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.