3. Discussion
3.1. The SMJUs
BVES is a division of GSWC. It provides retail electric service to about 23,000 customers in the Big Bear Lake area of San Bernardino County. Among its customers are two ski resorts. BVES obtains most of its electricity supplies through power purchase agreements, but also owns one small gas-fired peaking facility. It is within the California Independent System Operator (CAISO) transmission grid, but interconnects only to the system of SCE.
MU provides retail electric service to the small community of Kirkwood, in the mountains of Alpine County. Its principal customer is a ski resort. MU provides all its electricity from five small utility-owned diesel generators with a total capacity of 5.3 megawatts (MW). MU is not connected to the transmission grid.
PacifiCorp operates in six states: California, Idaho, Oregon, Utah, Washington, and Wyoming. In California, it serves about 50,000 retail customers in the counties of Siskiyou, Shasta, Modoc, and Del Norte. These customers comprise less than 5% of PacifiCorp's load. PacifiCorp maintains its own control area, which is not part of the CAISO grid.
Sierra provides retail electric service in northern Nevada and the Lake Tahoe area in California. It serves about 45,000 retail customers in California, comprising about six percent of Sierra's load. Sierra's transmission system is not part of the CAISO system.
3.2. Procurement Obligations
We begin our discussion by noting that neither SB 1078 nor SB 107 distinguishes SMJUs from other electrical corporations. In D.05-11-025, we concluded that the fundamental RPS procurement requirements applied uniformly to all LSEs: (1) an annual increase in energy procured from RPS-eligible renewable resources of one percent of the prior year's retail sales; and (2) the target of 20% of retail sales supplied from eligible renewable resources by the statutory deadline. We now apply these basic procurement rules in light of three additional factors:
· the lapse of time since D.05-11-025;
· the special requirements for multi-jurisdictional utilities in § 399.17; and
· the repeal of former section 399.14(a)(1), regarding RPS procurement obligations of utilities that are not creditworthy.
We first discuss the general procurement requirements for small utilities and multi-jurisdictional utilities. Section 399.177 does not affect the underlying procurement obligations of PacifiCorp and Sierra, but only the methods of calculation and planning for RPS procurement and compliance. We therefore include all SMJUs in this general rule.
Because of the complexities introduced by the statutory treatment of the creditworthiness of the utilities by former § 399.14(a)(1) and its repeal, we separately discuss the impact of the creditworthiness issue on the procurement obligations of MU and Sierra.
We apply to SMJUs the initial baseline procurement amount (IBPA) calculation method for all utilities set out in § 399.15(b)(2), as explained in D.06-10-050 and clarified in D.07-03-046. It is:
2003 IBPA = (2001 RPS-eligible procurement/2001 total retail sales) x 2003 total retail sales + 1% of 2001 total retail sales
This formula applies without modification to BVES and MU.
For Sierra and PacifiCorp, some adaptation is required. Sierra seeks a special baseline calculation that would take into account certain transactions it entered into in Nevada in 2003. We decline to give Sierra its own baseline methodology. The baseline calculation is set by statute, and has been the subject of extensive consideration by this Commission. Nothing in § 399.17 changes that.
Section 399.17 does allow multi-jurisdictional utilities to have their RPS obligations figured on the basis of the California portion of their total load. In keeping with our intention to have the most uniform possible administration of the RPS program among different types of LSEs, we therefore use the general formula, with a California allocation to determine the initial baseline of the multi-jurisdictional utilities:
2003 IBPA = (California proportion of 2001 RPS-eligible procurement/2001 total California retail sales) x 2003 total California retail sales + 1% of 2001 total California retail sales8
Section 399.15(b) establishes the IBPA calculation as part of the process of determining the annual procurement target (APT) for RPS-obligated LSEs. We set up the APT system in D.03-06-071, and provided definitive explanations and guidance for reporting and compliance in D.06-10-050. In R.04-04-026 (April 22, 2004), the Order Instituting Rulemaking (OIR) for the predecessor to this proceeding, we set the initial APTs for the three large utilities, for the year 2004. The formula is:
2004 initial APT = IBPA + 1% of 2003 total retail sales
For each succeeding year, until the 20% goal is attained, as set out in D.06-10-050, the APT formula is:
APT = Prior year's APT + 1% of prior year's retail sales9
As with the IBPA, the APT calculation applies directly to BVES and MU.
Sierra seeks to have its APT calculations adjusted to allow it to have the same percentage obligations in California as it does in Nevada, where the goal is 20% of sales from eligible renewable resources by 2015. This request is inconsistent with California's statutory mandate of 20% by 2010, as well as with our analysis and findings in D.05-11-025. We therefore reject it.
Instead, we apply to both Sierra and PacifiCorp the instructions of § 399.17(c) that their APT should be determined on the basis of the percentage of their total retail sales to end-use customers in California.
2004 initial APT = IBPA + 1% of 2003 total California retail sales
APT in succeeding years = Prior year's APT + 1% of prior year's California retail sales10
In D.03-06-071, due to the constrained time period for initiating the RPS program, we focused on the three large utilities, PG&E, SDG&E, and SCE. We stated that 2004 would be the first year of RPS obligation for the three large utilities. The RPS statute does not create different RPS obligations for different types of electrical corporations.11 In D.05-11-025, we found no reason to create such a differentiation. Therefore, we affirm here that the RPS procurement obligations of all electrical corporations, including SMJUs, commenced January 1, 2004.
In D.03-06-071, we allowed the three large utilities to defer their entire 2004 IPT obligation for three years, without need to show any of the excuses for shortfalls in actual deliveries required by the flexible compliance rules. (mimeo., p. 50, n. 41).12 This same allowance should apply to the SMJUs.13 In view of the lapse of time since D.05-11-025, we believe that the interests of the SMJUs' ratepayers and the goals of the RPS program would be best served by further extending the ability of the SMJUs to defer their initial IPTs, if they so choose.
First, we will allow SMJUs to roll all their IPT obligations for 2004-2006 into 2007, so that their 2007 IPTs consist of the cumulation of their IPTs for 2004, 2005, 2006, and 2007. Because we defer the IPTs for 2004-2006, the SMJUs have no APTs for those years.14 Their APTs for 2007, therefore, are their 2003 initial baseline procurement amounts plus their cumulated 2007 IPTs.
Second, although SMJUs have APTs for 2007, we will allow them to defer their entire (cumulated) 2007 IPT, without needing to provide any explanation under the flexible compliance rules for any shortfall greater than 25% of IPT, so long as the deficit is made up within three years. This is analogous to our practice for the large investor-owned utilities (D.03-06-071) and ESPs (D.06-10-019.) This deferral applies to 2007 only.15 SMJUs will be required to meet their RPS obligations on schedule for 2008 and later years, or invoke the appropriate elements of the flexible compliance mechanisms set out in D.03-06-071, D.06-10-050, and D.08-02-008.16
We now consider the impact of former § 399.14(a)(1) on the procurement obligations of Sierra and MU, the two SMJUs to which it applied.17
MU and Sierra have each provided declarations by corporate officers that they were not creditworthy in the period from January 1, 2004 through December 31, 2006.18 These declarations are undisputed. We therefore find that these two utilities were not creditworthy for purposes of RPS procurement during that period.
We must add to our review of creditworthiness, however, the inquiry mandated by prior § 399.14(a)(1)(A)(ii), added by SB 67 (Bowen), Stats. 2003, ch. 731. (See n. 16, above.) This provision could affect the obligations of MU and/or Sierra with respect to RPS procurement in the period 2004-2006.
Friends of Kirkwood (Friends) claims that MU should not be able to take advantage of its lack of creditworthiness because it is poorly managed and has not pursued opportunities to develop a viable RPS procurement strategy. These general claims do not provide any factual basis to believe that MU could have, during the period 2004-2006, procured eligible renewable energy resources on reasonable terms, that those resources could be financed if necessary, and the procurement would not impair the restoration of MU's creditworthiness. Friends' dissatisfaction with MU's service and disagreements with its management are not a persuasive substitute for specific information that could ground a conclusion that MU was able to contract for RPS-eligible power during this period.
MU asserts that, since it never was creditworthy, it cannot be restored to creditworthiness. It is unnecessary to explore the logic of this position, since the repeal of § 399.14(a)(1) makes this argument moot. The repeal puts all RPS-obligated LSEs on the same footing after January 1, 2007, regardless of their credit ratings. From January 1, 2004 through December 31, 2006, however, MU was not creditworthy for RPS procurement purposes and was not able to procure RPS-eligible energy on reasonable terms.
By contrast, TURN and Union of Concerned Scientists (jointly, TURN) present specific information in questioning whether Sierra was unable to procure RPS-eligible power during the 2004-2006 period.19 TURN notes that Sierra executed a power purchase agreement (PPA) for deliveries of renewable energy from a new solar thermal generating facility in Nevada. TURN suggests that this contract may show that Sierra could contract for RPS-eligible renewable generation.
Sierra responds that the project cited by TURN was made possible despite Sierra's poor credit rating because the Public Utilities Commission of Nevada (PUCN) established the Temporary Renewable Energy Development (TRED) Program. TRED uses Nevada ratepayer funds to establish a trust fund to protect the revenue stream to the renewable generator. Sierra notes that only its participation in TRED allowed the project to go forward; without the TRED guarantee, the developer could not have obtained financing.
In light of this information, we conclude that Sierra could not have procured eligible renewable energy on reasonable terms from resources that could have been financed without some government intervention such as TRED. We therefore determine that from January 1, 2004 through December 31, 2006, Sierra was not creditworthy for RPS procurement purposes and was not able to procure RPS-eligible energy on reasonable terms.
We now turn to the consequences of MU's and Sierra's lack of creditworthiness. In D.03-06-071, we decided that lack of creditworthiness did not eliminate a utility's RPS procurement obligations, but allowed its performance to be deferred. That is, a utility's RPS obligations accrue, but are not due. We reached this conclusion after considering the overall goals of the RPS program and the statutory mandate of an increase of at least one percent per year in RPS procurement. See § 399.15(b)(1).
SCE suggests that we should apply this reasoning to MU and Sierra as well.20 We adopt this suggestion, because it furthers our goal of equitable administration of the RPS program. Thus, in each year from 2004 (the first year of RPS procurement obligation) through 2006 (the last year § 399.14(a)(1) was in effect), Sierra and MU each had IPTs equal to 1% of their prior years' retail sales. But, in each of those years, the need for actual procurement of RPS-eligible energy was deferred.21
Beginning January 1, 2007, the effective date of SB 107, the requirement to procure was reinstated. As we explained in D.03-06-071, the prior years' deferrals are rolled into the first year of ability to procure. (D.03-06-071, mimeo., p. 54.) Thus, in 2007, Sierra and MU have APTs equal to their RPS initial procurement baselines, plus their cumulated IPTs for 2004, 2005, and 2006, plus their 2007 IPTs. That is:
2007 APT = 2003 Initial Baseline Procurement Amount + 2004 IPT + 2005 IPT + 2006 IPT + 2007 IPT
As we did for PG&E and SCE, we allow deferral of (cumulated) IPT deficits of any size in the first year of required procurement (in this case, 2007), without need for explanation, so long as the deficit is made up within three years. (See D.03-06-071, mimeo., p. 54.)22 Also in line with our previous requirements, the possible deferral of deficits up to 100% of IPT without explanation applies to 2007 only. The ordinary flexible compliance rules apply to Sierra and MU in 2008 and subsequent years. (See D.06-10-050.)
Despite this excursion on what is now a historical byway, Sierra and MU wind up on the same RPS road as PacifiCorp and BVES: RPS IPT obligations prior to 2007 are rolled into 2007 as part of the 2007 APT; the cumulated 2007 IPT (but not any obligations for 2008 or later years) may be deferred up to 100% without explanation, so long as it is made up within three years; and all regular flexible compliance rules apply in 2008 and later years.
3.3. Procurement Plans
In D.05-11-025, we concluded that SMJUs did not need to meet the five basic requirements of the RPS program in a manner that was identical to that of the three large utilities. The large utilities file annual RPS procurement plans, currently in R.06-05-027.
It is not fair and not necessary for any RPS administrative purpose to require the two small utilities to file the complex annual procurement plans we require of the large utilities. They may undertake their RPS procurement planning in any way that comports with their general planning processes. We nevertheless urge BVES and MU to consult with Energy Division staff before undertaking RPS procurement activities. Because their procurement planning does not undergo the review associated with the procurement plans of the three large utilities, these small utilities may benefit from advice of staff about how best to approach their RPS procurement.
Sierra and PacifiCorp are subject to § 399.17, which allows them to use the integrated resource plans (IRPs) that they file in other jurisdictions as the basis of their RPS procurement planning in California. Both utilities request that their IRPs approved by other state public utilities commissions be used in lieu of separate California RPS procurement plans. To that end, they each filed their 2004 IRPs in response to the ALJ's April 11, 2007 ruling requesting the filing of their current IRPs. In response to the ALJ's Ruling Requiring Submission of Multi-Jurisdictional Utilities' 2007 Integrated Resource Plan and Allowing Comments on Plans (July 25, 2007), PacifiCorp and Sierra filed and served their 2007 IRPs in August 2007.
3.4. IRPs
In order to be used for RPS procurement planning purposes, an IRP must be consistent with requirements of §§ 399.11, 399.12, 399.13, and 399.14, as they may be modified by § 399.17, as well as Commission decisions implementing the RPS statute.
The express statutory requirements for a utility's procurement plan are set out in § 399.14(a)(3):
Consistent with the goal of procuring the least-cost and best-fit eligible renewable energy resources, the renewable energy procurement plans submitted by an electrical corporation shall include all of the following:
A. An assessment of annual or multi-year portfolio supplies and demand to determine the optimal mix of eligible renewable energy resources with deliverability characteristics that may include peaking, dispatchable, baseload, firm, and as-available capacity.
B. Provisions for employing available compliance flexibility mechanisms established by the commission.
C. A bid solicitation setting forth the need for eligible renewable energy resources of each deliverability characteristic, required online dates, and locational preferences, if any.
In the Scoping Memo and Ruling of Assigned Commissioner (August 21, 2006) (August Scoping Memo) issued in R.06-05-027 regarding RPS procurement plans for 2007,23 the three large utilities were asked to flesh out these statutory provisions by providing more specific information.24
Aglet, the only commenter on the IRPs, notes that neither Sierra nor PacifiCorp specifically identifies how its respective IRP comports with the requirements set forth above. Aglet suggests that the IRPs be approved nevertheless, with instructions that the two utilities provide the necessary analysis in later years.25
We agree with Aglet. Because § 399.17(b)(3)(d) requires that IRPs show overall conformity to RPS procurement planning processes, we examine the IRPs briefly here. As we explain below, we accept the 2007 IRPs of both utilities, but note the need for additional information in the future. We also set a schedule for subsequent submissions.
Because the schedule on which PacifiCorp and Sierra prepare and file their IRPs is different from the procurement planning schedule of the large utilities, it is important to develop a relatively simple and efficient method for the multi-jurisdictional utilities to provide their IRPs and any additional information needed for RPS procurement planning. PacifiCorp, recognizing that its IRP does not have everything we would need, suggests that it file a supplement to its IRP, to cover those elements required for RPS purposes but not part of the IRP.
We adopt PacifiCorp's suggestion of a supplement to the IRP, in the context of a comprehensive procedure for future filing and evaluation of IRPs and related information. The elements of this procedure are:
● Multi-jurisdictional utilities file and serve their IRPs in R.06-05-027 or its successor at the same time they file with the jurisdictions requiring the IRP.
● Within 30 days of filing the IRP, multi-jurisdictional utilities file and serve, in R.06-05-027 or its successor, their IRP supplements. The supplement must include, either as a separate document or included in the supplements, an analysis of how the IRP and supplement comply with the requirements set out in § 399.17(d).
● At the discretion of and on a schedule set by the assigned ALJ, comments and reply comments on the IRPs and supplements may be filed and served.
● In years in which an IRP is not filed, multi-jurisdictional utilities must file and serve an annual supplement, providing the summary information we set forth below, at the same time that the large utilities file and serve their RPS procurement plans for the upcoming year.
● The supplements filed in the calendar year before an IRP is filed will address the year ahead (e.g., supplements filed in 2008 will address 2009). The supplement filed with the IRP in the following year will thus include some of the same topics, but use updated information.
The timing for IRPs and supplements is set out in tabular form for the coming five years in Appendix A. This process applies only to the procurement planning documents - IRPs and supplements. We emphasize that this procedure, including any comments on or evaluation of the IRPs or supplements, is solely for the purpose of satisfying the statutory requirements for California RPS procurement planning. Because this decision is being issued several months into 2008, we will not require PacifiCorp and Sierra to file supplements to their 2007 IRPs. As shown in the schedule in Appendix A, the process of annual supplements will begin in 2008, with the filing of supplements for 2009 at the same time as the large utilities file their 2009 RPS procurement plans.
Compliance reporting is addressed separately, below.
PacifiCorp is required by Oregon, Washington, Utah, and Idaho to develop an integrated resource plan on a biennial basis; an IRP is not required by either California or Wyoming. The utility is required by one or more of these jurisdictions to include the following components in its IRP:
● Resource management report, including analyses of particular uncertainties and contingencies in supply and demand reporting and forecasting.
● Energy portfolio analysis, including assessment of transmission costs, conservation, demand response and distributed generation resource potentials, environmental compliance costs, direct access load balance, multi-state planning approaches, risk of reliability, and plan for resource acquisition.
● Optimized resource portfolio, taking into account a combination of costs, risk and uncertainty; a range of load growth scenarios; present and future resources; an evaluation of the financial, competitive, reliability, and operational risks associated with various resource options; and an analysis of cost-effectiveness for customers.
● Transmission system capability and reliability assessment.
PacifiCorp's 2007 IRP satisfies the most important requirement for an annual RPS procurement plan set out in § 399.14(a)(3) - the multi-year assessment of supply and demand and determination of optimal mix of renewable resources. PacifiCorp has not included its plans for meeting its California APT, using flexible compliance, or its bid solicitation materials. None of these omissions is fatal to PacifiCorp's RPS compliance, since in future years they may be readily remedied through the IRP supplement, as we outline below. For 2007, we do not require a supplement.
PacifiCorp's IRP contains a robust assessment of supply and demand from 2007 through 2016. PacifiCorp optimizes its entire service territory's energy resource portfolio from 2007 through 2016. PacifiCorp uses a variety of modeling techniques to develop capacity and energy balances to project resource deficits, and conducts a portfolio analysis of 16 future scenarios. PacifiCorp then chooses one preferred portfolio, based on what it characterizes as "superior performance with respect to stochastic cost, customer rate impact, cost vs. risk balance, and supply reliability." (IRP, ch. 7, p. 139.)
The preferred plan projects that PacifiCorp would acquire 2,000 MW of system-wide renewables by 2013. PacifiCorp has also developed a separate report, the Renewable Plan, referenced in the IRP, which outlines objectives and action items to meet its system-wide renewables commitment.
The IRP does not discuss PacifiCorp's expected use of flexible compliance. This is not surprising, since the states requiring the IRP do not have the same compliance system as California. As PacifiCorp suggests, the flexible compliance component of its supplement should include use of flexible compliance mechanisms, a statement of accrued RPS procurement deficits and surpluses, and a procurement plan to satisfy any deficits.
Since § 399.17 does not require multi-jurisdictional utilities to undertake annual solicitations, bid materials should not be required to be submitted with an IRP. Because § 399.17 allows multi-jurisdictional utilities to allocate a proportion of their RPS-eligible procurement to California RPS compliance, it is unlikely that PacifiCorp will undertake a California RPS-only solicitation. If, however, PacifiCorp intends to undertake a competitive solicitation solely for California RPS purposes in any year, it should provide basic information about the solicitation, including the amount of energy the utility hopes to procure and any special characteristics of the solicitation. It should also include its pro forma contract, highlighting the standard terms and conditions (both modifiable and non-modifiable) required in all RPS contracts. (See D.07-02-011, D.07-11-025, D.08-04-009.) This information will allow us to have a fuller view of PacifiCorp's progress toward RPS goals. Requiring PacifiCorp to provide this information is not intended to interfere with any procurement activities undertaken pursuant to any PacifiCorp IRP.
Sierra is required to develop a 20-year IRP every three years pursuant to Nevada's resource planning statutes. The main components of the IRP include:
● Forecasts of energy consumption and peak demand;
● Analysis of market fundamentals and options for supply;
● Demand side management plan;
● Energy supply plan, which must discuss alternative strategies if the utility's preferred resources are not available;
● Renewable energy plan, which must identify renewable energy in sufficient amounts to meet its Nevada Portfolio Standard;
● Fuel procurement plan;
● Purchased power procurement plan;
● Risk management strategy;
● Financial plan; and
● Three-year detailed action plan that describes the steps the utility will take to meet its near-term supply requirements, which the PUCN evaluates for consistency with the IRP.
Sierra's IRP satisfies the most important requirement for an annual RPS procurement plan set out in § 399.14(a)(3)-the multiyear assessment of supply and demand and determination of optimal mix of renewable resources. Sierra has not included its plans for meeting its California APT, using flexible compliance, or its bid solicitation materials. None of these omissions is fatal to Sierra's RPS compliance, since in future years they may be readily remedied through the IRP supplement, as we outline below. For 2007, we do not require a supplement.
In its IRP, Sierra assesses and forecasts its supply and demand from 2007-2027. Sierra then develops an Energy Supply Plan and a three-year action plan. Sierra evaluates various portfolio alternatives by minimizing supply costs, minimizing retail price volatility and maximizing the reliability of the energy supply over the three-year term.
Since the Nevada RPS requires a certain portion of its renewable obligation to be satisfied with solar energy, Sierra's IRP makes a distinction between the need for solar and non-solar renewable resources. The IRP discusses the company's specific plans to procure solar and geothermal resources and to study wind resource potential. According to the IRP analysis, Sierra will have sufficient renewable energy to satisfy both its California RPS and Nevada non-solar RPS obligations from 2008 through 2024 and ample solar resources through 2011.
The IRP does not explicitly discuss Sierra's analysis of possible use of flexible compliance. This is not surprising, since Nevada does not have the same compliance system as California. Sierra's supplement should include analysis of flexible compliance mechanisms, a statement of accrued RPS procurement deficits and surpluses, and a procurement plan to satisfy any deficits.
For the same reasons as PacifiCorp, Sierra should not be required to submit bid materials with its IRP. If, however, Sierra intends to undertake a competitive solicitation for California RPS purposes in any year, it should provide basic information about the solicitation, including the amount of energy the utility hopes to procure and any special characteristics of the solicitation.26 It should also include its pro forma contract, highlighting the standard terms and conditions (both modifiable and non-modifiable) required in all RPS contracts. (See D.07-02-011, D.07-11-025, D.08-04-009.) This information, like that for PacifiCorp, will allow us to have a fuller view of the multi-jurisdictional utilities' progress toward RPS goals. Requiring Sierra to provide this information is not intended to interfere with any procurement activities undertaken pursuant to its IRP.
In years in which they file IRPs, PacifiCorp and Sierra should provide the information about plans for meeting California's APT, flexible compliance, and RPS contracting noted above. They should also include in the supplements any of the additional information required from the large utilities for their RPS procurement plans for that planning year. Using 2007 as an example only, the supplements would include: program metrics, such as retail sales and APT; significant changes in the 2007 IRP from prior IRP; lessons learned in RPS procurement to date; transmission, flexible delivery, and curtailability; workplan to reach 20% by 2010; utility-owned resources; and any other necessary issues.27 They should also explain how the IRPs and supplements meet the requirements of § 399.17(d).
It would be useful for purposes of program administration, compliance planning, and public information about RPS for PacifiCorp and Sierra to file annual supplements (as PacifiCorp suggests), even in those years IRPs are not filed. The components of these "off-year" supplements should be:
● overview of California RPS procurement to date;
● projected retail sales out to one year after the next expected IRP;
● flexible compliance information as set forth above;
● bid solicitation information and materials as set forth above, if relevant;
● workplan to reach 20% by 2010, or any succeeding binding RPS goal; and
● any additional information required by the assigned ALJ or assigned Commissioner.
We anticipate that PacifiCorp and Sierra will be able to prepare these supplements without undue expenditure of resources or pages, since almost all the information is in or related to information in their IRPs or their California RPS compliance reports. We note that Sierra also files with PUCN a Portfolio Standard Annual Compliance Report, which further reports its existing portfolio of renewable energy supplies, projects in the pipeline and future demand for renewables needed to meet its obligations. We agree with Sierra that this report can be filed with its supplement, but as part of, not in lieu of, the supplement.
Sierra also asks that it be able to recover incremental and administrative costs associated with the annual supplements from its California customers. Sierra may request such recovery in its general rate case (GRC).
Because this decision is being issued in mid-2008, we will not require PacifiCorp or Sierra to file supplements for 2008. Instead, each utility will file its 2009 supplement at the same time as the large utilities file their 2009 RPS procurement plans.
In order to make the process of compliance with the procurement planning requirements of § 399.17 as efficient as possible, we authorize the assigned ALJ or assigned Commissioner in R.06-05-027 or its successor proceeding to vary the requirements for the content or filing date of the annual supplements for years when an IRP is not filed. If no such proceeding is open, the Director of Energy Division is authorized to do so.
In all other respects, the Commission's usual requirements for seeking changes to or extensions of time to comply with Commission orders will apply to the multi-jurisdictional utilities' use of their IRPs for RPS procurement planning purposes. (See, e.g., Rule 16.6.)
3.5. Other RPS Procurement Issues
We are mindful of the special challenges faced by the SMJUs in doing their part in the RPS program. We discuss here several specific issues raised by BVES, MU, and Sierra.
BVES points out that, in D.02-07-041, a cap of $77/megawatt hour (MWh) was imposed for the weighted average annual energy cost used in calculating BVES' purchased power adjustment clause rate. BVES notes that this cap is significantly below the current MPR, and is likely to be below the MPR in the future.28 In order to allow BVES to undertake only one procedural step in seeking approval of RPS contracts, we will require that BVES submit any PPAs for RPS-eligible power for approval by means of an application, rather than an advice letter, as long as any cap on its charges for electricity is in place.29 The application should provide the same information as Energy Division recommends for an RPS advice letter filing. The application will, however, allow a more thorough examination of the pricing issues and will provide a record on the basis of which we could, in appropriate circumstances, consider varying the $77/MWh cap.
BVES also asks that we alter the MPR to include a premium for the higher costs of small amounts of power in remote locations. This request reflects a misunderstanding of the MPR, which provides a uniform statewide model for evaluating the per se reasonableness of prices of long-term contracts of utilities for RPS-eligible energy. (See D.05-12-042.) BVES' request is not consistent with the purpose or methodology of the MPR, and we therefore deny it. BVES may, of course, seek approval of RPS contracts with prices above the MPR. We would consider each such request on its own merits, and may allow the recovery of reasonable above-MPR costs in rates.
We also deny, for similar reasons, the request of BVES that it be exempted from calculating an MPR. That task is undertaken by Energy Division staff in the resolution calculating the MPR for each RPS procurement year.
MU seems to suggest that, because it is not connected to the California grid, it should have different RPS obligations. This is not correct. Rather, access to transmission is an element in determining whether MU has complied with its RPS obligations, in accordance with the flexible compliance rules we have adopted. See § 399.14(a)(2)(C)(ii)30 and D.08-02-008.
MU states that, in any event, it will explore the use of biodiesel in its utility-owned generators. Nothing prevents this course of action. Utility-owned generation located in California has always been recognized as a permissible form of RPS procurement. (See § 399.12(e) and Pub. Res. Code § 25741(b)(2)(A).).31 Biodiesel meeting the CEC's requirements would be an RPS-eligible fuel source.32 MU's proposed method of compliance with its RPS obligations would simply need the CEC's certification of the utility's generation facility and its determination that any proposed biodiesel fuel conforms to the requirements set out in the Eligibility Guidebook.
MU also makes various requests related to the accounting treatment of possible methods of compliance with RPS and studies related to RPS compliance. If and when MU has a CEC-approved plan for using biodiesel for RPS compliance, it may file an advice letter for any changes needed to its Diesel Fuel Balancing Account.
MU's other requests are not appropriate for decision here. Although MU is not required to file an RPS procurement plan, it undoubtedly has its own internal planning process. If, after considering this decision and other aspects of the RPS program, MU believes that it needs any additional authorization to take any particular steps with respect to its RPS compliance, it may file an advice letter or application, as MU deems appropriate, setting out its plans and requested relief.
Sierra states that, in order to receive contract approval from PUCN, it must have assurance that it will be able to recover the procurement and administrative costs of the California-allocated portion of contracts for the purchase of RPS-eligible energy that are at or below the MPR. As Sierra notes, such assurance is provided generally by § 399.17(e). To the extent that Sierra seeks contract-specific assurances, they cannot be provided in advance of examination of the specific contract. See D.05-12-042 and Res. E-4118 (setting out the complex methods and inputs for MPR). Although we generally do not require Sierra (or PacifiCorp) to submit their contracts for our approval, any evaluation that a particular contract price is at or below the MPR must be made by Energy Division staff, after submission of an advice letter that provides the information necessary for such a determination.33
3.6. Reporting, Compliance and Enforcement
As a general matter, RPS reporting is intended to allow all RPS-obligated LSEs to report accurately to this Commission their RPS procurement activities. Regular reporting also benefits the LSEs, by allowing them to track their RPS compliance in a uniform way. Because RPS reporting must respond accurately to changes in the program and must resolve problems in reporting, flexibility is necessary. The flexibility to make changes in reporting formats, and methods for doing so, are explained in the ALJ's Ruling Adopting Standardized Reporting Format, Setting Schedule for Filing Updated Reports, and Addressing Subsequent Process (March 12, 2007), issued in R.06-05-027.
Both PacifiCorp and Sierra request that they be allowed to submit a single, annual compliance and procurement filing in May each year. This single composite filing would replace the compliance reports that all LSEs are required to submit pursuant to D.06-10-050. We do not adopt this proposal. Our interests in uniformity of administration, fairness to all RPS-obligated LSEs, and provision of accurate information about RPS compliance to the public all counsel that we should not allow exceptions to RPS reporting requirements. Our resolution in this decision of the other issues related to the multi-jurisdictional utilities' reporting and compliance obligations should make it easier for them to incorporate reporting on the regular RPS schedule into their planning.34
In D.07-05-028, we implemented new § 399.14(b), added by SB 107.35 This section provides the statutory authorization for the use of short-term contracts36 with existing facilities37 to meet RPS procurement obligations, as long as the Commission sets a minimum quantity of long-term contracts38 and/or contracts with new facilities39 that must be signed for any short-term contracts to be used for RPS compliance.
If they choose to use any short-term contracts with existing facilities for RPS compliance, BVES and MU would be subject to the minimum quantity requirement as set out in D.07-05-028.
Because § 399.17 allows PacifiCorp and Sierra to use a proportional approach to meeting their California RPS APTs, it is fair and reasonable to allocate other responsibilities, including their "minimum quantity" obligations, proportionally as well. If either utility seeks to use any short-term contracts with existing facilities for California RPS compliance, it must meet the minimum quantity obligation; i.e., it must in that year sign contracts with new facilities or long-term contracts with existing facilities, equivalent to 0.25% of the previous year's retail sales to California customers.
Because, as noted in our discussion of § 399.17, Energy Division staff will generally not review RPS contracts of Sierra and PacifiCorp, we will require these utilities to certify compliance with this requirement separately. If any short-term contracts with existing facilities are being counted for RPS compliance in a particular reporting year, the report due March 1 of the following year must include a certification that the minimum quantity has been met. The certification should conform to the requirements set out in the Administrative Law Judge's Ruling Granting Motion for Reconsideration of Verification Requirement as Explained Herein and also Addressing Record (December 6, 2006), issued in R.06-05-027.
All SMJUs must participate in the CEC's verification process required by § 399.13)(b). Additionally, they must provide, upon request, copies of contracts for RPS-eligible energy on which they are relying for RPS compliance to Energy Division, for use with the CEC's verification reports in verifying their RPS reporting and compliance.
D.05-11-025 provides that SMJUs, ESPs, and CCAs are subject to the same reporting, compliance, and enforcement rules as the large utilities. In D.06-10-019, we reiterated that ESPs and CCAs are subject to these general rules. We set out uniform reporting rules and formats in D.06-10-050, which have been implemented through ALJ rulings in R.06-05-027 and the reporting spreadsheets developed by staff. Most recently, in D.08-02-008, we updated our flexible compliance rules to include changes made by SB 107. We also reiterated that the flexible compliance rules apply to all RPS-obligated LSEs. (D.08-02-008, mimeo., p. 21.)
Several possible exceptions to these rules have been requested by various SMJUs. We note initially that none of these exceptions would be relevant at all unless and until one of the SMJUs is not meeting one or more of its RPS obligations and none of the flexible compliance mechanisms is available to help the utility defer or excuse the shortfall.
PacifiCorp asks us to expand the list of excuses for shortfalls in RPS procurement. However, we explained in D.06-10-019 that the process set out in D.03-06-071 and D.03-12-065 provides notice to an LSE of the potential noncompliance and affords the LSE options to manage the noncompliance. Four options were initially set out: use of the 25% no-explanation-needed shortfall mechanism; presentation of one of the excuses for a shortfall greater than 25%; presentation of a different explanation for a shortfall greater than 25%; and proactive request to the Commission to allow a greater shortfall. (D.03-06-071, mimeo., p. 50.) These have been augmented by the Legislature's addition, in § 399.14(a)(2)(C)(ii), of the excuse of insufficient transmission, under certain circumstances. (See D.08-02-008.)
This process makes it unnecessary to consider in advance any request that additional excuses for shortfalls be recognized. If any SMJU (or other RPS-obligated LSE) believes that its RPS procurement shortfall should be excused for some reason other than those already enumerated, it is free to present that reason to us at the relevant time.
The SMJUs also urge us to lower the maximum penalty amount to which they may be subject, on the grounds that they are (or their California presence is) so small that the maximum penalty of $25 million per year (at $.05/kilowatt hours) is disproportionately large. We reject this suggestion, which is inconsistent with our prior decisions, including D.03-12-065 and D.06-10-050. In rejecting a similar request by ESPs and CCAs, we stated in D.06-10-019 (mimeo., p. 15):
The penalty amounts are calculated on the basis of kilowatt hours (kWh) of renewable energy generation to which the people of California were entitled, but they did not receive. An ESP that does not meet its RPS targets is failing to provide renewable generation to its customers, exactly the same as a large utility. But, as we noted in D.06-03-023, all potential penalties for RPS noncompliance lie in the future. An ESP facing a penalty in the future would be free to argue that the full potential penalty amount is disproportionately large. We have no reason to consider that issue now.
We also observe that none of the SMJUs will be potentially subject to any noncompliance penalty until 2010 at the earliest. We have cumulated prior IPT obligations into 2007 and, consistent with our prior decisions, allowed the entire 2007 IPT to be deferred without explanation for up to three years. We expect that this will allow all four SMJUs to implement RPS compliance activities appropriate to their circumstances without unnecessary focus on potential penalties.
7 Section 399.17 provides:
(a) Subject to the provisions of this section, the requirements of this article apply to an electrical corporation with 60,000 or fewer customer accounts in California that serves retail end-use customers outside California.
(b) For an electrical corporation with 60,000 or fewer customer accounts in California that serves retail end-use customers outside California, an eligible renewable energy resource includes a facility that is located outside California, if the facility is connected to the Western Electricity Coordinating Council (WECC) transmission system, provided all of the following conditions are met:
(1) The electricity generated by the facility is procured by the electrical corporation on behalf of its California customers, and is not used to fulfill renewable energy procurement requirements in other states.
(2) The electrical corporation participates in, and complies with, the accounting system administered by the Energy Commission pursuant to subdivision (b) of Section 399.13.
(3) The Energy Commission verifies that the electricity generated by the facility is eligible to meet the annual procurement targets of this article.
(c) The commission shall determine the annual procurement targets for an electrical corporation with 60,000 or fewer customer accounts in California that serves retail end-use customers outside California, as a specified percentage of total kilowatt hours sold by the electrical corporation to its retail end-use customers in California in a calendar year.
(d) An electrical corporation with 60,000 or fewer customer accounts in California that serves retail end-use customers outside California, may use an integrated resource plan prepared in compliance with the requirements of another state utility regulatory commission, to fulfill the requirement to prepare a renewable energy procurement plan pursuant to this article, provided the plan meets the requirements of Sections 399.11, 399.12, 399.13, and 399.14, as modified by this section.
(e) Procurement and administrative costs associated with long-term contracts entered into by an electrical corporation with 60,000 or fewer customer accounts in California that serves retail end-use customers outside California, for eligible renewable energy resources pursuant to this article, at or below the market price determined by the commission pursuant to subdivision (c) of Section 399.15, shall be deemed reasonable per se, and shall be recoverable in rates of the electrical corporation's California customers, provided the costs are not recoverable in rates in other states served by the electrical corporation.
8 The methodology for determining the correct California proportions for RPS purposes is set out in the RPS reporting spreadsheet, attached to the ALJ's Ruling Adopting Standardized Reporting Format, Setting Schedule for Filing Updated Reports, and Addressing Subsequent Process (R.06-05-027, March 12, 2007), as revised from time to time by Energy Division. The current version may be found at http://www.cpuc.ca.gov/PUC/energy/electric/RenewableEnergy/compliance.htm.
9 The 1% annual increase is often referred to as the incremental procurement target, or IPT.
10 The relevant California proportions are calculated according to the methodology developed for the reporting spreadsheet, described above. Appropriate use of the spreadsheet will allow complete RPS reporting and prevent double-counting of out-of-state renewable resources.
11 This is in contrast to the separate initial date of obligation for ESPs set by SB 107 (January 1, 2006). See § 399.12(h)(3).
12 We use here the terminology and framework adopted in D.06-10-050, which differs in language but not in content from D.03-06-071.
13 We discuss below whether any alteration is required by prior § 399.14(a)(1).
14 APTs for each of 2004, 2005, and 2006 could, in theory, be calculated according to the formulas set out in section 3.2.1.1. Because we are deferring the IPTs for those years, however, such a calculation has no meaningful result.
15 To the extent that this provision affects the compliance reporting of any SMJU, it should be reflected in the utility's August 2008 reports.
16 The regular flexible compliance rules allow, among other things, the deferral of a shortfall of up to 25% of IPT for up to three years, without need of explanation. In D.08-02-008, we integrated into our flexible compliance rules the new excuse for shortfalls added by SB 107: insufficient transmission. (See § 399.14(a)(2)(C)(ii).)
17 As it was prior to repeal, § 399.14(a)(1) provided:
(A) The commission shall not require an electrical corporation to conduct procurement to fulfill the renewables portfolio standard until the commission determines either of the following:
(i) The electrical corporation has attained an investment grade credit rating as determined by at least two major rating agencies.
(ii) The electrical corporation is able to procure eligible renewable energy resources on reasonable terms, those resources can be financed if necessary, and the procurement will not impair the restoration of an electrical corporation's creditworthiness. The provision shall not apply before April 1, 2004, for any electrical corporation that on June 30, 2003, is in federal court under Chapter 11 of the federal bankruptcy law.
(B) Within 90 days of the commission's determination as provided in subparagraph (A), an electrical corporation shall conduct solicitations to implement a renewable energy procurement plan. The determination required by this paragraph shall apply on to the requirements established pursuant to this article. The requirements established for an electrical corporation pursuant to Section 454.5 shall be governed by that section.
18 MU submitted the Declaration of David P. Likins, its chief financial officer, dated May 30, 2006. Sierra submitted the Affidavit of William Rogers, treasure of its parent, Sierra Pacific Resources, dated May 1, 2006.
19 Joint Comments of The Utility Reform Network and the Union of Concerned Scientists on the Renewables Portfolio Standard Compliance Proposals of Electric Service Providers, Community choice Aggregators, and Small and Multi-Jurisdictional Utilities (March 7, 2006).
20 SCE's Response to the Supplemental Comments of Sierra Pacific Power Company on the Issue of Creditworthiness (May 22, 2006).
21 As we noted in D.03-06-071, the RPS statute does not prevent voluntary procurement of RPS-eligible energy by an LSE subject to prior § 399.14(a)(1).
22 To the extent that this provision affects the compliance reporting of MU or Sierra, it should be reflected in the August 2008 reports of those utilities.
23 We use this procurement plan year because it is the same as the year in which the most recent IRPs were prepared.
24 The categories of information are: program metrics (e.g., retail sales, APT); changes in the 2007 plan from 2006 plan; lessons learned in RPS procurement to date; transmission, flexible delivery, and curtailability; workplan to reach 20% by 2010; utility-owned resources; and any other necessary issues.
25 Comments of Aglet Consumer Alliance on Integrated Resource Plans (May 8, 2007).
26 We discuss separately below Sierra's request for a determination that it will recover in rates procurement and administrative costs for RPS contracts that are at or below the MPR.
27 As noted above, no supplements for 2007 are required.
28 Res. E-4118 calculates the MPR for contracts resulting from 2007 RPS solicitations as more than $92/MWh.
29 Any application should be served on the service lists for R.06-05-027 or its successor proceeding and the service list for A.01-08-020, or any subsequent proceeding that maintains or imposes a similar cap on BVES electricity charges.
30 Section 399.14(a)(2)(C)(ii) provides:
The flexible rules for compliance shall address situations where, as a result of insufficient transmission, a retail seller is unable to procure eligible renewable energy resources sufficient to satisfy the requirements of this article. Any rules addressing insufficient transmission shall require a finding by the commission that the retail seller has undertaken all reasonable efforts to do all of the following:
(I) Utilize flexible delivery points.
(II) Ensure the availability of any needed transmission capacity.
(III) If the retail seller is an electric corporation, to construct needed transmission facilities.
(IV) Nothing in this subparagraph shall be construed to revise any portion of Section 454.5.
31 Pub. Res. Code § 2574(b)(2)(A) provides that one way an electric generation facility can meet the RPS locational eligibility criteria is if "the facility is located in the state or near the border of the state with the first point of connection to the transmission network within this state and electricity produced by the facility is delivered to an in-state location." (Emphasis added.)
32 The CEC set forth eligibility requirements for biodiesel in its initial Renewables Portfolio Standard Eligibility Guidebook in May 2004. It may be found at http://www.energy.ca.gov/portfolio/documents/2004-05-10_RPS_ELIG_GUIDEBK.PDF. The current (third) edition of the Eligibility Guidebook may be found at http://www.energy.ca.gov/2007publications/CEC-300-2007-006/CEC-300-2007-006-ED3-CMF.PDF.
33 Because this submission is not for purposes of contract approval, the advice letter would not need to include the standard requirements of RPS advice letters related to analysis of contract terms and conditions, other than those necessary to determine contract price in relation to the MPR. The advice letter should also indicate the year of the MPR Sierra proposes to use, so that Energy Division may evaluate that choice, if necessary.
34 Energy Division has implemented the reporting requirements by preparing and circulating detailed spreadsheets and instructions for RPS-obligated LSEs, including a version especially for multi-jurisdictional utilities. This substantially reduces any burden that compliance with the general reporting requirements might impose on PacifiCorp or Sierra.
35 Section 399.14(b) provides:
The commission may authorize a retail seller to enter into a contract of less than 10 years' duration with an eligible renewable energy resource, subject to the following conditions:
(1) No supplemental energy payments shall be awarded for a contract of less than 10 years' duration. The ineligibility of contracts of less than 10 years' duration for supplemental energy payments pursuant to this paragraph does not constitute an insufficiency in supplemental energy payments pursuant to paragraph (4) or (5) of subdivision (b) of Section 399.15.
(2) The commission has established, for each retail seller, minimum quantities of eligible renewable energy resources to be procured either through contracts of at least 10 years' duration or from new facilities commencing commercial operations on or after January 1, 2005.
36 Contracts that are less than 10 years in duration.
37 Generation facilities that commenced commercial operation prior to January 1, 2005.
38 Contracts that are at least 10 years in duration.
39 Generation facilities that commenced commercial operation on or after January 1, 2005.
