5. Compliance-Related Issues
The concept of a "gateway screen" approach to EPS compliance is an integral component of staff's recommendations and is supported by all parties. Under this approach, a series of questions or criteria are applied to first determine whether or not the LSE's financial commitment is a "covered procurement" subject to the EPS. If it is, then the commitment is screened to ensure that the associated GHG emissions rate does not exceed the adopted EPS performance level of 1,100 lbs of CO2 per MWh. Once the financial commitment successfully passes through the gateway screen, the LSE has demonstrated EPS compliance for that particular commitment. Ongoing Commission review or monitoring of the facilities underlying that commitment is not required.
We adopt this approach for demonstrating compliance with the interim EPS. We believe it 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). Moreover, as staff and the parties point out, a gateway screen approach is the most practicable and enforceable manner in which to determine EPS compliance.
While parties agree on the concept of a gateway screen approach to determining EPS compliance, there is some disagreement on what compliance submittals should be required of different types of LSEs (i.e., large electrical corporations, small electrical corporations, energy service providers, community choice aggregators), as well as what documentation those submittals should contain. There is also disagreement among some parties on how to interpret SB 1368 with respect to alternative compliance for multi-jurisdictional utilities. In addition, clarification to the definition of "capacity factor" has been requested by some parties for compliance purposes. The final report does not provide specific recommendations on these issues.
Finally, there is disagreement among parties over whether offsets or other compliance options (such as "portfolio averaging") are appropriate for an interim EPS. We address these and other compliance-related issues below.
5.1. Compliance Process for PG&E, SDG&E and SCE
Parties commenting on this issue recognize that the Commission requires the largest electrical corporations (i.e., SCE, PG&E and SDG&E) to file long-term procurement plans for review and approval by the Commission pursuant to § 454.5, and also requires SCE, PG&E and SDG&E to seek Commission pre-approval before they can enter into procurement contracts of five years or longer.188 There is consensus among the parties that the same procedural vehicles used by these LSEs to seek Commission pre-approval of their long-term procurement contracts should be used to seek pre-approval of covered commitments under the EPS rule we establish today. We agree, and outline those procedures below.
SCE, PG&E and SDG&E currently bring all power purchase contracts with terms of five years or longer before the Commission for review and pre-approval by filing either an advice letter (for RPS-contracts) or an application (for non-RPS contracts). For all RPS contracts, we use the advice letter process established in our RPS proceeding to pre-approve those procurements.189 Each advice letter is reviewed by Energy Division, and a Commission resolution addressing the RPS contract is prepared for Commission approval. Under existing procurement rules adopted in D.04-12-048, PG&E, SCE and SDG&E file applications requesting Commission review and pre-approval of all non-RPS contracts with a term of five years or more. The Commission issues a decision addressing the applications.
We will use these existing procedural vehicles for reviewing and pre-approving PG&E, SCE and SDG&E's covered procurements with respect to EPS compliance. As discussed in Section 4.2, "covered procurements" includes new and renewal contracts of five years or greater with baseload generation, LSE new investment in baseload generation (new construction) as well as major alterations to baseload facilities. For PG&E, SCE and SDG&E, each of the various types of covered procurements subject to the EPS will be reviewed and pre-approved through the advice letter process (for RPS resources) or application process (for non-RPS resources) described above.
More specifically, for covered procurements with RPS-eligible baseload generation, these utilities shall submit documentation to demonstrate compliance with the EPS through RPS advice letter filings. These advice letters shall be served on the service list in our RPS Rulemaking, R.06-05-027, or its successor proceeding. Should an application process be used for any particular RPS contract, or should the advice letter process set forth in D.03-06-071 be changed in whole or in part to an application process in the future, that process will automatically apply to the EPS compliance filings required of SCE, PG&E and SDG&E for RPS resources.190
For all non-RPS covered procurements, PG&E, SCE and SDG&E shall submit documentation to demonstrate compliance with the EPS through the non-RPS application process established by our procurement rules. This includes any request for a Commission finding of EPS compliance for covered procurements that employ geological formation injection for CO2 sequestration. These applications shall be served on the service list in our Long-Term Procurement Rulemaking, R.06-02-013, or its successor proceeding. The Commission's determination on these matters will address the compliance of the covered procurements with our EPS rules.
As discussed in this decision, any request for a reliability exemption or an exemption based on "extraordinary circumstances, catastrophic events, or threat of significant financial harm" will require Commission pre-approval. We direct SCE, PG&E and SDG&E to file such requests by application with service on the service list in both R.06-02-013 and this proceeding, or their successor proceedings. Any request for an extraordinary circumstances modification shall be filed as a petition for modification of this decision.
In addition, we require all LSEs to disclose in their compliance submittals any multiple contracts of less than five years with the same supplier, resource or facility. (See Section 5.5 below.) We direct SCE, SDG&E and PG&E to disclose this information in their Quarterly Procurement Plan Compliance Reports191 that demonstrate compliance with all Commission procurement rules.
5.2. Compliance Process for Small Electrical Corporations, Electric Service Providers and Community Choice Aggregators
Currently, the Commission does not require electric service providers, community choice aggregators or the "small electrical corporations" (i.e., those other than PG&E, SCE and SDG&E) to submit procurement plans or apply for pre-approval of long-term procurement contracts. AReM, Constellation, Plumas-Sierra and others argue that such pre-approval requirements should not be established for these entities for the purpose of demonstrating EPS compliance. Instead, they recommend that electric service providers, community choice aggregators and the small electrical corporations make a more simplified after-the-fact compliance showing. In particular, AReM recommends using the existing resource adequacy compliance submittal for this purpose, which SCE, PG&E, SDG&E, electric service providers and community choice aggregators are required to file annually as an Advice Letter.192 PG&E, SMUD, CMUA, Northern California Power Agency and the Southern California Public Power Authority support this approach in their comments.
Specifically, AReM envisions a process whereby in most cases, the electric service provider would simply certify that it had not entered into any financial commitments during the previous year that are subject to the EPS. If it had entered into such commitments, the electric service provider would provide documentation to show that the commitment was in compliance with the EPS. Constellation also suggests that the electric service provider could be subject to an independent third-party audit if the Commission has any doubt that the electric service providers are forthcoming in their demonstrations.
NRDC/TURN/UCS and WRA object to relying on procedures that would allow for after-the-fact compliance submittals, as recommended by AReM and others. They argue that this approach is not consistent with SB 1368 or with the concept of an upfront gateway standard. In their view, allowing electric service providers or other LSEs to show compliance after-the-fact would not offer the same protection to its customers and would open a significant loophole to compliance if in the end an electric service provider did enter into a long-term financial commitment that violated the performance standard. In their view the standard must be enforced on an upfront basis for all LSEs before any long-term commitments are made.193
We read § 8341(a) to mean that all LSEs must comply with the statute if they enter into any long-term financial commitment involving baseload generation, irrespective of whether (or how) this Commission reviews and approves such commitments. Subsections (1)-(6) of § 8341(b) describe a variety of things that the Commission shall or may do related to the implementation of the EPS program, none of which imposes a requirement on the Commission that it must pre-approve all long-term commitments made by the LSEs. Had it intended to make this requirement, the Legislature could have directed, for example, that no electrical corporation shall enter into a long-term financial commitment unless it is pre-approved by the Commission.
It did not do so. Instead, the language of subsection (1) states that "the Commission shall not approve a long-term financial commitment by an electrical corporation unless any baseload generation supplied under the long-term financial commitment complies with the greenhouse gases emission performance standard established by the commission..." We read this to mean that if the Commission does approve such commitments in the first place, which is the case for the large investor-owned utilities in our procurement proceeding, we must make a determination that the commitment complies with the EPS.194 Similarly, subsection (2) does not require that we review long-term financial commitments that are proposed to be entered into by an electric service provider or community choice aggregator, but only states that we "may" do so. Therefore, in adopting rules and procedures to ensure compliance with the EPS, pursuant to § 8341(b)(3), 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.
With certain exceptions, we provide for "after-the-fact" EPS compliance submittals for electric service providers, community choice aggregators and small electrical corporations.195 We concur with AReM, Constellation and others that EPS compliance procedures that do not require Commission pre-approval are appropriate for those LSEs who are not required to submit procurement plans or procurement contracts for pre-approval under current Commission procedures. We believe that the documentation and other requirements adopted today provide reasonable safeguards against the risks to ratepayers of potential non-compliance by an LSE that files an after-the-fact compliance showing. At the same time, this approach avoids creating new pre-approval requirements and associated administrative complexity for the Commission's regulation of the procurement practices of these entities. Moreover, we note that we have already established procurement-related compliance procedures for electric service providers and community choice aggregators that are similar to what AReM and others now propose for demonstrating EPS compliance. We think that this approach is reasonable for the interim EPS, with the following qualifications.
First, we do not adopt the resource adequacy filing as referred to by AReM and others as the procedural vehicle for these submittals. This filing is a compliance submittal related to a one-year ahead capacity obligation, rather than a multi-year procurement obligation or rule. The Commission does not review any contracts in the resource adequacy filing process. Compliance is demonstrated through a template and through the obligation of the capacity resources to "show up" through real time at the California Independent System Operator. Therefore, we do not believe it is appropriate to include the EPS-compliance showing in this particular filing. Instead, electric service providers, community choice aggregators and electrical corporations other than SCE, PG&E and SDG&E will be required to file an annual Attestation Letter, due by February 15 of each year, attesting to the Commission that the financial commitments it has entered into during the prior calendar year are in compliance with the EPS.
Second, the Attestation Letter shall comply with all documentation requirements described in Section 5.5, and contain a certification, including the name and contact information for the LSE officer(s) certifying the following under penalty of perjury:
"(1) I have reviewed, or have caused to be reviewed, this compliance submittal.
"(2) 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.
"(3) 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."
Third, the Attestation Letter shall be filed as an advice letter, subject to the Commission procedures governing advice letter filings, which include opportunity for protests and responses.196 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 elements required by the EPS documentation requirement, includes a certification by the responsible corporate officers, and if the facts state in the Attestation Letter show compliance with the EPS. Energy Division approval of the advice letter means that the Attestation Letter is in compliance with these rules, and that any procurement as reported in the Attestation Letter complies 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.
In its Opening Comments on the Proposed Decision, the City of San Francisco objects to our discussion of penalties, here and in other sections of the decision. It argues that it is inappropriate to address the imposition of penalties on LSEs that are governmental entities, until "more detail is provided regarding the authority and process for the imposition of penalties."197 We disagree. The specific authority and process for imposing any penalties can be addressed if and when any violations occur. The point of our brief discussion of penalties is to inform all LSEs that we will take violations of the EPS and our reporting requirements seriously, and thereby help ensure that violations do not occur.
In addition, an electric service provider, community choice aggregator or small electrical corporation may, at its discretion, submit an advice letter during the year requesting pre-approval of a new financial commitment as EPS compliant when there is uncertainty about whether the financial commitment will comply with our EPS rules. All advice letter filings, as well as responses or protests, shall be served on the service list in this proceeding or its successor proceeding.198 We caution electric service providers, community choice aggregators and small electrical corporations not to burden this process with requests for pre-approval of financial commitments that are clearly exempt from having to show EPS compliance, such as a single contract for a term of less than five years.
As discussed elsewhere in this decision, all LSEs are required to file (1) an application requesting Commission pre-approval for a reliability exemptions, (2) a petition for modification of this decision where the request is based on "extraordinary circumstances, catastrophic events, or threat of significant financial harm" or (3) an application for covered procurements that employ geological formation injection for CO2 sequestration. Accordingly, the advice letter process described above will not be applicable to these types of requests. Instead, small electric corporations, electric service providers and community choice aggregators are required to file such requests by application or petition for modification, and serve them on the service list in this proceeding, or its successor proceeding.
5.3. Alternative Compliance Provisions for Multi-Jurisdictional Electrical Corporations
SB 1368, permits the Commission to consider a showing of "alternative compliance" by multi-jurisdictional electrical corporations that serve 75,000 or fewer retail end-use customers in California. Specifically, § 8341(d)(9) states that these LSEs:
"...may file with the commission a proposal for alternative compliance with this section, which the commission may accept upon a showing by the electrical corporation of both of the following:
"(A) A majority of the electrical corporation's retail end-use customers for electric service are located outside of California.
"(B) The emissions of greenhouse gases to generate electricity for the retail end-use customers of the electrical corporation are subject to a review by the utility regulatory commission of at least one other state in which the electrical corporation provides regulated retail electric service."
Upon Commission approval of a showing of alternative compliance, under § 8341(d)(9), a utility shall not be required to demonstrate compliance at this Commission for their California operations pursuant to the procedures we adopt in Section 5.2 above.
The two multi-jurisdictional utilities subject to SB 1368, Sierra Pacific and PacifiCorp, both state in their comments that they meet § 8341(d)(9)'s qualification requirements for alternative compliance with the EPS. In the Proposed Decision, we agreed with PacifiCorp's proposal for how to determine whether a multi-jurisdictional electrical corporation's GHG emissions are "subject to a review" by the public utilities commission of another state, part B of the statutory alternative compliance requirements.199 Under this test, an electrical corporation would satisfy part B of SB 1368's alternative compliance provision when any of the following occur 1) a state jurisdiction requires the utility to review and report on the potential impacts of different carbon policies within its Integrated Resource Planning process; or 2) when it requires the utility to disclose its greenhouse gas emissions or expected change in overall emissions as a result of changes to its portfolio, including new capacity additions; or 3) when a state jurisdiction adopts rules specifically regulating emissions of greenhouse gases from electricity generating facilities.200 PacifiCorp further states that "four of our six state commissions require PacifiCorp to consider greenhouse gas emissions in electricity resource planning."201
In summary, a multi-jurisdictional electrical corporation can demonstrate alternative compliance if it (1) serves fewer than 75,000 retail customers within California, (2) a majority of its retail customers are located outside of California, and (3) it is subject to any one of the three kinds of carbon emissions related regulation described above.
In the Proposed Decision, we concluded that until alternative compliance was approved by the Commission each multi-jurisdictional should file its alternative compliance proposal as an application with service on the service list in this proceeding, or its successor proceeding. We further concluded that until the application was approved by the Commission, all multi-jurisdictional utilities should be required to submit annual Advice Letters demonstrating compliance with the EPS pursuant to the procedures discussed in Section 5.2 above. We further required that the multi-jurisdictional utility's compliance filings should describe the method used to identify and allocate its long-term financial commitments to California retail customer load.
Upon further review, however, we conclude that both Sierra Pacific and PacifiCorp meet the alternative compliance requirements described in the Proposed Decision. Both multi-jurisdictional utilities are still required to file annual advice letters on February 1 of each year, starting in 2008, attesting that they still meet the alternative compliance requirements.
Sierra Pacific provides electricity to 45,000 customers within the state of California with the vast majority of its load residing in Nevada.202 Nevada Administrative Code §§ 704.2783 and 704.2785 require Sierra Pacific to disclose to its customers twice each year the average emissions of carbon dioxide, sulfur dioxide, and carbon monoxide as measure in lbs/MWh produced by internal generation and purchased power.203 Since §§ 704.2783 and 704.2785 require that Sierra Pacific "disclose its greenhouse gas emissions" it satisfies option 2, thereby establishing that Sierra Pacific is "subject to a review", and satisfying part B of SB 1368's alternative compliance requirements.204
Similarly, a minority of PacifiCorp's customers, 2% or 43,777, are located in California.205 PacifiCorp further states that "four of our six state commissions require PacifiCorp to consider greenhouse gas emissions in electricity resource planning."206 In the table provided on page 8 of its October 18th comments PacifiCorp indicates that it is subject to some kind of carbon emissions regulations in Oregon, Utah, and Washington, each of which hosts a larger percentage of PacifiCorp's load than California.
Recently the Oregon Public Utility Commission issued Order 07-002207 which, in conjunction with Order 93-695, requires PacifiCorp to include in their Integrated Resource Planning filings the potential regulatory compliance costs for C02 Nitrous Oxides, Sulfur Oxides, and mercury emissions. Under option 1 of our "subject to a review" test, another state's regulation or statute which "requires the utility to review and report on the potential impacts of different carbon policies within its Integrated Resource Planning process" qualifies as "review" for the purposes of SB 1368's alternative compliance provision. Since 07-002 requires that PacifiCorp report the expected regulatory compliance costs associated with an array of GHGs, including C02, within its Integrated Resource Planning process, it satisfies Option 1 of our test to determine whether or not a multi-jurisdictional utility is "subject to a review" in another jurisdiction.
Both PacifiCorp and Sierra Pacific, therefore, have made a satisfactory showing that they satisfy SB 1368's alternative compliance requirements.
5.4. Portfolio Averaging, Offsets and Other Proposed Compliance Options
CEED, LS Power and SCE argue that the interim EPS should include an offsets program, whereby the LSE would have the option to offset emissions from a high-emitting baseload resource with GHG emissions reductions secured elsewhere to bring it into EPS compliance. For this purpose, these parties advocate allowing offsets secured from industries other than just the electric generating sector and without geographic restrictions. They provide no specifics on how such an offsets program could be established and enforceable by the statutory deadline, but contend that allowing them would provide flexibility in meeting the goals of the EPS, spur broader innovation, and control costs.
For similar reasons, CEED advocates "portfolio averaging," although it is not clear from CEED's submittal what exactly that means in the context of an EPS applied on a commitment-by-commitment basis. Presumably, the Commission would look at a "portfolio" of long-term commitments made by the LSE over some period of time, and then assess EPS compliance with respect to the average emissions rate of that portfolio.
In its draft and final report, staff recommends that the Commission not include these types of compliance options because they would require significant upfront analysis and ongoing reporting and monitoring requirements, resulting in delays in both the implementation and enforcement of an interim EPS. For this and other reasons, Calpine, IEP, NRDC, TURN, UCS and WRA do not support the use of offsets or portfolio averaging to comply with the EPS. In their view, such compliance options do not fit within the concept of an interim EPS and would serve to defeat its purpose.
We agree with staff and these parties that one reason to reject the compliance options proposed by CEED and others is that they cannot be designed and implemented within the timeframe contemplated for an interim EPS, particularly in light of the statutory requirement that an enforceable EPS be put in place no later than February 1, 2007. However, there is another, more fundamental reason to reject them: Allowing the LSE to use portfolio averaging or offsets to comply with the EPS would compromise the very purpose of establishing a GHG emissions-based standard in the first place.
As discussed throughout this decision, the interim EPS is intended to be a facility-based minimum performance standard governing long-term commitments made by an LSE to baseload generation facilities. This reflects a fundamentally different purpose, serving different policy objectives, than programs to reduce GHG emissions through a portfolio-wide cap, cap-and-trade programs or programs that permit LSE's to use offsets to meet an emissions cap or performance standard. 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.
In particular, portfolio-averaging permits an LSE to meet an emissions limit (or "cap") with a variety of short-term and long-term procurement combinations. For example, the LSE can procure electricity (build or purchase) on a long-term basis from a very high-emitting generating facility as long as it has other resources in its procurement portfolio that lower the average enough to meet the emissions cap from year-to-year. In other words, as long as the emissions associated with the LSE's overall procurement portfolio do not exceed the total number of allowances (permitted level of emissions) allocated to it, the LSE will be in compliance with the program.208 Under a "cap-and-trade" program, the allowances allocated to the various LSEs subject to the cap can be traded. Thus, for example, the emissions of an LSE's procurement portfolio may exceed the number of allocated emission allowances if the LSE can purchase additional allowances from LSEs that do not need the number of allowances that they currently hold.
An offset program permits the LSE to make a reduction in emissions outside the scope of the emissions cap, which in turn allows an increase in emission levels associated with the LSE's procurement portfolio. The LSE can purchase offsets from third parties making investments to reduce emissions elsewhere (for example, investments in reforestation or in low-emissions vehicles or in the electric sector of other countries), or make those investments itself. This permits the LSE to exceed its allocated GHG emissions allowances. Under any of these compliance approaches to a GHG emissions cap, the LSE may enter into long-term financial commitments with high-emitting powerplants as long as it meets the level of the emissions cap for its portfolio as a whole, or acquires allowances and/or offsets to increase the permissible level of portfolio emissions.
In contrast, the interim EPS is aimed at ensuring that an LSE does not enter into long-term financial commitments with high-emitting baseload resources in the first place. This is because the primary objectives of the interim EPS is to ensure that there is no "backsliding" as California transitions to a statewide GHG emissions cap. This objective cannot be accomplished if LSEs are permitted to comply with the standard by diluting the emissions from non-compliant powerplants through portfolio averaging or increasing the permissible level of emissions for these powerplants (e.g., through offsets). These options 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, such as the AB 32 declining cap on statewide GHG emissions.209
For these reasons, we do not adopt offsets or portfolio averaging in the context of today's adopted interim EPS. In the context of a load-based cap, however, we fully intend to evaluate a broad range of flexible compliance options as we proceed to implement the Procurement Incentive Framework during Phase 2 of this proceeding. Pursuant to AB 32, flexible compliance options will also be evaluated as California proceeds to implement the emissions limits required under that new law on a statewide basis.210 As we stated in D.06-02-032, we will focus our efforts during Phase 2 on ensuring that the compliance options that we do permit under the Procurement Incentive Framework are credible, verifiable and administratively feasible. During Phase 2, we intend to carefully explore the pros and cons of alternate proposals for offsets, trading, banking and borrowing and other compliance options before making our final determinations. Throughout the process, we will closely coordinate with CARB, the Governor's Climate Action Team as well as other state, regional or federal agencies that are exploring design options for cap-and-trade programs.211
5.5. Documentation Requirements and Contract Linkage Issues
In their compliance submittals, all LSEs212 should 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 (electric service providers, community choice aggregators, small electrical corporations) with documentation to demonstrate:
(a) That the commitments were not "covered procurements" under the interim EPS rule and/or
(b) 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 our discussion in today's 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 "linked" contracts whose combined term is five years or longer. Further, disclosure of LSE investments in retained generation, including "deemed-compliant" CCGTs, is also necessary to monitor compliance with the interim EPS rules. Therefore, we require all LSEs to disclose the investment amount and type of alteration to retained generation, by generation facility and unit. As discussed above, electric service providers, community choice aggregators and small electrical corporations will need to provide this information in their annual Attestation Letter. SCE, SDG&E and PG&E are required to disclose this information in their Quarterly Procurement Plan Compliance Reports213 that demonstrate compliance with all Commission procurement rules. In addition, the burden is on each LSE to provide sufficient documentation in compliance submittals to demonstrate that the limits to substitute energy purchases with unspecified resources described in Section 4.12 are reflected in any contracts with a term of five years or longer that include substitute energy provisions.
As discussed in this decision, we permit case-by-case review of reliability exemptions and requests for modification based on extraordinary circumstances, catastrophic events, or threat of significant financial harm" due to circumstances unforeseen by SB 1368 and this decision, with the caveat that any consideration of such exemptions comes with a heavy burden of proof on the LSE. Any LSE requesting review and pre-approval of a reliability-based exemption from the EPS rule must provide documentation demonstrating that such long-term procurements are necessary to ensure system reliability. We caution all LSEs that they should not asked to be excused from the requirements of this decision for any other reason 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. These requests must be pre-approved by the Commission and shall be made by application in the case of a reliability exemption request, or petition for modification in the case of an "extraordinary circumstances" request, as discussed in Section 4.8.5.
We also require LSEs to file an application requesting a Commission finding of EPS compliance for any covered procurement that employs geological formation injection for CO2 sequestration. As part of this filing, the LSE shall provide documentation demonstrating that the geological formation injection project has a reasonable and technically feasible plan that will result in a permanent sequestration of CO2 once the project is operational.
Several parties have requested further guidance on the documentation required to determine whether a long-term financial commitment represents a commitment to baseload generation and if so, the associated emissions rate to use in evaluating EPS compliance.
We believe that the guidance provided in SB 1368 is instructive on this issue. Specifically, in determining whether a long-term financial commitment is for baseload generation, § 8341(b)(4) directs that we "consider the design of the powerplant and the intended use of the powerplant." This section goes on to enumerate several sources of information that are relevant for this purpose (e.g., the electricity purchase contract, any certification received from the CEC, any other permit or certificate necessary for the operation of the powerplant, any procurement approval decision). It also states that we may base our determination on "any other matter" that we find to be "relevant under the circumstances."
Accordingly, in their compliance filings, LSEs are advised to present documentation regarding the design and intended use of the powerplant(s) underlying their new long-term financial commitments utilizing the sources of information listed in § 8341(b)(4), as well as any other sources of documentation that they believe will be relevant to this determination. The key concept here is that the documentation should relate to establishing the design and intended use of the powerplant. As discussed in Section 5.6 below, documentation of the annualized plant capacity factor for the powerplant should include historical annual averages in order to help determine whether the plant is "designed and intended" to be used for baseload generation.
We note that PG&E proposes demonstrating compliance with the EPS thorough "documentation of the facility's full load heat rate and expected capacity factor"214 However as NRDC and others observe, 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. Full load heat rates are lower than heat rates during actual plant operations, and therefore underestimate the heat rates and corresponding emissions of plants that are operating as "designed and intended."215 Rather than assume full load heat rates, as PG&E proposes, LSEs should provide documentation of capacity factors, heat rates and corresponding emissions rates that reflect the actual, expected operations of the plant.
For similar reasons, we reject the recommendation of PG&E and Northern California Power Agency that we require all LSEs to use the International Organization for Standardization measurement standards to document the capacity factors, heat rates and corresponding emission rates in demonstrating EPS compliance. Our understanding of these measurement standards is that they normalize based on the temperature, atmospheric pressure and relative humidity typical of those parts of the globe where the majority of the population lives, i.e., at the seacoasts.216 As a result, these standards may not be appropriate for use by all LSEs in documenting EPS compliance, particularly for those powerplants located in high temperature or high altitude regions.
In their opening comments on the Proposed Decision, both SCE and Constellation urge us to more clearly explain what we mean by "linked" contracts, that although individually for a term of less than five years, together have a term of five years or more, and therefore may be subject to the EPS. We agree that this concept needs to be spelled out in detail now, so that the LSEs can comply with the EPS. SCE makes several suggestions as to how to determine whether two, or more, contracts are "linked"; the second of these of these suggestions contains a number of useful elements. SCE suggests 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 six 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."217
The purpose of requiring "linked" contacts-for baseload generation-- with a combined term of five 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). With this goal in mind, we consider SCE's suggestion.
First we consider SCE's proposal that for contracts with an unspecified generation source the contracts must be executed within 24 hours of each other to be considered linked. This proposal would make it too easy to circumvent the EPS. Under this proposal an LSE could negotiate two contracts with the same seller (counter-party), one for a term of four years, and the other for a term of three years beginning on the expiration of the first contract, and avoid application of the EPS simply by delaying the signing of one contract by two days. The underlying reality would be that there was a single deal with one counter-party to provide electricity for a term of seven years. Pursuant to SB 1368, this deal should be required to meet the EPS if it is for baseload generation.
Furthermore, we do not think that the date of execution of the contracts, standing alone, should be the determining factor in deciding whether two contracts are sufficiently related to be considered one for purposes of applying the EPS. Turning again to the example in the above paragraph, we do not think that the two contracts described there should be considered separate, regardless of how long the parties wait to execute the second one, if they were negotiated at (or about) the same time. In that situation, the underlying reality would still be that there was a single deal with one counter-party to provide electricity for a term of seven years. Thus, we conclude that we should expand upon SCE's concept that two contracts should be considered linked if they are both executed within a specified window of time. Instead 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.)
While SCE proposed a 24-hour window for contracts with unspecified generation sources, it proposed a six-month window for contracts with specified generation sources. However, its six-month proposal would take into consideration only the dates of contract execution. As explained above, we must reject SCE's proposal for a 24-hour window and expand the window concept to consider whether negotiation of the two contracts occurred during the same window period. This expansion will cover contracts whose execution dates may be farther apart than the window-period. Accordingly, we conclude that a three-month-window period should be sufficient for contracts with specified generation sources, and that the same window period should apply to contracts with unspecified generation sources. This three-month window period represents a compromise between the one-day and six-month periods suggested by Edison, and is consistent with the use three-month periods used elsewhere in our procurement rules.
We now turn to consider one other detail of SCE's proposal that we decline to adopt. SCE proposes that in order for two "unspecified" contracts to be linked they must "specify the same delivery point." Because it is possible for power from the same plant (or group of plants) to be delivered to the LSE at different points, we conclude that such a requirement would make it too easy to evade the EPS by splitting up a single deal into two contracts with different delivery points. We will also modify SCE's proposal to substitute the word "powerplant" for the words "generating unit" to be consistent with the terminology we use throughout these EPS rules.
SCE's primary proposal for determining whether two contracts are "linked" is quite different from the proposal we have just been discussing. SCE suggests that if "two contracts are `independent' of each other, the Commission should not consider them to be `linked.' Two contracts are `independent' of each other if selection of one does not require selection of the other. That is, in order to be selected, each contract in a series of multiple contracts must `win on the merits.'" However, this proposal does not contain sufficiently clear guidelines to enable an LSE to determine if two contracts will be considered linked. Accordingly, we decline to adopt it.
However, the concept of "winning on the merits" does call to mind the utilities' RFO (Requests for Offers) procedures. And we think that one further modification to SCE's alternative proposal for dealing with "linkage" should be made to reflect those RFO procedures. Our concern has been that a single deal not be cut up into several contracts in order to avoid compliance with the EPS. The RFO procedures structure the utilities negotiation of contracts. Given that structure, we conclude that, under certain circumstances, even if two contracts are signed within three months of each other they should not be considered part of the same deal. More specifically, 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. In that situation it is clear that each contract was negotiated separately, and that they should therefore be treated as two separate deals. Conversely, if a bid on the second RFO is submitted before the first contract has been executed, it is possible that the two contracts might have been negotiated at the same time, and therefore the linkage rule should apply. Under some RFOs indicative bids are received first, followed by final bids; in other RFOs there are only final bids. In order to accommodate this variation we will require that the contract from the first RFO be executed before the LSE receives any bids (whether indicative or final).
LSEs might also attempt to circumvent the EPS by including an option for extension within a contract, rather than entering into a binding contract for a term of five years or more. For example, an LSE that wanted to enter into a seven-year contract with a non-compliant generator, might instead enter into a contract that required the LSE to purchase electricity for four years and also included an option to extend the contract for three more years. This is essentially a deal to purchase electricity for more than five years, and ought to be subject to the EPS screen. Accordingly, 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.
Putting all these concepts together and in a somewhat different format, we come up with the following rule:
For the purpose of determining the "term" of a contract under these EPS rules, two or more contracts, including contractual options, are 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).
Because parties expressed concern that they know, in advance, how the linkage rule will be applied, we will provide a number of examples, along with some explanation. For our first example, let us consider an LSE that enters into a contract for electricity from a specified powerplant for a two-month term, and repeatedly enters into additional contracts for electricity generated by the same powerplant, each with a term of two months commencing on the expiration of the prior contract. Although some of these contracts will be considered "linked," it is highly unlikely that a group of linked contracts will ever come close to the five-year term required for the EPS to be applicable. Two or more contracts are linked only where they are negotiated or executed within the same three-month period. Thus, in order for a group of linked contracts to have a five-year term, the contracts that are executed or negotiated within a single three-month period must have a final delivery date that is five or more years after the initial delivery date.218 In this first example (successive two-month contracts), it is likely that several of these contracts will be negotiated or executed within the same three-month period. However, it is highly unlikely that 30 of these successive contracts will have been negotiated or executed all within three months of each other, and unless they are, the total term of any group of linked contracts will not equal five years. In that case, the EPS will not apply.
For our second example, let us consider the situation where an LSE enters into a contract for 20% of the power from powerplant X, and the contract allows the seller to substitute power from powerplant Y, if X is unavailable. This contract is executed on 4/2/07, and has a term of three years, with delivery commencing on 1/1/09. On 5/15/07, the same LSE executes a contract for 15% of the power from powerplant Z, with substitute power to come from powerplant Y, if Z is unavailable. This second contract is for a term of four years, with delivery commencing on 1/1/11. These contracts are not linked. Although they were executed within three months of each other, they each specify a different powerplant as the primary delivery source. On the other hand, if both contracts specified that they were for power from powerplant X, with substitute power under the first contract coming from powerplant Y and under the second contract coming from powerplant Z, the two contracts would be linked. They would have been executed within three months of each other, and they would both specify the same powerplant as the primary delivery source. Furthermore, these linked contracts would have a term of five years or more, and therefore the EPS would apply. The first delivery would be on 1/1/09, and the final delivery is on 12/31/14. Thus the total term of these linked contracts would be six years. Finally, let us consider another variation on this scenario. Under this final variation both contracts designate powerplant X as the primary delivery source (even though they designate different powerplants as the source of substitute power), but the second contract has a term of only two years. Although the contracts are linked, the EPS would not apply, because the term of two contracts together is less than five years. (The first delivery would occur on 1/1/09, with the final delivery on 12/31/12.) The fact that the contracts were executed more than five years before the final delivery date is not relevant in determining the term of the contract.
For our next example, let us consider an LSE that uses an RFO procedure for soliciting contracts. The LSE puts out an RFO on 1/1/08. It receives bids on 2/1/08, and on 4/18/08 it executes a contract for unspecified sources with counter-party A. This contract has a term of four years with delivery commencing on 1/1/09. In the meantime, on 4/1/08 the LSE has put out a second RFO. No bids of any kind are received under this RFO until 5/1/08. Counter-party A submits a bid on 5/1/08. This bid is accepted by the LSE and results in a second contract for unspecified sources with counter-party A. This second contract is executed on 6/18/08 and has a term of four years, with delivery commencing on 1/1/10. These contracts are not linked, even though they were executed within three months of each other. This result is due to the provision of the linkage rule that says that two contracts are not linked if they are "entered into as a result of separate RFOs and the contracts from the earlier RFO are executed before the later RFO has received any bids". In this example, the first contract resulted from an RFO and was executed before any bids were received under the second RFO. Thus the EPS does not apply to these two contracts, because neither of them individually has a term of five years or more. On the other hand, if the first contract was executed on 5/5/08, after bids were received on the second RFO, the contracts would be linked and their combined term would be five years (first delivery on 1/1/09, final delivery on 12/31/13).
For our final example, we will consider two contracts that are negotiated within three months of each other, even though their execution dates are more than three months apart. On 6/5/07, the LSE begins discussions with counter-party B about several possible contracts for unspecified power. They quickly reach agreement about a contract with a four-year term and deliveries commencing 1/1/08. This contract is executed on 7/15/07. Their discussion about a second contract for unspecified power, with a three-year term and deliveries commencing on 1/1/10, drag on for a long time, as the parties have difficulty agreeing on a price term for a contract extending so far into the future. Eventually they do agree on a price term and execute this second contract on 12/15/07 (with a three-year term and deliveries commencing on 1/1/10). These two contracts are linked. The second contract was being negotiated at the same time as the first contract.219 The total term of these linked contracts is five years (first delivery on 1/1/08, final delivery on 12/31/12).
It is important to note that the linkage rule is only one 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." Thus, for example, if within a three-month period an LSE executes three contracts for the same specified source, that together have an initial delivery date of 1/1/08 and a final delivery date of 12/31/15 (and thus a total term of more than five years), but the source is not a "powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60 percent" then the EPS will not apply.
5.6. Definition of Capacity Factor
In their opening comments on the final report, EPUC/CAC request clarification of the definition of capacity factor to be used in the EPS baseload screen. They point out that SB 1368 defines baseload using the term "annualized plant capacity factor," whereas the staff report defines covered resources based on their "average annual" capacity factor. They suggest formally defining "annualized" as an "annual average." In particular, they propose that the capacity factor be calculated by summing the total annual energy "deliveries" of a resource, averaging them over the year, and then dividing that average by the plant's maximum permitted capacity.220
The Merriam-Webster Online Dictionary defines annualize as: "to calculate or adjust to reflect a rate based on a full year." We therefore find it reasonable to define the term "annualized" to mean "annual average" as EPUC/CAC suggest, but with a significant caveat. The annual average must be calculated in a manner that is consistent with today's decision, that is, it must be based on the annual production of the underlying facility, and not just what might be delivered under a specific contract with an LSE. As IEP points out, a strict interpretation of ECAC/CAC's proposed definition could result in partial year contracts being treated in a manner that conflicts with today's determinations.221
Moreover, 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 "designed and intended" to provide electricity at an annualized plant capacity factor of at least 60 percent. (§ 8340(a).) In fact, the definition of "plant capacity factor" provides for our 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." (§ 8340(l).) This makes sense, because a plant's operations may vary significantly from year to year, based on weather or economic conditions. However, if it were designed and intended to operate as baseload generation, under the law it is subject to the EPS. Therefore, in their showing of whether the EPS applies to a new long-term financial commitment (other than new plant construction), LSEs should include historical plant capacity factors for the underlying facility or facilities to document the annualized plant capacity factor.
Consistent with the above, the definition of plant capacity factor provided in SB 1368 and our definition of what constitutes a "powerplant," we clarify what is meant by "annualized plant capacity factor" as follows:
"An annualized plant capacity factor is the ratio of the annual amount of electricity produced, measured in kilowatthours, divided by the annual amount of electricity the powerplant could have produced if it had been operated at its maximum permitted capacity, expressed in kilowatthours."
We agree with EPUC/CAC's suggestion to use the term "permitted" in our definition of "plant capacity factor" to clarify what output should be used in the denominator of this equation (i.e., the maximum output designated by the manufacturer or the maximum output allowed under the operating permit). For this purpose, we believe that the maximum rated capacity allowed under the operating permit 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.
5.7. Long-Term Procurement Plans and the EPS
In our Long-Term Procurement Rulemaking (R.06-02-013), we directed SCE, PG&E and SDG&E to indicate in their long-term procurement plans (LTPPs) how they would comply with the EPS under consideration in this proceeding.222 Within sixty (60) days from the effective date of this decision, SCE, PG&E and SDG&E should update their LTPP filings in compliance with the adopted EPS rules, as necessary, to reflect today's determinations. If changes to the LTPP filing are necessary to show compliance with this decision, SCE, PG&E and SDG&E should 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. If additional rules related to GHG policy are adopted in the future, in between the biennial review process, SCE, PG&E and SDG&E should update their LTPPs using the standard procedure for amending those plans, i.e., currently they can update LTPPs in between the biennial review process via an Advice Letter filing.
We note that the Phase 2 Scoping Memo in R.06-02-013 did not require electric service providers and community choice aggregators to file LTPPs at this time.223 If that ruling changes for subsequent years of LTPP filings, then electric service providers and community choice aggregators will be required to include in their LTPPs how they plan on complying with the EPS rules.
5.8. Other Compliance-Related Issues
Today's decision provides direction to LSEs on how to submit their EPS compliance filings, and what information to include in them. 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. Moreover, any LSE may be audited if the Commission or staff has any doubt that the LSE is forthcoming in its demonstration of EPS compliance.
This includes any information on related contracts that the Commission or its staff may deem relevant in determining whether the LSE is circumventing the EPS rule by entering into multiple contracts of less than five years duration.224 This also includes any information on investments in retained generation, including deemed-compliant CCGTs, that the Commission or its staff may deem relevant in determining whether the LSE has complied with the interim EPS rules.
If any of the financial commitments entered into by LSEs appear to be out of compliance with the 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 the EPS, the Commission will address the level of penalties in the OII proceeding or other procedural forum, as it deems appropriate.
In complying with today's requirements, any LSE that seeks confidentiality protection for data contained in its EPS-related submittals must follow the policies and procedures set forth in D.06-06-066.
188 This section of the Public Utilities Code was added by AB 57 (Stats 2002, ch. 835), and applies to all electrical corporations. As provided for under § 454.5(i), electrical corporations serving less than 500,000 customers are exempt from this procurement plan review and approval process.
189 See D.03-06-071, p. 39, issued in R.04-04-026, the predecessor to our current RPS proceeding, R.06-05-027.
190 However, if the RPS advice letter process set forth in D.03-06-071 is modified to include procedures whereby these advice letters may be "deemed approved," such procedures shall not apply for the purpose of establishing EPS compliance.
191 Pursuant to D.02-10-062.
192 Currently, the smaller electrical corporations (e.g., Plumas-Sierra) and multi-jurisdictional utilities (Sierra Pacific Power Company (Sierra Pacific) and PacifiCorp) are not required to demonstrate resource adequacy compliance at this Commission. The resource adequacy rules for these entities are being developed in Phase 2 of R.05-12-013. See Assigned Commissioner's Ruling and Scoping Memo in R.05-12-013, March 1, 2006, p. 4.
193 Opening Comments/Legal Brief on Final Workshop Report and Staff Recommendations Regarding the GHG Performance Standard of NRDC/TURN/UCS/WRA, October 18, 2006, pp. 15-16, and Reply Comments on the Draft Workshop Report Regarding the GHG Performance Standard of NRDC/TURN/UCS/WRA, September 15, 2006, p. 5.
194 We may make that determination on a case-by-case basis requiring that the LSE present a showing for each individual commitment, or we may make a one-time, up front determination for specific resources or technologies, as we have today for certain renewable resource technologies.
195 The multi-jurisdictional utilities with less than 75, 000 California retail customers that receive Commission approval of alternate compliance under § 8341(d)(9) will not need to demonstrate EPS compliance at the Commission, and therefore would not be required to file an Attestation Letter. See Section 5.3 below.
196 See D.05-01-032, Appendix: Advice Letter Filing, Service, Suspension and Disposition. We are in the process of updating these procedures in R.98-07-038, and as indicated in Section 5.1 above, may also modify the advice letter process set forth in D.03-06-071 in the future. We recognize that some clarifications or modifications to procedures for the annual Attestation Letters and other advice letter compliance submittals adopted today may need to be made after the effective date of this decision in order to reconcile them with updated Commission procedures for advice letters in R.98-07-038 or R.06-05-027, or their successor proceedings. We delegate to the Assigned Commissioner the authority to make such clarifications or modifications by ruling or other manner, in consultation with the assigned ALJ and Energy Division.
197 Opening Comments of the City of San Francisco on the Proposed Decision, January 2, 2007, p. 10.
198 However, no such advice letter shall be "deemed approved."
199 We see no reason to put this policy decision off for another day as suggested by NRDC. (Opening Comments of NRDC on Final Staff Workshop Report. October 18, 2006, p. 8.) We agree with Sierra Pacific and PacifiCorp that we should now determine what constitutes a showing of alternative compliance, so as to facilitate their preparation of the resource plans that they will be presenting to several public utilities commissions.
200 Opening Comments of PacifiCorp on Draft Staff Workshop Report, September 8, 2006, p. 3.
201 Reply Comments of PacifiCorp on Final Staff Workshop Report, October 27, 2006, p. 5.
202 See Opening Comments of Sierra Pacific Power Company on Final Staff Workshop Report, October 18, 2006, pp. 3-4.
203 Id.
204 Moreover, Sierra Pacific stated in its comments that its 2007 Integrated Resource Plan, which will be filed with the Nevada Public Utilities Commission, is subject to review pursuant to Nevada Administrative Code § 704.9359 which requires Sierra to review and quantify environmental costs from air emissions. (Sierra Pacific Opening Comments to Staff Final Workshop Report, p. 4). This code section may satisfy part B's "review" standard independent of Nevada's emissions disclosure requirement.
205 Opening Comments of PacifiCorp on Final Staff Workshop Report, October 18, 2006, p. 6.
206 Reply Comments of PacifiCorp on Final Staff Workshop Report, October 27, 2006, p. 5.
207 Pursuant to Rule 13.9 of the California Public Utilities Commission Rules of Practice and Procedure, we may enter other state's agency's official orders into the record by official notice. We hereby take notice of Oregon PUC Order 07-002 (Investigation Into Integrated Resource Planning (Disposition: Guidelines Adopted; Rulemaking and Investigation Opened), January 8, 2007).
208 An "allowance" refers to a permit provided to the LSE within the scope of the emissions cap to emit one unit of emissions (e.g., tons of CO2). The total number of available allowances reflect the total amount of permissible emissions, and usually decline over time. Allowances are allocated administratively or by auction to the entities subject to the cap.
209 AB 32, § 38562(c).
210 AB 32, § 38561, § 38570.
211 D.06-02-032, p. 44.
212 With the exception of Sierra Pacific and PacifiCorp, both of which have made a satisfactory showing that they meet SB 1368's alternative compliance requirements. (See Section 5.3.) Their annual advice letters are not required to include the information contained in this section but rather, each should attest that the utility still meets the alternative compliance requirements described herein.
213 Pursuant to D.02-10-062.
214 Comments of PG&E on Draft Workshop Report, September 8, 2006, p. 4.
215 This is because as the plant output decreases, the corresponding heat rate (Btu/kWh) increases, and emissions are proportional to heat rate for the same fuel type.
216 Namely, 15 degrees Celsius (59 degrees Fahrenheit), 1 atmosphere of pressure (sea level, or 14.7 psi or 101.3 kPa), and 60 percent relative humidity.
217 Opening Comments of SCE on the Proposed Decision, January 2, 2007, p. 9.
218 See section 4.2.4 above, explaining how to determine the "term" of a contract.
219 Under this linkage rule, two contracts are linked so long as some of the negotiation for one of the contracts occurs within 3 months of the execution of the other.
220 Opening Comments of EPUC/CAC on the Final Workshop Report, October 18, 2006, p. 11.
221 See Reply Comments and Legal Brief of the Independent Energy Producers Association on the Final Staff Workshop Report, October 27, 2006, p. 5.
222 Assigned Commissioner's Ruling and Scoping Memo on the Long-Term Procurement Phase, R.06-02-013, September 25, 2006, p. 24.
223 Ibid., p. 36.
224 Other "slicing and dicing" concerns discussed during the workshop process and in the draft and final recommendations (see final report at page 102) have become moot with today's determinations on size exemptions and the treatment of partial contracts.
