California Independent 
System Operator

Memorandum
					
To:	Grid Reliability/Operations Committee 
From:	Kellan Fluckiger, Vice President, Operations
              Stephen Greenleaf, Director of Regulatory Policy
	Armando Perez, Director of Grid Planning
CC:        ISO Board, ISO Officers
Date:	June 17, 1999
Re:	Long-Term Grid Planning Proposal
EXECUTIVE SUMMARY

We are presenting for Board review and approval ISO Management’s long-term grid planning process proposal .  This proposal is the culmination of an effort begun with Strawperson I which was presented to the Board at the March meeting.  Strawperson II was subsequently developed and presented to stakeholders at the April 20 Stakeholder Grid Planning meeting.  As a result of the discussions surrounding Strawperson I and II, we then developed and presented Strawperson III at the special May 14 Grid/Ops Committee Meeting.  The purpose of that discussion was to seek guidance from the Committee as ISO Management prepared for the upcoming legislative hearings addressing planning issues.  We are now more convinced than ever that timely resolution of these issues is critical.  As the Legislature moves forward with certain proposals and the need for a coordinated planning process increases, the ISO must take a proactive step forward in advancing a long-term plan. These policy issues must be addressed now in order to facilitate needed upgrades to the grid, send pricing signals to generators, and fully transition to the new market paradigm.
	
As a result of the need for a comprehensive and coordinated grid planning process that will provide for the efficient expansion of the statewide transmission system, the ISO has developed, with stakeholder input, the conceptual framework of an integrated planning process.  In order to develop the necessary implementation details, Management seeks Board guidance on certain fundamental policy questions.  Therefore, we propose the following motion:  

Moved, that the Board approves Management’s recommendations with regard to the identified policy issues and authorizes Management to develop the implementation details in accordance with such policy direction and to present such details to the Board at the August meeting. 

ISSUE STATEMENT

Management seeks Board resolution of certain critical policy issues, the resolution of which  will help form the framework of our grid planning process.  While certain of the implementation details are still under development, we believe that is essential to obtain policy guidance from the Board at this time so that the ISO and stakeholders may properly focus future discussions on implementation issues.  We will come back to the Board in August with specific recommendations and necessary Tariff changes.  The policy issues on which we seek guidance are as follows:

•	The proper roles and responsibilities of the ISO, PTOs, stakeholders and public agencies in the planning process
•	The outline of the two-part planning process described below   
•	The appropriate role for the ISO in regional coordination/planning
•	ISO/PTO responsibility for grid reliability
•	The ISO’s interface and coordination with the state’s transmission and generation siting agencies

We address issues related to the ISO’s LARS initiative in a separate memo.

POLICY ISSUES

ISSUE NO.1 – Roles and Responsibilities for the ISO, PTOs, Public Agencies and Stockholders 

The ISO

ISO Management recommends that the ISO direct the review and evaluation of all transmission projects on the ISO Controlled Grid.  The ISO will perform this function both with respect to the review of the PTOs’ annual assessments and the evaluation of competitive alternatives to the projects identified in the annual assessments. In order to satisfy its responsibilities, the ISO must be able to direct the PTOs to perform technical studies of their own and other proposals.  The PTOs will be required to perform, at the direction of the ISO, System Impact Studies and Facilities Studies.  Such studies may be necessary as a result of, among other things, ISO-sponsored/identified projects, PTO-sponsored projects and third-party sponsored projects.  To the extent that the ISO directs the PTOs to perform studies as a result of an ISO-  or third-party sponsored project, the ISO or third-party should pay the costs of performing such studies.  As it is, the PTO will pay the costs of performing its own studies and evaluations.  In the future, if the costs and number of studies performed becomes too burdensome for the full-time staff of the PTOs, the ISO may want to consider increasing its own grid-planning staff.

As an independent entity, the ISO is the logical party to perform this lead coordination role.  The ISO has a statutory responsibility to ensure the reliable and efficient operation of the statewide transmission system.  The ISO has and will continue to exercise its independent authority to ensure implementation of those responsibilities.   We believe that Assembly Bill 1890 (AB1890) was clear in its intent to establish the ISO as the preeminent authority in transmission planning.  Moreover, FERC has expressed a clear desire for ISOs, as independent and regional entities, to assume a proactive and authoritative role in issues related to transmission planning and expansion.  Specifically, in FERC’s recently issued Notice of Proposed Rulemaking regarding Regional Transmission Organizations (RTOs), FERC clearly envisions that independent transmission organizations like the ISO are appropriately situated to coordinate the planning of the regional transmission system.  Lastly, we believe that the ISO Tariff already contemplates that the ISO will oversee the planning process.

The PTOs

The ISO recommends that the PTOs’ primary role continue to be to provide technical expertise and resources.  As recognized by FERC, the PTOs are the entities most familiar with their own systems.  The PTOs are also well situated to propose projects that will ensure the continued reliability of the system, as well as projects identified as economically advantageous.  It is the PTOs’ responsibility to develop the five-year bulk power programs for their systems.  The bulk power programs will utilize, and be consistent with, the ISO’s Grid Planning Criteria and will factor in load growth, congestion mitigation, RMR-requirements reduction, and known new transmission and generation projects.  The bulk power programs are the basis for the Annual Assessments submitted to the ISO each year.  The PTOs should be responsible for performing any additional studies requested by the ISO.  Such studies may be necessary as a result of identified deficiencies in the PTOs’ studies or the need to examine the results using different assumptions.  In addition, the PTOs would be responsible for performing the necessary studies to determine if alternative projects, identified through the ISO’s competitive solicitations, are both feasible and satisfy the ISO’s requirements.

Public Agencies

Public Agencies will play a unique role in the ISO’s planning process.  First, as entities responsible for protecting the public interest, Public Agencies including the Electricity Oversight Board (EOB), the California Public Utilities Commission (CPUC), the California Energy Commission (CEC), and FERC have a vested interest that California’s transmission system is planned in a manner that ensures reliability and public safety.  Participation by the Public Agencies in the review and evaluation of the PTOs’ Annual Assessments is therefore essential.

In addition, as administrators of public policy-related programs, such as demand-side management initiatives and renewable resource initiatives, the Public Agencies should  be active participants in the ISO-administered competitive solicitation process.  As part of the successful transition to a restructured marketplace, it is imperative that the Public Agencies actively participate and provide guidance through market-based initiatives.   ISO Management believes that the state’s public policy goals can be effectively satisfied through the market, rather than legislatively mandated requirements or programs.

Finally, as the agencies responsible for overseeing the siting process in California, it is imperative that Public Agencies actively participate and have knowledge of the ISO planning process and have final approval authority for projects identified as needed in that process.  The projects that are identified as “winning,” or approved as a result of the ISO’s planning process, will also have to secure the required regulatory approvals through the state’s siting and CEQA processes.  It would be unproductive and wasteful if projects selected as part of the ISO’s planning process were subsequently rejected because of Public Agency concerns that were not previously raised or addressed during the I ISO-administered process.

We believe that Public Agency participation in the ISO process is essential and that the ISO process can parallel the appropriate regulatory proceedings. Such a requirement will insure both adequate public notice of proposed projects and satisfaction of the data adequacy needs of the Public Agencies. We further believe that such an approach is administratively feasible.  That is, the ISO envisions that Public Agency participation in the ISO Planning Process will be essential as part of a parallel Public Agency process.  However, in order to ensure a timely process, the ISO believes that Public Agencies may have to be legislatively vested with final decision-making authority (i.e., state Public Agencies may need to have the authority to overrule local authorities).

Stakeholders would, of course, participate in both the ISO planning process and the concurrent Public Agency administrative process.

POSITIONS OF THE PARTIES - Roles and Responsibilities

April 27 Stakeholder Comments

PG&E commented that the expansion of the ISO’s grid planning responsibilities is not mandated by AB 1890 or FERC order.  PG&E wrote that  “the wiser course is for the ISO to work jointly with the PTOs and attempt to reach consensus on the upgrades and additions to transmission that should be pursued by the PTOs.”   Edison echoes PG&E’s statement that there is no demonstrated need or justification for the ISO’s contemplated changes to the planning process.  Edison believes the current structure strikes an acceptable balance between the PTOs’ and ISO’s interests.

Roseville Electric raised its concern that municipal utilities, which are also Public Agencies, do not have a specified role under the proposal and that as currently drafted, the proposal “strips from municipal utilities the power to control their own facilities and systems, ostensibly in the pursuit of a ‘timely’ process.”

June 14 Stakeholder Comments

PG&E, Edison and SDG&E raised concern that the ISO’s proposal is moving away from the “coordinated” planning envisioned at start-up and contemplated in the ISO Tariff, Transmission Control Agreement and the TO Tariffs.  The PTOs stated that a coordinated effort works best and establishes an appropriate working relationship among the affected parties.

ISSUE NO.2 – The Two-part Planning Process

Part I – Development of the Integrated Plan

Attachment A contains a flowchart which outlines the components and timing of the ISO’s two-part planning process.  The purpose of Part I of the planning process is to develop an integrated transmission plan for the state.  The integrated plan would be developed by consolidating the annual assessments of the PTOs using the Board-approved ISO Grid Planning Criteria. The PTOs will have already completed the stakeholder process regarding their individual annual planning assessment.  We believe that it will be necessary for the PTOs to adopt a common methodology or approach for submitting their annual assessments.  Currently, Edison and SDG&E approach the annual assessment process similarly – they submit one consolidated plan that incorporates numerous individual transmission projects.  Alternatively, PG&E proposes and seeks ISO concurrence on individual transmission projects throughout the year without developing a consolidated plan that includes all proposed projects.

The integrated plan would also incorporate those transmission projects sponsored by third parties and would recognize all new-generator interconnections, including those that require a  network upgrade.  Third-party-sponsored transmission projects and new-generator interconnections would not be subject to reevaluation, but would be considered in the development of the integrated plan.  During this phase, the ISO will direct the PTOs to perform any necessary System Impact Studies and Facility Studies, consistent with the timelines provided for in the PTO Tariff. These studies may entail evaluation of the proposed projects using alternative assumptions, such as load revised load-growth estimates, revised estimates of the level of market generation, and alternative projects.

During the initial and subsequent periods of review, the ISO will coordinate California representation in the regional planning process (i.e., RTA, RTO, WSCC).  The ISO is the appropriate entity to represent California on regional bodies and in regional forums.  Market Participants, by nature, are not independent and Public Agencies must represent the interest of California consumers.  Therefore, it’s both logical and appropriate for the ISO to fulfill this role.  As FERC works toward the establishment of regional entities responsible for the planning and expansion of the regional transmission system, it is important that it recognize that an ISO can satisfy FERC’s goals of independence and representation of regional interests.

Finally, the ISO Governing Board will approve or reject recommendations forthcoming from the integrated planning process.  Once approved, the ISO will publish the integrated plan.

Part II – The Competitive Process

The purpose of Part II of the proposed planning process is to conduct a solicitation for competitive alternatives to the projects identified in Part I.  We believe that this approach is consistent with the FERC’s NOPR on RTOs, in which FERC stated that:

…customers and regulators would want assurance that the decision to invest in transmission is made in the best interests of the region, considering not only all the transmission options but also the generation and demand management alternatives to transmission construction.

We believe it is important to phase the planning process for two reasons: 1) the creation of a statewide integrated plan will create a timely price signal for entities interested in siting new generation and transmission facilities (a one-part process will likely require as much time as a two-part process and will not provide early indications as to where the grid will need to be expanded); and 2) respondents in the competitive solicitation process should be aware of the benchmark (i.e., the projects identified in Part 1) against which their bids will be evaluated.

Part II of the ISO’s proposed planning process begins with the ISO’s publication of the results of Part I.  The posting of the approved integrated transmission plan will establish the benchmark or “bogey” against which all competitive alternatives will be judged in Part II.  For purposes of the initial competitive process, we recommend that the ISO identify a range of costs for each proposed project identified in the integrated plan as opposed to specifying the estimated cost. Management does not concur with concerns that identifying the cost of proposed transmission projects will increase the price of bids submitted through the competitive process.  The fundamental premise of the competitive solicitation is that competition will keep the bid prices low.  In addition, we note that the approximate cost of potential projects is publicly available anyway through the PTOs annual assessment process.  However, we are sensitive to this concern.  Therefore, we state here that it is not our intention to enter into contracts based on the “avoided cost” of a transmission project.  A significant factor in the ISO’s evaluation of alternative proposals will be the “firmness” of the resource.  The ISO will weigh significantly the fact that a transmission project will be in place for a long period (30 years) and that it will not be subject to the same operating constraints as a generating resource.  Therefore, a generation project bid in at substantially the same price a transmission project will not be considered comparable to the transmission project.  

The sole purpose of Part II is to conduct a comprehensive competitive solicitation for alternatives to the projects identified in Part I.  Third-party sponsored (i.e., economic projects) and new-generator-related projects will not be subject to the competitive part of the planning process, but will be included in the final integrated plan. 

After publication of the results of Part I, the ISO will within thirty (30) days issue a Request for Proposals (RFP) for competitive alternatives to proposed transmission projects.  The RFP will entertain transmission, generation and demand-based proposals.  The RFP will specify the criteria that each proposal must satisfy in order to be considered.  The RFP will also specify how the ISO will evaluate the proposals.  For example, the ISO’s 1998 LARS RFP specified that the ISO would evaluate proposals based on cost-efficiency, subject to such constraints as availability, ability to provide the service, environmental concerns, safety, etc.  Interested Market Participants will have thirty (30) days to submit a proposal.

Market Participants who wish to participate in public policy programs or initiatives would be responsible for securing the available funding, or satisfying the necessary requirements, prior to responding to the RFP.  For example, to the extent a Public Agency was sponsoring a program whereby it would provide incentives for DSM initiatives, Market Participants interested in availing themselves of such incentives would be expected to factor such an incentive into their bid.  After the deadline for proposals has passed, the ISO would screen all respondents to ensure that they have satisfied the identified minimum requirements.  The ISO would then review the proposals.

During the review period, the ISO will direct the PTOs to perform any studies necessary for the ISO to make a quantitative and qualitative assessment of any proposal.  Based on the review by all interested parties, ISO Management would recommend a proposal to the ISO Governing Board.  The ISO Governing Board will then approve winning bidders or direct a re-examination of the proposals.  After ISO Board approval, the EOB will review the project or integrated plan.  The responsible Public Agency will make a determination and certain findings so that the project(s) can proceed with any remaining regulatory proceedings.  Alternatively, the responsible Public Agency could recommend that the ISO Governing Board conduct further review of the project(s) or plan.  The ISO Governing Board has the right to reexamine its proposal or to send its initial recommendation forward.

If PTO-sponsored projects become part of the final integrated plan, the applicable PTO will proceed with all necessary regulatory proceedings to secure cost-recovery and the siting of the new transmission facilities.  The ISO will concur in those filings.  If third-party-sponsored transmission projects are approved, and the third party constructs such facilities, the third party will seek regulatory approval and recognition of the proposed project.  If a generation or demand-based project is identified and selected as a viable alternative to proposed transmission projects, that project will be required to execute a contract specifying that the ISO may call upon the project from time to time to provide necessary support to the system.  The contract will also specify the payment the ISO will make to the project sponsor for providing such service.  The ISO anticipates that the bids submitted by, and the payment to, generation and demand-based projects will be based on the quantifiable benefits from deferring transmission projects identified in the integrated plan.

After approval by the responsible Public Agency, the project would proceed with any remaining permitting and siting requirements to begin construction.  It is a desired outcome that approved projects face no undue regulatory burdens.  Since the responsible Public Agencies would be participating in the ISO process while conducting their own parallel proceedings, this is a more reasonable outcome than that which may arise if ISO and agency positions are not coordinated.  

POSITIONS OF THE PARTIES – The Two-Part Planning Process

April 27, 1999 Stakeholder Comments

CPUC staff wrote that appropriate coordination between utility and ISO planning processes and state siting processes is among the most important reliability issues to be resolved in the new California electricity market and that the creation of the ISO requires changes to grid planning and may require changes to the relationship between planning and siting.  The CPUC letter raises the agency’s concern that the ISO proposal overreaches its grid planning responsibilities, and enters into a regulatory role of “picking winners and losers, rather than relying on the market.”  The CPUC stated that clarification is needed as to whether all, meaning both reliability-driven and market-driven, proposed generation and transmission projects would be required to participate in the competitive process.  The CPUC also requested clarification regarding the eligibility of market-driven projects for the proposed three-year commitments and clarification of the criteria used to differentiate reliability-driven projects from market-driven projects. 

The IEP supports the proposal’s concept of a “one-stop shop” for reliability analysis and believes the ISO is “best suited to evaluate a project’s transmission impacts given the annual reliability  assessment process…” The IEP stated that “third-party transmission project proposals should be made to the ISO, with the ISO requesting the scope of studies required by the PTOs.  The IEP suggests that the ISO may need to review the proposed Part I timeline to ensure sufficient time for decision making and the public processes associated with the review process.  In addition, the IEP stated that  Part II should apply only to annual assessments and proposed transmission projects; new generation interconnection applications should not be subject to a subsequent solicitation process. 

Sempra Energy supports a more proactive transmission planning role for the ISO in the future in order to facilitate coordination that promotes adequate levels of transmission development for reliable service and competitive electricity markets.  Sempra further states that the ISO’s active participation will ensure a more credible process and assist with the prompt completion of siting processes.  However, Sempra recommends that the ISO proposal be clarified “to avoid injecting undue timing constraints and cost inefficiencies into the planning process.”  Sempra also believes that the “two-part process is too lengthy and exhaustive to effectively ensure continued transmission system reliability,” and estimates that an additional year would be added to project planning.

Sempra Energy opposes Part II’s submittal of a “cost bogey” through the RFP process, stating that “the use of such a bogey is nothing more than another form of selecting resources based on an avoided cost calculation. “ Sempra suggests that one outcome of using a “bogey” will be that market participants will propose alternatives that are unnecessarily too expensive and that a second outcome will be the disincentive for contractors to bid low because they will already know what the PTO expects the project costs to be.  Sempra also stated that when competing market participants know the cost for a proposed project submitted by the PTO “they will submit alternative ‘competing’ proposals at price levels slightly undercutting the bogey.”

BPA states that the current PTO Annual Assessment process is open to market participants and that they would like to see this practice continued.  BPA also urged the ISO to “develop and implement a review process which will be meaningful and effective.”  BPA mentioned a concern that in the past the ISO has solicited “input from market participants [but] comments were not always given a fair hearing, or explanations were not given as to why they were rejected.”   

Roseville Electric wrote that it is not objective or efficient for the proposal to rely exclusively on PTOs for technical analysis of all proposals.  Roseville opposes this and states, “This would mean that [the IOUs] would be evaluating proposals from municipal utilities, PMAs and IPPs which would potentially compete with their own plants and facilities.” 

The Transmission Agency of Northern California (TANC) wrote that the ISO’s leadership role in grid should be that of “facilitator or integrator in a complex matrix organization, not one of a preeminent authority in transmission planning.”  TANC believes that the two-part process is limited from a competitive standpoint and “extremely cumbersome” adding that the challenge of coordinating regulatory agencies and obtaining final approval creates a two- to four-year planning process.
Southern Company believes it is appropriate for the ISO to take a more active role in the grid planning process and the proposed two-part process “provides transparency and credibility.”  However, Southern stated that more work is needed to clarify each party’s role and responsibility.”
PG&E believes the current process allows the ISO and PTOs “considerable and appropriate latitude in discharging their planning obligations,” that this flexibility is positive and that it has been working effectively with the ISO to address reliability issues.  PG&E further believes that the “fundamental premise” of the ISO proposal “appears to be that the ISO should become solely responsible for all aspects of planning, while the PTOs would be reduced to planning advisors and technical subcontractors.  We see no basis for such a fundamental shift in roles and responsibilities where the PTOs would still be obligated to plan, finance, construct, and seek cost recovery of transmission projects that others cannot or do not provide competitively.  Such a framework would be highly problematic.” 
Calpine and Bechtel Enterprises (BEn) raise concerns with respect to the interrelationship between transmission and generation.  Calpine and BEn caution that the planning process must recognize the difference between transmission, which is still heavily regulated and generation, which is largely unregulated and subject to market forces.  Calpine and BEn state that new generation should bear the costs of interconnecting to the grid and that all transmission upgrades (necessary to serve load) should be evaluated on a public benefit basis.
Calpine and BEn propose that in circumstances where congestion is a factor in the interconnection of a new, more efficient, generator, the less competitive generator should be curtailed.  Where two equally competitive generators are competing for constrained transmission capacity, Calpine and BEn suggest that the ISO should direct the PTO to expand.  Calpine and BEn assert that under no circumstances should an existing or new generator be able to buy available transmission capacity or otherwise gain rights to transmission capacity.
Calpine and BEn state that the ISO’s contemplated competitive process should not apply to new or existing generation, unless it is in response to the competitive solicitation.
Edison states that the current open process for examining and reviewing the five-year bulk power programs of the PTOs works.  Edison states that the ISO has much more than an advisory role, as is evidenced by the ISO’s rejection of three of Edison’s eight project proposals.  Edison states that the current ISO proposal does not address certain of the funding and cost-recovery issues associated with wires or non-wires alternatives.  Moreover, the ISO has not demonstrated that there is a conflict of interest between PTOs performing transmission planning assessments and other PTO interests.
Edison also states that reliability needs should be the “bogey” for the competitive process and that use of the transmission projects as the basis for the competitive solicitation puts the transmission solutions at a competitive disadvantage and may reduce the chance of a lower-cost alternative being identified.  Edison states that thee are a large number of unresolved issues with respect to the competitive process including:  a method for evaluating alternative solutions, cost-recovery of non-wires solutions, commitment period, lead-time, etc.
Edison also states that generation interconnections should continue to be processed throughout the planning period and not be required to have applications submitted by ther start of the PTO’s annual planning cycle.
NCPA states that the ISO proposal is “planning by parts” (i.e., by local area) and that the final result should focus on meeting overall, state-wide, grid reliability.
June 14, 1999 Stakeholder Comments
Edison reiterated its concerns with regard to establishing a “transmission project/price” bogey.  Edison believes that we should identify only the “need” but not the cost of the transmission projects so that all potential bidders (i.e, generation, transmission, demand-based) will be on an equal footing and treated comparably.  Edison stated that bidding should be confidential.
PG&E raised concerns with respect to process, and stated that we should not be bound by arbitrary deadlines at the expense of process and the development of well-thought-out proposals.
Sempra raised concerns with the establishment of a “bogey” and  interface between of Part I and Part II of the process. 
DWR stated that generation and demand-based projects can be just as “dependable” as transmission projects if the appropriate contracts are entered into between such projects and the ISO.
PG&E raised concerns that third-party transmission projects will compete against the PTOs proposals.  ISO should identify needs and then solicit proposals to satisfy them.   PG&E stated that the PTOs still have responsibility for reliability.  PG&E also states that the PTOs should not be obligated to build “projects of last resort”.  PG&E raised concerns that the process may be too long to accommodate changing conditions on the grid and that the ISO may want to establish a threshold level at which the planning process requirements would apply.  
NCPA states that there is no overall statewide planning process.  NCPA states that there are not enough resources within the state to satisfy the demand and that something needs to be done.  NCPA urges the ISO to develop a statewide integrated transmission plan.
Calpine asked when the Part I and Part II process, if approved by the Board, will be implemented.  Calpine also asked about what kind of commitments (CEC, AFC) the ISO will require for generation and other projects.  Calpine stated that the ISO should consider “unsolicited” offers from developers to satisfy an ISO need.  Calpine also cautioned the ISO in regarding transmission solutions as always reliable, since lines can go out of service or be derated.  DWR also expressed some reservations with the way the ISO will compare the dependability of transmission and generation projects.
Dynegy asked when the ISO will solicit Voltage Support Service and asked whether the ISO will consider “paying load to leave” if it will pay for generation to locate in specific areas.
ISSUE No.3 – Interface and Coordination with the State’s Transmission and Generation Siting Agencies

First, the ISO sees clear benefits from a consolidated state siting process.  The ISO believes that both transmission and generation siting should be overseen by a single Public Agency.  A consolidated siting process will ensure that consistent evaluation criteria will be applied to both transmission and generation projects.  Moreover, the ISO believes that consolidation in a single agency will enable the state to establish and administer a common set of public policy goals.  Most importantly, the ISO believes that a consolidated siting process will expedite the siting process.  Under the ISO’s proposal, the information and results of the ISO planning process will be applied in the Public Agency siting process.  Therefore, we anticipate that this will facilitate an expedited review at the siting agency.

The ISO has no opinion at this time regarding which state agency should perform the consolidated siting function.  However, the ISO believes that the agency that ultimately undertakes these responsibilities should be vested with the authority to overrule local authorities in cases where the state’s interests are preeminent over the interests of local authorities.  In addition, the ISO believes that the consolidated siting agency should have the authority to exercise the power of eminent domain or convey such powers on the ISO.  The power of eminent domain is a critical element in the planning and siting process.  Absent such authority, or the ability to have an agency exercise it on the ISO’s behalf, the ISO could be foreclosed from considering a number of transmission projects proposed through the planning process outlined above.

CEQA and Eminent Domain Issues

Integration of, and coordination between, the ISO’s grid planning process and CEQA reviews is important.  The ISO will evaluate projects from several perspectives (reliability and/or economic), while the agencies performing CEQA reviews (the CPUC, CEC, or municipal agencies, depending on the nature of the project) are required to balance the need for a project (or its alternatives) versus any significant environmental impacts.  Since the basis for review will be different, it is probable that the ISO and CEQA agencies may rank alternatives differently.  The end result is that the ISO process may result in the selection of one project while the CEQA review may result in the selection of another.  The various roles of the CEQA lead agencies, which are governmental, and of the ISO need to be examined to allow full public review without unnecessary duplication.  The simplest approach to this problem may be that the ISO review projects from a reliability and cost perspective and then formally introduce the results into the CEQA lead agency’s process.  The CEQA Lead Agency would be the body to weigh all of this information.  An alternative approach, as discussed earlier, would be for the ISO to incorporate environmental impacts into its LARS evaluation criteria.  Incorporation of state public policy goals into the LARS process would ensure that state objectives are satisfied.  As envisioned, the CPUC, CEC, or relevant lead agency would have every opportunity to participate in the LARS process.

The newly restructured environment is resulting in mostly, if not solely, independent power projects.  The ISO Tariff and FERC orders have provided for “economically driven” transmission projects.  This raises two important issues with respect to how eminent domain authority will be exercised in the newly restructured environment.  

First, if a project is independently sponsored (i.e., by a non-utility market participant) there is no statutory authority available for the use of eminent domain should such power be necessary to the completion of a transmission project.  Currently, utilities and specified agencies are the only ones with statutorily conferred eminent domain authority.  While there has been thought given to the ISO eventually obtaining eminent domain authority, there are other factors to be considered.  Currently, the CPUC (on behalf of investor-owned utilities) or public agency boards (on behalf of municipal utilities and other publicly owned utilities) serve as “lead agencies” for purposes of finding transmission projects to be to the benefit and convenience of the public.  Should it be decided that the ISO, in its role of providing open access to transmission service, be able to exercise eminent domain authority on behalf of itself or confer such authority on a third party, a public “lead agency” would likely need to be designated for purposes of finding projects to the benefit and convenience of the public.

Second, even if the above problem is solved—whether the ISO obtains eminent domain authority or whether some agency can exercise eminent domain authority on behalf of the ISO, there is a question raised about the nature of “economically driven projects.”  Current eminent domain law is fairly restrictive with respect to definitions of public benefit and necessity.  While reliability-driven transmission projects can arguably be tied to public benefit and necessity, it becomes more difficult to justify eminent domain powers in the case of commercially driven (i.e., for profit) projects.  However, if the economics of a project are beneficial to the citizens of California, the tie to a public benefit could exist.

ISO Management recommends that the ISO further develop the policy and legal issues associated with eminent domain authority and/or CEQA lead agency authority.  This effort should be coordinated with the CEC, CPUC and the California Electricity Oversight Board—all of whom are interested in addressing the issue of how eminent domain authority will be exercised on behalf of non-utility sponsored transmission projects.

POSITIONS OF THE PARTIES – Coordination with State Agencies on Siting

April 27 Stakeholder Comments

Edison does not believe that addition of eminent domain authority is needed by the ISO, EOB, or market participants to ensure transmission construction.  Edison states that under the ISO Tariff the PTOs have an obligation to build, and that if others want to build reliability projects they can become utilities.  Edison states that use of eminent domain authority for economic projects is inappropriate.

PG&E states in its submitted comments that this proposal includes a “radical change in the process for siting not only transmission but also generation projects because of their potential impact on transmission reliability.”  PG&E also stated that while the ISO’s goal to streamline the regulatory process is a “laudable goal, the first step is to determine what aspects of the siting processes need fixing.”
IEP supports the ISO as “best suited to evaluate a project’s transmission impacts given the annual reliability assessment process and that the ISO’s evaluation should be directly incorporated into the siting process.”
Southern Company stated its belief that the current siting process is “fragmented and inefficient,” and that it will be difficult to establish a consolidated state siting process.  Southern recommended additional discussions and involvement of stakeholders and “other interested parties.”
The CPUC stated that the ISO proposal requiring siting agencies to participate in the ISO planning process “may conflict with the CEQA requirement that permitting be conducted by a public agency and include consideration of project alternatives.”  The CPUC went on to state that public agency staff participation in the ISO planning process could “add value to the process, and reduce the potential for conflicts between the outcome of the ISO process and the siting process.”  The CPUC added that “under current law, such participation could neither bind the Commissioners of the siting agency, nor replace the siting agency process.”
Edison states that mandatory Public Agency participation in the ISO planning process will not necessarily ensure approval in the permit process, meet CEQA’s legal requirements or shorten licensing time.

June 14 Stakeholder Comments
CMUA is concerned that the ISO proposal lacks clarity as to specific ISO Management recommendations regarding the role of local regulatory authorities in transmission planning and siting.  As the ISO is aware, municipal agencies may serve as Lead Agencies for CEQA review of transmission projects.  Also, the federal government has sheparded transmission projects through environmental review for recent major additions to the integrated California transmission grid.

CMUA is concerned that this continuing role of its members and other agencies in the siting and review process is not addressed in the document.  Statements such as "state Public Agencies may need to have the authority to overrule local authorities," while apparently focused on conflicts between state siting desires and local government general plans, add confusion regarding the ISO position on continued authority of local regulatory authorities to site and review transmission
projects.

CMUA states that its members retain the obligation to meet the electric service needs of their customer-owners, and must have the necessary tools fulfill this obligation.  At the same time, CMUA and its members recognize the role of the ISO in integrated grid planning.  CMUA states that it interprets the ISO proposal as not recommending any particular policy direction on the issue of continued siting authority for local regulatory authorities, and seeks clarification in this regard. 

The City and County of San Francisco raised concerns that the ISO proposal presumes a certain role for state agencies and that the role of state agencies is a matter largely out of the ISO’s control. 
ISSUE No.4 – Regional Coordination
ISO Management is concerned that too many organizations are presently responsible for coordinated regional planning.  Currently, three different Regional Transmission Groups (RTG) in the WSCC region perform similar functions, although for different groups of members.  These three RTGs are: 
•	Western Regional Transmission Association (WRTA) whose members cover much of the WSCC area; 
•	Southwest Regional Transmission Association (SWRTA) whose members are primarily located in the Arizona/New Mexico area; and 
•	Northwest Regional Transmission Association (NRTA) whose members are primarily located in the northwest.
In addition to the three RTGs, there is an organization called the Colorado Coordinated Planning Group (CCPG), as well as an umbrella organization that covers all of these groups called the Western Interconnection Coordination Forum (WICF).  It is likely that a single organization, or fewer organizations, could more efficiently and effectively facilitate coordinated regional planning.
ISO Management supports ongoing work toward consolidating the RTGs, WICF, and the CCPG into a single organization or a streamlined set of organizations.  It may also be possible that WSCC could fill the role of this single organization by expanding its responsibilities to include coordinated planning and commercial issues.  When the RTGs were formed, FERC stated its preference for the West to have a single RTG and that the WSCC could fill that role. 
Presently the Western Interconnection Coordination Forum is addressing this issue.  The ISO is a participant in this forum and is actively involved in resolving this issue.
ISSUE NO.5 - Responsible for Grid Reliability

It is not clear who is primarily responsible for ensuring that transmission facilities are in place when needed to provide for adequate system reliability.  Presently, based on the ISO Tariff and the Transmission Control Agreement (TCA), both TOs and the ISO share the responsibility for planning a reliable grid.  This raises the question of who will be held accountable if facilities are not in place when needed and reliability problems develop.  With the TOs having a significant role in planning responsibilities, there is also a potential concern with inappropriate incentives on the part of TOs either to advocate or defer transmission upgrades or expansions and whether the TOs can objectively weigh alternatives to transmission expansion.

Management believes that ultimate responsibility for ensuring the safe and reliable operation of the grid lies with the ISO.  However, in that capacity, ISO management believes the ISO must have the ability to direct the scope and assumptions of studies performed by the TOs, as discussed above.

June 14 Stakeholder Comments

PG&E, Edison, Dynegy and others raised the question as to who is ultimately responsible under the ISO’s proposal for grid reliability.  Dynegy stated that the ISO should be more proactive in assessing the adequacy of the PTOs’ maintenance practices and proposed projects and following through on these matters in the applicable PTO’s rate cases at FERC.

Management Response to Stakeholder Comments

With respect to comments on the role of the ISO, PTOs, stakeholders and Public Agencies in the planning process, we reiterate our position that the ISO intends to coordinate our activities with the PTOs and all interested stakeholders on the development of an integrated transmission plan.  Our proposal provides for the continued coordination with the PTOs but establishes a proper authoritative role for the ISO where matters are in dispute or where the ISO’s independent analysis indicates that additional or different studies should be performed.

We also believe that as part of that function, the ISO must bear primary responsibility for grid reliability, consistent with our statutory obligation.  However, we do not believe that our proposal eliminates any responsibility on the part of the PTOs to reliably plan and operate their respective systems.  Reliability is a shared responsibility.

A number of parties raised concerns that the ISO needs to examine the statewide need for transmission.  Our intent is to develop an integrated statewide transmission plan from the three PTOs’ annual planning assessments by the end of 1999.  Completion of the integrated plan will constitute completion of Part I of the planning process.  Early in 2000, we anticipate publication of the integrated plan and initiation of the competitive phase of the planning process (Part II).

We agree with PG&E that the ISO should consider threshold levels at which projects will be subject to the ISO’s proposed planning process.  We do not want to create an inflexible process that prohibits transmission owners from responding to changing system conditions and customer demands, especially at the lower voltage levels.  Moreover, we do not want to discourage transmission owners from initiating innovative proposals like the PG&E Rocklin RFP which are consistent with the ISO’s proposed approach.  We intend to further explore this option and make a recommendation to the Board in August as part of our overall implementation plan.

We will also consider Edison’s, SDG&E’s and PG&E’s statements that use of a “transmission cost-bogey” in Part II of the planning process is unfair and biases the solicitation process.  While we believe that establishing a “transmission bogey” is appropriate and necessary, we are willing to consider whether the ISO should disclose price information.  Price information is typically treated as confidential by the ISO in the PTO Annual Planning Assessment process.  We emphasize that it is not the ISO’s intent to implement an “avoided cost” procurement process, whereby generation and demand alternatives to transmission projects bid just below the cost of the proposed transmission project .  As we stated above, we will not consider generation and demand-based projects whose bids are substantially the same as a transmission project’s to be comparable.  We continue to believe that transmission projects are by their nature more reliable and available than generation or demand-based alternatives.

With respect to ISO/Public Agency coordination, while we recognize that certain decisions will be made by the state legislature on these matters, we believe it is necessary for the Board to establish a planning procedure that contemplates close ISO/Public Agency coordination and for the ISO to advocate such policy before the appropriate state bodies. We also clarify for CMUA that the ISO’s proposal does not contemplate a new or diminished role for Local Regulatory Authorities with respect to transmission and generation siting.  However, we strongly encourage municipal participation in our planning process and  anticipate that such entities would be part of the ISO’s planning process should they decide to join.   

MANAGEMENT RECOMMENDATION
Management recommends that the Board approve the recommendations contained in the body of this memorandum and approve the proposed motion.