4. Interim GHG Emissions Performance Standard: Design and Implementation
In the discussion that follows, we use the terms "interim GHG emissions performance standard," "standard," and "emissions performance standard" (or "EPS") interchangeably. We use the term "greenhouse gases" or "GHG" to refer to the types of emissions that will ultimately need to be included in the strategies to mitigate climate change. More specifically, this term refers to the six gases listed under Section 42801.1(h) of the California Health and Safety Code: (1) carbon dioxide (CO2), (2) methane, (3) nitrous oxide, (4) hydrofluorocarbons, (5) perfluorocarbons, and (6) sulfur hexafluoride, consistent with the definition contained in SB 1368.43
While the new law refers to all six of the gases listed above in its definition of greenhouse gases, it also establishes a deadline of February 1, 2007 for enforcement of the EPS. We do not have sufficient data to create and enforce a GHG emissions performance standard beginning February 1, 2007 that covers all of the gases. Currently, utility data for the CCGT standard contemplated by SB 1368 is only reported to the California Climate Action Registry for the largest GHG emissions source by volume, namely, for CO2. This is also the only GHG consistently reported by electrical corporations on an entity-wide basis at this time.44 The Commission will seek to identify options to integrate reporting of all GHGs in the future. However, in order to meet the February 1, 2007 statutory deadline, we limit today's adopted EPS to CO2 emissions as it is the most pervasive of the GHGs, and the most widely reported and verified of the GHGs at this time.
We may reevaluate how the EPS can be expanded to include some or all of the additional gases listed above when sufficient knowledge and data becomes available on their respective emission levels from generation sources, and when that information can be translated into an enforceable EPS.45
SB 1368 specifies several design and implementation parameters for the interim EPS, and in the following sections we highlight the relevant language from the statute. For each design or implementation issue, we briefly summarize the staff proposal as well as the chief points of contention reflected in parties' comments before presenting our conclusions. As usual in such proceedings, the record is voluminous, and therefore we do not summarize every nuance in individual positions.
4.1. Entities Subject to the EPS
Prior to the passage of SB 1368, there was some debate on both policy and legal grounds as to which entities should be subject to the EPS. All parties now conclude, as we do, that SB 1368 has laid this debate to rest by directing that this Commission develop an EPS for LSEs and by specifically defining that term in the new law. Consistent with that definition, the EPS we adopt today will apply to every electrical corporation, electric service provider, or community choice aggregator serving end-use customers in the state.46 Throughout this decision, we use the term "LSE" to refer collectively to these entities.
4.2. Types of Generation and Financial Commitments Subject to the EPS ("Covered Procurements")
SB 1368 describes what types of generation and financial commitments will be subject to the EPS ("covered procurements"). Under SB 1368, the EPS applies to baseload generation, but the requirement to comply with it is triggered only if there is a "long-term financial commitment" by an LSE.47 There are two kinds of "long-term financial commitments" under SB 1368. For LSE-owned powerplants a long-term financial commitment occurs when there is a "new ownership investment." For baseload generation procured under contract, there is a "long-term financial commitment" when the LSE enters into "a new or renewed contract with a term of five or more years."48 For purposes of our discussion here, we will call a long-term financial commitment for baseload generation a "covered procurement."
SB 1368 defines baseload generation as "electricity generation from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60 percent."49 The new law defines the terms "powerplant" and "plant capacity factor" for this purpose, as follows:50
· "Powerplant" means a facility for the generation of electricity, and includes one or more generating units at the same location.
· "Plant capacity factor" means the ratio of the electricity produced during a given time period, measured in kilowatt hours to the electricity the unit could have produced if it had been operated at its rated capacity during that period, expressed in kilowatt hours.
Finally, the statute also states that "all combined-cycle natural gas powerplants that are in operation, or that have an Energy Commission final permit decision to operate as of June 30, 2007, shall be deemed to be in compliance" with the EPS.51
In the following sections, we discuss the issues raised in parties' comments with respect to covered procurements.
In their comments, Green Power Institute (GPI) recommends that the Commission adopt a 50% capacity factor threshold in order to include high-use intermediate and shaping facilities in the definition of covered procurements. We prefer not to go beyond what the Legislature intended and, therefore, the interim EPS will apply to baseload generation that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60 percent. We note that staff and most parties to this proceeding recommended a 60% capacity factor threshold for covered procurements, even prior to the passage of SB 1368, based on the data submitted in Phase 1 of this proceeding. That data illustrates that a 60% capacity factor captures an estimated 78% of the incremental procurement needs in 2012 for PG&E, SDG&E and SCE combined, and would capture 72% of CO2 emissions associated with those procurement needs.52
Prior to the passage of SB 1368, parties were divided on the issue of whether contract renewals with existing baseload generating facilities should be subject to the EPS. The language of the statute is clear that new as well as renewal contracts having a term of five years or more represent a "new financial commitment," and therefore must comply with the EPS. Accordingly, we adopt the definition of new financial commitment contained in SB 1368 for the interim EPS.
Retained baseload generation refers to the existing baseload facilities (e.g., coal, nuclear or natural gas-fired plants) owned by the LSE and used to serve its load. As several parties note in their comments, under staff's proposal, retained baseload generation does not enter into the type of commitments that would trigger the EPS review, unless the LSE makes major plant renovations or sells that power under a contract of five years or more with another LSE. Two major questions were raised by parties with respect to retained baseload generation:
(1) Should the LSE's retained baseload facilities be subject to the EPS as a general principle-irrespective of whether the LSE makes a new financial investment in the plant?
(2) Should the utility's new investments (plant alterations) to retained baseload generation trigger application of the EPS, and if so, what types of plant alterations?
We discuss each of these issues below.
Constellation Energy Group (Constellation), Alliance for Retail Energy Markets (AReM) and a number of individual electric service providers propose that the Commission develop a mechanism to subject all of the utility's retained baseload generation to the EPS, either immediately upon implementation of the EPS or periodically thereafter.53 These parties contend that not doing so creates a de facto loophole in the establishment of an EPS, which violates the goals and statutory language of SB 1368.
In particular, Constellation et al.54 argue that the reference in § 8341(d)(1) to "all baseload generation of load-serving entities" precludes any disparate treatment for utility-owned generation and non-utility owned generation. They believe that such disparate treatment exists if the EPS is triggered for all contracts of five years or longer with non-utility owned existing baseload generation (with or without major renovations), but only for utility-owned existing baseload generation if and when it undergoes major renovations. Accordingly, they recommend that the Commission require the utilities to demonstrate compliance with the EPS upon renewal of any "rate recovery contract" for its retained baseload generation, meaning any time the utility seeks rate modifications or submits procurement plans supporting existing utility-owned assets.
Constellation et al.'s reading of the statute is incorrect. As discussed above, the plain language of SB 1368 provides clear direction as to what triggers the requirement to apply the EPS: Sections 8341(a), (b)(1), and (b)(2) provide that the EPS shall apply to all baseload generation in the event that the compliance requirement is triggered by a "long-term financial commitment" as defined in § 8340(j). And that subsection contains an asymmetric definition of what constitutes a "long-term financial commitment" for utility-owned generation and contracted-for generation.
In their comments, Constellation et al. take the phrase "all baseload generation of load-serving entities" in § 8341(d)(1) out of context with respect to the rest of the statute. In particular, that phrase is used in the context of the Legislature's direction for when ("on or before February 1, 2007") the Commission must establish and EPS and at what rate of emissions ("no higher than the rate of emissions of greenhouse gases for combined-cycle natural gas baseload generation."). To interpret this phrase to mean that the Legislature intended to subject utility-owned retained baseload generation to the EPS, with or without a "new ownership investment" as required by § 8341(a)(1), would contradict the language of §§ 8341(a), (b)(1), (b)(2) and § 8340(j), or render it meaningless.
Moreover, the only way to give the meaning to § 8340(j) that Constellation et al. suggest would be to assume, as these parties do, that a "renewed contract" under the definition of "long-term financial commitment" in § 8340(j) includes the type of "rate recovery contract" with existing utility-owned baseload generation facilities that these parties describe in their comments. First of all, it is doubtful that the kinds of regulatory measures that Constellation et al. describe are contracts as that term is ordinarily understood. Even if they are "contracts," they are not the kind of contracts the Legislature was describing in § 8340(j). Contracts for the procurement of baseload generation and "contracts" for the recovery of costs associated with generation are two separate things. The statute only applies to the former. Furthermore, Constellation et al. do not suggest how one would determine whether any particular "rate recovery contract" is for a period of less or more than five years.
Nothing in the statutory language or legislative history reflects this intent or direction.55 In fact, in the Senate Committee analyses of SB 1368 the term "long term contract" is consistently referred to in the context of the procurement contracts covered under the Commission's procurement planning process, which do not apply to utility-retained generation.56
Finally, contrary to Constellation et al.'s assertions, we believe that excluding utility-owned retained generation from EPS-covered procurements (unless the electricity sold to another LSE under a long-term contract or the powerplant is renovated as that term is defined in this decision) is fully consistent with the principles and objectives for an interim EPS articulated by the Legislature and this Commission. As discussed in Section 3 above, both the Legislature and this Commission have recognized that California utilities are "currently making new long-term financial commitments to electrical generating resources that will have major impacts on GHG emissions for many years to come," and have concluded that an EPS "for new long-term financial commitments to electrical generating resources will reduce potential financial risk to California consumers for future pollution-control costs."57 Accordingly, the definition of covered procurements that we adopt today focuses on preventing "backsliding" through new LSE procurement decisions that will make future GHG reductions more difficult.
Constellation et al. fundamentally disagree with these stated objectives for an EPS. Rather than focus on new financial commitments, they recommend that the EPS scope be broadened to apply to the LSE's existing fleet of baseload generation facilities that are used to meet the LSE's load. However, this is not the purpose of the EPS, as discussed above. In effect, the definition that Constellation et al. recommend would subject the millions of dollars in the LSE's already-built facilities to a standard that is being developed to prevent backsliding in LSE decisions made for future investments and avoid the additional financial and reliability risks that such backsliding would create.
For the above reasons, we reject this recommendation. We will adopt what the Legislature intended by using the same definitions for covered procurements as in the statute. As discussed above, § 8340(g) defines "long-term financial commitment" as "either a new ownership investment in baseload generation or a new or renewed contract with a term of five or more years, which includes procurement of baseload generation."
In its opening comments to the Proposed Decision, SCE argues that the definition of "covered procurements" might result in unconstitutionally impairing a contract that it has with its co-tenants concerning maintenance of the Four Corners Project. SCE does not state that the EPS rule as currently written will prevent it from complying with its contractual obligations, only that it may. Nor does it provide us with a copy of the contract. In short, this record does not establish whether the EPS rule as written will make it impossible for SCE to comply with its contractual obligations, and if so whether that would constitute an unconstitutional impairment of contract. Furthermore, SCE's proposed solution is to grant generic relief, rather than relief for the specific plant where SCE says it has problems. Accordingly, we see no reason to grant SCE's requested relief at this time. If SCE anticipates that the EPS will prevent it from complying with its contractual obligations at Four Corners, it should file an application or petition for modification, together with adequate supporting information, documentation, and analysis, and request appropriate relief.
SCE interprets SB 1368 to exclude from EPS review any new utility investment in retained generation. Specifically, in its comments on the draft report, SCE argues that the definition of "long term financial commitment" provided by SB 1368 is limited to an "'investment in baseload generation' that is also a `new ownership' interest."58 To support this reading SCE argues that the absence of a comma between "new" and "ownership" necessarily means that "new" modifies "ownership" and not "investment." Under SCE's reading, therefore, an investment in baseload generation that is part of an "existing ownership interest," such as repowering or otherwise renovating utility retained generation, would not have to comply with the EPS. SCE bases its grammatical argument on rules outlined in The Gregg Reference Manual.
SCE's assertion that the absence of a comma mandates its reading is incorrect. According to several other sources of grammatical usage, including The Chicago Manual of Style and The Random House Handbook, a comma should be inserted between adjectives when they both modify the same noun in the exact same way.59 Thus, the phrase "nutritious, delicious dinner" has a comma in it, because both "nutritious" and "delicious" modify the word "dinner." Where a comma is required, the two adjectives "can be reversed without affecting their meaning"60 Thus, a "nutritious, delicious dinner" is readily understood to mean the same thing as a "delicious, nutritious dinner."
Accordingly, a comma would only be necessary if one could substitute the phrase "ownership, new investment" for the phrase "new, ownership investment" without affecting the meaning. However, changing the order of the words does affect the meaning; indeed it is not easy to comprehend what the phrase "ownership, new investment" would mean if it had appeared in the statute. Furthermore, these authorities establish that no comma is required where the first adjective modifies the idea expressed by the combination of the second adjective and the noun.61 In these cases, the second adjective pairs with the noun, and the two together are then modified by the first adjective. Thus, no comma is required when we talk about the "typical American meal" or "traditional political institutions." In the first instance the word "typical" modifies the phrase "American meal"; in the second, "traditional" modifies "political institutions." Similarly, here the word "new" modifies the phrase "ownership investment" and no comma is required to express that meaning. Therefore, SCE's argument here is simply wrong.
In its comments on the final report, SCE adds several more arguments contending that SB 1368's definition of "long-term financial commitments" should be read to exclude significant renovations or repowering of utility retained generation. In particular, SCE argues that "the purpose of SB 1368 is to encourage new long-term financial commitments to zero- and low-carbon generating resources - not to prohibit other long-term financial commitments, such as major renovations of existing facilities as staff would do."62 In support of this argument SCE cites SB 1368 § 1(e) which states that "new long-term financial commitments to zero- or low-carbon generating resources should be encouraged."
We read this statement of intent to apply most directly to § 8341(b)(6), which provides for an increased return on investment for third parties selling "zero- or low-carbon generation" to electrical corporations. Not only does SCE misunderstand that "encourage" as it appears in SB 1368 specifically refers to § 8341(b)(6), but SCE also ignores the fact that the statute explicitly prohibits "load-serving entities from entering into long-term financial commitments unless any baseload generation" supplied under that commitment complies with the EPS established by the commission. [§ 8341(a).] Thus, SCE's reading is contrary to the plain language of the statute, since § 8341(a) clearly prohibits LSE's from entering into long-term financial commitments that fail to comply with the EPS.
SCE next contends that the legislative history supports its view that "SB 1368 does not apply to major renovations of exiting facilities where the ownership of the facility has not changed."63 As SCE notes, on June 22, 2006 the definition of "long-term financial commitment" was amended and the word "new" was inserted in front of "ownership investment." SCE argues that this change clearly demonstrates the Legislature's intent to include only "new ownership investments," as in acquisitions, and to exclude "existing ownership investments," as in renovations or repowering of utility retained generation.
We disagree. Before "new" was added to the definition, "ownership investment" could have been read to include all utility retained generation, including those facilities built, repowered and renovated prior to the statute's effective date. This is because "investment" can mean either: the sum which is currently invested; or, the placing or outlay of money for income or profit.64 Both meanings are commonly used, and we must assume that the Legislature was aware of this potential ambiguity. Absent the word "new" it is unclear as to whether "ownership investment" means: 1) the sum which is currently invested, as in all utility retained generation; or 2) the outlay of money for baseload generation, as in new commitments of money such as repowering and other major renovations to existing facilities. We conclude that the Legislature added "new" to preclude the broader interpretation that would include all utility retained generation and not, as SCE contends to exclude new investments in utility retained generation.
In its comments to the Proposed Decision, SCE replies that the word "ownership" is unnecessary if the legislature intended the phrase "new ownership investment" to include repowering and investments intended to extend the life of the plant by five years or more. Instead, SCE argues, the Legislature could have achieved the same result by requiring compliance for all "new investments." We disagree. By including the word "ownership" the Legislature clarified any ambiguity that would have otherwise existed between contracted for baseload generation and investments in baseload generation.
More importantly, SCE's reading would undermine the primary purpose of the EPS. One key precept in interpreting statutory language is that "all the rules of statutory construction are subservient to the one that legislative intent must prevail if it can be reasonably discovered in light of the intended purpose."65 The Senate Floor Analysis noted: "The purpose of this bill is to prevent long-term investments in powerplants with GHG emissions in excess of those produced by a combined-cycle natural gas powerplant."66 Here no distinction is drawn between different kind of investments, and we must, therefore, conclude that the Legislature intended to prevent those investments made by owners with long-term effects, such as repowering and alterations intended to extend the life of the plant by five years or more.67
In sum, we concur with staff, Natural Resources Defense Council (NRDC), The Utility Reform Network (TURN), Union of Concerned Scientists (UCS), Western Resource Advocates (WRA) and others that the term "new ownership investment" under SB 1368 encompasses new LSE investments in retained baseload generation.
Several suggestions were presented in comments regarding when the EPS would be triggered for such new ownership investments. Under the staff proposal, repowering of an existing baseload facility would trigger the application of the EPS, in addition to other new financial commitments to baseload plant.68 California Cogeneration Council (CCC) would add that LSE-owned generation be subject to the EPS whenever major equipment is replaced or added, and defines "added" to include the installation of air pollution control equipment. PG&E and SDG&E/SoCalGas recommend that the EPS be triggered for current retained generation (or once a new plant has demonstrated compliance with the EPS) only if the powerplant is repowered or upgraded in such a way that its design capacity has increased.69
In their joint comments on the draft report, NRDC, TURN, UCS and WRA recommend that the Commission consider all major refurbishments, in addition to repowering, to represent new ownership investments that would be subject to the standard. In determining what constitutes a major refurbishment, these parties recommend that the Commission set a threshold for the EPS based on total dollars and total greenhouse gas emissions at stake, but do not propose specific levels for this threshold. More generally, they suggest that the refurbishment be subject to the EPS if it is intended to extend plant life by more than five years and if the plant is designed and intended to operate at a 60 percent capacity factor or greater.
Among these suggestions, we are looking for the best and most workable approach to identifying changes in an existing powerplant that would increase the expected level of GHG emissions from the facility over the long-term. This is not accomplished by requiring that every replacement of equipment or addition of pollution control equipment should trigger the EPS, as CCC suggests. Even after such changes, the plant and its operation may remain essentially unchanged. More importantly, this approach could reduce reliability as old parts are repaired rather than replaced.
We also believe it would be arbitrary to try to set a dollar level threshold for new ownership investments, as NRDC and others recommend. However, their suggestion that the EPS be triggered by refurbishments that significantly extend the plant life does have merit. When coupled with the proposal by PG&E, SDG&E and SoCalGas, we think a workable definition of new ownership investments can be crafted.
Specifically, in addition to new baseload plant construction or the acquisition of new ownership interest in an existing plant owned by others, we will define "new ownership investments" to include any investment that is intended to extend the life of one or more units of an existing baseload powerplant for five years or more, or results in a net increase in the existing rated capacity of that powerplant. "Rated capacity" refers to the plant's maximum rated output under specific conditions designated by the manufacturer and usually indicated on a nameplate physically attached to the generator. New ownership investments will also include any investment made for the purpose of converting a non-baseload plant to a baseload plant (i.e., so that it is now designed and intended to provide electricity at an annualized plant capacity factor of 60 percent or greater).
We believe that the definition above covers "repowering" as the term is generally used in the industry, since the types of renovations normally undertaken during repowering (e.g., replacing one or more of the plant's existing turbine(s)) would significantly extend the life of the unit(s), increase the rated capacity of the powerplant, or both.) However, only those units in a multi-unit generating facility that are being added, replaced or altered must comply with the EPS.70 In any event, additional units may be considered new powerplants, as discussed in Section 4.2.4 below.
SB 1368 defines the term "powerplant" as "a facility for the generation of electricity, and includes one or more generating units at the same location."71 We therefore use the terms "powerplant" and "facility" interchangeably in today's decision.
We read this language to mean that a powerplant may be comprised of one or more generating units at the same location; however, it does not necessarily follow that all of the units at the same location comprise a single powerplant (facility). For example, different resources or technologies could be generating power at the same location, e.g., a generating unit fueled with a renewable resource located in the same site as a fossil-fueled unit. We do not believe that the Legislature intended for the term "powerplant" to mean that these distinct and separate generating technologies and resources should be treated as a combined, single "powerplant" for the purpose of applying the EPS. To do so would effectively permit the blending of high-emitting resources with low- or zero-emitting resources simply due to the physical co-location of the generating units. This could lead to an absurd result where power stations are expanded in order to co-locate high emitting generating units with renewable or low-emitting CCGTs, in order to circumvent the EPS rule.
To avoid this absurd result, we clarify that generating units utilizing different resources or technologies, no matter if they are at the same location or contracted for under the same purchase power agreement, must each be evaluated separately for the purpose of evaluating whether the resource operates as baseload generation and, if so, whether its emissions rate complies with the EPS.
In its comments on the Proposed Decision, IEP requests further clarification on how "units employing the same resource or technology and located at the same site (powerplant) should be treated: Is each unit to be treated as a `facility' or `source' or is the entire multi-unit powerplant the `facility' or `source?'72 In effect, IEP requests us to further clarify the circumstances under which a "powerplant" is a facility comprised of more than one generating unit in applying the EPS rules.73 The discussion above clarifies that if there is a generating unit that is fueled by a renewable resource at the same location as a fossil-fueled unit (i.e., two units that utilize different resources or technologies), we would apply the EPS as if each unit were a single-unit powerplant (or "facility"). The fact that both units happen to be at the same location is not a "sufficient" condition for treating them as a single powerplant, because doing so would lead to an absurd result.
However, as IEP's comments suggest, this clarification needs to be augmented to address situations when more than one generating unit utilizing the same resource (fuel) or technology are at the same location-in other words, does this automatically mean that the two comprise a multi-unit "powerplant" for purposes of applying the EPS? For example, what if there are two generating units utilizing natural gas, one designed and intended to operate as a baseload unit and the other as a load-following unit with a capacity factor of significantly less than 60%? Or what if two baseload generating units at the same location (i.e., each designed and intended to operate at a 60% annualized capacity factor or greater), but one has an emissions rate higher than the EPS and the other significantly lower? In each of these situations, treating the two generating units as a single multi-unit powerplant could lead to absurd results that undermine the intent of SB 1368, such as the "blending" of high and low-emitting generating units to meet the standard (second example), or avoiding the EPS altogether by combining units with high and low-capacity factors to produce an average below the 60% capacity factor threshold (first example).
Accordingly, for the purpose of applying the EPS rule we further clarify that a powerplant is considered to be a generation facility comprised of more than one generating unit if: (1) the units are at the same location and (2) each unit utilizes the same resource (fuel) or technology, and (3) one or more of the units are operationally dependent on another.74 This clarifies our EPS rules in a manner that avoids the absurd results discussed above, and addresses the issue raised by IEP.
In its comments on the Proposed Decision, Constellation suggests that the EPS be applied at a "power block" level, rather at the individual unit level, using the California ISO's Resource ID listing of power blocks for this purpose.75 However, as IEP points out in its comments, this approach has a practical limitation for contracts with planned new units, since the unit might not have a Resource ID at the time of contracting and EPS evaluation.76 Moreover, it is unclear from the example that Constellation presents in its comments whether or not the Resource ID approach to aggregation could lead to the types of absurd results discussed above. Therefore, we reject this recommendation in favor of the clarification we present above in response to IEP's comments.
4.2.5. "Deemed-Compliant" Combined Cycle Natural Gas Powerplants
This brings us to the issue raised by staff's final recommendations, namely, the treatment of combined cycle natural gas powerplants deemed to be in compliance under § 8341(d)(1). We use the term "combined cycle gas turbine" (or "CCGT") powerplant to refer to a "combined cycle natural gas plant" defined in SB 1368.77
SB 1368 provides that all CCGT powerplants "that are in operation, or that have an Energy Commission final permit decision to operate as of June 30, 2007, shall be deemed to be in compliance with the greenhouse gases emission performance standard."78 Staff recommends that a powerplant deemed compliant pursuant to § 8341(d)(1) ("deemed-compliant CCGT powerplant") be required to demonstrate actual compliance upon repowering or upon the renewal of a power purchase contract of five years or more. PG&E, SDG&E/SoCalGas and others argue that this recommendation is inconsistent with the statutory language described above that essentially "grandfathers" these plants, thereby exempting them from the requirement to demonstrate compliance with the EPS.
The staff proposal would essentially apply the same standard of review for deemed compliant CCGT powerplants as for all other LSE retained generation.79 As discussed in Section 4.2.3.2, SB 1368 requires that an LSE demonstrate compliance for all "new ownership investment" in retained generation, which we define as alterations intended to extend the life of one or more units of an existing baseload powerplant for five years or more, or result in a net increase in the existing rated capacity of the powerplant.
A CCGT powerplant that is deemed compliant does not have to demonstrate actual compliance with the adopted EPS standard, but is instead treated as if it met the EPS standard and is excused from making an affirmative showing of compliance.80 Reading § 8341(d)(1) to require that the same kind and scale of alterations, improvements, additions, or renovations that constitute "new ownership investment" would also trigger a requirement that deemed-compliant CCGT powerplants demonstrate actual compliance with the EPS, would render the § 8341(d)(1) deemed-compliant provision redundant as applied to utility-owned CCGT powerplants.
California courts have long observed the canon of statutory construction that when attempting to ascertain the meaning of a statute, "effect should be given...to the statute as a whole and to every word and clause thereof, leaving no part of the provision useless or deprived of meaning."81 In order to give § 8340(j), (defining long term financial commitment to include new ownership investments), § 8341 (requiring that all long term financial commitments meet the EPS) and § 8341(d)(1) (deeming CCGTs compliant) their full effect with respect to utility-owned CCGTs in operation as of the date of implementation of the EPS (or that obtain a CEC permit as of June 30, 2007), we conclude that "new ownership investment" in retained generation cannot automatically trigger EPS review for deemed-compliant CCGT powerplants.
Another canon of statutory construction, however, requires us to avoid interpretations of law that would lead to an absurd result.82 The purpose of SB 1368 would be thwarted if existing CCGT are deemed to be permanently in compliance regardless of any subsequent changes to the facilities. One could argue that if units are added to an existing deemed-compliant CCGT powerplant - thereby increasing its capacity from 50 MW to 250 MW - the additional units are nevertheless "deemed compliant" and do not have to demonstrate actual compliance. Under this construction, an LSE or non-LSE owner could circumvent the EPS simply by adding units that are operationally dependent on one or more existing units within a previously deemed-compliant CCGT powerplant.83 We should avoid construing the statute to achieve this absurd result. The deemed-compliant status is given to existing CCGT powerplants, and extending the exemption to units that did not exist at the time of the passage of the statute is contrary to the purpose and the intent of the law.
Therefore, we require that when additional generating units are added to a deemed-compliant CCGT baseload powerplant resulting in an increase of 50 MW or more to the powerplant's rated capacity, those additional units must demonstrate compliance with the EPS. We select a 50 MW threshold because it is already used to mark the boundary between significant and minor changes in generating capacity for the purpose of triggering CEC powerplant permitting requirements under Public Resources Code § 25123.84 In this way, we avoid the absurd result of creating a loophole that would allow for the installation of an unlimited amount of new capacity at an existing CCGT powerplant without any demonstration that that new capacity complies with the EPS. On the other hand, by not requiring deemed-compliant CCGT powerplants to demonstrate compliance with the EPS for repowering as it is defined within the context of "new ownership investments," we eliminate the redundancy that would otherwise exist between §§ 8340(j), 8341, and 8341(d)(1) with respect to retained generation.85 While the addition of new units resulting in an increase of 50 MW or more to a powerplant's rated capacity is certainly a "new ownership investment," as we define it above, it is a subset of all the possible activities that would constitute "new ownership investment." Thus, by limiting our reading of what parts of a CCGT powerplant are deemed compliant (to exclude additional units totaling 50 MW or more) we avoid redundancy and give each word of § 8341(d)(1) a legal effect distinct from the other provisions of the statute.
Furthermore, nothing in today's decision or in SB 1368 limits the Commission's existing authority to require that utility-owned, or contracted for, CCGT powerplants are properly maintained and are operated as cleanly and efficiently as possible. The Commission retains the right to address questions related to the maintenance and efficiency of CCGT powerplants including but not limited to, the emissions from these plants, in the investor-owned utility general rate cases, long-term procurement plans, or other appropriate proceedings.
Putting this within the context of the other provisions of SB 1368 and our discussion of covered procurements, this means that an LSE-owned CCGT baseload powerplant deemed compliant under § 8341(d)(1) must demonstrate compliance for any units that it adds to its CCGT powerplant that result in an increase of 50 MW or more to the powerplant's capacity as it was rated on the day it was deemed compliant. In effect, we will treat the additional unit(s) that result in an increase of 50 MW or more to the powerplant capacity as a separate powerplant for the purpose of demonstrating EPS compliance. The following example shows how we will prevent CCGTs from circumventing EPS compliance by piece-mealing additions of capacity: a deemed-compliant CCGT powerplant which adds 25 MW of capacity in 2008 and another 25 MW in 2010 will have to show actual EPS compliance for the additional capacity in 2010. The rated capacity of CCGTs for the purpose of establishing when the 50 MW addition is reached will be: 1) for all CCGT powerplants that are in operation on the effective date of this decision-the rated capacity of the powerplant that is operating, or 2) for all other CCGT powerplants (or additions to powerplants) that obtain a CEC final permit to operate as of June 30, 2007-the rated capacity authorized by the permit.
A LSE is also required to demonstrate compliance with the EPS for any new or renewal contract of five years or longer with any CCGT baseload powerplant deemed compliant under § 8341(d)(1) that added new units resulting in an increase of 50 MW or more to the powerplant's rated capacity, as defined above. However, the LSE need only demonstrate EPS compliance for those CCGT units that were added to the deemed-compliant powerplant after it was deemed compliant. Procurement contracts that exist at the time additional units are installed to a deemed-compliant CCGT powerplant (resulting in an increase of 50 MW or more) will not be required to demonstrate compliance until contract renewal.
In sum, consistent with the provisions of SB 1368, our adopted interim EPS will apply to:
(1) New ownership investments in baseload generation made by an LSE, defined as:
(a) Investments in new baseload powerplant (new construction), or
(b) Acquisition of new or additional ownership interest in existing baseload powerplant previously owned by others, or
(c) New investments86 in the LSE's own existing, non-CCGT baseload powerplants that:
(i) are designed and intended to extend the life of one or more units by five years or more,
(ii) result in a net increase in the rated capacity of the powerplant, or
(iii) are designed and intended to convert a non-baseload plant to a baseload plant, or
(d) Units added87 to a deemed-compliant CCGT powerplant that result in an increase of 50 MW or more to the powerplant's rated capacity,88 or
(2) New contract commitments (including renewal contracts) of five years or greater by an LSE with:
(a) baseload generation facilities, unless those facilities represent deemed-compliant CCGT powerplants, or
(b) any deemed-compliant CCGT powerplant that added units resulting in an increase of 50 MW or more to the powerplant's rated capacity. (The contracting LSE need only show that the added units meet the EPS).
In addition, we note that the statute does not specify how to establish the "term" of a contract. In order to implement this program effectively, we must clearly explain how to determine the "term" of a contract. Accordingly, for EPS-purposes we will define the "term" of a contract as "the date of first delivery through the date of last delivery (even if there are intervening periods during which there are no deliveries)." Thus, for example, a contract that provides for summer-only deliveries beginning in 2007 and ending in 2011, does not have a term of five years or more, because the last delivery occurs less than five years after the first delivery. On the other hand, a contract that provides for summer-only deliveries beginning in 2007 and ending in 2012 does have a term of more than five years, because the last delivery occurs more than five years after the first delivery. The date on which the contract is executed is not relevant in determining the "term" of the contract. Thus, in the above examples, it would make no difference whether the contracts mentioned were executed in January of 2006, or May of 2007.
4.3. EPS Performance Level (Emissions Rate)
Section 8341(d)(1) directs the Commission to establish an EPS performance level that is "no higher" than the rate of GHG emissions of a CCGT baseload powerplant. In that same section, SB 1368 includes the grandfathering provisions discussed above; namely, that "all combined-cycle natural gas powerplants that are in operation, or that have an Energy Commission final permit decision to operate as of June 30, 2007, shall be deemed to be in compliance with the greenhouse gases emissions performance standard."
The statute does not specify the emissions rate of a CCGT that it to be used for the EPS performance level. At the direction of the assigned ALJ, parties presented data on heat rates and emission factors for different types and vintages of CCGT powerplants and other generation technologies.89 Parties were directed to specifically consider this data in presenting their proposals for the EPS performance level.
The initial staff "straw proposal" presented during workshops recommended a dual standard-one for existing resources (at a higher emissions rate) and one for new resources (at a lower one). In its draft report, staff modified this proposal and recommended instead a single EPS emissions rate of 1,000 lbs of CO2/MWh (or "lbs/MWh"). After further consideration of the data, parties' comments and the provisions of SB 1368, staff now recommends that a single EPS emissions rate be established at 1,100 lbs/MWh. As discussed above, staff also recommends in the final report that existing CCGT's "deemed compliant" under § 8341(d)(1) be required to demonstrate compliance when repowered or upon contract renewal.
Independent Energy Producers Association (IEP), GPI, PG&E, SCE, SDG&E/SoCalGas (filing jointly), Energy Producers and Users Coalition and Cogeneration Association of California (EPUC/CAC, filing jointly) among others support an EPS level of at least 1,100 lbs/ MWh for a variety of reasons, including:
· An EPS level of 1,100-1,200 lbs/MWh would accommodate different CCGT configurations, some of which may have higher heat rates in order to meet other (non-greenhouse gas) environmental objectives, such as a facility with dry cooling technology for purposes of minimizing water use, or efficiency. (PG&E, IEP, GPI)
· A lower level (e.g., 1,000 lbs/MWh) would not appropriately take into account intermediate units, including reciprocating engine units that will be needed for reliable operation of the grid. (PG&E)
· An EPS level of at least 1,100 lbs/MWh would ensure satisfaction of SB 1368's mandate that all CCGTs currently in operation be deemed compliant with the EPS. (SDG&E/SoCalGas).
· An EPS even higher than 1,100 lbs/MWh should be set in order to ensure that all existing gas-fired units, not just CCGTs, are available for procurement. (EPUC/CAC, Center for Energy and Economic Development (CEED).)90
Division of Ratepayer Advocates (DRA), Sempra Global (Sempra), Calpine Corporation (Calpine) and NRDC support an EPS level of no more than 1,000 lbs CO2/MWh. They argue that there is no need, based on the data presented in this proceeding, to set the EPS level higher than 1,000 lbs CO2/MWh, given that SB 1368 already deems all existing CCGTs to be in compliance. DRA, in particular, contends that it is unnecessary to raise the EPS to 1,100 lbs/MWh to accommodate the minor reduction in efficiency associated with dry cooling.
In considering this issue, we note that SDG&E/SoCalGas interpret § 8341 (d)(1) to mean that the Legislature intended for all deemed-compliant CCGTs to be able to demonstrate that they would pass the adopted standard. We disagree with this interpretation. As we point out in Section 4.2.4 above, the verb "deem" means "to treat something as if (1) it were really something else, or (2) it has qualities that it doesn't have."91 This common definition, in conjunction with § 8341(d)(1)'s requirement that the Commission adopt an EPS that is no higher than the rate of emissions for CCGT baseload generation, indicates that the Legislature intended to allow the Commission to adopt a standard that some CCGT powerplants might not be capable of meeting. While many deemed-compliant CCGT powerplants will certainly also be capable of demonstrating "actual" compliance, some fraction of deemed-compliant CCGTs may not be capable of demonstrating compliance with the EPS if they were required to do so. Nonetheless, under the provisions of § 8341(d)(1), they will be treated as if they had passed the standard. Therefore, we do not agree with SDG&E/SoCalGas' recommendation that we should establish the EPS level high enough so that it could be met by all deemed-compliant CCGTS, if they were required to comply.
Nor do we agree with EPUC/CAC's suggestion that we establish the EPS level high enough to ensure that all gas-fired units would meet it. Had the Legislature intended for the EPS to reflect the GHG emissions rate associated with gas-fired units, not just CCGTs, it would have stated so explicitly. Instead, the Legislature selected combined-cycle, gas-fired power generation as the basis for the EPS. We must assume that in doing so, the Legislature recognized that CCGT technology is considered to be the "technology of choice" for new, baseload power generation fired by natural gas because of its efficiency advantages over other forms of gas-fired power generation.92 Moreover, the Legislature specifically directed that the emissions rate be reflective of a "baseload" CCGT powerplant, and not intermediate/load shaping gas-fired units, as some parties suggest in their comments.
That leaves us with the selection of a specific level of lbs of CO2/MWh emissions that is "no higher than the rate of emissions of greenhouse gases for combined-cycle natural gas baseload generation." The record in this proceeding establishes the following:93
· Based on the million British thermal units (MMBtus) consumed by CCGTs in California in 2004 and 2005 as reported in the CEC's Continuous Emissions Monitoring System (CEMS), CCGTs with capacity factors of 60% or more had emissions as low as 833 in 2004 and 794 in 2005.
· Based on the same CEMS reported data, CCGTs with capacity factors of 60% or greater had emissions as high as 1058 in 2004 and 1006 in 2005.
· The weighted average of emission rates based on the 2004/2005 CEMS data for baseload CCGTs is in the range of 856-915 lbs of CO2/MWh, depending on whether energy or capacity is used as the weighting factor.
· Data from the CEC dating back to 2000 for CCGTs in the Western Energy Coordinating Council region show some facilities not included in the foregoing data with capacity factors greater than 60% and with emission rates ranging from 993-1208 lbs of C02/MWh.94
· Dry cooling, which offers the benefit of lower water consumption, increases the heat rate of a CCGT on the order of 1.5%. 95
Based on this information, the Proposed Decision concluded that establishing an EPS standard for CO2 emissions of 1,000 lbs/MWh was reasonable. However, after considering the comments on the Proposed Decision, we are persuaded that allowing a small amount of leeway above this threshold would more appropriately take into account smaller-sized CCGTs utilizing newer technologies, as well as the variability in heat rates based on altitude and ambient temperatures where the facility is located.96
We conclude from the data and considerations described above, that establishing an EPS standard for CO2 emissions of 1,100 lbs /MWh is reasonable. It represents a level that reflects emission rates associated with both existing and new baseload CCGT units and reasonably accounts for potential CCGT plant "outliers" from the average CEMS that utilize dry cooling technologies, are smaller-sized facilities or are located in the desert or at high altitudes. At the same time, it avoids establishing a standard that is representative of the most inefficient, older deemed-compliant CCGT powerplants currently in operation. In this way, our adopted level reflects the intent of the Legislature to base the EPS on CCGT emissions rates, while acknowledging the concern reflected in the statute's grandfathering provisions that some of the older, less efficient CCGT powerplants currently operating may not be able to meet it.
In sum, we find that an EPS level of 1,100 lbs of CO2/MWh to be reasonable, and we shall adopt it.
4.4. Application of EPS to Contracts: Deliveries or Underlying Facility?
One of the threshold design issues in Phase 1 is how the EPS should be applied to contracts. While all parties agree that the characteristics of the facility supplying the energy should be considered when applying the EPS to new ownership investments, there was considerable debate during Phase 1 on whether the same should apply when considering contract commitments. The discussion focused on the treatment of "specified contracts" since, by definition, these are contracts where the generating units or facilities providing the power are known. We address the treatment of "unspecified" contracts in a separate section of this decision. (See Section 4.12.)
Some parties (including TURN, NRDC, UCS and WRA) recommend that this determination be made based on the annualized operations of the underlying facility or facilities, regardless of the type of contract deliveries. Staff supports this approach. Other parties (EPUC, CAC, SDG&E and SoCalGas) recommend that the Commission assess the capacity factor based only on the energy made available under the contract to the LSE, rather than on the operations of the underlying powerplant. These parties contend that this approach is supported by the "supplied under" language of in §§ 8341(a),(b)(1) and (3), in which the Legislature directs that baseload generation "supplied under" a contract or long-term financial commitment shall comply with the EPS.
In our view, accomplishing the goals of SB 1368 and this Commission's GHG reduction policies requires us to look at the characteristics and emissions of the powerplant(s) being contracted for, not just the characteristics of the contracted-for deliveries, as some parties propose. Indeed, it is the characteristics of the powerplant(s) underlying those financial commitments that create the potential financial risk to California consumers and exposure to future reliability problems that this Commission and the Legislature seek to reduce through the establishment of an EPS, as both have clearly expressed. (See Section 3 above.)
Moreover, the rules of statutory construction support a facility-based application of the EPS. As the Courts have stated on numerous occasions: "It is a cardinal rule of statutory construction that in attempting to ascertain the legislative intention effect should be given, whenever possible, to the statute as a whole and to every word and clause thereof, leaving no part of the provision useless or deprived of meaning."97 Focusing on the phrase "supplied under" to conclude that the Legislature intended for EPS compliance to apply only to contracted-for power deliveries violates this rule. In particular, it would render useless the language of § 8341(4) that states:
"In determining whether a long-term financial commitment is for baseload generation, the commission shall consider the design of the powerplant and the intended use of the powerplant as determined by the commission based upon the electricity purchase contract, any certification received from the Energy Commission, any other permit or certificate necessary for the operation of the powerplant, including a certificate of public convenience and necessity, any procurement approval decision for the load-serving entity, and any other matter the commission determines is relevant under the circumstances."98
In opening comments on the Proposed Decision, the California Municipal Utilities Association (CMUA) and EPUC/CAC quote selected phrases from this section to support their positions concerning what the Commission should consider in determining if the financial commitment is subject to the EPS. In particular, CMUA refers to phrases "the electricity purchase contract" and "any procurement approval decision for the load serving entity" in this section to support its position that application of the EPS should consider the characteristics of the LSE's commitment (and not just the capacity factor of the underlying facility) when that facility is owned and operated by a customer generator or represents bottoming cycle cogeneration.99 In its opening comments, EPUC/CAC highlights the phrases "based upon the electricity contract" and "any other matter the commission determines is relevant under the circumstances" to support its argument that, in the case of assessing the baseload characteristics of a third-party contract, it is the contract deliveries (not the underlying facility) that determines the financial commitment of the LSE and defines the commitment subject to regulation.100 Both CMUA and EPUC/CAC improperly construe these selected portions of § 8341 (b)(4) by taking them out of context. When considered in the full context of this section, the phrases "the electricity purchase contract," "any other permit or certificate," "any procurement approval decision for the load-serving entity" and "any other matter the Commission determines is relevant" refer to the type of information the Legislature expects the Commission to evaluate as it considers the "design of the powerplant and the intended use of the powerplant" for the purpose of "determining whether the long-term financial commitment is for baseload generation." It makes sense for the Legislature to have included the electricity purchase contract in this listing, since information contained in those contracts-such as the specific facilities providing the output-would be relevant to the Commission's consideration of the design and intended use of the powerplant. However, contrary to CMUC and EPUC/CAC's assertions, it does not follow that this section permits the Commission to consider alternative or additional criteria other than "the design of the powerplant and the intended use of the powerplant" in determining whether the commitment is for baseload generation.
We also note that in all instances where it appears in the statute, the phrase "supplied under" follows the term "baseload generation" which is defined by § 8340(a) in terms of electricity generation from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%. The term "plant capacity factor" is also defined by § 8340(l) in reference to the underlying plant operations, i.e., as the electricity the unit could have produced it had it been operated at its rated capacity. We interpret SB 1368 to ensure that LSEs do not enter into contracts with powerplants designed and intended for baseload operations with GHG emissions higher than combined cycle natural gas powerplants. Had the Legislature intended to only consider the terms of the contract (or deliveries under that contract) rather than the underlying facility in determining whether a contract supplied "baseload generation," it would have defined that term as well as "plant capacity factor" to clearly reflect that intent.101
We conclude that the determination whether the EPS applies to a resource should be made based on the characteristics of the generating facilities underlying the contract, and not on the contracted-for deliveries. As staff notes in its final report, for specified contracts the capacity factor, average heat rate and emissions factor of the underlying facility or facilities supplying power should be readily available, since operators are required to provide this information to multiple regulatory agencies such as the Environmental Protection Agency and California Air Districts. Pursuant to § 8341(4), we will use reported information, information from permits and certificates, as well as any other information we deem to be relevant in order to establish the design and intended use of the generating facilities underlying the contract.
As discussed in Section 4.2.4 above, there could be instances where different resources or technologies might be generating power at the same location. For example, a generating unit utilizing a renewable resource (e.g., wind) might be located in the same site as a fossil-fueled unit. Our definition of "powerplant" in Section 4.2.4 clarifies that generating units utilizing different resources or technologies, no matter if they are at the same location, must each be evaluated as a separate powerplant for the purpose of determining whether the resource operates as baseload generation and, if so, whether its emissions rate complies with the EPS.
4.5. LSE Contracts with Customer Generators
A related issue is how to treat LSE contracts with powerplants that also generate power for on-site load (referred to interchangeably in comments as "customer generators," "self-generators" or "self-generation facilities"). EPUC/CAC present the example of a customer generator that has a capacity of 50 MW and uses 45 MW to serve the industrial loads of its own site, selling any surplus energy to the utility on an as-available basis. If the unit were assessed, it would appear to be operating at a very high-capacity factor. However, if the deliveries to the grid under the utility contract were assessed, those deliveries would be at a very "low-capacity factor."102 EPUC/CAC take the position that only the electrical generation output actually delivered to the grid should be considered in determining whether the EPS will apply. In their view, it would be unreasonable to consider a 5 MW as-available sale by a customer generation facility a "baseload" powerplant in the utility portfolio.
NRDC, TURN, UCS and WRA disagree. They argue that self-generation facilities should be evaluated against the EPS based on the operational characteristics of the underlying facility, consistent with the application of the EPS to all specified contracts. Even if the amount of energy delivered to the grid is small, they contend that the facility is still a resource upon which the LSE relies, and long-term reliability risks would still be a concern if the facility is carbon-intensive. In their view, the Commission should avoid situations where the LSE makes separate arrangements for on-site high-polluting resources, since the same risks apply to those facilities.
We agree that the EPS should be applied consistently to the characteristics of the underlying facility or facilities supplying power under contract to the LSE, irrespective of whether those facilities are operated by a customer generator or by a merchant generator (i.e., that does not use any of the power produced on site). Under either circumstances, the operating characteristics of the powerplant(s) underlying contracts of five years or more with an electrical corporation, electric service provider or community choice aggregator, as those entities are defined under the statute, should be considered in assessing whether the EPS applies. As discussed in Section 4.2.4, a powerplant is generally defined as a single generating unit for the purposes of applying the EPS rules, except when the three-prong test for a "multi-unit" powerplant described in that section is met.
We find no merit to EPUC/CAC's argument that this approach creates "a possible discrimination" between customer-owned generation and merchant generation. In fact, the example EPUC/CAC present to support this argument focuses on powerplants with no operational similarities at all except for the amount of power contracted for with the LSE.103 The purpose of the EPS is not, as EPUC/CAC contend, to ensure that generators with similar deliveries to the grid are treated comparably. Rather, as discussed above, the purpose of the EPS is to ensure that LSEs do not enter into long-term financial commitments with powerplants designed and intended for baseload operations that emit GHG at a rate higher than a CCGT powerplant. Under EPUC/CAC's example, it is therefore consistent with this purpose that the 30 MW generator operating at a 90% capacity factor is subject to the EPS, whereas the 5 MW generator operating at a 20% capacity factor is not (assuming that the output of both facilities is under contract with an LSE for a term of five years or greater).
Moreover, we find no merit to EPUC/CAC's contention that applying the EPS to the underlying facility in the case of customer generators represents an attempt by this Commission to exceed its jurisdiction, and is "not allowed by law."104 In particular, EPUC/CAC argue that § 218 "excludes cogenerators from the jurisdiction of the Commission to the extent their generation is delivered on-site or over the fence," and therefore concludes that the Commission's jurisdiction is limited by law to the contract deliveries to the LSE.105
By law, the EPS governs the long term financial commitments of LSEs to any baseload generation, and SB 1368 directs this Commission to design and implement an EPS for this purpose.106 Therefore, once a customer generator decides to offer power over and above its own (or over the fence) on-site consumption to an LSE under a contract with a term of five years or more, the power supplied under that contract comes under our purview for the purposes of evaluating the LSE's (not the customer generator's) compliance with the EPS. For the reasons discussed above, we have determined that the criteria for determining whether or not the long-term financial commitment of the LSE meets the EPS (annualized capacity factor and emissions rate) should, and statutorily must, apply to the underlying facility.
4.6. Treatment of Partial Contracts
The issue of how to treat partial contracts is also related to the question of whether the contract terms or the underlying facility should be considered when applying the EPS. The example discussed at the workshop was a summer product contract for power from a specified pulverized coal plant. Staff recommends that the expected capacity factor of the contractual commitment (not the underlying powerplant(s)) be considered for any partial-year contract. Therefore, if the commitment under the contract represented less than a 60% capacity factor on an average annual basis, it would not be subject to the EPS.107 In staff's view this is reasonable because such contracts would likely be addressing seasonal reliability issues. PG&E concurs with this approach for similar reasons.108
NRDC, GPI, IEP and others object to this treatment of partial contracts, arguing that a blanket exemption for seasonal procurements is both unnecessary and inconsistent with the intent and purpose of the EPS. In particular, they argue that if the purpose of a partial year contract is to address system reliability concerns, then the contract would probably be less than five years in duration and therefore not subject to the EPS. In any case, they point out that such concerns can be addressed by providing for case-by-case review of reliability exemptions, rather than creating a loophole for partial contracts.
We agree. Considering the expected capacity factor of the partial year contractual commitment (rather than of the underlying powerplant) is clearly inconsistent with other aspects of the EPS we adopt today. Such treatment could easily permit baseload generation that would otherwise be prohibited from supplying power to the LSE to supply that power by simply limiting the time period for deliveries. The example presented by IEP clearly illustrates this inconsistency:
"For example, an out-of-state coal plant might enter into a long-term contract to provide baseload power to a California [LSE] for the months of May through October. This unit could also sell its output to another buyer (either an out-of-state buyer or a different California LSE) for the months of November through April. Even if the unit underlying this contract were to run at or near a 100% capacity factor level (certainly not a "shaping" resource by any stretch of the imagination), staff's recommended annual average basis for evaluation would show this resource to have less than a 60% capacity factor and thus not be subject to the screen."109
We agree with NRDC, TURN, UCS, GPI, IEP and others that there is no compelling reason to make a distinction for partial procurements based on horizontal or vertical slices of a facility's output. We already incorporate design parameters into the EPS that will minimize the potential impact of the standard on reliability concerns, and as we discuss in Section 4.8.5, provide for a case-by-case exemption to the EPS based on reliability considerations. This enables us to carefully assess those circumstances where waiver of the adopted EPS may be necessary to address reliability issues through a long-term seasonal contract, without creating an unnecessary loophole in our application of the EPS.
Instead, we will apply the same principle to partial contracts that we apply to other specified contracts, namely, that the generating facility underlying the contract (and not the contracted-for deliveries) will determine whether the commitment is for baseload generation and, if so, the associated emissions rate.
4.7. Treatment of Multiple Generating Sources, Including Contracts with Renewables Firmed by Non-Renewable Resources
Under the staff proposal, each individual generating source underlying a contract where those sources are specified must meet the EPS, with the exception of "firmed renewable products." Under these types of contracted-for deliveries, a renewable resource provides as-available energy and a non-renewable source or sources provide additional "firming" energy, so that the total amount of energy sums to an agreed upon amount. For firmed renewable products, staff proposes that the blend of the emissions from the renewable and non-renewable resources must meet the EPS. In the case of a renewable resource firmed by an unspecified resource, staff would similarly blend the imputed emissions value for that unspecified unit with those of the renewable resource. (See Section 4.12 below on how staff proposes to impute emissions rates for unspecified sources.)
In general practice, staff's proposal for firmed renewable products means the following: As long as the proposed procurement of firmed renewable energy is for deliveries with an annual average capacity factor below the 60% threshold level, then the procurement is automatically exempt from the interim EPS. If the procurement has an annual average capacity factor above this threshold, it generally means that half of the energy deliveries or more under the procurement will be from the non-renewable firming resource, and the procurement would be subject to the interim EPS. Under these circumstances the procurement would be judged as a whole (emissions of renewable and firming energy combined on an annual average basis), rather than applied to each generator separately.
There is general concurrence among parties with staff's overall recommendation on the treatment of contracts with multiple generating sources, namely that each source be treated individually for the purpose of determining both the capacity factor and net emissions rate.110 However, there is considerable debate over staff's blending proposal with respect to firmed renewable products. We discuss the range of views below.
PG&E does not support staff's position on this issue. Instead, PG&E recommends that any resource eligible under the RPS program should be categorically deemed in compliance with the EPS, without regard to the characteristics of any firming non-renewable resource behind the RPS-eligible resource.111 LL Power supports this approach.
GPI opposes PG&E's proposal for a blanket exemption to the EPS for firmed renewable products, arguing that this could provide a significant loophole for bringing high GHG-emitting baseload resources to California LSEs. Like staff, GPI examines the issue of how to treat a renewable product firmed by a non-renewable resource from the viewpoint of contract deliveries. GPI gives the example of a firmed wind contract for 8,760 hours of scheduled energy deliveries at the wind generator's rated capacity, where some two-thirds or more of the delivered energy under the contract would be firming power, rather than renewable. In this instance, GPI argues that a blanket exemption could permit contract deliveries of a baseload product that does not meet the EPS on even a blended basis. Instead, GPI supports the staff proposal to apply the EPS on a blended basis to firm renewable products, rather than apply the EPS separately to each source of power. GPI argues that this is appropriate because the relative contributions of the two sources of power under the procurement (renewable and firming) are intrinsically linked.
In contrast, NRDC, TURN, UCS, WRA and DRA argue that staff's proposed treatment of these contracts (and by extension, GPI's) runs counter to the intent of SB 1368 that the standard is to be applied to the underlying facilities behind a contract, not a blend of their emissions. These parties are particularly concerned that this exception would allow high-emitting resources that would never pass the standard alone (such as pulverized coal) to be blended with zero-emitting renewable resources. In their view the interim EPS should be applied in a manner consistent with the plain language of the statute, even for firmed renewable products.
Plumas-Sierra Rural Electric Cooperative (Plumas-Sierra) does not comment on the specific proposals described above, but generally urges that "that Commission implementation of the standard not result in a perverse situation where an entity delivering a totally clean and renewable resource is penalized by having a firming facility deemed a `baseload resource.'"112
In our view, the position advocated by NRDC, TURN, UCS, WRA and DRA is most consistent with the plain language of SB 1368. As we discussed in Section 4.4 above, SB 1368 requires that EPS compliance be based on the underlying powerplant or powerplants producing power, not just the delivered product under a contract. As NRDC and others point out, allowing a blanket exception for firmed renewable products would permit high-emitting baseload powerplants that would never pass the standard alone to be blended without restriction with zero-emitting renewable powerplants, thereby circumventing the intent of the interim EPS. Accordingly, for contracts with multiple generating sources, each specified powerplant must be treated individually for the purpose of determining both the annualized capacity factor and net emissions.
At the same time, SB 1368 recognizes the importance of renewable resources for the achievement of the state's energy policies,113 and today's decision should avoid creating impediments to long-term contracting with these resources in the process of meeting the requirements and goals of the statute. As discussed in Section 4.12 below, we believe that proposals put forth by PG&E and SMUD for the limited use of substitute system power in long-term contracts suggest a way we can provide a reasonable level of contracting flexibility for firming deliveries with renewables that does not undermine the objectives of the statute.
In sum, for contracts with multiple, specified generating sources, each specified source (powerplant) must be treated individually for the purpose of determining both the annualized capacity factor and net emissions. Based on the definition of "powerplant" presented in Section 4.2.4, this generally means that each generating unit supplying power under the contract will be evaluated individually for EPS compliance. Our EPS rules for long-term contracts (five years or more) with unspecified sources, including the use of substitute system energy to firm deliveries from renewable resources, are addressed in Section 4.12.
4.8. Proposed Exemptions from the EPS Standard
Staff recommends four areas of exemptions from the EPS standard. The first is a categorical exemption for any covered procurement that represents a commitment of less than 25 MW. This size threshold would be based on the unit size for new ownership investments, and on the amount of power contracted for under either specified or unspecified contracts.
Staff also recommends three areas where the Commission could provide exemptions from the EPS on a case-by-case basis, at its discretion. The first is a research, development and demonstration (RD&D) exemption for higher-emitting facilities upon demonstration that the commitment in question would make a significant contribution to developing a lower-emitting resource mix in the future. In addition, staff recommends that the Commission allow for reliability and cost-based exemptions on a case-by-case basis, at the discretion of the Commission.
We discuss each of these proposed exemptions, as well as additional ones recommended by parties in their comments, in light of SB 1368.
As discussed in the draft and final reports, staff concludes that a 25 MW size threshold is reasonable because, among other things, it is compatible with the Air Districts and federal environmental regulations and would comport with the Northeastern Regional Greenhouse Gas Initiative emissions cap program. Prior to the passage of SB 1368, most parties supported the staff proposal to exclude specified resources under 25 MW from the EPS for these and other reasons. In addition, many parties supported staff's recommendation to apply the same size threshold to all contracts, including unspecified, in order to maintain consistency and to minimize administrative complexity.
Since the passage of SB 1368, however, IEP, DRA, GPI and SCE conclude that a size exemption is not permissible under the new law, and now recommend against any size exemption for that and other reasons. While NRDC, TURN, UCS and WRA acknowledge that the language of the statute supports the argument for not having a size threshold at all, these parties still support a de minimus size threshold of 5 MW, consistent with the maximum size limit under the Self-Generation Incentive Program. They also recommend that the size threshold apply to the underlying facility, not the contract or amount delivered to the grid. These parties oppose any size exemption for unspecified contracts, since it is impossible to identify the resources behind these contracts
PG&E, on the other hand, argues that the staff proposal for a 25 MW size threshold for both specified and unspecified contracts is consistent under SB 1368, and continues to support this proposal.114
In our view, a size exemption of any size is incompatible with SB 1368. Section 8341(a) directs that "no load-serving entity or local publicly owned electric utility may enter into a long-term financial commitment unless any baseload generation supplied under the long-term financial commitment complies with the green house gases emission performance standard established by the commission" and § 8341(d)(1) requires this Commission to "establish a greenhouse gases emission performance standard for all baseload generation of load-serving entities" by February 1, 2007. (Emphasis added.) Nowhere in the statute does the language suggest that "all" or "any" may be qualified by the size of generating units covered or contracted-for deliveries. In its discussion of this issue, PG&E fails to mention or consider the plain meaning of § 8341(a) or 8341(d)(1), thereby violating a basic canon of statutory construction.115 As the courts have noted on many occasions: "It is a cardinal rule of statutory construction that in attempting to ascertain the legislative intention effect should be given, whenever possible, to the statute as a whole and to every word and clause thereof, leaving no part of the provision useless or deprived of meaning."116
We therefore cannot reconcile PG&E's position on this issue with the plain language of SB 1368. The legislative history of SB 1368 also provides no indication that the Legislature considered including an exemption for facilities or commitments under a certain size. Moreover, even though a small size exemption has some appeal in terms of administrative simplicity (i.e., reducing the number of procurements subject to the EPS), the selection of the size threshold would be an arbitrary one, and could have the unintended consequences of driving down the size of high-emitting facilities for the sole purpose of obtaining an exemption from the EPS. In addition, a blanket exemption that eliminates what could amount to be many facilities from EPS compliance could expose ratepayers to significant future risks and costs.
In their comments on the Proposed Decision, EPUC/CAC urge the Commission to reconsider a 25 MW minimum size threshold. EPUC/CAC argue that § 8341(b)(4), which permits the Commission to consider the design, intended use, and all other relevant matter in determining whether a specific plant is for baseload generation, grants the Commission the "discretion" and "flexibility" to excuse powerplants smaller than 25 MW from complying with the EPS. EPUC/CAC's argument stems from their confusion of the distinct concepts of "rated capacity" and "plant capacity factor". "Rated capacity" means a powerplant's maximum potential electrical output, and is measured in MWs. For our purposes here, "rated capacity" is synonymous with size. "Capacity factor," on the other hand, is defined as "the ratio of electricity produced during a given time period, measured in kilowatt hours, to the electricity the unit could have produced had it been operated at its rated capacity during that period," and is also measured in kilowatt hours.117 In order to determine a plant's capacity factor, therefore, we are not only permitted but required to consider the plant's rated capacity.
This is significant because SB 1368 defines baseload generation as "electricity generation from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60 percent."118 Section 8341(b)(4), the section EPUC/CAC argue permits a small size exemption, requires the Commission to consider the design and intended use of the powerplant, as well as any other relevant factors, in determining whether a financial commitment is for baseload generation, meaning generation from a powerplant with a capacity factor of at least 60 percent. Once the Commission has determined that a commitment is with a powerplant with a capacity factor of at least 60 percent, however, the question is resolved and the EPS applies.
SB 1368 mandates that all baseload generation, meaning all generation from powerplant with a plant capacity factor of 60 percent or more, comply with the EPS. The statute requires that we use the powerplant's rated capacity, no matter how small, to calculate the powerplant's capacity factor. To excuse a powerplant with a rated capacity of 25 MW or less and a capacity factor of greater than 60 percent from complying with the EPS, therefore, is contrary to the plain language of the statute.
In support of its request that the Commission exercise whatever discretion it is granted by SB 1368 and adopt a small size exemption, EPUC/CAC cite Government Code § 11342.2, which states:
Whenever by the express or implied terms of any statute a state agency has authority to adopt regulations to implement, interpret, make specific or otherwise carry out the provisions of the statute, no regulation adopted is valid or effective unless consistent and not in conflict with the statute and reasonably necessary to effectuate the purpose of the statute.
As explained above, granting an exemption for a class of powerplants based on their "rated capacity" is inconsistent with the definitions of "plant capacity factor" and "baseload generation." Government Code § 11342.2 expressly prohibits interpreting a statutory provision in way that is inconsistent with or conflicts with other provisions of the chapter. We therefore to decline to adopt a small size exemption.
We also interpret SB 1368 to require that all LSEs, irrespective of service territory size, must comply with the provisions of SB 1368. In its comments on the final report, CEED suggests that SB 1368 provides for an exemption for small utilities under § 8341(d)(9), and recommends that we permit one.119 As discussed in Section 5.3 below, § 8341(d)(9) states that the Commission may accept proposals for alternate compliance from small (less than 75,000 retail end-use customers in California) multi-jurisdictional utilities, if certain conditions are met. However, the statute does not provide for a blanket exemption from the EPS based on service territory size. Moreover, a blanket exemption for all utilities with less than 75,000 customers would not achieve the same level of emission reductions and associated reduction in future risks and costs intended by the Legislature.
For the reasons stated above, we do not adopt an exemption to EPS compliance based on the size of the facility or contractual commitment. Nor do we adopt an exemption for small utilities, except as specifically provided for under § 8341(d)(9) for multi-jurisdictional electrical corporations that meet the alternative compliance requirements of that section. (See Section 5.3 below.)
We recognize that a number of parties have been concerned specifically about the application of the EPS to small on-site generation. The Commission has several policies and a self-generation incentive program designed to encourage the installation of such small (and clean) on-site generation sources. These units appear to be the source of concern to NRDC and others. We clarify here that unless such facilities have long-term contracts (five years or greater) with LSEs for full or partial output to be delivered to the host utility grid, their output would not fall under the EPS. We do not believe that interconnection agreements with the distribution system constitute contracts for generation output as defined by the EPS rules adopted in this decision. In cases where small on-site generators do have long-term contracts to deliver output to their host utility, those agreements would fall under the EPS if the generation source is a baseload powerplant.
Staff's recommendation for a case-by-case RD&D exemption is supported by a number of parties, including San Francisco Community Power, PG&E, PacifiCorp, SDG&E and SoCalGas. These parties generally argue that an RD&D exemption will assist in the introduction and adoption of new technologies that can greatly reduce GHG emissions, thereby furthering the Commission's and State's energy policies. In PacificCorp's view, the EPS will act as a deterrent to the early commercialization of IGCC technology and CO2 sequestration projects unless we include an RD&D exemption.120 SCE argues that, without an RD&D exemption, the EPS will drive investment towards increased reliance on natural gas, while failing to encourage investments in new technologies.121
Other parties, including GPI, NRDC, TURN, UCS, WRA, DRA and Calpine, oppose the staff recommendation. They argue that, although the Commission should support RD&D and deployment of advanced technologies, it must not do so at the expense of potentially undermining the EPS. In particular, they contend that because the EPS is a gateway standard, the mere assurance that an Integrated Gasification Combined Cycle (IGCC) coal plant "has or will have in a reasonable period of time the capacity and existing plan to capture and store carbon dioxide" is not sufficient to ensure that it will actually realize such a plan and reduce and maintain emission at or below the EPS limit in the future. 122
We believe SB 1368 provides the flexibility to both encourage new technologies while meeting the EPS. In particular, the Legislature directed us to calculate emissions rates based on "net emissions" from the production of electricity and, with respect to CO2 sequestration projects, and provides for the following:
"Carbon dioxide that is injected in geological formations, so as to prevent releases into the atmosphere, in compliance with applicable laws and regulations shall not be counted as emissions of the powerplant in determining compliance with the greenhouse gases emissions performance standard."123
Therefore, any covered procurements with a baseload facility utilizing such CO2 sequestration projects will still need to meet the EPS (in contrast to a blanket RD&D exemption), but in calculating the net emissions rate we will not count the CO2 that is sequestered through injection in geological formations, as directed by SB 1368.
Because of the unique nature of such CO2 sequestration projects, we will require LSEs to file an application requesting a Commission finding of EPS compliance for any covered procurement that employs geological formation injection. As part of this filing, the LSE shall provide documentation demonstrating that the CO2 capture, transportation and geological formation injection project has a reasonable and economically and technically feasible plan that will result in a permanent sequestration of CO2 once the injection project is operational. This may mean that the sequestration project might become operational after the powerplant comes on line or the LSE enters into the contract. In implementing §§ 8341(d)(2) and (5), we clarify today that we will determine EPS compliance for such powerplants based on reasonably projected net emissions over the life of the facility.
The LSE is required to make a showing of EPS compliance by presenting projections (and documenting those projections) of net emissions over the life of the powerplant. This type of showing will ensure that the purposes of SB 1368 are served. The information presented should also include any emissions-related provisions that may be required through contract and/or permit conditions. In addition, if there are standards developed in the future by relevant regulatory or other entities, those standards should be applied in a uniform and non-discriminatory fashion for all such projects.
In sum, we conclude that a RD&D exemption for non-compliant baseload resources is inconsistent with SB 1368, but clarify how §§ 8341(d)(2) and (5) will be implemented under our interim EPS rules. We also remind parties that all RD&D projects that have an annualized plant capacity factor of less than 60% will not be subject to the EPS standard.
Several parties124 argue that QFs should be exempt from the EPS because the EPS conflicts with and is thereby preempted by federal law, specifically the Public Utility Regulatory Policies Act of 1978 (PURPA).125 In particular, parties argue that the EPS would conflict with the electric utilities' mandatory purchase obligation in 16 U.S.C § 824a-3.126 According to these parties, applying an EPS to new contracts (or contracts up for renewal) of five or more years violates federal law to the extent it may disallow QFs from selling energy on a long-term basis to electric utilities.
In 1978, Congress enacted PURPA (16 U.S.C. § 824a et seq.) which amended the Federal Power Act. Congress believed encouraging the development of certain cogeneration and small power production facilities, which meet specific criteria under 16 U.S.C. § 796 (collectively called QFs), would reduce demand for traditional fossil fuels and increase the use of alternative energy sources.127
16 U.S.C. § 824a-3 states that the Federal Energy Regulatory Commission (FERC) shall prescribe rules that "require electric utilities to offer to ...purchase electric energy from such facilities." In accordance with 16 U.S.C. § 824a-3, FERC promulgated 18 C.F.R. § 292.303. 18 C.F.R. § 202.303 states that "Each electric utility shall purchase, in accordance with § 292.304 [Rates for purchases], any energy and capacity which is made available from a qualifying facility: (1) Directly to the electric utility; or (2) Indirectly to the electric utility. . ." Although both the statute and the regulation require electric utilities to purchase energy from QFs, neither requires the utilities to enter into long-term contracts.
Under PURPA, state regulatory bodies are required to implement FERC's rules regarding purchases and sales between QFs and electric utilities. (16 U.S.C. § 824-a3(f)).128 States may thereby determine some of the circumstances under which sales of electricity by QFs to electric utilities take place.129 In its implementation of PURPA, this Commission has previously determined that PURPA does not require utilities to enter into long-term contracts to purchase QF power. As this Commission stated in D.05-09-022:
"Neither 18 C.F.R. section 292.303 or 18 C.F.R. section 292.304(b) [FERC Rules implementing PURPA] specifies an obligation of this Commission, or any other entity, to adopt a vehicle to deliver available QF power to the utilities. Rather, . . . these CFR sections require a utility to take power made available by a QF, and to pay the cost for power that is equivalent to the utilities avoided cost of procuring or producing that power. . . . Absent from the sections . . . is any mandate that this Commission must either require long-term contracts or establish any specific delivery vehicle."
Similarly, in D.96-10-036 we stated: "We begin with Section 210 &_butType=4&_butStat=0&_butNum=2&_butInline=1&_butinfo=16 USC 824A-3&_fmtstr=FULL&docnum=1&_startdoc=1&wchp=dGLbVtz-zSkAk&_md5=f332baf6032b9005395dbdfa7b2aa5eb" target="_top">(16 U.S.C. Section 824a-3(h)), which obligates utilities to purchase electricity from QFs. . . . Taking a look at the statute, we find no mandated minimum term for PURPA required purchases. Looking to FERC regulations, we similarly find no mandated minimum term." (p. 21, mimeo.) In short, although federal law mandates the purchase of energy from QFs, it does not require utilities to enter into long-term contracts. Therefore, an EPS that does not prohibit a utility from purchasing energy from a QF does not conflict with federal law.
Contrary to opponents' arguments, as the language of both PURPA and the FERC regulations demonstrate, there is no provision that requires that QFs be allowed to enter into long-term contracts. After implementation of SB 1368, electric utilities will still be required to purchase energy from QFs in conformity with federal law. Utilities will simply be limited from entering into new, or renewal, long-term contracts with baseload QFs that do not meet the EPS.130 QFs that do not comply with the EPS will still be able to enter into contracts of less than five years with the utilities. Thus we conclude that it is fully possible for electric utilities to abide by both federal law (PURPA) and SB 1368 as implemented by this Commission. Since the EPS will only apply to new contracts (or contracts up for renewal) of five or more years, electric utilities should be fully capable of complying with both federal and state law and regulation.
Furthermore, SB 1368 does not permit the Commission to exempt QFs from complying with the EPS unless there is a conflict with PURPA regulations. SB 1368 requires that:
(a) No load-serving entity or local publicly-owned electric utility may enter into a long-term financial commitment unless any baseload generation supplied under the long-term financial commitment complies with the greenhouse gases emission performance standard established by the commission, pursuant to subdivision (d), for a load-serving entity, or by the Energy Commission, pursuant to subdivision (e), for a local publicly owned electric utility.
(b)(1) The commission shall not approve a long-term financial commitment by an electric corporation unless any baseload generation supplied under the long-term financial commitment complies with the greenhouse gases emission performance standard established by the commission pursuant to subdivision(d).
SB 1368 requires that "the commission shall consider and act in a manner consistent with any rules adopted pursuant to [PURPA]" when we develop and implement the EPS. (§ 8341(d)(8).) As shown above, there is no conflict between SB 1368 and PURPA. Thus, requiring QFs to comply with the EPS is consistent with the PURPA regulation and we therefore conclude that we cannot grant QFs an exemption from the EPS required by SB 1368.
If a facility uses pre-approved renewable technologies or can otherwise show compliance with the EPS, such facilities are eligible, under SB 1368, to enter into long-term contracts. Small power production facilities that use solar thermal electric, wind, geothermal or certain biomass technologies are pre-approved as compliant under this decision. Other small power production QFs, such as hydroelectric facilities, may very well be able to meet the EPS. Finally, with regard to cogeneration QFs, the cogeneration efficiencies of QFs are accounted for in calculating the emissions rates for cogenerators (see Section 4.9.), thereby assisting cogenerators in meeting the EPS. In short, there is no conflict between SB 1368 and the policy of PURPA to encourage QF generation, unless PURPA is to be read as encouraging generation from high GHG-emitting facilities.
EPUC/CAC urge the Commission to deem all existing gas-fired cogeneration in compliance with the EPS, and thereby categorically exempt from it. In their view, this would appropriately recognize that gas-fired cogeneration has emissions rates similar to or less than CCGTs and would avoid discrimination among forms of cogeneration.
In addition, EPUC/CAC assert that the EPS cannot reasonably be applied to bottoming-cycle cogeneration.131 They request clarification that this technology is not included within the definition of "powerplants" under SB 1368. They argue that there are no emissions associated with the generation of electricity using a bottom-cycle generator-emissions are instead associated with the underlying industrial process. EPUC/CAC propose that the entire emissions output of such facilities should be exempt from EPS, regardless of whether the electrical output is used for on-site needs or is sold under contract to an LSE.
We do not adopt these recommendations. SB 1368 meant the EPS to apply to all cogeneration facilities since it specifies a rule for calculating the emissions of cogeneration facilities. (See § 8341(d)(3).) Had the Legislature intended to exempt gas-fired cogeneration from the EPS, it would have explicitly done so. This is clearly not the case.
We also find no basis in SB 1368 for EPUC/CAC's assertion that bottoming-cycle cogeneration is not a powerplant. SB 1368 establishes that "powerplant" means "a facility for the generation of electricity" and bottom-cycling generation uses waste heat to generate electricity. In addition, SB 1368 does not distinguish between emissions from topping-cycle and emissions from bottoming-cycle cogeneration facilities.
Moreover, EPUC/CAC provide no evidence for their assertion that there are no emissions associated with the production of electricity using this technology. In fact, they acknowledge that when supplemental firing is used to enhance the performance of bottoming-cycle facilities, "any resulting emissions attributable to the supplemental firing may be considered in developing an emissions rate for the cogeneration facility."132 Therefore, as PG&E and others suggest, the determination of net emissions from a bottoming-cycle plant should be made on a facility-specific basis.
In sum, consistent with the direction contained in SB 1368, today's adopted interim EPS will apply to cogeneration facilities. In Section 4.9 below, we address how to calculate the GHG emissions from cogeneration facilities, taking into consideration the thermal energy output contemplated by § 8341(d)(3). As discussed in that section, the calculations can be readily applied to bottoming-cycle cogeneration facilities.
Turning first to reliability exemptions, we note that there is general support for staff's recommendation that the Commission should be able to, at its discretion, provide for case-by-case exemptions to the EPS based on reliability concerns. We believe that this approach is reasonable because it provides us with flexibility to address specific system reliability concerns as they may arise during implementation. It is also workable to implement, since the need to provide an exemption for reliability reasons can be readily assessed as the "go, no-go" decision is being made for each new long-term financial commitments with baseload generation.
At the same time, we note that today's adopted EPS is purposely designed to both protect California ratepayers from long-term reliability risks while minimizing potential adverse impacts on short-term system reliability and associated costs. This has been accomplished by limiting the application of the EPS to long-term commitments, rather than short term transactions, and to baseload powerplants, rather than to those designed to be used for load shaping or peaking. In addition, as discussed further below, the interim EPS will be applied on a "gateway" basis, thereby providing LSEs with the flexibility to operate their facilities differently than originally designed or intended in order to address unanticipated short-term system reliability needs.133 Therefore, we will adopt staff's recommendation for a case-by-case review of reliability exemptions only with the caveat that any consideration of such reliability exemptions comes with a heavy burden of proof on the LSE.
Any reliability exemptions must be pre-approved by the Commission and LSE requests for pre-approval shall be made by application. Pursuant to § 8341(d)(6), we will consult with the California ISO to consider the effects of such requests on system reliability and overall costs to electricity customers. Based on our analysis above, and after consulting on this matter with the California ISO, it seems unlikely that such exemption will actually be needed. However we still want to allow for the possibility of granting such an exemption in the event that unexpected reliability problems arise during implementation.
Several parties, including SCE, SDG&E and SoCalGas, support cost-based exemptions or economic safety valves on a case-by-case basis, particularly when significant economic impacts result from implementation of the EPS. These parties argue that consideration of cost impacts on a case-by-case basis is necessary to ensure that compliance costs do not escalate beyond customers' ability to pay for them. CEED argues that the "only true method to protect the ratepayer" is to establish a specific price cap for CO2 emissions in implementing the EPS.134
Other parties, including GPI, NRDC and IEP strongly object to including case-by-case exemptions based on cost, or adopting other forms of economic safety valves or price caps in the EPS rule. They generally argue that the Commission's consideration of such cost-based exemptions opens the door to a parade of requests that would undermine the EPS.
In our view, approaches that would require us to assess costs or economic impacts on a case-by-case procurement basis are neither reasonable nor workable in the context of complying with the provisions of SB 1368. By its very nature and purpose, the EPS requires that each determination be made without respect to whatever other set of energy procurement opportunities a given LSE has available. This is because the EPS required by SB 1368 is designed to ensure that each baseload facility underlying a new long-term financial commitment meets a minimum level of performance, similar to an appliance efficiency standard. As GPI and others point out, in this context no single procurement can be said to cause significant cost or economic impacts, in and of itself, for a utility's customers.135 Moreover, while CEED criticizes the staff proposal for failing to include cost containment measures, it does not provide any evidence that the costs to ratepayers of procuring compliant resources will be high, or consider the economic, health and environmental benefits associated with EPS compliance that have been expressed by this Commission and the Legislature.136
CEED also faults the staff proposal for not containing price caps. However, we note that CEED does not explain how a dollar-per-ton of CO2 price cap would apply in the context of SB 1368 performance standard requirements, i.e., to each individual "go, no-go" long-term commitment decision made by the LSE. Perhaps CEED is suggesting that a long-term commitment to an otherwise non-compliant plant should nevertheless get a "go" rather than a "no go" because the cost of reducing GHG emissions for that particular plant would exceed more than $x/ton. (Or, as in the case of the Massachusetts, Oregon and Washington price cap policies CEED mentions, the long-term commitment should be allowed because the LSE can pay $x/ton to a qualifying organization (e.g., the Massachusetts GHG Expendable Trust) for each ton above the standard.) Such an approach would allow LSEs to build, or enter into long-term contracts with high GHG emitting plants without any reduction in those plants' emissions (so long as the cost of reducing GHG emissions at those plants is high). This would clearly undermine the SB 1368 goal of protecting ratepayers from the risks of entering into long-term commitments to high GHG emitting baseload facilities in the first place. In addition, we note that CEED fails to address how such a price cap could realistically be established by the statutory deadline of February 1, 2007.
However, we do find merit in Sempra's suggestion that some provision be made in our rules for "extraordinary circumstances, catastrophic events, or threat of significant financial harm" that may be arise during EPS implementation due to unforeseen circumstances.137 Therefore, we will permit an LSE to file a petition for modification of the requirements of this decision under such extreme (and therefore highly unlikely) circumstances, so long as they are unforeseen circumstances not contemplated by SB 1368 and this decision. As in the case of reliability exemptions, our consideration of such a request comes with a heavy burden of proof on the LSE. Any such request must be pre-approved by the Commission and LSE requests for pre-approval shall be made by petition for modification of this decision.
4.9. Calculation of GHG Emissions Associated with Cogeneration
SB 1368 requires the Commission to adopt a methodology for calculating the emissions rate associated with cogeneration facilities that recognizes both the thermal and electrical output associated with cogeneration.138 The relevant provisions of SB 1368 are:
8341(d)(3) The commission shall establish an output-based methodology to ensure that the calculation of emissions of greenhouse gases for cogeneration recognizes the total usable energy output of the process, and includes all greenhouse gases emitted by the facility in the production of both electrical and thermal energy. (Emphasis added.)
8340(k) "Output-based methodology" means a greenhouse gases emission performance standard that is expressed in pounds of greenhouse gases emitted per megawatt hour and factoring in the useful thermal energy employed for purposes other than the generation of electricity. (Emphasis added.)
Below, we briefly describe the output-based methodologies addressed in comments.
Three output-based methodologies were considered by the parties: (1) the Conversion Method (proposed by CAC/EPUC), (2) the Heat Rate of the Generator Method (presented as an option in the Assigned Commissioner's Ruling), 139 and (3) the Avoided Emissions Method (proposed by SDG&E/SoCalGas). Attachment 5 presents calculations using each method to illustrate GHG emissions rates both with and without a cogeneration credit for the thermal energy output.
This method accounts for the thermal energy output associated with cogeneration as follows:
TOTAL GHG EMISSIONS FROM COGENERATION FACILITY
KWH ELECTRICITY + BTU THERMAL ENERGY (expressed in kWh)
Under the Conversion Method, the thermal energy measured in British thermal units (Btu) is converted into a kWh equivalent using the standard engineering conversion factor of 3.413 MMBtu per MWh, or 3413 Btu per kWh. This method is illustrated in Table A of Attachment 5 for a typical topping-cycle cogeneration facility, where 100 MMBtu of natural gas is burned (fuel in) to produce electricity. This process also produces waste heat (steam) as a by-product. The assumptions used to calculate the amount of electricity (7.8 MWh) and steam (48 MMBtu) output are described in Table D. 140 This example shows that, without accounting for any of the steam (thermal) output, the GHG emissions rate for the cogeneration facility would be 1,492 lbs/MWh. This would exceed the adopted EPS of 1,100 lbs/MWh. When the total output of the facility accounts for the steam output (producing the "cogeneration credit"), the effective GHG emissions rate drops from 1,492 lbs/MWh to 537 lbs/MWh. Thus, without the cogeneration credit the facility does not pass the EPS, whereas with the credit the facility becomes EPS-compliant.
The formula for this method is the same as the Conversion Method described above. However, the conversion factor used to convert the BTU THERMAL ENERGY component of the formula into kWh is the heat rate of the generator (in Btu/kWh), rather than the engineering conversion factor of 3.413 MMBtu/MWh. As a result, the denominator of the equation above is divided by a much larger number (12.750 in the Table A example). This results in a smaller cogeneration credit and a higher resulting emissions rate. A comparison of the numerical examples in Attachment 5 shows that the Heat Rate of the Generator Method results in the highest emissions rates among the three alternative approaches, all other things being equal.
The Avoided Emissions Method is different from the two methods described above in that it separately determines the emissions rate for the thermal portion of the power output. This is done by calculating the emissions associated with a proxy steam boiler (with an assumed 80% efficiency). The emissions associated with the thermal portion are then deducted from the total emissions from the cogeneration facility, and the result is then divided by the electric output of the facility. The formula for the Avoided Emissions Method is as follows:
(Total GHG Emissions From Cogeneration Facility) |
- |
(Total GHG Emissions From a Proxy Steam Boiler) |
Electric Power in MWh Generated by the Cogeneration Facility | ||
Sample calculations using this method are presented in Attachment 5.
Based on the record in this proceeding, we conclude that the Conversion Method is the preferred approach to use for the interim EPS for the reasons discussed below.141
We find the Heat Rate of the Generator Method to be incorrect as a simple matter of engineering. Specifically, it does not recognize that the thermal output (from the primary electric generation process) at a cogeneration facility will most likely be used directly as steam to do work, not converted into electricity in a secondary electric generation process that would incur the thermodynamic losses at the heat rate of the generator. In effect, using an electric heat rate to convert thermal energy output to kWh in this manner can double count the efficiency losses in the context of an output-based methodology.142
With respect to the Avoided Emissions Method, we concur with CCC, NRDC, TURN, DRA and others that this method is problematic for several reasons. First, as CCC points out, it may be very difficult to determine the characteristics of the stand-alone boiler whose GHG emissions are avoided by a cogenerator:
"Is it the on-site boiler that the cogeneration unit replaced when it was first constructed? If the cogenerator or its thermal host continues to maintain an auxiliary boiler to provide steam when the cogeneration unit is down, is that the avoided boiler? Or is the avoided boiler a new, state-of-the-art boiler that the thermal host might use to replace the existing cogeneration unit?"143
Unraveling the answers to these questions during future power contract negotiations could end up being extremely complex and contentious. Moreover, the record in this proceeding does not provide us with a reasonable approach for estimating the emissions from the boiler that would be utilized in the absence of cogeneration. As NRDC and others point out, SDG&E/SoCalGas' assumption of 80% efficiency for such a boiler is an arbitrary selection. The CEC data that SDG&E/SoCalGas suggest could instead be used to determine the general efficiency of gas boilers may not be representative of boilers located outside of California. In any event, it would be inaccurate to assume a general efficiency for all boilers since not all cogeneration facilities are gas-fired. Finally, with respect to SDG&E/SoCalGas' alternate suggestion that the boiler efficiency be set at the minimum state or local standards, we note that the cogeneration facilities under consideration are not necessarily new facilities. Therefore, we concur with NRDC, TURN, UCS and WRA that it would not be accurate to assume that the boiler that would have been used in its place would have efficiencies that meet current standards.
A comparison of the Avoided Emissions Method with the Conversion Method also reveals that the Avoided Emissions Method may effectively ignore important fuel savings benefits associated with cogeneration. Across the range of usable steam output in our examples (e.g., near zero to about 55 MMBtu), we observe that the amount of fuel consumed in an avoided emissions analysis is always greater at the same level of usable steam output, everything else being equal. This appears to be due, in large part, to the fact that the Avoided Emissions Method uses two different resources to produce two different products (electricity and steam), whereas cogeneration uses one process that captures the benefit of two products. As a result, the Avoided Emissions Method may calculate an emissions rate based on the use of more fuel than a cogeneration facility might otherwise use during its actual operation.
In contrast to the Heat Rate of the Generator Method, the Conversion Method represents an output-based method that appropriately recognizes that the thermal output of a cogeneration facility can be used directly as steam to do work, and not for the secondary production of electricity. Relative to the Avoided Emissions Method, the Conversion Method has the advantage of being more accurate in calculating the actual emissions rate of the cogeneration facility, since it takes into account the actual thermal output of the cogeneration facility. It also is easier to implement and administer because it does not involve making assumptions about the type of boiler "avoided" and associated emissions rates. Finally, as discussed above, the Conversion Method fully recognizes the fuel savings benefits associated with cogeneration. For these reasons, we adopt the Conversion Method of calculating cogeneration emissions rates for the purpose of determining compliance with the interim EPS.
In their comments, some parties who support the Conversion Method express concern over how it may be implemented. In particular, SCE contends that, as currently formulated by EPUC/CAC, the method does not take into account the losses from converting available thermal energy into "useful work." NRDC, TURN, UCS and WRA express concern that the EPUC/CAC proposed formula does not acknowledge that some of the "available" thermal output may be wasted (not "used") by the thermal host. These parties suggest that further clarifications or adjustments to the formula are needed to ensure that "the useful thermal energy employed for purposes other than the generation of electricity is factored into the calculation," as directed by § 8340(k).
We believe that these concerns can be addressed by using the FERC definition of "useful thermal energy" in its regulations mandating the minimum efficiencies of a QF, as recommended by EPUC/CAC. More specifically, FERC defines a cogeneration facility as "equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam)." The regulations also define "useful thermal energy" as:
"(h) Useful thermal energy output of a topping-cycle cogeneration facility means the thermal energy:
"(1) That is made available to an industrial or commercial process (net of any heat contained in condensate return and/or makeup water);
"(2) That is used in a heating application (e.g., space heating, domestic hot water heating); or
"(3) That is used in a space cooling application (i.e., thermal energy used by an absorption chiller)."144
By defining useful thermal energy in terms of its application to a productive industrial process, we concur with EPUC/CAC's observation that the FERC definition of "useful thermal energy output" includes only the thermal energy that is actually intended to be delivered to the thermal host (or in the case of bottoming-cycle cogeneration, first applied to the thermal application or process), and not any remaining thermal energy intended to be exhausted as waste heat. Moreover, it is also consistent with the plain meaning of "useful" that the FERC definition of "useful thermal energy" requires losses from converting available thermal energy into useful work to be taken into consideration when estimating/computing that value. Accordingly, in our rules we will clarify that the BTU THERMAL OUTPUT (expressed in kWh) in the adopted Conversion Method formula represents "useful thermal energy" output as defined in the FERC regulations implementing QF policy under PURPA.
With respect to the application of this formula to bottoming-cycle cogeneration, EPUC/CAC suggest that the energy input amounts for calculating the numerator ("total GHG emissions from cogeneration facility") should only reflect the amount of fuel associated with supplemental firing in the electric generating process, and should not reflect any of the "fuel in" (energy input) used in the underlying industrial process.145 As we understand EPUC/CAC's argument, this is because if no supplemental energy is added to the waste heat to fire the generation, then there would be no electricity generated using this type of cogeneration technology, and therefore no emissions.146
However, if as EPUC/CAC suggest, only the energy input for supplemental firing for the electric generation is used to calculate the emissions levels in the numerator, we are left with a formula that divides this value by both the thermal energy output used for the industrial process and the electricity generation produced through the supplemental firing of the industrial process waste heat. We do not believe you can have it "both ways"-that is, only count the energy input for one of the co-generation outputs, but divide by both outputs. Therefore, we reject EPUC/CAC's recommended clarification to the Proposed Decision. Instead, the Conversion Method formula should be applied to bottoming-cycle cogeneration as discussed in Section 4.9.1.1 above, and the "fuel in" should reflect the fuel used to produce the thermal energy output for the industrial process as well as any supplemental fuel used for supplemental firing.
Nonetheless, we do find EPUC/CAC's recommendation on how best to document the useful thermal energy output of cogeneration facilities at the EPS "gateway screen" to be reasonable and workable. Specifically, EPUC/CAC recommend that we take advantage of the existing documentation requirements of cogeneration facilities, noting that they are required to complete a questionnaire on an annual basis to demonstrate compliance with FERC efficiency requirements. On this form, the cogenerator presents monthly and annual values for energy input (therms), useful power output (kWh), and useful thermal energy output (MMBtu).147 For the purpose of the interim EPS, we will calculate a cogenerator's emissions rates using the values presented in these questionnaires, which are readily available from the interconnected utility. For new cogeneration facilities, when this questionnaire has not been submitted to the utility, the emissions rate calculation will be based on readily available energy input, useful power output and useful thermal energy output information in FERC Form 556, required for QF certification.
We emphasize, however, that the above approach for calculating and documenting cogeneration emissions rates is adopted for the limited purpose of demonstrating compliance with the interim EPS. Our determinations today are in no way intended to prejudge or predetermine the approach to be established in the context of our Procurement Incentive Framework or under the statewide GHG emissions limit envisioned under AB 32.
4.10. Emissions Rates for Renewables
In the draft report, staff recommended that all renewables, including those from biogenic sources, be assigned an emissions rate of zero. Staff recommended this approach after considering EPS goals, including administrative ease, as well as the data presented in comments on the net emissions rates of various renewable technologies.148 In the final report, staff modifies this recommendation pointing to the statutory language of § 8341(d)(4), which states:
"In calculating the emissions of greenhouse gases by facilities generating electricity from biomass, biogas, or landfill gas energy, the commission shall consider net emissions from the process of growing, processing and generating the electricity from the fuel source."
Based on the language of this section, staff concludes that any long-term commitment to renewables should "appear at the gate and file their applicable net emissions rate" before the Commission.149
All parties commenting on this issue disagree with staff's amended recommendations. They generally argue that SB 1368 provides the Commission with flexibility to make upfront determinations regarding the emissions rates of renewables, and to find them compliant with the EPS based on those determinations. NRDC, TURN, UCS, WRA, SDG&E, SoCalGas, and PG&E point to the extensive analysis presented by GPI in its Phase 1 comments that, in their view, supports the following findings:
1) Many renewable generating sources operate without producing any GHG emissions at all, or levels of emissions much lower than the best available CCGT. This group of renewables includes geothermal, solar and wind.
2) Even without re-injection, the highest GHG emitting geothermal generators emit less than 100 lb (CO2 equivalent/MWh, which is a fraction of the GHGs emitted by the most efficient CCGTs,
3) Solar thermal generators with full gas assist (up to 25 percent gas heat input) produce approximately 375 (CO2 equiv) lb/MWh, still less than half the amount emitted by the most efficient CCGTs, and
4) When net emissions are accounted for, as required under SB 1368, generating electricity from biomass, biogas or landfill gas energy actually reduces the net GHG emissions associated with the disposal of society's waste and residue materials.
Attachment 6 summarizes the GHG emissions data filed by GPI. No party disputes the data or the conclusions drawn from it, as summarized above. Based on the record on net emissions rates of renewables, GPI, NRDC, TURN, UCS, WRA, SDG&E/SoCalGas, LS Power Generation (LS Power) and PG&E recommend that the Commission make a one-time determination in Phase 1 that renewables comply with the EPS.150
IEP generally concurs with this position, but presents an alternate recommendation for biogenic-based renewable technologies. IEP suggests that the Commission adopt a pre-established calculation of net GHG emissions for each type of biogenic-based renewable technology that is likely to be subject to the EPS. These pre-approved emission calculations would then be used by the LSE when seeking approval for such projects.
We agree with GPI, NRDC, TURN and others that requiring the LSE to demonstrate compliance with the EPS for each and every long-term commitment with a baseload renewable resource would not further our policy objectives or those of the Legislature. Those stated objectives recognize that renewable resources are valued as being both environmentally and economically sound in the context of addressing the adverse consequences of climate change on the economy, health and environment of California.151 In fact, SB 1368 echoes the policy expressed in the Energy Action Plan II that renewables (along with energy efficiency) are to be used to satisfy increasing energy and capacity needs before LSEs turn to fossil-fired generation.152
It is therefore fully consistent with these objectives to consider the approach recommended by these parties, that is, to issue an upfront finding in today's decision that renewable resources comply with the EPS. Moreover, if the record clearly demonstrates that these resources will pass the standard on a net emissions basis, it would be redundant and costly to require that LSEs demonstrate EPS compliance for each new ownership investment, new contract or renewed contract with renewables. Therefore, the general approach suggested by GPI and others would also enable us to reduce those costs, thereby reducing overall costs to electricity customers as well.
In its final report, staff expresses concern that SB 1368 may not permit the Commission to make an upfront one-time determination of EPS compliance for renewables. We find nothing in the statute that would preclude us from doing so. Section 8341(b)(1) directs that we shall not "approve" a long-term financial commitment by an electrical corporation "unless any baseload generation supplied under the long-term financial commitment complies" with the EPS. This language does not preclude us from determining, based on our consideration of these representative emissions rates, that specific baseload resources or technologies have emissions well below the EPS and should therefore be pre-approved as EPS-compliant. In fact, §§ 8341 (b)(3) and 8341(d)(6) require that we "establish procedures" to implement the EPS, and in doing so, § 8341(d)(6) also directs us to consider the effects of the standard on "overall costs to electricity customers."
For the reasons stated above, we find that the approach for finding renewables compliant with the EPS recommended by GPI, NRDC and others is both consistent with the language and intent of SB 1368, as well as reasonable in light of overall cost considerations. However, based on the record in Phase 1, we cannot make a blanket determination today that all renewable resources or technologies are EPS-compliant, as these parties suggest. This is because the evaluation of net emissions presented on the record and discussed in parties' comments did not consider several types of renewable resources or technologies, including hydroelectric, fuel cells, photovoltaics, biodiesel, and ocean thermal systems.
Nonetheless, as illustrated in Figure 1, the record clearly supports a finding that the net GHG emissions from the following renewable resources/technologies meet the interim EPS:
· Solar Thermal Electric (with up to 25% gas heat input)
· Wind
· Geothermal, with or without reinjection
· Generating facilities (e.g., agricultural and wood waste, landfill gas) using biomass that would otherwise be disposed of utilizing open burning, forest accumulation, landfill (uncontrolled, gas collection with flare, gas collection with engine), spreading or composting.
Consistent with the direction in SB 1368, the studies presented in the record calculated the emissions rates based on an evaluation of the net emissions resulting from the production of electricity.153 In particular, for electricity generated from biomass, the studies considered the net emissions from "the process of growing, processing and generating the electricity from the fuel source," as directed under § 8341(d)(4). Appropriately, the calculations of net emissions considered both CO2 and methane gases (on a CO2 equivalent basis) to reflect the GHG emissions impacts associated with these processes.
The resulting calculations show that the net GHG emissions produced from the resources and technologies listed above are either zero, significantly less than today's adopted interim EPS standard, or even result in a net reduction in GHG emissions. This can be seen from the summary data presented in Attachment 6.
In particular, electric generation using biomass (e.g., agricultural and wood waste, landfill gas) that would otherwise be disposed of under a variety of conventional methods (such as open burning, forest accumulation, landfills, composting) results in a substantial net reduction in GHG emissions. This is because the usual disposal options for biomass wastes emit large quantities of methane gas, whereas the electricity production alternatives either burn the wastes that would become methane gas or burn the methane gas itself, generating CO2. Since methane gas is on the order of twenty to twenty-five times more potent as a GHG than CO2, and since methane has an atmospheric residence time of twelve years, after which it is converted to atmospheric CO2, trading off methane gas for CO2 emissions from energy recovery operations leads to a net reduction of the greenhouse effect.154
The record fully supports an upfront determination that the renewable resources and technologies listed above are EPS-compliant. In practice, this means that an LSE does not have to demonstrate compliance with the EPS for any long-term financial commitments with baseload generation utilizing these renewable resources and technologies. Such commitments get an automatic "pass through the EPS screen" without requiring calculations to demonstrate that the net emissions rate is below the EPS, or requiring that the LSE wait for Commission approval of the proposed financial commitment, if such approval is required. (See Section 5 below.)
In their comments on the Proposed Decision, several parties suggest that the Commission establish additional proceedings or a process for adding to the above list of renewables that are pre-approved to be in compliance with the EPS. If and when there is sufficient data so that parties believe that the Commission could make such additional determinations, parties may file a Petition for Modification of this decision to augment the above list of pre-approved renewable resources and technologies.
4.11. Treatment of Null Renewable Power
There was considerable debate during workshops over how to attribute emissions factors to renewable resources that have sold off their renewable energy credits or "RECs." The term "null renewable power" refers to the power generated by those renewable resources that have transferred their renewable attributes through the trade or sale of RECs.
By way of background, the trading or sale of RECs may, under certain circumstances, provides a flexible compliance option to LSEs for meeting their RPS obligations, among other potential purposes. In California, LSEs are required to meet a minimum percentage of their load through RPS-eligible renewable resources. More specifically, electricity generated from eligible renewable resources must equal at least 20% of the total electricity sold to retail customers in California per year by December 21, 2010.155
A simplified example of a REC trade is depicted in Figure 2, where Utility B is procuring 10 MWs of power generated from a renewable resource, but does not need that amount to meet its RPS requirement, so it sells off the RECs to Utility A. Now the RPS obligation is met by each service territory, even though more of the renewable generation is located in service territory B.156 This example illustrates how the trading of RECs can serve to even out geographic disparities in where renewable development can occur.
In their written comments in Phase 1, some parties recommend that the Commission allow renewables to be treated as renewable power in terms of emissions profiles, regardless of REC status. Others recommend that the treatment of renewable power should require a transfer of all renewable attributes associated with the generation of electricity from the facility to the purchasing LSE. Under this approach, which staff supports, the resulting null renewable power would be considered an "unspecified" resource and treated the same as an unspecified contract for the purpose of imputing GHG emissions. Still others recommend that the Commission not consider this issue now, as the appropriate treatment will depend on how the REC market develops in California.
In considering this issue, we note that there is no regulatory REC market in California at this time.157 We have identified the investigation of a tradable REC system as one of the tasks for R.06-02-012 and plan to initiate this investigation during 2007. This task will now necessarily include integration of the requirements of recently enacted SB 107 (Stats. 2006, ch. 464).158 We therefore cannot predict at this time whether, how or when a REC market will develop in California. Therefore, there is some appeal to the suggestion of NRDC and others that we simply defer the issue of how to treat null power for the purpose of EPS compliance in today's decision.
However, deferring our consideration of this issue would introduce considerable uncertainty with respect to the treatment of renewables, with a potentially dampening effect on the development of these resources. For example, it would create uncertainty over whether a baseload renewable generator will pass or fail the EPS screen when a contract comes up for renewal if that generator sells off RECs in the meantime. We do not believe it serves the purpose of this proceeding, or our consideration of a future REC market, to leave these types of questions unanswered.
The fundamental issue we need to consider is this: Does it make sense to strip renewables of their GHG emissions attributes if RECs are sold when making the "go, no go" decision of whether an LSE can enter into a long-term financial commitment with that facility? We think the answer should be "no" for the following reasons.
First, stripping renewables of their emission profiles in this manner could easily create a "perverse" result in the context of EPS compliance, namely, it could discourage long-term commitments with renewable generators that have zero, low or even negative net GHG emission profiles in favor of resources with higher emissions rates. In the example depicted in Figure 2, the transfer of RECs from Utility B to Utility A simply determines where the power produced by the renewable resource is counted to meet RPS obligations. However, those desirable GHG emission profiles do not physically disappear from the facility with the transfer of the REC. The GHG emissions rate associated with the renewable facility under contract with Utility B continues to comply with the EPS, and renewing (or entering into a new) contract with that facility is preferable than entering into a long-term commitment with a baseload facility that may meet the EPS, but emits a higher level of GHGs than the renewable resource.
Moreover, in the context of EPS compliance, looking at the actual nature of the underlying powerplant even if RECs are sold does not create a double counting problem, as some parties suggest. This is because the EPS represents a "go-no go" standard for new long-term financial commitments separate from the RPS obligation to procure a minimum amount of electricity generation from EPS-eligible resources. As discussed above, each facility has to pass the EPS on its own emissions-generating merits, i.e., a high emitting facility would not be able to use a purchased REC for the purpose of reducing (or blending) its emissions to demonstrate compliance with the EPS. Therefore, there is nothing to double count here, since RECs would not have any value for EPS compliance under our rules. Moreover, our treatment of RECs in the context of a "go-no go" EPS compliance determination is not inconsistent with § 399.12, as amended by SB 107, which provides that a REC "includes all renewable and environmental attributes associated with the production of electricity" (emphasis added), and not discrete investment decisions.
In contrast, in the context of an RPS program, the REC that is sold carries with it all the renewable attributes associated with the production of electricity so that another entity (LSE) can apply those attributes to meet its RPS obligations, which are also defined in terms of electricity production. In determining RPS compliance, double counting would occur if you let the REC "seller" also count those attributes towards its own RPS compliance.159 If, down the road, RECs or similar instruments become tradable offsets for the purpose of meeting GHG emissions limits, then we will need to be very careful of potential double counting-just as we will for using tradable RECs to meet RPS obligations. But in the context of the interim EPS, we do not observe a double counting problem associated with our proposed treatment of null renewable power as long as RECs cannot be used to offset emissions for EPS-compliance purposes.160
Third, in the EPS-compliance context, stripping renewables of their renewable attributes with the sale of RECs would create an inconsistent treatment of RECs between LSE-owned and non-LSE owned baseload renewable generation. This is because, as discussed in Section 4.2.3.1 above, LSE-retained generation is not generally subject to the EPS. So, if an LSE currently owns a baseload renewable generator, or builds one and passes the EPS at the "new plant construction" review point, the emissions from that generator will never be subsequently reevaluated as "null renewable power" if the LSE sells off the associated RECs.161 However, if a third-party (non-LSE) does the same, the renewable facility will be reexamined and under staff's proposal imputed with an unspecified power emissions profile when the renewal contract comes up. Thus, the staff proposal could result in the emissions from two identical renewable baseload generators that sell off their RECs being valued very differently, depending upon who owns the generator.
Finally, as discussed at length in Section 4.12, there are considerable downsides to any approach presented in this proceeding for imputing emission factors to system purchases/unspecified power contracts. Even if we were inclined to impute null renewable power with something other than the facility's actual emissions, which we are not, we lack a reasonable method for doing so.
For all the reasons stated above, in applying the interim EPS we adopt today, the emissions of a renewable facility will not change if or when it sells RECs under a future regulatory REC market. Nor will RECs count towards compliance with the interim EPS by those LSEs who may purchase them for RPS compliance purposes in the future. However, we emphasize that today's determination on how to treat null renewable power and associated RECs is specific to the application of today's adopted interim EPS. This determination in no way guarantees that null renewable power will be assigned a zero or low GHG emissions value in the context of the Procurement Incentive Framework we are implementing in Phase 2 of this proceeding, or the statewide GHG emissions limits adopted by the Legislature in AB 32.
4.12. Consideration of Unspecified Contracts, including "Substitute Energy" Provisions
The staff workshop report defines "unspecified contracts" as those contracts/power purchases that are not linked to any particular generating source. Parties also refer to these types of contracts as "system energy" or "system power" contracts or purchase agreements, and we use these terms interchangeably in this decision. There was considerable debate during Phase 1 over whether to impute a specific emissions rate to unspecified contracts and, if so, what proxy rate to utilize for this purpose. The following approaches for imputing emissions rates were considered and discussed during the workshop process and in written comments:
a) Western Energy Coordinating Council (WECC) system average: Incorporates all generation activities throughout the western region.
b) WECC geographic average: Computes an emissions factor for all generation activities in various regions of the WECC system such as the Northwest, Southwest, etc.
c) CEC calculated "California Net System Power Average" or "California Net Power Mix": Represents the sources (e.g., coal, large hydroelectric, natural gas, nuclear, renewables) of electricity generated in California or imported to serve California customers that no retailer has identified through voluntary disclosure of specific purchases.
d) Coal emissions factor: would be based upon representative emissions from coal generation.
In written comments submitted after the workshop process, parties raise the issue of how to address "substitute energy" provisions under long-term contracts where the generating unit(s) are known ("specified" contracts), particularly in the context of firming deliveries from renewable resources. These contract provisions allow the seller to purchase energy from unspecified sources (also referred to as "system energy") to meet the contracted-for deliveries required under the unit-specified contract.
Below, we summarize staff's recommendations and the positions of the parties, followed by a discussion of our findings and conclusions.
Based upon review of the data and parties comments, staff concludes that the WECC system average is generally not reflective of California activities or markets, and therefore should not be used to impute emissions rates for unspecified contracts. Staff rejects the use of WECC sub-regional geographic averages, since it would appear to penalize and reward LSEs differently based upon the major geographic source of their imported system power. Staff also rejects the use of coal as a proxy emissions factor, concluding that it is not an accurate reflection of the characteristics of all unspecified resources.
Staff recommends utilizing the California Net Power Mix information produced by the CEC as the basis for imputing GHG emissions rates to unspecified contracts. This calculation sums all in-state generation and electricity imports by fuel type and subtracts from this total: 1) electricity procured by retailers (California investor-owned utilities, public power and electric service providers) that they reported as "specified purchases" to the CEC and 2) electricity generated in California for use on-site rather than for retail sales.
The net result is a California Net Power Mix label that presents the percentage of power by fuel type (coal, large hydroelectric, natural gas, nuclear, renewables).162 While reporting of specific purchases is voluntary, in order to make a claim that its mix of power is different from the California Net Power Mix, the retailer must disclose specific power purchases to their customers and to the CEC. The amount of electricity that retailers have elected not to disclose to their customers and to CEC (defined as "net system power") has declined over time as specific-purchase reporting in California has increased: In 1998, net system power represented 98 percent of retail electricity sales, while in 2005 it was less than 30 percent of the total.
In presenting its recommendation, staff acknowledges the concern raised by some parties that LSEs will be inclined to enter into unspecified contracts with high emitting resources in order to circumvent the EPS by having a possible lower emissions rate imputed to that contract. However, staff anticipates that this will not be a substantial issue based on its understanding that long-term contracts with unspecified resources are at most a small fraction of the incremental power supply. Moreover, staff states that it will "monitor contracting patterns and behaviors to ensure that they do not change for this reason."163
SDG&E/SoCalGas support the concept of using the California Net System Mix to impute the emissions profile for unspecified contracts, but only if the refined methodology proposed by CEC staff in May 2006 for the calculation of net system power is utilized for this purpose, rather than the current one. They argue that the refined methodology is appropriate because it results in imputed emissions that will enable unspecified contracts to pass the EPS, whereas the current one will not.
In contrast, Calpine, Sempra, PG&E and SCE, NRDC, TURN, UCS, GPI and WRA generally object to the use of the California Net System Mix, albeit for somewhat different reasons. NRDC, TURN, UCS and WRA argue that relying on any averaged emissions rate is problematic because it: 1) provides no information or guidance on the critical distinctions between emissions from different types of generating units, 2) invariably dilutes the emissions rates of the higher emitting sources and 3) could provide a significant loophole if the average rate enables all unspecified contracts to automatically pass the EPS.
To address these shortcomings, NRDC, TURN, UCS and WRA recommended in post-workshop comments and comments on the draft report that the Commission assign unspecified resource contracts the emissions level of a conventional pulverized coal generator. In their comments on the final report, these parties indicate that they are willing to support the use of the CEC Net Power Mix to calculate the emissions associated with unspecified contracts if the highest emissions rate for each fuel type is used in that calculation. Using the current 2005 California Net Power Mix, NRDC calculates that the result would be a weighted average emissions rate of 1,668 lbs CO2/MWh. Sempra and Calpine argue that using any proxy for imputing emissions rates to unspecified contracts would not be consistent with the Commission's goals or SB 1368. Although long-term commitments may currently make-up only a small fraction of the incremental power supply, Calpine and Sempra submit that the use of a proxy that would assign a lower emissions level to a resource could encourage long-term commitments with resources that would otherwise not meet the interim EPS limit. To address unspecified contracts in a manner that is consistent with SB 1368, these parties recommend that the Commission require that all long-term commitments for baseload generation be made with "specified resources" that can demonstrate compliance with the interim EPS.
GPI supports the position of Sempra and Calpine. In GPI's view, their recommended approach avoids the potential precedent-setting effect any alternative treatment of unspecified power may have for the design of the state's long-term AB 32 greenhouse gas program.
SCE opposes both the use of the California Net Power Mix as well as the recommendation of Sempra and Calpine. In SCE's view, the former represents an arbitrary method to determine whether such contracts should pass the EPS, and the latter fails to recognize that energy contracts without an upfront specified source are common transactions in the energy market today.
Instead, SCE recommends that LSEs be permitted to enter into a contract with a supplier with unspecified resources or facilities, and to provide documentation that shows the average emissions factor of that group of resources or facilities is lower than the rate used to impute emissions for unspecified contracts. If a system purchase is made, SCE recommends that this rate be based on the emissions of the system from which the purchase is being made, not the California Net System Mix. In the alternative, SCE recommends that the rate be based on the "default factor" used by the California Climate Action Registry (Registry) for calculating GHG emissions from the use of electricity. According to SCE, this factor is the average carbon intensity factor for the WECC California region, which is currently reflects "the average for Year 2000 egrid generators located in California, including imported energy."164
PG&E objects to using the California Net Power Mix, arguing that doing so has the potential to penalize or remove from California's resource mix system purchases that are otherwise clean, such as system imports from the Northwest. PG&E recommends that the Commission defer adopting a specific methodology for imputing GHG emissions from unspecified contracts until it can consider a more precise methodology, perhaps through a follow-up implementation workshop.
However, should the Commission adopt the position of Calpine, Sempra and GRI on the issue of unspecified contracts, PG&E requests that the EPS rules clarify that this would not preclude the use of substitute energy, which PG&E asserts is commonly permitted in unit-specific contracts with both non-renewables and renewables contracts.165 PG&E asserts that such contracts often contain substitute energy provisions whereby some portion of the energy delivered would not necessarily come from the specific unit, but instead from unspecified sources. PG&E proposes that the EPS rules maintain contracting flexibility over a contractually specified time period for the use of substitute energy to support contracts covered by the EPS, but to impose contract restrictions as outlined in the table below (Table A):
Table A - Proposed Restrictions for Substitute Energy in Energy Transactions Covered by the EPS
Transaction Type |
In-Area |
Imports |
Renewable and Non-Renewable (Unit Specific, RPS eligible if renewable) |
Substitute energy limited to 15% of forecast energy production if either Condition A or Condition B is met |
Substitute energy limited to 15% of forecast energy production if either Condition A or Condition B is met |
Non-Unit Specific or System Energy |
Cannot do these transactions |
Cannot do these transactions |
Condition A: A contract that permits the seller to provide system energy under a unit specific contract when the unit is unavailable due to a forced outage, scheduled maintenance, or other temporary unavailability for operational or efficiency reasons.
Condition B: A contract that permits the seller to provide system energy under a unit specific contract to meet operating conditions required under the contract, such as provisions for number of start-ups, ramp rates, minimum number of operating hours, etc.
In reply comments, GPI support PG&E's proposed clarification with respect to firming renewables. In GPI's view, this approach represents a "properly structured" firmed renewable contract, in that firming is used to accommodate short-term unpredictable variations in renewable output that is sufficiently limited and, by its nature, will be purchased in the form of as-available, short-term system power.166 Several additional parties, including NRDC, TURN, SDG&E and Sacramental Municipal Utility District (SMUD) also find the PG&E proposal to be reasonable in principle for unit-specific contracts, but express some reservations or suggest modifications. In particular, NRDC, TURN, UCS and WRA caution that any provision for the use of substitute energy should ensure that the 15 percent cap is truly a ceiling, and not a targeted level, and that the use of substitute system power be limited to event-driven, temporary circumstances. SDG&E and SoCalGas suggest that a higher percentage limit (25%) would be more consistent with the RPS eligibility criteria for hybrid systems.
SMUD expresses concern that the PG&E proposal would not adequately address the inherent difficulties associated with limiting firming power for "intermittent" renewable resources (e.g., wind)167 and presents two alternative options for Commission consideration in its comments on the Proposed Decision. Under the first option, the EPS rules would allow contracts for renewable power to be firmed with substitute system purchases but limit the total power purchased to the expected output of the renewable resource. Under the second option, the EPS rules would permit contracting for a fixed delivery amount equal to 80% of the maximum rated capacity of the renewable facility, allowing the purchasing entity to procure substitute energy as needed to meet the contracted level.168
More generally, in their comments on the Proposed Decision, SMUD, CMUA and Barclay et al.169 argue that restrictions on long-term contracts with unspecified contracts create adverse impacts that the Commission must consider. In particular, Barclay et al. argue that such restrictions arbitrarily eliminate power marketers from competition, thereby depriving California consumers of the benefits of their lower cost options. These parties also contend that relying on unit-specific long-term contracts will have an adverse impact on market liquidity and contract reliability. Finally, SMUD also argues that requiring all long-term contracts to be only with specified, unit-contingent resources would adversely impact the resource procurement programs of publicly-owned utilities and their ability to reliably serve load at stable prices.
SB 1368 provides the following general guidance on the issue of how to address unspecified contracts:
"In developing and implementing the greenhouse gases emission performance standard, the commission shall address long-term purchases of electricity from unspecified sources in a manner consistent with this chapter."170
In order to comply with SB 1368's mandate that we address unspecified sources in a manner consistent with the rest of the statute, we believe that our EPS rules should ensure that:
(1) LSEs only enter into long-term financial commitments with baseload generation that comply with the EPS, and
(2) EPS compliance cannot be achieved in a manner that would yield a contrary result, i.e., that results in an increase in long-term commitments with high-emitting sources.
Based on the record in this proceeding, we conclude that imputing emissions rates to unspecified contracts, would not be consistent with SB 1368 for several reasons. First, we have difficulty reconciling the concept of imputed emissions rates with the requirements of SB 1368 since, by definition, such proxies do not reflect the actual emissions from the underlying resources. As a result, using imputed rates does not permit us to determine whether a commitment with an unspecified resource is consistent with the Commission's goals or SB 1368 or simply exacerbates the problems the Commission and the Legislature are trying to address.
Moreover, any method to impute a GHG emissions rate to unspecified resources results in a binary outcome in the context of an EPS-that is, all financial commitments with unspecified resources will either "pass" or "fail" based on the selected level of imputed emissions. As a result, there is enormous pressure to game the methodology and input assumptions used for this purpose, thereby making it very difficult and contentious to implement this particular approach to addressing unspecified contracts.171
Not surprisingly, parties have generally lined up behind this issue based on whether they want "all" unspecified contracts to pass the EPS screen or "none" of them to pass. For example, NRDC originally proposed that the emissions of pulverized coal plants be used to impute emissions for unspecified contracts, an approach that would clearly result in none of them passing the EPS screen. NRDC now indicates qualified support for using the California Net Power Mix, but only if the very highest emissions rates for each technology is utilized. By NRDC's own calculation, this would have the same result: None of the unspecified contracts would pass the EPS screen.
On the other hand, SoCalGas and SDG&E support the use of the California Net Power Mix, but only if the revised version under consideration by the CEC staff is used. When coupled with mid-range emissions rates for each technology, this approach would permit all unspecified contracts to pass the EPS screen.
As DRA illustrates at some length in its comments, there are also various input assumptions associated with calculating an imputed emissions value using any proxy resource mix (California Net Power Mix, WECC system purchases, or others) that could be manipulated to "push" an unspecified contract through the EPS gateway, such as the use of full load heat rates versus heat rate ranges under less than full-load conditions.172
SCE's recommendation also has the potential to push an unspecified contract through the EPS gateway, since the proposed default rates are based on broad geographic averages that would permit high emitting resources to pass the standard. Moreover, under SCE's proposal, the case-by-case review would be one-sided: The Commission would be asked to grant an exception to the imputed emissions value only in those instances where the power is being purchased from a group of very low emitting resources (e.g., a group of all hydroelectric powerplants), but not when the opposite may be true.
Finally, none of the specific proxy approaches recommended by staff or in parties' comments are reasonable or workable for our purposes, at least not at this time. As staff points out, the WECC system average is generally not reflective of California activities or markets, and the use of WECC sub-regional geographic averages would also dilute the impact of high-emitting resources, allowing them to automatically pass through the GHG screen. Similarly, the WECC California region average metric suggested by SCE in its October 18, 2006 comments represents a broad statewide average that does not distinguish among different types of generating resources on the basis of their relative GHG emissions. It is also too broad a metric for the purpose of establishing whether an unspecified contract is EPS-compliant or not.
As discussed above, staff and some parties propose that we utilize the California Net Power Mix as a proxy for the resource mix associated with unspecified contracts for the purpose of evaluating EPS compliance. We note that this mix was developed by the CEC for a very different purpose (power content labeling), and has not been revised, updated or endorsed by the CEC for use in imputing GHG emissions under SB 1368 or in any other GHG emissions policy context.
Moreover, there is no clear conceptual link between this metric and the mix of resources that might underlie unspecified contracts now or in the future, even on a system-wide average basis. The calculation is based on what is left over after the amounts that retailers voluntarily report as the resources underlying their short- and long-term power purchases (and accounting for on-site generation). It was developed to encourage retailers to disclose their actual power mix to customers. For that purpose, the CEC reports that power content labeling has been successful since the amount of net system (unreported) power has decreased significantly since its inception. Nonetheless, we do not find a reasonable conceptual correlation between this metric and the resource mix that might underlie unspecified long-term contracts.
For the reasons discussed above, we find that adopting an approach to unspecified contracts that involves the use of proxy estimates for emissions rates would not further the goals of SB 1368 and would be problematic from an implementation standpoint.
That brings us to the approach recommended by Sempra and Calpine, namely, to require under our rules that all long-term commitments for baseload generation be made with "specified resources" that can demonstrate compliance with the interim EPS. This approach is fully consistent with SB 1368 since it ensures that "any" and "all" long-term financial commitments with baseload generation will meet the EPS, as the statute so directs.173 Moreover, it cannot be gamed in a manner that could result in the opposite outcome than the statute intended, i.e., an increasing number of long-term commitments to high emitting resources. Although SCE argues that this approach would deprive LSEs of needed flexibility in resource procurement, thereby increasing costs to ratepayers, this assertion is simply not supported by the record.
Throughout the workshop process, attendees indicated that the LSEs would be entering into very few, if any, new contracts or contract renewals with unspecified contracts with a term of five years or greater. At the assigned ALJ's direction, SCE, SDG&E and PG&E submitted data on how many contracts of five years or more for unspecified power they (1) actually entered into during 2004 and 2005 and (2) planned to enter into over the 2006-2008 period. These utilities also provided data on the amount of unspecified power they have purchased and plan to purchase under short- term contracts (less than five years).
All three utilities responded that they did not enter into any contracts of five years or more for unspecified resources in 2004 and 2005, and do not anticipate entering into any contracts with unspecified resources with a term of five years or more in the 2006-2008 period. In contrast, all three utilities entered into numerous contracts with short-term unspecified contracts during 2004-2005, which is to be expected given the type of energy products offered under them.174
In sum, the record shows that it is highly unlikely that the LSEs will be entering into any new or renewal power purchase contracts of five years or greater that are unspecified during the transition to a statewide GHG emissions limit. Therefore, requiring that long-term contracts with baseload generation be "specified" so that EPS compliance can be demonstrated should not have a significant, if any, impact on an LSE's resource procurement flexibility.175 Moreover, it is our understanding from consultations with the ISO staff that for the ISO's system reliability determinations, the ISO relies on specific information about the plant facility and its location within the ISO control area. Therefore, the requirement to specify the resources underlying long-term contracts for the purpose of demonstrating EPS compliance is consistent with the type of information that the ISO also requires for these reliability determinations.
A requirement that long-term power purchase contracts specify the underlying generation facilities is also consistent with our discussion of emissions registration in D.06-02-032 and represents a logical interim step towards the implementation of AB 32.176 Under that new law, CARB is required to establish the state's mandatory GHG reporting and verification program by January 1, 2008. At that point, all power contracts will need to provide verifiable GHG emissions documentation. To permit LSEs to enter into new or renewed long-term unspecified contracts with high GHG-emitting facilities through the use of an imputed emissions value for system power in the meantime could put them, and their customers, in a vulnerable position when these reporting requirements take effect in 2008 for the implementation of the statewide, load-based GHG emissions limits.
As Sempra points out, other jurisdictions have developed specific resource tagging mechanisms to track generation attributes, including GHG emissions, of resources within their control areas.177 In particular, PJM Interconnection utilizes the Generation Attribute Tracking System and ISO New England utilizes the Generation Information System for this purpose.178 In our view, it is entirely feasible to implement a program that tracks the GHG emissions of all generating units, and that would enable marketers and other sellers of unspecified resource contracts to assign a reasonable and accurate GHG emissions profile to their contracts. Over time, this should be the strategy pursued by California to deal with emissions from any unspecified resource contracts that LSEs may wish to pursue; however, as the record shows, this is not a likely pursuit for the types of LSE long-term procurements subject to the EPS.
For the reasons discussed above, we will require that all long-term commitments be with specified sources that can demonstrate EPS compliance (or demonstrate that compliance is not required), except when substitute system energy is purchased to firm deliveries from specified powerplants under the limited conditions we describe below. In response to comments on the Proposed Decision,179 we also clarify that the following circumstances would comply with our EPS rules: First, if the long-term contract specifies that power will be delivered exclusively from pre-approved renewable technologies or resources, and there are assurances in the contract to that effect, then the contract would comply with the EPS even if none of the generating sources are specified. Second, if a group of powerplants from which power will be delivered under a contract is specified, and there are assurances in the contract that deliveries will only be from one or more of the powerplants in that group and each of those that are baseload powerplants would individually pass the EPS, then the contract would comply with the EPS. The burden is on the LSE to provide sufficient documentation to demonstrate compliance with the EPS under these circumstances.
In its comments on the Proposed Decision, SMUD argues that if the Commission bans all long-term contracts without a specified unit, it will have failed to follow the requirement of SB 1368 to "address" unspecified contracts, thereby violating the rules of statutory construction.180 We disagree. As noted above, § 8341(d)(7) of SB 1368 requires the following with respect to unspecified sources:
"In developing and implementing the greenhouse gases emission performance standard, the commission shall address long-term purchases of electricity from unspecified sources in a manner consistent with this chapter. "
The word "address" is commonly understood to mean to turn one's attention to, deal with, or treat.181 Therefore, we read the phrase "the Commission shall address" in the context of §8341(d)(7) to mean that the Commission shall direct its attention to, deal with, or treat the subject of long-term purchases of electricity from unspecified sources. By requiring that the Commission "address" a specific topic the Legislature is not directing the Commission towards any particular determination.
To the contrary, the Legislature here has chosen to leave open the question of how to treat unspecified contracts to the Commission. It does not, as SMUD asserts, require that we allow long-term commitments with unspecified resources under the interim EPS. Nor does it prevent us from deciding that imputing an emissions rate for such contracts is unworkable or inconsistent with the objectives of SB 1368. Accordingly, we conclude that prohibiting LSEs from entering into long-term contracts for unspecified power is consistent with the Legislature's requirement that the Commission "address" the subject of unspecified sources with respect to the EPS and, for the reasons discussed at length above, that our treatment of unspecified contracts is consistent with "this chapter."
Nonetheless, we are persuaded by the comments of GPI and others on the Proposed Decision that providing for limited conditions under which system energy can be purchased to firm deliveries under long-term contracts is consistent with the overall objectives of SB 1368. As PG&E and other point out, many new renewable resources cannot by themselves meet the energy profile needs of LSEs without having backup access to flexible and firm system purchases. Completely prohibiting unspecified resources that are used for this purpose could therefore undermine the policies of California to increase reliance on renewable energy resources and thereby exacerbate the problems that the interim EPS is intended to address.182
PG&E's proposal would limit substitute system energy purchases by both (1) restricting the level of substitute energy purchases to no more than 15% of forecast energy production over the contractually specified time period and (2) specifying that such system purchases can only be made under event-driven conditions that are of limited duration. We agree with PG&E that this restricted use of substitute system energy is very unlikely to result in intentionally sourcing energy from high carbon intensive baseload resources, particularly because substitute energy events are often unpredictable and therefore "no new high-carbon generation will be built solely to provide substitute energy at the 15% level."183 Moreover, as PG&E and others points out in their comments on the Proposed Decision, the ability for a seller to substitute energy from the marketplace on a short-term basis is an important feature of a long-term contract because it enables better management of operating and financial risk that can provide greater performance assurance at a more moderate price to ratepayers.184
However, we take issue with PG&E's proposal in one respect.
As SMUD points out in its reply comments on the Proposed Decision, PG&E's proposal for limiting substitute energy purchases does not adequately recognize the unique characteristics of intermittent renewable resources, in particular wind generators. Unlike dispatchable renewable resources, such as biomass and geothermal, actual deliveries from intermittent renewable resources will fluctuate below the expected average output of the facility based on the natural and unpredictable variability of the energy resource, not just the event-driven conditions described under PG&E's proposal. Moreover, actual deliveries from intermittent resources will also fluctuate above the expected average output of the facility based on the unpredictable variability of the energy resource. As a result, there are both increments and decrements to the level of system energy associated with firming an intermittent renewable resource, which is not adequately recognized under PG&E's proposal.
This can be illustrated in the following (very simplified) numerical example: A wind generator with a long-term contract to deliver 40 MWh may sometime produce 25 MWh and sometimes produce 70 MWh. In any event, the buyer withdraws 40 MWh from the grid on an hourly basis. In those hours that the wind generator is producing 25 MWh, the wind generator (seller) will need to purchase 15 MWh of substitute system energy to meet the terms of the contract. Emissions during these hours are positive, but unknown, as the source of the 15 MWh is unknown. When the wind generator is producing more than 40 MWh (e.g., 70 MWh in this example) however, it displaces 30 MWh of system power with power generated from the renewable resource. In other words, there are both increments and decrements to unspecified system energy associated with firming an intermittent renewable resource due to the unique characteristics of such resources. Deliveries from dispatchable renewable resources, such as geothermal and biomass, on the other hand, create "increments" to system energy purchases under the types of event-driven conditions described in PG&E's proposal, but do not also produce the offsetting "decrements" to the levels of system energy described above.
Therefore, whereas PG&E's proposal appropriately restricts the use of substitute energy purchases in the context of dispatchable resources, we believe that SMUD's comments suggest a more appropriate approach to limiting substitute system energy purchases under long-term contracts with intermittent renewable resources. In particular, SMUD's first option recognizes that if the amount of substitute energy purchases is limited so that total purchases under the contract do not exceed the expected output of the intermittent renewable resource, we would expect those increments and decrements to average out to zero on balance. This approach provides the type of contracting flexibility and practicality that SMUD and others argue is uniquely required for long-term contracting with intermittent renewable resources, without creating a loophole or exception to the general rule on unspecified contracts that would be contrary to the intent of SB 1368.
In contrast, we find that SMUD's second option could undermine the objectives of SB 1368 by, in effect, permitting system purchases to equal far more than the expected output of intermittent renewable resources. As discussed above, under this option the LSE could contract for a fixed delivery amount equal to 80% of the maximum rated capacity of the renewable facility, allowing the purchasing entity to procure substitute energy as needed to meet the contracted level. By linking the levels of substitute energy purchases to a percentage of rated capacity that is high relative to the expected output of such intermittent resources, this approach results in "increments" to unspecified system power purchases that can be expected to significantly and regularly exceed the "decrements" to system power over the life of the contract.185 As a result, this approach has the potential to create a significant loophole to our general rule for unspecified contracts that would permit LSEs to enter into long-term contracts with high-emitting resources, yielding a result that is contrary to the intent of SB 1368.
In sum, we modify the Proposed Decision to permit LSEs to enter into contracts with a term of five years or longer that include provisions for substitute energy purchases from unspecified resources ("system energy") under the following circumstances:
1. The contract is with one or more specified powerplants, each of which is EPS-compliant under our adopted rules.
2. For specified contracts with non-renewable resources or dispatchable renewable resources (or a combination of each), substitute energy purchases for each specified powerplant are permitted up to 15% of forecast energy production of the specified powerplant over the term of the contract, provided that the contract only permits the seller to purchase system energy under either of the following conditions:
a) The contract permits the seller to provide system energy when the specified powerplant is unavailable due to a forced outage, scheduled maintenance or other temporary unavailability for operational or efficiency reasons; or
b) The contract permits the seller to provide system energy to meet operating conditions required under the contract, such as provisions for number of start-ups, ramp rates, minimum number of operating hours, etc.
A "dispatchable" renewable resource for the purpose of this rule is one that is not defined as "intermittent" under section 3 below.
3. For specified contracts with intermittent renewable resources (defined as solar, wind and run-of-river hydroelectricity), the amount of substitute energy purchases from unspecified resources is limited such that total purchases under the contract (whether from the intermittent renewable resource or from substitute unspecified sources) do not exceed the total expected output of the specified renewable powerplant over the term of the contract.186
The burden is on the LSE to provide sufficient documentation in compliance submittals to demonstrate that the above requirements are met. In particular, the LSE is required to make available to Commission staff the source data and methodology it uses in developing the level of expected output from renewable resources under contracts with a term of five years or longer that permit substitute energy purchases from unspecified resources, in order to demonstrate that the limits for substitute energy purchases for both intermittent and dispatchable renewable resources were properly established under the substitute energy provisions.
As discussed above, several parties urge us to permit long-term contracts with unspecified contracts under a broader range of circumstances than those permitted under the Proposed Decision. We have carefully considered their concerns in today's decision, and made modifications to the Proposed Decision that we believe can address those concerns and still be consistent with the legal and policy directives of SB 1368. In particular, as SMUD and DRA point out, the EPS rules should recognize that a long-term contract with a group of resources that may not specifically identify the units that will be delivering power should, under certain circumstances, be permitted--and we have clarified those circumstances in today's decision. Further, as SMUD, PG&E, GPI and others point out, the Proposed Decision's restrictions on purchases from unspecified resources does not adequately address the issue of substitute energy purchases under long-term contracts with specified powerplants, particularly for renewable resources.
As discussed above, we have carefully considered the suggestions for addressing this issue and have modified the Proposed Decision to provide additional contracting flexibility to the extent that we believe is consistent with the intent of SB 1368. In addition, in recognition of the reliability concerns raised by several parties in this proceeding, including Barclay et al., our EPS rules permit LSEs to request Commission consideration of a reliability exemption, on a case-by-case basis, in the event that an LSE must enter into a long-term unspecified contract to address system reliability concerns. (See Section 4.8.5.) Moreover, LSEs will continue to be able to enter into short- and intermediate term contracts with all types of resources, including unspecified resources if needed for reliability or economic purposes.
In its comments on the Proposed Decision, SMUD requests that we also make findings that would recognize differences in the procurement practices between publicly-owned utilities and LSEs, and specifically reflect those differences in today's adopted rules regarding purchases from unspecified resources.187 However, the CEC-not this Commission--is responsible for adopted EPS rules that will be applicable to SMUD and other publicly-owned utilities. We reiterate that nothing in today's decision is intended to suggest that the CEC may not consider unique circumstances facing these entities with respect to how an EPS that will apply to them should address purchases from unspecified resources. Nonetheless, we do believe that the policy, legal and implementation issues associated with imputing emission rates to unspecified contracts and with permitting substitute energy purchases under long-term contracts discussed above are relevant to the CEC's rulemaking. We therefore expect that these issues will be considered in consultation with this Commission as the CEC develops an interim EPS for publicly-owned utilities that is consistent with today's adopted EPS, as directed under § 8431(e)(1) of SB 1368.
43 § 8340(g).
44 In particular, as part of the California Climate Action Registry, Pacific Gas and Electric Company (PG&E) has only started to report the other gases beginning in 2006, and SDG&E and Southern California Edison Company (SCE) will start reporting them beginning in 2007.
45 As discussed in Section 4.10 below, we consider representative emissions of both methane and CO2 for a much more limited purpose, namely to show that generating electricity from biomass, biogas or landfill energy can actually reduce the net GHG emissions associated with the disposal of society's waste and residue materials, and therefore we should pre-approve biomass generation as complying with the EPS.
46 § 8340(c), (d), (e), and (h). To date, no community choice aggregator has been formed, though interest has been expressed in a number of localities.
47 § 8341(a), first sentence.
48 § 8340(j).
49 § 8340(a).
50 § 8340 (m) and (l), respectively.
51 § 8341(d)(1).
52 These figures represent the percentage of annual CO2 associated with the utilities' incremental procurement needs in 2012 that would be captured by new commitments to facilities operating at a 60% capacity factor (based on heat rates in the 7000-8600 range). See Response #3 to the ALJ's June 21, 2006 data request posted at www.cpuc.ca.gov/static/energy/electric/climate+change.
53 AReM's membership includes a number of electric service provider respondents in this proceeding: APS Energy Services Company, Inc.; Commerce Energy, Inc.; Constellation Newenergy, Inc.; Sempra Energy Solutions; and Strategic Energy, LLC.
54 See Joint Comments of Constellation Newenergy, Inc., Constellation Energy Commodities Group, Inc., Constellation Generation Group, LLC, NRC Energy, Inc., Mirant California, LLC, Mirant Delta, LLC, Mirant Potrero, LLC and Alliance for Retail Energy Markets on Final Workshop Report, October 18, 2006, p. 7.
55 Throughout this decision, our references to "legislative history" refer to the history of the bill as it was amended in the Legislature, the Committee Analyses at each reading (available at www.leginfo.ca.gov), as well as the public Committee hearing tapes available on SB 1368, all of which we have carefully reviewed.
56 See, for example, Senate Third Reading on SB 1368 (as Amended August 21, 2006 and as amended August 30, 206), p. F: "What is a long-term contract?"
57 See GHG Policy Statement, pp. 1-2 and SB 1368, Section 1, (a)-(l).
58 Reply Comments of SCE on the Draft Workshop Report, September 15, 2006, p. 4. In their comments SCE equates the word "investment" from the statute with the word "interest." Had the Legislature used the word "interest" instead of "investment" it would support SCE's reading. The Legislature, however, chose to use "investment" and not "interest," and therefore did not limit the application of the EPS to new ownership investments that also represent a new ownership interest.
59 Bergen Evans, A Dictionary of Contemporary American Usage, Random House (New York, © 1957).
60 Frederick Crews, Random House Handbook, 4th Ed. Random House (New York, © 1984).
61 The Chicago Manual of Style, 14th Ed., The University of Chicago Press (Chicago, © 1993).
62 Opening Comments of SCE on Final Staff Workshop Report, October 18, 2006, p. 3, emphasis in the original.
63 Ibid., p. 5.
64 Merriam-Webster's Collegiate Dictionary, 10th Ed. (2001), p. 615.
65 Ford & Vlahos v. ITT Commercial Finance Corp., (1993) 23 Cal. Rptr. 2d 175, 21 U.C.C. Rep. Serv. 2d (CBC) 1228 (App. 1st Dist.), as modified on denial of reh'g, (Oct. 20, 1993) and review granted and opinion superseded, 26 Cal. Rptr. 2d 475, 864 P.2d 1036 (Cal. 1993) and judgment rev'd on other grounds, 8 Cal. 4th 1220, 36 Cal. Rptr. 2d 464, 885 P.2d 877, 25 U.C.C. Rep. Serv. 2d (CBS) 630 (1994).
66 See, Senate Rules Committee, Office of Senate Floor Analysis, August 30, 2006, page 6, posted at http://www.leginfo.ca.gov/pub/05-06/bill/sen/sb_1351-1400/sb_1368_cfa_20060831_111932_sen_floor.html.
67 In its Opening Comments on the Proposed Decision, CMUA argues in support of SCE's reading and asserts that "in all cases, the words, phrases and sentences of SB 1368 evidence a legislative intent to trigger the EPS only when an LSE enters into a new legal relationship involving the procurement of baseload generation." Opening Comments, p. 7. CMUA cites no persuasive authority in reaching this conclusion. Furthermore, so limiting the application of the EPS would undermine the Legislature's intent as discussed above.
68 Repowering generally refers to the construction of new generating units at an existing site and the complete or partial dismantling of existing generation units at the same site. Existing units are not always entirely retired or dismantled. Generators can often re-use the busbar/transformer arrays, transmission tap lines to grid interconnect, water and gas supply lines and cooling structures during repowering.
69 Opening Comments of PG&E on Draft Workshop Report, September 8, 2006, p. 5. Reply Comments of SDG&E/SoCalGas on Draft Workshop Report, September 15, 2006, pp. 4-5.
70 At the request of the assigned ALJ, interested parties commented on this definition in their October 27, 2006 reply comments. We note that those comments indicate general concurrence with the definition presented above.
71 § 8340 (m).
72 Comments of the IEP on the Proposed Decision, January 2, 2007, pp. 5-6.
73 Under SB 1368, "powerplant" is defined as "a facility for the generation of electricity, and includes one or more generating units at the same location." (§ 8340(m), emphasis added.)
74 For example, there are ten different 15 MW gas-fired units strung together utilizing a reciprocating generation technology to provide a total output capability of 150 MW, and you need to have one unit on to run any of the others. Or you may have a 100 MW CT comprised of a 10 MW quick-start unit and a 90 MW unit strung together, so that you could never get MWs 11 to 100 unless you have 0-10 on.
75 Comments of Constellation et al. on Draft Decision, January 2, 2007, pp. 8-9.
76 Comments of the IEP on the Proposed Decision, January 2, 2007, p. 6, footnote 10.
77 Specifically, a CCGT powerplant refers to a powerplant that "employs a combination of one or more gas turbines and steam turbines in which electricity is produced in the steam turbine from otherwise lost waste heat exiting from one or more of the gas turbines." (§ 8340(b).)
78 § 8341(d)(1). We conclude that the Legislature intended that the concept of "deemed compliance" be distinct from the concept of "compliance" generally. (Hereinafter, we will use the terms, "actual compliance" and "compliance" interchangeably.)
79 We find no indication in SB 1368, or in its legislative history, that the Legislature intended that CCGT powerplants should lose their deemed-compliant status solely due to contract renewal. If the Legislature had intended to require that existing facilities demonstrate actual compliance upon contract renewal, instead of deeming the CCGT facilities themselves compliant, they could have stated so explicitly.
80 The verb "deem" means "to treat something as if (1) it were really something else, or (2) it has qualities it doesn't have". Black's Law Dictionary, 7th Ed, at 424, West Publishing (St. Paul, Minnesota © 1999).
81 Gay Law Students Association v. Pac. Tel. & Tel. Co., (1979) 24 Cal.3d 458, 478.
82 Landrum v. Superior Ct. of LA County, (1981) 30 Cal.3d 1, 9.
83 Under the definition of "powerplant" discussed in Section 4.2.4 above, adding a new CCGT baseload generating unit to the site that is not operationally dependent on one or more of the existing generating units within the deemed-compliant powerplant is equivalent to adding a new, separate baseload powerplant. Under these circumstances, the new unit would be subject to the same triggers for EPS compliance (irrespective of MW size) as any other baseload powerplant.
84 By citing Public Resources Code § 25123 in this case we are not adopting the language of the statute generally, nor are we importing any of the case law, regulations, or CEC decisions that have been generated in the process of interpreting that section, or the 50 MW number specifically.
85 In particular, under §§ 8340(j) and 8341, compliance with the EPS is triggered for LSE retained baseload generation only when there is a "new ownership investment" in those facilities. If we construed § 8341(d)(1) to mean that the very same "new ownership investment" trigger that applies to LSE retained generation applies equally to LSE-owned "deemed-compliant" retained CCGT generation, there would be redundancy among these sections of the statute.
86 Only those units in a multi-unit powerplant that are being added, replaced or altered must comply with the EPS. In any event, additional units may be considered "new" powerplants as discussed in Section 4.2.4, in which case they would be covered procurements under (1)(a) above.
87 Only the additional units must demonstrate compliance with the EPS. "Additional" units refer to units that were not previously operating at that specific powerplant (including additional refurbished or used units previously operating at a different powerplant).
88 For the purpose of establishing when there has been a 50 MW addition, the existing rated capacity will be determined as follows: 1) for all CCGT powerplants that are in operation on the effective date of this decision-the rated capacity of the powerplant that is operating, or 2) for all other powerplants (or additions to powerplants) that obtain a CEC final permit to operate by June 30, 2007-the rated capacity authorized by the permit.
89 Responses to the ALJ's request are posted at the Commission's website at www.cpuc.ca.gov/static/energy/electric/climate+change.
90 More generally, CEED objects to the staff proposed EPS of 1,100 lbs/MWh because at that level it would preclude powerplants that use oil, coal, petroleum and coke-fueled resources. Although CEED does not propose a specific EPS level in its comments, the record indicates that the EPS would need to be on the order of 1,700-1,800 lbs/MWh in order for baseload generation using these resources to be able to meet the standard. However, CEED ignores that fact that selecting this higher EPS level would not produce the amount of GHG emissions reduction that the statute clearly intends, as evidenced by the selection of a CCGT-based standard.
91 Black's Law Dictionary, 7th Ed, at 424, West Publishing (St. Paul, Minnesota © 1999).
92 See, Comments of the Green Power Institute on the Final Workshop Report, October 18, 2006, Appendix A, pp. 18-19.
93 Except as otherwise noted, the data summarized below is from the responses to the ALJ's request that are posted at www.cpuc.ca.gov/static/energy/electric/climate+change under Request #3.
94 Comments of PG&E on Draft Workshop Report, September 8, 2006, p. 12.
95 Opening Comments and Legal Arguments of DRA on the Final Workshop Report on Phase 1 Issues, October 18, 2006, p. 11, referencing Resolution E-3940, where the Commission found that a 1.5% increase in the referent CCGT baseload powerplant heat rate was an appropriate value to use to reflect the impact of dry cooling.
96 See, in particular, Comments of the Northern California Power Agency on the December 13 2006 Draft Interim Opinion, January 2, 2007, pp. 4-8. All other things being equal, CCGT powerplants located in a desert (high ambient temperature) or high altitude areas will have higher heat rates (and higher GHG emissions) than those located in the coastal regions of California.
97 Gay Law Students Association v. Pac. Tel. & Tel. Co., (1979) 24 Cal.3d 458, 478, citing Weber v. County of Santa Barbara (1940) 15 Cal.2d 82, 86.
98 § 8341 (b) (4), emphasis added.
99 Comments of CMUA on the Proposed Decision, January 2, 2007, pp. 11-12, 14.
100 Comments on the Proposed Decision of EPUC/CAC, January 2, 2007, p. 5.
101 The legislative history of SB 1368 supports the plain meaning of the statute. During the Senate Third Reading of SB 1368, the committee report states that "the purpose of this bill is to prevent long-term investments in powerplants with GHG emissions in excess of those produced by a combined-cycle natural gas power plant." The report also states that the bill would apply to contracts for "baseload power," where baseload power is defined as "electricity generation from a powerplant that is designed to provide electricity at least 60% of the total hours in a year (a 60% capacity factor)." See, for example, Senate Third Reading of SB 1368, as amended August 21, 2006, pp. E, F.
102 The "capacity factor" in this instance would be calculated as the amount of contracted-for deliveries divided by the annual average output of the facility.
103 See the EPUC/CAC example: A merchant generator with a combustion turbine with 5 MW capacity that has a capacity factor of 20% and an industrial customer generator with 30 MW capacity that operates at a 90% capacity factor and has a contract with an LSE to supply no more than 5 MW. Reply Comments of EPUC/CAC on the Final Workshop Report, October 27, 2006, pp. 8-9.
104 Ibid., p. 10.
105 Id.
106 §§ 8341(a) and (b).
107 Under this treatment, the "capacity factor" would also be calculated by dividing the amount of contracted-for energy deliveries by the annual average output of the facility.
108 Comments of PG&E on Draft Workshop Report, September 8, 2006, p. 9.
109 Comments of the Independent Energy Producers Association on the Draft Staff Workshop Report, September 8, 2006, pp. 2-3.
110 EPUC/CAC requests that the Commission specifically clarify that the treatment of multi-unit contracts would be applied on a unit basis where two or more units in a generating station are used for different purposes, as illustrated in the following example:
"A multi-unit facility may enter into one contract with an LSE. The contract could provide for 50 MW of energy at an 80% capacity factor from Unit 1, and a 20 MW peaking product, not to exceed a 30% capacity factor, from Unit II. The contract for the production from Unit 1 would pass the screens, and the EPS would be applied to Unit 1. However, the product from Unit II would not pass the screens for either minimum size or baseload capacity factor." (Comments of EPUC/CAC on Final Workshop Report, October 18, 2006, pp. 11-12.)
However, this example (and EPUC/CAC's request for clarification) is only relevant in the context of an EPS that looks at contract deliveries or products, rather than the operations of the underlying powerplant (as that term is defined in SB 1368). As discussed throughout today's decision, this is not the context for our adopted EPS (nor is consideration of a size threshold), and therefore the clarification that EPUC/CAC seeks here is neither relevant nor appropriate.
111 Resources that count towards the utilities' RPS requirements are established by the CEC and set forth in The RPS Eligibility Guidebook at:
http://www.energy.ca.gov/2006publications/CEC-300-2006-007/CEC-300-2006-007-F.PDF.
112 Comments of the Plumas-Sierra Rural Electric Cooperative...on the October 2, 2006 Workshop Report and Staff Proposal for an Interim Emissions Standard, October 18, 2006, p. 4.
113 See SB 1368, Section 1 (c) and (d).
114 PG&E basically argues that since SB 1368 authorizes the Commission to adopt rules to implement and enforce the EPS required by SB 1368, the Commission may balance the GHG reduction goals of the Legislature with other goals and conclude that there is little risk that a small size exemption will undermine the intent of SB 1368. See Comments of PG&E on Final Staff Recommendation on Greenhouse Gas Emissions Performance Standard, October 18, 2006, pp. 2-3.
115 Id.
116 Gay Law Students Association v. Pac. Tel. & Tel. Co., (1979) 24 Cal.3d 458, 478, citing Weber v. County of Santa Barbara (1940) 15 Cal.2d 82, 86.
117 SB 1368, § 8340(l).
118 SB 1368, § 8340(a).
119 CEED's Opening Comments on Final Workshop Report, October 18, 2006, p. 6.
120 Post-Workshop Comments of PacifiCorp, July 27, 2006, p. 4.
121 Post-Workshop Comments of SCE, July 27, 2006.
122 In discussing the RD&D exemption, Staff suggests that the following type of coal generation plant could qualify: "...[A]n advanced coal facility that has an equal or better emission rate than the estimated [Integrated Gasification Combined Cycle] average heat rate and emissions, and that has or will have within a reasonable period of time the capacity and existing plan to capture and store carbon dioxide...." Final Report, p. 27.
123 § 8341 (d)(5).
124 Including EPUC, CAC and CCC. In its comments on the Proposed Decision , CCC contends that "if [rules adopted pursuant to PURPA] include policies favoring long-term contracts for QFs, the GHG EPS must yield to such policies." Opening Comments of the California Cogeneration Council on the Proposed Decision, January 2, 2006, p. 3. CCC does not cite to any rules adopted pursuant to PURPA, nor are we aware of any rules adopted pursuant to PURPA, which require policies favoring long-term contracts for QFs.
In a related argument, IEP requested consideration of an exemption for QFs based on public policy objectives of state and federal law. Comments of the Independent Energy Producers Association on the Proposed Decision, January 2, 2007, pp. 4-5. As discussed in this Decision, no such exemption can be justified under the requirements of SB 1368.
125 A QF is a generating facility that meets the requirements for QF status under PURPA and part 292 of the Commission's Regulations (18 C.F.R Part 292). There are two types of QFs: (1) Cogeneration facilities that meet the requirements of 18 C.F.R §§ 292.203(b) and 292.205 for operation, efficiency and use of energy output, and (2) Small power production facilities whose primary energy source is renewable (e.g., hydro, wind solar, biomass, waste or geothermal resources) and that otherwise meets the requirements of 18 C.F.R §§ 292.203(a), 292.203(c) and 292.204. Small power production facilities are limited in size to 80 MW, with the exception of certain types of facilities certified prior to 1995.
126 According to a recent FERC rulemaking (Docket No. RM06-10-000; Order No. 688), California electric utilities are still subject to PURPA's mandatory purchase obligation. Nonetheless, as discussed herein, SB 1368 is consistent with the provisions of PURPA, including the electric utilities' mandatory purchase obligation.
127 &_butType=3&_butStat=2&_butNum=12&_butInline=1&_butinfo=&_fmtstr=FULL&docnum=1&_startdoc=1&wchp=dGLbVzb-zSkAl&_md5=bb594edf2b76312651f5b29b6624dca6" target="_top">FERC v. Mississippi, (1982) 456 U.S. 742, 750-51.
128 Accord Indep. Energy Producers Ass'n, Inc. v. Cal. Pub. Util. Comm'n, (9th Cir. 1994) 36 F.3d 848, 856 (PURPA delegates to the states broad authority to implement PURPA).
129 In addition, states may regulate environmental issues related to QFs. "While [PURPA] permits certain facilities to be exempt from State and Federal laws, it excludes exemptions from environmental laws. Thus a qualifying facility may not be built or operated unless it complies with all applicable local, State, and Federal zoning, air, water, and other environmental quality laws, and unless it obtains all required permits." Small Power Production and Cogeneration Facilities - Environmental Findings, 10 FERC ¶61,134 at 61,632 (1980). As an environmental law, SB 1368 is consistent with states' regulatory authority over QFs, as determined by FERC.
130 The statute does not require any showing of compliance with the EPS for existing contracts.
131 Bottoming-cycle cogeneration (also referred to as industrial waste-heat powered generators) is employed in industrial processes such as oil and gas producing and refining operations. Electricity is generated using a heat recovery steam generator, which generates electricity from waste heat produced by an industrial process (such as the industrial process of calcining petroleum coke).
132 Comments of ECAC/CAC on the Final Workshop Report, October 18, 2006, p. 8.
133 Thus, for example, an LSE might be able to temporarily operate a plant at 60% or more capacity, even though the plant was not designed or intended for such operation.
134 CEED's Opening Comments on Final Workshop Report, p. 6.
135 In contrast, as discussed above, a specific reliability concern and associated costs may be assessed on a procurement-by-procurement basis during EPS implementation.
136 GHG Policy Statement; SB 1368 (Section 1).
137 Comments of Sempra Global on Draft Workshop Report, September 8, 2006, pp. 7-8.
138 Topping-cycle cogeneration plants are the most common: They produce electricity first, and then the exhaust (thermal energy) from the electricity production is used in a process application (e.g., heating). Bottoming-cycle plants produce heat for an industrial process first, and then electricity is produced using a waste heat recovery boiler. Bottoming-cycle plants are only used when the industrial process requires very high temperatures, such as furnaces for glass and metal manufacturing and calcining coke. (See Section 4.8.4 above.) These terms have also been defined by FERC regulations implementing QF policy under PURPA (18 CFR § 292.202(d) and (e).)
139 Assigned Commissioner's Ruling: Phase 1 Amended Scoping Memo and Request for Comments on Final Staff Recommendations, October 5, 2006, Attachment 2.
140 Information from bottoming-cycle cogeneration facilities can be readily entered into Tables A, B and C of Attachment 5 by showing the thermal output first, followed by electric output. Table D could also be rearranged to apply to bottoming-cycle cogeneration so that thermal output precedes electric output.
141 We note that no party supports the Heat Rate of the Generator Method, only SDG&E/SoCalGas support the Avoided Emissions Method, and all other parties commenting on this issue support the Conversion Method, i.e, CCC, CAC/EPUC, DRA, IEP, and NRDC/TURN/UCS/WRA (filing jointly).
142 See Opening Comments/Legal Brief on Final Workshop Report of NRDC/TURN/UCS and WRA, October 18, 2006, p. 18.
143 Reply Comments/Brief of the CCC, October 27, 2006, p. 4, footnote 4.
144 18 CFR § 202(h). FERC regulations also refer to "useful thermal energy" in defining bottoming-cycle cogeneration facilities as follows: "Bottoming-cycle cogeneration facility means a cogeneration facility in which the energy input to the system is first applied to a useful thermal energy application or process, and at least some of the reject heat emerging from the application or process is then used for power production. (18 CFR § 292.202(e), emphasis added.)
145 Using Attachment 5, this would mean that the "fuel in" amount in Tables C and D for a bottoming cycle cogeneration would only reflect the amount of fuel associated with supplementary firing.
146 See Comments on Proposed Decision of EPUC/CAC, January 2, 2007, pp. 12-13: "In a bottoming cycle unit, some of that waste heat is used to produce electricity. If no supplemental energy is added to the waste heat to fire the generation, then there are no additional emissions created in order to produce electricity."
147 See Reply Comments of EPUC/CAC on the Final Workshop Report, October 27, 2006. A copy of this questionnaire is attached.
148 Draft Workshop Report, p. 29.
149 Final Workshop Report, p. 36.
150 PG&E and LS Power would also extend this upfront approval to renewable resources firmed by a non-renewable resource. We address this separate issue in Section 4.7, where we consider the treatment of contracts with multiple resources or facilities.
151 See SB 1368, Sections 1 (a)-(c), and also GHG Policy Statement, pp. 1-2.
152 SB 1368, Section 1(d).
153 Greenhouse-Gas Emissions From the Operation of Energy Facilities, Pacific Institute Report, July 22, 1989 ( Gleick, Morris and Norman); Biomass Energy Production in California: The Case for a Biomass Policy Initiative, November 2000, National Renewable Energy Laboratory Report No. NREL/SR-570-28805, (Morris), pp. 38-50. Summary data from these studies was submitted in GPI's July 27, 2006 post-workshop comments and the full text of the material referenced above was filed as attachments to the Comments of the Green Power Institute on the Final Workshop Report, dated October 18, 2006.
154 For the biomass technologies identified above, which utilize landfill gas, agricultural and wood waste as the biomass fuel source, by definition there are no emissions associated with growing the fuel. An LSE entering into a long-term financial commitment with a biomass generating project where the growing the fuel is required will need to calculate net emissions taking into account the emissions associated with "growing," as well as "processing and generating" the electricity from the fuel source pursuant to § 8341(d)(4).
155 SB 107 (Stats. 2006, ch. 464).
156 We recognize that this is a single, simplified example of how a REC trade would work, and that a future tradable REC system could apply to all RPS participants, generators and LSEs in the same service territory as well as different ones, and might be extended to allow non-RPS-obligated third parties, such as brokers, to buy and sell RECs.
157 As the Center for Resource Solutions described in their October 27, 2006 Reply Comments on the Final Report, there is a voluntary market for RECs that is used by municipal utilities in California to supply their green pricing customers and by REC marketers to sell RECS on the national market. However, this is not the regulatory REC market that this Commission addresses in its proceedings.
158 See D.06-10-019 in R.06-02-012, pp. 33-36.
159 In determining RPS compliance, double counting would occur if the REC "seller" (Utility B in the simplified example presented in Figure 2) also counted those attributes towards its own RPS compliance, after selling the RECs to another entity (Utility A in the Figure 2 example).
160 The Center for Resource Solutions suggests in its comments that a double counting problem would arise in the context of the voluntary REC market in which green pricing customers buy RECs from (for example) a utility in California. In particular, they contend that if the REC were purchased from a facility that qualified for a mandate such as EPS based on being a zero emission facility, "the purchase of green pricing electricity would have no impact since it would have happened anyway." Reply comments on final Workshop Report and Staff Recommendations Regarding the Greenhouse Gas Emissions Performance Standard of the Center for Resource Solutions, October 27, 2006, p. 6. We fail to see how this represents a double counting problem since the voluntary purchasers of RECs are paying for the environmental benefits created by the production of renewable energy (not discrete investment decisions), and the RECs will still reflect those benefits as long as the facility continues to operate. In any event, as discussed above, today's adopted treatment of null renewable power does not result in double-counting problems for EPS compliance or in a regulatory REC market, which is the focus of this Commission's consideration of REC-related issues.
161 Unless the LSE makes the types of renovations to plant that fall under the "new ownership investment" discussed in Section 4.2.3.2 above.
162 For 2005, the California Net Power Mix calculated by the CEC was as follows: Coal-38.5%, Large Hydroelectric-23.5%, Natural Gas-33.3%, Nuclear-0% and Eligible Renewables-4.7%. Keep in mind that this is different from CEC's calculation of the "gross system power," i.e., the fuel mix serving California load. The percentages above only reflect the fuel type break-downs for power that was not specified by retailers in their voluntary reporting to the CEC.
163 Final Staff Report, p. 38.
164 Opening Comments of SCE on Final Staff Workshop Report and Proposal, October 18, 2006, p. 11. See also Reply Comments of SCE on the Final Staff Workshop Report, October 27, 2006, pp. 10-11.
165 Opening Comments of PG&E on Proposed Decision, January 2, 2007, pp. 3-7.
166 Reply Comments of the GPI on the Proposed Decision, January 8, 2007, p. 2.
167 Wind and solar are considered "intermittent" generating sources because the output is controlled by the natural variability of the energy resource. Intermittent output usually results from the "direct, non-stored conversion of naturally occurring energy fluxes such as solar energy, wind energy, or the energy of free-flowing rivers" (that is, run-of-river hydroelectricity). [See www.eia.doe.gov/glossary/glossary_i.htm] In contrast, the output from a "dispatchable" renewable generator (e.g., those fueled by geothermal or biomass) can be controlled by the operator to meet system requirements, usually by regulating the flow of the fuel.
168 See Comments of SMUD on the December 13, 2006 Proposed Decision, January 2, 2007 pp. 9-10 and Reply Comments of SMUD on the December 13, 2006 Proposed Decision, January 8, 2007, pp. 2-4.
169 Barley et al. refers to the following organizations that jointly filed opening comments on the Proposed Decision: Barclay's Capital, J. Aron & Company, Morgan Stanley Capital Group.
170 § 8341(d)(7). We find no further discussion of unspecified contracts in the statute or legislative history.
171 In its comments on the Proposed Decision, SMUD argues that the resource mix for each system where unspecified power originates should be analyzed and a determination made of whether the mix of resources meets the EPS, thereby avoiding the binary outcome described above. Comments of the SMUD on the December 13, 2006 Proposed Decision, January 2, 2007, pp. 8-9. We fail to see how a binary outcome can be avoided under the approach SMUD suggests, since any contract procuring unspecified power from a particular originating system would still face either a "no go" or "go" outcome depending on the relative level of high- and low-emitting resources in that system's resource mix. Moreover, SMUD's proposed approach does not address the fundamental difficulty we have with permitting unspecified contracts as a general rule under the interim EPS, since we still would not know whether the deliveries will actually come from the high-emitting facilities in the system's resource mix, or not. Nor does it recognize that the statutory deadline for our adoption of an "enforceable" EPS is February 1, 2007, which does not provide sufficient time to conduct the analysis and reach the determinations SMUD suggests should be undertaken for each potential originating system of unspecified power that LSEs procure from.
172 Opening Comments and Legal Argument of the Division of Ratepayer Advocates on the Final Workshop Report on Phase 1 Issues, October 18, 2006, pp. 5-7. As DRA points out, under less than full-load conditions, one can expect the corresponding heat rates to go up, and therefore result in higher emission values.
173 Indeed, it could be difficult in the case of an "unspecified contract" even to devermine whether any "baseload" powerplant is being used to generate the power.
174 "Contracts with unspecified resources are for energy products whose offered prices are valid for a very short period of time. This is due to the fact that energy prices fluctuate constantly, in part due to fluctuations in commodity prices of natural gas as well as underlying market conditions. SCE has to decide whether to buy or not to buy such energy products in a very short period of time.... As a result, SCE is currently limited to soliciting contracts of energy products, including such contracts with unspecified resources, to those with durations less than five years consistent with its current procurement authority." See SCE Greenhouse Gas Emission Standards Data Response, October 18, 2006, Response to Question 03, posted at http://www.cpuc.ca.gov/static/energy/electric/climate+change/.
175 During our interagency consultations on SB 1368, CEC staff has indicated that the publicly owned electric utilities may not be similarly situated, i.e., they have entered into a significant amount of contracts of five years or greater with unspecified power in recent years and may be planning to do so in the future. Nothing in today's decision is intended to suggest that the CEC may not consider unique circumstances facing these entities with respect to how an EPS that will apply to them should address unspecified contracts. However, we believe that the policy, legal and implementation issues associated with imputing emission rates to unspecified contracts and permitting substitute energy purchases under long-term contracts discussed in today's decision will need to be carefully considered as the CEC develops an EPS that is consistent with the statute as well as today's adopted EPS, as directed by SB 1368.
176 D.06-02-032, pp. 47-48.
177 Comments of Sempra Global on Draft Workshop Report, September 8, 2006, p. 6.
178 PJM Interconnection is the regional organization that monitors and coordinates movement of wholesale electricity over a 56,000-mile section of the power transmission grid that spans across 13 northeastern and midwestern states and the District of Columbia. ISO New England serves similar functions across all of the New England states as the California ISO.
179 See, in particular, Reply Comments of DRA on the Phase 1 Proposed Decision, January 8, 2007, p. 2 in response to Comments of SMUD on the December 13, 2006 Proposed Decision, January 2, 2007.
180 Comments of SMUD on the December 13, 2006 Proposed Decision, January 2, 2007, p. 3.
181 Merriam-Webster online dictionary at www.m-w.com/dictionary/address.
182 See SB 1368, Section 1 (c) and (d).
183 Opening Comments of PG&E on Proposed Decision, January 2, 2007, pp. 5-6. In their joint reply comments, NRDC, TURN, UCS and WRA argue that the conditions as currently written could create "an avenue to build in system power into a long-term unit-specific contract." Reply Comments of NRDC/TURN/UCS and WRA, January 8, 2007, pp. 2-3. We fail to see how PG&E's proposed language for Conditions A and B, in combination with the 15% cap on permitted system purchases could lead to such a result. Moreover, we do see great difficulty in trying to distinguish between the limited use of system power for conditions that are "event driven" versus "due to economic considerations" as these parties suggest. Therefore, we retain PG&E's proposed language for these conditions.
We also do not find merit to SDG&E/SoCalGas' suggestion that PG&E's proposal be modified to allow substitute energy purchases up to 25% of in order to be consistent with CEC's RPS eligibility guidelines for "hybrid systems." SDG&E/SoCalGas' reference to the 25% number in the RPS guidelines is taken out of context. Under certain circumstances, the RPS guidelines allow up to 25% of non-renewable resources in the context of the fuel use for a specific facility (e.g., for solar thermal generators), but not in the context of substitute system purchases. Moreover, the RPS guidelines specifically state that RPS eligibility is not permitted for any fossil-fuel portion of any new or repowered non-QF facility. (See CEC-300-2006-007-F, Renewable Energy Program, "Renewables Portfolio Standard Eligibility Guidebook," April 2006, pp. 16-17.
184 See, for example, Opening Comments of PG&E on Proposed Decision, January 2, 2007, p. 5 and Comments of SMUD on the December 13, 2006 Proposed Decision, January 2, 2007, p. 10.
185 As GPI and others recognize in their reply comments on this issue, the second option put forth by SMUD is likely to permit up to 50% of deliveries under the contract from unspecified system substitute purchases for wind resources. Put another way, with wind facilities generally delivering on average 35-40% of their rated capacity, allowing substitute energy purchases up to 80% of the rated capacity means that, on average, unspecified resources would comprise about the same level of energy delivered under the contract as the energy delivered from the wind generator. As a result, there would be a significant net "increment" to system purchases permitted under these provisions that would not be offset by the normal fluctuations of the intermittent resource around the average expected output of the facility, as there would be under SMUD's option #1.
186 SMUD also recommends that the utility be required to purchase the RECs associated with the renewable generating unit. In Section 4.11, we address the issue of null power and RECs in the context of today's adopted interim EPS. In light of that discussion, we find SMUD's suggestion that such a requirement be imposed on LSEs (if and when a regulatory REC market exists in California) to be premature for our Phase 1 determinations, and therefore do not adopt it.
187 Comments of SMUD on the December 13, 2006 Proposed Decision, January 2, 2007, p. 6.
