Flexible Rules for Compliance

The third task before us is to adopt:

Flexible rules for compliance including, but not limited to, permitting electrical corporations to apply excess procurement in one year to subsequent years or inadequate procurement in one year to not more than the following three years. (Pub. Util. Code § 399.14(a)(2)(C).)

This requirement applies to what is known as the annual procurement target (APT), which is described in § 399.15:

(b) The commission shall implement annual procurement targets for each electrical corporation as follows:

(1) Beginning on January 1, 2003, each electrical corporation shall, pursuant to subdivision (a), increase its total procurement of eligible renewable energy resources by at least an additional 1 percent of retail sales per year so that 20 percent of its retail sales are procured from eligible renewable energy resources no later than December 31, 2017. An electrical corporation with 20 percent of retail sales procured from eligible renewable energy resources in any year shall not be required to increase its procurement of such resources in the following year.

When read together, the two sections indicate that the flexible compliance mechanism applies to annual procurement targets only. The language requiring utilities to procure 20 percent of their retail sales no later than December 31, 2017 is clear and unequivocal. The 2017 deadline is absolute. Accordingly, the task before us is to develop flexible rules for compliance applicable to the annual procurement targets.

PG&E raises a threshold issue regarding the basic nature of the APT. According to PG&E, an APT for a given year only exists if the utility identifies, in its general procurement plan, an unmet need for that year. If there is no unmet long-term need identified in the utility's general procurement plan for a given year, then there is no incremental APT for that year. (PG&E Opening Brief, pp. 6-7.)³²

PG&E bases this argument primarily on the language in § 399.15(a) that refers to "unmet long-term resource needs." (See, e.g., Ex. RS-7, pp. 1-4, 1-5, 2-5, 2-6.) PG&E places too much reliance on this phrase, and also interprets it, with scant legal analysis, to be utility-specific and utility-determined.³³

The section that PG&E relies upon says:

399.15. (a) In order to fulfill unmet long-term resource needs, the commission shall establish a renewables portfolio standard requiring all electrical corporations to procure a minimum quantity of output from eligible renewable energy resources as a specified percentage of total kilowatthours sold to their retail end-use customers each calendar year, if sufficient funds are made available pursuant to paragraph (2), and Sections 399.6 and 383.5 to cover the above-market costs of eligible renewables, and subject to all of the following:

This statute imposes an obligation upon the Commission to establish a standard applicable to all electrical corporations. The basis for that broad obligation is "to fulfill unmet long-term resource needs," a term which is not defined in SB 1078. However, the Legislature expressly found and declared that "[I]ncreasing California's reliance on renewable energy resources may promote stable electricity prices, protect public health, improve environmental quality, stimulate sustainable economic development, create new employment opportunities, and reduce reliance on imported fuels." And "The development of renewable energy resources may ameliorate air quality problems throughout the state and improve public health by reducing the burning of fossil fuels and the associated environmental impacts." (§ 399.11(b) and (c).)

The Legislature's target of 20 percent renewable energy is also a statewide target, with the purpose of "increasing the diversity, reliability, public health and environmental benefits of the energy mix." (§ 399.11(a).) PG&E's position that "unmet long-term resource needs" means a specific utility's resource needs, as defined and identified by that utility, is inconsistent with the statewide focus and purpose of the legislation. "Unmet long-term resource needs" must be considered on a statewide basis, not a utility-by-utility basis, and the Legislature has already essentially found that there are statewide unmet long-term resource needs.³⁴

Most of PG&E's arguments ultimately boil down to the fact that it considers a mandatory one percent APT to be bad policy. (See, PG&E Opening Brief, pp. 13-14; PG&E Reply Brief, p. 23.) Nevertheless, the statute contains a mandatory one percent APT. While PG&E may believe that to be a bad policy, PG&E's belief does not allow the Commission to ignore the statute's language. In fact, PG&E turns the statutory language on its head when it argues that it should only be required to procure "up to at least 1 percent" of its self-defined need. (PG&E Opening Brief, p. 6.) We decline to do a similar inversion of the plain language of the statute.

Annual procurement targets are not optional. Throughout SB 1078, they are treated as a requirement. (See, e.g., § 399.14(a)(2)(B) referring to annual obligations under the RPS program.) Flexible compliance is only necessary if compliance is required. Since compliance is required under the statute, we now turn to the real issue, which is how to implement the required flexible rules for compliance, as directed by § 399.14(a)(2)(C).

There is significant agreement among the parties that excess renewable procurement in one year should be allowed to be carried over to future years without limitations on time or quantity. (See, e.g., PG&E Opening Brief, p. 9; SDG&E Opening Brief, pp. 19-20; Green Power Opening Brief, p. 2; TURN Opening Brief, p. 34; CalWEA Opening Brief, p. 20.) Such unlimited forward banking is consistent with the language of § 399.14(a)(2)(C), which allows excess procurement in one year to be applied to subsequent years. Furthermore, giving credit for excess procurement is consistent with the purpose of SB 1078. It must be remembered that the 2017 date for 20 percent renewable procurement is a "no later than" date, and the annual procurement requirement of an additional 1 percent of retail sales is an "at least" amount. (§ 399.15(b)(1).) Accordingly, it is fully consistent with the statute for any utility to procure more than 1 percent per year, or to reach 20 percent renewables before 2017.³⁵

Furthermore, in the context of SB 1078, unlimited forward banking of excess procurement simply makes sense. As SCE puts it: "Adopting a rule ensuring that all renewable procurement in excess of the current year targets "counts" will effectuate the policy goals of the RPS legislation by creating an incentive for early procurement." (SCE Opening Brief, p. 5.) SDG&E also observes that, "It also would smooth out lumpiness in renewables procurement caused by certain renewables projects generating larger than immediately needed quantities." (SDG&E Opening Brief, pp. 19-20.) Accordingly, we will permit unlimited forward banking of excess procurement.

The main controversy regarding flexible compliance is in the case of inadequate procurement in a given year. In other words, what happens if a utility does not procure enough renewable generation to meet its APT.³⁶ There are three basic proposals that have been presented, ranging from virtually no flexibility to the absolute maximum flexibility. We adopt a middle ground that blends aspects of the various proposals.

CalWEA proposes the strictest regime. Under CalWEA's proposal, each utility would have three months after the end of a compliance year to remedy any shortfall that existed at the end of that year. (CalWEA Opening Brief, p. 19.) For example, if on December 31, 2007, a utility was short of its APT for 2007, it would have until March 31, 2008 to make up the difference. CalWEA's proposal would allow a utility to fall below its APT by 5 percent without penalty and without explanation, but not repeatedly. (Id., p. 20.) CalWEA's proposal is strongly opposed by all three utilities, and garnered no significant support among other parties.

CalWEA's proposal is too rigid, and does not reflect the present realities of renewable procurement. As CalWEA describes the basis for its proposal, its three-month true-up mechanism reflects the fact that a utility may be out of compliance "due to naturally occurring variances in annual renewable resource production or variations in load as a result of factors outside the utility's control (e.g., weather)." (Id., p. 20.) The five percent margin reflects the fact that "[I] is impossible to predict precisely how much renewable sellers will generate and how much retail customers will consume." (Id.)

CalWEA's arguments imply a constant supply of renewable generators, with the main variation being in how much energy they generate in a given year. This is not the current reality, nor is it the focus of either the legislation or this proceeding, which in large part is about bringing additional generation units on line-a much lumpier and uncertain process. The five percent margin proposed by CalWEA is simply inadequate to deal with the uncertainties of the real world issues facing the utilities, even if those utilities are committed to procurement of additional renewable resources. Furthermore, it would result in a needless expansion of the Commission's workload in the form of utilities seeking exemption from this requirement.³⁷

In addition, the three-month period allowed to make up any deficit is too short. As SCE points out, "CalWEA's true-up proposal essentially collapses the three-year deficit banking provision into three months." (SCE Opening Brief, p. 9.) While conceivably the Commission could in fact require the utilities to make up any deficit in three months (as the statute says that the adopted rules should allow "no more than" three years), it is simply not a good idea. As SDG&E argues, the three-month true-up period could create a seller's market (SDG&E Opening Brief, p. 22), which would not be in the best interests of ratepayers.

At the other extreme are the proposals of PG&E and SCE (supported by AReM). They propose adoption of a rule permitting deferral of the entire procurement obligation for up to three years, with no review or penalties. (PG&E Opening Brief, p. 9; SCE Opening Brief, pp. 7-8.)³⁸ The basically similar proposals of PG&E and SCE correspond to the absolute maximum flexibility permissible under the statute. (See, PG&E Opening Brief, p. 7; SCE Opening Brief, p. 4; Pub. Util. Code § 399.14(a)(2)(C).) While this is something the Commission could adopt, just as we could adopt the CalWEA proposal, it also is not a good idea.

Green Power notes that the SCE and PG&E proposals would allow unlimited deficit carryover for three years, and argues that such deficit carryover could easily be abused and ultimately threaten the goals of the RPS program. (Green Power Opening Brief, p. 2.)

PG&E additionally argues that renewable contracts that expire should not be added to the following year's APT. (PG&E Opening Brief, p. 10.) Instead, the utility would be given the discretion to replace that generation at any time "in order to meet the 20% requirement by 2017." (Id.) SCE takes a similar position. (See, SCE witness Bergmann, Tr. p. 2649.)

TURN responds by arguing that the RPS obligation requires a net increase each year, and that PG&E's position is inconsistent with SB 1078. (TURN Reply Brief, pp. 4-5.) CalWEA also opposes PG&E's (and SCE's) position, arguing that it could actually result in a year-to-year decline in the total amount of renewable generation. (CalWEA Reply Brief, pp. 2-3.) Ridgewood also disagrees with PG&E and SCE, arguing that the statutory language clearly mandates a net increase in renewable energy purchases. According to Ridgewood, PG&E and SCE's positions contradict the statute, as they do not require a net increase. (Ridgewood Opening Brief, pp. 8-9.) (See also Green Power, Opening Brief, p. 4; Vulcan Opening Brief, pp. 40-41.)

The position of TURN, CalWEA, and Ridgewood is more consistent with the statute than PG&E's and SCE's position. As TURN, CalWEA, and Ridgewood point out, the statute requires each electrical corporation increase its total procurement of eligible renewable energy resources by at least an additional 1 percent of retail sales per year. (TURN Opening Brief, pp. 2-4; CalWEA Reply Brief, pp. 2-4; Ridgewood Opening Brief, pp. 8-9, all citing § 399.15(b)(1).) The focus on the utilities' total procurement indicates that the Commission cannot ignore the expiration of renewable contracts, as those contracts are part of the total.

SCE and PG&E would sever any linkage between the annual targets of 1% and the eventual 20% target. This simply makes no sense; the small annual targets are steps on the way to the larger ultimate target, and eliminating the steps would make the ultimate target that much harder to reach. The criticisms of SCE's and PG&E's proposed flexible compliance rules are accurate: their proposed rules are simply too flexible, and fail to ensure compliance.

TURN and SDG&E have jointly proposed a flexible compliance mechanism. If a utility failed to procure (and did not have banked from previous years) sufficient energy to meet its APT, it would be allowed to carry forward a shortfall of 25% of its APT without Commission approval. (SDG&E Opening Brief, p. 20.) Carrying forward any shortfall larger than 25% would require Commission approval, dependent upon the utility making a showing of specific conditions. (TURN Opening Brief, p. 35.) The TURN/SDG&E proposal is based on the expectation that a utility should be able to obtain at least 75% of its APT in the current year. (SDG&E Opening Brief, p. 20.) Ridgewood, Green Power, and Solargenix support the TURN/SDG&E proposal.

TURN and SDG&E also differ from PG&E and SCE in how a deficit that is carried over is subsequently made up. SCE describes its proposal: "Any compliance in a year following a deficient year should be applied first in fulfillment of the oldest outstanding, unmet compliance targets." (SCE Opening Brief, p. 7.) So if in 2010, SCE had an APT of 50 units, but only acquired 40 units, the first 10 units acquired in 2011 would go to make up the deficit. TURN criticizes this feature as allowing the utility "to simply defer procurement for up to three years and carry a three year deficit indefinitely." (TURN Opening Brief, p. 37.) While slightly overstated, TURN's criticism is well founded, as SCE's proposal would allow a utility to essentially roll over its deficit each year.

By contrast, SDG&E would only permit a utility to use renewable MWh in excess of the utility's APT in a given year to make up a prior year's shortfall; in other words, a utility must first apply its procurement to its current year's APT, and only after that is satisfied can any excess procurement be utilized to satisfy a shortfall from a prior year. (SDG&E Opening Brief, p. 23.)

The TURN/SDG&E approach is the best of the methods presented. Accordingly, we adopt the compliance program proposed by TURN and SDG&E. A utility will be required to meet 75% of its APT each year but will be allowed to carry over a deficit of 25% of its APT to the next year without explanation.³⁹ A utility will be allowed to carry over any deficit up to the 25% allowed by the TURN/SDG&E proposal for up to three years, but must satisfy this deficit within that three year period.⁴⁰ The TURN/SDG&E proposal allows a utility flexibility in meeting its APT but does not allow a utility to get so far behind in its renewables procurement as to jeopardize either its ability to make up any deficits or to meet the overall RPS goals, or to compromise any future RFOs by requiring so much renewable procurement as to create an undue advantage for bidders (to the detriment of ratepayers). However, recognizing that this is a new program and that each utility deserves latitude in implementing a new program, we grant each utility an exemption from these requirements for the first year of the program.⁴¹

We also find that the TURN/SDG&E approach to deficit carryover, which requires the present year's APT to be met before applying procurement to previous years' deficits, is consistent with the language and purpose of the statute, and we adopt it.

In addition, as part of adopting the TURN/SDG&E proposal, annual shortfalls in excess of 25% of APT, with the exception of the first year exemption described above, would be permitted upon a demonstration of one of four conditions, outlined in the TURN/SDG&E proposal⁴²: (a)Insufficient response to RFO, (b) Contracts already executed will provide future deliveries sufficient to satisfy current year deficits, (c) Inadequate public goods funds to cover above-market renewable contract costs, (d) Seller non-performance.⁴³ These flexibility mechanisms are adopted in order to allow the utilities to engage in good faith efforts to maximize ratepayer benefits and promote orderly renewable resource development. For example, utilities should be encouraged to commit to long-term purchases from new facilities that, due to development lead time and a future online date, may not deliver energy to satisfy a current year RPS obligation. Discretion to use large deferrals should not be unlimited in order to ensure that a utility is not permitted to actively and unnecessarily frustrate RPS program objectives.

Every party that addressed penalties acknowledged the Commission's authority to impose penalties under Pub. Util. Code § 399.14(d) and its existing authority. (See, e.g., SCE Opening Brief, pp. 12-13; PG&E Reply Brief, pp. 30-31.) A number of parties, including CalWEA and TURN,⁴⁴ recommended the Commission adopt automatic penalties for non-compliance. We choose to adopt an upfront and automatic penalty of five cents per kilowatt-hour, as proposed by various parties including CEERT and TURN and implemented in other states (e.g., Texas and Massachusetts), with an overall annual penalty cap per utility of $25 million⁴⁵, as proposed by TURN.⁴⁶ An upfront penalty provides concrete and transparent rules in advance of each utility's RPS activities and removes the uncertainty of an open-ended order to show cause process with unspecified consequences for a utility. Moreover, advance penalties comport with the intent of SB 1976 (which contains the language commonly referenced as AB 57), which prohibits most instances of after-the-fact reasonableness review for procurement, and in Pub. Util. Code § 454(c)(3), requires the Commission to set "upfront and achievable standards and criteria" for procurement⁴⁷. The Commission's goal in setting this penalty is to create clear consequences for utility inaction and to provide further incentive to each utility to meet its APT. It is the Commission's clear desire to never visit these penalties out of our hope and expectation that each utility continually meets its APT or utilizes the flexible compliance mechanism to satisfy its APT.

In order to ensure each utility meets its APT requirement as outlined above, each utility is required to make a filing on February 1 of the year following the applicable APT year outlining the results of achieving its APT. In addition, on July 1 (or the next business day thereafter) of each year, each utility should make a filing to the Commission outlining its progress toward achieving that year's APT, using a similar format to the February 1 filing. In the February 1 filing, each utility should clearly indicate its APT for the relevant year, its additional renewable procurement that is eligible to meet this requirement, sorted by renewable source type (e.g., wind, solar, biomass, geothermal, etc.), an accounting of past, current and anticipated future deficits and any additional information deemed necessary based on utility consultation with the Commission's Energy Division. The July 1 filing should contain the same information but with a clear delineation between actual and forecast quantities for the applicable year.

If the utility has met its APT, subject to the flexible compliance mechanisms adopted in this decision, the February 1 filing will be only a compliance filing. However, if the utility is below the 75% annual threshold described above (while noting the first year exception), this filing is the utility's opportunity to demonstrate why its APT shortcoming is a result of one or more of the four reasons for non-compliance outlined above. If the utility's shortcoming is not a result of one or more of these reasons, this filing represents the utility's opportunity to seek approval for annual shortfalls greater than 25% of the APT if the conditions of §399.14(c) are triggered⁴⁸ or to convince the Commission that a deferral would promote ratepayer interests and the overall procurement objectives of the RPS program. This filing should also include a calculation of any automatic penalties to be assessed for APT deficits above the 25% threshold granted to the utility for each year, calculated based on the penalty levels described above (or any future modification of that penalty), which the Commission can choose to alter by taking the above outlined factors into consideration. The Commission will act within 90 days of receiving this filing, if Commission action is necessary.

We reject the TURN/SG&E recommendation to have each utility file this request to go below the 75% threshold before the end of the year as we expect utility data collection to have some lag behind actual energy production and because making this determination before the end of the year may be only an exercise in forecasting and speculation. However, any utility may seek advance Commission approval of any expected APT shortcoming beyond the 75% threshold by making a filing of its own volition. Given the long duration of anticipated renewables contracts, a utility should have the information to pursue this option if it prefers.

A utility's compliance with the statute is affected by its creditworthiness. As discussed above, utilities that are not creditworthy are not required to procure under the RPS program. (§ 399.14(a)(1).) Since we determined that a utility will have an APT for a given year even if that utility is not creditworthy, we need to determine how that APT is treated for compliance purposes. We find that just as the APT itself is deferred to future years when the utility is creditworthy, so are the compliance requirements. Compliance requirements are not triggered until the beginning of the first calendar year after the utility is deemed creditworthy by the Commission.

We can use an example of a utility that: 1) in 2004 was not creditworthy and had an APT for 2004 of 10 units; 2) sometime in 2005 became creditworthy and had an APT for 2005 of another 10 units; and 3) had an APT for 2006 of another 10 units. In 2006, rather than having a current year requirement of 10 units and a deficit of 20 units, the utility would merely have a current year requirement of 30 units. In other words, the three-year compliance period begins when the utility is fully creditworthy in 2006, rather than in 2004, when the APT came into existence.⁴⁹

Overall, the rules we adopt for compliance provide the necessary flexibility not only to deal with the issues of creditworthiness, market uncertainties, and teething pains of the RPS process, but also to satisfy the request of the ISO that our compliance mechanism be flexible enough to reduce the likelihood that utilities may have to deal with excess output at times of expected over-generation conditions. (ISO Opening Brief, p. 9.)

Despite our willingness to provide all utilities more compliance flexibility than recommended by CalWEA, we have concerns regarding PG&E's and SCE's apparent resistance to the requirements of SB 1078 and renewable procurement in general. CEERT argues, with some justification, that the intent of PG&E and SCE is to "dismantle, not implement, the RPS Program as intended by SB 1078." (CEERT Reply Brief, p. 2.) PG&E has made very aggressive arguments (especially on the issues of creditworthiness and utility need) in an attempt to remove itself from the requirements of SB 1078. SCE has been slightly less aggressive in its arguments, but SCE's main witness Bergmann (while very knowledgeable and precise) was extremely uncooperative.⁵⁰

We note that the utilities may procure more renewable energy resources than the minimum amount required by the statute and this decision. If PG&E and SCE are serious about proving CEERT wrong, the best way to do that is to voluntarily procure more than the bare legal minimum of renewable generation. This would certainly be the best way to alleviate our concerns, and would also be consistent with California's Energy Action Plan.

⁴³ Seller non-performance includes contract defaults, force majeure, terminations or project development delays. This condition assumes that the non-performance is due to factors beyond the control of the utility. If the utility was responsible for the seller's non-performance, no deficit banking would be permitted.