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.

Maine examines interconnection standards

Friday, April 29, 2016

The Maine Public Utilities Commission has opened an inquiry into whether it should change its rule governing how small distributed generation resources may interconnect with the electric grid.  This small generator interconnection procedures inquiry may reshape how distributed energy resources will interconnect with the Maine grid going forward.

While many large central power plants are subject to some federal regulation, states generally may prescribe the standards for how most solar photovoltaic panels and other small distributed energy resources may interconnect with the grid.  Interconnection standards and procedures are designed to provide a safe, fair, and timely way for utility customers to connect generation to the grid.

In a 2009 report, the Maine Public Utilities Commission concluded that it should create standardized, statewide interconnection procedures for Maine’s utilities.  In the Commission’s view, “standardized rules would increase the efficiency of the interconnection process, encourage the increased use of renewable energy and other distributed generation resources like micro combined heat and power systems, and may foster an easier business environment for the companies that sell and install small generation systems.”

In 2010, the Commission adopted its Rule Chapter 324, Small Generator Interconnection Standards.  That rule was based largely on model standards released by the Interstate Renewable Energy Council (IREC) in 2009, which were themselves based on the federal Small Generation Interconnection Procedures.  While the Commission adopted minor changes to Chapter 324 in 2013, it remains largely as originally adopted.

At the same time, the intervening years have brought changes to some of the context for interconnection issues.  First, IREC has updated its model standards.  The most recent edition, released in 2013, features significant changes from the prior standards, including the creation of a pre-application report, changes to the application fees for interconnection review, and definitional clarifications.

Second, increasing adoption of distributed generation has led FERC and state regulators to consider whether small generation facilities should be required to have “frequency and voltage ride through capability”, an ability to protect the grid’s reliability as amount of distributed generation grows on the electrical system.

In light of these developments, the Maine Commission has issued a notice of inquiry seeking comment on these issues.  According to that notice, the inquiry will assess “whether and to what extent Chapter 324 should be revised to (1) reflect changes in the IREC interconnection standards and procedures and (2) incorporate requirements for frequency and voltage ride through capability of small generation facilities.”

The Commission has docketed the case as Docket No. 2016-00068, and requests public comment by May 20, 2016.

Stanford declines to divest fossil fuels

Thursday, April 28, 2016

Should university endowments be invested in fossil fuel companies?  Or should they divest such holdings? Universities across the U.S. are considering these questions.  In the latest development, Stanford University's Board of Trustees has released a statement on climate change, describing the university's initiatives to battle climate change, but declining to divest Stanford's roughly $22 billion endowment from the fossil fuel industry.

In the April 25 statement, the Board describes climate change as "among the most serious challenges of our time."  The statement lists various elements of Stanford's strategic approach to combating climate change, including a $500 million transformative campus energy system, commitments to invest in solar, other renewable energy, wastewater recovery, green transportation, and energy efficiency in campus buildings.  The statement also announces the creation of a new climate task force to be composed of undergraduates, graduate students, faculty and staff, to solicit ideas for further action.

Much of the statement is structured as a response to a proposal by student organization Fossil Free Stanford that the university divest its endowment from the fossil fuel industry.  The trustees cite the university's Statement on Investment Responsibility as outlining a specific set of criteria by which the trustees may evaluate whether a company is inflicting social injury in a manner that warrants consideration of divestment.  The statement notes the establishment of an Advisory Panel on Investment Responsibility and Licensing, which studied the issues and made a recommendation to the Board’s Special Committee on Investment Responsibility, which in turn made a recommendation to the trustees.

According to the statement, the advisory panel "recommended divestment of companies whose primary business is oil sands extraction, a method that studies have found requires more water, and releases more carbon into the atmosphere, than other forms of fossil fuel extraction."  It cites Stanford Management Company as saying that the Stanford endowment has no direct exposure to companies whose primary business is oil sands extraction, so the trustees had no action to take on this point.

On the broader fossil fuel industry, the panel "concluded that it could not evaluate whether the social injury caused by the fossil fuel industry outweighs the social benefit it provides, and therefore did not recommend divestment."  The trustees agreed that the criteria were not met, and declined to divest.

That said, the statement expressed the trustees' belief "that the global community must develop effective alternatives to fossil fuels at sufficient scale, so that fossil fuels will not continue to be extracted and used at the present rate... the long-term solution is for all of us to reduce our consumption of fossil fuel resources and develop effective alternatives."

But despite investment and progress in research, including by Stanford, the trustees note that "at the present moment oil and gas remain integral components of the global economy, essential to the daily lives of billions of people in both developed and emerging economies."  The statement also notes the efforts of some oil and gas companies to explore alternatives.  The statement notes that "the trustees do not believe that a credible case can be made for divesting from the fossil fuel industry until there are competitive and readily available alternatives."

The statement also notes that the university's investment program does take climate change into consideration when evaluating the economic attractiveness of various investments.  In the trustees' words, "Prudent investors acknowledge that the world is beginning a transition away from carbon-based energy sources and that pricing for fossil fuels will reflect this transition."  The statement also notes the efforts of the endowment managers to "identify and support industry best practices that, in addition to positively impacting investment results, may pay significant environmental dividends."

This is not the first time Stanford has considered divesting from fossil fuels.  In 2014, after pressure from Fossil Free Stanford, the trustees announced a decision that Stanford would not make direct investments in coal mining companies, in recognition of "the availability of alternate energy sources with lower greenhouse gas emissions than coal."

FERC staff recommends against Bear River dam

Wednesday, April 27, 2016

Staff of the U.S. Federal Energy Regulatory Commission have recommended against licensing a dam, reservoir, and hydropower project proposed for the Bear River near Preston, Idaho.

The case involves a 2013 application by Twin Lakes Canal Company to the FERC for a license to construct, operate, and maintain the Bear River Narrows Project.  The project would be located on the main stem of the Bear River in Franklin County, Idaho, about 9 miles northeast of the city of Preston. It would feature a 109-foot-high dam impounding a 362-acre reservoir, and a powerhouse with an installed capacity of 10 megawatts and estimated average annual generation of of 48,531 megawatt-hours of electricity.  The reservoir would also be used to provide up to 5,000 acre-feet of water to Twin Lakes’ irrigation system during dry years.

Under the Federal Power Act, the FERC is charged with processing licenses for most hydropower projects in the U.S.  Federal law guides the FERC in this duty.  Sections 4(e) and 10(a)(1) of that act require the Commission to give equal consideration to the power development purposes and to the purposes of energy conservation; the protection of, mitigation of damage to, and enhancement of fish and wildlife; the protection of recreational opportunities; and the preservation of other aspects of environmental quality.  The Commission can only issue licenses that in its judgment are best adapted to a comprehensive plan for improving or developing a waterway or waterways for all beneficial public uses.  Additionally, the National Environmental Policy Act of 1969 requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Twin Lakes' application.

Commission staff released its final environmental impact statement on Twin Lakes' license application on April 27, 2016.  That document, called an EIS, analyzes the effects of proposed project construction and operation, and recommends conditions for any license that may be issued for the project.

In the Bear River Narrows Project EIS, FERC staff considered Twin Lakes’ proposal for licensing, as well as three alternatives: (1) no-action (i.e. not licensing the project, so it can't be constructed); (2) the applicant’s proposal with staff modifications (staff licensing alternative); and (3) the staff licensing alternative with an additional condition requested by the Bureau of Land Management.

The EIS notes the existence of four Commission-licensed hydroelectric facilities located on the Bear River in Idaho with a combined installed capacity of more than 78 MW, including the Oneida development directly upstream.  It also notes uses of the "Oneida Narrows" section of the Bear River that would be flooded by the Bear River Narrows Project impoundment, including a recreational trout fishery and boating opportunities, and habitat for sensitive wildlife species.

Based on a review of the anticipated environmental and economic effects of the proposed project and its alternatives, as well as the agency and public comments filed on this project, staff recommends no action (license denial) as the preferred alternative.  In staff's words, "The overall, unavoidable adverse environmental effects of both action alternatives would outweigh the power and water storage benefits of the project."

For these reasons, FERC staff concluded that "any license issued for the proposed project could not be best adapted to a comprehensive plan for improving or developing the Bear River for all of its beneficial public uses, especially its substantial public recreation use at the proposed project site. We, therefore, recommend license denial."

Twin Lakes Canal Company's application to the Commission for a license to construct the project remains pending.

Maine enacts biomass energy support

Thursday, April 21, 2016

Maine has adopted a new law to support the state's biomass energy industry.  Governor Paul LePage has signed LD 1676, An Act To Establish a Process for the Procurement of Biomass Resources, as emergency legislation.  As a result, the bill has been enacted into law as Public Law, Chapter 483, from the 127th Maine Legislature.

The Maine State House.

The bill directs the Maine Public Utilities Commission to initiate a competitive solicitation as soon as practicable.  That solicitation will ask for proposals for 2-year contracts for up to 80 megawatts of biomass resources.  To qualify, a biomass resource must be a source of electrical generation fueled by wood, wood waste or landfill gas that produces energy that may be physically delivered to the ISO New England or Northern Maine Independent System Administrator markets.  A resource must also operate at least at a 50% capacity for 60 days prior to the initiation of a competitive solicitation and continues to operate at that capacity except for planned and forced outages.

The law gives the Commission some direction on how to select proposals for contracting.  It requires the Commission to seek to ensure, "to the maximum extent possible" that a contract provides benefits to ratepayers as well as in-state economic development benefits, reduces greenhouse gas emissions, promotes fuel diversity, and supports or improves grid reliability.

The costs of the contracts, other than above-market costs, and all direct financial benefits from the contracts must be allocated to ratepayers according to Maine's statute on allocation of costs and benefits of long-term energy contracts.  Above-market costs will be paid for from a cost recovery fund created by the new law, which allocates up to $13.4 million from the unappropriated surplus of the state's General Fund. 

FERC grid modernization session

Wednesday, April 20, 2016

U.S. federal energy regulators convene tomorrow to discuss modernization of the nation’s electric power grid.

Recent years have brought significant changes in technology and the ways we use energy.  From distributed energy resources like solar panels to a variety of "smart grid" applications, society has new tools that may be able to improve the nation's energy sector.  As a result, state and federal energy regulators are considering "grid modernization."  Issues in play can include whether improvements to the nation’s electric power grid are appropriate, and if so, how to fund them.

For several years, the Federal Energy Regulatory Commission has considered grid modernization issues.  Now, the Commission has scheduled a grid modernization event for tomorrow.

At the Commission's April meeting, it will hear from representatives from the U.S. Department of Energy, including Patricia A. Hoffman, assistant secretary for the Office of Electricity Delivery and Energy Reliability, and Roland Risser, acting deputy assistant secretary for Renewable Power.  The Energy Department will also offer panelists from its National Renewable Energy Laboratory, Pacific Northwest National Laboratory, Idaho National Laboratory, Sandia National Laboratories, and Lawrence Berkeley National Laboratory. 

Following the FERC meeting, the panelists will be available for a post-meeting information session on the work of the Grid Modernization Laboratory Consortium.  Panelists are expected to discuss devices and integrated systems, sensing and measurement, system operations, control and power flow, design and planning tools, security and resilience, and institutional support.

Supreme Court rules on state energy incentives

Tuesday, April 19, 2016

The U.S. Supreme Court has released its ruling on a case affecting how states may provide incentives for electric power generation.  In Hughes v. Talen Energy Marketing, LLC, the Court upheld a lower court's ruling invalidating a Maryland program to subsidize construction of new power plants.  The ruling provides important insight into how the Court views the boundary between federal and state jurisdiction over energy matters.

The Supreme Court of the United States.

The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market.  Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales. 

For years,  Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development.  PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act.  But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program.  Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer.  The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.

But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM.  On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies.  The case then came to the Supreme Court of the United States.

The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings.  The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators."  In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."

The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation.  That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC."  The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.

The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable."  This suggests one potential path for permissible state incentives for electric power generation.

US Quadrennial Energy Review second round

Friday, April 15, 2016

The U.S. Department of Energy is holding a series of public meetings centered on the topic of the second installment of its Quadrennial Energy Review, an integrated study of the U.S. electricity system from generation through end use.

On January 9, 2014, President Obama issued a Presidential Memorandum establishing a task force and directing the administration to conduct a Quadrennial Energy Review (QER).  The task force was directed to “gather ideas and advice from state and local governments, tribes, large and small businesses, universities, national laboratories, nongovernmental and labor organizations, consumers, and other stakeholders and interested parties...”  This input is designed to inform a report to the President that includes the following:

  • Provides an integrated view of, and recommendations for, Federal energy policy in the context of economic, environmental, occupational, security, and health and safety priorities, with attention in the first report given to the challenges facing the Nation’s energy infrastructures.
  • Reviews the adequacy of existing executive and legislative actions and recommends additional executive and legislative actions, as appropriate.
  • Assesses and recommends priorities for research, development, and demonstration programs to support key energy innovation goals.
  • Identifies analytical tools and data needed to support further policy development and implementation.
The QER Task Force released the first installment of the Quadrennial Energy Review in 2015, “Energy Transmission, Storage, and Distribution Infrastructure”.  This volume reviewed U.S. infrastructure for transmission, storage, and distribution, including liquid and natural gas pipelines, the grid, and shared transport such as rail, waterways, and ports, and noted "the critical enabling role of electricity."

Based on this role, the Administration determined that the second installment of the QER will focus on the electricity system, including "not just physical structures, but also a range of actors and institutions." A stakeholder briefing memorandum for the QER's second round describes consideration of fuel choices, distributed and centralized generation, physical and cyber vulnerabilities, federal, state, and local policy direction, expectations of residential and commercial consumers, and a review of existing and evolving business models for a range of entities throughout the system.  The second installment is expected to result in a set of findings and policy recommendations to help guide the modernization of the nation’s electric grid and ensure its continued reliability, safety, security, affordability, and environmental performance through 2040.

As part of this process, the Department of Energy is holding a series of stakeholder engagement meetings.  Meetings will include a mix of panel discussions and public comment opportunities.

The first meeting of QER's second installment was held in Washington, D.C., on February 4.  Future meetings include:

Boston, Massachusetts -- April 15, 2016
Salt Lake City, Utah -- April 25, 2016
Des Moines, Iowa -- May 6, 2016
Austin, Texas -- May 9, 2016
Los Angeles, California -- May 10, 2016
Atlanta, Georgia -- May 24, 2016

NH regulation of solar PPAs, leases

Thursday, April 14, 2016

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

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

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

In a January 15, 2016 order -- Order No. 25,859 -- the Commission granted Vivint's petition.  First, the Commission noted the value of regulatory certainty:
We believe it is important for a party planning to do business in the state to have a vehicle through which it may clarify its regulatory status prior to entering the marketplace, provided that it can describe in sufficient detail its business plans and practices and these plans and practices are not hypothetical or speculative.
Next, the Commission concluded that the operations described by Vivint would not constitute sales to or for the "public" within the meaning of the statutory definition of "public utility."  Key factors recited in the order included the "conditional nature and relative complexity of Vivint’s relationships with its customers."

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

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

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

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

Massachusetts solar legislation signed

Wednesday, April 13, 2016

Massachusetts Governor Charlie Baker has signed a bill passed by the state legislature to expand the Massachusetts solar industry and establish a long-term framework for sustainable solar development.

The bill, An Act Relative to Solar Energy, preserves and expands net metering.  Net metering -- a customer's right to offset its solar power production against its consumption of electricity from the grid -- has been an important incentive for solar projects in Massachusetts, leading to the development of over 1,000 megawatts of solar capacity currently installed in Massachusetts.  Previous law set caps on how much solar capacity each utility was required to let its customers net meter against their load.  But at least one utility has reached its cap, cutting off future projects' access to net metering in that territory, and the other utilities are close behind.

In response to interest in preserving net metering, the bill signed into law on April 11 increases the state's solar net metering caps, which limit how much net metered capacity may be installed in each utility's service territory.  It raises the cap on publicly owned projects from 5% of utilities’ peak load to 8%, and lifts the cap on private net metered projects from 4% of utilities’ peak load to 7%.   

At the same time, the bill changes the value of net metering credits for some new projects.  When a net metered customer's solar system produces more electricity than the customer uses, the customer receives credit for its excess production.  Historically, that credit was at the full retail rate -- meaning the customer is credited the same amount for a kilowatt-hour exported to the grid as the customer pays the utility to buy that kilowatt-hour from the grid.  The fact that net metered generation is credited at the full retail rate, as opposed to any lesser amount, has helped net metering drive solar project development.

But some utilities have expressed concerns that net metering imposes costs on other customers who don't have net metered distributed generation.  In an effort to balance cost containment against effective incentives for solar development, the Massachusetts legislation sets the new credit value for most solar projects (other than residential, small commercial, municipal and government-owned) at 60% of the full retail rate once the state hits its goal of 1,600 megawatts of solar capacity.

But to "facilitate continued solar growth within communities around the Commonwealth," the bill preserves retail rate credits for municipal and government-owned projects.  It also continues to exempt residential and small commercial projects from the net metering cap and any net metering credit reductions.

Looking forward, the bill also requires the Department of Energy Resources (DOER) to "develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers."  The bill gives the Department guidance on the characteristics of that program, including that it must be one which: "promotes the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers," considers underlying system costs, takes into account electricity revenues and incentives, relies on market-based mechanisms or price signals, minimizes costs and barriers, features a declining incentive framework, differentiates incentive levels, "ensures that the utility customer realizes the direct benefits of the solar incentive program," considers the value of distributed generation and encourages solar generation where it benefits the distribution system, shares program costs collectively among all ratepayers, and promotes investor confidence through long-term incentive revenue certainty and market stability.

With the bill signed into law, the Department of Energy Resources is expected to open a rulemaking proceeding and solicit public comment on the development of the new solar incentive program.