XIX. Energy Efficiency
A. Cost Recovery for IOUs to Meet EE Savings Goals
While each of the utilities' LTPPs reflected energy efficiency as the top priority resource, they differed in their requests for funding approval to procure this resource. As NRDC noted in its reply brief, "PG&E specifically requests that the Commission approve funding for its 2006-2008 procurement of energy efficiency...In contrast, SCE's brief did not address how it intends to request funding approval for the efficiency procurement. And SDG&E requests that the Commission authorize it to file an advice letter to adjust EPEEBA to match the budgets approved in [D.] 04-09-060."75 NRDC urged the Commission to approve each utility's proposed investments to procure energy efficiency programs for 2006 through 2008, noting that the Commission cannot do so in the energy efficiency rulemaking (R.01-08-028) because it is not a ratesetting proceeding. PG&E shares similar views, further noting that the EE rulemaking authorizes only expenditures of PGC funds and is not the appropriate forum for augmenting EE expenditures by the utilities. SDG&E also noted that D. 04-09-060 approved much larger budgets to achieve the adopted energy savings targets but did not explicitly discuss where the incremental budget will come from. SDG&E assumed that the incremental budget could be authorized in this proceeding, just as D.03-12-062 approved the utilities' 2004-2005 procurement EE funding.
In addition, both PG&E and NRDC proposed that the Commission approve additional energy efficiency funding if savings targets are expected to be met and funds for 2006-2008 are depleted before the end of the three-year period. NRDC supports this proposal based on its analysis showing that more cost-effective energy savings remain in the outer years of the utilities' LTPPs.76
We disagree with NRDC and others that this proceeding is the appropriate forum for authorizing increases in procurement rates to fund incremental energy efficiency investments over and above the PGC funding levels. Since approving the utilities' procurement budget for energy efficiency in 2004-2005, we have consolidated consideration of both the administration and funding of energy efficiency in our energy efficiency rulemaking in proceeding. R. 01-08-028, consistent with our decision in D.04-01-050 that:
"As the Commission will authorize a uniform of energy efficiency, we believe it is necessary that the Commission have in place a unified administrative structure to oversee of all energy efficiency programs regardless of the source of funding in the years ahead. For this reason, we are referring the issue of administration of energy efficiency programs authorized in this proceeding.
Accordingly, we directed in D.04-09-060 that the program administrators we ultimately select for energy efficiency (which may or may not be the utilities) would submit proposed energy efficiency program plans and funding levels to meet the Commission-adopted savings goals every three years, beginning with a PY 2006-PY 2008 program implementation by Assigned Commissioner or ALJ ruling in R.01-08-028.77 Authorizing the utilities to request incremental funding via procurement rates for PY 2006-2008 in the manner that NRDC, PG&E and SDG&E propose, would prejudge the issues being addressed in R01-08-028 and result in a bifurcated administrative structure - which we expressly rejected in D.04-01-050. Therefore, we leave to the energy efficiency rulemaking all issues related to the funding levels for energy efficiency, and how the cost associated with programs will be recovered in rates.
B. Energy Efficiency Data in Future LTPPs
NRDC proposed that the Commission establish a list of required data on the energy efficiency programs that the utilities should provide at a minimum in their LTPPs. UCS concurred with NRDC's suggestion. This list include:
· Total proposed investments in energy efficiency every year over the next decade, broken out into the PGC and procurement component (in real and nominal dollars);
· New annual and cumulative energy savings as a result of the programs every year over the next decade, broken out into the PGC and procurement components (in GWh);
· New annual and cumulative peak savings every year over the next decade, broken out into the PGC and procurement components (both coincident-peak and non-coincident-peak, in MW);
· The total resource cost (TRC) test net benefits of the proposed investments;
· The average levelized cost of the energy efficiency resources;
· Comparison of cumulative energy and peak savings to the Commission's targets;
· The projected percent of demand growth reduced by the programs; and
· The per capita electricity consumption for the service territory over the next decade after factoring in the energy savings from the programs.
We agree that providing information about the energy efficiency programs in a consistent format in the utilities' future LTPP filings will facilitate the Commission and parties' analysis of the proposals. NRDC's list provides a good starting point; hence, we will direct the utilities to provide the said information to the extent possible.
C. Distributed Generation
The EAP prioritizes DG in the loading order along with renewable resources and enumerates the following policy objectives:
i. Promote clean, small generation resources located at load centers;
ii. Determine whether and how to hold distributed generation customers responsible for costs associated with Department of Water Resources power purchases;
iii. Determine system benefits of distributed generation and related costs;
iv. Develop standards so that renewable distributed generation may participate in the Renewable Portfolio Standard program;
v. Standardize definitions of eligible distributed generation technologies across agencies to better leverage programs and activities that encourage distributed generation;
vi. Collaborate with the Air Resources Board, Cal-EPA and representatives of local air quality districts to achieve better integration of energy and air quality policies and regulations effecting distributed generation; and
vii. Work together to further develop distributed generation policies, target research and development, track the market adoption of distributed generation technologies, identify cumulative energy system impacts and examine issues associated with new technologies and their use.78
The IOUs state that they are meeting the EAP policy goals for DG by reflecting customer-side DG in their load forecasts, by participating in the Rule 21 Interconnection Work Group, and by having Commission-approved methodologies in place for evaluating DG as a distribution alternative in system planning. Interveners did not file testimony specifically relating to DG and the EAP.
The state is currently meeting the goals of the EAP through two ratepayer-funded incentive programs: (1) the PUC's Self Generation Incentive Program; and (2) the CEC's Emerging Renewable Technology program. We also expect that the Governor's solar systems initiative when implemented, will contribute towards achievement of EAP goals by virtue of its focus on promoting and funding DG installations.
We find that the initiatives cited by the utilities in their LT plans (i.e., DG forecasting, the Rule 21 Work Group, including DG in distribution system planning) are consistent with EAP goals for DG. Furthermore, as we noted in Section A.2.3, we expect that the cost-effective work underway in R.04-03-017 will guide future guidance we provide the utilities for incorporating DG in resource planning.
D. Procurement contracting authority: AB 57, upfront standards, cost recovery and ratemaking
1. Contracting Authority
The initial procurement proceeding, R. 01-10-024, was the vehicle used by the Commission to put the IOUs back in the procurement business following the end of the deregulation experiment. Beginning in February 2002 and continuing up to the inception of this current procurement docket, the Commission issued the following decisions to direct the IOUs on filling their net open positions:79
· D.02-08-071 authorized the utilities to procure for low-case forecast scenario RNS needs between the effective date of the decision and January 1, 2003 (multi-year contracts were allowed).
· D.02-10-062 authorized contract terms for up to five years for transactions entered into under the modified short-term procurement plans addressing 2003 procurement activities. 80
· D.02-12-074 authorized the utilities to hedge 2004 first quarter residual net short positions with transactions entered into in 2003.81
· D.03-12-062 authorized the utilities to enter into contracts with terms up to five years to meet 2004 needs with delivery beginning in 2004.
· D.04-01-050 extended the procurement authority to the first three quarters of 2005, limiting the purchase authority to short-term contracts (contracts of one year or less duration).82
E. Parties' Positions
Immediately following the issuances of the December 2003 and January 2004 Commission procurement decisions, PG&E requested an extension to its procurement plan to enter into pre-approved transactions with terms up to five years during the term of its procurement plan, with changes suggested by PG&E in its petitions for modifications of D.03-12-062 and D.04-01-050 and for automatic renewal of procurement plans. Now, faced with the new reserve requirements of 15-17% by June 1, 2006, from the recently issued RA decision, D. 04-10-035, PG&E's net open position has increased over the next five years and increased its market risk exposure. The ability to enter into multi-year agreements is necessary to implement PG&E's midterm resource strategy and provide PG&E with the ability to acquire a resource portfolio with a mixture of contract terms to deal with load uncertainty over the next three to five years.83
CAISO, SCE, TURN supports and ORA does not oppose PG&E's request.
In its opening testimony, SCE proposed to have the AB 57 procurement plan be approved on a rolling five-year term. AB 57 does not say procurement transactions should be limited to five years or less duration, so there is no prescription against this modification, and PG&E supports it. In addition, SCE proposes to provide an updated capacity and energy position for seven years forward, based on its medium case scenario, beginning with a compliance advice letter submitted within 30 days of approval of its long term plan.84
SDG&E states that short-term procurement plans should continue to be affirmed by the Commission as the upfront standards and criteria for short-term procurement pursuant to AB 57. 85
TURN supports additional authority to enter into contracts of up to five years' duration regardless of the initial delivery date. However, TURN recommends that contracts with duration of three years or longer to be submitted to the Commission for pre-approval.
Duke urged the Commission to direct the utilities to undertake interim capacity procurement to meet the needs during the next three to five years; NRDC wants the Commission to require that the expected carbon emission costs should be used in procurement bid evaluation process; and Strategic argues the IOUs should be making shorter-term commitments, e.g. five year or less.
It is reasonable to extend the IOUs' procurement on a rolling 10-year basis, given that the long-term procurement plans cover a ten-year period and they will be updated and reviewed every two years. We will diligently oversee how the utilities are using this authority. Therefore we authorize the utilities to enter into short-term, mid-term, and long-term contracts, with contract delivery start date through 2014, provided that the IOUs submit the necessary compliance filings. We adopt TURN's proposal that contracts with duration three years or longer be submitted to the Commission for preapproval.
NRDC's recommendation is addressed in Section C.3 below.
F. Cost Recovery
1. Parties' Positions
PG&E proposes a ratemaking mechanism for cost recovery that includes the following features: upfront assurance of cost recovery; no opportunity for after-the-fact reasonableness review of project costs if the terms of the upfront approval are met; and a mechanism to allow cost recovery to begin as soon as the facility is operational. In addition, PG&E argues that the Commission's preapproval process should constitute upfront approval of the acquisition costs. That is, if the costs are determined to be reasonable in the preapproval process, and PG&E meets the preapproved upfront conditions, no after-the-fact reasonableness review should be necessary.
SCE states that its proposed revision to its Existing AB57 Procurement Plan86 is a component of it's long-term procurement plan. SCE further clarifies that it does not have a separate AB57 long-term procurement plan and AB57 short-term procurement plan. Instead, SCE has one AB57 procurement plan which is a component of SCE's LTPP showing in this proceeding (SCE LTPP, July 9, 2004, Vol.2, p.1). SCE states that the objective for each IOU's AB57 procurement plan is to set the limits (i.e., the upfront achievable standards and criteria called for in AB57), within which the IOU's transaction activity would be deemed reasonable. All transactions and actions that fall within the boundaries of an AB57 procurement plan are compliant with the approved procurement plan and accordingly are assured cost recovery. Statute requires that a procurement plan contain upfront achievable standards and criteria (Id., p.1-2).
SDG&E wants the Commission to provide reasonable assurance of timely and complete recovery of the costs of approved, newly acquired turnkey utility-owned generation assets. SDG&E suggest that the existing ERRA provides reasonable assurance that the cost of future procurement contracts acquired will be fully recovered through ERRA mechanism, but the utility is not certain that ERRA provide assurance for cost recovery for new turnkey generation assets.
For utility-owned turnkey generation projects, SDG&E proposes a regulatory framework for recovery of costs that includes the following:87
Initial Phase: The Commission should adopt the initial annual revenue requirement of a proposed turnkey project at the time of the approval filing. The initial revenue requirement would be recovered through the first full calendar year of the operation.
Second Phase: The authorized revenue requirement would be annually updated to incorporate attrition adjustments.
Third Phase: The updated revenue requirement will be reset in future COS filings for recovery during the term of the applicable COS.
TURN recommends that contracts with duration of three years or longer to be submitted to the Commission for pre-approval.
G. Cost recovery for Turnkey Projects:
In D. 04-06-011 we approved two turnkey generation projects for SDG&E: Ramco and Palomar. SDG&E, however, is concerned that the Commission did not establish a specific revenue requirements for these projects, nor has the Commission specified the framework under which the turnkey costs will be recovered. In the interim, SDG&E believes that ERRA mechanisms as established in Commission D.02-10-062, provide SDG&E with reasonable assurance that costs for future procurement contracts will be recovered. SDG&E requests that the Commission provide equivalent assurance for cost recovery of turnkey projects as it had for other procurement resources.
In the LTPP proceeding SDG&E proposes a three-phase cost recovery framework for turnkey project cost recovery that starts with the filing for Commission approval of the project. In that filing, SDG&E will identify the rate-base and O&M-related revenue requirements associated with the project for the first full calendar year of operation of the generation plant. SDG&E proposed to record costs associate with the turnkey plants to its Non-Fuel Generation Balancing Account (NGBA) and Energy Resource Recovery Account (EERA) for recovery through SDG&E commodity rates. Under SDG&E's proposal, the Commission will adopt the annual revenue requirement of the applicable turnkey plant simultaneously with approval of the project. Prior to the operation of the turnkey generation unit, SDG&E will file an advice letter to incorporate any adjustments to the adopted revenue requirement.
The second phase of the framework covers the period from the end of the initial phase until the implementation of SDG&E's next Cost of Service (COS) decision to allow for annual attrition adjustments to the authorized revenue requirement.
The third phase, SDG&E's revenue will be trued up to reflect the costs of these projects.
PG&E requests that the Commission provide timely cost recovery of utility owned generation when the facility starts serving utility customers, whether PG&E operates the plant itself or when it contracts with a third party to operate it. Under PG&E's proposal, PG&E would include the initial capital cost of the acquisition in its request for approval of the contract.
UCAN opposes SDG&E's proposal for cost recovery and argues that the Commission sets revenue requirements in the General Rate Case (GRC) and should not allocate separate revenue requirements for each asset owned by the utility in a non-GRC proceeding.
1. Discussion:
We find SDG&E's mechanism reasonable and adopt it for all three IOUs. In the next few years, IOUs could add extensive new generation to their resource portfolios in order to meet their future resource needs. We believe a rate making mechanism needs to be in place to ensure proper and timely cost recovery for these facilities. Two issues need to be decided; the timing and the scope of the cost recovery. First, we determine the appropriate timing of the rate recovery. Both SDG&E and PG&E propose to start cost recovery when the new facility starts operation to serve utility customers. We agree and adopt this proposal.
Second, we adopt SDG&E's proposal for cost recovery. SDG&E proposes to establish rate-base and O&M-related revenue requirements associated with the generation plant and to use its Non-Fuel Generation Balancing Account (NGBA) and Energy Resource Recovery Account (EERA) to record costs associate with the turnkey plants and for recovery through SDG&E commodity rates. PG&E, however, proposes differently. In addition to the costs listed above, PG&E proposes that in some cases, it may be necessary to request recovery for "financial burden associated with acquisition of utility-owned generation."88 In PG&E's opinion, these costs may include planning and administrative costs of preparing for the construction or acquisition of the generation facilities, financing costs as incurred, and costs if the project is ultimately abandoned. We believe that some of these costs or risks will be considered in our review and evaluation of IOU contracts for turnkey projects and some will be considered as part of establishing the revenue requirement for these facilities. For example, we expect contracts for turn key projects address provisions and penalties for project abandonment. As such these types of costs should not receive special recovery treatment. We reject PG&E's proposal in this respect.
H. ERRA Trigger Mechanism
1. Background
The ERRA trigger mechanism requires the Commission to adjust procurement rates if the ERRA balancing account becomes undercollected by more than 5% of the previous year's non-DWR generation revenues. The trigger mechanism is set to expire on January 1, 2006.
AB 57 added the following to the Public Utilities Code 454.5 (d)(3):
Ensure timely recovery of prospective procurement costs incurred pursuant to an approved procurement plan. The commission shall establish rates based on forecasts of procurement costs adopted by the commission, actual procurement costs incurred, or combination thereof, as determined by the commission. The commission shall establish power procurement balancing accounts to track the differences between recorded revenues and costs incurred pursuant to an approved procurement plan. The commission shall review the power procurement balancing accounts, not less than semiannually, and shall adjust rates or order refunds, as necessary, to promptly amortize a balancing account, according to a schedule determined by the commission. Until January 1, 2006, the commission shall ensure that any overcollection or undercollection in the power procurement balancing account does not exceed 5 percent of the electrical corporation's actual recorded generation revenues for the prior calendar year excluding revenues collected for the Department of Water Resources. The commission shall determine the schedule for amortizing the overcollection or undercollection in the balancing account to ensure that the 5 percent threshold is not exceeded. After January 1, 2006, this adjustment shall occur when deemed appropriate by the commission consistent with the objectives of this section. (emphasis added)
PG&E requests that the trigger mechanism remain in effect for the term of the LT contracts to be approved. DENA strongly supports PG&E's request on the grounds that the extension of the trigger mechanism will provide certainty needed to maintain or improve PG&E's credit rating and will benefit PG&E customers, by ensuring that any decreases in procurement costs are passed on to the customers.89 IEP joins in support with DENA.
We find that the ERRA trigger provides the IOUs assurance that procurement costs will be recovered in a timely fashion, and we keep the trigger in effect during the term of the long-term contracts, or ten-years, whichever is longer.
2. ERRA Disallowance Cap
In D.02-12-074, the Commission adopted a disallowance cap applicable to utility administration and dispatch of allocated DWR contracts. The cap amount is equal to two times the utility's costs of procurement function.(?)90 In D.03-06-067 the Commission ruled the following: SCE's request to expand the disallowance cap established in D.02-12-074 to include all procurement activities violates the legislative mandate of Assembly Bill 57, as codified in Pub. Util. Code § 454.5, as well as Sections 451 and 702.91
Current disallowance cap is applicable to utility administration and dispatch of allocated DWR contracts. PG&E Requests that disallowance cap apply to all utility dispatch, including URG, PPAs, and allocated DWR contracts on the ground that this would provide certainty in estimating the potential financial risk utilities face.
On July 8, 2004, the Commission issued D.04-07-028 requires utilities to consider local reliability effects in their dispatch decisions. Potentially, this could impact the least-cost dispatch process July 8 Reliability decision complicates the least-cost dispatch process that is an up-front standard that is included in procurement plans. PG&E argues that given the current concern in the investment community over the utilities financial health, if the Commission clarifies that the cap applies to all utility least-cost dispatch activities undertaken pursuant to the long-term plans approved by the Commission will provide needed regulatory assurance.
DWR does not oppose the development of a separate disallowance cap, but does oppose extending the disallowance cap to all IOU procurement activities, especially direct liabilities to DWR.
Consistent with our determination in D. 03-06-067, as discussed above, that an extension of the disallowance cap violates legislative intent and the statutes, we reject PG&E's request.
3. Upfront Standards for Utility Procurement Products and Transactions
75 NRDC Reply Brief, p. 9.
76 NRDC Opening Brief, p. 56.
77 See D.04-09-060, Ordering Paragraphs, 1,4 and 5.
78 State of California Energy Action Plan, May 8 2003, pp 4 & 8.
79 After existing resources and policy preferred resources have been compared to load and necessary reserves, the result is the amount of energy and capacity that an LSE must still acquire. This is called either "need" or the "net open" position, sometimes subdivided into "net short," the amount the LSE needs to acquire, or "net long," the surplus the LSE has to sell.
80 D. 02-10-062, p. 47.
81 D. 02-12-074, Ordering Paragraph 5.
82 D. 04-01-059, p. 91.
83 PG&E opening brief, p. 46.
84 SCE opening brief, p. 67.
85 SDG&E opening brief, p. 74.
86 The "Existing AB57 PP is the same as the "2004 Short-Term Procurement Plan - Confidential Version," dated May 15, 2003, as modified by the Commission in D.03-12-062 and submitted by SCE in Compliance Advice Letter 1770-E-A, dated February 23, 2004. These plans are also referred to at times in SCE's LTPP as the "Implementation Plan."
87 SDG&E opening brief, pp. 81-86.
88 PG&E's prepared Testimony, Page 2-38.
89 DENA opening brief, p. 13.
90 D. 02-12-074, Ordering Paragraph 25.
91 Id., Conclusion of Law 1.
