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

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

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Seth D. Hilton
Jason Johns
Jennifer H. Martin
Jennifer Mersing
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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 solar developer begins generating the first kilowatt of power, the developer must decide on a regulatory structure for the project, negotiate and execute net-metering or transmission and interconnection agreements, and purchase necessary transmission and ancillary services or distribution-level services. Solar projects come in many different forms, and business models range from installations for the installer’s own electric needs and sales directly to third-party retail customers to large, utility-scale solar developments dozens or hundreds of megawatts (“MW”) in size. Whether and to what extent the developer will be subject to regulation for the development of the project and the sale of the electricity generated by the project will depend on the business model, the size of the project, and the use to which the purchaser puts the energy (i.e., direct consumption or resale). This chapter presents a general discussion of these issues on the federal level and discusses the general procedures that may apply at the state level. Of course, specific state-level regulation will vary from state to state. 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. Federal Regulatory Structure Issues: PUHCA, EWGs, QFs, and Market-Based Rate Authority. The Energy Policy Act of 2005 repealed in part the Public Utility Holding Company Act of 1935 (“PUHCA 1935”) and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), thereby opening the door to certain utility acquisitions and mergers that had been prohibited since 1935.

PUHCA 2005 also ended the Securities and Exchange Commission’s extensive regulation of nonexempt electric utility companies, including solar developers. However, PUHCA 2005 (1) granted state regulators and the Federal Energy 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.

Solar project companies can obtain exemptions from these requirements. The two most common exemptions are for the project owner to obtain status as either an exempt wholesale generator (“EWG”) or a qualifying facility (“QF”). Each of these categories is summarized 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 regulation under PUHCA 1935 for companies that were “holding companies” solely with respect to EWGs. That exemption continues with respect to PUHCA 2005. EWG status is determined by FERC, and the EWG status begins once the independent power producer self-certifies such status with FERC. EWG status is available to any generator of electricity, regardless of size or fuel source, so long as such entity is exclusively in the business of owning and/or operating electric generation facilities (including certain incidental activities) 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 solar power generation facility and to sell its electrical 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 would permit the solar developer to sell directly to retail consumers without becoming regulated public utilities, as discussed below. Finally, EWGs are restricted in their ability to enter into certain types of transactions (such as leases) with affiliated regulated utilities.

Rates for power sales by EWGs are subject to FERC regulation under Section 205 of the Federal Power Act. As a result, an EWG must apply for, and FERC must grant, market-based rate authority, i.e., power-marketing rights, before an EWG can sell any wholesale power (including the generation of test energy). FERC generally grants market-based rate authority, 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 power markets, and have satisfied restrictions on affiliate abuses contained in FERC regulations. The criteria that FERC considers in granting market-based rate authority are subject to change, and instructive precedent is scattered throughout FERC’s many rulings on the subject. Once FERC grants market-based rate authority to an entity, the entity will have ongoing filing requirements at FERC (including filing quarterly reports on power sales and contracts).

B. Qualifying Facility Status. During the energy crisis of the 1970s, Congress passed the Public Utility Regulatory Policies Act of 1978 (“PURPA”) to encourage the development of cogeneration and small (up to 80 MW) renewable energy projects, which are referred to as QFs. Before the passage of the Energy Policy Act of 2005, PURPA was important to renewable power developers for several reasons, one of which was the exemption for QFs producing up to 30 MW from most of the provisions of the Federal Power Act, PUHCA and from certain types of state utility regulations. The Energy Policy Act of 2005 (and FERC’s interpretation thereof) has narrowed the exemptions from the Federal Power Act to a smaller class of QFs, making such exemptions less common than in the past. On the other hand, the Energy Policy Act of 2005 also eliminated PURPA’s requirement that restricted utility ownership of QFs, generating new interest from utilities in owning QF facilities—increasing the value of both new and existing QF projects.

The Energy Policy Act of 2005 also narrowed the advantages that renewable power generation QFs previously had over EWGs (although many renewable projects over 30 MW are certified as both QFs and as EWGs). First, as mentioned above, many QFs no longer enjoy broad exemptions from the requirements of the Federal Power Act. Significantly, only certain QFs continue to enjoy an exemption from the need to obtain market-based rate authority from FERC in order to sell wholesale power at market rates. Specifically, sales of energy and capacity made (1) by QFs 20 MW and smaller, (2) pursuant to a contract executed on or before March 17, 2006, or (3) pursuant to a state regulatory authority’s implementation of PURPA remain exempt from the market-based rate authority requirement. 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 energy purchased. A utility may petition FERC for an exemption from PURPA’s mandatory purchase requirement if it can demonstrate that QFs in its service territory would have nondiscriminatory access to competitive wholesale markets for energy and capacity that meet certain standards. Many utilities have already obtained this exemption, primarily in the areas with organized energy markets. Most of these exemptions have affected QFs that are larger than 20 MW; however, in a limited number of cases, QFs that are 20 MW and smaller have been affected, too. The loss of this “must buy” requirement can be significant because state-established “avoided cost” rates have often exceeded prevailing wholesale market prices, 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. Another distinction between QFs and EWGs is that QFs, when selling their energy under PURPA, are interconnected under state regulators’ interconnection rules, which may or may not be advantageous for a particular project.

To obtain QF status, solar developers were traditionally required to file a self-certification of QF status or apply for FERC certification. However, in 2010, developers became exempt from making any filing with FERC to obtain QF status with respect to a facility that is 1 MW or smaller. The size of the QF is based on the net power production capacity of all affiliated same-fuel source facilities within one mile. Larger facilities remain subject to the traditional methods of certification.

C. Other Ongoing Regulatory Requirements. Whether a solar developer is an EWG and/or a QF, and/or has market-based rate authority, the solar developer may also be subject to other filing and reporting obligations at FERC. For example, for those entities with market-based rate authority, FERC’s prior approval may be required before the developer disposes of FERC-jurisdictional facilities. This prior approval requirement generally applies to the direct or even indirect disposition of such assets, including the sale of project membership interests to investors, a foreclosure by debt providers, or an upstream change in corporate control. Likewise, FERC may require updates to the market-based rate authority, EWG certification, 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 solar developers.

II. State Regulatory Structure Issues: Regulation as a “Public Utility.” An important issue of state regulatory concern for solar developers looking to make retail sales to third parties is whether such sales will result in the generation owner being regulated as a “public utility.” This has become particularly important in recent years as large commercial and industrial customers have become more interested in structuring their own energy portfolio. (Note: If the sale is a wholesale sale (i.e., a sale for resale), the sale will be governed by federal law.) Parties selling electricity to end-use customers are often heavily regulated as public utilities under state law, including regulation of rates and terms of sale for electricity. Typically, a solar project owner will want to ensure that it is not regulated as a state-jurisdictional public utility if it sells power directly to end-use customers. Whether a solar generation owner is regulated as a public utility will vary from state to state, and potentially relevant factors include the number and type of customers supplied and the location of those customers relative to the location of the generation. In California, for example, generally an entity that sells electricity to end-use customers is a public utility regulated by the California Public Utilities Commission (“CPUC”). In some circumstances, however, a solar generation owner can sell power to not more than two other corporations or persons for use on the real property where the electricity is generated, or on property immediately adjacent thereto, without being regulated as a public utility.1

III. Transmission and Interconnection Issues. To gain access to markets for project output, solar project developers that are not interconnecting pursuant to a state’s net-metering rules or pursuant to a state-jurisdictional distribution tariff discussed below must negotiate agreements to interconnect with the transmission system of the local transmission provider. In addition, a developer will need to obtain any necessary transmission service to deliver project output to the purchasers of that output, and such services can become quite costly. 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 FERC jurisdiction, and therefore transmission service agreements and generation interconnection agreements are generally subject to regulation by FERC. However, some utilities are not subject to FERC oversight, and an interconnection with those utilities may raise unique issues, which should be considered when selecting a project site.

A. Generation Interconnection Agreements. A generation interconnection agreement is a contract between the generation owner and the transmission owner that owns the transmission facilities with which the project will be connected (and in certain instances, the Regional Transmission Organization (“RTO”)/Independent System Operator (“ISO”) that operates the transmission facilities will be a third signatory to the agreement). FERC’s Order No. 2003 established standard interconnection procedures, including a standard interconnection agreement for generators larger than 20 MW (“large generators”). Similarly, FERC Order No. 2006 established standard interconnection procedures, including a standard interconnection agreement for generators with a capacity of 20 MW or less (“small generators”). Certain RTOs, such as the Midwest Independent System Operator, the California Independent System Operator, and the Southwest Power Pool, have since reformed their interconnection procedures and agreements in response to substantial backlogs and delays in the existing queues. As a result, interconnection processes that were once largely uniform across the nation now vary widely across regions, requiring developers to obtain region-specific knowledge or suffer the consequences. 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 or modify their proposed generating facilities. Queue reform has had a dramatic impact on the interconnection process, and changes continue to occur as transmission providers further refine their processes.

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.

1. 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. Like many renewable energy projects, if it is located in a remote place without much existing transmission infrastructure, substantial new facilities and facility upgrades may be required.

Under FERC Order Nos. 2003 and 2006, the costs of interconnection facilities and distribution upgrades are paid for by the interconnection customer. Network upgrades (i.e., upgrades to the transmission system at or beyond the point of interconnection) are treated differently, however, and transmission credits or another form of reimbursement may be available to the interconnection customer. For example, if the transmission provider is a nonindependent entity, such as a vertically integrated utility, the interconnection customer will often pay the upfront cost of any required upgrades, but the transmission provider will reimburse the interconnection customer by providing transmission credits or cash reimbursement. However, in certain transmission systems, such as those controlled by the Midcontinent Independent System Operator or the PJM Interconnection, the interconnection customer will not be entitled to all or even a portion of this reimbursement. In these and other regional transmission systems, cost allocation and refund methodologies are often in flux.

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 reimbursement against the costs of such facilities. Consistent with FERC precedent, only those facilities that are necessary to reach the point of interconnection are properly classified as interconnection facilities. In addition, for most interconnections of small generators, extensive network upgrades are unusual unless a project will be located near a congested portion of the transmission system. In some cases, the costs of interconnection can make a project uneconomical.

2. Technical and Operational Issues. Interconnection agreements address such technical and operational issues as reactive power factors, responsibility for electrical disturbances, metering and testing of equipment, exchange of operating data, and curtailment events. In some cases transmission providers attempt to impose technical requirements or control area services that go beyond those that FERC has typically approved. Solar developers should therefore pay close attention to the technical requirements and control area charges proposed in the interconnection agreement. In addition, the generator interconnection agreement may require compliance with applicable National Electrical Code (“NEC”), Institute of Electrical and Electronic Engineers (“IEEE”), and Underwriters Laboratories (“UL”) standards or other state or local electrical code standards to ensure proper installation and use of certified equipment. Even if the generator interconnection agreement is silent on NEC, IEEE, and UL standards, such standards may apply through state or local law and rules and should be considered before hiring contractors and beginning engineering.

B. State Interconnection Agreements and Net Metering. Generally speaking, distribution-level interconnection is governed by state utility commission rules; however, if the distribution facilities to which the project would be interconnected are subject to a FERC-jurisdictional open access transmission tariff (“OATT”), and if the interconnection is for purposes of making wholesale sales (or even having the option of making wholesale sales), FERC’s generator interconnection procedures would likely apply. Such dual-use facilities (i.e., facilities that provide delivery to both end-users and wholesale purchasers) are regulated by both state and federal governments within their respective jurisdictions. In addition, if interconnection is with an entity that is not subject to state or FERC jurisdiction (such as an electric cooperative or public utility district), then the developer may face additional issues and negotiations that are beyond the scope of this summary.

If interconnection is governed by state utility commission rules, simplified procedures may apply for interconnection below a certain size threshold, including standardized form agreements specifically designed for interconnecting solar distributed generation. Standardized agreements have the benefit of lowering transaction costs, although the ability to negotiate terms and conditions in the agreement is significantly reduced if not prohibited. Interconnection procedures and agreements can in many cases be obtained by contacting the local utility. Generally, the state-level interconnection agreement will cover technical and operational issues, as well as the point of interconnection and responsibilities of the customer and utility.

Solar generation interconnecting at the distribution level may also be able to take advantage of net-metering rules. Net metering is an arrangement with a customer’s utility whereby the customer uses its own installed generation to offset its energy usage and may receive credit for limited excess generation. Generally, a customer ends up with a lower utility bill for two reasons: (1) the net-metering arrangement allows the customer to offset its own electricity usage on an instantaneous basis with the solar power produced by its own solar generation system, thereby reducing the amount of power the customer must buy from the utility, and (2) the customer can deliver generation in excess of that currently used by the owner back to the utility and receive a credit from the utility for such generation. Whether the customer can roll forward or receive a cash payment for any credits for excess generation varies from state to state. Essentially, a net-metering arrangement allows the generation owner’s meter to “run backward” when excess generation is supplied to the utility, offsetting the bill from the utility. However, FERC may assert jurisdiction over a net-metering facility if the facility makes net sales of energy (i.e., the facility produces more energy than can be consumed) to a utility over the netting period established by the applicable program (often one year).

Several restrictions usually apply to the net-metering arrangement. Generally, state law and public utility commission rules will set forth the process by which an entity becomes a net-metering customer. State law generally sets forth the criteria for the type of customer (i.e., residential, commercial, or, in some states, limited commercial or industrial customers) and the size of the distributed generation project eligible for the state’s net-metering program, plus safety requirements and other program restrictions and requirements. Finally, state law and public utility commission regulation may restrict the ability of a third party to own the renewable energy system used by a customer in that customer’s local utility’s net-metering program. In addition to eligibility restrictions, potential net-metering customers should look out for other potential issues in net-metering arrangements, such as high liability insurance coverage requirements, indemnification provisions, and other forms of customer charges associated with net metering. These charges may include interconnection charges, demand charges that the utility may assess to cover the costs of being on “standby” to provide power to the customer if the customer’s generation does not produce energy when expected, charges for use of the transmission system when excess power is delivered, and equipment charges for specialized metering or safety equipment.

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 beyond the interconnection point. 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.

FERC-jurisdictional transmission providers are required by FERC to offer transmission service on an open, nondiscriminatory 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 an RTO or ISO rather than the actual owner of the applicable transmission facilities. Acquiring transmission service from non-FERC jurisdictional transmission providers raises additional questions that depend on the nature of the entity, the scope of its transmission facilities, and other issues beyond the scope 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 service capacity (MW). A solar power project that is located far from adequate transmission infrastructure may require substantial system upgrades that will cause the transmission customer to pay an incremental cost that exceeds its pro rata share of the system costs. For these and other reasons, a developer may want to consider making a sale to a third party at the point of interconnection, rather than becoming a transmission customer of the transmission provider with which the project interconnects.

These transmission pricing rules may be different if the transmission provider is an RTO/ISO. The rules of the existing and proposed RTOs/ISOs may in fact be much more favorable to solar power generation than is FERC’s general transmission pricing. For example, an RTO/ISO may recover the fixed costs of the applicable transmission system from end-users, with a generator facing only transmission congestion charges. The RTO/ISO also may eliminate rate “pancaking,” which is the imposition of multiple transmission charges for use of more than one utility’s transmission facilities.

IV. Ancillary Services: Imbalance Charges, and Firming and Shaping Products. Project owners will be required under the transmission provider’s tariff to provide or purchase transmission ancillary services, which are products designed to ensure the reliability of the transmission system. These charges apply most often to project developers who obtain transmission service away from their project’s point of interconnection. Of these products, generation imbalance service often poses the most difficult issues for renewable energy power operators with variable resources. Generation imbalance service is a product that allows a generator to deliver an amount of energy that differs from the amount it had prescheduled for delivery. Although solar energy is expected to be more predictable than wind energy, certain types of solar technology have more variability, which must be considered in terms of imbalance requirements and penalties.

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 imbalances; however, these penalty-type imbalance charges punished variable resource generators for variations in output over which the generators lacked control.

Acknowledging that existing energy imbalance charges under Schedule 4 of the OATT and the generator imbalance charges described in FERC Order No. 2003 were discriminatory to variable energy generators, FERC established in Order No. 890 a tiered structure for imbalance charges, with imbalance charges increasing as the imbalances themselves grow larger. Order No. 890 also provided at least two benefits to variable resources. First, the rules provided for monthly netting of imbalance charges within the first tier. Second, variable resources were excused from exposure to the most expensive deviation charges. Although these rules can provide significant benefits to solar power resources, it is important to understand that transmission providers may be permitted to adopt different provisions applicable to variable resources within their respective control areas.

In addition, it is becoming common for transmission providers to revise their protocols for integrating variable resources into the grid and to impose generator regulation charges or other within-hour balancing charges on variable resources.

V. Greater Access to the Transmission Grid. FERC’s Order No. 890 was designed, in part, as an effort to improve transparency of transmission service and reduce transmission barriers for new market entrants. These amendments have resulted in increased and improved access to the transmission grid for renewable energy developers.

A major obstacle to making more transmission capacity available was that under previous practice, long-term requests for service from a new generator may be denied based on the unavailability of transmission in only a few hours of a year, even though that same capacity is nonetheless available for the large majority of hours of the year. To address these concerns, FERC created two options: conditional firm service and modified redispatch service. These two services provide options for variable resources to gain faster access to the transmission system, as such resources may avoid having to delay going in service until the completion of transmission upgrades.

Conditional firm service addresses the “all or nothing” problem transmission customers had faced, and it is a partial solution to the lack of available firm transmission capacity. Under this service, a conditional firm customer enters a long-term contract for the capacity that is available on a transmission path. The customer has firm service except for time periods designated in the contract and has priority over non-firm service customers for the hours in which available transfer capacity (“ATC”) is not available. Similarly, some transmission providers have transformed the conditional service concept to offer conditional or limited interconnection service as well, which service may subject the project to increased curtailment but will allow a project to become operational before the construction of substantial upgrades.

Modified redispatch service, which adjusts the output of various generators to allow transactions that otherwise would be blocked by congestion on certain transmission paths, is routinely used by integrated utilities (those with transmission and generation) to serve native load and network customers, and to make off-system sales. Order No. 890 required transmission providers to offer and study the use of redispatch service to create additional long-term firm capacity on a transmission system. Customers would agree to pay the costs of redispatch service during the periods when firm ATC is not available. Conditional firm service and modified redispatch service can provide a useful bridge service until new transmission capacity becomes available, although the services may not be sufficient to satisfy the demands of performing a power purchase agreement or obtaining third-party financing.

VI. Reliability Standards. Many solar power generation owners and operators are subject to mandatory reliability standards that include ongoing, audited obligations and potential sanctions for compliance failures. The North American Electric Reliability Corporation (“NERC”) is certified by FERC as the continent-wide 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 upwards of $1 million per day per violation for noncompliance, although penalties rarely reach that level when assessed. In addition, NERC has delegated to designated regional entities the authority to monitor and enforce the reliability standards, and the regional entities may in turn enforce region-specific reliability standards.

The reliability standards apply to certain users, owners, and operators of the bulk electric system, and the regional entities are tasked with maintaining a Compliance Registry, which lists organizations against which the reliability standards are enforceable. If an organization fails to register on the Compliance Registry, then the regional entity may register the entity itself. 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 Generator Operators register with the Compliance Registry. A Generator Owner is, broadly defined, as an organization that owns generating units, and a Generator Operator is defined as an organization that operates generating units and supplies energy. There are thresholds that may dictate whether a Generator Owner or Generator Operator must register or even meets the initial requirement of being a user, owner, or operator of the bulk electric system. Though initially exempted from registration, QFs can also be required to register with the appropriate regional entity and to comply with the reliability standards. Furthermore, solar developers should also understand that sharing a generator interconnection line with other projects (whether affiliated or not) may also lead to NERC registration. If the combined size of projects sharing a gen-tie exceeds 75 MVA and the point of interconnection is at 100 kV or higher, then NERC registration is likely.

Given the breadth of the reliability standards and the punitive sanctions attached, industry participants must take the appropriate steps to determine whether they should register with the applicable regional entity, to understand each function, and to implement a comprehensive program that will track and ensure compliance.

VII. California Regulatory Developments. In California, a dynamic regulatory environment with several active state agencies—including the CPUC, which regulates investor-owned utilities, and the California Energy Commission (“CEC”), which is California’s primary energy policy and planning agency and is responsible for siting thermal generation, including concentrated solar power (“CSP”)—has resulted in numerous ongoing efforts to increase opportunities for solar generation, both photovoltaic and CSP.

Among the recent developments in California is passage of Senate Bill 350 in October 2015, which increases California’s Renewable Portfolio Standard (“RPS”) to 50 percent by 2030. The RPS applies to all retail sellers of electricity, including investor-owned utilities, publicly owned utilities and community choice aggregators. Both the CPUC (in Rulemaking 15 02 020) and the CEC are in the midst of efforts to implement the new legislation. California’s RPS program contains a number of restrictions concerning how utilities may count renewable resources located outside a California balancing authority area toward their RPS obligations. Those restrictions vary depending on how the energy is delivered to California as well, and therefore are an important consideration for any project developments outside of California that intend to sell their output to California utilities.

The CPUC also has the Renewable Market Adjusting Tariff (“ReMAT”), a feed-in tariff for small renewable generators less than 3 MW. The ReMAT program allows renewable projects less than 3 MW to sign standard contracts, with a standard price, that must be accepted by the utilities until an overall megawatt cap is reached.

VIII. Summary. Solar developers range in size and business model greatly, and the regulatory and transmission-related issues are highly dependent on the unique circumstances presented by each particular project. Solar developers should be mindful of the various state and federal regulatory requirements, as well as the opportunities presented by the regulatory oversight in these areas. Download The Law of Solar - 5th Edition (PDF)


1 Certain additional restrictions also apply to this exemption; whether the exemption applies depends on the particular situation.

Key Contributors

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  • Bree Metherall Director of Business Development 503.294.9435
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