Oregon wave energy project surrenders license

Monday, August 25, 2014

Ocean waves contain tremendous amounts of energy that could be harnessed by humans -- but difficulties have led a pilot project proposed off the Oregon coast to surrender a key federal license.

Calm waters along the shore of Penobscot Bay, Maine.

Ocean Power Technologies subsidiary Reedsport OPT Wave Park, LLC had proposed a wave energy project in the Pacific Ocean off the central Oregon coast.  In 2012, the Federal Energy Regulatory Commission issued a license for the project.  That license authorized the developer to install a single "PowerBuoy" wave energy converter for testing, followed by additional grid-connected buoys.  The developer also envisioned a third phase that could bring the project's capacity to 50 megawatts, and secured a preliminary permit from the Commission to study the site.

Despite securing these key regulatory approvals, the Reedsport project quickly ran into technical difficulties.  Reedsport began construction of the project in September 2012, by installing a single floating gravity based anchor and auxiliary subsurface buoy.  However, this first phase of the project was unsuccessful and the auxiliary buoy sank.  Reedsport removed the buoy and associated tendon and outer mooring lines from the project area on October 17, 2013.  On February 28, 2014, Ocean Power Technologies notified the Federal Energy Regulatory Commission that it intended to surrender its preliminary permit for the 50 megawatt third phase, but left the first phase's license in place for the moment.

On May 30, 2014, Reedsport filed an application to surrender its license for project, stating that financial and regulatory challenges in developing the project have forced it to conclude that it cannot proceed with the development of the project.  The Commission accepted that license surrender by order dated August 14, to be effective following confirmation of the project's decommissioning.

With the Reedsport project shelved, no wave energy project currently holds a FERC license.  Several tidal projects have been licensed, one wave-based hydrokinetic project has secured a preliminary permit, and two other wave energy projects have pending applications for preliminary permits.  The ocean remains a demanding environment, and the economics of most wave energy projects are challenging.  Will others succeed where Reedsport OPT has not?

Maryland offshore wind sites auctioned

Wednesday, August 20, 2014


The U.S. Bureau of Ocean Energy Management has sold the rights to lease sites for offshore wind projects in federal waters off Maryland to US Wind Inc. for $8.7 million.

A lighthouse on an island in the Atlantic Ocean, off Maine.


Part of the Obama administration's "Smart from the Start" offshore wind leasing program, yesterday's auction covered the rights to lease nearly 80,000 acres of the outer continental shelf.  The Maryland Wind Energy Area ranges seaward from about 10 nautical miles offshore Ocean City.  According to Department of Energy’s National Renewable Energy Laboratory, the area could support between 850 and 1450 megawatts of commercial wind generation.

The Maryland auction drew three bidders: US Wind Inc., Green Sail Energy LLC and SCS Maryland Energy LLC.  After 19 rounds, BOEM declared US Wind Inc. the provisional winner.  US Wind Inc. is a subsidiary of Italian firm Toto SpA's Renexia group. 

While winning the auction is an important first step in leasing federal ocean sites for offshore wind projects, the process will likely continue to play out for several years.  Following the auction results, US Wind Inc. will have one year within which to submit a Site Assessment Plan to BOEM for approval.  In the Site Assessment Plan, the lessee must describe what it intends to do to assess of the wind resources and ocean conditions of its commercial lease area -- for example, installing meteorological towers and buoys.  If that plan is approved, the lessee will then have up to 4½ years in which to submit a Construction and Operations Plan providing more detailed information for the construction and operation of a wind energy project on the lease.  The filing of that plan triggers further public comment and environmental review; if approved, BOEM will then issue a lease with an operations term of 25 years.  Notably, these leases generally require the lessee to pay ongoing rents; placing the winning bid in the auction conveys the right to pay that rent, but paying that bid does not count towards the lease payment obligation.

Moreover, this entire leasing process is just one of several aspects of the project that must move forward in parallel.  At the same time, US Wind Inc. is likely considering engineering issues such as turbine selection and interconnection design as well as how to finance the project.

Will federal waters offshore Maryland soon become home to an offshore wind project?

Feds to auction North Carolina offshore wind sites

Friday, August 15, 2014

The U.S. Department of the Interior's Bureau of Ocean Energy Management has announced plans to auction the rights to lease sites off the North Carolina coast for offshore wind projects.

Under the Bureau of Ocean Energy Management's "Smart from the Start" competitive program for leasing sites on the outer continental shelf (OCS) for commercial wind energy development, BOEM conducts a series of stakeholder and environmental review processes.  Through these processes, BOEM identifies areas that are attractive for commercial offshore wind development, while also protecting important viewsheds, sensitive habitats and resources and minimizing space use conflicts with activities such as military operations, shipping and fishing.

For North Carolina, the process began in December 2012 when BOEM published in the Federal Register a Call for Information and Nominations and a Notice of Intent to Prepare an Environmental Assessment.  After considering the public comments and responses, BOEM defined three Wind Energy Areas off North Carolina:
  • The Kitty Hawk Wind Energy Area begins about 24 nautical miles (nm) from shore and extends approximately 25.7 nm in a general southeast direction at its widest point. Its seaward extent ranges from 13.5 nm in the north to .6 nm in the south. It contains approximately 21.5 OCS blocks (122,405 acres).
  • The Wilmington West Wind Energy Area begins about 10 nm from shore and extends approximately 12.3 nm in an east - west direction at its widest point. It contains just over 9 OCS blocks (approximately 51,595 acres).
  • The Wilmington East Wind Energy Area begins about 15 nm from Bald Head Island at its closest point and extends approximately 18 nm in the southeast direction at its widest point. It contains approximately 25 OCS blocks (133,590 acres). 

Map of North Carolina Wind Energy Areas, courtesy of BOEM.
The North Carolina auction will follow a series of similar auctions for East Coast offshore wind sites in federal waters over the past year, including sites off Massachusetts and Rhode Island and Virginia, and will come after the scheduled August 19 auction for sites off Maryland.  To date, BOEM has awarded five commercial wind energy leases off the Atlantic coast: two non-competitive leases (for the proposed Cape Wind project in Nantucket Sound and an area off Delaware) and three competitive leases (two offshore Massachusetts-Rhode Island and another offshore Virginia).  Altogether, the competitive lease sales have generated more than $5 million in high bids for more than 277,500 acres in federal waters.  BOEM expects to hold additional competitive auctions for wind energy areas offshore Massachusetts and New Jersey in the coming year.

When will North Carolina offshore wind sites be auctioned?  Who will bid?  Who will win -- and what will the high bid be?  Perhaps most fundamentally, will the BOEM leasing process lead to anyone developing a offshore wind project off North Carolina?

Boon Island lighthouse auction

Wednesday, August 13, 2014

The U.S. federal government is auctioning off Maine's tallest lighthouse, located on Boon Island near one of the state's designated offshore wind test sites.

Boon Island Light Station, seen from Cape Neddick.

The Boon Island Light Station auction, conducted online through the General Services Administration's website, covers a 133-foot granite tower sited on a barren outcrop of granite 14 feet above sea level.  Built in 1855 and listed on the National Register of Historic Places, the lighthouse will continue to serve as an unmanned navigational aid maintained by the United States Coast Guard.

In 2009, the Maine Legislature selected waters near Boon Island as one of three designated offshore wind test sites.  While the Monhegan offshore wind test site drew interest from the University of Maine-led Aqua Ventus consortium, to date, no project has publicly pursued plans to develop the Boon Island offshore wind test site.

Meanwhile, the federal government continues to sell or otherwise get rid of "surplus" property.  Two years ago, the federal government announced plans to give away two Maine lighthouses -- Boon Island and Halfway Rock -- to qualified entities willing to conserve the historic structures.  When no such transfer ensued, the General Services Administration placed both lighthouses on the auction block.

As of early Wednesday afternoon, 13 bidders had participated in the auction for the Boon Island light station, with a current high bid of $64,000.  The auction is scheduled to close midday on Thursday, although previous deadlines have been extended.

Feds to auction Maryland offshore wind sites

Monday, August 11, 2014

On August 19, the U.S. Department of the Interior's Bureau of Ocean Energy Management will auction off rights to lease sites off the Maryland coast for offshore wind.  Through the auction, which will represent the third auction for offshore wind sites in federal waters since July 2013, the Bureau hopes it will award leases to two areas covering approximately 80,000 acres about 10 nautical miles east of the Ocean City coastline.

Last year, the Department of the Interior held its first offshore wind site auction for sites off Massachusetts and Rhode Island; Deepwater Wind won that auction with a bid of $3.8 million.  The second auction, held for Virginia on September 4, covered approximately 112,799 acres about 23.5 nautical miles from the Virginia Beach coastline; Dominion Virginia Power won that auction with a bid of $1.6 million.

The Maryland auction later this month will follow procedures similar to those used in the previous two auctions.  Based on previous expressions of interest and qualifications, BOEM has determined that sixteen companies are eligible to bid on the Maryland sites:
  • Apex Offshore Maryland, LLC
  • Bluewater Wind Maryland LLC
  • Convalt Energy LLC
  • Dominion Wind Development, LLC
  • EDF Renewable Development, Inc.
  • Energy Management, Inc.
  • Fishermen’s Energy, LLC
  • Green Sail Energy LLC
  • IBERDROLA RENEWABLES, Inc.
  • Maryland Offshore Wind LLC
  • Orisol Energy US, Inc.
  • RES America Developments Inc.
  • SCS Maryland Energy LLC
  • Sea Breeze Energy LLC
  • Seawind Renewable Energy Corporation LLC
  • US Wind Inc.
How many of these entities actually participate in the auction remains to be seen.  8 qualified bidders (or their affiliates) also qualified to participate in the Virginia auction, but only winner Dominion and an Apex affiliate ever placed bids.  For Massachusetts and Rhode Island sites, 9 companies qualified to bid but only winner Deepwater, Sea Breeze, and US Wind participated.

Offshore wind project developers must coordinate regulatory, financial, and engineering efforts.  Securing a site for a project is a major step forward, but is only one of many important steps necessary to build an operating offshore wind project -- something the U.S. still lacks.  How much interest will the Maryland auction draw?  Who will win the right to lease the two parcels in the Maryland wind energy area, and how much will they pay?  Will the auction winners actually build offshore wind projects?  Some of these questions will be answered when the auction closes on August 19.

FERC approves second Southwest blackout penalty

Thursday, August 7, 2014

A California irrigation district has agreed to pay a $12 million penalty to settle its role in a 2011 power outage affecting over 5 million people in California, Arizona, and Mexico.

The September 8, 2011 outage started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded.  In the end, the outage deprived customers of 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.

Swiftly on the heels of the outage, the Federal Energy Regulatory Commission and electric reliability organization NERC launched an investigation into what had happened -- and whether any laws or regulations had been violated.  That investigation focused on APS and five other entities believed to have been involved: the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator.  Last month, the Commission approved a $3.25 million settlement with APS.

Today, the Commission issued an order approving a stipulation and consent agreement resolving  Imperial Irrigation District's role in the blackout.  Imperial Irrigation District is a not-for-profit, publicly owned, vertically integrated utility and political subdivision of the State of California.  The sixth largest utility in California, Imperial Irrigation District Electricity provides electric power to more than 145,000 customers in the Imperial Valley and parts of Riverside and San Diego counties.

Through their investigation, Commission enforcement staff and NERC found Imperial Irrigation District violated 10 requirements of four Reliability Standards on transmission operations and transmission planning, including a failure to coordinate its operations planning with neighboring systems.  The Commission noted that these violations were serious deficiencies that undermined reliable operation of the Bulk Power System.

Through that stipulation, Imperial Irrigation District agreed to pay a civil penalty of $12 million.  Of this amount, at least $1.5 million will go to the U.S. Treasury and another $1.5 million will go to NERC, and at least another $9 million will be invested in reliability enhancement measures that go beyond mitigation of the violations and the requirements of the mandatory Reliability Standards.  These reliability enhancements will include construction of one or more utility-scale battery energy storage facilities within IID’s transmission operations area, with the money spent by December 31, 2016.

Two of the six entities known to be targeted by the Commission's investigation have now settled their alleged violations by agreeing to pay penalties.  Perhaps more significantly, APS and Imperial Irrigation District represent two of the three vertically integrated utilities implicated.  Will the FERC/NERC investigation lead to further settlements soon?  What impact will the Imperial Irrigation District settlement and penalty agreement have?

FERC tests 2-year hydropower licensing process

Wednesday, August 6, 2014

Licensing some new hydropower projects in the United States -- traditionally a lengthy process -- may soon become easier, as federal regulators have approved an experimental two-year process that may soon be used to license some projects.

Water spills over a small, non-powered dam in Maine.

The Federal Energy Regulatory Commission regulates most hydropower development in the United States.  Under Part I of the Federal Power Act, the Commission considers applications for hydropower project licenses.  While the traditional licensure process has resulted in the issuance of thousands of licenses, winning a license for a project can take many years -- and some licensure proceedings have stretched toward a decade.

In response to concerns that lengthy licensing procedures stifle hydropower development, last year Congress enacted the Hydropower Regulatory Efficiency Act of 2013.  That law directed the Commission to investigate the feasibility of a two-year licensing process for certain projects, develop criteria for identifying projects that may be appropriate for the process, and develop and implement pilot projects to test the process.

In January 2014, the Commission solicited pilot projects to test a two-year process.  Two kinds of projects were eligible: hydropower development at existing non-powered dams and closed-loop pumped storage projects.  In the notice soliciting pilot projects, the Commission articulated additional criteria for eligibility including:
  • The project must cause little to no change to existing surface and groundwater flows and uses;

  • The project must not adversely affect federally listed threatened and endangered species;

  • If the project is proposed to be located at or use a federal dam, the request to use the two-year process must include a letter from the dam owner saying the plan is feasible;

  • If the project would use any public park, recreation area, or wildlife refuge, the request to use the two-year process must include a letter from the managing entity giving its approval to use the site; and

  • For a closed-loop pumped storage project, the project must not be continuously connected to a naturally flowing water feature. 
Ultimately, the Commission selected a project proposed by Free Flow Power Project 92, LLC: a 5-megawatt project at the Kentucky River Authority's existing Lock & Dam No. 11 on the Kentucky River in Estill and Madison counties, Kentucky.  Lock and Dam 11 were originally built from 1904-1906 and support a twenty mile long pool of water 201 miles above the mouth of the Ohio River, but have not previously supported a FERC-licensed hydropower project.

The Free Flow Power applicant's request to use the 2-year licensing process was filed on May 5, 2014, so the two years runs through May 5, 2016.  The Commission staff has issued a process plan and schedule with interim milestones through February 2016.  Compared to a traditional licensure process, the proposed schedule is accelerated -- but will this pilot case remain on schedule?  Will the accelerated process satisfy the various stakeholders, including the developer, regulator, neighbors, and public?

FERC testifies on EPA carbon regulations and electric reliability

Wednesday, July 30, 2014

The U.S. Environmental Protection Agency's proposed Clean Power Plan rule is projected to limit carbon dioxide emissions from power plants, improve human health and save money -- but will it jeopardize the reliability of the nation's electricity grid?

Poorly implemented carbon regulations could increase the risk of widespread power outages, but this risk can be managed, according to testimony offered by the Commissioners of the Federal Energy Regulatory Commission to the House Energy & Commerce Subcommittee on Energy & Power earlier this week.

In her written testimony, Acting Chairman Cheryl LaFleur acknowledged concerns that EPA's carbon rule may have an "adverse impact on the overall reliability of the bulk power system."  Noting that EPA's plan leaves much of the implementation to individual states, she suggested that the FERC work closely with states to consider how state implementation plans will affect the operation of the grid. 

Commissioner Philip Moeller's testimony was more critical of EPA's proposed rule, which he described as infringing upon the FERC's jurisdiction over electric system reliability.  Noting that electricity markets are interstate in nature, Commissioner Moeller warned that "the proposal’s state-by-state approach results in an enforcement regime that would be awkward at best, and potentially very inefficient and expensive."  He also expressed skepticism at the plan's inclusion of increased use of existing natural gas-fired generation as one "building block" states may use to reduce their power sector's carbon intensity.  Commissioner Moeller also pointed to EPA's Mercury and Air Toxics Standards (MATS) rule as giving him reliability concerns.  On the positive side, he urged state regulators to speed adoption of real-time pricing at the retail level, so consumers can feel price signals that could reduce the overall cost of energy.  Commissioner Moeller concluded with a plea that FERC be given a formal role in EPA's regulation of the electric power sector.

Commissioner John Norris testified that EPA's proposed rule is "an important first step that addresses climate change by appropriately seeking to reduce carbon emitted by our nation’s electric power system."  While he acknowledges that transitioning to a low-carbon economy is challenging, he expressed confidence that "we as a nation should be well positioned to meet those challenges."  Commissioner Norris cited the MATS standards as an example of our readiness: while EPA's MATS rule led to the retirement of many older, inefficient coal-fired power plants, the grid has generally responded in a way that will maintain reliability.  Commissioner Norris urged cooperation with electric reliability organization North American Electric Reliability Corporation (NERC) and states, and to be flexible in making market rule changes to enable states, regional transmission organizations and other system planners to meet resource adequacy requirements.

Commissioner Tony Clark testified that while the grid is more reliable than before, it remains vulnerable to cyberattack, physical security threats, and geomagnetic disturbances.  He also described environmental regulations as another source of risk, and warned of the "seismic" shift in EPA authority over the energy sector embodied in the rule.  Commissioner Clark described the Clean Power Plan as the most comprehensive reordering he has seen of the jurisdictional relationship between the federal government and states as it relates to the regulation of public utilities and energy development.  He painted a picture of states forced to choose between surrendering their authority over power plants willingly or losing it to federal supremacy.

Current FERC enforcement director Norman Bay also testified, noting that he was confirmed by the Senate as a Commissioner on July 15, but that he has not yet been sworn in.  His brief testimony focused on the need for cooperation between FERC, EPA, NERC, states, and regional transmission organizations to ensure reliability.

What happens next remains to be seen.  As expressed in the opening statements of Energy and Power Subcommittee Chairman Ed Whitfield and Energy and Commerce Committee Chairman Fred Upton, many remain concerned about what they perceive as an effort by EPA to assert control and new regulatory authorities over states’ electricity decision-making.  Will EPA's Clean Power Plan ultimately come into effect -- and if so, what path will it take?

Report projects modest need for electric generation capacity growth

Thursday, July 24, 2014

The U.S. Energy Information Administration has projected that 351 gigawatts of new electric generating capacity will be added to the U.S. grid between 2013 and 2040.  This projected new capacity, most of which EIA expects to be fueled by natural gas, will replace older power plants as they retire, as well as modestly increasing the country's net installed capacity.

EIA's forecast implies a growth rate well below recent annual levels observed.  Under EIA's projection, capacity additions through 2016 will average 16 GW per year.  But from 2017 through 2022, EIA expects additions of less than 9 GW per year as the existing generating fleet will be sufficient to meet expected demand growth in most regions.  From 2025 to 2040, annual additions increase to an average 14 GW per year, but remain below recent levels.

EIA expects that natural gas will be the primary fuel source for the projected added capacity, accounting for 73% of capacity additions in the reference case (or 255 GW).

Renewables will account for 24% of the new capacity (or 83 MW).  Of renewable capacity additions, 39 GW are solar photovoltaic (PV) systems (60% of which are rooftop installations).  Another 28 GW are wind, most of which will occur by 2015 to qualify for federal renewable energy production tax credits).

New nuclear capacity will total about 3% (or 10 GW), including 6 GW of plants currently under construction and 4 GW projected after 2027.

EIA also projects that 1% of capacity additions (or less than 3 GW) will come from coal, with more than 80% of that total currently under construction.  EIA notes that federal and state environmental regulations and uncertainty about future limits on greenhouse gas emissions reduce the attractiveness and economic merits of coal-fired plants.

Like any forecast, EIA's projections rest upon a series of assumptions.  Under alternative cases, we might experience actual capacity additions that differ from EIA's forecasts.  Nevertheless, the EIA Annual Energy Outlook 2014 offers a glimpse of changes to the portfolio composing our energy mix may come in the next decades.

Atlantic offshore wind energy targeted

Tuesday, July 15, 2014

A report released by the National Wildlife Foundation highlights the potential of U.S. states on the Atlantic Ocean to generate electricity from offshore wind -- and calls upon state leaders to take action to promote offshore wind development.

The 24-page report, Catching the Wind: State Actions Needed to Seize the Golden Opportunity of U.S. Offshore Wind Power, describes responsibly developed offshore wind as "a golden opportunity to meet our coastal energy needs with a clean, local resource that will spur investments in local economies."  In particular, the Atlantic coast offers a high-quality wind resource in close proximity to power-thirsty coastal cities.

Key findings in the report include:
The report highlights Massachusetts and Rhode Island as leading America's pursuit of offshore wind, followed by Maryland, Virginia, New York, New Jersey, and Delaware, with Maine, North Carolina, South Carolina, and Georgia bringing up the rear.  New Hampshire, Connecticut, and Florida are noted as "states to watch" with no offshore wind planning activities.

The report calls on state leaders to:
  • Set a bold goal for offshore wind in the state's energy plan.
  • Take action to ensure a competitive market for offshore wind power.
  • Advance power contracts for offshore wind.
  • Ensure an efficient, transparent, and environmentally responsible offshore wind leasing process that protects wildlife.
  • Invest in key research, initiatives, and infrastructure needed to spur offshore wind development.
Will Atlantic states develop their offshore wind resources? 

Arizona utility fined $3.25 million over 2011 blackout

Friday, July 11, 2014

On a hot summer afternoon in 2011, cascading power outages spread across the North American Southwest.  Over 5 million people in Southern California -- including all of San Diego -- Arizona and Mexico were left without power for up to 12 hours.  This week a federal investigation into the outage was partially resolved by a $3.25 million settlement with Arizona Public Service Company.

According to a joint report by the staffs of the Federal Energy Regulatory Commission and the North American Electric Reliability Corporation, the September 8, 2011 outage started when a 500-kilovolt transmission line owned by APS tripped.  The Hassayampa - N. Gila line serves as a major transmission corridor that transports power in an east-west direction, from generators in Arizona into the San Diego area.  The line's failure triggered significant voltage deviations and equipment overloads, causing transformers, transmission lines, and generating units to trip offline through automatic load shedding.  In all, 7,835 megawatts of customer load lost power -- over 30,000 megawatt-hours of energy -- primarily in the San Diego Gas and Electric service territory and in Baja California.

Following the outages, both the Commission's Office of Enforcement and NERC launched an investigation into the incident.  That investigation, which has been ongoing since 2011, focused on APS and five other entities believed to have been involved: the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator.


The investigation concluded that APS had violated NERC's mandatory Reliability Standards.  APS's role and liability was ultimately resolved this week when the Commission accepted a stipulation between APS, the Commission's Office of Enforcement and NERC.

Through that stipulation, APS agreed to pay a civil penalty of $3.25 million.  Of this amount, $1 million will go to the U.S. Treasury, $1 million will go to NERC, and $1.25 million will be invested in reliability enhancement measures that go beyond mitigation of the violations and the requirements of the mandatory Reliability Standards.  In finding the settlement to be in the public interest, the Commission cited APS's cooperation in the investigation as well as its voluntary mitigation efforts.

With APS's role in the outage settled, joint FERC/NERC investigations into other entities' roles continue.  While some targets of investigation choose to settle their cases, others insist to exercise their full legal rights.  Will the 2011 Southwest blackouts lead to further stipulations and penalties?

Energy Department offers $4 billion loan guarantee program for renewable energy and efficiency projects

Tuesday, July 8, 2014

The U.S. Department of Energy has announced a $4 billion loan guarantee program for renewable energy and energy efficiency projects.

The Renewable Energy and Efficient Energy Projects Loan Guarantee program is intended to support the first commercial-scale deployments of the next wave of innovative clean energy technologies. Through the program, the Energy Department solicits applications for loan guarantees.  When a successful applicant borrows money for project finance from a commercial bank, the federal government promises to assume the borrower's debt obligation if that borrower defaults.  This guarantee serves as a credit backstop for the borrower, ultimately reducing its cost of financing because the lender knows it has resort to federal funds if the borrower cannot repay the loan.

The current program follows a series of previous Energy Department loan guarantee programs.  These programs have helped finance projects including the NRG Solar, LLC's 290-megawatt Agua Caliente solar photovoltaic array (the world's largest), NRG Energy, Inc.'s 392-megwatt Brightsource concentrating solar power (CSP) plant (also the world's largest), the 845-megawatt Caithness Shepherds Flat wind project, and Abengoa Bioenergy Biomass of Kansas LLC's cellulosic ethanol plant.  While not all of the previous programs' awardees have been successful -- for example, failed solar panel maker Solyndra -- the Department touts the programs as aligned with President Obama's Climate Action Plan, by supporting investment in domestic energy resources and reductions in greenhouse gas emissions.

To be eligible for the present solicitation (48-page PDF), a project must be located in the United States and meet both of the following criteria:
1. Use renewable energy systems; efficient electrical generation, transmission, and distribution technologies; or efficient end-use energy technologies; and

2. Meet both of the following requirements : a) Avoid, reduce, or sequester anthropogenic emission of greenhouse gases; and b) employ new or significantly improved technology as compared to commercial technology in service in the United States. 
Beyond these general criteria, the Energy Department's Loan Programs Office has identified five target areas for awards:
  • Advanced Grid Integration and Storage: mitigating issues related to variability, dispatchability, congestion, and control of renewable energy systems by incorporating technologies such as demand response or local storage, enabling enhanced integration of renewable energy into the grid.
  • Drop-In Biofuels: developing biofuels that are more compatible with today’s engines, delivery infrastructure and refueling station equipment, enabling nearly identical bio-based substitutes for crude oil, gasoline, diesel fuel, and jet fuel
  • Waste-to-Energy: projects using waste materials which are otherwise discarded, such as landfill methane and segregated waste, as energy sources.
  • Enhancement of Existing Facilities: incorporating renewable generation technology into existing renewable energy and efficient energy facilities to significantly enhance performance or extend the lifetime of the generating asset. 
  • Efficiency Improvements: projects incorporating new or improved technologies to further improve on energy efficiency that would substantially reduce greenhouse gases. 

Under the solicitation, the first round of application materials is due on October 1, 2014.  For more information on the opportunity, contact the Energy Department, or consult a professional experienced with financing and developing energy projects.

The Preti Flaherty team advises our clients on all aspects of energy project development, including the pursuit of federal funding and financial support. For more information, please contact Todd Griset at 207-623-5300.

Muskrat Falls megahydro cost increases

Wednesday, July 2, 2014

The Canadian province of Newfoundland and Labrador is promoting the development of a multi-phase, gigawatt-scale hydropower project on the Churchill River in Labrador.  But estimates of the so-called megaproject's construction costs continue to mount, now reaching nearly $7 billion (Canadian).

The Churchill River drains much of western Labrador, combining large volumes of water with a significant drop in elevation.  For these reasons, Canadian provinces and utilities have long sought to harness its power.  In 1971, the Churchill Falls dam and hydropower plant came online; today, the Churchill Falls facility can generate 5,428 megawatts of power, giving it the second largest capacity of any power station in North America.

In 2010, Newfoundland and Labrador utility Nalcor Energy and Nova Scotia utility Emera announced the Lower Churchill project.  The first phase proposed, Muskrat Falls, entails the construction of a dam with an 824 megawatt power house, with the subsequent Gull Falls dam bringing the proposed Lower Churchill project's total capacity to over 3,000 megawatts.  The Muskrat Falls project received a key approval by provincial government in December 2012, and construction is now underway.  90 per cent of the project contracts have been awarded, and 98 per cent of the engineering on the project has been done.

Back in 2010 when Nalcor and Emera first announced the project, the cost forecast for the Newfoundland and Labrador portion was $5 billion.  But as the St. John's Telegram reports, the latest cost estimate for building the Muskrat Falls project has jumped by about $800 million, to $6.99 billion.

This estimate does not include the cost of the Maritime Link transmission system to be built by Emera, connecting Newfoundland to Nova Scotia via undersea cable.  The Maritime Link is expected to cost an additional $1.5 billion.

Despite the cost overruns, the project is reported to be on schedule to be completed in 2017.

EPA carbon rule: how it works

Monday, June 9, 2014

Last week, the U.S. Environmental Protection Agency issued a groundbreaking proposed rule to limit carbon emissions from power plants.  EPA's Clean Power Plan would require each state to develop a plan to limit the amount of carbon dioxide its power plants produce per unit of electricity generated.  By reducing the carbon intensity of electric generation, EPA projects that the Clean Power Plan would would achieve a 30 percent reduction in CO2 emission from the nation's power sector below CO2 emission levels in 2005, resulting in net climate and health benefits of $48 billion to $82 billion.  Importantly, the Clean Power Plan would rely on federal and state cooperation to achieve this goal.

Public Service of New Hampshire's Schiller Station, in Portsmouth, NH, can burn coal, oil, and wood chips.

EPA proposed the carbon rule pursuant to its authority under Section 111(d) of the Clean Air Act.  As with other Section 111(d) regulations, the Clean Power Plan relies on a combination of federal emission limits and state implementation plans.  First, EPA proposed state-specific carbon dioxide emission goals, stated as an emission rate of pounds of CO2 emitted per net megawatt-hour of electricity generated.  Second, EPA offered states guidelines for how to develop, submit, and implement their own plans to reach those emission goals.

At the federal level, EPA set a carbon emissions rate limit for each state based on the agency's evaluation of how much the state could feasibly reduce emissions by adopting the "best system of emission reduction", or BSER.  Effectively, EPA considered each state's portfolio of electricity generating resources as well as how hard it would be to reduce its carbon intensity.

At the state level, EPA expects each state to propose a plan based on a combination of four "building blocks" or types of measures:
  • Reducing the carbon intensity of generation at individual affected fossil-fired electric generating units (or EGUs) through heat rate improvements
  • Reducing emissions from the most carbon-intensive affected EGUs by substituting generation at those EGUs with generation from natural gas combined cycle power plants and other less carbon-intensive fossil-fired units
  • Reducing emissions from affected EGUs by substituting generation at those EGUs with expanded low- or zero-carbon generation
  • Reducing emissions from affected EGUs through demand-side energy efficiency measures 
State plans would be subject to EPA approval, based on their enforceability, ability to achieve emission performance, verifiability, and reporting process.  EPA suggested that states may develop collaborative multistate programs.  States may also incorporate existing CO2 emissions reduction programs such as the Regional Greenhouse Gas Initiative or California's carbon market into their plans.  Procedurally, EPA expects that states would submit their plans by June 30, 2016, for review and approval, with the possibility of a one-year extension of this deadline.

EPA is now taking public comment on its proposed Clean Power Plan rule for 120 days, and will hold public hearings on the proposal in July and August.  EPA projects that it would issue its final Clean Power Plan rule in June 2015.

EPA carbon rule: cost and benefit

Friday, June 6, 2014

Monday, the U.S. Environmental Protection Agency proposed a rule aimed at reducing carbon dioxide emissions from power plants.  Part of the EPA's "Clean Power Plan", the rule would rely on states developing and implementing their own plans to reduce the amount of carbon emitted by the electric power sector per unit of electricity generated.  EPA projects that if fully implemented, meeting this goal would reduce the power sector's carbon emissions to 30% below 2005 levels by 2030.  But what will this cost -- and what will the benefits be?

Steam rises from the Con Edison power plant at 14th Street and Avenue C, in New York City.  The plant can burn fuels including oil and natural gas.

Power plants represent the largest source of carbon dioxide emissions in the U.S., accounting for about one-third of the nation's greenhouse gas emissions.  Building on President Obama's 2013 Climate Action Plan and the May 2014 release of the third National Climate Assessment, the Clean Power Plan is premised upon the finding that greenhouse gas pollution "threatens the American public by leading to potentially rapid, damaging and long-lasting changes in our climate that can have a range of severe negative effects on human health and the environment."  The proposed rule targets carbon dioxide because is the most prevalent greenhouse gas, accounting for 82% of U.S. greenhouse gas emissions.

The Clean Power Plan requires states to develop plans to reduce the carbon intensity, or amount of carbon emitted per unit of useful energy, of their power plants.  Each state is allowed to select the measures it wishes to use to reach its carbon intensity goal.  This allows states flexibility to craft policies to reduce carbon pollution that:
1) continue to rely on a diverse set of energy resources, 2) ensure electric system reliability, 3) provide affordable electricity, 4) recognize investments that states and power companies are already making, and 5) can be tailored to meet the specific energy, environmental and economic needs and goals of each state .
The economic impacts of the Clean Power Plan will form a key theme in the debate over its implementation.  The flexibility afforded states makes projections of costs and benefits hard to quantify, even before consideration of the global social cost of carbon or economic concepts like the appropriate discount rate to apply to future costs and benefits.  With those caveats stated, EPA has analyzed two illustrative cases: a collaborative, regional compliance approach (perhaps along the lines of the Regional Greenhouse Gas Initiative) and a state-by-state approach.

Under EPA's analysis as stated in its proposed rule documents, the Clean Power Plan will produce economic benefits far in excess of its costs.  In 2020, EPA projects the regional compliance approach would have total costs of $5 billion, climate benefits of approximately $17 billion, and health co-benefits associated with reduced particulate matter and other emissions -- mostly in the form of reduced premature fatalities -- of between $16 billion and $37 billion.  In this scenario, the Clean Power Plan would yield net economic benefits of between $28 billion and $47 billion by 2020.  EPA's analysis of a state-by-state approach yields similar costs and benefits: a cost of $7.5 billion by 2020, climate benefits of approximately $18 billion, and health co-benefits of between $17 billion and $40 billion.  Under either case, net benefits continue to grow through 2030, reaching between $48 billion and $84 billion.

EPA also projects "job gains and losses relative to base case for the electric generation, coal and natural gas production, and demand side energy efficiency sectors."  In 2020, EPA projects job growth of 25,900 to 28,000 job-years in the power production and fuel extraction sectors, and an increase of 78,000 jobs in the demand-side energy efficiency sector.

What the ultimate costs and benefits of the Clean Power Plan will be remains uncertain, as does EPA's adoption of a final rule implementing the plan.  In the meantime, electric generators, consumers, and policymakers are taking close looks at the plan to ascertain its impacts.

EPA proposes carbon goals for power plants

Monday, June 2, 2014

The U.S. Environmental Protection Agency has proposed its plan to reduce carbon emissions from the nation's power plants by 30% below 2005 levels.

Stacks rise from the coal-fired Salem Harbor Station power plant, which closed on June 1, 2014.

Formally known as "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units", EPA's proposed rule spans 645 pages (PDF).  The so-called Clean Power Plan builds on President Obama's 2013 Climate Action Plan, relying on the agency's authority under Section 111(d) of the Clean Air Act.  Generally, Section 111 provides for the establishment of nationwide emission standards for major stationary sources of air pollution such as power plants.  Current regulations limit power plants' emissions of arsenic, mercury, sulfur dioxide, nitrogen oxides, and particle pollution, but there are currently no national limits on carbon pollution levels.

EPA's Clean Power Plan would, for the first time, provide federal regulation of power plants' carbon emissions.  EPA envisions a collaborative process through which federal limits are established for each state, but where states have the flexibility to identify their own path forward using either current or new electricity production and pollution control policies to meet the goals of the proposed program.  Each state's carbon emissions limit would be stated as a rate of allowable pounds of carbon emissions per megawatt-hour of electric energy generated.  EPA would set these rates based on a case-by-case evaluation of each state's energy mix -- including its portfolio of generation resources -- and EPA's evaluation of opportunities to reduce carbon emissions.

States would then be free to design a program to achieve those rates in a way that makes the most sense for each state's unique situation, combining diverse fuels, energy efficiency and demand-side management to create a tailored solution for each state. EPA also envisions collaboration among states, including the development of multi-state plans.  Some states have already organized collaborative programs to reduce the electric power sector's carbon emissions -- for example, the Regional Greenhouse Gas Initiative (RGGI) program in the eastern states

If adopted, EPA's rule would require states to submit their plans to EPA for review in June 2016.  But EPA's plan is not yet final.  It first faces public comment through the summer, including public hearings during the week of July 28 in Denver, Atlanta, Washington, DC and Pittsburgh.  EPA anticipates finalizing its standards in June 2015.

Additional materials, including fact sheets and a regulatory analysis, are posted on the EPA's Clean Power Plan program website.

US energy consumers paid $14 billion more last winter

Tuesday, May 27, 2014

U.S. consumers paid $14 billion more for their energy needs during the winter of 2013-2014 compared to the previous winter, according to a report by the U.S. Energy Information Administration.

The cost of energy affects people and businesses across the country.  Consumers are affected by both the price they pay per unit of electricity or fuel for transportation and heating and the volume of each energy commodity they demand.  In much of the U.S., demand for energy increases during winter months.  The winter season often sees prices increase as well, as more expensive supply is needed to meet consumer demand.

The winter of 2013-2014 was no exception, according to the EIA's data.  U.S. consumers spent $14 billion more for energy during the fourth quarter of 2013 and first quarter of 2014 compared to the previous winter.  This amounts to an increase of 4.4%, or a 0.1% increase when measured as a share of disposable income.

The biggest drivers of the increase in consumer energy costs were higher expenditures for electricity, natural gas, heating oil and propane.  Electricity expenditures increased $7.9 billion, or 10%, last winter compared with the previous winter.  Much of the increased cost of electricity came as a result of increased costs for natural gas, a key fuel used for electric power generation.  Constraints on interstate natural gas pipelines drive fuel prices up as demand increases.  Throughout much of the northeast region, interstate natural gas pipelines reach their maximum flow rates on an increasing number of winter days.  When the pipelines begin to fill, the price of natural gas delivered into the constrained region increases.  Ultimately, when the pipelines have reached their maximum capacity, no more natural gas can be bought at any price.

The price of natural gas also affects consumers directly, as consumers also rely upon natural gas for space heating and applications like drying.  EIA's data show that consumer expenditures for natural gas increased by $5.8 billion, or 16%, last winter compared with the previous winter.

Expenditures for the other major heating fuels -- oil and propane -- also increased by $6.0 billion, or 27%, over the previous winter.  As EIA notes, heating oil and propane are used predominantly for space heating and are used to heat a relatively small number of homes, but their use is concentrated in the Northeast -- the area of the country that experienced the coldest weather this winter.  Propane consumers experienced not only price spikes but even shortages during the coldest parts of the season.

As costly as the past winter was, the increase in consumer energy costs would have been even higher if transportation-related costs had not decreased significantly.  In fact, transportation accounts for the largest single share of U.S. consumers' energy budget -- often over two-thirds of energy expenditures during the summer driving season, and over half of energy expenditures even in the winter.  But transportation fuel expenses decreased by $5.8 billion, or 3%, last winter compared with the previous winter.  EIA cites reductions in demand for gasoline due to winter storms that reduced driving.

Weather is a significant factor affecting winter energy costs -- but policies and infrastructure also play major roles in shaping consumers' energy expenditures.  What will next winter bring?

Court overturns FERC Order 745 on demand response

Friday, May 23, 2014

A federal appellate court has overturned the Federal Energy Regulatory Commission's key ruling on demand response -- when electricity customers respond to signals about the scarcity of electricity by temporarily reducing their consumption -- and how it should be compensated.

A smart grid technology, demand response can be a key tool in reducing the cost and environmental impact of society's electricity needs.  In most US markets, as the demand for electricity rises (such as during a summer heat wave), grid operators turn to increasingly expensive generating units for new supply to meet that demand.  Those "peaking" units -- used primarily to supply energy during times of peak demand -- are thus relatively expensive.  In many cases, they also rely on fuels like oil that lead to increased emissions of pollutants and carbon dioxide.

Demand response offers an alternative solution.  Customers participating in demand response programs agree to reduce their consumption of power from the grid when so instructed by the grid operator.  For example, an office building might commit to temporarily reduce its air handling load, or a factory to reduce or pause its manufacturing operations.

This can provide much the same benefits as generation, by balancing electricity supply and demand, for a lower cost than generation solutions and without causing incremental air emissions.  Demand response can also avoid the need to develop new or upgraded transmission lines, because it solves the problem through reduced energy flows.  Demand response programs therefore provide benefits to the entire grid, and have been established by both organized wholesale markets and vertically integrated utilities across the country.

While demand response's value to the grid is clear, how to compensate customers for their curtailment remains a key question.  In 2011, the Federal Energy Regulatory Commission issued a landmark order known as Order No. 745.  In Order No. 745 (116 page PDF), the Commission ruled that organized wholesale energy market operators must pay demand response resources the market price for energy, known as the locational marginal price (LMP), when those resources have the capability to balance supply and demand as an alternative to a generation resource and when dispatch of those resources is cost-effective.  Order No. 745 thus represented a major step forward for both demand response providers as well as all customers in markets with demand response program.

But some energy industry associations did not like the rule, and challenged the legality of Order No. 745.  The Electric Power Supply Association appealed the Commission's order to a federal court.  Meanwhile, other groups supported the rule, including industrial energy consumers and environmental advocates.

Today the D.C. Circuit Court of Appeals agreed with the appellants, holding that the Commission overstepped its jurisdictional bounds by encroaching on the states’ exclusive jurisdiction to regulate the retail market.  The court ruling, issued in the case Electric Power Supply Association v. Federal Energy Regulatory Commission (44-page PDF), vacates Order No. 745 and remands it back to the Commission.

If the Commission is to require fair compensation for demand response providers, it will have to find a new way to do so -- and one that would survive renewed judicial challenge.  In the meantime, grid operators are faced with a challenge (and an opportunity): whether and how to revise the way they pay customers for demand response.  As demand response's value remains beyond debate, the economic and environmental pressures that led to Order No. 745 remain strong, so expect this issue to continue to play out over the next year.

Propane: winter shortages in 2014

Friday, May 16, 2014

Propane is widely used as a fuel -- but shortages this past winter led to an unprecedented emergency in the eyes of federal regulators.

Propane is a hydrocarbon produced as a byproduct from natural gas processing and crude oil refining.   Also known as liquefied petroleum gas, this natural gas liquid serves as a fuel in homes, businesses, and industry.  It is used for heating, cooling, cooking, motor vehicle transportation, and agriculture.  In the U.S., propane is transported on a network of pipelines stretching 56,000 miles long, and can also be shipped by rail and by truck.  In recent years, the U.S. propane industry has reached $10 billion in annual activity, with consumers using 15 billion gallons of propane annually for home, agricultural, industrial, and commercial uses.

A marker showing the location of an underground natural gas pipeline near Memphis, Tennessee.
This past winter, a propane shortage affected 24 states, primarily in the Midwest and Northeast regions.  Stored supplies of propane declined in the Midwest, and prices in some places increased by over 50% between January and February 2014.  As forecasts called for continued unseasonably cold weather, local, state, and federal agencies declared states of emergency.  The Federal Motor Carrier Safety Administration issued and extended emergency exemptions to provide regulatory relief for commercial motor vehicle operations directly supporting the delivery of propane and home heating fuels to areas under emergency, ultimately resulting in Congress's enactment of the Home Heating Emergency Assistance Through Transportation Act of 2014.

While the Federal Energy Regulatory Commission regulates neither propane as a commodity nor its storage or marketing, the Commission does regulate the transportation of propane on pipelines.  As this past winter's crisis deepened, some pipelines serving the Midwest voluntarily filed for permission to flow more propane into the region, but this was insufficient to meet demand.

In an unprecedented move, the Federal Energy Regulatory Commission exercised its emergency powers under the Interstate Commerce Act to require a pipeline company to temporarily provide priority treatment to propane shipments from Mont Belvieu, Texas, to locations in the Midwest and Northeast to help alleviate the shortage of propane supplies in those regions.  Citing school closures due to lack of heat, price hikes leading states to provide emergency heating assistance to those who could not afford fuel costs, and economic impacts on chicken farmers, pig farmers, and dairy farms in the South and Midwest who use propane to maintain the livelihood and health of their stock, the Commission found that an emergency existed requiring immediate action.

To address the emergency, the Commission targeted a pipeline owned by Enterprise TE Products Pipeline Company, LLC. In a February 7, 2014, Order Directing Priority Treatment, the Commission required the pipeline company to prioritize the shipment of propane on its natural gas liquids pipeline from the Mont Belvieu hub into the Midwest and Northeast.  That initial order provided for priority treatment for 7 days, which was extended once for another 7 days.

These actions apparently relieved the emergency.  According to testimony provided to the U.S. Senate Committee on Energy and Natural Resources by Commission staff member Nils Nichols, "no further action by the Commission with respect to propane supply was required this past winter."

Will propane again be in short supply next winter?  Will markets respond to align supply and demand at a reasonable price?  Will further regulatory action affect the U.S. propane industry?

U.S. natural gas to pass coal as electricity fuel in 2035

Thursday, May 15, 2014

Coal will continue to fuel the largest share of electricity generated in the U.S. until 2035, when natural gas will surpass it, according to a recent federal report.

The U.S. Energy Information Administration's 2014 Annual Energy Outlook presents a long-term forecast of energy supply, demand, and prices from the present through 2040.  Its scope includes predictions about shifts in the portfolio of types of electricity generating resources used to produce power.  The largest such trend projected in EIA's 2014 report is that the market share of coal and nuclear generators will likely decline over the next two decades, as natural gas-fired and renewable electricity sources grow in prominence.

Historically, coal has fueled the largest share of electricity generated in the U.S.  Typically operating as baseload generation, coal has traditionally been a relatively low-cost fuel for electric production.  Coal's share of the electricity mix peaked in 2007, at 49% of all electric power generated.  Since then, coal's share has declined; in 2012, coal-fired generators produced 39% of all electricity generated by utilities -- still the largest piece of the generation portfolio, despite a significant decline.

Coal's role in the nation's energy mix is under challenge from multiple fronts.  Economically, the increased availability of lower-cost natural gas has made coal less competitive.  Meanwhile, tighter environmental regulations -- such as the U.S. Environmental Protection Agency's Mercury and Air Toxics Standards, or MATS rules -- have placed additional pressure on coal plant operators to either invest in upgraded environmental controls or shut down.

At the end of 2012, 310 gigawatts of coal-fired generating capacity was available to run in the U.S.  Of that, EIA projects that 50 gigawatts will be retired by 2020 under its base case model.

Under EIA's model, natural gas will grow its market share while coal declines.  EIA projects that 70% of all new capacity added before 2040 will be fueled by natural gas.  If EIA's assumptions hold, natural gas will surpass coal as a fuel for electricity generation in 2035.

While EIA's model rests on a series of assumptions, all of the alternative cases examined by EIA assume that coal-fired capacity will be retired, while natural gas-fired and renewable generation will grow.  What will the future hold for the U.S. energy mix?

EIA releases 2014 Annual Energy Outlook

Wednesday, May 14, 2014

The U.S. Energy Information Administration has released its annual report projecting long-term trends in energy markets.

The Energy Information Administration, or EIA, is the statistical and analytical agency within the U.S. Department of Energy.  Its 2014 Annual Energy Outlook (269-page PDF) presents long-term annual projections of energy supply, demand, and prices focused on the U.S. through 2040. Based on data-driven models, the report considers a reference case under which it assumes current laws and regulations remain unchanged, as well as alternative cases that explore important areas of uncertainty for markets, technologies, and policies in the U.S. energy economy.

The report's biggest findings include projections that:
  • Growing domestic production of natural gas and oil continues to reshape the U.S. energy economy, largely as a result of rising production from tight formations, but the effect could vary substantially depending on expectations about resources and technology.
  • Industrial production expands over the next 10 to 15 years as the competitive advantage of low natural gas prices provides a boost to the industrial sector with increasing natural gas use.
  • There is greater upside uncertainty than downside uncertainty in oil and natural gas production; higher production could spur even more industrial growth and lower the use of imported petroleum.
  • Improvement in light-duty vehicle (LDV) efficiency more than offsets modest growth in vehicle miles traveled (VMT) that reflects changing driving patterns, leading to a sharp decline in LDV energy use.
  • Evolving natural gas markets spur increased use of natural gas for electricity generation and transportation, as well as expanded export opportunities.
  • Improved efficiency of energy use in the residential and transportation sectors and a shift away from more carbon-intensive fuels such as coal for electricity generation help to stabilize U.S. energy-related carbon dioxide (CO2) emissions.
The full report includes a series of specific projections -- for example that most new electricity generation capacity added will use natural gas or renewable energy, that solar photovoltaic and wind will dominate new renewable capacity.  The report also projects that through 2040, energy use per capita decreases, largely due to gains in appliance efficiency, a shift in production from cooler to warmer regions, and an increase in vehicle efficiency standards.

How will EIA's projections fare over the coming years?

Obama administration releases National Climate Assessment

Tuesday, May 13, 2014

The Obama administration has released its third National Climate Assessment, a document designed as a public presentation of the administration's comprehensive scientific assessment of how climate change is impacting the U.S. people and economy.

A view from the Lincoln Memorial to U.S. Capitol, in Washington, D.C.

The National Climate Assessment summarizes the impacts of climate change on the United States, now and in the future.  Produced as a collaboration between over 300 experts guided by the 60-member National Climate Assessment and Development Advisory Committee, the report was extensively reviewed by the public and experts, including federal agencies and a panel of the National Academy of Sciences.

The National Climate Assessment has a broad scope, in terms of both types of impacts and regions covered.  Thematically, it analyzes impacts on seven sectors – human health, water, energy, transportation, agriculture, forests, and ecosystems – and on the bigger-picture interactions between these sectors.  Geographically, the report also assesses key impacts on all U.S. regions: Northeast, Southeast and Caribbean, Midwest, Great Plains, Southwest, Northwest, Alaska, Hawai'i and Pacific Islands, as well as a more general look at coasts and oceans.

The report states that that increased scientific scrutiny has led to "increased certainty that we are now seeing impacts associated with human-induced climate change":
While scientists continue to refine projections of the future, observations unequivocally show that climate is changing and that the warming of the past 50 years is primarily due to human-induced emissions of heat-trapping gases. These emissions come mainly from burning coal, oil, and gas, with additional contributions from forest clearing and some agricultural practices.
Outcomes predicted under possible future scenarios include continued increases in average air and water temperatures, changes in rainfall and precipitation patterns, air quality decreases, sea level rise, and ocean acidification.  These changes can disrupt systems for food production, harm human health, or damage property and risk safety through flooding.

The National Climate Assessment also summarizes options for responding to climate change.  These include mitigation: reducing the amount and speed of future climate change by reducing emissions of heat-trapping gases or removing carbon dioxide from the atmosphere.  Efforts to limit emissions or promote carbon sequestration are considered mitigation efforts.  Other possible responses focus on adaptation: preparing for and adjusting to new conditions -- for example, building levees and seawalls, or promoting farmers' growth of crops more suitable to the changing conditions.

In all, the report provides insight into the Administration’s approach to addressing climate change, and can help people and businesses both minimize risks and identify new opportunities.

The full National Climate Assessment can be explored on the government's climate change website globalchange.gov, or can be downloaded.  The entire report, downloaded in print quality resolution, clocks in at over 170 megabytes.

Cybersecurity, solar energy and the electric grid

Monday, May 12, 2014

A group of Russian hackers claims to have identified security gaps in widely-used solar panel monitoring software.  The monitoring platform's developer is said to be fixing the gaps -- but can hackers damage the electric grid?

Solar panels supporting Goblin Valley State Park, Utah.
German company Solare Datensysteme GmbH makes a series of devices to track and monitor solar panel performance.  Its "Solar-Log" product line monitors the performance of solar photovoltaic systems and uses an internet connection and software to offer users additional management tools.  According to the company's website, Solar-Log systems manage roughly 229,300 solar plants that producing an aggregate average of 5.66 terawatt-hours (TWh) per day.

According to an article on tech website The Register, a Russian hacking firm known as Positive Security has warned that the previous Solar-Log software was vulnerable to malicious cyberattacks that could cause power grid reconfiguration and cascading blackouts.  The article claims that attackers could download and modify Solar-Log configuration files without needing propert authentication.  Files could be compromised to change user passwords and run code provided by the attacker.  The article suggests that malicious hackers could manipulate "specific power-generation related values", letting users could overstate the amount of power pumped back into grids by their solar installations.

The exact details of the weaknesses identified by Positive Security is being kept secret until the Solar-Log maker can distribute a patch shoring up system security.  As with past bugs, it is likely that Solare Datensysteme and other product makers will continue to plug holes in their cybersecurity, as new flaws are exposed and as systems evolve.  But solar panel monitoring systems are not the only energy-related infrastructure vulnerable to hacking; items ranging from utility smart meters to utility-scale power generator controls may be at risk of compromise from outside forces.

A series of regulations are designed to protect the grid against these threats.  The Federal Energy Regulatory Commission has approved mandatory cybersecurity reliability standards for the U.S. bulk power system.  Acting under its authority pursuant to the Energy Policy Act of 2005, through Order No. 706 the Commission has approved a series of Critical Infrastructure Protection (CIP) cyber security reliability standards proposed by electric reliability organization North American Electric Reliability Corporation (NERC).  Both NERC and the Commission continue to evaluate further changes to those standards, along with other standards bolstering the physical security of the electric grid.

New cybersecurity threats crop up regularly, prompting product developers, service providers, and regulators to engage in a continual effort to identify, block, and protect against threats to the electric power system.  For developers of energy technologies or projects, compliance with key regulations is a critical element of this protection, as is taking a proactive view to ensure safe and reliable operations.  While it is hard to predict the next front in this war, count on it to be ever shifting.

Hydrokinetic energy projects in 2014

Wednesday, April 2, 2014

Hydrokinetic energy projects generate electricity from moving water, capturing the power embodied in tides, waves, and currents without the use of dams.  Hydrokinetic energy resources are estimated to have a tremendous power potential -- according to one U.S. Department of Energy study, approximately 1,420 terawatt-hours per year, or approximately one-third of the nation's total annual electricity usage.  The technologies required are relatively new, do not have decades of operational experience, and remain relatively expensive.  Nevertheless, federal records show growth in hydrokinetic project development.

The Federal Energy Regulatory Commission regulates most hydrokinetic energy projects under its hydropower jurisdiction pursuant to the Federal Power Act.  Project developers may seek preliminary permits granting the right to study a particular site and priority to apply for a project license. 

Relatively few projects have received licenses to date.  In 2012, the Commission issued a pilot project license for the Roosevelt Island Tidal Energy project in the East River near New York City.  Last month, the Commission issued a pilot project license to the Public Utility District No. 1 of Snohomish County for a 600 kilowatt tidal project in Puget Sound, Washington.

As of last month, six projects have been issued preliminary permits that remain in effect:
  • Ecosponsible, Inc.'s Niagara Community project, a 1.25 megawatt inland project proposed for the Niagara River in New York
  • Ecosponsible, Inc.'s Niagara Community #2 project, a similar 1.25 megawatt inland project proposed for the Niagara River in New York
  • Iguigig Village Council's Iguigig RISEC project, a 40 kilowatt inland project proposed for the Kvichak River in Alaska
  • The Town of Edgartown, Massachusetts's Muskeget Channel Tidal Energy project, a 4.94 megawatt project proposed for the Muskeget Channel off the island of Martha's Vineyard
  • Turnagain Arm Tidal Energy's Turnagain Arm Tidal project, a 240 megawatt tidal project proposed for Cook Inlet, Alaska
  • Resolute Marine Energy, Inc.'s Yakutat project, a 750 kilowatt wave project proposed in the Gulf of Alaska
 As of March, another 15 applications for preliminary permits were pending before the Commission.

EPA issues draft permits for carbon sequestration

Tuesday, April 1, 2014

The U.S. Environmental Protection Agency has issued the first draft permits for injecting and storing carbon dioxide in underground rock formations, which could advance carbon capture and sequestration efforts.

EPA promotes carbon capture and sequestration for its expected ability to reduce greenhouse gas emissions, while enabling low-carbon electricity generation from power plants.  The process entails capturing and compressing carbon emissions at their source, piping the gas to injection wells, and injecting the gas into geologically stable rock formations capable of holding the gas for long periods of time.

EPA's simplified schematic of deep geologic carbon sequestration, available from EPA at http://www.epa.gov/climatechange/ccs/.


Under the federal Safe Drinking Water Act, EPA regulates most injections of waste and other materials into the ground.  EPA has developed a series of programs to manage such injections, including a "Class VI" geologic sequestration program.  While oil producers have long injected carbon dioxide into their wells to enhance oil recovery, EPA has not previously issued any permits under its Class VI program.  This lack of Class VI activity is largely because carbon capture and sequestration in the U.S. remains in its infancy, but some industry observers have expressed concerns that EPA's regulatory process is too restrictive to allow the technology to flourish.  The record of permit applications shows some support for these concerns: for example, Christian County Generation, LLC of Taylorville, IL withdrew its applications for two Class VI sequestration wells for the Taylorville Energy Center on July 9, 2013, and Archer Daniels Midland's applications for Class VI permits for two injection wells to store carbon emissions from its Decatur, Illinois agricultural products and biofuel production facility have remained pending since 2011.

Carbon capture and sequestration's future may be brightening, as on March 31, 2014, EPA issued four draft Class VI permits to FutureGen Industrial Alliance, Inc. for its proposed FutureGen 2.0 project.  The Alliance is a non-profit organization whose membership includes major coal producers, coal users, and coal equipment suppliers, including Alpha Natural Resources, AngloAmerican, JoyGlobal Inc., Peabody Energy, and Xstrata Coal Pty. Limited.  The FutureGen 2.0 project is designed to capture over 90 percent of the carbon emissions from a 168 megawatt power plant in Meredosia, Illinois, and to inject them into four nearby wells for deep geologic sequestration.

EPA's draft permits now face a public hearing on May 7 and public comments through May 15.

Smart meters are safe, says Maine agency staff

Thursday, March 27, 2014

The staff of the Maine Public Utilities Commission has issued a report concluding that the use of "smart meters" -- advanced utility metering infrastructure capable of communicating wirelessly with the utility -- is a "safe, reasonable, and adequate utility service."

Smart meters and other new utility technologies offer the opportunity to cut ratepayer costs while enabling new and innovative services.  Building on the ubiquity of cell phones, the internet, and other devices that can communicate using radio frequency emissions, smart meters can provide utilities with real-time data on each customer's consumption of electricity.  This can eliminate the need for traditional meter readers, enable utilities to manage outages in real-time, and can open up opportunities for real-time pricing of electricity.  Many utilities have adopted smart meters and other so-called "advanced metering infrastructure", including Maine's largest electric utility Central Maine Power Co.

But some people are concerned about the safety of smart meters, and in particular with the health effects of the radio frequency emissions associated with the meters' communication system.  Utilities around the country have faced questions, and even legal challenges, over the safety of smart meters.  As CMP rolled out its smart meter program, the Maine Public Utilities Commission received a series of complaints and requests for investigation into whether CMP's advanced metering infrastructure program complied with Maine law requiring utilities to provide safe, reasonable, and adequate utility service.

After legal proceedings before the Commission and Maine's highest state court, in 2012, the Commission opened an investigation into "the health and safety issue related to CMP's installation of smart meter technology."  That investigation led to Tuesday's release of a Commission staff report (67-page PDF) summarizing the evidence it had collected and staff's conclusions.  Highlights from the report include the following findings:
  • The radio frequency (RF) emissions from CMP' s smart meters and other AMI components comply with duly promulgated federal safety regulations and other RF emission standards;
  • No state, federal, or Canadian regulatory body or health agency that has considered the health impacts of smart meters (including Maine 's Center for Disease Control and Prevention (Maine CDC)) has found smart meters to be unsafe;
  • The scientific evidence presented in this proceeding is inconclusive with respect to the human health impacts from low-level RF emissions generally;
  • There are no credible, peer-reviewed scientific studies in the record that demonstrate, or even purport to demonstrate, a direct human health risk specifically from smart meter RF emissions;
  • The studies that have been presented in the record to demonstrate the risk to human health from exposure to RF-emitting devices are based on exposure to substantially higher levels of RF emissions than smart meters;
  • The relative RF emission exposure from smart meters is significantly less than other commonly used RF-emitting electronic devices; and
  • CMP' s installation and operation of its smart meter system is consistent with federal and state energy policy and is a generally accepted utility practice throughout the country.
Based on these findings, the staff report concludes that "CMP's installation and operation of its smart meter system is consistent with its statutory obligation to furnish safe, reasonable and adequate facilities and service."  That said, the report also concurs with recommendations that continued research should be done on the impacts on human health from radio frequency emissions.

It now falls to the full Commission to take up the issue.  Will the Commissioners agree with their staff's findings and conclusion?

Biofuels lead growth in U.S. biomass energy

Monday, March 24, 2014

The use of energy from biomass resources in the United States grew more than 60% over the decade between 2002 and 2013 -- primarily in the form of increased use of biofuels like ethanol and biodiesel that are produced from biomass.

A fuel pump displays prices for gasoline blended with up to 10% ethanol.

According to the U.S. Energy Information Administration, biomass accounted for about half of all renewable energy consumed in 2013 and 5% of total U.S. energy consumed. The three primary sources of this biomass are wood and forest products byproducts, waste including municipal solid waste and landfill gas, and raw organic feedstocks like corn and soybean oil used to produce biofuels.

Of biomass energy resources, biofuels experienced the greatest growth over the last decade. From 2002 to 2013, biofuels created from biomass grew more than 500%, driven largely by increases in U.S. production of ethanol and biodiesel for blending as transportation fuels. These biofuels are typically produced from feedstocks such as agricultural crops and other plant material, animal byproducts, and recycled waste. For U.S. ethanol production, corn is the dominant feedstock, while biodiesel producers rely on soybean oil for just over half of feedstock needs and an array of biomass resources for the rest. Market demand for these biofuels comes in part from federal mandates such as the U.S. Environmental Protection Agency's Renewable Fuel Standard, which requires the blending of certain volumes of biofuels into gasoline and diesel.

Meanwhile, EIA data shows that consumption of wood and waste energy increased just 4% over the decade. About two-thirds of U.S. wood energy is consumed for industrial processes, while nearly all U.S. waste energy is consumed for electric generation or industrial processes.

If this trend continues, woody biomass and waste energy will continue to hold their positions in our portfolio of energy resources, while continued growth in the conversion of biomass into biofuels for transportation and other needs will increase biofuels' weighting in the nation's energy mix.  At the same time, debates continue over the cost and value of programs encouraging the growth of corn as a biofuel feedstock.  What does the future hold for biomass in the U.S.?