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 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.
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
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.
The Federal Energy Regulatory Commission (the Commission) issued an order on Thursday, March 19, 2015, refusing to allow the abandonment of certificated working gas capacity when the reason for the request was unrelated to the physical characteristics of the storage facility and unsupported by engineering or geological data. The applicant had sought the abandonment authorization for the sole purpose of reducing its lease payments, which are largely based on the certificated working gas capacity of the facility.
The order, Tres Palacios Gas Storage LLC, 150 FERC ¶ 61,197 (2015), was issued following an application by Tres Palacios Gas Storage LLC (Tres Palacios) for authorization to abandon a significant amount of its certificated working gas storage capacity in a salt dome storage facility in Matagorda and Wharton Counties, Texas. Tres Palacios claimed that abandonment was justified because market conditions were such that it could not sell the capacity at rates that it considered acceptable.
In denying the application, the Commission ruled that Tres Palacios’s request was inconsistent with Commission policy, which requires specific facility parameters for each cavern, such as cushion gas capacity, working gas capacity and minimum pressures, and was inconsistent with Tres Palacios’s certificate authority, which authorizes specific parameters for each cavern. In addition, the Commission explained that no geological or engineering data was submitted to support the change. The order reaffirmed that certificated capacity is based on the physical attributes of a facility and that certificated working gas capacity is “unrelated to the amount of working gas capacity the storage company is able to sell.”
Karol Lyn Newman and Jessica Bayles represented the lessor, Underground Services Markham, LLC, in the proceeding before the Commission.
Commissioner Philip Moeller of the Federal Energy Regulatory Commission (FERC) held a public meeting on September 18, 2014 to discuss ideas to facilitate and improve the way in which natural gas is traded and to explore the concept of establishing a centralized natural gas trading platform. Although not an official FERC conference, the ideas at issue were an extension of FERC’s recent focus on gas-electric coordination. During the well-attended meeting, Commissioner Moeller presided over a large roundtable discussion of stakeholders, including electric generation owners, natural gas producers, pipelines and marketers, who engaged in a spirited discussion of whether natural gas supplies are meeting the needs of electric generators and improvement in supply practices. The central focus of the meeting was the creation of a natural gas information and trading platform containing bids and offers for the purchase and sale of commodity and capacity for receipt and delivery on points across multiple pipeline systems.
Participants agreed that the natural gas industry is evolving and an increasing share of natural gas is being supplied to electric generators—customers with different needs than the local distribution companies the natural gas pipeline industry was traditionally designed to serve. Most participants further agreed that the needs of generators do not always align with pipelines’ traditional services.
Natural gas-fired generation owners voiced concerns regarding unknown or unreasonable commercial terms in pipeline service agreements, a lack of transparency surrounding available services and illiquidity in the natural gas market. Pipeline representatives highlighted the availability of new services such as extra nomination cycles, no-notice service and the ability to reverse flow as examples of services intended to accommodate generators. Nevertheless, the pipeline representatives also made the point that natural gas liquidity is outside pipelines’ control as they do not have title to the gas they transport. Marketers and organized exchange representatives added that they have been responding to generators’ needs by making available bespoke products and exploring new standardized products to match generators’ demands.
In addressing possible solutions to transparency and liquidity problems, most meeting participants urged incremental change and expressed a preference for industry solutions over FERC’s regulatory intervention. Electric generators preferred increased use of non-ratable service, no-notice service and new, shaped products. Other proposals included eliminating the shipper-must-have-title rule, facilitating competition between capacity release and pipeline overrun services and encouraging generators to purchase firm transportation service rather than interruptible service.
FERC has established a docket number to allow interested parties to file written comments on any issue that was discussed at the meeting. Comments are limited to five pages and are due by October 1, 2014.
The D.C. Circuit Court of Appeals recently issued an opinion holding that the Federal Energy Regulatory Commission (FERC) violated the National Environmental Policy Act (NEPA) when it segmented its evaluation of the environmental impact of four separately proposed but connected projects to upgrade the “300 Line” on the Eastern Leg of Tennessee Gas Pipeline Company’s natural gas pipeline system. Going forward, the court’s ruling will likely compel proponents of interrelated or complimentary pipeline projects to seek their certification on a consolidated basis and will require FERC to evaluate their cumulative impact.
Tennessee Gas’s challenged Northeast Project was the third of four proposed upgrade projects to expand capacity on the existing Eastern Leg of the 300 Line. The Northeast Project added only 40 miles of pipeline, while the four proposed projects combined to add approximately 200 miles of looped pipeline. FERC approved Tennessee Gas’s first proposed upgrade, the “300 Line Project,” in May 2010. While that project was under construction, Tennessee Gas proposed three additional projects to fill gaps left by the 300 Line Project, one of which was the Northeast Project. As part of its review of the Northeast Project, FERC issued an Environmental Assessment (EA) required by NEPA that recommended a Finding of No Significant Impact. The EA for the Northeast Project, however, addressed only the Northeast Project’s environmental impact without reviewing the cumulative impact of all four projects.
The D.C. Circuit held that FERC was in error for failing to consider the cumulative impact. Under NEPA, the D.C. Circuit explained, FERC must consider all connected and cumulative actions. The D.C. Circuit found no “logical termini,” or rational endpoints to divide the four projects and found the projects were not financially independent. Rather, the court found the Northeast Project was “inextricably intertwined” with the other three improvement projects that, taken together, upgraded the entire Eastern Leg of the 300 Line. The court held that FERC must analyze the cumulative impact of the four projects and remanded the case to FERC for consideration.
The Court emphasized that in this case, “FERC was plainly aware of the physical, functional, and financial links between the two projects.” Regardless of whether an interstate pipeline initially plans to embark on a series of related upgrades, once FERC is aware of the interrelatedness of proposed expansion projects, it must take care to review any cumulative environmental impacts that may arise.
The D.C. Circuit’s decision may also be a warning that FERC must pay greater attention to the NEPA review in pipeline construction projects. The D.C. Circuit also has before it this term a case alleging that FERC did not sufficiently consider the environmental review of the siting of a new pipeline compressor station in light of less environmentally intrusive alternatives. See Minisink Residents for Environmental Preservation and Safety v. FERC, Case No. 12-1481. Both cases take issue with the rigor of FERC’s environmental review under NEPA, and the D.C. Circuit’s decisions may signal a new era of increased focus on the environmental review process.
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In three separate rehearing orders issued last Thursday, May 15, 2014, the Federal Energy Regulatory Commission reversed course on its decision in Order No. 1000 to prohibit references in transmission tariffs to state laws such as rights of first refusal (ROFR) to build transmission expansions. The Commission determined on further consideration that excluding such state and local laws from transmission tariffs could lead to inefficiencies and delays in the regional transmission planning process because regions would have to spend time and resources evaluating potential transmission developers that would ultimately be prohibited by state or local law from developing a transmission project. Commissioner Norris issued a statement opposing the Commission’s orders on the basis that they will exclude non-incumbents from participating in the regional transmission planning process, choking innovation and insulating incumbents from competition.
Order No. 1000 requires public utilities to participate in regional transmission planning and cost allocation planning for new transmission facilities. In order to allow competitive bidding of projects and developers, Order No. 1000 requires public utility transmission providers to remove provisions in Commission-jurisdictional tariffs that establish a federal ROFR for an incumbent transmission provider with respect to building transmission facilities selected in a regional transmission plan. Order No. 1000-A stated that it was not “intended to preempt or otherwise conflict with state authority over sitting, permitting, and construction of transmission facilities.” However, the order also stated that it “would be an impermissible barrier to entry to require, as part of the qualification criteria, that a transmission developer demonstrate that it either has, or can obtain, state approvals necessary . . . to be eligible to propose a transmission facility.”
On rehearing of compliance orders for the PJM Interconnection, Midcontinent Independent System Operator and South Carolina Electric & Gas Company, the Commission held that while it will continue to require the elimination of federal ROFRs, regional operators and utilities could recognize exclusionary state and local laws and regulations as a threshold issue in the regional transmission planning process. Specifically, the rehearing orders provided that tariffs could include state and local laws, giving incumbent utilities ROFRs and provisions excluding projects that alter the transmission providers’ use or control of rights-of-way. The Commission reasoned that ignoring these state or local laws or regulations at the outset of the regional transmission planning process would be counterproductive and inefficient, and could delay needed transmission facilities. In a dissenting statement, Commissioner Norris argued that this approach was irreconcilable with Order No. 1000 and condemns consumers to bear the burden of incumbents’ lack of innovation in developing transmission solutions and interest in preserving the status quo.