8. Remove Language Requiring IOUs to Purchase GHG Allowances

This issue was addressed in both the Joint Utilities' Petition for Modification and the Amended Scoping Memo.

8.1. The Joint Petition

The Joint Utilities request that the contract provision that utilities must purchase GHG allowances on behalf of CHP Sellers (Sellers) be removed. The Joint Utilities reason that they should have the choice to procure allowances on behalf of Sellers, but should not be required to do so. The Joint Utilities claim that emissions allowance decisions are complex and that in order to procure allowances on behalf of Sellers they will need more detailed information from Sellers.

DRA, TURN, and San Joaquin do not object to the proposal to modify the D.09-12-042 to remove the requirement that utilities procure GHG allowances on behalf of small Sellers. FCE similarly does not object to eliminating the requirement that the utilities procure GHG allowances on behalf of Sellers provided the Commission includes language acknowledging that many issues regarding GHG responsibilities and compliance are currently unresolved and that the Commission reserves the right to order the utilities to obtain allowances on behalf of the Sellers if doing so is necessary in order to effectuate the objectives of AB 1613.

CCDC supports the proposal to eliminate the utilities' obligation to procure GHG allowances on behalf of the Sellers but believe the utilities should have the option to do so on behalf of Sellers. CCDC suggests that D.09-12-042 be modified to make clear that the adopted GHG strategies are subject to revision pending implementation of GHG rules. Alternatively, CCDC proposes that the Commission modify the D.09-12-042 to require the utilities to work with Sellers under AB 1613 contracts to develop the most efficient, cost-effective strategy for GHG compliance with the excess energy sold under AB 1613 contracts.

8.2. The Amended Scoping Memo

The Amended Scoping Memo issued on September 9, 2010, sought additional comments on this issue. Specifically, the Ruling asked:

(1) If Sellers require reimbursement for GHG allowance costs, at what intervals should invoices be submitted to the Buyers?

(2) Is a test (market based or some other method) needed to ensure that the invoices submitted by the Seller leave the ratepayer no worse off than if the Buyer had managed these compliance costs? If so, how should the market test be structured?

Party comments reflected a wide range of views on these two questions. San Joaquin suggests that Sellers should submit invoices at the same frequency that GHG allowances are bought and sold through the auction mechanism. San Joaquin expects this to occur either quarterly or monthly. SDG&E contends that Sellers should submit an invoice for GHG reimbursement at least once per year, but no more than once per quarter. CCDC suggest that Sellers submit invoices as soon as practicable following the Seller's receipt thereof. DRA does not believe that the Commission should alter its original Decision. However, if Sellers are allowed to manage their own allowances, DRA suggests that invoices should be submitted at least annually.

PG&E and SCE reference the FERC Declaratory Order and argue that compensation to a generator cannot exceed the costs avoided by the purchasing utility. Therefore, the cost of GHG allowances should not be treated as a generator cost but as a component of the utility's avoided cost and included in payments due under the Seller's monthly invoice for delivered energy. SCE contends that any resolution of issues related to GHG costs must be consistent with the global QF Settlement Agreement¹³ (QF Settlement) filed with the Commission on October 8, 2010 and PG&E, in their reply comments, agrees with SCE. FCE and CCDC reply that the Commission should ignore these comments as they are outside the scope of the Ruling and therefore erroneous.

Regarding the question of whether a test is needed to ensure that the ratepayer is left no worse off if Sellers manage their own allowances, CCDC, FCE and San Joaquin agree that no such test is needed. However, SDG&E and DRA believe that a test is needed. SDG&E argues that the simplest method would be to apply auction prices to the net allowances needed based on the volume of electricity delivered for the invoiced period of time. DRA proposes a two-point test based on the average prices the Seller and Buyer pays for allowances in the market during the year. In their reply comments, PG&E disagrees with any receipt-based approach to GHG cost reimbursement.

8.3. Discussion

We agree with FCE and CCDC that comments from PG&E and SCE regarding short run avoided cost calculations, as provided in the QF Settlement, are outside the scope of the Amended Scoping Memo and outside the record of this proceeding, and should therefore be disregarded.¹⁴ Furthermore, the QF Settlement as proposed does not seek to modify any of the issues raised in this docket; so while the two matters are related, for the purposes of this issue of GHG allowance procurement associated with the AB 1613 program, any reference to a QF Settlement should have no impact on this Decision.

In addition, the FERC Clarification Order explains that compensation for environmental regulations that are an actual cost can be included in avoided cost calculations while compensation for environmental externalities can be attributed to other mechanisms, like a Renewable Energy Credit.¹⁵ Like Renewable Energy Credits, GHG allowances are external to avoided cost rates as defined under this program (the MPR minus the GHG adder). Under a
cap-and-trade program,¹⁶ GHG allowances will be traded and operate in a separate market that will not affect capacity or energy prices paid under an avoided cost rate. As described in D.10-04-055, the price offered under the contracts in this proceeding represent a long-run avoided cost to the utility based on a new combined-cycle natural gas turbine. Consistent with the FERC Clarification Order, D.09-12-042, as revised by D.10-04-055, establishes that the cost of GHG allowances associated with the electric power sold to the utility, should be paid for by the Buyer, which is a cost external to the avoided cost rate.

However, the Joint Utilities make a reasonable request in their Petition for Modification regarding which entity is best positioned to actually purchase the GHG allowances needed for an AB 1613 facility. The comments from CCDC and others suggest that the original Commission determination that the Buyer must procure the GHG allowances on behalf of the Seller might not yield the optimum outcome. Sellers that are obligated to comply with GHG regulations¹⁷ might be better suited to procure allowances for emissions associated with their exported electricity, because it is a function they will already be performing for emissions associated with their heat needs and on-site electricity consumption.

We agree with CCDC that the original Commission determination may not yield the optimum outcome. However, unlike the Joint Utilities original petition to modify, having the Seller be solely responsible to procure GHG allowances may not yield the optimum result either. Therefore, we determine that a better outcome is for the Seller to elect who (the Buyer or the Seller) will procure the GHG allowances associated with their exported electricity.

Therefore, we modify D.09-12-042 to provide the Seller the option of procuring the GHG allowances for electric power sold to the utility on its own behalf or electing to have the Buyer perform this function.

If the Seller elects to have the Buyer procure the GHG allowance, the Seller will be required to provide the Buyer with sufficient information regarding the emissions associated with their power sold to the electric utility. Provided that the Seller conveys accurate emissions information to the utilities in a timely fashion, we do not find that this will present a significant hardship to them. As was originally reasoned in D.09-12-042, the utilities will be managing GHG compliance obligations for their owned generation and will be well-suited to manage GHG allowances and compliance costs. Additionally, the combination of the adopted contracts, customer meter data, and the annual reporting requirements to the ARB will provide sufficient information for the utilities to make informed decisions regarding the compliance obligation from these resources. Once ARB finalizes its cap-and-trade regulations, Energy Division staff will issue (via Resolution) guidelines on the mechanics of this exchange (e.g., information that Sellers need to provide to the utilities, timing and frequency of the utility provision of allowances, etc.).

However, based on party comments, we expect that some Sellers will elect to manage their own GHG allowances. The Amended Scoping Memo asked the parties if it should employ a test in order to protect ratepayer interests. As commented on by San Joaquin, no test should be needed as long as the Seller purchases the allowance through a liquid and transparent market, and in a manner that is timely in terms of when the allowance must be surrendered to the regulators of the GHG program. PG&E agrees that the price paid for the allowances should be based on a public index, with the best option being the publicly available auction price. We agree. When the Seller elects to procure an allowance that will be reimbursed by the Buyer, the amount paid should be equal to the price established by the most relevant publicly available index, such as an auction, or other comparable index.

¹³ Joint Motion for Approval of Qualifying Facility and Combined Heat and Power Program Settlement Agreement, filed in the following dockets: Application 08-11-001, R.06-02-013, R.04-04-003, R.04-04-025, and R.99-11-022.

¹⁴ With respect to the table entitled "Illustrative Levelized Price Comparison" included by PG&E and SCE in their joint comments to the proposed decision filed on
December 6, 2010, neither the table nor the underlying data is part of the record in this proceeding. Thus, they must be disregarded.

¹⁵ California Public Utilities Commission, 133 FERC ¶ 61,059 at 31.

¹⁶ California Assembly Bill 32 Scoping Plan, developed by the California Air Resources Board (ARB), contains the main strategies California will use to reduce the GHG that cause climate change. The scoping plan has a range of GHG reduction actions including market-based mechanisms such as a cap-and-trade system. The Scoping Plan was approved at an ARB meeting on December 12, 2008, and the staff proposal for a
cap-and-trade regulation was released for public comment on October 28, 2010.

¹⁷ As currently proposed in ARB's Proposed Regulation to Implement the California Cap-and-Trade Program (October 2010), only facilities that produce more than 25,000 tonnes of carbon dioxide equivalent per year are "covered entities" and obligated to comply with GHG regulation during the first compliance period. Small generators will be covered upstream beginning in 2015.