4. Pricing

AB 1613 authorizes the Commission to require electrical corporations to offer to purchase "excess electricity" from eligible CHP customer generators and requires the Commission to "ensure that ratepayers not utilizing combined heat and power systems are held indifferent to the existence of this tariff."⁵¹

The Final Staff Proposal offered two pricing options. Pricing Option 1 is a proxy market price that includes fixed and variable inputs, and is meant to reflect the cost of operating a "proxy" combined-cycle gas turbine (CCGT) that would be avoided if not for eligible CHP. Pricing Option 2 is based on the generation component of the retail rate tariff applicable to the host customer where the eligible CHP is installed. Parties were asked to comment on the advantages and disadvantages of each pricing option and the appropriateness of each option relative to the ratepayer indifference provision in § 2841(b)(4).

4.1. Pricing Option 1

Staff's Pricing Option 1 is a proxy market price based on the costs of a new CCGT. The pricing formula uses many inputs from the 2008 MPR, including the fixed costs associated with a new CCGT (minus GHG compliance costs⁵²), variable operations and maintenance costs estimated for such a plant and the heat rate assumed for such a plant. Staff's pricing formula uses variable monthly natural gas prices based on actual market indices, instead of a forward gas price estimate like the MPR. The result of this pricing formula is an all-in price (in $/kWh) adjusted for time of delivery (based on MPR time of delivery (TOD) factors) that an eligible CHP facility would receive for every kWh of exported electricity. Staff proposes that a CCGT represents a reasonable proxy for the generation that a utility would have to procure if not for a CHP facility participating in this program. Staff also notes that since the inputs to this pricing formula have been litigated by parties in a prior Commission proceeding, these costs reasonably reflect the costs of a proxy CCGT.

SCE takes exception to the use of MPR inputs in a pricing formula for CHP. SCE argues that the MPR, which was intended as benchmark price for renewable procurement, "is not a proxy for avoided cost, and will result in a highly inflated price for CHP power."⁵³ SCE notes that the MPR uses a 20-year physical life of the generator and assumes the CCGT will never be dispatched. As such, SCE believes Option 1 would result in prices above its avoided cost. PG&E and TURN argue that the MPR is calculated to approximate the all-in costs of a fully-dispatchable CCGT that provides "firm" power, and is therefore inappropriate for a customer-owned CHP facility providing as-available power.⁵⁴

SDG&E/SoCalGas appear to agree with staff's basic assertion that a CCGT is a reasonable proxy for avoided cost of power produced by a CHP facility.⁵⁵ They note that, "small CHP facilities will have a baseload or mid-merit grid export profile, so that its export profile is closest to that of a CCGT."⁵⁶ However, SDG&E/SoCalGas note several differences between the operating profile of a CCGT and a CHP facility, namely that a CCGT can provide firm power and ancillary services. Thus, while SDG&E/SoCalGas do not object to Option 1, they do note that the data inputs would need to be measured correctly.

CCDC and Fuel Cell support Pricing Option 1, and assert that it would serve as an appropriate measure of ratepayer indifference. Both parties note that the fixed inputs in the formula, as well as the direct link between the variable gas price input and known index prices, provide pricing certainty that will facilitate financing of CHP facilities. CCDC further requests that the Commission adopt a process for updating the fixed components of the formula over time.

4.2. Pricing Option 2

Staff's Pricing Option 2 would provide payment to an eligible CHP facility for excess electricity delivered to the grid at a price based on the generation component of the host customer's otherwise applicable tariff. The exact amount of the price paid under this option will vary depending on a host customer's tariff and utility territory. Staff notes that under this option, the price paid for excess electricity will more closely reflect the cost of the electricity a host customer avoids when the CHP generation serves onsite load. Staff believes that this would attach a consistent value to all electricity generated by a CHP facility whether it offsets onsite load or is exported to the grid.

SCE, SDG&E/SoCalGas, and PG&E/TURN present various arguments against this pricing option. PG&E/TURN note that the "average generation cost" in the retail rate reflects embedded costs, including above-market legacy costs and therefore does not reflect the marginal cost of generation avoided by an eligible CHP facility. SCE contends that since Option 2 is based on average cost of generation and not market cost, it does not reflect the actual cost that a utility would have avoided but for the excess electricity from the CHP system.⁵⁷ SCE and PG&E/TURN also note that the variability in retail rates across customer classes, which can be as high as a factor of two, does not reflect actual avoided costs and "thwarts the concept of ratepayer indifference."⁵⁸ SDG&E/SoCalGas echo the opposition raised by SCE and PG&E/TURN. They further assert that failing to link actual fuel input costs and with the price paid under the tariff could create operational problems for CHP and potentially result in grid reliability problems.⁵⁹

CCDC notes that Pricing Option 2 will result in significant complexity and increased transaction costs for CHP customers. CCDC points out that because retail rates are regularly updated in each utility's rate cases, CHP parties would have to regularly participate in those rate cases to ensure that "the component(s) of utility rates used as the basis for AB 1613 pricing meet the criteria of AB 1613."⁶⁰ SDG&E and SoCalGas also note the significance of rate case participation. They further contend that rates in SDG&E territory were established by settlement among parties, and paying CHP for excess electricity based on the rate was not contemplated by negotiating parties.

DRA calculates that the actual price under pricing Option 2 is lower than the price under Pricing Option 1 in 4 out of 5 comparable time of use periods in both SCE and PG&E territories. Based on this, "DRA concludes that Option 2 is a superior pricing scheme to meet ratepayer indifference."⁶¹

4.3. Objections to Both Proposed Pricing Options

SCE and PG&E/TURN reject both pricing options proposed by staff as inappropriate. SCE asserts that both pricing options would violate the FPA, which, they argue, grants exclusive authority to FERC over wholesale price setting. PG&E/TURN take similar exception to staff's pricing options, claiming that they would both violate the ratepayer "indifference" requirement in AB 1613.

SCE and PG&E/TURN assert that the pricing is limited, depending on whether the CHP facility has QF status, to either utility avoided cost or market pricing based on the CAISO day-ahead integrated forward market.⁶² SCE and PG&E/TURN maintain their proposed methods are the only ones permitted under the FPA and PURPA.

4.4. Location Bonus

Staff proposed a 10% location bonus under both pricing options for any eligible CHP located in a distribution or transmission constrained area. Staff reasoned that CHP systems situated in constrained areas could provide system benefits such as transmission and distribution upgrade deferrals and local grid stability and reliability. Staff asked parties to comment on how to determine location or distribution constrained areas for purposes of applying this bonus.

SCE and PG&E/TURN note that staff's proposed location bonus of 10% is unsupported by analysis and unreasonable.⁶³ They assert that the "locational marginal price" (LMP) values in the CAISO market are the only accurate reflection of actual congestion and losses on the grid.

SDG&E/SoCalGas contend that if certain facilities receive a bonus because of their favorable location, then facilities located in less than favorable locations should receive less.⁶⁴ SDG&E/SoCalGas also contend that CHP located in its service territory is more valuable than CHP located elsewhere in the CAISO-controlled grid given the need for local resources. They argue that locational value should only be provided to CHP located in areas with local resource adequacy requirements when contracting with the local utility.⁶⁵

CCDC and Fuel Cell support staff's proposed location bonus. CCDC and Fuel Cell suggest that the location bonus should be provided to any location where the CAISO nodal LMP exceeds the zonal price.⁶⁶

4.5. Discussion

We have already addressed the arguments raised by SCE, PG&E, and TURN concerning our authority to set the price under AB 1613 in Section 3.1 of this decision and do not repeat them here. Accordingly, this section will focus solely on the two pricing options proposed by staff.

Pricing Option 2 would provide for the IOUs to offer to pay for excess electricity from eligible CHP customer-generators based on the generation component of the customer's retail rate. A major advantage of adopting this option would be the relative simplicity of applying this price, as it is the same price that eligible CHP generators receive for offsetting onsite electricity usage. However, many parties raise concerns with using this pricing approach, including the fact that retail rates are often the result of settlement agreements in the utility's general rate case and are heavily tied to legacy contracts. Thus, these parties believe rates would not bear any resemblance to the actual cost of a marginal unit of generation avoided. DRA believes that Option 2 is a superior pricing scheme, but it is unclear whether this conclusion is based primarily on the fact that pricing under this option is generally lower than pricing under Option 1.

We are persuaded by the concerns raised that the generation component of retail rates may not reflect the cost of the energy avoided. As such, there is a risk Option 2 could result in payments to eligible CHP facilities at a price that would not hold non-participating ratepayers indifferent. Further, since these prices will, in effect, be set in a utility's general rate case, customer-generators would not be able to forecast prices beyond the current rate period. This could serve as a deterrent to any eligible CHP systems from entering into contracts longer than three years. These considerations lead us to conclude pricing under the AB 1613 program should not be based on Option 2.

Pricing Option 1 would pay an eligible CHP customer-generator for excess electricity at a proxy market price, based on the costs of a CCGT. Staff asserts that a CCGT represents a reasonable proxy for the marginal unit of generation avoided by an eligible CHP facility. As SDG&E and SoCalGas note in their comments, the operating profile of a CHP facility most closely resembles that of a CCGT. We find that a CCGT is reasonable proxy for the marginal unit avoided by an eligible CHP facility. In light of these considerations, we shall adopt staff's proposed Option 1.

Several parties note that a CCGT represents a fully dispatchable resource and therefore provides greater value than CHP, which under this contract would be "as-available." PG&E and TURN note that a CCGT under a utility's operational control can be dispatched to aid the utility in serving load, while a CHP facility can appear and disappear from the system as the host customer's thermal load requires.⁶⁷ These parties therefore suggest that Pricing Option 1, which is based on the all-in costs of a CCGT, would overpay CHP under this program. SDG&E/SoCalGas suggest that Pricing Option 1, which is based on a CCGT providing firm capacity, would overpay eligible CHP under this program that will only provide as-available capacity. As its justification, SDG&E/SoCalGas point to the difference between as-available capacity prices and firm capacity prices adopted for Qualifying Facilities in D.07-09-040. Joint CHP Parties, in reply comments, disagree that CHP capacity is of lesser value than firm capacity, noting that "the long history of CHP facilities in California shows that CHP facilities of all sizes provide firm, reliable sources of generation."⁶⁸

We note that § 2843(a)(2-3) requires 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." As such, eligible CHP systems under this program are likely to operate as if they were a firm resource, in order to provide consistent thermal and electrical output to the host. While the product being delivered under the contract will be as-available and may vary based on the host-customer's onsite electrical demand, the eligible CHP facility will be operating as a firm resource. As such, it is appropriate that these new highly efficient CHP resources receive payment based on the cost associated with generating electricity from an alternative proxy resource. Pricing Option 1, which is based on the MPR, and assumes the costs associated with building and operating a CCGT as a baseload resource, provides such a price. Furthermore, the TOD factors applied to the MPR, and proposed in Pricing Option 1, account for the value of different products such as baseload and as-available electricity. In Resolution E-4214, which adopted the 2008 MPR, the Commission stated,

The MPR model calculates what it would cost to own and operate a baseload combined cycle gas turbine (CCGT) power plant over a 10, 15, 20 and 25-year period. The cost of electricity generated by such a power plant, at an assumed technical capacity factor and set of costs, is the proxy for the long-term market price of electricity. To ensure that the MPR represents "the value of different products including baseload, peaking, and as-available output," the IOUs apply their IOU-specific Time of Delivery (TOD) profiles to the baseload MPR when evaluating RPS renewable facilities. The application of TOD factors to the MPR result in a market price for each product and electric generating unit.⁶⁹

The adopted pricing formula for eligible CHP under this program is the following:

Table 2 Adopted Pricing Formula
Description	Participating eligible CHP will receive an all-in price in $/kWh, based on a proxy market price for a new combined cycle gas turbine (CCGT) with adjustments for as-available capacity value and time of delivery (TOD)70.
Fixed Component	=Fixed Component of the 2008 MPR minus GHG compliance costs, in $/kWh based on 10-year contract.
Variable Component	=(Monthly bidweek + Local gas transmission charge)* Heat Rate + Variable Overhead and Maintenance (O&M) Monthly bidweek =monthly bidweek gas price at PG&E Citygate for PG&E, and Topock for SCE and SDG&E (monthly bidweek gas prices shall be calculated as the average of three bidweek gas indices as reported in Gas Daily, Natural Gas Intelligence, and Natural Gas Weekly) Intrastate =tariffed intrastate gas transportation rate for large electric generators Heat Rate =6,924 Btu/kWh (based on average Heat Rate from 2008 MPR) Variable O&M = based on variable O&M adder from 2008 MPR.
Final Price (kWh)	=[(Fixed Component + Variable Component) * TOD factor] * 1.1 Location Bonus (if applicable)

Furthermore, we find staff's proposal to include a 10% location bonus appropriate as incentive for optimal siting of CHP facilities on the grid. We agree with Fuel Cell that areas eligible for the location bonus should be identified at the outset. The location bonus shall be applied to eligible CHP systems located in high-value areas, identified as areas with Local Resource Adequacy (LRA) requirements as originally proposed by SDG&E/SoCalGas. The Local RA program, approved in D.06-06-064, is intended to ensure that Load Serving Entities (LSEs) have acquired sufficient generation capacity to serve defined, transmission constrained local areas. Each year the Commission adopts Local RA requirements and identifies Local RA areas based on the California Independent System Operator (CAISO) annual study of local capacity requirements71. The CAISO study identifies the specific substations included in each Local RA area. Eligible CHP interconnected within any of the identified Local RA areas shall receive the location bonus. Each IOU shall make these Location Bonus areas, including the specific substations included in each area, publicly available on their websites. This information shall be updated each year upon adoption by this Commission of the Local RA program requirements⁷². The location bonus shall be applied for the entirety of a contract based on Location Bonus areas identified in the year the contract is executed.

While we find that the pricing formula adopted in this decision reflects the current market price for power from these eligible CHP facilities, it is possible that the formula will need to be revised in the future as the market for power from this source of generation develops. Consequently, Energy Division is directed to review subscription under the program no later than two years after this decision is issued and submit recommendations of necessary changes to the Assigned Commissioner. If subscription under the program is less than 100 MW at that time, the Assigned Commissioner reserves the right to defer this review.

⁵¹ Pub. Util. Code § 2841, subd. (b)(4).

⁵² See section 5.3.2.1 for discussion of GHG compliance cost allocation.

⁵³ SCE Comments, August 24, 2009, at 9.

⁵⁴ PG&E/TURN Comments, August 24, 2009, at 10.

⁵⁵ As with PG&E/TURN, SDG&E/SoCalGas question whether paying a firm price for as-available capacity would be consistent with ratepayer indifference.

⁵⁶ SDG&E/SoCalGas Comments, August 24, 2009, at 3.

⁵⁷ SCE Comments, August 24, 2009, at 11.

⁵⁸ PG&E/TURN Comments, August 24, 2009, at 12.

⁵⁹ SDG&E/SoCalGas Comments, August 24, 2009, at 5.

⁶⁰ CCDC Comments, August 24, 2009, at 8.

⁶¹ DRA Comments, August 24, 2009, at 6.

⁶² PG&E/TURN, Comments, August 24, 2009, at 9; SCE Comments, August 24, 2009, at 7-8.

⁶³ PG&E/TURN Comments, August 24, 2009, at 13; SCE Comments, August 24, 2009, at 12.

⁶⁴ SDG&E/SoCalGas Comments, August 24, 2009, at 6.

⁶⁵ SDG&E/SoCalGas Comments, August 24, 2009 comments, at 6.

⁶⁶ CCDC Comments, August 24, 2009, at 9; Fuel Cell Comments, August 24, 2009, at 9.

⁶⁷ PG&E/TURN Comments, August 24, 2009, at 10.

⁶⁸ Joint CHP Parties Reply Comments, September 3, 2009, at 4.

⁶⁹ Resolution E-4214, at 5 (citations omitted).

⁷⁰ The Time of Delivery (TOD) factors and periods shall be the IOU's Renewables Portfolio Standard TOD factors and periods in place at the time of contract execution. The TOD factors in place at the time of contract execution shall apply for the entire contract duration.

⁷¹ The CAISO's 2008 Local Capacity Requirement (LCR) Study is available from the CAISO website, http://www.caiso.com/1c44/1c44bbc954950.html

⁷² 2010 Resource Adequacy program requirements were adopted by this Commission in D.09-06-028.