa