FERC approves energy storage tariffs

U.S. utility regulators have approved the first two regional implementations of a landmark 2018 order designed to remove barriers to the participation of electricity storage in wholesale markets.

In 2018, the Federal Energy Regulatory Commission issued its Order No. 841, requiring each organized power market to revise its tariff to establish a "participation model" for electric storage resources in the capacity, energy and ancillary service markets. The rule requires each market's participation model to include market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets. The Commission later affirmed the rule, through its Order No. 841-A.

Last week, the Commission issued two orders approving Order No. 841 compliance filings by Southwest Power Pool, Inc. and by PJM Interconnection. The Commission generally found that the SPP and PJM tariff revisions complied with the new rule, and largely accepted their filings. For example, the Commission found that both proposals "generally enable electric storage resources to provide all services they are capable of providing; allow electric storage resources to be compensated for those services in the same manner as other resources; and appropriately recognize the unique physical and operational characteristics of electric storage resources."

However, the Commission also provided directives for further compliance filings by SPP and PJM to be made within 60 days. The Commission found that while both filed tariffs generally satisfy Order No. 841’s directive allowing electric storage resources to de-rate their capacity to meet minimum run-time requirements, neither tariff included minimum run-time requirements for resource adequacy and capacity, respectively. Because "such requirements affect rates, terms and conditions of service," the Commission initiated proceedings under section 206 of the Federal Power Act to address the specific issue of minimum run-time requirements.

In a pair of separate statements (on SPP and on PJM), Commissioner McNamee concurred with the orders insofar as they found compliance with the Commission's orders and regulations. But Commissioner McNamee said, "I write separately, however, to express my continuing concern that the Commission exceeded its statutory authority under the Federal Power Act, and should have, at the very least, provided states the opportunity to opt-out of the participation model created by the Storage Orders." Commissioner McNamee also reiterated jurisdictional concerns he had previously raised in a partial concurrence to and partial dissent from Order No. 841-A, "to the extent the Commission’s Storage Orders exercised authority over the distribution system and behind-the-meter."

Other organized wholesale market operators, such as ISO New England, Inc., are also adopting tariff revisions to comply with Order No. 841, to enhance the ability of electric storage facilities to participate in regional wholesale electricity markets.

FERC Order 848, cyber security and reliability

U.S. energy regulators have issued an order directing the nation's electric reliability organization to strengthen its standards for the mandatory reporting of cyber security incidents.

Federal law authorizes the Federal Energy Regulatory Commission to regulate significant aspects of the bulk electric system's reliability. The Commission's jurisdiction over reliability covers the nation's electric reliability organization, North American Electric Reliability Corporation (NERC), which is charged with developing and submitting mandatory reliability standards for the Commission for approval.

Following increased concern over cybersecurity and hacking affecting utilities, in 2017 the Commission issued a Notice of Proposed Rulemaking proposing to direct that NERC develop enhanced Cyber Security Incident reporting requirements. At that time, then-current reliability standards generally required responsible entities to report Cyber Security Incidents only if they have “compromised or disrupted one or more reliability tasks. But the Commission expressed a concern that this reporting threshold "may understate the true scope of cyber-related threats facing the Bulk-Power System, particularly given the lack of any reportable incidents in 2015 and 2016." As a result, the Commission proposed requiring NERC to develop and submit modifications to its reliability standards, to require the reporting of cyber security incidents that compromise, or attempt to compromise, certain security infrastructure.

On July 19, 2018, the Federal Energy Regulatory Commission issued its Order No. 848. Through that order, the Commission adopted its own proposal to "improve awareness of existing and future cyber security threats and potential vulnerabilities." As described by the Commission, Order No. 848's directive consists of four elements:

1. responsible entities must report Cyber Security Incidents that compromise, or attempt to compromise, a responsible entity’s Electronic Security Perimeter (ESP) or associated Electronic Access Control or Monitoring Systems (EACMS);
2. required information in Cyber Security Incident reports should include certain minimum information to improve the quality of reporting and allow for ease of comparison by ensuring that each report includes specified fields of information;
3. filing deadlines for Cyber Security Incident reports should be established once a compromise or disruption to reliable BES operation, or an attempted compromise or disruption, is identified by a responsible entity; and
4. Cyber Security Incident reports should continue to be sent to the Electricity Information Sharing and Analysis Center (E-ISAC), rather than the Commission, but the reports should also be sent to the Department of Homeland Security (DHS) Industrial Control Systems Cyber Emergency Response Team (ICS-CERT). Further, NERC must file an annual, public, and anonymized summary of the reports with the Commission.

The Commission directed NERC to submit these modifications to its reliability standards within six months of Order No. 848's effective date.

FERC Order 842 requires primary frequency response by generators

U.S. energy regulators have issued an order amending standard interconnection agreements to require new generators to install, maintain and operate a functioning governor or equivalent controls capable of primary frequency response as a precondition of interconnection. The Federal Energy Regulatory Commission's Order No. 842 also amended the pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions.

As described by the Commission, reliable operation of an alternating current grid requires maintaining system frequency within predetermined boundaries above and below 60 Hertz. Frequency response describes an interconnected grid’s ability to arrest and stabilize deviations from this predetermined range of frequencies after a sudden loss of generation or load.

Historically, the U.S. grid's primary frequency response capability came from baseload synchronous generators such as coal-fired power plants. But many such plants have retired in recent years, with further retirements expected. In 2016, the Commission noted that shifts in the portfolio of U.S. electric generators meant fewer resources could likely provide primary frequency response, especially if new variable energy resources such as wind and solar did not provide this service. In response, it opened an inquiry into what primary frequency response reforms it should make.

On February 15, 2018, the Commission issued its Order No. 842 revising its regulations to require newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. The final rule also amends the Commission's pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions. It provides exemptions for nuclear power plants and some combined heat-and-power plants.

These requirements will apply to most newly interconnecting generation facilities that execute, or request the unexecuted filing of, an LGIA or SGIA on or after the rule’s effective date, as well as to existing large and small generating facilities that take any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date.

In a press release, the Commission said its action was intended to address "the increasing impact of the evolving generation resource mix." Commissioner LaFleur made a separate statement in which she noted that while decreases in the nation's portfolio percentage of synchronous generation have contributed to declining frequency response performance, "recent technological advancements have enabled new non-synchronous generating facilities, such as wind and solar, to cost-effectively include primary frequency response capabilities in their facilities." Improved inverters and battery storage are among these innovations.

The Commission has also recently noted the potential of electric storage resources to provide frequency response and other services. Its Order No. 841 is designed to remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators, including markets for frequency response.

FERC Order 841 and electric storage markets

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.

Energy dept adopts grid emergency order rule

U.S. energy regulators have issued a final rule governing the procedures through which the Secretary of Energy may issue an emergency order under the Federal Power Act to respond to an electric grid security emergency.

Under the Fixing America's Surface Transportation Act of 2015, Congress authorized the Secretary of Energy to order emergency measures after the President declares a grid security emergency. Such an emergency could occur as the result of a physical attack, a cyber-attack using electronic communication, an electromagnetic pulse (EMP), or a geomagnetic storm event. The FAST Act added these powers to the Federal Power Act, which contained additional language authorizing the Secretary to order temporary emergency measures as needed to serve the public interest.

On January 10, the U.S. Department of Energy published its final rule governing grid security emergency orders.  According to the Department, the procedures established by this final rule "will ensure the expeditious issuance of emergency orders under the Federal Power Act." It says the final rule establishes a "consistent yet flexible set of procedures" for regulatory engagement with impacted parties as the Department issues emergency orders. The Department says it "expects that these emergency orders would be issued rarely," but emphasized its need for flexibility in tailoring a response to the particular circumstances of any grid disruption.

The new final rule is codified in 18 C.F.R. section 205.380 et seq.

FERC issues license for Monongahela Locks and Dam 4 project

U.S. hydropower regulators have issued an original license for a proposed 12-megawatt hydropower project, to be located at the U.S. Army Corps of Engineers’ Monongahela Locks and Dam 4 facility on the Monongahela River, in Pennsylvania.

On February 27, 2014, FFP New Hydro, LLC subsidiary Solia 4 Hydroelectric, LLC filed, pursuant to Part I of the Federal Power Act, an application for a license to construct, operate, and maintain the Monongahela Locks and Dam 4 Hydroelectric Project No. 13767.  The company is affiliated with US Renewables Group.

The project would be located at one of the nine existing lock and dam sites on the Monongahela River, which the Army Corps operates for commercial and recreational navigation.  If developed, new facilities for the project would include an intake channel, spill gates, a powerhouse housing two equally sized Kaplan turbine-generator units with a combined capacity of 12 MW, a tailrace channel, a substation, a transmission line, and an access road.  The project will operate in a run-of-release mode, using flows made available by the Corps that would normally be released through the Corps’ spillway gates

Under the Federal Power Act, the Federal Energy Regulatory Commission is charged with regulating and reviewing applications for most non-federal hydropower projects.  Because the project uses the water power or surplus water of a government dam, occupies federal land, and is located on the Monongahela River, which is a navigable waterway of the United States, the Commission concluded that the project is required to be licensed pursuant to section 23(b)(1) of the Federal Power Act.

On July 21, 2017, the Commission issued its Order Issuing Original License for the Monongahela Locks and Dam 4 project.  The license authorizes the installation of 12 MW of new, renewable energy capacity, while requiring a number of measures to protect water quality, fish, wildlife, recreation, and cultural resources at the project.  It bears a 50-year term, the maximum allowable for an original license under Section 6 of the Federal Power Act.

According to the order, as licensed with mandatory conditions and staff-recommended measures, the levelized annual cost of constructing and operating the project will be about $3,563,340, or $72.88/MWh.  Its expected average annual generation will be 48,894 MW. 

The Commission noted that the project as licensed is best adapted to a comprehensive plan for improving or developing the Monongahela River, "because: (1) issuance of an original license will serve to provide a beneficial and dependable source of electric energy; (2) the required environmental measures will protect and enhance fish and wildlife resources, water quality, recreation resources, and historic properties; and (3) the 12 MW of electric capacity will come from a renewable resource that does not contribute to atmospheric pollution."

NH regulation of solar PPAs, leases

As distributed energy resources like solar panels become more widely adopted, how do typical solar business models like solar power purchase agreements or solar leases match up to state utility laws?  While the answer may vary from state to state, an order issued by the New Hampshire Public Utilities Commission earlier this year found found that offering solar power purchase agreements or solar leases to customers in New Hampshire would not subject a solar company to Commission regulation under any of several theories.  The order finding no regulation required is consistent with other state policy and precedent supporting distributed generation, and could be a model for other states.

Federal law controls some many aspects of the U.S. electricity industry, but states can and do regulate public utilities and competitive electric power suppliers.  Knowing who these state-regulated utilities and suppliers were was straightforward under the dominant utility models of the twentieth century.  But as new technologies like solar photovoltaic panels or other distributed energy resources become more widely adopted, and new business models like solar power purchase agreements and solar leases arise, their regulatory status can be uncertain.  If a solar company installs solar panels on a customer's roofs, and sells that customers the power produced, will it be regulated like a public utility or supplier under state law?  What if the company leases the panels to the customer?

The New Hampshire Public Utilities Commission recently addressed these questions in answering a 2015 petition by Vivint Solar, Inc.  In that petition, Vivint asked the New Hampshire Public Utilities Commission for a declaratory ruling that it would not regulate Vivint as a public utility, competitive electric power supplier, or limited producer of electrical energy under state law, for offering solar power purchase agreements or solar leases to residential customers in New Hampshire.

In a January 15, 2016 order -- Order No. 25,859 -- the Commission granted Vivint's petition.  First, the Commission noted the value of regulatory certainty:

We believe it is important for a party planning to do business in the state to have a vehicle through which it may clarify its regulatory status prior to entering the marketplace, provided that it can describe in sufficient detail its business plans and practices and these plans and practices are not hypothetical or speculative.

Next, the Commission concluded that the operations described by Vivint would not constitute sales to or for the "public" within the meaning of the statutory definition of "public utility."  Key factors recited in the order included the "conditional nature and relative complexity of Vivint’s relationships with its customers."

The Commission then analyzed its rules regarding competitive electric power suppliers, concluding that although Vivint might meet the regulatory definition of a supplier, that definition "should not be read in isolation but in the context of the overall purpose and effect" of the rules in their entirety.  The Commission then noted that those "Puc 2000" rules "seem intended to regulate  a set of relationships and related transactions that is quite different from those undertaken in the context of customer-sited, behind-the-meter, distributed generation development involving sales of electricity directly to the host customers pursuant to the terms and conditions of PPAs."

Finally, the Commission concluded that neither Vivint's PPAs nor solar leases should be subject to Commission regulation under the New Hampshire Limited Electrical Energy Producers Act.  The Commission interpreted that act's retail sales provisions "as applicable to sales of electricity off-site from the generation facilities," not "on-site and behind-the-meter" sales of power as contemplated by Vivint.

The New Hampshire Public Utilities Commission noted that while the petition and briefs in the case focused on the residential solar energy market, its analysis and conclusions "would not be different if the relevant customers were non - residential, assuming that the Systems were installed on the customers’ premises behind the utility retail electric meter, we re sized no larger than necessary to meet the customers’ reasonably anticipated electric consumption, and involved sales of electricity directly to the host customer or leases of the installed Systems to the host customer."

While the ruling technically applies to the company and facts asserted in the petition, it confirms the possibility of an important role for third-party involvement in distributed generation.

Federal dams and preliminary permits

U.S. federal entities own dams with untapped hydropower potential that could be developed by private parties -- but a recent regulatory decision highlights the difficulty of winning key approvals when the federal dam owner opposes the project.  The Federal Energy Regulatory Commission's April 5, 2016 denial of an application for a preliminary permit for the McNary Lock and Dam Project illustrates this dynamic.

The U.S. Army Corps of Engineers owns and operates a 980-megawatt hydroelectric project at the McNary Lock and Dam on the Columbia River in Oregon and Washington. The project was authorized by the River and Harbor Act of 1945, and all its power units have been in operation since 1957.

But perhaps there may be untapped hydropower potential at the site that could be developed.  In 2015, a company called Advanced Hydropower, Inc. applied to the Federal Energy Regulatory Commission for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, to study the feasibility of the proposed McNary Dam Advanced Hydropower Project No. 14697.  That project would utilize the existing McNary Dam, plus new facilities including a 34-megawatt turbine.

But by an order dated April 5, 2016, the Commission denied Advanced Hydropower's application.  In doing so, the Commission cited judicial precedent that it "is not required to grant a preliminary permit application, so long as it articulates a rational basis for not doing so."  It then cited recent Commission decision denying preliminary permits for projects at federal facilities after receiving comments from the relevant federal entities indicating that no purpose would be served in issuing a permit because the federal entity would not approve modifications to its federal facilities.

Notably, in the McNary Lock and Dam case, the Corps filed timely motions to intervene and comments opposing the project.  In its order denying Advanced Hydropower's application, the Commission noted:

Here, because the Corps, which owns the McNary Lock and Dam facility and whose permission would be needed for the development of any project at that facility, has stated that it opposes the project, we find there is no purpose in issuing a preliminary permit here.

Based on the Corps' opposition to the project, the Commission thus denied Advanced Hydropower's application for a preliminary permit for the McNary Lock and Dam project.

FERC rules off-grid micro-hydro needs no license

Federal hydropower regulators have granted reconsideration of a 2015 order finding licensing required for an off-grid micro-hydropower project proposed in Massachusetts.  Based on newly submitted evidence that the proposed project would not be connected to an interstate grid, the order granting reconsideration finds that Section 23(b)(1) of the Federal Power Act does not require licensing of the proposed Egnaczak Net Zero Hydro Project.

The case involves a project proposed by Kenneth and Susan Egnaczak, to be located at an existing water-powered mill complex on the Hoosic River in Cheshire, Massachusetts.  The so-called "Egnaczak Net Zero Hydro Project" would have a total generating capacity of 10.7 kilowatts.  The power would be used at a home and workshop proposed for construction along the river.

Under Section 23(b)(1) of the Federal Power Act, an entity proposing a hydropower project must generally file with the Federal Energy Regulatory Commission either a hydropower license application, or a Declaration of Intention to determine if the proposed project requires a license.  The Egnaczaks filed a Declaration of Intention for the project in February 2015.  On September 11, 2015, Commission staff issued an order finding that the Federal Power Act requires a license to be issued for the project's construction, maintenance, and operation.

Section 23(b)(1) of the Federal Power Act requires a non-federal hydroelectric project to be licensed if it falls into any of four categories: (1) is located on “navigable waters of the United States;” (2) occupies lands or reservations of the United States; (3) uses surplus water or water power from a federal dam; or (4) is located on a non-navigable stream which is subject to the authority of Congress under the Commerce Clause, affects the interests of interstate or foreign commerce, and is constructed or enlarged after August 26, 1935.

In its September 2015 order on the Egnaczak project, Commission staff analyzed the facts as applied to these facts.  On category 1, staff found that there is insufficient evidence to determine whether the Hoosic River is navigable at the project site.  Staff readily dispensed with categories 2 and 3, finding that the project would neither occupy any public lands or reservations of the United States nor use surplus water or waterpower from a Federal government dam.

In September, staff found that the project fell into the fourth category.  In the order, staff noted that it would be located on a non-navigable Commerce Clause stream, would be constructed after 1935, and would affect the interests of interstate commerce because the project would offset both electrical and heating needs for the applicants’ home and workshop that would have been otherwise supplied by the interstate grid.  The order cited judicial precedent, noting, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of FPA section 23(b)(1)." Staff therefore determined that the project requires licensing under FPA section 23(b)(1).

But on January 6, 2016, the applicants filed a request for reconsideration and additional evidence in support of their argument that the project does not require licensing.  This evidence focused on the fact that the project would not be connected to the interstate grid and thus would not affect interstate commerce.  As later described by the Commission:

They state that, because neither their home nor workshop has been constructed, they have no existing grid connection. Further, they explain that the project alone will power their home and workshop. The applicants state that the project would produce hydro-mechanical power using a waterwheel, Archimedes Screw, or turbine. The mechanical power would be connected to the hydro generator units to produce electricity or to power rotating equipment, such as a sawmill. In addition, the applicants state that they will use backup power from a fossil fuel electric generator and storage batteries, which would be charged by the hydro generators or the fossil fuel electric generator.

In a March 24, 2016 order, the Commission staff found that the applicants had demonstrated that the Net Zero Project would not be connected to an interstate grid.  That order finds that the micro-hydro project would not displace power that would otherwise be supplied by the grid and thus would not affect interstate commerce.  As a result, it concludes that "section 23(b)(1) of the FPA does not require licensing of the proposed Net Zero Project."

The March 24 order does include a warning: "if the project or the applicants’ unconstructed home or workshop are connected to the interstate grid in the future, section 23(b)(1) of the FPA would require licensing and the Commission could require the applicants to apply for a license under section 4(g) of the FPA."

Thus in at least this one case, the off-grid nature of the micro-hydro project was a critical factor in the order finding that Section 23(b)(1) of the Federal Power Act does not require licensing of the proposed Egnaczak Net Zero Hydro Project.  The key to the revised finding that the project would have no effect on interstate commerce appears to be the fact that power would be consumed in buildings not yet built, with no existing grid tie.

Inflatable flashboards meet historic dam

A hydropower project in Lowell, Massachusetts won the right to replace wooden flashboards with an inflatable pneumatic crest gate system -- and now seeks to modify provisions requiring specific actions to mitigate impacts on historic properties.

The Lowell Hydroelectric Project is located on the Merrimack River.  While the project does not occupy any federal land, it is located within the administrative boundary of the Lowell National Historical Park.

On July 6, 2010, project licensees Boott Hydropower, Inc., and Eldred L. Field Hydroelectric Facility Trust filed an application to amend the license for the Lowell Hydroelectric Project.  The licensees requested authorization to replace the existing Pawtucket Dam’s wooden flashboards with a pneumatic crest gate system, and to change the configuration of the wooden flashboard system while the new crest gate system is being constructed.  Also called "inflatable flashboards", a pneumatic crest gate system allows the dam operator to increase or decrease the effective height of the flashboard system remotely.

The application was contested. Among other things, Pawtucket Dam is listed on the National Register of Historic Places as part of the Lowell Park and two historic districts, one of which is a National Historic Landmark.  Participants in the license amendment case disagreed about whether it is acceptable to alter the crest control structure on top of the dam and whether the effects of
doing so can be adequately mitigated.  Some concern related to the visual impact of the inflatable flashboards, relative to the project's historic context.

But in 2013, the Federal Energy Regulatory Commission issued an Order Amending License allowing the licensee to replace the wooden flashboards with a pneumatic crest gate system.  The Commission found "that the proposed pneumatic crest gate system can be installed without unacceptably altering the dam or adversely affecting the park and historic districts."  The Commission therefore granted the licensees’ amendment request, subject to additional conditions.
 
Those conditions included a paragraph in the Order requiring the licensees to take certain actions "to mitigate any adverse effects on historic properties of installing the pneumatic crest gate system."  These license required consultation with the Massachusetts State Historic Preservation Officer and the Lowell National Historical Park to the extent possible.  The conditions also included specific measures including interpretive exhibits, a design for the compressor house featuring "materials and colors that are compatible with the historic fabric of the adjacent architecture, to ensure that the compressor house resembles nineteenth century buildings in Lowell," color and appearance requirements for the inflatable flashboard system.

But National Park Service subsequently indicated its willingness to waive these design-related mitigation requirements.  According to a February 2, 2016, letter from the National Park Service, "it is National Park Service's policy not to make new construction look historic in appearance."  Two days later, the licensee applied to the FERC to remove these mitigation requirements.  That application notes that eliminating these requirements "decreases material ordering time and crest gate system installation time for this long-awaited improvement."

Comments on the application, motions to intervene, and protests are due by April 11, 2016.

FERC approves Iberdrola-UIL merger

Federal utility regulators have issued an order authorizing transactions the merger of utilities affiliated with Iberdrola, S.A. and UIL Holding Corporation.

Iberdrola is a Spanish-owned utility holding company, owning electricity and natural gas systems and electric generation across four continents.  Its direct wholly owned subsidiary Iberdrola USA holds all of Iberdrola’s energy-related operations in the United States through two intermediate holding companies. Iberdrola USA Networks, Inc., holds transmission owning public utility affiliates, including New York State Electric & Gas Corporation (NYSEG), Rochester Gas and Electric Corporation, Central Maine Power Company, Maine Natural Gas Company, and interests in Maine Electric Power Company. Iberdrola Renewables Holdings, Inc. owns and operates its generation segment in the United States through a number of indirect subsidiaries.

UIL is in the business of ownership of operating regulated utilities in Connecticut and Massachusetts. It owns and controls the United Illuminating Company, a business engaged in purchasing, transmitting, and distributing electric power to customers in southwestern Connecticut. United Illuminating owns a 50 percent equity interest in GCE Holding LLC which in turn owns two companies owning 187.6 MW dual-fuel generating plants in Milford and Middletown, Connecticut. UIL also owns natural gas local distribution companies in central and southern Connecticut and western Massachusetts, as well as Total Peaking Services, LLC which provides liquefied natural gas storage services.

On February 26, 2015, Iberdrola S.A. announced the boards of directors of Iberdrola S.A. and Iberdrola USA had approved a combination of Iberdrola USA with UIL Holdings in a friendly transaction, reportedly for about $3 billion.  On March 25, 2015, Iberdrola and UIL applied to the Federal Energy Regulatory Commission for authorization under section 203(a)(1) and (a)(2) of the Federal Power Act (FPA) for a series of transactions in which UIL will become an indirect wholly owned subsidiary of Iberdrola USA and, in turn, a wholly owned subsidiary of Iberdrola.

In a Section 203 case, the Commission examines a merger’s effect on competition, rates and regulation, and the potential for cross-subsidization.  Applicants must demonstrate that a proposed disposition or acquisition of jurisdictional facilities meets the standards of Section 203.   In the Iberdrola-UIL case, the applicants stated that their subsidiaries' portfolios of generation, transmission, natural gas assets, and other jurisdictional facilities had only de minimis overlap, that the transaction would not adversely affect rates or regulation, or result in cross-subsidization of a nonutility associate company or pledge or encumbrance of utility assets for the benefit of an associate company.

On June 2, 2015, the Commission issued an order finding that the proposed transaction is consistent with the public interest and is authorized, subject to routine conditions.  While other regulatory approvals may be required before the merger can proceed, securing prior authorization under Section 203 is an important milestone for the proposed deal.

According to Iberdrola, the combined company will have a 2014 pro forma EBITDA of approximately $2 billion, net income of $570 million, 3.1 million of points of supply, around 6.7 GW of installed capacity.  Iberdrola anticipates that the company will become the US's second largest wind operator and one of the nation's largest utilities.

FERC Order 676-H adopts NAESB standards

Last week the Federal Energy Regulatory Commission issued Order No. 676-H, adopting and incorporating into its regulations most of the latest version of a set public utility business practice standards and communications protocols developed by the North American Energy Standards Board (NAESB).  While most of the NAESB standards will now become mandatory and enforceable, to enable smart grid innovation the Commission posted NAESB's five Smart Grid standards as non-binding guidance.

Industry standards enable cooperation and communication, and can lead to more efficient and competitive markets.  Formally known as Version 003 of the Standards for Business Practices and Communication Protocols for Public Utilities adopted by NAESB's Wholesale Electric Quadrant (WEQ), the newly adopted standards represent the latest evolution of NAESB's consensus-based standards for public utilities.  NAESB is an ANSI-accredited non-profit standards development organization formed to develop and promote business practice standards that promote a seamless marketplace for wholesale and retail natural gas and electricity. Since issuing Order No. 676 in 2006, the FERC has incorporated elements of NAESB's standards into its regulations.

While the FERC made most of the NAESB standards mandatory, it decided to include NAESB's smart grid standards only "informationally, as guidance."  While FERC noted that the smart grid standards have value and should be adopted by public utilities, it ultimately agreed with utility trade group Edison Electric Institute and the ISO/RTO Council that NAESB's five Smart Grid standards should neither be incorporated into formal federal regulation nor be enforceable and mandatory.  Notably, as prepared by NAESB the Smart Grid standards are meant to be optional and informative, not prescriptive or restrictive, and could prove difficult to enforce.

Thus to "encourage further developments in interoperability, technological innovation and standardization", the FERC chose to include NAESB's five smart grid standards in Order No. 676-H as guidance, but not to incorporate them into its formal, enforceable regulations.

Through Order No. 676-H, the FERC hopes to improve business practices and interoperability among public utilities.  The order also shows an intent to foster smart grid technologies, without stifling their development through overly prescriptive or unenforceable regulations.  Will Order 676-H usher in a new era of smart grid and utility cooperation?

Court overturns FERC Order 745 on demand response

A federal appellate court has overturned the Federal Energy Regulatory Commission's key ruling on demand response -- when electricity customers respond to signals about the scarcity of electricity by temporarily reducing their consumption -- and how it should be compensated.

A smart grid technology, demand response can be a key tool in reducing the cost and environmental impact of society's electricity needs.  In most US markets, as the demand for electricity rises (such as during a summer heat wave), grid operators turn to increasingly expensive generating units for new supply to meet that demand.  Those "peaking" units -- used primarily to supply energy during times of peak demand -- are thus relatively expensive.  In many cases, they also rely on fuels like oil that lead to increased emissions of pollutants and carbon dioxide.

Demand response offers an alternative solution.  Customers participating in demand response programs agree to reduce their consumption of power from the grid when so instructed by the grid operator.  For example, an office building might commit to temporarily reduce its air handling load, or a factory to reduce or pause its manufacturing operations.

This can provide much the same benefits as generation, by balancing electricity supply and demand, for a lower cost than generation solutions and without causing incremental air emissions.  Demand response can also avoid the need to develop new or upgraded transmission lines, because it solves the problem through reduced energy flows.  Demand response programs therefore provide benefits to the entire grid, and have been established by both organized wholesale markets and vertically integrated utilities across the country.

While demand response's value to the grid is clear, how to compensate customers for their curtailment remains a key question.  In 2011, the Federal Energy Regulatory Commission issued a landmark order known as Order No. 745.  In Order No. 745 (116 page PDF), the Commission ruled that organized wholesale energy market operators must pay demand response resources the market price for energy, known as the locational marginal price (LMP), when those resources have the capability to balance supply and demand as an alternative to a generation resource and when dispatch of those resources is cost-effective.  Order No. 745 thus represented a major step forward for both demand response providers as well as all customers in markets with demand response program.

But some energy industry associations did not like the rule, and challenged the legality of Order No. 745.  The Electric Power Supply Association appealed the Commission's order to a federal court.  Meanwhile, other groups supported the rule, including industrial energy consumers and environmental advocates.

Today the D.C. Circuit Court of Appeals agreed with the appellants, holding that the Commission overstepped its jurisdictional bounds by encroaching on the states’ exclusive jurisdiction to regulate the retail market.  The court ruling, issued in the case Electric Power Supply Association v. Federal Energy Regulatory Commission (44-page PDF), vacates Order No. 745 and remands it back to the Commission.

If the Commission is to require fair compensation for demand response providers, it will have to find a new way to do so -- and one that would survive renewed judicial challenge.  In the meantime, grid operators are faced with a challenge (and an opportunity): whether and how to revise the way they pay customers for demand response.  As demand response's value remains beyond debate, the economic and environmental pressures that led to Order No. 745 remain strong, so expect this issue to continue to play out over the next year.