Hydro license transfers and fitness

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, LLC.  American 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

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

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

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

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

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

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

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

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

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

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.