CPUC Transmission Evaluation

Once the utilities have completed the ISO transmission planning process and selected a single project, they file an application with the Commission. Historically the utilities have initiated infrastructure expansion. However, more recently the Commission has become more proactive in transmission matters by calling upon the utilities to bring forward potential projects (see Attachment B for status of the Transmission Investigation, I.00-11-001). This more hands-on approach to initiating transmission evaluation was prompted by AB 970. Despite Commission actions to focus on transmission need, the decoupling of generation and transmission makes integrated planning challenging. It is important to highlight that, historically, the Commission has not been involved in the project selection process that occurs prior to the application filing at the Commission.

The Commission evaluates transmission projects from both a reliability and economic standpoint. The economic benefits of a project have been difficult to assess since an adequate model is lacking. Traditionally, the valuation of economic projects has been relatively simple in that the primary evaluation concentrated on whether access to cheaper generation justified the transmission cost increases. Since deregulation that evaluation has become much more complicated due to the dynamics of the market. For example, congestion costs and how they are treated under the market design, market power, and strategic bidding behavior are economic factors that must be assessed in the evaluation of an economic project. Given the inadequacy of traditional modeling to evaluate an economic transmission project in the current market, the Commission's decision regarding additional transmission to the Southwest directed the ISO and the utilities to develop a methodology to model the economic benefits of new transmission incorporating the market components that impact costs. The economic methodology is intended for universal application in transmission assessment recognizing the need for a more dynamic model that incorporates market factors.

While the Commission ordered the CAISO and the utilities to develop an economic methodology to evaluate transmission projects, it has yet to approve a methodology. Adopting an economic methodology will provide much needed clarity on project assessment going-forward, especially since many of the near-term projects are economic projects. The ISO filed an updated economic methodology developed jointly with London Economics, the consultant hired to develop this model, in February 2003. Path 15, Mission Miguel, and the need for new transmission to the Southwest have all been or are being evaluated based on economic benefit rather than whether the project is required for grid reliability⁸.

Recommendation

1. The determination of "need" for transmission should only be conducted once. The existing duplication in the ISO's and CPUC's transmission need determination should be eliminated. The Commission should adopt an economic methodology for universal application in transmission evaluation to eliminate the current redundancies in the CPUC's and ISO's need assessment.

The Commission should adopt an evaluation methodology that the ISO and IOUs would use in project assessment to allow the Commission to defer to the ISO's determination of need, and avoid a separate evaluation, while at the same time meeting the statutory requirements of 1001. Revisiting the question of need for economic transmission projects would not be necessary to the extent that the Commission adopts an economic methodology for application to future projects.

The ISO and utility should apply the Commission adopted economic methodology to projects before they are presented to the Commission for a CPCN. The determination of need will have been made using a Commission approved approach while allowing review of the application of the methodology rather than revisiting the determination of need in the CPCN evaluation. The advantages to this approach are that the Commission would be fulfilling its statutory responsibility under Section 1001 while at the same time creating a more streamlined process that eliminates the redundant evaluation of need that currently occurs. Eliminating duplicative need determinations by the ISO and Commission will result in reduced project evaluation costs, a more timely and efficient project evaluation, and resource efficiencies by all entities.

A comprehensive resource evaluation should start in the Commission's procurement process where an evaluation of resource options is conducted before the IOU's transmission component of the resource mix can be approved. Upon a comprehensive determination of the required resources mix (e.g. generation, transmission, demand-side options), the IOUs will incorporate the transmission components into the ISO transmission planning process⁹. The ISO will then analyze the economics and reliability criteria of transmission projects utilizing an agreed upon economic and reliability assessment for IOU projects. That is, the IOUs in their long-term plans should balance the benefits of generation, transmission, energy efficiency, and demand response to meet system needs. That determination would be approved by the Commission in the procurement proceeding, and would then be reflected in the ISO's transmission planning process.

Therefore, the recommended approach would eliminate the existing redundancy in the transmission need assessment. It would accomplish this by having the ISO responsible for assessing whether a project is needed to meet reliability standards and economic criteria and the CPUC responsible for reviewing the application of the approved economic methodology, conducting CEQA, and implementing overall comprehensive planning through the IOUs long-term plans. An approach that eliminates redundancy and relies on the core competencies of the CAISO and the CPUC would result in cost savings and improved planning efficiency.

The assessment of the utilities long-term procurement plans at the CPUC is an ideal forum for the CEC to coordinate and collaborate with both the CPUC and the ISO in its role in producing the statewide and regional assessment for the Integrated Energy Policy Report. Having these entities together making hands-on decisions regarding infrastructure will reduce the likelihood of overlapping efforts and inconsistent policies while at the same time bringing together decision-makers in a way that fosters information sharing, reliance on specific expertise, and coordination.

2. One concrete step towards eliminating existing redundancies in the need determination would be for the Commission to revise GO 131-D, or develop a new general order to make changes to the existing process for determining need.

Figure 2 represents a proposed alternative transmission planning process:

Figure 2

Federal Issues

Federal policy impacts transmission planning is three key ways: 1) through transmission pricing 2) wholesale market design; and 3) interconnection rules. The bottom line reason that FERC policies in these areas impact transmission is because they have cost implications for suppliers and thus provide the financial incentives for optimal generation siting. As mentioned, transmission planning in California is already being driven in large part by its reliance on imports and the large amount of new generation being built in neighboring states. FERC policies are also impacting transmission costs and siting decisions within California. Sub-optimal generation siting and by extension poor transmission planning, cannot be attributed to a single problem. Rather, the generation and transmission situation the state is facing today is a product of the interplay between several fundamental issues. The overriding factors influencing sub-optimal generation siting and potentially excessive transmission costs are interconnection rules and transmission cost allocation, transmission pricing, and a poor intra-zonal congestion management regime.

Interconnection

FERC's overarching policy has been to ease the ability of generators to interconnect to the transmission grid. Based on the premise that the interconnected nature of the transmission grid creates a benefit to all users, the FERC has long held that transmission service should be priced based on the cost of the grid as whole. That is, the FERC has favored "network" service based on average or incremental costs across the entire grid as opposed to direct assignment of costs to a particular entity. Therefore, a generator interconnecting to the grid would pay only the actual interconnection costs, but costs created throughout the system necessitated by the interconnection would be borne by all transmission customers in a "roll-in" fashion¹⁰.

Recognizing that this approach is a poor fit with merchant generation, FERC has relaxed this policy in recent years. The policy change was due to many generators wanting to interconnect prior to having lined up load to purchase the output of the unit. The revised policy resulted in interconnection facilities (i.e. all facilities required to connect the generator to the network) being treated as direct assignment facilities and were directly assigned. The generator pays for the network upgrade that would not have been necessary `but for' the interconnection. The transmission provider would then give a credit for the investment amount plus interest to the generator for the amount of the upgrade once transmission service begins¹¹. FERC has continually reinforced its policy that a generator that pays for network upgrades beyond the first point of interconnection be paid back its investment within five years¹².

However, FERC's most recent ruling on July 24, 2003, continues its policy of requiring the five-year credit for network upgrades for non-independent transmission providers, but permits considerable interconnection pricing flexibility for independent transmission providers that have Locational Marginal Pricing.

FERC's earlier interconnection policies essentially allowed generators to be almost entirely insulated from the transmission costs resulting from their choice to interconnect in a particular location. FERC's decision that generators pay the cost of upgrades upfront has increased generator internalization of transmission costs when making siting decisions. However, FERC's direction that the transmission owners repay the generator's investment with interest within a five-year period has reduced the rational siting benefit. As PG&E argued in its comments on the Interconnection NOPR:

If the credit is based on transmission revenue, many projects will get their money back in 8 to 24 months. In any event, under the credit proposed in section 11.4.1 of the Interconnection Agreement, the Generator would get its money back in five years at the latest, with interest. This approach has the effect of insulating generators from cost responsibility for any network upgrades necessary to interconnect their projects, taking away the incentive to pick the least-cost location.¹³

The ISO has raised similar issues arguing that such a fast pay-back for transmission upgrades mutes price incentives that lead to rational siting, which is not only the goal of sound transmission/generation planning, but most compatible and consistent with the pricing signals that will result from locational marginal pricing (LMP). In its July 24, 2003 Order FERC acknowledged the problems associated with the 5-year credit back stating:

While the Commission still finds these to be appropriate goals for an interconnection pricing policy, the commenters that object to the Commission's crediting policy make a number of valid points. Most importantly, as many point out, providing transmission service credits to an Interconnection Customer for the cost of Network Upgrades that would not be necessary but for the interconnection of the new Generating Facility mutes somewhat the Interconnection Customer's incentive to make an efficient siting decision that takes new transmission costs into account, and it provides the Interconnection Customer with what many view as an improper subsidy, particularly when the Interconnection Customer chooses to sell its output off-system¹⁴.

The interconnection cost allocation and pricing policy assigning generators the upfront costs is better than earlier policies, which provided little or no incentive to locate rationally. However, these policies still do not fully reflect the true costs associated with siting decisions. Put another way, a 5-year payback for network upgrades associated with interconnection discourages siting in the highest cost, least advantageous location, but does not deter mildly irrational, sub-optimal solutions.

As mentioned earlier, FERC's July 24, 2003 Order continues the policy of the 5-year payback but allows ISOs deference in this regard to tailor compensation for network upgrades to the market design. The premise is that in lieu of transmission cash credits, Congestion Revenue Rights (CRRs) could be allocated to generators that pay for transmission upgrades¹⁵¹⁶. CRRs may entice generators to pay for transmission investment by providing a hedge against congestion costs. The hedge against congestion charges could provide the generator with a competitive advantage when marketing power to load since load would not be faced with a `congestion mark-up' that might be associated with other supply options. Many contend this regime will provide better location pricing signals when siting generation. While this approach is new to California, it is used in the Eastern ISOs. However, in California where the value of CRRs is uncertain, especially in comparison to a cash credit, it is doubtful that compensating generators with CRRs alone would be sufficient to induce investment in network upgrades. Indeed, in the Eastern ISOs, CRRs are coupled with capacity incentives to induce transmission investment required by a generator interconnection. Under that construct, in addition to CRR allocation a generator that pays the costs of the network upgrade qualifies as a capacity resource to meet Load Serving Entity's (LSE's) capacity requirements. As a qualified capacity resource the generators must pay the cost of transmission upgrades to ensure that the power is deliverable.

By January 20, 2004, the ISO and PTOs must submit compliance filings with FERC's Order 2003. In the long-term, a process where a generator pays the cost of network upgrades that are required to accommodate an interconnection and is compensated with CRRs in addition to qualifying as a capacity resource to fulfill utility capacity obligation, is a more desirable approach than the 5-year payback. The predominant reason is that the capacity resource/ CRR approach safeguards against excessive transmission costs by forcing generators to internalize the costs of serving their generation while at the same time providing incentives to invest in transmission upgrades. However, this is an evolutionary process that will likely require continuation of the crediting mechanism until the Commission has completed its development of a capacity policy in its procurement proceeding (R.01-10-024) and the ISO's market redesign is implemented. It should also be noted that a continuation of the 5-year credit may be required beyond establishment of a capacity resources/ CRR regime as it is likely that uncertainty about the value of CRRs will persist for a period once market re-design is implemented and lenders may be more inclined towards a cash credit. It is important to recognize that a construct whereby generators pay the costs of the network upgrades that would not be necessary but for the generator's interconnection is not inconsistent and should not substitute for regular investments in necessary transmission infrastructure by Transmission Owners.

Transmission Pricing

The fact that load (i.e. consumers) pays for transmission service in California, not generators, is one key cause of sub-optimal generation siting decisions and associated transmission costs.

California is one of the few states, and may be the only state, where load pays the entire transmission service charge. Since generators do not pay transmission charges, they are insulated from the transmission costs associated with a siting location. As businesses, the generators will choose their least cost option, which may be to locate near fuel and/or water sources. Such a siting choice is not necessarily the least cost, optimal outcome for consumers.

In other areas of the country, generators pay a portion of transmission service. In PJM¹⁷, this is achieved by dividing up the network service transmission charge among load and suppliers. Alternatively, a generator could pay a point-to-point transmission charge with load paying a generic transmission charge. Under this construct, the transmission cost component tends to be rolled into the generators bilateral contract with load. Since transmission costs are directly internalized by generators and impact competitiveness, the result is more rational, least cost generation siting and transmission planning.

One of the reasons that California is witnessing a large amount of new generation locating in Arizona, Nevada, and Colorado, is because these locations are close to gas supplies. If generators assumed a portion of electric transmission charges, then generators would balance the costs of locating near a load center and paying lower transmission charges but incurring costs to transport gas to the units, or locating near a fuel source, mitigating gas transport charges, but incurring transmission costs¹⁸. As it stands under the current structure of load paying transmission service, the generators are choosing to locate near fuel sources, reducing gas transport charges. This situation could result in excessive transmission costs and infrastructure than otherwise would prevail if incentives were aligned in a manner that provide the appropriate price signals to locate generation in an overall least cost way.

Intra-zonal Congestion Management

Compounding the lack of appropriate incentives to locate generation in a least cost manner is the problem surrounding an inadequate intra-zonal congestion management system. Under the current market design, there exists three "zones" in the state. Following the premise that each megawatt is homogeneous and equally valuable in resolving system needs, generators are paid the market-clearing price no matter where in the state or zone the power is located. That is, a generator in Humboldt is paid the same price for its power as a generator in San Francisco. This is so even though the San Francisco power does not have to be transmitted as far to reach a load center and is thus "more valuable" in serving local and/or system needs. In short, current pricing has no mechanism to value location. In fact, due to the intra-zonal congestion management system, a generator has a financial disincentive to locate in a way that most economically benefits consumers.

Under the current market design, a generator is paid not to produce when the transmission system cannot accommodate the power. This is known as decrementing a unit and has lead to market manipulation in the form of the "dec game". Therefore, not only is the generator receiving the market-clearing price no matter where it locates, being sheltered from the interconnection costs no matter what transmission infrastructure is required to accommodate the interconnection, but the generator is paid for not producing when the system cannot accommodate the power resulting from sub-optimal siting decisions. In its May 30, 2003 decision addressing the problems surrounding the new generation on the Mexican border and the transmission constraints that are estimated to cost consumers $4 million / month to resolve, the FERC recognized the perverse outcomes that are resulting from the pervasive problems in the current market design:

As long as the CAISO continues to accept infeasible schedules, it will continue to face the result of potentially having to pay generation not to produce in areas of over-generation. The Commission sees it as a perverse outcome that increased generator availability and entry would potentially raise costs for California consumers. In general, in a market-based context, one would expect increased generation availability to lower the overall cost of electricity rather than increase costs to consumers¹⁹.

The interplay between an inadequate congestion management regime, pricing that does not reflect locational value, and interconnection cost allocation that insulates generators from siting costs, has been a contributor to the generation and transmission landscape the state witnesses today. Currently, there are several proposals to rectify the perverse incentives that exist.

The ISO's market redesign proposal, once implemented, should resolve congestion management problems by optimizing the system prior to real-time and only accepting schedules that are feasible on the transmission system (i.e. a closer alignment of transmission engineering and pricing). The ISO's implementation of locational marginal pricing will essentially produce a value for location and the contribution of a particular generation unit in meeting system and local demand. In other words, LMP will devalue power located in remote locations away from load centers by incorporating transmission related costs into the price equation.

Recommendations

1) The general recommendation is that the CPUC should drive a higher level of coordination between federal and state transmission related issues. There are two key areas where this sort of coordination is critical: 1) in the Commission's procurement proceeding; and 2) in the CPUC's on-going transmission proceeding.

The Commission's procurement policy will provide the opportunity to remedy several of the problems that continue to result in poor generation siting and potentially excessive transmission costs. Currently generators are not responsible for deliverability upgrades required by new generation facilities thus insulating them from transmission related costs. In addition, load pays for transmission costs in California. The Commission will directly impact the current incentives to invest in transmission infrastructure and provide economic incentive to site rationally by setting the policy framework in which the IOUs will procure resources. Requiring that contracted capacity be deliverable would impact the resources that will be able to meet that requirement and thus foster an incentive to invest in deliverability upgrades. Likewise, procurement contracts could split transmission related costs between load and generators thus serving to force the internalization of transmission related costs by generators. This internalization will filter into efficient siting decisions since the transmission related costs associated with those decisions would be incorporated into power contracts and impact competitiveness.

The Commission should move quickly to establish an economic methodology for application in new transmission projects. The reason the Commission ordered the ISO and IOUs to develop a more robust economic methodology was to more adequately capture market dynamics and apply such a methodology in the evaluation of economic transmission projects. While the availability of such a methodology for projects that require a CPCN will certainly be one of the benefits, the methodology will also be able to be applied at the interconnection stage to assess whether the benefits of a new generation facility outweigh the transmission related costs²⁰. Such analysis is particularly important so long as the generators continue to receive a full repayment of upfront transmission costs within 5-years, thus muting the incentive to locate in a least cost location.

Regional Issues

California depends on power from neighboring regions to meet its needs cost effectively. While analysis of regional transmission issues has always been important due to the interconnectedness of the Western grid, it is becoming more so due to the large amount of new generation siting outside California. The focus on inter-state transmission lines is increasing accordingly. The Commission is already being faced with large inter-state transmission projects²¹. It is conceivable, and even likely, that this will increase the number of intra-state projects as well. Most new generation is coming on-line in Arizona and Nevada. Compared to the Southwest there is little new generation coming on-line in the North. The extent to which PG&E, for example, starts contracting for cheap power from the Southwest, will have implications for large north-south transmission lines intra-state²².

There are several undertakings on regional transmission planning. These are discussed below.

Western Governor's Association

In the aftermath of the Energy Crisis the WGA has spent considerable time on Western Transmission issues²³. In 2002, Western Governors signed a Memorandum of Understanding with the Secretaries of Energy, Interior, and Agriculture and the heads of EPA and the Council on Environmental Quality to work cooperatively on energy development and conservation in the Western U.S. The focus of this MOU was inter-state transmission planning. The two key aspects include: 1) development of a region-wide planning process; and 2) development of a joint planning process that includes states, local governments, federal land management agencies, and tribal governments. The overall purpose of the MOU was to facilitate efficiency in the transmission planning process by coordinating among jurisdictional entities, eliminating duplicative review, creating an environmental review process that will facilitate document sharing, and streamlining review processes to make it structured and predicable. Western Governors signed a Protocol to implement the MOU that provides for cooperation on the review of any new applications to site transmission lines in the region (June 2002).

While the WGA continues to work on developing a joint review process, the Seams group has become the forum to address regional planning.

Seams Steering Group-Western Interconnection (referred to as Seams or SSG-WI)

The Seams working group is essentially designed to address issues that effect the three RTOs - CAISO, Westconnect in the Southwest, and RTO-west in the Northwest. CAISO is the only one of the three that has formalized its ISO/RTO status. This group is a forum to further the development of the West-wide inter-state transmission system. This working group was also formed in response to FERC encouraging transmission planning on a West-wide basis. In 2002 FERC said:

Accordingly, while we have approved much of the conceptual framework for the creation of WestConnect and have encouraged WestConnect to continue working to develop appropriate solutions to the many outstanding issues that remain, it is still necessary to address any seams issues that may be created where different solutions are proposed by different RTOs in the Western Interconnection. In an October 25 Notice, the Commission emphasized the need for state participation to provide policy guidance to the seams resolution process and further requested that the Seams Steering Group of the Western Interconnection (SSG-WI) submit to the Commission by mid-January 2003:

. . . a list of recommended market design elements appropriate for the western interconnect . . . which elements must be designed compatibly to avoid seams, and a plan and timeline for resolution of these issues that is coordinated with RTO development efforts. This plan would include specific tasks for each of the current SSG-WI working groups and any other working groups that may be necessary²⁴.

Currently the SSG-WI Transmission Planning Working Group is evaluating uneconomic inter-state transmission congestion as well as coal, gas, and renewable generation scenarios. Based on this analysis, the seams group is performing studies for the 2008 and 2013 time frame. While the results of the studies indicate some promising combinations of transmission and generation under particular of hydro and gas conditions, they are intended for further development and analysis.

The Seams group considers reliability-driven transmission planning as the purview of the individual ISOs/RTOs. Therefore, the Seams group is primarily focused on economic transmission projects. Additionally, the CAISO intends to integrate the results of its sub-regional planning effort in the Southwest (see below) into the Seams transmission effort²⁵.

Southwest Transmission Expansion Planning (STEP)

STEP is a forum to discuss possible solutions to particular transmission issues in Southern California and the Southwest. The meeting is conducted by the CAISO transmission planning team²⁶. It is a regional meeting with transmission owners and authorities from Arizona and Mexico, Imperial irrigation district, WAPA, SDG&E, SCE, CAISO, Salt River Project, the CPUC's Energy Division, and others. The reason that a regional meeting is occurring in the Southwest is due to the large amount of generation coming on-line in the near future and transmission constraints that either exist or will exist once the generation begins to flow.

STEP is an informal gathering of interested entities that evaluate projects in the preliminary stages. The forum is very interactive and everyone is invited to comment on the proposals, submit alternatives, and ask questions regarding the data supporting proposals. For the most part, the time frame for projects under consideration is between 7-10 years. Due to the current need based on known generation coming on-line in the Southwest and Southern California a shorter-term outlook is emphasized.

CAISO plans to initiate a northwest sub-regional transmission planning effort similar to STEP.

Conclusion

The transmission planning process in California is balkanized and fragmented. The single biggest improvement in the current process will be to reduce the redundant assessment of need that occurs at the CAISO and the Commission. To eliminate a redundant review, the Commission should take a comprehensive look at all the options available to meet demand - generation, transmission, and demand-side options - in the context of the Commission's procurement proceeding. The Commission should also adopt an economic methodology for application in future transmission projects. The Commission would then be able to defer in the CPCN process to the CAISO assessment of need made when it approved the project rather than doing an additional assessment since the project would have been assessment using a Commission approved methodology. The economic methodology would also be able to be applied when the CAISO is evaluating new interconnection if it appears that the transmission related costs of a new project might outweigh the benefits.

The Commission should also be formally involved in the CAISO planning process as an upfront effort to provide input and foster a better understanding regarding why a particular project was chosen and what criteria and assumptions were used in its selection. This upfront investment in the CAISO process should facilitate a smoother review process once the project is before the Commission.

Attachment A

There is an enormous amount of new generation that has been built in Arizona, Nevada, and Southern California that will serve California customers. The total megawatts from the projects listed below are 14,545²⁷. Therefore, it is likely that additional transmission capacity will be required. When thinking about transmission capacity it is important to remember that 1 500kV line can transmit 1500-2000 MW. It seems likely that the existing 2 500 kV lines from the Southwest (Southwest Power Link and Devers Palo Verde) will not be sufficient to import Southwest power into Southern California. The generation projects below are on-line or very nearly on-line.

The new generation includes the following:

Arizona

Hassiampa Substation:

Hassiampa is South of Palo Verde, in Western Arizona. There is 6,600 MW of new generation at or near the substation. These projects include:

· Red Hawk- 1000 MW in-service

· Arlington Valley- 600 MW in-service

· Mesquite- 1250 MW in 2003

· Harquahala- 1170 MW in 2003

At the Gila Bend, near Hassiampa, the following new plant is likely to be in-service:

· Panda Power- 2080 MW in 2003

Near the Phoenix Metropolitan area, the following new plant is likely to be in-service:

· W. Phoenix 5- 500 MW in 2003

Nevada

Las Vegas:
Approximately 3140 MW of new generation is likely to be in-serve near Las Vegas. These plants include:

· Las Vegas Cogen II (Black Hills) - 230 MW in-service since January 2003

· Apex (Mirant)- 550 MW in -service March 2003

· Bighorn- 570 MW in December 2003

· Silverhawk (Gen West)- 590 MW in April 2004

· Moapa (Duke)- 1200 MW (Currently suspended but 70% complete)

Mexico

Approximatley1660 MW of new generation is in-service in Mexico near the Imperial Valley sub-station:

· Ciclo Combinada Mexicali (Intergen)- 750 MW in-service July 2003 (590 MW connected to La Rosita and 160 MW connected to Imperial Valley 230 kV line)

· Central La Rosita (Intergen) - 310 MW in-service July 2003 (connected to Imperial Valley 230 kV line)

· Termoelectrica de Mexico (TDM, Sempra) - 600 MW. The generator is complete and able to be tested. However, given the large amount of congestion in that location, ISO operations has not permitted testing (connected to Imperial Valley 230 kV line).

A total of 1070 MW will be connected to the 230 kV system in Imperial Valley and 590 MW will be connected to the La Rosita substation in Mexico. 1160 MW of the power from these new units is intended to supply California customers.

Southern California

Several new units in California are likely to be in-service:

· Blyth # 1 - 520 MW in service in early 2003

· Pastoria Phase I (Calpine)- 750 MW suspended until 2004

· High Desert - 850 MW in-service 2003

Attachment B

Pursuant to AB 970, the Commission initiated a generic transmission investigation (I.00-11-001), which has considered transmission issues in 7 phases:

1) Phase 1 identified 32 transmission projects that were completed in 2001 (these were predominantly small scale upgrades). See D.01-03-077 dated March 27, 2001.


2) Transmission constraints to the Southwest. The decision concluded that new transmission to the Southwest was not required for reliability purposes within the planning horizon (i.e. not needed until 2008). It may be beneficial based on economic criteria. However, it was determined that a methodology to assess economic benefits of transmission projects needed to be developed. When rejecting the project, the Commission ordered development of a methodology to assess the economic benefits of transmission projects. See D.01-10-010 dated October 25, 2001.


3) Mission Miguel & Imperial Valley. Approved need on economic grounds. The economic analysis was based on traditional and more simplistic production cost analysis (i.e. the power cost savings justified transmission cost increases). That is, the economic analysis did not include market benefits and the more complicated economic factors surrounding the market dynamics such as strategic bidding and market power (See D. 03-02-069 dated February 27, 2003). The project is currently in the CEQA process. The Draft EIR is expected in early February 2004. A final decision is anticipated in early summer 2004.


4) Path 15 - proceeding completed. See D.03-05-083 dated May 29, 2003


5) Methodology to evaluate economic benefits of transmission projects. The ISO submitted a proposed methodology in February 2003 using a model it developed jointly with London Economics. However, this phase of the proceeding is not completed. The commission has yet to adopt a universal economic methodology for application in future transmission projects. In April 2003, an Administrative Law Judge ruling determined that the Commission should not move forward to adopt a generic methodology unless the Commission can evaluate its application to a specific project. The Commission deferred a determination on an economic methodology until the ISO had developed network model software and applied the methodology to an actual project. On December 15, 2003, the Assigned Administrative Law Judge issued a ruling proposing a schedule whereby the Commission will assess and validate the economic methodology that the CAISO has developed pursuant to D.01-10-070²⁸. A decision is anticipated in the fall on 2004


6) New transmission line and substation to interconnect Tehachapi wind resources. The proceeding is on going.


7) Statewide transmission plan for renewable generation development completed in December 2003.

Attachment C

The Commission's Transmission Evaluation Process

Pursuant to GO 95, the utilities must apply to the Commission for a permit if a project is greater than 50 kV. California Environmental Quality Act (CEQA) assessment is conducted on any proposal greater that 50 kV.

General Order 131-D, adopted in 1994 by D.94-06-014, sets forth the Commission's current regulations pertaining to the construction of new transmission facilities. For projects over 200kV, a utility is required to obtain a CPCN. For facilities between 50kV and 200kV, a utility is required to obtain a "permit to construct." The "permit to construct" process "focuses solely on environmental concerns, unlike the CPCN process which considers the need for and economic cost of a proposed facility." D.94-06-014.

Prior to the adoption of G.O. 131-D the Commission had not required environmental review of power line facilities operating between 50 and 200 kV.

Pursuant to PU Code Section 1001, a project proposal greater than 200kV requires a Certificate of Public Convenience and Necessity (CPCN).

In relevant part, Section 1001 states:

"no . . . gas . . . [or] electric corporation . . . shall begin the construction of a street railroad, or of a line, plant, or system, or of any extension thereof, without having first obtained from the commission a certificate that the present or future public convenience and necessity require or will require such construction."

A CPCN evaluation considers project need from reliability and economic perspective, environmental implications, and alternatives. Project alternatives are put forth in the environmental evaluation process.

GO 131-d gives the Commission 12-18 months to make a decision on the project (from the date the filing is deemed complete). When the utility requires a CPCN, it files a Proposed Environmental Assessment (PEA). This is the utility's own environmental assessment. The Commission rarely considers the PEA complete. This triggers the Commission's own environmental assessment

The PEA and the CPCN application are submitted simultaneously. The application triggers a CEQA evaluation by energy division. Contested environmental issues (following completion of the CEQA assessment) and the need for a CPCN are evaluated in evidentiary hearings. In evaluating a project under CEQA, one of two processes is followed. The first option is a negative declaration, which applies to more environmentally benign proposals. The second process is a full Environmental Impact Report (EIR), which involves a more extensive evaluation of the project's environmental impact. An EIR can take up to 1-2 years to complete.

(END OF ATTACHMENT B)

¹⁰ In the California context, the rolled-in transmission costs are reflected in the ISO's grid wide Transmission Access Charge or TAC. FERC prohibits "and" pricing, which means that FERC does not allow the charging of a transmission customer for both a transmission service rate with the cost of the upgrades rolled in and the incremental cost of a network upgrade.

²² It should be noted, however, that the degree of access to regional power supplies is heavily impacted by ISO market rules and how attractive the California market is compared to other regions in the West.