Insights

On June 16, 2022, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) proposing significant reforms to the procedures under which electric generators obtain interconnection to the transmission grid and which are intended to address the current interconnection queue backlogs and delays. FERC proposes to mandate that transmission providers study interconnection requests in clusters, rather than the current inefficient serial study process used by many utilities, and to take a first step toward addressing the uncertainty caused by inconsistent procedures for neighboring “affected systems” to make a claim for the generator to pay for transmission upgrades on its system by creating a standardized process for affected system participation in the interconnection study process. But the proposal also could create new, unnecessary obstacles to interconnection, and it fails to address some significant barriers to interconnection such so-called participant funding rules under which interconnection customers can be saddled with the full cost of system expansions, ignoring the fact that other system users benefit from these expansions.

As the Federal Energy Regulatory Commission (FERC) considers changes to Order No. 860 requirements, it has now delayed the order’s effectiveness for three months to July 1, 2021, and in so doing, it has clarified its definition of “Affiliate” for market-based rate (MBR) purposes. 

In September 2020, the Federal Energy Regulatory Commission (FERC) reversed 40-year old precedent by revoking the qualifying facility (QF) status of the Broadview facility made up of a 160 MW solar array and a 50 MW battery storage resource, as well as inverters that convert the direct current (DC) electricity generated by the solar panels into alternating current (AC) electricity, which (after subtracting parasitic load) physically limit the capacity that can be delivered to the grid to 80 MW, ruling at that time that capacity must be measured based on the DC capabilities. Last week, FERC reversed that decision. With its reversal, FERC again will apply the 80 MW size limit for small power production qualifying facilities to the amount of power that can be delivered to the grid, allowing the QF to take output limitations into account, such as where inverters are necessary for the QF’s ability to convert DC power to AC power in order to put power onto the grid at the interconnection point. However, FERC’s order also finds that mechanical means of limiting output presents a special circumstance for demonstrating QF eligibility. As such, facilities self-certifying to QF status through FERC Form 556 should take care to fully justify such special circumstances. 

The Federal Energy Regulatory Commission’s (FERC) new rules under Order No. 860 take effect on April 1, 2021, and will change the way market-based rate (MBR) filings are made. FERC’s aim is to create a relational database to contain MBR seller information that ultimately will allow, among other things, for the automatic generation of an appendix of relevant affiliated assets and indicative market power screens. The first focus will be for each MBR seller to make a baseline submission to FERC’s MBR Portal between April 1 and August 2, 2021. 

Distributed energy resources (DER) are often too small on their own to meet participation requirements of the energy and capacity markets of Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs).  To encourage greater DER participation, FERC's Order No. 2222 requires that RTOs/ISOs allow DER to participate in RTO/ISO markets through an aggregator that would register as the market participant.  Importantly, Order No. 2222 turns the long-running debate over DER market participation from one of whether it should be done into one about how best to achieve it. 

Reversing its 40-year old precedent, the Federal Energy Regulatory Commission (FERC) revoked the qualifying facility (QF) status of a facility made up of a 160 MW solar array and a 50 MW battery storage resource, as well as inverters that convert the direct current (DC) electricity generated by the solar panels into alternating current (AC) electricity, which (after subtracting parasitic load) physically limit the capacity that can be delivered to the grid to 80 MW. FERC rejected prior precedent that applied the 80 MW size limit for small power production qualifying facilities to the amount of power that can be delivered to the grid and now finds that the size will be based on the rated capacity of the facility without regard to the fact that the output is limited such as when the inverters necessary for operation limit the facility’s output. 

The Federal Energy Regulatory Commission (“FERC”) issued Order No. 872, its much-anticipated decision adopting major revisions to its regulations implementing the Public Utility Regulatory Policies Act of 1978 (“PURPA”).  PURPA generally requires utilities to purchase power from certain renewable energy sources and cogeneration projects (“Qualifying Facilities” or “QFs”) at the utilities’ “avoided cost” in order to incent generation development using those fuel sources. 

The New England Ratepayers Association (NERA) petitioned the Federal Energy Regulatory Commission (FERC) last week to assert jurisdiction over net metering programs created by states which allow a customer to receive credits on its retail electricity bill for generation from rooftop solar or other behind-the-meter generation in excess of what the customer uses to meet its on-site needs. This would be a significant change in FERC’s policy, established in 2001, which holds that there is no FERC-jurisdictional sale as long as the customer’s load during the relevant billing period exceeds the amount of energy deliveries credited to the customer during that period (called the “netting” period). If FERC grants NERA’s petition, and reverses its decades long precedent, it will increase the tension between FERC and the states and potentially undermine not only state objectives to incentivize renewable generation, but also the economic basis that retail customers relied upon when installing their on-site generation because, as NERA posits, any resulting rate likely will be lower than the value of the credits currently awarded under state net metering programs.

The Federal Energy Regulatory Commission (FERC) announced various measures to ease burdens of regulated entities so that the energy industry can focus on continuity, safety, and stability during the COVID-19 pandemic.

In FERC v. Silkman, decided January 4, 2019, the U.S. District Court for the District of Maine held that the Federal Energy Regulatory Commission (FERC) has up to five years from the date of its enforcement order to impose civil penalties on violators of FERC’s anti-market manipulation rule. The court reached its determination by applying the federal statute of limitations (28 U.S.C. § 2462), which provides that “an action, suit, or proceeding for the enforcement of any civil fine, penalty, or forfeiture, pecuniary or otherwise, shall not be entertained unless commenced within five years from the date when the claim first accrued” (emphasis added).

The Federal Energy Regulatory Commission has issued a declaratory order, finding that tax equity interests in public utilities or public utility holding companies do not constitute “voting securities” for the purposes of Section 203 of the Federal Power Act (FPA), so long as the voting/consent/veto rights of such securities have the same characteristics as those identified in the Commission’s order in AES Creative Resources, L.P., 129 FERC ¶ 61,239 (2009).

In recent orders, the Federal Energy Regulatory Commission (FERC or “Commission”) addressed claims that some states and local utilities have not been complying with the Public Utility Regulatory Policies Act of 1978 (PURPA), and generally reinforced the Commission’s long-standing policies in a manner supportive of generation developers. But PURPA’s opponents have persistently made their case before FERC and Congress that PURPA must be amended or repealed. They argue that PURPA is obsolete, a vestige of the pre-competitive era, and that PURPA saddles ratepayers with the costs of unneeded, overpriced power. And with PURPA’s supporters largely remaining silent as the anti-PURPA coalition has made its case over the past few years, these calls for reform very likely could gain traction with the new Congress and administration.

Indianapolis Power & Light Company (IPL), the developer of the first grid-scale energy storage resource in the Midcontinent Independent System Operator (MISO) footprint, has filed a complaint with the Federal Energy Regulatory Commission (FERC) asserting that MISO’s market rules fail to compensate IPL for providing important reliability services, and that MISO’s operating protocols would significantly degrade the useful life of IPL’s storage resource.

On June 10, 2016, the IRS released Notice 2016-36, modifying the safe harbor rules for the tax treatment of contributions of property (including payments made) by an electric generation or storage facility to a regulated public utility in connection with the construction of new or upgraded transmission facilities. A contribution meeting the requirements of the safe harbor will not result in taxable income to the utility. Thus, the safe harbor reduces the amount that a generator or storage facility must pay when the utility constructs or upgrades transmission facilities (or accepts contributions of property for such purpose) to benefit the generator or storage facility. Absent the safe harbor, the generator or storage facility would also have had to reimburse the utility for any taxes it would have had to pay for the contributed property.

The Federal Energy Regulatory Commission (FERC) has issued a Notice of Proposed Rulemaking (NOPR) that would require entities participating in regional electricity markets (i.e., regional transmission organizations and independent system operators) to disclose detailed information about their ownership and contractual relationships, signaling FERC's intent to significantly expand the reach of its market manipulation enforcement oversight. Under the NOPR, companies selling or buying electricity at wholesale in FERC-regulated regional electricity markets, that currently operate in 36 states, would have to provide to the regional market operator information about their "Connected Entities." Connected Entities would include their owners and affiliates, management personnel and traders, lenders, and companies that provide management or operations services to the market participants. The NOPR would require each regional market operator to share this information with FERC.