The U.S. Department of the Interior has proposed leasing federal ocean space offshore North Carolina for commercial offshore wind development. On August 12, 2016, the Bureau of Ocean Energy Management announced a proposed lease sale for the 122,405-acre Kitty Hawk Wind Energy Area. The proposal could lead to leasing of sites offshore North Carolina for one or more marine renewable energy projects.
The path to federal leasing of commercial wind development sites offshore North Carolina began in 2012, when the Bureau of Ocean Energy Management published a Call for Information and Nominations (or “Call”) in the Federal
Register, to evaluate industry interest in commercial wind leases in three areas offshore North Carolina and to
request comments regarding site conditions, resources and other uses
within the Call areas.
In 2014, BOEM announced its identification of three Wind Energy Areas offshore North Carolina, including the Kitty Hawk, Wilmington West, and Wilmington East Wind Energy Areas.
In 2015, BOEM published an Environmental Assessment of potential environmental and socioeconomic impacts associated with
issuing commercial wind leases and approving site assessment activities
on the lease areas, followed by a revised Environmental Assessment and a "Finding of No Significant Impact." This so-called FONSI concluded that
reasonably foreseeable environmental effects associated with the
commercial wind lease issuance and related activities would not
significantly impact the environment.
Most recently, BOEM published a Proposed Sale Notice (PSN) and Request for Interest (RFI) for Commercial Leasing for Wind Power on the Outer Continental Shelf Offshore North Carolina in the Federal Register on August 16, 2016. The notice applies to the Kitty Hawk Wind Energy Area. BOEM has rolled the Wilmington East and Wilmington West areas into its planning and leasing process for Call Areas offshore South Carolina, given their proximity and shared attributes.
If a developer is interested in bidding on the Kitty Hawk site lease rights, it must first submit a qualification package to BOEM. If BOEM finds the developer to be legally, technically and financially qualified by the time the Final Sale Notice is published, the developer is eligible to participate in the lease sale. Eligible bidders must notify BOEM within the 60-day comment period established by the notice.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Vineyard Wind offshore project changes hands
Tuesday, August 30, 2016
Danish fund management company Copenhagen Infrastructure Partners has acquired Offshore MW LLC, the holder of an offshore wind energy lease issued by the
U.S. Bureau of Ocean Energy Management over an area south of Massachusetts.
Copenhagen Infrastructure Partners describes itself as a fund management company founded in 2012. On August 25, 2016, CIP announced that on behalf of its fund Copenhagen Infrastructure II it had acquired 100% of Offshore MW LLC.
Acquired company Offshore MW LLC is developing the Vineyard Wind project over the Outer Continental Shelf south of Massachusetts. The site is part of the Massachusetts Wind Energy Area originally designated by BOEM for leasing in 2012. Offshore MW won the lease rights through a competitive lease auction held by the Bureau of Ocean Energy Management on January 29, 2015, in which it submitted the winning bid for Lease Area OCS-A 0501. That lease area covers 166,886 acres, or roughly 260 square miles of sea space in federal waters off Massachusetts.
According to CIP, it will continue with the Massachusetts project's development. The Vineyard Wind project could receive a boost from recently enacted Massachusetts legislation that will require utilities to purchase about 1,600 megawatts worth of offshore wind energy by 2027. That law, known as H. 4568, "An Act to promote energy diversity," requires electric distribution companies to issue an initial joint competitive solicitation for offshore wind proposals by June 30, 2017.
Copenhagen Infrastructure Partners describes itself as a fund management company founded in 2012. On August 25, 2016, CIP announced that on behalf of its fund Copenhagen Infrastructure II it had acquired 100% of Offshore MW LLC.
Acquired company Offshore MW LLC is developing the Vineyard Wind project over the Outer Continental Shelf south of Massachusetts. The site is part of the Massachusetts Wind Energy Area originally designated by BOEM for leasing in 2012. Offshore MW won the lease rights through a competitive lease auction held by the Bureau of Ocean Energy Management on January 29, 2015, in which it submitted the winning bid for Lease Area OCS-A 0501. That lease area covers 166,886 acres, or roughly 260 square miles of sea space in federal waters off Massachusetts.
According to CIP, it will continue with the Massachusetts project's development. The Vineyard Wind project could receive a boost from recently enacted Massachusetts legislation that will require utilities to purchase about 1,600 megawatts worth of offshore wind energy by 2027. That law, known as H. 4568, "An Act to promote energy diversity," requires electric distribution companies to issue an initial joint competitive solicitation for offshore wind proposals by June 30, 2017.
Tide Mill Institute - 2016 Boston conference
Monday, August 29, 2016
The Tide Mill Institute will hold its 12th conference, Boston's Tidal Power: Periodic & Perpetual, on Saturday, November 12th, at the Metropolitan Waterworks Museum in Boston, Massachusetts.
Tide Mill Institute is nonprofit corporation, whose mission is:
Previous Tide Mill Institute symposia have included tours, presentations, and exhibits on the past, present and future of tidal power. Topics range from archaeology and history to modern marine renewable energy projects and technology, from sites around the world.
Tide Mill Institute's 2016 conference will focus on Boston's tidal power heritage. Presentations will illustrate historical tide mills, based on tide mill relics from the 18th century found during the "Big Dig” construction project, as well as the 19th century project along Back Bay that was designed and built to provide “perpetual power.” Other invited speakers will describe millstone quarries, and tides and tidal power around the world. The event will also include a tour of the Waterworks Museum, which interprets of one of the country’s earliest metropolitan water systems, as well as the annual meeting of Tide Mill Institute.
Space is limited at the venue, so register early by contacting Tide Mill Institute at info@tidemillinstitute.org, 207-946-4156, or 18 Hummingbird Hill – Greene ME 04236. Please indicate your email address and phone number.
Tide Mill Institute is nonprofit corporation, whose 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.
Previous Tide Mill Institute symposia have included tours, presentations, and exhibits on the past, present and future of tidal power. Topics range from archaeology and history to modern marine renewable energy projects and technology, from sites around the world.
Tide Mill Institute's 2016 conference will focus on Boston's tidal power heritage. Presentations will illustrate historical tide mills, based on tide mill relics from the 18th century found during the "Big Dig” construction project, as well as the 19th century project along Back Bay that was designed and built to provide “perpetual power.” Other invited speakers will describe millstone quarries, and tides and tidal power around the world. The event will also include a tour of the Waterworks Museum, which interprets of one of the country’s earliest metropolitan water systems, as well as the annual meeting of Tide Mill Institute.
Space is limited at the venue, so register early by contacting Tide Mill Institute at info@tidemillinstitute.org, 207-946-4156, or 18 Hummingbird Hill – Greene ME 04236. Please indicate your email address and phone number.
BOEM advances California offshore wind leasing
Friday, August 26, 2016
U.S. ocean energy managers are moving closer to leasing sites in federal waters offshore California for wind energy development. Acting in response to a lease area requested by Trident
Winds, LLC, this month the Bureau of Ocean Energy Management (BOEM) issued a Request for Interest in that area to evaluate whether any other developer is interested in competing for a lease.
Trident Winds has initiated development of a commercial scale offshore wind farm off Point Estero, California. Its Morro Bay or MBO Project would be located in federal waters about 33 nautical miles northwest of Morro Bay; the site features water depths of 2,600 to 3,300 feet. In light of these site conditions, Trident Winds' proposed project would consist of 100 floating foundations, each supporting a wind turbine generating 7-8 megawatts of energy. Electricity would be brought ashore via a single transmission cable.
Trident Winds requested a commercial wind lease from BOEM on January 14, 2016, covering a 67,963-acre proposed lease area. Because BOEM had not previously solicited interest in leasing this area, BOEM treated Trident Winds' request as "unsolicited." Under BOEM's offshore renewable energy program, when presented with an unsolicited lease request, BOEM first evaluates whether the developer is qualified to hold a lease on the Outer Continental Shelf. In the case of Trident Winds, BOEM made this determination following consultation with the state of California.
Following this qualification determination, BOEM's next step is to determine whether it is appropriate to issue the company a lease on a non-competitive basis, or whether a competitive process is required. To inform this competitive interest determination, on August 17, 2016, BOEM published a Potential Commercial Leasing for Wind Power on the Outer Continental Shelf (OCS) Offshore California, Request for Interest in the Federal Register, with a 30-day public comment period. If BOEM finds competitive interest, it will initiate a competitive leasing process for the California site. If no expressions of interest are received, BOEM will proceed with its noncompetitive leasing process.
At the same time, BOEM is also seeking public comment on the project proposal, its potential environmental consequences, and other uses of the project area such as navigation, fishing, military activities, recreation. BOEM will also use responses to shape its decisionmaking and to flag potential issues for analysis under the National Environmental Policy Act.
So far, BOEM has awarded 11 commercial wind energy leases for sites off the Atlantic coast, nine of which came from competitive lease sales that generated about $16 million in winning bids. BOEM has also recently announced proposed lease sales for sites offshore North Carolina and New York. In the Pacific, BOEM is evaluating 3 unsolicited lease requests offshore Hawaii and has published a Call for Interest in Hawaiian site leasing.
Trident Winds has initiated development of a commercial scale offshore wind farm off Point Estero, California. Its Morro Bay or MBO Project would be located in federal waters about 33 nautical miles northwest of Morro Bay; the site features water depths of 2,600 to 3,300 feet. In light of these site conditions, Trident Winds' proposed project would consist of 100 floating foundations, each supporting a wind turbine generating 7-8 megawatts of energy. Electricity would be brought ashore via a single transmission cable.
Trident Winds requested a commercial wind lease from BOEM on January 14, 2016, covering a 67,963-acre proposed lease area. Because BOEM had not previously solicited interest in leasing this area, BOEM treated Trident Winds' request as "unsolicited." Under BOEM's offshore renewable energy program, when presented with an unsolicited lease request, BOEM first evaluates whether the developer is qualified to hold a lease on the Outer Continental Shelf. In the case of Trident Winds, BOEM made this determination following consultation with the state of California.
Following this qualification determination, BOEM's next step is to determine whether it is appropriate to issue the company a lease on a non-competitive basis, or whether a competitive process is required. To inform this competitive interest determination, on August 17, 2016, BOEM published a Potential Commercial Leasing for Wind Power on the Outer Continental Shelf (OCS) Offshore California, Request for Interest in the Federal Register, with a 30-day public comment period. If BOEM finds competitive interest, it will initiate a competitive leasing process for the California site. If no expressions of interest are received, BOEM will proceed with its noncompetitive leasing process.
At the same time, BOEM is also seeking public comment on the project proposal, its potential environmental consequences, and other uses of the project area such as navigation, fishing, military activities, recreation. BOEM will also use responses to shape its decisionmaking and to flag potential issues for analysis under the National Environmental Policy Act.
So far, BOEM has awarded 11 commercial wind energy leases for sites off the Atlantic coast, nine of which came from competitive lease sales that generated about $16 million in winning bids. BOEM has also recently announced proposed lease sales for sites offshore North Carolina and New York. In the Pacific, BOEM is evaluating 3 unsolicited lease requests offshore Hawaii and has published a Call for Interest in Hawaiian site leasing.
Vermont adopts Renewable Energy Standard
Thursday, August 25, 2016
This summer Vermont energy regulators issued an order implementing a Renewable Energy Standard. This standard, or RES, requires
Vermont
electric
utilities to
procure
an
increasing
share
of electricity from
renewable
sources.
Under a 2015 law called Act 56 (formerly called bill H.40), the Vermont Legislature directed the Public Service Board to issue an order implementing the RES to take effect on January 1, 2017. Act 56 set certain rules for the RES, but left other issues to the Board. Following working group meetings, workshops, and opportunities for written comment, the Board adopted the RES by order dated June 28, 2016.
The RES sets targets for utility procurement of renewable energy, starting at 55% of the electricity sold to customers from renewable sources in 2017, increasing gradually to 75% in 2032. Of these amounts, at least 1% must come from new, distributed renewable generators, such as net-metering systems, rising to l0% by 2032.
The RES also establishes a category of "energy transformation projects," to encourage utility investment in projects that directly reduce customers' fossil-fuel consumption. Energy transformation projects might include measures like weatherization, biomass heating, cold-climate heat pumps, demand management, or clean vehicle technologies. To satisfy this requirement, utilities must demonstrate fossil-fuel savings equivalent to 2% of their annual retail sales (increasing to 12% by 2032) or procure an equal amount of additional renewable generation. The Board has described the energy transformation project program as the first of its kind in the U.S.
Most states have adopted binding renewable portfolio standards for electricity supply. Before the enactment of Act 56 and the Board's adoption of the RES, Vermont had renewable goals under its Sustainably Priced Energy Enterprise Development or SPEED program, but no mandatory renewable portfolio standard.
Under the act, the Vermont Public Service Board order adopting the RES will take effect on January 1, 2017.
Under a 2015 law called Act 56 (formerly called bill H.40), the Vermont Legislature directed the Public Service Board to issue an order implementing the RES to take effect on January 1, 2017. Act 56 set certain rules for the RES, but left other issues to the Board. Following working group meetings, workshops, and opportunities for written comment, the Board adopted the RES by order dated June 28, 2016.
The RES sets targets for utility procurement of renewable energy, starting at 55% of the electricity sold to customers from renewable sources in 2017, increasing gradually to 75% in 2032. Of these amounts, at least 1% must come from new, distributed renewable generators, such as net-metering systems, rising to l0% by 2032.
The RES also establishes a category of "energy transformation projects," to encourage utility investment in projects that directly reduce customers' fossil-fuel consumption. Energy transformation projects might include measures like weatherization, biomass heating, cold-climate heat pumps, demand management, or clean vehicle technologies. To satisfy this requirement, utilities must demonstrate fossil-fuel savings equivalent to 2% of their annual retail sales (increasing to 12% by 2032) or procure an equal amount of additional renewable generation. The Board has described the energy transformation project program as the first of its kind in the U.S.
Most states have adopted binding renewable portfolio standards for electricity supply. Before the enactment of Act 56 and the Board's adoption of the RES, Vermont had renewable goals under its Sustainably Priced Energy Enterprise Development or SPEED program, but no mandatory renewable portfolio standard.
Under the act, the Vermont Public Service Board order adopting the RES will take effect on January 1, 2017.
Massachusetts develops next solar incentive
Wednesday, August 24, 2016
The Massachusetts Department of Energy Resources (DOER) is designing a new solar incentive program to encourage the continued development of solar renewable energy
generating sources by residential, commercial, governmental and
industrial electricity customers, based on a state law enacted this spring. The so-called "next solar initiative" program could affect the pace of solar photovoltaic project development in Massachusetts, as policymakers seek a smooth transition from the current SREC II program as it reaches full capacity.
On April 11, 2016, Governor Charlie Baker signed into law An Act Relative to Solar Energy, also known as Chapter 75 of the Acts of 2016. The law preserved and expanded net metering, preserving the value of that policy for projects developed by residential, small commercial, municipal and government customers.
As described by the Baker administration, the law also allows DOER and the Department of Public Utilities to "gradually transition the solar industry to a more self-sustaining model." In particular, section 11 of the act directed DOER to "develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers throughout the commonwealth."
The law prescribed twelve requisite characteristics of the solar incentive program, but left the creation of rules and regulations to DOER. Some criteria are process-oriented, such as that the program "promotes the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers," or considers underlying system costs, environmental benefits, energy demand reduction and other avoided costs provided by solar renewable energy generating facilities.
Other criteria define structural requirements for the program, such as that it "relies on market-based mechanisms or price signals as much as possible to set incentive levels," "differentiates incentive levels to support diverse installation types and sizes that provide unique benefits," and "features a known or easily estimated budget to achieve program goals through use of a declining adjustable block incentive, a competitive procurement model, tariff or other declining incentive framework." The law also requires the program to promote investor confidence through long-term incentive revenue certainty and market stability.
After the solar bill's enactment, DOER held two public listening sessions, and solicited comments on the development of the "next solar incentive" through June 30, 2016. Many commenters expressed support for a continuation of the SREC framework, such as "SREC III." Other comments focused on locational issues, such as proposing policies to deter the development of projects located on farmland or other undeveloped "greenfield" sites.
DOER is expected to release a first draft of its next solar incentive program this summer.
On April 11, 2016, Governor Charlie Baker signed into law An Act Relative to Solar Energy, also known as Chapter 75 of the Acts of 2016. The law preserved and expanded net metering, preserving the value of that policy for projects developed by residential, small commercial, municipal and government customers.
As described by the Baker administration, the law also allows DOER and the Department of Public Utilities to "gradually transition the solar industry to a more self-sustaining model." In particular, section 11 of the act directed DOER to "develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers throughout the commonwealth."
The law prescribed twelve requisite characteristics of the solar incentive program, but left the creation of rules and regulations to DOER. Some criteria are process-oriented, such as that the program "promotes the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers," or considers underlying system costs, environmental benefits, energy demand reduction and other avoided costs provided by solar renewable energy generating facilities.
Other criteria define structural requirements for the program, such as that it "relies on market-based mechanisms or price signals as much as possible to set incentive levels," "differentiates incentive levels to support diverse installation types and sizes that provide unique benefits," and "features a known or easily estimated budget to achieve program goals through use of a declining adjustable block incentive, a competitive procurement model, tariff or other declining incentive framework." The law also requires the program to promote investor confidence through long-term incentive revenue certainty and market stability.
After the solar bill's enactment, DOER held two public listening sessions, and solicited comments on the development of the "next solar incentive" through June 30, 2016. Many commenters expressed support for a continuation of the SREC framework, such as "SREC III." Other comments focused on locational issues, such as proposing policies to deter the development of projects located on farmland or other undeveloped "greenfield" sites.
DOER is expected to release a first draft of its next solar incentive program this summer.
DesertLink transmission project wins rate incentives under Section 219
Tuesday, August 23, 2016
Federal energy regulators have granted a petition by the developer of a proposed electric transmission project in Nevada for certain transmission rate incentives available under federal law. On August 19, the Federal Energy Regulatory Commission ruled on DesertLink, LLC's petition for declaratory order, with respect to DesertLink's new Harry Allen to Eldorado 500 kV transmission project. The order grants DesertLink's requests for transmission rate incentives under section 219 of the Federal Power Act, and illustrates how those incentives operate.
DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation. CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects. The project is designed to have an in-service date of May 2020.
Rate incentives can be available to promote capital investments in certain transmission infrastructure. The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce. Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments. The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.
Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.” Order No. 679 established a rebuttable presumption that this standard is met if:
In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).
Last week, the Commission granted DesertLink's petition. First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.
Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink. The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project. On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs. Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies." The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.
The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates. As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA." In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment. Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.
DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation. CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects. The project is designed to have an in-service date of May 2020.
Rate incentives can be available to promote capital investments in certain transmission infrastructure. The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce. Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments. The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.
Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.” Order No. 679 established a rebuttable presumption that this standard is met if:
(1) the transmission project results from a fair and open regional planning process that considers and evaluates the project for reliability and/or congestion and is found to be acceptable to the Commission; or (2) a project has received construction approval from an appropriate state commission or state siting authority.Order No. 679 also requires an applicant to demonstrate that there is a nexus between the incentive being sought and the investment being made. The Commission clarified in Order No. 679-A that this "nexus test" is met when an applicant demonstrates, on a project-specific basis, that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant.”
In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).
Last week, the Commission granted DesertLink's petition. First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.
Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink. The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project. On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs. Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies." The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.
The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates. As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA." In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment. Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.
New Jersey FERC license surrender and dam removal
Monday, August 15, 2016
U.S. energy regulators have accepted an application to surrender the licensee for a New Jersey hydropower project. Earlier this month, the Federal Energy Regulatory Commission accepted Great Bear Hydropower Inc.'s application to surrender its license for the Columbia Dam Project, located on the Paulins Kill. While the Commission decision to accept license surrender does not necessarily mean the dam will be removed, it represents a significant step toward letting the dam owner pursue dam removal if it wishes. The case also illustrates tensions between hydropower development and dam removal, which remain active in U.S. policy discussions, and the consequences of state jurisdiction following FERC license surrender.
On January 15, 1986, the Commission issued a 40-year license for the construction, operation, and maintenance of hydroelectric facilities at the existing Columbia Dam. The project includes a 20-foot-high, 330-foot-long concrete dam, originally built by a utility in 1909. The site was sold to the state in 1955, after which the original electric generation was discontinued. Following the project's 1986 licensing by FERC, the licensee added a powerhouse containing two generating units with a total installed generating capacity of 530 kilowatts.
The dam remains owned by the state of New Jersey as part of the Columbia Wildlife Management Area, and the licensee has been operating the project under a long-term lease with the state. But significant efforts are under way to improve water quality in the Delaware River basin. The Nature Conservancy has described a strategy for watershed restoration that features the Columbia Dam's removal as a key component. After the state and The Nature Conservancy entered into an agreement to remove the dam, the licensee ultimately agreed to surrender its license and remove only its hydroelectric facilities originally added to the dam, leaving the state to perform any future dam removal.
Because the Columbia Dam Project is subject to Part 1 of the Federal Power Act, its license could not be surrendered without approval of the Federal Energy Regulatory Commission. The licensee applied for surrender in October 2015. The Commission granted that approval on August 10, 2016.
The FERC license surrender does not necessarily mean that the dam itself will be removed, although it does provide for decommissioning of the hydropower equipment. The Commission accepted the licensee's proposal to remove the generating equipment, transformers from the powerhouse, and disconnect the electric connection to the local utility. The license surrender will not be effective until the Commission agrees that the project’s facilities have been decommissioned in accordance with this surrender order.
As for the dam, the Commission noted, "It will be up to the state of New Jersey, the dam owner, to decide whether to remove the Columbia Dam, once the hydroelectric facilities have been decommissioned. Dam removal would have some ecological, social, and economic benefits for the Paulins Kill watershed." Following the effectiveness of license surrender, safety matters would primarily be state jurisdictional, and any dam removal would proceed primarily under state law.
While hydropower continues to play a significant role in the overall U.S. energy mix, with new and ongoing federal initiatives to increase hydropower generation, in some cases economics and environmental considerations may lead to the surrender of some project licenses. This may be particularly true for some relatively small dams with fish passage issues facing relicensing in coming years.
On January 15, 1986, the Commission issued a 40-year license for the construction, operation, and maintenance of hydroelectric facilities at the existing Columbia Dam. The project includes a 20-foot-high, 330-foot-long concrete dam, originally built by a utility in 1909. The site was sold to the state in 1955, after which the original electric generation was discontinued. Following the project's 1986 licensing by FERC, the licensee added a powerhouse containing two generating units with a total installed generating capacity of 530 kilowatts.
The dam remains owned by the state of New Jersey as part of the Columbia Wildlife Management Area, and the licensee has been operating the project under a long-term lease with the state. But significant efforts are under way to improve water quality in the Delaware River basin. The Nature Conservancy has described a strategy for watershed restoration that features the Columbia Dam's removal as a key component. After the state and The Nature Conservancy entered into an agreement to remove the dam, the licensee ultimately agreed to surrender its license and remove only its hydroelectric facilities originally added to the dam, leaving the state to perform any future dam removal.
Because the Columbia Dam Project is subject to Part 1 of the Federal Power Act, its license could not be surrendered without approval of the Federal Energy Regulatory Commission. The licensee applied for surrender in October 2015. The Commission granted that approval on August 10, 2016.
The FERC license surrender does not necessarily mean that the dam itself will be removed, although it does provide for decommissioning of the hydropower equipment. The Commission accepted the licensee's proposal to remove the generating equipment, transformers from the powerhouse, and disconnect the electric connection to the local utility. The license surrender will not be effective until the Commission agrees that the project’s facilities have been decommissioned in accordance with this surrender order.
As for the dam, the Commission noted, "It will be up to the state of New Jersey, the dam owner, to decide whether to remove the Columbia Dam, once the hydroelectric facilities have been decommissioned. Dam removal would have some ecological, social, and economic benefits for the Paulins Kill watershed." Following the effectiveness of license surrender, safety matters would primarily be state jurisdictional, and any dam removal would proceed primarily under state law.
While hydropower continues to play a significant role in the overall U.S. energy mix, with new and ongoing federal initiatives to increase hydropower generation, in some cases economics and environmental considerations may lead to the surrender of some project licenses. This may be particularly true for some relatively small dams with fish passage issues facing relicensing in coming years.
NEPA guidance on greenhouse gas emissions
Thursday, August 11, 2016
Federal agencies have new guidance on how to address the effects of greenhouse gas emissions and climate change as
those agencies satisfy their duties under the National Environmental
Policy Act. This month the White House Council on Environmental Quality or CEQ issued its Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews. The document is designed to improve clarity and consistency in how federal agencies address climate change in the environmental impact assessment process under NEPA.
Enacted in 1970, NEPA generally requires agencies to consider the environmental effects of proposed agency actions, and to provide the public and decision makers with useful information regarding reasonable alternatives and mitigation measures. To coordinate federal environmental efforts, NEPA also established CEQ within the Executive Office of the President. CEQ is now charged with issuing mandatory regulations for NEPA implementation, as well as guidance documents such as the recent greenhouse gas guidance.
In its final greenhouse gas guidance, CEQ described climate change as "a fundamental environmental issue" whose effects fall squarely within NEPA's purview. In CEQ's words, "Analyzing a proposed action’s GHG emissions and the effects of climate change relevant to a proposed action — particularly how climate change may change an action’s environmental effects — can provide useful information to decision makers and the public." CEQ views focused and effective consideration of climate change in NEPA reviews as enabling higher quality agency decisions.
To this end, CEQ offered guidance that:
In one sense, the final guidance is just guidance. As CEQ noted, agencies have discretion in how they tailor their individual NEPA reviews to accommodate the guidance. CEQ directed that agencies should apply this guidance to all new proposed agency actions as of the initiation of NEPA review. It suggested that agencies "should exercise judgment" when considering the application of the guidance to an on-going NEPA process, but that CEQ does not expect agencies to apply the guidance to concluded NEPA reviews, nor to any actions for which a final Environmental Impact Statement (EIS) or Environmental Assessment (EA) has been issued.
CEQ recommended that agencies review their NEPA procedures and propose any updates they deem necessary or appropriate to facilitate their consideration of greenhouse gas emissions and climate change. Agency procedures to implement NEPA may be in the form of regulations, although they are not required to take that form. CEQ's final guidance on greenhouse gas emissions may lead other federal agencies to revise regulations, policies, or implementing procedures to ensure full compliance with NEPA.
Enacted in 1970, NEPA generally requires agencies to consider the environmental effects of proposed agency actions, and to provide the public and decision makers with useful information regarding reasonable alternatives and mitigation measures. To coordinate federal environmental efforts, NEPA also established CEQ within the Executive Office of the President. CEQ is now charged with issuing mandatory regulations for NEPA implementation, as well as guidance documents such as the recent greenhouse gas guidance.
In its final greenhouse gas guidance, CEQ described climate change as "a fundamental environmental issue" whose effects fall squarely within NEPA's purview. In CEQ's words, "Analyzing a proposed action’s GHG emissions and the effects of climate change relevant to a proposed action — particularly how climate change may change an action’s environmental effects — can provide useful information to decision makers and the public." CEQ views focused and effective consideration of climate change in NEPA reviews as enabling higher quality agency decisions.
To this end, CEQ offered guidance that:
when addressing climate change agencies should consider: (1) The potential effects of a proposed action on climate change as indicated by assessing GHG emissions (e.g., to include, where applicable, carbon sequestration); and, (2) The effects of climate change on a proposed action and its environmental impacts.The guidance presents further information and interpretation on each of these points. For example, it recommends that agencies quantify the direct and indirect greenhouse gas emission resulting from a proposed agency action, as well as both short- and long-term adverse and beneficial effects. The guidance also stated that "a NEPA review should consider an action in the context of the future state of the environment."
In one sense, the final guidance is just guidance. As CEQ noted, agencies have discretion in how they tailor their individual NEPA reviews to accommodate the guidance. CEQ directed that agencies should apply this guidance to all new proposed agency actions as of the initiation of NEPA review. It suggested that agencies "should exercise judgment" when considering the application of the guidance to an on-going NEPA process, but that CEQ does not expect agencies to apply the guidance to concluded NEPA reviews, nor to any actions for which a final Environmental Impact Statement (EIS) or Environmental Assessment (EA) has been issued.
CEQ recommended that agencies review their NEPA procedures and propose any updates they deem necessary or appropriate to facilitate their consideration of greenhouse gas emissions and climate change. Agency procedures to implement NEPA may be in the form of regulations, although they are not required to take that form. CEQ's final guidance on greenhouse gas emissions may lead other federal agencies to revise regulations, policies, or implementing procedures to ensure full compliance with NEPA.
DOE Hydropower Vision report
Tuesday, August 9, 2016
The U.S. Department of Energy (DOE) has released a report on the future of domestic hydropower. Its Hydropower Vision finds that U.S. hydropower could grow from 101 gigawatts of capacity in 2015 to nearly 150 gigawatts by 2050. More than 50% of this growth could be realized by 2030, according to the report. Much of the new capacity would come from pumped storage, with the remainder coming from upgrades to existing plants, adding power at existing dams and canals, and "limited development of new stream-reaches."
DOE's Wind and Water Power Technologies Office describes its report, Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source, as presenting "a first-of-its-kind comprehen sive analysis to evaluate future pathways for low-carbon, renewable hydropower (hydropower generation and pumped storage) in the United States, focused on continued technical evolution, increased energy market value, and environmental sustainability." While it does not evaluate or recommend new policy actions, the report does analyze the "feasbility and certain benefits and costs of various credible scenarios, all of which could inform policy decisions at the federal, state, tribal, and local levels."
The report's Executive Summary presents an overview of the report, and its three "pillars" or foundational principles developed in collaboration with stakeholders: optimizing the value and power generation contribution of the existing hydropower fleet, exploring the feasibility of "credible long-term deployment scenarios for responsible growth of hydropower capacity and energy production," and sustainability. Analyzing data and modeled scenarios, the report found that "under a credible modeled scenario in which technology advancement lowers capital and operating costs, innovative market mechanisms increase revenue and lower financing costs, and a combination of environmental considerations are taken into account—U.S. hydropower including PSH could grow from 101 GW of capacity in 2015 to 150 GW by 2050."
Chapter 1 of the Hydropower Vision describes how technical resource assessments and computational models can be used to interpret hydropower's future market potential. It also evaluates potential innovations or nontraditional approaches to technology and project development that could affect the future development of new hydropower projects.
Chapter 2 of the Hydropower Vision presents a snapshot of the state of the U.S. hydropower industry as of year-end 2015, from the Energy Department's perspective. It notes that hydropower generation and pumped storage have "provided a stable and consistently low-cost energy source throughout decades of fluctuations and fundamental shifts in the electric sector, supporting development of the U.S. power grid and the nation’s industrial growth in the 20th century and into the 21st century." The report points to 2015 data showing 2,198 active hydropower plants in the U.S. with a total capacity of 79.6 gigawatts, plus 42 pumped storage hydro plants totaling another 21.6 gigawatts. In 2015, hydropower provided about 6.2% of net U.S. electricity generation, and 48% of all U.S. renewable power.
Chapter 3 of the report explores over 50 possible future scenarios for the hydropower industry, to assess the nation's hydropower potential. It presents an extensive body of analysis, considering potential contributions over time to the electric sector of both the existing hydropower fleet and new hydropower deployment resulting from: upgrades at existing plants, powering of non-powered dams (NPD), pumped storage hydropower (PSH), and new stream-reach development (NSD). It found that the greatest influence on potential growth scenarios comes from 3 variables: technological innovation, environmental considerations, and financial improvement.
The report's fourth chapter lays out a roadmap of 64 potential actions for stakeholder consideration, "to optimize hydropower’s continued contribution to a clean, reliable, low-carbon, domestic energy generation portfolio while ensuring that the nation’s natural resources are adequately protected or conserved." These actions are organized around 5 topical areas: technology advancement, sustainable development and operation, enhanced revenue and market structures, regulatory process optimization, and enhanced collaboration, education, and outreach.
As noted by the Energy Department, while utility-scale battery storage projects are starting to be developed, most U.S. electricity storage capacity takes the form of pumped storage. Flexible and reliable generating or storage resources can support efforts to integrate increasing amounts of intermittent renewable energy sources, like wind and solar, into the grid.
DOE's Wind and Water Power Technologies Office describes its report, Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source, as presenting "a first-of-its-kind comprehen sive analysis to evaluate future pathways for low-carbon, renewable hydropower (hydropower generation and pumped storage) in the United States, focused on continued technical evolution, increased energy market value, and environmental sustainability." While it does not evaluate or recommend new policy actions, the report does analyze the "feasbility and certain benefits and costs of various credible scenarios, all of which could inform policy decisions at the federal, state, tribal, and local levels."
The report's Executive Summary presents an overview of the report, and its three "pillars" or foundational principles developed in collaboration with stakeholders: optimizing the value and power generation contribution of the existing hydropower fleet, exploring the feasibility of "credible long-term deployment scenarios for responsible growth of hydropower capacity and energy production," and sustainability. Analyzing data and modeled scenarios, the report found that "under a credible modeled scenario in which technology advancement lowers capital and operating costs, innovative market mechanisms increase revenue and lower financing costs, and a combination of environmental considerations are taken into account—U.S. hydropower including PSH could grow from 101 GW of capacity in 2015 to 150 GW by 2050."
Chapter 1 of the Hydropower Vision describes how technical resource assessments and computational models can be used to interpret hydropower's future market potential. It also evaluates potential innovations or nontraditional approaches to technology and project development that could affect the future development of new hydropower projects.
Chapter 2 of the Hydropower Vision presents a snapshot of the state of the U.S. hydropower industry as of year-end 2015, from the Energy Department's perspective. It notes that hydropower generation and pumped storage have "provided a stable and consistently low-cost energy source throughout decades of fluctuations and fundamental shifts in the electric sector, supporting development of the U.S. power grid and the nation’s industrial growth in the 20th century and into the 21st century." The report points to 2015 data showing 2,198 active hydropower plants in the U.S. with a total capacity of 79.6 gigawatts, plus 42 pumped storage hydro plants totaling another 21.6 gigawatts. In 2015, hydropower provided about 6.2% of net U.S. electricity generation, and 48% of all U.S. renewable power.
Chapter 3 of the report explores over 50 possible future scenarios for the hydropower industry, to assess the nation's hydropower potential. It presents an extensive body of analysis, considering potential contributions over time to the electric sector of both the existing hydropower fleet and new hydropower deployment resulting from: upgrades at existing plants, powering of non-powered dams (NPD), pumped storage hydropower (PSH), and new stream-reach development (NSD). It found that the greatest influence on potential growth scenarios comes from 3 variables: technological innovation, environmental considerations, and financial improvement.
The report's fourth chapter lays out a roadmap of 64 potential actions for stakeholder consideration, "to optimize hydropower’s continued contribution to a clean, reliable, low-carbon, domestic energy generation portfolio while ensuring that the nation’s natural resources are adequately protected or conserved." These actions are organized around 5 topical areas: technology advancement, sustainable development and operation, enhanced revenue and market structures, regulatory process optimization, and enhanced collaboration, education, and outreach.
As noted by the Energy Department, while utility-scale battery storage projects are starting to be developed, most U.S. electricity storage capacity takes the form of pumped storage. Flexible and reliable generating or storage resources can support efforts to integrate increasing amounts of intermittent renewable energy sources, like wind and solar, into the grid.
NH adopts Energy Efficiency Resource Standard
Friday, August 5, 2016
The New Hampshire Public Utilities Commission has approved a settlement agreement that establishes a statewide Energy Efficiency Resource Standard. The Commission described the EERS as "a framework within which the
Commission’s energy efficiency programs shall be implemented," effective January
1, 2018.
Historically, most of the Commission's energy efficiency work has been through New Hampshire's so-called Core programs, with savings goals set more based on how much funding is available than on overall savings potential. But pressure has been mounting for change. Studies have shown that "additional opportunities for cost-effective energy efficiency exist beyond those attained through the Core program." In 2014, the Governor's Office of Energy Planning's 10-year State Energy Strategy called for an EERS "aimed at achieving all cost effective efficiency over a reasonable time frame."
Last year, the Commission opened a case to establish a policy that sets specific targets or goals for energy savings, which utility companies serving New Hampshire ratepayers must meet. The Commission described the creation of an EERS as "an opportunity to set savings goals based on savings potential in addition to consideration of the funding level." Following proposals by Commission staff, utilities, and advocates for sustainable energy and environmental goals, negotiations to resolve the case developed into an April 2016 settlement agreement.
On August 2, 2016, the New Hampshire Public Utilities Commission issued its Order No. 25,932, approving the EERS settlement agreement. That order establishes a long-term goal of achieving all cost-effective energy efficiency, and a framework consisting of three-year planning periods and savings goals. Initial EERS programs will be administered by electric and gas utilities. Specific programs will be subject to Commission approval, and must be shown to be cost effective. The Commission also established a recovery mechanism to compensate the utilities for lost revenue related to the EERS programs.
For the first triennium of the EERS, the Commission adopted savings goals as a percentage of 2014 statewide delivered sales, intended to reach overall cumulative savings by 2020 of 3.1% of electric sales and 2.25% of gas sales, relative to the 2014 baseline year. The existing Core program will also continue through next year; statewide savings goals for the "2017 Core-extension" will be 0.6% of 2014 statewide delivered sales for electric and 0.66% for gas.
The Commission noted that while all customers may face small short-term rate increases to recover the cost of an EERS, "customer bills will decrease when their energy consumption decreases as well as when the impact of consumption decreases are reflected in reduced grid and power procurement costs."
Historically, most of the Commission's energy efficiency work has been through New Hampshire's so-called Core programs, with savings goals set more based on how much funding is available than on overall savings potential. But pressure has been mounting for change. Studies have shown that "additional opportunities for cost-effective energy efficiency exist beyond those attained through the Core program." In 2014, the Governor's Office of Energy Planning's 10-year State Energy Strategy called for an EERS "aimed at achieving all cost effective efficiency over a reasonable time frame."
Last year, the Commission opened a case to establish a policy that sets specific targets or goals for energy savings, which utility companies serving New Hampshire ratepayers must meet. The Commission described the creation of an EERS as "an opportunity to set savings goals based on savings potential in addition to consideration of the funding level." Following proposals by Commission staff, utilities, and advocates for sustainable energy and environmental goals, negotiations to resolve the case developed into an April 2016 settlement agreement.
On August 2, 2016, the New Hampshire Public Utilities Commission issued its Order No. 25,932, approving the EERS settlement agreement. That order establishes a long-term goal of achieving all cost-effective energy efficiency, and a framework consisting of three-year planning periods and savings goals. Initial EERS programs will be administered by electric and gas utilities. Specific programs will be subject to Commission approval, and must be shown to be cost effective. The Commission also established a recovery mechanism to compensate the utilities for lost revenue related to the EERS programs.
For the first triennium of the EERS, the Commission adopted savings goals as a percentage of 2014 statewide delivered sales, intended to reach overall cumulative savings by 2020 of 3.1% of electric sales and 2.25% of gas sales, relative to the 2014 baseline year. The existing Core program will also continue through next year; statewide savings goals for the "2017 Core-extension" will be 0.6% of 2014 statewide delivered sales for electric and 0.66% for gas.
The Commission noted that while all customers may face small short-term rate increases to recover the cost of an EERS, "customer bills will decrease when their energy consumption decreases as well as when the impact of consumption decreases are reflected in reduced grid and power procurement costs."
FERC declares QF rights
Thursday, August 4, 2016
Federal energy regulators have issued an advisory opinion regarding the rights of Qualifying Facility electric generators to sell power to their local utility under the Public Utility Regulatory Policies Act (PURPA). The Federal Energy Regulatory Commission's declaratory ruling illustrates how the Commission interprets PURPA and QF rights, in the context of state renewable energy portfolio standards and
PURPA was enacted by Congress in 1978 to promote goals including energy conservation and greater production of domestic and renewable energy. It established a new class of generating facilities called QFs, to receive special rate and regulatory treatment. A chief benefit of QF status is the
right to sell energy and capacity to a utility, usually at either at the utility's avoided cost or at a negotiated rate. By regulation, QFs generally have the option to sell energy either "as-available," or as part of a long-term contract or other legally enforceable obligation for delivery of energy or capacity over a specified term.
The Federal Energy Regulatory Commission oversees this program, although state energy commissions play important roles. Section 210 (H)(2)(A) and (B) of PURPA give the Commission discretionary power to enforce its PURPA rules, including the power to require state commissions and non-regulated utilities to comply. But the Commission may also decline to initiate an enforcement action, on a case by case basis.
Earlier this year, a group of QFs filed a complaint to the Commission against the Connecticut Public Utilities Regulatory Authority. Windham Solar LLC and Allco Finance Limited alleged that Connecticut law and PURA’s regulations violate the Commission's PURPA regulations regarding an electric utility’s mandatory purchase obligation and a QF’s ability to sell pursuant to a legally enforceable obligation. Complainants effectively alleged that they couldn’t get a long-term contract to sell energy and capacity at avoided cost rates on a forecasted basis, unless the energy and capacity were bundled with renewable energy certificates (RECs), or unless the energy and capacity were provided under a short-term contract not to exceed one year.
Some of those basic facts were contested by PURA and others, and the Commission noted a history of dispute and litigation among the complainants and Connecticut energy regulators. So the Commission declined to initiate an enforcement action on the complaint.
But the Commission did issue a declaratory ruling, reciting case law and interpretation on two points: the relationship between state RECs and PURPA, and QF opportunities to secure long-term contracts. The Commission noted that RECs exist under state law and not PURPA, but that avoided cost contracts do not automatically include RECs. It also noted that winning a competitive solicitation cannot be the only way a QF may be allowed to obtain long-term avoided cost rates.
The original comes with robust citations to precedent, omitted for convenience below:
PURPA was enacted by Congress in 1978 to promote goals including energy conservation and greater production of domestic and renewable energy. It established a new class of generating facilities called QFs, to receive special rate and regulatory treatment. A chief benefit of QF status is the
right to sell energy and capacity to a utility, usually at either at the utility's avoided cost or at a negotiated rate. By regulation, QFs generally have the option to sell energy either "as-available," or as part of a long-term contract or other legally enforceable obligation for delivery of energy or capacity over a specified term.
The Federal Energy Regulatory Commission oversees this program, although state energy commissions play important roles. Section 210 (H)(2)(A) and (B) of PURPA give the Commission discretionary power to enforce its PURPA rules, including the power to require state commissions and non-regulated utilities to comply. But the Commission may also decline to initiate an enforcement action, on a case by case basis.
Earlier this year, a group of QFs filed a complaint to the Commission against the Connecticut Public Utilities Regulatory Authority. Windham Solar LLC and Allco Finance Limited alleged that Connecticut law and PURA’s regulations violate the Commission's PURPA regulations regarding an electric utility’s mandatory purchase obligation and a QF’s ability to sell pursuant to a legally enforceable obligation. Complainants effectively alleged that they couldn’t get a long-term contract to sell energy and capacity at avoided cost rates on a forecasted basis, unless the energy and capacity were bundled with renewable energy certificates (RECs), or unless the energy and capacity were provided under a short-term contract not to exceed one year.
Some of those basic facts were contested by PURA and others, and the Commission noted a history of dispute and litigation among the complainants and Connecticut energy regulators. So the Commission declined to initiate an enforcement action on the complaint.
But the Commission did issue a declaratory ruling, reciting case law and interpretation on two points: the relationship between state RECs and PURPA, and QF opportunities to secure long-term contracts. The Commission noted that RECs exist under state law and not PURPA, but that avoided cost contracts do not automatically include RECs. It also noted that winning a competitive solicitation cannot be the only way a QF may be allowed to obtain long-term avoided cost rates.
The original comes with robust citations to precedent, omitted for convenience below:
4. The Commission has previously addressed issues regarding the relationship between state-created RECs and PURPA. The Commission has stated that the states have the authority to determine who owns RECs in the initial instance and how they are transferred, and has explained that the automatic transfer of RECs within a sale of power at wholesale must find its authority in state law, not PURPA. The Commission has also held, however, that a state regulatory authority may not assign ownership of RECs to utilities based on a logic that the avoided cost rates in PURPA contracts already compensate QFs for RECs in addition to compensating QFs for energy and capacity, because the avoided cost rates are, in fact, compensation just for energy and capacity. Moreover, while the Commission has made clear that states have the authority to regulate RECs, states cannot impede a QF’s ability to sell its output to an electric utility pursuant to PURPA. Thus, regardless of whether a QF has previously sold its RECs under a separate contract, that QF has the right to sell its output pursuant to a legally enforceable obligation.As noted in the declaratory ruling, the Commission's "decision not to initiate an enforcement action means that Petitioners may themselves bring an enforcement action against the Connecticut Authority in the appropriate court."
5. The Commission has also held that “requiring a QF to win a competitive solicitation as a condition to obtaining a long-term contract imposes an unreasonable obstacle to obtaining a legally enforceable obligation.” The Commission likewise has determined a state regulation to be inconsistent with PURPA and the Commission’s PURPA regulations “to the extent that it offers the competitive solicitation process as the only means by which a QF . . . can obtain long-term avoided cost rates.” Accordingly, regardless of whether a QF has participated in a request for proposal, that QF has the right to obtain a legally enforceable obligation.
NY Clean Energy Standard adopted
Wednesday, August 3, 2016
The New York Public Service Commission has issued an order adopting a clean energy standard. The standard will require 50% of New York’s electricity to be
generated by renewable sources by 2030. This so-called "50 by 30" mandate is consistent with the State Energy Plan's strategy to
reduce statewide greenhouse gas emissions by 40% by 2030. It will also provide support for existing nuclear power plants said to be at risk for closure without state support. This is a time of change for the New York energy industry, as the Clean Energy Standard adds to
the regulatory and retail market
changes that the state is already pursuing
under
its
Reforming the Energy Vision or REV program.
The New York commission noted that the state has adopted "strongly proactive policies to combat climate change and modernize the electric system to improve the efficiency, affordability, resiliency, and sustainability of the system." The state's 2015 State Energy Plan called for the "50 by 30" goal for renewable energy.
In the Commission's words, it determined "that a series of deliberate and mandatory actions to build upon and enhance opportunities for consumer choice are necessary to achieve State environmental, public health, climate policy and economic goals; to enhance and animate voluntary retail markets for energy efficiency, clean energy and renewable resources; to preserve existing zero-emissions nuclear generation resources as a bridge to the clean energy future; to ensure a modern and resilient energy system; and to accomplish its objectives in a fair and cost-effective manner."
As a result, the Commission adopted a Clean Energy Standard or CES consisting of a Renewable Energy Standard and a Zero-Emissions Credit Requirement program. The Commission also adopted supporting structures, which it describes as including:
The Clean Energy Standard order also creates a Zero-Emissions Credit or ZEC requirement, along with a process through which state energy agency NYSERDA will offer qualifying nuclear facilities a multi-year contract for the purchase of ZECs, at a price ultimately derived from the calculations of "social cost of carbon." NYSERDA will ultimately resell the ZECs to New York load serving entities, who will recover costs from ratepayers through commodity charges on customer bills. The Commission described the ZEC mechanism as "the best way for the State to preserve the nuclear units’ environmental attributes while staying within the State’s jurisdictional boundaries. "
As described in the order, the Renewable Energy Standard and ZEC components "are interrelated but the goals are additive," meaning efforts to comply with the RES will not count toward the ZEC requirement, even if the combination will "contribute toward the State's comprehensive greenhouse gas reduction goals."
The New York commission noted that the state has adopted "strongly proactive policies to combat climate change and modernize the electric system to improve the efficiency, affordability, resiliency, and sustainability of the system." The state's 2015 State Energy Plan called for the "50 by 30" goal for renewable energy.
In the Commission's words, it determined "that a series of deliberate and mandatory actions to build upon and enhance opportunities for consumer choice are necessary to achieve State environmental, public health, climate policy and economic goals; to enhance and animate voluntary retail markets for energy efficiency, clean energy and renewable resources; to preserve existing zero-emissions nuclear generation resources as a bridge to the clean energy future; to ensure a modern and resilient energy system; and to accomplish its objectives in a fair and cost-effective manner."
As a result, the Commission adopted a Clean Energy Standard or CES consisting of a Renewable Energy Standard and a Zero-Emissions Credit Requirement program. The Commission also adopted supporting structures, which it describes as including:
(a) program and market structures to encourage consumer-initiated clean energy purchases or investments; (b) obligations on load serving entities to financially support new renewable generation resources to serve their retail customers; (c) a requirement for regular renewable energy credit (REC) procurement solicitations; (d) obligations on distribution utilities on behalf of all retail customers to continue to financially support the maintenance of certain existing at-risk small hydro, wind and biomass generation attributes; (e) a program to maximize the value potential of new offshore wind resources; and (f) obligations on load serving entities to financially support the preservation of existing at- risk nuclear zero-emissions attributes to serve their retail customers.As described by Governor Andrew Cuomo, the program will feature a ramp-up of renewable power sourcing. Utilities and other energy suppliers will be initially required to procure 26.32 percent of the state's total electricity load from renewable sources in 2017, increasing to 30.54 percent by 2021. The Commission described the 50 by 30 goal as "not only part of a larger greenhouse gas goal, it is part of the State’s sweeping initiative to transform the way energy is produced, delivered, and consumed" through the REV process.
The Clean Energy Standard order also creates a Zero-Emissions Credit or ZEC requirement, along with a process through which state energy agency NYSERDA will offer qualifying nuclear facilities a multi-year contract for the purchase of ZECs, at a price ultimately derived from the calculations of "social cost of carbon." NYSERDA will ultimately resell the ZECs to New York load serving entities, who will recover costs from ratepayers through commodity charges on customer bills. The Commission described the ZEC mechanism as "the best way for the State to preserve the nuclear units’ environmental attributes while staying within the State’s jurisdictional boundaries. "
As described in the order, the Renewable Energy Standard and ZEC components "are interrelated but the goals are additive," meaning efforts to comply with the RES will not count toward the ZEC requirement, even if the combination will "contribute toward the State's comprehensive greenhouse gas reduction goals."
Offshore wind in Massachusetts energy bill
Tuesday, August 2, 2016
The Massachusetts legislature has enacted an energy bill that will require utilities to purchase offshore wind energy by 2027. The legislation, known as H. 4568, "An Act to promote energy diversity," has been laid before Governor Charlie Baker for signature.
Earlier this session, the Massachusetts House and Senate had passed two different bills calling for renewable energy procurement. A conference committee reported out the final bill, H. 4568, on July 31. Through the newly enacted law, the Massachusetts legislature has added a new program of offshore wind energy procurement.
The final enacted bill adds a new section 83C to the state's 2008 Green Communities Act. Among other provisions, section 83C provides, "In order to facilitate the financing of offshore wind energy generation resources in the commonwealth, not later than June 30, 2017, every distribution company shall jointly and competitively solicit proposals for offshore wind energy generation; and, provided, that reasonable proposals have been received, shall enter into cost-effective long-term contracts."
Much of the solicitation and contracting process will occur pursuant to regulations yet to be promulgated by the Department of Public Utilities. The law provides a framework for developing and approving the competitive bidding process, and requires the schedule to "ensure that the distribution companies enter into cost-effective long-term contracts for offshore wind energy generation equal to approximately 1,600 megawatts of aggregate nameplate capacity not later than June 30, 2027." Individual solicitations must be seek proposals for 400 megawatts or more, and may be conducted jointly with other states.
Proposed long-term contracts are subject to the review and approval of the Department of Public Utilities. The law requires the department of public utilities to weigh the potential costs and benefits of the proposed long-term contract, and directs it to approve a proposed long-term contract "if the department finds that the proposed contract is a cost-effective mechanism for procuring reliable renewable energy on a long-term basis," taking into account factors like reliability, mitigation of price volatility, cost-effectiveness, mitigation of environmental impacts, and economic development.
The law requires the implementing regulations to be adopted by the Department of Public Utilities to "provide for an annual remuneration for the contracting distribution company up to 2.75 per cent of the annual payments under the contract to compensate the company for accepting the financial obligation of the long-term contract." It also entitles distribution companies to cost recovery of payments made under an approved long-term contract. Utilities may elect to to use any energy purchased under such contracts for sale to its customers and retain renewable energy certificates for their use, or may sell the energy and RECs into the market. Any proceeds from such market re-sales will be netted against the cost of contract payments, resulting in a credit or charge to all distribution customers through a uniform fully reconciling annual factor in distribution rates.
The law also provides a variety of "outs" or circumstances under which contracts might not result, such as if a "proposal’s terms and conditions would require the contract obligation to place an unreasonable burden" on a distribution company’s balance sheet.
Notably, the law's definitions of “Offshore wind developer” and “Offshore wind energy generation” place a variety of restrictions on projects eligible for contracting. The definitions effectively require that projects be located on the Outer Continental Shelf, in a designated wind energy area for which an initial federal lease was issued on a competitive basis after January 1, 2012, have no turbine located within 10 miles of any inhabited area, and have a commercial operations date on or after January 1, 2018, that has been verified by the department of energy resources. This effectively limits projects to a subset of those winning recent (or future) federal Bureau of Ocean Energy Management lease auction sales.
To date, no commercial offshore wind projects operate in U.S. waters, although Deepwater Wind is currently constructing the Block Island Wind Farm off Rhode Island. Federal programs, along with some state incentives, are available to support qualifying offshore wind projects.
Earlier this session, the Massachusetts House and Senate had passed two different bills calling for renewable energy procurement. A conference committee reported out the final bill, H. 4568, on July 31. Through the newly enacted law, the Massachusetts legislature has added a new program of offshore wind energy procurement.
The final enacted bill adds a new section 83C to the state's 2008 Green Communities Act. Among other provisions, section 83C provides, "In order to facilitate the financing of offshore wind energy generation resources in the commonwealth, not later than June 30, 2017, every distribution company shall jointly and competitively solicit proposals for offshore wind energy generation; and, provided, that reasonable proposals have been received, shall enter into cost-effective long-term contracts."
Much of the solicitation and contracting process will occur pursuant to regulations yet to be promulgated by the Department of Public Utilities. The law provides a framework for developing and approving the competitive bidding process, and requires the schedule to "ensure that the distribution companies enter into cost-effective long-term contracts for offshore wind energy generation equal to approximately 1,600 megawatts of aggregate nameplate capacity not later than June 30, 2027." Individual solicitations must be seek proposals for 400 megawatts or more, and may be conducted jointly with other states.
Proposed long-term contracts are subject to the review and approval of the Department of Public Utilities. The law requires the department of public utilities to weigh the potential costs and benefits of the proposed long-term contract, and directs it to approve a proposed long-term contract "if the department finds that the proposed contract is a cost-effective mechanism for procuring reliable renewable energy on a long-term basis," taking into account factors like reliability, mitigation of price volatility, cost-effectiveness, mitigation of environmental impacts, and economic development.
The law requires the implementing regulations to be adopted by the Department of Public Utilities to "provide for an annual remuneration for the contracting distribution company up to 2.75 per cent of the annual payments under the contract to compensate the company for accepting the financial obligation of the long-term contract." It also entitles distribution companies to cost recovery of payments made under an approved long-term contract. Utilities may elect to to use any energy purchased under such contracts for sale to its customers and retain renewable energy certificates for their use, or may sell the energy and RECs into the market. Any proceeds from such market re-sales will be netted against the cost of contract payments, resulting in a credit or charge to all distribution customers through a uniform fully reconciling annual factor in distribution rates.
The law also provides a variety of "outs" or circumstances under which contracts might not result, such as if a "proposal’s terms and conditions would require the contract obligation to place an unreasonable burden" on a distribution company’s balance sheet.
Notably, the law's definitions of “Offshore wind developer” and “Offshore wind energy generation” place a variety of restrictions on projects eligible for contracting. The definitions effectively require that projects be located on the Outer Continental Shelf, in a designated wind energy area for which an initial federal lease was issued on a competitive basis after January 1, 2012, have no turbine located within 10 miles of any inhabited area, and have a commercial operations date on or after January 1, 2018, that has been verified by the department of energy resources. This effectively limits projects to a subset of those winning recent (or future) federal Bureau of Ocean Energy Management lease auction sales.
To date, no commercial offshore wind projects operate in U.S. waters, although Deepwater Wind is currently constructing the Block Island Wind Farm off Rhode Island. Federal programs, along with some state incentives, are available to support qualifying offshore wind projects.
Maine biomass commission first meeting
Monday, August 1, 2016
A special commission formed by the Maine Legislature to study the economic, environmental and energy benefits of the state's biomass industry holds its first meeting this week.
This spring, the Maine legislature enacted a resolve establishing the Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry. Known as Resolve 2015, chapter 85, the legislation established a study commission to examine the state's biomass energy resources, as well as public policy and economic proposals to create and maintain a sustainable future for the industry.
The Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry holds its first meeting tomorrow. According to the agenda published for the first meeting, following introductions and a review of the resolve itself, the group will hear presentations from and hold discussion with a variety of people interested in biomass. Presenters on the agenda include a Commissioner of the Maine Public Utilities Commission, the state's Public Advocate, and the executive director of the Efficiency Maine Trust. Other speakers represent loggers, the wood pellet fuel industry, users of biomass energy fuels, the pulp and paper industry, and woodlot owners. The agenda states that the meeting will also include a public comment period.
According to the agenda, possible future meeting dates for the Maine biomass commission include August 16 and August 30, 2016.
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| The Maine State House, where the 2016 biomass resolve was enacted. |
This spring, the Maine legislature enacted a resolve establishing the Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry. Known as Resolve 2015, chapter 85, the legislation established a study commission to examine the state's biomass energy resources, as well as public policy and economic proposals to create and maintain a sustainable future for the industry.
The Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry holds its first meeting tomorrow. According to the agenda published for the first meeting, following introductions and a review of the resolve itself, the group will hear presentations from and hold discussion with a variety of people interested in biomass. Presenters on the agenda include a Commissioner of the Maine Public Utilities Commission, the state's Public Advocate, and the executive director of the Efficiency Maine Trust. Other speakers represent loggers, the wood pellet fuel industry, users of biomass energy fuels, the pulp and paper industry, and woodlot owners. The agenda states that the meeting will also include a public comment period.
According to the agenda, possible future meeting dates for the Maine biomass commission include August 16 and August 30, 2016.
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