Coal power plants retiring in 2015

Thursday, May 21, 2015

The U.S. portfolio of electric power plants will continue to shift in 2015, according to a federal assessment projecting that nearly 16 gigawatts (GW) of generating capacity will retire in 2015.  Most of the capacity to be retired this year is coal-fired generation.  This continues a multi-year trend away from coal, and toward natural gas and renewable resources.

According to the U.S. Energy Information Administration, nearly 16 GW of generating capacity is expected to retire in 2015.  Of this, 81% (12.9 GW) is coal-fired generation.  Generator retirements are heavily composed of coal-fired generation, split between bituminous coal (10.2 GW) and subbituminous coal (2.8 GW).  Most of this retiring coal capacity is found in the Appalachian region, with slightly more than 8 GW combined in Ohio, West Virginia, Kentucky, Virginia, and Indiana.

New environmental regulations and struggles to remain cost-competitive explain most of these retirements.  This year, the Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) take effect.  MATS requires existing large coal- and oil-fired electric generators to meet stricter emissions standards by retrofitting the units with new emissions control technologies.  While some units have been granted extensions to operate through April 2016, some power plant operators are choosing to retire units instead of making cost-prohibitive investments in pollution control.

Most of the coal-fired units slated for retirement are smaller and operate at a lower capacity factor than average coal-fired units in the United States.  According to EIA, the to-be-retired units have an average summer nameplate capacity of 158 MW, just 60% as big as the 261 MW average for other coal-fired units.  In 2014, the average capacity factor for all coal units was 61%, but the subset of coal units retiring in 2015 had an average capacity factor of just 36%.  The relatively small size and low capacity factor of these power plants make it harder for them to compete economically against other generation sources.  This competition is especially difficult if sufficient natural gas-fired generating capacity is available, as the cost of natural gas has fallen to levels not seen since 2012.

The coal capacity retiring in 2015 accounted for 1.6% of total U.S. generation during 2014.  At the same time, electric generating companies expect to add more than 20 GW of utility-scale generating capacity to the power grid.  This new capacity is dominated by wind (9.8 GW), natural gas (6.3 GW), and solar (2.2 GW), which together compose 91% of expected new capacity in 2015.

House subcommittee considers reliability draft

Tuesday, May 19, 2015

A congressional committee is considering legislation to assure reliability and security of the U.S. electricity grid.  The House Subcommittee on Energy and Power's discussion draft includes a series of provisions designed to harden the grid against disturbance.

To understand the discussion draft, you must first understand its context.  2015 is a time of great change for the U.S. electricity system.  The grid continues to shift away from coal-fired generation and towards use of natural gas and renewable energy sources.  New environmental regulations affecting power plants are taking effect.  Smart grid technology now enables real-time communication and coordination between supply and demand for electricity, but creates millions of potential access points for hackers to target the grid.  Meanwhile utilities plan to invest more than $60 billion in transmission infrastructure over the next decade. 

Faced with these shifts, the House Subcommittee on Energy and Power held a hearing today on a "discussion draft" of proposed measures to strengthen grid reliability, security and readiness to survive disturbance.  The discussion draft includes measures that would:
  • Resolve conflicts between choosing whether to comply with an emergency order from the Department of Energy or violate environmental obligations;
  • Require the Federal Energy Regulatory Commission to complete an independent reliability analysis of any proposed or final major federal rule that affects electric generating units;
  • Direct the Secretary of Energy to develop and adopt procedures to enhance communication and coordination between governmental entities and the private sector to improve emergency response and recovery;
  • Give the Secretary of Energy powers to address grid security emergencies, and facilitate information sharing;
  • Require the Energy Department to submit a plan to Congress evaluating the feasibility of establishing a Strategic Transformer Reserve for the storage, in strategically-located facilities, of spare large power transformers in sufficient numbers to temporarily replace critically damaged large power transformers;
  • Direct DOE to create a voluntary Cyber Sense program to identify cyber-secure products and technologies intended for use in the bulk-power system, like controls and SCADA systems;
  • Directs state public utility commissions and utilities to improve grid resilience and promote investments in energy analytics technology to increase efficiencies and lower costs for ratepayers while strengthening reliability and security; and
  • Require FERC to work with each regional transmission organization to encourage a diverse generation portfolio, long-term reliability and price certainty for customers, and enhanced performance assurance during peak period.
As noted in the opening statements of Chairmen Ed Whitfield and Fred Upton, elements from this discussion draft may be included in a bipartisan energy bill expected to emerge from the House committee later this session.

FERC proposes geomagnetic disturbance reliability standard

Thursday, May 14, 2015

Is the U.S. electric grid ready for solar storms and other geomagnetic disturbances?  Today the Federal Energy Regulatory Commission proposed approving a new reliability standard for the grid to address its vulnerability to these hazards.

A utility substation near Treasureton in southeast Idaho.

Periodic activity on the Sun's surface sends powerful waves of energetic particles toward the Earth.  These solar events can distort the Earth's magnetic field, affecting the flow of electricity on Earth.  While serious geomagnetic disturbances are expected to be infrequent, they can cause blackouts and damage key utility infrastructure.

The Federal Energy Regulatory Commission has jurisdiction over the reliability of the U.S.'s bulk electric power system.  To this end, it has designated the North American Electric Reliability Corporation (NERC) as the nation's electric reliability organization.  In May 2013, FERC directed NERC to develop and submit new standards for protecting the grid against geomagnetic disturbances (Order No. 779)

FERC and NERC have proceeded in a two-stage process.  First, in June 2014 FERC approved a standard on implementation of operating plans, procedures and processes to mitigate effects of geomagnetic disturbances (Order No. 797).

Reserved for the second stage were further requirements that transmission planners and owners assess the vulnerability of their systems to a theoretical benchmark event.  NERC subsequently proposed such a standard, calling for an evaluation of what would happen in a “one-in-100-year” benchmark event.

In a Notice of Proposed Rulemaking issued today, the FERC proposes to largely adopt NERC’s proposed second-stage standard.  The standard would require covered entities to have system models needed to complete vulnerability assessments, to have criteria for acceptable steady state voltage performance during a benchmark event, and to complete a vulnerability assessment once every 60 calendar months. If the assessment indicates that a system does not meet the performance requirements, the entity would have to develop a corrective action plan addressing how the requirements will be met.

The proposed rulemaking would direct NERC to further modify its standard to require that the study and benchmarking of geomagnetic disturbance events is based on a more complete set of data and a reasonable scientific and engineering approach.

Comments on today’s Notice of Proposed Rulemaking are due 60 days after its publication in the Federal Register.

Geomagnetic disturbances, and their impacts to the grid, are a hot topic in energy regulation at the present. States are considering laws regulating utility readiness for and response to geomagnetic disturbances; for example, next week the Maine Legislature’s Joint Standing Committee on Energy, Utilities, and Technology will consider LD 1363, An Act To Secure the Maine Electrical Grid from Long-term Blackouts.

ISO-NE projects slow growth in electricity demand

Wednesday, May 13, 2015

New England's electric grid operator predicts slow growth in annual energy usage in the region over the next decade, with slightly quicker growth in peak demand.

A Maine power plant -- the ecomaine Waste-to-Energy plant in Portland, Maine.

ISO New England, Inc. develops an annual long-term load forecast using factors including state and regional economic forecasts and 40 years of weather history.  Its most recent baseline forecast projects a compound annual growth rate of 1.0% in total energy usage in New England from 2015 to 2024.  For 2015, ISO-NE projects 138,745 gigawatt-hours (GWh) of load, growing to 152,280 GWh in 2024.

ISO-NE's forecast also projects future peak demand, a measure of the highest amount of electricity used in a single hour in New England.  Often, peak demand drives the need for constructing and maintaining power plants and transmission lines (and energy efficiency investments).  According to the latest ISO-NE forecast, New England's peak electricity demand is projected to rise by a compound annual growth rate of 1.3%, from 28,395 MW this year to 31,905 MW in 2024.

These baseline projections for future peak demand and energy usage take into account load reductions that can be expected from future installations of distributed solar photovoltaic facilities.  ISO-NE has prepared a separate Distributed Generation Forecast to estimate the load-reducing effects of distributed solar facilities developed as a result of state policy goals.

ISO-NE's baseline projections do not account for significant energy-efficiency savings, neither those committed through the region’s three-year Forward Capacity Market (FCM) nor future savings that can be expected beyond the FCM timeframe.

Report on Maine renewable portfolio standard in 2013

Wednesday, May 6, 2015

The Maine Public Utilities Commission has issued a report on Maine's use of renewable electricity in 2013.  The report shows the impact of Maine's renewable portfolio standard, a state law requiring electricity suppliers to source specified percentages of their electricity from “new” renewable resources.

Since 2000, Maine law has required electricity suppliers to include renewable energy in their portfolio of supply sources.  Maine’s original electric industry restructuring legislation included a 30% eligible resource portfolio requirement. The eligible resource portfolio requirement, now referred to as Class II, mandated that each retail competitive electricity supplier meet at least 30% of its retail load in Maine from “eligible resources.”  Eligible resources are defined in statute as either renewable resources or efficient resources.  Renewable resources are defined in statute as fuel cells, tidal power, solar arrays, wind power, geothermal installations, hydroelectric generators, biomass generators, and municipal solid waste facilities. Renewable resources may not exceed a production capacity of 100 megawatts. “Efficient” resources are cogeneration facilities that were constructed prior to 1997, meet a statutory efficient standard and may be fueled by fossil fuels.

During its 2007 session, the Maine Legislature enacted an Act to Stimulate Demand for Renewable Energy.  This Act established a new "Class I" standard, requiring Maine electricity suppliers to source specified percentages of their electricity from “new” renewable resources.  Generally, new renewable resources are renewable facilities that have an in-service date, resumed operation or were refurbished after September 1, 2005.  The Act set the initial renewable percentage requirement at 1% in 2008, increasing in annual one percentage point increments to 10% in 2017.  Pursuant to the Act, the renewable requirement will remain at 10% thereafter, unless the Commission suspends the requirement.

The Commission's March 31, 2015 report, Annual Report on New Renewable Resource Portfolio Requirement, reports on renewable portfolio standard compliance activity in calendar year 2013.  This lag between the study period and the report's issuance is driven by the timing of the most recently filed Competitive Electricity Provider (CEP) annual compliance reports, which were filed in July 2014 for calendar year 2013.  In 2013, the Act required suppliers to source 5% of their power from new renewable resources.  Suppliers can comply either by acquiring sufficient renewable energy certificates or RECs to cover their compliance obligation, or by paying an "alternative compliance payment".

According to the report, in 2013 suppliers purchased 727,291 Class I RECs from 21 certified generating facilities to meet the portfolio requirement.  Nearly 97% of these RECs came from biomass facilities located in Maine.  According to the report, 17 of the 21 facilities are biomass, three are hydro, and one is a wind facility.  18 of the 21 facilities are located in Maine, one is located in Connecticut, one is located in Massachusetts and one is located in Vermont.

The Commission's report also documents the cost of compliance in 2013.  During 2013, the cost of RECs used for compliance with the Class I requirement ranged from approximately $1.50 per MWh to $60 per MWh, with an average cost of $19. 8 7 per MWh and a total cost of $14, 292,438.  As noted in the report, the cost of Maine Class I RECs has dropped substantially since 2013, with the report citing a current trading range of $3.00 to $5.00.  With minor use of the alternative compliance mechanism by two suppliers, the total cost to ratepayers during 2013 was $14,296,249, which the Commission's report translates into an average rate impact of about 0.12 cents per kWh (about 60 to 65 cents monthly for a typical residential bill, or a residential customer bill impact of about 1%).

The report also documents the 2013 costs of RECs used to satisfy the "Class II" eligible resource portfolio requirement as ranging from $0.00 per MWh (some RECs were included as part of an energy transaction at no specified extra cost) to $1.00 per MWh, with an average cost of $0.16 per MWh and a total cost of $589,386. This translates into less than three cents per month on a typical residential bill.

Champlain Hudson Power Express gets Army Corps permit

Monday, May 4, 2015

The Champlain Hudson Power Express, an electric transmission line proposed from Quebec to New York, has completed its federal permitting process according to project developer Transmission Developers Inc.

Project developer TDI is a Blackstone portfolio company, with an apparent focus on HVDC lines.  First proposed in 2008, the current incarnation of the Champlain Hudson Power Express is a 333-mile high voltage direct current (HVDC) transmission line to be installed underground and underwater, from the U.S.-Canada border to New York City, running down Lake Champlain and parts of the Hudson River.  The line is slated to be able to import up to 1,000 megawatts of power from Canada to the U.S. 

In a press release issued last month, TDI announced that the U.S. Army Corps of Engineers has issued a permit that allows the Champlain Hudson Power Express project to be placed in waters of the United States along its proposed route.  The permit authorizes TDI to construct the project pursuant to Section 10 of the Rivers and Harbors Act and Section 404 of the Clean Water Act.

According to TDI, the Army Corps permit represents the final federal or state permit necessary to begin construction.  According to the permit, the work authorized must be completed by December 30, 2019.

More hydropower relicensure expected

Thursday, April 16, 2015

Many U.S. hydropower projects face relicensure by the Federal Energy Regulatory Commission within the next 3 years, making hydro project relicensing a hot topic.

The FERC is the nation's primary federal regulator of hydropower facilities.  Under Part I of the Federal Power Act, the Commission's responsibilities over hydropower include issuing licenses for the construction of new projects, relicensing for the continuance of existing projects, and oversight of all ongoing project operations, including dam safety inspections and environmental monitoring.

According to the Commission, about 1,023 issued licenses were active as of April 1, 2015.  Licenses are typically effective for up to 50 years, largely because dams and hydroelectric power facilities are typically long-lived assets and because the regulatory process for licensure is extensive (and expensive for project developers or owners).  Nevertheless, as time marches on, even a 50-year license will ultimately expire, so owners of FERC-licensed hydropower projects must eventually evaluate relicensure

Federal law and regulations, including Section 15(b)(1) of the Federal Power Act and 18 C.F.R. §5.5 of the Commission’s regulations, govern the relicensure process.  Between 5 and 5.5 years before an existing license expires, the licensee must notify the Commission whether or not it intends to file an application for a new license.  This filing is known as a Notice of Intent or NOI.  At the same time, the licensee seeking relicensure must also file a Pre-Application Document (PAD).  The PAD must include: (1) a process plan and schedule; (2) a description of the project’s location, facilities, and operation; (3) a description of the existing environment at the project and its resource impacts; (4) a preliminary list of issues and proposed studies; and (5) a list of contacts.  A licensee must also distribute the PAD to appropriate federal, state, and interstate resource agencies, Indian tribes, local governments, and members of the public likely to be interested in the project’s relicensing.

The Commission has noted an anticipated uptick in the rate of relicensure applications.  From October 1, 2010 through September 30, 2014, the Commission has received an annual average of about 12 Notices of Intent to relicense hydroelectric projects.  According to the FERC, 47 licensed projects were in the relicensure process as of April 1.  But even more projects face relicensure in the next 3 years.  According to an April 1 notice issued by the Commission, about 100 FERC-licensed hydropower projects will begin the relicensing process between October 1, 2016, and September 30, 2018.  The Commission thus anticipates the annual average number of Notices of Intent to increase to about 34.

Owners of FERC-licensed hydropower projects nearing the end of their license terms must plan ahead to prepare for relicensure.  Given the expected increase in hydroelectric project relicensure, Commission staff reasonably expects an increase in their workload.  While most existing projects have historically been able to win new licenses, in some cases hydropower project relicensing can become controversial.  Expect the next several years to bring increased relicensing activity.

Maine considers nuclear energy law change

Monday, April 13, 2015

The Maine legislature is considering a proposal to amend state laws regarding the siting and construction of new nuclear power plants. The bill known as LD 1313, "An Act To Amend the Laws Regarding Nuclear Power Generating Facilities", is listed as a "Governor's Bill", indicating its origin from Maine Governor Paul LePage. What might LD 1313 mean for Maine?

Maine is not currently home to any operating nuclear power plants.  From 1972 to 1996, the Maine Yankee Nuclear Power Plant operated a 900 megawatt reactor in Wiscasset.  While it operated, Maine Yankee was the state's largest generator of electricity.  But a Nuclear Regulatory Commission investigation launched in 1995 identified safety and other problems that ultimately rendered continued plant operation uneconomic; the site was decommissioned from 1997 through 2005, with spent fuel remaining on site to date.

Maine Yankee was controversial from its inception, with significant opposition to its construction from anti-nuclear groups and others.  Partially in response to this controversy, in 1987 Maine enacted a law "to provide for citizen participation in any decision to construct a nuclear power plant within the State."  As part of that law (as amended in 1999), the Legislature enacted a finding "that construction of a nuclear power plant is a major financial investment, which will have consequences for consumers for years to come."  The law also included a finding that, "In the recent past, investments in nuclear power plants have caused severe financial strain on consumers."  In addition, the law required a statewide voter referendum prior to the construction of any nuclear power plant in Maine, and prohibited construction of a nuclear power plant without this voter approval.

Governor LePage's proposal would amend those two sections of existing law relating to the process for siting nuclear power plants.  First, LD 1313 would delete the legislative finding that "In the recent past, investments in nuclear power plants have caused severe financial strain on consumers." Second, LD 1313 would limit the referendum requirement to nuclear power plants "with capacity greater than 500 megawatts."

LD 1313 would appear to encourage the construction of relatively small nuclear power plants in Maine -- that is, those with capacity of 500 megawatts or smaller, roughly half of Maine Yankee's size.  But of the approximately 100 nuclear power plants in commercial operation in the U.S. today, nearly all can generate more than 500 megawatts of power.  The Omaha Public Power District's Fort Calhoun plant in Nebraska is rated at 476 megawatts, and is one of the only commercial reactors in the U.S. smaller than 500 megawatts.  The technical and security aspects of nuclear power have traditionally pushed utilities to develop relatively large nuclear power plants, making the development of small but traditional nuclear power in Maine relatively unlikely.

Perhaps more likely to benefit if LD 1313 is enacted would be the development of small modular nuclear reactors.  According to the U.S. Department of Energy, small modular reactors offer the advantage of lower initial capital investment, scalability, and siting flexibility at locations unable to accommodate more traditional larger reactors.  They also have the potential for enhanced safety and security.  The Department of Energy has expressed interest in advancing small modular reactor technology.  If LD 1313 is enacted, it could eliminate the requirement of statewide voter approval of the construction of a nuclear power plant using small modular reactor technology.

But whether LD 1313's enactment would actually lead to the construction of small modular reactors in Maine is unclear.  Is the voter referendum requirement really the chief obstacle to small modular reactor construction in Maine?  Or can Maine's lack of small modular reactors be explained by other limitations -- like technology, financing, or safety regulations?

LD 1313 has been referred to the Maine State Legislature's Joint Standing Committee on Energy, Utilities and Technology.  To date, no public hearing has been scheduled.

Energy Department to fund low-impact hydropower R&D

Friday, April 10, 2015

The U.S. Department of Energy has announced $7 million in funding for the research and development of advanced low-impact hydropower systems.  The Energy Department's competitive solicitation is designed to fund projects that help advance hydropower drivetrains -- the systems passing turbines' rotational energy along to their attached generators -- and structural foundations enabling low environmental impacts and reduced lifetime operating and maintaining costs.

The funding is available from the Energy Department's Office of Energy Efficiency and Renewable Energy.  This office, known as EERE, runs programs designed to speed up the development and deployment of energy efficiency and renewable energy technologies and market-based solutions.  hydropower manufacturing. 

This funding opportunity is designed to attract innovations that enable rapidly built, removable, and replaceable hydropower systems.  It solicits proposals to develop alternative hydropower systems with low civil infrastructure development costs, deployable within 2 years with relatively low environmental impacts, and which can be removed or replaced after their intended life is completed.  According to the funding opportunity announcement, these concepts and systems will be able to operate at a cost that is competitive with traditional sources of generation.

The complete funding opportunity announcement -- DE-FOA-0001286: RESEARCH AND DEVELOPMENT OF INNOVATIVE TECHNOLOGIES FOR LOW IMPACT HYDROPOWER DEVELOPMENT -- is available through the Office of Energy Efficiency and Renewable Energy's Funding Opportunity Exchange.

While this funding opportunity supports a wide variety of technological innovations for new hydropower development, specific areas of interest include:
  • New, rapidly deployable and removable hydropower technologies, such as innovative prefabricated structures, water impoundment structures, and water conveyance systems.
  • Innovative methods and materials for the construction of conventional hydropower facilities, including, but not limited to, concrete alternatives, in-water construction, and innovative advanced tunneling methods.
  • Design and lab testing of innovative conventional hydropower powertrain and generator components, such as advanced composite materials and replaceable blade technologies for turbine runners, new generator technologies, and materials and coatings for powertrain components.
The Energy Department will hold a webinar on this funding opportunity announcement on Tuesday, April 21, 2015 at 3:00 pm (ET).  Applicants must first submit a concept paper (currently due no later than 5:00 PM (ET) on May 7), with full applications currently due by 5:00 PM (ET) on June 15, 2015.

Obama links climate and health

Thursday, April 9, 2015

President Obama has issued a Presidential Proclamation declaring this week, April 6-12, 2015, as National Public Health Week.  Climate change, and its impacts on human and environmental health, figure prominently in his proclamation.

The Obama administration has focused on climate change since taking office in 2009.  In 2013, President Obama released his administration's Climate Action Plan, calling for reductions in U.S. emissions of carbon and greenhouse gases, adoption of mitigation and adaptation measures, and global action.  He has also addressed climate change in his State of the Union speeches to Congress, and the U.S. Environmental Protection Agency has issued its proposed Clean Power Plan to reduce the carbon intensity of the nation's electric power sector.

While interest in addressing climate change arises from a broad range of factors, health plays an important role in the Obama administration's action on climate issues.  In this week's Presidential Proclamation on health, President Obama noted the interdependence of climate, environment, and human health:
America's public health is deeply tied to the health of our environment. As our planet becomes more interconnected and our climate continues to warm, we face new threats to our safety and well-being. In the past three decades, the percentage of Americans with asthma has more than doubled, and climate change is putting these individuals and many other vulnerable populations at greater risk of landing in the hospital. Rising temperatures can lead to more smog, longer allergy seasons, and an increased incidence of extreme-weather-related injuries and illnesses.

My Administration is dedicated to combating the health impacts of climate change. As part of my Climate Action Plan, we have proposed the first-ever carbon pollution limits for existing power plants -- standards that would help Americans live longer, healthier lives. And as we continue to ensure the resilience of our health care system, we are working to prepare our health care facilities to handle the effects of a changing planet. Climate change is no longer a distant threat. Its effects are felt today, and its costs can be measured in human lives. Every person, every community, and every nation has a duty to protect the health of all our children and grandchildren, and my Administration is committed to leading this effort.
This week the Obama administration announced further actions to protect communities against the impacts of climate change.  These actions include convening stakeholders to prepare for a White House Climate Change and Health Summit later this spring that will feature the Surgeon General, and an Adaptation in Action Report by the Centers for Disease Control and Prevention (CDC).

The Obama administration also announced an expansion of its Climate Data Initiative to include more than 150 health-relevant datasets on climate.data.gov.  President Obama unveiled the Climate Data Initiative in 2014 to host data related to climate change that can help inform and prepare businesses and citizens for the impacts of extreme weather.  The newly released datasets are designed to help the public answer questions, including:
  • In what ways does the changing climate affect public health where I live?
  • What risk factors make individuals or communities more vulnerable to climate-related health effects?
  • How can public health agencies, communities, and individuals plan for uncertain future conditions?

Maine long-term contracting for electricity

Tuesday, April 7, 2015

Maine energy regulators have asked for public comment on the goals and objectives for a decade-old program supporting long-term contracts between utilities and independent power producers.  At stake is the future of Maine's long-term contracting program for electricity resources.

In 2006, the Maine State Legislature enacted an Act to Enhance Maine’s Energy Independence and Security, P.L. 2005, ch. 677.  Part C of that Act (codified at 35-A M.R.S. § 3210-C) authorizes the Maine Public Utilities Commission to direct transmission and distribution utilities to enter into long-term contracts for capacity and energy.  The statute directs the Commission to conduct a competitive solicitation for contracts at least every three years, and specifies the framework that the Commission must use in selectingcapacity resources for contracting, including a stated priority list of types of resources and a duty to select lowest price offers.

Since the Act's enactment, the Commission has conducted five solicitations under this program (including the current solicitation, under which proposals are due by May 1, 2015).  In each case, the Commission has hired an outside consultant to forecast relevant markets for energy, capacity, and renewable energy credits to be used in evaluating the value of the market products offered in responsive bids.

Today, the Commission issued a Notice of Inquiry into the goals and objectives for long-term contracting under the Act.  In the notice, the Commission asks for public comment on how long-term contracts can most effectively be used to support the development of increased generation from renewable resources, and reduce price volatility and greenhouse gas emissions; how the Commission should evaluate proposals' price reduction benefits; and how to best structure transactions.

The Commission also asked for comment on relatively novel potential uses of the program, including leveraging federal support for energy programs to benefit Maine ratepayers, increasing in-state generation capacity such that Maine would “separate” from the rest of New England in the regional forward capacity market to yield reduced in-state prices for capacity, and "geo-targeting" capacity resources to avoid transmission and distribution costs more effectively.

Finally, the Commission requested feedback on its long-term contracting process.  Should the Commission issue requests for proposal on a set schedule (e.g. every two years), or should it retain discretion as to when to issue an RFP?  Should the process include fixed dates for key milestones like submission of final bids or Commission decisions, or should it remain flexible and unfixed?

Comments are due to the Maine Public Utilities Commission by May 6, 2015.

Virginia offshore wind research lease

Friday, April 3, 2015

The U.S. federal agency responsible for leasing offshore wind sites on the outer continental shelf has executed its first wind energy research lease, giving Virginia's state energy agency the right to pursue the Virginia Offshore Wind Technology Advancement Project (VOWTAP), a 12-megawatt offshore wind test facility to be located in federal ocean waters.

Offshore wind energy offers the potential to generate large amounts of electricity from a renewable resource, but to date no commercial grid-tied U.S. offshore wind projects are operating.  The U.S. Bureau of Ocean Energy Management is responsible for leasing sites on the outer continental shelf for energy projects, including offshore wind and other renewable energy developments.  BOEM has auctioned off sites for offshore wind projects off several East Coast states, including Virginia, but had not previously issued a research lease.

On March 24, BOEM announced the execution of a wind energy research lease with the Commonwealth of Virginia’s Department of Mines, Minerals and Energy (DMME).  Under research lease OCS-A 0497 (35 pages), the Virginia agency proposes to design, develop and demonstrate a grid-connected, 12-megawatt offshore wind test facility on the Outer Continental Shelf off the coast of Virginia, in partnership with a local utility affiliated with Dominion Resources, Inc.

The 30-year lease covers approximately 2,135 acres of sea space east of Virginia Beach, adjacent to the Wind Energy Area leased to Virginia Electric and Power Company (dba Dominion Virginia Power) for commercial development since 2013.  The lease describes the project as "a research project to generate energy using wind turbine generators and conduct any associated resource assessment activities, as well as install associated offshore substation platforms, inter-array cables, and subsea export cables."  As a research lease, the Virginia agreement does not include any fees payable from DMME to BOEM "for the purpose of ensuring a fair return for the use of this lease area."

As is standard for BOEM's offshore wind site leases, the lease itself does not give the lessee the right to build or operate an offshore wind project.  Rather, the lease gives the Virginia DMME the exclusive right to submit to BOEM for approval a Site Assessment Plan and a Research Activities Plan, and then to allow a designated operator to conduct whatever activities are described in those plans once they are approved by BOEM. 

In this case, DMME has designated Dominion subsidiary Virginia Electric and Power Company as the lease operator.  Dominion's partnership with DMME on offshore wind dates back at least to 2012, when the U.S. Department of Energy announced funding awards for seven proposed Offshore Wind Advanced Technology Demonstration Projects.  Dominion won one of these 2012 awards, and partnered with DMME and others to establish VOWTAP.  VOWTAP won a second funding award from DOE in 2014 for deployment activities.

Dominion and DMME have already filed a Research Activities Plan for VOWTAP.  With the research lease in hand, the path forward includes approval of that plan and a Site Assessment Plan by BOEM.  If the VOWTAP project is built, the data obtained and lessons learned from this project will be made publicly available and inform the future production of renewable energy within the adjacent commercial Wind Energy Area leased to Dominion.

Texas small hydro project loses exemption

Wednesday, March 25, 2015

What happens to a proposed hydroelectric project takes longer than anticipated to be built, due to difficulties with project financing and severe flooding?  As the developer of a proposed project in Texas recently found out, federal regulators can be lenient up to a point -- but under some circumstances the developer can lose its federal authorization to develop and operate the project.

The A.H. Smith Dam on the San Marcos River in Martindale, Texas was originally constructed in about 1894 to provide mechanical power a cotton gin; later, electric generation was installed, but power production ceased in the 1940s when low wholesale energy prices made operation uneconomic.  Modern hydropower facilities rated at 150 kilowatts were installed in 1984, but were ultimately abandoned.

In 2005, developer Hydraco Power, Inc. applied to the Federal Energy Regulatory Commission for an exemption from the licensing requirements of Part I of the Federal Power Act for its proposed A.H. Smith Dam Project.  Hydraco's project included refurbishing and restoring the operation of the existing turbine located at the dam's powerhouse, installing a new buried transmission line and a water surface elevation gate in the headpond.

On June 2, 2006, the Commission granted Hydraco an exemption for the project.  As a standard condition of exemptions, the Commission retained the right to revoke the exemption if any term or condition was violated.  Among the terms was a requirement that Hydraco file within 120 days a
plan and schedule to install the new transmission line and restore the powerhouse, turbine, and trash racks to operating condition, as well as notice that the Commission could terminate the exemption if actual construction of any proposed or required facility had not begun within two years or had not been completed within four years of the date of issuance of the exemption.

Over the next 8 years, Hydraco filed a series of construction plans and schedules, but never completed the project despite obtaining repeated extensions of key deadlines.  After multiple prompts by Commission staff to file a revised plan and schedule for restoring project operation or an application to surrender the exemption, the Commission noted that Hydraco either failed to respond or responded by stating that it could not estimate a schedule for restoring project operation because project construction, including major component repairs, was on hold due to lack of funds.

After the Commission issued a public notice in August 2014 stating its intent to terminate the project exemption "due to Hydraco’s longstanding violation of exemption Article 10 and its failure to provide a timeframe for restoring project generation", on November 20, 2014, the Commission issued an Order Terminating Exemption. That order found that "Hydraco has only performed minimal work at the project since obtaining its exemption in 2006 and that it lacks the funding to proceed with the necessary component repairs, including construction of the powerhouse interior and generating unit."

Hydraco filed a request for rehearing of the Order Terminating Exemption.  On rehearing, Hydraco asserted that it had reached a financing agreement with a new investor and, consequently, it is ready to perform the work needed to comply with its exemption. Hydraco also objected to the findings that project construction was at a standstill and that Hydraco intended to abandon the project, noting that the Commission should excuse construction delays caused by severe flooding.

Last week, the Commission issued an Order Denying Rehearing in the case.  It first noted that Hydraco had not demonstrated that it now has the money needed to bring the project on line.  Not only did Hydraco not show evidence of a final financing agreement, but the documents showed a source of only half of the funding needed for project restoration.  Second, the Commission noted that Hydraco's recent activities -- regularly inspecting the dam and removing debris from its spillway, trashracks, and grates, securing the site against vandalism and installing lighting, and repairing damage caused by a flood -- are "either maintenance or repair, not project development."  Finally, the Commission articulated its "doctrine of implied surrender", which it applies where the entity responsible for the project has, by action or inaction, clearly indicated its intent to abandon the project, but has not filed a surrender application.

With the exemption terminated and Hydraco's request for rehearing denied, the A.H. Smith Dam project faces an uncertain future.  On the one hand, the site presumably still offers many of the same values that Hydraco hoped to capture -- use an existing dam, with existing generation facilities, to generate renewable electricity.  However, the loss of the FERC exemption means that Hydraco (or any other developer) will have to start the federal hydropower process over if it hopes to redevelop the dam as a hydroelectric generating site.

The case of the A.H. Smith Dam project illustrates a number of themes: interest in restoring existing hydropower infrastructure to generate renewable energy with relatively less environmental impact than newly-built dams, the challenge of securing financing for small hydropower projects -- and perhaps most importantly the value of compliance with FERC hydropower rules.

FERC 2014 State of the Markets report

Monday, March 23, 2015


U.S. energy markets overseen by the Federal Energy Regulatory Commission in 2014 were impacted by extreme weather and changes in the mix of electric generation resources, according to a report by Commission staff.

The 2014 State of the Markets report issued on March 19 by FERC's Office of Enforcement’s Division of Energy Market Oversight presents Commission's staff’s assessment of recent developments in natural gas, electric, and other energy markets.

Extreme cold temperatures in the first quarter of 2014 affected natural gas infrastructure and power markets across the country.  The price of natural gas in the U.S. reached record high levels, driving corresponding spikes in the price of electricity.  For example, the price of natural gas at the Transco Zone 6 Non-NY pricing point hit $123/MMBtu in January -- about 33 times higher than the average 2013 U.S. price.  Largely due to these price spikes, the spot natural gas price at the Henry Hub pricing point averaged $4.32/MMBtu in 2014, a 16% increase over 2013.

Meanwhile, natural gas and renewable resources continued to displace coal as a fuel for electric power generation.  Total U.S. generating capacity increased 10.8 GW in 2014, with natural gas and renewable projects representing the bulk of new capacity.  At the same time, utilities retired coal-fired power plants, continuing a trend that started in 2012.  Commission staff projects continued coal retirements in 2015, particularly after the April effective date of additional air emissions regulations imposed by the Environmental Protection Agency's Mercury and Air Toxics Standards.

FERC's 2014 State of the Markets report also provides a quick look at 2015 year-to-date market performance.  Wholesale electricity prices rose again this winter, although not as sharply as in the first quarter of 2014.  FERC staff's report suggests factors helping to moderate winter prices included better cold-weather preparation of assets, programs like ISO New England's Winter Reliability Program, better coordination between operators of electric transmission and natural gas pipelines, record high levels of natural gas production, the development of new pipeline infrastructure, and low oil prices.

More solar faster, predicts New England grid operator

Tuesday, March 17, 2015

New England will likely see even more solar photovoltaic energy projects over the next decade than was previously projected, according to the latest draft forecast by the operator of New England's electric grid.

Solar photovoltaic panels on the roof of a Massachusetts home.

To help plan for future needs, grid operator ISO New England, Inc. is developing an updated forecast of solar photovoltaic project development in New England.  In 2014, ISO New England developed its first multistate forecast of PV capacity growth.  It based its 2014 PV forecast heavily on development goals articulated as policies in the six New England states.

ISO New England is now updating that forecast for 2015.  Its draft 2015 Solar PV Forecast, released on February 27, notes that PV development is happening more rapidly than was previously projected.  Using updated historical data, it acknowledges that through 2014, 40% more solar capacity was developed in the region than it previously estimated.  As a result of this faster-than-expected growth, the draft now predicts a higher level of cumulative photovoltaic project development through 2023.

Perhaps more significantly for the solar boom, ISO-NE's draft 2015 forecast also frontloads more new project capacity into 2015 and 2016, while decreasing the amount predicted to be newly developed in later years.  While last year's forecast also predicts more incremental solar capacity will be developed in each of the next three years than in later years, the frontloading is more prominent in the draft 2015 forecast.


The draft 2015 forecast projects that 2,138.8 megawatts of solar photovoltaic projects will be developed in New England by 2024.  This capacity is stated as an alternating current nameplate rating, even though photovoltaic cells essentially generate direct current electricity.  The study derates direct current capacity to alternating current with an 83% array-to-inverter ratio, so this implies an even higher number of megawatts if stated as direct current capacity, as most solar projects are described.



The draft 2015 forecast projects that these solar photovoltaic projects will give rise to a summer seasonal claimed capability of 748.6 megawatts.

ISO New England did not include in its draft 2015 PV forecast any update to its forecast of how much energy these projects would produce.  Instead it suggests that it must first finalize its forecast of installed photovoltaic capacity, and can then estimate the energy production associated with the forecast.  The report does repeat 2014's forecast of energy as illustrative, keeping in mind that actual amounts of energy generated from solar photovoltaic capacity in New England will likely be higher if capacity forecasts are revised upward as is proposed in this draft.


The 2015 draft PV report is now under review by ISO New England's Distributed Generation Forecast Working Group.  That group next meets on April 14, where the final draft forecast will be presented.

Controversy over renewable energy claims

Thursday, March 5, 2015

If an electric utility generates power from renewable resources and sells renewable energy certificates representing the renewable attributes of that energy, can it still call the underlying power "renewable"? No, according to the U.S. Federal Trade Commission.

Solar panels in the Utah desert.

While this question may seem metaphysical, it arises from the structure of most U.S. renewable energy markets.  Most states have adopted renewable portfolio standards, which require utilities and competitive electricity suppliers to source some of their power from renewable resources.  In most cases, utilities and suppliers can satisfy this requirement by using renewable energy certificates or credits known as RECs.  While each state's program differs, these RECs typically represent the renewable attributes of electric energy -- the right to claim that energy is renewable -- but are distinct from that underlying energy.  As a result, a renewable generator can sell RECs to one buyer and the underlying energy to another.

Vermont utility Green Mountain Power Corporation recently found itself at the center of controversy over its claims regarding renewable energy.  The utility owns and is involved with a variety of renewable energy generation projects in Vermont, including wind and solar projects.  It sells energy produced from these projects to Vermont customers, while simultaneously selling some of the RECs generated by these sources to out of state utilities.

In 2014, concerns over "double counting" of renewable energy attributes led Connecticut to ban the use of RECs from renewable generation that also is counted toward another state’s renewable goals for meeting Connecticut's requirements, and REC marketer NextEra Energy to notify New England market participants that it would no longer buy Vermont RECs.

On September 15, 2014, a group of petitioners asked the Federal Trade Commission to investigate Vermont utility Green Mountain Power Corporation's claims that it is providing its customers with electricity from renewable sources such as commercial wind and solar projects, given its separate sale of the RECs to out of state utilities.  The Federal Trade Commission regulates claims about the environmental impacts of commerce under Section 5 of the Federal Trade Commission Act, including claims regarding the production, sale, and use of renewable energy.  In their complaint, the petitioners claimed that "Vermont customers are being misled into thinking that they are buying 'renewable energy,' when in fact what they are getting is 'null' electricity consisting of a mix of fossil fuel, nuclear, gas and other 'brown' sources of electricity from the regional grid."

The FTC responded to this petition in February 2015 by issuing a letter to Green Mountain Power's counsel expressing concern that the utility might have created confusion for its customers about the renewable attributes of the power they purchased by not “clearly and consistently communicating” that it sells RECs for most of its renewable energy-generating facilities to entities outside Vermont.  In the letter, the FTC said that it had not found that any Green Mountain Power statements violated the Federal Trade Commission Act.  However, the Commission urged Green Mountain Power in the future to prevent any confusion by clearly communicating the implications of its REC sales for Vermont customers and REC purchasers.

The FTC letter represents the latest salvo in efforts to regulate claims regarding the production, sale, and use of renewable energy.  To help marketers avoid making deceptive environmental claims, for over 20 years the FTC has issued "Green Guides" providing its administrative interpretation of the law. The Green Guides outline general principles that apply to all environmental marketing claims and provide guidance regarding many specific environmental benefit claims, including renewable energy claims.  The Green Guides, as well as the recent FTC letter, illustrate the importance of caution in making claims about renewable energy in business activities.

North Carolina offshore wind environmental assessment

Tuesday, February 17, 2015

The U.S. Department of the Interior's Bureau of Ocean Energy Management has released an environmental assessment of the impacts of leasing sites off the North Carolina coast for offshore wind projects.  This milestone supports the Obama administration's plan to offer site leases on the outer continental shelf for renewable energy projects.

Since 2012, BOEM has solicited public comment on the prospect of leasing about 307,590 acres off North Carolina for potential offshore wind development.  BOEM has identified three Wind Energy Areas offshore North Carolina:
  • the Kitty Hawk Wind Energy Area (about 122,405 acres), beginning about 24 nautical miles (nm) from shore and extends approximately 25.7 nm in a general southeast direction;
  • the Wilmington West Wind Energy Area (about 51,595 acres), beginning about 10 nm from shore and extends approximately 12.3 nm in an east-west direction at its widest point; and
  • the Wilmington East Wind Energy Area (about 133,590 acres), beginning about 15 nm from Bald Head Island at its closest point and extends approximately 18 nm in the southeast direction at its widest point.

BOEM's map of North Carolina Wind Energy Areas.
On January 22, 2015, BOEM announced the availability of an environmental assessment for public review and comment.  Under the National Environmental Policy Act or NEPA, an environmental assessment or EA considers the potential impacts of proposed federal action and analyzes reasonable alternatives to the proposed action.  In this case, the action proposed is BOEM's issuance of commercial wind leases and allowing of site characterization and assessment activities on the Atlantic Outer Continental Shelf offshore North Carolina.

BOEM's environmental assessment for North Carolina offshore wind leasing provides the framework for potential federal lease auctions for North Carolina offshore wind sites.  The environmental assessment is available for public comment through February 23, 2015. 

Apple makes California solar deal

Thursday, February 12, 2015

Electronics manufacturer Apple has announced an $848 million deal to buy electricity from a solar energy project to be developed in California. Project developer First Solar has described the power purchase agreement as "the largest agreement in the industry to provide clean energy to a commercial end user."

Solar photovoltaic panels in the Utah desert.

Earlier this week, Apple announced the deal with First Solar, Inc., to buy power from First Solar's California Flats Solar Project in Monterey County, California.  Under a 25-year power purchase agreement or PPA, Apple will buy the equivalent of 130 megawatts of the solar project's output. 

First Solar is a vertically-integrated solar company, manufacturing solar photovoltaic panels, developing utility-scale photovoltaic power plants, and providing solar project support services.  First Solar boasts involvement with over 10 gigawatts of installed solar photovoltaic capacity worldwide.  Its resume includes the 550-megawatt Topaz Solar project in California and the 290-megawatt Agua Caliente project, which was once the world's largest operating solar energy project.

First Solar's California Flats Solar Project will occupy a 2,900-acre site on the Jack Ranch in Cholame, California.  Owned by Hearst Corporation, the project site was formerly a dryland farm, and occupies about 3% of the Jack Ranch property.  First Solar expects to begin construction later this year, and to complete the project by the end of 2016.

With a total project capacity of 280 megawatts, Apple's 130-megawatt commitment covers about 46% of the project's output.  The project's remaining 150 megawatts will be sold to utility Pacific Gas & Electric under a separate long-term PPA.

Apple has developed other renewable energy projects, including fuel cells and solar panels at its Maiden, North Carolina data center.  Other high-tech companies have also made significant investments in renewable energy, including Google's commitment of over $1.5 billion to solar and wind projects through power purchase agreements and direct investments.

2014: natural gas, wind, solar led new projects

Friday, January 30, 2015

Natural gas, wind, and solar power projects dominated the rankings of new U.S. electric generation placed in service in 2014.

According to the Federal Energy Regulatory Commission staff's December 2014 Energy Infrastructure Update, developers placed in service 15,384 megawatts of new utility-scale electric generation capacity in 2014.  This new capacity buildout is within 4% of 2013's figure (15,886 megawatts).

Of 2014's new generating capacity, nearly half (7,485 megawatts, or 49%) is powered by natural gas.  U.S. production of natural gas has increased significantly in recent years, and natural gas prices have decreased in most regions of the country.  At the same time, new environmental regulations have made historically dominant coal relatively more expensive as a fuel source, while relatively low carbon emissions have made natural gas more attractive.  2014 thus continued the trends of coal-fired power plant retirement and the construction of new natural gas-fired generating capacity.

Wind represents the next largest category of new U.S. electric generating capacity placed in service in 2014.  Nearly 27% of 2014's new capacity, or 4,080 megawatts, is powered by wind.  As President Obama noted in his 2015 State of the Union address, the U.S. has more wind energy supplying its electrical grid than any other country.

Solar energy represents the third largest category of new generation placed in service last year.  Over 20% of new 2014 capacity, or 3,139 megawatts, is powered by solar energy.  The rapid growth of solar energy in the U.S. was also featured in President Obama's 2015 State of the Union speech, in which he noted, "Every three weeks, we bring online as much solar power as we did in all of 2008."

Combined, these three energy sources (natural gas, wind, and solar) account for over 95% of all new utility-scale generation capacity placed in service in 2014. Of the remaining capacity, biomass took the largest share (1.6% of total new capacity), with a diverse mix of other sources including water power, coal, and nuclear rounding out the list.  Notably, renewable sources including wind, solar, biomass, and hydropower account for nearly half of all new capacity placed in service in 2014.

What will 2015 bring?

Federal offshore wind auction held for sites off Massachusetts

Thursday, January 29, 2015

Federal ocean energy managers have concluded an auction to lease over 350,000 acres off the Massachusetts coast to prepare for offshore wind development.  Of the four parcels up for bid in today's auction, one was provisionally awarded to RES America Developments, Inc. and another to Offshore MW LLC.  Two other parcels failed to attract any bids.

Onshore wind turbines near the Massachusetts coast.
In today's auction conducted by the Interior Department’s Bureau of Ocean Energy Management (BOEM), RES America Developments, Inc. provisionally won the rights to Lease OCS-A 0500 (187,523 acres) after two rounds of bidding, with a winning bid of $281,285.  Offshore MW LLC provisionally won the rights to Lease OCS-A 0501 (166,886 acres) after two rounds of bidding, with a winning bid of $166,886.  These winning bids are significantly below those that were required to win previous federal competitive lease sales for offshore wind sites.

While today's lease awards are a step forward for U.S. offshore wind, neither lease awarded today grants the right to construct or operate an offshore wind project.  Rather, these leases have a preliminary term of one year, to allow the lessee time to prepare a Site Assessment Plan describing the installation of meteorological towers and buoys and other activities the lessee plans to perform to assess local wind resources and ocean conditions.  Site Assessment Plans must be submitted to BOEM for review and approval.

Once BOEM approves a Site Assessment Plan, the lessee will then have up to five years in which to prepare and submit to BOEM a Construction and Operations Plan (COP) providing detailed information for the construction and operation of a wind energy project on the lease.  After BOEM receives a Construction and Operations Plan from a lessee, BOEM will conduct an environmental review of and public comment period for the proposed project.  If BOEM approves a Construction and Operations Plan, the lessee will have an operations term of 25 years.

Lease OCS-A 0502 (248,015 acres) and Lease OCS-A 0503 (140,554 acres) did not receive bids in today's auction.  As shown on a BOEM nautical chart of the Massachusetts Wind Energy Area, these lease areas are generally farther from the Massachusetts coast than the areas awarded through today's auction.

BOEM touts its offshore wind leasing program as part of President Obama’s Climate Action Plan.  The auction held today by BOEM represents the nation’s fourth competitive lease sale for renewable energy sites in federal waters.  Including this auction, competitive lease sales have generated more than $14.5 million in high bids for more than 700,000 acres in federal waters.  Previous auctions covered sites off Rhode Island and Massachusetts, Virginia, and Maryland.  BOEM expects to hold another competitive lease sale offshore the New Jersey coast in 2015.  

FERC and EPA's Clean Power Plan

Wednesday, January 28, 2015

Following the U.S. Environmental Protection Agency's 2014 proposal to regulate carbon emissions from electric power plants and other major sources, federal energy regulators have scheduled a series of public technical conferences on how the Clean Power Plan may affect electric reliability, wholesale electric markets and operations, and energy infrastructure.

On June 2, 2014, the U.S. Environmental Protection Agency announced the Clean Power Plan, its proposed rule under Section 111(d) of the Clean Air Act to reduce carbon emissions from the nation's power plants.  Designed to reduce carbon emissions 30 percent below 2005 levels by 2030, EPA's proposal would impose limits on each state's rate of carbon emissions per megawatt-hour of electric energy generated.

The Federal Energy Regulatory Commission regulates the transmission and wholesale sales of electricity in interstate commerce, monitors energy markets, and protects the reliability of the high voltage interstate transmission system.  Acting out of concern over the possible impacts of the EPA Clean Power Plan on its regulated sector, on December 9, 2014, the Commission scheduled a series of technical conferences to develop public comment on these issues.

First, the Commission will hold a National Overview technical conference on February 19, 2015, at its Washington, DC headquarters.  Earlier this month, the Commission issued a supplemental notice describing the agenda for the National Overview.  After an introduction by EPA, the Commission expects to discuss:
  • Electric reliability considerations: How will the Clean Power Plan affect electric reliability?  How can the U.S. sustain reliability as states and regions develop their plans to comply with the proposed carbon rule?  How could state, regional, and federal plans for compliance affect grid operations?  What tools are available to identify potential reliability impacts?  How can reliability planning processes and compliance planning efforts  coordinated to address potential issues?  What is the Commission's role in this area?
  • Identifying and addressing infrastructure needs: What potential infrastructure needs may arise from various state or regional compliance approaches?  How can any infrastructure needs met in a timely manner in order to ensure system reliability?  How can relevant planning entities, industry, and states coordinate reliability and infrastructure planning and siting processes with state and/or regional environmental compliance efforts to ensure the adequate and timely development of new infrastructure?  Are additional mechanisms needed to ensure timely development of new infrastructure? Are adaptations to current Commission policies needed to facilitate the infrastructure needed for compliance with the proposed Clean Power Plan?
  • Potential implications for Commission-jurisdictional markets:  How could potential compliance approaches to the proposed Clean Power Plan impact Commission-jurisdictional electric and natural gas markets?  What aspects, if any, of the wholesale and interstate markets would facilitate implementation of state or regional compliance plans?  What tools are available to address market issues as they arise?  What opportunities are available to coordinate compliance approaches with Commission-jurisdictional markets to meet the requirements of the proposed Clean Power Plan rule?
Following the National Overview, the Commission has scheduled three regional conferences in February and March 2015.

Natural Gas Pipeline Permitting Reform Act

Monday, January 26, 2015

Last week, the U.S. House of Representatives voted to pass a bill to expedite federal review of some spects of proposed natural gas pipelines.  Known as H.R. 161, the Natural Gas Pipeline Permitting Reform Act is officially summarized as providing for the "timely consideration of all licenses, permits, and approvals required under Federal law with respect to the siting, construction, expansion, or operation of any natural gas pipeline projects."  If enacted into law, what would H.R. 161 do?

Congress debates proposed reforms to the natural gas pipeline permitting process.
Relatively brief for federal legislation, the printed draft of H.R. 161 comes in at just 3 pages.  Overall, it defines and accelerates the timelines for federal approvals of some proposed natural gas pipelines.  If enacted, the bill would give the Federal Energy Regulatory Commission one year to decide whether or not to issue a pipeline permit, following which other federal agencies would have 90 days to issue any ancillary permits.

The pipelines that would benefit from this bill are those that have applied to the Federal Energy Regulatory Commission under Section 7 of the Natural Gas Act (15 U.S.C. 717f) for a certificate of public convenience and necessity, and have used the Commission's "prefiling" process.

First, H.R. 161 amends Section 7 of the Natural Gas Act to require the Federal Energy Regulatory Commission to approve or deny an application for a certificate of public convenience and necessity for a prefiled project not later than 12 months after receiving a complete application that is ready to be processed.

Second, H.R. 161 requires any agency responsible for issuing any license, permit, or approval required under Federal law in connection with a prefiled project for which a certificate of public convenience and necessity is sought under the Natural Gas Act to approve or deny the issuance of the license, permit, or approval not later than 90 days after the Commission issues its final environmental document relating to the project.  Generally speaking, if such as agency cannot complete its review process within this timeline, it is compelled to deny the license, permit, or approval, but H.R. 161 would allow the Commission to extend the 90 day deadline by an additional 30 days.  H.R. 161 also changes federal law to provide that in the case of agency inaction within the 90 day time period or extra 30 day period, the requested license, permit, or approval shall take effect upon the expiration of 30 days after the end of such period.

On January 22, the House voted 253-169 in favor of the bill.  It now goes before the Senate.  But on January 20, the Executive Office of the President issued a statement of administrative policy stating, "If the President were presented with H.R. 161, his senior advisors would recommend that he veto the bill."  In that administrative policy statement, the administration acknowledged the need for additional energy infrastructure and supports the timely consideration of project applications, but notes risks from that H.R. 161.  These risks include effective limits on public participation in pipeline review processes, and that agencies may be forced to make decisions based on incomplete information or information that may not be available.  The executive branch's statement also cites a FERC report that since Fiscal Year 2009, FERC has completed action on 91 percent (512 out of 563) of all pipeline applications that it has received within one year of receipt, with the remaining decisions involving complex proposals that merit additional review and consideration.

Will the Natural Gas Pipeline Permitting Reform Act be enacted into law?  How will its enactment -- or non-enactment -- affect proposed new natural gas pipelines, and the customers they would serve?

FERC issues EIS for Algonquin Incremental Market gas project

Friday, January 23, 2015

Staff of the Federal Energy Regulatory Commission have issued a final Environmental Impact Statement for a proposed natural gas transmission project connecting New York and New England.  In that report, Commission staff found that Algonquin Gas Transmission, LLC's Algonquin Incremental Market Project would result in some adverse environmental impacts, but that most of these impacts could be mitigated and reduced to less-than-significant levels.

A marker for the Williams Northwest Pipeline in Arches National Park, Utah.
 Algonquin Gas Transmission, LLC -- a subsidiary of Spectra Energy Partners, LP -- already owns a natural gas pipeline and transmission network running from the Texas Eastern Transmission system in New Jersey to the Maritimes & Northeast system near Boston.

In 2014, Algonquin proposed the Algonquin Incremental Market project.  The AIM project's would provide firm transportation service of 342,000 dekatherms per day of natural gas to local distribution companies and municipal utilities in Connecticut, Rhode Island, and Massachusetts.  Algonquin’s stated objectives for the Project are:
  • to provide the pipeline capacity necessary to transport additional natural gas supplies to meet the immediate and future load growth demands of local gas utilities in southern New England;
  • eliminate capacity constraints on existing pipeline systems in New York State and southern New England;
  • provide access to growing natural gas supply areas in the Northeast region to increase competition and reduce volatility in natural gas pricing in southern New England;
  • improve existing compressor station emissions through the replacement of existing compressor units with new, efficient units; and
  • provide the additional service by November 2016.

As envisioned by Algonquin, the project will include the construction and operation of about 37.4 miles of natural gas pipeline in New York, Connecticut, and Massachusetts.  The project entails replacing some segments of existing pipeline, extending an existing loop pipeline to increase the system's capacity to ship gas, and installing some new pipeline.  It also includes modifications to six existing compressor stations, modifying existing meter and regulating stations, and the construction of 3 new meter and regulation stations.

Under federal law, Algonquin needs authorization from the Federal Energy Regulatory Commission to construct and operate the AIM project.  Algonquin filed its application to the FERC on February 28, 2014.  As part of the FERC's review process, the National Environmental Policy Act requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Algonquin's application.

In Algonquin's case, that documentation took the form of a Final Environmental Impact Statement issued by the FERC staff today. In the final EIS, FERC's environmental analysts conclude that construction and operation of the AIM project would result in some adverse environmental impacts. However, FERC staff found that most of these impacts would be reduced to less-than-significant levels with the implementation of mitigation measures and plans proposed by Algonquin, along with additional measures recommended by the FERC staff.  Staff pointed to factors including the degree to which proposed AIM project pipeline facilities would be within or adjacent to existing rights-of-way, the planned use of the horizontal directional drill method to cross the Hudson and Still Rivers, which would avoid any direct impacts on these resources, as well as plans to minimize impacts on natural and cultural resources during construction and operation of the Project.

With the final Environmental Impact Statement issued, the FERC Commissioners will consider its staff's recommendations in making a final a decision on the AIM project.  Multiple studies have highlighted the need for up to 2 billion cubic feet per day (Bcf/d) of new pipeline capacity into New England and neighboring markets to improve reliability and reduce the cost to consumers of electricity and natural gas.  At a planned size of 342,000 dekatherms (or 0.342 Bcf) per day, the AIM project is relatively small in capacity compared to other proposed projects such as Tennessee Gas Pipeline Company, L.L.P.'s proposed Northeast Energy Direct Project, which is designed to be scalable up to 1.2 to 2.2 billion cubic feet per day of natural gas capacity.  Which pipelines end up being approved and built will shape the New England energy landscape in the coming years.

Energy and State of the Union 2015

Thursday, January 22, 2015

President Obama delivered his 2015 State of the Union address on January 20, 2015.  In his remarks as prepared for delivery, he addressed energy-related themes including the growth of U.S. energy resource production and climate change.

As in his 2013 and 2014 addresses, increased domestic production of energy resources featured prominently in the 2015 State of the Union speech, for its economic, political, and national security benefits:
At this moment – with a growing economy, shrinking deficits, bustling industry, and booming energy production – we have risen from recession freer to write our own future than any other nation on Earth.  It’s now up to us to choose who we want to be over the next fifteen years, and for decades to come...
We believed we could reduce our dependence on foreign oil and protect our planet.  And today, America is number one in oil and gas.  America is number one in wind power.  Every three weeks, we bring online as much solar power as we did in all of 2008.  And thanks to lower gas prices and higher fuel standards, the typical family this year should save $750 at the pump.
During the past several years, U.S. production of oil and natural gas has increased significantly.  According to the U.S. Energy Information Administration, total U.S. crude oil production averaged an estimated 9.2 million barrels per day (bbl/d) in December 2014, and forecasts for oil productino continue to grow.  EIA predicts that projected crude oil production will reach 9.5 million bbl/d in 2016, constituting the second-highest annual average level of production in U.S. history (after 9.6 million bbl/d in 1970.)

EIA also predicts continued growth in the use of renewable energy resources to produce electricity and heat. In 2014, 6.4% of electric generation came from hydropower and 6.7% from nonhydropower renewables. EIA projects continued growth of nonhydropower renewables, reaching an electricity generation share of 7.9% by 2016.  Wind is the largest source of nonhydropower renewable generation, and it is projected to contribute 5.3% of total electricity generation in 2016.

President Obama also addressed climate change in this year's State of the Union address, and his administration's efforts to combat and mitigate its effects:
2014 was the planet’s warmest year on record.  Now, one year doesn’t make a trend, but this does – 14 of the 15 warmest years on record have all fallen in the first 15 years of this century. 
I’ve heard some folks try to dodge the evidence by saying they’re not scientists; that we don’t have enough information to act.  Well, I’m not a scientist, either.  But you know what – I know a lot of really good scientists at NASA, and NOAA, and at our major universities.  The best scientists in the world are all telling us that our activities are changing the climate, and if we do not act forcefully, we’ll continue to see rising oceans, longer, hotter heat waves, dangerous droughts and floods, and massive disruptions that can trigger greater migration, conflict, and hunger around the globe.  The Pentagon says that climate change poses immediate risks to our national security.  We should act like it.
That’s why, over the past six years, we’ve done more than ever before to combat climate change, from the way we produce energy, to the way we use it.  That’s why we’ve set aside more public lands and waters than any administration in history.  And that’s why I will not let this Congress endanger the health of our children by turning back the clock on our efforts.  I am determined to make sure American leadership drives international action.  In Beijing, we made an historic announcement – the United States will double the pace at which we cut carbon pollution, and China committed, for the first time, to limiting their emissions.  And because the world’s two largest economies came together, other nations are now stepping up, and offering hope that, this year, the world will finally reach an agreement to protect the one planet we’ve got.
His 2015 remarks on climate change reflect a belief or fear that Congress will not act on the issue, or will act to frustrate the Obama administration's efforts on climate change.  In 2013, President Obama asked Congress to develop a market-based solution to climate change, but said he would take executive action if Congress failed to act.  In 2014, he noted Congress's apparent unwillingness to act, and highlighted his administration's proposed new standards on power plant emissions of carbon.  This year's remarks continue the trend of featuring executive-branch solutions, and downplaying the likelihood of near-term legislative support.

Will U.S. production of energy continue to grow?  What economic, political, and national security impacts will flow from the shifts in and growth of the U.S. energy sector?  Will the U.S. continue to act -- or take more serious action -- on climate change?  The remainder of 2015 -- and of President Obama's term in office, which runs into January 2017 -- will show how these themes evolve.