II. DISCUSSION

A. Commission Jurisdiction over CCAs

CCSF alleges that the Commission exceeded its jurisdiction in requiring CCAs to undertake CHP purchases to meet GHG targets and directing the investor owned utilities ("IOUs") to undertake the purchases on the CCAs' behalf.

The Settlement Agreement establishes GHG Emissions Reduction Targets based on the GHG reductions attributable to CHP in the California Air Resources Board ("CARB") Scoping Plan. The targets are allocated to the IOUs, ESPs, and CCAs based on the current percentage of retail sales in California. The Settlement Agreement provides that the non-IOU load-serving entities ("LSEs") will achieve these targets by entering into CHP power purchase agreements ("PPAs") or, in the alternative, that the IOUs will procure the appropriate amount of CHP for the non-IOU LSEs and that the net capacity costs of this procurement will then be allocated to the customers of the non-IOU LSEs. The Decision adopts the latter option based on concerns raised regarding the ability of ESPs and CCAs to procure CHP resources and based on the reduced administrative burden of the approach. (D.10-12-035, p. 56.)

CCSF alleges that the Commission based its determination that it had jurisdiction to require ESP and CCA participation in the QF/CHP Program on six mistaken grounds: (1) Public Utilities Code section 365.1(c)(1);² (2) the CARB scoping plan; (3) section 365.1(c)(2); (4) section 366.2(f)(2); (5) Opinion on New Generation and Long-Term Contract Proposals and Cost Allocation [D.06-07-029] (2006) __Cal.P.U.C.3d __; and (6) Opinion on Procurement Incentives Framework
[D.06-02-032] (2006) __Cal.P.U.C.3d __. CCSF also alleges that the Commission's determination is inconsistent with Commission precedent regarding CCAs. For the reasons discussed below, the Commission has the jurisdiction to allocate GHG emissions reduction targets to CCAs and ESPs, to require the IOUs to procure CHP resources on behalf of the non-IOU LSEs, and to allocate the costs and benefits associated with this procurement to IOU, CCA, and ESP customers. Therefore, CCSF fails to demonstrate that the Commission exceeded its jurisdiction.

1. Section 365.1(c)(1)

CCSF alleges that the Decision relies on section 365.1(c)(1) to direct CCAs to undertake CHP purchases. According to CCSF, reliance on this section to direct CCAs to procure CHP resources is unlawful because CCAs are exempt from the requirements of section 365.1(c)(1). (CCSF Rehrg. App., p. 7.) Section 365.1(c)(1) requires the Commission to ensure that "other providers" are subject to the same requirements applicable to the IOUs relating to resource adequacy ("RA"), the renewables portfolio standard ("RPS") program, and CARB's requirements for the electricity sector adopted pursuant to Assembly Bill ("AB") 32 (Stats. 2006, ch. 488). CCSF is correct that CCAs are excluded from the definition of "other provider," and therefore, the Commission is not required to ensure that these requirements apply to CCAs. (See Pub. Util. Code,
§ 365.1, subd. (a).)³ However, CCSF is mistaken that the Decision references section 365.1(c)(1) in relation to CCAs. The Decision only references section 365.1(c)(1) in relation to ESPs. (D.10-12-035, p. 47.) Therefore, CCSF does not demonstrate any legal error on this issue. As discussed further below, there are other bases for the Commission's jurisdiction to allocate the GHG emissions reduction targets and costs of the QF/CHP program to CCAs.

2. CARB Scoping Plan

CCSF alleges that the Decision improperly creates a legal requirement to procure CHP out of CARB's Scoping Plan. CCSF further alleges that with respect to CCAs, the Commission does not have jurisdiction to impose CARB-based GHG requirements on CCAs. (CCSF Rehrg. App., p. 7.)

As stated above, section 365.1(c)(1) requires the Commission to ensure that "other providers" are subject to the same requirements applicable to the IOUs relating to CARB's requirements for the electricity sector adopted pursuant to AB 32. The CARB Scoping Plan, which CARB adopted pursuant to AB 32, states: "[CARB] approved this Scoping Plan at its December 11, 2008 meeting, providing specific direction for the State's greenhouse gas emissions reduction program. The recommended measures will be developed into regulations over the next two years, to go into effect by January 1, 2012." (CARB Scoping Plan, p. 1.)

CCSF argues that CARB's statement that it will develop measures in its Scoping Plan over the next two years does not turn the CHP target in the Scoping Plan into a requirement for the purposes of section 365.1(c)(1). AB 32 required CARB to issue a scoping plan. (Health and Safety Code, § 38561.) Although the recommended measures in the Scoping Plan are not yet binding, CARB contemplates that the recommended measures will be developed into regulations. The Decision allocates CHP targets consistent with the CHP targets in CARB's Scoping Plan but also provides for adjustments to the targets depending on what CARB ultimately adopts in its regulations and so long as the modifications are approved by the Commission in the long term procurement plan ("LTPP") proceeding.⁴ (Term Sheet, § 6.7.) To the extent that the Settlement Agreement implements the CHP targets adopted by CARB, section 365.1(c)(1) requires the Commission to impose the same requirements applicable to the IOUs on "other providers."

As discussed further below, even apart from SB 695, we possess the authority to allocate GHG emissions reduction targets to ESPs and CCAs. CCSF does not identify anything in SB 695 that limits our authority in this area. In exercising this authority, we adopted the Settlement Agreement, which provides that the CHP targets are consistent with the targets currently recommended by CARB and provides for adjustments to those targets if CARB adjusts its CHP targets. CCSF fails to demonstrate that the Commission lacks jurisdiction to do so.

3. Section 365.1(c)(2)

CCSF argues that the Commission's reliance on section 365.1(c)(2) to require CCAs to procure CHP is flawed as that section only deals with cost recovery. (CCSF Rehrg. App., p. 8.) This argument lacks merit. Section 365.1(c)(2) provides that where the Commission authorizes an electrical corporation to obtain generation resources that the Commission determines are needed to meet system or local area reliability needs for the benefit of all customers in the electrical corporation's distribution service territory, the net capacity costs of those generation resources are to be allocated to bundled, ESP, and CCA customers. The Decision requires the IOUs to procure CHP resources on behalf of bundled, CCA and ESP customers, allows the IOUs to recover the net capacity costs of this procurement from CCA and ESP customers, and requires the associated resource adequacy benefits to be allocated to CCAs and ESPs. This arrangement fits squarely within the purview of section 365.1(c)(2).

CCSF disputes that CHP resources procured under the settlement agreement are needed to meet system or local reliability for the benefit of all customers in the electrical corporation's distribution service territory. (CCSF Rehrg. App., pp. 13-14.) CCSF argues that the question of whether there is a system or local area reliability need in the IOUs' service territories is currently being examined in the LTPP proceeding (Rulemaking (R.) 10-05-006) and that it is premature for the Commission to conclude that the CHP resources procured pursuant to the Settlement Agreement are needed. (CCSF Rehrg. App., p. 14.)

In the current LTPP proceeding, R.10-05-006, we are considering system or local resource adequacy needs over the 2011-2020 planning horizon. However, in an earlier LTPP proceeding, R.06-02-013,⁵ we adopted LTPPs for PG&E, SDG&E, and Edison for the ten-year period from 2007 through 2016. With regard to QF capacity, the Commission required the IOUs to maintain their current QF capacity over the next decade. (Opinion Adopting PG&E's, Edison's, and SDG&E's Long-Term Procurement Plans [D.07-12-052], (2007) __Cal.P.U.C.3d __, p. 85 (slip op.).) The IOUs' QF capacities were recorded as 2,166 MW for PG&E; 4,162 MW for SCE; and 270 MW for SDG&E. (Ibid.)

The procurement obligations set forth in the Settlement Agreement and under the RPS program supersede and replace the QF MW requirements adopted in D.07-12-052. (Term Sheet, § 16.2.6.) The Settlement Agreement contemplates different procurement targets based on different time periods. During the initial program period, which starts with the settlement effective date and ends 48 months thereafter, the Settlement Agreement adopts MW targets of 1,402 MW for SCE; 1,387 MW for PG&E; and 160 MW for SDG&E. (Term Sheet, § 5.1.2.) During the second program period, which starts at the end of the initial program period and ends on December 31, 2020, with the exception of SDG&E, there are no established MW targets but rather GHG emissions reduction targets.⁶ (Term Sheet, § 5.1.4.6.) The Settlement Agreement states that the MW targets for the second program period shall be established in the LTPP proceeding. (Term Sheet, § 2.3.2.3.) The Settlement Agreement provides that the GHG emissions reduction targets may also be reviewed and revised in the LTPP proceeding. (Term Sheet, § 6.6)

Consistent with section 365.1(c)(2), the only resources procured pursuant to the Settlement Agreement will be resources that we have determined are needed for system and local reliability. The MW targets set forth in the Settlement Agreement, and adopted in the Decision, do not exceed the MW targets the Commission already determined were required in the previous LTPP proceeding. With regard to any procurement relating to the GHG emissions reduction targets for the second program period, the Settlement Agreement already provides that those MW targets will be established by the Commission in the LTPP proceeding. Moreover, the Settlement Agreement provides that a lack of need would justify an IOU not meeting the GHG emissions reduction targets. (Term Sheet, § 6.9.3.) Therefore, if there is a demonstration that CHP resources are not needed during the second program period, the IOUs would not be required to procure these resources and there would be no costs to be allocated to CCA or ESP customers.

CCSF alleges that there is no record support for the conclusion that CHP resources provide reliability benefits. (CCSF Rehrg App., pp. 14-15.) However, as explained in the Decision, CHP resources benefit all customers because they count toward RA requirements and provide system and local area reliability benefits commensurate with their Net Qualifying Capacity. (D.10-12-035, p. 66 [Conclusion of Law 12].) RA requirements ensure that LSEs, including the IOUs, ESPs, and CCAs, have procured sufficient generation capacity in order to assure electric system reliability. (Interim Opinion Regarding Resource Adequacy [D.04-10-035] (2004) __Cal.P.U.C.3d __, pp. 3-4 (slip op.).) Therefore, to the extent that CHP provide RA credits, they provide system and local area benefits.

Furthermore, as noted in section one of the Settlement Agreement entitled "Goals and Objectives," CHP resources provide reliability benefits. Among other things, this section states that CHP resources provide: grid reliability and/or local area reliability, including self-service of power supply for facilities' loads in resource-constrained areas (Term Sheet, § 1.2.4.3); a reduction in transmission and distribution energy losses (Term Sheet, § 1.2.4.4); a diversified portfolio of resources for California generation supply (Term Sheet, § 1.2.4.5); and support for California's manufacturing, industrial and commercial base without cross subsidization by electric customers (Term Sheet,
§ 1.2.4.6).

Evidence in the consolidated proceedings supports the reliability characteristics of CHP resources set forth in the "Goals and Objectives" section of the Settlement Agreement. Evidence supports that CHPs operate reliably during high demand and emergency situations. (R.04-04-003/R.04-04-025 - CCC Exh. 102, Beach Direct Testimony, 14:16-15:9; R.04-04-003/R.04-04-025 - CAC/EPUC Exh. 134, Ross and Schoenback Direct Testimony, 18:15-23.) Many CHP are located in load centers and therefore reduce transmission and distribution losses, and provide stability and reliability to the state's electric grid. (R.04-04-003/R.04-04-025 CCC - Exh. 102, Beach Direct Testimony, 15:11-16:5; R.04-04-003/R.04-04-025 - CAC/EPUC Exh. 134, Ross and Schoenback Direct Testimony, 19:20-20:7.) Evidence supports that reliability of CHP resources compares favorably to that of other baseload resources. (R.04-04-003/

R.04-04-025 - CAC/EPUC Exh. 134, Ross and Schoenback Direct Testimony, 19:3-17.)

As noted in the Settlement Agreement, the state has recognized that CHP enhances the reliability of local generation supply. (See Pub. Util. Code, § 372, subd. (a).) The Energy Action Plan II ("EAP II") identifies CHP as a preferred loading order resource.⁷ The California Energy Commission ("CEC") in its 2005 Integrated Energy Policy Report ("IEPR") observed that: "[c]ogeneration, or combined heat and power (CHP), is the most efficient and cost-effective form of [distributed generation], providing numerous benefits to California including reduced energy costs, more efficient fuel use, fewer environmental impacts, improved reliability and power quality, locations near load centers, and support of utility transmission and distribution systems." (2005 IEPR, p. 76.)⁸ CCSF also acknowledges that it supports the increase use of CHP resources. (See CCSF Rehrg. App., p. 3.)

For the foregoing reasons, section 365.1(c)(2) applies to the procurement authorized in the Decision, and this statute authorizes the Commission to allocate the net capacity costs of this procurement to bundled, ESP, and CCA customers. Although the provisions in the Settlement Agreement support that the only resources procured pursuant to the QF/CHP program are those that we determine are needed for system and local reliability, the Decision may not be quite clear on this point. Therefore, we will modify the Decision, as set forth in the ordering paragraphs below, to include this additional explanation.

4. Section 366.2(f)(2)

CCSF argues that the Commission's reliance on section 366.2(f)(2) to require CCAs to procure CHP is flawed as that section only deals with cost recovery. (CCSF Rehrg. App., p. 8.) However, the Decision does not rely on this statutory provision as a basis for requiring CCAs to procure CHP resources. Section 366.2(f)(2) authorizes the Commission to approve cost recovery for net unavoidable electricity purchase contract costs attributable to former IOU customers purchasing electricity from a CCA. The Decision cites to that section in support of the proposition that CCA customers should be responsible for their fair share of the costs of the QF/CHP Program. (D.10-12-035, pp. 48-49.) CCSF fails to explain how this constitutes legal error.

5. D.06-07-029

CCSF argues that the Decision's reliance on D.06-07-029 is flawed as this particular decision only provided for cost recovery from ESP and CCA customers and did not direct ESPs or CCAs to undertake particular procurement. (CCSF Rehrg. App., pp. 8-9.) CCSF also argues that the cost recovery set forth in D.06-07-029 is no longer relevant as it has been superseded by section 365.1. (CCSF Rehrg. App., p. 9.)

The Decision cites D.06-07-029 as an example of a previous Commission decision that determined that direct access ("DA") and CCA customers who benefit from procurement should pay their fair share of the procurement costs. (D.10-12-035, p. 49.) Similarly, as adopted, the Settlement Agreement, requires DA and CCA customers to pay for CHP procurement undertaken on their behalf. ESPs and CCAs receive benefits from this procurement, including the associated RA benefits. CCSF fails to demonstrate that the Decision's reference to D.06-07-029 was in error.

Furthermore, the Decision does not adopt the cost recovery set forth in D.06-07-029. Therefore, CCSF's argument that the cost recovery set forth in

D.06-07-029 has been superseded by section 365.1 is irrelevant.⁹ CCSF does not point to anything in SB 695 that superseded the principle articulated in D.06-07-029 that DA and CCA customers who benefit from procurement should pay their fair share of the procurement costs.¹⁰

6. Jurisdiction relating to GHG Reductions

The Decision notes that the Commission previously determined in
D.06-02-032, as affirmed in Order Denying Rehearing of Decision 06-02-032
[D.06-06-071] (2006) __Cal.P.U.C.3d __, that it had jurisdiction to regulate ESP and CCA procurement activities related to GHG. (D.10-12-035, pp. 49-50.) CCSF argues that D.06-02-032 does not provide authority for the Commission to impose GHG-related procurement obligations on CCAs. CCSF argues that AB 32 and SB 695, which were enacted after the issuance of D.06-02-032, superseded the decision. According to CCSF, AB 32 and SB 695 dictate that CARB is the state entity with jurisdiction over reduction of GHG emissions. (CCSF Rehrg. App., p. 9.)

AB 32 does not confer exclusive jurisdiction on CARB in the state's implementation of a GHG reduction program. AB 32 charges CARB with monitoring and regulating sources of emissions of GHG. (See Health and Safety Code, § 38510). However, AB 32 also states that: "Nothing in this division affects the authority of the Public Utilities Commission." (Health and Safety Code, § 38593(a).) AB 32 further provides that: "Nothing in this division shall limit the existing authority of a state entity to adopt and implement greenhouse gas emissions reduction measures." (Health and Safety Code, § 38598(a).) CARB itself acknowledges that: "AB 32 does not affect the existing authority of other state agencies, and in addition to [CARB], many state agencies will be responsible for implementing the measures and strategies in [the Scoping Plan]." (CARB Scoping Plan, pp. 6-7.)

AB 32 also acknowledges that the Commission's requirements for electricity and natural gas providers under its jurisdiction may overlap with CARB's regulation of GHG emissions. AB 32 states:

It is the intent of the Legislature that the State Air Resources Board consult with the Public Utilities Commission in the development of emissions reduction measures, including limits on emissions of greenhouse gases applied to electricity and natural gas providers regulated by the Public Utilities Commission in order to ensure that electricity and natural gas providers are not required to meet duplicative or inconsistent regulatory requirements.

(Health and Safety Code, § 38501(g).) The Legislature neither prohibited our regulation of issues relating to GHG reductions nor required that CARB's regulations supersede the Commission's regulations where there was a conflict. Rather, the Legislature required CARB to consult with the Commission.

In D.06-02-032, as affirmed by D.06-06-071, we determined that the issue of reduction of GHG emissions was intrinsically linked to our authority to regulate RA requirements and RPS.¹¹ (D.06-02-032, p. 25 (slip op.); D.06-06-071, pp. 17-18 (slip op.).) We also determined that we had the jurisdiction to regulate GHG emissions pursuant to section 701, which authorizes us to "do all things, whether designated in [the Public Utilities Code] or in addition thereto, which are necessary and convenient" in the exercise of [our] power and jurisdiction" over public utilities. (D.06-02-032, pp. 20-21 & 25 (slip op.); D.06-06-071, pp. 19-20 (slip op.).)

It is reasonable to conclude that the Legislature was aware of the Commission's decisions issued prior to the enactment of AB 32. Had the Legislature intended to restrict our authority to regulate GHG emissions, it could have done so. However, in AB 32, the Legislature preserved the authority of the Commission, as well as the existing authority of state entities to adopt and implement GHG emissions reduction measures. In fact, AB 32 recognizes that the Commission's regulation of public utilities relates to the issue of GHG emissions reductions. (See Health and Safety Code, § 38501, subd. (g).) Therefore, unless there is a direct conflict between AB 32 and the Commission's regulation of procurement activities relating to GHG reductions, this legislation does not otherwise limit the Commission's jurisdiction in the area of GHG reductions.

CCSF also fails to demonstrate that SB 695 limited the Commission's authority to allocate certain GHG emissions reduction targets to CCAs. SB 695 merely requires that the Commission ensure that "other providers" are subject to the same requirements applicable to the three largest IOUs relating to RA requirements, RPS, and CARB's requirements adopted pursuant to AB 32. (Pub. Util. Code, § 365.1, subd. (c)(1).) Contrary to CCSF's contention, this language does not set forth the respective roles of CARB and the Commission as to GHG regulation. (See CCSF Rehrg. App., p. 9, fn. 12.) SB 695 does not discuss, let alone limit, the Commission's jurisdiction to regulate reduction of GHG emissions. Furthermore, nothing in the statute prohibits the Commission from imposing requirements on CCAs.¹²

For the foregoing reasons, CCSF fails to demonstrate that either AB 32 or SB 695 superseded the Commission's determination in D.06-02-032 regarding its jurisdiction to regulate GHG emissions insofar as it is related to its regulation of public utilities. To the contrary, AB 32 preserves the Commission's existing authority to regulate reduction of GHG emissions. Therefore, there are no grounds for granting rehearing on this issue.

7. Commission Precedent Regarding CCAs

According to CCSF, Commission precedent recognized that our jurisdiction over CCAs is limited to a few areas. CCSF alleges that the Decision departs from this precedent, which is arbitrary and capricious, and contrary to public policy. (CCSF Rehrg. App., p. 10.)

According to CCSF, the Commission's jurisdiction over CCAs was established in Decision Resolving Phase 2 Issues on Implementation of Community Choice Aggregation Program and Related Matters [D.05-12-041] (2005) __Cal.P.U.C.3d __. (CCSF Rehrg. App., p. 11.) D.05-12-041 discusses our jurisdiction over CCAs in the context of implementing AB 117's (Stats. 2002, ch. 838) requirements. However

D.05-12-041 also notes that: "Other [statutes] and our own decisions have addressed other areas of jurisdiction over CCAs and ESPs...." (D.05-12-041, p. 8, fn. 3 (slip op.).) Therefore, D.05-12-041 did not address all areas of our jurisdiction over CCAs, and there is no merit to CCSF's allegation that the Commission's jurisdiction is limited to the areas discussed in that decision. For example, in addition to the areas of jurisdiction over CCAs conferred on it by AB 117, the Commission has jurisdiction over areas including, but not limited to, the RPS program, resource adequacy requirements, and cost allocation. (See e.g. Pub. Util. Code, §§ 399.11 et seq., 380, & 365.1, subd. (c)(2).)

The provisions of the Settlement Agreement are consistent with Commission precedent relating to CCAs. For example, in D.06-02-032, we determined that we had jurisdiction over CCAs on GHG-related issues because it was linked to our authority to regulate RA requirements and RPS. (D.06-02-032, p. 25 (slip op.).) Furthermore, in D.06-07-029, we determined that CCA customers should pay their fair share of procurement costs. (D.06-07-029, p. 56 [FOF 19] (slip op.).) Therefore, CCSF's allegation that the Decision departs from Commission precedent regarding jurisdiction over CCAs lacks merit.

B. Cost-Recovery

1. Adoption of CAM Cost Recovery

CCSF alleges that the Decision erred in adopting cost allocation mechanism ("CAM") cost recovery as opposed to vintaged cost recovery for CHP resources procured by the IOUs pursuant to the Settlement Agreement. CCSF alleges that our adoption of the CAM in this case is unjustified, unsupported by applicable statutes, and contrary to Commission precedent. (CCSF Rehrg. App., p. 12.)

The Settlement Agreement set forth two alternatives for allocating the costs of the QF/CHP Program. (Term Sheet, § 13.1.2.) If the Commission required ESPs and CCAs to procure CHP resources on behalf of their customers, the Settlement Agreement provided that the above-market costs of the IOU portion of the program would be allocated to future DA, CCA, and departing load customers with the exception of CHP departing load, on a vintaged basis. (Term Sheet, § 13.1.2.1.) Alternatively, if the Commission required the IOUs to procure CHP resources on behalf of DA and CCA customers, then the net capacity costs associated with the program would be recovered from all bundled, DA, CCA, and departing load with the exception of CHP departing load, on a nonbypassable basis. (Term Sheet, § 13.1.2.2.)

The Decision provides that the IOUs shall procure CHP resources on behalf of non-IOU LSEs and that the net capacity costs and associated benefits shall be allocated as described in section 13.1.2.2 of the Term Sheet. (D.10-12-035, p. 56.) For the reasons discussed above and in the Decision, section 365.1(c)(2) applies to this procurement and this statute authorizes allocation of net capacity costs on a fully nonbypassable basis while the associated RA credits are allocated to the ESPs and CCAs.

CCSF argues that the meaning of and standards for implementing section 365.1(c)(2) are being considered in the LTPP proceeding, R.10-05-006, and therefore, that it is premature for the Commission to conclude that section 365.1(c)(2) applies to the CHP resources procured pursuant to the Settlement Agreement. (CCSF Rehrg. App.,
p. 15.) In R.10-05-006, the ALJ directed interested parties to file comments on how, if at all, existing procurement rules should be modified or refined to comply with the resource adequacy provisions of SB 695. (ALJ's Ruling on Implementation of SB 695 and the Cost Allocation Mechanism (Track III) in R.10-05-006, dated September 15, 2010, at
p. 1.)

The fact that the Commission is considering how existing procurement rules should be modified, if at all, based on SB 695 does not necessarily preclude application of SB 695 in this proceeding. It is unclear that any modification to the D.06-07-029 CAM would affect cost recovery of the CHP resources procured pursuant to the QF/CHP program since these resources were not subject to cost recovery under the D.06-07-029 CAM. Further, neither the statute nor Commission decisions require implementation of section 365.1(c)(2) only in the LTPP proceeding. Outside of R.10-05-006, we have previously authorized utilities to recover net capacity costs pursuant to section 365.1(c)(2) where a resource was found to meet system or local area reliability needs. (See Decision on PG&E's 2008 Long-Term Request for Offer Results and Adopting Cost Recovery and Ratemaking Mechanisms [D.10-07-045] (2010) __Cal.P.U.C.3d __, pp. 46 & 50 (slip op.).)

CCSF also argues that CAM cost recovery for CHP resources is inconsistent with Commission precedent. This allegation lacks merit. Adoption of a CAM cost recovery is appropriate because, as it did in D.06-07-029, in this proceeding the Commission directed the IOUs to procure resources on behalf of the non-IOU LSEs. The Commission determined that ESPs and CCAs should pay their fair share for the CHP program. The Commission also determined that the IOUs should procure CHP resources on behalf of the non-IOU LSEs due in part to concerns regarding the ability of ESPs and CCAs to procure CHP resources. (D.10-12-035, pp. 56 & 64 [FOF 31].) In D.06-07-029, the Commission adopted a CAM for resources that the Commission directed the IOUs to procure on behalf of CCAs and ESPs. (D.06-07-029, p. 56 [FOF 19] (slip op.).) Similarly, it is reasonable to allocate net capacity costs and associated benefits to CCAs and ESPs in this case.

In D.08-09-012, the Commission adopted vintaged cost recovery for stranded new generation costs that result from departing load. (D.08-09-012, p. 108 [Ordering Paragraph 10] (slip op.).) CCSF fails to explain why vintaged cost recovery would apply where the IOUs are procuring on behalf of CCAs and ESPs. CCSF contends that a vintaged cost recovery regime "sensibly recognizes that once customers depart from IOU service, IOUs should adjust their procurement activities to account for that fact...." (CCSF Rehrg. App., p. 16.) However, since the IOUs are procuring CHP resources not only on behalf of bundled customers, but also on behalf of CCAs and ESPs, the IOUs' procurement activities would not require any adjustment due to any departing load. The two alternatives for cost allocation set forth in the Settlement Agreement appropriately recognize that vintaged cost recovery is relevant where the IOUs are not purchasing on behalf of CCAs and ESPs, while CAM cost recovery is relevant where the IOUs are purchasing on behalf of CCAs and ESPs. (See Term Sheet, § 13.1.2.)

CCSF argues that in D.08-09-012 the Commission declined to extend the CAM to QF contracts. CCSF states that the Decision provides no basis for its departure from D.08-09-012. (CCSF Rehrg. App., p. 17.) Unlike the procurement at issue in the Decision, the QF contracts at issue in D.08-09-012 did not involve procurement that the Commission required the IOUs to procure on behalf of CCAs and ESPs. Furthermore, the cost allocation methodology adopted in the Decision is not identical to the CAM that was adopted in D.06-07-029. For instance, unlike in the Decision, the D.06-07-029 CAM involved an energy auction process. In D.08-09-012, one of the reasons the Commission declined to extend the D.06-07-029 CAM to new QF contracts was that cost recovery under the CAM did not make sense due to the costs and requirements associated with the energy auction process. (D.08-09-012, p. 37 (slip op.).) This rationale does not apply in this case.

For the foregoing reasons, CCSF fails to demonstrate any legal error regarding the authorization of CAM cost recovery in this case.

2. Extension of Cost Recovery to Twelve Years

CCSF alleges that the Decision departs from Commission precedent by approving provisions in the Settlement Agreement that extend cost recovery for CHP resources from ten years to twelve years. CCSF alleges that the Decision does not provide justification for this departure, and is arbitrary and capricious. (CCSF Rehrg. App., pp. 18-19.)

The Settlement Agreement provides that some PPAs under the QF/CHP Program can have a duration of up to twelve years. (Term Sheet, § 4.2.3.2.) The Decision finds that it is appropriate to extend the ten year cost recovery in D.08-09-012 to twelve years to ensure recovery of the QF/CHP Program costs that will be incurred over the entire term of the PPAs.¹³ (D.10-12-035, p. 51.) The Decision also observes that the Commission previously extended the ten year limitation in other areas, most notably for RPS contracts, which may be recovered over the life of the PPA. (D.10-12-035, p. 51.)

CCSF alleges that in the past, Commission extended the ten-year cost recovery limitation only after analysis of each individual contract and that therefore, there is no basis that an extension is appropriate categorically in the case of CHP. (CCSF Rehrg. App., p. 19.) This allegation lacks merit because we previously categorically exempted RPS contracts from the ten year limitation. In Opinion Adopting PG&E, Edison, and SDG&E's Long-Term Procurement Plans [D.04-12-048] (2004) __Cal.P.U.C.3d __, we noted that we had authorized RPS contracts with terms for up to twenty years in order to encourage the development of those resources and that therefore, RPS contracts were exempt from the ten year limitation on cost recovery. (D.04-12-048, p. 63 (slip op.).) In light of the goals and benefits of the CHP/QF program, and the state's policy to encourage development of CHP, it is likewise reasonable to extend cost recovery to the entire term of the PPAs to ensure full recovery for the CHP/QF program costs.

C. Standards Governing Settlements

CCSF alleges that the Decision errs because it fails to properly apply the heightened standard for settlement agreements that do not include all parties because: (1) provisions of the Settlement Agreement that apply to CCAs are not in the public interest in that they are uncompetitive; and (2) the cost recovery provisions in the Settlement Agreement are contrary to the public interest. (CCSF Rehrg. App., pp. 19-21.)

Rule 12.1(d) of the Commission's Rules of Practice and Procedure provides that "[t]he Commission will not approve settlements, whether contested or uncontested, unless the settlement is reasonable in light of the whole record, consistent with law, and in the public interest." Because the Settlement Agreement was not an all-party settlement, the Commission found that it was appropriate to apply a heightened standard of review for settlement agreements that do not include all parties. The heightened standard of review requires the Commission to consider the proposed settlement as a whole and its individual elements, in order to determine whether it balances the various interests at stake, as well as to assure that each element is consistent with the Commission's policy objectives and the law. (D.10-12-035, p. 27.)

CCSF does not demonstrate that the Decision fails to apply the heightened standard for settlement agreements. The Commission considered how the Settlement Agreement affects CCAs and ESPs and found that it provides for the equitable allocation of costs associated with the QF/CHP program to all Commission-jurisdictional LSEs.
(D.10-12-035, p. 58, see also discussion at II.A.3, supra.) The Commission explained that it is consistent with Commission precedent to recover costs from CCA and DA customers for procurement from which they benefit. (D.10-12-035, p. 49.) The Commission also reiterated its previously expressed policy that "it is imperative that GHG reduction goals and responsibilities be shared as broadly as possible."
(D.10-12-035, p. 49 citing D.06-02-032, at p. 26 (slip op.).) The Commission also noted that exempting ESPs and CCAs from GHG-related requirements would give these LSEs an improper competitive advantage over the IOUs. (D.10-12-035, p. 50.) Although CCSF may disagree with how the Commission balanced the interests of the CCAs and ESPs as a policy matter, they fail to demonstrate any legal error on this issue.

In addition to issues relating to CCAs and ESPs, the Commission found other elements of the Settlement Agreement, and the Settlement Agreement as a whole, to be in the public interest. The Decision explains the many public interest benefits of the Settlement Agreement. (See e.g. D.10-12-035, pp. 56-58.) Among other things, the Settlement Agreement resolves numerous past and ongoing disputes regarding QFs, and establishes a framework for a QF/CHP Program that advances state policies encouraging efficient CHP operations and promoting GHG emissions reductions. CCSF does not dispute these other benefits of the QF/CHP Program.

For the foregoing reasons the Commission properly considered the Settlement Agreement as a whole and its individual elements, and properly applied the heightened standard of review.

D. Request for Oral Argument

CCSF requests oral argument pursuant to Rule 16.3 of the Commission's Rules of Practice and Procedure. CCSF alleges that oral argument will materially assist the Commission in resolving the issues raised in its rehearing application because it will allow CCSF to present to the Commission the "significant legal errors" in the Decision. CCSF also alleges that the Decision is of major significance because it is the first decision to rely on section 365.1(c)(2) for cost recovery since that section was enacted. (CCSF Rehrg. App., p. 2.)

Rule 16.3(a) of the Commission's Rules of Practice and Procedure states that a request for oral argument "should explain how oral argument will materially assist the Commission in resolving the application, and demonstrate that the application raises issues of major significance for the Commission ...." (Cal. Code of Regs., tit. 20, § 16.3, subd. (a).) The Commission has complete discretion to determine the appropriateness of oral argument in any particular matter. (Ibid.)

CCSF does not explain how oral argument would "materially assist the Commission in resolving the application." CCSF states that oral argument would allow CCSF to present to the Commission the "significant legal errors" in the Decision. As detailed above, CCSF's rehearing application sets forth its arguments regarding legal error in the Decision and it is unclear what further assistance oral argument would provide. Furthermore, CCSF is incorrect when it alleges that the Decision is of major significance because it is the first decision to rely on section 365.1(c)(2) for cost recovery since that section was enacted. As discussed above, in D.10-07-045, the Commission previously authorized cost recovery pursuant to section 365.1(c)(2). Accordingly, the request for oral argument should be denied.

² Section 365.1 was enacted as part of Senate Bill ("SB") 695 (Stats. 2009, ch. 337). All subsequent section references are to the Public Utilities Code, unless otherwise specified.

³ The Commission is still required to comply with section 380(e), which provides: "Each load-serving entity shall be subject to the same requirements for resource adequacy and the renewables portfolio standard program that are applicable to electrical corporations pursuant to this section, or otherwise required by law, or by order or decision of the commission. (Pub. Util. Code, § 380, subd. (e).) Section 380(e) does not exempt CCAs.

⁴ Finding of Fact ("FOF") 20, which discusses possible adjustments to the GHG Emissions Reduction Targets omits that Commission approval would be required for any adjustment to take effect. (D.10-12-035, p. 62 [FOF 20].) We modify FOF 20, as set forth in the ordering paragraph below, to clarify that Commission approval would be required.

⁵ R.06-02-013 is one of the consolidated proceedings for purposes of considering the Settlement Agreement.

⁶ The Settlement Agreement only allocates the GHG emissions reduction targets to CCAs and ESPs. The Settlement Agreement does not allocate the MW targets of the initial program period to CCAs and ESPs.

⁷ The EAP II is available at: www.cpuc.ca.gov/published/report/49078.htm

⁸ The 2005 IEPR is available at: http://www.energy.ca.gov/2005publications/CEC-100-2005-007/CEC-100-2005-007-CMF.PDF.

⁹ The effect, if any, of SB 695 on the cost recovery adopted in D.06-07-029 is being considered in the LTPP proceeding, R.10-05-006. (Administrative Law Judge's ("ALJ's") Ruling on Implementation of SB 695 and the Cost Allocation Mechanism (Track III) in R.10-05-006, dated September 15, 2010.)

¹⁰ The Commission has consistently applied the fair share principle. (See e.g. D.08-09-012, p. 10, fn. 15 (slip op.) The fair share principle is also incorporated in statutes, including section 366.2(d).

¹¹ CCSF challenges the Commission's reasononing in D.06-02-032 and D.06-06-071 that RPS and RA are intrinsically related to GHG reduction. (CCSF Rehrg. App., p. 9, fn. 12.)
D.06-02-032 and D.06-06-071 are final and unappealable Commission decisions. (Pub. Util. Code, § 1709.) Furthermore, CCSF's argument is based on the flawed premise that CARB has exclusive jurisdiction in the area of GHG reductions. As explained above, AB 32 does not confer CARB with exclusive jurisdiction.

¹² As explained above, in regards to RA and RPS requirements, the Commission is still required to comply with the nondiscrimination requirements in section 380(e), which also apply to CCAs.

¹³ In D.08-09-012, the Commission also authorized the IOUs to make requests for extending the cost recovery period for specific non-RPS resources and stated that the Commission could fully extend, partially extend, or not extend the cost recovery period based on such a request.
(D.08-09-012, p. 55 (slip op.).)