As Maine utility regulators consider how drought and other factors affect water utility supplies, staff at the Maine Public Utilities Commission have again requested comments and information on water supply emergencies and regulatory responses. The feedback will inform a preliminary staff recommendation to be released in January 2017, which could lead to changes in how Maine regulates water utility supplies.
Drought and water shortage are affecting parts of the U.S., including much of New England. In October, the Maine Public Utilities Commission issued a Notice of Inquiry (NOI) into water supply issues. The Commission requested information about water supply problems, potential solutions, and development of plans to address any problems identified. Specifically, the Commission posed 14 questions about water supply emergencies, plus 9 more questions about how the Commission should respond to water supply emergencies. The Commission requested responses to these questions by November 4, 2016.
Some Maine water utilities responded to the Commission's water supply Notice of Inquiry, but many did not file a public response. In a November 28, 2016 Procedural Order, Commission staff expressed a firm belief "that the more input the Commission receives from affected parties, the greater the likelihood that the final outcome in this Inquiry will meet the needs of those affected parties." Accordingly, the procedural order invites any entity that did not initially respond to the NOI to do so by December 23, 2016.
The November 28 procedural order establishes a schedule for the remainder of the inquiry. Staff intends to issue a Preliminary Recommendation in January, to which interested persons will be invited to respond during February, whether orally or in writing. The schedule contemplates that staff would incorporate written and oral comments regarding the Preliminary Recommendation into a Final Recommendation in March, for presentation to the Commissioners during April.
The Commission has docketed the Maine water supply inquiry as Docket No. 2016-000233.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
FERC considers hydro license term policy
Monday, November 28, 2016
U.S. hydropower regulators have requested public comments on whether to revise a policy setting the length of license terms for hydroelectric projects. The Federal Energy Regulatory Commission's notice of inquiry could lead to changes in how the Commission sets license terms.
Under Section 6 of the Federal Power Act, the Commission may issue hydropower licenses for a term not to exceed 50 years. Original licenses have no minimum license term. Section 15(e) of the Federal Power Act provides that any new license (i.e. relicense) shall be for a term that the Commission determines to be in the public interest, but not less than 30 years or more than 50 years.
Within these statutory bounds, the Commission has discretion to set its own policy governing the term length of hydropower licenses. At present, the Commission policy is to set a 50-year term for licenses issued for projects located at federal dams. For projects located at non-federal dams, the Commission’s current policy is to set a 30-year term where there is little or no authorized redevelopment, new construction, or environmental mitigation and enhancement; a 40-year term for a license involving a moderate amount of these activities; and a 50- year term where there is an extensive amount of such activity.
The Commission has described the purpose of this policy as "to ease the economic impact of new costs, promote balanced and comprehensive development of renewable power generating resources, and encourage licensees to be better environmental stewards." But the lengths of new licenses have been contested in several recent relicensing proceedings, in which parties have argued that the Commission should have considered or given more weight to other factors. These other factors proposed for consideration include capacity-related investments or environmental enhancements made by the licensee during the current license and before issuance of the new license; total cost of the relicensing process; losses in generation value related to environmental measures; the license terms of projects that the licensee states are similarly situated to its project; and the license term provided for in settlement agreements.
In a November 17, 2016 notice of inquiry, the Commission outlined five potential options that Commission staff has identified for establishing license terms:
Under Section 6 of the Federal Power Act, the Commission may issue hydropower licenses for a term not to exceed 50 years. Original licenses have no minimum license term. Section 15(e) of the Federal Power Act provides that any new license (i.e. relicense) shall be for a term that the Commission determines to be in the public interest, but not less than 30 years or more than 50 years.
Within these statutory bounds, the Commission has discretion to set its own policy governing the term length of hydropower licenses. At present, the Commission policy is to set a 50-year term for licenses issued for projects located at federal dams. For projects located at non-federal dams, the Commission’s current policy is to set a 30-year term where there is little or no authorized redevelopment, new construction, or environmental mitigation and enhancement; a 40-year term for a license involving a moderate amount of these activities; and a 50- year term where there is an extensive amount of such activity.
The Commission has described the purpose of this policy as "to ease the economic impact of new costs, promote balanced and comprehensive development of renewable power generating resources, and encourage licensees to be better environmental stewards." But the lengths of new licenses have been contested in several recent relicensing proceedings, in which parties have argued that the Commission should have considered or given more weight to other factors. These other factors proposed for consideration include capacity-related investments or environmental enhancements made by the licensee during the current license and before issuance of the new license; total cost of the relicensing process; losses in generation value related to environmental measures; the license terms of projects that the licensee states are similarly situated to its project; and the license term provided for in settlement agreements.
In a November 17, 2016 notice of inquiry, the Commission outlined five potential options that Commission staff has identified for establishing license terms:
(1) retain the existing license term policy; (2) add to the existing license term policy the consideration of measures implemented under the prior license; (3) replace the existing license term policy with a 50- year default license term unless the Commission determines that a lesser license term would be in the public interest (f or example, to better coordinate, to the extent feasible, the license terms for projects in the same river basin for future consideration of cumulative impacts); (4) add a more quantitative cost- based analysis to the existing license term policy ; and (5) alter current policy to accept the longer license term agreed upon in an applicable settlement agreement, when appropriate.The Commission now seeks comment on issues relating to license terms, due within 60 days from the Notice of Inquiry's November 25 publication in the Federal Register.
Adding micro-hydro to licensed hydropower project
Wednesday, November 16, 2016
What happens when a FERC hydropower licensee applies for a preliminary permit to study the feasibility of developing a micro-hydro project, where the new project will be sited at an existing project's dam? In a recent case involving the city of Aspen, Colorado, Commission staff dismissed the preliminary permit application, instead suggesting that the licensee apply to amend its existing license to include the proposed new capacity and facilities. Because many other existing dams may be candidates for the installation of new hydropower facilities, the Aspen Micro Hydro Project case illustrates important dynamics of hydropower licensing under the Federal Power Act.
The case centers on a March 4, 2015 application by the City of Aspen for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, to study the feasibility of developing the Aspen Micro Hydro Project. Most grid-connected hydropower in the U.S. is regulated under the Federal Power Act, and requires approvals by the Federal Energy Regulatory Commission. As described in Commission documents, the proposed Aspen project would include an existing concrete diversion dam and intake structure, plus proposed new equipment including a draft tube, 10- to 20-kilowatt turbine-generator unit, and associated facilities interconnected to an existing utility transmission line. The application describes project values including energy production, protection of the city's water rights, and instream flow protection for environmental benefit. As noted in the application, "Renewable projects such as the Aspen Micro Hydro Project will permit the City of Aspen to reduce its reliance on coal-fired energy and comports with the City’s goal of reducing its energy-related greenhouse gas emissions. A local facility also will provide tangible evidence to residents and visitors of Aspen’s commitment to renewable energy."
Crucially, as noted by the Commission, the dam proposed for use in the Aspen micro-hydro project is currently licensed as part of another hydropower project: the City of Aspen's Maroon Creek Project. Commission staff have noted that "for licensed projects, such as the Maroon Creek Project, section 6 of the [Federal Power Act] prohibits the alteration of licensed project works without the mutual consent of the licensee and the Commission." On April 16, 2015, Commission staff sent the city a letter explaining that because the proposed micro-hydro project would be sited within the existing project boundary of the city’s Maroon Creek Project, any application for a permit or license within the project boundary would be denied. For this reason, Commission staff concluded that "a preliminary permit for the Aspen Project would serve no purpose." Instead, Commission staff informed the city "that it could instead file an application to amend its existing license to add the Aspen Project’s proposed capacity and related facilities to the Maroon Creek Project."
Over a year later, the city filed a status report describing its intention to "enter into a business relationship with T-Lazy Seven Ranch (T-Lazy), a Colorado ranching company, for joint development of the Aspen Project." The status report describes plans to form a new limited liability company, and ultimately to amend the permit application to replace the city as applicant with the new company.
In a November 15, 2016 Order Dismissing Preliminary Permit Application, Commission staff noted that the purpose of a preliminary permit is "to encourage hydroelectric development by affording its holder priority of application (i.e., guaranteed first-to-file status) with respect to the filing of development applications for the affected site." The order also notes that the prohibition in section 6 of the Federal Power Act against the alteration of licensed project works without the mutual consent of the licensee and the Commission applies, no matter whether it is the existing licensee or the new entity who seeks to pursue additional development within the project boundary of the Maroon Creek Project. The Commission's consent to alter licensed project works would presumably come in the form of an order amending the Maroon Creek Project's license -- a consent not formally requested int the Aspen Project's docket.
Continuing to find that a preliminary permit for the Aspen Project would serve no purpose for these reasons, the order dismissed the city's permit application. The order leaves the door open for the licensee to seek to amend the Maroon Creek Project's license, potentially in concert with an application to transfer the licensee to a new licensee or co-licensee.
Beyond the City of Aspen's interests in hydropower, the case has regulatory implications for other proposals to develop micro-hydro or new generating capacity at dams or other structures already part of FERC-licensed projects. A Department of Energy report released earlier this year found significant national potential to increase hydropower capacity, including by adding power at existing dams and canals. Where the existing assets are part of a FERC-licensed project, developers will be wise to be mindful of how the Commission interprets the Federal Power Act.
The case centers on a March 4, 2015 application by the City of Aspen for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, to study the feasibility of developing the Aspen Micro Hydro Project. Most grid-connected hydropower in the U.S. is regulated under the Federal Power Act, and requires approvals by the Federal Energy Regulatory Commission. As described in Commission documents, the proposed Aspen project would include an existing concrete diversion dam and intake structure, plus proposed new equipment including a draft tube, 10- to 20-kilowatt turbine-generator unit, and associated facilities interconnected to an existing utility transmission line. The application describes project values including energy production, protection of the city's water rights, and instream flow protection for environmental benefit. As noted in the application, "Renewable projects such as the Aspen Micro Hydro Project will permit the City of Aspen to reduce its reliance on coal-fired energy and comports with the City’s goal of reducing its energy-related greenhouse gas emissions. A local facility also will provide tangible evidence to residents and visitors of Aspen’s commitment to renewable energy."
Crucially, as noted by the Commission, the dam proposed for use in the Aspen micro-hydro project is currently licensed as part of another hydropower project: the City of Aspen's Maroon Creek Project. Commission staff have noted that "for licensed projects, such as the Maroon Creek Project, section 6 of the [Federal Power Act] prohibits the alteration of licensed project works without the mutual consent of the licensee and the Commission." On April 16, 2015, Commission staff sent the city a letter explaining that because the proposed micro-hydro project would be sited within the existing project boundary of the city’s Maroon Creek Project, any application for a permit or license within the project boundary would be denied. For this reason, Commission staff concluded that "a preliminary permit for the Aspen Project would serve no purpose." Instead, Commission staff informed the city "that it could instead file an application to amend its existing license to add the Aspen Project’s proposed capacity and related facilities to the Maroon Creek Project."
Over a year later, the city filed a status report describing its intention to "enter into a business relationship with T-Lazy Seven Ranch (T-Lazy), a Colorado ranching company, for joint development of the Aspen Project." The status report describes plans to form a new limited liability company, and ultimately to amend the permit application to replace the city as applicant with the new company.
In a November 15, 2016 Order Dismissing Preliminary Permit Application, Commission staff noted that the purpose of a preliminary permit is "to encourage hydroelectric development by affording its holder priority of application (i.e., guaranteed first-to-file status) with respect to the filing of development applications for the affected site." The order also notes that the prohibition in section 6 of the Federal Power Act against the alteration of licensed project works without the mutual consent of the licensee and the Commission applies, no matter whether it is the existing licensee or the new entity who seeks to pursue additional development within the project boundary of the Maroon Creek Project. The Commission's consent to alter licensed project works would presumably come in the form of an order amending the Maroon Creek Project's license -- a consent not formally requested int the Aspen Project's docket.
Continuing to find that a preliminary permit for the Aspen Project would serve no purpose for these reasons, the order dismissed the city's permit application. The order leaves the door open for the licensee to seek to amend the Maroon Creek Project's license, potentially in concert with an application to transfer the licensee to a new licensee or co-licensee.
Beyond the City of Aspen's interests in hydropower, the case has regulatory implications for other proposals to develop micro-hydro or new generating capacity at dams or other structures already part of FERC-licensed projects. A Department of Energy report released earlier this year found significant national potential to increase hydropower capacity, including by adding power at existing dams and canals. Where the existing assets are part of a FERC-licensed project, developers will be wise to be mindful of how the Commission interprets the Federal Power Act.
BLM rule for renewable energy leasing of federal lands
Monday, November 14, 2016
The federal Bureau of Land Management has issued a final rule establishing a competitive process for leasing federal lands for renewable energy development. The Obama administration describes the rule as strengthening the agency's existing "Smart from the Start" leasing program, consistent with the president's Climate Action Plan. But following the 2016 election, the future Trump administration could change the agency's course.
Part of the Department of the Interior, the BLM manages federal lands across the U.S. While BLM lands have been used for mining for years, under the Obama administration BLM took steps to open up federal lands for leasing for renewable energy projects. Under federal laws including the Federal Land Policy and Management Act (FLPMA) and the Mineral Leasing Act (MLA), BLM is authorized to issue what it calls "grants" -- easements, leases, licenses, and permits to occupy, use or traverse public lands for particular purposes -- for facilities for the generation, transmission, and distribution of electric energy, and oil and gas pipelines.
On November 10, BLM released its final rule, "Competitive Processes, Terms, and Conditions for Leasing Public Lands for Solar and WindEnergy Development and Technical Changes and Corrections for 43 CFR Parts 2800and 2880.” It amends BLM's regulations governing rights-of-way issued under two federal laws. BLM described the amendments as necessary to "facilitate responsible solar and wind energy development on BLM-managed public lands and to ensure that the American taxpayer receives fair market value for such development."
The final rule includes provisions to promote the use of preferred areas for solar and wind energy development. These areas, called “designated leasing areas” (DLAs), are defined parcels of land with specific boundaries identified by the BLM land use planning process as being a preferred location for solar or wind energy that can be leased competitively for energy development.
The rule expands BLM's existing regulations, allowing BLM to offer lands competitively on its own initiative, both inside and outside DLAs, even in the absence of identified competition. Within DLAs, the rule will require competitive leasing procedures except in certain circumstances, when applications could be consider ed outside the competitive process. Outside DLAs, the BLM will have discretion whether to utilize competitive leasing procedures.
The final rule also updates payments charged by BLM, to ensure that it obtains fair market value for the use of public lands. Updated fee structures include both an acreage rent and a megawatt-capacity fee.
Given the November 8 election results, it is unclear whether the Trump administration will continue in this direction. While campaigning, President-elect Trump emphasized leasing more federal land for fossil fuel production. The BLM renewable energy rule's future is thus in question.
Part of the Department of the Interior, the BLM manages federal lands across the U.S. While BLM lands have been used for mining for years, under the Obama administration BLM took steps to open up federal lands for leasing for renewable energy projects. Under federal laws including the Federal Land Policy and Management Act (FLPMA) and the Mineral Leasing Act (MLA), BLM is authorized to issue what it calls "grants" -- easements, leases, licenses, and permits to occupy, use or traverse public lands for particular purposes -- for facilities for the generation, transmission, and distribution of electric energy, and oil and gas pipelines.
On November 10, BLM released its final rule, "Competitive Processes, Terms, and Conditions for Leasing Public Lands for Solar and WindEnergy Development and Technical Changes and Corrections for 43 CFR Parts 2800and 2880.” It amends BLM's regulations governing rights-of-way issued under two federal laws. BLM described the amendments as necessary to "facilitate responsible solar and wind energy development on BLM-managed public lands and to ensure that the American taxpayer receives fair market value for such development."
The final rule includes provisions to promote the use of preferred areas for solar and wind energy development. These areas, called “designated leasing areas” (DLAs), are defined parcels of land with specific boundaries identified by the BLM land use planning process as being a preferred location for solar or wind energy that can be leased competitively for energy development.
The rule expands BLM's existing regulations, allowing BLM to offer lands competitively on its own initiative, both inside and outside DLAs, even in the absence of identified competition. Within DLAs, the rule will require competitive leasing procedures except in certain circumstances, when applications could be consider ed outside the competitive process. Outside DLAs, the BLM will have discretion whether to utilize competitive leasing procedures.
The final rule also updates payments charged by BLM, to ensure that it obtains fair market value for the use of public lands. Updated fee structures include both an acreage rent and a megawatt-capacity fee.
Given the November 8 election results, it is unclear whether the Trump administration will continue in this direction. While campaigning, President-elect Trump emphasized leasing more federal land for fossil fuel production. The BLM renewable energy rule's future is thus in question.
Nova Scotia tidal turbine installed
Thursday, November 10, 2016
A Canadian tidal power developer has installed a turbine at a test site in the Bay of Fundy. Cape Sharp Tidal's project off Nova Scotia could demonstrate the feasibility of larger-scale marine hydrokinetic power plants connected to the mainland electricity grid.
Cape Sharp Tidal is a joint venture between Canadian utility Emera Inc. and marine turbine manufacturer OpenHydro. Its project entails a grid-connected 4-megawatt array consisting of two tidal turbines. The project is located at the Fundy Ocean Research Center for Energy (FORCE) site. Headquartered near Parrsboro, Nova Scotia, FORCE is Canada's leading research center for in-stream tidal energy, with demonstration berths, a grid interconnection capable of accepting tidal power, and environmental monitoring capabilities.
This week Cape Sharp Tidal deployed the project's first turbine-generator, a 2-megawatt OpenHydro unit. In subsequent work, crews interconnected the turbine cable tail to the FORCE site's main interconnection cable, an existing 16MW subsea export cable connected to an onshore substation.
Previous efforts to develop hydrokinetic tidal energy projects in the Bay of Fundy have met with difficulty. While the bay offers large and powerful tides, weather and sea conditions can prove challenging, as can obtaining environmental and regulatory approvals. A test tidal turbine deployed in 2009 was quickly destroyed; the turbine installed this week was originally slated for installation earlier but was delayed due to concerns over impacts to fisheries and the environment. This week's installation represents a concrete step forward for Canadian tidal power.
Cape Sharp Tidal intends to install and connect a second turbine at the FORCE site in 2017. According to the developer, its future plans -- subject to regulatory and business approvals -- could include a commercial-scale project of up to 300 megawatts capacity within 15 years.
Cape Sharp Tidal is a joint venture between Canadian utility Emera Inc. and marine turbine manufacturer OpenHydro. Its project entails a grid-connected 4-megawatt array consisting of two tidal turbines. The project is located at the Fundy Ocean Research Center for Energy (FORCE) site. Headquartered near Parrsboro, Nova Scotia, FORCE is Canada's leading research center for in-stream tidal energy, with demonstration berths, a grid interconnection capable of accepting tidal power, and environmental monitoring capabilities.
This week Cape Sharp Tidal deployed the project's first turbine-generator, a 2-megawatt OpenHydro unit. In subsequent work, crews interconnected the turbine cable tail to the FORCE site's main interconnection cable, an existing 16MW subsea export cable connected to an onshore substation.
Previous efforts to develop hydrokinetic tidal energy projects in the Bay of Fundy have met with difficulty. While the bay offers large and powerful tides, weather and sea conditions can prove challenging, as can obtaining environmental and regulatory approvals. A test tidal turbine deployed in 2009 was quickly destroyed; the turbine installed this week was originally slated for installation earlier but was delayed due to concerns over impacts to fisheries and the environment. This week's installation represents a concrete step forward for Canadian tidal power.
Cape Sharp Tidal intends to install and connect a second turbine at the FORCE site in 2017. According to the developer, its future plans -- subject to regulatory and business approvals -- could include a commercial-scale project of up to 300 megawatts capacity within 15 years.
US designates alternative fuel corridors for transportation
Thursday, November 3, 2016
U.S. federal highway administrators have announced the designation of 55 routes as "alternative fuel" corridors, capable of accommodating electric vehicles or those powered by hydrogen, propane, or natural gas. The announcement sets the stage for further federal action supporting alternative transportation fuels.
The U.S. Department of Transportation’s Federal Highway Administration (FHWA) oversees construction and maintenance of the nation's highways, bridges, and tunnels. FHWA data suggests U.S. drivers travel over 3.15 trillion miles per year. Overall, the U.S. transportation sector is a major consumer of energy, and among the largest contributors to domestic greenhouse gas emissions.
Congress and the Obama administration are now pursuing strategies to reduce the transportation sector's greenhouse gas emissions. Electric vehicles and alternative transportation fuels form one tool in these efforts. Under a 2015 law -- Section 1413 of the Fixing America's Surface Transportation (FAST) Act -- the Secretary of Transportation is required to designate national electric vehicle (EV) charging, hydrogen, propane, and natural gas fueling corridors. In July, the Department of Transportation asked states to nominate corridors along major highways, for EVs and other alternative fuels designated in the FAST Act.
In a November 3, 2016, announcement, the FHWA unveiled its designation of the nation's first alternative fuel corridors. The network is nearly 85,000 miles long, and crosses 35 states. Some corridors have been designed as "sign-ready," meaning alternative fueling stations are operational; these corridors are eligible to feature new signs showing where drivers can refuel.
The FHWA has posted maps of its alternative fuel corridors on its website. The agency intends to add more miles in the future, as additional charging and fueling stations are built.
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| An electric vehicle charging station, in an underground parking garage in Boston. |
The U.S. Department of Transportation’s Federal Highway Administration (FHWA) oversees construction and maintenance of the nation's highways, bridges, and tunnels. FHWA data suggests U.S. drivers travel over 3.15 trillion miles per year. Overall, the U.S. transportation sector is a major consumer of energy, and among the largest contributors to domestic greenhouse gas emissions.
Congress and the Obama administration are now pursuing strategies to reduce the transportation sector's greenhouse gas emissions. Electric vehicles and alternative transportation fuels form one tool in these efforts. Under a 2015 law -- Section 1413 of the Fixing America's Surface Transportation (FAST) Act -- the Secretary of Transportation is required to designate national electric vehicle (EV) charging, hydrogen, propane, and natural gas fueling corridors. In July, the Department of Transportation asked states to nominate corridors along major highways, for EVs and other alternative fuels designated in the FAST Act.
In a November 3, 2016, announcement, the FHWA unveiled its designation of the nation's first alternative fuel corridors. The network is nearly 85,000 miles long, and crosses 35 states. Some corridors have been designed as "sign-ready," meaning alternative fueling stations are operational; these corridors are eligible to feature new signs showing where drivers can refuel.
The FHWA has posted maps of its alternative fuel corridors on its website. The agency intends to add more miles in the future, as additional charging and fueling stations are built.
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