5. Contract Terms and Conditions
The Final Staff Proposal recommended various modifications to the standard contract and simplified contract proposed by the Working Group. This section addresses the major issues raised by the parties in both the Working Group reports and individual comments. Minor modifications recommended by staff and not discussed below are hereby accepted and reflected in the actual contracts. The standard contract is attached to this Decision as Attachment A and the simplified contract is attached as Attachment B.
5.1. Contract Sizing and Overview
Staff proposed establishing two separate contracts, one for eligible CHP systems less than or equal to 20 MW, and another simplified contract for smaller CHP systems that export no more than 5 MW. The Final Staff Proposal recommends using the contracts submitted by the Working Group on May 15, 2009 and June 30, 2009, respectively, as the basis for these contracts.
Parties generally agree with establishing two contracts, one for larger facilities and a simplified contract for smaller facilities. The simplified contract filed by the Working Group on June 30, 2009 noted that SCE objected to the 5 MW maximum size for the simplified contract and instead preferred a 1 MW maximum size. PG&E, SDG&E, CCDC, and Fuel Cell all agreed to a 5 MW maximum export size for the simplified contract. In its comments to the Final Staff Proposal, SCE did not provide any further justification for its preferred 1 MW cutoff. Accordingly, we see no reason why the Working Group's recommended 5 MW limitation should be lowered. We herein adopt two contracts, one for eligible CHP less than or equal to 20 MW (Attachment 1), and another simplified contract for smaller CHP systems that export no more than 5 MW (Attachment 2).
CCDC requests an even further simplified contract for eligible CHP systems less than 500 kW, stating that many of the terms in the simplified contract are too onerous for these very small generators. In its reply comments, SCE notes that many of the terms CCDC identifies as onerous, such as requirements of the CAISO, may not even be applicable to very small generators.73 It further contends that many of the terms that CCDC seeks to change were the result of compromise between all parties and that CCDC fails to provide sufficient justification why an even further simplified contract is necessary.
In comments to the Proposed Decision, Fuel Cell notes that parties involved in negotiations to develop contract terms and conditions "agreed by consensus" not to discuss a contract for very small CHP in order to agree on terms for larger facilities. However, Fuel Cell notes that it would support further effort to develop a simplified contract for smaller facilities. CCDC also recommends that a separate contract for systems less than 500 kW should be developed. It states that CHP systems that are 500 kW or less would have minimal effect on an electrical corporation's distribution system and should be allowed to participate under AB 1613 without undue costs and administrative burdens.74 Although we decline to adopt an even more simplified contract for eligible CHP systems exporting 500 kW or less in this decision, we believe that such a contract may be beneficial in encouraging smaller customer-generators to participate in the program. Therefore, parties shall work together to identify contract terms in the simplified contract terms that do not apply to very small CHP. Within six months of the effective date of this decision, each electrical corporation, unless otherwise excused, shall file a Tier 2 Advice Letter with a proposed contract for purchase of excess electricity from CHP systems exporting 500 kW or less. The Advice Letter shall include a redline version of the simplified contract showing the proposed contract terms to be deleted or revised, as well as an explanation why these deletions or revisions are needed
Finally, SCE notes that nothing in AB 1613 prohibits utility-specific differences, and points to differences in the utilities distribution and transmission system configurations as reason why differences in contracts may be appropriate. Except as discussed in Section 6.1 below, we find no compelling reason why these contracts should differ and direct all utilities to adopt the same contracts.
5.2. Maximum Contracting Under Simplified Contract (Simplified Contract Term 7.02(c))
SCE proposes that a single entity may not sign contracts for delivery of more than 20 MW using this simplified contract. No other parties support this requirement. The staff proposal recommended removing any limitation on the amount that any one entity could contract for under either contract.
SCE argues that since certain provisions such as credit and collateral were removed from the simplified contract, unlimited contracting by a single entity through this contract could create a concentration of risk for the utility and its ratepayers if that entity fails. SCE assumes that the risk of contract failure is multiplied by the number of projects developed by a single CHP generator.
We find SCE's arguments unconvincing. The risk associated with an individual project is dealt with in the contract for that project. We believe the simplified contract adequately addresses risk relative to the size of the projects eligible for that contract. It is not clear that the risk of contract concentration perceived by SCE is real. For any individual project, there will be a range of stakeholders including host customer, project developer, and equipment manufacturer. The fact that a single entity may be involved in more than one project does not mean that if that entity fails, all projects associated with that entity would also fail. For example, it is conceivable that in the event of the failure by a single project developer involved in multiple projects, the host customers for those projects could simply find new developers. We also note that a limit on contracting by a single entity would be largely unenforceable. A single entity could easily establish affiliates expressly to get around this limitation.
Therefore, we do not find it appropriate or beneficial to impose a limit on how many contracts a single entity may enter into, whether for the simplified contract or the standard contract. It is not our intent to limit successful project developers or host customers interested in installing multiple projects at multiple sites from helping the state to achieve its GHG emissions reductions objectives.
5.3. Green Attributes and GHG Compliance Costs (Simplified Contract Terms 3.01, 3.03 and Definitions; Standard Contract Term 3.01(b), 3.03 and Definitions)
A major point of discussion in the proceeding related to GHG compliance costs and green attributes associated with CHP, and how these costs and benefits should be addressed in the contract. The Final Staff Proposal recommended that the Buyer (i.e., electrical corporation) should pay for GHG compliance costs for the excess electricity sold to the grid, and that any green attributes associated with the resource should transfer to the Buyer.
SDG&E/SoCalGas agree that it is appropriate for the Buyer to pay for the GHG compliance costs for the emissions associated with the grid-delivered electricity. They contend, however, that the costs should be paid for once and only once.75 Put another way, if the cost of GHG compliance is embedded in either the fuel cost or in another payment, or if a free distribution of allowances to these facilities is included in a future State or Federal cap and trade program, then there is no need for the Buyer to make an additional payment to the facility. SDG&E/SoCalGas also suggest that given Pricing Option 1, the Buyer should pay up to the heat rate associated with the MPR and that the Seller should bear the rest of the GHG compliance cost for emissions associated with these less efficient units. SCE agrees with this idea of sharing GHG compliance costs; SCE suggests in its comments that the Buyer should pay for some form of compliance costs, depending on the pricing option. SCE further suggests that there should be some form of sharing because the Buyer does not have operational control. PG&E/TURN echo the concept of dispatch control as being important for GHG cost compliance. They state that the Buyer should not have to pay for emissions that could have been eliminated because of operational control.76 PG&E/TURN further suggest that since it is a customer investment, the Seller will not optimize its investment correctly if the Seller does not pay the GHG cost.
CCDC agrees that the Buyer should take on some form of GHG compliance cost but also points out the high amount of uncertainty associated with California's emerging regulation of GHG.77 Fuel Cell also echoes that a straight pass-through of costs (i.e., the Buyer bears the GHG cost/allowance retirement obligation) is the best approach in light of this regulatory uncertainty.
Fuel Cell suggests that the Commission establish a GHG principle in this decision and suggests that once more information is known about the outcome of the ARB regulatory process, the Commission could order a change to the contract. CCDC also suggests that other green attributes, such as renewable energy credits (RECs), should not be bundled in the contract. CCDC asserts that if a renewable fuel is used, then it should be compensated as such. PG&E/TURN disagree with CCDC's proposal. They note that these other environmental attributes are a component of the product being purchased.
5.3.2.1. Allocation of GHG Compliance Costs
In determining how to best allocate GHG compliance costs and green attributes, we need to consider unit efficiencies, operational and dispatch control, and the size of the facility. Based on these considerations, we agree with staff's recommendation that the Buyer should pay compliance costs for the excess electricity.
PG&E/TURN's position that the Seller will not optimize its investment correctly if the Seller does not pay the GHG cost ignores the fact that AB 1613 requires CHP facilities to be new or repowered and to operate at a high operational efficiency, and includes strict technical eligibility guidelines. Similarly, although it is true that the utility will not have dispatch control over the unit, the CEC Staff Draft Guidelines ensure that the electricity being sold to the grid is being produced in a highly efficient manner and meets strict standards for carbon dioxide equivalent emissions.
SCE states that while D.08-10-037 recommended that the point of compliance for the excess electricity should be on the deliverer, the cost of compliance, and who pays it, was not specified. Although it is true that D.08-10-037 recommended that the deliverer be the point of compliance for electricity sold to the grid from CHP systems, it does not follow that the deliverer should always bear the compliance cost. In a carbon constrained system, electricity's carbon content is another attribute that the facility is selling. As such, we agree with staff that the Buyer (and ultimately benefiting customers)78 should bear reasonable GHG compliance costs for the electricity delivered to the grid.
Although we conclude that the Buyer should bear GHG compliance costs, we want to ensure that there is no double payment of these costs and that the payment is limited to the electricity exported to the grid.79 Presently, the ARB has not yet determined the point of compliance for these small and medium (up to 20 MW), highly efficient CHP units, nor have they determined how new CHP entrants will operate under a cap-and-trade system. It is also unknown how these CHP units would be handled in a larger federal system. However, even with the uncertainty surrounding future GHG compliance regimes, the principle that the Buyer shall reimburse the Seller for actual GHG compliance costs associated with the electricity sold to the grid can be applied. For compliance costs associated with procuring emissions allowances, as opposed to direct compliance costs in the form of fees or taxes, we believe that instead of reimbursing the Seller for allowance costs paid by the Seller, the Buyer shall procure allowances on behalf of the Seller. Since the utility Buyer will be procuring allowances for its entire portfolio it will be better equipped to manage allowance procurement at a lower cost for ratepayers.
As an initial matter, we note that AB 32 mandates that GHG compliance costs for electricity commence in 2012 and there is currently no GHG regime in place at the federal level. Additionally, the first compliance period under AB 32 (2012-2014) will focus on large emitters of GHG emissions, while the second compliance period (2015 and beyond) will include smaller emitters of GHG emissions. Therefore, until a compliance program is established in 2012, none of the eligible CHP systems will have GHG compliance costs.
After 2012, eligible CHP systems will either have or not have a direct GHG compliance obligation. For those CHP systems that do not have a direct GHG compliance obligation, and in turn no GHG compliance costs, there is no need for the utility to compensate the CHP facility for GHG and there will be no risk of a double payment.
In contrast, eligible CHP systems that have a direct compliance obligation will need to be compensated for any direct compliance costs that they may incur under a future GHG compliance regime. This is because the pricing method adopted in this decision is based on the costs of a proxy plant constructed and operational prior to 2012. Since there are no GHG compliance costs embedded in the price, requiring the Buyer to pay for these costs would not result in double payment.80
Although the utility (Buyer) would be responsible for compliance costs associated with the exported electricity portion of a CHP facility's annual compliance obligations, this obligation should only be up to the emissions associated with operating the facility at the minimum efficiency level determined by CEC.81 This is reasonable, since the Buyer does not have dispatch or operational control over an eligible CHP facility. We believe that while AB 1613 seeks to foster the development of highly efficient CHP units, if the CHP operator decides to operate its plant in a sub-optimal manner, the ratepayer should not be accountable for the extra GHG compliance costs. Under the CEC Staff Draft Guidelines, an eligible CHP facility that is out of compliance has an opportunity to return to compliance before it is decertified. We do not believe it would be reasonable to ask utilities to bear GHG compliance costs for underperforming facilities. To do so would provide no incentive for an out-of-compliance CHP operator to return to compliance quickly. Therefore, the facility host will be responsible for any additional compliance obligation associated with emissions beyond the limit prescribed in the CEC Staff Draft Guidelines deriving from suboptimal operation of the facility.
5.3.2.2. GHG Reductions and Benefits
According to the contract, a CHP facility will convey all "green attributes" associated with the excess electricity delivered to the grid, including emissions reductions. However, the 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. For accounting purposes only, the utility will need to track the entire facility's avoided GHG emissions that occurred as a result of the installation of the new CHP facility. This information will be used for tracking purposes with the ARB Scoping Plan target for avoided GHG emissions from CHP. Thus, while there is no monetary value to the GHG reduction itself, for program accounting purposes the utility will count the avoided GHG emissions for any facility that signs up under this tariff.
Finally, it is worth noting that there are up to three different elements of the CHP process that will likely have a GHG compliance costs - electricity delivered to the grid (the subject of Section 5.3.2.2 above), electricity consumed on-site, and on-site thermal demand. However, under this FIT, only those compliance costs associated with excess electricity delivered to the grid are considered. Any GHG compliance costs for the other two elements are outside of the scope of the FIT, and we presume that any facility contemplating the development of CHP that would operate under the proposed tariff would consider these other compliance costs during the course of project financing, and that these other sources of GHG compliance costs will also motivate the facility to install, invest, and operate with GHG emissions efficiencies in mind.
5.3.2.3. Other Green Attributes
As mentioned in Section 3.2.2 and the discussion above, several parties argue that the contract price should be even higher to reflect the value of other green attributes. We agree that the electricity being delivered to the grid contains several attributes that have distinct societal and environmental benefits. However, as we have already explained, the adopted Pricing Option 1 includes the value of these benefits. Thus, the transfer of these green attributes are included in the price paid and are embedded in the electricity sold to the grid.
PG&E further maintains that if the Buyer is taking on the GHG risk and associated costs, then it should also receive green attributes such as RECs, if applicable. Fuel Cell maintains that the price paid will not reflect the value of RECs, and therefore the Seller should retain RECs if the Seller uses an eligible renewable fuel. As discussed above, we believe the price paid through this program reflects the value of all the green attributes associated with the power delivered from an eligible CHP facility. However, we note that an eligible CHP facility that is also RPS-eligible could choose to participate in a utility's RPS program rather than this program if the facility believes the price offered under this program is not sufficient.
While the eligible CHP systems under AB 1613 are not required to be RPS-eligible, we look to that program as a comparison. As discussed in D.08-08-028 and SB 107, all green attributes, including RECs, are included in the product sold to the grid. Thus, because the price paid and the benefit received by the customer embody green attributes, the product delivered to the grid contains all green attributes and they cannot be separated.
5.4. Delivery Point, (Simplified Contract Term 1.06; Standard Contract Term 1.03)
The utilities argue that power must be delivered to the point of interconnection with the CAISO-controlled grid, because the power must be scheduled at the CAISO. CHP parties argue that the delivery point should be the first point of interconnection with the utility grid, which may or may not be the same as the point of interconnection with the CAISO-controlled grid. The utilities imply that there are risks associated with accepting delivery at the first point of interconnection with the utility grid and having to transmit and schedule power at the point of interconnection with the CAISO-controlled grid. However, they do not explain the exact nature of the risks.
Fuel Cell suggests that there may be risks associated with either line losses associated with transmitting power over the utility's distribution system or the outright failure of the utility's distribution system.82 Fuel Cell notes that the Delivery term in the contract accounts for line loss risk by requiring the Seller to assume all responsibility for line losses. As for the risk associated with the failure of the utility's distribution system, Fuel Cell suggests this should be borne by the utility.
The Final Staff Proposal recommends that delivery occur at the first point of interconnection between the facility and the grid for both contracts. The Final Staff Proposal noted that all parties except SCE agreed to this for the simplified contract. It further noted the fact that the contract equitably allocates financial risk associated with line losses between the first point of interconnection and the point of interconnection with the CAISO-controlled grid.
In comments to the Final Staff Proposal, SCE reiterated distinctions between its service territory and that of the other two utilities, which result in interconnection more frequently occurring at a point that is not under CAISO jurisdiction. PG&E states that while it and SDG&E agreed to delivery at the first point of interconnection for the simplified contract, they did not think it appropriate for the larger contract. But again, neither party articulated the nature or magnitude of the risk it would assume as a result.
Since line loss risk is addressed in the contract, and the only other risk associated with delivery has to do with utility distribution system failure, which should rightly be the responsibility of the utility, we find no compelling reason to require delivery to the CAISO-controlled grid for either contract. We find it instead appropriate for the utility to accept delivery of power at the first point of interconnection between the CHP system and the grid. We understand that in many cases, particularly for larger systems interconnecting at transmission voltage in PG&E's and SDG&E's territories, this will be the same as the point of interconnection with the CAISO-controlled grid.
5.5. Termination Rights of Buyer (Simplified Contract and Standard Contract Term 2.02(a))
The IOUs propose that signed contracts may be terminated by the Buyer based on subsequent actions by the Commission. Specifically the IOUs propose that if the Commission "in any way diminishes the Buyer's rights...to collect any above-market costs of this Agreement from Departing Load Customers" or if the Commission eliminates the mandatory purchase obligation under this program, then the Buyer can terminate existing contracts. CHP parties oppose this term arguing that it would provide uncertainty in the contract.
The Final Staff Proposal agrees with CHP parties that this contract term is unreasonable and provides too much uncertainty in the contract. SCE urges the Commission to reject staff's recommendation. It states that the utility's obligation to purchase stems from AB 1613. Thus, it argues that if AB 1613 were repealed or eliminated, or the state were to place a higher priority on other sources of generation, the utility should not be required to continue purchasing power under an AB 1613 contract.83
We do not find SCE's arguments persuasive. The contracts entered into under this program would be for no more than 10 years in duration and do not provide for extensions under the existing terms. Further, if AB 1613 were repealed or eliminated, the electrical corporations would not be required to enter into any more contracts. Thus, if AB 1613 were repealed or eliminated, the electrical corporations would purchase power under these existing contracts for no more than 10 years. In contrast, to allow any future regulatory action to nullify an existing contract would undermine the contract and compromise the efficacy of this program in promoting CHP deployment. Based on these considerations, we agree with staff that the IOUs' proposed term should not be included in the contract. Moreover, SCE's comments are essentially asking the Commission to include a term that would permit a utility to breach the AB 1613 contract in the future without any consequences. We decline to adopt such a provision and accept staff's proposal to eliminate this term in its entirety.
5.6. Indemnity (Simplified Contract Term 7.03(d); Standard Contract Term 9.03 (f))
The Final Staff Proposal recommends removing a provision in both contracts requiring the Seller to indemnify the Buyer against failure to deliver electricity, capacity or resource adequacy (RA) benefits. Staff reasons that such a requirement is not appropriate for an as-available contract.
SCE was the only party that thought this provision was necessary for the simplified contract. PG&E argues that while not necessary for smaller facilities under the simplified contract, it is necessary for the larger contract since the utility may incur RA penalties as a result of a facility's failure to operate. Fuel Cell notes that such penalties and requirements to provide the Seller specific RA benefits are not required by AB 1613, and inappropriate for as-available contracts.
We do not find it reasonable for a CHP generator under the simplified contract to be required to indemnify the utility against potential penalties for failure to deliver any benefits. However we do find it reasonable for larger facilities under the standard contract to be subject to such a requirement. Because the contract transfers all benefits of the power product from the CHP generator to the utility, CHP generators under the standard contract should be required to the greatest extent possible to ensure that those benefits can be used by the utility to meet its obligations. We discuss this further in Section 5.10 below.
5.7. Eligible CHP Facility Status (Simplified Contract Term 3.14; Standard Contract Terms 2.01(a) & 3.16)
AB 1613 directed the CEC, by January 1, 2010, to adopt technical guidelines for CHP systems eligible for this program. Work is ongoing at the CEC to establish these guidelines and a process for certifying an eligible CHP facility. As previously discussed, the CEC issued its draft guidelines on October 1, 2009.
In order to be eligible for either the simplified contract or the standard contract adopted by this Commission in this decision, a CHP facility must obtain certification from the CEC as an eligible CHP facility and maintain that certification throughout the contract period. The standard contract submitted by the Working Group on May 15, 2009 included several provisions to ensure that any CHP system participating under AB 1613 had been certified by the CEC. Further, the standard contract provides that failure to maintain CEC certification throughout the contract period would represent an event of default under the contract. A similar provision shall be included in the simplified contract. The guidelines adopted by the CEC ensure that CHP facilities will provide the benefits envisioned by this program.
5.8. Qualifying Facility Status (Standard Contract Terms 1.02(f), 2.01(b), 3.10(a)(v), 3.16, 6.01(c)(xviii) & 9.02(h) and Exhibit O)
The Final Staff Proposal recommends removing all references to QFs in the contract. This recommendation is based on the Amended Scoping Memo, which clarified: "Although CHP facilities developed under AB 1613 could qualify as QFs under the Public Utilities Regulatory Policies Act of 1978, AB 1613 is not a subset of the QF Program adopted in D.07-09-040. Instead, AB 1613 focuses on a specific type of generator (i.e., new CHP under 20 MW that will meet efficiency standards established by the CEC) and does not require this type of generator to have QF status. More importantly, AB 1613 was enacted to reduce waste heat, which furthers the State's overall policy goal to reduce greenhouse gas emissions."84
We agree with staff's recommendation to remove any references or terms related to QFs in the contracts. As discussed in Section 3.1 above, AB 1613 does not make any references to PURPA and there is no requirement that an eligible CHP have QF status in order to participate in the AB 1613 program. Accordingly, all references and terms related to Qualifying Facilities or QFs in this contract should be deleted in their entirety. While eligible CHP facility may choose to become a QF, this shall not be a requirement of the contract.
5.9. Credit and Collateral (Standard Contract Term 1.06 and Exhibit D)
CHP parties dispute the need for Performance Assurance and Development Security. The IOUs prefer to include the bulk of credit and collateral provisions from the QF contract. The Final Staff Proposal recognizes the need for credit and collateral provisions in balancing financial risk between Buyer and Seller. Staff, however, recommends reducing the amounts of Performance Assurance and Development Security proposed by utilities.
Staff recommends Performance Assurance of 5% of expected revenue over the life of the contract instead of 12 months of expected revenue as the utilities propose. Staff recommends Development Security of $20/kW, not to rise over the project development timeline. The utilities' proposal would increase Development Security to $60/kW after 18 months into the project development timeline.
In comments to the Final Staff Proposal, SDG&E and PG&E reassert their position that credit and collateral protect ratepayers and IOUs against CHP defaults, and are necessary to mitigate credit risk. PG&E agrees with the staff proposal that 12 months of expected Performance Assurance may be excessive given the fact that contract term lengths under this program may be as little as one year. PG&E instead proposes Performance Assurance of 10% of expected contract revenue. PG&E argues that increasing Development Security to $60/kW-year after 18 months is required to protect ratepayers from relying on CHP power for planning purposes only to find out that it is not available. PG&E does not explain why $20/kW-year is inadequate for this purpose.
We agree with staff's assessment that credit and collateral provisions can play an important role in balancing financial risk between utilities and ratepayers on the one hand and CHP project developers on the other. We note that the utilities' proposed credit and collateral requirements are based on a QF contract that contemplates much larger systems than the 20 MW maximum system size under this program. Just as 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, we find it appropriate to reduce the level of credit and collateral provisions for systems less than or equal to 20 MW. Even credit and collateral provisions that are based on the proportional size of a project, such as those proposed here, can have a disproportionate impact on smaller project developers who are likely to face higher costs to post credit and collateral.
Since the projects and project developers participating in this program are likely to be smaller than those contemplated by the QF contract, we find it appropriate to reduce the levels credit and collateral from that contract. We note that one important role of credit and collateral is to ensure that only real and viable projects sign contracts. We find the levels of credit and collateral proposed by staff reasonable for this purpose given that the likely participants in this program will be smaller developers.
5.10. Conveyance of the Power Product (Standard Contract Term 3.01) and Resource Adequacy Benefits (Standard Contract Term 3.02)
The Final Staff Proposal recommended replacing two terms related to the Conveyance of the Power Product (3.01) and Resource Adequacy Benefits (3.02) in the standard contract with the terms proposed in the simplified contract. Staff believes that the terms in the standard contract are vague and potentially problematic and that the terms in the simplified contract sufficiently address the same issues.
PG&E argues that these terms should not be replaced, noting that these more detailed terms are relevant for larger projects and that the simplification agreed upon by parties in the simplified contract is only applicable to smaller facilities. Fuel Cell notes that it does not object to the first term. However it does object to the second. Fuel Cell notes that language in contract term 3.02 of the standard contract imposes burdensome obligations on a CHP generator that are not required by AB 1613. Fuel Cell notes that this term introduces significant risk upon a CHP facility because it would oblige the facility to commit its output to the Buyer for use in meeting its RA obligations no matter how those obligations may change in the future.
We decline to adopt staff's recommendations. These two contract terms had originally been proposed by staff in the February 3rd Staff Proposal. Standard contract term 3.01 was subsequently revised by parties as part of the Workshop Report, these revisions served to clarify the term. The Workshop Report does not indicate any dispute between parties on the revisions to the term. No revisions were made to standard contract term 3.02.
We agree with PG&E that the more detailed terms should be retained for the standard contract. Moreover, with respect to term 3.02, under the contract the Seller will convey to the Buyer all benefits associated with the product, including energy and capacity benefits. For this, the Buyer will compensate the Seller. We find it reasonable that to the degree the capacity of CHP helps the utility meet its RA obligations, the Seller should be obliged to commit its output for this purpose. Accordingly, we retain contract terms 3.01 and 3.02 originally proposed by the Working Group for the standard contract.
5.11. Generating Facility Modifications (Standard Contract Term 3.07(b))
The IOUs propose a provision that the Seller must obtain consent of the Buyer before making any material modifications to the CHP facility. The CHP parties prefer the existing provision that a Seller must provide 30 days advance notice to Buyer of material modifications. The staff proposal recommended deleting the requirement that a Seller must obtain consent of the Buyer before making modifications to the CHP facility.
SCE claims that without this provision, a CHP generator could expand a facility's nameplate rating or amount of export and could impact the adequacy of the interconnection facilities. Fuel Cell points out that the CHP generator's interconnection agreement has specific capacity requirements and that if a modification to the facility would go beyond what is allowed by the interconnection agreement, then the facility would be responsible for all study fees and upgrade costs. Furthermore, Fuel Cell notes that a requirement that utility consent is required for any modifications would discourage participation.
We find no compelling reason why the utility's consent should be required by this contract for facility upgrades. Interconnection impacts will be addressed by the interconnection agreement. Furthermore, the requirement in standard contract term 3.16 that a CHP facility maintain certification as an eligible CHP pursuant to the CEC's guidelines will ensure that no modifications will increase the size above 20 MW or alter the facility beyond what is allowed for this program.
5.12. Assignment (Standard Contract Term 9.04)
The Final Staff Proposal recommends deleting the sentence "Any direct or indirect change of control of Seller (whether voluntary or by operation of law) will be deemed an assignment and will require the prior written consent of Buyer, which consent will not be unreasonably withheld." from Term 9.04. Staff notes that Fuel Cell objects to this language. Fuel Cell claims this provision would give the utility de facto veto rights over the CHP generator's internal business decisions.85 Fuel Cell also notes that the contract does not give a CHP generator the reciprocal right over changes of ownership by the utility.
SCE opposes staff's recommendation, stating "it is commercially unreasonable to give the parties an unlimited right to arbitrarily change their ownership or the ownership of their parent entities."86 PG&E and SDG&E state that this sentence may be deleted if Performance Assurance and Development Security remained in the contract. However, PG&E argues that since the Final Staff Proposal recommended reducing the Performance Assurance and Development Security, there is a concern that a change of ownership of a CHP generator that occurs without the utility's consent would limit the utility's ability to collect damages in the event of a default.
We decline to adopt staff's recommendation. The sentence at issue clarifies what would be included as an assignment. As SCE notes, it would be unreasonable to give parties an unlimited right to arbitrarily change ownership, especially if the transfer is to an insolvent entity. Further, the provision does not grant the utility automatic veto power, but rather a right to consent, which consent will not be unreasonably withheld. We do believe, however, that Fuel Cell raises a valid concern that this term only applies to the Buyer. Concerns over assignment of the contract and solvency of a new owner apply equally to the Buyer and the Seller. Consequently, we modify Term 9.04 to read:
Neither Party may assign this Agreement or its rights under this Agreement without the prior written consent of the other Party, which consent may not be unreasonably withheld or delayed. Any direct or indirect change of control of either Party (whether voluntary or by operation of law) will be deemed an assignment and will require the prior written consent of the other Party, which consent will not be unreasonably withheld. Notwithstanding anything to the contrary in this Section 9.04, Seller may, without the consent of Buyer (and without relieving itself from liability hereunder):
(a) Transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements in accordance with Section 9.05; and
(b) Transfer or assign this Agreement to an Affiliate of Seller which Affiliate's creditworthiness is equal to or higher than that of Seller.
73 SCE Reply Comments, September 3, 2009, at 9-11.
74 CCDC Opening Comments to PD, November 19, 2009, at 7-8.
75 SDG&E/SoCalGas Opening Comments, August 24, 2009, at 8-9.
76 PG&E/TURN Comments, August 24, 2009, at 3.
77 CCDC Comments, August 24, 2009, at 7.
78 As discussed in Section 3.3 above, GHG compliance costs shall be allocated to all benefiting customers.
79 In comments, PG&E and TURN asked for additional guidance on this issue. The ARB has already adopted its mandatory reporting requirements for CHP, which provides the methodology to determine the GHG emissions associated with the electricity exported to the grid; the mandatory reporting requirements methodology will determine the number of emissions that are subject to payment in this program. Rules about the mandatory reporting requirements are available online at http://www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep.htm.
80 We note that there is a possibility that at some point in the future the direct GHG compliance obligation on CHP facilities may be removed. There has been some discussion from ARB of imposing a compliance obligation on upstream natural gas; in this instance, the direct compliance obligation would be removed and the compliance obligation on CHP facilities would be embedded in the price of natural gas. In such a case, where GHG compliance costs are embedded in the price of natural gas, pricing Option 1 would account for this, since actual gas prices are included in that pricing formula. Therefore, if the ARB were to impose such a compliance obligation on upstream natural gas, it would no longer be necessary for the utility to compensate the CHP facility for these "indirect" GHG compliance costs and doing so would represent a double payment.
81 Based on the CEC Draft Staff Guidelines, this is 1,100 pounds/MWh.
82 Fuel Cell Reply Comments, September 3, 2009, at 4.
83 SCE Comments, August 24, 2009, at 21.
84 Amended Scoping Memo and Ruling of Assigned Commissioner and Administrative Law Judge, April 1, 2009, at 3.
85 Fuel Cell Reply Comments, September 3, 2009, at 9.
86 SCE Comments, August 24, 2009, at 22.
