DECISION GRANTING A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY FOR THE SUNRISE POWERLINK TRANSMISSION PROJECT

Procedural History

The proceedings began on December 14, 2005, when SDG&E submitted Application (A.) 05 12 014, seeking a Certificate of Public Convenience and Necessity (CPCN) for the construction of the Sunrise project Due to significant shortcomings in the initial application, such as the lack of a defined route and the absence of a Proponent’s Environmental Assessment (PEA), SDG&E submitted a new set of documents on August 4, 2006 Although this 2006 submission has sometimes been informally referred to as an "amendment" to the 2005 application, it was officially designated as a distinct filing.

2006 filing as a new application and assigned a new proceeding number,

A.06 08 010 (2006 Application) The Chief Administrative Law Judge (ALJ) consolidated the dockets for the 2005 and 2006 Applications and subsequently, in D.07 11 008, we affirmed the consolidation and then closed the 2005 Application.

On September 6, 2006, responding to requests from the Commission’s Energy Division, SDG&E filed a multiple volume supplement to the 2006

Application On September 13, 2006, the assigned ALJ held a Prehearing

Conference in Ramona, California During this period the Commission continued to receive protests and ultimately more than a dozen were filed 14 A

14 The following persons and entities filed protests to the 2005 Application, the 2006 Application, or both: California State Parks Foundation (State Parks Foundation);

Carmel Country Highland Owners; the Cities of Hemet, Murrieta and Temecula;

Community Alliance for Sensible Energy; the Center for Biological Diversity and the Sierra Club, San Diego Chapter (Conservation Groups); Division of Ratepayer

Advocates (DRA); Imperial Irrigation District; Mussey Grade Road Alliance (Mussey Grade); Nevada Hydro Company (Nevada Hydro); Ramona Alliance Against Sunrise Powerlink; Ratepayers For Affordable Clean Energy Coalition; Starlight Mountain

The Scoping Memo, issued after the Prehearing Conference as mandated by law, outlines the scope and schedule of the proceeding, aligning the CPCN review with the timeline for the concurrent CEQA/NEPA review It appoints ALJ Steven Weissman as the presiding officer and divides the hearings into two phases: Phase 1 will address all relevant issues before the Draft EIR/EIS is released, while Phase 2 will focus on matters related to the Draft EIR/EIS Further details on the Scoping Memo are provided in Section 2.2 On October 2, 2006, SDG&E submitted additional information.

2006 Application to include and rank four alternative routings which, unlike its initial route, would not pass through Anza Borrego On January 19, 2007,

SDG&E filed corrections to certain cost/benefit assumptions in the 2006

The scoping processes for NEPA and CEQA began on August 31, 2006, when the Bureau of Land Management (BLM) published a Notice of Intent in the Federal Register to prepare an Environmental Impact Statement (EIS) This was followed by the initiation of the CEQA scoping process on September 15, 2006.

In October 2006, the Commission Energy Division staff released a Notice of Preparation for an Environmental Impact Report (EIR) The Bureau of Land Management (BLM) and Commission staff, along with their environmental consultants, conducted seven public scoping meetings By November 2006, the Commission had gathered more than 300 comments regarding the Notice of Preparation.

Estates Owners; West Chase Homeowners Association; and Utility Consumers' Action Network (UCAN)

15 Assigned Commissioner and Administrative Law Judge’s Scoping Memo and Ruling (Scoping

Memo), November 1, 2006. public, private, and tribal agencies and from members of the public In February

In 2007, after initially identifying alternatives for the EIR/EIS, BLM and Commission staff, along with their consultants, conducted eight additional public scoping meetings to gather further input The CEQA/NEPA review then continued with ongoing public notice and opportunities for input at key milestones, in accordance with environmental regulations.

Though we originally expected to release the Draft EIR/EIS on August 3,

2007, issuance of the document was delayed by five months when, in the course of Phase 1 hearings, SDG&E disclosed new information critical to the

On January 4, 2008, the Commission and BLM published the Draft EIR/EIS, followed by a series of nine workshops from January 28 to February 1, 2008, aimed at presenting the document to the public and gathering written feedback In late February 2008, the ALJ and assigned Commissioner conducted five Public Participation Hearings to collect both written and oral statements On July 11, 2008, the lead agencies issued a Recirculated Draft EIR/Supplemental Draft EIS for further public comment, ultimately leading to the release of the Final EIR/EIS after reviewing all additional feedback.

16 Assigned Commissioner’s Ruling Addressing Newly Disclosed Environmental Information, July 24, 2007

The review of this application encompassed four Prehearing Conferences, multiple workshops, and public input gathered during Public Participation Hearings in various locations, including Borrego Springs, Ramona, San Diego, Julian, and Pine Valley Notably, Borrego Springs hosted three sessions, one attended by four commissioners and another by three, while Ramona held three sessions with comments collected during two Prehearing Conferences Additionally, the review included 37 days of evidentiary hearings, split evenly between San Diego and San Francisco.

Commissioner Dian M Grueneich actively participated in all Prehearing Conferences and Public Participation Hearings Following the Phase 1 hearings, we received a series of Opening and Reply Briefs, and a subsequent round after Phase 2 Shortly after, a Revised Scoping Memo was issued, instructing CAISO to conduct additional modeling runs to finalize the record, which were to be submitted as Exhibit Compliance 1.

17 The following parties filed briefs: (1) Phase 1 Opening Briefs (on or about

On November 9, 2007, Cabrillo Power I LLC collaborated with various stakeholders, including the California Independent System Operator (CAISO), conservation groups, the California Department of Parks and Recreation, the California Farm Bureau Foundation, the Division of Ratepayer Advocates (DRA), the Imperial Irrigation District, Mussey Grade, Nevada Hydro, and Rancho Peñasquitos.

Concerned Citizens (Rancho Peủasquitos), SDG&E, South Bay Replacement Project (South Bay), and UCAN; (2) Phase 1 Reply Briefs (on or about November 30, 2007): CAISO; Conservation Groups, DRA, Imperial Irrigation District, Mussey Grade,

Nevada Hydro, Rancho Peủasquitos, SDG&E, South Bay, State Parks and UCAN;

(3) Phase 2 Opening Briefs (on or about May 30, 2008): CAISO, City of Santee,

Conservation groups, including DRA, the Farm Bureau, and the Imperial Irrigation District, alongside key stakeholders such as Jacqueline Ayer, Mussey Grade, Nevada Hydro, and Powers Engineering, are actively engaged in discussions regarding Phase 2 Reply Briefs, expected around June 13, 2008 This collaborative effort also involves the City of Santee, Rancho Peñasquitos, SDG&E, South Bay, State Parks, and UCAN, highlighting a unified approach to addressing regional energy and environmental concerns.

(Compliance Exhibit), authorized parties to file a round of comments, and addressed other outstanding matters 18

The procedural history of our review of Sunrise involved numerous discovery conferences and modeling workshops due to the complexity of the issues and the number of parties involved These sessions were essential for conducting detailed computer modeling, which played a crucial role in assessing SDG&E's justification for the Proposed Project in relation to alternative options.

Scoping Memo

In accordance with §1701.1, the Scoping Memo defined the scope of the proceeding, set a preliminary schedule, and covered essential procedural matters including discovery and the submission of prepared testimony and pleadings.

The Scoping Memo identified the scope of this application as including

The proposed project evaluates SDG&E's preferred route and configuration, alongside alternative routes, the no project alternative, and non-wires alternatives It also outlines the legal framework for review, focusing on the assessment of the project's necessity and cost-effectiveness.

18 Revised Scoping Memo and Ruling of the Assigned Commissioner and Administrative Law

Judge (Revised Scoping Memo), June 20, 2008 A subsequent ruling revised the dates for comment Administrative Law Judge’s Ruling Memorializing Dates for Comments on Exhibit

Compiance 1, August 28, 2008 The following parties filed comments/briefs:

(1) Opening (on September 5, 2008): CAISO, DRA, Nevada Hydro, Rancho

On September 10, 2008, key stakeholders including Peñasquitos, SDG&E, UCAN, CAISO, DRA, Jacqueline Ayer, and SDG&E engaged in discussions regarding a project under § 1001 This involved evaluating four critical factors outlined in § 1002(a): community values, recreational and park areas, historical and aesthetic significance, and environmental impact, necessitating a thorough environmental analysis.

The Scoping Memo outlined clear guidance for the parties involved, emphasizing the importance of CEQA compliance and adherence to other relevant laws mentioned in Section 4 of this decision, while also detailing the need for additional modeling and related activities.

The Revised Scoping Memo, released following the Phase 2 hearings, recognized the necessity to recirculate the Draft EIR/EIS and outlined the fundamental modeling assumptions that CAISO will utilize in its preparation.

Compliance Exhibit, and adjusted the schedule of the proceeding accordingly

Project Objectives

SDG&E's PEA outlines that the Sunrise project was created to fulfill eight specific objectives In accordance with CEQA and NEPA regulations, lead agencies are required to define the project's objectives for evaluation purposes, which are essential for compliance with these environmental review processes.

19 Section 3.1 of SDG&E’s PEA sets forth the eight objectives, which we paraphrase as follows:

1) Ensure that SDG&E’s transmission system satisfies reliability criteria.

To ensure effective transmission facilities, it is essential to maintain a voltage level and transfer capability that accommodates prudent system expansion for both anticipated short-term load growth by 2010 and long-term growth extending beyond 2015 Additionally, these facilities should facilitate the regional expansion of the electric grid.

To support SDG&E customers in achieving California's renewable energy goals, it is essential to enhance transmission capacity for renewable resources in the Imperial Valley This initiative aims to meet or surpass the state's mandate of 20% renewable energy by 2010 and the Governor's ambitious target of 33% by 2020 After careful evaluation, the Commission and BLM staff have refined SDG&E's eight Project Objectives into three fundamental goals, which serve as the basis for our review of the Sunrise project.

• Basic Project Objective 1: to maintain reliability in the delivery of power to the San Diego region;

• Basic Project Objective 2: to reduce the cost of energy in the region; and

The primary objective of the project is to facilitate the delivery of renewable energy, aiming to fulfill state and federal renewable energy targets This initiative will harness geothermal and solar resources from the Imperial Valley, along with wind and other energy sources from San Diego County.

Description of the Northern Routes

The Proposed Project

The Proposed Project consists of a 150 mile transmission line between Southern California’s Imperial and San Diego counties 21 The major project components comprise:

• A new 91 mile, single circuit 500 kV overhead electric transmission line linking SDG&E’s existing Imperial Valley Substation (in

Imperial County near the City of El Centro) with a new 500/230 kV Central

East Substation to be constructed in the San Felipe area of central San Diego

County, southwest of the intersection of County Highway S22 and S2;

• A new 59 mile 230 kV double circuit and single circuit transmission line, running partly overhead and partly underground through San Diego County from the proposed new 500/230 kV Central

East Substation to SDG&E’s existing Peủasquitos Substation (in the City of

Recent upgrades include the installation of a 230 kV shunt capacitor at SDG&E’s San Luis Rey Substation and a 69 kV shunt capacitor at the South Bay Substation Additionally, the conductors on an existing 8.2-mile, 69 kV transmission line have been replaced to enhance efficiency and reliability.

SDG&E’s existing Sycamore Canyon Substation to its existing Elliott

The project’s two transmission components (the 91 mile 500 kV component and the 59 mile double and single circuit 230 kV components) consist of five separate segments or “links”:

21 See Draft EIR/EIS, Sec B.2 and B.3 for a more complete description of the Proposed Project.

• The Imperial Valley Link 60.9 miles of 500 kV line from

Imperial Valley Substation (west of El Centro) to the eastern boundary of Anza Borrego;

• The Anza Borrego Link 22.6 miles of 500 kV line entirely within the boundaries of Anza Borrego;

• The Central Link (Central San Diego County) 27.3 miles (7.4 miles of

500 kV line; 19.9 miles of 230 kV line) in the communities of Ranchita and San Felipe;

• The Inland Valley Link (West Central San Diego County) 25.5 miles of

230 kV through the communities of Santa Ysabel and Ramona, and through Marine Corps Air Station Miramar; and

• The Coastal Link (Western San Diego County) 13.6 miles of 230 kV line with new towers in communities of Rancho Peủasquitos and Torrey Hill (City of San Diego)

The Proposed Project also requires the relocation of several segments of existing transmission lines, as follows:

• Move nine miles of an existing 69 kV transmission line to parallel the proposed new 230 kV line at a point between the junction of

State Route 76 and State Route 79, near the existing Santa Ysabel

The project involves relocating the existing 69 kV and 92 kV transmission lines situated between the eastern boundary of Anza Borrego and a location near the proposed Central East Substation This will be achieved by undergrounding sections of the lines within the adjacent State Route 78 roadway and installing additional segments on the new infrastructure.

500 kV towers sited within Anza Borrego.

SDG&E’s “Enhanced” Northern Route

In response to concerns and suggestions raised by agencies and landowners, SDG&E proposed, after the Phase 1 hearings, an “Enhanced”

Northern Route, a 148.6 mile long transmission line that follows the same general corridor as the Proposed Project, with certain modifications 22 The major changes include:

The Anza Borrego Link's footprint will be modified to restrict the 500 kV line to the current right of way of the existing wood pole line in Anza Borrego This adjustment aims to prevent the necessity of acquiring new right of way within the Park or redesignating state wilderness.

• A few minor segment alternatives and/or modified reroutes through portions of the Proposed Project’s Imperial Valley and Inland

The Final Environmentally Superior Northern Route

The EIR/EIS evaluated and compared various routing alternatives that reduce the environmental impacts of the Proposed Project’s route, including the

“Enhanced” Northern Route, to identify the least environmentally damaging Northern Route The Final Environmentally Superior Northern Route,

140.8 miles long, is a combination of segment alternatives and reroutes that

“replace” corresponding sections of the Proposed Project The Final

Environmentally Superior Northern Route is almost identical to the Draft

The Northern Route, deemed environmentally superior, has been revised to incorporate reroutes proposed by SDG&E, aimed at further minimizing the route's environmental impacts, as detailed in the Recirculated Draft EIR/Supplemental Draft EIS.

22 For a more detailed description, see Recirculated Draft EIR/Supplemental Draft EIS, Sec 5.3.1 major differences between the Final Environmentally Superior Northern Route and the Proposed Project include:

• Relocation of the 230/500 kV substation east of Anza

• Installation of a double circuit bundled 230 kV line through Anza Borrego (the All Underground Option); 23 and

• Construction of the Santa Ysabel All Underground

Alternative in the Santa Ysabel Valley.

The EIR/EIS describes the Final Environmentally Superior Northern Route in more detail 24

Standard of Review and Governing Law

Burden of Proof

SDG&E, as the Applicant, is required to prove the necessity for the Commission to grant the Certificate of Public Convenience and Necessity (CPCN) The utility must clearly demonstrate the reasonableness of its entire application, while intervenors are not obligated to prove any unreasonableness in SDG&E's claims.

Evidence Code §115 defines burden of proof as follows:

23 The 230 kV transmission line between the San Felipe Substation and the connection to the Proposed Project would be installed underground in State Route 78 and County Highway S2.

25 Investigation into Methodology for Economic Assessment of Transmission Projects,

D.06 11 018, 22 [“The Commission has long held that the applicant carries the burden of proof in a certification proceeding, and we reiterate those determinations today.”]

26 Southern California Edison Test Year 2006 General Rate Application, D.06 05 016, 7

The term "burden of proof" refers to the responsibility of a party to provide sufficient evidence to convince the trier of fact regarding a specific fact This obligation may involve creating reasonable doubt about a fact's existence or establishing it through varying standards of proof, including preponderance of the evidence, clear and convincing evidence, or proof beyond a reasonable doubt.

Except as otherwise provided by law, the burden of proof requires proof by a preponderance of the evidence.

SDG&E contends that the preponderance of the evidence standard should be utilized in this case, referencing D.07-04-049, which indicates that the Commission has exclusively applied the higher clear and convincing standard in general rate cases and reasonableness reviews, explicitly rejecting its application in other contexts Conversely, DRA, UCAN, and others cite multiple rate case and reasonableness review decisions to argue that the clear and convincing evidence standard is appropriate for the Sunrise case Notably, no party has mentioned any prior decisions related to a transmission line CPCN.

Southern California Edison’s Application for Approval of Summer 2007 New Generation RFOs and Cost Recovery, D.07 04 049, modified the previous decision D.07 01 041 and denied rehearing This ruling establishes that the preponderance of evidence standard is applicable for reviewing the contract in question, specifically concerning Long Beach.

Generation will repower 260 megawatts of peaking capacity at Long Beach and make this capacity available to Edison for ten years

28 The parties’ citations include: Pacific Gas & Electric Co Energy Cost Adjustment Clause

In the case of Application D.82486, 701 (1980) and D.00 02 046 concerning Southern California Edison, as well as General Rate Case D.83 05 036 (1983), our research indicates that the Commission initially required clear and convincing evidence in D.44923 This was evident during its review of a motion to dismiss a telephone utility's application for a rate increase, where the Commission emphasized the necessity for substantial proof.

Witkin provides valuable insights into two key legal standards: preponderance of the evidence and clear and convincing evidence The former is characterized by a likelihood of truth, where evidence outweighs opposing evidence in convincing force In contrast, clear and convincing evidence is defined as being explicit and unequivocal, leaving no substantial doubt and being strong enough to gain the unhesitating agreement of any reasonable person.

The preponderance of the evidence is generally the default standard in civil and administrative law cases and we apply that standard in this decision 31

Section 1001 et seq

Section 1001 et seq establishes the framework for our review of Sunrise and we focus, here, on the two basic components of that framework, §§ 1001 and

In this legislative proceeding, the applicant bears the significant burden of proof, needing to demonstrate through clear and convincing evidence that the current rates they challenge result in the confiscation of their property, unlike ordinary civil cases where only a prima facie case is required.

(Pacific Telephone & Telegraph Co Rate Application, D.44923, (1950) 50 CPUC 247, 248.)

However, it is unclear from the discussion in D.44923 whether the Commission used the words “clear and convincing” in a lay sense only, or whether it was adopting a specific legal standard.

29 Witkin, Calif Evidence, 4 th Edition, Vol 1, 184

30 Witkin, Calif Evidence, 4 th Edition, Vol 1, 187

31 California Administrative Hearing Practice, 2d Edition (2005), 365

Before authorizing a Certificate of Public Convenience and Necessity (CPCN) for the Proposed Project, it is essential to determine if the construction is required for present or future public convenience and necessity, as mandated by § 1001 In making this determination, § 1002(a) requires the consideration of four key factors: community values, recreational and park areas, historical and aesthetic values, and environmental impact The Commission has concluded that § 1002 imposes an obligation, separate from the California Environmental Quality Act (CEQA), to incorporate these environmental influences and community values when evaluating requests.

The Commission has concluded that the assessment of a project's environmental influence is adequately handled through the CEQA process The Sunrise EIR/EIS examines not only environmental impacts but also effects on recreational, park, historic, and aesthetic values due to the terrain traversed by the Proposed Project and its transmission line alternatives This decision reviews the comprehensive record on these issues, which was developed during Phase 2 hearings, specifically in Sections 13, 14, and 15 Additionally, a thorough record on the implications for community values has been compiled by the parties involved.

32 Application of Southern California Edison for CPCN for Kramer Victor Transmission Line,

The Lodi Gas Storage application for CPCN highlights the importance of addressing environmental impacts within the Environmental Impact Report (EIR) to avoid duplicating efforts in the proceedings Public input is a crucial aspect of this review process, which is further examined in Sections 13 to 15 of the record.

Rebuttable Presumption of Economic Need

The Commission's Economic Methodology Decision 34 establishes essential principles and minimum requirements for modeling the economic benefits of proposed transmission lines It creates a rebuttable presumption favoring economic evaluations approved by CAISO's Board of Directors, contingent upon adherence to these principles and procedural safeguards These safeguards ensure public participation by allowing comments on the economic evaluation, which must be thoughtfully considered in the Board's assessment Importantly, the rebuttable presumption is limited to future proceedings, unless the economic analysis complies with the stipulated safeguards and the assigned commissioner explicitly opts to apply it to an ongoing transmission case.

CAISO and SDG&E propose that a rebuttable presumption should be utilized in CAISO's economic assessment of the Proposed Project; however, we disagree with this stance When the Economic Methodology Decision was released, SDG&E's 2005 Application was already under consideration.

The proposed project under application 35 D.06 11 018 has been pending for nearly a year, with CAISO's Board having previously approved its economic evaluation as part of the South Regional Transmission Plan Additionally, the assigned Commissioner for Sunrise did not issue a ruling regarding the rebuttable presumption for either the 2005 or 2006 applications While CAISO acknowledges that no party requested such a ruling, it describes the lack of a ruling as a failure to meet the necessary technical compliance standards.

Economic Methodology Decision 36 We do not agree

The Economic Methodology Decision was established to clarify the evidentiary burden that parties must meet when contesting a CAISO economic analysis during pending proceedings The ruling from the Assigned Commissioner, mandated by this decision, plays a crucial substantive role rather than merely serving as a procedural formality.

During the CPCN review, CAISO did not utilize the economic evaluation previously presented to its Board, opting instead to introduce a new economic analysis developed during Phase 1 and 2 hearings in response to stakeholder feedback Consequently, the economic evaluation approved by the CAISO Board is now deemed irrelevant.

The CAISO Board's approved economic evaluation fails to meet the principles and minimum requirements outlined in the Economic Methodology Decision, as well as the specific procedural safeguards necessary for a rebuttable presumption to be applicable.

SDG&E and CAISO's request for a rebuttable presumption regarding CAISO's subsequent economic evaluation during the CPCN review is not granted for three key reasons First, the Economic Methodology Decision established the framework for evaluating such presumptions, and we find it necessary to adhere to these established guidelines.

To enhance the efficiency of the CPCN process, it is essential to conduct an economic evaluation that incorporates substantial public input at the outset of the proceedings While the economic evaluation developed by CAISO during the Sunrise CPCN review contributes valuable insights, it fails to achieve the intended streamlining effect Additionally, despite its thoroughness, CAISO's evaluation does not adhere to its own Transmission Economic Assessment Methodology (TEAM) or meet the criteria outlined in the Economic Methodology Decision Furthermore, establishing a rebuttable presumption at this stage would be unjust to other parties, as they have already prepared their cases under the assumption that such a presumption does not apply to Sunrise.

A rebuttable presumption is established when the CAISO Board-approved evaluation is submitted to the Commission in a timely manner, ensuring its inclusion in the proceeding's scope.

The 39 TEAM methodology proposed by CAISO aims to quantify the economic benefits of transmission projects It emphasizes five key principles essential for evaluating the economic impact of proposed projects, one of which includes conducting an uncertainty analysis.

Economic Methodology Decision describes CAISO’s TEAM methodology in more detail

It is important to understand the structure of SDG&E’s electric system to understand the potential role Sunrise 40 may play in that system.

SDG&E’s service area covers all of San Diego County and some of

Southern Orange County relies on SDG&E to meet customer demand by utilizing a mix of local generation resources and imported capacity This capacity is delivered from the east and south via the Imperial Valley and San Miguel Substations, as well as from the north through the San Onofre Nuclear facility.

The article explores SDG&E's transmission and generation resources, highlighting future additions to its system It outlines the reliability criteria that define SDG&E's Local Capacity Requirements, detailing how these criteria influence the necessary generation and transmission resources for effective system operation Additionally, it examines the future transmission plans of the Imperial Irrigation District, specifically focusing on the proposed Green Path project.

In this decision, "Sunrise" refers to the Proposed Project and its alternatives, including both transmission and generation options, as defined in the EIR/EIS For clarity in Sections 5 through 14, we adopt the terminology used by parties in the CPCN portion of this proceeding, where "Sunrise" encompasses the Proposed Project along with all Northern and Southern Route Alternatives considered in the EIR/EIS Specifically, in these sections, "Sunrise" excludes the LEAPS Transmission Only Alternative, which is part of the LEAPS Transmission Plus Generation Alternative.

SDG&E’s Transmission Resources

SDG&E's service area features three key high voltage transmission connections: Path 44, which connects to the San Luis Rey and Talega Substations; the Imperial Valley Substation, linking to the Southwest Powerlink and additional lines; and the Miguel Substation, which connects to the Tijuana Substation in Baja, Mexico.

Path 44, running north and south between the SDG&E and Edison service areas, consists of five 230 kV lines, two from SONGS to SDG&E’s Talega

Substation, and three from SONGS to SDG&E’s San Luis Rey Substation The rating for Path 44, which has not been updated since 2001, is 2,500 MW 41

The Imperial Valley Substation connects SDG&E’s system to the Imperial Irrigation District, Baja California in Mexico, and points east SDG&E’s

The Southwest Powerlink transmission line is SDG&E's sole 500 kV line, linking its system to Arizona It stretches from the Miguel Substation in the western part of SDG&E's service area to the Imperial Valley Substation at the eastern edge, ultimately connecting to the Palo Verde transmission hub in Arizona Additionally, transmission lines extend from the Imperial Valley Substation.

• The Imperial Irrigation District system via a 230 kV transmission line that runs north from the Imperial Valley

• The La Rosita Substation in Baja, Mexico via a 230 kV line that runs south from the Imperial Valley Substation; and

• Three gas fired generators totaling 1,070 MW of capacity in

Baja, Mexico The 600 MW Termoelectrica de Mexicali plant is owned by an affiliate of SDG&E; the 160 MW Ciclo Combinado

Mexicali plant and the 310 MW Central La Rosita plant are owned by affiliates of Intergen.

SDG&E also connects to the Comision Federal de Electricidad (Mexican

Electricity Commission) system via a 230 kV transmission line from the Miguel Substation to the Tijuana Substation in Baja, Mexico.

SDG&E’s Generation Resources

Existing generation resources in San Diego’s service area include:

• The Palomar Energy Facility – 541.5 MW 42 connected at 230 kV;

• The Encina Power Plant – 960 MW connected at 138 and

• The South Bay Power Plant – 702 MW connected at 69 and 138 kV;

• A number of combustion turbines, qualifying facilities and small renewable generators totaling 728 MW and connected at lower voltages;

• A 50 MW (nameplate) wind generation facility connected at 69 kV; and

42 Unless otherwise stated, capacities are Net Qualifying Capacity as set forth in

CAISO's Compliance Exhibit establishes the Net Qualifying Capacity (NQC) of generators, which indicates their contribution to meeting peak demand in their respective Local Reliability Areas NQC is defined by CAISO as the capacity of a generator during summer peak load conditions, ensuring accurate assessment of each generator's performance.

Capacity at the generator’s terminal.

• A 4.5 MW contract with the San Diego County Water

Authority for power from the Rancho Peủasquitos Hydro Facility.

Future Generation Additions

The South Bay Power Plant and portions of the Encina Power Plant are expected to retire within the next decade, prompting SDG&E to plan several new generation additions in its service area.

SDG&E has signed Power Purchase Agreements for the following future resource additions to serve its bundled customer load:

• The 561 MW Otay Mesa Generating Project in the southern portion of SDG&E’s service area projected to be online in

• Contracts with the 94 MW Pala Peaker under development by J Power at SDG&E’s Pala Substation and the 44 MW

Margarita Peaker under development by Wellhead Power at

SDG&E’s Margarita Substation, both projected to be online before 2010;

• The 40 MW Lake Hodges Pumped Storage Project projected to be online by 2010;

• The 20 MW Bull Moose Biomass Facility projected to be online by 2010; and

• A 20 MW increase in capacity at the existing Palomar Energy

Facility due to the installation of air inlet coolers by 2010.

SDG&E also has contracts with several demand response suppliers, including:

• An 8 MW contract with Envirepel at Ramona; and

SDG&E has also announced Power Purchase Agreements with projects in the Imperial Valley including:

• A three phase contract for 900 MW of solar thermal generation with Stirling Energy Systems; 44

• One 20 MW contract and another 40 MW contract with

Esmeralda for geothermal generation; and

• Two 49.5 MW contracts with Bethel solar thermal generation.

Three combined cycle generation facilities are proposed for construction within SDG&E's service area, currently at different stages of development, with further details provided in Section 6.7.

• The South Bay Replacement Project 620 MW (nameplate capacity);

• The San Diego Community Power Project (also known as the

ENPEX project) – 750 MW (nameplate capacity); and

SDG&E has a contract for an additional 30 MW with EnerNOC, which was submitted to the Commission for approval through an Advice Letter However, the Commission rejected this Advice Letter, stating that a Certificate of Public Convenience and Necessity (CPCN) review is necessary As of now, SDG&E has not submitted the required CPCN application.

44 SDG&E characterizes the Sterling Solar contract as a 300 MW contract, plus a 300 MW option, plus the equivalent of a 300 MW right of first refusal Tr November 13, 2009 AllParty Meeting, 36.

• The Encina Power Plant Repowering (also known as the

Carlsbad Energy Center) 540 MW (nameplate capacity).

In 2006 and 2007, SDG&E issued Requests for Offers (RFOs) for peaking and baseload resources aimed at becoming operational by 2008 and 2010, respectively These solicitations led to signed contracts for the Pala and Margarita Peakers, which together provide a total of 138 MW Furthermore, SDG&E is reportedly still in negotiations with some bidders from these RFOs, indicating that additional generation resources may be accessible in its service area beyond 2010.

• A 49 MW contract with the Miramar II Peaker, which was submitted to this Commission for approval on June 16, 2008; 45

• A 15 MW diesel fired peaking plant in Borrego Springs; and

• The repowering of the MMC Generation Facility located in

Chula Vista and currently in permitting at the Energy Commission

The repowering would replace an existing 44.5 MW gas fired peaking plant with a nominal 100 MW gas fired peaking plant.

The Commission has authorized the installation of a substantial amount of new solar photovoltaic (PV) capacity in the SDG&E service area, in line with the California Solar Initiative SDG&E and other stakeholders have reported a firm capacity range for this new resource, estimated between 70 MW and 46 MW.

45 A.08 06 017 We do not prejudge the outcome of other pending applications in this decision.

SDG&E is seeking approval from the Commission to construct, own, and operate an additional 35 MW of solar photovoltaic (PV) capacity in its service area, complementing its existing projects of 150 MW or more.

Local Capacity Requirement

SDG&E's Local Capacity Requirement plays a vital role in assessing the necessity of Sunrise and other generation or transmission resources to ensure reliability According to the reliability standards set by the North American Electric Reliability Corporation (NERC), SDG&E is obligated to maintain sufficient local generation resources to reliably meet the demand in its Local Reliability Area 50, particularly after experiencing the loss of the largest generating unit in its service area, followed by the loss of its most essential transmission line.

“G 1/N 1” criteria) The G 1/N 1 criteria determine SDG&E’s “Local Capacity Requirement” since the Local Capacity Requirement is the amount of local generation that SDG&E must have to continue operating reliably after a G 1/N 1 event

Today, the worst G 1/N 1 event for the San Diego area would be the overlapping outage of the SDG&E owned Palomar power plant (G 1) plus loss of

The SDG&E Local Reliability Area coincides with SDG&E’s service area, specifically including the Imperial Valley – Miguel 500 kV segment of the Southwest Powerlink A G 1/N 1 event will occur when a generator with a capacity exceeding that of Palomar, such as Otay Mesa, is added to the SDG&E Local Reliability Area or when a new transmission line connects to this area.

The reliability of the Local Capacity Requirement is crucial, as the loss of the Reliability Area line leads to a more significant decrease in import capacity compared to the loss of the Imperial Valley – Miguel segment of the Southwest Powerlink Furthermore, CAISO regularly reassesses the Local Capacity Requirement, which can be adjusted based on various factors such as shifts in the regional transmission grid and fluctuations in the generation capacity available in SDG&E’s Local Reliability Area.

Upgrades Planned for Neighboring Transmission Systems

Imperial Irrigation District Transmission Upgrades

The Imperial Irrigation District is actively working on multiple transmission projects designed to enhance the Southern Route Alternative 52 to Sunrise and facilitate the delivery of both renewable and non-renewable energy from the Imperial Valley to CAISO customers Alongside the Green Path project, these initiatives aim to improve energy transmission infrastructure and support California's energy needs.

• The Coachella Valley Devers 2 project, which will carry up to

1,600 MW via either a double circuit 230 kV or single circuit 500 kV line

52 We describe the Southern Route Alternatives in Section 15.7. from the Imperial Irrigation District’s Coachella Valley Substation to the proposed Devers 2 Substation, thus connecting to the Los Angeles

Department of Water and Power and CAISO control areas; 53

• The new 230 kV Midway Bannister line which will allow

1,200 MW of renewable energy to flow from Imperial Irrigation District to Edison or SDG&E; 54

• The new 230 kV Dixieland Imperial Valley line, which will increase export capability from the Imperial Irrigation District to

• A re rating of and upgrades to Path 42, which interconnects the Imperial Irrigation District and Edison systems Imperial Irrigation

The District is raising the rating of Path 42 from 600 MW to 800 MW to enhance resource flow to the CAISO grid via Edison’s system, with no transmission upgrades needed for this change Furthermore, CAISO anticipates additional upgrades on Path 42 that will boost its transfer capability to 1,200 MW.

The Imperial Irrigation District is set to enhance its infrastructure by extending its system eastward to connect with the Arizona Public Service grid and the Southwest Powerlink through the Highline Knob North Gila transmission line project.

53 Imperial Irrigation District Exhibit ID 3, 8

54 Imperial Irrigation District Exhibit ID 3, 4 5.

55 Imperial Irrigation District Exhibit ID 3, 4 6.

56 Imperial Irrigation District Phase 2 Opening Brief, 21

57 The Compliance Exhibit makes this assumption.

Green Path

Green Path is a very large transmission project sponsored by the Los

The 59 Green Path project aims to connect the Imperial Irrigation District grid with the California Independent System Operator (CAISO) and the Los Angeles Department of Water and Power grids This interconnection will facilitate the transmission of renewable energy from Imperial Valley to major load centers in Southern California, enhancing the region's access to sustainable energy sources.

Green Path comprises two primary transmission components, with the southern segment known as Green Path South This segment establishes a transmission route linking the Imperial Irrigation District’s current infrastructure in Coachella Valley.

The Green Path South project will connect to Edison’s existing Devers Substation and will pass through the proposed Indian Hills Substation by the Imperial Irrigation District, as well as Edison’s planned Devers 2 Substation Notably, Green Path South will not directly interconnect with the SDG&E system The northern component of the Green Path project will proceed onward from this point.

61 The southern component of Green Path consists of: (1) a new 500 kV Devers 2

The project involves the construction of a new substation and the installation of one or two one-mile 500 kV transmission lines that will link the new Devers 2 Substation to the existing Devers Substation, serving as the interconnection point between Green Path and the CAISO grid Additionally, a new 30-mile 500 kV line will be established to enhance the transmission capacity and efficiency of the energy grid.

230 kV transmission line from a new Imperial Irrigation District Indian Hills Substation to the new Devers 2 Substation; and (4) a new 230 kV line from the new Imperial

Irrigation District Indian Hills Substation to its existing Coachella Valley Substation north and then west from the new Devers 2 Substation, up to Los Angeles

Department of Water and Power’s service area 62

CAISO assumes that Green Path, in conjunction with the proposed

The Talega/Escondido – Valley/Serrano transmission line (TE/VS) will enable the delivery of up to 2,000 MW of renewable energy resources from the Imperial Valley and surrounding areas into the CAISO system.

Modeling Assumptions for the Analytical Baseline

Before issuing a Certificate of Public Convenience and Necessity (CPCN) for Sunrise, it is essential to determine its necessity in accordance with § 1001 SDG&E asserts that the Sunrise project is vital for delivering significant benefits to its ratepayers.

• Access to low cost out of state power;

• Access to low cost renewable resources.

The three benefits align with the Basic Project Objectives established for our environmental analysis of Sunrise Much of the CPCN aspect of this process has focused on quantifying these three key benefits.

62 The northern component of Green Path consists of: (1) a new 500 kV Hesperia

Substation; (2) a new, 85 mile, 500 kV transmission line from the Devers 2 Substation to the Hesperia Substation; and (3) a new 5 mile 287 kV tap line from the Hesperia

Substation to the existing Victorville – Century line, which would create a Century – Hesperia 287 kV line The Hesperia – Victorville portion, approximately 17 miles long, would be upgraded to 500 kV.

63 TE/VS is described in more detail in note Error: Reference source not found, below, and in the text accompanying that note.

64 CAISO Phase 1 Opening Brief, 30. benefits to determine whether the Proposed Project can meet these goals more economically than other alternatives

We model SDG&E’s three benefits as follows:

• Access to low cost out of state power = energy benefits generated by energy cost savings;

• Enhanced reliability = reliability benefits generated by reducing Local Capacity Requirements; and

• Access to low cost renewable resources = potential savings from accessing least cost renewable resource areas 65

The assumptions used in modeling greatly influence the projected benefits of these models A notable instance is a typographical error made by SDG&E concerning future gas prices, which led to inaccurate estimates of energy benefits.

$468 million per year – nearly five times its previous estimates, and more than twice the next highest estimate SDG&E used in this proceeding 66

The ongoing debates surrounding modeling have centered on the foundational assumptions, known as the Analytical Baseline, that inform these models Section 6 delves into the disputes regarding these Analytical Baselines and outlines the assumptions we utilize to assess the energy benefits, reliability advantages, and potential savings derived from utilizing the most cost-effective renewable resources across the different Sunrise alternatives.

65 There are a number of qualitative benefits that cannot be quantified at all, and we address those benefits in Section 9.3.4, below.

66 See discussion in Section 8.3, below.

Section 7 explains what the Analytical Baseline assumptions tell us about the reliability need or “shortfalls” predicted for SDG&E’s service area, when they will be, and how large they will be 67

Following the discussion of reliability need in Section 7, we address the parties’ efforts to model energy benefits (Section 8), reliability benefits

In Section 9, we explore potential savings from utilizing least-cost renewable resources for the Sunrise alternatives Section 10 outlines the projected net benefits associated with these alternatives, which are determined by combining energy benefits, reliability improvements, and savings from renewable resources, while deducting the anticipated project costs Section 11 summarizes our conclusions regarding the key areas of contention within these assessments.

After considering the net benefits, we examine in Section 11.3 the net benefit results from CAISO’s Compliance Exhibit modeling performed by

At the conclusion of the proceedings, CAISO utilized several of our Analytical Baseline assumptions to update the Compliance Exhibit, estimating the net benefits of the Proposed Project and its alternatives This update allows us to summarize our findings regarding the advantages of various transmission and generation alternatives, ultimately reinforcing the necessity for the Sunrise project.

The baseline assumptions for resource development are grounded in reasonably foreseeable future events However, it is essential to recognize that actual resource development will follow relevant statutes and policies, meaning the model does not prescribe a specific outcome Consequently, the development of resources will have a considerable effect on future reliability shortfalls.

Summary of Adopted Analytical Baseline Assumptions

We utilize CAISO's modeling framework to assess energy and reliability advantages, as well as potential savings from utilizing the most cost-effective renewable resources However, we diverge from CAISO's final Phase 2 modeling assumptions in several key aspects.

• We rely on the Energy Commission staff’s November 2007

Forecast of 1 in 10 peak demand (Section 6.2), including its embedded assumptions for the California Solar Initiative (Section 6.3), energy efficiency (Section 6.4), and other distributed generation (Section 6.5);

• We adjust the November 2007 Forecast by including the demand response savings we have approved in SDG&E’s most recent

Long Term Procurement Plan (Section 6.6);

• We 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 (Section 6.7.1);

• We assume 540 MW from the Carlsbad Energy Center will come online in the summer of 2013, resulting in a net increase of 222

We estimate that only 25% of the new coal-fired generation listed in the SSG WI database will become operational, and that gas-fired combined cycle resources will be utilized to substitute for the canceled coal plants.

• We assume that at least 50% of the out of state renewables identified by CAISO for its renewable savings modeling will be available to California (Section 6.11);

68 Table B 1 in Appendix B sets forth all of the assumptions modeled in the CAISO Compliance Exhibit

• We adopt CAISO’s initial renewable cost estimates

• We assume the implementation of UCAN’s Miguel Import

• We 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 (Section 6.14.5);

• We assume Rancho Peủasquitos’ proposed Coastal Link

• We assume SDG&E’s estimated capital costs for all of the

Sunrise alternatives, and SDG&E’s 58 year amortization period for the

The assumptions outlined, along with CAISO's additional modeling criteria, establish our Analytical Baseline for evaluating the energy and reliability benefits, as well as the potential savings from utilizing the most cost-effective renewable resources across all Sunrise alternatives.

Assumptions Regarding the Proper Peak Demand Forecast

Parties’ Positions

Various stakeholders have suggested different methods for establishing the peak demand forecast to be used in the Analytical Baseline Notably, parties such as SDG&E, UCAN, and DRA have initiated their proposals based on specific iterations of the Energy.

The Energy Commission's 1 in 10 peak demand forecast, initially presented in the 2006 Integrated Energy Policy Report, has undergone several updates throughout the proceeding Various stakeholders have adjusted their peak demand forecasts in alignment with these changes The forecasts from 2006 and subsequent years account for anticipated savings from energy efficiency and distributed generation initiatives, such as the California Solar Initiative However, they do not incorporate projected savings from demand response measures, including those expected from the implementation of advanced metering infrastructure (AMI).

SDG&E originally relied upon the 2006 Forecast 70 SDG&E amended its Analytical Baseline in Phase 1 to address, in part, the Energy Commission staff’s May 2007 update 71

In May 2007, CAISO initiated its planning process based on forecasts from the Energy Commission staff; however, it opted not to utilize their projections for peak demand in subsequent years Instead, CAISO relied on a more conservative estimate, specifically the 1 in 10 peak demand forecast.

In generating the peak demand forecast for future years, CAISO initially based its calculations on a 1.7% annual escalation rate, reflecting the historic growth in peak demand from 2006 to 2008 However, this rate was not the long-term figure utilized in the May or November 2007 forecasts Throughout the proceeding, CAISO relied solely on its own future forecasts without making any adjustments to its escalation rates.

72 CAISO Phase 1 Opening Brief, 21, referring to Energy Commission, “Staff Forecast of 2008 Peak Demand,” report Energy Commission 200 2007 006, May 2007.

The California Energy Commission's November 2007 Forecast assessed the impact of adjusting escalation rates, concluding that the changes were not significant Although CAISO mentioned this evaluation in its Phase 2 Opening Brief, it failed to present the evaluation as evidence, and it is not included in the official record of the proceeding.

UCAN initiated its efforts with the 2006 Forecast, subsequently adjusting its projections for demand-side reductions based on more recent updates By the conclusion of Phase 1, UCAN advised the implementation of the Energy.

Commission staff’s October 2007 forecast, with adjustments to supply discussed below 77

In Phase 2, all of the parties except CAISO used the November 2007

Forecast as the basis of their peak demand forecasts in their Analytical Baselines

As stated above, CAISO continued to rely upon its initial demand forecast throughout the proceeding.

Discussion

The Scoping Memo ordered parties to use, to the degree possible, “the most recent Commission adopted assumptions, goals, policies and levels of

75 CAISO Phase 2 Opening Brief, 10; RT 5418.

77 UCAN Motion Requesting the Commission Take Official Notice of Regulatory Filings,November 9, 2007. effort in its base case forecasts of loads and resources.” The Economic

Methodology Decision sets forth this requirement also 79 The Commission’s

December 2007 decision in the Long Term Procurement Plan proceeding (LTPP

Decision) uses the Energy Commission’s November 2007 Forecast 80 While the

The LTPP Decision utilizes a 1 in 2 peak demand forecast to guide procurement authorization, while the November 2007 Forecast additionally provides a 1 in 10 peak demand forecast To ensure alignment with the LTPP Decision, we will adopt the November 2007 Forecast's 1 in 10 peak demand.

California Solar Initiative Adjustments to the Peak Demand Forecast

Parties’ Positions

In Phase 1, SDG&E’s projected load reduction associated with the

The California Solar Initiative saw a significant growth in capacity, rising from 2 MW in 2008 to 150 MW by 2015, aligning with SDG&E's 2006 Long Term Procurement Plan SDG&E highlighted its expectations for solar PV penetration rates and noted that these systems are projected to generate at 50% of their installed capacity during peak hours, emphasizing the reliability of solar energy during high-demand periods.

81 SDG&E Compliance Filing in R.06 02 013, “2007 2016 Long Term Procurement Plan,” (December 11, 2006). aggressive.” In Phase 2, SDG&E lowered its projections, consistent with the November 2007 Forecast, to 13 MW in 2010 and 30 MW by 2015 83

CAISO assumes California Solar Initiative impacts consistent with

UCAN asserts that SDG&E halted the expansion of the program's impacts post-2015, suggesting that the utility could have added an extra 60 MW of solar PV capacity by 2017.

In Phase 2, Powers Engineering introduced a solar-centric alternative to the Sunrise project, detailed in the "San Diego Smart Energy 2020 – The 21st Century Alternative" report This initiative, known as the "San Diego Solar Initiative," aims to install 2,040 MW of rooftop solar PV, prioritizing large commercial systems, alongside battery storage to maximize capacity usage during peak demand The proposal seeks to secure $1.5 billion through ratepayer-funded incentive programs, positioning solar PV and other renewable distributed generation as key components of San Diego's energy future.

86 Powers Engineering Exhibit Powers 1, Attachment B, 3.

Powers Engineering is introducing a scaled-down Solar Initiative, aiming for 920 MW of solar PV capacity at an estimated cost of $700 million This initiative is projected to meet half of the energy demand for San Diego County in 2020.

SDG&E has expressed opposition to the Powers Engineering proposal, citing that none of the thousands of megawatts mentioned are currently under construction, sited, or proposed by developers Additionally, SDG&E raises concerns about the validity of Powers Engineering's claims regarding cost effectiveness, cost assumptions, program penetration, and the technical feasibility of the proposed battery backup systems intended to address the utility's peak demand.

Discussion

The November 2007 Forecast revises peak demand estimates based on the California Solar Initiative's impact, which differs notably from initial assumptions by SDG&E and other stakeholders Initially, it was anticipated that the initiative would decrease peak demand by about 150 MW by 2015, highlighting the significant variance in expectations among the parties involved in the proceedings.

2007 Forecast assumes that it will reduce peak demand in 2015 by only 30 MW 92

SDG&E argues that the Phase 2 California Solar Initiative capacity should be increased to a minimum of 70 MW, significantly higher than the 33 MW projected in the November 2007 Forecast for 2016.

Commission has allocated California Solar Initiative funds such that SDG&E will

In alignment with the LTPP Decision, we accept the November 2007 Forecast determinations for the Analytical Baseline Nonetheless, we will re-examine the significance of the California Solar Initiative and its effects on the necessity for Sunrise in Section 11.3 below.

Energy Efficiency Adjustments to the Peak Demand Forecast

Parties’ Positions

The Energy Commission's forecasts for 2006 and 2007 include energy efficiency assessments; however, UCAN argues that these forecasts do not encompass all possible energy efficiency improvements To address this, UCAN proposes several modifications to the 2006 and 2007 forecasts, citing more recent Energy Commission projections that indicate greater energy efficiency impacts within SDG&E’s territory Specifically, UCAN recommends revising the November 2007 forecast to account for post-2008 energy efficiency impacts of 0 MW in 2009 and 26 MW in 2010.

115 MW in 2016 94 UCAN also points to approximately 102 MW of additional receive enough funding to acquire 180.3 MW (nameplate) See D.06 12 033,

Appendix B, Table 11 SDG&E claims that the firm peak delivery from those solar

PV units will be 39% of nameplate See SDG&E Exhibit SD 27, 6, e.g., 180.3 MW * 39% 70 MW This is significantly greater than 33 MW See SDG&E Phase 1 Opening Brief, 47 48

93 UCAN Phase 1 Opening Brief, 43; see also UCAN Phase 2 Opening Brief, 60 61.

94 UCAN Phase 2 Opening Brief, 60. energy efficiency attributable to new building standards that will materialize over a 10 year period, at about 10 MW a year 95

Powers Engineering suggests a 20% reduction in SDG&E's projected energy usage from a 2003 baseline through enhanced energy efficiency measures However, SDG&E disputes this recommendation, arguing that Powers Engineering has not proposed any additional energy efficiency measures beyond those already considered by SDG&E and the Energy Commission Furthermore, SDG&E questions the cost-effectiveness of the specific measure identified by Powers Engineering, which is the installation of high-efficiency air conditioners, due to concerns about the mixing of incremental and replacement costs.

Discussion

We reject the proposed changes to energy efficiency assumptions by UCAN and Powers Engineering Instead, we will maintain consistency by adopting the methodology utilized in the LTPP Decision, which relies on the energy efficiency levels already integrated into the November 2007 Forecast.

Distributed Generation Adjustments to the Peak Demand Forecast

Parties’ Positions

The 2006 and 2007 Energy Commission forecasts incorporate projected distributed generation, yet UCAN highlights SDG&E's "Utility of the Future" proposal, which claims the potential for an additional 48,159 MW of distributed generation Furthermore, Powers Engineering estimates that combined heat and power sources could contribute an extra 700 MW of "clean" distributed generation.

Discussion

The November 2007 Forecast incorporates adjustments for the impact of distributed generation, and we acknowledge these adjustments to align with the LTPP Decision, which also references the November 2007 Forecast.

Demand Response Adjustments to the Peak Demand Forecast

Parties’ Positions

The 2006 and 2007 Energy Commission forecasts do not take into account projected impacts of demand response, including those expected from the

101 Powers Engineering Exhibit Powers 2, 5 This combined heat and power generation is proposed to replace the in area combined cycle plant in the All Source Generation Alternative discussed in Section 15.4.

The installation of Advanced Metering Infrastructure (AMI) was a key focus of Decision 102 LTPP, prompting parties to assess its impacts throughout the proceedings Throughout the discussions, positions on the relevant issues evolved repeatedly, leading to ongoing debates regarding the inclusion of demand response in the final Analytical Baseline until the conclusion of the record development.

SDG&E and CAISO initially did not incorporate demand response in their Analytical Baselines However, they later reached an agreement to include demand response measures to fulfill Local Capacity Requirements and revise the peak demand forecast Consequently, SDG&E modified its Analytical Baseline to reflect an inclusion of 29 MW of demand response, while CAISO also updated its baseline accordingly.

59 MW of demand response, which consisted of three contracts: Celerity

The DRA and UCAN have proposed that the Analytical Baseline should encompass CAISO's projected demand response along with an additional 30 MW contract with EnerNOC, which has been signed by SDG&E However, both SDG&E and CAISO noted that the Commission did not approve this contract when it was initially submitted by SDG&E as an Advice Letter.

Demand response enables electric customers to decrease or shift their electricity consumption during specific time frames in response to price signals, financial incentives, environmental conditions, or reliability alerts The Commission has determined that the implementation of Advanced Metering Infrastructure (AMI) will enhance the effectiveness of demand response initiatives.

104 See SDG&E Exhibit SD 5, Vol 2, Part 1, Chap 2, page II 29; CAISO Exhibit I 1,

The Commission did not evaluate the merits of the contract but instead deemed the Advice Letter an inappropriate method for contract review It encouraged SDG&E to submit an application for Certificate of Public Convenience and Necessity (CPCN) review, which has not yet been filed.

UCAN maintains that SDG&E's Analytical Baseline fails to accurately reflect committed demand response savings Specifically, aside from the 30 MW EnerNOC contract initiated in 2008, UCAN claims there is an additional 4 MW of demand response savings that have been overlooked since 2010.

Determining the demand response related to Advanced Metering Infrastructure (AMI) for the Analytical Baseline has proven challenging SDG&E initially relied on estimates from its AMI application approved by the Commission, a stance also taken by the DRA However, CAISO asserts it has factored in the effects of SDG&E's AMI program, reporting values that were 72 MW lower in 2010 and approximately 26 MW lower from 2011 to 2020 compared to SDG&E's figures.

In its analysis, UCAN claims that SDG&E's Advanced Metering Infrastructure (AMI) estimates should be adjusted to include an additional 77 MW for 2010 and 96 MW for 2020, asserting that these figures were part of SDG&E's Test Year 2008 General Rate Case However, SDG&E contests UCAN's proposal, indicating that it does not align with their assessment.

109 UCAN Phase 1 Opening Brief, 44 45. unreasonable since our final decision in that proceeding adopts a lower number 110

Later in Phase 1, SDG&E reduced its AMI estimates to 82 MW in 2010 and

232 MW in 2020, claiming that the Commission settlement in its General Rate Case will result in lower AMI savings than SDG&E projected 111

Powers Engineering advises a reduction of electric demand by 1,136 MW compared to the 2007 peak demand, primarily through demand response initiatives, including Advanced Metering Infrastructure (AMI) They estimate that demand response can account for 231 MW of peak demand; however, it remains unclear whether this figure is additional to or overlaps with SDG&E’s reported 279 MW.

Discussion

The parties involved have contrasting views on future demand response projections, particularly concerning the effects of Advanced Metering Infrastructure (AMI) SDG&E's assumptions about demand response levels in this proceeding do not align with the actual performance of its current demand response programs To maintain consistency with prior determinations, it is essential to reassess these assumptions.

110 SDG&E Phase 1 Reply Brief, 12 UCAN Exhibit U 66 is SDG&E’s testimony in its

In the 2008 Phase 2 General Rate Case (A.07 01 047), the projections for Advanced Metering Infrastructure (AMI) ultimately accepted in decision D.08 02 034 were found to be lower than those presented in UCAN Exhibit U 66 This discrepancy indicates reduced anticipated impacts of AMI For further details, refer to the Motion for Adoption of All Party and All Issue Settlement, A.07 01 047.

111 SDG&E Phase 1 Opening Brief, 50 51, referring to D.07 04 043.

112 Powers Engineering Exhibit Powers 1, Attachment B, 3.

In accordance with the Long Term Procurement Plan proceeding, we endorse the demand response savings outlined in SDG&E’s latest Long Term Procurement Plan, which incorporates Advanced Metering Infrastructure (AMI) and other price-sensitive demand response strategies Additionally, Table B2 in Appendix B details the approved demand response impacts from SDG&E in relation to the November 2007 Forecast.

Assumptions Regarding In­Area Fossil Resources

The Existing South Bay Power Plant

The South Bay Power Plant, a 702 MW combined cycle facility situated in Chula Vista, is facing uncertainty regarding its retirement date, with 123 parties holding differing opinions Certain units of the plant are bound by Reliability Must Run (Must Run) contracts with the California Independent System Operator (CAISO), preventing their retirement until CAISO officially releases them from these obligations.

The South Bay Replacement Project would replace the existing plant with a

620 MW facility located on a much smaller portion of the same site Chula Vista

123 The South Bay Power Plant consists of five units: four dual fuel steam units

The South Bay Power Plant, consisting of five units installed between 1960 and 1971, includes four units (Units 1-4) and one combustion turbine (Unit 5) However, officials are against replacing the plant at its current location due to interest in developing the surrounding bay property As a result, LS Power, the developer of the replacement project, has withdrawn its application to the Energy Commission.

The certification for the repower project faced significant opposition and was hindered by the inability to secure a Power Purchase Agreement from SDG&E Consequently, the timeline for resuming development efforts remains uncertain.

SDG&E and CAISO assume in Phase 1 that the existing South Bay Power Plant will retire before 2010 DRA disagrees, but does not offer an alternative date for its retirement

The South Bay Power Plant will not retire until three conditions are met: the expiration of the lease on November 1, 2009, the retirement of specific bonds, and the California Independent System Operator (CAISO) terminating the plant's Must Run status South Bay emphasizes that the critical factor for retirement is CAISO's decision regarding this status Due to the plant's significant size and its strategic position within the San Diego load pocket, South Bay argues that additional resources must be in place before CAISO would consider terminating the Must Run status Therefore, it is unlikely that the existing South Bay Power Plant will retire before the necessary replacement resources are operational.

124 South Bay Phase 1 Opening Brief, 19. and thus CAISO and SDG&E assumptions of a retirement before 2010 are unrealistic

CAISO's stance on when it will lift the Must Run status of the South Bay Power Plant has evolved during the proceedings, but it has consistently maintained that the plant cannot be retired until it is officially released from these obligations.

CAISO initially suggested that the South Bay Power Plant could retire with the operation of Sunrise However, a letter from CAISO to Chula Vista clarified that at least two out of three facilities—Otay Mesa Generating Facility, Pala and Margarita Peakers, or Sunrise—must be operational before the South Bay Power Plant can retire.

CAISO has outlined new conditions for the retirement of the South Bay Power Plant, emphasizing the necessity of ocean-cooled power plants for maintaining reliability and integrating renewable resources The study suggests that the South Bay Power Plant cannot retire until an additional 900 MW of power is generated from projects like the Stirling Solar Project in the Imperial Valley.

CAISO also states that it will be “critically important” to maintain existing generating capacity to accommodate renewable resources that will come under the state’s RPS program 128

The South Bay Power Plant, despite its age, plays a crucial role in meeting SDG&E’s reliability needs However, concerns about the viability of the plant as a long-term resource arise due to the age of its units and replacement costs, with no engineering evidence supporting its extended operation In the short term, SDG&E and CAISO plan to depend on the existing plant if the Sunrise project is not operational by 2010 and local generation alternatives are insufficient SDG&E acknowledges that maintaining the current South Bay Power Plant is likely the best option if there are delays with Sunrise Therefore, it is anticipated that some units of the plant will remain operational until Sunrise is online or sufficient new generation capacity is established For our Analytical Baseline, we project that the South Bay Power Plant will retire by December 31, 2012, or at the end of the year when Sunrise begins operations, whichever comes first.

130 RT 1764; see also SDG&E Exhibit SD 26, 56. continuing to operate South Bay, with its continued reliance on its once through cooling system, runs counter to several state environmental policy objectives.

Peakers 58 1.Parties’ Positions

CAISO, UCAN, and DRA anticipate that the Pala and Margarita Peakers, part of SDG&E’s 2006 solicitation, will be operational by 2010 Additionally, UCAN suggests incorporating an extra 46 MW of peaking capacity into the energy plan.

After 2010, the analytical baseline highlights three potential power plants expected to come online before 2012 This includes a 49 MW expansion of the MMC Power Plant in Chula Vista, currently in the permitting phase with the Energy Commission Additionally, SDG&E is negotiating two other peaker projects, the Miramar II project and a new peaker in Borrego Springs, as part of its 2006 and 2007 RFOs Furthermore, UCAN asserts that several other peaker projects are also in development.

SDG&E’s service area For example, UCAN identifies 330 MW of new

On September 20, 2008, CAISO announced the removal of the Lake Hodges, Otay Mesa, and Pala and Margarita Peakers projects from the 2009 Local Capacity Requirements study due to developers indicating that their service dates would extend beyond summer 2009 Despite this, the report does not suggest that these projects will not be operational before the end of 2010, although it is important to note that this report is not part of the official record for the proceeding.

The new MMC project is set to replace a 45 MW peaking plant with a more powerful facility boasting a nominal capacity of 100 MW, located at the same site This upgrade includes combustion turbine capacity that aims to interconnect with SDG&E’s Otay Mesa Substation For more information, visit the California Energy Commission's site.

Including the Pala and Margarita Peakers in the Analytical Baseline prior to 2011 is a reasonable decision, and we acknowledge that the CAISO has made this adjustment Even if these projects face delays, there remains sufficient time to build these plants or their replacements.

We find it more reasonable to consider other potential future peaker capacity as an alternative to Sunrise, rather than as part of the Analytical

Baseline, since SDG&E theoretically could avoid the need for additional peakers if Sunrise were constructed Thus, we do not include UCAN’s other additional peaker capacity in the Analytical Baseline.

Other Fossil Resources

The 561 MW Otay Mesa Generating Project, located in the southern region of SDG&E’s service area, is unanimously recognized as a key component of the Analytical Baseline This project has a signed Power Purchase Agreement with SDG&E, is currently under construction, and is anticipated to commence operations before 2011.

133 See UCAN Phase 2 Opening Brief, 58.

UCAN anticipates that more than 800 MW of new fossil-fired power plants will be developed in SDG&E's service area by 2016, highlighting several potential resources beyond the previously mentioned peaker plants.

• 222 MW of new net capacity in 2011 or 2012 from the Carlsbad

Energy Center, currently in permitting at the Energy Commission;

• 565 MW from a new combined cycle plant interconnected in the Escondido area; and

• The planned addition of air inlet coolers at Palomar

Cabrillo, the operator of the Encina Power Plant and developer of the Carlsbad Energy Center, has submitted an Application for Certification to replace a portion of the existing facility.

Energy Commission 135 and expects it to be acted on by the end of 2008 The existing plant has a nominal rated capacity of 965 MW The new Carlsbad

Energy Center would replace the existing steam boilers at Encina Units 1 3

(318 MW) with a more efficient 540 MW combined cycle power plant 136 The repowering would result in a 222 MW net increase in capacity at the Encina site

DRA asserts that it is unrealistic to assume that other existing in area generation, in particular the Encina Power Plant, will remain in operation until

2020 137 DRA notes that additional generation could be developed pursuant to

137 DRA Phase 1 Opening Brief, 17 19. offers currently pending before SDG&E in its 2007 request for offers (RFO), but it offers no assumptions to include in our Analytical Baseline 138

The updated Analytical Baseline from CAISO incorporates the 561 MW Otay Mesa Generating Project and 20 MW from the Palomar air inlet coolers We believe it is reasonable to assume that both projects will be operational before 2011 for our Analytical Baseline assessment.

Given the numerous proposals for conventional fossil generation facilities within SDG&E's service area, and the advanced status of at least one proposal, it is reasonable to anticipate that at least one additional combined cycle unit will be operational in the coming years, alongside the Otay Mesa Generating Project Furthermore, we concur with UCAN that the Carlsbad Energy Center, currently in the permitting phase at the Energy Commission, has a strong likelihood of becoming operational soon.

2012 or 2013 For that reason, we assume a net increase of 222 MW before

Summer 2013 as a result of including the Carlsbad Energy Center in the

Assumptions Regarding Out­of­State Generation – Including Coal Plant Construction

Parties’ Positions

Parties disagree significantly over the availability and type of low cost power to assume in WECC Specifically, many parties believe that SDG&E and

The 139 WECC is the interconnected transmission region where California's investor-owned utilities function, encompassing western states, Baja California, and parts of Canada The addition of a transmission line to the WECC grid will influence the dispatch of generation resources across the region, prompting an examination of Sunrise's effect on this dispatch.

140 AB 32 ( Stats 2006, c 598), codified at Health & Saf Code § 38500 et seq.

142 Energy Action Plan 1, May 8, 2003, 4; Energy Action Plan II, September 21, 2005, 2.

CAISO overestimate the amount of new generation that will be constructed in WECC 143

SDG&E and CAISO analyzed energy dispatch behavior across WECC using SSG WI data on transmission, loads, and generation forecasts Notably, SDG&E made significant modifications to the SSG WI data, particularly by replacing 1,300 MW of peaker plants expected to be operational near the Palo Verde Substation with combined cycle facilities This change is projected to produce more cost-effective power compared to the peaker plants they supplanted.

CAISO based its CAISO South Regional Transmission Plan 146 report for the Board's approval of Sunrise on modifications made by SDG&E to the SSG WI database However, after conducting a comprehensive review of its input assumptions for the plan, CAISO decided to discard the majority of SDG&E's alterations to the SSG WI.

143 These parties argue that this overstatement results in an overstatement of the energy benefits the Sunrise transmission alternatives will generate by displacing in state generation with low cost imports

The 144 SSG WI initiative was a collaborative volunteer effort by WECC participants aimed at enhancing transmission planning across the western interconnect Members of SSG WI created a comprehensive database that cataloged current and future loads, generation, and transmission resources within WECC This valuable database has since been handed over to WECC, where it is now maintained and updated by the Transmission Expansion Planning and Policy Committee (TEPPC).

146 2006 Application, Volume 2 Part 2, Appendix I 1, 63, Table 6.16. data, including the replacement of the Palo Verde peakers with combined cycle facilities 147

SDG&E's modified SSG WI database indicates that by 2015, Arizona and New Mexico are expected to add 6,988 MW of thermal capacity, primarily from coal, oil, gas, and nuclear sources, with 3,697 MW (over 57%) being coal CAISO forecasts a similar trend, projecting 6,532 MW of thermal capacity additions, including 3,308 MW from coal Collectively, both SDG&E and CAISO predict over 12,000 MW of new coal plants in the WECC region by 2015, with significant contributions from the Rockies (approximately 7,500 MW), Nevada (700 MW), and the Pacific Northwest (500 MW) This influx of coal-fired generation is anticipated to lower regional spot prices, potentially benefiting SDG&E and other California load-serving entities.

UCAN argues that SDG&E is planning significant overbuilding of coal and natural gas plants in Arizona and other locations, which Sunrise would allegedly bring into California.

400 MW of the 3,697 MW of coal plants included by SDG&E in Arizona and New Mexico (less than 11%) have been justified 150 UCAN argues that using Sunrise

150 UCAN Phase 1 Opening Brief, 197 198. to facilitate the delivery of coal fired resources to California conflicts with

Commission policy discouraging reliance upon such fuels 151

SDG&E clarifies that California law prohibits load serving entities from entering new long-term contracts for energy from high greenhouse gas (GHG) emitting sources, like coal-fired generation However, the law allows these entities to reduce their commodity costs by capitalizing on lower spot market energy prices.

UCAN argues that SDG&E's assumption of building combined cycle plants near the Palo Verde Substation, which have yet to be proposed, unjustifiably inflates the forecast of low-cost generation from Arizona to California via Sunrise.

DRA criticizes SDG&E for relying on an "unsupportable WECC capacity expansion plan" in its modeling, which includes projections for 12,000 MW of new coal plant capacity They question the reliability of the SSG WI database used by SDG&E and argue that the utility should have validated the database's resource expansion assumptions through a review of existing studies, discussions with the analysts who created the database, and an assessment of the results' reasonableness.

SDG&E states that it conducted such reviews and discussions, and checked the reasonableness of its results 155

DRA contends that the SSG WI database relies on unrealistic future planning margins, asserting that its developers mistakenly believe a 29% aggregate planning margin indicates an overestimation of generation capacity They argue that such excessive generation would not be supported or financed by the market.

SDG&E conducted a thorough review of the current WECC database, which relies on SSG WI data, and found that the planning reserve margin for 2015 is approximately 23%, rather than the claimed 29% They argue that this figure is further inflated due to potential transmission constraints, rainfall variability, and weather conditions impacting solar and wind resource output Ultimately, SDG&E suggests that a more accurate calculation yields a planning reserve margin of around 20% for 2015.

South Bay, like UCAN and DRA, is highly critical of SDG&E’s and

CAISO’s assumed resource additions in WECC South Bay assumes that only

400 MW of the 5,945 MW of new thermal generation expected to be built in

156 DRA Exhibit D 56, 6; see also CAISO Exhibit I 7, 35.

By 2015, Arizona and New Mexico are projected to rely heavily on coal, with South Bay highlighting that excessive generation assumptions can depress imported power prices, thereby enhancing the benefits of the Sunrise project South Bay critiques the 2005 SSG WI database for forecasting an unrealistic 17,000 MW of new generation capacity expected to come online between 2006 and 2015, citing issues such as non-operational plants and market heat rates falling below 6,000 Btu per kWh This assessment is supported by both DRA and UCAN, who agree that the anomalies produced by the SSG WI database indicate significant flaws in its future generation assumptions.

South Bay critiques the assumptions made by SDG&E and CAISO regarding new coal-fired generation in the Southwest, highlighting four key flaws Firstly, they argue that the rising concerns over global warming reduce the likelihood of constructing new conventional coal plants Secondly, South Bay contends that any new coal generation in the Southwest is unlikely to meet California's energy demands.

160 South Bay Phase 1 Opening Brief, 20.

The opening brief for 161 South Bay Phase 1 highlights that South Bay's witness consistently monitors and predicts planned resource additions across the Western region His testimony is grounded in these regular assessments, rather than a specific study conducted for this case.

162 DRA Exhibit D 56, 6 8; see also, UCAN Exhibit U 1, 6; UCAN Exhibit U 4, 120.

South Bay indicates that the substantial planning reserve margin in the SSG WI assumptions may not justify investments in coal Additionally, it emphasizes that the anticipated high levels of coal generation are contingent upon the successful upgrades of transmission lines connecting northern Arizona to northwestern New Mexico, which are essential for transferring power from the Four Corners region to California.

Discussion

SDG&E and CAISO have exaggerated the projected fossil fuel generation in WECC's Analytical Baselines, leading to artificially lower out-of-state power prices that undermine in-state generation This misrepresentation makes the Sunrise project seem more cost-effective than it realistically is, a conclusion supported by CAISO’s modeling.

We find CAISO's assertion that the overstatement has minimal effects on cost-effectiveness results unconvincing Their argument relies on the assumption that new out-of-state generation will mirror California's existing generation resources.

CAISO anticipates a surplus of out-of-state coal-fired generation, while assuming that in-state generation relies on gas Consequently, the modeling must consider that the lower-cost, out-of-state coal power will compete against the higher-cost, in-state gas generation, highlighting the associated economic advantages.

Sunrise's ability to import energy from out of state is crucial, as highlighted by UCAN SDG&E's modeling indicates that a decrease in out-of-state capacity leads to a significant reduction in energy benefits, exceeding 50%, underscoring the importance of maintaining this capability.

We agree that the SDG&E and CAISO assumption of approximately

12,000 MW of new coal generation construction in WECC is excessive in today’s world First, we believe the long term carbon procurement restrictions in

SB 1368 aims to deter the establishment of new coal plants near California, as it is unlikely that generation developers will invest in large, base load coal facilities solely for the spot market Additionally, the anticipated carbon regulations and the push for federal climate legislation further diminish the prospects for significant new conventional coal generation.

Due to significant variations in coal plant projections and the unusual effects that high estimates have on modeling, we conclude that conventional coal plant development will not reach the extreme levels projected by CAISO and SDG&E Therefore, our Analytical Baseline incorporates only 25% of the coal-fired generation identified in the SSG WI database.

Mexican Imports

Parties concur that the combined cycle plants in Baja, Mexico, which supply power to the United States, will remain operational in the future.

CAISO Analytical Baseline that includes all of these resources.

Assumptions Regarding In­Area Renewables

Parties’ Positions

Parties have differing opinions on the renewable development potential within SDG&E's service area SDG&E's Analytical Baseline projects that 40 MW from the Lake Hodges pumped storage project will be operational by 2008, and 20 MW from the Bullmoose biomass project will be available by 2009 Additionally, SDG&E anticipates that all other local renewable generation will maintain its current output levels The California Independent System Operator (CAISO) includes these resources, along with a 4.5 MW contract with San Diego.

County Water Authority, in its Analytical Baseline 176

SDG&E recognizes the significant renewable energy potential within its service area; however, it contends that much of this potential is not economically feasible The company estimates that biomass projects could supply up to 10% of its retail load in the San Diego region, yet only 150 MW have been proposed, with a mere 2.2 MW deemed viable.

SDG&E fails to explain how it defined viability in the context of this biomass analysis.

In Phase 1 of the proceedings, SDG&E highlighted a notable lack of developer interest in its Renewable Portfolio Standard (RPS) solicitations, which it used to argue that renewable energy sources are not feasible in the area Despite receiving numerous solicitations, SDG&E maintained that the response from developers has been insufficient to support the viability of renewables.

175 SDG&E Exhibit SD 26, Appendix I, page I 2.

176 CAISO Phase 1 Opening Brief, Table V 1, 21.

A total of 190 offers, amounting to 8,300 MW of capacity from various regions, were submitted, with only 51 offers (representing 988 MW) coming from developers willing to connect outside of the Southwest Powerlink within SDG&E’s service area Out of these bids, SDG&E has signed contracts for 11 projects, totaling 107 MW.

SDG&E estimates that wind generation in the eastern regions of its service area could achieve a capacity of 500 to 600 MW, representing significant potential for new renewable energy sources within the basin However, the company asserts that an investment of $300 million in new transmission infrastructure is necessary to supply this power to its customers Consequently, SDG&E has classified previously proposed in-area wind projects as uneconomic.

Discussion

We challenge SDG&E's assertion that in-area renewables are not economically viable According to a supply curve developed by CAISO, approximately 750 MW of additional wind generation could be harnessed at a competitive cost of $77 per megawatt hour (MWh) (levelized 2007$), marking it as CAISO's most cost-effective source of new renewable energy While we cannot definitively confirm the availability of these resources to SDG&E at the stated prices, the CAISO data indicates it is premature to dismiss the potential for wind resources located east of San Diego.

Rather than modifying the Analytical Baseline to account for varying levels of future renewable energy development in SDG&E’s service area, we evaluate future in-area renewable generation through both All Source Generation and In Area Renewable Alternatives to Sunrise These alternatives are detailed in our analysis.

We adopt the same in area renewables for our Analytical Baseline that CAISO assumes: the Lake Hodges Pumped Storage Project (40 MW online in

2008), the Bullmoose Biomass Project (20 MW online 2009) and the 4.5 MW contract with the San Diego County Water Authority.

Assumptions Regarding Imperial Valley Renewables

Parties’ Positions

While there is consensus among stakeholders that the construction of the Sunrise transmission line will lead to some increase in renewable energy development in the Imperial Valley, opinions diverge on the extent and timeline of this development Notably, only CAISO and DRA anticipated a boost in renewable generation due to the Sunrise project for modeling purposes, whereas other parties maintained that renewable development levels would remain unchanged regardless of the line's construction.

Sunrise in their Analytical Baselines

SDG&E assumes a significant amount of renewable development in

The Imperial Valley is projected to see significant renewable energy development, with SDG&E estimating over 1,100 MW of new capacity by 2010 and more than 2,700 MW by 2015 This growth is supported by over 5,000 MW of new generator interconnection requests that the Sunrise project would facilitate, including 3,000 MW of wind energy connections in the region.

SDG&E does not quantify the projected development in Imperial Valley resulting from the Sunrise project, claiming it's too challenging to differentiate the renewable benefits of Sunrise from its overall benefits Consequently, SDG&E assumes that aggressive renewable development in the Imperial Valley will remain unchanged, regardless of the Sunrise project Additionally, SDG&E's Analytical Baseline indicates that there will be no incremental renewable resource additions in the Imperial Valley after 2015.

CAISO assumes that approximately 600 MW of geothermal resources would be developed in the Imperial Valley and delivered over the existing

Path 42 between the Imperial Irrigation District and Edison 185 In addition,

CAISO assumes that if Sunrise is developed 900 MW of solar thermal and

1,000 MW of geothermal resources will come on line by 2015, which would result

According to CAISO Exhibit I 2, Table 4.3, the Imperial Valley is expected to contribute an additional 9,900 GWh of renewable energy generation However, CAISO indicates that without the Sunrise project, the incremental 1,900 MW of renewable generation in the Imperial Valley will not be realized.

Observing the slow pace of development in the Imperial Valley, UCAN assumes only 178 MW of new Imperial Valley renewables will come online by

2010 with or without Sunrise 188 It assumes for analytical purposes a total of 1,885 MW of renewable resources online in the Imperial Valley in 2015, with or without Sunrise 189

DRA does not propose assumptions for the renewable portion of the

SDG&E can fulfill its Renewable Portfolio Standards (RPS) obligations without the Sunrise project; however, Sunrise is expected to lower RPS compliance costs by easing the delivery of renewable resources from the Imperial Valley to the CAISO grid Additionally, it may encourage further investment in renewable resources in the Imperial Valley.

186 CAISO Exhibit I 2, Table 4.7 CAISO assumes no wind development in the Imperial Valley CAISO Exhibit I 2, Table 4.3.

187 See Compliance Exhibit Work Papers CAISO assumes that SDG&E receives

Resource Adequacy credit for the new renewables in the Imperial Valley only if Sunrise comes online Thus, these resources would create a reliability benefit.

189 UCAN also appears to contemplate the possibility of only 700 MW of renewable development in the Imperial Valley See, e.g., UCAN Phase 1 Opening Brief, 60 63.

Discussion

It is reasonable to assume that, without a secure transmission path, no significant amount of new renewable generation will be constructed in the

In the Imperial Valley, developers are hesitant to invest in renewable energy projects without assurance that the generated power can be reliably delivered to consumers Conversely, having sufficient transmission infrastructure does not automatically ensure the development and delivery of new renewable energy to the California Independent System Operator (CAISO) grid There are three potential markets for new renewable generation in the region: the CAISO grid through existing routes like the Southwest Powerlink and Sunrise, or the proposed Green Path South, as well as the Imperial Irrigation District and Los Angeles.

The Department of Water and Power is exploring new transmission options to connect renewable energy sources in the Imperial Valley to the California Independent System Operator (CAISO) grid This includes potential links through the proposed Green Path and existing lines like the Southwest Powerlink However, the construction of new generation projects in the Imperial Valley is not assured, as it depends on various factors such as demand for renewable energy, project ownership, and the ease of contracting.

On balance, we agree with CAISO and SDG&E that the construction of Sunrise would encourage the development of renewable resources in the

The Imperial Valley has experienced a notable surge in development activity following SDG&E's announcement of the Proposed Project, despite the challenges posed by the CAISO interconnection queue.

From 2011 to 2015, CAISO anticipates an annual increase of 200 MW in geothermal capacity and 180 MW in solar thermal capacity Although the exact annual resource additions may vary, this projection is a sensible estimate for incremental renewable energy contributions from the Imperial Valley by 2015 Therefore, we incorporate CAISO's projected levels of renewable resource development in the Imperial Valley into our Analytical Baseline for modeling purposes.

Assumptions Regarding the Availability of Out­of­State Renewables to California

Parties’ Positions

CAISO revised its assumptions about the availability of out-of-state renewable resources for RPS compliance savings multiple times Ultimately, it determined that 25% to 50% of the renewable resources identified in WECC outside of California would be developed and delivered to the state.

Nevada Hydro takes issue with CAISO’s assumption, pointing out that CAISO did not make any assumptions regarding the failure of renewable resources planned for development in California 194

192 Compliance Exhibit Work Papers, “Template_case11_use_sunrise_v3.xls,” tab “RPS Capacity.”

194 Nevada Hydro Phase 1 Opening Brief, 34 35.

UCAN disputes CAISO's claim regarding the limited availability of renewable resources from neighboring states, asserting that numerous new out-of-state renewable projects can connect to the existing grid without the need for dedicated transmission lines for California exports They believe that these connections will facilitate the delivery of renewable energy to California efficiently.

Discussion

While we acknowledge CAISO's point that some out-of-state resources may not be accessible to California, we believe their estimate that 75% of these projects will be unavailable is overly pessimistic We concur with UCAN's view that a significant amount of out-of-state renewable energy can be delivered to California without the need for new transmission infrastructure, as evidenced by SDG&E's recent Advice Letter filing, which seeks approval for two wind contracts from Montana with a combined capacity of [insert capacity].

210 MW 196 We adopt CAISO’s initial assumption that 50% of CAISO identified out of state renewables will be available to California.

Assumptions Regarding Development of Renewables in Mexico

Parties’ Positions

Parties generally agree on the level of future renewable generation in Mexico that should be included in the Analytical Baseline While SDG&E

According to SDG&E Advice Letter 1997 E, dated June 4, 2008, the development of several thousand megawatts of new wind generation is underway to utilize Sunrise; however, the modeling does not factor in any new generation from Mexico.

CAISO's modeling does not take into account any new renewable generation in Mexico, but it does recognize the proposal for a transmission line connecting Mexico to the United States Additionally, it highlights the necessity for upgrades, such as the Sunrise transmission project, to effectively transport this wind power.

UCAN expresses skepticism regarding SDG&E's assertions about the wind generation potential in Mexico, highlighting inconsistencies in SDG&E's data Furthermore, UCAN emphasizes that being listed in the CAISO interconnection queue does not ensure that these projects will be constructed.

Discussion

We align with the assumptions made by CAISO and SDG&E, presuming no future renewable energy contributions from Mexico in the Analytical Baseline Additionally, the proposed 500 kV transmission line for importing power from Mexico remains unapproved, and the CAISO interconnection queue does not ensure the expected generation capacity in specific regions.

197 SDG&E Exhibit SD 6, Appendix IV, Table IV 11, page IV 5.

Assumptions Regarding Renewable Costs

Parties’ Positions

CAISO based its renewable resource savings modeling on two key sets of cost estimates For in-state resources, it utilized data from a 2005 study by the Center for Resource Solutions, while for out-of-state resources, CAISO primarily referenced the Northwest Transmission Assessment Committee's 2006 report on transmission costs from Canada to Northwest California.

In 202, CAISO suggested adjusting renewable cost assumptions by lowering the generation costs for solar thermal to $100/MWh, while increasing costs for wind projects to $85/MWh.

$66/MWh) (CAISO’s Alternative Renewable Costs) 203 CAISO justified its increase in wind cost estimates on an Energy Commission staff report, 204 and

201 CAISO Phase 1 Opening Brief, 31, citing to “Achieving a 33% Renewable Energy Target,” The Center for Resource Solutions, November 1, 2005.”

202 See CAISO Exhibit I 2, 48, which cites to “Canada Northwest California

Transmission Options Study,” Northwest Power Pool, Northwest Transmission

Assessment Committee, Canada NW California Study Group, May 16, 2006 Neither this study, nor the Center for Resource Solutions study, are part of the record in this proceeding.

204 CAISO Exhibit I 6, 44. based its proposed solar thermal cost estimates on anecdotal information from developers 205

UCAN and DRA criticize CAISO's Alternative Renewable Costs, arguing that CAISO selectively referenced costs from an Energy Commission staff report for wind energy while neglecting the solar thermal cost estimates UCAN asserts that had CAISO included both solar thermal and wind costs, the alternative renewable cost scenario would indicate that Sunrise renewable resource costs would amount to $828 million annually, contrasting with the reported renewable resource savings of $160 million per year.

DRA suggests that CAISO has engaged in “cherry picking” and that it fails to consider other, equally plausible, renewable cost scenarios 207

In Phase 2, the DRA utilized CAISO’s model to generate its own estimates for RPS compliance savings, implementing several modifications to the model's inputs, particularly regarding renewable costs Following these adjustments, DRA analyzed various renewable development scenarios, resulting in gross annual benefit estimates for Sunrise that range significantly.

$1 million to over $100 million per year, depending on the scenario examined and the assumed online date for Sunrise 208

CAISO disputes DRA's application of its model and the modifications made to its cost estimates CAISO argues that DRA's assumptions about increased geothermal generation costs and decreased wind generation costs are unrealistic Furthermore, even DRA's own witness acknowledged that these assumptions were improbable.

Discussion

In its initial analysis, CAISO based its renewable energy cost assumptions on two primary sources, emphasizing the consistency of these assumptions across technologies as a strength However, the organization later revised its cost projections specifically for solar thermal and wind, undermining the internal consistency achieved through its initial reliance on just two sources Unlike its thorough review of combustion turbine costs, CAISO acknowledged that its reassessment of the new renewable costs was not extensive.

We prefer CAISO's initial method of relying on cost estimates from two reliable sources over using diverse and potentially inconsistent data, which can create conflicting assumptions Therefore, we have chosen to adopt CAISO's CRS Renewable Costs as our Analytical Baseline.

Assumptions Regarding Transmission Resources

The Dispatch Limit at Imperial Valley Substation

UCAN argues that SDG&E significantly underestimates the import capacity of the Southwest Powerlink, leading to an inflated perception of resource needs within its service area By increasing the assumed transfer capability of this power link, UCAN believes that more energy could be imported into SDG&E’s area, thereby decreasing the necessity for local generation resources, including Sunrise To address this issue, UCAN has proposed various enhancements to the transfer capability within the SDG&E system, which were extensively discussed and debated during Phase 1.

In its Phase 2 opening testimony, CAISO announced limitations on the amount of generation that could be dispatched from the Imperial Valley

In late 2007, following the completion of the Phase 1 hearings, CAISO implemented a dispatch limit of 1,150 MW for all generation facilities linked to the Imperial Valley Substation and the Imperial Valley Miguel area.

The Southwest Powerlink has faced a dispatch limit imposed by CAISO due to an interconnection study that indicated a significant rise in risk to the Mexican electrical system when generation exceeds 1,150 MW at the Imperial Valley Substation CAISO noted that the Mexican Electricity Commission is currently not willing to accept this heightened risk, leading to a collaborative decision involving CAISO, SDG&E, and the Mexican Electricity Commission.

CAISO has set a dispatch limit of 1,150 MW based on reliability criteria, which stipulate that the outage of any single transmission element must not exceed the maximum generation that can be simultaneously tripped For SDG&E, this limit corresponds to the capacity of one unit of the San Onofre Nuclear Generating Station (SONGS), amounting to 1,150 MW.

CAISO has established a dispatch limit that restricts the simultaneous generation capacity connected to the Imperial Valley substation to 1,150 MW While additional generation can be connected to the substation, only a portion can be operational at any given time.

CAISO contends that the Analytical Baseline cannot assume the dispatch of more

215 RT 5319. than 1,150 MW of generation directly interconnected to the Imperial Valley

UCAN disputes the 1,150 MW dispatch limit, asserting that it is entirely possible to connect and generate more than 1,150 MW at both the Imperial Valley substation and the Southwest Powerlink They argue that even in the event of a loss of a Miguel transformer or the Southwest Powerlink line, it would not necessitate a reduction of more than 1,150 MW of generation Furthermore, UCAN contends that any implication from SDG&E regarding a 1,150 MW limit on Southwest Powerlink flows or deliveries to the Miguel or Imperial Valley substations is inaccurate.

CAISO argues that UCAN's claims are inaccurate, stating that the Miguel transformer tripping scheme is designed to safeguard the Miguel transformers but fails to protect the interconnected Mexican system Furthermore, CAISO emphasizes that UCAN neglects to consider the negative effects on the Mexican system resulting from the interconnection of over 1,150 MW of generation at the Imperial Valley substation.

The timing of CAISO's disclosure regarding the dispatch limit raises concerns, as evidence suggests it was established prior to Phase 2 and was previously overlooked by CAISO Notably, SDG&E testified in Phase 1 about this issue.

In the 217 CAISO Phase 2 Reply Brief, it was noted that despite the unfortunate timing of the disclosure, CAISO has provided credible evidence regarding the dispatch limit As a result, we are adopting the 1,150 MW dispatch limit that CAISO has utilized for the Analytical Baseline.

Upgrades at Miguel Substation

UCAN proposes two sets of modifications to SDG&E’s Miguel Substation:

(1) increase the all hours import limit into the Miguel Substation from

The Miguel Import Limit Upgrade aims to increase the capacity from 1,450 MW to between 1,700 MW and 1,900 MW, while the Miguel Output Limit Upgrade proposes raising the all-hours export limit from 1,900 MW to 2,100 MW According to UCAN, these enhancements would facilitate increased energy flows across the Southwest Powerlink.

UCAN explains that to implement the Miguel Import Limit Upgrade

CAISO only would need to approve a Remedial Action Scheme 220 permitting the tripping of a second transformer at Miguel Substation when two conditions exist:

(1) the first transformer at Miguel Substation trips and (2) flows over the

Southwest Powerlink exceed 1,450 MW UCAN claims that instituting this

Remedial Action Scheme would increase CAISO’s ability to import renewable

The 220 Remedial Action Schemes enable load shedding during specific circumstances to safeguard the system and avoid expensive upgrades This adjustment permits the Miguel Substation to facilitate additional energy imports, enhancing low-cost energy delivery over the Southwest Powerlink by 200 to 450 MW during peak operational hours UCAN asserts that the implementation of this Remedial Action Scheme incurs no costs and has requested the Commission to mandate SDG&E to proceed with the Miguel Import Limit Upgrade in Phase 1.

SDG&E and CAISO acknowledge the potential of the Miguel Import Limit Upgrade proposal, indicating that it is not deemed infeasible They intend to conduct further studies to evaluate its impact on other systems.

UCAN forecasts that the Miguel Output Limit Upgrade will necessitate various enhancements, potentially including the establishment of an additional Remedial Action Scheme, with estimated incremental costs ranging from $4 million to $35 million Notably, SDG&E has not contested this evidence.

We find UCAN’s Miguel Import Limit Upgrade proposal to be reasonable The record demonstrates that the CAISO is currently reviewing this potential

221 Motion by Utility Consumers’ Action Network to Compel SDG&E to Upgrade its Import

Capability at Miguel Substation, June 5, 2007.

222 See, e.g., SDG&E Phase 1 Reply Brief, 59; CAISO Phase 1 Reply Brief, 28.

The 224 UCAN Phase 1 Opening Brief highlights a proposal that necessitates the implementation of a Remedial Action Scheme without requiring physical upgrades, allowing for swift execution We have adopted this proposal as the Analytical Baseline and directed SDG&E to provide a status report on its implementation within 60 days of this decision This report must be served to each Commissioner, the Director of the Commission’s Energy Division, and the service list for A.06 08 010.

UCAN acknowledges that the Miguel Export Limit Upgrade offers minimal advantages, as the unconstrained flows from the Miguel Substation are unlikely to surpass 1,900 MW Additionally, this upgrade introduces operational complexities to SDG&E’s system, leading us to exclude it from our Analytical Baseline.

Path 44 Upgrades

Path 44 links the Edison and SDG&E high voltage transmission systems UCAN points out that Path 44’s rating has not been updated since 2001 and proposes that SDG&E “take the actions necessary” to upgrade the N 1/G 1 rating of Path 44 from 2,500 MW to 2,850 MW 226 If feasible, this upgrade would permit greater energy flows from Edison to SDG&E, reducing the need for new in area resources It also would allow increased flows to SDG&E in

UCAN's Phase 1 Opening Brief indicates that the proposed upgrade is expected to elevate the N 0 All Lines in Service rating from 2,850 MW to 3,200 MW, which would enhance SDG&E's simultaneous and non-simultaneous import limits by 350 MW This upgrade is anticipated to operate under unconstrained conditions, leading to a reduction in SDG&E’s locational marginal costs and ultimately providing benefits to ratepayers.

• Require adding a third 230/69 kV transformer at SDG&E’s

• “[Q]uite possibly” require upgrading the Barre Ellis transmission line [located in southern Orange County in Edison’s service territory)];

• “[M]ay or may not require” upgrades to the SONGS San Luis

• Require modifications to the Mira Loma Chino #3 line; and

• “[P]robably” require reactive devices such as capacitors to be added to the SDG&E system 228

SDG&E disagrees with UCAN about the viability of this proposal First, SDG&E points out that increasing a path rating is a long, complex process

SDG&E asserts that upgrading Path 44, specifically the Barre Ellis transmission line in Edison’s service area, faces significant challenges due to the already congested corridor The proposed enhancements may necessitate the installation of new towers between existing ones, which complicates feasibility Additionally, SDG&E contends that the necessary upgrades to boost the rating on Path 44 may not be economically viable.

227 UCAN also suggests that addition of a transformer at SDG&E’s San Luis Rey

The implementation of the substation, alongside the adoption of the 1,900 MW Miguel Import Limit and the Path 44 Upgrade proposal, is expected to enhance the Southwest Powerlink's all lines in service rating by approximately 350 MW, increasing it from 2,850 MW to around 3,200 MW This upgrade will facilitate greater import capacity over the Southwest Powerlink.

228 UCAN Phase 1 Opening Brief, 81 82. effective Finally, SDG&E notes that CAISO’s stakeholder process considered and rejected UCAN’s Path 44 proposal as an alternative to Sunrise 230

UCAN claims that the CAISO stakeholder process cited by SDG&E not only excluded UCAN from participation, but its results have been discredited in hearings and disavowed by CAISO itself 231

CAISO opposes UCAN’s Path 44 proposal due to concerns that raising the path rating could lead to transient frequency dips in Mexico, resulting in violations of NERC criteria and potential thermal overloads Additionally, CAISO argues that the proposal may be economically unviable, as any reduction in SDG&E’s Local Capacity Requirements would likely be counterbalanced by an increase in Local Capacity Requirements in the Los Angeles area.

UCAN disagrees with CAISO’s assessment, contending that UCAN’s plan of service under the Path 44 proposal includes reinforcements to correct the criteria violations and thermal overloads 233

We are not convinced at this time that UCAN’s Path 44 proposal presents a viable means to increase import capability into the SDG&E load area and do not

233 UCAN Phase 1 Reply Brief, 48. adopt it for the Analytical Baseline However, we agree that a review of

Path 44’s rating is warranted, particularly since the last one occurred in 2001, and UCAN presents credible evidence that an increase in Path 44’s rating may be possible

We direct SDG&E to take the necessary steps to institute a review of

Path 44 is required to submit a report within 60 days of the decision's effective date, detailing the status of the review This report must be served to each Commissioner, the Director of the Commission’s Energy Division, and the service list.

The Talega­Escondido/Valley­Serrano Transmission Line

The Talega Escondido/Valley Serrano 500 kV transmission line (TE/VS) aims to link the SDG&E and Edison transmission systems, establishing a crucial second extra high voltage interconnection with the CAISO grid Proposed by Nevada Hydro as part of the Lake Elsinore Advanced Pumped Storage (LEAPS) project, the company has submitted a Certificate of Public Convenience and Necessity (CPCN) application for TE/VS, asserting that the line could be operational by 2011.

234 Nevada Hydro Phase 2 Opening Brief, 46 Nevada Hydro filed A.07 10 005, which seeks a CPCN for TE/VS from this Commission The Sunrise EIR/EIS identifies

LEAPS Transmission Only Alternative, proposed by TE/VS, serves as a transmission-focused option distinct from the larger project by Nevada Hydro While LEAPS encompasses the pumped storage generation component, it is important to note that it does not include the generation aspects of the overall project.

Transmission Only Alternative The Sunrise EIR/EIS identifies this larger project as

TE/VS will not connect to the Imperial Valley or other transmission-constrained renewable areas, which limits its direct contribution to California's Renewable Portfolio Standards (RPS) goals However, it can enhance energy movement, including renewables, across the CAISO grid by increasing transfer capacity between the SDG&E and Edison systems This improvement would enable SDG&E to acquire and deliver more renewable energy from regions north of its system.

Parties disagree about the transfer capability of TE/VS, the costs to build TE/VS and integrate it into the SDG&E and Edison systems, and the timing of construction

Nevada Hydro asserts that the TE/VS transfer capability can supply 1,000 MW between the Edison and SDG&E service areas In contrast, SDG&E argues that this capability is limited to 795 MW Additionally, there is an alternative option referred to as the LEAPS Transmission Plus Generation Alternative.

We discuss the environmental impacts of both of these alternatives in Section 15

The Imperial Irrigation District's Phase 2 Opening Brief highlights the potential for delivering renewable energy from the Imperial Valley to the SDG&E service area This delivery is made possible through the combination of TE/VS and proposed transmission upgrades by the Imperial Irrigation District.

236 Nevada Hydro Phase 2 Opening Brief, 39 40.

Nevada Hydro has not provided any evidence regarding costs to construct TE/VS, but claims that TE/VS will cost less than $400 million 238

SDG&E estimates that integrating Transmission Expansion/Voltage Support (TE/VS) into its system, accommodating about 795 MW of transfer capability, would cost approximately $1 billion, leading to a total installed cost of $1.8 billion However, Nevada Hydro disputes this claim, arguing that CAISO analysis indicates that TE/VS, when paired with Green Path, offers nearly the same levelized net benefits for ratepayers as the Sunrise project.

Expansion Plan process found that a line similar to TE/VS could provide

750 MW of transfer capability with only “minor upgrades.” 241

There is a disagreement among parties regarding the timeline for the construction of TE/VS, with Nevada Hydro asserting that it can be operational by 2011, while SDG&E believes it will be ready in 2012 Ultimately, CAISO has revised its initial Phase 1 assumption and now aligns with SDG&E's timeline.

Nevada Hydro argues that LEAPS, in conjunction with TE/VS, should not be considered as an alternative to Sunrise It argues that we consider only

238 Nevada Hydro Phase 2 Opening Brief, 66.

240 Nevada Hydro Phase 2 Opening Brief, 6.

241 Nevada Hydro Phase 1 Reply Brief, 22.

TE/VS (without the LEAPS component) in our Analytical Baseline, and if not that, then as an alternative to Sunrise 244

We recognize that TE/VS is crucial for assessing our economic and environmental options To remain impartial regarding the ongoing TE/VS CPCN application, we will not presuppose its existence for the Analytical Baseline Instead, we will examine it as a potential alternative within both the Environmental Impact Report/Environmental Impact Statement (EIR/EIS) and the economic modeling for this process.

Imperial Irrigation District Upgrades

Section 5.5 above summarizes Imperial Irrigation District’s plans to upgrade its high voltage transmission system to deliver Imperial Valley renewables to the CAISO and Los Angeles Department of Water and Power control areas The plans include, among other things, re rating and upgrading Path 42 and constructing three transmission lines: the Coachella Valley Devers 2 line, the Midway Bannister line, and the Dixieland Imperial Valley line.

Parties are divided on which upgrades should be included in the Analytical Baseline SDG&E argues that the transmission upgrades and new facilities from the Imperial Irrigation District are just one aspect of a broader strategy to access renewable resources from the Imperial Valley They emphasize that the absence of the Sunrise project would hinder this access.

244 Nevada Hydro Phase 1 Opening Brief, 8 9. renewables will, to a great degree, remain stranded even if all of Imperial

Irrigation District’s upgrades are assumed to occur 245

UCAN notes that Imperial Irrigation District’s proposals to upgrade

Path 42 and construct the Coachella Valley Devers 2 transmission line will double the existing transfer capability between it and Edison UCAN suggests that Imperial Irrigation District’s proposed 230 kV Dixieland Imperial Valley line will also increase Imperial Valley exports to the CAISO grid UCAN also notes the potential for other new transmission interconnections from the Imperial Irrigation District system to the east (the proposed Highline Knob North Gila transmission line) to connect to Arizona Public Service and the Southwest

CAISO has announced that the upcoming upgrades to Path 42 will enhance the transfer capacity between the Edison and Imperial Irrigation District Systems to 1,200 This assumption has been incorporated into their modeling efforts.

Our Analytical Baseline assumes that Path 42 will be upgraded to 1,200 MW this year, and the Dixieland Imperial Valley line, which has received approval from the Imperial Irrigation District Board, is expected to be operational by mid-2010.

248 Imperial Irrigation District Phase 2 Opening Brief, 20.

The Green Path Transmission Line

The Green Path project is a proposed 500 kV transmission initiative aimed at transporting energy from the Imperial Irrigation District to the CAISO and Los Angeles Department of Water and Power control areas This project is expected to facilitate the delivery of up to 2,000 MW of electricity from the Imperial Valley and surrounding regions to the CAISO grid.

Green Path cannot directly deliver renewable resources from Imperial Valley to SDG&E’s service area due to its lack of interconnection with the SDG&E system However, renewable resources that are delivered to the CAISO system can contribute to Renewable Portfolio Standard (RPS) compliance Therefore, Green Path plays a role in supporting RPS objectives by enabling access to renewable resources on the CAISO grid.

In Phase 1, CAISO anticipated the Green Path project would be operational by 2010, but this timeline was adjusted to 2011 in Phase 2 SDG&E argues that Green Path should not be considered a viable option for delivering renewable energy to the CAISO grid, as the Los Angeles Department of Water and Power plans to use Green Path to fulfill its own 20% renewable energy mandate.

UCAN argues that we should include Green Path in our Analytical

The Imperial Irrigation District has affirmed its dedication to the Green Path project in Phase 1, which has successfully completed the third and final step of the WECC review and approval process Furthermore, CAISO now anticipates that Green Path will be constructed to meet its Local Capacity Requirement and deliverable studies.

In our environmental analysis, we did not recognize Green Path as a viable alternative to Sunrise due to its speculative nature Consequently, we recommend excluding Green Path from the Analytical Baseline Nonetheless, given its potential significant impact on the benefits associated with Sunrise, CAISO acknowledges its relevance.

Green Path, alongside LEAPS and TE/VS, serves as an alternative to the Sunrise project To assess the potential impact of Green Path on the advantages offered by Sunrise, we will examine the findings of CAISO’s modeling presented in Section 11.

Modified Coastal Link

In Phase 1, Rancho Peủasquitos identified a series of transformer and reconductoring projects intended to eliminate the need for the Proposed Project’s

230 kV Coastal Link transmission line segment, which is described in

Section 3.2.1, above Rancho Peủasquitos suggested that its Coastal Link

Alternative would minimize local impacts (by eliminating the line through the community entirely) and reduce costs 253

SDG&E's Phase 2 modifications to the transmission topology necessitated a redesign of the Rancho Peñasquitos Coastal Link Alternative The updated plan now features the installation of an additional 230/69 kV, 224 MVA transformer at SDG&E's Sycamore Canyon Substation, along with necessary substation enhancements Additionally, the project includes reconductoring both 69 kV circuits of the transmission line connecting Sycamore Canyon to Pomerado Substation.

The project involves reconductoring the 69 kV circuit of the Sycamore Canyon to Scripps transmission line and installing a 230/138 kV, 392 MVA transformer at SDG&E’s Encina Substation This is contingent upon CAISO's approval of a Remedial Action Scheme aimed at redirecting Encina Power Plant generation to alleviate overloads on the Sycamore Canyon to Chicarita 138 kV transmission line.

In Phase 1, SDG&E contended that the reliability analysis for Rancho Peñasquitos was insufficient to justify its potential as a replacement for the Coastal Link They highlighted that the Coastal Link incurs higher costs due to the extensive undergrounding required to reduce community impact compared to the Rancho Peñasquitos alternative.

253 Rancho Peủasquitos Phase 1 Opening Brief, 7ư10.

254 Between Phases 1 and 2 of this proceeding, SDG&E cancelled a transmission project which would have obviated the need for this reconductoring.

255 Rancho Peủasquitos Phase 2 Opening Brief, 16ư17.

In Phase 2 SDG&E estimates that Rancho Peủasquitos’ Coastal Link

The Rancho Peñasquitos alternative is estimated to cost $83.66 million based on a 2012 timeframe SDG&E has consistently opposed this alternative, advocating instead for the perceived technical advantages of the Coastal Link Additionally, SDG&E argues that the Rancho Peñasquitos option necessitates the installation of a transformer at Encina.

CAISO conducted an analysis of multiple scenarios put forth by Rancho Peñasquitos in Phase 1 and concluded that the Coastal Link Alternative sufficiently addresses reliability requirements Additionally, in Phase 2, CAISO evaluated the alternatives proposed by Rancho Peñasquitos and found no concerns regarding their reliability.

We adopt Rancho Peủasquitos’ Coastal Link Alternative, defined in

Rancho Peñasquitos’ Phase 2 Reply Brief highlights its position within the Analytical Baseline, demonstrating that CAISO supports Rancho Peñasquitos’ alternative solution as a viable option compared to SDG&E’s proposed Coastal Link Rancho Peñasquitos effectively counters SDG&E’s arguments, emphasizing the substantial cost savings and reduced environmental impacts associated with their alternative, which SDG&E fails to adequately address.

257 Rancho Peủasquitos Phase 2 Opening Brief, 17ư18.

259 SDG&E Phase 2 Reply Brief, 155 156 SDG&E does not clarify if the transformer would be at the Encina Power Plant or the Encina Substation.

The Final EIR/EIS identifies the Environmentally Superior Southern Route, explicitly stating that the reconductoring of the Poway Pomerado 69 kV transmission line is not included in the Coastal Link Alternative.

Rancho Peủasquitos Coastal Link Alternative compared to SDG&E’s proposed Coastal Link 262

Assumptions Regarding Gas Price Forecasts

Parties’ Positions

Gas price forecasts play a crucial role in the production cost models of SDG&E and CAISO Starting at around $7 per million Btu (MMBtu) at the California border in 2007, SDG&E anticipates a significant escalation in gas prices over time.

$9/MMBtu in 2020 (nominal dollars) 263 SDG&E does not add intrastate gas transportation charges to derive a burnertip gas price for generators in

CAISO's modeling for 2015 assumes a constant gas price of $6.89/MMBtu at the Southern California border Additionally, it incorporates intrastate gas transportation charges of $0.3935/MMBtu and $0.1651/MMBtu for gas delivered to generators in the Southern California Gas and Pacific Gas and Electric regions.

Company (PG&E) service areas, respectively After UCAN pointed out that CAISO had failed to include gas taxes in Arizona, 265 CAISO added 5.6% to the

The EIR/EIS evaluated the Rancho Peñasquitos Coastal Link Alternative and found it to be environmentally superior to SDG&E's proposed Coastal Link As a result, the Rancho Peñasquitos Alternative has been adopted in place of SDG&E's proposal for both the Final Environmentally Superior Northern and Southern Routes.

265 UCAN Phase 1 Opening Brief, 198 199. border gas price for generators in Arizona Given this change, UCAN generally supports CAISO’s gas price forecast, especially when compared to that used by SDG&E 267

DRA asserts that SDG&E’s forecast is too high for a base case analysis and that it inflates the benefits of Sunrise 268

Discussion

Assumptions about gas prices significantly influence the economic advantages of the Sunrise project The California Independent System Operator (CAISO) provides a gas price forecast that highlights the disparity in gas prices between Arizona and California generators, which is crucial for assessing Sunrise's value In contrast, SDG&E's gas price forecasts do not account for this difference Furthermore, CAISO's forecasts are conservative, aligning with recommendations from the Division of Ratepayer Advocates (DRA) Therefore, we have chosen to utilize CAISO's gas price forecasts as our Analytical Baseline.

Assumptions Regarding Combustion Turbine Costs

Parties’ Positions

Reliability benefits encompass the cost savings from postponing new generation resources due to the introduction of a proposed generation or transmission resource aimed at addressing reliability needs In this analysis, these benefits are quantified as the value of deferred combustion turbines, which CAISO assessed at $78 per kW per year (in 2007 dollars), with an annual escalation of 2%.

The 268 DRA Phase 1 Opening Brief indicates an interconnection cost adder of 35.2% of the combustion turbine's cost In Phase 2, CAISO significantly increases this figure to $162.10 per kW per year (in 2007 dollars, adjusted for a 2% annual escalation), as derived from a December 2007 Energy Commission staff study However, the 35.2% cost adder for interconnection costs remains unchanged.

UCAN challenges CAISO's decision to nearly double the costs of new combustion turbines from Phase 1 to Phase 2, asserting that such an increase should also affect the costs of Local and System Resource Adequacy, which rely on these turbines In response, CAISO partially disagrees, clarifying that System Resource Adequacy is determined by overall generation costs rather than solely the costs of new combustion turbines.

UCAN argues that the interconnection costs for new combustion turbines are misaligned with CAISO's assumptions for the Sunrise project They highlight that CAISO treats these interconnection costs as a fixed percentage of the combustion turbine costs, leading to a doubling of expenses in Phase 2 when the costs of new turbines increase In contrast, UCAN points out that CAISO's projected costs for Sunrise do not rise nearly as significantly from Phase 1 to Phase 2.

271 UCAN Comments on Compliance Exhibit, 22 23.

272 CAISO Reply Comments on Compliance Exhibit, 10 11.

Phase 2 CAISO counters that the cost differences are not unreasonable and attributes them to the greater detail underlying the cost estimates for Sunrise CAISO also argues that even if the new combustion turbine interconnection costs escalate at the same rate as Sunrise costs, Sunrise still will be economically superior to all of the alternatives, assuming 33% RPS and the higher combustion turbine costs CAISO uses 274

DRA 275 and SDG&E 276 support CAISO’s higher combustion turbine costs.

Discussion

The significant disparity in cost estimates for combustion turbines between CAISO's Phase 1 and Phase 2 is striking Both CAISO and SDG&E advocate for using the combustion turbine cost estimates from a December 2007 Energy Commission staff study However, during the period from January 2007 until the conclusion of Phase 1 hearings, SDG&E and CAISO relied on cost estimates that were less than half of those presented in the December 2007 study, showing a stark contrast of $78/kW year compared to $162.10/kW year (both figures adjusted to 2007 dollars and escalated at 2% annually).

The cost estimates from the December 2007 Study are deemed unreasonable, particularly in Phase 2, where CAISO relies on the study for combustion turbine cost estimates while rejecting other financial projections within the same report.

273 UCAN Comments on Compliance Exhibit, 21 22.

274 CAISO Reply Comments on Compliance Exhibit, 10.

275 DRA Reply Comments on Compliance Exhibit, 2, note 2.

The December 2007 Study's estimates for combustion turbine prices were deemed reasonable by CAISO, which supported its findings with market data Both DRA and SDG&E endorsed CAISO’s Phase 2 combustion turbine prices Although UCAN raised concerns about necessary adjustments due to increased combustion turbine costs, they did not dispute the accuracy of the estimates Consequently, we find CAISO’s Phase 2 combustion turbine costs to be reasonable and adopt them for our Analytical Baseline.

Assumptions Regarding Project Costs

Parties’ Positions

To calculate net benefits, it is essential to estimate the project costs for each alternative and subtract these costs from the total gross benefits Project costs encompass capital expenditures as well as operating and maintenance expenses, which are annualized over a designated recovery period Each of these cost components will be discussed in detail below.

In Phase 1, SDG&E projected the capital expenditure for the Proposed Project to be approximately $1.265 billion, which encompasses all associated costs, including essential upgrades to substations and transmission lines.

277 See RT 2393 2395; see also RT 5542 5545.

The SDG&E Phase 1 Opening Brief outlines that the cost estimate for the project includes expenses related to engineering, environmental considerations, construction management, and support services Additionally, it accounts for overheads such as Allowance for Funds Used During Construction, escalation, and an 18.35% contingency to cover unforeseen changes SDG&E emphasizes that this estimate is derived from preliminary design work and does not include a detailed cost estimate.

In Phase 2, SDG&E updated its capital cost estimates to account for a revised online date of 2011 and to incorporate environmental mitigation costs, resulting in a total estimated capital cost of $1.792 billion for its Proposed Project This figure includes mitigation expenses and considers the RPCC alternative segment SDG&E asserts that its methodology for developing these cost estimates has not been credibly disputed by any other party.

CAISO also presented capital costs estimates for the Proposed Project and some of its alternatives, based on information from SDG&E and others.

SDG&E and CAISO translate the capital costs for the Proposed Project and various alternatives into levelized annual revenue requirements, as set forth below:

Table 3: SDG&E and CAISO Capital Cost Estimates

SDG&E Alt 1: All Source Generation Alternative 507

SDG&E Alt 2: In Area Renewable Alternative 544

SDG&E Alt 3: LEAPS Transmission Only 263

SDG&E Alt 4: Draft EIR/EIS Environmentally Superior Southern

SDG&E Alt 5: Draft EIR/EIS Environmentally Superior Northern

DRA raises concerns about whether SDG&E's cost estimates comprehensively account for all capital expenditures, noting that construction costs could fluctuate following the completion of environmental reviews and the finalization of routing details Additionally, DRA contends that SDG&E should have factored in the expenses associated with the San Felipe Substation in Imperial.

282 Unless otherwise stated, tables containing annual levelized benefits are for benefits from 2010 2049 for Phase 1 and from 2012 2058 for Phase 2.

284 CAISO Exhibit I 13, 22 We calculate the capital cost of Green Path by subtracting the capital cost of Sunrise from the Sunrise + Green Path total.

Valley in its capital costs, because that substation appears to be necessary to achieve any reduction in Local Capacity Requirements 286

UCAN advocates for the inclusion of the San Felipe Substation in the estimated capital costs, along with other facilities required to address the overloads they claim will result from the Sunrise project They also suggest that SDG&E may not have accounted for costs related to future transmission additions deemed necessary if Sunrise is built Additionally, UCAN identifies several potential projects that may be required as a consequence of the Sunrise construction.

Operating and Maintenance Costs

In Phase 1, SDG&E projected the annual operating and maintenance costs for the Sunrise project to be $10 million (in 2010 dollars), resulting in a total revenue requirement of $624 million over 40 years However, in Phase 2, SDG&E revised this estimate, reducing the operating and maintenance revenue requirement to $327 million This updated forecast is based on a more comprehensive analysis than the initial estimates, with annual costs fluctuating and the project duration extended to 58 years UCAN has raised concerns regarding these adjustments.

SDG&E has significantly underestimated the operating and maintenance costs for its Phase 1 Sunrise project, projecting only 0.7% of its transmission plant valuation, compared to the actual 3.3% in 2006, which amounted to over $30 million UCAN argues that a more accurate estimate for Sunrise's annual operating and maintenance costs should be $26.3 million, alongside at least $8.4 million for administrative and general costs, and $0.6 million for other fees, totaling approximately $35.3 million per year.

SDG&E argues that UCAN makes a mistake by calculating operating and maintenance costs in current dollars and dividing them by the gross book cost of the plant, which was recorded in previous years using deflated dollars.

CAISO has incorporated an annual operating and maintenance cost of around $3.9 million in the Compliance Exhibit, while disputing UCAN's inflated cost estimates CAISO aligns with SDG&E in criticizing UCAN's methodology for calculating the operating and maintenance costs per dollar of net book value for the Sunrise project, highlighting flaws in their approach Additionally, CAISO raises concerns about the ratio used in UCAN's estimates.

294 SDG&E Phase 1 Reply Brief, 117. operating and maintenance costs to capital costs are likely to decline given the increases in costs of transmission construction materials 295

Mussey Grade contends that the potential costs of wildfires, which could accidentally arise from Sunrise’s operations, must be assessed and incorporated into the overall project expenses They estimate these wildfire-related costs to be significant.

SDG&E argues that Mussey Grade's assessment exaggerates the wildfire risk associated with Sunrise, noting that the potential costs of wildfires are already factored into SDG&E's operating expenses through liability insurance, amounting to $2 million annually.

Cost Recovery Period

In Phase 1, SDG&E and other parties used a 40 year life to amortize

In Phase 2, SDG&E has announced its agreement with the Federal Energy Regulatory Commission (FERC) concerning the amortization of transmission investments, indicating that the Sunrise project will be amortized over a period of 58 years.

UCAN opposes the 58-year amortization period, arguing that it stems from a settlement approved on May 18, 2007 They assert that SDG&E should have incorporated this information into its Phase 1 presentation, especially since it was established before the deadline for submitting prepared rebuttal testimony in that phase of the proceeding.

295 CAISO Reply Comments on Compliance Exhibit, 8 9.

296 Mussey Grade Phase 1 Opening Brief, 5.

Discussion 112 7.Estimates of SDG&E’s Reliability Need Based on Analytical Baseline

Parties’ Positions

SDG&E, CAISO, and UCAN utilize distinct Analytical Baseline assumptions to forecast the timeline and magnitude of reliability shortfalls within SDG&E's service area Their collaborative analysis culminates in Table 4, which presents the final estimates of SDG&E's anticipated reliability needs.

Table 4: Parties’ Final Projections of Reliability Need

DRA, Nevada Hydro, and Powers Engineering dispute CAISO and

SDG&E estimates of reliability need DRA concludes SDG&E will not require additional resources until at least 2013, but more likely 2015 or 2016, whether or not Sunrise is built 305

Both CAISO and SDG&E initially forecasted energy shortfalls beginning in 2010, but neither updated their Phase 1 load and resource assessments They later recognized that the Sunrise project would not be operational in 2010, with CAISO now projecting a 2011 start date Adjustments to CAISO's data indicate that 145 MW will operate under a Must Run contract during 2010 and 2011, aligning with the details provided about the South Bay Power Plan in Section 6.7.1.

SDG&E proposed that the reliability issue arising from the delay in the Sunrise project could be resolved by introducing new peaker plants in the San Diego region This assumption is reflected in Table 4, aligning with the analysis presented in Section 6.7.2.

RMR_AlL_Revised_Alternatives_Workpapers SDG&E’s final numbers were adjusted to keep the N 1 import limit at 2,500 MW.

304 UCAN Exhibit U 101, “Phase IIrebuttalworkpapers.xls.”

Nevada Hydro states that, with the addition of the TE/VS line, SDG&E will require additional resources no sooner than 2020 306

Powers Engineering’s proposed combination of increased solar PV, other distributed generation, demand response, and energy efficiency is designed to avoid any need for new resources until 2020.

Discussion

Section 6.1 summarizes our adopted Analytical Baseline assumptions We adopt the findings in Table 5, which presents the projected “reliability need” for SDG&E’s service area applying our adopted Analytical Baseline assumptions

Table 5: Commission’s Adopted Projections of Reliability Need

According to Table 5, under the Analytical Baseline assumptions, SDG&E's service area does not require new resources for reliability before 2014, demonstrating a capacity surplus of 773 MW in 2010, 698 MW in 2011, 624 MW in 2012, and 55 MW in 2013 However, a reliability need for new resources begins to emerge starting in 2014.

22 MW in 2014 and 95 MW in 2015, with a total of 456 MW by 2020

However, we note that the projection of reliability need shown in Table 5 above, is premised on a number of assumptions As the parties have

The 306 Nevada Hydro Phase 1 Opening Brief highlights critical assumptions that could significantly impact the resource mix and availability within San Diego's service area Notably, the South Bay facility, which has a nameplate rating, plays a crucial role in this analysis.

The 702 MW capacity plays a crucial role in shaping reliability need assumptions Furthermore, the baseline projections include several projects at different development stages, such as the Carlsbad Energy Center with a net output of 222 MW, and the Pala and Wellhead projects contributing a net total of 138 MW.

The facilities collectively contribute over 1,000 MW of local generation, with South Bay nearing the end of its operational life yet remaining essential as a Must Run resource designated by CAISO Currently, South Bay plays a crucial role in ensuring the reliability of the electrical system in the San Diego region CAISO warns that SDG&E will face capacity shortages if South Bay is decommissioned without a viable replacement, highlighting the importance of not merely assuming South Bay's continued operation until it is deemed unnecessary.

Relying on an outdated and inefficient unit for system reliability in the greater San Diego region poses significant risks To enhance reliability, SDG&E should proactively explore more effective solutions.

307 The baseline assumes that South Bay will operate until the earlier of December 31,

2012 or the end of the year in which Sunrise comes online

308 CAISO Opening Brief on Compliance Exhibit 1, 13. methods to replace the reliability benefits currently provided by the South Bay unit 309

Recent experience indicates that developing and executing competitive Requests for Offers (RFOs), along with financing, permitting, and constructing new generation resources, necessitates procurement decisions to be made up to seven years in advance Failing to do so leads to "just in time" procurement, which jeopardizes reliability, increases power delivery costs, and often fails to yield additional preferred or renewable resources.

Considering the information provided, we establish baseline assumptions for project comparison, fully recognizing that a single incorrect assumption could greatly affect the reliability requirements within SDG&E's service area.

Encouraging the retirement or repowering of California's aging power plants aligns with several state policy objectives, such as reducing once-through cooling units and promoting Brownfield development.

AB 1576, renewable resource integration, air quality goals, and reduction of GHGs).

311 A one year delay in commercial operation of the Carlsbad facility could turn a

55 MW reliability “surplus” into a 167 MW deficit, based on modeling assumptions

What They Are and How They Are Estimated

and How They Are Estimated

SDG&E asserts that the Sunrise project will reduce consumer expenses by enhancing access to more affordable out-of-state power, which is termed an "energy benefit." Additional forms of energy benefits include various savings and efficiencies that contribute to overall cost reductions for consumers.

• Transmission grid efficiencies that reduce the total cost to deliver energy throughout the year, including line loss reductions and congestion cost savings; and

• Increased profits from utility retained nuclear and hydro generation resulting from reduced market prices, which are passed through to California investor owned utility ratepayers 312

The Sunrise transmission project will transform grid operations and the dispatch of generation resources across WECC, leading to significant energy benefits or costs.

Planners assess the impact of a proposed high voltage transmission line on the grid by employing advanced production cost simulation models These models effectively simulate utility system operations, accounting for hourly load variations across regions and the optimal dispatch of power plants to meet these demands By considering operational constraints, reliability requirements, and power flows, the simulations ensure that generation is managed in the most cost-effective manner.

If a proposed project leads to a decline in profits, it should be considered a project cost rather than a benefit The interconnected grid facilitates the dispatch of power plant fleets, allowing models to forecast hourly marginal power prices across various locations in WECC To determine the production cost savings from the proposed transmission project, the total cost of generated power with the project in operation is subtracted from the total cost in a reference case that does not include the line.

The assumptions used in production cost models greatly influence the outcomes of the modeling process In this case, both SDG&E and CAISO initiated their production cost modeling with generation and transmission resource databases provided by SSG WI They subsequently adjusted this data according to their individual assumptions, as outlined in Section 6.8.1 This led to markedly different estimates of energy benefits due to the varying assumptions employed by each entity.

Overview of Conclusions

Four parties presented production cost modeling cases to estimate the energy benefits of the Proposed Project and its alternatives, while UCAN and DRA calculated energy benefits based on the modeling results of others SDG&E concluded that the Proposed Project offers significant energy benefits.

$105 million per year, which are reduced to $52 million per year when compared

Production cost models can estimate overall emissions, including greenhouse gas emissions, from power plants CAISO projects annual energy benefits at $34 million, while DRA estimates a range between $20 million and $80 million per year UCAN does not provide a specific energy benefits figure but suggests its estimate would be lower than that of SDG&E.

SDG&E revised its estimated energy benefits to correct modeling errors and test new assumptions, resulting in projections that significantly exceed those of other parties, including CAISO Due to these discrepancies and additional factors, we find SDG&E's estimated energy benefits unreliable Consequently, we adopt the energy benefits for Sunrise as outlined in the Compliance Exhibit, estimating $5 million per year under a 20% RPS and $18 million per year under a 33% RPS.

Parties’ Modeling Efforts

Parties’ estimates of Sunrise’s energy benefits have evolved throughout the proceeding in response to SDG&E’s changes in assumptions and modeling methodologies and corrections of errors in its analyses

Table 6 below summarizes the change in SDG&E’s projected energy benefits over the course of the proceeding SDG&E estimated energy benefits of

In the 2005 Application, the projected energy benefits were $96 million annually, which increased to $468 million per year in the 2006 Application, ultimately reaching an estimated $105 million per year by July 2007 When compared to a combustion turbine reference case modeled with its own Analytical Baseline assumptions in Phase 2, SDG&E anticipates energy benefits of $52 million per year from the Sunrise project.

Table 6: SDG&E Assessment of Energy Benefits

Sunrise compared to combustion turbine reference case 320 52

318 Correction to Amended Application of San Diego Gas & Electric Company, filed January 19, 2007, page IV 8

In Phase 2, SDG&E initially submitted net benefit calculations without a standard combustion turbine reference case, using the Proposed Project as the reference point instead, which complicated comparisons with Phase 1 results To address this issue, the ALJ instructed SDG&E to provide testimony including a combustion turbine reference case akin to its Phase 1 assessment, along with two additional reference cases In May 2008, SDG&E presented these results, revealing significantly lower net benefits compared to Phase 1 Following the hearings, CAISO criticized SDG&E's benefit analysis in its Phase 2 reply brief, labeling it as fundamentally flawed.

In its report to the Governing Board, CAISO initially estimated energy benefits of $125 million for 2015, based on 2006 dollars However, following a comprehensive review at the start of Phase 1, this estimate was revised to $140 million in 2015 dollars, equivalent to $112 million in 2006 dollars After a workshop in March 2007, CAISO further adjusted its projections, resulting in a downward revision of levelized benefits for the Sunrise project to $34 million per year in 2006 dollars.

Instead of pursuing varied assumptions to test these energy benefit revisions, CAISO elected to keep them constant – at $34 million per year – through the rest of the proceeding 323

Discussion

Throughout this proceeding, parties identified a number of errors in

SDG&E's energy benefit modeling has been scrutinized, revealing that despite attempts to address deficiencies, the company lacks sufficient affidavits to support its claims and has not proposed a viable remedy Notably, SDG&E did not reference Exhibits SD 142, SD 143, or SD 144, which detail the results of this analysis, in either its Phase 2 opening or reply briefs.

321 For consistency, CAISO Exhibit I 1 2015 benefits have been brought to 2006 dollars from 2015 dollars by deflating at 2.5%

In Phase 2, CAISO did not conduct production cost modeling, instead prioritizing the projected reliability and RPS compliance benefits of the project The decision reveals that CAISO failed to identify or rectify all modeling errors and unreasonable assumptions, particularly those made by SDG&E For instance, SDG&E's assumption of consistent renewable resource levels in the Imperial Valley, regardless of the construction of the Sunrise or alternative transmission options like Green Path, contradicts its own testimony about potential renewable development in the area without Sunrise Furthermore, this assumption conflicts with SDG&E's claim that the existing 1,150 MW dispatch limit hinders the interconnection of new resources at the Imperial Valley Substation.

CAISO’s modeling yielded diverse outcomes based on key assumptions that we do not accept Notably, it does not incorporate the November 2007 Forecast of peak demand, along with the adjustments we have adopted Additionally, it presumes more than

In the WECC region, there are plans for 12,000 MW of new coal generation, with an assumption that only 25% will be utilized, as previously mentioned in Section 6.11 At the conclusion of Phase 1, CAISO estimated the annual energy benefits of the Sunrise project to be $34 million, without conducting additional production cost models to evaluate any potential shortcomings in this assessment.

324 See, for example, SDG&E Exhibit SD 15.

SDG&E's assumptions conflict with CAISO power flow modeling, which identified reliability criteria violations linked to the proposed level of renewable development in Imperial Valley without the Sunrise project Specifically, CAISO Exhibit I 3 highlights these violations in a scenario outlined by UCAN that matches SDG&E's renewable capacity estimates for Imperial Valley.

We do not endorse CAISO's energy benefit projections mentioned in this article Instead, we utilize the energy benefits derived from the CAISO Compliance Exhibit, which extends CAISO's Phase 1 production cost modeling to align with the majority of our Analytical Baseline assumptions presented here.

The Compliance Exhibit in Section 11.3 estimates that both SDG&E’s “Enhanced” Northern Route and the Draft EIR/EIS Environmentally Superior Southern Route will provide energy benefits amounting to $5 million annually, assuming a 20% Renewable Portfolio Standard (RPS).

$18 million per year under 33% RPS CAISO estimates no energy benefits for the All Source Generation Alternative.

What They Are and How They Are Estimated

and How They Are Estimated

Reliability benefits are savings generated when a generation or transmission resource results in:

• Deferred or avoided new generation (generally quantified as combustion turbine costs); and

• Must Run contract savings – also referred to as “reduced local reliability costs” or “market power mitigation costs.”

By improving the transfer capability between the San Diego load area and generation resources outside of the load area, Sunrise will lower the Local

In the San Diego area, capacity requirements are currently met, reducing the necessity for Must Run contracts and new generation facilities However, if transmission alternatives like Sunrise are implemented, they may lead to increased generating capacity in neighboring localities.

Reliability Area to become committed to SDG&E, this will simultaneously reduce SDG&E’s Local Capacity Requirement and increase the Local Capacity

CAISO anticipates that the Sunrise project will elevate the Local Capacity Requirement in the Los Angeles Basin, leading to an associated "reliability cost" for ratepayers within the system.

Resource Adequacy generation that Sunrise draws from the Los Angeles basin CAISO also calculates avoided System Resource Adequacy based on new renewable generation resulting from Sunrise.

The value of avoided Must Run contracts is assessed through cost analysis, while the value of deferred new generation is determined by the discounted cost difference of new generation resources, typically combustion turbines, with and without the deferral For instance, the financial benefit of postponing the need for a new combustion turbine by five years is calculated by comparing the cost of the turbine constructed instead of Sunrise to the discounted cost of the turbine built five years later.

Proposed projects and their alternatives can offer unquantifiable reliability benefits For instance, transmission line options are more vulnerable to outages caused by wildfires compared to generation alternatives Additionally, generation alternatives can deliver essential reliability services to CAISO, including reactive power support and grid regulation, which transmission alternatives are unable to provide.

326 CAISO assumes Sunrise will draw resources from the Imperial Irrigation District that would have otherwise met Los Angeles basin Local Resource Adequacy needs.

Finally, SDG&E presents a quantitative assessment of the potential customer costs associated with outages on different transmission alternatives.

Overview of Conclusions

As set forth in Section 7 above, parties predict, based on their own

The analytical baseline assumptions reveal varying reliability needs across SDG&E's service area, which have evolved over different years Key stakeholders, including SDG&E, CAISO, UCAN, and DRA, conducted models to assess the reliability benefits of the Proposed Project The final estimates of these reliability benefits, as presented in Table 7, highlight the collaborative efforts of these parties in evaluating the project's impact on service reliability.

Table 7: Parties’ Final Projected Reliability Benefits

This table shows CAISO’s total projected reliability benefits to be substantially higher than other parties’ projections.

330 UCAN Phase 1 Opening Brief, 261 63 UCAN does not separately estimate reliability benefits, however its reliability benefits would be less than SDG&E’s.

We adopt CAISO’s modeling methodology for reliability benefits consistent with our adopted Analytical Baseline assumptions as discussed in Section 11.4.

Parties’ Modeling Efforts

Sunrise’s Impact on Local Capacity Requirements

Parties are contesting CAISO's findings on the impact of Sunrise on Local Capacity Requirements in San Diego and the Los Angeles basin Nevada Hydro challenges CAISO's assertion that reductions in Local Capacity Requirements in SDG&E's service area due to TE/VS will be counterbalanced by an equivalent increase in the Los Angeles basin Furthermore, Nevada Hydro argues that both SDG&E and CAISO have applied more rigorous criteria than what is stipulated in the CAISO Grid Planning Criteria In response, SDG&E and CAISO claim that Nevada Hydro has misinterpreted or lacks a proper understanding of the CAISO Grid.

Standards, in particular how they relate to Path 44 336

334 Nevada Hydro Phase 1 Opening Brief, 32.

335 Nevada Hydro Phase 2 Opening Brief, 35.

336 SDG&E Phase 2 Reply Brief, 140 141; CAISO Phase 2 Reply Brief, 14 17.

The DRA contends that SDG&E has inaccurately estimated the reliability benefits of the Sunrise project, presuming it will provide 1,000 MW of reduced Local Capacity Requirements without accounting for the risk of not achieving these benefits They argue that none of the proposed transmission alternatives will significantly enhance local reliability for SDG&E customers and emphasize the need for ongoing monitoring of local reliability, irrespective of decisions made regarding Sunrise Additionally, DRA highlights CAISO reports indicating that Sunrise may actually lead to increased Local Capacity Requirements in San Diego, noting that while it could reduce the need for new generation by 1,000 MW in the local area, the new "South Bay Sub area" will still necessitate contracts with the South Bay Power Plant or system upgrades, and the "Greater Imperial Valley San Diego" area might require up to 3,190 MW of local generation.

CAISO and SDG&E argue that the DRA's analysis is incorrect, stating that resources in the Greater Imperial Valley San Diego area, which currently do not contribute to Local Capacity Requirements, will be included once the Sunrise project becomes operational They emphasize that there are minimal or no additional costs linked to these resources, allowing SDG&E to potentially avoid the need for up to 1,000 MW of new capacity.

339 See, for example, DRA Exhibit D 45.

The combined cycle generators in Mexico, which connect directly to the Imperial Valley substation, are efficient and relatively new, currently supplying power to the CAISO grid As renewable energy projects in Imperial Valley are developed and linked to the Sunrise or Southwest Powerlink, they will fulfill local capacity requirements at minimal cost, as acknowledged by DRA However, CAISO warns that delays in the development of these renewables could significantly diminish reliability benefits, estimating a reduction of $11 million annually if progress is slower than anticipated Notably, SDG&E has not addressed how these delays might affect its reliability benefit forecasts.

UCAN contends that the effects of Sunrise on Local Capacity Requirements remain ambiguous They highlight that under specific contingencies, there are overloads when analyzing Sunrise with all lines operational and 4,200 MW of imports.

(2) under G 1/N 1 conditions and 3,500 MW of imports Because of these overloads, UCAN contends that it is uncertain that Sunrise will increase

SDG&E’s import capacity under contingency conditions by 1,000 MW (thus lowering Local Capacity Requirements) 342 SDG&E claims that upgrades have been completed to address this issue 343

342 UCAN Phase 1 Opening Brief, 55, note 214.

UCAN contends that the Sunrise project is significantly larger than necessary for the demand in the SDG&E service area, highlighting that it surpasses their estimated reliability shortfall of just 6 MW by an excessive 994 MW.

South Bay concurs with CAISO and SDG&E that the Sunrise project will enhance import capacity into San Diego by approximately 1,000 MW However, South Bay argues that local generation can offer greater reliability benefits at a lower cost They express skepticism regarding the availability of additional System Resource Adequacy capacity for import over Sunrise, particularly due to rapid load growth in the Southwest and the Arizona Corporation Commission's recent denial of the Devers-Palo Verde transmission line.

344 UCAN Phase 1 Opening Brief, 55 UCAN ultimately projects a reliability shortfall of

157 MW in 2017 See Table 4 in Section 7 above.

345 South Bay Phase 1 Opening Brief, 11.

Under the Commission’s System Resource Adequacy requirements, load serving entities must secure the necessary capacity resources to meet their overall system load However, they are not obligated to consider local transmission constraints that may hinder the availability of these resources Consequently, while entities may appear resource adequate on a system-wide basis, certain local areas may still face resource deficiencies due to transmission limitations Local Resource Adequacy requirements aim to address this issue by ensuring that if the transfer capability into a local load pocket is insufficient to meet demand, additional generation capacity must be installed within that area to fulfill reliability standards This situation highlights the challenges of establishing out-of-state energy facilities to support California customers.

South Bay concludes that SDG&E will need to procure local generation resources to meet its Local Capacity Requirements, regardless of the construction of the Sunrise project They emphasize that local generation sources, including the existing South Bay Power Plant and its replacement, fulfill both System and Local Resource Adequacy requirements According to the Commission's regulations, imported generation does not qualify as Local Capacity.

Estimating Benefits of Deferred New Generation

SDG&E indicates that the value of combustion turbines deferred by Sunrise reflects the avoided revenue requirement linked to fixed costs In Phase 1, SDG&E projected annual deferred generation savings from Sunrise at around $96 million However, in Phase 2, these anticipated savings have been significantly reduced to approximately $44 million per year.

347 South Bay Opening Phase 1 Brief, 13.

348 South Bay Opening Phase 1 Brief, 13.

350 SDG&E Exhibit SD 26, Exhibit H, Table H 17.

In its final Phase 1 showing, CAISO estimated that without Sunrise

In 2015, an estimated 313 MW of new combustion turbine resources were required, with the value of these additions calculated at $78 per kW per year (adjusted to 2007 dollars and escalated at 2% annually), leading to avoided new generation costs amounting to $115 million each year.

As discussed in Section 6.16, CAISO’s Phase 2 combustion turbine cost estimates increase to $162.10/kW yr (2007$, escalated at 2% per year) The updated combustion turbine costs double CAISO’s projected generation savings to

UCAN contended in Phase 1 that SDG&E exaggerated the costs of combustion turbines by factoring in 138 MW linked to the Pala and Margarita Peakers This inclusion, according to UCAN, inflates the reliability benefits calculations by approximately $15 million annually.

Estimating Must Run Contract Savings

SDG&E estimated the Must Run contract savings of Sunrise to be

$96.7 million 355 per year in Phase 1; its Phase 2 estimate is $104 million per year 356

352 CAISO Exhibit I 12, 8 The assumed increase of $119 million from updated combustion turbine costs was added to the $87 million non Must Run reliability benefits from Exhibit I 6, Table 6.

CAISO estimated the Must Run contract savings of Sunrise to be

In Phase 1, the estimated savings amount to $42 million annually, while Phase 2 is projected at $35 million per year These benefit estimates were calculated by CAISO using a spreadsheet model that analyzed Must Run contract savings across various scenarios and compared the findings to a reference case.

CAISO's modeling approach is based on key assumptions: it presumes that existing Must Run generators will continue to be viable and prepared to accept contracts, even after years without them Additionally, it assumes that all non-Sunrise scenarios yield equivalent RPS-related System Resource Adequacy, irrespective of the in-area renewable generation levels Finally, CAISO's model posits that Sunrise will permanently eliminate the need for new combustion turbines, rather than just delaying their construction.

In Phase 1, the DRA criticized SDG&E and CAISO's Must Run cost estimates as unrealistic, arguing that they included older units likely to retire and unable to operate economically under CAISO's assumptions The DRA projected savings from Must Run contracts due to reduced Local Capacity Requirements by considering several factors: higher combustion turbine costs from SDG&E’s 2008 Peaker RFO, the expectation that all future Must Run contracts would ensure full cost recovery, the retirement of local units without full cost recovery contracts replaced by combustion turbines, and the continued payment by San Diego customers for System.

Resource Adequacy costs to compensate for reduced Local Capacity

Requirements 358 Based on those assumptions, DRA estimated the total reliability benefits associated with Sunrise at $56 million per year in Phase 1, with Must Run contract savings constituting a portion of that 359

In Phase 2, the DRA contends that CAISO incorrectly predicts a decline in Must Run contract prices due to competition, asserting that these prices will remain close to their FERC-established cost of service DRA further argues that many Must Run units are inefficient and challenges CAISO's assumption that they will recover operating costs from the market, suggesting instead that these units will need contracts ensuring full cost recovery Conversely, CAISO argues that the introduction of Sunrise will lessen the reliance on Must Run contracts, allowing for agreements with lower-cost generators and ultimately driving Must Run contract prices below current levels.

UCAN highlights several modifications in the assumptions used by SDG&E and CAISO for Must Run benefits calculations, indicating that both entities are likely to align with UCAN's initial stance over time.

UCAN asserts that SDG&E's modeling relies on the assumption that the existing Encina units can be temporarily shut down and later reactivated instead of investing in more costly combustion turbines They argue that due to the Encina units' inferior heat rates compared to new combustion turbines, these units are unlikely to generate significant operating profits from energy sales As a result, UCAN believes SDG&E cannot anticipate the availability of the Encina units without incurring capacity payments Furthermore, UCAN warns that shutdowns would reduce the number of merchant generators, intensifying competition for resources needed to meet local demand.

Capacity Requirement and the net effect would be the same MW of local capacity sold by fewer merchant generators at a higher price 363

Unquantifiable Reliability Benefits

Parties recognize several difficult-to-quantify reliability benefits associated with alternatives, including reduced fire risks and the overall enhancement of SDG&E’s aging transmission infrastructure SDG&E highlights the unquantified advantages of the Sunrise project, emphasizing its potential to improve reliability and safety in the long term.

• A reduced vulnerability to fires, as Sunrise would not share a corridor with the Southwest Powerlink;

364 Mussey Grade, as well as the EIR/EIS, attempt to quantify some of the fire risks associated with Sunrise and its alternatives Mussey Grades’ efforts are discussed in Section 6.17.2.

• Improved maintenance, as Sunrise would allow for

“maintenance to be performed more readily on all interconnections with less risk”;

• A more robust southern California transmission system;

• Support of future system expansion and interconnection;

• Long term improvement to the aging infrastructure, including facilitating the replacement of aging power plants in the San Diego area and the consequent reduction in airborne emissions;

• Insurance against unexpected high load growth in SDG&E’s service area;

• Reduced uncertainty created by potential qualifying facility contract terminations; and

• Reduced electricity costs by increased competition and fuel diversity in wholesale electricity markets selling into California 365

Parties contest the claimed benefits of the Sunrise project, labeling them as either inaccurate or unverified Conservation Groups assert that placing Sunrise in fire-prone, remote areas heightens fire risks and the system's vulnerability UCAN challenges SDG&E's assertion of enhanced maintenance, suggesting it is unsubstantiated and may lead to increased costs instead Meanwhile, Nevada Hydro contends that TE/VS not only offers all the advantages SDG&E outlines but is also superior by providing a connection to the north rather than an additional link to Arizona.

366 Conservation Groups Phase 1 Opening Brief, 37.

368 Nevada Hydro Phase 1 Reply Brief, 15.

CAISO agrees Sunrise provides future expandability options, but assigns no more than a 50% probability that an expansion would occur in the next ten years 370

Generation alternatives offer several unquantifiable benefits, particularly in terms of reliability that transmission lines cannot match South Bay highlights three key advantages: first, reactive power support helps maintain the transmission system's voltage within required limits, which becomes increasingly crucial as intermittent renewable generation grows Second, the ability for CAISO to dispatch generation resources aids in mitigating intrazonal congestion, addressing the challenges that necessitate the Must Run designation for much of San Diego's existing generation Lastly, the regulation of reserves is vital for ensuring the CAISO grid frequency meets reliability standards and for effectively integrating intermittent renewable resources to meet CAISO load demands.

SDG&E’s “Decision Quality” Framework Modeling

In Phase 2, SDG&E presented an analytical framework for making strategic decisions “involving multiple stakeholders and values, long time

SDG&E has introduced the "Decision Quality" framework to analyze various scenarios and alternatives in a future filled with uncertainty This approach aims to determine the most advantageous course of action for the benefit of SDG&E's customers and stakeholders.

SDG&E employs a modeling framework to assess six decision alternatives based on criteria such as outage risk, service date, GHG impact, RPS compliance, reliability needs, and future expandability While GHG impact and RPS compliance are not focused on reliability, the remaining criteria aim to quantify reliability benefits The analysis yields expected values for each alternative, with outcomes ranging from a 10% to 90% likelihood Ultimately, SDG&E concludes that its “Enhanced” Northern Route is equal to or better than other options, particularly highlighting significant costs linked to outage risks associated with alternative transmission routes.

Parties generally agree on the value of the Decision Quality modeling methodology but challenge the underlying assumptions made by SDG&E The modeling witness from SDG&E indicates that he exclusively depended on SDG&E for all relevant data.

376 The alternatives considered in the modeling were the All Source Generation

Alternative, the In Area Renewable Alternative, the LEAPS Transmission Only

Alternative, Environmentally Superior Southern Route Alternative, the

Environmentally Superior Northern Route Alternative, and SDG&E’s “Enhanced” Northern Route SDG&E Exhibit SD 34c, pages 13.5 13.6. data input into the model, and that he did not verify the data provided by

SDG&E, nor consider other parties’ perspectives regarding that data 377

Planning for and Maintaining Reliability

Pursuant to § 451, SDG&E as an electric utility is required to provide

Electric utilities, as Load Serving Entities (LSEs), are required to provide adequate, efficient, and reasonable services and facilities to ensure the safety, health, and convenience of the public, which includes securing sufficient electricity supplies for their customers The Commission mandates that these utilities plan for and meet the current and anticipated electric demands within their service areas Additionally, SDG&E, as the owner of transmission and distribution facilities, is legally obligated to deliver these services not only to its bundled customers but also to customers of other LSEs operating within its service area, in accordance with state and federal regulations.

In 2010, SDG&E demonstrated a significant reliability deficiency, with its analysis indicating a shortfall of at least 90 MW and potentially reaching up to 247 MW, based on the assumptions outlined in its January 26, 2007 supplemental testimony.

378 See, e.g., SDG&E Exhibit SD 26 at 47

In 2010, while some intervenors questioned the necessity of the Sunrise project, there was a consensus on the grid reliability issues facing the San Diego area, with many acknowledging its critical importance The loss of the Imperial Valley Miguel 500 kV line poses significant reliability challenges for SDG&E and the broader transmission system To address this deficiency, the DRA emphasizes the need for substantial investments in generation and transmission resources in the San Diego area from 2010 to 2020 Both DRA and SDG&E agree that the Sunrise project would offer a more reliable solution for meeting San Diego's energy demands compared to major generation alternatives Additionally, expanding transmission capacity is expected to provide SDG&E and other load-serving entities with greater procurement options beyond relying solely on local generators UCAN also recognizes SDG&E's legitimate reliability needs over the next decade.

Discussion

We find reasonable CAISO’s assumptions regarding Sunrise’s impacts on Local Capacity Requirements in both San Diego and Los Angeles Nevada

Hydro’s showing is unpersuasive; we do not accept Nevada Hydro’s claims that

381 South Bay Exhibit S 8, 5; DRA Exhibit D 66, 60:6 7; UCAN Exhibit U 101, 3.

CAISO and SDG&E have used improper metrics in evaluating TE/VS impacts on Local Reliability Requirements, nor that CAISO failed to perform its studies properly 387

We reject DRA's claims regarding the potential effects of Sunrise on Local Capacity Requirements We concur with CAISO that establishing a Greater Imperial Valley San Diego local reliability area would enable renewable energy generation in the Imperial Valley to meet both Renewable Portfolio Standard (RPS) and Local Capacity Requirement (LCR) obligations.

UCAN's warning about potential technical reliability issues with Sunrise raises significant concerns Neither SDG&E nor CAISO have demonstrated that the criteria violations in Sunrise's power flow and technical modeling are negligible.

We find reasonable CAISO’s modeling approach for avoided new generation costs Among other things, we assume the same combustion turbine costs as those used by CAISO in Phase 2

We concur with UCAN's assessment that SDG&E has inaccurately incorporated the 138 MW from the Pala and Margarita Peakers in its reliability savings forecasts, as both CAISO and our Analytical Baselines account for these peakers.

As a result, they are not counted as reliability savings generated by Sunrise

Our findings in this matter are intended solely for this proceeding and will not set a precedent for any future cases, including the currently pending TE/VS CPCN Application.

388 CAISO Phase 2 reply brief at 7 8; SDG&E Phase 2 reply brief at 259 261;

We question certain assumptions in CAISO's modeling of Must Run contract savings, particularly regarding the long-term availability of potential Must Run generators without contracts While we are uncertain about the permanent avoidance of new combustion turbines due to Sunrise, we believe that its construction will eliminate the need for some turbines and significantly delay others.

After careful consideration, we conclude that the CAISO’s reliability benefits modeling approach is more effective than other methodologies Therefore, we will implement the CAISO’s reliability benefits modeling methodology in alignment with our established Analytical Baseline assumptions, as detailed in Section 11.4.

The Commission recognizes the challenges in resource planning and development, particularly the uncertainty in predicting the retirement of aging power plants This difficulty in forecasting the exact timing of infrastructure additions, whether in generation or transmission, adds further complexity to capacity planning and development initiatives.

Permitting, siting, and constructing generation projects in California has become increasingly difficult, leading to project delays that are now more common than ever The evidence indicates that SDG&E will encounter significant capacity challenges as a result of this challenging regulatory environment.

389 See, LTPP Decision, 85 86, D.07 12 052, D.08 02 019, and D.08 11 004. shortfall The difficult question to answer is exactly when this shortfall will occur

During the proceedings, parties utilized modeling efforts to assess the need, costs, and benefits of the proposed project and its alternatives However, it is crucial to understand that the model does not aim to accurately forecast the future or dictate resource procurement activities Actual resource development will follow the procurement processes defined by statutory regulations and Commission decisions.

Given California's challenging permitting environment, we believe that relying solely on in-basin generation to meet SDG&E's long-term capacity needs is not a viable solution While conventional peaking resources may address short-term reliability issues, they are inadequate for ensuring long-term system reliability Experience from other service territories shows that short-term, 'just in time' procurement is inefficient, costly, and poses significant risks, potentially conflicting with the State's loading order Therefore, it is not a sustainable strategy for meeting the reliability needs of SDG&E's ratepayers.

The transmission alternatives discussed in this proceeding demonstrate significant reliability benefits, both measurable and intangible, prompting us to support a transmission solution that addresses SDG&E's reliability requirements.

The 390 LTPP Decision highlights that the Sunrise transmission solution offers SDG&E the optimal opportunity to address both current and future reliability requirements across its service area This approach not only satisfies SDG&E’s reliability needs but also promotes the development of renewable energy resources, aligning with state policies aimed at reducing greenhouse gas emissions Additionally, we concur with SDG&E that the Sunrise solution will yield several valuable, albeit unquantifiable, reliability benefits.

Sunrise will enhance the transmission system in Southern California, offering protection against unforeseen increases in load within SDG&E's service area, a benefit that generation alternatives cannot match.

As discussed elsewhere in this decision, the environmental review will guide us in determining the final environmentally superior route for the Sunrise Project

We do not consider the outcomes of SDG&E’s Decision Quality modeling to be credible Although the modeling methodology might have some validity, the assumptions made by SDG&E in their modeling were not substantiated and could potentially contradict our established Analytical framework.

10 Potential Savings from Accessing Least Cost

What They Are

The RPS law requires utilities to engage in renewable energy procurement, 391 and SDG&E claims that Sunrise is needed to support the cost

391 See, e.g., § 399.12. effective development of Imperial Valley renewables One way to support

SDG&E aims to show that the development of the Sunrise project will facilitate access to more affordable renewable resources compared to those available without the project However, due to the recent establishment of the Renewable Portfolio Standards (RPS), there is currently no standardized method for measuring these potential savings.

The Renewable Energy Transmission Initiative (RETI), launched in mid-2007, aims to identify and prioritize developable renewable resource areas in California based on economic and environmental criteria, with a report expected by the end of 2008 Although RETI was not established when SDG&E submitted its 2006 Application, CAISO recognized the necessity of assessing the value of developing Imperial Valley renewables relative to other areas To address this, CAISO created a new modeling approach to estimate the annual levelized ratepayer benefits of prioritizing one renewable resource area over another.

While lacking the environmental, engineering, and updated RPS cost components included in the RETI analysis, CAISO’s modeling of renewable resource savings associated with various renewable resource areas provides

392 Additional information about RETI is available at http://www.energy.ca.gov/reti/index.html. useful information regarding Sunrise’s cost impacts on renewable development in the Imperial Valley.

Overview of Conclusions

We commend CAISO for its renewable resource savings modeling effort and have adopted its methodology However, we disagree with several key assumptions in CAISO's final showing, specifically rejecting its Alternative Renewable Costs and the assumption that only 25% of out-of-state renewable resources will be available to California Instead, our adopted Analytical Baseline incorporates CAISO's CRS Renewable Costs and assumes that 50% of out-of-state renewable resources will be accessible to California Additionally, we take a different approach when the model indicates the development of Imperial.

The integration of renewable resources in the Valley could lead to increased costs In the Sunrise cases, CAISO determined that the most cost-effective renewable resources would be available regardless of the construction of Sunrise Conversely, in the All Source Generation Alternative, CAISO assumed that San Diego's renewable resources would be utilized even if they were pricier than other options We argue that CAISO's methodology in the Sunrise cases is more logical, prompting us to adjust the All Source Generation approach accordingly.

The model finds that building Sunrise will not result in potential savings from accessing least cost renewable resources assuming a 20% RPS However, significant savings could be achieved assuming a 33% RPS.

How CAISO Estimates Potential Renewable Resource Savings

CAISO's analysis of potential renewable resource savings is based on specific assumptions regarding California's Renewable Portfolio Standard (RPS) program It anticipates that SDG&E and other load-serving entities within CAISO's jurisdiction will achieve a 20% RPS by 2010, with plans to increase renewable procurement to 26.5% by 2015 and 33% by 2020 Additionally, CAISO expects that 75% of non-Commission regulated utilities will voluntarily meet the 20% RPS target by 2010 and 33% by 2020.

CAISO created "least cost" supply curves by identifying all Renewable Portfolio Standard (RPS) eligible generation resources within the Western Electricity Coordinating Council (WECC) that could be developed and delivered to California in the years 2010, 2015, and 2020 The organization then estimated the costs associated with these resources utilizing its CRS Renewable Costs methodology.

CAISO aggregated the renewable resources it identified into 17 geographic

“resource areas” and averaged the cost of each resource area 396 CAISO added transmission related costs to each resource area to arrive at a levelized cost of

394 CAISO Phase 1 Opening Brief, 30; see also CAISO Exhibit I 2, 31.

395 Table 4.3 at CAISO Exhibit I 2, 52 presents CAISO’s assumed generation related costs by type and location Costs presented in this table do not include delivery costs to the CAISO grid.

CAISO Exhibit I 2, 52 outlines the resource costs categorized by area, detailing the delivered renewable resources from each region After determining the quantity and levelized delivered cost of power for each resource area, CAISO ranked them from lowest to highest cost to formulate a renewable supply curve Figure 1 illustrates CAISO's initial supply curve before any subsequent adjustments were made.

397 CAISO Exhibit I 2, Table 4.5, 54 presents CAISO’s assumed transmission costs by resource area.

Figure 1: CAISO’s Initial Supply Curve of Potential Renewable

To Meet Varying RPS Levels in California 398

The CAISO’s model assumes the 20%, 26.5%, and 33% RPS targets will be met through the delivery of the lowest cost renewable resources available to

California's Renewable Portfolio Standard (RPS) goals illustrate the state's commitment to sustainable energy The 20% RPS target is primarily achieved through local distributed resources, while the 26.5% goal incorporates resources from Tehachapi To reach the 33% target, additional resources are sourced from the Reno area, Montana, and Southern Oregon Figure 1 depicts the supply curve before adjustments, emphasizing the diverse energy sources contributing to California's renewable energy landscape.

The supply curve indicates that if all renewable resources were fully developed, the Imperial Valley would deliver more energy than Sunrise, as shown in CAISO Exhibit I 2, Figure 4.1 This section is referred to as "Imperial Valley Sunrise."

Renewables) would only be delivered if the RPS target were above 33% 399

In Phase 1, CAISO modeled three cases: (1) Sunrise is online by 2010;

By 2010, the Green Path and TE/VS projects became operational, alongside the 620 MW South Bay Replacement Project Additionally, CAISO established a combustion turbine reference case, projecting 565 MW of capacity to be online by 2015.

CAISO developed three distinct resource portfolios tailored to the specific scenarios modeled, with projected levels of renewable development in Imperial Valley outlined in Section 6.10 These projections indicate that all scenarios anticipate approximately 700 MW of renewable energy capacity, both with and without the Sunrise project.

Imperial Valley's geothermal resources are self-sufficient and expected to be operational by 2010, identified as "Imperial – Path 42." CAISO believes that enhancing transmission to the Imperial Valley will facilitate increased renewable energy development in the region.

399 See CAISO Exhibit I 2, Table 4 3, 52 for a more specific listing of the generation resources.

400 In Phase 2, CAISO assumes Sunrise is online in 2011, South Bay Replacement Project is online in 2010, and Green Path + TE/VS + LEAPS is online in 2012 CAISO

The analysis presumes sufficient capacity on Path 42 between the Imperial Valley and Edison, considering the levels of renewable development in the Imperial Valley since 2011 To facilitate this, CAISO prioritizes the Imperial Valley Sunrise Renewables in the supply curve, despite their higher projected costs, effectively replacing more expensive resources that would otherwise be utilized With an anticipated greater transfer capability than the Green Path, CAISO forecasts a larger inclusion of Imperial Valley Sunrise Renewables in its resource portfolio by 2015, comprising 1,000 MW of geothermal and 900 MW of solar thermal, compared to the Green Path + LEAPS portfolio, which includes 1,341 MW of geothermal and 667 MW of solar thermal.

CAISO has revised its renewable supply curve assumptions, reducing the projected out-of-state renewables delivered to California to 50% This adjustment reveals that the levelized costs of Imperial Valley Sunrise Renewables, at $109/MWh, are higher than those of other renewable sources until 2020 However, starting in 2020, these costs become lower than a small amount of renewable resources from British Columbia, leading to annual savings of $5 million Prior to 2020, the estimated costs for Imperial Valley Sunrise Renewables remain significantly higher than those from other regions.

CAISO's model calculates renewable resource savings by assuming that renewables delivered through alternatives, such as Imperial Valley renewables for Sunrise and San Diego renewables for All Source Generation, replace the highest-cost renewables that would otherwise be used In Sunrise scenarios, if Imperial Valley Sunrise Renewables are more costly than the resources they displace, the potential renewable savings are considered zero Conversely, in All Source Generation cases, CAISO assumes that San Diego renewables would be delivered regardless of their cost, leading to negative renewable energy savings in some instances.

CAISO introduced a second renewable cost scenario that incorporates reduced generation costs for solar thermal energy and increased costs for wind projects Additionally, the modeling was revised to reflect that only 25% of out-of-state renewables would be available to satisfy the Renewable Portfolio Standard (RPS), rather than the previously assumed 50% As a result of these adjustments, CAISO projects that the Sunrise initiative could yield $228 million in potential savings from renewable resources beginning in 2015.

405 CAISO Exhibit I 2, 67 We see this result in CAISO’s Compliance Exhibit, discussed below.

The 406 CAISO projects indicate a lack of wind resources in the Imperial Valley, while highlighting its abundant solar thermal potential As outlined in Section 6.10, CAISO's updated renewable cost assumptions enhance the economic viability of renewable energy in the Imperial Valley compared to other regions that rely on wind resources.

Discussion

The California Independent System Operator (CAISO) renewable savings model differs significantly from the Renewable Portfolio Standard (RPS) program implemented by the Commission According to RPS statutes and Commission decisions, investor-owned utilities are required to conduct periodic solicitations for renewable resources These utilities employ a "least cost" and "best fit" evaluation method to select resources, considering quantitative factors such as curtailability, dispatchability, local reliability, and repowering, alongside qualitative factors like benefits to low-income or minority communities, environmental stewardship, local reliability, and resource diversity Selected renewable contracts are then submitted to the Commission for approval.

Commission approves or denies resources based on a number of factors, of which cost is only one Since 2002 the Commission has approved at least

95 contracts with renewable resources for 5,900 MW including 61 contracts with new renewable projects, totaling 4,480 MW, all under the existing RPS framework 410

The contracts approved by the Commission differ from the least cost resources identified in CAISO's analysis Specifically, the model's assumptions indicate that distributed renewable sources, such as urban municipal waste and landfill gas, could play a significant role in resource allocation.

The 410 Renewables Portfolio Standard Quarterly Report from July 2008 indicates that distributed renewable resources constitute a minor fraction of the total resources approved by the Commission to achieve the 20% Renewable Portfolio Standard (RPS) There is uncertainty regarding the existence of developers for these distributed sources and whether utilities can procure them effectively The Commission has sanctioned a diverse range of resource types, including wind, geothermal, and solar, which vary in size and are located throughout California and beyond However, many of these approved resources are identified as relatively higher-cost options in the California Independent System Operator's (CAISO) analysis.

We utilize CAISO’s modeling methodology in this proceeding to effectively identify potential cost savings from renewable resources associated with the construction of Sunrise and other alternatives If Sunrise or similar projects grant access to lower-cost renewable resources, the CAISO model serves as a reliable tool for estimating these potential savings.

CAISO's assumptions regarding least cost result in a reference case where renewable resource costs are significantly lower than anticipated by the Commission As alternatives are evaluated against this least cost scenario, the estimated savings likely fall short of reflecting the actual potential cost savings associated with these alternatives.

In Section 6.13, we clarify that we do not accept CAISO's Alternative Renewable Costs or its assumption that only 25% of out-of-state renewables will be accessible to California Instead, we choose to adopt CAISO's CRS Renewable Costs from its initial modeling and assume that 50% of out-of-state renewables will be available to California Consequently, we reject the final outcomes of CAISO's renewable resource cost modeling.

DRA highlighted that CAISO's Compliance Filing model did not permit renewable resource benefits to drop below zero, which could potentially raise the total costs of renewable resources in the 20% RPS Sunrise scenarios Nonetheless, we find CAISO's methodology in these Sunrise cases to be justifiable.

CAISO's model is based on the principle that the most affordable renewable energy sources should be prioritized for delivery Consequently, it would be contradictory to expect that the more expensive renewable energy from the Imperial Valley would be utilized solely due to the construction of the Sunrise project Therefore, when estimating potential savings from accessing the least costly renewable resources, it is reasonable to conclude that the savings could be, at most, zero.

In the All Source Generation Alternative, CAISO considered the possibility of negative savings from renewable resources To maintain a consistent approach across all scenarios, it is assumed that the more costly renewable resources will not be included in the All Source Generation framework.

Alternative; therefore, the renewable resource savings would be zero

Applying our adopted Analytical Baseline assumptions, the model finds that Sunrise will not result in renewable resource savings assuming 20% RPS However, Sunrise potentially generates significant savings assuming 33% RPS.

411 DRA Opening Comments on Compliance Exhibit, 6

The findings should not be misconstrued to suggest that renewable energy from Imperial Valley will be hindered by the construction of Sunrise or the retention of a 20% Renewable Portfolio Standard (RPS) Evidence indicates that Sunrise will actually promote significant renewable development in the Imperial Valley, despite the RPS cap The Commission has already sanctioned multiple utility contracts for renewable projects in the area It is important to view the model as a theoretical estimate of potential savings based on idealized assumptions, rather than a precise forecast of future outcomes The actual realization of RPS projects will depend on the statutory processes and decisions made by the Commission.

The model's conclusion that Sunrise will not produce renewable resource savings under a 20% Renewable Portfolio Standard (RPS) should be contextualized While the California Independent System Operator's (CAISO) modeling is useful for estimating potential savings, actual cost savings may arise from discrepancies between the model's assumptions and the RPS program's implementation Additionally, the approval of several contracts with Imperial Valley resources indicates the presence of appealing renewable resources in the region.

The estimates of energy and reliability benefits from the Proposed Project and its alternatives differ significantly among parties, with CAISO being the only entity to attempt an estimation of potential savings from accessing low-cost renewable resources To determine net benefits, we aggregate energy benefits, reliability benefits, and renewable resource savings, then deduct project costs To illustrate the magnitude of these net benefit estimates, we compare the Proposed Project and its alternatives against a reference case that assumes the addition of combustion turbines to fulfill future reliability requirements.

Overview of Conclusions

Given parties’ changing assumptions about combustion turbine costs, renewable costs, capital costs, and other assumptions, their net benefit calculations also changed throughout the proceeding

Recognizing these disparities, and in an attempt to bring clarity to this proceeding, the Revised Scoping Memo directed CAISO to prepare a Compliance

413 Essentially, SDG&E assumed that the project would not provide any benefits of reducing renewable resource costs, since it assumed the same level of renewables in all scenarios.

We evaluate the three benefits in comparison to a reference case, where transmission costs are included in the expenses of new combustion turbines Consequently, we do not deduct Sunrise costs from the reference case's transmission costs to assess net benefits.

The Compliance Exhibit establishes a comprehensive set of consistent and reasonable assumptions for various scenarios, similar to those used in current decision-making processes By adjusting the assumptions related to RPS compliance requirements and the prices of renewable and combustion turbine technologies, the exhibit evaluates the net benefits produced by three distinct alternatives.

“Enhanced” Northern Route, the Draft EIR/EIS Environmentally Superior

Southern Route, and the All Source Generation Alternative 416 relative to a combustion turbine reference case (Reference Case) In summary, the

The Compliance Exhibit concludes that there are no net benefits associated with any alternatives under the current 20% Renewable Portfolio Standard (RPS) However, it identifies that the Draft EIR/EIS's Environmentally Superior Southern Route offers slightly higher net benefits compared to SDG&E’s “Enhanced” Northern Route Alternative when evaluated under a 33% RPS Additionally, it indicates that there are positive net benefits for the non-wires alternatives.

Source Generation Alternative only under specific combustion turbine and renewable cost assumptions.

In response to discovered errors and comments by parties, and to analyze the Compliance Exhibit’s three alternatives using the Analytical Baseline

The Analytical Baseline assumptions utilized in this analysis differ from those in the Compliance Exhibit prepared by CAISO, as they were not available at that time We address these discrepancies in an upcoming Update.

The "Enhanced" Northern Route and the Draft EIR/EIS Environmentally Superior Southern Route Alternatives represent all Sunrise transmission routes, assumed to yield equivalent gross benefits while differing only in capital costs Therefore, we collectively refer to these scenarios as "Sunrise," as modeled in the Compliance Exhibit and the Update We have also updated the Compliance Exhibit based on the assumptions outlined in Section 11.4.

Based on the results of the Update we find that, assuming a 20% RPS, Sunrise would result in significant economic benefits for ratepayers The

Implementing an All Source Generation Alternative could lead to even greater net benefits With a 33% Renewable Portfolio Standard (RPS), Sunrise is projected to deliver over $115 million annually in net benefits, surpassing the All Source option by $24 million each year.

Generation Alternative Adding the unquantifiable benefits of a transmission alternative to our consideration, we find that Sunrise is the superior alternative for meeting SDG&E’s longer term reliability needs economically.

Parties’ Modeling Efforts

SDG&E's net benefit estimates have significantly decreased over the course of the proceedings, with energy benefits being the main contributor Initially estimated at $468 million per year in its 2006 Application, this figure dropped to $105 million per year by the conclusion of the Phase 1 hearings.

The analysis reveals that the energy benefits from Sunrise fluctuate significantly, with net benefits reported by SDG&E ranging from $57 million annually in 2005 to $447 million in 2006, before decreasing to $142 million by the end of Phase 1 and further dropping to $41 million thereafter This variation is assessed against a combustion turbine reference case, demonstrating the dynamic nature of these benefits over time.

417 See note 338, above. compared to a combustion turbine reference case applying SDG&E’s own

Analytical Baseline Table 9 presents SDG&E’s changing net benefit estimates for the Proposed Project 418

Table 9: SDG&E Estimates of Net Benefits

2006 Application, Chapter IV, pages IV 8 to V 9 621 174 447 3.57:1

Sunrise compared to combustion turbine reference case 421 201 160 41 1.26:1

Likewise, CAISO’s net benefit showing has varied – from $52 to

The estimated annual costs for renewable energy range from $145 million to $318 million, depending on whether lower renewable costs or alternative renewable costs are considered In Phase 1, CAISO projected that the net benefits of the Sunrise project under a 33% Renewable Portfolio Standard (RPS) could vary between $52 million and $226 million.

The gross benefits outlined in Table 9 are applicable to Sunrise, irrespective of its routing However, the costs associated with the different Sunrise routes vary, leading to differences in net benefits when these costs are considered.

419 Correction to Amended Application of San Diego Gas & Electric Company,

January 19, 2007, pages IV 8 to IV 9; see also SDG&E Exhibit SD 6, pages IV 8 to IV 9.

Section 6.13 outlines the renewable costs, with lower estimates based on CAISO’s CRS Renewable Costs and higher estimates reflecting CAISO’s Alternative Renewable Costs, which include increased wind and reduced solar thermal costs Additionally, the higher estimates consider only 25% of out-of-state renewable resources accessible to California.

In Phase 2, CAISO estimates that the Sunrise project, under a 33% Renewable Portfolio Standard (RPS), will yield annual net benefits ranging from $145 million to $318 million This increase in projected benefits compared to Phase 1 is primarily due to revised assumptions regarding higher combustion turbine costs, which have a dual impact: they enhance reliability benefits, thus boosting net benefits across all alternatives, while simultaneously raising costs for options reliant on combustion turbines, leading to a decrease in their net benefits Table 10 illustrates CAISO's updated net benefit projections for the Proposed Project, based on CRS Renewable Costs and the assumption of a 33% RPS.

Table 10: CAISO Estimates of Net Benefits Under 33% RPS Assuming

CRS Renewable Costs (Annual Levelized $ Millions)

Table 11 below presents CAISO’s changing net benefit estimates for the Proposed Project, using CAISO’s Alternative Renewable Costs and assuming 33% RPS

425 Benefit/Cost Ratios = Gross Benefits/Costs.

426 Benefits and costs are NPV 2010$.

427 Benefits are 2015 nominal dollars and costs are levelized costs of transmission.

Table 11: CAISO Estimates of Net Benefits Under 33% RPS Assuming

CAISO’s Alternative Renewable Costs (Annual Levelized $ Millions)

Errata to Rebuttal Testimony, Phase 1)

Many parties, excluding SDG&E and CAISO, contend that the Sunrise project will provide minimal or no net benefits, potentially leading to increased costs for ratepayers UCAN argues that SDG&E exaggerates the advantages of Sunrise while downplaying its expenses and inflating the costs associated with the baseline combustion turbine scenario.

In its analysis, UCAN projected that the Sunrise project would incur an additional cost of $81 million annually for ratepayers compared to its combustion turbine reference case in Phase 1 By Phase 2, this projected cost decreased to $74 million per year more than the combustion turbine reference case, and it could reach up to $120 million annually compared to other alternatives Conversely, UCAN estimates positive net benefits for its own all-source generation alternative but does not provide net benefit estimates for other options.

428 Benefit/Cost Ratios = Gross Benefits/Costs.

In Phase 1, the DRA projected that the Sunrise project would incur an additional annual cost of $37.8 million compared to the combustion turbine reference case, leading to a benefit-cost ratio of 0.76:1 In Phase 2, the DRA asserted that, despite SDG&E implementing several recommended corrections, the economic justification for the project remains "deeply flawed," and further adjustments could lower the benefit-cost ratio below one.

Not all stakeholders have provided estimated net benefits or benefit-cost ratios for the Proposed Project and its alternatives Furthermore, those who did offer estimates did not assess the net benefits of all options To illustrate the differences in calculations among the parties, Table B 3 in Appendix B displays the final net benefit and benefit-cost ratios for the Proposed Project and its alternatives.

The analysis reveals that incorporating Sunrise after the construction of TE/VS and Green Path results in a reduction of net benefits, indicating that Sunrise does not contribute any additional advantages.

• Southern Route Alternatives generally provide larger net benefits than Northern Route Alternatives;

• There is an enormous disparity in parties’ estimated net benefits for TE/VS and LEAPS; and

• Only DRA provided a range of net benefits, even though

SDG&E was required to provide sensitivity analysis.

CAISO’s Compliance Exhibit

Overview

The Revised Scoping Memo instructed CAISO to create a Compliance Exhibit that includes additional model runs based on specified assumptions CAISO suggested changes to these assumptions, and the final modeled assumptions are detailed in Table B1 of Appendix B.

The assumptions in the Compliance Exhibit align with the Analytical Baseline assumptions established in this proceeding The Revised Scoping Memo instructed CAISO to apply its preferred modeling assumptions from Phase 2 when not specified Additionally, CAISO was tasked with assessing the operational grid impacts of each alternative, along with estimating their energy benefits, reliability advantages, and RPS compliance savings In cases where CAISO identified specific alternatives as equivalent, it refrained from conducting separate analyses.

In August 2008, CAISO developed a draft Compliance Exhibit featuring initial estimates of net benefits, which was discussed during a workshop on August 22, 2008 During this workshop, stakeholders reviewed CAISO's methodology and provided feedback, leading to revisions in the draft based on the comments received.

434 Consistent with the Revised Scoping Memo, the Compliance Exhibit, including its Work Papers, has been received in evidence as Exhibit Compliance 1 It is the only

The Compliance Exhibit estimates net benefits for 13 cases, based on three alternatives:

• The Draft EIR/EIS Environmentally Superior Southern Route; and

• The All Source Generation Alternative.

Cases 2 4 in the Compliance Exhibit present net benefits for each alternative under 20% RPS Cases 6 8 present net benefits under 33% RPS All of these cases assume the CAISO’s lower Phase 1 combustion turbine costs Case 9 presents net benefits assuming Sunrise comes online in 2011, rather than 2012, as assumed for all the other cases 436 CAISO added cases 11 13, which estimate net benefits under 33% RPS using the higher combustion turbine costs it assumes in Phase 2 CAISO used SDG&E’s estimated capital costs for the alternatives, consistent with our adopted Analytical Baseline assumptions However, to provide a range of renewable resource costs for the All Source Generation compliance exhibit in the record

435 Net benefits for each case are estimated relative to the three combustion turbine Reference Cases, Cases 1, 5, and 10.

Due to the reasons outlined in Section 15.5, the Compliance Exhibit and our Update project that SDG&E’s Enhanced Northern Route will be operational in 2012, contrary to the 2011 timeline proposed by SDG&E and CAISO.

Alternative, CAISO also ran Cases 4b, 8b, and 13b using its CRS Renewable Costs, consistent with our adopted Analytical Baseline assumptions

To assess the gross benefits of each alternative based on new assumptions, CAISO aimed to evaluate energy benefits, reliability benefits, and potential renewable resource savings compared to a reference case However, due to time constraints and challenges in data development, CAISO opted not to conduct new GridView runs with the Revised Scoping Memo assumptions, which are essential for estimating energy benefits The existing evidence indicated that energy benefit calculations were complex and required further analysis.

The updated assumptions in the Revised Scoping Memo indicate that annual energy benefit estimates will be below $34 million, which is relatively insignificant compared to the overall value of other benefits being considered Consequently, rather than conducting new production cost models to determine energy benefits, CAISO opted to derive these estimates from previous production cost modeling results.

CAISO calculated reliability benefits and renewable resource savings — the first and second most significant benefits on a dollar basis — using its own spreadsheet models, which were made available to parties

CAISO presented load and resource tables to support the Compliance Exhibit These tables show that there is no need for additional in area generating

437 The cost of the transmission alternatives are not impacted by renewable costs.

In 438 CAISO, stakeholders received detailed work papers outlining the proposed methodology, allowing them to provide feedback on the approach It is anticipated that capacity constraints will persist until at least 2014, largely based on the assumption that the South Bay Power Plant will remain operational through 2012.

Carlsbad Energy Center (which replaces Units 1 3 at the Encina Power Plant) will come online before Summer 2013

Table 5 in Section 7, above summarizes by year the Compliance Exhibit findings we adopt regarding the reliability need in SDG&E’s service area

The 13 cases (plus the 3 cases using CAISO’s CRS Renewable Costs) modeled by CAISO and their estimated net benefits are set forth in Table 12 below Table 13 shows the major components of the net benefit calculation — energy benefits, reliability benefits, potential renewable savings, and cost The Compliance Exhibit shows:

• Under 20% RPS, all of the generation and transmission alternatives are more expensive than the combustion turbine reference case, assuming the lower Phase 1 combustion turbine costs (Cases 2 through 4b);

• Under 33% RPS assuming the lower Phase 1 combustion turbine costs, the “Enhanced” Northern Route and the Draft EIR/EIS

Environmentally Superior Southern Route Alternatives have positive net benefits of $22 and $25 million per year, respectively (Cases 6 and

7) The Southern Route has higher net benefits because of its lower projected capital costs;

• Under 33% RPS assuming the substantially higher Phase 2 combustion turbine costs, the projected net benefits of the “Enhanced”

Northern Route and the Draft EIR/EIS Environmentally Superior

Southern Route Alternatives are 5 to 6 times greater (at $129 and $132

439 Compliance Exhibit, 6 8. million per year, respectively) than estimates under the lower Phase 1 combustion turbine costs (Cases 11 and 12 compared to Cases 6 and 7);

• Under all RPS scenarios and combustion turbine cost assumptions, the All Source Generation Alternative is not economic using SDG&E’s proposed renewable costs (Cases 4, 8, and 13);

• Assuming CAISO’s CRS Renewable Costs, the lower Phase 1 combustion turbine costs, and 33% RPS, CAISO estimates that the All

Source Generation Alternative produces net costs of $3 million per year

• Assuming CAISO’s CRS Renewable Costs, the higher Phase 2 combustion turbine costs, and 33% RPS, CAISO estimates that the All

Source Generation Alternative produces net benefits of $49 million per year (Case 13b); and

• Delaying the online date of the “Enhanced” Northern Route from 2011 to 2012 increases the net benefits of that alternative by $2 million per year (compare $22 million per year in Case 6 assuming a

2012 online date to $20 million per year in Case 9 assuming at 2011 online date) 440

440 This is consistent with CAISO’s results from Phase 1, which showed that 2010 was not the optimal online date for Sunrise.

Table 12: Summary of CAISO Compliance Exhibit

Net Benefits Relative to Reference Case ($ million)

441 In Phase 1, the CAISO estimated combustion turbine costs at $78/kW year In

Phase 2, the CAISO revised this estimate to $162.10/kW year (both 2007$, escalated at 2% per year)

Table 13: Costs and Benefits in CAISO Compliance Exhibit

Net Benefits Relative to Referenc e Case

NOTE: Components may not sum to total due to rounding.

Production cost modeling for the Compliance Exhibit could have clarified the implications of committing to only 25% of the coal-fired generation anticipated in the WECC In lieu of this modeling, we find CAISO’s energy benefit estimates, derived from previous production cost analyses, to be reasonable Consequently, this methodology leads to an estimated annual Sunrise energy benefit of $5 million for scenarios with a 20% Renewable Portfolio Standard (RPS).

$18 million per year for 33% RPS cases CAISO assumed the All Source

Generation Alternative would provide no energy benefits.

Multiple stakeholders have submitted feedback on the Compliance Exhibit UCAN points out that if the California Solar Initiative program is expected to succeed, the solar PV costs associated with it should not be considered incremental costs for the All Source Generation alternatives, as these costs are already accounted for within the California Solar Initiative program Furthermore, CAISO acknowledged that it did not adjust the Sunrise costs to incorporate UCAN's operations and maintenance estimates.

442 UCAN Comments on Compliance Exhibit, 9. relying on the operating and maintenance assumptions from the CAISO’s

Compliance Exhibit for our Analytical Baseline assumptions.

Discussion

The Compliance Exhibit highlights the impact of changes in Renewable Portfolio Standards (RPS) compliance requirements and the prices of renewable and combustion turbines on the net benefits of the Sunrise and All Source Generation Alternatives compared to the Reference Case It indicates that none of the alternatives are economically viable under a 20% RPS However, under a 33% RPS with low combustion turbine costs, the exhibit reveals that while the net benefits of transmission alternatives are positive, they are minimal, and the generation alternatives incur negative net benefits, indicating additional costs rather than savings.

CAISO's Phase 2 combustion turbine costs, used as our Analytical Baseline, indicate that the transmission alternatives yield significantly higher net benefits compared to All Source Generation.

Alternative, regardless of renewable cost assumptions

Under a scenario with a 33% Renewable Portfolio Standard (RPS), the costs associated with CAISO Phase 2 combustion turbines, and CAISO CRS renewable costs, the Compliance Exhibit indicates that Sunrise will generate net benefits surpassing those of the All Source Generation Alternative by about $80 million annually.

443 Using SDG&E’s renewable costs for the All Source Generation Alternative increases the relative benefit of Sunrise to nearly $110 million per year.

The Commission’s Update to the Compliance Exhibit

Overview

We have utilized our established Analytical Baseline assumptions to create an Update to the Compliance Exhibit To determine the net benefits for this Update, we employed the same spreadsheet models used by the CAISO for the original Compliance Exhibit, while revising the input assumptions in these models.

In our Update, we have applied CAISO’s Phase 2 combustion turbine costs specifically to the 20% RPS scenarios Additionally, we identified and corrected four key changes in the Compliance Exhibit Notably, CAISO previously used an inaccurate mix of generation resources for the All Source Generation cases, leading to an overestimation of renewable energy contributions The initial assumptions included 300 MW of solar thermal, 400 MW of wind, 100 MW of biomass/biogas, and 210 MW of solar PV by 2016, which reflected the total renewable capacity outlined in the EIR/EIS for the In Area Renewable Alternative Our Update rectifies this oversight.

200 MW of wind, 50 MW of biomass/biogas, and 210 MW of solar PV by 2016, as specified for the All Source Generation Alternative 445

Second, we agree in part with UCAN’s observation that the solar PV costs associated with the 105 MW (firm capacity) due to the California Solar Initiative

444 No party noted this error in the Draft Compliance Exhibit workshop or in their

All capacity values are based on nameplate ratings and should not be added to the Reference Case for cost estimates of the All Source Generation Alternative Instead of subtracting all solar PV costs, we project that by 2016, a specific assumption will be made regarding these expenses.

The All Source Generation Alternative includes the addition of 37 MW of firm solar PV capacity, funded through the California Solar Initiative, meaning these costs are not associated with the All Source Generation project.

Alternative 446 Both of these changes result in lower cost estimates for the

Third, we assume that least cost renewable resources will be delivered in all cases This change affected the All Source Generation alternative

Fourth, we adjust the CAISO’s assumed costs for the Draft EIR/EIS

Environmentally Superior Southern Route to be consistent with SDG&E’s cost estimates for the Final Environmentally Superior Southern Route we approve here

In summary, our Update makes the following changes to the Compliance Exhibit:

• We assume CAISO’s Phase 2 combustion turbine costs for all cases;

446 In 2016, our adopted Analytical Baseline assumes 33 MW (firm) of solar PV

SDG&E estimates its firm capacity under the California Solar Initiative to range from 70 MW to 150 MW, with a conservative assumption of 70 MW for its installed capacity.

California Solar Initiative, meaning that the costs of 37 MW (70 MW – 33 MW) beyond our Analytical Baseline should not be attributable to the All Source Generation

• We adjust 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;

To account for the 37 MW of solar PV that has already been funded, we deduct $367 million annually from the projected capital cost of the All Source Generation Alternative across all scenarios.

• We adjust the treatment of renewable resource savings for the

All Source Generation Alternative so that least cost renewable resources are delivered in all cases; and

• We update the capital cost estimate for the Modified Southern

Route to match the revised cost estimate of $1.883 billion adopted in this decision.

Table 14 summarizes the net benefits given these changes Table 15 provides further detail on the major benefit and cost components for each case.

447 We assume CAISO’s CRS Renewable Costs for solar PV Assuming SDG&E’s estimated solar PV costs, we would subtract $776 million from the cost of the All SourceGeneration Alternative.

The Update generates the following results:

Table 14: Commission Update to Compliance Exhibit

CAISO Compliance Exhibit Net Benefits

20% CRS RPS Costs Phase 1 33 Phase 2 93

33% CRS RPS Costs Phase 1 3 Phase 2 93

33% CRS RPS Costs Phase 2 49 Phase 2 93

Table 15: Costs and Benefits in Commission Update

Net Benefits Relative to Referenc e Case

NOTE: Components may not sum to total due to rounding.

Discussion

The Update differs from the preliminary findings in the Compliance

Exhibit Unlike the Compliance Exhibit, the Update estimates that assuming a 20% RPS, Sunrise will result in significant cost savings for ratepayers—nearly

Assuming the Southern Route, the projected annual benefits amount to $40 million, primarily driven by the CAISO Phase 2 combustion turbine costs In contrast, the All Source Generation Alternative significantly boosts these benefits to $93 million per year, as it is based on the premise that the least cost renewable resources will be consistently available.

Source Generation Alternative has higher net benefits than Sunrise assuming a 20% RPS

With an assumed 33% Renewable Portfolio Standard (RPS) and utilizing CAISO Phase 2 combustion turbine costs, Sunrise is projected to yield over $115 million annually in net benefits This figure notably surpasses the $93 million per year in net benefits anticipated for the All Source Generation Alternatives.

Because of its higher estimated capital costs, the Draft EIR/EIS

Environmentally Superior Southern Route is estimated to generate $13 million per year less in net benefits than SDG&E’s “Enhanced” Northern Route 448

Taking into account the unquantifiable reliability costs and benefits discussed in Section 9 above, and the environmental issues discussed in

Sections 15 and 17 below, the modeling further supports our conclusion that the Final Environmentally Superior Southern Route (which is a variation on the Draft EIR/EIS Environmentally Superior Southern Route modeled in the

Compliance Exhibit and Update) is the superior alternative.

AB 32 requires that California reduce its GHG emissions to 1990 levels by

2020 449 This Commission, with the Energy Commission, has adopted recommended policies and rules to be implemented by the CARB to meet

California aims to significantly reduce greenhouse gas emissions in the energy sector by increasing the renewable energy share in its resource mix from 20% in 2010 to 33% by 2020 This requirement will apply to all retail providers in the state, including publicly owned utilities The expanded Renewable Portfolio Standard (RPS) is a crucial component of the California Air Resources Board's (CARB) climate strategy.

Change Scoping Plan for achieving the emissions reductions mandated under

The capital cost estimate for the Southern Route has been updated in response to feedback on President Peevey's Alternate Proposed Decision In contrast, no recommendations were provided for revising the Northern Route's capital cost estimate, leaving us without grounds for adjustments to that figure.

On December 11, 2008, the board unanimously adopted AB 32, which aims to significantly reduce greenhouse gas emissions The Scoping Plan outlines that raising the Renewable Portfolio Standard (RPS) from 20% to 33% is projected to achieve a reduction of 21.3 million metric tons of CO2 equivalent (MMtCO2E) by 2020, contributing to an overall reduction of 174 MMTCO2E compared to the business-as-usual scenario.

California's Attorney General is rigorously enforcing greenhouse gas (GHG) emission goals and mandating full disclosure of climate change impacts in Environmental Impact Reports (EIRs) As the lead agency under the California Environmental Quality Act (CEQA), we have incorporated a GHG emission analysis in the EIR/EIS, which quantifies CO2 emissions related to the Sunrise transmission alternatives This analysis also compares the GHG impacts of various generation alternatives to Sunrise By appropriately limiting the scope of our environmental review to Sunrise and its connected actions, we effectively exclude the GHG impacts of Sunrise from the broader context of the Renewable Portfolio Standard (RPS) and the essential grid upgrades required to achieve the 33% target by 2020.

GHG Emissions Projected in the EIR/EIS

GHG Impacts of the Proposed Alternatives

Legal Issues Unique to the Anza­Borrego Link

Overview of the Environmental Impacts on Anza­Borrego

All­Source Generation Alternative

In­Area Renewable Alternative

LEAPS Transmission­Only Alternative

Final Environmentally Superior Southern Route

No Project Alternative