The potential for a federal renewable energy standard (RES) and carbon regulation, considered with the effect of state-imposed renewable energy standards, is fueling a strong, but challenging, market for renewable energy. Utilities are competing to sign up the best new projects, the types of renewable technologies available are increasing, and there are various government stimulus programs for energy; yet, the financial markets still are hesitant.
Against this backdrop, how should contracts for power from new renewable resources be shaped so that those deals will look as good five, 10 and 15 years after execution as on the day the ink dries? Some market trends, creative answers and best practices are emerging in the marketplace.
Legislative and regulatory changes are forcing utilities to “go green.” The American Clean Energy and Security Act of 2009, passed in the U.S. House of Representatives on June 26, 2009 (Waxman-Markey Bill), proposes a federal RES and roughly 30 states already have established their own standards—some mandatory, some advisory. The proposed federal RES would require each utility to obtain a portion of the energy that it delivers to consumers from renewable resources, starting at 6 percent in 2012 and increasing to 20 percent by 2021—with up to 25 percent of its obligation met by energy efficiency. A utility that fails to meet the requirement in any given year would be obligated to procure offsets or allowances from the market to cover the shortfall. Of course, final federal legislation might differ or include no federal standard at all. But even so, utilities must consider the possibility of adverse financial consequences under their state programs, where such programs exist. Further, the likelihood of federal carbon legislation being passed in the coming years provides another source of financial pressure.
Clean-tech investments in non-renewable resources, such as emerging carbon-sequestration technologies, may reduce the base amount against which renewable penetration is measured. For example, in the Waxman-Markey Bill, a utility’s achievement of its annual renewable target is measured by the proportion of generation met by renewable resources and energy-efficiency measures as compared to a base amount of megawatts sold at retail. But the base amount excludes clean generation, such as from a hydroelectric plant that doesn’t qualify as a renewable resource, new nuclear generation and the portion of fossil-fueled generation for which the associated greenhouse-gas (GHG) emissions have been geologically sequestered. Thus, the mix of a utility’s resources, including its use of clean technologies other than renewable energy, can affect the amount of renewable power needed. Further, the decision to invest in renewable and clean-tech projects is strongly influenced by the expected market cost of carbon allowances, which in turn will be influenced by the market penetration of renewable and clean-tech projects.
The pressure on utilities to acquire renewables influences the balance of negotiating leverage between a utility purchaser and a renewable developer in favor of the developer, but developers must compete against others for contracts. Thus, each negotiating party has incentive to maintain a competitive market position. Buyers need to think about how to secure long-term protection in an evolving market, despite the pressure to contract quickly for a large quantity of renewable energy, and sellers need to consider how to differentiate themselves from the market as the resource for now and the future.
In many respects, a contract to purchase the output of a renewable resource is like any other unit-specific power purchase and sale agreement; it includes terms and conditions for price, quantity, term, place of delivery, creditworthiness and security, events of default and remedies, indemnifications, limitations on liability and dispute resolution. But some issues deserve special attention, including environmental attributes and transmission risk. In addition, the concerns of prospective project lenders should always be considered during contract negotiations in order to assure the final contract is financeable and, therefore, viable.
A key question involves whether a resource will count toward the requirements of a state program or a potential federal program. The answer depends on the applicable statutes and regulations. A renewable resource typically is defined to include solar, wind and geothermal, but other acceptable technologies vary substantially by jurisdiction. Many states limit the types of biomass and hydropower generation eligible to qualify under an RES. For example, unlike California or Washington, Arizona’s regulations don’t include any ocean technologies—not surprising given its non-coastal location. But Arizona’s regulations have very specific requirements for other types of qualifying hydropower. Arizona will include energy from certain hydropower facilities of 10 MW or less installed after Jan. 1, 2006, incremental energy from increased capacity resulting from efficiency or operational improvements at a pre-1997 hydropower facility, and the amount of energy from a pre-1997 hydropower plant of any size used to firm-up or regulate an intermittent resource.
The Waxman-Markey Bill would allow the federal RES to be met by more common forms of energy such as wind, solar, geothermal and renewable biomass, but also energy from several other specific resource types, including:
• Biogas and biofuels derived exclusively from renewable biomass;
• Energy from efficiency gains and capacity additions added after 1988 at pre-1988 hydropower facilities;
• Energy from generation capacity added after 1988 to a dam built before 1988 with no previous power production, if certain qualifications are met;
• Marine and hydrokinetic projects;
• Landfill gas, wastewater treatment gas, and coal mine methane used to generate electricity at or near the mine mouth; and
• Qualified waste-to-energy.
States are permitted under the House bill to impose requirements that are more stringent than the federal standard, but the details of how to reconcile conflicts in the programs, such as subtle differences in the types of projects that may qualify, will require attention.
To assure the resource meets the applicable requirements, the contract should contain representations and covenants regarding the characteristics of the facility. Omitting such provisions is unwise—although it happens, presumably by oversight—because those provisions are a necessary predicate to addressing the more challenging question: namely, how to address the change in contract value if the applicable standard changes? Few contracts presently address this.
One contractual approach requires seller’s certification of the resource’s expected and continuing qualification under the applicable state law. In the event of a change in the applicable state law, the seller is protected from default for failure to meet the changed qualification so long as the seller uses “commercially reasonable efforts” to qualify under the changed legal standard. However, the contracting parties should also consider the impact of a shift from a state-defined to a federally-defined RES. If a federal standard is enacted, and that definition of a renewable resource fails to incorporate the technology of a facility that meets the applicable state standard, then the continuing value of the renewable energy credits (REC) generated by that state-qualified facility would depend on whether an independent state REC requirement, for which the state-qualified RECs have value, continues to exist.
The problem can be addressed contractually; for example, the parties could agree to a lower price applicable in the event the facility cannot generate RECs that meet a changed regulatory scheme (i.e., reflecting its continuing value as a clean resource, even if not generating RECs), but the adjusted price will need to be sufficient both in amount and in definition to support financing. Under this approach, equity would absorb the difference. Legislatively, a possible fix is to grandfather into any federal program all contracts entered into in compliance with a state program. In the absence of a solution, the market simply might shy away from technologies that are sufficiently removed from the mainstream until the standard is clarified.
Allocating the project’s RECs and other possible environmental attributes (i.e., green attributes, environmental benefits, or similar terms; referred to here, inclusive of RECs, as environmental attributes) between the buyer and seller is another key component of a renewable contract that differentiates it from other types of power-purchase agreements.
Contracts commonly transfer environmental attributes to the buyer with the energy. However, a clear statement conveying the environmental attributes to the buyer or specifying that they remain with the seller is essential. Some states have enacted default provisions for state-created RECs that operate in the absence of a contrary contract provision. For example, in Rhode Island, the seller retains the “tradable emission credits” unless conveyed. In New Mexico, in the absence of a contrary contractual arrangement, the RECs are transferred with the energy if the project is a qualifying facility (QF) and sells energy to a utility purchaser, or the energy is sold under a contract in effect prior to Jan. 1, 2004. Otherwise, the seller retains them. The Waxman-Markey Bill provides that federal RECs generated by a facility placed in service prior to the enactment date of the proposed legislation will be deemed to remain with the owner of the facility unless a contract provides otherwise.
A fundamental step in transferring the environmental attributes is to define them. In today’s market, most contracts include a very broad definition of environmental attributes. However, some also include a reference to the type of environmental attribute of primary interest, such as a particular state’s RECs. This balanced strategy of sweeping and specific provisions has the most resilience, and will withstand change, including a shift from a state to federal standard. An environmental attribute is almost always explicitly defined to exclude any tax incentives, consistent with the typical allocation of environmental attributes to the buyer and tax benefits to the seller.
An important term that is sometimes overlooked is a representation, or series of representations, that the project is qualified to receive environmental attributes and the seller holds good title to all the environmental attributes associated with the energy generated by the project and hasn’t, and won’t, transfer title to the environmental attributes associated with the energy sold to the buyer to any other purchaser during the term of the contract. This type of representation is a necessary foundation to the conveyance clause.
The parties also should limit transfer of the environmental attributes to those associated with the power purchased by the buyer and provide for a return of any environmental attributes associated with power for which the buyer defaults in its payment obligation. Contracts also commonly specify the allocation of responsibility, including responsibility for paying fees, for registering and tracking the environmental attributes through an appropriate registry such as the Western Renewable Energy Generation Information System (WREGIS).
Much of the recent growth in the renewable sector is in technologies with intermittent output, such as wind and solar. This limitation becomes more critical as renewable generation’s market share grows. In particular, the need for new clean baseload resources will become more acute as existing fossil-fired baseload plants are retired in the normal course of operation or due to escalating carbon costs. Utilities must balance the immediate need to meet renewable standards with long-term needs for a portfolio that will have the operating characteristics necessary to meet future load.
An obvious strategy is to mix existing renewable baseload technologies that are available now, such as geothermal, biomass and landfill gas resources, with wind, solar and demand-response technologies. However, there also are promising new energy-storage technologies. Buyers requiring the flexibility of storage should consider building into their competitive procurement processes a mechanism that gives credit in the ranking process to projects that either provide a storage option or can be adapted in the future to integrate a storage technology. Sellers should consider the adaptability of their projects for storage as an additional selling point.
Contract terms can be structured to permit or facilitate the addition of storage at a later time. For example, each party can commit to engage in an evaluation and planning process for a storage addition if the buyer requests, and the buyer and seller can agree to a process for negotiating cost allocations and price adjustments and adapting scheduling provisions to facilitate use of the flexibility provided by storage, if a determination is made that storage would be cost-effective.
Notwithstanding the “as-available” nature of most renewable contracts, guarantees of a minimum quantity of energy over a specified period (e.g., annually) are ubiquitous. Such provisions provide at least two benefits to the buyer. First is usefulness as a planning tool. The minimum-performance guarantee serves as support for the reasonableness of the buyer’s treatment of the resource in its resource plan. Also, it provides reasonable assurance that the time spent negotiating the contract will result in measurable progress toward the buyer’s renewable energy target. Second, it provides a basis against which damages can be measured if the resource fails to perform or, in some cases, for termination, so the buyer can limit its further obligations to the non-performing (or low-performing) resource and clear the way for a replacement resource.
The benefit to the seller is less direct, but important. A seller’s willingness to make such a commitment, and to stand behind it with damages, is a marketing advantage. The minimum-performance guarantee also will become a benchmark for lenders in their due diligence review and provide all the parties—buyer, seller and lender—with a clear expectation that can reduce the potential for misunderstandings and later disputes.
However, when setting minimum-performance guarantees, the seller should try to protect itself from the risk of financial liability to the buyer when the performance failure results from measures beyond its direct control. Points for negotiation may include performance levels that include a sufficient margin to accommodate reasonably expected variations in weather conditions, measurement periods of sufficient length to allow volatility or temporary abnormalities to be averaged out, excused performance for force majeure, excused performance or extended cure periods for failures due to manufacturer’s defects, and a form of remedy (e.g., liquidated damages and replacement power) geared to make the buyer whole, without undue gain. Sellers may seek the right to adjust the minimum-performance guarantee prior to commercial operation. For example, a geothermal plant may readjust after test wells are drilled, a solar or wind facility after the completion of more specific site evaluation, or an emerging technology after a specified period of performance at a demonstration facility is completed.
Contract prices for renewable resources differ from prices for conventional resources primarily due to the issues of: 1) productivity; 2) the premium cost for clean power and environmental attributes; and 3) government incentives.
Renewable energy typically is purchased solely on a per-megawatt hour (MWh) basis, rather than with separate rates for capacity and energy, as is typically found in a unit-specific fossil-resource contract. The buyer usually claims the capacity value and any associated capacity attributes of the project, including the right to count the resource toward a resource-adequacy or installed-capacity requirement, but does not pay a separate price for capacity.
In the current market, the rolled-in per-MWh price is a bundled price measured by the energy scheduled or delivered, but also includes full payment for any environmental attributes transferred to the buyer. However, in the contracts that permit some type of replacement-cost pricing for shortfalls, the replacement price typically is determined by a two-part formula consisting of: 1) an energy price determined by reference to an index or specific node; and 2) a REC price or liquidated damage amount to cover the environmental attributes’ value. Thus, buyers and sellers recognize the price as having multiple value components, but elect not to unbundle the contract price to make the components transparent. Presumably, this reluctance stems in part from the difficulty of valuing the environmental attributes in an evolving market. However, the current preference for bundled pricing might pose challenges for price reporting and regulatory oversight in the future.
Past issues posed by government incentives provide guidance for the future. In prior years, when the investment tax credit (ITC) and production tax credit (PTC) for renewables were established for limited (e.g., two-year) periods, the continuing availability of the incentive as of the in-service date of a new facility, given the vagaries of project development, often was uncertain. Therefore, during those years, sometimes buyers agreed that if the tax incentives weren’t extended to include the in-service date of the facility, the buyer would pay the higher cost of renewable energy without a tax subsidy. In the more carefully-worded contracts, the negotiators limited applicability of the without-incentive pricing to cases in which the tax incentive wasn’t available, so as to preclude the possibility of the seller not availing itself of the tax credit and claiming the without-incentive pricing. Further, many of these same contracts provided for reversion to the with-incentive pricing, if the incentive was reinstated after operations commenced and, further, a refund of the difference between the without-incentive price to the extent it had been paid and the with-incentive price, if the incentive was reinstated after operations commenced and made retroactive. If the contract didn’t provide for a higher without-incentive price, and the project was at risk under its expected construction schedule for going into service after the date on which the PTC or ITC would expire, the seller might have been granted the ability to terminate without liability if an extension to the PTC or ITC program wasn’t granted by a date certain. Alternatively, it might have been granted a liberal right to extend its expected commercial operation date and other milestones so that financing and construction could be delayed until after Congress acted.
Under current federal tax law, the PTC and ITC have substantially longer lives, but the pricing uncertainty remains. The new Treasury program permitting tax incentives to be converted into cash grants requires the projects to be placed in service before Dec. 31, 2010 or to have started construction by that date and be in service by a future date that varies based on the technology. Given the many uncertainties of project development, some pending projects that hope to avail themselves of the grants, but aren’t quite shovel-ready, face the problem of appropriately pricing their product without knowing if they’ll meet the deadline for the grant program. Moreover, some projects might be eligible for other Department of Energy grants or loan guarantees, but won’t receive notification of the award or denial until after the power-purchase contract is executed. Thus, contracting parties continue to struggle to find a competitive price when the actual costs of financing, development and ownership—after government incentives are considered—aren’t yet known. The types of mechanisms previously used and described above—alternative pricing schemes, extension dates and termination rights—now are being used again.
Determination of the payment due a seller as cover costs for a curtailment, or damages for a default by the buyer, is made more complex by the existence of government incentives. Where a buyer has agreed to pay a seller for curtailing, and the seller will be relying on PTCs, the cover price typically includes the contract price plus the grossed-up loss of the associated PTCs. But in the event of default, the seller’s ability to recover its potentially lost tax benefit varies. Some contracts provide for a termination payment upon buyer’s default that expressly includes the value of lost ITC and lost PTCs. Others expressly deny recovery for such losses. Other contracts avoid confronting this issue altogether by not specifying a termination payment or termination-payment formula. Instead such contracts merely provide that the non-defaulting party is entitled to its rights at law, often specifically limited to direct damages.
Another problem in the pricing of renewable contracts is realizing economies of scale. The first commercial installation of a new technology is likely to encounter novel issues and risks that must be reflected in the price. As the technology improves and is more widely deployed, prices likely will decline. Thus, the utility that agrees to purchase from a project using a new technology, for example to take advantage of the greater operational flexibility it might provide or due to a scarcity of more conventional renewable options in its geographic region, might pay a premium for the power.
Government incentives such as loan guarantees and grants may help some new technologies reduce their costs. However, other strategies to mitigate the price impact and risk of new technologies on the buyer should be considered. For example, a buyer can contract for power from multiple projects, or increments of the same project developed over time, from the same seller, bargaining for declining prices for each incremental block. Rights in future projects may be structured as an option for first offer or first refusal, to provide time to evaluate the performance of the initial project. To avoid concentrating the buyer’s risk exposure to the seller or the new technology and to spread the premium associated with the first project, the buyer might want to take only a small part of each of several projects, thus forcing the seller to find other purchasers with which to share the premium cost of the first commercialization. A buyer also can seek to recapture some of the premium it pays for power from that first commercial installation by securing a right to a share of royalties or licensing revenues or other equity-like return.
The typical contract for a new fossil-fuel unit anticipates a period of construction, a period of commissioning and testing, in which sometimes the buyer purchases the energy, a specific expected commercial-operation date, a grace period or cure period during which daily liquidated damages might be due if commercial operation isn’t achieved by the expected date, and ultimately a termination right if the facility isn’t completed by a date certain. However, renewable contracts sometimes require a different approach.
Most wind farms and some solar facilities are brought onto the grid in increments. As each section of a wind farm or photovoltaic (PV) installation is completed, the power is ready to start flowing proportionally to the number of MW installed. With a PV resource in particular, commissioning and testing is relatively brief. The seller typically wants to have each phase declared commercial as early as possible to increase its cash flow. To accommodate this preference, the contract must define the period over which commercial operations will be phased-in, address the consequences of a deficiency if only a portion of the expected project becomes commercially operable within the expected period, and for the portion of the facility that comes on line prior to completion of the entire facility, the appropriate price and performance measures to be applied during that pre-completion period.
Like their fossil-unit counterparts, many renewable contracts allow the expected commercial operation date to be extended for force majeure, but in the case of renewable contracts, a pre-COD force majeure may include insufficient wind or sun to complete testing. Also it’s increasingly common to see extensions allowed to complete the interconnection to the grid.
The need for new transmission capacity to support the development of renewable resources has received substantial attention. It has become a central issue in addressing the challenges of climate change. The stimulus act (The American Recovery and Reinvestment Act of 2009), for example, added Section 1705 to provide federal loan guarantees to sponsors of certain transmission infrastructure investment projects and assigned a preference to otherwise eligible transmission expansions that support renewable energy generation. The Waxman-Markey Bill states that regional electric grid planning should “facilitate the deployment of renewable and other zero-carbon and low-carbon energy sources for generating electricity to reduce greenhouse gas emissions” and would require the Federal Energy Regulatory Commission (FERC) to establish grid-planning principles that meet these policy goals within a year. FERC also has taken measures to enhance the financial feasibility of transmission facilities needed for renewable resources. In April 2009, FERC approved rate incentives for a project that would deliver wind power from the upper Midwest to consumers in and around major metropolitan areas, despite significant opposition. In February 2009, FERC approved the first “anchor tenant” structure for merchant transmission, in order to facilitate the development of two transmission projects intended to deliver wind power from Montana and Wyoming to Nevada and the Southwest.
The appropriate allocation of costs of needed transmission for renewable resources, including the costs of interconnecting renewable resources to the grid, also is receiving attention. With regard to interconnection costs, FERC’s general policy assumes that generators “can choose where to interconnect and will do so in an economically efficient manner, so as to minimize costs of interconnection.”1 However, this policy was established before renewable energy resources began to develop on a larger scale. As FERC Chairman Wellinghoff recently testified before Congress, “[r]enewable energy resources such as wind, solar and geothermal are usually found in large quantities at dispersed locations remote from load centers…. [T]here are often high costs associated with developing transmission facilities needed to deliver power from such resources. If the resource developer or host utility is compelled to bear all of the cost of these transmission facilities, they may not be developed….”2
Regional transmission providers and independent system operators have struggled with how to allocate these costs equitably among stakeholders. In 2007, FERC approved an innovative approach by the California Independent System Operator (CAISO) to allocate interconnection costs for location-constrained renewable resources. The approved CAISO financing mechanism applies to qualifying generation tie lines. The CAISO tariff initially treats such facilities as “network upgrades” such that the costs are reflected in CAISO-wide transmission rates paid by all users of the CAISO system. Each generator that thereafter interconnects to the tie-line becomes responsible for paying its pro rata share of the going-forward costs of the line, thereby reducing the costs allocated to the system generally.
In June 2009, FERC approved changes to the Southwest Power Pool’s (SPP) rules for allocating the costs of transmission for wind generation. SPP’s proposals would make more of the costs associated with wind resources able to be funded as part of SPP’s regional “base plan” for transmission upgrades and reduce the costs that would be allocated directly to the wind projects or their transmission customers. Under SPP’s cost allocation rules, the costs of transmission upgrades would be eligible for base-plan funding if, among other things, the costs were less than or equal to a “safe harbor limit.” Costs that exceed the safe harbor limit would be directly assigned to the transmission customer. The safe harbor limit was based on the lesser of the planned maximum net dependable capacity of the resource or the requested capacity. Because of the intermittent nature of wind energy, SPP generally was assigning a very low “net dependable capacity” to wind resources—i.e., 10 percent of their nameplate capacity—to calculate the safe harbor limit. As a result, the costs of transmission upgrades that were allocated to the base plan for wind resources were significantly limited, and a disproportionate amount of costs were directly assigned to the wind project or its customer. For wind resources, SPP now uses the requested nameplate capacity of the project instead of its net dependable capacity. FERC concluded that this would “eliminat[e] existing provisions that currently disadvantage wind resources.”3
FERC also approved a change in SPP’s cost-allocation mechanism that addresses the situation when a transmission customer designates a wind generating facility as a network resource to serve the customer’s load, but the wind facility isn’t located in the same zone as the load it’s contracted to serve. In this circumstance, 67 percent of the costs are borne by all load in the SPP region on a postage-stamp basis. FERC determined that SPP’s proposals struck a reasonable sharing of costs between wind projects and their customers and the rest of the load in SPP’s region.
Even with the attention given by policy makers, regulators and transmission providers to the macro solutions to potential transmission barriers to renewable development, contracts for renewable purchases need to address specific circumstances and an allocation of transmission risk needs to be allocated.
If a utility is using a competitive procurement process for renewable energy, it needs to evaluate all elements of the proposal, such as the point of delivery (i.e., the point at which the seller and buyer will transfer title and risk of losses), the extent of the infrastructure to be installed for interconnection, and the extent of network upgrades needed to accommodate the interconnection beyond the point of delivery. Whether the cost is borne in the first instance by the developer or by the transmission provider, the cost eventually is borne by some utility’s ratepayers, and thus the total cost should be a pertinent consideration in selecting among competing resources. To facilitate its evaluation, a buyer may ask to receive interconnection studies and information on the progress of the seller’s interconnection as part of the bid and throughout the interconnection process.
In negotiating the allocation of transmission risk, the buyer that’s using the purchase to satisfy a renewable purchase mandate might be particularly incented to consider creative and flexible allocations of risks so that needed interconnection facilities and network upgrades will be funded, constructed and ready in a timely manner. For example, a buyer might agree to bear up-front the costs of network upgrades, as well as more extensive transmission improvements that would permit the buyer to designate the renewable resource as a full network resource in service to the buyer’s load. The buyer thus may satisfy a renewable portfolio standard, and the seller can minimize the risk of curtailment because network resource interconnection service is of a higher quality than energy resource interconnection service.
The contract should set project milestones, including dates by which the seller must execute an interconnection agreement with the transmission provider and have the interconnection facilities constructed and installed. The parties should negotiate clear consequences if these milestones aren’t satisfied. If there are extensive network upgrades that the transmission provider is responsible for constructing, delay risk needs to be addressed so the seller isn’t inappropriately penalized if it’s ready to deliver energy, but the transmission system isn’t ready to accommodate delivery. Potentially resolvable delays should be remedied if possible. For example, FERC recently granted El Paso Electric a one-time waiver of its interconnection queue processing procedures so it could conduct cluster studies, thereby speeding up the study process for all queued projects, including those chosen to meet state renewable requirements.
A continuing challenge for all intermittent resources is the problem of forecasting and scheduling deliveries and the resulting deviation penalties when weather conditions change unexpectedly. Schedule 9 of the pro forma open-access transmission tariff was revised by FERC’s Order No. 890 to impose lighter penalties for deviations on intermittent resources than on others. As Chairman Wellinghoff recently explained to Congress, “This reform was important because intermittent resources have a limited ability to control their output, and must therefore be assured that imbalance charges are no more than is required to provide appropriate incentives for prudent behavior.”4
One marked trend in recent years is an increase in the number of contracts that include highly specific requirements for meteorological data to be collected from the project site and transmitted directly to the buyer or grid operator. In California, the installation of such data-collection equipment is required of resources that avail themselves of CAISO tariff provisions designed to help manage intermittent resources’ deviations. The cost of data collection equipment typically is allocated to the seller in a power-purchase contract, since it becomes a part of the facility.
When schedule deviations are incurred, sometimes the cost is allocated to, or shared by, the buyer, rather than routinely placed on the seller as it usually is for fossil units. The allocation of responsibility for settling deviations in a renewable contract, however, is challenging and, consequently, sometimes handled awkwardly. In the case of under-generation, the difference between the contract price and the imbalance power price includes a green-price and brown-price differential, because the imbalance power delivered to the buyer to make up the shortfall doesn’t have associated environmental attributes. For over-generation, the environmental attributes associated with over-generation have to be allocated. Thus, deviations require careful attention.
Like the growth of qualifying facilities (QFs) in the late 1980s to mid-1990s, the growth of the current renewable market is spurred by legislative or regulatory mandates; utilities must purchase renewables, without particular regard to whether the new resources are needed to meet their load growth or load shape. Care must be taken to avoid some of the same pitfalls as occurred with QFs.
Purchase contracts must anticipate and allocate the risk of a negative value for renewable power. Periods of low demand combined with a lack of buyer control over deliveries can result in over-generation or, if renewables are concentrated on certain parts of the grid, regional or localized congestion. In the 1990s, some utility purchasers used the protection included in the Public Utility Regulatory Policies Act regulations that permitted curtailments when the purchaser’s cost of QF power exceeded its alternative. 5 Even so, disputes ensued over curtailment priority, frequency and duration, underscoring the need to clearly define curtailment rights in today’s contracts. The buyer and seller both have an interest in assuring that the power-purchase contract allows the seller to comply with its operational obligations under its interconnection agreement, applicable reliability standards and directives of the grid operator.
In markets with locational or nodal pricing, some buyers and sellers have agreed that the seller will curtail its output in periods of negative prices or compensate the buyer for the price differential between its contract price and the locational price. In other cases, the buyer simply has an absolute right to curtail for various operational conditions that threaten the reliability of the buyer’s facilities or the transmission grid. Many contracts permit non-emergency curtailments if the seller is fully compensated for the energy it would’ve produced, including for lost PTCs.
When negotiating these provisions, the seller should concern itself with the frequency and duration of curtailment, including caps on the total number of hours, particularly if it won’t be compensated. If the seller doesn’t have the protection of an ISO or RTO and market monitor, it must protect itself from discriminatory curtailments by insisting on clear criteria under which curtailment is permitted, and access to information, after the fact, to monitor the buyer’s application of its curtailment rights to other generators, including its owned generation.
The problem of credit risk is far more complex, but history shows its importance. In a market that’s relying on power-purchase contracts, a seller’s creditworthiness depends on its buyer. Financial distress or bankruptcy of a single buyer, leading to delayed payments, can be devastating to projects from which the buyer purchases power. To address this risk and anticipate the concerns of lenders, sellers should look for assurance, if the buyer is rate-regulated, that it has received regulatory assurance for the pass-through of its power purchase costs. For example, the California Public Utilities Commission allows utility buyers to present renewable contracts for approval immediately after execution.
A more controversial issue is buyer-posted security. Buyers and their ratepayers prefer to avoid the higher costs associated with posting collateral to the sellers and instead rely on regulatory approvals and their investment-grade credit ratings. Sellers may be content to accept such assurances, sometimes coupled with a right to performance assurance, in lieu of an on-going obligation to post collateral. However, if the buyer suffers an adverse credit event, multiple demands likely will be made on the buyer simultaneously. Thus, negotiating a right for the seller to demand performance assurance based on early indicators of distress can enhance the financing of the purchase contract and facilitate development of a viable renewable project.
1. Cal. Indep. Sys. Operator Corp. 119 FERC ¶ 61,061 at p. 65, order on reh’g, 120 FERC ¶ 61,244 (2007).
2. The Future of the Grid: Proposals for Reforming National Transmission Policy: Hearing Before the Subcomm. on Energy and the Env’t. of the H. Comm. on Energy and Commerce, 111th Cong. (June 12, 2009) (Testimony of Jon Wellinghoff, Chairman, FERC).
3. Sw. Power Pool, Inc., 127 FERC ¶ 61,283 at p. 28 (2009).
4. Testimony of Jon Wellinghoff, Chairman, FERC, Before the Comm. on Env’t. and Pub. Works, 111th Cong. (Aug. 6, 2009).
5. 18 CFR § 292.304(f).