LIPA Deepwater offshore wind decision delayed

Tuesday, July 26, 2016

Long Island Power Authority has postponed a meeting of its trustees at which an offshore wind project was expected to be up for approval, after a state energy agency asked for delay to align the process with the expected release of new state energy policy documents.

Long Island Power Authority, or LIPA, is a municipal subdivision of the State of New York. It owns the retail electric transmission and distribution system (T&D) on Long Island, and oversees electric service provided by PSEG Long Island over those assets.

In 2015, PSEG Long Island issued a request for proposals for local resources to serve the South Fork areas of Long Island.  In response, offshore wind developer Deepwater Wind has proposed to supply capacity and renewable energy from the 90 megawatt, 15-turbine Deepwater ONE – South Fork offshore wind project, along with 15 megawatts of onshore lithium ion battery storage.

The Deepwater ONE - South Fork project would be developed in federal waters over the outer continental shelf; in July 2013, Deepwater won the rights to lease sites through the federal Bureau of Ocean Energy Management's first-ever competitive lease auction for offshore wind.  Project power would be delivered to LIPA’s existing substation in East Hampton, so the proposal could serve growing load on the South Fork without adding new transmission lines or fossil power plants.

As reported by the East Hampton Star earlier this month, LIPA has formally recommended to its board that it approve Deepwater's proposal.

But on July 19, 2016, LIPA issued a media advisory that its board meeting scheduled for the next day would be postponed.  The press release stated that LIPA
received a request late this evening by its partner agency NYSERDA (New York State Energy and Research Development Authority) to postpone tomorrow’s consideration of an off-shore wind farm to align the proposed Long Island project with the State’s off-shore wind master plan and the State’s Clean Energy Standard, both of which are scheduled to be released in the next several weeks.
NYSERDA is a public benefit corporation whose mission is to "Advance innovative energy solutions in ways that improve New York's economy and environment."

Governor Cuomo announced the creation of an Offshore Wind Master Plan in his 2016 State of the State address.  It followed his December 2, 2015 decision to direct the state Department of Public Service to design an enact a Clean Energy Standard mandating that 50 percent of all electricity consumed in New York in 2030 come from renewable sources.  Both the offshore wind master plan and the Clean Energy Standard remain under development by the administration.

In light of NYSERDA's request, LIPA postponed its July 20 board meeting.  LIPA's statement states an expectation "to reschedule the meeting after the release of the NYSERDA off-shore wind blueprint."  It closes with a reassurance that, "LIPA remains committed to its renewable energy goals and meeting the energy needs of the South Fork."  Meanwhile, for now Deepwater's proposal remains pending.

Alta, snowmaking pipes and conduit hydro power

Thursday, July 14, 2016

Federal energy regulators have issued Alta Ski Area a written determination that its proposed micro-hydropower project will not be required to be licensed under the Federal Power Act.  If developed, Alta's project would be one of the first to generate electricity from a snowmaking water supply pipeline.

Most grid-connected hydropower projects in the U.S. fall under the Federal Power Act, and generally require a license or exemption from the Federal Energy Regulatory Commission.  The process of securing an original license or exemption for a new project can take years and have high costs.  But under a 2013 law, some so-called "conduit" hydro projects -- using pipelines and other existing manmade water conveyances -- can be developed and operated without a license or exemption.  The Hydropower Regulatory Efficiency Act of 2013 defined criteria for the Commission to declare a project to be a "qualifying conduit hydropower facility," and provided that such facilities are not required to be licensed or exempted from licensing under the Federal Power Act.  Key factors include the use of a non-federally owned, manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity.  If the Commission determines that a project qualifies, it can be built and maintained without a FERC license or exemption.

Under the Commission's process for evaluating conduit hydro projects, the developer must file a notice of intent to construct a qualifying conduit hydropower facility.  If the developer's filing demonstrates that the project meets the statutory criteria, the Commission will issue a notice of its preliminary decision that the project qualifies.  Following a 45-day period within which others may contest the determination, assuming no adverse facts are uncovered, the Commission issues a letter constituting its written determination that the proposed project meets the qualifying conduit hydropower facility criteria.

Alta's course before the Federal Energy Regulatory Commission followed this trail.  In May 2016, Alta filed its notice of intent to construct the Alta Micro-Hydro Project.  That notice and a supplemental filing described a project to tap the existing underground 6-inch-diameter snowmaking water supply pipeline delivering water from Cecret Lake to the Wildcat Pump House.  Parallel to that pipeline, Alta would add a new powerhouse with a 75-kilowatt turbine/generating unit.  Later that month, Commission staff issued a public notice that preliminarily determined that the project met the statutory criteria.  After the 45-day contest period, during which no interventions or comments were filed, in July the Commission issued Alta a written determination that the Alta Micro-Hydro Project meets the qualifying criteria under section 30(a) of the Federal Power Act, and is not required to be licensed under Part I of that law.

The Commission's letter reminds Alta that qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations.  But the ability to develop a conduit hydropower project without requiring a license from the FERC will ease the project's regulatory path.  So far, most projects that have qualified for the conduit hydropower program have been proposed by water districts.  But as ski areas seek to align their operations with sustainability goals, adding low-impact renewable electricity generation may make sense for some.  If Alta's micro-hydro project is successful, other ski areas with existing snowmaking or other water infrastructure over a sufficient vertical drop may follow suit by developing their own conduit hydropower projects.

Maine tidal project preliminary permit issued

Tuesday, July 12, 2016

A tidal energy developer has been granted a preliminary permit to study a proposed project in Western Passage, near the city of Eastport, Maine.

Under the Federal Power Act, most grid-connected tidal power projects require licensing by the Federal Energy Regulatory Commission.  Section 4(f) of the Federal Power Act authorizes the Commission  to issue preliminary permits to allow prospective applicants for a hydropower license time to secure the data and perform the acts required to prepare a license application.  A preliminary permit preserves the holder's right to have first priority in applying for a license for the project being studied.

On December 4, 2015, ORPC Maine, LLC applied for a preliminary permit to study the feasibility of the proposed Western Passage Tidal Energy Project No. 14743.  As described in that application, the project would include fifteen of ORPC's proprietary 500-kilowatt hydrokinetic marine turbine-generator units for a combined capacity of 7.5 megawatts, along with anchoring and mooring systems, and transmission lines running ashore to an existing distribution line.  The materials describe an estimated average annual generation of 2.6 to 3.53 gigawatt-hours.

The Commission granted that preliminary permit by an order dated July 13, 2016.  In that order, the Commission addressed comments filed by the Maine Department of Environmental Protection, the U.S. Department of the Interior, the Passamaquoddy Tribe, and an individual.

In its comments, the tribe raised concerns over what the Commission calls "site banking".  As described by the Commission, the essence of its policy against site banking is that "an entity that is unwilling or unable to develop a site should not be permitted to maintain the exclusive right to develop it."  In some cases, the Commission invokes its policy against site banking to deny applications for successive preliminary permits.

The tribe questioned whether ORPC Maine should be granted a new preliminary permit when it has held two prior preliminary permits for the site of the proposed Western Passage Project -- the first issued in 2007, and a successive permit in 2011 -- without ever filing a development application. 

But in ORPC's case, the Commission noted that the project site has been unencumbered by a permit since ORPC's most recent permit expired in 2013, and that no other entity has filed a preliminary permit or development application for the site.  The Commission concluded that "a sufficient amount of time has passed for any other entity interested in developing the Western Passage Project site to have filed a preliminary permit or development application for the site and none has done so. Consequently, issuing a permit at this time to ORPC Maine for this site would not contribute to site banking."

ISONE External Market Monitor report 2015

Monday, July 11, 2016

A report by the New England electricity market's external monitor has found that "the markets performed competitively in 2015."

ISO New England operates wholesale electricity markets covering most of New England.  It employs two independent market monitors -- one internal to ISO-NE, one a hired external consultant -- to regularly review, analyze, and report on market results, and offer recommendations on market improvements.

Potomac Economics serves as the External Market Monitor for ISO-NE. In this role, it is charged with evaluating the competitive performance, design, and operation of the wholesale electricity markets operated by ISO-NE.  Last month, the external market monitor released its "2015 Assessment of the ISO New England Electricity Markets" (102-page PDF), presenting its perspective on the New England electricity markets.

Among other findings, the report notes that energy market trends "have been dominated by reductions in fuel prices over the last two years.  In particular, from 2014 to 2015:
  • Natural gas prices declined more than 40 percent, falling to multi -year lows in mid -2015 largely because of higher shale production from the Marcellus and Utica regions; and
  • Fuel oil prices fell by more than 35 percent because of increased global supply, and world liquefied natural gas (LNG) prices have fallen similarly. These reductions helped limit the increase in natural gas prices during tight gas supply conditions in the winter. 
The report notes that as a result, energy prices dropped 35 percent over the same time.  According to the external market monitor, "The strong relationship between energy and natural gas prices indicated by these results is expected in a well-functioning, competitive market. Natural gas-fired resources were the marginal source of supply in most intervals in 2015 and competition compels suppliers submit offers consistent with their marginal costs, most of which are resources’ fuel costs."

ISO New England's internal market monitor released its 2015 Annual Markets Report earlier this year.  That report similarly found that overall, "the ISO New England capacity, energy, and ancillary service markets performed well in 2015."

Maine biomass commission to meet

Thursday, July 7, 2016

A commission charged by the Maine legislature to study the state's biomass energy industry will hold its first meeting next month.  The study committee's work will result in a report to the legislature, and could include recommended changes to state law.

The Maine State House.

At the end of its 2016 session, the Maine legislature enacted a resolve establishing the Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry.  The resolve directed the commission to:
1. Review and evaluate the economic, environmental and energy benefits of Maine's biomass resources, as well as public policy and economic proposals to create and maintain a sustainable future for the Maine biomass industry;
2. Consider the interconnection of economic markets for biomass and forest products and the energy policy of the State;
3. Consider whether the environmental, economic and energy benefits of biomass support updating the State's energy policy to strengthen and increase the role that biomass and the forest products industry play throughout the State;
4. Consider the costs of implementing any recommendations and the effect of leaving current policies in place; and
5. Examine any other issues to further the purposes of the study. 
The Maine biomass commission has now been formed, and has scheduled its first meeting for August 2, 2016.  As prescribed by the resolve, its membership includes a mix of legislators and others interested in the state's biomass energy policy.

The resolve directed the biomass study commission to submit a report and any suggested implementing legislation for committee consideration by December 6, 2016.

Biomass was a hot topic in the past legislative session.  On a separate track, this spring the Maine legislature enacted a law establishing a long-term contracting program for biomass-fueled power plants.  The Maine Public Utilities Commission has issued a request for proposals under that program, with contract proposals due on or before July 29, 2016.

FERC Order 826 increases penalty power

Tuesday, July 5, 2016

Acting under a 2015 law, the Federal Energy Regulatory Commission has released an interim final rule increasing the maximum civil monetary penalties that it can assess for violations of statutes, rules, and orders within the Commission’ s jurisdiction.  FERC Order No. 826 effectively raises the Commission's maximum penalty authority by nearly 20 percent, to $1,193,970.

FERC, along with some other federal agencies, is authorized by statute to impose civil monetary penalties for violations of Federal law and regulations.  In some cases, the maximum penalty is set and specified in dollars.  But the 1990 enactment by Congress of the Federal Civil Penalties Inflation Adjustment Act established a mechanism to allow for regular adjustment for inflation of civil monetary penalties, primarily to support enforcement and maintain the deterrent effect of civil monetary penalties.

Congress revamped that mechanism last year by enacting the Federal Civil Penalties Inflation Adjustment Act Improvements Act (FCPIA) of 2015.  The FCPIA of 2015 amends the 1990 law, requiring federal agencies to adjust the level of civil monetary penalties through rulemaking to reflect inflation in order to maintain the deterrent effect on regulated entities.

Specifically, the 2015 adjustment act requires the head of each federal agency to issue an “interim final rule” by July 1, 2016 adjusting for inflation each civil monetary penalty provided by law within the agency’s jurisdiction.  The process is driven by changes in the U.S. Department of Labor’s Consumer Price Index for all-urban consumers (CPI-U), relative to the baseline used the last time the penalties were set.  After a "catch-up" round when the penalties are initially adjusted under the 2015 law, the law requires agencies to update penalty amounts on an annual basis every January 15.

In response, on June 29, the Federal Energy Regulatory Commission issued Order No. 826.  In Order 826, the FERC noted the previous maximum civil monetary penalty authority of up to $1,000,000 per violation, per day under section 316A(b) of the Federal Power Act.  The Commission then found that inflation during the relevant period -- the ten years from October 2005 through October 2015 -- inflation was 19.397 percent.  Accordingly, the Commission increased the Commission's maximum penalty authority to $1,193,970.

In Order No. 826, FERC also adjusted its maximum civil monetary penalties for other violations, including violations of Sections 31(c) and 315(a) of the Federal Power Act, Section 22 of the Natural Gas Act, and sections of the Natural Gas Policy Act of 1978 and the Interstate Commerce Act.

The regulation is effective upon its publication in the Federal Register.

NH net metering under review

Friday, July 1, 2016

New Hampshire utility regulators have paused their review of a utility’s proposed changes to rates for customers with solar and other distributed energy resources, pending a more holistic review of the state’s net metering policy. Interest now focuses on Docket DE 16-576, in which the Commission may develop new alternative net metering tariffs or other regulatory mechanisms applicable to customer-sited generation.

Under New Hampshire law, the net energy metering section of the Limited Electrical Energy Producers Act, each electric distribution utility must make standard tariffs providing for net energy metering available to eligible customer-generators in accordance Public Utilities Commission regulation.

On April 29, 2016, distribution company Unitil Energy Systems, Inc. (Unitil) filed a petition to the New Hampshire Public Utilities Commission seeking authority to, among other things, implement new permanent delivery rates for distribution service, beginning June 1, 2016. Among Unitil’s proposed changes was a new tariff schedule for Domestic Distributed Energy Resources, called Schedule DDER, applicable to certain residential customers with renewable distributed generation systems installed behind the retail meter. If adopted, it would change how Unitil’s customers may net meter solar panels and other eligible distributed generation.

Changes to net metering policy can be controversial.  Consumers and solar advocates typically support net metering as a key incentive for solar project development, even if it might undercompensate consumers relative to the value of solar.  But some utilities oppose net metering, arguing that it hurts their revenues or shifts costs to customers without solar panels.  Debate over the issue led the New Hampshire legislature to enact a net metering bill, House Bill 1116, earlier this year. Signed by Governor Hassan on May 2, 2016, House Bill 1116 amended several provisions of RSA 362-A:9.

Among the new statutory language is new paragraph XVI, requiring the Commission, within a ten month period, to initiate and conclude a proceeding to develop new alternative net metering tariffs, which may include other regulatory mechanisms and tariffs, taking into consideration a number of specified factors deemed relevant to such development. By Order of Notice issued on May 19, 2016, the Commission opened Docket DE 16-576 to conduct this holistic review of net metering.  That case remains ongoing.

Given the overlap between the holistic net metering case and Unitil’s proposed Schedule DDER, on June 9, the New Hampshire Public Utilities Commission issued an order suspending the investigation of, and staying any litigation regarding, Unitil’s proposed tariff schedule. In its June 9 order suspending the investigation, the Commission concluded that “it it would be inconsistent with the intent of HB 1116 and would represent an inefficient allocation of limited Staff, stakeholder, and Unitil ratepayer resources to address rate design proposals directly affecting net-metered customer-generators in this proceeding as well as in Docket DE 16-576.”

In the Commission’s words, it initiated Docket DE 16-576 based on the legislative mandate “to conduct a proceeding involving all regulated electric distribution utilities to develop new alternative net metering tariffs, which may include other regulatory mechanisms.” Noting that Schedule DDER is effectively a net metering tariff, the Commission found that separately reviewing, evaluating, and litigating Schedule DDER in both the Unitil docket and Docket DE 16-576 would impose additional burdens on the limited resources of Staff and its consultant, as well as on those of other parties and stakeholders, and “could result in conflicting schedules, redundant discovery, and potentially inconsistent results in the separate proceedings.”

The Commission noted that under the HB 1116 amendments to the net metering law, “net metering will continue indefinitely and without limit, unless and until otherwise determined by the Commission in the proceeding we have opened as Docket DE 16-576… In effect, customer -generators will continue to participate in net metering under RSA 362-A:9 even in excess of the 100 megawatt “cap,” but those above this statutory limit ultimately will be subject to the new alternative net metering tariffs approved by the Commission in Docket DE 16-576.”

Accordingly, the Commission placed the suspension and stay of the Unitil case in effect until the completion of Docket DE 16-576.  The net metering review in that case remains pending, with a schedule set through the coming winter.

Hydro license transfers and fitness

Thursday, June 30, 2016

U.S. hydropower regulators have approved the transfer of the license for an Idaho hydroelectric project, despite an argument that the transferee is not fit to operate the project. At issue is the Smith Creek Project, No. 8436, located on Smith Creek in the Panhandle National Forest in Idaho.

The Federal Energy Regulatory Commission issued a 50-year license for the project in 1987, which was transferred to Eugene Water & Electric Board in 2000. Earlier this year, EWEB applied to the Commission for a transfer of the Smith Creek project license to Smith Creek Hydro, LLCAmerican Whitewater opposed the transfer, raising arguments including that Smith Creek did not meet the Commission's "fitness standard".

On June 23, 2016, the Commission issued an order approving the Smith Creek license transfer.  In that order, the Commission noted that while Section 8 of the Federal Power Act governs license transfers, it does not articulate a standard for approving a transfer application.  Under Commission precedent, a transfer may be approved on a showing that the transferee is qualified to hold the license and operate the project, and that a transfer is in the public interest.  According to the Commission, an applicant's fitness, including its prior performance as licensee, is a relevant factor to be considered in a licensing decision.  In performing a fitness inquiry, the Commission typically takes a broad look at conduct by affiliated entities: "The Commission does not separate the identities of partners and partnerships where matters of fitness to receive a license are concerned. In fact, the Commission has consistently examined the conduct of the persons controlling and directing licensees and exemptees in this context."

In the Smith Creek case, American Whitewater argued that "Smith Creek is unfit to hold a license based on compliance issues at the Power Creek Project No. 11243, the Cascade Creek Project No. 12495, and the unlicensed Electron Hydroelectric Project."  The group pointed to a fatality by avalanche during the Power Creek project construction, the fact that the Cascade Creek project was issued preliminary permits but was never licensed, and that litigation was pending relating to the alleged Endangered Species Act violations at the Electron project.

While the Commission does not list Smith Creek as a licensee on any of these projects, it did consider these allegations relating to entities now or formerly affiliated with Smith Creek.  But the Commission declined to find a lack of fitness of the transferee.  It distinguished the issues raised by American Whitewater, noted the transferee's responsiveness to Commission staff inquiries, and overall compliance with the Commission.  The Commission described denial of a license application on the ground of lack of fitness as "a strong sanction, particularly since the Commission has the means to secure license compliance, including civil penalties."  It therefore approved the Smith Creek license transfer.

Whitestone hydrokinetic license surrendered

Wednesday, June 29, 2016

Despite efforts to offer a streamlined regulatory path for some demonstration hydropower projects, earlier this year the holder of a hydrokinetic pilot project license for a project proposed for the Tanana River in Alaska surrendered its license due to an inability to find financing. The case of the Whitestone Poncelet River-In-Stream-Energy-Conversion (RISEC) Pilot Project No. 13305 illustrates the Federal Energy Regulatory Commission’s hydrokinetic pilot project licensing process, the difficulties of testing and developing new hydropower technologies, and how the Commission handles pilot license surrender.

Whitestone Power and Communications, an assumed name of the Whitestone Community Association, had proposed the project as a 100-kilowatt demonstration of its proprietary hydrokinetic prototype technology. It was to be located on the Tanana River at its confluence with the Delta River, about 90 miles southeast of Fairbanks. A Poncelet undershot waterwheel and generator unit mounted on a floating platform, seasonally installed and moored to a cliff. Power produced would be supplied to the Golden Valley Electric Association grid.

The Federal Energy Regulatory Commission granted WPC a five-year pilot project license on October 19, 2012. In processing WPC’s application, the Commission used a hydrokinetic pilot project licensing process derived from from its Integrated Licensing Process. According to the Commission, the hydrokinetic pilot project licensing process was designed “to meet the needs of entities, such as Whitestone, who are interested in testing new hydropower technologies while minimizing the risk of adverse environmental impacts.” The Commission describes the goal of the pilot licensing process as “to allow developers to test new hydrokinetic technologies, to determine appropriate sites for these technologies, and to confirm the technology’s environmental and other effects without compromising the Commission’s oversight of the projects and limiting agency and stakeholder input.”

As outlined in a white paper prepared by Commission staff, a hydrokinetic pilot project should be: (1) small; (2) short term; (3) located in environmentally nonsensitive areas; (4) removable and able to be shut down on short notice; (5) removed, with the site restored, before the end of the license term (unless a new license is granted); and (6) initiated by a draft application in a form sufficient to support environmental analysis. After finding the WPC project met these standards, the Commission issued it a license in 2012. Article 301 of the license required the licensee to commence construction of the project works within two years from license issuance, i.e., by October 19, 2014.

Despite winning a license, the project was never built. In 2014, WPC asked for and received a two-year extension of the start-of-construction deadline, “due to unforeseen setbacks in obtaining the necessary financing to begin construction.” But in that order, the Commission reminded the licensee that, pursuant to section 13 of the Federal Power Act, the deadline for starting construction may only be extended once, for a period not exceeding two additional years. Therefore, the Commission noted its inability to grant any further extensions of time for the commencement of project construction.

But in September 2015 WPC applied to the Commission for surrender of its license. In its surrender application, WPC stated that it was unable to obtain the funding necessary to construct the project and had not constructed any project facilities.

In April 2016, the Commission granted WPC's surrender application without condition, citing the facts that the licensee had not commenced construction and that the project site remained unaltered.

The Whitestone project was among the first to use the Commission’s hydrokinetic pilot project licensing process. But despite receiving expedited regulatory treatment in licensing, financing challenges led the licensee to surrender its license before the project could be constructed. Some other proposed hydrokinetic projects have been canceled or put on hold, following licensure; earlier this year, the Commission accepted license surrender for a Washington tidal power project licensed as a 10-year pilot project, after the public utility district proposing it found it economically infeasible. Another project -- an ocean wave energy farm off the Oregon coast -- surrendered its pilot license
 in 2014.

Edgartown's Muskeget tidal project faces questions

Tuesday, June 28, 2016

A municipal tidal power project proposed for the Massachusetts island of Martha's Vineyard faces federal deadlines if its licensing process is to continue.  The Muskeget Channel Tidal Energy Project, proposed by the Town of Edgartown, is seeking a pilot project license from the Federal Energy Regulatory Commission -- but faces questions from Commission staff.

On February 1, 2011, the Town of Edgartown filed, pursuant to the Commission’s pilot licensing procedures, a draft license application for the proposed Muskeget Channel Tidal Energy Project.  The project would feature an array of 14 marine hydrokinetic tidal turbines, with a commercial generating capacity of 5 megawatts or less.

But that license application remains incomplete.  On April 1, 2011, Commission staff issued a letter requesting that Edgartown provide additional information, including details about the proposed project and multiple plans, drawings, and reports.  Over the ensuing years, Edgartown filed some responsive information, but according to the Commission, Edgartown did not file the remaining information by the deadline or provide a schedule indicating when the information would be filed after the deadline was missed.

Over two years after the deadline, on April 21, 2016, Commission staff issued a letter requiring Edgartown to show cause, within 30 days, why Commission staff should not terminate the prefiling licensing process for the project.  According to the Commission, Edgartown did not respond, but Congressman William Keating asked the Commission to extend the show cause deadline until the Massachusetts Clean Energy Commission decides whether to award the project a grant.

In a June 2 letter, Commission staff directed Edgartown to, within 30 days, provide a schedule specifying when it will file with the Commission each of the outstanding items requested in Commission staff’s April 1, 2011 letter.  The letter says, "Upon receipt of this information, Commission staff will make a determination on how to proceed with the incomplete application for the Muskeget Channel Tidal Energy Project."  For now, the prelicensing process for the Muskeget tidal project remains pending.

BOEM Call for Hawaii offshore wind interest

Monday, June 27, 2016

U.S. ocean energy managers have asked for information to evaluate industry interest in leasing sites offshore Hawaii for commercial offshore wind development.

Under U.S. law, the Bureau of Ocean Energy Management (BOEM) is charged with managing energy activities on the federally controlled Outer Continental Shelf.  On June 22, Secretary of the Interior Sally Jewell announced that BOEM issued a Call for Information and Nominations for waters off Hawaii. The Call is designed to gauge the offshore wind industry's interest in acquiring commercial wind leases in two areas spanning approximately 485,000 acres of submerged lands in federal waters offshore Oahu. One parcel lies generally south of the island, while the other is to its northwest.

BOEM also published in the Federal Register a Notice of Intent (NOI) to Prepare an Environmental Assessment (EA) for the Hawaii Call area. The purpose of the NOI is to solicit public comment for determining issues and alternatives to be analyzed in the Environmental Assessment.

BOEM is also considering three unsolicited requests for site leases off Hawaii for floating offshore wind projects: two lease requests from AW Hawaii Wind, LLC (AWH), the AWH Oahu Northwest Project and the AWH Oahu South Project; and one from Progression Hawaii Offshore Wind, Inc. (Progression), the Progression South Coast of Oahu Project.

In other areas, BOEM has used Calls to shape the designation of Wind Energy Areas and ultimately the sale by competitive auction of leasing rights for commercial offshore wind development.  To date, BOEM’s offshore wind program has identified wind energy areas in federal waters off seven Atlantic states (including an area off New York designated in March) and awarded 11 commercial wind energy leases off that coast, including nine leases through competitive lease sales that generated about $16 million in winning bids.  Earlier this month, BOEM announced a proposed sale of leases for sites offshore New York.

FERC says Nicatous microhydro doesn't need license

Friday, June 24, 2016

Federal energy regulators have ruled that a micro-hydroelectric project proposed by a remote Maine sporting camp does not require licensing under the Federal Power Act. The Nicatous case illustrates one expedited regulatory path for off-grid micro-hydropower projects.

Nicatous Lake Lodge and Cabins, LLC has proposed the Nicatous Lodge Micro Hydroelectric Project. The one-kilowatt project would be located on Nicatous Stream in Maine, and would supply electricity to an off-grid sporting camp currently powered by a diesel generator.

The camp owner filed a Declaration of Intention concerning the proposed project on March 18, 2016. The Commission issued a notice of the Declaration of Intention on May 10, setting a 30-day public comment period.

On June 21, 2016, Commission staff issued an order ruling on the Declaration of Intention and finding that licensing is not required. As articulated by the Commission in that order, pursuant to section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:
(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.
In this case, the order found “insufficient evidence to determine whether Nicatous Stream is navigable,” but determined that the stream is a headwater of the navigable Penobscot River, and thus “the project would be located on a Commerce Clause stream and also would be constructed after August 26, 1935.”

Crucially, the order found that the off-grid nature of the project – its lack of an interconnection to the interstate electric grid – meant that licensing was not required: “The project would not affect interstate commerce because it would not displace grid power nor would it connect to an interstate grid. Therefore, the project does not require licensing under section 23(b)(1) of the FPA.”

While licenses are available for hydropower projects under the Federal Power Act, the regulatory process for licensing is relatively lengthy and may require costly studies. A hydropower project that can be developed without a license thus has some advantages.

The Commission’s order includes a note emphasizing the relevance of a grid connection in licensing determinations for hydropower projects: “If the Nicatous Lodge property is connected to the interstate grid in the future or if other evidence sufficient to require licensing is found, section 23(b)(1) would require licensing. Under section 4(g) of the FPA, the project owner could then be required to apply for a license.” This note is consistent with Commission precedent finding that the existence or absence of a grid tie for a proposed microhydro project can determine whether hydropower licensing is required.

Canada NEB starts Energy East pipeline review

Canada's National Energy Board has ruled that the applications are complete for the Energy East Pipeline Project and a related gas project.  This determination starts the NEB's review process, under which the Board must issue its recommendations to the Minister of Natural Resources within 21 months.

The National Energy Board is an independent federal regulator of several parts of Canada's energy industry, including the regulation of pipelines, energy development and trade in the Canadian public interest.

As envisioned by proponents TransCanada and Energy East Pipeline Ltd., Energy East would be a 4,500-kilometer pipeline that will transport approximately 1.1 million barrels of crude oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick.  Some existing natural gas pipeline would be converted to oil transportation pipeline, while other facilities would be newly built.  The project is motivated in part by a relative surplus of Western Canadian crude production, with relatively few ways to ship that crude to refineries or ports.

The related Eastern Mainline Project entails about 279 kilometers of new gas pipeline and related components, designed to let TransCanada continue to supply gas after the proposed transfer of certain Canadian Mainline facilities to Energy East Pipeline Ltd. for conversion to crude oil service.

On June 16, 2016, the National Energy Board announced its determination that due to the interconnections between the applications, the Energy East and Eastern Mainline projects are more effectively assessed within a single hearing process, with one record, reviewed by one Panel of Board Members.   It also deemed the applications complete to proceed to assessment and a public hearing, starting the 21-month review process.

The Panel must submit a report to the Minister of Natural Resources recommending whether or not the projects should proceed, or on what conditions. This report is due no later than March 16, 2018.  According to the NEB, the process will include hearings, panel sessions, and assessments of the upstream greenhouse gas emissions associated with the project.

Maine biomass resource RFP issued

Wednesday, June 22, 2016

The Maine Public Utilities Commission has issued an order approving a Request for Proposals for biomass energy resources.  At stake are two-year contracts through which biomass resources may sell energy and related products to Maine transmission and distribution utilities.

Earlier this year, the Maine legislature enacted An Act to Establish a Process for the Procurement of Biomass Resources.  Originally proposed as LD 1676 and enacted as Public Law 2015, Chapter 483, that law requires the Public Utilities Commission to initiate a competitive solicitation for 2-year contracts for up to 80 megawatts of biomass resources

By order dated June 17, 2016, the Commission approved a Request for Proposals pursuant to its authority under the Act.  The RFP document -- formally styled a Request for Proposals for the Sale of Energy from Biomass Resources -- was released at the same time. It asks for proposals from Biomass Resources for the sale of energy under one or more two-year contracts; bidders may also offer to sell capacity and/or renewable energy attributes as part of the contract.

The RFP defines a Biomass Resource as "a source of electrical generation fueled by wood, wood waste or landfill gas that produces energy delivered to the ISO-NE or NMISA region."  Additional requirements and criteria apply, including minimum capacity factor thresholds and preferences for creating in-state benefits.  It is possible that no contracts will be awarded, or that there won't be money to pay under those contracts.  If the Commission concludes that this solicitation is not competitive, based either on the solicitation process or the resulting bids, no bidders may be selected.  By law, payments are also contingent on the availability of funding for any above-market portion of the contracts, from a Cost Recovery Fund established by the Act.

Contract proposals are due on or before July 29, 2016. According to the Commission's materials, the RFP and all related documents and information will be available on the Commission's RFP website.

FERC Order 827 and reactive power

Monday, June 20, 2016

Federal energy regulators have issued a final rule requiring all newly interconnecting non-synchronous generators to provide reactive power, which supports the reliability of the electric grid.  The rule adopted by the Federal Energy Regulatory Commission in Order No. 827 primarily affects wind generators, who have previously been exempt, and some solar projects.

Reactive power -- and generators capable of supplying or consuming it -- play an important role in controlling system voltage for efficient and reliable operation of an alternating current transmission system.  Previously, as a condition of interconnection under the FERC's pro forma Large Generator Interconnection Agreement and Small Generator Interconnection Agreement, most generators have been required “to maintain a composite power delivery at continuous rated power output at the Point of Interconnection at a power factor within the range of 0.95 leading to 0.95 lagging.”

But historically, the costs to design and build a wind generator that could provide this kind of reactive power were high.  In recognition that requiring wind generators to provide reactive power could have created an obstacle to the development of wind generation, the Commission previously exempted wind generators from the general requirement to provide reactive power, absent a study finding that the provision of reactive power is necessary to ensure safety or reliability.

But in 2014, a FERC staff report found that the cost of providing reactive power no longer presents an obstacle to the development of wind generation.  So-called Type III and Type IV inverter-based turbines now offer inherent reactive power capabilities.  As described in Order No. 827, "The resulting decline in the cost to wind generators of providing reactive power renders the current absolute exemptions unjust, unreasonable, and unduly discriminatory and preferential."  The Commission also noted that integrating increasing amounts of wind increases the potential that some systems will need more reactive power.

Acting under Section 206 of the Federal Power Act, on June 16, 2016, the Commission found "that wind generators should not have an exemption from the reactive power requirement which is unavailable to other generators." At the same time, the Commission recognized technical differences that would add costs if non-synchronous generators were required to provide reactive power at the Point of Interconnection -- and that these "added costs will ultimately be borne by customers, whether through reactive power payments in regions that compensate for reactive power capability, or through elevated prices for capacity or energy in regions that do not compensate for reactive power capability."

It thus adopted reactive power requirements for newly interconnecting non-synchronous generators, but let non-synchronous generators provide dynamic reactive power at the high-side of the generator substation, as opposed to the Point of Interconnection.

The Commission described its expectation that non-synchronous generators may meet the dynamic reactive power requirement by utilizing a combination of the inherent dynamic reactive power capability of the inverter, dynamic reactive power devices (e.g., Static VAR Compensators), and static reactive power devices (e.g., capacitors) to make up for losses.

The Final Rule will become effective 90 days after its publication in the Federal Register.  Its requirements will apply to all newly interconnecting non-synchronous generators that have not yet executed a Facilities Study Agreement as of the rule's effective date.

FERC proposes FAST Act CEII rules

Friday, June 17, 2016

The Federal Energy Regulatory Commission has proposed amending its regulations designed to protect critical information about utility infrastructure.  If adopted, the new regulations would govern the treatment of Critical Energy/Electric Infrastructure Information (CEII) whose disclosure and misuse could put the electric grid at risk.

In the wake of the September 11, 2011 terrorist attacks, the Commission took steps to identify and protect sensitive information it considered "Critical Energy Infrastructure Information," or CEII.  In general, FERC defined CEII as specific engineering, vulnerability, or detailed design information about proposed or existing critical infrastructure (physical or virtual) that:
  1. Relates details about the production, generation, transmission, or distribution of energy;
  2. Could be useful to a person planning an attack on critical infrastructure;
  3. Is exempt from mandatory disclosure under the Freedom of Information Act; and
  4. Gives strategic information beyond the location of the critical infrastructure.
Some previously public material was designated as CEII, and going forward newly filed or issued documents had to be screened for CEII.  FERC also created a process to allow individuals with a valid or legitimate need to access CEII, while protecting it from other disclosure.

But last year, Congress weighed in on the protection of certain sensitive information about infrastructure.  The Fixing America's Surface Transportation (FAST) Act, signed into law on December 4, 2015, included provisions designed to improve the security and resilience of energy infrastructure in the face of emergencies.  In particular, the FAST Act added section 215A to the Federal Power Act, directing the Commission to issue regulations covering the security and sharing of "Critical Electric Infrastructure Information."

Federal Power Act section 215A(a)(3) defines the new term Critical Electric Infrastructure Information as:
information related to critical electric infrastructure, or proposed critical electrical infrastructure, generated by or provided to the Commission or other Federal agency, other than classified national security information... Such term includes information that qualifies as critical energy infrastructure information under the Commission’s regulations.
As interpreted by the Commission, this encompasses "not only information regarding the Bulk-Power System but also information regarding other energy infrastructure (i.e., gas pipelines, LNG, oil, and hydroelectric infrastructure) to the extent such information qualifies as Critical Energy Infrastructure Information under the Commission’s current regulations. "

On June 16, 2016, the Commission issued a Notice of Proposed Rulemaking, proposing to amend its regulations to implement the provisions of the FAST Act pertaining to the designation, protection and sharing of critical electric infrastructure information, and also proposing to amend its existing regulations pertaining to CEII. The proposed changes include criteria and procedures for designating information as CEII, a specific prohibition on unauthorized disclosure of that information, and sanctions for knowing and willful wrongful disclosure of CEII by federal personnel.

Comments on the Notice of Proposed Rulemaking are due 45 days after its publication in the Federal Register.

Maine opens net metering inquiry

Tuesday, June 14, 2016

The Maine Public Utilities Commission has issued a Notice of Inquiry to obtain feedback on whether its net energy billing rules should be modified, or other action taken to affect Maine's net metering policy.

Rooftop solar panels on a Maine business.

Under Chapter 313 of the Commission's rules, Maine electricity customers may net the output of qualified solar panels or other distributed generation resources against their utility loads.  To date, this rate treatment, known as "net energy billing," has been a major incentive for the development of solar photovoltaic and other customer-sited renewable energy projects in Maine.  Most other U.S. jurisdictions have adopted similar net metering programs.

But the Maine regulations provide for a review by the Commission of its rules once a utility gives notice that net metered capacity reaches 1% of peak demand.  Maine transmission and distribution utility Central Maine Power Company gave that notice earlier this year.

At a deliberative session held on June 14, the Commission unanimously decided to initiate an inquiry into the matter.  The Commission's 4-page Notice of Inquiry seeks comment and information on a list of specific issues related to the net metering rules.  Issues identified in that notice include possible changes to the value of net metering credits or the kinds of customer generating facilities may be net metered, grandfathering of existing systems, the adoption of consumer protection standards, and an alternative contracting structure:
1. In what respects (if at all) should Chapter 313 be revised, and what objective is each such revision intended to achieve?
2. In what respects (if at all) should there be revisions to the retail rate components that are netted such that less than the full retail rate (T&D and supply) would be netted, and what objectives are such revisions intended to achieve?
3. Should the Commission consider changes in the current kWh (660kW) threshold for qualified projects? What is the rationale for such a change?
4. If there are revisions to NEB, should existing NEB customers be “grandfathered” with respect to any future changes that affect NEB? Please provide the rationale for your answer, and, if yes, for how long should customers be grandfathered?
5. How can an NEB program be designed to track changes in the costs of distributed generation facilities?
6. Should issues of revenue loss and rate impacts be addressed through T&D utility rate design? How should rate design be approached--through cost of service, avoided cost, or a value of solar approach? Please discuss any equity issues that might arise from these approaches.
7. With respect to the structural app roach discussed in the Commission’s Report to the Legislature Regarding Market-Based Solar Policy Design Stakeholder Process Pursuant to Resolves 2015, ch. 37 (Jan. 30, 2016) (which was the basic structural approach that was considered by the Legislature last session through LD 1649) in which the output from solar facilities would be purchased and re-sold into the wholesale market, please comment on the statutory authority under which the Commission could implement such an approach. In the event the Commission has the statutory authority, should the Commission pursue such an approach and, if so, how should the purchase price be established for the various distributed generation resources that participate in NEB?
8. Should solar PV be treated differently than other NEB eligible resources with regard to any changes that might be adopted to the program?
9. How should any changes to NEB arising from CMP’s January 14, 2016 letter request for review apply to Emera Maine and the consumer-owned utilities?
10. Does the Commission have statutory authority to regulate or oversee lease arrangements or other custom er agreements that involve NEB? If so, should the Commission consider additional consumer protection standards with respect to distributed generation lease programs or other customer arrangements (i.e., sales of community solar project shares)?
11. Please comment on any other issues related to NEB?
The Commission requested comments on these issues by July 22, 2016.  Public comment and information will help inform the Commission's review of its Chapter 313 rules.

NY offshore wind leasing advances

The U.S. Bureau of Ocean Energy Management is moving closer to leasing ocean sites offshore New York for commercial offshore wind development.

On June 2, 2016, the Department of the Interior and BOEM announced the proposed lease sale for 81,130 acres offshore New York for commercial wind energy leasing.  The area available for leasing includes a Wind Energy Area designated by BOEM earlier this year.  Roughly triangular, the WEA starts about 11 nautical miles offshore Long Beach, and runs about 26 nautical miles southeast.

Under BOEM's leasing procedures, the agency published a “Proposed Sale Notice (PSN) for Commercial Leasing for Wind Power on the Outer Continental Shelf Offshore New York” in the Federal Register on June 6, 2016.  The PSN includes a 60-day public comment period ending on August 5, 2016.

Any companies wishing to participate in the lease sale must also submit a qualification package by that date, demonstrating legal, technical, and financial qualification to participate.  To date, seven companies have qualified to participate in a future auction for the New York Wind Energy Area.

As required by federal environmental law, BOEM also published an Environmental Assessment (EA) considering potential impacts associated with issuing a lease, associated surveys, and approving the installation of resource assessment facilities in the area.  The EA is available for public comment for 30 days.

BOEM has scheduled a public seminar Wednesday, June 29, 2016 in New York City to describe the auction format, explain the auction rules, and demonstrate the auction process through meaningful examples.  Other public meetings will focus on the agency's planning and leasing efforts regarding New York offshore wind energy activities, as well as the EA.

So far, BOEM has awarded 11 commercial offshore wind leases, generating approximately $16 million in winning bids for over 1,000,000 acres in federal waters.  Previous competitive lease sales have resulted in 9 leases: two offshore New Jersey, two in an area offshore Rhode Island-Massachusetts, another two offshore Massachusetts, two offshore Maryland and one offshore Virginia.

Maine to consider net metering rules

Friday, June 10, 2016

The Maine Public Utilities Commission is set to consider opening an inquiry into the state's net energy billing rules, which allow electric utility customers to offset their load with distributed generation.

Under Maine's form of net metering, customers with qualifying distributed electric generation may net the power they produce against their consumption of power from the grid.  The Maine Public Utilities Commission adopted rules governing this "net energy billing" or net metering arrangement, which is a key incentive for customer-scale solar photovoltaic projects in Maine.

But those rules, found in Chapter 313 of the Commission's regulations, provide for an agency review of net metering as more customers go solar or participate in other net-metered distributed generation.  Earlier this year, Maine transmission and distribution utility Central Maine Power Company notified the Commission that the cumulative capacity of net metered generating facilities in its service territory had exceeded 1 percent of annual peak demand.  By rule, this notification will trigger a review by the Commission "to determine whether net energy billing ... should continue or be modified."

The Commission has now placed consideration of a Notice of Inquiry related to this item on its agenda for deliberations on June 14, 2016.

FERC assesses Coaltrain penalties

Wednesday, June 1, 2016

U.S. energy regulators have issued an order assessing $38 million in civil penalties for alleged energy market manipulation, plus disgorgement of unjust profits.

The case involves Coaltrain Energy, L.P., two of its individual owners, and three traders.  In January 2016, the Commission issued an Order to Show Cause and Notice of Proposed Penalty, alleging that the respondents had engaged in fraudulent transactions in PJM Interconnection L.L.C.'s energy markets.  The show cause order, and a supporting Enforcement Staff Report, also include allegations that Coaltrain made false and misleading statements and material omissions during the Commission's investigation. 

FERC's case against Coaltrain has now moved forward.  In a May 27 order, the Federal Energy Regulatory Commission found that Coaltrain and five named individuals violated section 222 of the Federal Power Act and section 1c.2 of the Commission’s regulations, which prohibit energy market manipulation, through a scheme to engage in fraudulent Up-To Congestion (UTC) transactions to garner excessive amounts of certain credit payments to transmission customers. 

According to the Commission, the Coaltrain respondents engaged in UTC trading conduct "similar to the behavior the Commission found fraudulent in its Chen and City Power orders issued last year," in that the UTCs were traded "not to profit based on price spread arbitrage, as the product was designed, but instead, to profit solely or primarily from a transmission credit that had nothing to do with the underlying product."  FERC alleges that the Coaltrain respondents "designed and implemented a fraudulent UTC trading scheme to receive excessive amounts of MLSA payments," or Marginal Loss Supply Allocation transmission credits.  In the Commission's words, "Respondents’ OCL Trades were manipulative because they were executed for the sole or primary purpose of targeting and garnering MLSA payments. Additionally, they were manipulative because they falsely appeared to PJM as being placed for the market design purpose of arbitraging price spreads, thus concealing their fraudulent nature and purpose."

The Order Assessing Civil Penalties also found that Coaltrain violated section 35.41(b) of the Commission's regulations, which in relevant part, prohibits a seller, such as Coaltrain, from submitting false or misleading information to or omitting material information from Commission staff.  The Commission found that in the course of responding to an investigation by FERC Office of Enforcement staff, Coaltrain intentionally withheld relevant documents from Commission staff while repeatedly representing to that its productions were “true, complete, and accurate.”  In particular, FERC concluded that Coaltrain held back documents recorded on its Spector 360 keystroke logging software discussing and reflecting its trading strategy, and only produced the documents to the Commission after agency staff discovered the documents' existence on their own.

The May 27 order states that based on the "seriousness of these violations," it is appropriate to assess civil penalties pursuant to section 316A(b) of the Federal Power Act in the following amounts:
$26,000,000 against Coaltrain (jointly and severally with Messrs. Peter Jones and Sheehan); $5,000,000 against Mr. Peter Jones; $5,000,000 against Mr. Sheehan; $1,000,000 against Mr. Robert Jones; $500,000 against Mr. Miller; and $500,000 against Mr. Wells. The Commission further directs Coaltrain, Mr. Peter Jones, and Mr. Sheehan to disgorge, jointly and severally, unjust profits, plus applicable interest, pursuant to section 309 of the FPA, in the amount of $4,121,894.
The Commission directed the respondents to pay the civil penalties within 60 days, or else the Commission said it will commence an action in a United States district court for an order affirming the penalty.

Nicatous Lodge proposes off-grid micro-hydro project

Monday, May 30, 2016

A Maine sporting camp has proposed developing an off-grid micro-hydropower project to provide it electricity.  Nicatous Lake Lodge and Cabins LLC proposes to develop the micro-hydro project at its remote property near Burlington, Maine.  A filing made by the camp earlier this spring has triggered a federal review process to evaluate whether the project will require a license or exemption under the Federal Power Act.

Under federal law, most hydropower projects cannot be constructed, operated, or maintained without licensing under the Federal Power Act.  But some projects -- typically off-grid or remote ones -- fall outside the Federal Power Act's jurisdiction.  To reduce uncertainty about what regulations might apply, Section 23(b)(1) of the Federal Power Act requires an entity proposing a new project to 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.

When a developer files a Declaration of Intention with the Commission, the Federal Power Act requires the Commission to investigate and determine if the project would affect the interests of interstate or foreign commerce. The Commission also determines whether or not the project: (1) would be located on a navigable waterway; (2) would occupy public lands or reservations of the United States; (3) would utilize surplus water or water power from a government dam; or (4) would be located on a non-navigable stream over which Congress has Commerce Clause jurisdiction and would be constructed or enlarged after 1935.  Each of these evaluations supports a key jurisdictional finding under the Federal Power Act; collectively, they can determine whether or not licensing is required.

Other recently proposed micro-hydro projects illustrate how the Commission evaluates whether or not a license or exemption will be required.  For example, the Commission found that licensing or exemption was required for the Patton Colorado Hydropower Project, which would be grid-tied -- but that no license is required for the Egnaczak Net Zero Hydro Project in Massachusetts, which would have no connection to the interstate electric grid.

This jurisdictional determination is now underway for the Nicatous micro-hydro project.  On March 15, 2016, the sporting camp owner submitted a Declaration of Intention to the Federal Energy Regulatory Commission.  That Declaration of Intent describes the project site as about 15 miles away from the nearest electric utility grid, where Nicatous Stream leaves Nicatous Lake.  The project does not rely on a dam, although the remains of a former dam are located nearby.  Instead, an intake in the lake would supply water to a low head (60 inches or less) PowerPal micro-hydroelectric generator, rated at 1,000 watts power.  Power from the generator would be fed into the lodge's electric system, not which is not connected to any utility grid.

On May 10, 2016, the Commission issued its notice of the filing, setting a 30-day deadline for filing comments, protests, and motions to intervene.  Commission action on the filing could follow later this year.

Alta Ski Area conduit micro-hydro project

Friday, May 27, 2016

Alta Ski Area has proposed developing a micro-hydropower project along an existing pipeline, and hopes to benefit from a streamlined regulatory process.  Federal regulators have made a preliminary determination that the proposed Alta Micro-Hydro Project, in Alta, Utah, satisfies the requirements to be treated as a "qualifying conduit hydropower facility," which would not require licensing under the Federal Power Act.

Alta's proposed project would include a new powerhouse to be built along the existing underground 6-inch-diameter snowmaking water supply pipeline delivering water from Cecret Lake to the Wildcat Pump House, a new turbine/generating unit with an installed capacity of 75 kilowatts, intake and discharge pipes, and appurtenant facilities.  The unit is estimated to generate between 115 and 225 megawatt-hours annually.  There is no dam associated with the project.  Alta presented its micro-hydro project as part of a 2012 request to update its master plan, which the U.S. Forest Service accepted.

Ski areas with snowmaking capacity typically have existing pipelines and water infrastructure, coupled with significant vertical relief.  This can create opportunities to generate electricity using energy harvested from water flowing downhill through a pipeline, particularly if reducing system pressure (like a pressure relief valve) is otherwise needed. 

A 2013 law was designed to help small conduit-based hydropower projects by eliminating their need for a license or exemption from licensing issued by the Federal Energy Regulatory Commission.  Section 4 of the Hydropower Regulatory Efficiency Act of 2013 amended Section 30 of the Federal Power Act.  Section 30 now provides that a "qualifying conduit hydropower facility" -- one that is determined or deemed to meet defined criteria -- is not required to be licensed or exempted from licensing under the Federal Power Act.  These criteria include:

  • The conduit the facility uses 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 not primarily for the generation of electricity.
  • The facility is constructed, operated, or maintained for the generation of electric power and uses for such generation only the hydroelectric potential of a non-federally owned conduit.
  • The facility has an installed capacity that does not exceed 5 megawatts. 
  • On or before August 9, 2013, the facility is not licensed, or exempted from the licensing requirements of Part I of the FPA.

The Federal Energy Regulatory Commission administers this statute.  To start the regulatory process, on May 16, 2016, Alta filed a notice of intent to construct a qualifying conduit hydropower facility.  Alta supplemented its notice on May 20 to clarify that the project "will only operate when there is excess capacity available in the pipeline and when water is hydrologically available", generally after the winter snowmaking season, during spring runoff.  Alta also restated that the pipeline's main purpose will continue to be snowmaking.

Yesterday the FERC issued its notice of preliminary determination of a qualifying conduit hydropower facility for Alta's project.  That notice examines the project relative to each of the four statutory criteria, and then provides the Commission's preliminary determination:

The proposed addition of the hydroelectric project along the existing water supply pipeline will not alter its primary consumptive purpose. Therefore, based upon the above criteria, Commission staff preliminarily determines 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 also sets 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 and providing an evidentiary basis.

Other recently proposed conduit hydro projects have been determined to be qualifying conduit hydropower facilities, including a Colorado project using an existing "ditch drop," a Castle Valley, Utah water treatment project, a California wholesale water agency conduit project, and a New Hampshire water works.

Hydro relicensing and intervention timing

Wednesday, May 25, 2016

The Federal Energy Regulatory Commission issues hydropower licenses for terms of up to 50 years.  At least 5 years before license expiration, the licensee is required to notify the Commission and the public whether it intends to apply for a new license for the project, and what licensing process it requests.  Any license application might not come for years after the filing of that notice of intent.  But as a recent Commission order shows, the opportunity for a third party to intervene in the relicensing case is triggered not by the notice of intent, but only after an application for a new license is actually filed and notice is published.

That recent order involved New York State Electric & Gas Corporation (NYSEG), the licensee for the Upper Mechanicville Hydroelectric Project, FERC No. 2934.  The Upper Mechanicville project is located on the Hudson River in upstate New York, and has an authorized capacity of 18.5 megawatts.  Its original license, issued in 1981 for a 40-year term, expires on March 31, 2021.

On March 30, 2016, NYSEG filed a Notice of Intent to relicense the project, under the Commission's Integrated Licensing Process or ILP, along with a Pre-Application Document.

On April 13, 2016, the New York State Council of Trout Unlimited filed a motion to intervene in the docket, citing Rule 214 of the Commission's Rules of Practice and Procedure.  But on May 24, the Commission issued a notice dismissing that motion.

The notice first points to Rule 214(a)(3) of its procedural order, any person may seek to intervene and become a party in a proceeding by filing a motion to intervene that complies with the content requirements of Rule 214(b).  But the notice states that because NYSEG has not yet filed an application for a new license, there is no proceeding in which to intervene.  It therefore dismissed the motion to intervene as premature.

The notice does offer the Trout Unlimited group two other approaches to involvement.  First, it suggests that interested persons can register and eSubscribe to the docket.  Second, it notes that should NYSEG file an application for a new license for its project, notice of the application will be published, and interested entities "will have an opportunity to intervene and present views concerning the project as proposed in the license application."

FERC Summer 2016 energy market and reliability report

Friday, May 20, 2016

Federal energy regulatory staff have presented their 2016 Summer Seasonal Assessment to the Federal Energy Regulatory Commission.  The "Summer 2016 Energy Market and Reliability Assessment" presents an summer outlook by FERC's Office of Electric Reliability and Office of Enforcement on electricity and natural gas markets and reliability issues.

Highlights include:
  • "low natural gas prices that have resulted from robust production and near record levels of natural gas in storage"
  • electric system reserve margins are expected to be adequate this summer, though tighter in Texas
  • total U.S. load forecast, when weather-adjusted, is essentially unchanged in recent years, largely due to little to no load growth in commercial and residential sectors
  • the total generating capacity in the U.S. has decreased by approximately 2 percent since last summer, primarily due to coal retirements. According to the report, "The factors that prompted these closures include increased competition from natural gas, environmental regulations and an average fleet age that exceeded 50 years old."
  • Over 18 gigawatts of new generating capacity will be installed nationwide through the summer, with a majority of these capacity additions coming from renewables such as wind and solar, plus the first new U.S. nuclear unit in over 20 years.
  • Organized markets are attempting to manage the growing impacts of renewable generation.
  • FERC staff expects natural gas fired generation to remain robust; natural gas fired generation has surpassed coal plant output since July 2015. Meanwhile coal stockpiles are growing due to a decrease in coal generation.
  • Natural gas future prices have fallen since last year, though the Boston region's price drop is not significant.  Basis swaps -- financial instruments that represent the natural gas price differential between a specific point and the Henry Hub -- for Boston are priced higher than last summer, "suggesting expectations for greater congestion due to above-normal temperatures and a reduction in capacity along the Algonquin pipeline because of planned maintenance to tie in the Algonquin Incremental Market (AIM) expansion project this summer."

Maine biomass procurement competitive standards

Thursday, May 19, 2016

As the Maine Public Utilities Commission prepares for its upcoming procurement of biomass power resources, the Commission has requested public comment on the standards and criteria to be used in evaluating whether the solicitation is "not competitive."

This spring, the Maine State Legislature enacted An Act To Establish a Process for the Procurement of Biomass Resources.  The law directs the Maine Public Utilities Commission to initiate a competitive solicitation as soon as practicable, seeking proposals for 2-year contracts for up to 80 megawatts of biomass resources.  

But largely due to fairness and cost-containment concerns, the legislature created a "safety valve" in case the solicitation turns out to be "not competitive."  The Act specifies that “If the commission concludes that the solicitation ... is not competitive, no bidders may be selected and the commission is not obligated to enter into a contract.”

On May 17, 2016, the Commission issued a request for comment in its Procurement of Biomass Resources docket.  That request describes the Commission's plans to initiate the procurement process "in the near future" through the issuance of a request for proposals or RFP.  But before issuing the RFP, the Commission has requested comment on the standards and criteria to be used to determine whether the solicitation is “not competitive” pursuant to the Act.

Comments are requested by May 30, 2016.

FERC and microhydro licensing

Wednesday, May 18, 2016

Federal energy regulators have ruled that a micro-hydroelectric project proposed in New York cannot be constructed or operated without a license.

The proposed Henson Micro Hydroelectric Project would be located on the West Branch of Onondaga Creek, near Onondaga, New York.  It would include an existing 14-foot-high concrete dam, plus new construction including a penstock, a powerhouse, and a 10 kilowatt generating unit.  The dam was rebuilt in 2002, and had previously been used to power a grist mill.  The project developer, an individual, proposed to use the project power to provide electricity to his home and barn.
In his declaration of intention, the developer described himself and his approach to project development and compliance:
I would like to point out that I am not a corporation, or a rich man just a simple middle class Joe. I am an hourly employee at AT&T. Although blessed beyond what I actually deserve, I do not have a bunch of money that I could spend. In fact I am using funds recently obtained from a loss of use settlement from the NYS Workers Compensation Board to fund this. I am trying to do the right thing for the environment and save some money on my power bill. I am hoping that we can work this out to everyone’s satisfaction based upon the material and information that I currently have available. Of course, if additional information is required by you folks I will do everything to comply.
Identifying what approvals are necessary is a core step in developing any project.  Under section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed by the Federal Energy Regulatory Commission (unless it has a still-valid pre-1920 federal permit) if it:
(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.
To reduce uncertainty over whether a project will require licensing, a developer may file a Declaration of Intention with the FERC describing the project.  Following public notice and an opportunity for protests, comments, and motions to intervene, FERC will rule on the jurisdictional questions raised by the declaration.

In the Henson project's case, the developer filed a Declaration of Intention on December 18, 2015.  That declaration was supplemented; after the second supplement, FERC issued its public notice of the declaration.  No protests, comments, or motions to intervene were filed.

On May 10, FERC issued its ruling on the declaration, finding that licensing is required.  FERC easily found that the project would not occupy any public lands or reservations of the United States or use surplus water or waterpower from a Federal government dam.  It found "insufficient evidence" to determine whether the West Branch of the Onondaga Creek is navigable.

However, FERC found that the West Branch of Onondaga Creek is a headwater or tributary of the Oswego River, a navigable water of the United States.  As a result, FERC concluded the project would be located on a "Commerce Clause stream."  FERC noted the project would be constructed after 1935.

FERC also concluded that the project would affect interstate commerce through its connection to the interstate grid, relying on precedent 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."  Thus even though the Hanson project's developer proposed using project power for the onsite home and barn, the fact that those buildings were grid-tied drove FERC to conclude that licensing was required. 

On this reasoning, FERC concluded that construction, operation, and maintenance would require a license.  As an alternative, FERC suggested the developer consider applying for an exemption from licensing as a small hydroelectric power project.

By contrast, another recent FERC decision concluded that a micro-hydro system proposed in Massachusetts did not require licensing, because (among other reasons) neither the project nor the structures it would serve would be grid-tied.  Thus whether or not the project and the facilities it serves are grid-tied or off-grid can be an important factor in whether a FERC hydropower license is required.

FERC relicensing and annual licenses

Thursday, May 5, 2016

What happens when the holder of a hydropower license applies to the Federal Energy Regulatory Commission for a new license, but the original license expires before the relicensing case is resolved?  Depending on which federal laws and regulations apply, possible outcomes can include the Commission issuing an annual license, or continued operation under the license terms, until a new license is issued or other disposition is ordered.

A recent FERC case illustrates this dynamic, involving the Don Pedro Hydroelectric Project, Project No. 2299, located on the Tuolumne River in California.  Turlock Irrigation District and Modesto Irrigation District are the licensees for Project No. 2299, under a license issued for a period ending April 30, 2016.

Just over 2 years before the Don Pedro project's license expired, on April 28, 2014 the licensees filed an Application for a New License pursuant to the Federal Power Act (FPA) and the Commission's regulations thereunder.  That relicensing application remains pending.

Section 15(a)(1) of the FPA, 16 U.S.C. 808(a)(1), requires the Commission, at the expiration of a license term, to issue from year-to-year an annual license to the then licensee under the terms and conditions of the prior license until a new license is issued, or the project is otherwise disposed of as provided in section 15 or any other applicable section of the FPA.  But some projects operate pursuant to licenses which include waivers of the applicability of Section 15 of the FPA.

In the Don Pedro project's case, on May 5, 2016, the Commission issued a Notice of Authorization for Continued Project Operation, including language covering both the scenario under which Section 15 applies, as well as the scenario under which the prior license waived Section 15's applicability.

If the project is subject to section 15 of the FPA, the Commission gave notice that an annual license for Project No. 2299 is issued to the licensee for a period effective May 1, 2016 through April 30, 2017 or until the issuance of a new license for the project or other disposition under the FPA, whichever comes first.  If issuance of a new license (or other disposition) has not occurred by April 30, 2017, the Commission gave notice that, pursuant to 18 CFR 16.18(c), an annual license under section 15(a)(1) of the FPA is renewed automatically without further order or notice by the Commission, unless the Commission orders otherwise.

If Section 15 does not apply, the Commission gave notice that based on section 9(b) of the Administrative Procedure Act, 5 U.S.C. 558(c), and as set forth at 18 CFR 16.21(a), if the licensee of such project has filed an application for a subsequent license, the licensee may continue to operate the project in accordance with the terms and conditions of the license after the minor or minor part license expires, until the Commission acts on its application. If the licensee of such a project has not filed an application for a subsequent license, then it may be required, pursuant to 18 CFR 16.21(b), to continue project operations until the Commission issues someone else a license for the project or otherwise orders disposition of the project.

The irrigation districts' relicensing case remains pending.

FERC rejects BOST1 preliminary permit application

Wednesday, May 4, 2016

If the holder of a preliminary permit under section 4(f) of the Federal Power Act to study the feasibility of a proposed hydropower project is denied a successive permit to study the same project at the same site, will the Federal Energy Regulatory Commission accept a new application for a preliminary permit for the same applicant and project?

In a recent case, Commission staff said no, dismissing the new permit application.  That case involved a March 7, 2016 application by BOST1 Hydroelectric LLC proposing to study the feasibility of the Coon Rapids Dam Hydroelectric Project No. 13458, to be located at the existing Coon Rapids Dam on the Mississippi River in Minnesota.

Under the Federal Power Act, a developer interested in exploring the feasibility of a proposed hydropower project may apply for a preliminary permit, issued for up to three years.  A preliminary permit is not a development approval; it does not authorize construction.  Rather, it gives the holder the guaranteed right to have first priority to file a timely development application.

But this wasn't the first preliminary permit application FERC had received from BOST1 for this project.  In 2009, BOST1 applied for a preliminary permit for the Coon Rapids Project, which the Commission granted on October 7, 2010.  BOST1 was selected following a random drawing against a competing application filed by the Three Rivers Park District, which had previously held a preliminary permit for the site under Project No. 12618-000.  BOST1 was then granted a two-year extension of the permit term on September 6, 2013.

That permit expired on September 30, 2015.  BOST1 undertook predevelopment activity and made filings with the Commission, but did not file a final license application before the permit expired.

On October 1, 2015, BOST1 filed a successive permit application.  But Commission staff denied that application on January 20, 2016, because BOST1 had "failed to show that extraordinary circumstances or factors outside of its control prevented it from filing a development application."  The Commission requires a developer holding a preliminary permit to demonstrate diligent action under that permit, if the developer wishes to receive a successive permit.

The applicant then took two actions.  On February 19, 2016, it filed a request for rehearing, which remains pending.  Then, weeks later, it filed a new application for a preliminary permit for the project.

In a May 4, 2016 order, Commission staff dismissed that new application.  The order describes the new permit application as "nearly identical to its successive permit application," which the Commission denied this part January.  In the order's words, "To justify a permit in either case, BOST1, which has already had five years to prepare a development application, needed to demonstrate that extraordinary circumstances or factors outside of its control prevented it from filing a license application.  It failed to do so."

Commission staff therefore ordered that the applicant's March 7, 2016 application is denied.  BOST1's request for rehearing, relating to the January successive permit denial, remains pending.