7. Pricing of Power as an "As Available" Resource
The Joint Utilities ask the Commission to reduce the price paid under the Form Power Purchase Agreements to reflect the fact that eligible units are "as available" resources. The Joint Utilities contend that D.09-12-042 erred in concluding that the eligible CHP systems are likely to operate as if they were a firm resource and that the factors applied to the MPR and proposed in the adopted pricing formula account for the value of different products such as baseload and as available electricity.
FCE opposes the Joint Utilities proposal to reduce the feed-in-tariff price to reflect that CHP resources are "as available" because it is nothing more than repetition of arguments considered and rejected in D.09-12-042.
CCDC objects to the Joint Utilities' proposal to reduce the AB 1613 price to reflect pricing for an as available product. CCDC contends the proposal is based upon the same arguments previously raised in the underlying proceeding that the Commission previously rejected. There the Commission explained that the time-differentiated MPR pricing mechanism specifically accounted for the value of different products, including the difference in value between baseload and as-available electricity. CCDC contends that the Commission appropriately recognized that the MPR does differentiate between as available and firm baseload power. As a result, CCDC contends the Commission should reject the Joint Utilities' proposal to reduce the price under AB 1613 contracts to reflect an as-available product.
7.1. Discussion
The arguments raised by the Joint Utilities are similar to those raised in both the underlying proceeding and their joint application for rehearing of D.09-12-042. The Commission has already considered and rejected similar arguments in D.09-12-042 and D.10-04-055.10 The logic set forth in those decisions, while not focused on avoided cost principles, remains valid and supports our conclusion here: Paying AB 1613 generators an "all in" price for as-available energy that is calculated based on the long term costs of constructing and operating a proxy baseload resource is appropriate and does not exceed the utilities' avoided costs because AB 1613 CHPs operate as firm resources and avoid capacity procurement for the utilities. We provide further clarification on this point here to resolve any questions that remain.
7.1.1. AB 1613 Requires Eligible CHPs to Operate As Firm Resources And Allows Procuring Utilities to Avoid Resource Adequacy Obligations
AB 1613 CHPs are required by statute to operate as firm resources. Public Utilities Code §§ 2843(a)(2) and (3) require that an eligible CHP system must "be sized to meet the eligible customer-generator's thermal load," and must "operate continuously in a manner that meets the expected thermal load and optimizes the efficient use of waste heat." Consistent with this obligation, § 2841(f) provides that the utilities are entitled to count the firm resource towards their resource adequacy obligations. These obligations are reflected in Sections 1.02 and 3.02 of the pro forma contracts approved in D.09-12-042, which require the generator to commit to an expected amount of energy production per term year and to pledge its generating capacity to the purchasing utility to use in meeting its resource adequacy obligations. Significantly, when a utility contracts with an AB 1613 CHP, it avoids a resource adequacy procurement obligation equivalent to the full capacity of the AB 1613 CHP (in other words, all of the power generated by the CHP), but the CHP is not paid for the full value of this avoided cost. Instead, the generator only receives a payment for the excess energy it sells to the utility. Thus, this payment clearly does not exceed the utility's avoided CCGT procurement costs.
7.1.2. FERC Rulings Recognize A State's Ability To Compensate QFs For Their Capacity Value
The Joint Utilities' continued attempts to challenge the firm/as available decision made by this Commission are troubling given the support for the Commission's actions. FERC expressly affirmed a state's ability to "determine that capacity is being avoided, and so ... rely on the cost of such avoided capacity to determine the avoided cost rate" - which is exactly what the Commission is doing here.11 FERC went on to state:
Further, in determining the avoided cost rate, just as a state may take into account the cost of the next marginal unit of generation, so as well the state may take into account obligations imposed by the state that, for example, utilities purchase energy from particular sources of energy or for a long duration.12
Here, consistent with AB 1613 requirements, the Commission has determined that an AB 1613 CHP will avoid capacity costs that the utility would otherwise incur, and quantifies those costs based on the marginal CCGT.
Reliance on a CCGT as the marginal unit is reasonable because, as we have determined in all of the CHP decisions, it is much more likely that the Joint Utilities would seek to meet the baseload needs served by AB 1613 CHPs through a long term contract with a new, highly efficient CCGT. Among other things, the Commission's emission performance standards adopted in D.07-01-039 would likely compel such an outcome. That decision prohibits the utilities from entering into contracts of five years or longer with facilities that emit in excess of 1100 lbs/MWh of carbon dioxide equivalent. In effect, this means that the utilities are limited to procuring long term commitments13 for sales of electricity from CCGTs, renewables, other non-carbon emitting resources such as hydroelectric power, and CHPs.14
A payment for capacity value based on avoided procurement is not new policy. FERC addressed this very issue when it adopted Order 69 implementing Section 210 of PURPA in 1980. In response to claims that avoided cost should not include capacity payments, FERC explained that purchases of power from QFs "will fall somewhere on the continuum between" firm and non-firm service or capacity and energy. For facilities that demonstrate "a degree of reliability that would permit the utility to defer or avoid construction of a generating unit or the purchase of firm power from another utility, then the rate for such a purchase should be based on the avoidance of both energy and capacity costs."15 As AB 1613 CHPs must, pursuant to statute, provide this degree of reliability and allow the utility to avoid local resource adequacy procurement, they provide both energy and capacity and are properly compensated for both under the AB 1613 price formula.
10 See D.09-12-042 at 36.
11 California Public Utilities Commission, 133 FERC ¶ 61,059 at 26.
12 Id.
13 For GHG emissions purposes, Pub. Util. Code § 8340(f) defines a "Long-term financial commitment" to mean a new or renewed contract for a term of five years of more. Pub. Util. Code § 8341(a) prohibits the utilities from entering into contracts of 5 years or more for baseload generation that does not comply with the Commission's GHG emission performance standards. While an AB 1613 CHP may contract for a term of one to ten years, we anticipate most AB 1613 CHPs to contract for ten years for financing purposes.
14 See, e.g., D.07-01-039 at Findings of Fact 2, 3, and 4.
15 Order No. 69, FERC Stats. & Regs., Regs. Preambles, 1977-1981, ¶ 30, 128 at 30,882 (1980).
