An interstate natural gas pipeline system bringing gas from eastern Canada into Maine has asked U.S. regulators for approvals necessary for a project that would marginally increase the system's capacity to bring gas to Maine and the New England market.
At issue is Portland Natural Gas Transmission System (PNGTS), a pipeline that
spans New England from the Canadian border to pipeline connections in
New Hampshire, Maine, and Massachusetts. Its facilities include 142 miles of wholly-owned mainline from an interconnection with Trans-Québec & Maritimes Pipeline Inc. at the U.S./Canada border to Westbrook, Maine plus two laterals, as well as 101 miles of mainline from Westbrook to Dracut, Massachusets, which PNGTS owns jointly with another interstate pipeline, Maritimes & Northeast Pipeline, L.L.C. PNGTS operates pursuant to a number of federal approvals, including a certificate issued by the Federal Energy Regulatory Commission and a Presidential Permit authorizing its facilities for importing gas from (or exporting gas to) Canada.
On December 21, PNGTS applied to the Commission for authorization for Phase I its "Westbrook Xpress Project," which would increase the certificated capacity on the northern portion of its system from Pittsburg, New Hampshire, to Westbrook, Maine, by 42.482 million cubic feet per day (MMcf/d), effective November 1, 2019. The pipeline's application includes both public materials and materials that are protected against public disclosure as "controlled unclassified information", including privileged information and "critical energy infrastructure information."
In the public materials, PNGTS describes continued increased demand for natural gas: "Growing demand for natural gas for space heating, industrial processes and electric generation is driving a commensurate demand for incremental pipeline deliverability from abundant North American supply basins." PNGTS says its Westbrook XPress project "will provide access to, and allow for the transportation of, natural gas supplies from key North American supply basins such as Marcellus, Utica, and others" via Canadian pipelines. The company describes its Westbrook Xpress project is "a solution to meet this growing demand in areas of North America that have some of the highest residential gas prices in the winter." It envisions two distinct phases of the project: Phase I with an incremental 42.482 million cubic feet per day of certificated capacity, with an anticipated Phase II to bring an incremental 62.989 million cubic feet per day of capacity.
The Commission has docketed PNGTS's application for Phase I of the Westbrook XPress project as Docket No. CP19-32, and has issued public notice of the opportunity to intervene or comment through 5:00 pm Eastern Time on January 29, 2019.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Showing posts with label interstate. Show all posts
Showing posts with label interstate. Show all posts
FERC holds CO microhydro needs license
Wednesday, February 24, 2016
In an order issued earlier this month, the Federal Energy Regulatory Commission found that the developer of a micro-hydropower project proposed in Colorado must obtain a license for the Patton Colorado Hydropower Project's construction, maintenance, and operation. The order illustrates one challenge facing small, distributed hydroelectric projects in the U.S.: a federal regulatory process that at times can treat microhydro projects much like traditional large dams, despite interest in a streamlined permitting process for small projects.
At issue is Section 23(b) of the Federal Power Act. It provides that any person intending to construct project works on a non-navigable commerce clause water must file a declaration of their intention to do so with the Commission. Section 23(b) further provides that upon the filing of a Declaration of Intent, the Commission will investigate the proposed project, and, if it finds that the “interests of interstate or foreign commerce would be affected” by the proposed project, then the person intending to construct the project must obtain a Commission license before starting construction.
Under section 23(b)(1) of the Federal Power Act, 16 U.S.C. § 817(1), a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:
In the case of the Patton Colorado Hydropower Project, the Commission found that licensure is required under the fourth prong of Section 23(b)(1) of the Federal Power Act, which itself has three components.
First, the Commission found that the Patton project would be located on a "Commerce Clause stream." Specifically, the Commission found that Colombine Creek is a headwater or tributary of the South Fork of the Rio Grande, which is a tributary of the Rio Grande River, a navigable water of the United States. Under a 1965 Supreme Court precedent, for purposes of FPA section 23(b)(1), the headwaters and tributaries of navigable rivers are Commerce Clause streams.
Second, the project would be constructed after August 26, 1935.
Third, citing a 1992 opinion from the 11th Circuit Court of Appeals, the Commission noted, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of the FPA section 23(b)(1)." Thus the Commission concluded that the Patton Colorado Hydropower Project would affect interstate commerce through its connection to the interstate grid.
Based on these conclusions, the Commission found that in accordance with section 23(b)(1) of the Federal Power Act, the applicant must obtain a license for the construction, maintenance, and operation of the Patton Colorado Hydropower Project. The Commission also ruled that no construction or operation of the project may commence until a license has been obtained.
Notably, the Commission was able to reach this conclusion without making a navigability finding for Colombine Creek itself. In particular, the order notes "insufficient evidence to determine whether Colombine Creek is navigable." But because the Commission found licensing to be required on other grounds -- grounds derived from the ultimate navigability of a downstream river -- it did not make a navigability finding for the river reach where the project would be located.
The Commission's order did suggest that an easier path may be available for the Patton Colorado Hydropower Project. In particular, the order notes that the project may be eligible for an exemption from licensing. It suggests that the applicant consider applying for a small hydroelectric power project exemption of 10 megawatts (MW) or less. This more limited approval could enable project development and operation through a more streamlined regulatory processes than that required for a full project license.
Incentives and policy support for microhydro projects are growing. But as the Patton Colorado Hydropower Project case before the FERC illustrates, even small hydropower projects may be subject to federal regulation. For some projects, an exemption may be available, but others may not be able to be developed without a FERC license. Even an exemption can take time and expense to secure, and it can be hard to preduct the outcome of an application for an exemption. How does this dynamic affect the rate of development of U.S. micro-hydropower projects?
At issue is Section 23(b) of the Federal Power Act. It provides that any person intending to construct project works on a non-navigable commerce clause water must file a declaration of their intention to do so with the Commission. Section 23(b) further provides that upon the filing of a Declaration of Intent, the Commission will investigate the proposed project, and, if it finds that the “interests of interstate or foreign commerce would be affected” by the proposed project, then the person intending to construct the project must obtain a Commission license before starting construction.
Under section 23(b)(1) of the Federal Power Act, 16 U.S.C. § 817(1), a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:
(a) is located on a navigable water of the United States;On May 11, 2015, as supplemented on November 10, 2015, Steve Patton filed a Declaration of Intention with the Commission concerning the proposed Patton Colorado Hydropower Project. The project would be located on Colombine Creek, a feeder stream to the South Fork of the Rio Grande, near the town of South Fork, Mineral County, Colorado. It would consist of an intake and pipes feeding a gravitation water vortex-type generating unit rated between 2 and 10 kilowatts with 2.5 feet of head, transmission line, and appurtenant facilities. The proposed project would be connected to the interstate electric grid.
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.
In the case of the Patton Colorado Hydropower Project, the Commission found that licensure is required under the fourth prong of Section 23(b)(1) of the Federal Power Act, which itself has three components.
First, the Commission found that the Patton project would be located on a "Commerce Clause stream." Specifically, the Commission found that Colombine Creek is a headwater or tributary of the South Fork of the Rio Grande, which is a tributary of the Rio Grande River, a navigable water of the United States. Under a 1965 Supreme Court precedent, for purposes of FPA section 23(b)(1), the headwaters and tributaries of navigable rivers are Commerce Clause streams.
Second, the project would be constructed after August 26, 1935.
Third, citing a 1992 opinion from the 11th Circuit Court of Appeals, the Commission noted, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of the FPA section 23(b)(1)." Thus the Commission concluded that the Patton Colorado Hydropower Project would affect interstate commerce through its connection to the interstate grid.
Based on these conclusions, the Commission found that in accordance with section 23(b)(1) of the Federal Power Act, the applicant must obtain a license for the construction, maintenance, and operation of the Patton Colorado Hydropower Project. The Commission also ruled that no construction or operation of the project may commence until a license has been obtained.
Notably, the Commission was able to reach this conclusion without making a navigability finding for Colombine Creek itself. In particular, the order notes "insufficient evidence to determine whether Colombine Creek is navigable." But because the Commission found licensing to be required on other grounds -- grounds derived from the ultimate navigability of a downstream river -- it did not make a navigability finding for the river reach where the project would be located.
The Commission's order did suggest that an easier path may be available for the Patton Colorado Hydropower Project. In particular, the order notes that the project may be eligible for an exemption from licensing. It suggests that the applicant consider applying for a small hydroelectric power project exemption of 10 megawatts (MW) or less. This more limited approval could enable project development and operation through a more streamlined regulatory processes than that required for a full project license.
Incentives and policy support for microhydro projects are growing. But as the Patton Colorado Hydropower Project case before the FERC illustrates, even small hydropower projects may be subject to federal regulation. For some projects, an exemption may be available, but others may not be able to be developed without a FERC license. Even an exemption can take time and expense to secure, and it can be hard to preduct the outcome of an application for an exemption. How does this dynamic affect the rate of development of U.S. micro-hydropower projects?
Court ruling cuts demand response uncertainty
Tuesday, January 26, 2016
Yesterday the U.S. Supreme Court issued an opinion upholding federal regulation of the compensation paid for wholesale electricity demand response. The Court's opinion, FERC v. Electric Power Supply Assn., hinges on the distinction between wholesale and retail sales of electricity. It provides the latest look at the boundary between federal and state jurisdiction over the electric grid.
Under the Federal Power Act, the Federal Energy Regulatory Commission is authorized to regulate "the sale of electric energy at wholesale in interstate commerce." Its jurisdiction under the Federal Power Act does not extend to "any other sale of electric energy," such as a retail sale. Traditionally, sales of energy directly to users are viewed as retail sales subject to state ratemaking jurisdiction, while sales of energy for resale are viewed as wholesale sales subject to federal ratemaking jurisdiction.
The case before the Supreme Court arose from a challenge by a group of generators to FERC Order No. 745. Through that order, FERC adopted a rule requiring wholesale market operators to compensate cost-effective demand response resources for their performance at the same price paid to generators. Last year, the D.C. Circuit Court of Appeals vacated FERC Order No. 745 on the ground that FERC lacked jurisdiction to set rates for this kind of demand response. The D.C. Circuit implied that "wholesale" demand response was really retail in nature and thus subject only to state ratemaking jurisdiction. FERC appealed this decision to the Supreme Court.
As described in the Supreme Court opinion, the appeal presented two legal issues:
The case now returns to the D.C. Circuit for further proceedings consistent with the Supreme Court's opinion. The most widespread direct impact of the Supreme Court in FERC v. EPSA will likely be a reduction to the uncertainty that has hung over the markets since the D.C. Circuit decision. Market participants, consumers, aggregators, and grid operators have all been awaiting the ruling. Some market changes, such as ISO New England's implementation of full integration of demand response, had been delayed pending a decision from the Court, as regional wholesale demand response programs hinge on FERC approvals under the Federal Power Act. With the jurisdictional question resolved, these changes, and other refinements to regional transmission organizations' wholesale demand response programs, can now get back on track.
Under the Federal Power Act, the Federal Energy Regulatory Commission is authorized to regulate "the sale of electric energy at wholesale in interstate commerce." Its jurisdiction under the Federal Power Act does not extend to "any other sale of electric energy," such as a retail sale. Traditionally, sales of energy directly to users are viewed as retail sales subject to state ratemaking jurisdiction, while sales of energy for resale are viewed as wholesale sales subject to federal ratemaking jurisdiction.
The case before the Supreme Court arose from a challenge by a group of generators to FERC Order No. 745. Through that order, FERC adopted a rule requiring wholesale market operators to compensate cost-effective demand response resources for their performance at the same price paid to generators. Last year, the D.C. Circuit Court of Appeals vacated FERC Order No. 745 on the ground that FERC lacked jurisdiction to set rates for this kind of demand response. The D.C. Circuit implied that "wholesale" demand response was really retail in nature and thus subject only to state ratemaking jurisdiction. FERC appealed this decision to the Supreme Court.
As described in the Supreme Court opinion, the appeal presented two legal issues:
First, and fundamentally, does the FPA permit FERC to regulate these demand response transactions at all, or does any such rule impinge on the States’ authority? Second, even if FERC has the requisite statutory power, did the Commission fail to justify adequately why demand response providers and electricity producers should receive the same compensation? The court below ruled against FERC on both scores. We disagree.In analyzing the first issue, the majority found that compensation for demand response directly affects wholesale prices -- "Indeed, it is hard to think of a practice that does so more." The majority found, "A FERC regulation does not run afoul of section 824(b)’s prescription just because it affects―even substantially―the quantity or terms of retail sales." The Court finally noted that FERC had offered substantial reasoning and arguments in support of its conclusion that demand response should be paid comparably to generation, and thus that FERC's actions satisfied the applicable standard that they not be "arbitrary and capricious."
The case now returns to the D.C. Circuit for further proceedings consistent with the Supreme Court's opinion. The most widespread direct impact of the Supreme Court in FERC v. EPSA will likely be a reduction to the uncertainty that has hung over the markets since the D.C. Circuit decision. Market participants, consumers, aggregators, and grid operators have all been awaiting the ruling. Some market changes, such as ISO New England's implementation of full integration of demand response, had been delayed pending a decision from the Court, as regional wholesale demand response programs hinge on FERC approvals under the Federal Power Act. With the jurisdictional question resolved, these changes, and other refinements to regional transmission organizations' wholesale demand response programs, can now get back on track.
Utilities plan over $51.1 billion in transmission development
Tuesday, March 5, 2013
Growth in renewable electricity production will drive significant upgrades to the U.S. electric transmission grid, according to a study released by the Edison Electric Institute. EEI's seventh annual "Transmission Projects: At a Glance" identifies over 150 transmission projects planned by EEI member utilities for development over the next decade. According to the report, these projects entail investments of at least $51.1 billion through 2023. While the transmission projects may advance multiple goals, the majority of the projected investments will be for projects supporting the integration of renewable resources into the grid.
EEI is a trade association composed of investor-owned electric utilities. Its members represent approximately 70 percent of the U.S. electric power industry. EEI tracks transmission investment by its members. According to the report, annual transmission investment is increasing, from 11.1 billion in 2011 to approximately $15.1 billion in 2013. At the same time, EEI has revised its total future projection downward. In 2012, EEI members reported $64 billion in planned transmission over the next decade, but changing projections of system needs have revised that number downward to $51.1 billion.
Under federal laws including the Energy Policy Act of 2005, utilities are given incentives to develop transmission lines and related assets. These incentives are designed to ensuring a safe and reliable electric grid, but also reward utilities for developing projects to integrate renewable resources like wind farms into the grid. Because ratepayers ultimately bear the cost of transmission infrastructure, the Federal Energy Regulatory Commission and state public utilities commission regulate utility proposals to expand the grid.
According to EEI, most proposed transmission projects advance multiple goals. The study shows that 76% of projects (approximately $38.7 billion) are pitched as supporting the integration of renewable resources. In the aggregate, these projects entail the addition or upgrade of 13,300 miles of transmission lines. Similarly, most projects are designed to enable electricity to flow across state lines; 52% ($26.5 billion) represent large interstate transmission projects spanning multiple states.
Whether each project identified in the EEI report will be built remains to be seen. As demand for electricity shifts -- whether due to energy efficiency improvements, a declining economy, or newly proposed generating projects -- the need for any given transmission line may diminish. For example, last year the $2 billion Potomac Appalachian Transmission Highline (PATH) project was canceled after it was deemed unnecessary. The proposed Northern Pass transmission project connecting Quebec to New Hampshire is facing significant opposition due to the siting of its planned route, as well as on environmental and economic grounds. Nevertheless, the significant transmission development projected by EEI remains likely to occur in the aggregate.
EEI is a trade association composed of investor-owned electric utilities. Its members represent approximately 70 percent of the U.S. electric power industry. EEI tracks transmission investment by its members. According to the report, annual transmission investment is increasing, from 11.1 billion in 2011 to approximately $15.1 billion in 2013. At the same time, EEI has revised its total future projection downward. In 2012, EEI members reported $64 billion in planned transmission over the next decade, but changing projections of system needs have revised that number downward to $51.1 billion.
Under federal laws including the Energy Policy Act of 2005, utilities are given incentives to develop transmission lines and related assets. These incentives are designed to ensuring a safe and reliable electric grid, but also reward utilities for developing projects to integrate renewable resources like wind farms into the grid. Because ratepayers ultimately bear the cost of transmission infrastructure, the Federal Energy Regulatory Commission and state public utilities commission regulate utility proposals to expand the grid.
According to EEI, most proposed transmission projects advance multiple goals. The study shows that 76% of projects (approximately $38.7 billion) are pitched as supporting the integration of renewable resources. In the aggregate, these projects entail the addition or upgrade of 13,300 miles of transmission lines. Similarly, most projects are designed to enable electricity to flow across state lines; 52% ($26.5 billion) represent large interstate transmission projects spanning multiple states.
Whether each project identified in the EEI report will be built remains to be seen. As demand for electricity shifts -- whether due to energy efficiency improvements, a declining economy, or newly proposed generating projects -- the need for any given transmission line may diminish. For example, last year the $2 billion Potomac Appalachian Transmission Highline (PATH) project was canceled after it was deemed unnecessary. The proposed Northern Pass transmission project connecting Quebec to New Hampshire is facing significant opposition due to the siting of its planned route, as well as on environmental and economic grounds. Nevertheless, the significant transmission development projected by EEI remains likely to occur in the aggregate.
Subscribe to:
Posts (Atom)
