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.
Role of RPS policies in all-source procurement: A number of parties, particularly PG&E, raised questions in their comments regarding the interaction of all-source renewable procurement with RPS policies around the Market Price Referent (MPR) and Supplemental Energy Payments (SEPs). To be clear, neither of these policy implements are to be employed in the all-source solicitation process. As described in the previous section, renewable bids are to be favored in the all-source solicitation process to the extent that they provide the desired electricity product and are cost-competitive in light of our greenhouse gas policies.
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, despite our direction in D.04-01-050, as discussed below. The Commission also agrees that the utilities' LTPPs did not fully integrate generation and transmission planning. We note that the Commission intends to explore this issue more fully in R.04-01-026.78 In D.04-01-050, the Commission discussed changes that would be needed to move from the current planning process to a more integrated process, and including the following direction:
"The integrated resource planning we seek to achieve would provide a comprehensive context for all of a utility's resource decisions and would include the following features:
1. Rather than considering projected load and resource needs only on a statewide or service territory scale, each utility would assess the different characteristics of the many planning areas within its service area - taking into account the nature of local customer load (such as specific industries, the residential mix, and related load profiles), transmission and distribution constraints, existing generation resources, land use concerns and community values.
2. Each utility would develop a base plan that would take into account least-cost resources, reliability needs, fuel diversity, and other risk management concerns. On the local level, the utility would determine the optimal way to meet demand (whether it would be through energy efficiency, demand reduction, transmission or distribution additions, distributed generation, renewables, or fossil generation).
3. On a service territory-wide basis, the utility would then determine whether the optimal local solution adequately supports total resource needs and the achievement of the state's policy preference for energy efficiency and renewables, and adjust the plan as needed to serve those broader needs."
In that decision, the Commission recognized that it would take time for the utilities to develop the capability to plan on this level. We note that in most respects, the utilities have not achieved this type of disaggregated planning. Undertaking the steps described above is consistent with, and perhaps critical to an effective integration of generation and transmission planning. SDG&E, in its current plan, has shown signs of moving in this direction. We fully expect SDG&E to continue to improve its planning process along these lines, and for PG&E and Edison to do so as well.
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 2005.79 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.
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 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.
79 See also discussion of temporary local reliability requirements under Section VIII.B. Local Reliability as Part of the Procurement Process.