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."39
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 costs40), 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."41 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.42
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.43 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."44 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.45 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."46 SDG&E/SoCalGas echo the opposition raised by SCE and PG&E/TURN. They further assert that failing to link actual fuel input costs with the price paid under the tariff could create operational problems for CHP and potentially result in grid reliability problems.47
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."48 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."49
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.50 SCE and PG&E/TURN maintain their proposed methods are the only ones permitted under the FPA and PURPA.
4.4. Location Bonus
At the initiation of this rulemaking, CCC filed comments noting that the Commission currently uses a model to calculate average T&D avoided cost values for each utility's service area, by each utility division or planning region.51 CCC provided, as Attachment A to its comments, a sample of the T&D avoided costs calculated for each utility by the model (CCC Attachment A). The spreadsheet model is commonly referred to as the "E3 Model" in the parties' comments. To calculate T&D avoided costs, the E3 Model relies upon each utility's marginal T&D costs adopted in their general rate cases.
Based on the avoided cost numbers reflected in Attachment A, CCC proposed to pay an avoided T&D cost "adder" to AB 1613 generators located in areas that would produce higher than average avoided cost benefits to ratepayers, but did not specifically identify the amount of the adder.52 CCC proposed that the generators would cooperate with the utilities to identify the best areas to site such projects to generate the highest avoided costs. In making this proposal, CCC acknowledged that the utilities have traditionally argued against such a T&D avoided cost on the basis that such costs are "highly site-specific and that a case-by-case analysis is needed."53 CCC noted that "to the CCC's knowledge, no CHP or renewable projects have ever been compensated for such locational benefits."54
In commenting on the CCC's proposal to identify T&D avoided costs, all three utilities agreed that distributed generation facilities have the potential to avoid T&D costs; however, each one argued that this proceeding was not the forum for quantifying those costs.55 Among other things, they argued, as CCC anticipated, that each DG facility must be considered separately, on a case-by-case basis, to calculate such avoided costs. None of the utilities suggested that the E3 Model avoided cost calculations provided in the CCC Attachment A were inaccurate.
On August 4, 2009, an Administrative Law Judge's ruling incorporated the Final Staff Proposal into the record of the proceeding and requested party comments on the proposal. The Final Staff Proposal suggested a 10% location bonus under both proposed pricing options for any eligible CHP located in a distribution or transmission constrained area. The Final Staff Proposal 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. The Final Staff Proposal asked parties to comment on how to determine location or distribution constrained areas for purposes of applying this bonus.
SCE and PG&E/TURN argued that the proposed location bonus of 10% was unsupported by analysis and unreasonable.56 They also asserted that the "locational marginal price" (LMP) values in the CAISO market are the only accurate reflection of actual congestion and losses on the grid."57 SCE also pointed out that adopting a generic location adder would be inconsistent with the generator-specific methodology adopted in D.03-02-068.58
SDG&E/SoCalGas contended that if certain facilities received a bonus because of their favorable location, then facilities located in less than favorable locations should receive less.59 SDG&E/SoCalGas also contended 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 in their service territory. They argued that locational value should only be provided to CHP located in areas with local resource adequacy requirements when contracting with the local utility.60
CCDC and Fuel Cell supported the Final Staff Proposal's location bonus. CCDC and Fuel Cell suggested that the location bonus should be provided to any location where the CAISO nodal LMP exceeds the zonal price.61
4.5. Discussion62
As discussed in Section 3.1, we agree with SCE, PG&E, and TURN concerning our authority to set the price under AB 1613. The AB 1613 price must not exceed the utilities' avoided costs pursuant to PURPA and we analyze staff's pricing options with that obligation in mind.
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, and would violate our avoided cost obligations under PURPA. 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 avoided costs of procuring energy from 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 a reasonable proxy for the marginal unit avoided by an eligible CHP facility and that the MPR-based price proposed as Option 1 reasonably approximates the costs of constructing and operating that marginal unit. The MPR is intended to represent the long term market price of electricity for fixed price contracts.63 The MPR is derived from the construction, operating and maintenance costs associated with a highly efficient 500 MW CCGT. The MPR inputs and methodology were developed pursuant to Public Utilities Code section 399.15(c) through a public process and the Commission relies on a public process to periodically update the MPR inputs and methodology.64
Based on this history of the MPR, the fact that many of the pricing components of the MPR correspond to AB 1613's pricing requirements,65 and the fact that we agree that the MPR's CCGT unit is the unit most likely to be procured by the IOUs in the absence of the AB 1613 procurement obligation, we 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.66 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."67
We conclude that paying AB 1613 generators a price for as-available energy that is calculated based on the costs of constructing, operating, and maintaining a proxy baseload resource, consistent with Option 1, is appropriate and complies with our obligation to pay such resources no more than the IOUs' avoided costs for several reasons, including those discussed below.
4.5.2.1. 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 here, 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.
4.5.2.2. FERC Rulings Recognize A State's Ability To Compensate QFs For Their Capacity Value
Consistent with AB 1613 requirements, the Commission recognizes that an AB 1613 CHP will avoid capacity costs that the utility would otherwise incur, and we quantify those costs based on the marginal CCGT.
Reliance on a CCGT as the marginal unit is reasonable because 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 commitments68 for sales of electricity from CCGTs, renewables, other non-carbon emitting resources such as hydroelectric power, and CHPs.69
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."70 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.
Historically, the Commission has agreed with the utilities that while distributed generation facilities unquestionably generate avoided T&D costs, a facility-specific analysis was required before a T&D avoided cost could be paid to generators. The Commission has therefore previously declined to adopt a uniform avoided cost calculation for T&D. Instead, D.03-02-068, issued February, 2003, established four facility-specific criteria to be met for a facility to qualify for avoided T&D costs. To our knowledge, which is consistent with CCC's, no facility has ever qualified for T&D avoided costs under this test.
Notwithstanding the determinations in D.03-02-068, the Commission's position on this matter has evolved over the last eight years in other proceedings so that today the E3 Model is used to calculate avoided T&D costs to determine the cost effectiveness of the utilities' energy efficiency and demand response programs.71 The utilities benefit from the inclusion of uniform avoided T&D costs in these programs. The more cost-effective the program, because of the addition of T&D avoided costs, the more money utility shareholders may receive in the form of performance incentives.
We find merit to SDG&E/SoCal Gas's contention that a location bonus is appropriate for generators located in areas with local resource adequacy (RA) requirements. As a result, we adopt a 10% location bonus for eligible CHP systems located in CAISO-identified location-constrained resource areas, which the Commission identifies as Local RA areas for purposes of establishing local RA procurement requirements.72
The Local RA program, approved in D.06-06-064, is intended to ensure that the utilities 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 CAISO's annual study of local capacity requirements.73 The CAISO study identifies the specific substations included in each Local RA area - constrained areas that require the purchase of a specified amount of Local RA resources to avoid T&D system failures.
An AB 1613 CHP interconnected within any of the identified Local RA areas should receive the location bonus. We require each utility to make these location bonus areas, including the specific substations included in each area, publicly available on its website. This information is required to be updated each year upon adoption by this Commission of the Local RA program requirements.74 The location bonus is to be applied for the entirety of an AB 1613 CHP's contract term based on the Local RA areas identified in the year the contract is executed.
To the extent that parties believe that the 10% location bonus does not reflect avoided cost, or will push the MPR-based price above avoided cost, they are wrong. As an initial matter, it should be noted that all of the utilities agree that distributed generation, which includes AB 1613 CHPs, results in avoided T&D investment. Nevertheless, the 10% location bonus will only be made available to new AB 1613 facilities constructed in Local RA areas. AB 1613 CHPs located in these Local RA areas will generate avoided costs to the utilities well above the 10% location bonus the utilities will pay them.
CCC Attachment A sets forth utility-specific avoided T&D costs by geographic "divisions" which average $5.60/MWh for PG&E's service area, $6.66/MWh for SCE's service area, and $13.03/MWh for SDG&E's service area, assuming a baseload profile, which is the profile of an AB 1613 generator. Based on these average avoided costs for T&D, a 10% location bonus paid to CHP facilities located in Local RA areas for avoided T&D investment is a conservative estimate of the actual T&D costs avoided in Local RA areas for several reasons.
First, the 10% location bonus is only paid on the amount of energy sold to the utility, and not on the amount of energy that the utility avoids producing due to the existence of the AB 1613 generator. Thus, the AB 1613 CHP will receive a payment for far less than the T&D costs it actually avoids. For example, when a utility achieves 10 MWh in energy efficiency savings, it gets credit for 10 MWh of avoided T&D costs, measured by the E3 Model and reflected in the CCC Attachment A. However, if an AB 1613 generator generates 10 MWh of energy, but only sells 1 MWh to the utility, while it avoids 10 MWh of generation, and thus, produces savings similar to 10 MWh of energy efficiency, the AB 1613 generator is only paid the 10% location bonus on the 1 MWh sold to the utility. Pursuant to AB 1613, generators must size output to load and may only sell their excess power to the utility. Thus, any payment to an AB 1613 generator for avoided T&D costs will be less than actual T&D costs avoided.
Second, the CCC Attachment A averages calculated from the data provided in the E3 model are based on avoided T&D investment in the entire utility service area. The 10% adder will only be paid to generators located in Local RA areas, which are the most constrained resource areas and will therefore have the highest avoided T&D costs. For example, CCC Attachment A shows that avoided T&D costs are as high as $9.17/MWh in PG&E's service area, $8.33 in SCE's service area, and $13.03 in SDG&E's service area. In that regard, the 10% Location Bonus based upon "average" T&D costs is a conservative estimate of the cost actually avoided by the utility for T&D. Further, the avoided T&D costs reflected in CCC Attachment A are likely to increase as a result of utility filings for increases in transmission rates at FERC, and increases in distribution rates in Commission proceedings.
In adopting the 10% location bonus for AB 1613 generators located in local RA areas, the Commission recognizes that it must be consistent with federal law and the bonus must be based on an actual determination of the expected avoided costs of T&D upgrades. However, the Commission has a great deal of discretion in determining this expected avoided cost. As the Ninth Circuit Court of Appeals recognized in Independent Energy Producers, the Commission has broad authority to implement Section 210 of PURPA, "states play the primary role in calculating avoided costs," and states have "a great deal of flexibility ... in the manner in which avoided costs are estimated ..."75
The U.S. Supreme Court's holdings in American Paper support the Commission's determination to adopt a uniform T&D avoided cost in the form of the 10% location bonus, instead of requiring the project-specific determination of prior years. In that case, the Supreme Court found that FERC appropriately adopted a uniform rule that every CHP was entitled to full avoided cost payments. Among other things, the Supreme Court referred to PURPA's legislative history stating that such rate determinations should not be subject to the same level of scrutiny typically applied to utility rate applications. The Supreme Court quoted that legislative history at length, including the directive to encourage CHPs:
"[C]ogeneration is to be encouraged under this section and therefore the examination of the level of rates which should apply to the purchase by the utility of the cogenerator's or small power producer's power should not be burdened by the same examination as are utility rate applications, but rather in a less burdensome manner. The establishment of utility type regulation over them would act as a significant disincentive to firms interested in cogeneration and small power production."76
The Supreme Court examined FERC's policy reasons for adopting the full avoided cost rule, instead of a generator-specific avoided cost. Among them, the Supreme Court recognized FERC's desire to provide development incentives, and that such development would serve the public interest:
The Commission recognized that the full-avoided-cost rule would not directly provide any rate savings to electric utility consumers, but deemed it more important that the rule could "provide a significant incentive for a higher growth rate" of cogeneration and small power production, and that "these ratepayers and the nation as a whole will benefit from the decreased reliance on scarce fossil fuels, such as oil and gas, and the more efficient use of energy." [footnote omitted] 45 Fed. Reg. 12222 (1980).77
The Supreme Court properly noted that "[t]he Commission would have encountered considerable difficulty had it attempted to determine an appropriate rate less than full avoided cost."78 Similarly here, the Commission's project-specific T&D adder has proven to be unworkable. To encourage CHP consistent with both federal and state law, the Commission adopts a uniform rule here to compensate AB 1613 CHPs located in Local RA areas for some portion of the T&D costs they allow the utility to avoid.
In summary, the 10% location bonus the Commission adopts here is consistent with FERC's regulations because it is based on an actual determination of the utilities expected T&D costs, as established in their general rate cases and incorporated into the E3 Model relied on here. Based on these costs, and as explained above, the 10% location bonus is a conservative under-estimate of the avoided T&D costs associated with AB 1613 generators situated in location constrained resource areas and will not result in AB 1613 generators receiving more than avoided costs for their energy sales to the utilities.
As discussed above, the Option 1 MPR-based price formula is based on the utilities' avoided costs associated with the construction, operation, and maintenance of a combined cycle gas turbine. The MPR is set annually by the Commission in accordance with Pub. Util. Code § 399.15(c) and represents the long-term market price of electricity. The MPR is used as a benchmark in the RPS Program.
The methodology for calculating the MPR was first developed in
D.04-06-015. The methodology has been revised several times since, in
D.05-12-042, D.07-09-042, and most recently in D.08-10-026. Each year the Energy Division updates the cost inputs and recalculates the MPR based on this methodology.
The AB 1613 price formula we adopt here utilizes several inputs from the MPR. These inputs include:
· Fixed Component = MPR fixed component for 10 year contract;
· Variable Operations & Maintenance = MPR variable Operations & Maintenance;
· Heat Rate79 = MPR average heat rate for a combined cycle gas turbine; and
· Time of Delivery periods and factors.
At the time the record for this proceeding was developed, the most current MPR available was the 2008 MPR and staff proposed using the 2008 MPR inputs.80 However, given our determination that the cost of a proxy natural gas generation resource should serve as a basis for determining the price to be offered to eligible CHP facilities under the AB 1613 program, it is reasonable that the price formula reflects the most current cost of a proxy natural gas generation resource. Since the MPR itself is not static, but is updated to reflect the dynamics of the market, it logically follows that the most current MPR inputs - rather than static 2008 MPR inputs - should be used in the price formula adopted here. Therefore, going forward, the price formula in the form contracts shall be updated to reflect the most current MPR.81
As long as the MPR is calculated based on the costs of a proxy conventional natural gas generation resource, the four pricing components identified above from the most recent MPR shall be used in the AB 1613 price formula in order to determine the utilities' avoided cost for this program. Each year, upon adoption by this Commission of a new MPR calculation, each IOU shall file a Tier 1 Advice Letter updating its AB 1613 tariffs and standard contracts with the new MPR inputs. The advice letters shall be filed and served within five days of the date that the order adopting the MPR is mailed. If, however, the MPR ceases to be based on a proxy natural gas generation resource or ceases to exist entirely, then the most recent MPR inputs that were developed using a proxy conventional natural gas generation resource shall continue to apply to AB 1613 contracts until otherwise modified by this Commission.82
The adopted price formula for eligible CHP under this program is the following:
Table 2 Adopted Price 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 time of delivery (TOD)83. |
Fixed Component |
=Fixed Component of the MPR in effect at the time of contract execution for the year of the Term Start Date in $/kWh based on 10-year contract.84 |
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 =the average Heat Rate from the MPR in effect at the time the contract is executed Variable O&M = based on variable O&M adder from the MPR in effect at the time the contract is executed. |
Final Price (kWh) |
=[(Fixed Component + Variable Component) * TOD factor] * 1.1 Location Bonus (if applicable) |
39 Pub. Util. Code § 2841, subd. (b)(4).
40 See section 5.3.2.1 for discussion of GHG compliance cost allocation.
41 SCE Comments, August 24, 2009, at 9.
42 PG&E/TURN Comments, August 24, 2009, at 10.
43 As with PG&E/TURN, SDG&E/SoCalGas question whether paying a firm price for as-available capacity would be consistent with ratepayer indifference.
44 SDG&E/SoCalGas Comments, August 24, 2009, at 3.
45 SCE Comments, August 24, 2009, at 11.
46 PG&E/TURN Comments, August 24, 2009, at 12.
47 SDG&E/SoCalGas Comments, August 24, 2009, at 5.
48 CCDC Comments, August 24, 2009, at 8.
49 DRA Comments, August 24, 2009, at 6.
50 PG&E/TURN Comments, August 24, 2009, at 9; SCE Comments, August 24, 2009, at 7-8.
51 CCC Comments, July 31, 2008.
52 CCC Comments, July 31, 2008, at 10-14 and Attachment A.
53 CCC Comments, July 31, 2008, at pp.12-13.
54 CCC Comments, July 31, 2008, at p. 13.
55 See, e.g., SCE Comments, August 15, 2008, at 4 ("Thus, although SCE would agree that generation systems can be used to defer T&D investment, it is unlikely that this could or should be accomplished through enactment of this tariff.."); PG&E Comments, August 15, 2008, at 7 (PG&E "agrees that, in situations where CHP units truly allow a utility to avoid T&D costs, a benefit exists for its customers that would warrant paying an additional amount. However, as the Commission has previously determined, such `right place, right time' situations may be fairly rare, and depend on a number of conditions being met for a T&D value to exist."); see also, SDG&E/SoCal Gas Comments, August 15, 2008, at 2 (outlining SDG&E's 4 criteria proposal for when a facility may qualify for T&D avoided costs, adopted in D.03-02-068).
56 PG&E/TURN Comments, August 24, 2009, at 13; SCE Comments, August 24, 2009, at 12.
57 PG&E/TURN Comments, August 24, 2009, at p.13; SCE Comments, August 24, 2009, at p. 14.
58 SCE Comments, August 24, 2009, at pp. 12-14.
59 SDG&E/SoCalGas Comments, August 24, 2009, at p. 6.
60 SDG&E/SoCalGas Comments, August 24, 2009, at p. 6.
61 CCDC Comments, August 24, 2009, at 9; Fuel Cell Comments, August 24, 2009, at 9.
62 An additional pricing provision is discussed in Section 5.8 below in the event an AB 1613 CHP fails to comply with CEC certification requirements.
63 Pub. Util. Code § 399.15 (c)(1).
64 See, e.g., D.05-12-042; D.07-09-024; D.08-10-026; and the Commission's MPR website at http://www.cpuc.ca.gov/PUC/energy/Renewables/mpr
65 See Final Staff Proposal at 10.
66 PG&E/TURN Comments, August 24, 2009, at 10.
67 Joint CHP Parties Reply Comments, September 3, 2009, at 4.
68 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.
69 See, e.g., D.07-01-039 at Findings of Fact 2, 3, and 4.
70 Order No. 69, FERC Stats. & Regs., Regs. Preambles, 1977-1981, ¶ 30, 128 at 30,882 (1980).
71 The E3 Model for calculating avoided costs for energy efficiency was adopted in D.05-04-024 and updated in 2008 to apply to the utilities' 2009-2011 energy efficiency portfolio plans. (Assigned Commissioner's and Administrative Law Judge's Ruling, R. 06-04-010, April 21, 2008.) These updates did not include changes to the methodology for calculating avoided T&D.
72 D.09-12-042 at 38-39.
73 The CAISO's 2008 Local Capacity Requirement (LCR) Study is available from the CAISO website, http://www.caiso.com/1c44/1c44bbc954950.html
74 2010 Resource Adequacy program requirements were adopted by this Commission in D.09-06-028.
75 Independent Energy Producers Association, Inc. v. CPUC (9th Cir. 1994) 36 F.3d 848, 856.
76 American Paper Inst. v. American Elec. Power ("American Paper") (1983) 461 U.S. 402, at 414, quoting from H. R. Conf. Rep. No. 95-1750, pp. 97-98 (1978).
77 Id. at 415.
78 Id. at 416.
79 Heat Rate is expressed as the number of British Thermal Units required to generate a kilowatt hour of electricity.
80 The Commission adopted the 2009 MPR on the same day that it adopted D.09-12-042.
81 New contracts would utilize the 2009 MPR until the 2010 MPR is adopted by the Commission.
82 The pricing for executed contracts shall be based on the pricing inputs in effect at the time the contract was executed. We do not require parties to modify contracts that have already been executed because it is important to protect contract stability and the expectations of the contracting parties.
83 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.
84 The chart here reflects changes ordered by D.10-12-055 regarding the fixed price component of the AB 1613 price formula and GHG compliance costs. See D.10-12-055 at pp. 10-14.
