11. Assignment of Proceeding
Michael R. Peevey is the Assigned Commissioner and Meg Gottstein is the assigned ALJ in this phase of the proceeding.
1. As described in this decision, the Commission has consulted with the California ISO, CARB and CEC during the development of the interim EPS rules.
2. SB 1368 establishes a minimum performance requirement for any baseload generation facility that represents a new long-term financial commitment entered into by entities providing power to California ratepayers. This minimum performance requirement is a GHG emissions performance standard, or "EPS," which limits the powerplant emissions rate to no higher than the emissions rate of a CCGT baseload powerplant.
3. The EPS functions similar to an appliance efficiency standard by ensuring that an LSE does not enter into long-term financial commitments with baseload resources that do not meet a minimum standard of performance.
4. The EPS serves to address the serious adverse consequences of global warming on California's economy, health and environment.
5. The EPS is needed to prevent "backsliding" during California's transition to a statewide load-based GHG emissions cap, that is, to reduce California's exposure to (1) the costs of complying with future laws and regulations that will further limit the emission of GHG gases in the process of generating electricity, and (2) future reliability problems, such as those caused by taking plants out of service to retrofit them (or to retire them early) in order to comply with future laws and regulations limiting GHG emissions.
6. The EPS will help protect Californians from climate change-related phenomena such as: increased number of extremely hot days, air pollution formation, oppressive heat, wildfires, infectious disease vectors, asthma triggers, decreases to the Sierra Nevada snowpack and its derivative effects on California's water supply, diminished electric supply, sea level rise, and the increased occurrence of extreme oceanic events.
7. For the reasons discussed in this decision, current Commission oversight of utility resource planning or the use of a GHG adder in utility procurement does not establish sufficient safeguards against the risks associated with long-term procurement commitments to high-emitting fossil-fueled facilities.
8. SB 1368 directs that the Commission reevaluate and continue, modify or replace the EPS adopted by this decision ("interim EPS") when an enforceable GHG emissions applicable to LSEs limit is established and in operation.
9. There is insufficient data to create and enforce an EPS by the statutory deadline of February 1, 2007 that covers all six of the GHGs.
10. CO2 is the most pervasive of the GHGs, and the most widely reported and verified of the GHGs at this time.
11. SB 1368 addresses the issue of what entities shall be subject to the EPS by directing that the Commission develop an EPS for LSEs, and by specifically defining that term in the new law.
12. Under SB 1368, the requirement to comply with the EPS is triggered if there is a "long-term financial commitment" by an LSE to baseload generation. For LSE-owned baseload generation, a long-term financial commitment occurs whenever 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.
13. SB 1368 defines baseload generation as "electricity generation from a powerplant that is designed and intended to provide electricity at an annual plant capacity factor of at least 60 percent, and defines the terms "powerplant" and "plant capacity factor" for this purpose as follows:
(a) "Powerplant" means a facility for the generation of electricity, and includes one or more generating units at the same location.
(b) "Plant capacity factor" means the ratio of the electricity produced during a given time period, measured in kilowatthours to the electricity the unit could have produced if it had been operated at its rated capacity during that period, expressed in kilowatthours.
14. A 60% capacity factor captures an estimated 78% of incremental procurement needs in 2012 for PG&E, SDG&E and SCE combined and would capture 72% of CO2 emissions, based on the data submitted in Phase 1.
15. GPI's recommendation that the EPS be applied to generation from facilities with an annual plant capacity factor of at least 50 percent would establish an interim EPS that is significantly different from the standard intended by the Legislature with the passage of SB 1368.
16. SB 1368 grandfathers CCGT baseload powerplants currently in operation, or that have a CEC final permit decision to operate as of June 30, 2007, as "deemed to be in compliance" with the EPS.
17. Under the provisions of SB 1368, an LSE does not enter into the types of commitments with "retained generation" (i.e., existing baseload facilities owned by the LSE to serve its load) that would trigger the requirement to comply with the EPS, absent additional investment.
18. Constellation et al.'s interpretation of § 8341(d)(1) to mean that the Legislature intended to subject utility-owned retained generation to the EPS, with or without a "new ownership investment," would contradict the language of §§ 8341(a), (b)(1), (b)(2) and § 8340(j), or render it meaningless.
19. It is doubtful that the "rate recovery contract" with retained generation and kinds of regulatory measures that Constellation et al. describe in their comments are "contracts" as that term is ordinarily understood. Even if they are, they are not the kind of contracts that the Legislature describes in § 8340(j).
20. It is not clear under the proposal made by Constellation et al. how one would determine whether any particular "rate recovery contract" is for a period of less or more than five years.
21. Contracts for the procurement of baseload generation and "contracts" for the recovery of costs associated with generation are two separate things, and we read the plain language of SB 1368 to only apply to the former.
22. In the legislative history of SB 1368, "long-term contract" is consistently referred to in the context of the procurement contracts covered by the Commission's procurement planning process, which do not apply to utility-retained generation.
23. Nothing in the statutory language or legislative history reflects the intent of the Legislature to define a "contract" in the manner suggested by Constellation et al.
24. The definition of covered procurements proposed by Constellation et al. 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 to avoid the additional financial and reliability risks that such backsliding would create.
25. SCE's interpretation of "long-term financial commitment" under SB 1368 is that the Legislature intended to limit that commitment to an investment in baseload generation that is also a new ownership interest. In effect, under SCE's interpretation, the EPS would never be triggered for new investments made by the LSE to its retained generation.
26. SCE's assertion that the absence of a comma in the phrase "new ownership investment" mandates their reading is incorrect based on the rules of grammar described in several sources of grammatical usage. According to those sources, 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, which is not the case for the phrase "new ownership investment." These authorities also establish that no comma is required for this phrase, since the first adjective ("new") modifies the idea expressed by the combination of the second adjective and the noun ("ownership investment").
27. As discussed in this decision, SCE's reading of § 8341(b)(6) in support of its interpretation is contrary to the plain meaning of the statute, which explicitly prohibits LSE's from entering into long-term commitments that fail to comply with the EPS.
28. We conclude from the legislative history 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.
29. SB 1368 does not specify what types of new investments made by an LSE in retained generation would trigger the EPS.
30. The Senate Floor Analysis for SB 1368 states that "the purpose of this bill is to prevent long-term investment in powerplants with GHG emissions in excess of those produced by a combined-cycle natural gas power plant."
31. Requiring that every replacement of equipment or addition of pollution control equipment would trigger compliance with the EPS does not recognize that the plant and its operation may remain essentially unchanged and such alternations may not even increase the level of expected emissions from the facility over the long-term. More importantly, this approach could reduce powerplant reliability as old parts are repaired rather than replaced.
32. Setting a dollar level threshold to trigger EPS compliance for new ownership investments, as some parties suggest in their comments, would be an arbitrary exercise.
33. Defining the EPS trigger to include LSE investments in retained generation intended to (1) extend the life of one or more units of an existing busload powerplant for five years or more, or (2) that result in a net increase in the existing rated capacity of that powerplant, or (3) is designed and intended to convert a non-baseload plant to a baseload plant, is a workable definition that is consistent with the objectives of SB 1368.
34. Defining the EPS trigger in this manner covers "repowering" as the term is generally used in the industry, which is the type of investment in retained generation that staff and most parties agree should be included under the definition of new ownership investments.
35. The fact that more than one generating unit happen to be at the same location should not be a "sufficient" condition for treating them as a single powerplant, because doing so could lead to the absurd results described in this decision. These include encouraging the co-location of renewables or other low-emitting generating units with units that emit very high GHG emissions, or co-locating generating units designed and intended to operate at capacity factors much lower than 60% with those designed and intended to operate as baseload generation (60% or greater capacity factor), in order to circumvent the EPS rules. Clarification of the circumstances under which a "powerplant" is a facility comprised of more than one generating unit will avoid the absurd results described in this decision, and improve the implementation and enforcement of the EPS.
36. Based on the common definition of the verb "deem," 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.
37. The staff proposal would essentially apply the same standard of review for deemed compliant CCGT plants as for all other existing plants.
38. There is no indication in SB 1368, or in its legislative history, that the Legislature intended that CCGT powerplants, or any of the individual CCGT units such powerplants contain at the time they are deemed compliant, should lose their deemed-compliant status solely due to contract renewal.
39. 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.
40. In order to give §§ 8340(j), 8341 and 8341(d)(1) 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), it is reasonable to interpret SB 1368 to mean that "new ownership investment" in retained generation does not automatically trigger EPS review for deemed-compliant CCGT powerplants.
41. Interpreting SB 1368 to mean that existing CCGT are deemed to be permanently in compliance regardless of any subsequent changes to the facilities, however, would lead to absurd results, e.g., it would allow an LSE or non-LSE owner to circumvent the EPS simply by co-locating additional units with existing units within a previously deemed-compliant CCGT powerplant.
42. The deemed-compliant status is given to existing CCGT plants, 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.
43. To give meaning to each section of the statute and avoid absurd results, it is reasonable to require EPS compliance when units are added to a deemed-compliant CCGT powerplant that result in a significant increase to the powerplant's rated capacity.
44. Establishing a 50 MW threshold for this purpose recognizes that Public Resources Code § 25123 establishes a 50 MW threshold to demarcate the boundary between significant and minor changes in generating capacity for the purpose of triggering CEC powerplant permitting requirements.
45. Limiting our reading of what parts of a CCGT powerplant are deemed compliant (to exclude additional units totaling 50 MW or more) avoids redundancy and gives each word of § 8341(d)(1) a legal effect distinct from the other provisions of the statute.
46. Nothing in today's decision or 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.
47. For EPS purposes the "term" of a contract should be defined as "the date of first delivery through the date of last delivery (even if there are intervening periods during which there are no deliveries)."
48. SB 1368 directs the Commission to establish an EPS at a rate of emissions of GHGs that is "no higher" than the emissions rate of a CCGT powerplant, but does not specify the emissions rate for a CCGT.
49. SDG&E/SoCalGas interpret SB 1368 to mean that the Legislature intended for all deemed-compliant CCGTs to be able to demonstrate that they would pass the adopted standard, if they were required to do so.
50. Our reading of SB 1368, in conjunction with the common definition of the verb "deem," indicates that the Legislature intended to allow the Commission to adopt a standard that some deemed-compliant CCGT powerplants might not be capable of meeting.
51. 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.
52. In selecting CCGT technology as the basis for the EPS, we must assume that the Legislature recognized that this technology is considered to be the technology of choice for new baseload power generation fired by natural gas due to its efficiency advantages over other forms of gas-fired power generation.
53. SB 1368 specifically directs that the EPS emissions rate be reflective of a baseload CCGT, and not intermediate/shaping gas-fired units, as some parties suggest in their comments.
54. An EPS performance level of 1,100 lbs of CO2 per MWh is above the weighted average of 2004-2005 data of emissions rates associated with a broad range of CCGT powerplants of varying vintages, but lower than the emissions rates associated with the oldest, most inefficient "deemed compliant" CCGT powerplants still in operation.
55. In Resolution E-3940, this Commission found that a 1.5% increase in the heat rate is a reasonable estimate for the impact of dry cooling on the heat rate of the RPS-referent CCGT baseload powerplant.
56. 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.
57. Based on the record in this proceeding, an EPS emissions rate of 1,100 lbs of CO2 per MWh is consistent with the intent of the Legislature to base the EPS on CCGT emissions rates, and also reasonably accounts for potential CCGT plant "outliers" from the average data on CCGT emissions rates to accommodate those units that utilize dry cooling technologies, are smaller-sized facilities or are located in the desert or at high altitudes.
58. At the same time, an EPS emissions rate of 1,100 lbs of CO2 per MWh avoids establishing a standard that is representative of the most inefficient, older CCGT powerplants in operation, which is appropriate in light of the statute's grandfathering provisions. Those provisions reflect the Legislature's concern that some of the older, less efficient CCGT powerplants in operation would not be able to meet the standard.
59. It is the characteristics of the powerplant(s) underlying new long-term contractual 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.
60. Accomplishing the goals of SB 1368 and this Commission's GHG reduction policies requires looking 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.
61. Interpreting the "supplied under" language of §§ 8341(a),(b)(1) and (3) as permitting us to assess the applicability of the EPS based only on the energy made available under contract to the LSE, rather than on the operations of the underlying powerplant, would :
(a) 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..." (Emphasis added.)
(b) Ignore that "supplied under" in all instances where it appears in SB 1368 follows the term "baseload generation," which is defined under § 8340(a) in terms of "electricity from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%." (emphasis added), and similarly,
(c) Ignore that the term "plant capacity factor" is also defined by § 8340(1) in reference to the underlying plant operations.
62. Customer generators that sell power to the LSE under long-term contract (i.e., contracts with a term of five years or greater) still represent a resource upon which the LSE relies, even if the amount of energy delivered to the grid is small.
63. Application of the EPS should avoid situations where the LSE makes separate arrangements for high GHG-emitting resources that also generate power for on-site load, since the same risks of high costs and reliability problems in the future apply to those facilities.
64. Applying the EPS 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, ensures that LSEs do not enter into long-term contract commitments with powerplants designed and intended for baseload operations with GHG emissions higher than CCGT powerplants. As discussed in this decision, the treatment of the powerplants under EPUC/CAC's example is consistent with this purpose, and does not create a "possible discrimination" between customer-owned generation and merchant generation.
65. 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.
66. 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 of five years or more, the power supplied comes under Commission purview for the purposes of evaluating the LSE's (not the customer generator's) compliance with the EPS.
67. Staff's proposed treatment of partial contracts would exempt partial year contracts from the EPS if the contracted-for hours of energy delivery under the contract represent less than 60% of the total number of hours in the year. In effect, this represents a blanket exemption for seasonal procurements, even if the underlying facility generating the summer product is a baseload generation facility as defined under SB 1368.
68. Considering the expected capacity factor of the contractual commitment (not the underlying powerplant(s)) for partial-year contracts is inconsistent with the application of the EPS to all other contract commitments under the adopted EPS, and would create a significant loophole in EPS compliance.
69. Staff's proposed treatment of partial contracts is not necessary to address potential seasonal reliability concerns. To the extent that such concerns arise from the application of an EPS that applies only to long-term contractual commitments with baseload facilities, LSEs may request a reliability exemption on a case-by-case basis, as provided for by this decision. There is no compelling reason to create a blanket exemption for this purpose.
70. Staff's and GPI's proposal for firmed renewable products applies the EPS from the viewpoint of contract deliveries, i.e., by applying the EPS on a blended basis to the contracted-for deliveries from the renewable and non-renewable resources underlying that product. In general practice, this means that the procurement would be automatically exempt from the EPS as long as less than half of the deliveries are from the non-renewable firming resource.
71. PG&E's proposed treatment of firmed renewable products would exempt all firmed renewable product from the EPS, irrespective of the emissions profile of the underlying non-renewable firming resource or the level of deliveries from that contract.
72. The proposed treatment of firmed renewable products presented by staff, GPI and PG&E is inconsistent with the direction of SB 1368 that EPS compliance be based on the underlying facility or facilities producing power, not just the delivered product under a contract.
73. Nothing in the language of SB 1368 or its legislative history indicates that the Legislature intended to carve out an exception for firmed renewable products.
74. The proposal of NRDC, TURN, UCS, WRA and DRA to apply the EPS to each facility underlying a contract, including one for a firmed renewable product, is consistent with the plain language of SB 1368.
75. PG&E's argument that SB 1368 permits a small facility or contract size exemption violates a basic rule of statutory construction by ignoring the "any" and "all" language of §§ 8341(a) and 8341(d)(1).
76. We cannot reconcile PG&E's recommendation for a small size exemption with the plain language of SB 1368.
77. The legislative history of SB 1368 provides no indication that the Legislature ever considered including a blanket exemption for facilities or commitments under a certain size.
78. Any selection of a size threshold for such an exemption 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.
79. A blanket exemption for small utilities (less than 75,000 retail customers) is not provided under § 8341(d)(9) as CEED suggests, but rather, that section of the statute states that the Commission may accept proposals for alternate compliance from multi-jurisdictional utilities under specific circumstances. Moreover, a blanket exemption for all utilities with less than 75,000 customers would not achieve the same level of emissions reductions and associated reduction in future risks and costs intended by the Legislature.
80. SB 1368 provides the flexibility to both encourage new technologies while meeting the EPS standard. In particular, SB 1368 directs the Commission to: (1) calculate emissions rates based on "net emissions" from the production of electricity and (2) not to count CO2 that is injected in geological formations as emissions of the powerplant in determining compliance with the EPS. However, neither the plain language of SB 1368 nor the legislative history indicates that the Legislature contemplated the type of RD&D exemption proposed by staff when drafting the statute.
81. Calculating the emissions rate of powerplants with sequestration projects contemplated under § 8341(d)(5) based on the net emissions over the life of the powerplant recognizes that a CO2 injection project may not be operational until after the powerplant comes on-line or the LSE enters into the contract.
82. Implementing §§ 8341(d)(2) and (5) to require EPS compliance based on reasonably projected net emissions over the life of the facility serves the purposes of SB 1368.
83. Small power production facilities that use solar thermal electric, wind, geothermal or certain biomass technologies are pre-approved as compliant under this decision.
84. Other small power production QFs, such as hydroelectric facilities, may very well be able to meet the EPS.
85. The cogeneration efficiencies of QFs are accounted for in calculating the emissions rates for cogenerators, thereby assisting cogenerators in meeting the EPS.
86. EPUC/CAC's recommendation that all existing gas-fired cogeneration should be deemed to be in compliance with the EPS is inconsistent with the plain language of SB 1368, including § 8341(d)(3) directions on how the emissions for cogeneration facilities should be calculated in demonstrating EPS compliance.
87. Both topping and bottoming-cycle cogeneration generate electricity. Bottoming cycle cogeneration generates electricity using waste heat from an industrial process, whereas topping cycle cogeneration does the reverse: It utilizes the waste heat from the generation of electricity.
88. ECAC/CAC's assertion that bottoming-cycle cogeneration is not a powerplant does not comport with the SB 1368 definition of powerplant as a "facility for the generation of electricity."
89. SB 1368 does not distinguish between topping and bottoming-cycle cogeneration in the application of the EPS.
90. EPUC/CAC provide no evidence for their assertion that there are no emissions associated with the production of electricity using bottoming-cycle cogeneration technologies.
91. EPUC/CAC acknowledge, in fact, that when supplemental firing is used to enhance the performance of bottoming cycle facilities, any resulting emissions attributable to the supplemental firing may need to be considered in developing an emissions rate for the cogeneration facility.
92. 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, the adopted EPS protects California ratepayers from long-term reliability risks while minimizing potential adverse impacts on short-term reliability and associated costs.
93. Applying the interim EPS on a gateway basis also provides LSEs with the flexibility to operate their facilities differently than originally designed or intended in order to address unanticipated short-term reliability needs.
94. A reliability exemption will probably not be needed given the definition of covered procurements and other design aspects of the interim EPS. Nonetheless, allowing for the possibility of granting this limited exemption, on a case-by-case basis, addresses concerns that unexpected reliability problems may arise during EPS implementation.
95. A reliability exemption is workable to implement, since a specific reliability concern and associated costs may be readily assessed as the "go, no-go" decision is being made for each new long-term financial commitment with baseload generation.
96. In contrast, in the context of an EPS no single procurement can be said to cause significant cost or economic impacts, in and of itself, for a utility's customer. This is because by its very nature and purpose, and similar to an appliance efficiency standard, the EPS requires that each determination be made without respect to whatever set of energy procurement opportunities a given LSE has available.
97. No party proposing cost-based exemptions or cost containment measures provides any evidence that the costs to ratepayers of procuring EPS-compliant resources will be unreasonable, or considers the economic, health and environmental benefits associated with the EPS in arguing that such proposals are warranted.
98. Price caps in the context of an EPS could mean 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 $s/ton. Or, as in the case of the Massachusetts, Oregon and Washington price cap policies mentioned by CEED, 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.
99. Either way, price caps would allow the LSE to build or enter into long-term contracts with high GHG-emitting plants without any reduction in those plants' emissions. This would 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.
100. No party has addressed how such a price cap could realistically be established by the statutory deadline of February 1, 2007.
101. It is reasonable to make some provision in our rules for "extraordinary circumstances, catastrophic events, or threat of significant financial harm" that may arise during EPS implementation due to unforeseen circumstances.
102. 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.
103. The Heat Rate of the Generator Method for calculating the emissions rate of cogeneration 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.
104. 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.
105. The Avoided Emissions Method is problematic because it can be very difficult to determine the characteristics of the stand-alone boiler whose GHG emissions are avoided by a cogenerator. As a result, future power contract negotiations could end up being extremely complex and contentious over this issue.
106. 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. SDG&E/SoCalGas' assumption of 80% efficiency for such a boiler is an arbitrary selection.
107. 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 and, in any event, it would be inaccurate to assume that general efficiency for all boilers since not all cogeneration facilities are gas-fired.
108. Cogeneration facilities under consideration are not necessarily new facilities. Therefore, it would be inaccurate to assume that the boiler used in its place would have efficiencies that meet current standards, as SDG&E/SoCalGas suggest as an alternative.
109. 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. 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.
110. 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.
111. Relative to the Avoided Emissions Method, the Conversion Method has the advantage of being (1) 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, (2) easier to implement and administer because it does not involve making assumptions about the type of boiler "avoided" and associated emissions rates. In addition, the Conversion Method fully recognizes the fuel savings benefits associated with cogeneration.
112. The emissions and cogeneration credit calculations presented in Attachment 5 are currently shown as though the facility operates as a topping-cycle facility. These calculations can readily be shown for a bottom-cycle facility by: (1) showing the thermal output first, followed by the electric output in Tables A, B and C and (2) rearranging Table D so that thermal output precedes electric output.
113. EPUC/CAC's proposal in their comments on the Proposed Decision on how to calculate the emissions from bottoming-cycle cogeneration should be rejected because it produces a formula that counts the energy input for only one of the co-generation outputs, but divides by both outputs to produce the resulting emissions rate.
114. The FERC definition of "useful thermal energy" in its regulations mandating the minimum efficiencies of a QF recognizes that there are losses from converting available thermal energy into "useful work," and that some of the available thermal output may be wasted (not "used") by the thermal host.
115. Using the existing documentation requirements of cogeneration facilities, as described in this decision, represents a reasonable and workable way to document the useful thermal energy output and other values for the Conversion Method formula of cogeneration facilities at EPS gateway screen.
116. Based on our reading of SB 1368, we are not precluded from making an upfront one-time determination of EPS compliance for renewables based on our consideration of representative emissions rates.
117. It would be redundant and costly to require that LSEs demonstrate EPS compliance for each new ownership investment, new contract or renewed contract with baseload renewable resources if the record clearly demonstrates that these resources comply with the EPS on a net emissions basis.
118. The record in Phase 1 demonstrates that the net GHG emissions produced from the renewable resources and technologies listed below are either zero, significantly less than the EPS or even result in a net reduction in GHG emissions (in the case of biomass):
(a) Solar Thermal Electric (with up to 25% gas heat input)
(b) Wind
(c) Geothermal, with or without reinjection
(d) 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.
119. The usual disposal options for biomass wastes emit large quantities of methane gas, which is on the order of twenty to twenty-five times more potent as a GHG than CO2.
120. Electric production alternatives either burn the wastes that would become methane gas or burn the methane gas itself, generating CO2.
121. Electricity production using biomass 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.
122. It would not be reasonable for us to make a blanket determination today that all renewable resources or technologies are EPS-compliant, however, since the evaluation of net emissions presented on the record and discussed in parties' comments did not consider any other types of renewable resources or technologies (e.g., hydroelectric, fuel cells, photovoltaics, biodiesel, and ocean thermal systems), or biomass generating projects where growing the fuel is required.
123. The issue of how to treat RECs or "null renewable power" (renewable resources that have sold off their RECs) in the context of EPS compliance should be addressed even though there is no tradable regulatory REC market in California at this time. Deferring the issue would introduce considerable uncertainty with respect to the treatment of renewables and create a potentially dampening effect on the development of these resources.
124. 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 obligation, which is also defined in terms of electricity production.
125. In the context of EPS compliance, however, stripping renewables of their emission profiles when RECs are sold could easily create a "perverse" result; namely, it could discourage new long-term commitments with baseload renewable generators that have zero, low or even negative net GHG emission profiles in favor of facilities with higher GHG emission profiles.
126. As long as RECs cannot be used to offset emissions for the "go, no-go" EPS-compliance determination, looking at the actual nature of the underlying plant even if RECs are sold does not create a double counting problem. Moreover, such treatment 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), not discrete investment decisions.
127. As discussed in this decision, stripping renewables of their emissions attributes in the context of EPS compliance 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.
128. Stripping renewables of their emissions attributes with the sale of RECs requires imputing emission factors to the resulting null renewable power, for which we lack a reasonable method at this time.
129. SB 1368 directs this Commission to address long-term purchases of electricity from unspecified sources (or "unspecified contracts") in a manner consistent with the statute.
130. By requiring that the Commission "address" the matter of unspecified contracts, SB 1368 does not require any particular outcome and defers the matter to the Commission's discretion.
131. 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 must 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.
132. The concept of imputing emissions rates with the requirements of SB 1368 is difficult to reconcile with the requirements of SB 1368 since, by definition, such proxies do not reflect the actual emissions from a resource. As a result, using imputed emissions rates does not permit one to determine whether a commitment with an unspecified resource is consistent with SB 1368 or simply exacerbates the problems this Commission and the Legislature are trying to address.
133. 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. This results in 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.
134. As illustrated in comments in this proceeding, various input assumptions associated with calculating an imputed emissions value using the California Net Power Mix, as well as other proxies for the resource mix, can be manipulated to "push" an unspecified contract through the EPS.
135. SCE's recommendation for the treatment of unspecified contracts also has the potential to push an unspecified contract through the EPS gateway, since the proposed default rates are based on broad regional averages that would permit high emitting resources to pass through the EPS screen.
136. 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.
137. The WECC system average is generally not reflective of California activities or markets.
138. The use of WECC sub-regional geographic averages, including SCE's proposed alternative of using the WECC California region average carbon intensity factor, represent broad emissions averages that would dilute the impact of high-emitting resources and potentially allow them all to automatically pass through the EPS screen.
139. The California Net Power Mix is a calculation 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 by the CEC for power content labeling, and has not been revised, updated or endorsed by the CEC for use in inputting GHG emissions under SB 1368 or in any other GHG policy context.
140. There is no clear conceptual link between the California Net Power Mix and the mix of resources that might underlie unspecified contracts now or in the future, even on a system-wide basis.
141. Requiring all long-term commitments for baseload generation be made with "specified resources" that can demonstrate compliance with the interim EPS ensures that "any" and "all" long-term financial commitments with baseload generation will meet the EPS, as SB 1368 so directs. Moreover, this approach 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.
142. SCE, SDG&E and PG&E did not enter into any contracts of five years or more for unspecified resources in 2004 and 2005 and state that they do not anticipate entering into any contracts with unspecified resources with a term of five years or more during the 2006-2008 procurement period.
143. Based on the record in this proceeding, it appears highly unlikely that LSEs will be entering into any new or renewal contracts of five years or greater that are unspecified during the transition to a statewide GHG emissions limit.
144. Requiring that all long-term contracts with baseload generation be "specified" in order to demonstrate EPS compliance should not have a significant, if any, impact on an LSE's resource procurement flexibility.
145. "Specified" contracts (or "specified resources") identify the powerplant(s) that will be delivering power under the contract, but the following circumstances would also comply with the 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 should be on the LSE to provide sufficient documentation to demonstrate compliance with the EPS under these circumstances.
146. The ISO relies on specific information about the plant facility and its location in making system reliability determinations 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.
147. A requirement that long-term power purchase contracts specify the underlying generation facilities for EPS compliance is consistent with our discussion of emissions registration in D.06-02-032 and represents a logical interim step towards the implementation of the statewide emissions cap under AB 32.
148. Permitting 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 could put them, and their customers, in a vulnerable position when the AB 32 reporting requirements take effect in 2008 for the implementation of the statewide, load-based GHG emissions limits.
149. The record indicates that 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. As discussed in this decision, specific tagging mechanisms have been developed in other jurisdictions to track generation attributes, including GHG emissions. While LSEs have stated that they are not likely to pursue long-term unspecified contracts as a general rule, the record in this proceeding indicates that they do intend to continue negotiating long-term contracts with specified resources that contain "substitute energy provisions," i.e., provisions that permit the seller to substitute system energy on a short-term basis as needed for operational or efficiency reasons.
150. Substitute energy provisions in long-term contracts can provide greater performance assurance at more moderate price to ratepayers, and appropriate restrictions to their usage can be put in place to guard against the intentional sourcing of energy from high carbon-intensive baseload resources.
151. PG&E's proposal appropriately restricts substitute system energy purchases under long-term contracts in the context of dispatchable resources by limiting such purchases to no more than 15% of forecasted output of the specified powerplant and restricting the use of substitute system energy purchases to unpredictable events or circumstances, such as forced outages.
152. However, PG&E's proposal does not adequately recognize the unique characteristics of intermittent renewable resources (wind, solar, run-of-river hydroelectricity), where both increments and decrements to the level of system energy are associated with firming such resources.
153. One way to recognize these unique characteristics is to limit the purchases of substitute system energy purchases such that total purchases under the contract (whether from the intermittent renewable resource or from substitute unspecified sources) does not exceed the total expected output of the specified renewable powerplant. Under this approach, one can expect the increments and decrements in system energy purchases to average to zero on balance.
154. Limiting substitute energy purchases in this manner provides the type of contracting flexibility and practicality that is uniquely required for long-term contracts with specified 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.
155. Permitting substitute system energy purchases under long-term contracts with intermittent renewable resources to equal far more than the expected output of the intermittent renewable resource (e.g., 80% of rated capacity for a wind generator) would result in increments to unspecified system energy purchases that can be expected to significantly and regularly exceed the decrements to system power over the life of the contract. As a result, this approach has the potential to create a significant loophole to the 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.
156. A gateway screen approach for demonstrating compliance with the interim EPS is consistent with the intent of SB 1368, which directs us to look to the "design and the intended use" of the powerplant under § 8340(a).
157. A gateway screen approach is the most practicable and enforceable manner in which to determine EPS compliance.
158. As discussed in this decision, EPS compliance submittals can be readily incorporated into existing Commission procedures for LSEs that currently file their procurement plans and contracts for Commission pre-approval; namely, for SCE, PG&E and SDG&E.
159. New procedural vehicles need to be established for LSEs that are not currently required to submit procurement plans or apply for Commission pre-approval of procurement contracts, that is, for community choice aggregators, electric service providers and the small electrical corporations" (those other than PG&E, SCE and SDG&E).
160. Permitting small electrical corporations, electric service providers and community choice aggregators to submit an after-the-fact EPS compliance showing avoids creating new pre-approval requirements and associated administrative complexity for the Commission's regulation of the procurement practices of these entities.
161. Permitting small electrical corporations, electric service providers and community choice aggregators to file an after-the-fact compliance submittal for EPS compliance is consistent with other procurement-related compliance procedures we have established for electric service providers and community choice aggregators.
162. The documentation and other requirements adopted in this decision provide reasonable safeguards against the risks to ratepayers of potential non-compliance by an LSE that files an after-the-fact compliance showing.
163. For the reasons discussed in this decision, the resource adequacy filing submitted by these entities is not the appropriate procedural vehicle for documenting after-the-fact EPS compliance.
164. An annual Attestation Letter, filed as an advice letter with opportunity for response/protest, is a reasonable procedural vehicle for community choice aggregators, electric service providers and small electrical corporations to use for documenting after-the-fact compliance with the interim EPS standard.
165. As discussed in this decision, an electric service provider, community choice aggregator or small electrical corporation should also be permitted to file an Advice Letter requesting Commission pre-approval of a new financial commitment as EPS compliant.
166. Under SB 1368, the Commission may consider a showing of "alternate compliance" by multi-jurisdictional electrical corporations that serve 75,000 or fewer retail end-use customers in California pursuant to § 8341(d)(9).
167. The two multi-jurisdictional utilities subject to SB 1368, Sierra Pacific and PacifiCorp seek alternative compliance with the EPS.
168. There is no compelling reason to defer our decision to consider what constitutes a showing of alternative compliance.
169. PacifiCorp's three alternative compliance tests to determine what qualifies as "review" closely track the statutory language and appear consistent with staff's final recommendations.
170. Both PacifiCorp and Sierra Pacific serve fewer than 75,000 customers within California, and are required to disclose GHG emissions related to procurement to another state's utility regulatory commission, and therefore meet the alternative compliance requirement.
171. The EPS serves a fundamentally different purpose, reflecting different policy objectives, than programs to reduce GHG emissions through a portfolio-wide cap, cap-and-trade programs or programs that permit LSEs to create or purchase offsets to meet an emissions cap or performance standard. As discussed in this decision, the purpose of these programs is to provide varying degrees of compliance flexibility when the primary policy goal is to reduce the overall level of emissions generated through procurement activities.
172. The purpose and objective of the interim EPS (i.e., to ensure that the LSE does not enter into long-term financial commitments with high-emitting baseload resources in the first place) cannot be accomplished if LSEs are permitted to comply with the standard by diluting the emissions from high-emitting powerplants through portfolio averaging, or by increasing the permissible level of emissions for non-compliant powerplants through offsets or other means.
173. Portfolio averaging or increasing the permissible level of emissions for non-compliant powerplants through offsets or other means would only disguise the types of problems that the EPS is designed to avoid, e.g., the high costs of future plant retrofits and reliability disruptions as it becomes increasingly difficult for these high-emitting facilities to comply with GHG emission regulations.
174. A workable offsets program cannot be designed and implemented within the timeframe contemplated for an interim EPS, particularly in light of the SB 1368 statutory requirement that an enforceable EPS be put in place no later than February 1, 2007.
175. The documentation required by this decision will provide this Commission and Commission staff with information necessary to review EPS compliance, either in pre-approval requests or in reviewing after-the-fact Attestation Letters.
176. Disclosure of LSE investments in retained generation, including "deemed-compliant" CCGTs is necessary to monitor compliance with the adopted EPS rules.
177. Consistent with the guidance in § 8341(b)(4), LSEs should present documentation that relates to establishing the design and intended use of the powerplant.
178. LSEs should provide documentation of capacity factors, heat rates and corresponding emissions rates that reflect the actual, expected operations of the plant.
179. The full load heat rate is the heat rate of a plant at full output and is not representative of the actual operations of a plant.
180. As discussed in this decision, using the International Organization for Standardization measurement standards may not provide appropriate documentation for the purpose of demonstrating EPS compliance, particularly for those powerplants located in high temperature or high altitude regions. Therefore, it would not be reasonable to require all LSEs to use these standards.
181. For the purpose of determining the "term" of a contract under these EPS rules, two or more contracts, including contractual options, should be treated as one ("linked") under certain circumstances.
182. The concept of linkage needs to be spelled out in detail now, so that the LSEs can comply with the EPS.
183. SCE suggested that contracts be considered "linked" in either of the following situations: "(1) the contracts specify the same generating unit as the primary source and the gap in contract execution dates is 6 months or less; or (2) the contracts do not specify the generation source, are with the same supplier, specify the same delivery point, and are executed within 24 hours."
184. The purpose of requiring "linked" contacts -- for baseload generation -- that have a combined term of 5 years or more to comply with the EPS is to prevent LSEs from circumventing the EPS by splitting up a single commitment into multiple contracts (or using a contractual option in place of a binding contract).
185. Requiring that contracts with an unspecified generation source must be executed within 24 hours of each other to be considered linked would make it too easy to circumvent the EPS.
186. The date of execution of the contracts, standing alone, should not be the determining factor in deciding whether two contracts are sufficiently related to be considered one for purposes of applying the EPS.
187. Two contracts should be considered linked if both of them are negotiated or executed within a specified time-window. (For more than two contracts to be "linked" all of them would have to be negotiated or executed within the same window of time.)
188. A window period of three months should be sufficient for both specified and unspecified contracts.
189. Because it is possible for power from the same powerplant (or group of powerplants) to be delivered to the LSE at different points, we conclude that a requirement that in order for two "unspecified" contracts to be linked they must "specify the same delivery point" would make it too easy to evade the EPS by splitting up a single deal into two contracts with different delivery points.
190. The linkage rule should use the term "powerplant" rather than "generating unit" to be consistent with the terminology used throughout these EPS rules.
191. Two contracts should not be considered linked if they are entered into as a result of separate RFOs and the contract from the earlier RFO is executed before the later RFO has received bids, because in that situation it is clear that each contract was negotiated separately.
192. SCE's suggestion that if "two contracts are `independent' of each other, [i.e., if selection of one does not require selection of the other] the Commission should not consider them to be `linked'" should be rejected, because it does not contain sufficiently clear guidelines to enable an LSE to determine if two contracts will be considered linked.
193. In order to prevent circumvention of the EPS, both binding contracts and contractual options should be analyzed to see whether they are "linked" and if so, whether their "term" is for five years or more.
194. A linkage rule is only the initial step in determining whether a particular group of linked contracts must comply with the EPS. It is simply used to determine whether the length of the linked contracts is sufficient for there to be a contract with a term of five years or more.
195. Defining the term "annualized" in § 8340(a) to mean "annual average" is reasonable based on the common definition of the word "annualize," namely "to calculate or adjust to reflect a rate based on a full year."
196. For the purpose of calculating the plant capacity factor, using the maximum output allowed under the powerplant's operating permit in the denominator of the equation will best captures the "designed and intended" language of the statute in those instances when permit provisions represent the effective constraint on the maximum output of the facility, rather than the manufacturer's rated capacity.
197. To be applied in a manner that is consistent with this decision, the annual average capacity factor must be calculated based on the annual production of the underlying facility, and not just what might be delivered under a specific contract with an LSE.
198. A plant's operations may vary significantly from year to year, based on weather, maintenance schedules or economic conditions.
199. There are likely to be situations where more than a single year of annual electricity production will need to be considered in determining whether or not a powerplant is a baseload facility as defined under § 8340(a), i.e., whether it is "designed and intended" to provide electricity at an annualized plant capacity factor of at least 60 percent.
200. The definition of "plant capacity factor" under § 83401(l) provides for consideration of more than a single year, in that it expresses the capacity factor as a ratio of electricity produced to electricity production at rated capacity "during a given time period."
201. SCE, PG&E and SDG&E are in the process of preparing and submitting long-term procurement plans for Commission pre-approval in R.06-02-013, and may need to update those plans to reflect how they will comply with today's decision.
202. Developing or clarifying the Commission's overall policies with respect to zero or low-carbon generation resources is beyond the scope of Phase 1.
203. The long-term procurement rulemaking, R.06-02-013 or its successor proceeding, is the appropriate procedural forum for the Commission's consideration of any requests by electrical corporations for § 8341(b)(6) rate-of-return increases on investments made by third parties.
204. Calpine's recommendation that the Commission take additional steps to encourage long-term commitments with resources with emissions below the EPS limit, including providing financial incentives, is beyond the scope of Phase 1.
205. Going beyond the specific direction of SB 1368 by taking a lifecycle approach to net emissions calculations, as CE Council suggests in its comments on the Proposed Decision with respect to LNG facilities, was not raised during the scoping of Phase 1, during workshops or in pre- or post-workshop written comments. Even if it were, we do not have a sufficient record or time before the statute requires us to adopt an enforceable standard to take this approach for the interim EPS.
206. It would be premature, and beyond the scope of Phase 1, to establish target dates in today's decision for the determination of emission allowances under a load-based cap, as recommended by San Francisco Community Power in their comments.
207. An LSE is free to enter into long-term contracts with both in-state and out-of-state generators because the EPS makes no distinction between in-state and out-of-state sources of electricity.
208. Under the EPS, electricity generated from high-GHG emitters can still be sold to California LSEs under existing contracts, or under new or renewal contracts of less than five years.
209. Coal-fired and other plants that use technology to reduce GHG emissions could meet the EPS.
210. Under the EPS, a substantial amount of electricity generated out-of-state would meet the EPS and therefore continue to be available for procurement.
211. Nothing in the EPS prohibits high-GHG emitters from transmitting electricity through the California grid to other states and nations.
212. Many local low-capacity generators are required to generate electricity at specific locations for the operational reliability of the electric transmission grid.
213. Long-term baseload generation operating at a capacity factor of 60% or greater performs a totally different function and would be responsible for a much greater amount of GHG emissions than low-capacity factor generation (such as peakers) operating at a capacity factor of less than 60%, including many which are operating at only 10% or 20% of the time during the year and essential for the reliability of the grid.
214. The generators competing under the EPS for long-term, high-capacity baseload contracts are not similarly situated with low-capacity generation plants.
215. The EPS does not give California firms any competitive advantage over out-of-state firms.
216. By setting a GHG emissions limit, the EPS would create an incentive to further the development of clean coal technology, rather than hinder it.
217. Beyond a specific class of high-GHG emitters seeking to sell to California LSEs, out-of-state generators would generally be able to meet the EPS.
218. As the Legislature found in SB 1368, global warming will have devastating impacts on the economy, health and environment of the State of California.
219. The EPS is indifferent to electric sales to entities in other states.
220. In developing the interim EPS, the Commission has considered the effects on reliability and overall costs to electric customers in the following ways:
a. By designing the EPS so that it functions similar to an appliance efficiency standard and thereby:
i. Protecting electricity customers from reliability problems and high compliance costs in the future, and
ii. Reducing GHG emissions that will mitigate adverse impacts on the economy, health and environment, which reduces overall costs to all Californians, including electricity customers.
b. By defining covered procurements as new long-term commitments to baseload generation, which:
i. Captures the largest percentage of impact on GHG emissions,
ii. Excludes the types of procurements that the LSE is most likely to need for system reliability requirements (e.g., short-term power purchases, long-term contracts with load-following and peaking generation facilities, or new construction of non-baseload powerplants), and
iii. Focuses compliance on the types of facilities over which the LSE has the most discretion and choice, thereby minimizing the costs of compliance to the LSE and its electricity customers.
c. By not subjecting 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.
d. By providing for Commission review of reliability exemptions on a case-by-case basis in the event that unforeseen reliability concerns and associated costs arise during implementation of the EPS.
221. No showing has been made in this proceeding that new, EPS-compliant procurements will not be available at reasonable costs to ratepayers.
1. For the reasons discussed in this decision, it is reasonable to limit today's adopted EPS to CO2 emissions, at least at this time.
2. Pursuant to SB 1368, the EPS adopted today should apply to every electrical corporation, electric service provider or community choice aggregator serving end-use customers in the state, as the statute defines those terms.
3. The interim EPS should apply to baseload generation as that term is defined in SB 1368.
4. Constellation's proposal for defining covered procurements is not reasonable in light of the plain language of SB 1368, legislative history and the objectives of this Commission and the Legislature for an interim EPS, and should be rejected.
5. The interim EPS should define "long-term financial commitment" as set forth in § 8340(g) of SB 1368.
6. SCE's interpretation of "new ownership investment" to only encompass an investment in baseload generation that is also a new ownership interest is not reasonable for the reasons discussed in this decision, and should be rejected.
7. We conclude from our reading of SB 1368 that the term "new ownership investment" under SB 1368 encompasses new LSE investments in retained baseload generation.
8. As discussed in this decision, excluding retained generation from EPS-covered procurements (unless a review is triggered by a new "long-term financial commitment" as defined under SB 1368) is fully consistent with the principles and objectives for an interim EPS articulated by the Legislature and this Commission.
9. As discussed in this decision, reading the definition of "powerplant" in SB 1368 to mean that a powerplant (facility) may be comprised of one or more generating units at the same location-but not that is necessarily follows that all of the units at the same location comprise a single powerplant (facility)-is consistent with the language and intent of SB 1368, and avoids absurd results.
10. The clarifications in today's decision of what constitutes a multi-unit powerplant for the purpose of applying the EPS rule are reasonable and should be adopted.
11. For the reasons discussed in this decision, we conclude that it is reasonable and consistent with the direction of SB 1368 to apply the EPS to the following "covered procurements":
(1) New ownership investments in baseload generation made by an LSE, defined as:
(e) Investments in new baseload powerplant (new construction), or
(f) Acquisition of new or additional ownership interest in existing baseload powerplant previously owned by others, or
(g) New investments in the LSE's own existing, non-CCGT baseload powerplants that are:
(iv) designed and intended to extend the life of one or more units by five years or more,
(v) result in a net increase in the rated capacity of the powerplant, or
(vi) designed and intended to convert a non-baseload plant to a baseload plant, or
(h) Units added to a deemed-compliant CCGT powerplant that result in an increase of 50 MW or more to the powerplant's rated capacity (the LSE owner need only show that the added units meet the EPS), 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.)
12. For the purpose of determining the "term" of a contract under these EPS rules, two or more contracts, including contractual options, should be treated as one ("linked"), where:
A. (1) They specify the same powerplant as the primary delivery source or, (2) for an unspecified source, they are with the same counter-party;
and
B. They are negotiated or executed within any three consecutive-month period, except if entered into as a result of separate RFOs and the contract from the earlier RFO is executed before the later RFO has received any bids (either indicative or final).
13. 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.
14. SDG&E/SoCalGas' suggestion that we establish the EPS level high enough to ensure that all deemed-compliant CCGTs could meet the standard is inconsistent with the Legislature's direction to deem them to be in compliance, based on the common definition of the term "deem," and should be rejected.
15. EPUC/CAC's suggestion that we establish an EPS level high enough to ensure that all gas-fired units meet that level is inconsistent with the direction of SB 1368, and should be rejected.
16. Based on the record in this proceeding and direction of SB 1368, an EPS performance level of 1,100 lbs. of CO2 per MWh is reasonable and should be adopted.
17. Determining whether the EPS applies to a contract commitment should be made based on a "facility" basis, i.e., based on the characteristics of each generating source underlying the contract, and not on the contracted-for deliveries. This application of the EPS will further the policy objectives of SB 1368 and is supported by the rules of statutory construction.
18. Applying the EPS to the underlying facility in the case of customer generators does not exceed the Commission's jurisdiction or violate any laws, as some parties contend in this proceeding.
19. As discussed in this decision, a blanket exemption from the requirement to examine the capacity factor of the underlying facility for partial contracts is both unnecessary and inconsistent with other aspects of the EPS we adopt today.
20. For the reasons discussed in this decision, a small facility, commitment or service territory size exemption from the requirement to comply with the EPS should not be adopted, except as specifically provided for under § 8341(d)(9) for multi-jurisdictional electrical corporations that meet the alternative compliance requirements of that section.
21. Under federal law, California electric utilities are required to purchase energy from QFs.
22. Nothing in the language of PURPA or FERC's regulations requires utilities to offer QFs long-term contracts (contracts of five years or more).
23. Under SB 1368, electric utilities will still be required to purchase energy from QFs in compliance with PURPA. For those QFs that do not meet the EPS, utilities can meet the purchase obligation through contracts of less than five years.
24. Neither SB 1368 nor the Commission's implementation of it conflict with PURPA.
25. SB 1368 does not allow this Commission to provide exemptions for QFs unless application of the EPS would conflict with PURPA.
26. QFs should not be exempt from compliance with SB 1368.
27. It is reasonable and consistent with the language of SB 1368 to require EPS compliance of all covered procurements with gas-fired cogeneration facilities, including existing facilities and bottoming-cycle technologies.
28. Subject to the caveats discussed in this decision, it is reasonable to permit requests for reliability exemptions on a case-by-case basis, including reliability exemptions from the requirement that all covered procurements must be with specified resources.
29. Any consideration of reliability exemptions or requests to be excused from the requirements of this decision due to "extraordinary circumstances, catastrophic events or threat of significant financial harm" comes with a heavy burden of proof on the LSE. Any such requests should be pre-approved by this Commission.
30. Pursuant to § 8341(d)(6), the Commission has consulted with the California ISO during the development of the interim EPS rules and should continue to consult with the ISO during implementation in considering the effects of requests for reliability exemptions on system reliability and overall costs to electricity customers.
31. 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.
32. LSEs should not petition to be excused from the requirements of this decision unless they can clearly demonstrate that: (1) they are facing extraordinary circumstances, catastrophic events or threat of significant financial harm not contemplated by SB 1368 and this decision, and (2) an exemption from some requirement of this decision is necessary to significantly mitigate or eliminate the challenges posed by these circumstances.
33. It is reasonable to adopt the Conversion Method of calculating cogeneration emissions rates for the purpose of determining compliance with the interim EPS, with the clarification that the Btu Thermal Energy Output (expressed in kWh) in the formula represents "useful thermal energy" as defined in the FERC regulations implementing QF policy under PURPA.
34. Today's adopted approach for calculating and documenting cogeneration emissions rates for the interim EPS should not prejudge or predetermine the approach to be established in the context of the Commission's Procurement Incentive Framework or under the statewide GHG emissions limit envisioned under AB 32.
35. Based on the record in this proceeding, it is reasonable to make an upfront determination that the following renewable resources and technologies are EPS-compliant:
(a) Solar Thermal Electric(with up to 25% gas heat input)
(b) Wind
(c) Geothermal, with or without reinjection
(d) 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.
36. If and when there is sufficient data so that parties believe that the Commission could make determinations for pre-approval of additional renewable resources and technologies, it is reasonable to permit parties to file a Petition for Modification of this decision to augment the above list.
37. For the reasons discussed in this decision, the emissions profile of a renewable facility should not change if or when it sells RECs under a future regulatory REC market for the purpose of demonstrating EPS compliance. Nor should RECs count towards compliance with the interim EPS by those LSEs who may purchase them for RPS compliance purposes in the future.
38. Today's determinations on how to treat null renewable power and associated RECs in the context of the interim EPS should not be construed to mean 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.
39. 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.
40. For the reasons discussed in this decision, it is reasonable and consistent with the intent of SB 1368 to require for the interim EPS rules that all contracts with a term of five years or more be with specified resources 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 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 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.
41. A gateway screen approach to determining compliance with the interim EPS is reasonable and should be adopted.
42. Under § 8341(a), LSEs must comply with SB 1368 if they enter into any long-term financial commitment involving baseload generation, irrespective of whether (or how) this Commission reviews and approves such commitments. Under §§ 8341(a) and (b), in adopting rules and procedures to ensure compliance with the EPS, we have the flexibility under the statute to consider a range of procedural vehicles for use by those LSEs for whom we do not currently have a procurement pre-approval process in place.
43. The procedures and documentation requirements for a showing of compliance with the EPS gateway screen required of large electrical corporations, small electrical corporations, electric service providers and community choice aggregators, as set forth in this decision, are reasonable and should be adopted.
44. No after-the-fact Attestation Letter or Advice Letter request for pre-approval of covered procurements submitted in compliance with the Interim EPS Rules should be "deemed approved," as may be permitted under the Commission's current or future Advice Letter procedures in R.98-07-038 or R.06-05-027, or their successor proceedings.
45. As discussed in this decision, consideration of a reliability exemption to the EPS or request for an "extraordinary circumstances" modification of this decision should come with a heavy burden of proof on the LSE, as it must be based on extreme (and therefore highly unlikely) circumstances.
46. As discussed in this decision, the Commission should consider any request for a reliability exemption or "extraordinary circumstances" modification on a case-by-case basis. LSE requests for pre-approval of a reliability exemption should be made by application. LSE requests to obtain "extraordinary circumstances" relief from this decision should be made by filing a petition for modification.
47. Because of the unique nature of CO2 geological injection sequestration projects, an LSE entering into an EPS covered procurement utilizing such projects should request Commission pre-approval by application. In order to ensure that the purposes of SB 1368 are served, the LSE should be required to (1) provide documentation that the project has a reasonable and economically and technically feasible plan that will result in the permanent sequestration of CO2 once the injection project is operational and (2) present projections (and documentation of those projections) of net emissions over the life of the powerplant, and (3) provide documentation that the CO2 injection project complies with applicable laws and regulations.
48. PacifiCorp's three alternative compliance tests for a showing under § 8341(d)(9)(B) are reasonable and should be adopted.
49. It is consistent with Section 8341(d)(9) to exclude PacifiCorp and Sierra Pacific from the EPS Interim Rules since they have demonstrated that they qualify for alternative compliance.
50. Multi-jurisdictional utilities that qualify for alternative compliance should still be required to file annual advice letter on February 1 of each year attesting that they continue to meet the alternative compliance requirements.
51. For the reasons discussed in this decision, our rules for demonstrating compliance with the interim EPS should not permit offsets or portfolio averaging. However, nothing in today's decision should be construed as precluding consideration of these and other compliance options in the context of Phase 2, when this Commission will be addressing the implementation of the load-based GHG emissions cap adopted in D.06-02-032.
52. Consistent with the definition of plant capacity factor provided in SB 1368 and today's decision, the term "annualized plant capacity factor" should be defined as: "the ratio of the annual amount of electricity produced, measured in kilowatt hours, divided by the annual amount of electricity the unit could have produced if it had been operated at its maximum permitted capacity, expressed in kilowatt hours.
53. In order to determine whether the plant is "designed and intended" to provide electricity at an annualized plant capacity factor of at least 60 percent, LSEs should include historical plant capacity factors for the underlying facility or facilities in their documentation of whether the EPS applies to a new long-term financial commitment (other than new plant construction).
54. SCE, PG&E and SDG&E should update their long-term procurement plans in R.06-02-013 in compliance with the EPS, as necessary, to reflect today's determinations.
55. If electric service providers and community choice aggregators are required by the Commission to file long-term procurement plans in the future, they should describe in those filings how they plan on complying with EPS.
56. CEED cites authorities which may show that the United States has a foreign policy of not entering into treaties that do not require the curbing of C02 emissions from developing nations.
57. This Commission is not proposing to enter into any treaties or agreements with foreign governments or entities.
58. When, and if, the U.S. does sign a GHG treaty or otherwise promulgates a GHG policy that is binding on the states, this Commission will be required to bring its program into compliance if there is a conflict.
59. Statements by representatives of the federal government show that the federal government acknowledges and supports states' efforts to reduce GHG emissions.
60. Neither SB 1368 nor the Commission's implementation of it conflict with federal foreign policy.
61. No party has cited to any provision in the Global Climate Protection Act of 1987 (GCPA), or the Energy Policy Acts of 1992 and 2005, that preempts states from requiring their utilities to take actions to decrease GHG emissions.
62. The Global Climate Protection Act of 1987 (GCPA), and the Energy Policy Acts of 1992 and 2005 include provisions that acknowledge states' role in regulating GHG emissions and that contemplate states' participation in the reduction of GHG emissions.
63. Neither SB 1368 nor the Commission's implementation of it conflict with either the Global Climate Protection Act of 1987 (GCPA), or the Energy Policy Acts of 1992 and 2005.
64. The EPS regulates LSEs, which sell electric energy in the retail market in California.
65. The EPS is a component of the regulation of procurement practices of the retail sellers of electric energy in California.
66. The EPS is not regulating wholesale generators or marketers.
67. Under the Federal Power Act, FERC does not have jurisdiction over retail sellers of electric energy, including their procurement decisions.
68. The Federal Power Act does not preempt state regulation of procurement choices by retail sellers of electric energy, including programs designed to reduce GHG emissions, such as the EPS.
69. Any party challenging the constitutional validity of the EPS under the dormant Commerce Clause bears the burden of demonstrating discrimination.
70. The EPS does not discriminate based on geographic origin.
71. Because low-capacity generators are not similarly situated with plants subject to the EPS, the exemption of low-capacity factor generators from the EPS cannot constitute discrimination against interstate commerce.
72. The dormant Commerce Clause does not require California to protect the pecuniary interests of out-of-state coal burners.
73. The Commerce Clause protects the interstate market, not particular interstate firms, from prohibitive or burdensome regulations.
74. Any shift towards or away from out-of-state resources is speculative at this point, and could not possibly indicate discriminatory intent.
75. The EPS is an evenhanded regulation that lacks discriminatory intent or effect as to interstate commerce.
76. When a state enactment is not facially discriminatory, the Pike balancing test is generally applied.
77. A regulation's burdens on interstate commerce must be "clearly excessive" in relation to the local benefits in order for a regulation to be struck down under Pike.
78. The burden of proving "excessiveness" under Pike falls on the party challenging a regulation.
79. The EPS has substantial local benefits.
80. Selectively characterizing the interstate market does not necessarily establish an impermissible burden on interstate commerce.
81. While national displacement of coal may have some economic effects, this does not establish an impermissible burden on interstate commerce
82. The "burdens" on interstate commerce, alleged by CEED and others, are incidental and not "clearly excessive" in relation to the substantial local benefits of the EPS.
83. Extraterritorial regulation means regulation that impacts commerce that occurs "wholly" outside the state.
84. When a state regulates contractual relationships in which at least one party is located within California, it does not regulate commerce entirely outside of the State of California.
85. Simply because the sales to California LSEs under the EPS may affect the costs or profits of an out-of-state generation company, this does not make the regulation extraterritorial.
86. The EPS does not have an impermissible extraterritorial reach.
87. The EPS is valid under the dormant Commerce Clause.
88. In developing the interim EPS, the Commission has considered the effects of the standard on system reliability and overall costs to electricity customers as required under § 8341(d)(6).
89. The interim EPS fulfills both the letter and the spirit of SB 1368 by effectively "raising the bar" for the GHG emissions performance of new long-term commitments with baseload generation serving California during the transition to a statewide GHG emissions cap.
90. In order to meet the February 1, 2007 deadline established by SB 1368 for the adoption of an enforceable interim EPS, this decision should be effective immediately.
IT IS ORDERED that:
1. As defined in Senate Bill (SB) 1368 (Stats. 2006, ch. 598) and by today's decision, every electrical corporation, electric service provider, or community choice aggregator serving end-use customers in the state (collectively referred to as "load-serving entities" or "LSEs") shall be subject to the greenhouse gas interim emissions performance standard rules ("Interim EPS Rules") described in this decision and set forth in Attachment 7.
2. The Interim EPS Rules presented in Attachment 7 and described in this decision shall be effective and enforceable immediately.
3. Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE) and San Diego Gas & Electric Company (SDG&E) shall submit for Commission pre-approval all procurements subject to the Interim EPS Rules ("covered procurements") as follows:
(a) For covered procurements eligible under the Renewable Portfolio Standard (RPS) program:
i. PG&E, SCE and SDG&E shall request pre-approval through RPS advice letter filings, and
ii. These advice letters shall be served on the service list in Rulemaking (R.) 06-05-027, or its successor proceeding.
iii. Should an application process be used for any particular RPS contract, or should the advice letter process set forth in Decision (D.) 03-06-071 be changed in whole or in part to an application process in the future, that application process shall automatically apply to the EPS compliance filings required of PG&E, SCE and SDG&E for RPS resources. However, if the advice letter process set forth in D.03-06-071 is modified to include procedures whereby RPS advice letters may be "deemed approved," such procedures shall not apply for the purpose of establishing EPS compliance.
(b) For covered procurements with non-RPS generation:
i. PG&E, SCE and SDG&E shall request pre-approval through the non-RPS application process established by the Commission's procurement rules in R.06-02-013, or its successor proceeding, and
ii. These applications shall be served on the service list in R.06-02-013, or its successor proceeding.
(c) For covered procurements that employ geological formation injection for carbon dioxide (CO2 ) sequestration:
i. PG&E, SCE and SDG&E shall request pre-approval through the non-RPS application process established by the Commission's procurement rules in R.06-02-013, or its successor proceeding, and
ii. As part of this filing, PG&E, SCE and SDG&E 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 the permanent sequestration of CO2 once the project is operational, and that the CO2 injection project complies with applicable laws and regulations. This showing shall include any emissions-related provisions that may be required through contract and/or permit conditions.
iii. These applications shall be served on the service lists in R.06-02-013 and this proceeding, or their successor proceedings.
4. All LSEs other than PG&E, SCE and SDG&E are required to file annual Attestation Letters, due by February 15 of each year, attesting to the Commission that the financial commitments entered into during the prior calendar year are in compliance with the EPS. The Attestation Letter shall include a certification, including the name and contract information for the LSE officer(s) certifying the following under penalty of perjury:
A. I have reviewed, or have caused to be reviewed, this compliance submittal.
B. Based on my knowledge, information, or belief, this compliance submittal does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements true.
C. Based on my knowledge, information, or belief, this compliance submittal contains all of the information required to be provided by Commission orders, rules and regulations.
The Attestation Letter shall be filed as an advice letter and served on the service list in this proceeding, or its successor proceeding. The Attestation Letter shall be subject to the Commission procedures governing advice letter filings, which include opportunity for protests and responses. However, no Attestation Letter shall be "deemed approved" under those procedures.
Energy Division shall review each Attestation Letter and approve it if it contains all the elements required by the EPS documentation requirements, includes a certification by the responsible corporate officers, and if the facts stated in the Attestation Letter show compliance with the EPS. Energy Division approval of the Attestation Letter means that the Attestation Letter is in compliance with these rules, and that any procurements as reported in the Attestation Letter comply with the requirements of the EPS program. Energy Division approval does not mean that LSE procurements that are unreported or inaccurately reported comply with the EPS. LSEs shall be subject to penalties if the attestation letters are found, at a later date, to be incomplete, misleading or incorrect.
5. Except as otherwise directed under Ordering Paragraphs 6, 7 and 8, LSEs other than PG&E, SCE and SDG&E may submit advice letters during the year requesting pre-approval of a new financial commitment as EPS compliant, at their discretion. These advice letter filings, as well as any responses or protests, shall be served on the service list in this proceeding or its successor proceeding. The advice letter shall be subject to the Commission procedures governing advice letter filings, which include opportunity for protests and responses. However, no advice letter submitted for this purpose shall be "deemed approved" under those procedures.
6. For covered procurements that employ geological formation injection for CO2 sequestration, LSEs other than PG&E, SCE and SDG&E shall request Commission pre-approval by filing a separate application with service on the service list in this proceeding, or its successor proceeding. 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 permanent sequestration of CO2 once the injection project is operational and that the CO2 injection project complies with applicable laws and regulations. The LSE shall also make a showing of EPS compliance by presenting projections, and documentation of those projections, of net emissions over the life of the powerplant. This showing shall include any emissions-related provisions that may be required through contract and/or permit conditions.
7. Any request for a reliability exemption shall require Commission pre-approval and shall be made by separate application, as follows:
(a) PG&E, SCE and SDG&E shall serve such requests on the service lists in R.06-02-013 and this proceeding, or their successor proceedings, and
(b) All other LSEs shall service such requests on the service list in this proceeding.
Any LSE requesting review and pre-approval of a reliability-based exemption from the EPS rule shall provide documentation demonstrating that such long-term procurements are necessary to ensure system reliability. As discussed in this decision, the Commission shall consult with the California Independent System Operator during implementation in considering the effects of requests for reliability exemptions on system reliability and overall costs to electricity customers.
8. LSEs shall not ask to be excused from the requirements of this decision for any other reason unless they can clearly demonstrate:
(a) They are facing extraordinary circumstances, catastrophic events or threat of significant financial harm not contemplated by SB 1368 and this decision, and
(b) An exemption from some requirement of this decision is necessary to significantly mitigate or eliminate the challenges posed by these circumstances.
Any requests to be excused from the requirements of this decision for such "extraordinary circumstances" must be pre-approved by the Commission and shall be made as a petition for modification of this decision and served on the service list in this proceeding, or its successor proceeding.
9. The Commission's consideration of any request for a reliability exemption or petition for modification to be excused from the requirements of this decision due to "extraordinary circumstances, catastrophic events or threat of significant financial harm" shall come with a heavy burden of proof on the LSE.
10. In the compliance submittals required under Ordering Paragraphs 3 and 4 above, all LSEs shall include a listing of the new long-term financial commitments of five years or longer they plan to enter into (SCE, PG&E and SDG&E) or have entered into during the prior year (all other LSEs) with documentation to demonstrate:
(i) That the commitments are not "covered procurements" under the Interim EPS Rules and/or
(j) For those that represent covered procurements, documentation demonstrating that such procurements are EPS-compliant, including any contracts with a term of five years or longer that include provisions for substitute energy purchases.
(c) For any requested reliability-based exemptions that have been pre-approved by the Commission, a reference to the application and Commission decision number.
Consistent with the discussion in this decision that "linked" contracts are to be treated as a single contract for purposes of EPS compliance, this listing of new long-term financial commitments of five years or longer must include any "linked" contracts whose combined term is five years or longer. LSEs are also advised to present documentation regarding the design and intended use of the powerplant(s) underlying the new long-term financial commitments utilizing the sources of documentation listed under § 8341(b)(4) of the Public Utilities Code, as well as any other sources of documentation that they believe will be relevant to the Commission's determination of whether the commitment represents a "covered procurement" under the Interim EPS Rules. As discussed in this decision, LSEs are required to include historical annual averages in their documentation of annualized plant capacity factors. In documenting the emissions rates associated with covered procurements, LSEs shall comply with the Interim EPS Rules governing the calculation of those rates, which include the adopted method for cogeneration facilities.
11. The burden is on the LSE to document that the limits to substitute energy purchases with unspecified resources described in this decision are reflected in any contracts with a term of five years or longer that include substitute energy provisions. In particular, the LSE shall 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.
12. In addition to other documentation required by this decision, all LSEs shall disclose their investments in retained generation, including combined-cycle gas turbine (CCGT) powerplants deemed to be in compliance under § 8341(d)(1). This information shall describe the investment amount and type of alteration by generation facility and unit. PG&E, SCE and SDG&E shall disclose this information in their Quarterly Procurement Plan Compliance Reports established by D.02-10-062. All other LSEs shall disclose this information in the annual Attestation Letter required under Ordering Paragraph 4.
13. The advice letter procedures for the annual Attestation Letters and other compliance submittals described in this decision are adopted for the limited purpose of EPS compliance. In the event that some clarifications or modifications to these procedures may need to be made after the effective date of this decision in order to reconcile them with updated Commission procedures for advice letter filings in R.98-07-038 or R.06-05-027, or their successor proceedings, the Assigned Commissioner shall provide such clarifications or modifications by ruling or other manner, in consultation with the assigned Administrative Law Judge (ALJ) and Energy Division.
14. Sierra Pacific Power Company and PacifiCorp are excused from showing compliance with the Interim EPS Rules based on their showing of alternative compliance. They are still required, however, to file annual attestation letters on February 1 of each year, beginning February 1, 2008, stating that they continue to qualify for alternative compliance consistent with this decision.
15. Within sixty (60) days from the effective date of this decision, SCE, PG&E and SDG&E shall update their long-term procurement plan (LTPP) filings in R.06-02-013 in compliance with the Interim EPS Rules, as necessary, to reflect today's determinations. If changes to the LTPP filings are necessary to show compliance with this decision, SCE, PG&E and SDG&E will file an Amendment to the LTPP, Volume 1, indicating whether the Amendment supersedes or adds to specific sections of the plan, with service on the service list in R.06-02-013.
16. As discussed in this decision, the Commission, Assigned Commissioner ALJ and/or Commission staff retain the right to data request any of the LSEs, including the electric service providers, community choice aggregators or small electrical corporations, to ask for any copies of contracts or procurement information that is deemed necessary to evaluate compliance with the EPS. Any LSE may be audited if the Commission or staff has any doubt that the LSE is forthcoming in its demonstration of EPS compliance.
17. If any of the financial commitments entered into by LSEs appear to be out of compliance with the Interim EPS Rules, the Commission may consider issuing an Order Instituting Investigation (OII) or take other appropriate action. If the Commission finds that the LSE did not comply with those rules, the Commission shall address the level of penalties in an OII proceeding or other procedural forum, as it deems appropriate.
18. Any LSE that seeks confidentiality protection for data contained in its EPS-related submittals shall follow the policies and procedures set forth in D.06-06-066.
This order is effective today.
Dated January 25, 2007, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
Commissioners
