Chapter 5 Developing Markets for Renewable Energy Certifi cates
B. Commodity Futures Trading Commission
VI. Documenting Compliance REC and Voluntary
As with all new products, documenting transactions and executing master agreements are initial challenges. As of the date of this writing, there is no widely accepted stan- dard industry master agreement for trading RECs, although market participants are working to finalize a trading annex to the Edison Electric Institute (EEI) Master Agreement, which if adopted, likely will be replicated by the International Swaps and Derivatives Association, Inc. (ISDA). In 2006, the Environmental Markets Association (EMA) undertook a heroic effort to try to synthesize industry preferences into a stan- dard trading agreement that could be widely adopted, but the agreement has yet to gain momentum in the industry.
Drafting homegrown master agreements to trade new products is expensive, and negotiating them to execution is even more costly. The absence of standardized terms means that counterparties must read and analyze in some cases more than twenty pages of individualized physical, legal, and credit terms. This makes it very difficult, if not impossible, to efficiently establish master agreements with a reasonable number of counterparties.
As an alternative to lengthy master agreements, some market participants enter into long-form confirmations, which in some cases, are nearly the length of master agree- ments. That said, long-form confirmations can be easier to get executed, in part, because they only apply to one transaction, as opposed to all transactions between the parties. Moreover, once long-form confirmations are negotiated, parties often agree to use the same terms as a template for subsequent deals. Most recently, many market participants desiring to reduce transaction costs and increase the ease with which they complete negotiations, have started to negotiate long-form confirmations to trade RECs under an ISDA power or emissions annex or under an EEI master agreement without a REC Annex.
A. Unique Documentation Risks
1. Product/Defi nitional Risk In the absence of standardized physical terms, there is a great deal of risk in defining the product that is being sold. For those that intend to purchase and subsequently resell RECs, rather than use them for compliance or other purposes, standardization of physical terms becomes even more important because
“you can’t sell what you don’t have.”
DOCUMENTING COMPLIANCE REC AND VOLUNTARY REC TRANSACTIONS
Transactions for RECs involve certain unique problems. For example, some coun- terparties use individualized product definitions, rather than keying the definition to the requirements of the applicable RPS. An example of a standard definition that can be easily replicated from transaction to transaction and which tracks the governing RPS is as follows:
“Renewable Energy Certificate” or “REC” means a NJ [Class I]/[Class II]
Renewable Energy Certificate that has been issued by the New Jersey Board of Public Utilities (BPU) or PJM-EIS for the applicable Reporting Year(s) and that represents all of the environmental benefits and attributes of one megawatt-hour of generation that, for and during the applicable Reporting Year(s), qualifies as [Class I]/[Class II] renewable energy generation from a generating facility that meets all of the requirements of New Jersey’s Renewable Portfolio Standards, N.J.A.C.
14:8–2.1 et seq. as may be amended from time to time (RPS).
This definition helps to ensure that the purchaser is buying a product that is issued by the appropriate governmental agency and that meets the requirements of the RPS.
Some counterparties will attempt to freeze the RPS in time and define the product as a REC that meets the requirements of the RPS as it exists at the time the contract is executed. This presents practical problems because, in general, the issuing agency will only issue a REC that meets the requirements of the RPS at the time it is issued.
Counterparties wishing to reduce risks associated with regulatory change are better served by negotiating change in law provisions separate and apart from the product definition. 40
Sometimes counterparties will try to commoditize the various sticks in the bundle of environmental attributes. In other words, they may attempt to carve out a certain envi- ronmental attribute from the definition of a REC. They may provide that the REC rep- resents all of the environmental benefits and attributes of one megawatt-hour of generation “except to the extent that the applicable law allows them to receive additional credit for carbon or another environmental attribute.” This can create problems, both for commercial desks trying to determine what they own and also in terms of the REC’s value as a compliance product to a downstream buyer. Most RPSs require that RECs represent all of the environmental attributes associated with a MWh of generation.
The risks increase exponentially with respect to voluntary RECs that cannot be defined by reference to a state RPS. Some RECs, like Green-e RECs, have nearly unlimited possible definitions. Green-e RECs are defined not only in terms of vintage years, state of generation, and resource type, but also can consist of any number of resource mixes, such as 40 percent wind and 60 percent hydro, etc.
2. Verifi cation Risk Although compliance RECs are issued by governmental authori- ties, those same authorities sometimes will require the purchaser of RECs to file docu- mentation supporting the eligibility of the underlying renewable resource. For example, the New Jersey Board of Public Utilities sometimes requires the compliance entity to submit documentation verifying the generator of the RECs. If the compliance entity
40 See Section IV.A.3, above, for a discussion of regulatory change provisions.
has purchased its RECs from a middleman or a broker, it may have difficulty obtaining this documentation unless it specifically asks for such documentation in its purchase and sale agreement.
3. The Risk of Regulatory Change The nature of RECs, the value of which stems solely from regulation, creates a great deal of uncertainty in the market because regula- tions and rules are subject to change. For this reason, some companies participating in the REC markets have crafted rigorous regulatory change provisions for their transac- tion documents to govern how the parties will address changes to applicable law. Many also include broad seller limitations of warranty, including with respect to merchant- ability and fitness for a particular purpose. One of the most significant issues facing REC market participants today is the possibility of a national RPS, and how such a program would interact with the various state RPS programs. 41 See Section VIII, below for a discussion of initiatives to create a federal RPS.
4. Calculating Cover Costs and the Impact of the ACP In those states that provide for payment of an ACP in lieu of retiring RECs, sellers should consider capping the damages they may be required to pay for failure to deliver RECs at the amount of the ACP. The ACP provides a reasonable cap because it generally is equal to the damages the buyer would suffer as a result of not receiving the RECs pursuant to its agreement.
VII. RECs AND RENEWABLE FINANCING
A. Who Owns What?
RECs often are used as collateral and revenue sources in hedging, finance, and power purchase agreement structures. 42 The best way to ensure that RECs are allocated in accordance with the intent of the parties to a structured transaction or long-term power purchase agreement is to include precise language in the agreement. 43 For preexisting agreements that do not clearly allocate the environmental attributes (EAs) of a project, courts and PUCs likely will apply general principles of contract law to determine the apparent intent of the parties. 44 This analysis is particularly challenging when evaluating contracts that were negotiated prior to the development of regulatory and voluntary programs that require and/or allow registry and submission of RECs or other green allowances or credits because the parties most likely did not contemplate the existence of EAs at the time they entered into such agreements. Moreover, a court or PUC’s
41 See Section II.A, above, for a discussion of the ACP.
42 See Chapters 15 and 18.
43 See Chapter 20 for a discussion of power purchase agreements.
44 A court’s or PUC’s interpretation of the parties’ intent will depend on many factors, including the state law governing the contract, whether the UCC applies (e.g., if electricity is considered a good under the applicable law), the language of the contract as interpreted using the general principles of contract law (e.g., course of dealing between the parties, industry custom and usage, and course of performance of the contract at issue, if applicable).
RECs AND RENEWABLE FINANCING
determination can differ from state to state and also can differ depending on the type of EA at issue (such as RECs, carbon avoidance, or tax equity credits).
Several state PUCs have considered the issue with respect to whether newly created RECs belong to the purchaser or seller of renewable electric power sold pursuant to power purchase agreements executed before the existence of state RPS programs. At least nine PUCs that have considered the issue in the context of power sold by qualify- ing facilities (QFs) 45 to state utilities have found that the associated RECs transferred to the purchaser of the energy under the power purchase agreement. 46 For example, both Connecticut and New Jersey have ruled that long-term contracts for the purchase of renewable energy from QFs that had been negotiated prior to the implementation of the state REC program also transfer the ownership of the associated RECs. In Wheelabrator , the Connecticut Department of Public Utility Control (DPUC) deter- mined that, under Connecticut law, a QF that had contracted to sell its “entire net electrical output” to a utility prior to the existence of Connecticut’s REC program was deemed also to have contracted to sell its RECs, referred to as “GIS certificates” in Connecticut. 47 The DPUC considered the intent of the parties when entering into the contract and concluded that the QF and its purchaser “intended that renewable energy attributes generated by [the QF] . . . be included in the entire net electric output of the facility” even though GIS certificates did not exist at that time. 48 The DPUC based its conclusion, in part, on the fact that it had approved the utility purchase expressly because the electricity had been generated by renewable fuel, a policy goal articulated in the Public Utility Regulatory Policies Act of 1978 (PURPA), which directed utilities to purchase energy from QFs. 49 The U.S. Court of Appeals for the Second Circuit affirmed the DPUC’s decision in 2008. 50
45 A qualifying facility, or QF, is a generating facility that meets the requirements for QF status under the Public Utility Regulatory Policies Act of 1978 (PURPA) and Part 292 of the Federal Energy Regulatory Commission’s (FERC) Regulations (18 C.F.R. Part 292), and which has obtained the necessary certifi cations. There are two types of QFs: cogeneration facilities and small power production facilities. A cogeneration facility is a generating facility that sequen- tially produces electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, residential, or institutional purposes. A small power produc- tion facility is a generating facility whose primary energy source is renewable and that other- wise meets the requirements of 18 C.F.R. §§ 292.203(a), 292.203(c) and 292.204. Small power production facilities are limited in size to 80 megawatts (MW), with certain limited exceptions.
46 At least nine states have ruled that, as applied to existing contracts for the sale of power to utilities by renewable energy producers, RECs are the property of the purchasing utility, rather than the producer. See Edward A. Holt et al., Who Owns Renewable Energy Certifi cates? An Exploration of Policy Options and Practice , at xiv (Ernest Orlando Lawrence Berkeley National Laboratory 2006), available at eetd.lbl.gov/ea/emp/reports/59965.pdf.
47 Wheelabrator Lisbon Inc. v. State of Connecticut Department of Public Utility Control , 526 F. Supp. 2d 295, 300 (D. Conn. 2006).
48 Id.
49 Id . at 305.
50 Wheelabrator Lisbon, Inc., et al. v. State of Connecticut Department of Public Utility Control , 531 F.3d 183 (2d Cir. 2008).
Similarly, in New Jersey, the Superior Court affirmed a ruling of the BPU, allocat- ing the RECs associated with energy purchased from a QF under a preexisting long- term power contract to the purchasing utility. 51 Like the Connecticut DPUC, the New Jersey BPU relied, in part, on the fact that the BPU had approved the long-term utility contracts because the electricity had been generated by a renewable facility. In addi- tion, the BPU relied on the fact that it had approved such contracts at prices that were higher than the market rate for electricity to “[take] into account the environmental attributes of the power being sold.” 52 The BPU, therefore, ruled that the environmental attributes associated with the renewable generation were an intrinsic aspect of the electricity purchased under the agreements.
At least one state PUC faced with the question of whether RECs transferred to the buyer under a long-term power purchase agreement with a QF, ruled that the RECs did not transfer to the buyer. In In re Midwest Renewable Energy Projects , the Iowa Public Utilities Board (the Iowa Board) found that “[the seller] may, but need not, sell its Green Credits to [the buyer].” 53 The Iowa Board accepted the seller’s argument that the
“avoided cost rate” under the contract did not include the value of the associated RECs, rejecting the buyer’s argument that the RECs were part of the energy and capacity sold under the agreement. 54 The Iowa Board based its decision in part on the fact that PURPA does not explicitly require that utilities purchase renewable power — but rather power — from QFs, which can also include fossil-fuel-cogeneration facilities, and thus the value of the Green Credits was not included in the avoided-cost rate approved by the Iowa Board. 55
Some state PUCs have passed the issue back to market participants to resolve. For example, in the process of developing its tradable REC program, Minnesota recently considered (and then specifically declined to make a general determination) as to how RECs would be allocated under preexisting long-term energy contracts. The Minnesota PUC explained: “The interpretation of particular power purchase agreements is not an issue the [Minnesota PUC] must decide in this Order . . . however, the [Minnesota PUC] will require utilities with power purchase agreements that are silent or ambigu- ous on the ownership of green tags, including renewable attributes, to actively pursue negotiations and settlements to clarify the ownership issue, if such facilities are to be used to meet the renewable energy objectives/renewable energy standards.” 56
51 See In re Ownership of Renewable Energy Certifi cates Under the Electric Discount and Energy Competition Act, As It Pertains to Non-Utility Generators and the Board’s Renewable Energy Portfolio Standards , 389 N.J. SUPER. 481 (2007), appealed from Board of Public Utilities, Agency Docket No. EO04080879 (2005).
52 Id. at 487 ( citing from the BPU decision).
53 In re Midwest Renewable Energy Projects , 2005 Iowa PUC LEXIS 540 at * 19 (2005).
54 Id. at * * 15–20; see also a related case at Midwest Renewable Energy Projects, LLC , 116 FERC P61,017 (July 7, 2006) ( discussing In re Midwest Renewable Energy Projects , at 2005 Iowa PUC LEXIS 540).
55 Id. at * 18–20. This decision may have been infl uenced by the fact that Iowa does not allow the use of Green Credits for compliance with its mandatory alternate energy production purchase requirement although this factor is not expressly relied on in the opinion. Id. at * 15.
56 See Minnesota PUC, Order Establishing Initial Protocols for Trading Renewable Energy Credits, Docket Nos. E-999/CI-04–1616 and E-999/CI-03–869 at 11 (2007) (REC Order).
RECs AND RENEWABLE FINANCING
In general, the cases and proceedings addressing this issue indicate that any court or PUC reviewing a particular power purchase agreement likely will consider evidence of the parties’ intent, including, but not limited to (1) the price paid for power, (2) the lan- guage of the agreement, and (3) the regulatory framework within which the agreement was executed, in determining how to allocate EAs under an agreement that is ambigu- ous or silent with respect to such allocation. Broad generalizations are difficult to make because each court or PUC will review the facts and law from its own perspective.
Another issue related to REC ownership includes who owns RECs as between a photovoltaic rooftop solar developer who owns the solar cells and related equipment that produces the REC, and the business or home owner who leases its rooftop space to that developer. In several states, including Arizona, for example, the owner of the asset that generates the REC—the solar cells—owns the REC, not the business or homeowner, unless the REC is specifically transferred to another party by contract.
B. Insolvency Issues — What Is a REC?
You may have determined that you have a right to receive the RECs associated with a particular project or power purchase agreement, but is your right protected if the proj- ect developer goes bankrupt? With respect to a project or a unit-contingent agreement, if the developer becomes insolvent or bankrupt, the rights of any entity with a lien on the project or its assets would be effectively superior to the rights of the investor because the lien holder could foreclose on and sell the assets that would be used to generate the RECs. This would leave the investor or the purchaser of RECs under a unit-contingent agreement with only a claim against the bankruptcy estate. The inves- tor/purchaser could improve its position by obtaining and perfecting a security interest in the RECs that have already been generated or in the other project assets because the value of the investor’s secured claim would then be superior to unsecured creditors’
claims against the developer’s estate.
For purchasers of RECs pursuant to a non-unit contingent agreement, the primary question is whether the agreement is a forward contract and, thus, exempt from the automatic stay. Whether a purchase of RECs also is considered a forward contract depends in part upon whether a REC is considered a “commodity” under the Bankruptcy Code. The Bankruptcy Code defines a commodity by referring to the definition of commodity in the CEA.
Also note that all RECs used for compliance with the Minnesota RPS must be tracked and traded on the Midwest Renewable Energy Tracking System (M-RETS). See id. at 12 (requiring that all generation units used to meet the state’s renewable energy objectives/renewable energy standards must be registered in M-RETS, commencing with the 2009 compliance year). The REC Order also indicates that the generator must attest to the ownership of the renewable attributes during the registration process on Schedule A. The language of Schedule A, how- ever, requires only that the generator attest to the ownership of the generation unit. Compare id. at 10–11 with M-RETS Schedule A, available at http://www.mrets.net/resources/M-RETS_
SCHEDULE_A-11.2008.pdf .
As discussed in Section V.B, above, RECs generally are considered commodities for purposes of the CEA and would therefore be commodities for purposes of the bankruptcy safe harbor for forward contracts. Although there are some REC prod- ucts for which there are no futures contracts, the CEA defines the term “commodity”
very broadly to include commodities that at some point could form the basis of a futures contract. It is very likely that the CFTC would view all tradable RECs as com- modities despite the fact that certain state RECs do not yet form the basis of a futures contract.
VIII. A FEDERAL RENEWABLE ENERGY STANDARD OR RPS?
About half of the states in the United States have enacted some form of RPS to require retail power suppliers to provide a portion of their electricity sales from renewable energy sources. Although a number of those states now allow for compliance through the submission of RECs, many require that the RECs be generated within the state or at least generated by an eligible resource that delivers power into the applicable ISO.
While REC trading theoretically creates price signals that drive investment in renew- able projects, the fragmented nature of state RPS geographic and other eligibility requirements has limited their usefulness in this regard.
A federal RPS could provide one standard set of eligibility requirements and, thus, a national market for RECs. This may significantly increase the value of voluntary RECs that meet the national standard and provide greater incentives to invest in renew- able projects. Still, some question the need for a federal RPS. Given the success of many state RPS programs, some believe that federal intervention would be unneces- sary, wasteful, and duplicative, or might discourage individual states’ efforts.
Whether those concerns are valid depends, in large part, on the type of federal RPS implemented (e.g., a preemptive federal RPS or a federal RPS that overlays existing state RPS requirements). Although both options raise concerns, a preemptive approach would be more likely to cause significant disruptions, because it would force states to forgo their own RPS efforts and interfere with existing contracts and commercial expectations. A preemptive federal RPS likely also would fail to sufficiently accom- modate states’ individual RPS needs. And lastly, from a practical perspective, a preemptive federal RPS would be less likely to garner enough votes in Congress due to probable opposition from many states’ representatives.
While a federal RPS overlay would be less likely to significantly disrupt individual state efforts and would continue to allow renewable standards to be tailored to individ- ual state needs, it may raise other concerns. Foremost among them, a federal overlay would result in inconsistent RPS standards across the country. It also would create a two-tiered compliance obligation for entities in states with existing RPS that could cause greater confusion for some entities regarding their dual compliance requirements.
The most strongly supported legislative initiative pending in Congress, as of the time of this writing, is the American Clean Energy and Security Act of 2009 (May 18, 2009), commonly referred to as the Waxman-Markey Bill. The proposed Waxman Markey Bill appears to adopt an overlay approach and expressly (1) preserves current