IV. How the Utilities' Long-Term Plans Reflect Policies, Goals, And Outcomes From Other Umbrella Proceedings and Comport with the Energy Action Plan

A. Umbrella Proceedings

This OIR was designed to be an "umbrella" proceeding to coordinate and incorporate Commission efforts in the CCA, DR, DG, EE, QF, RPS, Transmission Assessment and Transmission Planning proceedings, as well as to address RA requirements. The June 4, 2004 ACR identified LTPP and RA as the "critical path" issues that need to be addressed in this proceeding.

1. Resource Adequacy

The Commission's decision in RA, D.04-10-035, issued October 28, 2004, among other things, established that all LSEs, including the IOUs, must have reserve margins of 15-17% by June 1, 2006. As part of meeting this reserve margin requirement, each LSE must have 90% of its next summer's requirement [May through September] fully resourced by September 30 of the year before. The decision also established a 100% forward commitment obligation for a month-ahead horizon for the entire year. The IOUs are to plan to meet all RA requirements as set forth in D.04-10-035 as they go forward with their LTPPs.

2. CCA

In R.03-10-003, the Commission is implementing certain provision of AB 11748 which provides local governments with the opportunity to aggregate energy procurement on behalf of the consumers in their communities. The decision in Phase 1 of that proceeding will facilitate utility planning and procurement decisions.

Much of the debate over the LTPPs raised by potential CCAs, municipalities or irrigation districts, centered on how the IOUs should plan prospectively and judiciously for departing load attributable to CCAs in the future, mainly to avoid utility procurement on behalf of CCA customers. Potential CCAs and others naturally want to limit their liability for utility energy purchases which they would have to assume as part of a "cost responsibility surcharge" (CRS), which is required by Section 366.2(h) of AB 117. The CRS is intended to make remaining bundled ratepayers indifferent to the departure of utility customers who will be served by the CCA. Phase 1 in R.03-10-003 implements this legislative requirement by adopting a methodology for CCA customers to pay their share of the costs of DWR bonds and contracts, utility procurement contracts and other items. Phase 2 in that proceeding will address customer protections and switching protocols, billing and metering issues and reentry and switching fees.

The IOUs, on the other hand, are concerned with their respective obligations to procure sufficient resources for all of their customers and cite the uncertainty surrounding potential departing load, both in terms of timing and number of customers, for their need to provide for these customers until their departure is definite. This issue of timing is an important facet of achieving balance in light of this customer uncertainty.

TURN takes this issue head-on by identifying a trigger point whereby an IOU can proceed with confidence to stop procuring for potential departing load. TURN suggests that the IOU should stop buying power for CCA customers when the CCA provides a binding statement of intent.

We do not determine a precise trigger point when an IOU can stop procuring in this decision. Instead, we encourage cities and counties that intend to procure power as a CCA to work with the IOU to develop an agreement, which allocates procurement risk in subsequent periods. Based on comments from Chula Vista and TURN, we believe it is appropriate that potential CCAs have the opportunity of providing to the Commission and the relevant IOU, a binding notice of intent. The Commission adopts TURN's concept of providing a "default" option for entities seriously considering CCA. We hereby direct the IOUs, along with interested CCAs, to develop such an agreement. The agreement should specify a date at which the IOU's planning responsibility for the CCA load terminates and the CCA will be responsible for this function, so that the CCA's customers will not bear the stranded costs responsibility for utility procurements entered into after the agreed upon date. The agreement should also identify the load that the CCA intends to serve. In the event that the CCA cannot meet this date, the CCA will be liable for any net incremental procurement costs incurred by the utility.

Future IOU procurement plans shall incorporate reasonable anticipated CCA departing load. IOU plans should acknowledge potential CCA departing load by identifying the CCA, estimated departing load, and the implication for utility procurement liabilities.

A major issue in this proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligations to provide reliable service to their customers. The implementation of CCA, departing municipal load, and the potential for lifting, in some form or another, the current ban on allowing new DA all create a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. Given the potential for a significant portion of the utilities' load to take service from a different provider, the utilities are concerned that they could end up over-procuring resources and incurring the stranded costs associated with these resources.

One solution to this problem, discussed above, is the adoption of load forecasts that seek to address, to the extent possible, the uncertainties over the future load that the utilities will be responsible for. Another solution is for the utilities to be entitled to recover any stranded costs occurring as a result of their efforts to meet their load obligations.

The IOUs support the concept of stranded cost recovery for their investments and believe it is a critical factor that needs to be resolved in order for them to plan their future procurement strategies. Consumer groups (TURN, ORA) worry that absent such a safeguard, the utilities' remaining customers would wind up responsible for these costs, violating the ratepayer indifference standard that the Commission has previously adopted. While limiting procurement choices to short-term options might tend to mitigate stranded costs, it could also lead to the rejection of longer-term contracts, especially in the area of renewables, and could result in a non-optimal resource portfolio and higher costs to all consumers.

Needless to say, the parties opposing the imposition of exit fees are either those customers most likely to depart the existing system (CMTA/CLECA, Modesto, SSJID) or ESPs that would serve this departing load. Modesto and Strategic/Energy, however, recognize that some stranded cost recovery might be allowed but only due to "unforeseen circumstances."

The above parties generally advocate that the primary means to minimize or eliminate stranded costs is for the utilities to develop flexible portfolios with significant shorter-term purchases that could be rapidly reduced as load fluctuates.

WPTF also opposes stranded cost recovery, believing the utility should recover the costs of any excess capacity through a capacity market. Constellation makes a similar argument, proposing a "slice of load" approach wherein the utility would sell off a share of its resource commitments to other suppliers and that any new contracts entered into by a utility contain assignability provisions.

In general we agree that the utilities should be allowed to recover their stranded costs from all customers, including an exit fee. Such an approach best meets the Commission's goals of providing "the need for reasonable certainty of rate recovery" (as required under AB 57 and noted in the June 4th ACR) as well as best ensuring that California meets its energy needs.

Requiring departing customers to assume a fair share of their costs is also consistent with the Commission's policy of holding captive ratepayers harmless as required by state law.

As many parties noted, in its last procurement decision (D.04-01-050) the Commission stated that a flexible utility portfolio, consisting of a mix of short-, mid- and long-term resources would be the best mechanism to protect against utility over-procurement. However, since the issuance of that decision, the Commission has now made the utilities responsible for ensuring local reliability, accelerated the resource adequacy requirement from 2008 to 2006, and adopted RPS target goals resulting in the solicitation of new renewable energy sources by the utilities. These initiatives, combined with the existing overhang of utility retained generation and long-term DWR contracts significantly limit the flexibility that the utilities have to quickly adjust their resource portfolios. All of these resource additions benefit all existing customers by improving reliability and promoting renewable energy development.

There is also a potential mismatch between the types of resources that the utilities need to procure (primarily peaking and load following) and the resources that departing customers require (primarily base load with a lesser amount of peaking/load following capability). Thus it may not be possible for the utility to develop a resource portfolio that accurately matches the load profile of expected departing load.

Providing for stranded cost recovery provides a greater incentive for the utilities to enter into five year or longer contracts for existing capacity that many parties (IEP, Duke, Calpine, SCE, PG&E, ISO) are advocating as the optimal approach to ensure the availability of these resources.

Even WPTF, which does not support exit fees, is advocating for the utilities to enter into these longer-term contracts.

There is also the concern that the utilities may need to enter into new contracts (and/or construct) new capacity to ensure that California has sufficient resources toward the latter years of this decade. In order for these resources to be on-line when needed, it may be necessary to begin construction of these projects in the very near term. Almost all parties, including WPTF, agree that new construction would require a minimum ten-year contractual commitment. In the near-term, it appears that the utilities are the only entities capable of facilitating the financing of these projects through long-term contracts. 49

New renewable projects, necessary for the achievement of the EAP and legislative goals, also require long-term commitments in the range of 10 to 20 years.

For the above reasons, it appears that the utilities may need to make longer-term commitments for capacity and energy that may become stranded at some point during the life of these projects.

Therefore, the utilities should be allowed to recover the net costs of these commitments from all customers, including departing customers. This does not mean that the utility should recover the total cost of these commitments, only the uneconomic portion. Similar to the treatment of DWR energy commitments, the utilities must take appropriate steps to minimize their costs by selling excess energy and capacity needs into the marketplace. These other revenue sources (market sales, sales into the ISO's energy/ancillary services market, and potential sales into capacity markets should they develop) should be credited against the utilities' costs. As the utilities will be acquiring their new resource needs through the competitive and transparent procurement process that we are adopting, it is our expectation that there should be little if any stranded costs. However, any longer-term contract implicitly can become stranded based on changes in the market.

At this time, California utilities do not have access to a functioning capacity market. Moreover, such a market should not be the utilities' sole recourse. As Edison and others note50, there is no guarantee that revenues from a capacity market would be equal to the utilities' costs. Still, development of a liquid and competitive capacity market would reduce the risk of the utilities acquiring assets even as they face the risk of customer departure. It would also facilitate the mitigation of any remaining costs. The resource adequacy workshop process will discuss methods of trading capacity so that LSEs, including the utilities, will have a method for exchanging capacity that otherwise could become stranded. Constellation's "slice-of-load" proposal is also better considered as part of the resource adequacy process. Allowing the utilities to recover stranded costs from all customers who benefited is consistent with recent Commission policy with regards to new resource additions. In its decisions on SDG&E's Reliability RFP (D.04-06-011) and on Edison's Mountainview facility (D.03-12-059) the Commission required that all existing customers of the utility were responsible for any potential stranded costs for a period of ten-years. This decision therefore adopts the same standards for fossil-fueled resources acquired by the utilities either directly or through contract. The utilities should be allowed to recover stranded costs for these resources from departing load over either the life of the contract or 10 years, whichever is less. The ten year recovery period will also apply to any utility-owned generation acquired as a result of the procurement process, commencing once the resource begins commercial operation.

As several parties have noted, limiting commitments for new resources to only ten years may still increase costs for captive ratepayers due to the need for the project developer to seek accelerated cost recovery for their investments rather than amortizing these assets over a longer time period. Because any utility commitment for longer than five years must be approved by the Commission, we will allow the utilities the opportunity to justify in their applications, on a case-by-case basis, the desirability of adopting a cost recovery period of longer than ten years. In reviewing any such requests the Commission will examine the benefits to ratepayers as well as the current state of the utilities' customer base.

With regard to the long-term contracts for renewable generation called for by the legislature, we have previously authorized the utilities to enter into contracts with terms of up to twenty years order in order to encourage development of these resources. We will therefore exempt RPS contracts (but not renewable energy contracts that may emerge from all-source solicitations) from the 10-year cost recovery requirement and allow any stranded costs from these contracts to be recovered from all customers including departing load, over the life of the contract. Similar to fossil-fueled resources, the utilities also retain the opportunity to justify a longer cost-recovery period in their applications for those renewable resources selected as a result of an all-source solicitation.

Cost recovery for that portion of a resource acquired by the utilities to meet local reliability needs should be recovered from all customers.

As part of the issue of stranded cost recovery, SCE proposes that we change the direct access switching rules adopted by the Commission. NRDC requests that departing customers provide 10-years notice. Other parties seek further clarification as to how stranded costs would be collected from new DA customers. All of these proposals are premature at this time. They are better discussed if and when the Commission addresses the issue of allowing new direct access to occur51, which, under present legislation, cannot be before expiration of the last DWR contracts in 2013.

3. Demand Response (DR)

DR programs can be used to help achieve both system efficiency and reliability goals. There are two general types of DR programs that the IOUs use to reduce demand when energy prices are high or when supplies are tight: `price-responsive' programs (in which customers choose how much load reduction they can provide based on either the electricity price or a per-kW or kWh load reduction incentive), and emergency-triggered programs (in which customers agree to reduce their load to some contractually-determined level in exchange for an incentive, usually a commodity discount). Both types of programs motivate customers to reduce their loads in exchange for some type of benefit - such as reduced energy rates, bill credits or exemptions from rotating outages. For purposes of clarification, the term `demand response program' should be interpreted in this decision to mean `price-responsive' programs for which the Commission has established specific MW targets to be incorporated into the IOUs' LTPPs.

Price-responsive programs have been the subject of R.02-06-001. D.03-06-032 adopted price-responsive programs, set target goals and directed the utilities on how to integrate DR goals into their procurement plans. As of July 2004, the IOUs have a combined total of 519 MWs52 enrolled in the authorized programs.53 D.03-06-032 also adopted DR goals for years 2003 - 2007.
The 2005 goal is 3% of `annual system peak demand', increasing to 4% in 2006 and 5% in 2007. The adopted goals apply only to `price-responsive' DR programs. MW savings generated by interruptible programs do not count toward the DR goals articulated in the EAP. Enrollment in interruptible programs is capped at 2,500 MW.

D.03-06-032 also directed the IOUs to include the adopted DR MW goals in their procurement plans, along with documentation of the amount of MWs to be achieved by July of each year, the programs and/or tariffs they will rely on to achieve the MW targets and a contingency plan for covering capacity needs should they fall short of meeting the MW goals.

On October 15, 2004, the IOUs submitted DR program proposals in the DR proceeding for the purpose of meeting their 2005 goals. These proposals include modifications to existing DR programs as well as new programs. If their proposals are approved by the Commission, the IOUs anticipate enrollment of the following amounts of demand response MWs by July 2005:

PG&E complies with D.03-06-032 in that its LTPP contains DR MW goals that are derived by applying the appropriate percentages to its forecasted system peak demand for future years (PG&E assumes the 5% is applicable to the years after 2007) for the low, medium and high scenarios. In terms of specific MWs, PG&E assumes 450 MWs of price-responsive DR for year 2005 (medium load scenario). PG&E acknowledges that it does not know if achieving this MW goal, or future years goals, are feasible, implying that its DR component is not an accurate forecast of the future, but rather an attempt to be in regulatory compliance with D.03-06-032.

In contrast to PG&E, SCE's LTPP does not assume the adopted 3% of annual system peak DR will occur but provides a modest forecast of 358 DR MWs for future years. SCE's forecast reflects what it believes is realistically achievable for the programs. This constitutes less than 2% of SCE's annual system peak demand in 2005.

Like SCE, SDG&E's LTPP acknowledges that it will be short of achieving the Commission's DR MW goals. Specifically, SDG&E estimates 27 MWs of DR by 2007. SDG&E's plan reflects what it believes is realistically achievable for these programs.

All three IOUs question the achievability and cost-effectiveness of the DR MW goals, noting that there may be more cost-effective alternatives to meet their loads. The IOUs also note that it is currently unknown as to how many MWs DR programs can actually produce, and that current methods of measuring their effect may need to be revised. In addition, all three IOUs, in particular PG&E, advocate an annual review of the DR goals and adjustments to the goals based on the performance of the DR programs and their cost-effectiveness relative to other procurement options.

Since D.03-06-032 established the parameters of the DR program, the only issue in this procurement proceeding is whether the IOUs are implementing the adopted goals in their LTPPs and how they treat the load savings. ORA observes that PG&E categorizes DR as a supply resource, while SCE and SDG&E consider it a `load modifier.' SDG&E rebuts ORA's observation, noting that it categorized DR as a supply resource.

In this procurement proceeding, the utilities provide an estimate of the number of MWs that constitute 3% of their annual system peak demand. The following are the MW targets for the year 2005:

It is clear that the utilities have used inconsistent definitions of annual system peak in arriving at their MW targets for price-responsive demand. For each utility, the "annual system peak' should be the annual system peak for their respective service territories, inclusive of all customers taking service within those boundaries. We direct the utilities to verify in their compliance filing, detailed below, that the numbers reported above are consistent with this definition, or provide updated targets that reflect this definition.

It is too early to judge whether or not the current DR goals are achievable. Rather than adjust them now or institute an annual review/adjustment process as suggested by the IOUs, the Commission will retain the current 3% of annual system peak goal and further encourage the IOUs to continue with their best efforts in reaching them. Cost-effectiveness of DR programs is also important to the Commission, and future DR proposals will be evaluated for their cost-effectiveness in the DR rulemaking (R.02-06-001) or its successor.

The Commission recognizes that by keeping DR MW goals at their current levels there may not be, at some point, any program that is cost-effective relative to alternative supply resources. As stated above, we believe it is premature to make that judgment today. Because DR programs are currently voluntary, the challenge of designing cost-effective programs while in pursuit of greater amounts of DR MWs each year may very well prove to be an impossible task. If and when that point becomes evident, the Commission will need to either reduce its DR MW goals or begin consideration of mandatory DR programs and tariffs.

SCE's and SDG&E's LT plans provide DR MWs that they believe are realistically achievable, as opposed to incorporating the Commission's DR MW goals into their plans. PG&E's 2005 program plans would meet the MW goal for 2005, but it is not clear that the 3% figure PG&E calculated is based on its "annual system peak" as defined herein. In fact, the LTPPs for SCE and SDG&E reflect an even lower amount of MWs than the utilities expect to enroll in programs by July 2005. This decision's approval of the IOUs' LT plans is not an affirmation that the utilities are no longer required to pursue the more aggressive DR goals, rather they are expected to continue to explore and find ways to meet those goals until otherwise directed. The Commission will consider whether or not to approve specific proposed programs in
R.02-06-001.

4. Distributed Generation (DG)

In D.04-01-050, the Commission provided direction for the inclusion of DG in this long-term procurement proceeding as follows:


"The utilities next round of long-term procurement plans should include a more robust discussion of distributed generation to include: (1) a line item entry clearly identifying distributed generation separate and apart from other entries such as energy efficiency and departing load; (2) the energy (GWh) and demand (MW) reduction attributed to distributed generation; and (3) a description of the technologies the utility includes in its definition of distributed generation as well as a statement noting whether its forecast includes utility-side distributed generation, such as QFs."57

On March 16, 2004, the Commission opened a new DG rulemaking, R.04-03-017. Among the high-priority tasks of the rulemaking is the development of a cost-benefit analysis methodology applicable to DG technologies. Parties filed opening testimony on October 4, 2004. Reply testimony is expected in early 2005 and evidentiary hearings are scheduled for March 2005.

To date, the Commission's efforts in the area of DG have focused on promoting customer-side DG installations in utility service territories. These efforts are directed in four areas:


i. Financial Incentives - rebates are offered to customers installing DG through the Self-Generation Program & CEC's Emerging Renewables Technology program


ii. Interconnection Rules -- streamlining interconnection regulations and processes through the Rule 21 Working Group.


iii. Special Tariffs and Exemptions -- such as the standby charge exemptions for certain DG in accordance with Pub.Util. Code §§ 353.1 and 353.2 and the Departing Load Cost Responsibility Surcharge exemptions from D.03-04-030.


iv. Net Metering - the PUC expanded net metering eligibility to include biogas digester and fuel cell projects along with the currently-eligible solar and wind projects.

In addition to promoting customer-side DG, the Commission is also pursuing grid-side initiatives. In accordance with D.03-02-068, the three IOUs are required to evaluate DG as an alternative to distribution system upgrades, subject to a prescribed set of conditions enumerated in the decision. As of the effective date of this decision, none of the utilities have yet issued RFOs identifying projects where DG might serve as an appropriate alternative.

With respect to the utilities' LTPPs, each IOU prepared a DG forecast that is based on a forecast of DG operating on the customer-side of the meter. These estimates are then deducted from the load forecast. This treatment is consistent with the load forecasting approach recommended in the Workshop Report on Resource Adequacy Issues, dated June 15, 2004, and later adopted in D.04-10-035. The workshop report stated that "Parties agreed that customer-side distributed generation should be deducted from LSE load forecasts."58 This resource counting protocol recognizes that customer-side DG reduces the utility's actual load to be served and the associated reserve margin attributed to that self-served load.

In its LTPP testimony, SCE states that "it is planning on issuing a [RFP], soliciting location-specific demand-side DG to defer distribution upgrades in 2004."59 SCE indicates in its Opening Brief that this effort has been pushed back to 2005.60 61 Interveners did not offer testimony on any DG specific issues raised in the utility resource plans.

We find that the utilities' treatment of DG as a component of the load forecast is appropriate. The utilities shall continue to adhere to the directives for reflecting DG estimates in load forecasting consistent with D.01-04-050 and
D.04-10-035. We also encourage SCE to move forward with its planned DG RFO, the results of which will be monitored by the Commission for guidance in both the DG rulemaking and this docket. Lastly, we note that the DG rulemaking's progress towards developing a cost-benefit analysis methodology for DG will inform future policy guidance we provide to the utilities regarding DG as a procurement resource.

5. Energy Efficiency (EE)

The utilities reflected the Commission's preferred loading order by including EE savings targets in their LTPPs as the priority procurement resource. Since the IOUs filed their LTPPs on July 9, 2004, the Commission issued D.04-09-060 on September 23, 2004. D.04-09-060 translated into a numeric goal the mandate from the EAP to reduce energy use per capita. For the electric IOUs the adopted savings goals reflect the expectation that EE efforts in their combined service territories should be able to capture on the order of 70% of the economic potential and 90% of the maximum achievable potential for electric energy savings over the 10-year period covered by the LTPPs. The annual and cumulative goals for energy savings through 2013 are presented in tables to D. 04-09-060.62 In its post-hearing brief, SCE states that its targets are already higher than the Commission goals established in D.04-09-060, but PG&E's targets in its 10-year plan are lower than those in the said decision. SDG&E, on the other hand, continued to use its EE forecast from its 2003 LTP with the expectation that it will need to update its forecast and resource plans to reflect the goals adopted in D.04-09-060.63

PG&E, SCE and SDG&E should meet or exceed the Commission's EE goals over the next ten years and specifically over the next EE funding cycle (2006-2008) and to revise and update their plans to be in alignment with these goals. PG&E, SCE and SDG&E are to incorporate the goals from the EE decision in their LTPPs, and as these energy savings goals are updated and amended by subsequent decisions, the IOUs are to incorporate the most recently adopted energy savings goals into their plans. As directed in D. 04-09-060:


The energy savings goals adopted in this proceeding shall be reflected in the IOUs' resource acquisition and procurement plans so that ratepayers do not procure redundant supply-side resources over the short- or long-term. To this end, our upcoming decisions in R.04-04-003 concerning the long-term procurement plans and 2005/2006 ongoing procurement authorizations of PG&E, SCE and SDG&E shall be made in full recognition of the aggressive energy savings goals we adopt today. For the procurement plans that will be filed in 2006 and during subsequent procurement plan cycles, or for any updating to the long-term procurement plans required by the Commission before then, PG&E, SDG&E and SCE shall incorporate the most recently-adopted energy savings goals into those filings. "(D.04-09-060, Ordering Paragraph 6, emphasis added)

SCE proposed to add a 1% reliability factor to downgrade program savings from non-utility EE programs operating in its territory. SCE asserted that this reliability factor would address the uncertainty in the timing and magnitude of savings from non-utility programs until rigorous evaluation, measurement and verification (EM&V) of these programs becomes available.64 We reject SCE's proposal and reiterate our prior directive in D.04-01-050 for the utilities to count expected energy savings from non-utility programs that operate in their service territories. As we stated in D.04-01-050:


As more and more non-utility entities enter the energy efficiency program delivery field, more and more energy savings will be attributed to non-utility providers. Therefore, in this proceeding, in the next utility filing of their long- and short-term procurement plans, we order utilities in their demand forecasts for those filings to include expected energy savings from non-utility programs that operate in their service territories. (D.04-01-050, p. 107)

The utilities noted in their LTPPs that several issues are critical to the achievement of their energy savings targets and success of EE programs. These include EE program administrative structure, program funding cycle and duration, EM&V framework and protocols, performance incentives, fund shifting authority, and avoided costs used in cost effectiveness calculations for EE, demand response, and other applications. The Commission has deferred consideration of most of these issues to the EE rulemaking (R.01-08-028) and not in this proceeding, as discussed in D.04-01-050. The Commission has also instituted R.04-04-025 to address avoided cost issues pertinent to EE programs and other resource applications. We will continue to coordinate these various proceedings to the extent that our decisions in those proceedings impact the utilities' LTPPs.

6. Qualifying Facilities: Long-Term Policy For Expiring QF Contracts

On September 30, 2004, ALJ Wetzell issued a ruling "initiating the Commission's consideration of a long-term policy for expiring QF contracts" (p.1). The ruling called for proposals for such a policy [to] be filed on November 10, 2004, which "may also address policy for new QFs" Id. Comments in response to those proposals are due December 8, 2004. The ruling further stated that "the final schedule for adopting a long-term policy for expiring QF contracts [in R.04-04-003] will be determined after review of the comments and a determination of whether evidentiary hearings are required" (p.4). The ruling "anticipated establishing a schedule providing for a Commission decision in the first quarter of 2005 if hearings are not required. If hearings are required, ... a Commission decision [is anticipated] in the second quarter of 2005.

Although we anticipate adopting a long-term policy for expiring QF contracts in this rulemaking, R.04-04-003, by mid-2005, we may be able to benefit from the work being done on avoided cost issues in R.04-04-025, Order Instituting Rulemaking to Promote Consistency in Methodology and Input Assumptions in Commission Applications of Short-run and Long-run Avoided Costs, Including Pricing for Qualifying Facilities. Parties are, however, aware that R.04-04-025 will be litigated during 2005. A PHC in R.04-04-025 was held on November 9, 2004. To the extent that the development of a long-term policy for expiring QF contracts in R.04-04-003 becomes contingent upon any anticipated policy outcomes in R.04-04-025, unacceptable delays in the establishment of such a policy could result. Specifically, QFs whose contracts expire after December 31, 2005 are not eligible for the one-year or five-year contract extension options set forth in D.03-12-062 and D.04-01-050, respectively. Currently, the only recourse for QFs, whose contracts expire in 2006 and beyond, is (1) to participate in any upcoming power solicitations, or (2) negotiate bilateral contracts with utilities. Neither of these two options is entirely certain. Though we expect QFs to continue to participate actively in these opportunities, thus, without contract extensions or a new long-term policy, QF contracts that lapse in 2006 could cause QF power to go off-line at that time. However, our plan to address these issues by mid-2005 will avert these concerns.

7. Renewable Energy Resources

On August 8th, 2003, this Commission, via an Assigned Commissioner's Ruling, established criteria for interim renewable energy solicitations prior to full Renewable Portfolio Standard (RPS) implementation. The ACR acknowledged that "some utilities may wish to execute contracts for renewable generation prior to full development of the criteria and rules for a solicitation under the RPS, based on current market conditions" and directed that the ruling "gives guidance and parameters for utilities wishing to consider renewable purchases in advance of full RPS implementation". Sixteen months after the establishment of these temporary rules the RPS program is now in effect, and we will therefore terminate the interim authority granted by the August 8th, 2003 ACR, on February 8th, 2005. After that date no Advice Letters seeking approval of interim renewable contracts will be accepted; compliance with the procurement goals of the RPS program will be via RPS-specific solicitations, supported by any renewable generation procured through all-source solicitations.

The RPS Program requires each IOU to increase "its total procurement of eligible renewable resources by at least an additional 1% of retail sales per year so that 20% of its retail sales are procured from eligible renewable energy resources no later than December 31, 2017."65 The EAP and the current RPS implementation proceeding, R.04-04-026, have adopted a policy of accelerating the target date to 2010, and we remain committed to that goal.

As stated above, following the "loading order" contained in the EAP is the first priority for IOU resource procurement, meaning that EE and demand-side resources should be employed first. When these opportunities are captured, renewable generation is to be procured to the fullest extent possible - whenever an IOU issues an RFO for generation resources, it must be prepared to defend its selection of fossil generation over renewable generation offers. In other words, selection of renewable generation is the rebuttable presumption guiding IOU generation procurement.

However, we are concerned that this loading order policy preference may not be fully realized if the transmission cost methodology employed by the Commission in I.00-11-001 has the effect of putting renewables in "last place." In that proceeding, CEERT has questioned whether renewables are being held to a more rigid standard than conventional generation resources in terms of determining available transmission resources for, and assigning costs to, renewable generation. It is critical that the Commission move quickly to continue the process of refining the transmission cost methodology. As stated below, the IOUs are directed to file fully-developed RPS plans in the RPS proceeding, including detailed information regarding necessary changes to transmission policy in order to achieve the 2010 goal. These plans should be modeled on the detailed renewable generation information provided by SDG&E in this proceeding. The RPS docket is part of the "umbrella" of cases this proceeding is coordinating, and therefore this RPS planning effort will have full access to the record under consideration here. Parties can utilize the filings in this docket in advocating for inclusion of specific issues in those plans.

In general, IOUs are directed to procure the maximum feasible amount of renewable energy in the general solicitations authorized by this decision, and will be allowed to credit this procurement towards their RPS targets. If an IOU succeeds in procuring sufficient renewable resources to meet its 2005 RPS Annual Procurement Target (APT) via an all-source RFO, it will not be required to undertake an RPS-specific solicitation. This is in keeping with the Legislature's clear intent, in creating the RPS program, that renewable procurement be integrated as closely as possible with general IOU procurement practices. To further this effort, we will be working over the course of the next LTPP cycle to fully imbed the RPS into long-term planning, placing renewable energy development where it belongs - central to the IOUs' resource planning efforts.

Development of the RPS program will continue, however, and the IOUs will be prepared to issue RPS solicitations in 2005. The direction provided in this decision regarding the application of the EAP loading order to IOU all-source solicitations, and the increased emphasis on renewable energy in all-source solicitations, does not in any way indicate a change in Commission policy regarding the importance of the RPS program or our commitment to its continued implementation. The RPS program remains the principal means by which this Commission will achieve its renewable energy goals.

Party Comment on Renewables in the Proposed Decision

Party comments on the Proposed Decision suggest the need for greater clarity regarding several aspects of this renewable energy direction66. We address these issues below.

"Maximum feasible" procurement of renewable generation: A number of parties requested greater specificity regarding this direction. The all-source solicitation should consider renewable resources as follows: in preparing its RFO, the IOU will identify the specific types of electricity products it is seeking, and will employ the least cost-best fit method of bid evaluation. This requires that a renewable bidder be responsive to the IOU's expressed power needs - i.e. meets the "best fit" criteria. In this instance, the IOU will employ the GHG adder discussed below in comparing the bid prices of the renewable and non-renewable options. If the renewable resource is cost-effective when the adder is included (i.e. its bid price is less than or equal to the fossil generator's bid price), the IOU is to select the renewable bid. Thus, the renewable generator must both provide the specific product sought, and be cost-effective when the GHG adder is employed, in order for the "maximum feasible" standard to be in effect.

Combination of all-source renewable procurement with ongoing RPS activities: Parties expressed a range of views regarding the implications for the RPS program of the all-source emphasis on renewable generation bids. CEERT and others are deeply concerned that the RPS program not be forsaken with this new emphasis, and that the necessary improvements to the IOUs' RPS plans not be unduly delayed. TURN and UCS share these concerns. On the other hand, Sempra and CLECA/CMTA approve of what they consider the decision's rejection of resource-specific solicitations in the future. To be clear: the all-source solicitations are meant to complement our ongoing work in the RPS program, and to present a second opportunity for renewable resource development to take place. The RPS program remains a top priority for this Commission and the state, and work is ongoing in that docket to address the concerns expressed by CEERT in its comments. The RPS proceeding has full access to the record in this docket, including the filings concerning the present IOU planning for RPS development. These weaknesses will be addressed in the RPS proceeding in 2005, and solutions will be incorporated to the extent feasible into the 2005 RPS solicitations and the next round of IOU long-term plans in 2006.

To further the state's clear goal of promoting environmentally responsible energy generation, we also adopt a policy that reflects and attempts to mitigate the impact of GHG emissions in influencing global climate patterns. As described in this decision, the IOUs are to employ a "GHG adder" when evaluating fossil generation bids. This method, which will be refined in future proceedings, will serve to internalize the significant and under-recognized cost of GHG emissions, help protect customers from the financial risk of future GHG regulation, and will continue California's leadership in addressing this important problem.

As described above, this will have the effect of improving the economic viability of renewable energy resources in all-source IOU RFOs. In time, as this method is refined to incorporate our ongoing efforts in the Avoided Cost proceeding, it may be possible to recast the RPS program as more central to IOU procurement than a set-aside for particular types of resources. We reiterate, however, that we will continue to develop and implement the RPS program as a principal means of increasing the state's renewable generation stock.

PG&E projects that under the load assumptions of its medium load scenario, if it increases its renewables procurement by 1% annually and obtains the assumed wind repowering, it will achieve its 20% RPS target in 2010.67 On June 30, 2004, the ED approved PG&E's Renewable Energy Procurement Plan, and in accordance with that approval PG&E issued an RFO on July 15, 2004, for renewable resources. PG&E's 2004 annual procurement target is 9,474 GWh per year. To meet the 20% renewable energy target by 2010, PG&E anticipates incremental energy deliveries from newly-contracted resources at an average rate of approximately 700 to 800 GWh per year. PG&E does not identify a preferred resource stack because the utility does not want to thwart market innovations that may occur over the course of the plan and believes the market is the best determiner of what resource is bid.

SCE's long-term plan includes a scenario for achieving the 20% target by 2017 and an accelerated target for achieving the 20% target by 2010. Under both scenarios SCE expects to achieve the 20% target by 2007. SCE's long-term plan does not foreclose procurement that would result in SCE's exceeding the 20% RPS target. SCE states that it will consider renewable resources as part of its all-source solicitation and evaluate all bids, including renewable bids, without regard to whether the 20% target will be exceeded. SCE does not express any preference for a technology type, but instead intends to procure the LCBF renewable resources. SCE fears expressing a preference for technology types would create a bias for future renewable solicitations and could elevate a "preference" as a consideration over LCBF.68

SDG&E's LTPP includes an aggressive renewables resource plan that is designed to meet an overall renewables resource goal of 20% by 2010. SDG&E's aim is to attain a diversified portfolio resulting in a renewable resource mix consisting of Bio-Gas, Bio-Mass, Wind, Geothermal, Solar and Small Hydro technologies. SDG&E developed this portfolio stack and technology mix based upon information obtained from its 2002 renewable RFO process, discussions with potential developers, bilateral negotiations, information from the CEC and the utility's "best estimates" of the types and amounts of resources likely to be available in the future.69 In order to achieve the target by 2010 with an ideal mix of technologies, SDG&E plans on procuring an additional 2,496 GWh through bilateral contracts and RPS RFP solicitations, including exploring the possibility of utility ownership.

While SDG&E is aggressively working towards achieving the 20% target by 2010, it realistically knows that a number of factors, including the availability of renewable resources, in and out of area, transmission access to sources in other areas, availability of funding, utility ownership, pricing issues, and the ability to procure and trade Renewable Energy Credits (REC)70 may affect its ability to meet its goal. SDG&E issued its first RPS RFO on July 1, 2004, and does not yet know the final results of that solicitation.

Many intervenors expressed agreement with the approach SDG&E took in identifying a renewable resource stack, estimating costs and benefits of each and identifying potential barriers to access. PG&E and SCE did not include the same level of specificity in their discussion of future RPS procurement and many parties urged the Commission to direct these utilities to supplement their LTPPs. PG&E and SCE retorted that they want to be open for what ever mix of resources presents itself in a RPS RFO and do not want to prejudge what bids will meet the LCBF test.

The City of San Diego focused on SDG&E's LTPP and especially on the utility's RPS goals to ensure that they comport with the direction the city is headed. Specifically, CSD is concerned that the utility will replace renewable DG with imported renewables, especially if the requested 500 kV transmission line is approved. Instead, CSD would like SDG&E to balance its RPS goals with net-metered generation. While CSD supports the concept of tradable RECs, it argues that the utility should not be able to take DG RECs in an effort to achieve its RPS target. Instead SDG&E should pay for the RECs.71

UCS was one of the intervenors that wants PG&E and SCE to supplement their filings and provide more detailed annual analysis of renewable resource potential over the next 10 years. Specifically, the renewable resource analysis should include (1) assumptions for renewables procurement for the next 10 years, (2) development of a resource "stack," identifying the preferred potential resources, estimated costs and benefits of each, and potential barriers to access and (3) identification of transmission upgrades that the utility believes will be needed in order to access sufficient renewable energy to meet its RPS goals.72

UCS also urges the Commission to direct the utilities to file their 2005 RPS procurement plans and on a going-forward basis, to include renewable resources in any and all future resource solicitations, regardless of whether the IOUs have already met their RPS targets. If the Commission adopts debt equivalency (DE) then long-term renewable contracts should have a lower DE (5%) than non-renewable contracts. And finally, UCS wants the transmission constraints on renewable resources that SDG&E discusses addressed in the January 2005 supplement.73

Strategic Energy proposes that the Commission not require SDG&E to achieve the 20% RPS target by 2010, unless a REC trading system is established. Strategic is concerned that if SDG&E enters into long-term renewable contracts, and there is no REC trading, there will be stranded costs if load migration occurs.74

NRDC seeks clarification that the RPS targets establish a floor, not a cap. The IOUs should not curtail their procurement of renewables once the target is met, but should consider investments in all cost-effective renewable resources beyond 20%. Also, transmission planning should involve an integrated comparison of alternative resources.75

CEERT agrees with UCS that PG&E's and SCE's renewable procurement plans are inadequate and require immediate revisions. CEERT asks the Commission to direct PG&E and SCE to supplement or amend their LTPPs, no later than January 15, 2005, to include a comprehensive and credible renewable procurement plan consistent with that submitted by SDG&E. CEERT also adopts the same recommendations made by UCS for the renewable resource analysis. In addition, CEERT wants SCE to report on the status of its 2003 interim procurement negotiations.76

We agree that the renewable procurement sections in SCE's and PG&E's LTPPs are inadequate and need revision. However, the revisions, with a detailed analysis, will be developed in the IOUs' 2005 RPS procurement plans, which will be filed in R.04-04-026, reflecting the concerns expressed in this Decision and following the guidance to be developed in that docket. All IOUs will provide detailed annual analysis of renewable resource potential over the next 10 years in their 2006 LTPPs. All IOUs will need to include transmission planning for renewable resources in their 2006 LTPPs. Transmission issues will be further addressed in I.00-11-001, in coordination with the RPS docket.

We also find that RPS targets are a floor - not a ceiling. EAP loading order places renewables above conventional generation. "...clear direction was given to the utilities to consider all cost effective energy efficiency, demand response, and renewable resources prior to considering the addition of conventional supply or transmission resources in meeting future resource needs."77

With regards to using unbundled RECs for RPS compliance, this is a complex issue and the record here is insufficient. To make a determination on this policy in this proceeding at this stage is premature. R.04-04-026 will consider this issue as appropriate.

8. Transmission Assessment Process

The April 2003 EAP identified collective agency support for improvements to transmission planning and permitting. It was in this context that the Commission initiated R.04-01-026, issued January 24, 2004, to streamline the transmission planning process for the IOUs by eliminating the duplicative transmission need assessments that currently exist at the CAISO and the Commission. We directed the IOUs through the June 5 ACR and Scoping Memo to take steps toward integration of generation and transmission planning when they made their July 2004 LTPP filings. Various parties identify weaknesses with the IOU filings in this respect. The CAISO asserts that one criterion for judging the LTPPs is whether they were adequate to allow the Commission to accomplish the objectives outlined in R.04-01-026. In this context the CAISO observes that the utilities' LTPPs are insufficient, and that additional information must be obtained from the IOUs in future submissions, in order to allow the Commission and CAISO to accurately assess transmission requirements. The CAISO recommends that the utilities include conceptual scenarios for planned resource additions and assessments of associated transmission requirements. The CAISO adds that integrating the CAISO Transmission Expansion Planning Process (TEP) with the LTPP process should be a key element of this proceeding.

The Commission agrees that the LTPPs do not include sufficient information to enable the CAISO to accurately assess transmission requirements. We agree that integrating the CAISO grid planning processes with the Commission's LTPP process is a worthwhile goal. We further conclude that this integration should include the CEC's IEPR process. The September 16, 2004, ACR in this docket outlines a first order description of how these processes should be coordinated. However, as the ACR states "some subjects, such as transmission planning, are being addressed in more detail in other venues..." One of these other venues is R.04-01-026. In that regard we observe that on October 15, 2004, the Assigned Commissioner in R.04-01-026 issued a ruling stating "[t]o achieve a comprehensive resource planning framework, the Commission must streamline the transmission planning process and integrate that with the biennial procurement process." Finally, since the conclusion of the EH in the LTPP proceeding, the legislature passed and the Governor signed SB 1565, which requires the CEC to prepare a strategic transmission plan as part of its IEPR responsibilities. Clearly there is no shortage of desire for improvements, but actual progress has been slower than many would like.

Investigation (I.) 00-11-001 was issued by the Commission in November 2000 to implement AB 970 regarding the identification of electric transmission and distribution constraints, actions to resolve those constraints, and related matters affecting the reliability of electric supply. Eight transmission issues have been addressed in eight separate phases of this investigation. Phase 1 identified 30 initial projects designated by the utilities to relieve constraints; Phase 3 evaluated a proposal by SDG&E for a second 230 kV Mission-Miguel transmission line based on economic need and Phase 4 ruled on the application by PG&E for a certificate of public convenience and necessity (CPCN) for the Path 15 upgrade. Three phases of the proceeding are still active:

It is generally accepted that transmission projects are undertaken for two reasons: reliability and economics. Reliability standards are issued by the North American Electric Reliability Council (NERC), WECC and the CAISO. These standards are implemented by the utilities with little or no controversy (keep the lights on).

On the other hand, the evaluation of the need for transmission projects not required for reliability, but which could yield economic benefits, and to whom the benefits would apply (a set of ratepayers, consumers as a whole, electricity producers, or a combination of the foregoing) is extremely complex and methods are still being developed. The essential problem is that the benefits depend on future conditions which cannot be accurately predicted: the cost of fuel, interest rates, construction costs, the quantity of hydropower available and the behavior of merchant producers in optimizing their return. The CAISO has been working on a generic methodology for more than three years; the latest effort is called Transmission Economic Assessment Methodology (TEAM), which calculates the benefits of transmission and generation on an integrated basis. However, the Commission staff and others have found that improvements and refinements in the methodology should be pursued.

The development of a generic methodology for evaluating the economic feasibility of transmission infrastructure is still a work in progress.

The CEC has identified 4000 MW of potential wind generation in the Tehachapi area in Kern County and an additional 500 MW south of Tehachapi in Los Angeles County. The purpose of Phase 6 is to define and then construct the transmission infrastructure necessary to transmit this power to load centers. In D.04-06-010 the Commission staff, to be assisted by the CAISO as needed, was assigned the task of coordinating a nine-month study "to develop a comprehensive development plan for the phased expansion of transmission capabilities in the Tehachapi area." Each phase will trigger an application by SCE for a CPCN for construction of facilities defined in that phase. Because the lead time for transmission is longer than for generation, the challenge for the planners is to provide incremental transmission such that new generation has access to load as it comes on line, without building transmission that will not be used. A report on the study's findings will be filed by SCE on March 9, 2005.

In addition, SCE is required to file by December 9, 2004 an application for a CPCN for the construction of the first phase of the Tehachapi transmission. On September 1, 2004, SCE filed a report stating that by December 9, 2004 it would file a complete CPCN application for a transmission line to accommodate wind generation in the Los Angeles County area and "...as much of the CPCN application information as it has completed..." for the first phase of the Tehachapi transmission. Staff are reviewing SCE's filings.

PG&E says that it will "examine a number of economically-driven projects...in accordance with Decision 04-06-010" [Tehachapi]. SCE describes the development of transmission for Tehachapi in its Renewable Conceptual Transmission Plan, dated August 2003. This plan is being currently reviewed and revised in Phase 6 of I.00-11-001.

The intention of Phase 6 is to define and bring about the timely construction of the transmission infrastructure required to connect the Tehachapi and Los Angeles County wind power to load centers, but D.04-06-10 also calls for the study group to address whether the transmission planning approach adopted for the Tehachapi area should also apply in other areas of the state with renewable resources, consistent with the CEC's Plausible Resource Scenarios. A similar collaborative process now is underway in the Imperial Valley region focusing on transmission to accommodate geothermal and other renewable development.

Bids from developers of renewable resources are to be evaluated on the basis of LCBF. A factor in the cost to the utility of the connection to the network of a generation facility is the cost of the transmission upgrades required by the connection. Formulating the methodology for estimating this cost and dividing it among potentially multiple bidders is the subject of Phase 8. In D.04-06-013 a methodology was prescribed for the assignment of transmission costs to the first round of bids beginning on July 1, 2004. Accordingly, the utilities filed Transmission Ranking Cost Reports (TRCRs) for use in the 2004 RPS solicitations and these were adopted by ACR. Only one party, CEERT, filed comments on the TRCRs. CEERT questioned whether renewables are being held to a more rigid standard than conventional generation resources in terms of determining available transmission resources for, and assigning costs to, renewable generation. CEERT also argues that this result is in conflict with the EAP's "loading order" policy preferences and has the effect of putting renewables in "last place."

The Commission intends to move quickly to continue the process of refining the transmission cost methodology.

PG&E suggests that an iterative process between resource planning and transmission planning is needed, so both can be planned in an orderly manner. However, it is PG&E's position that until the locations, timing and characteristics of the new resources can be identified and incorporated into the resource mix, it is not possible to definitively identify the transmission needed to accommodate them. PG&E adds that it is not desirable to plan transmission based on speculation that certain resources may develop. PG&E argues that to do so would waste ratepayer money and distract attention from developing transmission projects whose need is more immediate.

SCE believes that transmission and deliverability issues should be considered during the individual RFP solicitations in the economic evaluation of the individual bids.

SDG&E is convinced that its LTPP emphasizes the need for a diverse portfolio of supply- and demand-side options, as well as transmission, in order to balance lowest cost with reduced volatility and risk.

CEERT alleges that only SDG&E presented a credible renewable procurement plan integrating both resource and transmission planning. UCS found that each of the utilities' LTPPs should be supplemented to add specific and detailed information on transmission upgrades. UCS further adds that the CAISO's grid planning process is a complement to, but not a substitute for, the Commission's oversight of the utilities' procurement responsibilities. NRDC states that the CAISO's transmission economic assessment methodology (the TEAM being examined in Phase 5 of our Transmission Investigation as described elsewhere in this decision) should complement more robust utility LTPPs, but should not substitute for the integrated analysis necessary in the LTPPs.

TURN found that the issue of integration of generation and transmission planning in long-term procurement planning was not explored in any real depth in this proceeding but notes that the Commission is exploring this issue in R.04-01-026 and Phase 5 of I.00-11-001. UCAN found the integrated analysis to be lacking. ORA urges the Commission to insist that the IOUs include consideration of generation alternatives in the "need" determination for proposed transmission lines.

NRDC believes that the IOUs should be directed to thoroughly compare "non-wires" alternatives to transmission projects in an integrated fashion and include more detailed information in future LTPPs about alternatives to the proposed transmission projects that were considered.

The Commission agrees that the issue of integration of generation and transmission planning was not fully explored in this proceeding. The Commission also agrees that the utilities' LTPPs did not fully integrate generation and transmission planning. However, as discussed earlier, we note that the Commission intends to explore this issue more fully in R.04-01-026. It is our desire that the CEC and CAISO collaborate with the Commission in that proceeding. As we work with the CEC and the CAISO to implement the coordination among processes called out in the September 16, 2004, ACR and the mandates of SB 1465, we will require further integration of generation and transmission planning as a planning process. SDG&E came the closest in its LTPP filing, and we expect SCE and PG&E to match the SDG&E approach when they make integrated filings to the CEC in the 2005 IEPR proceeding.

We do not endorse or in any way approve the transmission projects proposed in the utilities' LTPP. Specifically with regard to SDG&E's request, we do acknowledge the lengthy process that is needed to plan, license and construct transmission, so we encourage SDG&E to continue its planning efforts and move forward with evaluating these transmission alternatives for meeting a local resource deficiency by 2010.

Phase 2 of the RA portion of this proceeding will provide a determination on local capacity requirement and deliverability for resource adequacy in the early summer of 2005.78 Those requirements will inform and govern the utility transmission and procurement requirements going forward. Therefore, it is premature to address specific requirements in this proceeding. However, it is important to clarify how the local capacity and deliverability requirements will come into play in future planning decisions. We expect that the CAISO will work closely with the Commission to establish the local capacity procurement requirements based on deliverability of resources into load pockets and transmission constrained areas of the grid and to work with the CEC to provide guidance for LSE filings in the 2005 IEPR proceeding.

Once the local procurement and deliverability criteria are established and then updated as needed to reflect changes such as new transmission or generation, we expect the criteria to be incorporated into and guide the long-term plans going forward. For example, the a determination is made that "x"% of the supply to meet San Francisco load must come from within the local area
given the transmission transfer capability into that area, the long-term plan should incorporate that criterion. In this example, the long-term plans should specify how the utility will meet the "x"% in-city supply criteria, including through approved demand side options, or the transmission upgrades the utility intends to build to increase the transfer capability and decrease the local procurement requirement. We recognize the importance of the CAISO in helping us to establish the criteria so that the Commission can apply them to the utilities' planning practices. The CAISO core expertise in the area of transmission planning and grid operations is critical to inform the Commission's procurement decisions. This approach will assure that the long-term resource procurement meets the CAISO short-term grid requirements. It will also assure that the resources the utilities procure pursuant to their resource adequacy requirements meet the CAISO operational needs.

48 AB 117 (Chapter 838, September 24, 2002), which added Pub. Util. Code §§ 218.3, 331.1, 366.2, 381.1 and 394.25.

49 See, for example, the comments of Calpine, the CAISO, TURN and PG&E.

50 TURN, NRDC.

51 For example, the Commission did not address these issues in either Edison's Mountainview facility or SDG&E's RFP proceedings.

52 290MW for PG&E, 205 MW for SCE and 24 MW for SDG&E, derived from utility demand response/interruptible monthly reports.

53 The IOUs currently have a combined total of 1,500 MWs of potential interruptible MWs from programs authorized by previous Commission decisions.

54 R.02-06-001 Proposal of Pacific Gas and Electric Company (U 39-E) Concerning Working Group 2 Programs and Related Issues, Public Version, October 15, 2004, Appendix C, p. 2.

55 R.02-06-001 Southern California Edison Company's (U338-E) Demand Response Program Proposals for 2005-2008, October 15, 2005, p. 64.

56 R.02-06-001 Filing of San Diego Gas & Electric Company, October 15, 2004, p. 8.

57 D.04-01-050, p.122.

58 Workshop Report on Resource Adequacy Issues, Prepared by ALJ Cooke, June 15, 2004, p.15.

59 Exhibit 73, SCE testimony, p. 85.

60 Edison's opening brief, pp. 29-30.

61 We note current Self-Generation Incentive Program (SGIP) eligibility rules prohibit utility customers "who have entered into contracts for DG services (e.g., DG installed as a distribution upgrade or replacement deferral) and who are receiving payment for those services; (this does not include power purchase agreements, which are allowed) from participating in the SGIP program." [D.01-03-073, Attachment 1, p.25]

62 Tables 1A to 1E of D.04-09-060 show the total electricity and natural gas program savings goals for each IOU service territory and for all IOUs. Attachment 9 to the said decision shows the corresponding funding levels (PGC + procurement funds) implied by the adopted energy savings goals.

63 NRDC's opening brief presents a comparison of the utilities' LTPPs' proposed electricity savings targets versus those adopted in D.04-09-060.

64 SCE opening brief, p.36.

65 Pub. Util. Code § 399.15(b)(1).

66 Parties commenting on the renewable generation aspects of the Proposed Decision include Strategic Energy/Constellation New Energy, SVMG, City of San Diego, SCE, SDG&E, ORA, Sempra, PG&E, CEERT, NRDC, TURN, CLECA/CMTA, and Calpine.

67 PG&E opening brief, p. 37, citing Ex. 34, PG&E/LaFlash, pp. 5-12.

68 SCE opening brief, p. 39.

69 SDG&E opening brief, p. 53.

70 Tradable RECs allow the positive environmental attributes associated with renewable energy generation to be sold independently of the underlying electricity. In concept, an entity obligated under the RPS - or some other environmentally-derived procurement restriction - could purchase a tradable REC instead of electricity to satisfy its obligations.

71 CSD opening brief, pp. 4, 10, 11.

72 UCS opening brief, p. 8.

73 UCS opening brief, pp. 4, 8, 17, 18, 19 and 24.

74 Strategic opening brief, p. 11.

75 NRDC opening brief, pp. 57-58.

76 CEERT opening brief, pp. 15 and 26.

77 D.04-01-050 p. 53.

78 See also discussion of temporary local reliability requirements under Section VIII.B. Local Reliability as Part of the Procurement Process

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