FERC announced actions in response to the 2017 tax reform legislation and a revised income tax policy, which eliminates the income tax allowance for Master Limited Partnerships. Regulated entities should ensure that they comply with FERC’s orders regarding the treatment of income taxes and consider whether to file comments on the proposed rulemaking and notice of inquiry.
On February 15, the Federal Energy Regulatory Commission (FERC) issued a much-anticipated order designed to remove barriers to electric storage resource participation in organized wholesale electricity markets. The order—dubbed Order No. 841—creates new rules that require each regional transmission operator (RTO) and independent system operator (ISO) to revise its tariff to establish a “participation model” consisting of market rules that facilitate the participation of electric storage resources in the RTO/ISO markets. Order No. 841 will make it easier for electric storage resources to participate in wholesale power markets and access the accompanying revenue streams.
Each RTO/ISO must file its tariff changes to implement Order No. 841 within 270 days (i.e., by November 12, 2018). FERC will review the filings and must approve all tariff changes. Each RTO/ISO will have an additional one year from the filing date to implement its new tariff provisions.
FERC defined an electric storage resource as “a resource capable of receiving electric energy from the grid and storing it for later injection of the electric energy back to the grid.” This definition encompasses a variety of technologies including batteries, flywheels, compressed air and pumped hydro. It also explicitly includes resources located on a distribution system or behind the meter, as well as resources located on the interstate transmission grid, and opens the door to participation in RTO/ISO markets for smaller storage resources.
On January 8, 2018, the Federal Energy Regulatory Commission (FERC) rejected the Department of Energy’s (DOE) Proposed Rule, which would have required organized wholesale electricity markets run by independent system operators (ISOs) or regional transmission organizations (RTOs) to establish tariff mechanisms for purchasing energy from eligible “reliability and resilience resources” and mandated a recovery of costs plus a return on equity for such resources. Eligible reliability and resilience resources would have to be (1) located within an RTO/ISO, (2) able to provide essential reliability services, and (3) have a 90-day fuel supply on-site. Practically, these requirements would limit participation to coal and nuclear plants. Continue Reading FERC Rejects Department of Energy Proposal Benefitting Coal and Nuclear
On September 28, 2017, the US Department of Energy (DOE) submitted a proposed rule to the Federal Energy Regulatory Commission (FERC) that, if implemented, could reshape organized wholesale electricity markets. Citing electric grid reliability and resiliency issues like the 2014 Polar Vortex and recent hurricanes, DOE asked FERC to enact a new compensation system for coal and nuclear power plants—dubbed “fuel-secure resources” by DOE. Coal and nuclear plants have been retiring prematurely and, according to DOE, the retirements are “threatening the resilience of the Nation’s electricity system.”
In order to stem the tide of retirements, DOE submitted to FERC a proposed rule requiring organized wholesale electricity markets run by independent system operators (ISOs) or regional transmission organizations (RTOs) to develop and implement market rules that “accurately price generation resources necessary to maintain the reliability and resiliency” of the bulk power system. The proposed rule would require ISOs and RTOs to provide “a just and reasonable rate” for the purchase of electricity from a fuel-secure resource and “recovery of costs and a return on equity for such resource.” Eligible resources must (i) be located within an ISO or RTO, (ii) be able to provide energy and ancillary services, (iii) have a 90-day fuel supply on site, (iv) be compliant with all environmental laws, and (v) not be subject to cost-of-service rate regulation at the state or local level. Practically, these requirements limit participation to coal and nuclear plants. Continue Reading Department of Energy Proposes Rule Benefiting Coal and Nuclear to FERC
Last week, the Federal Energy Regulatory Commission (FERC) issued a Policy Statement to provide guidance on the ability of electric storage resources to recover costs through both cost-based and market-based rates concurrently. The Policy Statement appears intended to reconcile two lines of FERC precedent on this topic. The issue of multiple payment streams is one of particular concern for electric storage resources that, due to their technological capabilities, can switch from one type of service to another almost instantaneously. The Policy Statement is separate from FERC’s ongoing Notice of Proposed Rulemaking regarding electric storage resource participation in wholesale electricity markets (RTO/ISO markets), discussed here and here.
FERC’s guidance stems from two orders with opposite outcomes – Nevada Hydro and Western Grid. In the 2008 Nevada Hydro order, FERC denied a hydroelectric storage project’s petition to be treated as a transmission facility that would receive payments through cost-based rates. Then, in the 2010 Western Grid order, FERC granted the applicant’s request for cost-based rate recovery for its sodium sulfur batteries that would provide voltage support and thermal overload protection for transmission facilities.
FERC identified three major concerns present in scenarios where an electric storage resource seeks both cost-based and market-based rates: (1) the potential for cost-based and market-based rate recovery to result in double recovery; (2) the potential for cost-based rates to inappropriately suppress competitive market prices; and (3) the level of control of a storage resource exercised by a RTO/ISO that could jeopardize the RTO/ISO’s independence from market participants.
To address the concern of double recovery, FERC suggested that crediting any market revenues back to the cost-based ratepayers is a possible solution. Such crediting may vary depending on how the cost-based rate is structured; FERC provided examples of an up-front reduction in the cost-based rate or a later crediting procedure for cost-based ratepayers. Addressing the issue of suppressing competitive market prices, FERC disagreed with commenters that allowing market participants with cost-based rate recovery to also sell at market-based rates would create an adverse impact on other market competitors. FERC pointed out that some vertically integrated public utilities currently recover costs through cost-based retail rates while also making market-based rate sales to others. Finally, to maintain RTO/ISO independence, FERC clarified that RTO/ISO dispatch of a storage resource should receive priority over the resource’s provision of market-based rate services and that the provision of market-based rate services should be under the control of the resource owner rather than the RTO/ISO.
FERC Commissioner LaFleur dissented from the Policy Statement, arguing that its sweeping conclusions related to storage resources may be read to reflect FERC’s views about the impact of multiple payment streams more generally. Commissioner LaFleur also disagreed with FERC’s decision to separate the issues from FERC’s pending Notice of Proposed Rulemaking on storage participation.
As this blog previously reported here, the Federal Energy Regulatory Commission (FERC) issued a notice of proposed rulemaking (NOPR) last month with the goal of requiring organized wholesale electricity markets (RTO/ISO markets) to modify their tariffs and rules to accommodate electric storage resources. FERC has received several comments and recently agreed to extend the deadline for filing comments until February 13, 2017.
On November 17, 2016, the Federal Energy Regulatory Commission (FERC) issued a notice of proposed rulemaking (NOPR) that, if adopted, would require organized wholesale electricity markets (RTO/ISO markets) to modify their open access transmission tariffs and market rules to accommodate electric storage resources and allow participation of distributed energy resource aggregators. This NOPR is part of FERC’s ongoing efforts to remove barriers to participation in wholesale electric markets. FERC recognizes that electric storage resources and distributed energy resources are often constrained by antiquated wholesale market rules that were, as FERC puts it, “developed in an era when traditional generation resources were the only resources participating in the organized wholesale electricity markets.” This NOPR will promote far greater market participation by storage resources of all types, including batteries, flywheels, compressed air and pumped hydro, as well as distributed resources such as distributed generation, electric storage, thermal storage and electric vehicles.
For electric storage resources, which are defined as resources capable of receiving electric energy from the grid and storing it for later injection of electricity back to the grid, the NOPR would require each RTO/ISO to implement tariff provisions that will:
- Ensure an electric storage resource is eligible to provide services it is technically capable of providing
- Incorporate bidding parameters that reflect the physical and operational characteristics of the resources
- Ensure that electric storage resources can set the market clearing price as a seller or buyer
- Establish a minimum size requirement that does not exceed 100 kW
- Specify that sales and purchases must be made at the wholesale locational marginal price
The provision contained in incumbent electric utility tariffs—conferring on the holder the right of first refusal (ROFR) to construct additions to the high-voltage electrical grid, regardless of who conceived of and proposed the addition—is unduly discriminatory, the U.S. Circuit Court of Appeals for the D.C. Circuit held in a July 1 decision in Oklahoma Gas & Electric Co. v. FERC, No. 14-1281. The court’s decision upheld utility-specific applications of the FERC mandate—a central open-access innovation of the agency’s Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities)—that directed independent system operators and regional transmission organizations (ISO/RTO) to remove from their existing tariffs and membership agreements the ROFR provision (Removal Mandate).
Earlier in South Carolina Public Service Authority v. FERC, 762 F.3d 41 (D.C. Cir. 2014), the same court generally had upheld the Removal Mandate as applied to ISO/RTOs but had reserved judgment on whether the 60-year-old Mobile-Sierra presumption that the rates in negotiated arm’s length natural gas and power sales agreements are just and reasonable applied to the ROFR provisions of the ISO/RTO tariffs and membership agreements. In Sierra, the Supreme Court of the United States held that the presumption applies against not only the parties to a negotiated agreement but against FERC itself; thus, if it were found to apply to the ROFR, FERC could overcome the presumption only by showing that the ROFR seriously harmed the public interest.
The court could have resolved ISO/RTO and incumbent utilities’ challenges to the Removal Mandate in either of two ways. First, it could have determined that the context in which the ROFR provision was included in the tariffs and membership agreements prevented the presumption from applying in the first instance because of infirmities or unfair dealings in contract formation, such as fraud or duress. Second, it could determine that the presumption did apply and then address the question of whether FERC had overcome the presumption with evidence that the ROFR in member agreements seriously harmed the public interest. The court took the former course. It ruled that the Mobile-Sierra presumption never applied in the first instance because (quoting Order No. 1000 and citing South Carolina), the ROFR “created ‘a pre-existing [i.e., not negotiated] barrier to entry’ for nonincumbent transmission owners.” Citing precedent from the Seventh Circuit, the court found that “such terms” as the ROFR are “self-protective and anti-competitive [and] cartel-like.”
By cabining its holding to the anticompetitive effects of the ROFR, the court was able to bypass two other and possibly more complicated issues. First, it bypassed the issue of whether the Mobile-Sierra presumption applies not only to the rates in regulated natural gas and power sales agreements, but also to agreement terms that affect rates. As the court noted, both the petitioners and FERC argued the case based “on the premise” that the presumption applies to both to rates and agreements terms that affect rates. Second and possibly more nettlesome is whether the Mobile-Sierra presumption would protect other provisions of ISO/RTO tariffs even though (quoting the court) “[t]ariffs are the mechanism through which regulated utilities unilaterally set their rates and terms of service,” whereas Mobile-Sierra protects contracts negotiated bilaterally between sophisticated parties at arm’s length. The court held open resolution of this issue for future unilateral challenges to other ISO/RTO tariff or member agreements.
Last week the Commodity Futures Trading Commission (CFTC) issued a notice of proposed order and request for comment proposing to allow a private right of action to enforce violations of the anti-manipulation, anti-fraud or scienter based provisions (Anti-fraud provisions) of the Commodity Exchange Act (CEA) in organized electricity markets. The proposal is a controversial reversal of policy that critics say could open electricity market participants to increased costs and liability. Continue Reading CFTC Proposes Reversing Course, Granting Private Right of Action in Energy Market Manipulation
In the wake of two recent D.C. Circuit decisions, the Federal Energy Regulatory Commission (FERC) has begun to implement its new policy concerning the review of natural gas pipeline construction proposals under the National Environmental Policy Act (NEPA). To decide whether a NEPA review must include other projects proposed by the pipeline, FERC will look at the timing and maturity of other proposals and the independence of the projects.
In the first decision, Delaware Riverkeeper Network, the U.S. Court of Appeals for the D.C. Circuit held that FERC failed to consider the cumulative environmental impact of four projects that had been separately proposed by the same pipeline. The D.C. Circuit held that the projects were not financially independent and were “a single pipeline” that was “linear and physically interdependent,” so the cumulative environmental impacts must be considered concurrently.
In the second decision, Minisink Residents for Environmental Preservation and Safety, the D.C. Circuit held that FERC had properly considered and rejected an alternative site to build a natural gas pipeline compressor station. Contrasting the decision to Delaware Riverkeeper, the court clarified that the “critical” factor in the previous decision was that all of the pipeline’s projects were either under construction or pending before FERC for environmental review at the same time.
In several recent orders, FERC has implemented the D.C. Circuit’s guidance in addressing claims of improper segmentation. For example, FERC recently authorized Transcontinental Gas Pipe Line Company (Transco) to construct and operate the Leidy Southeast Project. The Leidy Southeast Project will include nearly 30 miles of new pipeline loop and four compressor stations to provide capacity from supply areas in Pennsylvania to various receipt points as far south as Choctaw County, Alabama. Opponents of the pipeline project (coincidentally Delaware Riverkeeper Network) claimed that FERC should have also considered in its NEPA review three other Transco projects—one already constructed and two proposed projects.
FERC rejected opponents’ request to conduct a joint NEPA review. FERC emphasized that (1) the first Transco project was approved nearly a year before Transco proposed the Leidy Southeast Project; (2) the other two Transco projects “were not fully defined ‘proposals’ at any time during the period that the Leidy Southeast Project was receiving consideration;” and (3) the Leidy Southeast Project was not “connected” to the other Transco projects, as it did not “rely on” other projects for its operation and “would have been built even if” the first project had not been constructed.