FERC rules tribes exempt from some energy regulation

Tuesday, December 16, 2014

When a Native American tribe acquires a hydroelectric power plant licensed by the Federal Energy Regulatory Commission, does the project become exempt from some federal regulations?

Yes, according to a FERC order recently issued to the Confederated Salish and Kootenai Tribes of the Flathead Reservation.

The tribes are poised to become the first American Indian tribe to own and operate a Commission-licensed hydroelectric power plant, the Kerr Hydroelectric Project.  Docketed by FERC as Project No. 5, the Kerr Project consists of a reservoir, dam, penstocks, 196-megawatt power plant, and related assets located on Flathead Lake and Flathead River, mostly within the Tribes’ treaty-reserved Flathead Reservation.

The Commission issued the Kerr Project's current license on July 17, 1985, with a 50-year term.  Under the terms of a settlement between Montana Power Company and the Tribes as competing applicants for the license, the utility and the Tribes were joint licensees, and after a term of thirty years, the license allows the project to be transferred to full ownership by the Tribes.  While Montana Power Company's interests were sold to PPL Montana, LLC and ultimately transferred to Northwestern Corporation, the Tribes are slated to take over the project on September 5, 2015. On this date of conveyance, the Tribes will be the sole owner and operator of the Kerr Project, through and until the license expires on September 4, 2035.

In anticipation of that conveyance, the Tribes and their wholly owned operating company known as Energy Keepers, Inc. or EKI petitioned the Commission for a declaratory order finding that they are exempt public utilities under section 201(f) of the Federal Power Act and that they are not required to maintain or make available their books and records to the Commission under the Public Utility Holding Company Act of 2005 and related regulations.

Section 201(f) of the FPA provides exemptions from the Commission’s authority under most provisions of Part II of the FPA for “the United States, a State or any political subdivision of a state, or any agency, authority or instrumentality of any one or more of the foregoing, or any corporation which is wholly owned, directly or indirectly, by any one or more of the foregoing.”  This exemption is generally viewed as applicable to "governmental entities."  The Public Utility Holding Company Act of 2005, or PUHCA 2005, requires holding companies to provide the Commission access to their books and records. 

Based on the facts as presented in the Petition, the Commission determined that the Tribes and EKI are exempt public utilities as defined in section 201(f) of the Federal Power Act.   The Commission found that the Tribes are an “agency, authority or instrumentality” of the “United States, a State or any political subdivision of a state,” and that their wholly owned subsidiary EKI assists the Tribes in performing their inherent government functions.

The Commission also concludes that PUHCA 2005 and relevant Commission regulations do not apply to the Tribes and EKI.  The Commission found that EKI will operate the Kerr Project for the generation, transmission, or distribution of electric energy for sale and is thus an electric utility company, and thus a public utility company under PUHCA 2005 -- and therefore the Tribes are a holding company under PUHCA 2005.  However, because the Tribes are an exempt governmental entity, they are exempt from its books and records requirement.

The Commission thus determined that the Confederated Salish and Kootenai Tribes will be exempt from many parts of Part II of the Federal Power Act and the books and records requirement of PUHCA 2005.  While the Tribes are not scheduled to take over the Kerr Project until September 2015, they want to be able to secure contracts to sell the project's power well in advance.  The Commission's declaratory order reduces regulatory uncertainty, facilitating the Tribes' efforts to sell the project's future power into the Pacific Northwest electricity market.

Developer applies to VT for Clean Power Link transmission line

Friday, December 12, 2014

A proposed electric transmission line from Quebec into New England took a step forward this week, as the developer of the New England Clean Power Link applied to Vermont regulators for key project approvals.

Transmission Developers Inc. subsidiary TDI New England has proposed the New England Clean Power Link to bring Canadian hydropower and other electricity to the renewable-hungry New England market.  With an estimated project cost of $1.2 billion, the 1000-megawatt high-voltage direct-current transmission line would run under Lake Champlain and underground to a converter station in Ludlow, Vermont, near where it would connect to the existing electric grid owned by Vermont Electric Power Company (VELCO).

Under Vermont law, the state Public Service Board regulates many aspects of the electric grid.  Section 248 of Title 30 of Vermont's statutes requires companies to obtain approval from the Board before beginning site preparation or construction of electric transmission facilities, electric generation facilities and certain gas pipelines within Vermont.  For facilities like the proposed transmission line, that Board approval comes in the form of a Certificate of Public Good. 

On December 8, 2014, TDI subsidiary Champlain VT, LLC d/b/a TDI New England applied to the Board for a Certificate of Public Good for the project.  TDI's petition notes that the project "would contribute to meeting State and regional energy and sustainability goals and result in millions of tons/year in reduced greenhouse gas emissions by replacing electricity generated by fossil fuels," and that running cables under the lake and underground avoids adverse impacts from above-ground installations.  Other benefits touted by TDI include economic development (with about $1.5 billion in claimed economic benefits to Vermont and the entire region over the project's 40-year life), improved electric reliability and fuel diversity, and help in mitigating the impacts of the anticipated loss of the Vermont Yankee nuclear station and other major power plants.

TDI's proposal includes components specifically designed to yield local community benefits and thus to cultivate local support for the project.  These components include creating $122 million in funds to improve Lake Champlain's water quality, habitat, and recreational values, plus another $40 million for Vermont's Clean Energy Development Fund.

TDI's project now comes before the Vermont Public Service Board for review.  The project also needs a presidential permit issued by the U.S. Department of Energy to cross the international boundary, as well as a U.S. Army Corps of Engineers permit for impacts to water resources.

At the same time, another transmission line has been proposed under Lake Champlain, namely the $2.2 billion Champlain Hudson Power Express meant to connect Quebec to New York City.

FERC plans conferences on EPA carbon rule impacts

Thursday, December 11, 2014

If the U.S. Environmental Protection Agency's proposed carbon regulations for power plants are adopted, how will state and regional efforts to comply with the rule impact the electric power grid?  If states need new infrastructure like electric transmission lines or natural gas pipelines to comply with the EPA rule, what can be done to reduce regulatory barriers to new infrastructure development?

A fossil fuel-fired power plant near New York, NY.
The EPA's proposed Clean Power Plan rule would require states to meet customized standards for how much carbon dioxide their electric power sector emits per unit of useful energy.  As envisioned by EPA, each state can choose its own path to meeting these standards by combining elements from a menu of four "building blocks": better coal plant efficiency, increased utilization of natural gas plants, increased renewable energy, and increased energy efficiency.

The implications of different approaches to complying with the proposed rule will be the focus of an upcoming series of technical conferences to be held by the Federal Energy Regulatory Commission.  According to the Commission's public notice, state, regional and/or federal plans for compliance with the proposed Clean Power Plan may impact Commission-jurisdictional markets, grid operations, and infrastructure.  The series of technical conferences is designed to provide forums for identifying issues and solutions.  The Commission also plans to provide an opportunity to discuss how compliance scenarios may impact existing infrastructure and drive the need for additional infrastructure, especially new electric transmission and natural gas pipeline facilities, and whether there are regulatory barriers that need to be addressed, and by whom, to ensure the timely development of those facilities.

The conferences will begin with a Commission-led National Overview session at FERC headquarters on February 19, 2015.  The National Overview will address whether regulators and industry have the appropriate tools to identify any reliability or market issues that may arise, potential strategies for compliance with the EPA regulations and coordination with FERC-jurisdictional wholesale and interstate markets, and how to coordinate reliability and infrastructure planning processes with state and/or regional environmental compliance efforts to ensure the adequate development of new infrastructure and to manage any potential reliability and operational impacts of proposed compliance plans. The Commission will offer a live webcast of the National Overview, which will be archived for three months.

Following the National Overview technical conference, the Commission will hold three regional technical conferences, on dates to be announced, in Washington, DC, St. Louis, MO, and Denver, CO.  Each regional event will include discussion of the specific potential impacts to regional reliability, power system operations and generator dispatch, and needed infrastructure upgrades.

Will the EPA's Clean Power Plan be finalized and take effect?  If so, when -- and in what form?  Federal carbon emission limits are as yet untested in the U.S., and other innovative regulatory efforts have met with years or even decades of delay before taking effect.  At the same time, the prospect of federal carbon rules affecting the electric power sector spurs energy regulators to take a serious look at potential impacts of the carbon rules, and to begin planning for their possible future effectiveness.

Salem power plant wins market deferral

Wednesday, December 10, 2014

Federal regulators have granted a request by the developer of a power plant in Salem, Massachusetts, to defer its commitment to provide power to the New England market.  The process reflects challenges inherent to developing power plants in the Boston area, as well as methods to mitigate the impacts of those challenges.

Stacks of the former Salem Harbor Power Station, before its decommissioning.

Footprint Power Salem Harbor Development LP is in the process of redeveloping the site of a defunct coal-powered generation plant.  The former Salem Harbor Power Station could produce up to 745 megawatts of power, fueled by coal and oil.  In 2010, Footprint identified the site as a potential facility for redevelopment and, on August 3, 2012, it acquired the plant from Dominion Energy Salem Harbor, LLC.  Footprint now plans to build what the Federal Energy Regulatory Commission has described as two state-of-the art, efficient, low-emission, quick-start natural gas turbine generators; two steam-turbine generators; and two heat-recovery steam generators, including pollution control equipment, with aggregate generating capacity of 674 megawatts.

The New England electricity market compensates generators and other resources for two main products: energy and capacity.  Energy represents the volume of power sold by a market participant (measured in megawatt-hours), while capacity represents the intended full-load sustained output of a facility (measured in megawatts).  Regional grid operator ISO New England, Inc. operates a forward capacity market, under which generators can lock in the payments for capacity several years in advance of actually operating.  This structure is designed to ensure that the region has sufficient generating capacity to meet future needs, as well as to help new generation projects secure financing and be built despite long permitting and construction lead times.

Footprint bid its proposed natural gas power plant into New England's seventh Forward Capacity Auction, also known as FCA7.  That auction was held in February 2013, and gave Footprint a future capacity market revenue stream in exchange for the obligation to provide capacity over a one-year capacity commitment period starting on June 1, 2016.  According to Footprint, it then had 39 months to obtain all necessary permits, secure financing arrangements and complete construction of the plant, a process that had never been tested for a new plant not subsidized or sponsored by a state.

While Footprint secured many of the necessary permits promptly, one permit in particular -- a federal Prevention of Significant Deterioration (PSD) permit under the Clean Air Act -- took longer than expected.  Obtaining a PSD permit from the Massachusetts Department of Environmental Protection, acting under federally delegated authority, involves a five-phase process: (1) pre-application; (2) application; (3) draft permit preparation; (4) public participation; and (5) final decision to issue or deny a PSD permit.  While Footprint finally obtained its PSD permit -- and survived a last-minute appeal of that permit's issuance -- Footprint says the delay and revenue uncertainty the resulting uncertainty of revenues impaired its ability to finance the project. While Footprint had exercised an option to lock in its capacity rates for five years, without the deferral one full year of stable revenue would be lost, making potential lenders and equity providers unwilling to provide financing.

Under ISO-NE's tariff, a market participant may seek a deferral of its capacity supply obligation if three criteria are met.  First, the resource must first request and receive from ISO-NE a written reliability determination indicating that the absence of the resource's capacity would result in a transmission system reliability issue in both the associated Capacity Commitment Period and the next Capacity Commitment Period.  If ISO-NE makes such a determination, then the resource may file with the Federal Energy Regulatory Commission for a one-year deferral of its Capacity Supply Obligation. The resource must include in its filing to the Commission (1) the reliability determination from ISO-NE; (2) a demonstration that the project's development delay is due to factors beyond the control of the resource; and (3) a demonstration that the deferral is critical to the resource's ability to achieve commercial operation.

Footprint applied to the Commission for such a deferral on October 7, 2014.  On December 5, the Commission granted Footprint's request.  The Commission noted that ISO-NE had issued a reliability determination finding that the Footprint facility is needed for reliability in the 2016-2017 Capacity Commitment Period and the subsequent 2017-2018 period, that Footprint had demonstrated that it has failed to achieve commercial operation on time due to factors beyond its control, and that Footprint has demonstrated that the deferral is critical to the Facility’s ability to achieve commercial operation.

Footprint's experience highlights several key dynamics affecting New England power plant development.  The story is framed by the retirement of an aging coal plant and its replacement with natural gas-fired generation, a trend occurring across the U.S.  It features the challenges of securing necessary environmental permits and surviving appeals by project opponents.  Footprint's experience also highlights the features of the New England forward capacity market, and how it affects developers of new power plants.

US Presidential Permits for cross-border infrastructure

Monday, December 8, 2014

As the U.S.'s international trade in energy grows, so too has interest in the process for securing a federally required approval known as a Presidential Permit.

A marker shows the route of a natural gas pipeline in Utah.

The construction, operation, and maintenance of infrastructure that crosses the U.S.'s border with Mexico or Canada -- think pipelines, transmission lines, and bridges -- generally requires prior authorization by the federal government in the form of a Presidential Permit.  How you obtain a Presidential Permit depends on the type of facilities in question, as permits may be issued by several federal agencies under different legal authorities.

Presidential permits for oil, petroleum products, and other liquids pipelines have been issued by the U.S. State Department since since the promulgation of Executive Order 11423 in 1968.  Executive Order 11423 provided that, except with respect to cross-border permits for electric energy facilities, natural gas facilities, and submarine facilities:
The Secretary of State is hereby designated and empowered to receive all applications for permits for the construction, connection, operation, or maintenance, at the borders of the United States, of: (i) pipelines, conveyor belts, and similar facilities for the exportation or importation of petroleum, petroleum products, coal, minerals, or other products to or from a foreign country; (ii) facilities for the exportation or importation of water or sewage to or from a foreign country; (iii) monorails, aerial cable cars, aerial tramways and similar facilities for the transportation of persons or things, or both, to or from a foreign country; and (iv) bridges, to the extent that congressional authorization is not required.
The State Department's Bureau of Energy Resources Office of Energy Diplomacy receives and processes permit applications for liquid product pipelines, including water and petroleum products.  The standard by which the Secretary of State reviews applications for presidential permits is prescribed by an executive order issued in 2004.  Executive Order 13337 directs the Secretary of State to authorize those border crossing facilities that the Secretary has determined would “serve the national interest."

By contrast, cross-border natural gas pipelines are regulated by the Federal Energy Regulatory Commission, while electric transmission infrastructure is regulated by the Department of Energy.  Section 3 of the Natural Gas Act requires any person desiring to export any natural gas from the United States to a foreign country or to import any natural gas from a foreign country to the United States to obtain an order from the Federal Power Commission authorizing it to do so.   Section 202(e) of the Federal Power Act requires any person desiring to transmit any electric energy from the United States to a foreign country to obtain an order from the Federal Power Commission authorizing it to do so.

Executive Order 10485 designated the FERC's predecessor agency, the Federal Power Commission, to receive applications for natural gas and electricity facilities.  When the Department of Energy Organization Act of 1977 eliminated the Federal Power Commission, it shifted most of the FPC's responsibilities to the FERC, but Section 402(f) of that act specifically reserved import/export permitting functions for the Department of Energy.  For facilities governed by the Department of Energy, the Presidential Permit process is governed by Part 205 of the Department's rules.  In 2006, the Department delegated its authority to issue Presidential Permits for natural gas pipeline border crossings to FERC, via DOE Delegation Order No. 00-004.00A.

Infrastructure projects subject to the Presidential Permit process range widely in type, scope, and controversy, from the proposed Keystone XL oil pipeline from Canada to the proposed Champlain Hudson Express high-voltage direct current electric transmission line.

4th California blackout FERC enforcement case settles

Friday, December 5, 2014

Federal regulators have approved a settlement with another federal agency over its role in a 2011 blackout in California, Arizona, and Mexico.

On September 8, 2011, the Southwest's electric grid was hit with a widespread power outage that left over 5 million people in California, Arizona and Baja California, Mexico, without power for up to 12 hours.  Previous investigations by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) found that the blackout occurred when Arizona Public Service Company's 500-kilovolt Hassayampa-N.Gila transmission line tripped out of service, overloading the remaining elements of the regional grid. 

Earlier this year, FERC approved stipulations and consent agreements among its Office of Enforcement, NERC, and three public utilities.  Arizona Public Service agreed to pay $3.25 million in civil penalties, California's Imperial Irrigation District agreed to a $12 million settlement, and  Southern California Edison Company agreed to pay a $650,000 civil penalty and undertake additional compliance actions.

FERC approved a fourth settlement on November 24, 2014, with the Western Area Power Administration – Desert Southwest Region (Western-DSW).  One of four power marketing administrations within the United States Department of Energy, the Western Area Power Administration (WAPA) markets and transmits electricity to a fifteen-state region from hydroelectric power facilities at the Hoover, Parker, and Davis dams. Western-DSW is one of four regions carrying out this mission for WAPA, serving customers in Arizona, Southern California, and Southern Nevada. It sells more than ten billion kilowatt hours of hydroelectric power to approximately seventy municipalities, cooperatives, federal and state agencies, and irrigation districts. Western-DSW also operates and maintains more than forty substations and 3,100 miles of transmission lines.

In the FERC Order Approving Stipulation and Consent Agreement, the Commission notes that Western-DSW violated four Requirements of three Reliability Standards in the Transmission Operations (TOP) and Voltage and Reactive Control (VAR) categories. These groups of standards cover the responsibilities and decision making authority for reliable operations and maintenance of Bulk Power system facilities within voltage and reactive power limits to protect equipment and ensure reliable operation of the interconnection.  In particular, FERC Enforcement staff and NERC found that Western-DSW failed to operate its portion of the transmission system within voltage system operating limits and to maintain sufficient situational awareness prior to and during the event, undermining reliable operation of the Bulk Power System.

Western-DSW stipulated to the facts in the agreement and agreed to implement compliance measures necessary to mitigate the violations and improve overall reliability, including improving its models, better coordination with neighboring entities, and improving its situational awareness by adding a real-time monitoring tool that analyzes and alerts operators to potential contingencies. Western-DSW also agreed to make semi-annual compliance reports to Enforcement staff and NERC for at least one year.  Notably, the stipulation does not require Western-DSW to pay a civil penalty.

FERC's general investigative report on the incident identified six potential targets for enforcement action.  With cases settled against Western-DSW, SoCal Edison, the Imperial Irrigation District, and Arizona Public Service, only the California Independent System Operator and the Western Electricity Coordinating Council Reliability Coordinator have not yet been parties to a stipulation and consent agreement.

US to auction Massachusetts offshore wind sites

Wednesday, December 3, 2014

The U.S. Department of the Interior has announced plans to auction more than 742,000 acres offshore Massachusetts for commercial wind energy development.

On January 29, 2015, the Department's Bureau of Ocean Energy Management will hold a competitive commercial lease sale for the rights to site offshore wind facilities in the federally designated Massachusetts Wind Energy Area.  Generally located south of the islands of Martha's Vineyard and Nantucket, the area will be auctioned as four leases.  It starts about 12 nautical miles offshore Massachusetts; from its northern boundary, the area extends 33 nautical miles southward and runs about 47 nautical miles from east to west.  The Massachusetts Wind Energy Area is significantly larger than previously auctioned areas off Massachusetts, Rhode Island, Virginia, and Maryland.  The U.S. Department of Energy’s National Renewable Energy Laboratory has estimated that fully developing the Massachusetts area could support between 4 and 5 gigawatts of commercial wind generation.

BOEM has found twelve companies to be legally, technically and financially qualified to participate in the auction for the Massachusetts Wind Energy Area:

  • Deepwater Wind New England, LLC
  • EDF Renewable Development, Inc.
  • Energy Management, Inc.
  • Fishermen’s Energy, LLC
  • Green Sail Energy, LLC
  • NRG Bluewater Wind Massachusetts, LLC
  • OffshoreMW, LLC
  • RES America Developments, Inc.
  • Sea Breeze Energy, LLC
  • US Mainstream Renewable Power (Offshore), Inc.
  • U.S. Wind, Inc.
Bidders will be ranked based on a combination of monetary factors (primarily their bids) and non-monetary factors (whether or not the bidder has a Community Benefits Agreement or Power Purchase Agreement in place).

The Massachusetts auction will be the fourth competitive lease sale for renewable energy on the Outer Continental Shelf, following previous auctions for sites off Massachusetts-Rhode Island, Virginia and Maryland.  Bidders winning previous auctions have committed over $14 million in bids to secure over 357,500 acres in federal waters.  BOEM expects to hold another lease auction for sites offshore New Jersey in 2015.