The Law of Wind: A Guide to Business and Legal Issues

The Law of Wind: A Guide to Business and Legal Issues

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Jason Johns
Jennifer H. Martin
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  • Bree Metherall Director of Business Development 503.294.9435

Regulatory and Transmission Related Issues


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Long before a wind energy developer begins generating the first megawatt of power, the developer must decide on a regulatory structure for the project, negotiate and execute transmission and interconnection agreements, and purchase necessary transmission ancillary services. This chapter presents a general discussion of these issues. Before embarking on a particular course of action, it is highly recommended that a developer seek the opinion of qualified counsel, especially considering that many of the laws and regulations relating to these topics may be affected by recent legislation and ongoing rulemaking proceedings.

I. Regulatory Structure Issues—PUHCA, EWGs, and QFs. The Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935 (“PUHCA 1935”), in part, and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). By opening the door to certain utility acquisitions and mergers that had been prohibited since 1935, PUHCA 2005 eliminated certain restrictions that prevented the consolidation of the electric utility industry, and corporate affiliations allowed under PUHCA 2005 present both challenges and opportunities for wind energy developers.

Although nonexempt wind energy project companies are no longer subjected to extensive regulation by the Securities and Exchange Commission, PUHCA 2005 has (1) granted state regulators and the Federal Energy and Regulatory Commission (“FERC”) broad access to books and records of such companies and (2) provided for FERC review of the allocation of costs for nonpower goods or services between regulated and unregulated affiliates of such companies. However, wind energy project companies may obtain exemptions from these requirements, with the two most common exemptions occurring when a project owner obtains status as either an exempt wholesale generator (“EWG”) or a qualifying facility (“QF”). Each of these categories is summarized below.

In addition, because privately owned wind generation companies are public utilities under Part II of the Federal Power Act (“FPA”), developers are subject to FERC’s regulation as a “public utility,” including rate regulation, electric reliability rules, and other regulation. However, a developer may avoid rate regulation under section 205 of the FPA for certain small projects by obtaining status as a QF. Furthermore, a developer of a project of any size can obtain market based rate authority if it can make the necessary showings; such authority exempts the developer from the need to justify its rates on a cost basis. But one way or the other, a developer selling energy at wholesale must obtain either authority from FERC to do so or an exemption from such regulation. These other regulatory issues are addressed in Sections A, B, and C below.

A. Exempt Wholesale Generator Status. In an effort to stimulate wholesale electric competition, Congress enacted the Energy Policy Act of 1992, which created an exemption from PUHCA 1935 for independent power producers that qualify as EWGs. EWG status is determined by FERC, and EWG status begins once the independent power producer files an application with FERC. EWG status is available to any generator of electricity, regardless of size or fuel source, so long as such entity is exclusively engaged in the business of owning and/or operating electric generation facilities for the sale of energy to wholesale customers.

Independent power producers should be aware of several issues associated with EWG status. First, the “exclusively own and/or operate” requirement mentioned above typically requires the creation of a special purpose entity to own the wind generation facility and sell its electric output. Second, EWGs are restricted to wholesale sales and therefore cannot take advantage of retail sale opportunities in jurisdictions that have approved retail direct access. Finally, EWGs are restricted in their ability to enter into certain types of transactions (such as leases) with affiliated regulated utilities. EWG status does not give a developer any authority to sell power; EWG status primarily provides nothing more than an exemption from PUHCA regulation.

Rates for wholesale power sales by EWGs are subject to FERC regulation under section 205 of the FPA. As a result, an EWG must apply for and FERC must grant market based rate approval, i.e., power marketing rights, before an EWG can sell bulk wholesale power at market prices. FERC generally grants market based rate approval, provided that the applicant and its affiliates (if any) demonstrate a lack of horizontal market power (electric generation) and vertical market power (transmission and other barriers to market entry) in the relevant markets, and have satisfied restrictions on affiliate abuses contained in FERC regulations. Power sellers that have market power may nevertheless obtain market based rate approval by showing that the seller has adequately mitigated its market power. Because FERC often revises or modifies its criteria for satisfying these requirements, wind developers should contact knowledgeable attorneys before filing for market based rate approval. Once FERC grants market based rate approval, the EWG will have ongoing filing and reporting requirements and must comply with FERC’s rules regulating market behavior.

B. Qualifying Facility Status. The Energy Policy Act of 2005 also changed the rules for QFs, introducing both risk and opportunity. Developers of new wind projects, as well as sellers under existing QF contracts (especially with contracts that will be expiring soon), will want to familiarize themselves with these changes.

During the energy crisis in the late 1970s, Congress passed the Public Utility Regulatory Policies Act of 1978 (“PURPA”) to encourage the development of cogeneration and small renewable energy projects, including wind projects, all which are referred to as QFs. Before the passage of the Energy Policy Act of 2005, PURPA provided valuable benefits to wind energy developers, one of which was the exemption for wind QFs producing up to 30 MW from many provisions of the FPA and from certain types of state utility regulations. The Energy Policy Act of 2005 (and FERC’s interpretation thereof) has limited the applicability of these exemptions, making the eligibility requirements narrower than in the past.

The Energy Policy Act of 2005 narrowed the advantages that wind generation QFs previously enjoyed compared to EWGs. First, as mentioned above, QFs no longer enjoy broad exemptions from the requirements of the FPA. Significantly, only certain QFs continue to enjoy an exemption from the need to obtain authority from FERC to sell power at market based rates before selling energy from the project as discussed above. Specifically, (1) sales of energy and capacity made (2) by QFs 20 MW and smaller, (3) pursuant to a contract executed on or before March 17, 2006, or (4) pursuant to a state regulatory authority’s implementation of PURPA remain exempt from sections 205 and 206 of the FPA. Second, the Energy Policy Act of 2005 weakened the “must buy” obligation that allows QFs to require retail public utilities to purchase QF output at the utility’s “avoided costs,” i.e., the costs the utility would have incurred but for the QF purchase. Utilities may now petition FERC for an exemption from PURPA’s mandatory purchase requirement if the utility can demonstrate that a QF in its service territory would have nondiscriminatory access to wholesale markets for energy and capacity that meet certain standards—something that is routinely done in regions with an organized wholesale energy market. The potential loss of this “must buy” requirement could be significant because utilities’ appetite for renewable energy has been reduced as Renewable Portfolio Standard requirements are met, and such published rates have been an effective negotiating tool for gaining favorable pricing under non QF renewable energy sale agreements. One clear advantage of QFs over EWGs is that PURPA does not restrict the ability of QFs to make retail sales to the extent such sales are allowed under state law. For a wind project that is 30 MW or smaller, QF status is more advantageous than EWG status. Above 30 MW, a wind developer might choose EWG status, QF status, or both, depending on the circumstances.

C. Other Ongoing Regulatory Requirements. Whether a wind developer is an EWG or a QF, or has FERC approval to sell power at market based rates, the wind developer may also be subject to other filing and reporting obligations at FERC. For example, FERC’s prior approval may be required before the developer disposes of FERC jurisdictional facilities, subject to certain value thresholds. This prior approval requirement generally applies to indirect disposition of such assets, which can include the sale of project membership interests to investors, and accordingly, consultation with a knowledgeable FERC attorney is advised in connection with any plans by the developer to restructure, sell, or otherwise dispose of its assets. Likewise, FERC may require updates to the market based rate filing, EWG application, and/or QF certification in connection with changes in the material facts on which FERC relied in granting such status. Finally, FERC notice or approval may be required when certain directors or officers hold similar positions in related affiliates. The foregoing list is not exhaustive and is intended to highlight only some of the various FERC notification and filing requirements related to jurisdictional wind developers, and therefore consultation with knowledgeable attorneys is recommended.

II. Transmission and Interconnection Issues. To obtain project financing and gain access to markets for project output, wind project developers must negotiate agreements to interconnect with the transmission system of the applicable transmission provider. In addition, a developer will need to obtain any necessary transmission service to deliver project output to the purchasers of that output. Most lenders and many investors will require evidence of executed generation interconnection and/or transmission service agreements as a condition of financing or project purchase. Most transmission providers are subject to jurisdiction by FERC, and therefore transmission service agreements and generation interconnection agreements are generally subject to regulation by FERC. Interconnection to utilities exempt from FERC interconnection rules raises unique questions, which should be considered when selecting project sites.

A. Generation Interconnection Agreements. A generation interconnection agreement is a contract between the generation owner and the transmission provider that owns the transmission system with which the project will be connected. In regions where the transmission system is owned and operated by separate entities, FERC will require that both of those entities sign the interconnection agreement. FERC Order No. 2003 established standard interconnection procedures and a standard interconnection agreement for generators larger than 20 MW (“Large Generators”). Similarly, FERC Order No. 2006 establishes standard interconnection procedures and a standard interconnection agreement for generators with a capacity of 20 MW or less (“Small Generators”). Since that order was issued, however, certain regional transmission organizations, such as the Midcontinent Independent System Operator (“ISO”), Southwest Power Pool, and the California ISO, have reformed their interconnection procedures and agreements in response to crippling backlogs and delays in the existing queues. Generally, queue reform has implemented a “first ready, first to advance” methodology, requiring larger study deposits that may be nonrefundable and stricter adherence to progress milestones, and allowing fewer opportunities for developers to delay the process. Queue reform continues to happen across the nation—sometimes even outside of the ISO markets—and each reform to FERC’s traditional approach to interconnection responds to the problems faced in a particular region. But it also means that what was once a generally uniform process across the country might now look very different depending on the region where a project is being developed.

Generally, the two main purposes of interconnection agreements are (1) to identify and allocate the costs of any new facilities or facility upgrades that need to be constructed and (2) to set forth the technical and operational parameters governing the physical interconnection.

B. Interconnection Facilities and Cost Allocation. In general, before the execution of an interconnection agreement, the transmission provider will commission a series of interconnection studies, at the interconnection customer’s expense, to determine what new interconnection and transmission facilities need to be constructed to accommodate the new generation facility and the cost of such construction. Because wind projects typically span large geographical areas and are often located in remote places, substantial new facilities and facility upgrades may be required.

Order Nos. 2003 and 2006 directly assign the costs of interconnection facilities and distribution upgrades to the interconnection customer. Network upgrades (i.e., upgrades to the transmission system at or beyond the point of interconnection) are treated differently, however, and even though the costs of upgrades may initially be borne by the interconnection customer, those costs may be reimbursed to the interconnection customer in the form of transmission credits or cash payments. In certain transmission systems, however, such as those controlled by the Midcontinent ISO or the PJM Interconnection, the interconnection customer will not be entitled to all or even part of this reimbursement.

Determining the point of interconnection for purposes of distinguishing between interconnection facilities and network facilities is an area of potential dispute between the parties. Transmission providers have an incentive to design interconnections in a manner that places the majority of the new facilities on the customer’s side of the interconnection, thereby depriving the customer of a transmission credit to offset the costs of such facilities. Consistent with FERC precedent, only such facilities as are necessary to reach the point of interconnection are properly classified as interconnection facilities. Agreements to reclassify interconnection facility costs as network upgrades, or vice versa, have not been found to be “just and reasonable” and have been rejected by FERC.

C. Transmission Service Agreements. Interconnection service or an interconnection by itself does not confer any delivery rights from the generating facility to any points of delivery. Therefore, unless the project owner is able to sell the output of the project at the point of interconnection with the transmission grid, the project owner will be required to obtain transmission service from one or more transmission providers to wheel project output to the purchaser. An alternative is for the project owner to sell some or all of the output under a contract shifting the transmission obligation to the purchaser. This typically requires that the contract terms qualify the sale for designation as a network resource by a load on the transmission system to which the project is interconnected. In addition, acquiring adequate transmission service is essential to obtaining debt or project financing on reasonable terms and conditions.

Transmission providers are required by FERC to offer transmission service on an open, nonpreferential basis pursuant to a transmission tariff that will govern the terms by which such service is provided. Upon receiving a request for service, the transmission provider will evaluate available transmission on its system and determine whether additional transmission facilities need to be constructed to accommodate the requested service. In major parts of the United States, the transmission provider is a Regional Transmission Organization (“RTO”) or ISO rather than the actual owner of the applicable transmission facilities. Acquiring transmission service from transmission providers not subject to FERC’s jurisdiction under sections 205 and 206 of the FPA raises additional questions that depend on the nature of the entity, the scope of its transmission facilities, and other issues beyond the purview of this chapter.

Under FERC’s general transmission pricing policy, generators pay the greater of the incremental costs or embedded costs associated with requested transmission service. Incremental costs refer to the additional system costs (e.g., construction of new facilities and upgrades) resulting from the requested service. Embedded costs reflect an allocation of system costs to the various users, generally based on megawatts of service. Wind projects, because of their remote locations, may necessitate substantial system upgrades that will result in the transmission customer paying an incremental cost rate that exceeds its pro rata share of the system costs.

Although the average output of wind projects is in the 30 to 40 percent range, during periods of adequate wind flow, wind projects can operate at or near full capacity. As a result, the owners of wind projects typically need to have available transmission service to accommodate the full project capacity. One result is that much of this transmission capacity will go unused during periods when wind flows amount to less than full operation. Another result is that the cost of transmission for a wind project will normally be substantially higher on a per megawatt hour (“MWh”) basis than the cost of baseload thermal generation. Sometimes combinations of firm and nonfirm transmission, or transmission and redispatch, can be more cost effective than purchasing transmission for the project’s maximum capacity. The challenge is convincing third party financiers to accept such arrangements.

These transmission pricing rules may be different if the transmission provider is an RTO. The rules of the existing and proposed RTOs may in fact be much more favorable to wind generation than FERC pricing, because an RTO eliminates rate “pancaking,” which is the imposition of multiple transmission charges for use of more than one transmission owner’s transmission facilities.

III. Ancillary Services—Imbalance Charges, and Firming and Shaping Products. Project owners will be required under the transmission provider’s tariff to either provide or purchase transmission ancillary services, which are products designed to ensure the reliability of the transmission system. Of these products, generation imbalance service often poses the most difficult issues for wind operators. Generation imbalance service is a product that allows a generator to deliver an amount of energy to the electric grid that differs from the amount it had prescheduled for an hour and compensates the transmission provider for the cost of delivering the scheduled amount of energy to the generator’s point of delivery.

Most transmission providers had historically priced generation imbalance service based on the cost or value of the generation, plus a premium. For example, a transmission provider may have charged generators 110 percent of the cost of providing replacement energy in hours when the actual output of a generator was less than scheduled output, and compensated generators 90 percent of the value of energy produced in excess of the amount scheduled. In addition to this basic charge, penalties attached if the difference between scheduled and actual generation exceeded a specified threshold. Such charges were intended to promote accurate scheduling and to prevent system reliability concerns associated with large scale imbalances; however, these penalty type imbalance charges punished wind generators for variations in output over which the generators lack control.

Acknowledging that existing energy imbalance charges under Schedule 4 of the open access transmission tariff (“OATT”) and the generator imbalance charges described in FERC Order No. 2003 are the subject of “significant concern and confusion in the industry,” FERC found that imbalance charges varied widely, were excessive, and penalized transmission customers whose actual generator or energy imbalances deviated from corresponding schedules without reference to the actual cost of providing imbalance service. This approach made sense if customers could predict generation output with a high degree of accuracy and control the quantity dispatched. FERC recognized, however, that the penalty did not make sense when applied to variable generation, which cannot be forecasted as reliably and for which the customer has little control over dispatchability.

Accordingly, FERC adopted rules in Order No. 890 that designed a tiered structure for imbalance charges, with increasing imbalance charges as the imbalance increases into the next largest tier. Order No. 890 also provides at least two benefits to intermittent resources. First, the rules provide for monthly netting of imbalance charges within the first tier. Second, intermittent projects are not subject to the third tier of deviation charges. Although these new rules can provide significant benefits to wind power resources, it is important to understand that transmission providers may be permitted to adopt different provisions applicable to intermittent resources within their control areas.

To avoid imbalance charges, wind project operators may look to other generation suppliers to provide firming and shaping products to accommodate their variations in output. Such products consist of arrangements whereby the supplier will take or provide energy, as applicable, in hours when the actual generation differs from the scheduled amount. Several transmission providers in the Pacific Northwest have sold a limited amount of shaping and storage service, generally using the hydro system’s flexibility to store and shape wind into peak and off peak blocks.

In addition to imbalance charges, some transmission providers require certain wind generators to pay for a wind integration service, which is typically a capacity charge that may be designed similar to the load regulation charges found in Schedule 3 of the transmission provider’s tariff. Transmission providers have justified these new charges by citing the variability of wind within the hour or shorter scheduling increment and the resulting strain that such variability places on the transmission system. Wind integration charges are rare, but where they exist they can be costly and highly complex in design.

IV. Reliability Standards. Developments in federal law have transformed historically voluntary standards into mandatory reliability standards with accompanying obligations and potential sanctions for failure to comply. In compliance with federal law requiring it to do so, FERC issued Order No. 672 in 2006, qualifying the National Electric Reliability Corporation (“NERC”) as the continent wide, FERC certified Electric Reliability Organization (“ERO”) responsible for proposing and enforcing mandatory reliability standards. As the ERO, NERC is responsible for monitoring and improving the reliability and security of the bulk electric system and, to do so, NERC has the authority to propose and enforce mandatory reliability standards and assess fines upward of $1 million per day for noncompliance. Pursuant to the FPA, all reliability standards must be just, reasonable, not unduly discriminatory or preferential, and in the public interest. NERC has delegated to designated regional entities the authority to monitor and enforce the reliability standards. In addition to their delegated duties, regional entities may also enforce region specific reliability standards.

The reliability standards may apply to users, owners, and operators of the bulk electric system, and the specific applicability of a particular standard is specified therein. The regional entities are tasked with maintaining a Compliance Registry, which lists organizations against which the reliability standards are enforceable. If a bulk electric system user, owner, or operator fails to register with the Compliance Registry, then the regional entity may take steps to register that user, owner, or operator. The Compliance Registry lists organizations by function, and compliance is analyzed by reference to function specific reliability standards.

As is most relevant to wind developers, NERC requires that certain generator owners and operators register with the Compliance Registry. A generator owner is an organization that owns generating units, and a generator operator is an organization that operates generating units and supplies energy. There are minimum requirements before a generator owner or generator operator is required to register, but consider that these requirements are not always straightforward. For instance, although a single wind power facility may itself be too small to trigger mandatory reliability standards, its sharing interconnection facilities with other facilities (either affiliated or not) might be aggregated for purposes of determining whether the combined facilities are subject to NERC standards.

Overall, the mandatory reliability standards pose a challenge to an industry that recognized voluntary standards for many years. Given the breadth of the reliability standards and the punitive sanctions attached, industry participants must take appropriate steps to determine whether they should register with the appropriate regional entity, to understand each function, and to implement a comprehensive program that will track and ensure compliance. Download The Law of Wind - 8th Edition (PDF)

































Key Contributors

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Media Inquiries

  • Bree Metherall Director of Business Development 503.294.9435
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