US Department of Interior features energy as a priority

The United States Department of the Interior has updated its regulatory priorities for the coming six months, with energy issues featured prominently.  The nation's principal steward of federal public lands and resources, the Department manages more than 500 million acres of Federal lands, including 401 park units, 560 wildlife refuges, and approximately 1.7 billion of submerged offshore acres on the Outer Continental Shelf.  These lands and waters are home to significant energy and mineral resources, including renewable energy sources such as solar, wind, and hydropower, as well as oil, gas, coal, and minerals such as uranium.  The Interior Department's recently-announced priorities highlight the importance of energy issues in its regulatory agenda for 2014.

The Parker River National Wildlife Refuge, managed by the Department of the Interior's U.S. Fish and Wildlife Service.

Energy issues are not new to the Interior Department.  Its mission statement, captioned, "Protecting America’s Great Outdoors and Powering Our Future", reads:

The U.S. Department of the Interior protects America’s natural resources and heritage, honors our cultures and tribal communities, and supplies the energy to power our future.

Twice a year, the Interior Department publishes a statement of its regulatory priorities.  The most recent statement, issued November 26, features several initiatives designed to promote the development of renewable resources on public lands.

As noted in the Department's statement, under the Obama Administration, the Department has focused on renewable energy issues and has established priorities for environmentally responsible development of renewable energy on public lands and the Outer Continental Shelf.  Energy producers and developers are investing in the development of wind farms off the Atlantic seacoast and solar, wind, and geothermal energy facilities throughout the West.  The Department announced its intent to continue its intra- and inter-departmental efforts to move forward with the environmentally responsible review and permitting of renewable energy projects on public lands, and to streamline regulatory processes to facilitate the responsible development of these resources.

Like most federal agencies, the Interior Department is organized as a collection of bureaus and offices.  These agencies include the Bureau of Land Management, which manages the 245-million-acre National System of Public Lands, located primarily in the western States, including Alaska, and the 700-million-acre subsurface mineral estate located throughout the nation.  The Bureau of Land Management's regulatory priorities include creating a competitive process for offering lands for solar and wind energy development.  Specifically, the Bureau is proposing competitive bidding for lands within designated solar and wind energy development leasing areas.  The proposed rule is designed to enhance BLM's ability to capture fair market value for the use of public lands, ensure fair access to leasing opportunities for renewable energy development, and foster the growth and development of the renewable energy sector of the economy.

If the Bureau of Ocean Energy Management's recent auctions for offshore wind sites on the Outer Continental Shelf are any example, the Bureau of Land Management may soon be holding competitive auctions for land-based renewable energy sites.  These auctions will likely seek to balance support for responsible resource development against conservation, as the Department also includes conservation-oriented agencies such as the U.S. Fish and Wildlife Service and the National Park Service.

Yet how these regulatory priorities translate into regulatory action -- and how that regulatory action affects the development of renewable resources -- remains to be seen. 

Nova Scotia tidal power projects

Plans to develop tidal power resources in the Canadian province of Nova Scotia are moving forward, as Fundy Tidal Inc. announces firmer plans to deploy tide-powered generators at three locations in Digby County.

The extreme tidal range in the upper Bay of Fundy gives Nova Scotia a tremendous tidal energy resource.  The province has been home to the 20 megawatt barrage-based Annapolis Royal Tidal Power Plant for almost 30 years; more recently, Nova Scotia established a Marine Renewable Energy Strategy setting a target of 300 MW of commercial tidal development by 2020, an amount roughly equal to 10% of the province's electricity consumption.  Nova Scotia also established a Community-Based Feed-in-Tariff or COMFIT program designed to give qualified tidal energy developers certainty over project revenues early in the development phase.

Fundy Tidal Inc. proposed three projects in Digby County that have received approval through the feed-in tariff program.  The largest, to be developed in the Digby Gut, could generate up to 1.95 megawatts of power.  Two smaller projects in Grand Passage and Petit Passage could each generate up to 500 kilowatts of power.  These three projects have an expected development cost of $30 million.  Fundy Tidal also received approval for COMFIT funding for two projects on Cape Breton Island.

Last month, Fundy Tidal announced a strategic partnership with Tribute Resources Inc. and Tocardo International BV to develop the three Digby County sites.  Under the terms of that partnership, Tocardo will delivery tidal turbines, and will set up a tidal turbine assembly and manufacturing plant in Nova Scotia.  Fundy Tidal will serve as the overall developer and will retain a 51 percent interest in the projects, with Tribute Resources owning the remaining 49 percent interest.

This is not the first time tidal power projects have been proposed in Digby County; previous concepts have ranged from tidal barrage development to deployment of hydrokinetic turbines in conjunction with Ocean Renewable Power Co.  Fundy Tidal now plans to construct and deploy the Digby area projects to deliver power as soon as 2015.  Will these plans come to fruition?

Solar energy led new installations in October 2013

Solar-powered projects led new electric generation capacity installed in October 2013.  According to the Federal Energy Regulatory Commission's October 2013 Energy Infrastructure Update, most of the electric generation placed in service in October relies on solar energy technologies.  Developers placed 504 megawatts of solar capacity online in October, out of 699 megawatts of total new capacity for the month.  Solar also led the month in terms of the number of projects installed, accounting for 12 of 21 projects.

Solar photovoltaic panels line the roof of the visitor center at the Parker River National Wildlife Refuge in Massachusetts.

The solar energy projects placed in service last month vary widely in scale and in technology.  The largest, Abengoa SA's Solana Generating Station in Arizona, generates up to 280 megawatts of power using a thermal concentrating solar power technology.  2,700 parabolic trough mirrors focus the sun's rays on a pipe containing a synthetic oil.  This heat transfer fluid can reach 735 degrees Fahrenheit, and is sent to boilers where it produces steam from water.  The steam turns turbines attached to generators, much as in a conventional thermal power plant.  The Solana plant also features energy storage in the form of molten salt tanks that can enable it to generate electricity for up to 6 hours after sunset.

On the other end of the spectrum, Constellation Solar New York LLC placed its 2 MW Owens Corning Delmar Solar photovoltaic project online.  The project, located at an Owens Corning factory in Delmar, New York, consists of about 9,000 ground-mounted, photovoltaic panels covering over 9 acres.  Power produced by the project is sold to Owens Corning under a long-term power purchase agreement for use at the thermal and acoustical insulation factory; the project is expected to cover about 6 percent of the plant's annual electricity need.

While the use of solar energy is increasing rapidly, it remains a relatively small component of the nation's overall energy mix.  Solar powered projects account for 6.79 gigawatts of capacity, just 0.59% of the 1,158 gigawatts of existing electric generation capacity nationwide.  Nevertheless, the relatively small market penetration of solar technologies suggests that rapid growth may continue for the near term.

Federal energy enforcement: $304 million in penalties in 2013

The Federal Energy Regulatory Commission has released its report on its enforcement activities in fiscal year 2013.  The FERC's 2013 Report on Enforcement (69-page PDF) gives the public insight into how the Commission's Office of Enforcement operates.  The report also provides key statistics on the Commission's 2013 enforcement actions, which led to over $304 million in civil penalties and disgorgement of almost $141 million in unjust profits.

In recent years, the Commission has increased its market surveillance and enforcement of federal energy law.  The Commission has explained that conduct involving fraud and market manipulation poses a significant threat to energy markets, and that this in turn harms consumers who are exposed to losses from intentional misconduct.  These concerns, coupled with increased enforcement powers granted in the Energy Policy Act of 2005, have led the Commission to ramp up its enforcement efforts.  Today, the Commission's Office of Enforcement is now structured around four divisions: Investigations, Audits and Accounting, Energy Market Oversight, and Analytics and Surveillance.  These divisions are designed to identify and prosecute violations of federal energy laws and regulations.

The enforcement report describes the Commission's 2013 activity, which includes the largest civil penalty ever assessed by the Commission.  In that case, the Commission found that Barclays Bank PLC and four traders violated the Commission’s rule against market manipulation.  As a result, the Commission assessed civil penalties of $435 million against Barclays and $18 million against the traders, and directed the company to disgorge $34.9 million plus interest in unjust profits.  That case is now before the U.S. District Court for the Eastern District of California.

The report also describes 29 financial and operational audits of public utilities and natural gas pipelines conducted in fiscal 2013.  According to the report, these audits resulted in 360 recommendations for corrective action, and directed the targeted companies to pay $15.4 million in refunds. Other recommendations directed improvements to companies’ internal processes and procedures, enhancements to the accuracy and transparency of reports and web sites, and more efficient and cost-effective operations.

The Commission announced that it does not intend to change its enforcement priorities for 2014.  As described in the report, the Commission will continue to target fraud and manipulation, serious violations of mandatory reliability standards, anticompetitive conduct, and conduct that threatens the transparency of regulated markets.

New England Clean Power Link proposed

A developer of electric transmission lines has proposed a new line that would connect New England to Quebec.  The so-called New England Clean Power Link would run about 150 miles from the U.S.-Canadian border to Ludlow, Vermont.  While the line shares some features with other proposed ties to the Canadian power grid -- including its development team -- the New England Clean Power Link differs from prior proposals in several regards.

Demand for electricity in the northeastern United States, and in particular for renewable power, has led to interest in developing several transmission lines to Canada.  Provincial crown corporation Hydro-Quebec has many large hydroelectric dams, and continues to develop Quebec's rivers for power production.  Meanwhile, Newfoundland utility Nalcor is developing gigawatt-scale hydropower on the Churchill River in Labrador, with aims to export the power to eastern Canada and the U.S.

This relative surplus of Canadian hydropower has led developers to propose transmission lines connecting Quebec resources to New England consumers.  These lines include the Champlain-Hudson Power Express from Canada to New York City, and the Northern Pass from Canada into New Hampshire.

The $1.2 billion Clean Power Link would have a capacity of 1,000 megawatts, roughly equal to the size of a nuclear power plant.  Like previous proposals, the newly-proposed line is motivated by the perceived opportunity to sell Canadian power in New England.  The Clean Power Link also shares features in common with other proposals, in that it would be a high-voltage direct current or HVDC line.  Notably, it would also be developed and financed by TDI New England, a Blackstone Group subsidiary led by the team behind the Champlain-Hudson Power Express.

Like that line, it would run about 100 miles under Vermont's Lake Champlain.  South of the lake, the Clean Power Link proposal features lines buried underground.  This contrasts with the Northern Pass, whose traditional wires-on-towers architecture has drawn significant opposition in New Hampshire.

The Clean Power Link faces a regulatory process including environmental and energy permitting, and is also dependent on the market forces that motivated its proposal.  It is unclear whether any of the proposed transmission lines to Canada will actually be built, let alone which one.  For now, TDI aims to build the line and place it in service by 2019.

Google invests in solar energy projects

Google has announced an investment in six solar photovoltaic projects to its portfolio.  The projects, located in California and Arizona, have a combined electric generating capacity of 106 megawatts.  This deal illustrates the trend of renewable energy investments by data centers and other tech companies.

The projects are under development by Recurrent Energy.  Five are located in Southern California, while the sixth is in Arizona.  Google and investment firm KKR invested $400 million in the projects; Google's share is reportedly $80 million.  The partners will sell the power produced by the facilities to local utilities including Southern California Edison.

Google announced that this represents its fourteenth investment in renewable energy since 2011.  In 2010, the Federal Energy Regulatory Commission granted market-based rate authority to Google subsidiary Google Energy LLC, enabling it to sell power at wholesale.  Google has since entered into long-term agreements to purchase power from wind farms and other renewable generators.

Other tech companies are pursuing similar strategies.  Earlier this month Microsoft announced a deal to purchase energy produced by a Texas wind farm for its data center in San Antonio.  In September, eBay received market-based rate authorization from the Federal Energy Regulatory Commission, allowing it to sell surplus power from its generators to the grid.

For consumers like Google with significant demand for power, developing on-site electric generation or entering into a long-term power purchase agreement can be cost-effective, either by reducing the cost of energy or by reducing its exposure to price volatility.  Investments in renewable energy can also position companies for improved sustainability and "green" their public images.  For these reasons, the trend of tech company investment in renewable energy infrastructure will likely continue for the foreseeable future.

Voluntary renewable power markets small but growing

Electricity generated from renewable energy resources continues to grow its share of the U.S. market, according to a recent U.S. governmental report.  While most renewable energy sales are motivated by renewable portfolio standards -- state laws requiring utilities to source specified amounts of energy from renewable resources -- a small but growing amount of electricity is sold in voluntary green power markets.

Consumer demand for renewable-sourced electricity has led to voluntary markets in which consumers and institutions voluntarily purchase renewable energy to meet their electricity needs.  These markets include green power offers, competitive supplies, and over-the-counter renewable energy certificate (REC) sales.  According to the National Renewable Energy Laboratory's report, Status and Trends in the U.S. Voluntary Green Power Market, in 2012 voluntary retail sales of renewable energy represented approximately 1.3% of total U.S. electricity sales, or about 48 million megawatt-hours.  According to NREL, these sales represent the power produced by about 17,000 megawatts of installed renewable capacity.

While the voluntary renewable electricity market remains relatively small in absolute terms, it is growing rapidly.  NREL's report found that from 2010 to 2012, total green power market sales increased by 36%, for a compound annual growth rate of 1%.

In 2012, the resource mix supplying renewable energy to the voluntary renewable market was dominated by wind energy, at 80.1% of total green power sales.  Other resources in the mix include landfill gas and biomass (12.8%), hydropower (6.2%), solar (0.6%), and geothermal (0.3%). Like the entire voluntary market itself, solar power is a small but growing segment, experiencing a tripling of market share between 2010 and 2012.

For now, despite its recent growth, voluntary retail sales of renewable energy represent a small fraction of power sold.  The vast bulk of renewable energy is sold in compliance markets, established pursuant to state renewable portfolio standards or targets.  Will voluntary markets continue to grow?  How will proposals to increase state standards affect the voluntary markets?

Tidal power past, present, and future at Tide Mill Institute 2013

The Tide Mill Institute held its ninth annual conference this past Friday and Saturday.  About 60 people interested in the past, present, and future of tidal energy gathered at the Topsfield Historical Society's Gould Barn in Massachusetts.  The audience included developers of recreated historic tide mills and modern tidal power projects, inventors of tidal turbine technology, academics, state legislators, historians, architects, and other enthusiasts of tidal power.

Tide Mill Institute's John Goff speaks about historic tide mills in Salem, Massachusetts.

Ocean Renewable Power Company's president and CEO, Chris Sauer, gave the keynote presentation on ORPC's efforts and success in developing modern hydrokinetic tidal power plants in the Gulf of Maine and elsewhere.  Chris described the research and development process that led to ORPC's Turbine Generator Unit or TGU.  He also described the engineering, regulatory, and commercial challenges of developing tidal power plants today, as well as ORPC's approach to overcoming these challenges.

Other presentations included: Professor Kerr Canning's exposition of a tide mill site he discovered on the Apple River in Nova Scotia; Professor Robert Gordon's look at tide mill mechanics at sites in York, Maine; a review of tide mill history on the Gowanus Canal in Brooklyn, New York, by Angela Kramer of the Brooklyn Historical Society and Proteus Gowanus; and a survey by representatives of local historical societies of tide mills on the North Shore of Massachusetts.

Tide Mill Institute members and attendees also enjoyed displays on historic and modern tide power projects, and informal discussions of archaeological discoveries and modern developments. 

The Tide Mill Institute will hold its 10th annual conference in 2014.

Japan's floating offshore wind turbines

A recently-installed floating wind turbine off the Japanese coast marks the second operating floating project in Asia.  Located about 12 miles off the coast of the site of the 2011 Fukushima nuclear power disaster, the government-funded project is being developed by a consortium led by Marubeni Corp.  So far, it consists of a single 2-megawatt Hitachi turbine coupled with a floating substation, with near-term plans to add two 7-megawatt Mitsubishi Heavy Industries Ltd. turbines, and a longer-term vision of installing 1,000 megawatts of capacity.

The Fukushima project follows a 2-megawatt floating offshore wind project installed off Nagasaki.  The Nagasaki project is located about 1 kilometer off the island of Kabashima, a 9-sq.-km island with some 110 households, and followed a 100-kilowatt test project deployed in 2012.

Japan's push for offshore wind development is motivated in large part by the Fukushima nuclear disaster.  Before 2011, nuclear power provided about 30% of Japan's electricity, but all 54 of Japan's nuclear reactors were shut down or inoperable after the disaster.

As an island nation with extensive coastal resources and little if any native fossil fuels, offshore wind may be a natural fit for Japan.  Relatively deep waters surrounding Japan make seabed-mounted towers impractical, so floating platforms may enable greater use of renewable wind energy.  The floating pilot projects off Nagasaki and Fukushima are designed in part to test different technologies, and may help reduce the costs of future projects.

Under the Japanese approach, each of these projects is funded by a separate ministry: the Fukushima project is supported by the Ministry of Economy, Trade and Industry, while the Nagasaki project is funded chiefly by the Environment Ministry.

Will Japan continue to develop its deepwater offshore wind resources?  Will floating platforms and turbines play a significant role in powering Japanese society?  Will the pilot projects lead to engineering and manufacturing knowledge that could place Japan at the forefront of the growing deepwater offshore wind industry?

Massachusetts to develop wind energy siting guidance

As interest continues to grow in the generation electricity from wind energy, the siting of wind projects is an important issue.  While producing power from wind energy avoids the use of fossil fuel along with the emission of carbon dioxide and other pollutants, society has an interest in ensuring that wind projects are developed responsibly and in appropriate locations.  Regulation of sites for wind energy development generally occurs at the state and local levels, and some observers - both wind developers and opponents of specific wind projects - have complained of bad results from a patchwork of regulations, some of which are not based on good science.

Wind turbines in Ipswich, MA, visible across Plum Island Sound from the Parker River National Wildlife Refuge.

In Massachusetts, the state Department of Public Utilities has launched an initiative to remedy this defect.  On October 31, 2013, the Department opened an investgation into best practices for the siting of land-based wind energy facilities.  According to the Department's notice:

The investigation will result in the development of wind energy facility siting guidance based on sound scientific, technical, and policy information. Specifically, the Department will examine the following topics related to land-based wind energy facilities: design, environmental and human health, safety, construction impacts, socio-economic impacts, decommissioning, and the review process for wind projects.

The Department has docketed this case as D.P.U. 13-165, Investigation into Best Practices for Siting of Land-Based Wind Energy Facilities, and has solicited public comment by December 6. Following receipt and review of the comments, the Department anticipates holding public hearings beginning in January.

The guidelines developed through this process will shape the siting and development of land-based wind projects in Massachusetts.  Massachusetts has a strong commitment to renewable energy, as evidenced in the Green Commnities Act, its renewable portfolio standard, and in public sentiment.  That said, to date most wind power consumed in Massachusetts comes in the form of renewable energy certificates representing power generated from wind facilities in Maine and other states, largely due to the relative difficulty of siting a wind energy project in Massachusetts.  Will this process lead to more wind energy development in Massachusetts?

 

Yellowstone park proposes utility upgrades

The U.S. National Park Service manages over 84 million acres of land for both conservation and visitor use.  For wilderness parks, these joint objectives lead to the challenge of providing park facilities with electricity despite their remote location.  The Park Service has launched energy efficiency and sustainability programs, but many visitor and administrative facilities still need electricity for safety and comfort.  How should the Park Service balance conservation and development?

Old Faithful geyser erupts in Yellowstone National Park.

Yellowstone National Park, the nation's first park, highlights the difficulty.  Most facilities in the park receive electricity from transmission and distribution lines owned by utility NorthWestern Energy, but the park's rugged environment, challenging climate, and relatively old electrical infrastrucutre lead to frequent power outages - over 250 in 2012.  Unlike much of the electric grid outside the park, facilities in Yellowstone lack modern communication infrastructure - a Supervisory Control and Data Acquisition or SCADA system - that would let the utility diagnose and correct the cause of power outages from the utility's central offices in Montana.

As a result, Yellowstone and NorthWestern Energy have proposed to update the park's electrical distribution system.  Proposed upgrades include an automated, remote monitoring and control system, the installation of equipment buildings, back-up power generators and propane fuel tanks.  The proposed communication system would require the construction of seven towers for radio equipment within the park, generally located at existing electrical substation sites.

Under the National Environmental Policy Act, the Park Service cannot approve the plan without conducting an environmental assessment of the impacts of the proposed development.  The Park Service has released its Environmental Assessment (10.5 megabyte PDF), which is open for public comment until December 6.

The use of national park lands for energy infrastructure can be controversial due to differing philosophies on the level of development desirable in parks.  At the same time, the Park Service notes that the Yellowstone outages have had negative effects on park operations and visitor experience, creating health and safety concerns and lost revenue for concessioners.  How will this balance play out in Yellowstone?

Tide Mill Institute to hold conference November 8-9, 2013

The Tide Mill Institute will hold its 9th annual conference this week in Topsfield, Massachusetts.  The event, to be held at the Topsfield Historical Society's Gould Barn on November 8 and 9, brings together people interested in the past, present, and future of tidal energy.

Tidal energy has been used to produce useful power since at least 619, based on archaeological finds at the site of Nendrum Monastery on an island off Northern Ireland.  Tide mills came to the New World along with early European settlers, who captured the energy embodied in the rise and fall of tides and put it to use powering grist mills, lumber mills, and other industries.  According to a 1979 paper, "Early Tide Mills: Some Problems", at one point over 300 tide mills operated in North America.  As their functionality was supplanted by steam engines, electricity, and internal combustion energy, much of society's historic use of tidal energy has been forgotten.

Meanwhile, people still look to the tides to provide useful power.  The Canadian province of Nova Scotia has been home to a 20 megawatt tidal power plant since 1984, and is promoting even more innovative uses of tidal energy resources through incentive programs and policies.  In the United States, the Ocean Renewable Power Company (ORPC) has developed the nation's first major grid-tied tidal electric generator, and has ambitious plans to bring more tidal and hydrokinetic projects online around the country.

This week's Tide Mill Institute event brings these themes together into a continuous narrative, from past through the present to the future.  The Tide Mill Institute's mission is:

• to advance appreciation of the American and international heritage of tide mill technology;
• to encourage research into the location and history of tide mill sites;
• to serve as a repository for tide mill data for students, scholars, engineers and the general public and to support and expand the community of these tide mill stakeholders; and 
• to promote appropriate re-uses of old tide-mill sites and the development of the use of tides as an energy source. 

The 2013 conference kicks off Friday night with an informal reception, followed by a symposium and dialogues Saturday from 8 AM through 3:30 PM.

For more information about the Tide Mill Institute, please contact:

• Bud Warren - budw@myfairpoint.net 207-373-1209
• Earl Taylor - ERMMWWT@aol.com 617-293-3052
• Todd Griset - tgriset@preti.com 207-791-3000

Wind to power Microsoft's Texas data center

Microsoft has agreed to purchase energy produced by a Texas wind farm to power its data center in San Antonio.  The announcement, posted on the official blog of Microsoft's Sustainability Development Team, describes a 20-year power purchase agreement with RES Americas under which Microsoft will purchase all of the output of the 110 megawatt Keechi Wind project located about 280 miles north.

The power purchase agreement fits with Microsoft's stated commitment to carbon neutrality.  Since 2012, Microsoft has imposed an internal fee on the use of carbon-based forms of energy; Microsoft uses that fee to make investments in alternative or carbon-neutral energy, such as this power purchase agreement.

The Keechi project will be owned and operated by RES Americas, a subsidiary of British company RES Ltd.  RES Americas currently operates over 600 MW of renewable energy projects, and has a renewable energy construction portfolio that exceeds 6,500 MW and 64 projects, as well as 534 miles of transmission lines.  Its Keechi project is expected to cost $200 million, and will feature 55 turbines expected to produce 430,000 megawatt hours of energy per year.  (To put this figure in context, it could power up to 45,000 homes, or cover between 5 and 10 percent of Microsoft's total electricity consumption.)  Construction is expected to begin in 2014, with the project going operational by June 2015.

Microsoft is not alone in promoting its use of renewable or alternative energy to power its data centers.  In 2012 Google entered into an agreement to purchase the output of a wind farm in Oklahoma to power its Pryor data center.  Apple's new data center in Maiden, North Carolina is powered in part by a solar photovoltaic array and a biogas-fed fuel cell.  eBay has proposed siting a 6 megawatt natural gas-fired fuel cell at its Utah data center.  Whether the data center is powered by on-site distributed generation or buys power from a designated off-site renewable resource, the trend is toward promoting cleaner, greener computing through these arrangements.  These choices may help the companies with cost control and power reliability as well as public relations.

Will large consumers of electricity continue to invest in alternative or renewable electric generation?  If so, will they favor arms-length power purchase agreements with developers of remote projects, or will they rely more heavily on on-campus development of distributed generation?  Will this trend spread beyond the big names so far - Microsoft, Apple, Google, and eBay - to the point where smaller or less tech-oriented companies develop or do similar projects and deals?

  Googa 20-year power purchase agreement (PPA) for wind energy in Texas that will be funded in part by proceeds from Microsoft’s carbon fee - See more at: http://blogs.msdn.com/b/microsoft-green/archive/2013/11/04/microsoft-signing-long-term-deal-to-buy-wind-energy-in-texas.aspx#sthash.4l62oNbo.dpuf

a 20-year power purchase agreement (PPA) for wind energy in Texas that will be funded in part by proceeds from Microsoft’s carbon fee - See more at: http://blogs.msdn.com/b/microsoft-green/archive/2013/11/04/microsoft-signing-long-term-deal-to-buy-wind-energy-in-texas.aspx#sthash.4l62oNbo.dpuf

a 20-year power purchase agreement (PPA) for wind energy in Texas that will be funded in part by proceeds from Microsoft’s carbon fee - See more at: http://blogs.msdn.com/b/microsoft-green/archive/2013/11/04/microsoft-signing-long-term-deal-to-buy-wind-energy-in-texas.aspx#sthash.4l62oNbo.dpuf

Will YieldCo structure change energy investments?

A relatively new way some utility companies are structuring their assets is drawing increased investment.  Dubbed the "YieldCo" model, the basic idea is that an established energy and utility companies will create a YieldCo subsidiary as a vehicle for holding investments in assets that produce sustained or increasing cash flow.  The YieldCo then pays out a relatively high percentage of its earnings to its shareholders as dividend yield.  Utility giant NRG Energy Inc. launched NRG Yield, Inc. this July, and other companies and market watchers have hinted that more YieldCo spinoffs may come in the near future.  Will the YieldCo model catch on?  How will it change the flow of money to and from energy projects?

The YieldCo model offers several kinds of benefits.  One is an answer to the question of renewable energy projects can compete during long-term periods of low power prices and reduced demand for electricity?  YieldCos are hoped to offer lower cost of capital for these projects.  Most often, they are conceived of as as holding electric generation projects whose output is fully contracted for, and older renewable and other assets that no longer qualify for special tax benefits.  The structure lets owners monetize assets without giving up control.  Meanwhile, the expected high and consistent yields can also attract capital and new investors, much as real estate investment trusts (REITs) or master limited partnership (MLPs) have done for other sectors. 

In the case of NRG Yield, its initial asset base featured a mix of conventional and distributed elcetric generation projects.  This mix included eleven utility-scale power plants and renewable projects, plus and two portfolios of distributed solar projects.  NRG Yield appears to have been a success, attracting $430 million in its initial public offering, with shares subsequently rising over 50% more in value. 

But despite NRG Yield's success since July, the structure is relatively novel as applied to electric generating infrastructure.  Downsides to the YieldCo structure include less favorable tax treatment than is available to REITs or MLPs (basically, a higher level of taxation), the cost of establishing a spinoff YieldCo, and increased exposure to interest rate risk.

If the YieldCo structure catches on, it could attract new investment capital to the renewable and conventional electric generation sector.  Will other companies follow NRG Yield's example?  NextEra Energy Inc. (owner of Florida Power & Light) is said to be exploring the concept, and is reportedly considering a portfolio of 1,500 to 2,000 MW of operating assets and another 1,200 MW in the development pipeline for contribution to a YieldCo in the next 4 years.  How big a shift we see to YieldCos remains to be seen, but for now excitement about the possibilities remains high. 

FERC temporarily extends EQR deadline

As federal regulators of U.S. energy markets update their systems to track electricity sales, the Federal Energy Regulatory Commission has temporarily extended the deadline for utilities to file Electric Quarterly Reports (known as EQRs).

Under Section 205(c) of the Federal Power Act, "public utilities" must file their rates with the FERC and make them availble for public inspection.  These utilities include traditional vertically-integrated electric companies owning transmission systems as well as independent generators, and even industrial manufacturers with on-site electricity generating facilities and other entities authorized to sell electricity into wholesale markets.

To implement this requirement, the FERC requires utilities to file information about they electricity they sell at negotiated or market-based rates.  To accomplish this, utilities make quarterly filings using FERC's EQR system, which has been in place since 2002.  Most recently, utilities have been required to use free software developed by the FERC to submit EQRs.

While the FERC has updated this proprietary software from time to time, it has been left behind in capability and convenience by more modern technologies and interfaces.  Following the recent FERC Order No. 768, which broadenied EQR filing responsibilites to cover certain non-public utilities, the FERC announced in Order No. 770 that it would transition to a new web-based interface effective with the filings for the third quarter of 2013.  In explaining this shift, the FERC noted that technology changes will render the current filing process "outmoded, ineffective, and unsustainable."  These filings would normally be due on October 31, 2013.

When filing requirements change, as they have several times in the last decade, filers experience a learning curve as they seek to understand the new system.  At the same time, the FERC's development of the new system remains a work in progress.  In an order issued on October 16, the FERC announced that the new web-based approach is not yet available, and extended the deadline to file Q3 2013 EQRs from October 31, 2013 to "a date to be determined."  Once the new web-based approach is available, the FERC will notify all filers and provide the new deadline for filing Q3 2013 EQRs.

For now, filers have some time to prepare for the new system. 

How New England plans to keep the lights on this winter

Concerns over the reliability of New England's electricity grid this coming winter have led the regional grid operator to develop a new program designed to ensure sufficient energy is available. While natural gas remains the dominant cost-effective fuel for electric generation in New England, grid operator ISO New England expressed concern over its ability to ensure a reliable supply of electricity in the event of a natural gas shortage or supply disruption. As a result, the grid operator launched a so-called Winter Reliability Program to compensate oil-fired generators, dual-fuel generators, and demand response resources for their promise to stand ready to serve if needed.  Is the program necessary?  If so, will it prove sufficient to protect consumers against power outages and high prices?

ISO New England's Winter Reliability Program plan was designed to address the reliability risks arising from constraints on the interstate pipeline system's ability to meet demands for natural gas deliveries into New England, increased reliance on natural gas-fired generation, and generating resource performance during periods of stressed system conditions.  While regional stakeholders are developing a longer-term fix for these risks, last winter highlighted the urgency of the problem, as natural gas pipelines supplying fuel to New England reached full capacity through the winter season, leaving natural gas more expensive and less available than it should be.

As a short-term solution, through its Winter Reliability Program, ISO New England will procure up to 2.4 million megawatt-hours of energy for the coming winter, from a combination of oil-fired generators, dual-fuel generators, and demand response assets.  In exchange for their commitment to provide power when called upon, the selected generators and demand response assets will receive payments regardless of whether they are actually needed this winter.

This program was conditionally accepted by the Federal Energy Regulatory Commission last month, after which the grid operator held its competitive bidding process. When the bidding settled, ISO New England had failed to procure commitments to provide as much energy as it had sought.  According to a FERC order accepting the bid results, market participants submitted bids totaling 2.29 million MWh, or 96 percent of the target, at a total offer price of $114.3 million.  ISO New England proposed to trim the offered supply farther, accepting bids from 20 participants for just 1.995 million MWh, or 83.1 percent of the target, for a total price of $78.8 million.

How did ISO New England reach this result?  According to the grid operator's filing to the FERC, the selected bids are all less than $31 per MWh-month.  ISO New England says that beyond this point, the supply curve became steeper, and the grid operator wanted to balance fuel security for the region against the costs to consumers.  But as the FERC found, ISO New England did not adequately explain its selection process, nor did it sufficiently describe why it cut off supply bids at $31 per MWh-month.  As a result, the FERC directed the grid operator to submit a compliance filing within 15 days describing its process in more detail.

Once ISO New England submits its compliance filing, we will have better insight into the selection process.  Further questions, such as whether the program will prove necessary or effective, cannot be answered until the winter season hits New England.  Will ISO New England's Winter Reliability Program yield consumers value in excess of its $78.8 million cost?

End in sight for New England's largest coal plant

New England's largest coal-fired power plant will close by May 2017, according to its owner.  The Brayton Point Power Station in Somerset, Massachusetts, consists of three coal-fired units and a unit capable of burning natural gas and oil, with a net generating capacity of 1,537.6 megawatts.  Within 4 years, it will follow other large New England coal-fired power plants like Salem Harbor Power Station into history.

The Salem Harbor Power Station in Salem, Massachusetts, scheduled to close in May 2014.

The forces leading to Brayton Point's closure have been gathering for years.  The U.S. energy industry is in the midst of a revolution led by affordable and abundant natural gas supplies.  Meanwhile, tighter environmental regulations on air emissions from coal-fired power plants have made these traditionally cheap generators more and more expensive to run.  This past March, Brayton Point's previous owner Dominion Resources Inc. announced plans to sell the plant and two other fossil-fired plants to a subsidiary of Energy Capital Partners LLC.  That deal was consummated in August.

In an effort to keep the plant economic, Energy Capital Partners reportedly worked with regional electricity grid operator ISO New England Inc. on an agreement under which Brayton Point would have been paid for its ability to be called upon to provide electric generating capacity when needed.  But when Brayton Point demanded a higher price for this capacity than ISO New England was willing to offer, the generator submitted papers indicating that it would not provide capacity for the 2017-2018 forward capacity year.

Without those capacity market revenues, Brayton Point's owners have said it will close by May 2017, according to AP reports.  If it does, it will follow Salem Harbor and other coal-fired power plants around the country which have either closed or been converted to natural gas.  What will the future hold for Brayton Point's site in Somerset?  With transmission lines already in place, will it be redeveloped with other energy infrastructure?  What environmental issues will closure or repowering entail?

Predictions for renewable energy in 2013

With under three months left in 2013, we will soon learn whether this year's projections for the energy industry prove accurate.  The U.S. Energy Information Administration publishes a series of short-term energy outlook reports covering crude oil and liquid fuels, natural gas, coal, and electricity.  What has EIA forecast for the year in renewable energy?

Fall foliage and solar photovoltaic panels at Cider Hill Farm in Amesbury, Massachusetts.

EIA projects a continued increase in the consumption of renewable energy in the forms of electricity and heat generation.  Overall, in 2013 EIA expects 4.5% growth over 2012's renewable energy consumption, with further growth of 2.3% in 2014.

EIA also predicts shifts in the resource mix providing this renewable energy.  In 2013, EIA expects a 1.5% decline in hydropower production, offset by 8.3% average growth of nonhydropower renewables used for electricity and heat generation.  In particular, EIA expects 2.5% growth in wind capacity this year, reaching a total installed capacity of about 61 gigawatts from wind.  This capacity is predicted to enable generation from wind to increase 19% in 2013 and another 2.4% in 2014, at which point it is expected to reach over 4% of all electricity generated in the U.S.

Solar energy is expected to grow more sharply, but will remain a relatively small segment of the nation's overall energy portfolio.  EIA expects solar generation by the electric power sector to increase a staggering 79% in 2013 and 80% in 2014.  In recent years, customer-sited distributed generation projects have led the charge in new capacity additions, but EIA expects utility-scale projects to more than double in total installed capacity between 2012 and 2014.  Most of this new utility-scale solar capacity will continue to come from photovoltaics, but several large solar thermal generation projects may come online the next two years.  Despite this relative growth, the small absolute size of the U.S. solar market means that solar energy will only account for about 0.3% of energy consumed in 2014.

When 2013 has ended, will EIA's predictions come true?  We will learn in several months.

NJ offshore wind project faces dilemma

Fishermen's Energy's proposed offshore wind project off the New Jersey coast has essentially all its permits in place to start construction -- but the project's future is in doubt over a question of financial support from electricity ratepayers.

Fishermen's Energy has proposed building a 25-megawatt wind project about 2.8 miles off the coast of Atlantic City.  The $200 million project would be connected to the mainland electricity grid, enabling the power it produces to be sold to New Jersey electric customers.  The project has already received key permits, such as approval by the Army Corps of Engineers to begin construction.

Building what could be the nation's first commercial offshore wind project will be expensive.  While future offshore wind projects could be cost-competitive against more traditional electric generation resources, the New Jersey pilot project's finances rely on a portfolio of federal and state financial incentives.  These include federal tax credits, a grant from the U.S. Department of Energy, and a state commitment that utility ratepayers will shoulder above-market costs.

A 2010 New Jersey law established an offshore wind renewable energy certificate program known as OREC that was designed to provide that ratepayer commitment.  For over a year, Fishermen's Energy has been waiting for the New Jersey Board of Public Utilities to decide whether to require mainland utilities to purchase the project’s renewable energy output.  But that case remains pending, with no clear state-law timeline for its resolution.  Issues in play include the project's cost to ratepayers, particularly if the project fails to win further competitive grants from the federal Department of Energy.

In the meantime, Fishermen’s Energy needs to spend at least $10 million on the project this year to remain eligible for the federal investment tax credit.  Yet the developer is presumably reluctant to commit those funds before learning whether it will also win ratepayer support.  As December 31 draws nearer, this dilemma makes it more challenging for Fishermen's Energy to sustain project development efforts.

What federal shutdown means for energy

With Congress's failure to pass a budget, today the U.S. federal government entered shutdown mode.  For 800,000 federal workers, shutdown means being furloughed until Congress resolves the budget.  What does the shutdown mean for the energy sector?

Each federal agency is reacting differently to the shutdown.  For the Federal Energy Regulatory Commission, it means continued normal business operations - as long as it still has funds on hand.  What happens after that?  According to a contingency plan issued last week, when those funds run out, FERC will continue "only those excepted activities authorized by law" to the extent that they protect life and property.  These activities include the work of the Commissioners themselves, hydroelectric and liquefied natural gas inspections, managing the reliability of the nation's electric and gas systems, and monitoring market operations.

The U.S. Department of Energy faces similar impacts from the shutdown.  It has some funds remaining on hand, but when those funds run out, according to its "lapse in appropriations plan", of its 13,814 employees, only 1,113 excepted personnel and 11 Presidentially-appointed and Senate-confirmed employees will remain on the job.

The Bureau of Ocean Energy Management will continue some operations.  According to its contingency plan, between 35 – 40% of Bureau employees will continue to report for full time duty, and BOEM will continue to work on current offshore wind projects and other renewable energy plans.

Coal freighter traverses Northwest Passage

Today, a sea freighter capable of carrying 75,000 tons of cargo is traversing the Northwest Passage.  The Nordic Orion is carrying coal from Vancouver, British Columbia, to Finland.  Does this trip illustrate a new trend?

The traditionally ice-bound Northwest Passage across the Arctic edge of the North American continent is increasingly ice-free during summer months.  For shippers, the route offers a significant savings in distance, fuel, and cost compared to alternatives.  For example, cargo shipments between the west coast of Canada and northern Europe can cut off over 1,000 nautical miles by taking the Northwest Passage instead of the Panama Canal.  This saves time and money, and enables ships to carry more cargo (and less fuel) per trip.  It can also reduce carbon dioxide emissions associated with the shipping industry.

The Nordic Orion's cargo - coal - highlights another trend.  If the Northwest Passage becomes practical as a shipping route, Canadian west-coast ports become that much closer to markets in Europe and elsewhere along the Atlantic.  Plans to increase U.S. coal exports from Pacific ports are facing headwinds, but the economics of Canadian exports may improve if coal can be shipped east through the Northwest Passage.

At the same time, transit routes through the Northwest Passage come with risks, including icebergs, less well-mapped hazards, and local impacts to the Arctic environment.  Royal Dutch Shell PLC's aborted attempts to drill for oil in U.S. Arctic waters in 2012 illustrate some of these hazards.

Will cargo traffic through the Northwest Passage continue to increase?  How will it affect global markets?  What impacts will it have to the Arctic?

eBay OKed for wholesale electricity sales

As customer-sited electric generation becomes increasingly economic, major companies outside the energy sector are entering electricity markets.  Federal regulators this month granted eBay Inc.'s request for authorization to sell electricity at wholesale.  What does this mean?

U.S. wholesale electricity markets are generally regulated by the Federal Energy Regulatory Commission.  Most sellers in those markets are regulated as public utilities - but in recent years, the category of "utilities" has expanded beyond the traditional vertically-integrated utility serving retail customers with electricity.  The growth in this sector has come largely from end-users of electricity who have developed on-site generation to meet their needs - and to sell excess power into wholesale markets.  Recent big-name entries into the wholesale electricity market include Google Inc. and Wal-Mart Stores Inc. - and now eBay.

On September 5, 2013, the Commission granted eBay market-based rate authority.  This approval enables eBay to sell electric energy, capacity, and other products.  As described in the Commission's order, eBay plans to own and operate a 6 megawatt fuel cell generation facility located at its data center in South Jordan, Utah.  In a June 21 filing, eBay described plans to install five natural gas-fueled "Bloom Box" units at the data center to provide power to run the facility. 

eBay's plans bear some resemblance to the fuel cell system Apple developed at its data center in Maiden, North Carolina.  Data centers consume significant amounts of energy, both for processing and for cooling.  In many cases, on-site generation projects offer data centers a way to cut costs while improving their reliability and their environmental footprint.

Maximizing the cost-effectiveness of a distributed generation project requires it to be sized appropriately for the load to be served.  In some applications, there may be little to no excess power available for sale at wholesale to the grid, while other on-site generation projects may be capable of exporting significant amounts of energy to the grid.  With its market-based rate authorization in hand, eBay stands ready to enter the wholesale market with any excess power its Utah fuel cells produce.

Northern Pass transmission line faces public hearings

A proposed high-voltage transmission line across the U.S.-Canada border in northern New Hampshire faces a series of public hearings this month.  The Northern Pass transmission line would provide an additional tie between Hydro-Quebec's electric grid and the New England grid, and would expand U.S. imports of electricity from Canada.

The project is proposed by Northern Pass Transmission LLC, an entity jointly owned by NU Transmission Ventures, Inc., a wholly-owned subsidiary of Northeast Utilities, a publicly held public utility holding company, and NSTAR Transmission Ventures, Inc., a wholly-owned subsidiary of NSTAR, a publicly held public utility holding company.

The project includes a high-voltage direct current or HVDC transmission line capable of transmitting up to 1,200 megawatts of power from Canada to the U.S. or from the U.S. to Canada.  45 miles of line would connect the northern HVDC converter terminal in Québec to the U.S.-Canada border into New Hampshire.  The line would extend south from the international border approximately 140 miles to an HVDC converter terminal that would be constructed in the city of Franklin, NH. 

Federal law governs the import and export of electricity.  To construct, operate, maintain, or connect an electric transmission facility crossing the borders of the United States, Northern Pass must first obtain a Presidential permit issued by the U.S. Department of Energy.  Under the National Environmental Policy Act, this approval requires the Department of Energy to consider the environmental impacts of granting the permit.

Since its unveiling in 2011, the Northern Pass project has provoked controversy.  The public has voiced concerns over the environmental and economic impacts of large-scale Canadian hydropower, the risk of private property being seized by the developer through eminent domain, and a route through New Hampshire's White Mountain National Forest and nearby mountains and woodlands.  In response, Northern Pass retooled its route, triggering a need to revise the project's environmental impact statement.  As part of that process, the Department of Energy has scheduled four additional scoping meetings in New Hampshire:

• Concord, NH, Grappone Conference Center, 70 Constitution Avenue, Monday, September 23, 2013, 6-9 p.m.;
• Plymouth, NH, Plymouth State University, Silver Center for the Arts, Hanaway Theater, 17 High Street, Tuesday, September 24, 2013, 5-8 p.m.;
• Whitefield, NH, Mountain View Grand Resort; Spa, Presidential Room, 101 Mountain View Road, Wednesday, September 25, 2013, 5-8 p.m.; and
• West Stewartstown, NH, The Outback Pub at The Spa Restaurant, 869 Washington Street, Thursday, September 26, 2013, 5-8 p.m.

Thousands of stakeholders attended the first round of scoping meetings in 2011, overwhelmingly expressing concerns about the project and its route.  While Northern Pass has made some efforts to address and accommodate these concerns, many - like New Hampshire Governor Maggie Hassan - continue to express concerns about the project's potential impacts on the White Mountain National Forest, as well as on New Hampshire's economy, environment, natural resources, communities and people.  This month's events may draw similar attendance to those in 2011 - the New Hampshire Congressional delegation has asked the U.S. Department of Energy to move the West Stewartstown meeting to Colebrook to accomodate more seating.  Public testimony at this month's scoping sessions will shape the Department of Energy's environmental review process, and may affect whether and how the line is eventually developed.

Small hydro helped by Hydropower Regulatory Efficiency Act of 2013

Hydropower in the United States may soon expand thanks to recently enacted federal legislation.  The Hydropower Regulatory Efficiency Act of 2013, signed into law on August 9, 2013, is designed to promote hydropower by streamlining the Federal Energy Regulatory Commission's process for developing and operating hydroelectric projects.

The Hydropower Regulatory Efficiency Act of 2013 is predicated on the value of hydropower in providing renewable electricity - and on hydropower's estimated growth potential.  Congressional findings in the Act include that "hydropower is the largest source of clean, renewable electricity in the United States", producing about 7 percent of the nation's power and about 100,000 megawatts of capacity, and employing approximately 300,000 workers across the country.  Yet only 3 percent of the 80,000 dams in the United States generate electricity, highlighting substantial potential for adding hydropower generation to nonpowered dams.  According to one study, by utilizing currently untapped resources, the United States could add approximately 60,000 megawatts of new hydropower capacity by 2025.

To promote the use of these "currently untapped" resources, the Act enhances and streamlines the regulatory framework for some hydropower projects.  For example, the Act exempts certain so-called "conduit" hydropower facilities from the licensing requirements of the Federal Power Act.  Conduit facilities generate electric power using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  To qualify, conduit facilities must have an installed generating capacity that does not exceed 5 megawatts (MW), and must not have been licensed or exempted from the licensing requirements of Part I of the Federal Power Act on or before August 9, 2013.  While qualifying conduit hydropower facilities are not required to be licensed or exempted by the Commission, developers of qualifying facilities must file a Notice of Intent to Construct a Qualifying Conduit Hydropower Facility with the Commission.

The Act also streamlines other regulatory procedures.  For example, it amends Section 405 of the Public Utility Regulatory Policies Act of 1978 to define "small hydroelectric power projects" as having an installed capacity that does not exceed 10,000 kilowatts.  The Act also authorizes the Federal Energy Regulatory Commission to extend the term of preliminary permits for hydropower development for up to 2 additional years beyond the 3 years previously allowed under Section 5 of the Federal Power Act.  It also directs the Commission to investigate the feasibility of a 2-year licensing process for hydropower development at non-powered dams and closed-loop pump storage projects.

The Commission is moving forward with the implementation of the Act.  The conduit, 10-megawatt exemption, and preliminary permit processes are already underway.  On October 2, 2013, the Commission will hold a workshop to launch its investigation of the feasibility of a two-year process for issuing a license for hydropower development at non-powered dams and closed-loop pumped storage projects.

Will the Act lead to the development of more hydropower in the U.S.?  While the Act eases regulatory burdens on project developers and operators, the rate of project development is also driven by market forces.  The intersection of regulations and these market forces will determine the addition of new hydropower capacity.  Nevertheless, the reductions in regulatory burden and uncertainty appear poised to support the buildout of hydroelectric generation from previously untapped resources.

Dominion wins Virginia offshore wind lease

Dominion Virginia Power was the winning bidder in today's auction for the right to lease sea space off Virginia to develop an offshore wind project.  The auction, held the federal Bureau of Ocean Energy Management, was for a lease for a designated wind energy area covering about 112,799 acres of the outer continental shelf.  The site, about 23.5 nautical miles off the Virginia Beach coastline, is considered capable of supporting over 2,000 megawatts of wind generation.  

Prior to the auction, the Bureau of Ocean Energy Management approved eight bidders as eligible to participate.  But only Dominion and Apex Virginia Wind LLC participated in the auction.  By the sixth round, Apex dropped out and Dominion won.  While the official results have not yet been published, Dominion reportedly paid between $1.1 and $1.6 million for the right to this lease.

The Virginia auction follows July's auction in which Deepwater Wind paid $3.8 million for the right to lease 164,750 acres off Rhode Island and Massachusetts.  To compare projects against each other, one metric for evaluation is the effective premium the winning bidder paid in dollars per megawatt of resource potential in the area.  This premium represents the cost of outbidding the competition for the site, and is distinct from the ongoing lease payments that would ultimately be due when a lease is entered into.

With an estimated resource potential of 3,395 megawatts, the Massachusetts bid implies a lease premium of about $1.12 per megawatt of potential.  Dominion's winning bid for Virginia implies a lower lease premium of 55 to 80 cents per megawatt of potential.  The difference between these premiums could be due to a combination of several factors, including the degree of competitive interest in the site, and bidders' varying projections about the development, fixed and operating costs of a project.  The value of winning the lease also depends on the bidder's plans and capital availability.  Any development of the sites would likely occur in phases over the coming years, and seems unlikely to reach its full estimated potential in the near term.  Nevertheless, the lower Virginia lease premium illustrates the market results for this auction; its implications may depend on Dominion's plans.

The Bureau of Ocean Energy Management anticipates holding subequent auctions for offshore wind site leases elsewhere in the country in the coming months.  Will these leases lead to the development of offshore wind in U.S. waters?