California Independent 
System Operator

Memorandum
										
To:	Market Participants				
From:	Stephen Greenleaf, Director of Regulatory Affairs
	Brian Theaker, Manager of Reliability Contracts
Date:	July 11, 2000
Re:	Draft Recommendation on Competitive Solicitation for SDG&E’s Valley-Rainbow 500 kV Transmission Project 
 At the May ISO Governing Board meeting the Board directed Management to bring back to the Board a recommendation on the “parameters and process” for proceeding with a competitive solicitation (Valley-Rainbow RFP) to determine if there are cost-effective and reliable alternatives to SDG&E’s proposed Valley-Rainbow transmission project.  Information on the project can be found at http://www.caiso.com/thegrid/planning/sdge500kvtrans.html
	These matters are scheduled to be addressed at the August 1 Board meeting. Outlined below are Management’s preliminary thoughts and recommendations on how to structure the process for conducting and the parameters of the Valley-Rainbow RFP.  Please provide us your thoughts and feedback on these matters no later COB Friday, July 21.  Please send your comments to: sgreenleaf@caiso.com and btheaker@caiso.com. While the recommendations outlined below are clearly a work-in-progress, it is imperative that we receive your substantive feedback early so that we can develop a fair and reasonable final recommendation. Thanks for your time and consideration.
THE PROCESS
	Proposed Timeline
	Management proposes that the Valley-Rainbow Project competitive solicitation be conducted according to the following timetable:
August 11	ISO issues a Request For Proposal (RFP) for non-wires alternatives to the Valley-Rainbow Project pursuant to the parameters approved by the Board at its August 1 meeting;
	September 1		Due date for letters of intent to respond to the RFP;
November 3		Due date for responses to the Valley-Rainbow RFP;
November-January	ISO Management evaluates the responses.  Such evaluation includes an assessment of the proposed project’s impact on reliability and a determination as to what facilities and/or transmission system upgrades are necessary in order to connect the proposed non-wires project to the grid.  If necessary, Management will request that SDG&E assist Management in determining the connection requirements of proposed projects.  (Management will not disclose the name of the respondent or the price bid of the project).  Management may also meet with individual respondents to gain a complete understanding of their proposal;
February 2001	ISO Governing Board determines whether to proceed with the development of the Valley-Rainbow Project or to select a non-wires alternative.  
	We believe the proposed timeline provides potential respondents ample time to submit a response to the RFP, provides ISO Management the essential time it needs to properly evaluate any non-wires project proposals received, and ensures that SDG&E will be able to keep to the Valley-Rainbow Project’s critical-path schedule.  We believe that a ninety-day response time is sufficient in light of the fact that discussions regarding the Valley-Rainbow Project have occurred over the past several months and that issuance of the RFP has been long anticipated. Management cautions that any extension of the time period to respond to the RFP must be accompanied by an extension of time for Management to review the project.  In addition, further extending the timeline may jeopardize SDG&E’s ability to proceed with the Valley-Rainbow Project.     
THE PARAMETERS
	Policy Issues
	In order for Management to proceed with a competitive solicitation on the Valley-Rainbow Project, we believe the issues outlined below must be addressed.  Management has identified various options for resolving these issues and has identified preliminary preferred alternative.  We believe that the recommended resolution of the following issues will address the concerns that certain Board members and Market Participants had with respect to fairness and specificity of the evaluation criteria in the Tri-Valley RFP.   
Policy Issue No. 1:  Is the ISO’s conceptual approach of paying non-wires alternatives a “locational incentive” to locate in an area that supports the grid applicable to the Valley-Rainbow Project?
During the development of its long-term grid planning process in 1999, the ISO stated its willingness to compensate generation owners for the legitimate and verifiable costs they would incur from siting their project in the area of need, as opposed to their “preferred” site.  Such costs may include the increased cost of securing land, land rights, fuel, air permits, and other costs that may increase as a result of locating in a developed area as opposed to a preferred site, such as in the desert, where interconnection, fuel and land costs are lower.  The premise of the ISO’s approach was that generation should come into the market based on an expectation of market revenues (not payments from the ISO), but that that ISO could furnish an incentive for generation to locate in areas that would support the grid.
In its competitive solicitation regarding Pacific Gas and Electric’s Southern Tri-Valley transmission project (“Tri-Valley RFP”) the ISO learned that by identifying a developed/developing area as the preferred site, the ISO implicitly changed the type of generating facility that a respondent could and would use to satisfy the need.  Had the preferred site been in the desert, a respondent/developer could have used a larger, more efficient generating facility such as a gas-fired combined-cycle facility.  However, by requiring that the project be located in the Tri-Valley area, the ISO was effectively requiring a developer to utilize a smaller, less efficient, generator that would not have as great an impact on the local community (visibility, noise, etc.) and resources (air, water, etc.).  By “requiring” the use of such less efficient generation, the ISO was necessarily limiting the opportunities for such a resource to participate in the market.  Whereas an efficient gas-fired combined-cycle unit, by virtue of its low heat rate, is competitive and will therefore run more often in the market, a gas turbine unit is likely to run only during the peak periods and therefore would have to recover all of its costs (e.g., return on and of investment capital and operating expenses) during a limited number of hours.  The bids the ISO received in response to the Tri-Valley RFP from generation developers reflected this fact.
Based on these considerations, Management believes the following options should be considered:
Option 1:  Apply the “locational incentive” conceptual approach to Valley-Rainbow and explicitly state that the ISO is willing to compensate non-wires projects for the legitimate and verifiable costs of locating their project in a manner and in an area that will satisfy the reliability requirements proposed to be addressed by the Valley-Rainbow Project.
Pros:	This approach is consistent with the conceptual approach of only paying non-wires projects for locational cost differences and does not place the ISO in a position of having to underwrite or subsidize a non-wires project’s market activities.
Cons:	The ISO cannot be guaranteed that the Rainbow or Pala areas are areas where a non-wires project can otherwise locate a competitive resource (i.e., where there is easy access to fuel, water and other supplies and where a resource can obtain the necessary air, land and other necessary permits).
Option 2:  Do not specify any parameters for payment and let the individual respondents develop bids structured around their individual requirements for cost recovery.
Pros:	Provides for a flexible approach to paying non-wires projects whereby each respondent can reflect in its bid what they believe to be necessary and appropriate cost recovery.
Cons:	Places the ISO in the difficult position of potentially underwriting a non-wires project’s market activity and thereby susceptible to allegations that it is “re-bundling” products (transmission and generation/load) that were previously unbundled in the restructured market.
Recommendation:
Management recommends Option 1.

Policy Issue No.2:  Can a non-wires project effectively “displace” the Valley-Rainbow Project or will a non-wires project merely “defer” the Project? (i.e., Should the ISO pre-specify the period of time it is willing to contract with a non-wires project?)
	In the Tri-Valley RFP, the ISO stated that it would contract for non-wires alternatives for a five-year period (2001-2006).  The five-year period was based on a presumption that load growth in the area was such that the transmission project would have to be built in five years anyway, regardless of whether non-wires projects are selected initially (i.e., a deferral period).  As noted above, the ISO’s conceptual approach for compensating non-wires alternatives, combined with the five-year term, resulted in making the generation-based non-wires alternatives uneconomic.  Therefore, we believe there are a number of options for evaluating non-wires alternatives, as outlined below:
Option 1 - Deferral::  Compare the cost of a non-wires project against the cost or value of “deferring” the proposed transmission project for a certain number of years.  The fundamental premise of this approach is that any such non-wires alternatives will only defer construction of a proposed transmission project. Therefore, based on that premise, the value of a non-wires project could be determined by calculating the present value of the savings realized by delaying the construction of the proposed transmission project some number of years. Such savings can be estimated by calculating the net present value of the cost stream of the transmission project by first estimating the annual cash flow by applying a reasonable carrying charge to the total cost of the transmission project.  A carrying charge is the amount of money needed to cover a reasonable return on the investment (debt and equity), taxes, operation and maintenance, etc.  A typical carrying charge on such transmission investments is around 15%.; a very conservative carrying charge is 20%.   It should be noted that factors such as escalating real-estate costs may create additional costs, not savings, by deferring a transmission project.
Pros:	The deferral method necessarily recognizes the benefits of transmission expansion (e.g., greater access to regional markets, increased operating flexibility) and therefore results in more transmission being built.  This benefit is particularly clear in this instance.  ISO Management believes that the Valley-Rainbow Project is a necessary first step in upgrading the regional transmission system.  Moreover, with respect to the San Diego basin, both transmission and generation/load management are needed.  
Cons:	Generation projects are less likely to compete with transmission projects on a deferral basis. 
Option 2 - Displacement :  Compare the cost of a non-wires project against the cost or value of “displacing” the transmission project.  Under this approach a non-wires project would be compared to the total cost incurred from building the transmission project.  The value of displacing the transmission project would then be determined by calculating the present value of the stream of payments for the transmission project over the life of the facility.
Pros:	Assuming that they are complete substitutes, the displacement method will enable generation and load-based projects to compete more effectively with transmission.
Cons:	The displacement method does not recognize the other benefits of transmission expansion, such as increased operating flexibility, staging transmission requirements and increased access to the market.  Furthermore, the “displacement” method requires continued reliance on the non-wires project and therefore raises concerns both with respect to maintaining “reliability through contracts” (potentially long-term contracts) and market power issues (e.g., the non-wires project may be the only “solution” that exists in a given area on a going forward basis).
Option 3 – Compare Costs of Alternative Projects over Fixed Time Period:  Compare the cost of a non-wires project and transmission project over a fixed period of time (e.g., the period associated with the incremental “need”) , based on the net-present value (NPV) of the stream of payments for each of the projects.
Pros:	Reduces the probability of assertions that the ISO’s methodology was unfair or inappropriate.
Cons:	Places particular emphasis on the need to select an appropriate evaluation time period.  See Issue No. 3 below.
Option 4 – Deferral With 50%Benefit Cap:  SDG&E proposes that the maximum capital benefit of deferring the Valley-Rainbow Project should not exceed 50% of the annual deferral value in order to provide savings to San Diego area customers.
Pros:	Places an appropriate emphasis on the benefit to end-use customers.
Cons:	Places non-wires projects at a significant disadvantage with respect to their ability to compete against transmission projects.
Recommendation:
	At his time, Management recommends Option 3.  Application of both the deferral and displacement methodologies can satisfy reliability requirements.  However, when applying the displacement method, it may be difficult to determine the timeframe associated with cancellation.  On the other hand, there may be better advantages to selecting bigger projects (e.g., transmission).  In any event, there may be an inherent risk to selecting one type of project over another due to the multiple externalities (e.g., fleeting opportunity to obtain the necessary environmental and right-of-way acquisitions, etc.).  Depending on the project complexities, each one may require a quantitative as well as qualitative analysis.

Policy Issue No.3:  What is appropriate time period for evaluating proposals?
A significant issue related to the time-period question is the issue of what capability should the ISO attribute to the transmission project.  In the Tri-Valley case, the ISO used, but did not expressly state up-front, 615 MW as the transfer capability of the proposed transmission project.  While the ISO did not include an express reference to the 615 MW capability of the transmission project in the Tri-Valley RFP, the ISO understood that such information is readily ascertainable when reviewing the details of the proposed project (if you recall, the ISO did not expressly provide the dollar amount or other details of PG&E’s proposed project, to avoid respondents from specifically using those numbers as benchmarks for their bid).  At the April Board meeting, Board members and others raised concerns that it was inappropriate or unfair, when developing per unit costs for comparison purposes, to use the 615 MW number for the transmission project and only the 175 MW (requested in the Tri-Valley RFP) number for the non-wires projects.  Parties stated that use of different numbers for each proposal was inappropriate and would lead to an “apples-to-oranges” comparison.
As a way to avoid such “apples-to-oranges” comparison, parties asserted that 1) the ISO must make clear the magnitude of the reliability benefit provided by the proposed transmission project; 2) it was essential that all proposals be evaluated over the same time period and 3) the time period should have some relationship to the value of the projects to the ISO.  For example, parties argued that in the case of Tri-Valley the ISO should have evaluated the cost of all proposals over the twenty-year life of the transmission project (when the “full” 615 MW capability of the project would be utilized).  Absent such a comparison, certain parties believe that it would be inappropriate to attribute the full (but not utilized) capability of a transmission project when determining such project’s unit cost.
Therefore, an appropriate issue for resolution is whether the ISO should establish (and explicitly state) an evaluation period that would be applicable to all proposed projects, including a transmission project.
	Option 1:  Specify that the evaluation horizon will be the service life of the transmission project.
Pros: 	Recognizes the full value/cost of the transmission facility over its depreciable life.  Enables non-wires projects to be compared against the cost of transmission over a comparable time period.  (To the extent that a non-wires project can only defer a transmission project for a portion of the evaluation period, the “cost” of the non-wires alternative would be its bid costs plus the cost of supplementing its bid to secure the necessary reliability resources, which may be the cost of building the transmission project).
Cons: 	May require that the ISO enter into longer-term arrangements with non-wires projects, which could reduce the ISO’s flexibility in satisfying its reliability requirements on a going forward basis.
Option 2:  Do not specify a time-period for evaluating proposals but instead base the ISO’s evaluation on a strict $/MW criterion.
Pros	Permits the ISO to flexibly evaluate proposals based their value to the ISO (including the period of time they are of value to the ISO).
Cons	Raises issues as to whether proposals have been appropriately and fairly evaluated.
Option 3:  Determine the evaluation horizon by the number of years the project meets the reliability criteria (i.e., satisfies incremental load growth).
Pros	Permits the ISO to flexibly evaluate proposals based their value to the ISO (including the period of time they are of value to the ISO).
Cons	Does not necessarily fix the time period for evaluation up front at the beginning of the process and may result in projects being evaluated over different time periods
Recommendation:
Management recommends Option 3. 

Policy Issue No.4:  What cost recovery method is appropriate and how and when should the ISO secure approval of the preferred cost recovery mechanism?
In Tri-Valley the ISO proposed to recover the costs of any non-wires projects selected in the process by passing those costs on to PG&E and requiring that PG&E recover such costs through its transmission rates.  While the conceptual approach was not necessarily opposed by PG&E or the respondents to the Tri-Valley RFP, certain parties did state that they are opposed to recovering such costs through transmission rates.
Option 1:  Recover the costs of non-wires projects through transmission rates.
Pros:	Recovery of non-wires costs through transmission rates is consistent with the concept that such costs are incurred “in lieu of” transmission investment.  Moreover, recovering such costs through transmission rates will provide the necessary price signal to the applicable transmission owner to upgrade he transmission system.
Cons:	In the case of Valley-Rainbow, SDG&E is opposed to recovering the cost of any non-wires project(s) through its transmission rates.  Based on the likely opposition of SDG&E (the host utility), it is unlikely that the ISO will be able to secure the necessary tariff authority at FERC.  Moreover, based on informal discussions with FERC staff, they are unlikely to approve recovery of such costs for two reasons:  1) it “rebundles” transmission and generation costs -  contrary to the purpose and intent of Order No. 888; 2) such “incentive” payments to non-wires projects would be unnecessary if the ISO had established appropriate price signals to such resources in the first place (through its congestion management process).  In addition, FERC staff indicated that transmission rate recovery of such costs may be more acceptable if the ISO brought the issue before the Commission as a policy issue that was common to all the ISOs in the country (I.e., filed a joint Petition for Declaratory Order with the other ISOs).  While Management is not opposed to such an approach, we believe the timing of the Valley-Rainbow project is such that we may not receive guidance from FERC in the necessary timeframe (i.e., within the year). 
Option 2: Recover non-wires project costs through specific tariff provisions that asses the costs to SDG&E (applicable Participating Transmission Owner) but do not prescribe that SDG&E must include such costs in its transmission rates.
Pros:	May enable the ISO to secure SDG&E’s support in securing FERC approval of the necessary cost-recovery provisions.
Cons:	May mute what we believe are appropriate price signals to the applicable PTO (SDG&E in this instance) regarding the need to upgrade or expand their transmission system.  In addition, recovery of these costs through “RMR-type” cost recovery mechanisms may blur the difference between these services and RMR and thereby raise most-favored nations (MFN) issues with existing RMR contract holders. 
Recommendation:
Management recommends Option 2.

DETAILS OF THE PROPOSAL
	Based on the recommended resolution of the above issues, at this point we believe that the Valley-Rainbow RFP should specify and include the following details:
Each proposed project must demonstrate that:
•	The alternative can meet the reliability needs of the San Diego service territory (reliability needs include meeting the ISO’s reliability criteria (G-1/N-1), providing voltage stability and reactive power support (MVar Margin - see attached table entitled, “SDG&E Area Needs for Competitive Solicitation.”)
•	The alternative offers reduced capital cost and operating cost benefits to San Diego area customers, including reducing RMR contract requirements and offering assurances and quantifying such benefits to the same extent possible as the Valley-Rainbow Project. 
•	The project can meet an in-service date of 2004 (each respondent must include a Project Development Schedule, the details of must include target dates for significant project milestones, and a plan and schedule for obtaining, as applicable to the project being proposed, all required land rights, all applicable permits, fuel and water arrangements, interconnection, metering and telemetry arrangements and any necessary contractual commitments with third parties
In addition, respondents should provide the following information, if applicable:
•	Alternative generation proposals must include potential impacts on generation market power and LARS requirements in the San Diego area.
•	Alternative load reducing proposals shall include an evaluation of their ability to verifiably sustain the stated load reduction over time (see requirements as stated in Attachment II to the RFP).
Reliability Assessment
	As part of the ISO’s evaluation process the ISO will determine whether a proposed project satisfies the reliability requirements of the ISO by:
•	Determining the net load serving capability of each alternative, including whether a project could reduce the ISO’s import capability due to the project’s location and placement within the transmission system;
•	Evaluating alternatives over several different planning horizons: 1 yr., 3 yrs., 10 yrs., etc.;
•	Determining the percentage availability of the supply component at coincident system peak demand in terms of Loss of Load Exposure (LOLE), Loss of Load Probability (LOLP), etc.; 
•	Determining the expected number of years the project will satisfy the reliability requirements; and.
•	Evaluating whether the proposed Project Development Schedule is viable.
Cost Assessment
The next step in the ISO’s evaluation process will be a determination of each project’s costs/benefits and shall include the following:
•	A determination of the net present value of the cost of each project over the period it satisfies the stated reliability requirements;
•	A qualitative assessment of the project’s impact on the Ancillary Services markets, LARS/RMR services and market power, congestion, losses, and other effects on market competition; and
•	A determination of the cost of additional transmission upgrades/projects, if any, necessary as a result of selecting the project; and
•	A qualitative assessment of risks including the limited window of opportunity to build the Valley-Rainbow project (If the project is deferred, even for a short period of time, the routing and necessary land and right of way acquisition could be affected and lead to increased route length and higher project cost.  A portion of the transmission line passes through a “high growth area,” and there is a risk that project deferral may eliminate feasible routes as the area continues to develop).