Net Metering and Distributed Generation Part II: Legal Background
This article is the second of three discussing states’ implementation of net energy metering (NEM) policies within their authority over energy utilities.
Abstract: Distributed generation promises society-wide benefits to the energy grid. States can further the mass distribution of energy generation resources through progressive policies such as net metering. However, some states have begun to end their formerly robust net metering policies. In light of these changes, this paper will explain why existing legal principles constrain state action which adversely impacts existing net metered customers.
I. LEGAL BACKGROUND
The success of NEM to deploy DG is stunted by the battle over the division of authority and whether NEM can exist under federal law. These customers are in a unique legal position because they may not require all of the energy they produce, so they might sell energy for end-use in a wholesale market, where FERC would regulate under the Federal Power Act (FPA) or PURPA. At the same time, these customers have not ended their state-regulated retail consumer relationship with the utility because they may not produce enough electricity to always self-supply, so the state utility commissions would regulate their retail purchases, connection to the grid, and service fees. This section will explain where the boundaries of the legal relationships between the federal government, the states, the utilities, and the customers began, how it evolved with the FPA, and ultimately changed with PURPA. Applying this background, the next section will analyze the limits on the states’ ability to implement NEM according to federal law.
B. The Federal Power Act
Congress passed the FPA to close the “Attleboro gap” that left a regulatory vacuum once states could not regulate wholesale sales of energy.[1] The FPA authorizes the Federal Energy Regulatory Commission (hereinafter FERC or the Commission), to regulate the “sale of electric energy at wholesale,” which is any sale to any person for resale.[2] The FPA prohibits states from regulating any aspects of wholesale transactions, even those that occurred entirely intrastate.[3] In turn, FERC cannot infringe on the powers traditionally left to the states “over facilities used in local distribution or only for the transmission of electric energy in intrastate commerce, or over facilities for the transmission of electric energy consumed wholly by the transmitter.”[4]
Several cases illustrate how the state and federal government share power over retail and wholesale sales under the FPA. In F.P.C. v. Southern Cal. Edison Co.[5], the city of Colton petitioned FERC’s predecessor, the Federal Power Commission (FPC), to assert jurisdiction over the rates charged to an out-of-state public utility from which it purchased power for resale under § 201(b) of the FPA, which extends the Commission’s jurisdiction to the “sale of electric energy at wholesale in interstate commerce.” The Court held that the FPC’s jurisdiction is “plenary”[6] and affirmed its jurisdiction over the petitioner’s interstate sales.[7] Later, the Court deferred to the Commission’s expansion of its jurisdiction in Fed. Power Comm’n v. Fla. Power & Light[8]; there, it held the FPA’s federal jurisdiction included intrastate transfers of power. The Commission argued it had jurisdiction over the utility because, although the utility mostly transacted intrastate, the fact it also moved power to and from another state caused both power supplies to mix.[9] The Court sustained federal jurisdiction on the assertion the energy “commingles in a bus.”[10] Relying on the “elusive nature of electrons,” the majority refused to require the petitioners to trace their energy from beginning to end to establish jurisdiction.[11]
The Supreme Court has continued this trend of expanding federal jurisdiction by affirming FERC’s regulation of wholesale demand response.[12] Demand response is the opposite of marketing the supply of energy; in these programs, retail customers agree to receive compensation for reducing their energy demand at specific times to balance the grid. Because demand response is the quintessential non-sale of electricity, and the FPA grants jurisdiction for “sales” of electricity, FERC asserted jurisdiction based in its remedial power to ensure “all rules and regulations affecting … rates” in connection with wholesale sales are “just and reasonable.”[13] The Supreme Court agreed with FERC that demand response was a practice directly “affecting” wholesale rates, so FERC had jurisdiction.[14]
i. The State Retail Ratemaking Process
The FPA authorizes the states to design retail tariffs as part of their local distribution and billing jurisdiction, which they do through their state Public Utility Acts[15]. Ordinarily, utilities enjoy a guaranteed return on money spent to acquire their assets of power production; as states expand access to DG, especially through NEM, utilities’ revenues decline along with their share of ownership in the means of power production.[16] From the inception of the modern electric regulatory system, states have entitled utilities to recover whatever “revenue requirement” their regulatory authority sets to cover the utilities’ overall costs; after the utility successfully petitions for its revenue requirement, regulators determine the amount individual customers pay on their bills by allocating the revenue requirement among each of the classes of customer in a manner that is proportionate with the demands that class places on the system as a whole.[17]
States may classify customers, so NEM or rooftop solar customers may have their costs allocated according to their class as NEM customers under cost-causation principles.[18] The costs each class causes are apportioned among the individual customers within the class based on other characteristics, such as time of use or income level.[19] Once the utility’s costs are allocated according to a cost-of-service study that establishes empirical evidence of cost-causation in the administrative record, rates are considered just, reasonable, nondiscriminatory, and in the public interest .[20] Under threat of reversal, utility regulatory authorities can be forced to prove non-discrimination by requiring the utility to present evidence contained in a “cost of service study” and justify a tariff proportional to the DG customer’s costs and benefits to the grid.[21] However, because there are as many empirical methods of allocating costs as there are willing analysts, the state regulators are left to fill certain gaps with policy judgments.[22]
ii. The Filed-Rate Doctrine
In the context of electric utility regulation, the filed-rate doctrine is grounded in FERC’s exclusive rate-setting authority under the FPA and applies to states as a matter of enforcing the Supremacy Clause and FERC’s wholesale jurisdiction under the FPA.[23] The filed-rate doctrine is a century-old Supreme Court canon that can be applied to dismiss many types of lawsuits from antitrust, tort, to contract claims. It applies regardless of whether PURPA is at issue.[24] It is “a form of deference and preemption”[25] that prohibits state and federal courts from invalidating rates after they have been “filed” with FERC, even where they purport to correct an unreasonable methodology in hindsight.[26] If FERC has made a determination as to the reasonableness of a wholesale rate, which it does by filing the rate, states cannot order a retail rate that would undermine the wholesale rate.[27] This prohibition prevents the passage of rates other than those FERC approved, even if the rate purportedly violates state law.[28] The doctrine extends beyond actual rates per se.[29] In Nantahala Power, utilities challenged their state’s allocation of “entitlement” and “purchased” power that differed from one FERC adopted in a wholesale proceeding.[30] The Supreme Court held the state’s rate conflicted with the filed-rate doctrine by causing utilities to incur greater costs than they would if they had followed FERC’s allocation.[31]
The filed-rate doctrine protects rates even where FERC is not the ratemaking authority. In 2019, the First Circuit maintained a broad interpretation of the doctrine, dismissing retail customers’ claims of price manipulation against their utility.[32] Plaintiffs alleged the defendant unreasonably inflated the wholesale and retail rates by reserving excess capacity along a pipeline without using or reselling it to constrain the supply of volume.[33] The Court dismissed the claim because the filed-rate doctrine prohibits challenges to approved rates “even in markets in which FERC has eschewed traditional ratemaking.”[34] To respond to the allegations, FERC stated a “staff inquiry… revealed no evidence of anticompetitive withholding of natural gas pipeline capacity,” so the Commission would “take no further action on the matter.”[35]
So long as a FERC-approved tariff governs market transactions, a rate determined by that market is protected by the filed-rate doctrine.[36] Even if FERC abdicates its oversight of a market, the filed-rate doctrine prohibits courts from reviewing reasonableness between hypothetical and actual rates.[37] This trending broad interpretation of the doctrine excludes federal and state courts, relying entirely on FERC to hold anti-competitive behavior accountable and leaving injured parties without redress once it declines to enforce. While the breadth of the filed-rate doctrine mostly disadvantages consumer-plaintiffs, it should protect any NEM rates from repeal or modification where they have been filed with FERC or with authorities to which FERC has delegated ratemaking responsibility.
iii. The Mobile-Sierra Doctrine
The Mobile-Sierra doctrine is a companion theory of interpreting the FPA and Natural Gas Act that is named after a pair of 1956 Supreme Court decisions.[38] The doctrine obligates FERC to treat any “freely negotiated wholesale-energy contract” as “just and reasonable” under the FPA; that presumption may only be overcome if FERC concludes the contract seriously harms the public interest. [39] A contract rate filed under the FPA is only unlawful if it is unduly discriminatory, excessively burdensome to customers, or a continued threat to service.[40] FERC may suspend the rate while it investigates whether the rate is reasonable.[41] FERC may decline to investigate and permit the rate to go into effect — which does not amount to a determination that the rate is “just and reasonable.”[42] After a rate goes into effect, whether or not the Commission deemed it reasonable when filed, it may respond to a complaint or conclude on its own motion that the rate is not just and reasonable and replace it with a lawful rate.[43] Under a newer aspect of FERC’s regulatory regime, sellers could file a “market-based” tariff, which created contracts that did not have to be filed with FERC before they go into effect.[44] Instead of fixed rates or schedules, the tariffs stated the seller would enter into “freely negotiated contracts” with purchasers.[45] Because the parties filed the market-based tariff with FERC first, the contracts were not subject to FERC’s immediate filing requirement.[46]
In Morgan Stanley, the town of Snohomish entered a long-term contract at relatively high rates after the Western United States’ energy crisis caused a dramatic increase in energy prices.[47] The town petitioned to modify its contract filed under a “market-based” tariff on grounds that FERC could not presume the rates just and reasonable under Mobile-Sierra without the initial opportunity to review them; the town also argued the rates were so high they violated the public interest.[48] The Ninth Circuit rejected FERC’s position that the contracts did not seriously harm the public interest and the Supreme Court affirmed. The Court held FERC was required to apply the Mobile-Sierra doctrine to the contracts filed under the “market-based” tariff because the parties claimed to have freely negotiated; therefore, FERC does not need the initial opportunity to review a contract rate for the presumption of reasonableness to apply because it can review that rate at any time.[49] The Court reserved FERC’s contract-abrogation power for extraordinary circumstances where the public would be harmed.[50] Next, the Court found FERC misapplied its analysis of whether the public would be harmed because it did not compare the difference between rates with and without the presence of a “dysfunctional market”, i.e. the energy crisis, over the long-term to determine whether that disparity amounted to an “excessive burden.”[51] The Court also found FERC could not presume a contract was just and reasonable because it dismissed allegations that parties engaged in market manipulation.[52]
The doctrine has since been expanded to include challenges brought by non-contracting parties.[53] The Court explained since FERC, as the highest arbiter of these disputes, is bound to presume fairness between contracting parties, so must lay consumers, advocacy groups, state utility commissions, and elected officials acting parens patriae; a holding to the contrary would defeat the doctrine’s intention of stability.[54]
C. PURPA and the Purchase Mandate
The passage of PURPA made a specific, important alteration to the FPA’s jurisdictional divide. Congress enacted PURPA in response to the 1970’s American energy crisis to increase small power production and cogeneration and reduce national reliance on fossil fuels, thus realizing national energy independence.[55] For the first time, federal law required states to implement laws requiring utilities to purchase wholesale energy from certain statutorily-designated providers.[56] Located in Title II of PURPA, the Section 210 “purchase mandate” authorizes FERC to promulgate regulations, which in turn require states to promulgate regulations, to increase energy purchases from small power producers and cogenerators called Qualifying Facilities (QFs) at rates representing their “incremental” costs, or avoided costs.[57]
The states argued PURPA’s purchase mandate violated the Tenth Amendment and the Commerce Clause.[58] The Supreme Court rejected both grounds, finding Congress’s jurisdiction over interstate commerce constitutionally justified by the actual aggregate impact on interstate commerce of energy transactions, even wholly intrastate retail transactions.[59] It held the federal government “can pre-empt the States completely in the regulation of retail sales … and in the regulation of transactions between such utilities and cognerators.”[60] It explained, while Section 210 is “the most intrusive” on state powers under the Tenth Amendment, it “does nothing more than pre-empt conflicting state enactments in the traditional way” because the regulations give states a degree of latitude and allow dispute resolution on a case-by-case basis.[61] The Court reasoned Congress designed PURPA with the same type of cooperative federalism dynamic under the Commerce Clause as statutes like the Surface Mining Control and Reclamation Act .[62]
i. Protecting the “Little Guy”
PURPA’s legislative history reflects Congress understood the disadvantages faced by this new class of independent power producers as compared to traditional utilities, such as a lack of guaranteed return on investment.[63] Accordingly, to promote independent power production, states were to exempt QFs from traditional utility-style ratemaking proceedings as protection for their return on investments. The prohibition on “utility-style” ratemaking prevented non-consensual changes to long term contracts between utilities and QFs once effective. In Freehold Cogeneration, a potential QF, Freehold, sought a declaratory judgment that PURPA preempted its state commission from modifying the terms of a previously approved power purchase agreement between it and a utility.[64] The utility had agreed to pay 100% of avoided costs at the 1989 level; but, by 1993, decreased power costs caused the utility to seek to modify or buyout the agreement. After Freehold refused, the state ordered Freehold to negotiate. The Third Circuit sided with Freehold’s challenge to the order, holding PURPA Section 210(a) prevented a state from reviewing a rate by imposing changes to existing contracts between QFs and utilities without the QF’s agreement once it approves agreements on the grounds they are consistent with avoided cost.[65] State and federal courts have since accepted this limitation of authority.[66]
ii. PURPA Contracts and LEOs
Once a QF commits itself to sell to a utility, it immediately commits the utility to buy from the QF, regardless of whether the parties negotiated a contract.[67] QFs larger than 1MW must self-certify with FERC as formal evidence of their commitment to sell power; retail customers that own on-site generators with a maximum net generating capacity of less than 1 MW (which includes most residential rooftop solar installations) may self-certify their QF eligibility to require utilities to purchase their power without notifying FERC.[68] Once certified by the relevant authority, a QF must be able to choose to sell on an “as-available” basis, price the power at the “time of delivery,” and the utility must not refuse purchasing this power.[69]
Alternatively, a QF must also be able sell power for a specified term pursuant to a “legally enforceable obligation” (LEO).[70] If a QF chooses a LEO, it must be able to choose a rate based either on avoided cost at the time of delivery or “the time the obligation is incurred.”[71] In promulgating these requirements, FERC explained that it used the term “legally enforceable obligation” to prevent utilities from circumventing the mandatory purchase obligation by refusing to negotiate or enter into a contract.[72] The “latitude” extended to states under Section 210(f)(1) includes the requirements to create a LEO in that state.[73] For instance, in Exelon Wind, the Fifth Circuit affirmed Texas’s PURPA rules that only permitted QFs which generated firm power to obtain LEOs since QFs with non-firm power, like Exelon Wind, could still sell energy “as-available” for time of delivery rates.[74]
FERC also prohibits states from interfering with a QFs option to enforce the purchase mandate through a LEO.[75] In Grouse Creek, the Commission found that Idaho’s requirement that a QF file a “meritorious complaint” before obtaining a LEO “would both unreasonably interfere with a QF’s right to a LEO and also create practical disincentives to amicable contract formation.”[76] Similarly, in Hydrodynamics Inc., FERC held Montana’s rule limiting access to long-term contracts for QFs larger than 10 MW to only a competitive bidding process was an unreasonable barrier to their right to a LEO.[77] The rule was “inconsistent … to the extent that it offers the competitive solicitation process as the only means by which a QF … can obtain long-term avoided cost rates” because a utility may refuse to offer such a process.[78] FERC also reviewed Montana’s installed capacity limit set at 50 MW which applied to purchases of all wind QFs greater than 100 kW but equal to or below 10 MW.[79] Because the utility had already met the 50 MW capacity limit, only wind QFs less than 100 kW could obtain non-competitive long-term contracts for energy and capacity. FERC ruled the 50 MW installed capacity limit also violated PURPA by singling out and denying QFs larger than 100 kW their right under Section 210 to obtain avoided cost rates under a LEO for long terms.[80]
FERC has stressed the purpose of LEOs in addition to contracts to “ensure the certainty of rates for purchases from a qualifying facility which enters into a commitment to deliver energy or capacity to a utility.”[81] Accordingly, states cannot rely on PURPA’s reference to the utility’s “incremental costs” to re-evaluate long-term rates between QFs and utilities from a LEO once in place.[82] The date a LEO takes effect sets the relevant rate for compensation.[83] In Grouse Creek, Idaho’s PUC provided for “standard offer” rates for QFs up to 10 MWs, but later passed a new rule setting an expiration date for the standard offer rates; the new rule deprived existing QFs of their entitlement to the original standard offer rate, forcing them to bargain with utilities for lower contractual rates.[84] FERC ruled the expiration date violated PURPA since the QFs had committed to their obligations as required and were guaranteed fixed, full avoided cost rates from the time the obligation was incurred.[85]
The Tenth Circuit recently refused to hear an argument over New Mexico’s implementation, or lack thereof, of LEOs.[86] In Great Divide, a wind farm petitioned its state utility commission that a utility had a LEO to purchase the wind farm’s output when the project would begin commercial operation in 2020 under New Mexico’s Rule 570. [87] The state commission determined that the wind farm did not meet Rule 570’s “interconnectedness requirement” because they were not built, so there was no LEO on behalf of the utility.[88] The wind farm challenged Rule 570 under Section 210 because it did not define LEOs as described in FERC’s rule, but the court granted the utility’s motion to dismiss on jurisdictional grounds.[89] The wind farm compares Rule 570 to FERC decisions that reject states’ requirements for QFs to sign interconnection or power purchase agreements to establish a LEO; however, requiring QFs to be ninety days from operation compares to the Texas rule implemented in Exelon Wind.[90]
iii. Avoided Cost Rates
States also set the utilities’ “avoided” or “incremental” cost rates for wholesale power purchased from QFs through formal proceedings where they must consider specific factors like the QF’s capacity and reliability.[91] In turn, regulation of the QF is exempt from FERC wholesale jurisdiction under the FPA.[92] In lieu of a traditional wholesale price set by competitive bidding, the states must set a rate for purchases from QFs that is no greater than “the incremental cost to the electric utility of alternative electric energy” and is “just and reasonable and in the public interest” and that does “not discriminate against qualifying cogeneration and small power production facilities.”[93] PURPA requires “rates for sales . . . [s]hall not discriminate against any [QF] in comparison to rates for sales to other customers served by the electric utility.”[94] The law requires identical protection for the retail rates the QF pays to the utility, absent the avoided cost requirement.[95] It entitles small QFs to standardized avoided cost rates and terms, which are pre-set, as opposed to negotiated rates that are usually lower.[96] Standard cost rates may distinguish among QFs depending on the type of production, so long as they are justified and do not target a QF for unfavorable treatment.[97]
To avoid excess charges to the entire consumer base, the avoided or incremental cost must be the amount the utility would have spent “had it generated the electricity itself or purchased…from another source.”[98] Full NEM rates result in the utility compensating the customer for energy produced and consumed on site as well as excess sent back for resale at near or exactly the retail rate.[99] Retail rates are the primary economic incentive for potential DG developers because they are up to three times higher than avoided cost rates.[100]
In addition to the netting dynamic illustrated in MidAmerican and Sun Edison, the states’ use of Renewable Portfolio Standards (RPS) lends further jurisdictional support to compensating certain QFs at rates greater than the utilities’ avoided cost. FERC has issued several decisions to this end. In 1995, two utilities challenged an order of the California Public Utilities Commission (CPUC) to enter long-term, fixed-price contracts with QFs in prices “far in excess of their avoided costs.”[101] The Commission found the CPUC’s method of determining avoided costs to be inconsistent with PURPA because it did not allow certain QFs to bid, so the utility could not purchase from all potential sources of capacity as required by Section 210.[102] The Commission stated:
“regardless of whether the State regulatory authority determines avoided cost administratively, through competitive solicitation (bidding), or some combination thereof, it must in its process reflect prices available from all sources able to sell to the utility whose avoided cost is being determined.”[103]
Over a decade later, the Commission responded to an argument that CPUC’s decision to require utilities to offer a certain price to small combined heat and power (CHP) facilities was preempted by the FPA because it set rates for wholesale sales of energy.[104] The CPUC requested clarification that it could “require retail utilities to consider different factors in the avoided cost calculation in order to promote development of more efficient CHP facilities” and avoided cost can “properly take into account real limitations on ‘alternate’ sources of energy imposed by state law.[105] FERC held CPUC could set new avoided cost rates using a multi-tiered avoided cost rate structure and that the state could take into account obligations it imposed that require its utilities to procure energy from particular sources or for a certain period.[106] For example, if a state required a utility to purchase 10 percent of its energy from renewable resources, a natural gas-fired unit would not be a source “able to sell” to that utility for the purposes of meeting the RPS, so the cost of its energy would be irrelevant to determining avoided cost for that portion of the utility’s needs. Although FERC’s opinion said states could calculate avoided costs in the manner described, the Ninth Circuit later found a state must base the avoided cost on renewables only if an RPS existed and a QF could meet that need.[107] The Court explained where a state has an RPS and the utility is using a QF’s energy to meet the RPS, the utility cannot calculate avoided costs based on energy sources that would not also meet the RPS.[108]
iv. Judicial Review of PURPA Implementation
Located in Title II, PURPA Section 210 governs the relationship between FERC, utilities, independent power producers, and state public utilities commissions in implementing PURPA.[109] The statute directs FERC to promulgate rules to encourage the development of small power production and reduce demand on fossil fuels and requires each state regulatory authority and nonregulated utility to implement FERC’s rules.[110] Section 210(g) provides state courts with jurisdiction “respecting any proceeding conducted by a State regulatory authority or nonregulated electric utility for purposes of implementing any requirement of a [FERC] rule….”[111] In contrast, Section 210(h) authorizes FERC to enforce the implementation requirement against any State regulatory authority or nonregulated electric utility or, if FERC declines to do so, authorizes any utility or QF to bring an action in federal court.[112]
A line of cases has divides preemption claims in terms of “implementation” challenges under Section 210(h) versus “application” challenges under Section 210(g). The implementation-versus-application analysis has its genesis in two cases, Greensboro Lumber[113] and M.I.T.[114]. In Greensboro Lumber, a biofuel QF claimed their utility failed to provide it with non-discriminatory rates for back-up and maintenance power.[115] The Eleventh Circuit deferred to FERC’s interpretation of Section 210, categorizing the claim as an “as-applied” challenge under Section 210(g) because the plaintiffs attacked the state’s poor adherence “to its own implementation plan in its dealings with a particular [QF].”[116] Facing a similar challenge in M.I.T., the District Court explained:
“[a]n implementation claim … involves a contention that the state agency has failed to implement a lawful implementation plan under § 210(f) of PURPA. An as-applied claim, in contrast, involves a contention that the agency’s implementation plan is unlawful, as it applies to or affects an individual petitioner.”[117]
When a state fails to implement FERC regulations in accordance with Section 210(f)(1)’s requirements, most courts treat that failure to comply as a failure to implement.[118] In Freehold Cogeneration, the Third Circuit found it had subject matter jurisdiction to hear the utility’s argument that the state was preempted by PURPA from modifying the terms of a previously-approved power purchase agreement.[119] Freehold alleged the state action was inconsistent with, and so preempted by, Section 210(e),[120] whereas the respondent argued Freehold’s complaint referred to the rules implemented under Section 210(a). The Court held Freehold’s claim arose under federal question jurisdiction because it complained the state interfered with its federally-granted right to be exempt from utility-style state regulation under Section 210(e) and that the limitations of Section 210(g) divesting the federal courts of jurisdiction were not relevant.
In August, 2019, solar advocates in New Mexico brought an action under PURPA Section 210(h), arguing that because the defendant utility set rates that did not reflect cost-causation principles, it failed to “implement” FERC’s anti-discrimination provision contained in its regulations.[121] Specifically, it alleged the utility charged discriminatory service riders that “imposed higher and additional charges for customers who self-supply…with solar;” where the utility “lack[ed] the requisite data showing a difference in loads and costs by solar compared to non-solar customers.”[122] The District Court granted the utility’s motion to dismiss because the plaintiffs’ claim that the utility adopted a discriminatory rate in violation of PURPA was not a claim that the utility failed to implement any antidiscrimination rule at all.[123] It explained “[f]ederal jurisdiction under Section 210(h) should not be stretched to cover disputes over how well a regulatory entity implements FERC’s rules or the propriety of that entity’s state or local rules.”[124] This holding follows the same reasoning in Great Divide, where the court found it lacked jurisdiction because the challenge to Rule 570 was an “as-applied” claim.[125] This case, alongside Great Divide, suggests federal courts are willing to eschew oversight of PURPA’s implementation. The holdings of City of Farmington and Great Divide threaten to foreclose federal courts from redressing anticompetitive treatment of QFs.
C. Implementing Net Metering
Even before Congress introduced PURPA and net metering, the energy policy objectives of federal regulators superseded traditional state authorities.[126] Many states implemented NEM laws after PURPA was passed in 1978 but before the policy was added through an amendment to Section 111(d) of PURPA under the Energy Policy Act of 2005 (EPAct).[127] The EPAct defined net metering as “service to an electric consumer under which electric energy generated by that electric consumer from an eligible on-site generating facility and delivered to the local distribution facilities may be used to offset energy provided by the electric utility to the electric consumer during the applicable billing period.”[128] However, the phrase “electric energy” has sparked debate as to whether states should grant consumers “credit,” i.e. wholesale, based energy supplied, or instead grant a retail rate, which often accounts for grid and service costs.[129]
As opposed to Title II, which provides for the powers of the federal government to regulate transmission and requires states to implement the purchase mandate, Section 111(d) is located in Title I of PURPA that concerns retail regulatory policies and standards for electric utilities. Section 111(d) required states to consider implementing NEM policies through regulatory proceedings by a specified deadline, then make a yes or no decision on whether to adopt that standard. The Secretary of Energy, any affected utility, and any of the affected utility’s customers may intervene as of right in state regulatory proceedings relating NEM rates.[130] This right is enforceable against in federal court.[131] For purposes of judicial review in any court “in accordance with [Section 123],” the policies under Section 111(d) serve to “supplement otherwise applicable State law.”[132] The inclusion of NEM policies as a “supplement” to state law within PURPA encourages states to adopt NEM after considering federal standards without conflicting with federal wholesale jurisdiction.[133] States can even mandate system-wide deployment of NEM systems without conflicting with PURPA.[134]
Because states are required to implement QF contracts, but are only required to consider implementing NEM contracts, all potential DG installers are guaranteed compensation under PURPA. Pursuant to FERC’s position in MidAmerican, states can credit at the retail rate up to the net and apply the avoided cost rate to surplus sales over the net on behalf of either QFs or NEM customers if the state has created them.
i. Trouble with MidAmerican
Iowa led the nation with an early full net metering policy. Utilities including MidAmerican challenged Iowa’s NEM policy because it compensated small power producers’ surplus power transmissions at greater than avoided cost rates.[135] The District Court ruled the FPA and PURPA’s avoided cost requirement preempts Iowa’s implementation of its NEM policy.[136] MidAmerican argued states were prohibited from compensating sellers at greater than wholesale rates, regardless of whether the independent sellers were QFs. If the sellers were not QFs, the FPA preempted NEM because states cannot regulate a wholesale “sale.”[137] If the arrangement existed between QF and utility as a “sale” for resale, states were preempted by PURPA from setting rates above avoided cost.[138]
Facing the demise of NEM, FERC refused exclusive wholesale jurisdiction over net metering transactions on the theory that they do not result in a “sale.” FERC argued states could use their billing authority to offer retail credit by characterizing flows of power between a DG customer and a utility as a “net” transaction so long as the customer’s production did not exceed consumption.[139] This position preserved the state’s ability to compensate NEM customers at rates higher than avoided cost so long as the customer did not produce more than they consumed.[140] In the event of a net sale from the customer to the utility, a QF would receive avoided cost, where non-QFs rates would file under the FPA.[141]
After the initial MidAmerican ruling, FERC rejected a nearly identical challenge to Iowa’s NEM policy.[142] MidAmerican complained it was paying greater than avoided cost rates and that Iowa violated the FPA by allowing non-QFs to “sell” wholesale power.[143] FERC applied its earlier position; this time, by comparing net metering to the facts of PJM Interconnection, L.L.C.[144] There, a generator’s self-supply of power did not constitute a “sale of energy at wholesale in interstate commerce.”[145] Following this logic, generators could “net” their demand against their supply per billing cycle without causing a “sale,” and that only when the generator’s demand exceeded its supply would the transaction become a “sale.”[146] FERC quickly extended this authority to power flowing from generating equipment owned by someone other than the equipment’s host, such as lessors of solar panels, in Sun Edison.[147]
Through MidAmerican, FERC endorsed the states’ use of retail billing authority to promote investment in independent power production facilities at greater than avoided cost rates. A state’s choice to implement NEM policies is conditioned on providing the same minimum federal protections that limit its design of avoided cost rates, namely the requirement that they be “just and reasonable,” in the public interest, and nondiscriminatory. Establishing precedent for states to treat NEM users with the same minimum contract and anti-discrimination protections afforded to QFs, without treating them as QFs per se by requiring a federally-set wholesale rate would address the tension between PURPA’s mission to lower rates and the failure of renewable DG deployment without a degree of incentive.
When FERC took the position that “no sale” occurs during a netted transaction to allow the states to deploy NEM, it did not anticipate that states such as Nevada would redesign NEM and undermine homeowners with solar once they made costly investments. Without PURPA Section 210 and FERC’s position in MidAmerican that justified netting as a component of retail billing, states would otherwise lack the necessary authority to set the wholesale rates utilities pay to their customer-generators. Likewise, the federal government would not intrude on the states’ right to fix retail rates and billing systems but for the creation of Section 210’s purchase requirement that protects QFs in not only the sale to the utility, but also in purchases from the utility.
Despite the fact states assert jurisdiction to regulate NEM customers through their authority over local distribution and end-use, or retail, power transactions, the Supreme Court has not wavered in declaring federal regulation of the energy market down to the retail level constitutional under the Commerce Clause for its aggregate impact on interstate commerce.[148]
In Sun Edison, a company that financed, installed, and maintained solar panel units petitioned FERC to declare its program was not selling at wholesale.[149] Its customers sent energy to utilities and that energy was netted against their purchases from the utility.[150] The Commission agreed with Sun Edison that where there is no “net sale” over the billing period applicable to the local utility, there is no wholesale sale.[151]
iii. The End of Net Metering as We Know It?
In 2020, a group called the New England Ratepayers Association (NERA) petitioned FERC to declare exclusive federal jurisdiction over sales from NEM participants.[152] The petition tried to force FERC to reconcile the D.C. Circuit’s rejection of its “netting theory” in S. Cal Edison Co. and Calpine Corp. [153] with its position in MidAmerican and Sun Edison, threatening to leave FERC without any remaining legal theory supporting NEM.[154] The NERA claimed S. Cal. Edison Co. v. F.E.R.C.[155] invalidated the same “netting theory” supporting MidAmerican and Sun Edison.[156] The Commission’s wholesale authority, it argued, did not extend to netting “separate services with different cost structures” to determine whether a wholesale sale occurs and it should not have used a retail billing cycle as the netting period.[157] FERC could not deem customer-generated power, which it argued was wholesale, as equal to retail value, utility-generated power without violating its wholesale jurisdiction.[158]
In S. Cal. Edison Co., the D.C. Circuit held FERC exceeded its jurisdiction by ordering a state grid operator to use the same netting period to calculate transmission charges for station power and retail charges, allowing generators to avoid paying retail rates for “station power” i.e., the energy used to operate the station. Instead of paying retail rates, the generating stations would subtract their use from their gross output. Thus, the generating stations netted energy at a one-to-one ratio, similar to how the owner of a residential solar unit nets their power under a full net metering scheme. The Court vacated FERC’s tariff because FERC failed to demonstrate a connection between its jurisdiction over transmission and the netting intervals governing retail sales for the use of station power and failed to explain why the station’s consumption did not create a sale.[159] The D.C. Circuit did “not understand why FERC is empowered to conclude that a retail sale has not taken place unless it can claim the transaction is, instead, a wholesale sale or transmission.”[160] FERC issued a new order, acknowledging it lacked a jurisdictional basis to determine when the supply of station power becomes a retail sale and indicating its tariff could only govern transmission, not retail charges.[161] In Calpine Corp., the Court revisited the question of FERC’s authority to set netting periods. The court found FERC’s wholesale jurisdiction did not include retail consumption of station power, preventing it from regulating the netting of charges. FERC lacked jurisdiction despite the fact the amount of generator-supplied wholesale energy and the amount of station power consumed affected wholesale prices.[162]
Only a few months after the NERA submitted its petition, FERC unanimously rejected it without addressing the merits.[163] Specifically, the petition failed to “identify a specific controversy or harm that the Commission should address…to terminate a controversy or to remove uncertainty.”[164] Using FERC’s version of a standing doctrine may have saved it from answering to the D.C. Circuit for now, but it created a broad precedent to dismiss consumer-driven challenges to FERC’s general use of its wholesale jurisdiction, let alone over NEM. Although the D.C. Circuit denied FERC’s authority to set netting periods for station power for a state, it left discussing whether FERC lacks jurisdiction to allow states to implement NEM by paying participants greater than avoided cost rates for another day. Neither of the opinions in S. Cal. Edison Co. and Calpine Corp. mentions net metering, MidAmerican, or the Sun Edison cases. However, all involve FERC’s authority over wholesale sales netted against retail consumption. FERC’s jurisdiction does not permit it to order the netting periods for the consumption of station power to determine whether a wholesale sale took place.
The fact that FERC lacks jurisdiction to set retail netting periods does not disturb its jurisdiction over NEM because MidAmerican only established the existence of a net flow of power accounted over a retail billing cycle, or netting period, determines jurisdiction, not that FERC has authority to order the billing cycle. So long as netting occurs, the entity setting the interval is irrelevant because no traditional sale occurs. Netting prevents the need for a sale by its nature as a conservation tool and trading program. States, through their billing authority, set netting periods and determine the existence of a net sale, while FERC may use its authority over QFs to protect NEM users from discriminatory terms that are against the public interest.
[1] PUC of RI v. Attleboro Steam & Elec. Co., 273 U.S. 83 (1927) (held that the Commerce Clause prohibited Rhode Island from regulating the rate charged by its utility for electricity sold in Massachusetts).
[2] 16 U.S.C. § 824(d) (2000) (emphasis added).
[3] Fed. Power Comm’n v. Fla. Power & Light, 404 U.S. 453 (1972).
[4] 16 U.S.C. 824(b)(1).
[5] 376 U.S. 205 (1964).
[6] Id. at 216.
[7] Id.
[8] 404 U.S. 453 (1972).
[9] Id. at 458.
[10] Id. at 463.
[11] Id. at 466.
[12] F.E.R.C. v. Elec. Power Supply Ass’n, 136 S. Ct. 760 (2016), as revised (Jan. 28, 2016) (“EPSA”).
[13] 16 U.S.C. §§ 824d(a), 824e(a).
[14] EPSA, 136 S.Ct. at 784, citing California Indep. Sys. Operator Corp. v. F.E.R.C., 372 F.3d 395, 399 (D.C. Cir. 2004) (limiting FERC jurisdiction under FPA to rules directly affecting the wholesale rate).
[15] See, e.g., VA CODE ANN. §§ 56–235 et seq. and 56–576 et seq (Electric Utility Regulation Act).
[16] Lazar, et. al., Electricity Regulation in the US: A Guide, Second Edition, Montpelier, VT: The Regulatory Assistance Project, (2016), 51–53, http://www.raponline.org/wp-content/uploads/2016/07/rap-lazar-electricity-regulation-US-june-2016.pdf.
[17] Id. at 61.
[18] Id. at 51–53.
[19] Id.
[20] Id.
[21] 16 U.S.C. § 824a-3(c); Complaint at 10, 13; Lazar, supra, at 61.
[22] Id.
[23] Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 965 (1986).
[24] See Williams Natural Gas Co. v. F.E.R.C., 3 F.3d 1544, 1554 (D.C. Cir. 1993) (denying retroactive effective date to an agency rule to protect expectations of those relying on preexisting rule); Pearlman v. F.E.R.C., 845 F.2d 529, 534 (5th Cir. 1988)(stating no retroactive effect to a new FERC rule); Clark-Cowlitz Joint Operating Agency v. F.E.R.C., 826 F.2d 1074, 1081 (D.C. Cir. 1987) (holding retroactive application of new rule avoided to prevent manifest injustice); Aliceville Hydro Assocs. v. F.E.R.C., 800 F.2d 1147, 1152–53 (D.C. Cir. 1986) (allowing retroactive application under certain conditions); Tenn. Gas Pipeline Co. v. F.E.R.C., 606 F.2d 1094, 1115–16, 1116 n.77 (D.C. Cir. 1979) (permitting retroactive application of new rule when there was no reasonable basis for reliance on preexisting rule).
[25] Wah Chang v. Duke Energy Trading & Mktg., LLC, 507 F.3d 1222, 1225 (9th Cir. 2007).
[26] Transmission Agency of N. California v. Sierra Pac. Power Co., 295 F.3d 918, 929 (9th Cir. 2002).
[27] Narragansett Elec. Co., v. Burke, 381 A.2d 1358, 1362 (1977), cert. denied, 435 U.S. 972 (1978) (explaining rate filed with federal Commission was “reasonable” operating expense the state was required to allow in rate base).
[28] Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 579 (1981) (stating it would undermine the federal scheme of uniform rate regulation to ‘allow state to award as damages a rate never filed with the Commission and thus never found to be reasonable’ within the meaning of the Natural Gas Act and that such a course impermissibly grants states more remedial power than the federal government.)
[29] Nantahala Power & Light Co. v. Thornburg, 476 U.S. at 965; Northern Natural Gas Co. v. Kansas Corporation Comm’n, 372 U. S. *967 84, 90–91 (1963) (“our inquiry is not at an end because the orders do not deal in terms of prices or volumes of purchases.”).
[30] Id. at 955.
[31] Id. at 968–969.
[32] Breiding v. Eversource Energy, 939 F.3d 47 (1st Cir. 2019).
[33] Id.
[34] Id. citing Town of Norwood v. New Eng. Power Co., 202 F.3d 408, 419 (1st Cir. 2000).
[35] News Release, FERC Staff Inquiry Finds No Withholding of Pipeline Capacity in New England Markets, Federal Energy Regulatory Commission (Feb. 27, 2018).
[36] Breiding v. Eversource Energy, 939 F.3d 47 (1st Cir. 2019).
[37] Breiding v. Eversource Energy, 344 F. Supp. 3d 433, 451 (D. Mass. 2018).
[38] United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956); Federal Power Comm’n v. Sierra Pacific Power Co., 350 U.S. 348 (1956).
[39] Id.
[40] Id.
[41] 16 U.S.C. § 824(e).
[42] See 18 CFR §35.4 (2007).
[43] 16 U. S. C. §824e(a) (2000 ed., Supp. V).
[44] See generally Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity And Ancillary Services By Public Utilities, Order №697, 72 Fed. Reg. 39904 (2007).
[45] Id.
[46] Id.
[47] Morgan Stanley Capital Grp Inc. v. Pub. Util. Dist. №1, 554 U.S. 527 (2008).
[48] Id.
[49] Id. at 546–47.
[50] Id. at 547.
[51] Id. at 550–51.
[52] Id. at 550, 554.
[53] NRG Power Marketing, LLC v. Maine Pub. Util. Comm’n, 558 U.S. 165 (2010).
[54] Id.
[55] Am. Paper Inst., Inc. v. Am. Elec. Power Serv. Corp., 461 U.S. 402, 417 (1983) (API).
[56] The mandatory purchase obligation was later reformed to relieve utilities of the requirement as PURPA achieved its goals. For instance, states could exempt utilities from purchasing if they operated in a competitive market. For purposes of serving national discussion, this note will conduct analysis under the assumption any relevant purchase mandate waiver does not apply.
[57] See 16 U.S.C. §§ 796(17), 824a–3(a); 18 C.F.R. §§ 92.101(b)(1), 292.203; F.E.R.C. v. Mississippi, 456 U.S. 742, 759 (1982) (“§ 210 has the States enforce standards promulgated by FERC”).
[58] 456 U.S. 742.
[59] Id.at 755–56.
[60] F.E.R.C. v. Mississippi, 456 U.S. 742, 759 (1982) (emphasis added).
[61] Id. at 758–59.
[62] Id., citing Hodel v. Virginia Surface Min. & Reclamation Ass’n, Inc., 452 U.S. 264 (1981).
[63] H.R.Conf.Rep. №95–1750, pp. at 97–98, U.S.Code Cong. & Admin.News 1978, pp. 7659, 7831–32 (1978) (“The conferees recognize that cogenerators and small power producers are different from electric utilities, not being guaranteed a rate of return of their activities generally or … the sale of power to the utility and whose risk in proceeding forward … is not guaranteed to be recoverable”).
[64] Freehold Cogeneration Associates v. Board of Regulatory Commissioners of the State of New Jersey, 44 F.3d 1178 (3rd Cir. 1995) cert. denied, 316 U.S. 815 (1995).
[65]Id. (“The present attempt to either modify the PPA or revoke BRC approval is “utility-type” regulation — exactly the type of regulation from which Freehold is immune under section 210(e).”).
[66] See also W. Penn Power Co. v. Pa. Pub. Util. Comm’n, 659 A.2d 1055, 1066 (Pa. Commw. Ct. 1995) (citing Freehold, PURPA preempts the state utility regulatory commission from changing or reconsidering its prior approval of rates established in QF contracts); New York State Elec. & Gas Corp. v. Saranac Power Partners L.P., 117 F. Supp. 2d 211 (N.D.N.Y. 2000), aff’d, 267 F.3d 128 (2nd Cir. 2001) (denying a utility’s request to modify long-term contracts for unfavorable long-run avoided costs).
[67] JD Wind 1, LLC, 129 F.E.R.C. ¶ 61, 148 (2009).
[68] 18 C.F.R. § 292.203(d).
[69] Id. § 292.304(d)(1).
[70] Id. § 292.304(d)(2).
[71] Id.
[72] Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order №69, FERC Stats. & Regs. ¶ 30,128, at 30,880, order on reh’g, Order №69-A, FERC Stats. & Regs. ¶ 30,128, 30,880 (1980).
[73] Power Resource Group, Inc. v. Public Utility Comm’n of Texas, 422 F.3d 231 (5th Cir. 2005).
[74] Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380, 400 (5th Cir. 2014).
[75] Grouse Creek Wind Park, LLC, 142 FERC ¶ 61,187 (2013) (Grouse Creek).
[76] Id. at ¶ 40
[77] 146 F.E.R.C. ¶ 61193 (Mar. 20, 2014).
[78] Id. at P 9.
[79] Id. at 61840.
[80] Id.
[81] 45 Fed.Reg. 12224 (Feb. 25, 1980).
[82] Id.
[83] Grouse Creek Wind Park, LLC, 142 F.E.R.C. ¶ 61,187 (2013).
[84] Id.
[85] Id.
[86] Great Divide Wind Farm 2 LLC v. Becenti Aguilar, 405 F. Supp. 3d 1071 (D.N.M. 2019).
[87] Id. at 1077.
[88] Id.
[89] Id.
[90] Jennifer Key, The Formation of Legally Enforceable Obligations: The Year in Review (2018), Steptoe PURPA and Distributed Energy Resources Blog, (Dec. 8, 2018). https://www.steptoepurpablog.com/2018/12/formation-legally-enforceable-obligations-year-review-2018/.
[91] Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, 45 Fed.Reg. 12214, 12215 (Feb. 25, 1980).
[92] 18 C.F.R. §§ 292.304(e), 601(c).
[93] 16 U.S.C. § 824a-3(b); 18 C.F.R. § 292.304.
[94] 18 C.F.R. § 292.305(a)(1)(ii) (2019).
[95] 16 U.S.C. § 824a-3(c).
[96] Id. § 292.304(c)(2).
[97] Id. §§ 292.304(a)(1)(i)-(ii), ©(3).
[98] Am. Paper Inst., Inc. v. Am. Elec. Power Serv. Corp., 461 U.S. 402, 405 (1983) (API).
[99] In New Hampshire, customers receive a price, through a billing credit, that is just below the full bundled retail rate when their monthly output exceeds their load; this is several times higher than the market price for energy or the established avoided cost. N.H. Rev. Stat. § 362-A:9 (2019).
[100] Melissa Powers, Small is (Still) Beautiful: Designing U.S. Energy Policies to Increase Localized Renewable Energy Generation, 30 Wis. Int’l L.J. 595, 636–638 (2012).
[101] SoCal Edison Co., 70 F.E.R.C. ¶ 61,215 (1995).
[102] Id. at 26.
[103] Id.
[104] CPUC v. SCE, 133 F.E.R.C. ¶ 61, 059 (2010).
[105] Id. at 3.
[106] Id. at 12–13.
[107] CARE V. CPUC, 922 F.3d 929 (2019).
[108] Id.
[109] See 16 U.S.C. § 824a-3
[110] 16 U.S.C. § 824a-3(f).
[111] 16 U.S.C. § 824a–3(g).
[112] 16 U.S.C. § 824a–3(h).
[113] Greensboro Lumber Co. v. Georgia Power Co., 643 F. Supp. 1345, 1374 (N.D. Ga. 1986), aff ‘d, 844 F.2d 1538 (11th Cir. 1988).
[114] Mass. Inst. of Tech. v. Mass. Dep’t of Pub. Utilities, 941 F. Supp. 233, 237 (D. Mass. 1996).
[115] Greensboro Lumber, 643 F. Supp. at 1374.
[116] Id.
[117] M.I.T., 941 F. Supp. at 237.
[118] See 16 U.S.C. §824a-3(f)(1),(h)(1); Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d at 388–95 (assuming state regulatory action violating PURPA and the FERC regulation can form the basis for as-implemented claim); Power Res. Grp., Inc. v. Pub. Util. Comm’n of Tex., 422 F.3d 231, 239 (5th Cir. 2005) (same); N.Y. State Elec. & Gas Corp. v. F.E.R.C., 117 F.3d at 1473, 1476 (D.C. Cir. 1997) (“The failure of a state commission to ensure that a rate does not exceed a utility’s avoided cost is a failure to comply with a regulation implementing [PURPA].”); N.Y. State Elec. & Gas Corp. v. Saranac Power Partners L.P., 117 F. Supp. 2d 211, 242 (N.D.N.Y 2000) (“Since [New York State Electric and Gas Co.] complains herein about [New York Public Service Commission’s] inconsistency with both PURPA as well as FERC’s regulations, it asserts the existence of district court jurisdiction pursuant to PURPA Section 210(h)(2)(A).”).
[119] Freehold Cogeneration Associates v. Board of Regulatory Commissioners of the State of New Jersey, 44 F.3d 1178 (3rd Cir. 1995) cert. denied, 316 U.S. 815 (1995).
[120] See 16 U.S.C. § 824a-3(e)(1); 18 C.F.R. § 292.602(c).
[121] Solar v. City of Farmington, No. CV 19–753 JAP/CG, 2020 WL 673087, at *12 (D.N.M. Feb. 11, 2020); 18 C.F.R. § 292.305(a).
[122] Id. at *3
[123] Id. at 23.
[124] Solar v. City of Farmington, at *8.
[125] Great Divide Wind F. Supp. 3d at 1098–99.
[126] Ark. Power & Light Co. v. Fed. Power Comm’n, 368 F.2d 376, 384 (8th Cir. 1966) (stating that federal regulation of sales for resale under Section 201 of the FPA precludes concurrent state jurisdiction over utility or independent power producers); see also Hodel v. Virginia Surface Min. and Reclamation Ass’n, Inc., 452 U.S. at 290 (stating the federal government may “prohibit the States’ prerogatives…”).
[127] 16 U.S.C. § 2621(d)(10)(E)(11).
[128] Id. (emphases added).
[129] See FirstEnergy Corp. v. Pub. Utils. Comm’n of Ohio, 768 N.E.2d 648 (Ohio 2002) (affirming utility definition of “electricity” within net metering definition as requiring credit for electricity at unbundled generation rate instead of the bundled retail rate).
[130] 16 U.S.C. § 2631(a).
[131] Id. § 2633(b).
[132] Id.§ 2622(a) (emphasis added).
[133] Romeo v. Pennsylvania Pub. Util. Comm’n, 154 A.3d 422 (Pa. Commw. Ct. 2017).
[134] Id.; accord New York State Dep’t of Soc. Servs. v. Dublino, 413 U.S. 405, 421 (1973).
[135] MidAmerican Energy, 94 FERC ¶ 61,340 (2001) (“MidAmerican”).
[136] MidAmerican Energy Company v. Iowa Utilities Board, No. AA3173, 3195, 3196, at 18–20 (Iowa District Court May 25, 1999).
[137] Id.
[138] Id.; Connecticut Light & Power Co., 70 FERC ¶ 61012, 61023 (Jan. 11, 1995) (vacating state’s final per kWh charge for QF wholesale sale for failure to comply with avoided cost requirement).
[139] Midamerican Energy Co., 85 FERC ¶ 61470, 62713 (Dec. 30, 1998).
[140] Id.
[141] Id.
[142] 94 F.E.R.C. ¶ 61340 (Mar. 28, 2001).
[143] Id.
[144] 94 F.E.R.C. ¶ 61251 (Mar. 14, 2001).
[145] Id. at 61889.
[146] Id. at 61,881.
[147] Sun Edison, LLC, 129 F.E.R.C. ¶ 61,146 (Nov. 19, 2009).
[148] F.E.R.C. v. Mississippi, 456 U.S. 742.
[149] Sun Edison LLC, 129 FERC ¶ 61,146, 61618, at ¶ 61618 (2009).
[150] Id. at ¶ 61619.
[151] Id. at ¶ 61621.
[152] Petition for Declaratory Order of New England Ratepayers Association Concerning Unlawful Pricing of Certain Wholesale Sales, April 14, 2020 (No. EL20-__-000) (hereinafter “NERA Petition”); Catherine Morehouse, Secretive Group’s Petition to FERC Could ‘End Net Metering as We Know It,’ Lawyers Say, Utility Dive, (Apr. 21, 2020), https://www.utilitydive.com/news/secretive-groups-petition-to-ferc-could-end-net-metering-as-we-know-it/576400/.
[153]Calpine Corp. v. F.E.R.C., 702 F.3d 41 (D.C. Cir. 2012).
[154] NERA Petition at *12.
[155] 603 F.3d 996, 997 (D.C. Cir. 2010).
[156] NERA Petition at *12.
[157] Id. *7.
[158] Id. at *12.
[159] Calpine Corp. v. F.E.R.C., 702 F.3d at 45.
[160] S. Cal. Edison Co. v. F.E.R.C., 603 F.3d 996, 1000–01.
[161] Calpine Corp. v. F.E.R.C., 702 F.3d at 45.
[162] Id. at 48.
[163] New England Ratepayers Association, 172 F.E.R.C. ¶ 61,042 (2020).
[164] Id. at ¶ 36.
