Regulatory and Transmission-Related Issues

Long before a solar energy developer begins generating the first megawatt of power, the developer must decide on a regulatory structure for the project and negotiate and execute transmission and interconnection agreements. 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 Authorizations and Exemptions—MBRs, EWGs, and QFs. Solar generation companies selling wholesale power are “public utilities” under Part II of the Federal Power Act (“FPA”) and therefore subject to the Federal Energy Regulatory Commission’s (“FERC”) 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 qualifying facility (“QF”). Furthermore, a developer of a project of any size can obtain market-based rate (“MBR”) 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. QF exemptions and MBR authorization are discussed further below.

In addition to regulation under the FPA, developers must consider the risk of regulation under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), which replaced its predecessor, the Public Utility Holding Company Act of 1935 (“PUHCA 1935”). Although solar energy project companies are no longer subjected to extensive regulation by the Securities and Exchange Commission, PUHCA 2005 has (1) granted state regulators and 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, most solar energy project companies 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 QF. Each of these categories is summarized below.

A. Market-Based Rate Authorization. Rates for wholesale power sales are subject to FERC regulation under section 205 of the FPA. As a result, absent an exemption, a developer must apply for and FERC must grant market-based rate approval, i.e., power-marketing rights, before a project 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, solar developers should contact knowledgeable attorneys before filing for market-based rate approval. Once FERC grants market-based rate approval, the project company will have ongoing filing and reporting requirements and must comply with FERC’s rules regulating market behavior.

B. 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 a self-certification 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.

EWG status does not give a developer any authority to sell power; EWG status primarily provides nothing more than an exemption from PUHCA regulation. But 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 solar 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 or that might be presented in direct-to-load sales to commercial or industrial customers—to take part in these transactions, an EWG will need to sleeve its sales through an entity that can transact at retail. Finally, EWGs are restricted in their ability to enter into certain types of transactions (such as leases) with affiliated regulated utilities.

C. Qualifying Facility Status. 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 solar projects, all which are referred to as QFs. PURPA was later modified by the Energy Policy Act of 2005. PURPA continues to provide favorable regulatory exemptions for certain QFs. In particular, certain QFs enjoy an exemption from the need to obtain authorization from FERC to sell power wholesale, as discussed above. Specifically, sales of energy and capacity by (1) by QFs 20 MW and smaller, (2) QFs 30 MW and smaller pursuant to a contract executed on or before March 17, 2006, or (3) QFs 30 MW and smaller pursuant to a state regulatory authority’s implementation of PURPA remain exempt from sections 205 and 206 of the FPA. Keep in mind that these capacity size thresholds also have special rules that apply to them—they are not calculated solely by looking at the subject facility; rather, they can be impacted by commonly-owned or affiliated facilities located up to 10 miles away! Certain QFs that are 30 MW or less are also entitled to exemptions from other sections of the FPA, from PUHCA, and from state laws and regulations respecting the rates and financial and organizational regulation of electric utilities. For a solar project that is 30 MW or smaller, QF status may be more advantageous than EWG status, because PURPA does not restrict the ability of QFs to make retail sales to the extent such sales are allowed under state law. Above 30 MW, a solar developer might choose EWG status, QF status, or both, depending on the circumstances.

Second, the “must buy” obligation in PURPA allows certain 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 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. In addition, developers should also take into account that QFs are not required to transact under PURPA; instead, most use this status simply for the regulatory exemptions that it provides.

D. Other Ongoing Regulatory Requirements. Whether a solar developer is an EWG or a QF, or has FERC approval to sell power at market-based rates, the solar 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 passive investors if not structured correctly, 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 many FERC notification and filing requirements related to jurisdictional solar 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, solar 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 established 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 almost two decades ago, however, nearly all of the independent system operators (“ISOs”), such as the Midcontinent 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. These queue reform efforts have been repeated multiple times over the last decade or so, and as a result much of the country no longer administers generator interconnection using a uniform process or agreements.

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. These studies may be performed on a project-specific basis or as a cluster that evaluate many projects together. Because solar 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 many ISOs, however, an interconnection customer will not be entitled to all or even part of this reimbursement.

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, either on a bilateral basis or into an organized market, the project owner will be required to obtain point-to-point 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 or for the purchaser to obtain point-to-point transmission service. 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 most 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. Solar 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.

In addition, although a solar project may not operate at full capacity 24/7, the owners of solar 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 solar flows amount to less than full operation. Another result is that the cost of transmission for a solar project will normally be substantially higher on a per-megawatt-hour 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 solar 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. Reliability Standards. Over a decade ago, 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 for the power industry. 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 solar 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 solar 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.