FERC approves Berkshire Power settlement

Thursday, March 31, 2016

Federal energy regulators have approved a stipulation and consent agreement under which two companies admit violations of the Federal Power Act and regulations prohibiting energy market manipulation.

The case involves Berkshire Power Company LLC (Berkshire), and Power Plant Management Services LLC. Berkshire owns an approximately 245 MW natural gas-fired, combined-cycle generating facility in Agawam, Massachusetts. Berkshire hired PPMS to provide project management and administrative services at the plant.

According to Federal Energy Regulatory Commission documents, at the direction of a general manager hired by PPMS, "Berkshire Power engaged in a fraudulent scheme to perform unreported maintenance work and to conceal that work and associated maintenance outages from ISO-NE."  The documents allege that individuals at the plant scheduled maintenance work for times when the plant was unlikely to be dispatched, and then failed to notify ISO-NE about the work or the associated Plant unavailability.  In at least six instances, this led to representations to ISO New England dispatchers that the plant was starting up or was able to start up when it was, in fact, unavailable due to ongoing maintenance or other technical problems.

The Commission's Office of Enforcement initiated its investigation in June 2014, following a referral from the United States Attorney’s Office for the District of Massachusetts.  Following fact-finding, Enforcement concluded that Berkshire and PPMS violated section 222 of the Federal Power Act and the Commission’s Anti-Manipulation Rule by concealing its maintenance work and associated outages from ISO-NE. That rule prohibits any entity from using a fraudulent device, scheme, or artifice, or engaging in any act, practice, or course of business that operates or would operate as a fraud; with the requisite scienter; in connection with a transaction subject to the jurisdiction of the Commission.

Enforcement also concluded that Berkshire violated Commission regulations by violating provisions of the ISO-NE tariff requiring it to schedule and disclose plant maintenance and to accurately report on plant availability, and by making false and misleading representations to ISO-NE. Finally, Enforcement concluded that Berkshire violated Commission-approved reliability standards by withholding information regarding its planned maintenance outages and plant capabilities and availability.

According to the order, the Office of Enforcement, Berkshire, and PPMS have resolved the matter by a stipulation and consent agreement.  Under that deal, Berkshire and PPMS stipulate to the facts, admit the violations set out in the Agreement, and agree to pay a civil penalty of $2,000,000 to the United States Treasury. Berkshire agrees to pay to ISO-NE disgorgement of $1,012,563, plus interest. Berkshire further agrees to pay a civil penalty of $30,000 to the United States Treasury for its violations of the Reliability Standards.

In its March 30, 2016 order accepting that settlement, the Commission noted Enforcement's consideration of the factors in the Revised Policy Statement on Penalty Guidelines.  Factors cited here as supporting "the appropriate remedy" include "that both companies cooperated fully and comprehensively throughout the investigation, both accepted responsibility for their violations, and neither has a prior history of violations."  The order notes that the remedy also reflects that neither company had an effective compliance program in place during the relevant period, and that a high-level employee at the plant directed the scheme.

The order directs Berkshire and PPMS to make the disgorgement and civil penalty payments as required by the Agreement within ten business days of its Effective Date. ISO-NE was directed to allocate the disgorgement funds pro rata to network load during the applicable period. The order also directs Berkshire and PPMS to comply with the provisions in the Agreement also requiring them to implement procedures to improve compliance going forward, subject to monitoring via submission of semi-annual reports for at least one year.

West Branch storage project relicensed

Wednesday, March 30, 2016

Earlier this month U.S. hydropower regulators issued a new license for the West Branch Project, which includes water storage facilities on the West Branch of the St. Croix River in Maine.

The Federal Energy Regulatory Commission first issued an original license for the West Branch Project on September 4, 1980.  The project includes two developments, Sysladobsis and West Grand, that operate as water storage facilities to provide flood storage and flow releases for downstream hydroelectric generation.  The Sysladobsis Development uses Sysladobsis Lake as its impoundment.  The license describes the West Grand Development as composed of several natural lakes including Scraggly Lake, Keg Lake, Bottle Lake, Junior Lake, Junior Bay, Norway Lake, Pug Lake, Pocumcus Lake, Horseshoe Lake, and West Grand Lake. 

Dikes and dams are used to control and release water, first from Sysladobsis Lake into the downstream West Grand impoundment, then into either Grand Lake Stream or Grand Lake Brook.  Many of the dams and dikes at these sites are old -- the Sysladobsis dam, West Grand dam, and Farm Cove dike were constructed in 1861, 1836, and 1879, respectively, although all three have since been rebuilt.

Each of these developments operates in a seasonal store-and-release mode whereby water is stored to reduce downstream flooding during periods of high flow and released during periods of low flow to augment generation at the downstream hydroelectric projects.

The West Branch Project also operates as part of the larger St. Croix River headwater storage system.  This network of dams includes Woodland Pulp LLC’s Forest City Project No. 2660 and the recently relicensed Vanceboro Project No. 2492. Generation associated with these projects occurs at the Grand Falls and Woodland hydroelectric projects downstream on the St. Croix River.

The West Branch Project's original 1980 license was amended in 1987 to include the existing Farm Cove dike, but the original license expired on September 30, 2000.  Since then, the licensee has operated the project under an annual license pending the disposition of a new license application.

On March 19, 2009, the licensee filed, pursuant to sections 4(e) and 15 of the Federal Power Act (FPA), an application for a new license to continue operating and maintaining the West Branch Project. The licensee proposed to continue store-and-release operation with some changes, continue operating fishways and take other measures to promote fish populations, enhance a land use plan, and develop a historic properties management plan.

Fishery issues have been contentious in the St. Croix River system.  After opportunity for public comment, agency consultation, and preparation of an Environmental Assessment, the Maine Department of Inland Fisheries and Wildlife asked the Commission to delay its licensing decision until fishery management talks concluded.  After being notified by the Department that those talks had concluded, on March 15, 2016 the Commission issued Woodland Pulp a new license to continue operating and maintaining the West Branch Project. 

The new license requires a number of measures to protect and enhance water quality, aquatic habitat, fisheries resources, terrestrial resources, and recreation opportunities at the project. These include a requirement to operate the developments in store-and-release mode between defined pond elevations, to provide certain minimum flows of water, to develop an Operation Compliance Monitoring Plan, and to provide and enhance fish passage.

A list maintained by the Federal Energy Regulatory Commission shows over 1,000 active hydropower licenses.  Many of these licenses will expire in the near future, so relicensing activity for FERC-licensed hydroelectric projects is expected to increase. 

Colorado conduit hydropower project

Tuesday, March 29, 2016

A proposed hydroelectric project in Colorado has received a federal determination that it qualifies as a "qualifying conduit hydroelectric facility" and thus is not required to be licensed under Part I of the Federal Power Act.  The Park Farm Hydro Project illustrates the rapid pace with which the Federal Energy Regulatory Commission can act on conduit hydropower projects under a 2013 amendment to its law.

The Federal Power Act requires most hydropower projects to be licensed by the Federal Energy Regulatory Commission.  But Section 4 of the Hydropower Regulatory Efficiency Act of 2013 amended the Federal Power Act to facilitate "conduit hydropower" projects -- those generating electricity using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  Reforms in 2013 exempted qualifying conduit hydropower facilities from needing a license, and established a fast process for to solicit public comment and confirm whether the new exemption applies.  In the ensuing years, a number of projects have qualified for this treatment.

On January 27, 2016, an applicant filed a notice of intent, pursuant to section 30(a) of the Federal Power Act, as amended by Section 4 of the Hydropower Regulatory Efficiency Act of 2013, to construct a qualifying conduit hydropower facility, the Park Farm Hydro Project, to be located near the Town of Kersey, in Weld County, Colorado.  The notice described a proposal to add ten 1-kilowatt Crossflow turbines alongside an existing "ditch drop" or conduit in the Lower Latham Ditch.

On February 2, 2016, the Commission issued its notice of preliminary determination that the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing.  The notice set a 30-day deadline for filing motions to intervene, and a 45-day deadline for filing comments contesting whether the facility meets the qualifying criteria.  No such comments or motions were received.

On March 22, 2016 -- less than 2 months after the applicant first filed its notice of intent -- the Commission issued a letter constituting its written determination that the Park Farm Hydro Project meets the qualifying criteria under Federal Power Act section 30(a), and is not required to be licensed under Part I of the FPA, although other federal, state, and local laws do apply.

This quick timing on the Park Farm project is consistent with other recent FERC action on proposed conduit hydropower projects.

Alaska tidal permit surrendered

Monday, March 28, 2016

Five years after applying for and receiving a preliminary permit to study a proposed Alaska tidal energy project, the project developer has surrendered that permit.

At issue is ORPC Alaska 2, LLC's proposed East Foreland Tidal Energy Project.  The developer first applied to the Federal Energy Regulatory Commission for a preliminary permit under Section 4(f) of the Federal Power Act on August 2, 2010. 

That application described a project site in middle Cook Inlet, a marine waterway of the northern Pacific Ocean. The proposed hydrokinetic project would lie offshore of the East Foreland, near the west coast of the Kenai Peninsula by Nikiski, Alaska.  The application described the site in middle Cook Inlet as offering a maximum tidal range of up to 9.20 meters, with geomorphology favorable to strong currents.  The application described the developer's intent to install a pilot or commercial project in a phased approach.

The FERC issued a first preliminary permit for the East Foreland project by order dated March 11, 2011.  As permitted, the East Foreland project would include a series of 150-kilowatt TideGen and/or 150-kW OCGen turbine-generator modules developed by ORPC, with a combined capacity between 5 megawatts (MW) and 100 MW, with an average annual generation between 13 and 340 gigawatt-hours.

Over the ensuing years, the permittee studied the site and the project and filed periodic reports to the Commission. The preliminary permit required the permittee to file a notice of intent and draft pilot license application within two years of the permit date, but ORPC requested and received a six-month extension

On March 3, 2013, the permittee filed a request for a successive preliminary permit for the East Foreland Tidal Energy Project.  The Commission granted a successive preliminary permit on June 16, 2014, describing a project with a combined capacity of no more than 5 megawatts.  Study and reporting activities continued.

But on December 11, 2015, the permittee filed a request for acceptance of its surrender of the East Foreland Tidal Energy Project's preliminary permit.  In that request, the permittee described its "significant progress in evaluating the feasibility of a tidal energy project at East Foreland, Alaska, over the past several years."

Yet the surrender request also described the headwinds that stalled the project:
Nonetheless, the strength of the conventional energy market in Alaska precludes timely integration of new technology, like tidal energy systems, and advancement of the Project at the pace established by the original Schedule of Activities. As a result, public and private funding sources have sought nearer-term market impact from their investments. This in turn has negatively affected ORPC’s ability to expeditiously gather site data during Alaska’s limited field season window and maintain pace with FERC milestones.
As a result, the request describes the permittee's decision to surrender the East Foreland tidal project's preliminary permit and "to continue our focus and dedication of resources towards technology optimization and development of near term market opportunities that are available to ORPC and its power system technology."

Wisconsin municipal hydro project license extended

Friday, March 25, 2016

Federal energy regulators have granted a Wisconsin city's request to extend its hydropower project license for five years to allow time for comprehensive river corridor planning.  The March 17 order was the result of a rehearing following a denial by agency staff.  It relies on a finding of "relatively unique facts," which include a stakeholder process that will inform the licensee's upcoming decision whether to continue an effort to seek a new license for the project, or to surrender the license.

At issue is the Federal Energy Regulatory Commission license held by the City of River Falls, Wisconsin, for the 375-kilowatt River Falls Project on the Kinnickinnic River.  The municipal hydro project's current 30-year license expires on August 31, 2018, and a relicensing process is already underway -- but the city is also considering alternatives including surrendering the license.  As a result, last year the City filed a request to extend the expiration date of its license by five years, until August 31, 2023.  The City asked for more time to work with stakeholders and the community to complete a comprehensive river corridor plan, and determine whether to relicense the project or surrender the license.

But on December 9, 2015, Commission staff issued an order denying the City’s request. The order noted that the Commission has granted extensions of license terms only in a few specific instances and under limited circumstances.  For example, the Commission has extended license terms to amortize the cost of substantial new improvements or substantial new environmental measures, to coordinate the expiration dates of licenses in the same river basin, or because of unique circumstances or circumstances beyond a licensee’s control -- factors it did not originally find applicable to this proceeding. 

The City filed a timely request for rehearing of this denial, which the Commission recently granted.  In its March 17, 2016 order extending the license term five years, the Commission noted that it "generally does not favor actions that delay the completion of licensing proceedings," and historically "has extended license terms only in very narrow circumstances."  But "given the relatively unique facts of this case", the Commission found that an extension of the license term was in the public interest.

The Commission cited a list of specific factors making this proceeding unique:
We find that the unique circumstances of this proceeding – the combination of unanimous stakeholder support for the extension, the tying of the extension to the development of a comprehensive river plan, and the fact that the licensee is a small municipality – demonstrate that a five year extension of the project license is in the public interest. All resource agencies and stakeholders support the City’s proposal to extend the license term in order to complete the corridor plan and decide whether to seek a subsequent license or surrender the project. This strong support and lack of any adverse comments demonstrates that the City is not requesting an extension of the license term merely to delay the preparation of a relicense application and to continue generating under more favorable terms.
It also noted an efficiency benefit from extending the license term, given the pending question: whether to relicense the project, or surrender the license:
Last, allowing the City time to determine if it should relicense or surrender prior to having to file a relicensing application is the most efficient use of resources. As a small municipality, the City may incur significant costs in preparing and processing a relicensing application despite the fact that it may later surrender its license.
The Commission's order extended the license term for the River Falls Hydroelectric Project to August 31, 2023.  Meanwhile, the comprehensive Kinnickinnic River corridor planning process will continue.  That process may inform the City's decision whether to relicense the River Falls project, surrender its license, or pursue some other alternative.

FERC rules off-grid micro-hydro needs no license

Thursday, March 24, 2016

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.

NY offshore wind zone announced

U.S. ocean energy regulators are advancing plans to lease sites off New York for potential commercial wind energy development.  The federal Bureau of Ocean Energy Management's designation of a Wind Energy Area could ultimately lead to the development of one or more offshore wind energy projects off Long Island.

While the U.S. still is not home to any operating commercial offshore wind projects, BOEM has issued 11 commercial wind energy leases off the Atlantic coast.  Leases awarded include two offshore New Jersey, two offshore Rhode Island-Massachusetts, another three offshore Massachusetts, one offshore Delaware, two offshore Maryland and one offshore Virginia.

In 2011, the New York Power Authority (NYPA) applied to BOEM for a commercial wind lease.  At that time, the public power authority proposed installing up to 194 wind turbines, each generating 3.6 megawatts, for a total project capacity of nearly 700 megawatts.

In January 2013, BOEM issued a Request for Interest to assess whether any other entities were parties interested in developing commercial wind facilities in the same area.  BOEM's review of the nominations of interest it received in response, including indications of interest from Fishermen’s Energy, LLC and Energy Management, Inc., led the agency to determine that there was competitive interest in the area.  As a result, BOEM initiated its competitive leasing process.

In 2014, BOEM published in the Federal Register a Call for Information and Nominations and a Notice of Intent to Prepare an Environmental Assessment, and has held stakeholder meetings.

The process took a step forward on March 16, 2016, when BOEM announced that it had completed the Area Identification process to delineate a Wind Energy Area (WEA) offshore New York. The wedge-shaped area covers approximately 127 square miles (81,130 acres, or 32,832 hectares), beginning about 11 nautical miles south of Long Beach, and extending about 26 nautical miles southeast along its longest portion.

Next steps in the offshore wind leasing process might include BOEM's publication of a Proposed Sale Notice for public comment, along with environmental assessment (EA) and agency consultations, followed by publication of a Final Sale Notice that announces the date, time, and specific conditions of the auction.  According to BOEM, its environmental review is expected to be completed later this year.

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.

Vanceboro Dam Storage Project relicensed

Tuesday, March 22, 2016

The Federal Energy Regulatory Commission has issued a new license to Woodland Pulp LLC to continue operating and maintaining the Vanceboro Dam Storage Project.  Located on the East Branch of the St. Croix River along the Canadian border in Washington County, Maine, the FERC-licensed project operates as a water storage facility that provides flood storage and flow releases for downstream hydroelectric generation.

The 469-foot-long, 16-foot-high Vanceboro Dam and 178,000 acre-foot project impoundment span the U.S.-Canada border.  The project is subject to the Boundary Waters Treaty of 1909 which established the International Joint Commission (IJC), a bi-national agency with the mission of preventing and resolving disputes between the United States and Canada over boundary waters.

The Vanceboro project is part of the larger St. Croix River headwater storage system.  This system also includes the Forest City Project, located about 24 miles upstream on the East Branch of the St. Croix, as well as the West Branch Project.  Water flows into the Vanceboro project’s impoundment from the Forest City Project. The project operates in a store-and-release mode whereby water is stored during periods of high flow to reduce downstream flooding, and then released during periods of lower flow to increase generation at the downstream hydroelectric projects.   Generation associated with these projects occurs at the unlicensed Grand Falls and Woodland hydroelectric projects located downstream on the St. Croix River.  Collectively, these storage projects provide flood storage and helps to regulate and augment flows, resulting in increased generation at Woodland Pulp’s downstream hydroelectric projects.

The Federal Energy Regulatory Commission issued an original license for the United States portion of the Vanceboro project on April 4, 1966.  The project is docketed as No. 2492.  That original license expired February 29, 2016, so two years earlier the licensee filed an application to the Commission for a new license to continue operating and maintaining the project.  In the interim, Woodland Pulp operated the project under an annual license pending resolution of its FERC relicensing process. 

On March 22, 2016, the FERC released an order issuing a new license for the Vanceboro Project. The new license authorizes no new capacity, and requires what the Commission characterized as "a moderate amount of new environmental mitigation measures."  These include a mandatory prescription issued under section 18 of the Federal Power Act, relating to new upstream fish passage facilities for American eel, river herring, and landlocked Atlantic salmon.

Given the fact that the Vanceboro Project is operated in coordination with the recently-relicensed West Branch Project No. 2618 and Forest City Project No. 2660 which each received 30-year license terms within the past 5 months, the Commission similarly relicensed the Vanceboro project for a 30-year license term to allow coordination of all three projects during any future relicensing.

Based on the large number of FERC-licensed hydropower projects whose licenses will expire in the near future, regulators expect to see an uptick in relicensing activity for hydroelectric projects and dams.

Washington tidal power license surrendered

Monday, March 21, 2016

U.S. hydropower regulators have accepted a Washington public utility district's application to surrender its license for an unconstructed tidal power project.

Public Utility District No. 1 of Snohomish County, Washington was the licensee for the Admiralty Inlet Pilot Tidal Project No. 12690.  The hydrokinetic energy project was to be located on the east side of Admiralty Inlet in Puget Sound, about 0.6 mile west of Whidbey Island. Project works were to consist of two 300-kilowatt OpenHydro tidal turbines, each mounted on a triangular subsea base, adaptable monitoring devices, trunk cables extending from each turbine to an onshore cable termination vault, and transformers and other facilities connecting to Puget Sound Energy’s electrical distribution system.

The Federal Energy Regulatory Commission issued a minor, pilot project license for the Admiralty Island project on March 20, 2014, enabling construction, operation, and maintenance of the project for a period of ten years.

But in September 2014, the licensee was notified that it would not receive additional funding to proceed with the development of the project. Unable to locate alternative funding sources, the licensee determined that the project was no longer financially feasible. The licensee therefore requested to surrender its license.

On December 4, 2015, the licensee filed an application to surrender its license. Two entities filed motions to intervene in support of the license surrender.

On March 21, 2016, the Commission issued its order accepting the Admiralty Inlet tidal project's license surrender. In that order, the Commission noted that no construction or ground-disturbing activity has occurred, that the project site remains unaltered, and that surrendering the license would not affect any environmental resources.  The Commission therefore approved the licensee’s application to surrender its license without condition.

As a result of the order, the license for the proposed Admiralty Inlet Pilot Tidal Project No. 12690 is surrendered, effective at the close of business on March 21, 2016.  The site could still be developed as a tidal power resource, if a future application for development is granted.

Massachusetts net metering expansion bills

As Massachusetts solar energy legislation seems stalled over debate on the value of solar renewable energy credits, 100 state legislators have written to the Massachusetts House of Representatives leadership calling for "a bill to raise net metering caps as expeditiously as possible."  Governor Baker, the state House and Senate have each agreed to expand net metering programs, but legislation has yet to be fully enacted due to a lack of agreement over the separate SREC issue.

Solar panels on a rooftop in Massachusetts.

Massachusetts solar energy policy is at an inflection point, as the state's two most significant solar photovoltaic offerings -- net metering and the Department of Energy Resources SREC II program -- reach prescribed limits.

Current law caps public sector net metering at 5% of a distribution company's historical peak load, and private sector net metering at 4%.  Last year, Governor Charlie Baker and legislators agreed to increase each of these caps by another 2% of load. The Baker administration described An Act relative to a long-term, sustainable solar industry as maintaining:
strong support for solar generation in the Commonwealth by raising the private and public net metering caps two percent each, to six and seven percent, respectively. The enhancement of cap space represents a 50% increase for public entities, and a 40% increase for private entities, in the allowable amount of solar energy available for net metering credits. This increase will provide immediate support for projects being developed in service territories where the caps have already been reached, and provides the Department of Public Utilities with the authority to raise the caps further, as needed in the future.
In the last legislative session, the Massachusetts House and Senate each passed a similar bill expanding net metering.  But because these bills differed on the reimbursement rate for solar renewable energy credits (SRECs), a conference committee must now try to find agreement between the versions if the concept is to advance. 

In an apparent attempt to prompt action from the conference committee, 100 state legislators signed a March 14, 2016, letter calling for a floor vote on a bill at the earliest opportunity.  The legislators described net metering credits as "compensation for the value provided by solar generation exported to the grid."  They articulated a pro-consumer net metering policy:
In our view, a strong net metering policy, at a minimum, calls for maintaining retail net metering credit value for preferred classes of projects, such as (1) community shared solar, (2) projects that serve low income housing and low-income ratepayers and (3) municipalities until an official, publicly scrutinized analysis of costs and benefits has been completed. In addition, we ask the Conference Committee to ensure grandfathering of existing systems. We also are in favor of the inclusion of new or expanded programs to achieve solar equity for low-income residents.
The legislators noted increased urgency given the filling up of the SREC II program.

The bills -- H.3854 and S.2058 -- are now before the Conference Committee.

Maine community solar farms

Friday, March 18, 2016

As the Maine legislature considers a bill to change the state's solar energy laws, opportunities for customers to participate in community solar farms are drawing interest.  As a result of this interest, some of the legal structures within which Maine community solar projects operate may change.

Community solar farms offer one model for connecting electricity consumers with solar power.  While there are various definitions of what qualifies a project as "community solar", most concepts feature a solar-electric system that provides power or financial benefit to, or is owned by, multiple community members.  This shared ownership, or shared benefit, is key to the community renewable energy model.

The Solar Energy Industries Association notes 25 states with at least one community solar project on-line, with 91 projects and 102 cumulative megawatts installed as of early 2016.  According to the National Renewable Energy Laboratory, interest in the community solar segment flows from "the recognition that the on-site solar market comprises only one part of the total market for solar energy."  Renters, those with shaded or otherwise unsuitable roofs, or anyone choosing not to install a residential system at home might prefer to invest in an off-site, shared ownership solar project.

State laws or regulations typically shape how customers can participate in community solar projects.  For example, Maine's current community solar model relies on the state's shared ownership net energy billing regulations. The Maine Public Utilities Commission rules governing "net energy billing" require investor-owned transmission and distribution utilities to offer net energy billing to any customer of a transmission and distribution utility that owns or has the legal rights to energy generated using an eligible facility.

The current Maine rules allow up to 10 customer accounts to be netted against a commonly-owned eligible generating facility located in the same utility service territory.  These accounts must belong to "shared ownership customers" -- customers that have an ownership interest (or legally enforceable rights and obligations) in the generating facility.  Participating customers must have joint responsibility for the costs of the shared ownership facility, as well as the rights to the benefits of the project's output in proportion to the cost responsibilities.  The local public utility will allocate the project's generation output among the participants, along with any banked credits, based on each customer's ownership interest in the project. 

Under these shared ownership net metering regulations, a solar project in South Paris developed in 2014 became Maine's first shared ownership community solar farm, and a project in Edgecomb became Maine's second operating community solar farm in 2015.  Other community solar projects are under development.

But when community solar projects rely on state laws, they may be affected by changes in law.  The Maine legislature is now considering a bill that would change Maine's solar energy law.  LD 1649 would largely replace a billing treatment called net metering with a series of long-term contracts and utility procurement orders.  It would establish a procurement target for large-scale community solar distributed generation resources of 45 megawatts by 2022.  Under this model, project sponsors would propose projects (up to 5 megawatts each) and could bid for long-term contracts to sell the project output to the local utility.  Project sponsors would recruit "subscribers" to take proportional interests in the resource, with each subscription sized to represent at least one kilowatt of the resource's generating capacity. Each subscriber would receive a bill credit based on his or her percentage interest in the project's production.

This model could enable more than 10 customer accounts to participate in a shared ownership solar project, which would address the limit on how many customers may participate in a community solar project under current regulations.  This could enable an expansion of shared-ownership solar, albeit under a model that relies on power sales to the local utility, instead of self-consumption or net metering.  But LD 1649 could also have an impact on those community solar projects already operating or under development, because it would effectively end net metering and offer only limited grandfathering of existing projects.

One alternative that could support community solar without impacting existing projects would be to expand the net metering paradigm, for example by allowing municipalities or groups of consumers to participate in larger projects that could offset more customer accounts.  For example, Massachusetts encourages municipal participation in solar projects by allowing governmental entities to net meter larger projects than individual customers.  Maine could adopt a similar model, expanding opportunities for municipally owned or shared ownership solar projects.

The Maine legislature's Joint Standing Committee on Energy, Utilities, and Technology held a public hearing on LD 1649 on March 16.  The committee is expected to give the bill further consideration this month.

NH net metering bills passed

Thursday, March 17, 2016

The New Hampshire legislature is acting to expand that state's net metering programs.  Now the question is how much: a 50% expansion, or a doubling?

New Hampshire law requires electric distribution utilities to offer eligible customer-generators a standard tariff for net energy metering. Solar panels are the most commonly net metered type of generation, but other technologies are also used.  Net metering under these tariffs is available "on a first-come, first-served basis within each electric utility service area" until each utility hits its specific cap on net metered capacity.  Under existing law, each utility's cap is effectively its share of a statewide program cap of 50 megawatts.

On January 20, 2016, utility Eversource announced it had reached its cap, and that it would place new projects going forward on a wait list.  But New Hampshire is home to significant interest in expanding net metering.  In the same announcement, Eversource described its work with the state legislature "to enact an expansion to the net metering program."  As the utility said, "Such an expansion would alleviate much of the uncertainty being faced by customers and developers, and would provide time for stakeholders to investigate all of the various costs and benefits of distributed generation and to provide for a sustainable evolution of the net metering program."

Meanwhile, Eversource also indicated a request that state regulators "develop a more permanent solution to the challenge of fairly compensating developers of new distributed generation in a manner that does not shift costs to other customers."

In February, the New Hampshire Senate voted to increase the net metering cap from 50 megawatts to 75 megawatts.  That bill, S.B.333, also directed the New Hampshire Public Utilities Commission to develop a net metering tariff for all generation above the 75 megawatt cap.

This month the New Hampshire House passed H.B.1116, a bill that would double the cap, to 100 megawatts.

Under New Hampshire legislative process, these two bills must be reconciled before a proposal can be sent to Governor Maggie Hassan.  But she has expressed strong support for reconciling the bills and expanding net metering:
Lifting the cap on net metering is essential to the continued success of New Hampshire’s solar industry, and I applaud the House for its bipartisan vote to pass this critical measure. The Senate has already supported this legislation, and I urge them to concur with the version passed by the House and send this bill to my desk as quickly as possible so that we can lift the cap on net metering.
The New Hampshire House and Senate now have the opportunity to reconcile the bills and present them to Governor Hassan for her signature.  Assuming this happens, New Hampshire will significantly expand its net metering program in the near term.

FERC denies Oregon LNG project applications

Tuesday, March 15, 2016

U.S. energy regulators have denied applications to site, construct, and operate the proposed Jordan Cove liquefied natural gas (LNG) export terminal, an associated pipeline and related facilities slated for development in Oregon.

The Jordan Cove LNG Terminal and the Pacific Connector Pipeline were proposed as two segments of a single, integrated project.  According to the FERC record, the applicants designed the facilities to enable the production of up to 6.8 million metric tons per annum (MMTPA) of LNG, using a feed of approximately 1.04 billion standard cubic feet per day (Bcf/d) of natural gas, for export to international or domestic markets in the non-contiguous United States.  The proposed pipeline would carry natural gas to the LNG terminal, for liquefaction, storage in cryogenic tanks, and loading onto ocean-going vessels.

Under U.S. federal law, the Federal Energy Regulatory Commission exercises permitting authority over several types of natural gas infrastructure, including LNG terminals and interstate pipelines.  In 2013, Jordan Cove Energy Project, L.P. applied under section 3 of the Natural Gas Act (NGA) and Parts 153 and 380 of the Commission’s regulations to site, construct, and operate the LNG terminal.  Several weeks later, Pacific Connector Gas Pipeline, LP applied under NGA section 7(c) and Part 157 of the Commission’s regulations for a certificate of public convenience and necessity to construct and operate an approximately 232-mile-long, 36-inch-diameter interstate natural gas pipeline running to the Jordan Cove LNG Terminal.

Over the next few years, Commission staff engaged in a back-and-forth with the applicants over the status of liquefaction contracts for the LNG terminal and precedent agreements for pipeline capacity.  The Sierra Club and others intervened and filed protests.  Concerns stated included environmental issues and landowner complaints, as well as an alleged lack of need for the projects.  Meanwhile the Commission issued the project a generally favorable environmental assessment.

The Commission ultimately denied the applications on March 11, 2016.  In its order denying the applications, the Commission cited its Certificate Policy Statement as providing "guidance for evaluating proposals to certificate new construction."  In the Commission's words:
The Certificate Policy Statement establishes criteria for determining whether there is a need for a proposed project and whether the proposed project will serve the public interest. The Certificate Policy Statement explains that in deciding whether to authorize the construction of major new pipeline facilities, the Commission balances the public benefits against the potential adverse consequences. The Commission’s goal is to give appropriate consideration to the enhancement of competitive transportation alternatives, the possibility of overbuilding, subsidization by existing customers, the applicant’s responsibility for unsubscribed capacity, the avoidance of unnecessary disruptions of the environment, and the unneeded exercise of eminent domain in evaluating new pipeline construction. 
The threshold requirement for pipelines proposing new projects under this policy is that the pipeline must be prepared to financially support the project without relying on subsidization from its existing customers.  In this case, the Commission found that Pacific Connector satisfies the threshold "no subsidization" requirement of the Certificate Policy Statement because it is a new natural gas company and does not have existing customers. 

Next, the Commission determine whether the applicant has made efforts to eliminate or minimize any adverse effects the project might have on the applicant’s existing customers, existing pipelines in the market and their captive customers, or landowners and communities affected by the route of the new pipeline. If these interest groups face residual adverse effects after efforts have been made to minimize them, the Commission essentially performs an economic balancing test on the evidence of public benefits to be achieved as compared to the residual adverse effects. Only when the benefits outweigh the adverse effects on economic interests will the Commission proceed to complete the environmental analysis where other interests are considered.

The benefits test proved problematic for the Pacific Connector pipeline.  The Commission found no adverse impact to existing customers, existing pipelines in the market or their captive customers.  But the Commission noted the landowner concerns, and a lack of evidence that the applicant had obtained any easement or right-of-way agreements for the necessary use of private lands.  In the Commission's view, these concerns must be weighed against the benefits to be gained from the project.

But the Commission found that "Pacific Connector has presented little or no evidence of need for the Pacific Connector Pipeline."  The Commission noted that the pipeline applicant had "neither entered into any precedent agreements for its project, nor conducted an open season, which might (or might not) have resulted in “expressions of interest” the company could have claimed as indicia of demand." According to the Commission, the applicant offered only "generalized allegations of need."  These did include the fact that Jordan Cove received U.S. Department of Energy authorization for export of LNG to free trade agreement and non-free trade agreement nations as "consistent with the public interest."  But the FERC noted that this DOE authorization for LNG was pursuant to different statutes, and moreover did not apply to the pipeline

The Commission noted that it "has not previously found a proposed pipeline to be required by the public convenience and necessity under NGA section 7 on the basis of a DOE finding under NGA section 3 that the importation or exportation of the commodity natural gas by an entity proposing to use the services of an associated LNG facility is consistent with the public interest."  As a result, the Commission found that "the generalized allegations of need proffered by Pacific Connector do not outweigh the potential for adverse impact on landowners and communities." Because the record did not support a finding that the public benefits of the Pacific Connector Pipeline outweigh the adverse effects on landowners, the Commission denied Pacific Connector’s request for certificate authority to construct and operate its project.

Turning next to the LNG terminal, the Commission noted that the Pacific Connector Pipeline is the only proposed transportation path for natural gas to reach the Jordan Cove LNG Terminal, and that the Commission has not previously authorized LNG export terminal facilities without a known transportation source of natural gas. Because the Commission concluded that the record did not support a finding that the Jordan Cove LNG Terminal can operate to liquefy and export LNG absent the Pacific Connector Pipeline, the Commission instead found that authorizing its construction would be inconsistent with the public interest. Therefore, it also denied Jordan Cove’s request for authorization to site, construct and operate the Jordan Cove LNG Terminal.

Inflatable flashboards meet historic dam

Monday, March 14, 2016

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.

Maine solar legislation released

Wednesday, March 9, 2016

The Maine legislature has printed a bill whose enactment would reshape the state's solar energy laws.  The bill, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development, has been numbered as LD 1649.  It would replace a billing treatment called net metering with a series of long-term contracts and utility procurement orders.

Solar photovoltaic panels on the roof of Gallagher's Auto Parts, in Patten, Maine.

Under net metering or “net energy billing,” an electric utility invoices a customer with solar panels based on the difference between the customer's energy use and the solar project's output.  If the generator output exceeds monthly usage in any billing period, the customer earns kilowatt-hour credits that can be banked and netted against future usage.  The bipartisan non-governmental organization National Conference of State Legislatures has noted that "Net metering policies have facilitated the expansion of renewable energy through on-site generation, also known as distributed generation."

But a 2015 Maine legislative resolve directed the Public Utilities Commission to convene a stakeholder group to consider alternatives to net energy billing, largely in the hopes of helping more consumers connect with solar power.  As part of that case, the state's Office of Public Advocate proposed a structure where individual solar projects would enter into contracts to sell solar power to their local utility.  While stakeholders developed consensus around exploring the concept, there was not uniform agreement around whether it should immediately replace net metering, or whether the new concept should operate "side by side" with net metering for some test period.

The bill now printed as LD 1649 largely reflects the contract-based, solar standard buyer proposal.  It would direct the Public Utilities Commission to enter into twenty-year contracts for the procurement of 248 megawatts of solar energy between 2017 and 2022.  The bill allocates 60 megawatts (24%) to grid-scale solar distributed generation resources; 45 megawatts (19%) to large-scale community solar resources; 25 megawatts (10%) to commercial and industrial resources; and 118 (47%) megawatts to residential and small business resources.  This would represent a significant expansion of solar capacity in Maine compared to what has been developed to date.

Under LD 1649, customers could seek contracts to sell solar power to a standard buyer (the utility) at prices set by the Public Utilities Commission. The standard buyer's stated role is to purchase the output of these distributed generation resources, aggregate the portfolio of resources procured, and sell it into the relevant New England markets. 

Consumers with projects up to 250 kilowatts in capacity could have two options.  The first is to sell the project's entire output to the utility under a contract, and buy all the customer's electricity requirements back from the utility in a separate transaction.  This is sometimes described as a "buy-all, sell-all" structure.

The second option is to use onsite generation to first offset electric consumption, and sell any excess electricity.  This would allow hourly offsetting of onsite load, but would not allow customers to carry forward monthly credits for excess production that could be used to offset future load.  This differs from net metering under Maine's current regulations, which measure net energy use over an entire month billing period, and carry credits forward for up to 12 billing months.

This contracting structure would effectively replace net metering. No new customers could participate in net metering once the new rules take effect.  Those residential and small business customers who already net meter their loads against a distributed solar project would face a choice: either seek a long-term contract under the new program, or elect to net meter for 12 more years.    

The bill would also largely eliminate Maine's policy of virtual net metering, which has allowed customers to net meter load at one site against a solar project located elsewhere in the same utility's service territory.

As of late on March 9, LD 1649, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development, had not yet been referred to committee, nor a public hearing scheduled.

Wind, solar lead new generation in Jan. 2016

Wind and solar projects accounted for all new electric power generation placed in service in the U.S. in January 2016, according to a report by federal energy regulators.

The Federal Energy Regulatory Commission's Office of Energy Projects releases a monthly Energy Infrastructure Update.  These reports provide summary data and narrative highlights of energy infrastructure developments in the past month.  Energy Infrastructure Update reports typically cover natural gas, nonfederal hydropower, electric generation, and electric transmission.

The report for January 2016 shows that all tracked electric generation placed in service that month was powered by either wind or solar.  The report notes 5 wind projects placed in service in January 2016, with a total installed capacity of 468 megawatts. These projects are:
  • MidAmerican Energy Co.’s 153.4 MW Adams Wind Project in Adams County, Iowa
  • Fowler Ridge IV Wind Farm LLC’s 150 MW Amazon Wind Farm Expansion Project in Benton County, Indiana -- developed by Pattern Energy; power generated is sold to Amazon Web Services under long-term contract
  • Los Vientos Windpower IV LLC’s 110 MW Los Vientos Windpower Phase 2 Expansion Project in Starr County, Texas -- power generated is sold to Bryan Texas Utilities, Garland Power and Light, and Greenville Electric Utility System under long-term contract
  • Milo Wind Project LLC’s 50 MW Milo Wind Project in Roosevelt County, New Mexico -- power generated is sold to Southwestern Public Service Co. under long-term contract
  • Patriot Renewables LLC’s 4.5 MW Beaver Ridge Hill Wind Project in Waldo County, Maine
The report also covers 6 solar projects totaling 145 megawatts of installed capacity placed in service.  Notably, it does not include plants with nameplate capacity less than 1 megawatt, so most rooftop and distributed solar projects were excluded from this data set.

The January 2016 infrastructure update also notes that a battery storage project in Ohio has come online.  Willey Battery Utility LLC’s Willey Battery Storage Project in Hamilton County, Ohio is described as providing supply-demand balancing service for the frequency regulation market in the PJM region.  Under FERC Order No. 755, battery storage and other innovative technologies can be compensated for offering frequency regulation to the grid.

Complaint over FERC hydro project property transfers

Tuesday, March 8, 2016

What happens when the holder of a Federal Energy Regulatory Commission license for a hydropower project buys, sells, or transfers real estate that is part of the project?  A complaint recently filed with the Commission raises this question in relation to a hydropower project located in Montana.

At issue in the complaint is the North Willow Creek project, licensed by the FERC in 1985 as Project No. P-7804.  According to the complaint filed on February 16, 2016, by Pony Ranch, LLC, the run-of-the-river hydroelectric project is located mostly on private lands near the Tobacco Root Mountains in Madison County, Montana.  The complaint describes the project as consisting of a steel intake structure located on North Willow Creek, an 8,180-foot steel penstock, and a powerhouse containing a 400-kW generating unit, and a tailrace discharging project flows back into North Willow Creek.

According to the complainant, Pony Ranch owns much of the land where the project is sited, including the land where the intake structure and upper 2,800 feet of the penstock are located.  But the complaint alleges that the project licensee has "for more than two decades regularly bought and sold real property underlying the Project and within Project boundaries without either informing the Commission or seeking Commission permission for those transactions requiring FERC approval."

The complaint alleges at least six transactions or transfers of the parcel of real estate on which the project powerhouse and tailrace are located.  The complaint alleges that even the licensee's transfer of the Pony Ranch lands to its present owners -- who appear to be substantially the same people as the complainants -- was a license violation because no FERC approval was obtained nor notice given.

According to the complaint, these transfers violate several articles of the project's license which relate to project land rights.  These include Standard Article 5, which provides that "none of such properties shall be voluntarily sold, leased, transferred, abandoned, or otherwise disposed of without the prior written approval of the Commission."

The Commission has required reporting and authorization for outright sales of project lands, but also for divorce-related transfers of joint interests in a project license, other transfers of joint interests in FERC licenses, actions limiting access across property owned by nonlicensees where access is needed to assure access to project works, transfers that occur under the will of a deceased licensee, and involuntary transfers where project property or equipment is foreclosed to satisfy tax or mortgage debt.

The complaint asks the Commission to find that the licensee has abandoned the project and should surrender the license under the doctrine of implied surrender.  Under that doctrine, the Commission can infer a licensee's intent to abandon a project from its action or inaction..

On March 7, 2016, the Commission's Office of Energy Projects sent the licensee a letter describing the complaint as a "non-compliance allegation" and requesting a response.  That letter notes that consistent with Commission practice with respect to allegations of non-compliance by hydropower licensees, the Pony Ranch complaint has been referred to the Commission’s Office of Energy Projects, Division of Hydropower Administration and Compliance.  That division is charged with ensuring compliance.  The letter requests a response from the licensee within 30 days.

ISO New England Regional Electricity Outlook 2016

Wednesday, March 2, 2016

The New England regional power system is in a state of major transformation, according to regional grid operator ISO New England, Inc.'s 2016 Regional Electric Outlook.

ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England.  In this role, the ISO plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.

The 2016 Regional Electric Outlook report is the latest annual installment of the grid operator's update on the state of the grid and the ISO’s efforts to ensure reliable electricity and to improve services and performance.  This year's report describes the New England grid administrator as "in the vanguard of a major transformation in how electricity is produced and delivered in the US."

Three waves of change -- natural gas, renewable energy and demand resources, and distributed generation -- are affecting New England's fleet of power resources, according to the report:
Natural-gas-fired generation has displaced older coal, oil, and nuclear plants. Weather-dependent renewable power resources and energy-efficiency measures are multiplying. On the horizon comes a “hybrid grid”—a combination of large power resources supplying the regional system while smaller ones directly supply consumer sites.
According to the report, coal, oil, and nuclear resources are retiring; it noted that resources representing about 30% of regional capacity have committed to cease operation or are at risk of retirement by 2020.  Most power plants planned to replace them will rely in part or in whole on natural gas or renewable generation.  The report notes:
Our region's natural-gas-fired power resources are among the newest, most efficient, and lowest-emitting plants in the country. When their access to low-priced gas from the Marcellus shale is unrestricted, New England has reliable, low-priced electricity.
The report also states that "wintertime access to natural gas has grown tight over recent years because the regional fuel transportation network has not kept up with demand from both generation and heating sectors."  As a result of pipeline constraints, the ISO notes "grid reliability challenges, emission increases during winter, and spikes in wholesale electricity prices."

The report also describes the ISO's tactics for managing the reliability risks associated with these shifts in the region's energy mix, including stronger "pay for performance" financial incentives for power resources to perform as required.  It cites various ISO studies indicating "that, ultimately improving the natural-gas-delivery infrastructure in New England" will best address reliability concerns, price spikes, and unnecessary emission impacts from oil and coal units during winter.

The report, along with previous years' reports, are available on the ISO's website.

MA solar policy faces change

Tuesday, March 1, 2016

Massachusetts solar energy faces uncertainty, as the two state policies most supportive of solar photovoltaic project development -- a solar project's right to produce solar renewable energy certificates and a customer's right to net meter -- reach their end.  With the Massachusetts SREC II and net metering programs ending, new solar energy projects face diminished and uncertain financial incentives.

Massachusetts has made a strong commitment to solar energy.  The Commonwealth met its original goal of 250 megawatts of solar power installations four years early, then set a new goal was set of 1,600 MW by 2020. As of May 2015, over 841 megawatts of solar capacity had been installed in Massachusetts.

As the Solar Energy Industries Association has noted, "The Massachusetts market is driven by net metering, a renewable portfolio standard with a solar goal along with an accompanying SREC market."  The Massachusetts Clean Energy Center seemingly agrees, listing net metering and SRECs as two key "production-based incentives and benefits" for solar system owners.
The Massachusetts Department of Energy Resources ran its Solar Carve-Out II, or SREC II, program from April 25, 2014 to February 5, 2016.  The DOER described the program as designed to support the market until 1,600 megawatts of photovoltaic capacity has been installed statewide.

But that limit has been reached, counting the 653.8 megawatts of PV capacity installed under the Department's SREC I program (which ran from 2010-2014), additional capacity installed under SREC II, and over 600 megawatts of additional projects having reservations filed for the remaining SREC II program capacity.  The practical effect is that new projects will not likely be able to participate in the SREC II program.  This removes a key incentive for Massachusetts solar development.

The other Massachusetts solar promotional program reaching its limit is the Commonwealth's net metering program.  Under net metering, customers of certain electric distribution companies who generate their own electricity may offset their electricity usage.  Effectively, the retail meter spins forward when the customer uses electricity from the utility grid, and it spins backward when the customer generates excess electricity.

Massachusetts law requires each distribution company to maintain net metering caps equal to 4% of the company’s highest historical peak load for private net metering customers, and another 5% for municipal or public entities.  Once an electric distribution company fills its net metering caps, it can no longer allow customers to take service under its net metering tariff.  National Grid has reached its cap in its service territory, with other service territories close to full.  If net metering is not available to Massachusetts customers, it will remove another incentive that has supported significant growth in the state's solar sector in recent years.

In 2015, several pieces of legislation were proposed to lift the net metering caps, but no bill respecting net metering passed both the House and Senate.  The House measure contained provisions including a shift from retail rate compensation for net metering to a wholesale rate for most systems after the 1,600 megawatt target is met, authority for utilities to impose a minimum bill charge on net metering customers after the target is reached, and increased opportunity for utility ownership of solar.  A 2014 effort to lift net metering caps and reform solar policy similarly died.

But with significant interest in solar, from citizens and communities to the Commonwealth, U.S., and even the United Nations following the 2015 Paris Climate Agreement, how will Massachusetts react to the end of its SREC II and net metering programs?  Will a third effort to increase net metering work?  What will the Department of Energy Resources offer as a successor to the Solar Carve-out II SREC program?