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?
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
eBay OKed for wholesale electricity sales
Friday, September 13, 2013
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.
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
Wednesday, September 11, 2013
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:
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.
Small hydro helped by Hydropower Regulatory Efficiency Act of 2013
Tuesday, September 10, 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.
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
Wednesday, September 4, 2013
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?
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?
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