9. Assignment of Proceeding
Michael R. Peevey is the assigned Commissioner and Amy Yip-Kikugawa is the assigned ALJ in this proceeding.
1. AB 1613 - The Waste Heat and Carbon Emissions Reduction Act - was enacted by the California Legislature in 2007 to be effective January 1, 2008, in order to further environmental objectives, particularly the reduction of GHG emissions.
2. AB 1613 requires the Commission to establish a "standard tariff" for qualifying CHP generators to sell their excess electricity to the utilities.
3. AB 1613's policy goal to reduce carbon-based emissions is part of the state's overall objective to reduce GHG emissions, as articulated in AB 32.
4. To advance the state's policy goals beyond a traditional CHP program, an AB 1613 CHP must meet strict efficiency and emission requirements.
5. AB 1613 imposes requirements to ensure reliable and continuous onsite generation to address the state's energy supply and transmission congestion challenges.
6. Staff have proposed two separate contracts for purchase of excess electricity from AB 1613 CHPs: a standard contract would be offered to all eligible CHP systems up to 20 MW, and a simplified contract would be offered to eligible CHP systems that export up to 5 MW.
7. All customers will receive the environmental and locational benefits produced by CHP systems participating under AB 1613.
8. Pub. Util. Code § 2841.5 requires POUs to establish their own programs for purchase of power under AB 1613.
9. POU customers would bear all responsibility for costs associated with the POU's implementation of AB 1613.
10. Once a POU develops its own power purchase program under AB 1613 and enters into contracts under the program, there is a risk that POU customers could be subject to double payment for the benefits derived under AB 1613.
11. The costs for GHG compliance and locational benefits are directly related to the benefits received by all benefiting customers.
12. Because all retail end-use customers, including DA and CCA customers, receive transmission and distribution services from the investor owned utilities, all customers receive the locational benefits of any transmission and distribution upgrade deferrals.
13. Because the benefits under AB 1613 will be received equally by all benefiting customers, the costs associated with GHG compliance and any adder for locating within certain load areas should be allocated on an equal cents/kWh basis.
14. An electrical corporation should file an application seeking authorization to establish a maximum kilowatt hours limitation on the amount of excess electricity it must purchase under this program before a maximum MW limitation is set.
15. The Final Staff Proposal offered two options for the pricing of power purchased under AB 1613.
16. Staff's Pricing Option 1 is a proxy market price based on the costs of constructing, operating, and maintaining a new CCGT.
17. The Staff's Pricing Option 1 uses many inputs from the 2008 MPR, including the fixed costs associated with a new CCGT (minus GHG compliance costs), variable operations and maintenance costs estimated for such a plant and the heat rate assumed for such a plant.
18. 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.116
19. Staff's Pricing Option 1 uses variable monthly natural gas prices based on actual market indices, instead of a forward gas price estimate like the MPR.
20. The result of Staff's Pricing Option 1 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.
21. The operating profile of a CHP facility most closely resembles that of a CCGT.
22. 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.
23. Paying AB 1613 generators a price for as-available energy that is calculated based on the costs of constructing and operating 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.
24. 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.
25. Since the MPR itself is not static, but is updated to reflect the dynamics of the market, it is appropriate that the most current MPR inputs - rather than static 2008 MPR inputs - should be used in the price formula.
26. 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.
27. 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.
28. At the initiation of this rulemaking, the 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.
29. CCC provided, as Attachment A to its comments, a sample of the T&D avoided costs calculated for each utility by the model. The spreadsheet model is commonly referred to as the "E3 Model" in the parties' comments.
30. To calculate T&D avoided costs, the E3 Model relies upon each utility's marginal T&D costs adopted in their general rate cases.
31. Based on the avoided cost numbers reflected in Attachment A to CCC's comments, 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.
32. The Final Staff Proposal's pricing options include a 10% location bonus for eligible CHP systems located in a distribution or transmission constrained area.
33. AB 1613 CHPs are required by statute to operate as firm resources.
34. 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, but the CHP 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.
35. Historically, the Commission has agreed with the utilities that while distributed generation facilities unquestionably generated avoided T&D costs, a facility-specific analysis was required before a T&D avoided cost could be paid to generators.
36. 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.
37. No facility has ever qualified for T&D avoided costs under this test.
38. The Commission's project-specific T&D adder has proven to be unworkable.
39. The Commission's position on T&D avoided costs 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.
40. The utilities benefit from the inclusion of uniform avoided T&D costs in their energy efficiency and demand response programs.
41. SDG&E/SoCal Gas propose that a location bonus is appropriate for generators located in areas with local RA requirements.
42. Each year the Commission adopts Local RA requirements and identifies Local RA areas based on the CAISO's annual study of local capacity requirements.
43. 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.
44. All of the utilities agree that distributed generation, which includes AB 1613 CHPs, results in avoided T&D investment.
45. AB 1613 CHPs located in Local RA areas will generate avoided costs to the utilities well above the 10% location bonus the utilities will pay them.
46. The 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.
47. The Final Staff Proposal proposes a standard contract for eligible CHP systems that are less than or equal to 20 MW and a simplified contract for eligible CHP systems that export no more than 5 MW.
48. All parties, except SCE, agreed to a 5 MW maximum export size for the simplified contract.
49. SCE failed to provide sufficient justification to adopt a lower cutoff point for the simplified contract.
50. CCDC requested an even more simplified contract for CHP systems less than 500 kW.
51. There may be some terms in the simplified contract that are inappropriate and burdensome for very small CHP systems.
52. SCE has failed to provide convincing evidence that entities that develop multiple CHP systems under AB 1613 may not utilize the simplified contract.
53. Because GHG compliance will not begin until January 1, 2012, at the earliest, the regime will not apply to all facilities at that time, and many critical elements of the regime have not yet been finalized, the Commission cannot accurately quantify the costs the GHG compliance regime will impose in the future.
54. It is appropriate and expedient to adopt the Final Staff Proposal's suggested cost pass-through.
55. Any other approach to GHG compliance costs may over or under compensate AB 1613 CHPs for their GHG compliance costs, and this would not meet the "ratepayer indifference" requirements of AB 1613.
56. Setting a cap on GHG compliance costs at the proxy CCGT's heat rate ensures that the price paid to AB 1613 CHPs for GHG compliance will not exceed the utilities' avoided cost.
57. Benefiting customers should only pay for GHG compliance costs once.
58. Pricing Option 1 does not have GHG compliance costs embedded in the price.
59. If there is no direct compliance obligation, there will be no GHG costs.
60. GHG emissions reductions that the facility experiences (compared to generating heat and electricity separately) cannot be isolated to delivered electricity but must be calculated on a facility-wide basis.
61. Pricing Option 1 includes the value of green attributes associated with the excess electricity delivered to the grid.
62. The utilities do not explain why setting the delivery point as the first point of interconnection between the facility and the utility grid, rather than the point of interconnection with the CAISO-controlled grid presents more risk.
63. The risk associated with utility distribution system failure should be borne by the utility.
64. The utility's proposed buyer termination clause would create too much uncertainty and compromise AB 1613's objectives.
65. An indemnity clause against failure to deliver electricity, capacity or resource adequacy benefits is appropriate for the standard contracts.
66. In order to be eligible to participate under AB 1613, a CHP facility must obtain and maintain certification from the CEC and maintain QF status throughout the contract period.
67. It is appropriate that failure to maintain eligibility pursuant to AB 1613, but retaining QF status will result in a facility being paid the most current short run avoided cost instead of the AB 1613 price.
68. A utility may not unilaterally declare a default under the AB 1613 contract without the CEC decertifying the facility, just like a utility may not unilaterally declare a QF is in default under a QF contract without the FERC finding that the facility has lost its QF status.
69. It is appropriate for the state to require higher efficiency from CHPs in exchange for an avoided cost payment; such a program advances both state and federal goals to encourage efficient CHPs.
70. The IOUs' proposed credit and collateral requirements are based on a QF contract that contemplates systems larger than 20 MW.
71. Parties agreed to remove the credit and collateral provision for the simplified contract as a result of the reduced level of risk associated with systems exporting less than 5 MW.
72. The CEC guidelines and certification process will ensure that a participating CHP system will not upgrade its facility above 20 MW or alter the facility beyond what is allowed under AB 1613.
73. Pub. Util. Code § 2841(h) permits the Commission to modify the requirements of AB 1613 for any electrical corporation with less than 100,000 service connections.
74. CASMU's motion to bifurcate the proceeding and defer implementation of AB 1613 for the CASMU members was appropriately denied by an ALJ Ruling.
75. Based on the composition of Sierra Pacific's and PacifiCorp's customer base, it is unlikely that an eligible CHP system exporting more than 5 MW would locate in the service territory of either of these electrical corporations in the immediate future.
76. The costs imposed on Mountain Utilities' and BVES' ratepayers to implement either of the contracts adopted in this decision would likely be excessive, especially in consideration of the number of eligible CHP systems that might locate within their service territories.
77. Since AB 1613 requires the price paid to eligible CHP for excess electricity represent fair compensation for that electricity, the price is not a subsidy.
78. AB 1613 does not prohibit an eligible CHP facility or host customer from receiving ratepayer funded incentives, provided the facility is eligible for them.
1. The AB 1613 program must be implemented pursuant to PURPA.
2. AB 1613 CHPs must be QFs.
3. The prices paid to AB 1613 CHPs must not exceed the procuring utility's avoided costs.
4. Pub. Util. Code §§ 2840.2 (a) and (e), 2841, and 2843 provide that an AB 1613 CHP must be sized to meet its onsite load, must operate continuously in a manner that meets the expected thermal load, and may only sell its excess power to the utilities.
5. Pub. Util. Code § 2841 (f) provides that the entire physical generating capacity of the AB 1613 CHP, not just the excess energy sold to the utility, counts towards the purchasing utility's resource adequacy obligations.
6. Pub. Util. Code § 2841 (b)(4) 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."
7. The customer indifference standard of AB 1613 is met by setting the price paid to the AB 1613 generators at the utilities' avoided costs.
8. AB 1613 requires the costs and benefits associated with any tariff or contract entered into pursuant to the AB 1613 program to be allocated to all benefiting customers.
9. It would be reasonable to allocate the costs to encourage development of eligible CHP systems to all retail end-use customers as they will receive environmental and locational benefits from the systems.
10. Pub. Util. Code § 2841(e) does not include any language that expressly limits the term "benefiting customer" to three categories of customers.
11. It would be unreasonable to include POU customers within the term "benefiting customer" since the POU is mandated to implement its own program for purchase of power under AB 1613.
12. Consistent with Pub. Util. Code § 2841(a), program cap should not be imposed until the Commission first determines that the number of eligible CHP systems participating in this program has an adverse impact on an electrical corporation's long-term resource planning or system reliability.
13. Staff's Pricing Option 2 should not be adopted because it is not consistent with our avoided cost obligations under PURPA.
14. Staff's Pricing Option 1 should be adopted because it is consistent with our avoided cost obligations under PURPA.
15. FERC has recognized that it is appropriate to compensate QFs for their capacity value. It has stated that 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."
16. Staff's proposal to include a 10% location bonus to encourage optimal siting of CHP facilities should be adopted because it is based on an actual determination of the utilities expected T&D costs, and therefore complies with our avoided cost obligations under PURPA.
17. 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.
18. Parties should continue working together to develop an even more simplified contract for eligible CHP systems that export 500 kW or less.
19. It would be unreasonable to impose a limit on the number of contracts entered into by a single entity, as such a limitation could prevent successful project developers or host customers from installing multiple projects.
20. In order to comply with avoided cost principles, the costs paid by the utility to the AB 1613 CHP for GHG compliance costs should not exceed the avoided GHG compliance costs of the proxy CCGT the Commission has relied on to establish the avoided costs for energy.
21. Since the standard contract transfers all benefits of the power product to the utility, it would be reasonable to require CHP generators to ensure that those benefits can be used by the utility to meet its obligations and to indemnify the Buyer against potential penalties for failure to deliver any benefits.
22. A CHP system participating under AB 1613 that fails to maintain its CEC certification through the contract period should be considered in default under the contract.
23. It is appropriate that failure to maintain eligibility pursuant to AB 1613, but retaining QF status will result in a facility being paid the most current short run avoided cost instead of the AB 1613 price.
24. The Supreme Court has recognized that a qualifying facility and a utility may negotiate a contract setting a price that is lower than a full-avoided cost rate.
25. A utility may not unilaterally declare a default under the AB 1613 contract without the CEC decertifying the facility, just like a utility may not unilaterally declare a QF is in default under a QF contract without the FERC finding that the facility has lost its QF status.
26. Credit and collateral provisions in the AB 1613 contracts should balance the financial risk between Buyer and Seller.
27. It would be appropriate to reduce the level of credit and collateral provisions for CHP systems participating under AB 1613 because the projects and project developers participating in this program are likely to be smaller than those contemplated by the QF contract.
28. It would be reasonable to adopt a performance assurance of 5% of expected revenue for both contracts.
29. It would be reasonable to adopt a development security of $20/kW, not to rise over the project development timeline.
30. If the capacity of CHP helps the utility meet its Resource Adequacy obligations, the Seller should be obliged to commit its output for this purpose.
31. The assignment provision in the Standard Contract should apply equally to both the Buyer and the Seller.
32. The Energy Division staff's Final Staff Proposal, submitted on July 31, 2009 should be adopted, as modified.
33. Sierra Pacific and PacifiCorp should offer either the simplified contract or the even more simplified contract for eligible CHP systems exporting 500 kW.
34. Mountain Utilities and BVES should comply with the requirements of AB 1613, but should not be required to offer either of the contracts adopted in this decision.
IT IS ORDERED that:
1. A standard contract for eligible combined heat and power systems up to 20 megawatts (Attachment A) and a simplified contract for eligible combined heat and power systems that export up to 5 megawatts (Attachment B) are adopted. The California electrical corporations should offer these contracts only to combined heat and power systems that are certified by the California Energy Commission as meeting the requirements of Assembly Bill 1613 and, if appropriate, having Qualifying Facility status pursuant to the Public Utility Regulatory Policies Act.
2. Energy Division staff's recommendation to base pricing on the costs of a combined cycle gas turbine is adopted. However, inputs from the most recently adopted Market Price Referent must be used in the pricing formula as long as the Market Price Referent is calculated based on the costs of a proxy natural gas generation resource. Only new contracts executed after the effective date of this decision are impacted by updated pricing inputs. The pricing for executed contracts continues to be based on the pricing inputs in the contract at the time the contract was executed, for the life of the contract.
3. Each year, upon adoption by this Commission of a new Market Price Referent calculation, each California investor-owned utility must file a Tier-1 Advice Letter updating its Assembly Bill 1613 tariffs and standard contracts with the new Market Price Referent inputs. The advice letters must be filed and served within five days of the date that the order adopting the Market Price Referent is mailed. This advice letter must also include a summary table of information about resources procured as a result of this program in the previous year and over the life of the program and updates on Location Bonus areas. Energy Division staff will provide the utilities with a template for the information to be provided in this table prior to the end of the program's first implementation year.
4. The California investor-owned utilities must revise the standard and streamlined contracts to reflect the fact that, when entering into the contract, the Combined Heat and Power Seller can (1) elect to manage its own allowances (and request payment from the California investor-owned utilities according to the terms outlined in this reimbursement methodology) or (2) elect to have the California investor-owned utility purchase allowances for the emissions associated with their electricity exports. Energy Division staff must determine an appropriate publically available index for use in determining the price to be paid for the allowances after seeking input from stakeholders by January 31, 2012. Energy Division will make this information available to stakeholders in an appropriate manner.
5. The California investor-owned utilities must revise the standard and streamlined contracts to reflect the definition of "Eligible CHP Facility" provided herein.
6. The California investor-owned utilities must revise the standard and streamlined contracts to reflect that in the case that a facility is decertified from participating in the Assembly Bill 1613 program, the combined heat and power generator should still be provided with the established short-run avoided cost rate at the time of decertification and the utility should offer the combined heat and power generator the standard offer contract associated with that rate unless the Federal Energy Regulatory Commission were to revoke the Qualifying Facility status of the facility.
7. An AB 1613 CHP located within a Local Resource Adequacy area shall receive a 10% location bonus. Each utility shall to make its Local Resource Adequacy 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 Resource Adequacy program requirements.
8. Within 45 days of the date this order is mailed, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall file an advice letter in compliance with General Order 96-B. The advice letter shall include tariff sheets to implement the standard contract (Attachment A) and the simplified contract (Attachment B) adopted herein. The tariff sheets shall become effective on filing subject to Energy Division determining that they are in compliance with this order.
9. Within 6 months of the date this order is mailed, Sierra Pacific Power Corp. and PacifiCorp shall file an advice letter in compliance with General Order 96-B. The advice letter shall include tariff sheets to implement either:
a. the simplified contract (Attachment B) with proposed modifications to account for their location outside of the California Independent System Operator-controlled grid, or
b. a proposed simplified contract for eligible combined heat and power system less than 500Kw, as discussed in Ordering Paragraph 6 below.
10. Mountain Utilities and Bear Valley Electric Service shall be required to comply with the requirements of Assembly Bill 1613. If a combined heat and power system that is certified by the California Energy Commission under Assembly Bill 1613 wishes to locate in Mountain Utilities' or Bear Valley Electric Service's service territory, Mountain Utilities and Bear Valley Electric Service shall negotiate and enter into a contract with that eligible combined heat and power system if the system does not have an adverse effect on Mountain Utilities' or Bear Valley Electric Service's long-term resource planning, is cost effective, technologically feasible, and environmentally beneficial.
11. Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, Sierra Pacific Power Corp. and PacifiCorp shall convene a working group with combined heat and power parties to establish a further simplified contract for eligible CHP system less than 500Kw. Within 6 months of the effective date of this decision, each investor-owned utility shall file an advice letter in compliance with General Order 96-B. The advice letter shall include tariff sheets to implement a further simplified contract for very small combined heat and power less than 500 Kw. The tariff sheets shall become effective on filing subject to Energy Division determining that they are in compliance with this order.
12. The costs and benefits arising from power received under Assembly Bill 1613 shall be allocated among bundled service customers of the electrical corporation, customers of the electrical corporation that receive their electric service through a direct transaction, as defined in Public Utilities Code Section 331(c), and customers of an electrical corporation that receive their electric service from a community choice aggregator, as defined in Public Utilities Code Section 331.1. The costs to be allocated, if any, shall consist of the 10% location bonus and any greenhouse gas compliance costs passed from the eligible combined heat and power system (Seller) to the electrical corporation (Buyer). These costs shall be allocated on an equal cents per kilowatt-hour basis. The calculation of the costs to be allocated, if any, shall be included in each electric corporation's annual Energy Resource Recovery Account proceeding.
13. Rulemaking 08-06-024 remains open to address implementation of a "pay-as-you-save" program.
This order is effective today.
Dated December 17, 2009, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
TIMOTHY ALAN SIMON
Commissioners
Peevey Attachment A
Peevey Attachment B
116 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
