Top energy stories of 2015

As 2015 comes to a close, here's a quick guide to some of the year's top energy stories, organized by theme:

EPA Clean Power Plan

• FERC and EPA's Clean Power Plan
• US Clean Power Plan adopted
• Resources on Clean Power Plan

The Paris climate agreement

• Paris climate agreement walkthrough

Natural gas pipeline developments proposed, undergo permitting

• FERC issues EIS for Algonquin Incremental Market gas project
• Natural gas pipeline permitting reform

Renewable energy issues

• Controversy over renewable energy claims
• Report on Maine renewable portfolio standard
• Block Island offshore wind project celebrated
• US auctions NJ offshore wind sites

Coal-fired power plants continue to close

• Coal power plants retiring in 2015

A nuclear energy renaissance?

• Maine considers nuclear energy law

Grid modernization, energy storage, non-transmission alternatives

• Maine explores non-transmission alternatives
• CT examines energy storage
• NH explores electric grid modernization

FERC enforcement

• Feds settle on final 2011 Southwest blackout penalty

Mojave Water Agency conduit hydropower project qualifies

A California wholesale water provider has received a written determination from federal regulators that its proposed hydroelectric power project qualifies for easier regulatory treatment under federal law.  The project entails replacing a pressure reducing valve on an existing water supply pipeline with a hydropower turbine and generator, to create renewable electric energy.  Crucially, its qualification as a conduit hydropower project under a 2013 federal law enables its construction without a license under the Federal Power Act.

Under the Federal Power Act, most hydropower projects must be licensed by the Federal Energy Regulatory Commission.  But the Hydropower Regulatory Efficiency Act of 2013 amended the Federal Power Act to ease the regulatory burden on certain projects described as "conduit hydropower" -- those generating electricity using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  The 2013 reform law exempted qualifying conduit hydropower facilities from needing licensure, and created an expedited process for soliciting public comment and determining whether the exemption applies.

This reform has led to a resurgence of interest in developing in-conduit hydroelectric projects.  For projects meeting the qualifying criteria, the FERC can act swiftly in issuing a determination that no licensure is required.  In some cases, this determination can come less than 60 days after an applicant files its notice of intent.

FERC's first conduit hydro docket in fiscal year 2016, CD16-1, illustrates this pace.  In that docket, the Mojave Water Agency was able to secure a written determination that the project it proposed meets the qualifying criteria under section 30(a) of the Federal Power Act, and thus is not required to be licensed under Part I of the FPA.

Among other operations, the Mojave Water Agency stores and distributes water in California's High Desert region.  An existing 48-inch pipeline conveys raw water sourced from the State Water Project to the Mojave River Basin for groundwater recharge.  Currently, pressure is reduced through a sleeve valve before discharging the SWP water to the Mojave River Basin by gravity flow.  But under the proposed Deep Creek Hydroelectric project, a hydroelectric turbine will perform the pressure reducing function while powering a generator capable of producing renewable electric energy.  According to the Mojave Water Agency, the hydroelectric station capacity will be 800 kW, with annual estimated power generation of 5,424 MWh.

On October 13, 2015, the MWA applied to the FERC for a determination that the Deep Creek project is a Qualifying Conduit Hydropower Facility, meeting the requirements of section 30(a) of the Federal Power Act (FPA), as amended by section 4 of the Hydropower Regulatory Efficiency Act of 2013 (HREA).

On October 15, 2015, Commission staff issued a public notice that preliminarily determined that the project met the statutory criteria for a qualifying conduit hydropower facility, and thus was not required to be licensed under Part I of the FPA. The notice established a 45-day period for entities to contest whether the project met the criteria. No comments or interventions were filed in response to the notice.

As a result, on December 3 the FERC issued a letter constituting a written determination that the Deep Creek Hydroelectric Project meets the qualifying criteria under FPA section 30(a), and is not required to be licensed under Part I of the FPA.

Other proposed conduit projects have benefited from this quick timeline and relatively streamlined process.  Qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations.

ISO-NE Winter Reliability Program 2015 by the numbers

The operator of New England's electric grid is running a special Winter Reliability Program to address fuel security and power system reliability concerns, relating largely to natural gas pipeline constraints.  A December 2015 presentation by ISO New England, Inc.'s CEO provides initial cost and participation data on this winter's program.

More than 45% — about 13,650 MW—of the total generating capacity in New England uses natural gas as its primary fuel.  Out of this gas-fired capacity, ISO-NE's Winter Outlook has identified 4,220 MW of natural gas-fired generation at risk of not being able to get fuel when needed due to constraints on interstate natural gas pipelines.

As in 2013 and 2014, in 2015 ISO-NE again proposed a Winter Reliability Program to address concerns over reliability.  The 2015-2016 program includes 4 main components: oil, LNG, demand response, and dual-fuel commissioning.  According to a December 2015 presentation to the NEPOOL Participants Committee, program participation and expected cost exposure breaks down as follows:

Oil Program

• 81 units submitted intent to provide 4.464 million barrels
• Total eligible oil is anticipated to be 2.965 million barrels
• Total oil program cost exposure is anticipated to be $38.25M (@$12.90/barrel

LNG Program

• 8 units submitted intent to provide at least 1.42 million MMBTU
• Total eligible LNG is 1.278 million MMBTU
• Total LNG program cost exposure is anticipated to be $2.75M (@$2.15/MMBTU

Demand Response Program

• 7 assets submitted an intent to participate; 6 accepted by ISO-NE, to provide at least 26.5 MW of interruption capability
• Total DR program cost exposure is anticipated to be $132K

Dual-fuel Commissioning Program

•  6 units submitted intent to commission Dual Fuel Capability
• 4 units for 2014/15 (1,039 MW)
• 2 units for 2015/16 (735 MW)
• Total additional winter seasonal claimed capability represented: 1,774 MW

ISO-NE will release additional information on actual 2015/2016 Winter Reliability Program operations and costs over the winter period.

USDA REAP loan guarantee Maine funding available

Funding is available for energy projects at Maine's rural small businesses and agricultural producers through the USDA Rural Development agency's Rural Energy for America Program (REAP).  At stake is about $200 million in guaranteed loan funds available to finance renewable energy and energy efficiency projects in fiscal year 2016.

Since 2008, the USDA REAP program has provided grants and loan guarantees for renewable and energy efficiency projects at qualifying rural small businesses and agricultural producers.  Its loan program helps finance renewable energy systems and energy efficiency improvements.  Typical projects awarded funding in previous rounds include biomass fueled anaerobic digesters and biodiesel production, solar, wind, geothermal, efficient lighting conversions, motor upgrades, building envelope and HVAC improvements. 

REAP describes its loan guarantee program as lender-driven.  Usually, a qualifying farm or business will approach a lender to discuss financing a proposed project.  That lender then requests the USDA Rural Development loan guarantee, and if approved, makes and services the loan.  Guaranteed loan amounts can range from $5,000 to $25 million.  The guaranteed loan amount can cover up to 75% of the total eligible project cost, while 25% of project costs must come from other sources like business equity or other borrowed funds.

USDA Rural Development provides more information on its website about how to apply for a USDA REAP loan guarantee.  The Preti Flaherty team helps our clients understand how to benefit from REAP funding and other incentive programs for renewable energy and energy efficiency.  Contact Todd Griset to learn more.

FERC 2015 report on demand response, advanced metering

Staff of the Federal Energy Regulatory Commission have released their tenth annual report on demand response and advanced metering.  The FERC staff report, 2015 Assessment of Demand Response and Advanced Metering, provides an update on deployment of demand response and advanced metering.

Section 1252(e)(3) of Energy Policy Act of 2005 (EPAct 2005) directed the FERC to prepare and publish an annual report covering six sets of items:

• saturation and penetration rate of advanced meters and communications technologies, devices and systems;
• existing demand response programs and time-based rate programs;
• the annual resource contribution of demand resources;
• the potential for demand response as a quantifiable, reliable resource for regional planning purposes;
• steps taken to ensure that, in regional transmission planning and operations, demand resources are provided equitable treatment as a quantifiable, reliable resource relative to the resource obligations of any load - serving entity, transmission provider, or transmitting party; and
• regulatory barriers to improved customer participation in demand response, peak reduction and critical period pricing programs.

Previous reports have noted growth in the penetration of advanced metering and the value of demand response.  As in recent years, the 2015 FERC demand response report notes a continued increase in advanced meter penetration rates and the number of advanced meters in operation in the United States.

Based on 2013 data from the Energy Information Administration, the report suggests a 37.6 percent overall penetration rate.  It also shows a slightly higher percentage of residential customers have an advanced meter (37.8 percent) than do customers in the commercial (36.1 percent) or industrial (35.2 percent) customer classes.

At the same time, the FERC report shows a 4.9 percent drop in nationwide total potential peak reduction from retail demand response programs between 2012 and 2013, or a drop of 1,408 MW of demand response capability.  It also notes legal uncertainty over FERC’s final rule on demand response compensation in organized wholesale electric markets, Order No. 745, given that the U.S. Court of Appeals for the D.C. Circuit vacated and remanded that order in Electric Power Supply Association v. FERC, No. 11-1486 (D.C. Cir. May 23, 2014).  FERC's appeal of the EPSA v. FERC decision is now pending before the U.S. Supreme Court, with a final decision expected in early 2016.

Section 242 hydroelectric incentive program funding

For the first time, the U.S. Department of Energy has funding for its Section 242 hydroelectric incentive program.  The program, arising from Section 242 of the Energy Policy Act of 2005,  provides incentive payments for adding new turbines or other hydroelectric generating devices to existing sites. The Department is accepting applications for the incentive payments through February 1, 2016.

In 2005, as part of the Energy Policy Act of 2005, Congress created the Section 242 hydroelectric incentive program to support the expansion of hydropower energy development at existing dams and impoundments.  Section 242 establishes an incentive for qualified hydroelectric facilities, defined as "a turbine or other generating device owned or solely operated by a non-Federal entity which generates hydroelectric energy for sale and which is added to an existing dam or conduit."  The incentive is set at up to 1.8 cents per kilowatt-hour of net electric energy generated and sold by a qualified hydroelectric facility, indexed for inflation (about 2.3 cents per kilowatt-hour today) up to a maximum of $750,000 per year, for a specified 10-year period.

To get this money, an owner or operator must apply for the incentive payments.  An application for an incentive payment for electric energy generated and sold in a calendar year must be filed during the applications period defined by the Department of Energy in the Federal Register.  But according to the Energy Department's final guidance for the Section 242 program, "DOE will accept applications and make payments to qualified hydroelectric facilities in years when appropriations are available for this purpose."  Until recently, no such appropriations were available.

In Congressional appropriations for Federal fiscal year 2015, the Department of Energy received funds to support this hydroelectric incentive program for the first time. As shown in the conference report to the law that made appropriations for Fiscal Year 2015, Congress appropriated $3,960,000 for conventional hydropower under section 242 of EPAct 2005.

With funding now available, the Energy Department is only accepting applications from owners and authorized operators of qualified hydroelectric facilities for hydroelectricity generated and sold in calendar year 2014. Applications for this round of Section 242 funding are due by February 1, 2016.

FERC hydro dam relicensing, timing and options

Under U.S. law, the Federal Energy Regulatory Commission has jurisdiction over most hydropower dams and projects.  The Federal Power Act directs the Commission to issue licenses for hydropower projects for a defined term of years, and provides the basis for the FERC hydro relicensing process.  The relicensing process can take years, and often must be started before a licensee has made final long-term plans for the project's fate.  For example, what if a FERC licensee is considering surrendering the license and removing the dam, at the same time that its existing license approaches expiration and a relicensing application is due?

A recent order by FERC staff under its delegated authority in City of River Falls, Wisconsin, P-10489-014, illustrates this dynamic.  The City of River Falls, Wisconsin, holds the license for the River Falls Project on the Kinnickinnic River, in Pierce County, Wisconsin.  When the license for the River Falls Project was issued, the Commission determined that a 30-year term was appropriate and in the public interest.  That current license expires on August 31, 2018.

Because the FERC hydropower relicensing process can take years -- or longer -- licensees who wish to retain licensure are required to start the planning, stakeholder, and application filing processes early.  In the River Falls case, a relicense application will be due by August 31, 2016.  To get the ball rolling, in 2013 the City filed a Notice of Intent (NOI) to relicense the project and Pre-Application Document (PAD) and elected the Commission’s Traditional Licensing Process (TLP).

Meanwhile, the City of River Falls is trying to evaluate the project's future.  The City is considering surrendering the license instead of continuing with relicensing, and to draft and adopt a Kinnickinnic River Corridor Planning Strategy to "reflect a single community vision for the river, with or without the hydroelectric project."

But the studies and deliberation required to evaluate dam relicensing, surrender, or alternatives take time.  Meanwhile, the clock ticks toward license expiration.  The City tried to buy 5 more years, by asking FERC to extend the termination date of its existing license, so that it expires on August 31, 2023.  As described by FERC:

The City states the additional time is needed so that it does not spend time and money relicensing the project only to determine through its Corridor Plan that the license should be surrendered and the project decommissioned. The City believes that a lengthy and expensive licensing process is the wrong process for making such a determination. The City explains that a decision about the future of the project would be made by the fall of 2017, and a notice of intent to relicense the project or a surrender application would be filed no later than August 31, 2018.

The City's request was supported by public commenters, mostly on the theory that an extension would allow time to explore license surrender and dam removal.

But as expressed in the order, the Commission saw "no reason why the City cannot evaluate both license surrender and relicensing in the remaining time it has to file a relicense application (due August 31, 2016). In fact, analysis of studies and feedback from agencies would help inform its decision of whether or not to continue to pursue the project."  In particular, the Commission did not view the simultaneous City's Corridor Plan process as "unique circumstances or circumstances beyond the City’s control that prevent it from making a determination by August 31, 2016... as to whether to relicense or to surrender the project."

The Commission also distinguished the River Falls case from precedent where it has extended other license terms, either to enable a licensee to amortize the cost of substantial improvements to project facilities or substantial new environmental measures, or to coordinate the license expiration date with the expiration dates of other licenses in the same river basin.

Ultimately, the Commission denied the City of River Falls, Wisconsin’s application to extend the license term for the River Falls Project from August 31, 2018, to August 31, 2023.  As noted in the Commission's order, the "City remains able to work on both a relicensing option and a surrender option while it develops its Corridor Plan should the City wish to do so."

The City has filed its Notice of Intent and Pre-Application Document, and has received Commission approval to use the Traditional Licensing Process.  Any relicense application will be due 2 years before the current license expires, or on August 31, 2016.  In the meantime, the City will presumably continue to explore its options, including license surrender and dam removal, or relicensing the project.

FERC hydropower and successive preliminary permits

U.S. federal regulators can give a preliminary permit to the developer of a proposed hydropower projects -- but won't give out a successive permit unless the developer demonstrates it acted diligently under its prior permit.

Developers of proposed hydropower projects in the U.S. can apply for a preliminary permit from the Federal Energy Regulatory Commission.  During its term -- up to three years, according to the Federal Power Act -- a preliminary permit for a hydropower project does not authorize construction, but gives the permittee first priority to apply for a license for the project.  This exclusivity allows the permittee to study the site, communicate with stakeholders, and develop the information necessary to support a license application.  It also gives the permittee something of a "reservation" for the site during its term.  In exchange, the permittee must submit periodic reports on the status of its outreach efforts and studies.

Sections 4(f) and 5 of the Federal Power Act authorize the Commission to issue preliminary permits to potential license applicants for a period of up to three years.  While the statute does not specify how many preliminary permits an applicant may receive for the same site, the Commission's policy is to grant a successive preliminary permit only if it concludes that the applicant has pursued the requirements of its prior preliminary permit in good faith and with due diligence.   The Commission has noted that each application for a successive preliminary permit is considered on a case-by-case basis, but has described "a minimum bar that a permittee must achieve to be diligent."

A recent FERC delegated staff order in Coralville Energy, LLC, Project No. 14431-001, illustrates this policy.  On November 2, 2015, Coralville Energy applied to the FERC for a preliminary permit for the Burlington Street Dam Hydroelectric Project, to be located at the existing Burlington Street Dam on the Iowa River, near Iowa City in Johnson County, Iowa. 

But this was not Coralville Energy's first application relating to the Burlington Street; it had received a preliminary permit three years earlier, on October 18, 2012.  According to the 2015 order, the record under that prior permit "shows that Coralville Energy did not pursue the requirements of its prior permit with due diligence for purposes of receiving a successive permit because it fails to demonstrate progress toward preparing a development application."

In particular, the 2015 order notes that semi-annual reporting under the 2012 preliminary permit noted a series of items: late reports filed subsequent to Commission staff’s letters warning Coralville Energy of probable cancellation for failure to file progress reports; reports that were too brief, vague, and "nearly identical"; no change to the study plan from that proposed in 2012, suggesting no progress made toward the preparation of a development application; and no information about conducting, reviewing, or coordinating environmental studies or the status of the permittee’s efforts to obtain permission to access and use land not owned by the permittee.

By contrast, the order describes Commission staff's view that the requisite diligence requires completion of certain steps towards preparing a development application, including "developing study plans, conducting studies in a timely fashion, consulting with  resource agencies, and developing the application in accordance with the Commission’s regulations."  Additionally, Commission staff have said that it "must be able to discern a pattern of progress toward the preparation of a development application from the content of a permittee’s filings."

On this basis, the 2015 order denied Coralville Energy’s application for a successive preliminary permit.  The order illustrates FERC hydropower staff's perspective on the level of diligence expected of the holder of a preliminary permit.  It also highlights the importance of substantive action in pursuit of a license or development application as well as timely and adequate semi-annual reporting by preliminary permittees.

Paris climate agreement walkthrough

On December 12, the Parties to the United Nations Framework Convention on Climate Change adopted Decision 1/CP.21, adopting the Paris Agreement under that convention. The Paris Agreement itself is 12 pages long, and includes a preamble and 29 articles.  Its details merit a close read, as parties spent countless hours negotiating every word and piece of punctuation in the document.  Some articles have many operative clauses and address topics like temperature change and greenhouse gas emissions, while other articles are more ministerial.  Billions of dollars, and maybe the fate of the world, rests on the terms of these legal documents and how they are implemented.

Here's a overview-level walkthrough of the Paris Agreement:

• Preamble: recognizes climate change as a "common concern of humankind" and an "urgent threat" to which an "effective and progressive response" is necessary, that least developed countries and others may have specific needs, and interactions with other social values like food security, decent work and quality jobs, and "the importance for some of the concept of 'climate justice'".
• Article 1 provides definitions for Convention, Conference of the Parties, and Party.
• Article 2 defines the Agreement's aim as "to strengthen the global response to the threat of climate change, in the context of sustainable development and efforts to eradicate poverty," including a long-term temperature goal, a call for increased adaptation, and "making finance flows consistent with a pathway towards low greenhouse gas emissions and climate-resilient development."
• Article 3 requires all parties "to undertake and communicate ambitious efforts as defined in Articles 4, 7, 8, 10, 11, and 13" as "nationally determined contributions to the global response to climate change."
• Article 4 addresses the long-term temperature goal established in Article 2.  It requires each party to "prepare, communicate and maintain successive nationally determined contributions that it intends to achieve" and to pursue domestic mitigation measures.  Parties are expected to increase the level of ambition reflected in their nationally determined contributions over time.  Developed country parties are expected to take the lead, while supporting developing country parties and small island developing states.
• Article 5 calls for conservation and enhancement of sinks and reservoirs of greenhouse gases, including forests.  
• Article 6 recognizes that some parties may choose to pursue voluntary cooperation in implementing their nationally determined contributions.  It establishes a mechanism to promote and track "internationally transferred mitigation outcomes."  It also defines a framework to promote non-market approaches.
• Article 7 establishes a global goal of enhancing adaptive capacity, strengthening resilience and reducing vulnerability to climate change.  It requires parties to engage in adaptation planning processes and actions.  It also requires periodic "adaptation communication" reporting to the secretariat.
• Article 8 addresses averting, minimizing, and dealing with "loss and damage" associated with the adverse effects of climate change, "including extreme weather events and slow onset events."  It uses the Warsaw International Mechanism for Loss and Damage associated with Climate Change Impacts as its basis.
• Article 9 calls for developed country parties to provide financial resources to assist developing country parties with respect to both mitigation and adaptation, and to take the lead in "mobilizing climate finance from a wide variety of sources, instruments, and channels."
• Article 10 promotes technology development and transfer to "improve resilience to climate change and to reduce greenhouse gas emissions."
• Article 11 calls for "capacity-building", to enhance the capacity and ability of developing country and vulnerable parties to take effective climate change action such as adaptation and mitigation.
• Article 12 requires cooperation on "climate change education, training, public awareness, public participation and public access to information."
• Article 13 creates an "enhanced transparency framework for action and support" to build trust and confidence while allowing flexible and effective implementation.  It requires each party to regularly provide a "national inventory report of anthropogenic emissions by sources and removals by sinks of greenhouse gases," and information on how it has provided financial, technology transfer and capacity-building support to other countries.
• Article 14 requires a "global stocktake" -- that the parties periodically "take stock of the implementation of this Agreement to assess the collective progress towards achieving the purpose of this Agreement and its long-term goals."  Article 14 provides that the Conference of the Parties shall undertake its first global stocktake in 2023 and every five years thereafter unless the Conference otherwise decides.
• Article 15 establishes an expert-based committee as "a mechanism to facilitate implementation of and promote compliance with" the Paris Agreement.
• Article 16 provides procedures for aligning future meetings of parties to the Paris Agreement with the meetings of the Conference of the Parties.
• Articles 17, 18, and 19 provide procedures for the Convention secretariat, Subsidiary Body for Scientific and Technological Advice and Subsidiary Body for Implementation established by the Convention to also apply to the Paris Agreement.
• Article 20 provides processes for signature, ratification, acceptance, approval and accession of the Paris Agreement.
• Article 21 provides that the Paris Agreement "shall enter into force on the thirtieth day after the date on which at least 55 Parties to the Convention accounting in total for at least an estimated 55 percent of the total global greenhouse gas emissions have deposited their instruments of ratification, acceptance, approval or accession."
• Articles 22 and 23 provide processes for adopting any amendments or annexes to the Paris Agreement.
• Article 24 governs dispute resolution.
• Article 25 provides that each party shall have one vote, and establishes a process for "regional economic integration organizations" to vote as a bloc.
• Article 26 provides that the Secretary-General of the United Nations shall be the Depositary of the Paris Agreement.
• Article 27 prohibits any reservations being made to the Agreement.
• Article 28 provides a process for a party to withdraw from the Paris Agreement.
• Article 29 governs the original of the Paris Agreement.

The final language of the Paris Agreement's 29 articles, and Decision 1/CP.21 adopting the Paris Agreement, were each adopted by consensus by all of the 195 member states and the European Union participating in the COP21 summit.  Decision 1/CP.21 and the Paris Agreement will play important roles going forward as the world tackles climate change.  Their language will shape business, government, society, and the environment. 

Guide to the Paris climate agreement decision

Representatives from 195 countries signed a climate agreement on Saturday at the COP21 United Nations climate summit in Paris.  The resulting Paris climate agreement calls upon both developed and developing nations to reduce emissions of greenhouse gases, and establishes a framework for reviewing progress every five years.  This post examines the formal decision to adopt the Paris Agreement taken by the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change (UNFCCC).

Under the procedural rules governing the Conference of the Parties, the parties adopted "decision 1/CP.21", the draft of which was proposed by the President of the Conference of the Parties.  Decision 1/CP.21 formally adopts the Paris Agreement -- contained in an annex to the decision -- and creates processes supporting its implementation.

Decision 1/CP.21 emerges from the parliamentary procedures used by the U.N. and the Conference of the Parties.  Written in formal language, the draft decision includes a preamble and six active sections:

• The preamble recites the agreed-upon facts motivating the Paris agreement, such as, "climate change represents an urgent and potentially irreversible threat to human societies and the planet and thus requires the widest possible cooperation by all countries."
• Section I, "Adoption," formally adopts the Paris Agreement under the United Nations Framework Convention on Climate Change as contained in the annex, and establish the Ad Hoc Working Group on the Paris Agreement to facilitate its implementation.
• Section II, "Intended Nationally Determined Contributions," invites participating countries to submit "intended nationally determined contributions" towards achieving the objective of the Convention "as soon as possible and well in advance of the twenty-second session of the Conference of the Parties (November 2016)."
• Section III, "Decisions to Give Effect to the Agreement," includes sections covering mitigation, adaptation, loss and damage, finance, technology development and transfer, capacity-building, transparency of action and support, global stocktake, facilitating implementation and compliance.
• Section IV, "Enhanced Action prior to 2020," calls for "the highest possible mitigation efforts in the pre-2020 period," such as "the provision of urgent and adequate finance, technology and capacity-building support by developed country Parties in order to enhance the level of ambition of pre-2020 action by Parties," with a goal of jointly providing USD 100 billion annually by 2020 for mitigation and adaptation.
• Section V, "Non-Party Stakeholders," welcomes interest, participation, and parallel efforts by non-Party Stakeholders, such as "civil society, the private sector, financial institutions, cities and other subnational authorities."
• Section VI, "Administrative and Budgetary Matters," notes potential limits on available financial resources, and urges that parties voluntarily make additional resources available.

Through this COP21 decision, the Conference of Parties adopted the Paris Agreement itself.   In a companion post, I provide a walkthrough of the terms of the Paris Agreement itself.

Maine community renewable energy project winds down

Maine energy regulators will soon act on proposals for community-based renewable energy projects, as legal authority for a community energy pilot program winds down.

In 2009, the Maine Legislature enacted An Act To Establish the Community-based Renewable Energy Pilot Program, P.L. 2009, ch. 329.  The Act established a pilot program to provide incentives for the development of community-based renewable projects.  To qualify, projects must be “locally owned electricity generating facilities” (51% or more of the facility must be owned by “qualifying local owners”) and must not exceed 10 MW.  The Maine Public Utilities Commission was charged with administering the program, including certifying qualifying facilities.  To a community renewable energy project developer, the program offered the opportunity to win a long-term contract to sell project power to a Maine utility at predictable prices.

A 2015 law amended the community-based renewable energy program.  Among other changes, it required the Commission to perform a "viability assessment" of all projects that have been certified under the program but have not yet reached commercial operations.  For any projects the Commission determines will not be viable by December 31, 2018, the Act states that the Commission must revoke any contract awarded, though the projects will remain certified.  In September 2015, the Commission completed its viability assessment and identified approximately 21 megawatts of capacity that is available for contract awards. 

The 2015 law effectively provides that the Commission's authority to order utilities to enter into community-based renewable energy projects expires on December 31, 2015.   In light of the 21 megawatts of program capacity identified as available, on September 30, the Commission issued a request for proposals for projects seeking the remaining contract awards.

Proposals were due by November 6, 2015. According to the RFP,  the Commission will complete its evaluation of proposals and accept or reject proposals no later than December 31.

ORPC Maine files Western Passage preliminary permit application

A Maine-based tidal energy company has applied to federal regulators for a preliminary permit for a tidal energy project proposed for development off the coast.  ORPC Maine, LLC, a wholly-owned subsidiary of Ocean Renewable Power Company, LLC, filed its application with the Federal Energy Regulatory Commission on December 4, 2015, seeking a preliminary permit for the Western Passage Tidal Energy Project off the downeast city of Eastport.  The preliminary permit could set ORPC up to develop hydrokinetic energy generation at the site, though process and uncertainty lie ahead before the project could be developed.

ORPC filed its application for preliminary permit for the Western Passage project on December 4, 2015.  The FERC docketed the filing under P-14743.  As described in its application, the project would entail "a next generation TidGen® Power System with a buoyant tension mooring system (BTMS)."  The turbine generator unit, or TGU, would be similar to that installed by ORPC in Cobscook Bay in 2012.  While ORPC noted that it will determine the ultimate project configuration based on activities conducted during the preliminary permit phase, ORPC estimates the project will consist of approximately 15 total TGUs. The nameplate rating of each will be up to 500 kilowatts (kW) with the total project output capped at 5 MW.

ORPC previously held preliminary permits for the Western Passage site (P-12680) which expired on December 31, 2013. ORPC requested a successive preliminary permit on January 1, 2014, but the FERC issued an order denying a third preliminary permit for lack of extraordinary circumstances.

In its recent application, ORPC notes that it has "continued environmental studies and engagement with local stakeholders and regulatory officials regarding the Cobscook Bay Project, and have kept them informed regarding potential future plans for Western Passage," and highlights its other recent successes, including support from the U.S. Department of Energy and local stakeholders.

It is unclear whether the FERC will grant ORPC's application.  Assuming it does, the preliminary permit will give ORPC exclusive rights for 36 months to study the site, and priority to file an application for a project license.  That preliminary permit term should enable ORPC to study any technical and economic challenges relating to the Western Passage project -- after which the developer may be in a better position to evaluate the project's feasibility and support an application for a license.

Maine report on distributed solar

A report by staff of the Maine Public Utilities Commission to a working group convened by New England's electric grid operator describes growth in Maine's solar and other distributed generation resources. The report highlights faster growth in solar resources than some previous forecasts, at the same time that Maine reevaluates its solar net metering policies.

Under existing Maine law, electric utility consumers who develop solar energy projects can choose "net energy billing."  This net metering rate structure lets the customer offset its load from the grid by its own solar power production, with the utility bill based on the customer's net draw from the utility.  In the words of the Maine legislature, "net energy billing is a simple mechanism that has supported the development of distributed generation in Maine."  It is the principle state incentive for residential solar photovoltaic development.

Regional grid operator ISO New England, Inc. has convened a Distributed Generation Forecast Working Group to provide input on the region's long-term distributed generation forecast.  Staff from the Maine Public Utilities Commission recently presented to the working group on Maine's distributed generation growth. According to the December 8 report, solar PV makes up 78% of reported net metering capacity and is the fastest growing component.

The Maine Commission also submitted a forecast developed by the National Renewable Energy Laboratory of "Distributed PV Adoption in Maine through 2021".  Its predicts growth curves for Maine distributed solar generation under several scenarios:

 

But Maine is in the midst of a reevaluation of its solar energy policy.  In 2015, the legislature enacted a Resolve, "To Create Sustainable Growth in Maine's Distributed Energy Sector That Uses Market Forces To Fairly Compensate Energy Producers" (H.P. 863 - L.D. 1263, 2015).  That Resolve found that "net energy billing may not provide a suitable long-term foundation for distributed generation."

As a result, it directed the the Maine Public Utilities Commission to initiate a Solar Policy Design Stakeholder Process to develop "an alternative to net energy billing that fairly and transparently allocates the costs and benefits of distributed generation to all customers, allows participation by all customers and creates a sustainable platform for future growth of distributed generation to the benefit of all ratepayers."

The Commission stakeholder process is ongoing, under Docket 2015-00218.

Santee Cooper sets solar standby charge

The board of South Carolina's state-owned electric utility has approved a plan to increase retail rates and -- controversially -- add new charges for customers who install solar panels.  Santee Cooper is South Carolina's largest power producer, providing electricity for about 2 million people.  Its interim rider for distributed generation includes a "standby fee" charged to customers with rooftop solar projects and other customer-sited generation.  It also declined to adopt a net metering structure similar to those used by South Carolina's investor owned utilities.

Notably, Santee Cooper says it "supports development of solar power resources".  Its Distributed Generation Approach notes that Santee Cooper has generated solar energy for its customers since 2006, including demonstration projects across South Carolina.  Santee Cooper buys solar power from sources including the 3-megawatt Colleton Solar Farm.  The Colleton project, owned and operated by TIG Sun Energy, is South Carolina's largest solar installation.  Santee Cooper also offers its customers blocks of Green Power.
But residential solar projects aren't typically owned by or developed for utilities.  From the utility perspective, this means that the costs associated with serving customers with solar generation need to be recovered from ratepayers.  But the allocation of those costs among ratepayers is an issue.  Should they fall on all consumers equally?  Or should a rider or specific charge be added to recover these costs from the consumers who install distributed solar generation?

In Santee Cooper's case, the board approved a new charge, called a “standby fee,’’ on residential customers of $4.40 per month per kilowatt of installed solar capacity.  It also elected to use rebates and credits to reward customers for solar generation, instead of a net metering rate.  At the same time, the board set the rates for crediting generation at less than its retail rate.

From the utility perspective, it needed to adjust its rates to account for growth in rooftop solar and other distributed generation resources, and to protect customers who don't develop solar projects from unfairly bearing costs imposed by those who do.   Cost-shifting is a typical utility concern; the issue is to make sure that the allocation of consumer costs is fairly related to how the costs were incurred.
  
But from the perspective of advocates for rooftop solar and other distributed generation resources, a "solar fee" would deter people from developing alternative energy projects.  Under this view, these fees and rate structure are unnecessary and "penalize customers for exercising their right to use this clean, renewable resource."

Santee Cooper is not alone in considering how to adjust utility rates to handle more rooftop solar projects.  But its approach differs from that of South Carolina's largest investor owned utilities, Duke Energy Carolinas and South Carolina Electric and Gas, which have agreed to net energy metering and solar development targets.

How should utility rate design allocate the costs and benefits of connecting distributed solar projects to the grid?  How can essential fairness in ratemaking be balanced against policy values like customer choice and renewable energy?

Merced River hydro relicensing Environmental Impact Statement released

Staff of the Federal Energy Regulatory Commission have released a final Environmental Impact Statement (EIS) evaluating proposals to relicense two hydroelectric power projects located on the Merced River in California.

The two projects are Merced Irrigation District’s existing 101.25 megawatt Merced River Project No. 2179-043, and Pacific Gas and Electric Company’s (PG&E) existing 3.4-MW Merced Falls Project No. 2467-020.  Prepared as part of the relicensing process for those projects, the Merced River EIS contains FERC staff evaluations of the applicants’ proposals and the alternatives for relicensing the Merced River and Merced Falls Hydroelectric Projects.  The staff’s recommendation is to relicense the project as proposed, with certain modifications, and additional measures recommended by the agencies.

The Federal Energy Regulatory Commission is authorized by the Federal Power Act to issue licenses for up to 50 years for the construction and operation of nonfederal hydroelectric development subject to its jurisdiction, on condition:

That the project adopted…shall be such as in the judgment of the Commission will be best adapted to a comprehensive plan for improving or developing a waterway or waterways for the use or benefit of interstate or foreign commerce, for the improvement and utilization of water-power development, for the adequate protection, mitigation, and enhancement of fish and wildlife (including related spawning grounds and habitat), and for other beneficial public uses, including irrigation, flood control, water supply, and recreational and other purposes referred to in section 4(e)…

The Commission may also require such other conditions not inconsistent with the FPA as may be found necessary to provide for the various public interests to be served by the project.  To assist in this evaluation, and as required by the National Environmental Policy Act, FERC staff prepares the EIS.  It is designed to record the view of governmental agencies, non-governmental organizations, affected Indian tribes, the public, the license applicants, and FERC staff.

In the Merced River cases, the licensees used FERC's Integrated Licensing Process (ILP) and filed relicensing applications in February 2012.  FERC elected to process the applications for the two projects together "because they: (1) are located contiguously on the Merced River; (2) the Merced Falls Project’s operation depends entirely on flows released by the upstream Merced River Project; and (3) downstream of the Merced River Project, the environmental effects of both projects are interrelated."

Each applicant proposed some modified environmental measures in its license application, but no new capacity and no new construction at the project.  In the Merced projects' 840-page final EIS, Commission staff noted that the "primary issues associated with relicensing the projects are flow regimes in project-affected reaches for aquatic resources, project effects on physical habitat for aquatic resources, protection of wildlife resources, recreation enhancements, and protection of cultural resources." After consideration, Commission staff recommended the staff alternative, which consists of measures included in Merced ID’s and PG&E’s proposals, as well as some of the mandatory conditions and recommendations made by other state and federal agencies and non-governmental organizations, plus additional measures developed by FERC staff:

We chose the staff alternative as the preferred alternative because: (1) the projects would provide a dependable source of electrical energy for the region; (2) the generation comes from a renewable resource that does not contribute to atmospheric pollution, including greenhouse gases; and (3) the recommended environmental measures proposed by Merced ID and PG&E, as modified by staff, would adequately protect and enhance environmental resources affected by the projects. The overall benefits of the staff alternatives would be worth the cost of the environmental measures.

Ultimately, the Merced River hydropower relicensing project EIS concludes that "issuing new licenses for the Merced River and Merced Falls Projects, with the environmental measures we recommend, would not be major federal actions significantly affecting the quality of the human environment."

Maine court interprets wind energy law

Maine's highest court has issued an opinion interpreting Maine's laws governing wind energy project development.  The opinion, Champlain Wind, LLC v. Board of Environmental Protection, 2015 ME 156, is noteworthy for its analysis of "competing legislative purposes" in Maine wind energy law -- those designed to expedite the development of wind power in Maine, and those designed to protect scenic resources.

The Maine Supreme Judicial Court's December 3, 2015 opinion affirms an earlier decision by the state Board of Environmental Protection to deny a permit for the Bowers Wind Project.  In 2012 developer Champlain Wind had filed a consolidated application with the Maine Department of Environmental Protection, seeking state permits to construct the project.  As described in the opinion, that project would include 16 wind turbines with a combined generating capacity of 48 megawatts.  Geographically, the turbines fell "just within the boundary" of an area designated by the state Legislature for expedited wind energy development.  However, its turbines would be visible from nine great ponds classified as a "scenic resource of state or national significance" under state law.  Maine law gives enhanced protections to such scenic resources in wind project siting decisions affecting specified geographic areas.

After some process, the Department ultimately denied Champlain's application.  In so doing, the Department concluded that the project met all but one applicable standard.  The Department found that the project “would have an unreasonable adverse effect on the scenic character and existing uses related to the scenic character” of the nine affected great ponds.  This failure of the statutory scenic character standard led the Department to deny the requested consolidated permit.

Champlain appealed from the Department's denial to the Board of Environmental Protection.  The Board issued an order in June 2014 affirming the Department's denial.  Champlain appealed again, this time to the Maine Supreme Judicial Court.

The court's opinion on that case was published today.  Much of the court's opinion focuses on specific legal arguments in play -- for example, whether the Board could take an aggregated or "holistic approach" when considering a proposed project's impact on multiple scenic resources of state or national significance, and the level of judicial deference the court should afford the Board.

But for those interested in Maine wind energy development law, the most interesting parts of the opinion are likely those showing how the court interprets the Maine Wind Energy Act and related statutes.  As characterized in the introduction to the court's opinion,

the Board considered and balanced competing statutorily defined policies applicable to wind energy projects in Maine. The applicable statutes establish the dual policies of expediting wind energy development in defined geographic areas of Maine and at the same time providing enhanced protection for specific scenic resources. 

In its discussion, the court noted:

The generating facilities and wind turbines that make up the Project are proposed to be sited within the expedited permitting area; however, most of the nine great ponds affected by the Project—all of which are rated as outstanding or significant from a scenic perspective—are fully excluded from the expedited permitting area. Thus, as previously noted, the Board was confronted with a project that falls directly between competing legislative priorities.

The court recited the Board's consideration as having included:

• the “existing character of the surrounding area” and “significance of the potentially affected scenic resource,” see 35-A M.R.S. § 3452(3)(A), (B);
• the Legislature’s intent in balancing the goal of encouraging and expediting wind power development with the goal of protecting Maine’s scenic resources by limiting the geographic scope of the expedited permitting area; 
• the exclusion of most of the nine affected great ponds from the expedited permitting area; and 
• the unique interconnectedness of the affected great ponds, which would result in users being repeatedly confronted with views of the turbines from multiple scenic resources of state or national significance when traveling from one lake to another.

The court described these as "unique circumstances" and a "context of competing legislative priorities and unusually interconnected scenic resources."  In the court's view, presented with these circumstances and this context, it wasn't unreasonable, unjust, or unlawful for the Board to decline to issue the permit.  Because the court could not conclude that the Board acted unlawfully or arbitrarily or that the statutes compel a different result, the court deferred to the Board’s interpretation of the Maine Wind Energy Act and the statutes governing expedited permitting for grid-scale wind energy projects.

This opinion likely is most direct in its effect on those interested in the Bowers Wind Project, the parties and other stakeholders.  The Champlain Wind, LLC v. Board of Environmental Protection opinion may also catalyze renewed discussion about balancing what the court labeled "competing legislative purposes" in Maine wind energy project siting law -- on the one hand, to expedite the development of wind power in Maine; on the other, to protect scenic resources. 

US evaluates South Carolina offshore wind interest

The U.S. Bureau of Ocean Energy Management has taken action that could ultimately lead to it leasing sites off South Carolina for offshore wind development.

Offshore wind is an abundant renewable resource.  If it can be captured, it could be used to produce electricity without many of the impacts of traditional power plant construction and operation.  To date, no commercial offshore wind project is operating in U.S. waters, though globally over 11,800 megawatts of offshore wind capacity is expected by year's end.

President Obama has included development of U.S. offshore wind resources in his Climate Action Plan. Under federal law, the Department of Interior controls most energy and development activities over the Outer Continental Shelf.  Within the Interior Department, the Bureau of Ocean Energy Management or BOEM has responsibility for evaluating interest in leasing and developing sites.

To date BOEM has awarded nine commercial wind energy leases in federal waters off the Atlantic coast.  The New Jersey offshore wind auction held on Nov. 9, 2015 yielded two more lease awards that are now pending Department of Justice and BOEM review.  Including these, competitive lease sales have generated more than $15.7 million in revenue for over one million acres in federal waters.

Under BOEM's process, leasing efforts typically begin with consultation with state stakeholders and task forces.  In South Carolina's case, BOEM held at least four task force meetings between 2012 and the present.  That stakeholder engagement occurred primarily through the South Carolina Intergovernmental Renewable Energy Task Force, composed of federal, state, local, and tribal government representatives.

Following stakeholder process, a preliminary formal step is BOEM's issuance of a Call for Information and Nominations.  The Call document is designed to evaluate industry interest in acquiring commercial wind leases in one or more defined Call Areas, and to solicit feedback about site conditions, resources and other uses in and near those areas. 

For South Carolina, BOEM issued its Call for Information and Nominations on November 23, 2015.  After consultation with the South Carolina Intergovernmental Renewable Energy Task Force, BOEM identified four areas in federal waters offshore South Carolina where commercial wind energy leasing could take place.  These so-called “Call Areas” are named Grand Strand, Cape Romain, Winyah and Charleston, and total about 1,167 square nautical miles.

BOEM also published in the Federal Register a Notice of Intent to Prepare an Environmental Assessment (EA), a review process required under the National Environmental Policy Act.  The EA will consider potential environmental and socioeconomic impacts associated with issuing commercial wind leases and approving site assessment activities on the lease areas.  To inform its analysis, BOEM issued the Notice of Intent to seek public comment for determining significant issues and alternatives to be analyzed in the EA.

While the ultimate outcome of BOEM's South Carolina offshore wind site leasing efforts remains to be seen, the publication in the Federal Register of the Call and Notice of Intent on November 25, 2015, represents the passing of key milestones along the path.

House subcommittee holds hearing on FERC oversight

Members of the Federal Energy Regulatory Commission testify today before the House Energy & Commerce Committee, Subcommittee on Energy and Power, as that committee considers its oversight of the FERC.

The FERC is an independent administrative agency within the Department of Energy.  Its mandate includes regulating the transmission, reliability, and wholesale sale of electricity in interstate commerce pursuant to the Federal Power Act; the transmission and sale of natural gas for resale in interstate commerce pursuant to the Natural Gas Act; the transportation of oil by pipeline in interstate commerce pursuant to the Interstate Commerce Act; and evaluating proposals to build liquefied natural gas (LNG) terminals and interstate natural gas pipelines, as well as the licensing of non - federal hydropower projects.

As described in a committee background memorandum for today's hearing, the Subcommittee on Energy and Power is exploring whether FERC’s statutory authorities require modernization to reflect current energy realities.  Chief among those statutory authorities are the Federal Power Act and the Natural Gas Act.  The committee memorandum also notes an interest in evaluating "whether FERC is overstepping its existing statutory boundaries to pursue policy goals not intended by Congress."

Specific issues expected to be examined at the hearing include:

• Potential impacts of the U.S. EPA's Clean Power Plan rule on electricity markets, fuel diversity, and electric reliability;
• Commission oversight of organized wholesale electricity markets and their operation
• Risks to the security of the electric grid, including physical and cyber security, geomagnetic disturbances, electromagnetic pulse, and severe weather;
• How to integrate renewable, intermittent resources and distributed generation;
• The role of demand response and other demand-side management technologies in wholesale markets, at issue in the EPSA v. FERC case pending before the U.S. Supreme Court; 
• Electric transmission operations and planning, including implementation of Order No. 1000;
• Natural gas pipeline permitting, LNG siting, and hydropower licensing;
• FERC market manipulation authorities and enforcement practices; and
• FERC’s implementation of the mandatory purchase obligation from qualifying facilities (QFs) under section 210 of the Public Utility Regulatory Policies Act of 1978.

Based on prefiled documents, today's hearing features:

• testimony by FERC Chairman Norman Bay
• testimony by Commissioner Cheryl LaFleur
• testimony by Commissioner Tony Clark
• testimony by Commissioner Colette Honorable

More information about today's hearing can be found on the committee's webpage.