In response to the COVID-19 pandemic, U.S. energy regulators have adopted a variety of measures, including designating a single point point
of contact for all industry inquiries related to impacts of the Novel
Coronavirus on their activities jurisdictional to the Federal Energy Regulatory Commission, issuing a Policy Statement providing regulatory guidance on energy infrastructure, market, reliability and security matters, and providing other regulatory relief.
On March 19, 2020, the Federal Energy Regulatory Commission named Caroline Wozniak to lead a team of 14 technical staff from the Commission’s 12 program offices, as the Commission’s point of contact for all industry inquiries related to impacts of their COVID-19 preparations and responses on their FERC-jurisdictional activities.
On April 2, 2020, the Commission issued a Policy Statement providing regulatory guidance on energy infrastructure, market, reliability and security matters. Through the Policy Statement, the Commission noted that Commission-regulated entities have taken actions in response to the national emergency conditions that may disrupt,
complicate, or otherwise change their normal course of business
operations, which "may
create questions about entities’ ability to meet regulatory requirements
and/or recover the costs necessary to take steps to safeguard the
business continuity of their systems." The Policy Statement emphasizes that the Commission will prioritize its processing of filings made for the purpose of assuring the
reliable operation of energy infrastructure during this emergency, including requests for relief such as "cost recovery necessary to assure business continuity of
the regulated entities’ energy infrastructure in response to the
national emergency."
Separately, Commission Chair Neil Chatterjee issued a statement describing the Commission's efforts to help regulated entities manage their potential enforcement and compliance-related burdens during the COVID-19 pandemic. Announcing "that the Commission will
exercise appropriate prosecutorial discretion in addressing events that
arise during the emergency period", he noted that enforcement staff will take the current emergency into account when
evaluating compliance programs, as part of an audit for operations taking place during
the emergency, and in assessing
the timeliness of self-reports.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Showing posts with label Policy Statement. Show all posts
Showing posts with label Policy Statement. Show all posts
FERC disallows MLP pipelines' recovery of income tax allowance
Wednesday, March 21, 2018
U.S. energy regulators have revised their policies, and will no longer allow master limited partnership (MLP) interstate natural gas and oil pipelines to recover an income tax allowance in their cost-of-service rates. The Federal Energy Regulatory Commission issued its Revised Policy Statement on Treatment of Income Taxes following a 2016 federal court order addressing the topic.
At issue is the Commission's policy on how MLP pipelines may set their cost-based rates. As described by the Commission, an MLP is a partnership form in which units are traded on exchanges much like corporate stock. To be treated as an MLP for Federal income tax purposes, an MLP must receive at least 90 percent of its income from certain qualifying sources, including natural gas and oil transportation.
MLP pipelines are not corporations, but are pass-through entities. This means that MLPs are not taxed at the pipeline level; instead, for tax purposes, the partnership agreement allocates to each partner a share of the partnership’s taxable income, and each partner is personally responsible for paying income taxes on the partnership’s net taxable income.
From 2005 until a 2016 court ruling, the Commission's 2005 Income Tax Policy Statement allowed all partnership entities (including MLPs) to recover an income tax allowance for the partners' tax costs, much like a corporation receives an income tax allowance for its corporate income tax costs. Alongside this income tax policy, the Commission has used a discounted cash flow (DCF) methodology to determine the rate of return regulated entities need to attract capital.
In 2008, a pipeline MLP named SFPP, L.P. filed a cost-of-service rate increase to increase the rates for a line running between California and Arizona. Shippers protested the filed rates, including the interaction between (a) the Commission’s policy permitting an income tax allowance policy for partnership business forms (such as SFPP) and (b) the Commission’s DCF methodology used to determine a cost-of-service rate of return. The Commission eventually issued orders addressing issues in the case including the income tax allowance issue, which were challenged in court.
On appeal, in 2016 the United States Court of Appeals for the District of Columbia Circuit issued a decision known as United Airlines, Inc. v. FERC, 827 F.3d 122 (2016). In that case, the D.C. Circuit held that because both the partnership income tax allowance and the DCF ROE may include investors’ tax costs, permitting both may result in a double recovery, and remanded the case back to the Commission for further action.
This week, the Commission took that further action. It issued an order in the SFPP case denying that MLP an income tax allowance. More holistically, the Commission concurrently issued a Revised Policy Statement on Treatment of Income Taxes. In the revised policy statement, the Commission found that "an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology."
At issue is the Commission's policy on how MLP pipelines may set their cost-based rates. As described by the Commission, an MLP is a partnership form in which units are traded on exchanges much like corporate stock. To be treated as an MLP for Federal income tax purposes, an MLP must receive at least 90 percent of its income from certain qualifying sources, including natural gas and oil transportation.
MLP pipelines are not corporations, but are pass-through entities. This means that MLPs are not taxed at the pipeline level; instead, for tax purposes, the partnership agreement allocates to each partner a share of the partnership’s taxable income, and each partner is personally responsible for paying income taxes on the partnership’s net taxable income.
From 2005 until a 2016 court ruling, the Commission's 2005 Income Tax Policy Statement allowed all partnership entities (including MLPs) to recover an income tax allowance for the partners' tax costs, much like a corporation receives an income tax allowance for its corporate income tax costs. Alongside this income tax policy, the Commission has used a discounted cash flow (DCF) methodology to determine the rate of return regulated entities need to attract capital.
In 2008, a pipeline MLP named SFPP, L.P. filed a cost-of-service rate increase to increase the rates for a line running between California and Arizona. Shippers protested the filed rates, including the interaction between (a) the Commission’s policy permitting an income tax allowance policy for partnership business forms (such as SFPP) and (b) the Commission’s DCF methodology used to determine a cost-of-service rate of return. The Commission eventually issued orders addressing issues in the case including the income tax allowance issue, which were challenged in court.
On appeal, in 2016 the United States Court of Appeals for the District of Columbia Circuit issued a decision known as United Airlines, Inc. v. FERC, 827 F.3d 122 (2016). In that case, the D.C. Circuit held that because both the partnership income tax allowance and the DCF ROE may include investors’ tax costs, permitting both may result in a double recovery, and remanded the case back to the Commission for further action.
This week, the Commission took that further action. It issued an order in the SFPP case denying that MLP an income tax allowance. More holistically, the Commission concurrently issued a Revised Policy Statement on Treatment of Income Taxes. In the revised policy statement, the Commission found that "an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology."
FERC Order 841 and electric storage markets
Monday, February 19, 2018
U.S. energy regulators have issued a final rule designed to help electric storage resources participate in the capacity, energy and ancillary services markets operated by regional grid operators. The Federal Energy Regulatory Commission said its Order No. 841 would remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators.
Electricity storage technologies have been around for some time, and some technologies like pumped hydropower storage have been deployed on a significant scale -- but new electric technologies are developing on top of these traditional technologies. New England's regional grid operator recently cited fast-responding energy storage devices as among the new technologies entering its markets. Many states have recognized the opportunities created by storage, and are enacting incentives to support its development and integration into microgrids. At the same time, regulators are grappling with how to fit energy storage resources into existing markets and incentive programs, like retail net metering.
The Federal Energy Regulatory Commission has considered electric storage for some time, including stakeholder workshops, data requests, and technical conferences. The Commission expressed concerns that barriers to electric storage resources participation in organized wholesale markets could lead to unjust and unreasonable wholesale electricity rates. In November 2016, the Commission proposed a rule to facilitate electric storage resources' participation in organized wholesale markets. In January 2017, the Commission issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.
In issuing Order No. 841 on February 15, 2018, the Commission adopted a final rule requiring each RTO and ISO to revise its tariff to establish a "participation model" for electric storage resources. As envisioned by the Commission, these participation models will consist of market rules that facilitate electric storage resources' participation in organized wholesale markets, while recognizing storage resources' physical and operational characteristics.
The new rule provides that each RTO and ISO must adopt its own participation model for electric storage resources, within certain guidelines. First, the participation model must ensure that storage resources using it are eligible to provide all capacity, energy, and ancillary services they are technically capable of providing. Second, the participation model must ensure that participating storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, consistent with rules that govern the conditions under which a resource can set the wholesale price. Third, the participation model must account for the physical and operational characteristics of electric storage resources through bidding parameters or other means Fourth, it must a minimum size requirement for participation in the RTO and ISO markets that does not exceed 100 kW.
The rule also requires that the sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.
In an accompanying statement, Commissioner LaFleur described electric storage as "like a 'Swiss army knife' that can serve customers in multiple ways," including including providing energy, particularly in conjunction with variable renewable generation (example: Deepwater Wind has proposed offshore wind plus storage in response to the pending Massachusetts offshore wind solicitation) as well as providing frequency regulation and other ancillary services, and helping defer distribution and transmission needs. Commissioner Powelson noted its consistency with the Commission's "longstanding commitment to fostering innovation and competition by reducing and eliminating barriers to entry." Commissioner Glick said Order No. 841 "will facilitate the development of a class of technologies—ranging from batteries to pumped hydro—that has the potential to play a leading role in the transition to the electricity system of the future, but that has heretofore been hindered by market rules that were designed primarily to accommodate more conventional means of electric generation."
Once it takes effect, the final rule gives RTOs and ISOs 270 days to develop and file their proposed rule changes, and a year for their implementation.
Electricity storage technologies have been around for some time, and some technologies like pumped hydropower storage have been deployed on a significant scale -- but new electric technologies are developing on top of these traditional technologies. New England's regional grid operator recently cited fast-responding energy storage devices as among the new technologies entering its markets. Many states have recognized the opportunities created by storage, and are enacting incentives to support its development and integration into microgrids. At the same time, regulators are grappling with how to fit energy storage resources into existing markets and incentive programs, like retail net metering.
The Federal Energy Regulatory Commission has considered electric storage for some time, including stakeholder workshops, data requests, and technical conferences. The Commission expressed concerns that barriers to electric storage resources participation in organized wholesale markets could lead to unjust and unreasonable wholesale electricity rates. In November 2016, the Commission proposed a rule to facilitate electric storage resources' participation in organized wholesale markets. In January 2017, the Commission issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.
In issuing Order No. 841 on February 15, 2018, the Commission adopted a final rule requiring each RTO and ISO to revise its tariff to establish a "participation model" for electric storage resources. As envisioned by the Commission, these participation models will consist of market rules that facilitate electric storage resources' participation in organized wholesale markets, while recognizing storage resources' physical and operational characteristics.
The new rule provides that each RTO and ISO must adopt its own participation model for electric storage resources, within certain guidelines. First, the participation model must ensure that storage resources using it are eligible to provide all capacity, energy, and ancillary services they are technically capable of providing. Second, the participation model must ensure that participating storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, consistent with rules that govern the conditions under which a resource can set the wholesale price. Third, the participation model must account for the physical and operational characteristics of electric storage resources through bidding parameters or other means Fourth, it must a minimum size requirement for participation in the RTO and ISO markets that does not exceed 100 kW.
The rule also requires that the sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.
In an accompanying statement, Commissioner LaFleur described electric storage as "like a 'Swiss army knife' that can serve customers in multiple ways," including including providing energy, particularly in conjunction with variable renewable generation (example: Deepwater Wind has proposed offshore wind plus storage in response to the pending Massachusetts offshore wind solicitation) as well as providing frequency regulation and other ancillary services, and helping defer distribution and transmission needs. Commissioner Powelson noted its consistency with the Commission's "longstanding commitment to fostering innovation and competition by reducing and eliminating barriers to entry." Commissioner Glick said Order No. 841 "will facilitate the development of a class of technologies—ranging from batteries to pumped hydro—that has the potential to play a leading role in the transition to the electricity system of the future, but that has heretofore been hindered by market rules that were designed primarily to accommodate more conventional means of electric generation."
Once it takes effect, the final rule gives RTOs and ISOs 270 days to develop and file their proposed rule changes, and a year for their implementation.
FERC may change natural gas pipeline policy
Wednesday, January 3, 2018
U.S. energy regulators have signaled potential changes to a decades-old policy on the certification and pricing of new interstate natural gas pipelines.
The Federal Energy Regulatory Commission is charged by the Natural Gas Act with regulating the transmission and sale of natural gas for resale in interstate commerce, and approving the siting and abandonment of interstate natural gas pipelines and storage facilities.
In 1999, the Commission issued a Statement of Policy "to provide the industry with guidance as to how the Commission will evaluate proposals for certificating new construction." The FERC's 1999 policy statement came about at a time when the Commission faced both pressure "to authorize new pipeline capacity to meet an anticipated increase in the demand for natural gas" and "to act with caution to avoid unnecessary rights-of-way and the potential for overbuilding with the consequent effects on existing pipelines and their captive customers." In adopting the 1999 policy statement, the Commission said its publication was intended "to provide more certainty as to how the Commission will analyze certificate applications to balance these concerns."
But the Commission could soon change its policies. Last month, on December 21, 2017, Commission Chairman Kevin J. McIntyre issued a statement that the Commission will consider changes to the 1999 policy statement, "as part of a pledge he made during his Senate confirmation to take a fresh look at all aspects of the agency’s work."
According to that statement, while next steps will soon be announced and scheduled, "any review of this type would be thorough, and the Commission would invite the views of all stakeholders to ensure that FERC accurately and efficiently assesses the pipeline applications it receives."
The Federal Energy Regulatory Commission is charged by the Natural Gas Act with regulating the transmission and sale of natural gas for resale in interstate commerce, and approving the siting and abandonment of interstate natural gas pipelines and storage facilities.
In 1999, the Commission issued a Statement of Policy "to provide the industry with guidance as to how the Commission will evaluate proposals for certificating new construction." The FERC's 1999 policy statement came about at a time when the Commission faced both pressure "to authorize new pipeline capacity to meet an anticipated increase in the demand for natural gas" and "to act with caution to avoid unnecessary rights-of-way and the potential for overbuilding with the consequent effects on existing pipelines and their captive customers." In adopting the 1999 policy statement, the Commission said its publication was intended "to provide more certainty as to how the Commission will analyze certificate applications to balance these concerns."
But the Commission could soon change its policies. Last month, on December 21, 2017, Commission Chairman Kevin J. McIntyre issued a statement that the Commission will consider changes to the 1999 policy statement, "as part of a pledge he made during his Senate confirmation to take a fresh look at all aspects of the agency’s work."
According to that statement, while next steps will soon be announced and scheduled, "any review of this type would be thorough, and the Commission would invite the views of all stakeholders to ensure that FERC accurately and efficiently assesses the pipeline applications it receives."
NY energy storage bill would launch program
Monday, June 26, 2017
The New York legislature has unanimously passed a bill establishing an energy storage deployment program. The bill, S. 5190, aims to promote the installation of energy storage systems. The bill now awaits Governor Andrew Cuomo's signature, before it can take effect.
New York is in the midst of major shifts in its energy policy. Governor Cuomo's "Reforming the Energy Vision" or REV process aims to build a clean, more resilient, and affordable energy system for all New Yorkers. As part of that process, last year, the Public Service Commission adopted a Clean Energy Standard which requires 50% of New York’s electricity to be generated by renewable sources by 2030, and provides support for 3 nuclear power plants considered at risk of closing. Meanwhile, the state is also reforming the way energy service companies, or retail electric suppliers, market their services.
In adopting renewable energy procurement mandates as part of the Clean Energy Standard in 2016, the Commission also considered creating specific mandates for energy storage. As noted in the order adopting the Clean Energy Standard, "Storage is a critically important component of the energy system that is both distributed and increasingly reliant on intermittent resources. Unlike other resources, the load shifting and fast response capabilities of various forms of storage resources allow them to provide simultaneous value as an energy and reliability resource. Storage can also provide value to the distribution based retail and bulk power markets... In short, it is without question that modern markets must sufficiently and accurately value storage as a vehicle to design and optimize network planning and operations."
But in that order, the Commission concluded that "as a reliability support and system optimizing resource, storage is not properly characterized as a standalone renewable energy resource under the CES. That being said, if the various mechanisms that the Commission is pursuing to ensure storage takes it rightful place as a critical resource for the modern grid prove insufficient, this topic will be revisited."
S. 5190 would change New York's position, by requiring that the Commission establish 2030 targets for the installation of qualified energy storage systems. It defines a qualified system as technology using mechanical, chemical, or thermal processes to absorb, store, and dispatch energy generated from renewable resources or mechanical processes. The bill's official justification statement cites the increased use of intermittent renewable energy sources, such as solar and wind, in an effort to combat climate change, and the efficiency of using energy storage systems to solve issues relating to changes in how energy supply and demand align in time.
Three other states -- Massachusetts, California, and Oregon -- have adopted energy storage procurement policies, and the Federal Energy Regulatory Commission is exploring how electric storage resources can be integrated into wholesale and regulated markets.
New York is in the midst of major shifts in its energy policy. Governor Cuomo's "Reforming the Energy Vision" or REV process aims to build a clean, more resilient, and affordable energy system for all New Yorkers. As part of that process, last year, the Public Service Commission adopted a Clean Energy Standard which requires 50% of New York’s electricity to be generated by renewable sources by 2030, and provides support for 3 nuclear power plants considered at risk of closing. Meanwhile, the state is also reforming the way energy service companies, or retail electric suppliers, market their services.
In adopting renewable energy procurement mandates as part of the Clean Energy Standard in 2016, the Commission also considered creating specific mandates for energy storage. As noted in the order adopting the Clean Energy Standard, "Storage is a critically important component of the energy system that is both distributed and increasingly reliant on intermittent resources. Unlike other resources, the load shifting and fast response capabilities of various forms of storage resources allow them to provide simultaneous value as an energy and reliability resource. Storage can also provide value to the distribution based retail and bulk power markets... In short, it is without question that modern markets must sufficiently and accurately value storage as a vehicle to design and optimize network planning and operations."
But in that order, the Commission concluded that "as a reliability support and system optimizing resource, storage is not properly characterized as a standalone renewable energy resource under the CES. That being said, if the various mechanisms that the Commission is pursuing to ensure storage takes it rightful place as a critical resource for the modern grid prove insufficient, this topic will be revisited."
S. 5190 would change New York's position, by requiring that the Commission establish 2030 targets for the installation of qualified energy storage systems. It defines a qualified system as technology using mechanical, chemical, or thermal processes to absorb, store, and dispatch energy generated from renewable resources or mechanical processes. The bill's official justification statement cites the increased use of intermittent renewable energy sources, such as solar and wind, in an effort to combat climate change, and the efficiency of using energy storage systems to solve issues relating to changes in how energy supply and demand align in time.
Three other states -- Massachusetts, California, and Oregon -- have adopted energy storage procurement policies, and the Federal Energy Regulatory Commission is exploring how electric storage resources can be integrated into wholesale and regulated markets.
FERC electric storage policy statement
Monday, January 23, 2017
U.S. energy regulators have issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates. The Federal Energy Regulatory Commission's January 19, 2017 policy statement on storage provides insight into how the Commission views its role in regulating the rates at which energy storage would be compensated -- but was accompanied by a dissenting view expressed by Commissioner LaFleur. The result is a mix of both greater certainty and continued debate.
Electricity storage is a growing industry, both in terms of installed capacity and its capability to flexibly support the grid. Today's electric storage resources can both charge and discharge electricity to and from the grid. Moreover they can provide various services to multiple entities -- for example, consumers, grid operators, or transmission and distribution utilities -- and can switch nearly instantaneously between modes of operation or services provided. In these ways, electric storage resources share some functions of consumer load, generation, transmission, and distribution.
Some of these functions -- e.g. sales of electric energy at wholesale in an organized market -- may be compensated at market-based rates. But other functions of energy storage could be compensated at cost-based rates under federal law -- perhaps functioning as a transmission asset, compensated through transmission rates. Thus it's possible that a particular energy storage resource -- think a battery attached to the electric grid, perhaps sited at a factory or other consumer's location -- might be compensated for its operations under both cost-based and market-based rates.
This is a good thing, according to the Federal Energy Regulatory Commission. According to the January 19, 2017 policy statement, "Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers."
But previous proceedings before the Federal Energy Regulatory Commission have exposed some concerns about allowing electric storage resources to recover costs through both cost-based and market-based rates concurrently. As described by the Commission, these include "double recovery of costs to the detriment of cost-based ratepayers, potential for adverse competitive impacts in wholesale electric markets to the detriment of other competitors, and the need for independence of regional grid operators from market participants."
With respect to utilities subject to its jurisdiction, the Commission's recent policy statement, "Utilitzation of Electric Storage Resources for Multiple Services When Receiving Cost-Based Rate Recovery," provides guidance regarding these issues. It details possible approaches for avoiding double recovery of costs. The Commission notes that with regard to adverse market impacts, it "is not convinced there will be a detriment to other market competitors." The policy statement also offers guidance on how grid operators and electric storage owners or operators should interact, to ensure independence as required by Commission policy.
Commissioner LaFleur issued a dissenting opinion, while nevertheless calling storage "an important and promising resource that warrants Commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions." While expressing an openness "to potential structures that compensate storage providing transmission service at a cost-based rate while participating in the wholesale markets", she expressed concern "about the broad rationale for this approach put forth in the Policy Statement," which she called "both flawed in its conclusions and premature in its timing." In particular her dissent focused on what she described as "the Policy Statement’s sweeping conclusions about the potential impacts of multiple payment streams on pricing in wholesale electric markets" -- and whether it might have implications for resources other than storage that receive multiple payment streams. She also disagreed with the Commission's decision to issue the policy statement separate from its pending Notice of Proposed Rulemaking on the participation of electric storage in wholesale markets.
Both the majority policy statement and Commissioner LaFleur's dissent shed light on how the Commission approaches energy storage rate issues. Storage seems universally considered worth investigating or supporting, but disagreement remains within the Commission with respect to some aspects of how storage resources should be compensated (as well as procedural issues related to the Commission's consideration of these questions). Nevertheless the policy statement does provide guidance and clarification into how a majority of the Commission views the compensation of storage resources under both cost- and market-based rate structures -- while also framing future discussions over how storage resources will be integrated into markets.
Electricity storage is a growing industry, both in terms of installed capacity and its capability to flexibly support the grid. Today's electric storage resources can both charge and discharge electricity to and from the grid. Moreover they can provide various services to multiple entities -- for example, consumers, grid operators, or transmission and distribution utilities -- and can switch nearly instantaneously between modes of operation or services provided. In these ways, electric storage resources share some functions of consumer load, generation, transmission, and distribution.
Some of these functions -- e.g. sales of electric energy at wholesale in an organized market -- may be compensated at market-based rates. But other functions of energy storage could be compensated at cost-based rates under federal law -- perhaps functioning as a transmission asset, compensated through transmission rates. Thus it's possible that a particular energy storage resource -- think a battery attached to the electric grid, perhaps sited at a factory or other consumer's location -- might be compensated for its operations under both cost-based and market-based rates.
This is a good thing, according to the Federal Energy Regulatory Commission. According to the January 19, 2017 policy statement, "Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers."
But previous proceedings before the Federal Energy Regulatory Commission have exposed some concerns about allowing electric storage resources to recover costs through both cost-based and market-based rates concurrently. As described by the Commission, these include "double recovery of costs to the detriment of cost-based ratepayers, potential for adverse competitive impacts in wholesale electric markets to the detriment of other competitors, and the need for independence of regional grid operators from market participants."
With respect to utilities subject to its jurisdiction, the Commission's recent policy statement, "Utilitzation of Electric Storage Resources for Multiple Services When Receiving Cost-Based Rate Recovery," provides guidance regarding these issues. It details possible approaches for avoiding double recovery of costs. The Commission notes that with regard to adverse market impacts, it "is not convinced there will be a detriment to other market competitors." The policy statement also offers guidance on how grid operators and electric storage owners or operators should interact, to ensure independence as required by Commission policy.
Commissioner LaFleur issued a dissenting opinion, while nevertheless calling storage "an important and promising resource that warrants Commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions." While expressing an openness "to potential structures that compensate storage providing transmission service at a cost-based rate while participating in the wholesale markets", she expressed concern "about the broad rationale for this approach put forth in the Policy Statement," which she called "both flawed in its conclusions and premature in its timing." In particular her dissent focused on what she described as "the Policy Statement’s sweeping conclusions about the potential impacts of multiple payment streams on pricing in wholesale electric markets" -- and whether it might have implications for resources other than storage that receive multiple payment streams. She also disagreed with the Commission's decision to issue the policy statement separate from its pending Notice of Proposed Rulemaking on the participation of electric storage in wholesale markets.
Both the majority policy statement and Commissioner LaFleur's dissent shed light on how the Commission approaches energy storage rate issues. Storage seems universally considered worth investigating or supporting, but disagreement remains within the Commission with respect to some aspects of how storage resources should be compensated (as well as procedural issues related to the Commission's consideration of these questions). Nevertheless the policy statement does provide guidance and clarification into how a majority of the Commission views the compensation of storage resources under both cost- and market-based rate structures -- while also framing future discussions over how storage resources will be integrated into markets.
DesertLink transmission project wins rate incentives under Section 219
Tuesday, August 23, 2016
Federal energy regulators have granted a petition by the developer of a proposed electric transmission project in Nevada for certain transmission rate incentives available under federal law. On August 19, the Federal Energy Regulatory Commission ruled on DesertLink, LLC's petition for declaratory order, with respect to DesertLink's new Harry Allen to Eldorado 500 kV transmission project. The order grants DesertLink's requests for transmission rate incentives under section 219 of the Federal Power Act, and illustrates how those incentives operate.
DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation. CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects. The project is designed to have an in-service date of May 2020.
Rate incentives can be available to promote capital investments in certain transmission infrastructure. The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce. Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments. The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.
Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.” Order No. 679 established a rebuttable presumption that this standard is met if:
In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).
Last week, the Commission granted DesertLink's petition. First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.
Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink. The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project. On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs. Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies." The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.
The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates. As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA." In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment. Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.
DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation. CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects. The project is designed to have an in-service date of May 2020.
Rate incentives can be available to promote capital investments in certain transmission infrastructure. The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce. Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments. The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.
Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.” Order No. 679 established a rebuttable presumption that this standard is met if:
(1) the transmission project results from a fair and open regional planning process that considers and evaluates the project for reliability and/or congestion and is found to be acceptable to the Commission; or (2) a project has received construction approval from an appropriate state commission or state siting authority.Order No. 679 also requires an applicant to demonstrate that there is a nexus between the incentive being sought and the investment being made. The Commission clarified in Order No. 679-A that this "nexus test" is met when an applicant demonstrates, on a project-specific basis, that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant.”
In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).
Last week, the Commission granted DesertLink's petition. First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.
Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink. The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project. On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs. Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies." The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.
The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates. As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA." In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment. Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.
FERC to examine competitive transmission incentives
Wednesday, March 23, 2016
The Federal Energy Regulatory Commission has scheduled a Commissioner-led technical
conference for this summer to discuss issues related to competitive
transmission development processes. At issue will be the use of cost containment
provisions, the relationship of competitive transmission development to transmission
incentives, and other ratemaking issues.
As part of the Energy Policy Act of 2005, Congress added section 219 to the Federal Power Act. Section 219 directs the Commission to establish, by rule, incentive-based rate treatments to promote capital investment in certain transmission infrastructure. The Commission's Order No. 679 sets forth processes by which a public utility may seek transmission rate incentives pursuant to section 219. To qualify, an applicant must show that "the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion" and also demonstrate a nexus between the incentives being sought and the investment being made. Order No. 679-A clarified that this nexus test is satisfied when an applicant demonstrates that the total package of incentives requested is tailored to address the demonstrable risks or challenges faced by the applicant.
But a case decided earlier this year has led the Commission to reevaluate broader policy considerations relating to the role of cost containment proposals in competitive transmission development. In a January 8, 2016 order, NextEra Energy Transmission West, LLC, 154 FERC ¶ 61,009, the Commission partially rejected a request by a public utility transmission owner for certain transmission rate incentives pursuant to section 219 and Order No. 679. That case involved proposed transmission development under the California Independent System Operator Corporation (CAISO)'s competitive transmission developer selection process adopted to comply with Order No. 1000.
Most controversial in the "NEET West" case was a conditional adder to the utility's return on equity that would be triggered if the return on equity fell below the 10 percent that was the foundation for the utility's competitive bids for transmission project development. On the specific facts and circumstances of that case, the Commission found that the utility had not provided adequate support for the "conditional ROE incentive" and therefore denied it.
But in ruling on the NEET West case, the Commission noted that "this case highlights broader policy considerations related to the potential benefits of cost containment proposals in the context of competitive transmission development." In the NEET West order, the Commission signaled its intent to convene a technical conference in the future to explore further such issues, including how they relate to a 2012 Policy Statement issued by the Commission providing additional guidance regarding its evaluation of applications for transmission rate incentives under section 219 of the Federal Power Act and Order No. 679.
The first specific issue identified in the NEET West order involves the relationship between an expectation stated in the Policy Statement and risks associated with cost containment proposals. The Policy Statement requires an applicant seeking an incentive ROE to demonstrate that the proposed project faces risks and challenges that are not either already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives. The Commission expressed interest in exploring more broadly "why cost containment-related risks would not be accounted for in a base ROE level below 10 percent and yet would be accounted for in a base ROE of 10 percent" as NEET West argued.
The second specific issue involves "whether and how risks voluntarily assumed through submittal of a cost containment proposal relate to the second expectation set forth in the Policy Statement." The Commission expects an applicant seeking an ROE incentive based on a project’s risks and challenges to demonstrate that it is taking appropriate steps and using appropriate mechanisms to minimize its risks during project development. But it noted that NEET West "voluntarily submitted cost caps to make its bids to CAISO more attractive, which exposes NEET West’s shareholders to risks they would not have faced absent the cost caps." The Commission expressed intent to explore "whether and how voluntarily assuming this type of risk is consistent with minimization of risk envisioned by the Policy Statement."
On March 17, the Commission denied a request by ITC Grid Development for a declaratory order on whether cost-capped bids that won a competitive transmission project selection process should automatically be considered just and reasonable. But that same day, the Commission issued a Notice of Technical Conference in Docket No. AD16-18-000. In a footnote, the notice states that topics to be discussed include, but are not limited to, those that the Commission described in its NEET West order.
The technical conference to explore these and related issues has now been scheduled for June 27 and 28, 2016, at the Commission ’s headquarters at 888 First Street, NE, Washington, DC 20426.
As part of the Energy Policy Act of 2005, Congress added section 219 to the Federal Power Act. Section 219 directs the Commission to establish, by rule, incentive-based rate treatments to promote capital investment in certain transmission infrastructure. The Commission's Order No. 679 sets forth processes by which a public utility may seek transmission rate incentives pursuant to section 219. To qualify, an applicant must show that "the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion" and also demonstrate a nexus between the incentives being sought and the investment being made. Order No. 679-A clarified that this nexus test is satisfied when an applicant demonstrates that the total package of incentives requested is tailored to address the demonstrable risks or challenges faced by the applicant.
But a case decided earlier this year has led the Commission to reevaluate broader policy considerations relating to the role of cost containment proposals in competitive transmission development. In a January 8, 2016 order, NextEra Energy Transmission West, LLC, 154 FERC ¶ 61,009, the Commission partially rejected a request by a public utility transmission owner for certain transmission rate incentives pursuant to section 219 and Order No. 679. That case involved proposed transmission development under the California Independent System Operator Corporation (CAISO)'s competitive transmission developer selection process adopted to comply with Order No. 1000.
Most controversial in the "NEET West" case was a conditional adder to the utility's return on equity that would be triggered if the return on equity fell below the 10 percent that was the foundation for the utility's competitive bids for transmission project development. On the specific facts and circumstances of that case, the Commission found that the utility had not provided adequate support for the "conditional ROE incentive" and therefore denied it.
But in ruling on the NEET West case, the Commission noted that "this case highlights broader policy considerations related to the potential benefits of cost containment proposals in the context of competitive transmission development." In the NEET West order, the Commission signaled its intent to convene a technical conference in the future to explore further such issues, including how they relate to a 2012 Policy Statement issued by the Commission providing additional guidance regarding its evaluation of applications for transmission rate incentives under section 219 of the Federal Power Act and Order No. 679.
The first specific issue identified in the NEET West order involves the relationship between an expectation stated in the Policy Statement and risks associated with cost containment proposals. The Policy Statement requires an applicant seeking an incentive ROE to demonstrate that the proposed project faces risks and challenges that are not either already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives. The Commission expressed interest in exploring more broadly "why cost containment-related risks would not be accounted for in a base ROE level below 10 percent and yet would be accounted for in a base ROE of 10 percent" as NEET West argued.
The second specific issue involves "whether and how risks voluntarily assumed through submittal of a cost containment proposal relate to the second expectation set forth in the Policy Statement." The Commission expects an applicant seeking an ROE incentive based on a project’s risks and challenges to demonstrate that it is taking appropriate steps and using appropriate mechanisms to minimize its risks during project development. But it noted that NEET West "voluntarily submitted cost caps to make its bids to CAISO more attractive, which exposes NEET West’s shareholders to risks they would not have faced absent the cost caps." The Commission expressed intent to explore "whether and how voluntarily assuming this type of risk is consistent with minimization of risk envisioned by the Policy Statement."
On March 17, the Commission denied a request by ITC Grid Development for a declaratory order on whether cost-capped bids that won a competitive transmission project selection process should automatically be considered just and reasonable. But that same day, the Commission issued a Notice of Technical Conference in Docket No. AD16-18-000. In a footnote, the notice states that topics to be discussed include, but are not limited to, those that the Commission described in its NEET West order.
The technical conference to explore these and related issues has now been scheduled for June 27 and 28, 2016, at the Commission ’s headquarters at 888 First Street, NE, Washington, DC 20426.
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