The Department of Energy on Thursday issued the final environmental impact statement for the New England Clean Power Link, recommending approval of a presidential permit for the cross-border project, which would transmit 1,000 MW of Canadian hydropower into New England.
The 154-mile, $1.2 billion HVDC project was proposed in early 2014. The final report includes changes made in response to comments on the department’s draft EIS in June. (See Lake Champlain Cable into New England Progresses.)
Among the changes were updated technical information; alternatives included in the U.S. Army Corp of Engineers 404 permit; additions to water resource analyses requested by the Environmental Protection Agency; and details on the project construction period and impacts on the long-eared bat and wetlands.
The merchant line, which would be entirely underwater or underground, is still undergoing permitting review by Vermont.
Transmission Developers Inc. New England, a unit of The Blackstone Group, anticipates that all major federal and state permits will be granted by the end of the year and the project would be in service in 2019. Ninety-eight miles of the cable would be buried under Lake Champlain, and most of its land-based route would be underground to Ludlow, Vt.
TD-NE began an open solicitation on Oct. 15 for customers to buy capacity on the line, with expressions of interest due by Dec. 4.
“We are confident that, once built, the New England Clean Power Link will deliver environmental and economic benefits to the people of Vermont and New England and do so in a way that minimizes impacts to communities and helps meet the region’s growing energy and environmental challenges,” TDI-NE CEO Donald Jessome said in a statement.
The Northern Pass line, which would deliver 1,090 MW to New England from Canada, has an agreement between its U.S. sponsor, Eversource Energy, and Hydro-Quebec. That $1.6 billion project has generated much more controversy because most of it is above ground. It also is not as far along in the regulatory process as the Clean Power Link. (See Northern Pass Files for Siting Approval, Revises Cost.)
FERC staff has concluded that a 13.5-mile natural gas pipeline expansion to serve increased demand in Connecticut will have “no significant” environmental impact.
The Connecticut Expansion Project, proposed in July 2014 by Tennessee Gas Pipeline, will provide an additional 72.1 million cubic feet per day of firm transportation service to three shippers: Connecticut Natural Gas, Southern Connecticut Gas and Yankee Gas Services.
Public comments on FERC’s environmental assessment of the project are due Nov. 23 (CP14-529).
Tennessee Gas said that gas delivered into its system has increased by 32% over the past four years, with lines serving the state nearing capacity. “Tennessee states that it is only through the expansion of its existing infrastructure that it would be able to deliver the incremental volumes requested by the project shippers in binding precedent agreements, while maintaining service to existing shippers and pressure profiles necessary for system operations,” FERC’s report states.
The demand is being driven by increased gas use in electric generation and heating. The 2013 Connecticut Comprehensive Energy Strategy proposed the addition of 300,000 natural gas heating customers among homes and businesses, most of them switching from fuel oil.
The environmental assessment rejected allegations that Tennessee Gas attempted to reduce the level of environmental scrutiny by improperly separating the Connecticut project from the Northeast Energy Direct Project, which is intended to increase supply throughout New England. (See New England Governors Revise Energy Strategy.)
“The proposed project would function independently from the NED Project,” staff wrote. “… The projects have different purposes [and] different start and end points.”
The Connecticut project, which will predominately use existing rights-of-way, includes:
4 miles of new 36-inch-diameter pipeline loop near the Town of Bethlehem, in Albany County, N.Y.;
8 miles of 36-inch-diameter pipeline loop near the Town of Sandisfield, in Berkshire County, Mass.; and
3 miles of 24-inch-diameter pipeline loop near the Town of Agawam, in Hampden County, Mass., and the Towns of Suffield and East Granby in Hartford County, Conn.
The project also includes modifications to a compressor station in Massachusetts and other facility improvements.
Construction could start this year if approvals are granted, with an in-service date of Nov. 1, 2016, Tennessee Gas said.
The developer of a multistate pipeline project to move natural gas from the Marcellus shale region through New England asked FERC on Tuesday to start a process to expedite its formal application.
Spectra Energy’s Algonquin Gas Transmission asked FERC to grant permission for the pre-filing review on the proposed Access Northeast project by Nov. 13 (PF16-1).
Source: Spectra Energy
The company expects to file a formal application in about a year and hopes to put the first phase of the project in service by November 2018.
“Algonquin is seeking authorization to use the pre-filing review process to provide the necessary environmental information to commission staff for review at the earliest practicable time in order to expedite the processing of Algonquin’s certificate application,” the filing states.
Developers say the $3 billion Access Northeast project will allow direct pipeline interconnections for 60% of ISO-NE’s gas-fired power plants. Proponents say that will save the region’s ratepayers $1 billion annually in lower electricity costs.
Access Northeast will have capacity to deliver up to 925,000 dekatherms/day, enough to supply 5,000 MW of generation, the company says. Algonquin says more than 95% of Access Northeast will use existing pipeline and utility rights of way.
The line will be able to accommodate new power plants being sited on Algonquin, or nearly 2,750 MW of additional generation that has been publicly announced or cleared the ISO-NE capacity auctions, according to the company.
The project is being developed by a consortium of Spectra Algonquin Holdings, Eversource Energy and National Grid. In addition, Central Maine Power submitted a bid to secure firm transportation service during the pipeline’s open season earlier this year.
“Access Northeast will provide true ‘last mile’ supply access for 5,000 MW of generation from the approximately 12,000 MW of gas-fired generation currently attached — or expected to be attached over the next five years — to Algonquin and Maritimes & Northeast pipeline systems,” Bill Yardley, Spectra Energy Partners’ president of U.S. transmission and storage, said in a statement. “That is firm capacity directly to the generator during the coldest days. Without the last mile capacity, New England’s electric reliability concerns related to gas power plants will remain unresolved.”
Pipeline plans have generated controversy as some state regulators have endorsed a regional plan to have funding come from electricity customers. (See Massachusetts Regulators Endorse Pipeline Contracts.)
FERC has again denied a rehearing request by Public Citizen over the results of ISO-NE’s eighth Forward Capacity Auction (EL14-99, ER15-117).
The consumer group had challenged a previous order that accepted the results for the 2017/18 capacity commitment period, arguing that capacity from the Brayton Point facility in Massachusetts had been withheld to drive up prices. In accepting the results of the February 2014 auction and dismissing the Public Citizen challenge last December, FERC opened a section 206 proceeding on the appropriate treatment of imports and establishing review and mitigation procedures for import capacity. (See FERC OKs Tightened ISO-NE Screening on Capacity Imports.)
FERC said in its Oct. 28 order that Public Citizen inappropriately tried to expand the import capacity proceeding with an unrelated matter. “The commission previously stated that there was no evidence that the owners of Brayton Point engaged in any inappropriate behavior in FCA 8, and Public Citizen has provided no argument or evidence that causes us to reconsider this finding,” it wrote.
The commission accepted Tariff revisions filed by the RTO intended to address FERC’s concern that future auctions with small surpluses might not protect customers against the exercise of market power by import resources.
BOSTON — The Northeast may be further along than most regions in meeting the Environmental Protection Agency’s new carbon emission rules, but it also faces challenges, speakers at Infocast’s 2nd Annual Northeast Energy Summit agreed. About 60 people attended the conference Oct. 27-28.
As part of the Regional Greenhouse Gas Initiative, New York and the New England states are already doing much of what EPA’s Clean Power Plan requires.
Although the region will need to add electric transmission and gas pipelines to serve the change from coal to gas that’s already occurred, “I don’t see a big change resulting from the Clean Power Plan against business as usual,” said Ann Weeks, legal director for the Clean Air Task Force. She predicted New England will be a net exporter of carbon allowances under the EPA rule. (See Northeast on Way to Compliance with Clean Power Plan.)
But the region’s public policies and energy markets aren’t always aligned, said others.
While the region has long supported renewables, the closure of two nuclear plants adds more pressure to further develop clean and cost-effective resources, said Jon Norman, vice president of commercial development for Brookfield Renewable Energy, a Canadian firm that primarily owns hydropower resources. Entergy recently announced it will close both its Pilgrim nuclear plant in Massachusetts and its FitzPatrick plant in New York.
“We need to continue to push that ball forward in the wake of losing that non-emitting generation,” Norman said.
“The Northeastern markets for investors in renewable generation are not on the whole a very friendly environment, compared to others,” added James Guidera, North America managing director of energy and infrastructure for Credit Agricole.
Wind developers in the Midwest and West have benefited from the certainty of long-term power purchase agreements that have “a dramatic impact on promoting projects,” he said.
With cheap natural gas increasingly setting marginal prices, energy markets in the Northeast “do not really recover the cost of renewable energy,” he added. Renewable portfolio standards, meanwhile, provide “subsidies that don’t provide enough [money] to encourage investment.”
One attempt to address New England’s challenges is a multi-state clean energy procurement process, which seeks to bring economic scale to projects that might not be viable for individual states. (See New England States Combine on Clean Energy Procurement.)
“We now know with experience in New England that without long-term contracts, even the renewable portfolio standard and the volatile spot market for renewable energy credits is not sufficient to make those investments happen,” said Judy Chang, principal at The Brattle Group.
But that does risk sustainable development of the clean energy market, she cautioned. “We don’t want everything under long-term contract because that takes away price signals for the investment community.”
Regional or statewide policy mandates also can run headlong into local concerns, said Michael Voltz, director of energy efficiency and renewables for PSEG Long Island, which runs the power system for the publicly owned Long Island Power Authority.
Next year, PSEG Long Island will develop an integrated resource plan, which will require it to balance the constituencies of clean energy proponents, who would like more solar and wind power, against those of consumer advocates, who may prefer cheaper new natural gas generators.
“The other constituency is the local school district or tax body because there are town and school officials receiving fairly significant tax revenue from old antiquated natural-gas fired power plants that we don’t feel we need anymore,” Voltz said. “But shutting them down is not an easy thing to do politically.”
Market-to-market (M2M) operations between SPP and MISO continue to show improvement, with the two RTOs on track for their second-lowest exchange of funds since the process began in March.
M2M is designed to improve price convergence on flowgates along the RTOs’ seams. They compensate each other for re-dispatching generation to reduce congestion in a way that reduces overall costs.
(Click to zoom.)
SPP staff told the Seams Steering Committee on Nov. 5 that through Oct. 20, SPP is set to receive more than $102,000 for 504 hours in M2M during the month’s first three weeks. Since MISO compensated SPP for congestion costs with almost $7.9 million for March to May, neither RTO has incurred more than $379,000 in a month (see chart).
However, SPP’s Gerardo Ugalde said October’s M2M results will likely need to be recalculated. He said the Western Area Power Administration’s addition to SPP’s footprint Oct. 1 and several allocation changes led to errors in the M2M calculations.
SPP and MISO representatives are meeting this week to discuss whether M2M’s objectives are being met on some of the more troublesome flowgates, along with other issues.
“SPP and MISO agree on most of the principles, so now we’re to the point of developing criteria for those principles and discussing whether to apply that criteria going back to prior periods or only going forward,” said David Kelley, SPP’s director of interregional relations.
The seams committee also reviewed and made additional language changes to the Congestion Management Process baseline, which guides how SPP, MISO, PJM and several other entities manage market flows across their seams. The document is expected to be filed with FERC by Dec. 1, ending a year-long project.
“The idea is to get the parties to agree to a single baseline,” Kelley said.
The U.S. Department of Energy released its final environmental impact statement (EIS) for the Plains & Eastern Clean Line transmission project Nov. 4, clearing a major hurdle for the proposed $2 billion project.
The department said in the final EIS that it “did not identify widespread significant impacts as a result of construction or operations and maintenance of the project.”
However, Arkansas’ Congressional delegation urged Energy Secretary Ernest Moniz to delay a decision on the project until concerns they outlined in a Sept. 14 letter are addressed. Among those concerns are possible infringements on private property rights and the exclusion of MISO and SPP from control of the line.
“We are very concerned that you have not provided a thorough written response, and we need to meet with you at your earliest convenience,” the delegation — Sens. John Boozman and Tom Cotton, and Reps. Rick Crawford, French Hill, Steve Womack and Bruce Westerman — told Moniz. “The department should not have issued the [final EIS] before responding to our Sept. 14 letter.”
Transmission developer Clean Line Energy Partners said it expects a “record of decision” later this year that will determine whether and how the department will participate in the project. If approved, the department would act through the Southwestern Power Administration (SPA), a federal agency that markets hydroelectric power from 24 dams in six states.
The Plains & Eastern project stems from the Energy Department’s 2010 request for proposals for transmission projects under Section 1222 of the Energy Policy Act of 2005. Section 1222 authorizes the SPA to participate in “designing, developing, constructing, operating, maintaining or owning” new transmission in the states in which Southwestern operates, Oklahoma, Arkansas and Texas.
Environmental Endorsement
The Plains & Eastern would ship 4,000 MW of renewable energy from wind farms in the Oklahoma Panhandle through Arkansas and into Tennessee over 700 miles of HVDC transmission lines. It would interconnect with the Tennessee Valley Authority near Memphis, after dropping off 500 MW in a converter station in central Arkansas.
“The release of the final EIS marks the culmination of more than five years of work and the consideration of thousands of stakeholder comments,” said Clean Line President Michael Skelly in a statement.
Glen Hooks, director of the Arkansas Sierra Club, said the group endorses the Clean Line project because of its environmental and economic benefits. “This is a significant step toward ramping up clean wind energy in our region … and will also lead to the retirement of several dirty coal-fired power plants,” Hooks told RTO Insider.
Clean Line said the project will provide about $1 billion of private investment in Oklahoma. The Houston-based company also promised a direct investment of more than $100 million in Arkansas through the converter station near Russellville.
Conflict of Interest?
Despite that, the project has brought opposition from Arkansas landowners and government officials over the potential use of eminent domain.
A week before the Energy Department issued its final EIS, Cotton wrote to Moniz, accusing Clean Line of paying the salaries of department employees working on the statement.
“Clean Line representatives stated that they receive monthly invoices from DOE listing the names, roles and hours of DOE personnel working on their application,” Cotton wrote in his Oct. 27 letter. He claimed that Clean Line is paying the department between $10,000 and $1 million a month. “A process with consequences this serious should be conducted with integrity [and] transparency and free from blatant conflicts of interests.”
Clean Line responded that “there are many instances in which Congress has chosen to allow federal agencies to receive funds from private companies to enable the agencies to comprehensively review, assess and potentially to participate in a proposed project. The reasons for this approach are to ensure that the costs fall on the applicant and private sector, and that projects providing substantial public benefits can move forward without their costs being borne by the taxpayer.”
Meanwhile, Boozman and Womack are co-sponsoring a bill that would require the Energy Department to obtain approval from a governor, a state public service commission and any local tribal government before approving transmission projects and subsequent use of federal eminent domain. It also would require the projects to be placed on federal, rather than private, land whenever possible.
Boozman and Womack both spoke in support of the bill before a House subcommittee Oct. 28. Boozman said support for renewable energy projects “has been set back in Arkansas by a sense that a federal agency may force a transmission project for which there is no clear demand or demonstrated need.”
Clean Line said in a statement it “takes property rights very seriously” and would only use condemnation “as a very last resort after all reasonable attempts at voluntary easement acquisition have been exhausted.” The company projects it will have to spend more than $30 million to Arkansas landowners, “well above the estimated fair market value of those easements.”
ISO-NE and the New England Power Pool (NEPOOL) bar the public and the press from virtually all of their stakeholder meetings. They are the only one of the seven regional electric grid operators in the U.S. to do so.
New England is unique in its hybrid structure. NEPOOL, created in 1971, has more than 440 members (about 260 voting members) including utilities, independent power producers, marketers, load aggregators, end users and demand resource providers. ISO-NE was formed in 1997 at NEPOOL’s suggestion — and with FERC’s approval — to administer the region’s Open Access Transmission Tariff. ISO-NE describes NEPOOL “an advisory body” to the RTO.
NEPOOL’s four principal committees — the Participants, Markets, Reliability and Transmission committees — met 76 times and took almost 300 votes in 2014, according to the organization’s annual report. None of the meetings were open to the public or press.
The only ISO-NE-hosted meetings that are open are the Consumer Liaison Group, which meets quarterly; the annual Regional System Plan public meeting; and the Planning Advisory Committee, which meets once or twice monthly.
“However, virtually every PAC meeting includes presentation and discussion of material that is classified as Critical Energy Infrastructure Information (CEII),” ISO-NE spokeswoman Marcia Blomberg told RTO Insider. “As you know, CEII materials can’t be discussed publicly, reported upon or distributed.”
No other region covered by RTO Insider considers planning committee materials CEII1. In fact, we have received their blessings to reproduce documents such as transmission project maps to illustrate our articles. (Blomberg said the RTO can provide some maps and other materials that don’t disclose CEII, with determinations made on a case-by-case basis.)
NEPOOL Secretary David T. Doot told RTO Insider that while his group’s meetings are not public, “all meeting materials, including agendas, supporting materials (to the extent they are not confidential), and notices of all actions taken by each committee,” are posted on the NEPOOL website. Doot said he is willing to answer reporters’ questions before or after the meetings.
Indeed, NEPOOL provides unusually detailed meeting minutes. Its account of the Sept. 11 Participants Committee, for example, ran more than 20 pages.
We’re not suggesting NEPOOL or ISO-NE has anything to hide. So why do anything that makes it look that way?
— Rich Heidorn Jr.
1 FERC defines Critical Energy Infrastructure Information in the Code of Federal Regulations:
(1) Critical energy infrastructure information means specific engineering, vulnerability, or detailed design information about proposed or existing critical infrastructure that:
(i) Relates details about the production, generation, transportation, transmission, or distribution of energy; (ii) Could be useful to a person in planning an attack on critical infrastructure; (iii) Is exempt from mandatory disclosure under the Freedom of Information Act, 5 U.S.C. 552; and (iv) Does not simply give the general location of the critical infrastructure.
(2) Critical infrastructure means existing and proposed systems and assets, whether physical or virtual, the incapacity or destruction of which would negatively affect security, economic security, public health or safety, or any combination of those matters.
WASHINGTON — The White House convened a “Summit on Nuclear Energy” on Friday as the industry’s main trade group sounded an alarm over Entergy’s decision to shut down its FitzPatrick reactor in New York, just weeks after announcing the closure of its Pilgrim plant in Massachusetts.
The session appeared to be an attempt by the Obama administration to make up with the industry, which was upset this summer that the final Clean Power Plan did not do more to help existing nuclear plants. But with no major policy pronouncements emerging from the session, it’s unclear exactly what the industry gained. The Environmental Protection Agency’s carbon emission rule will credit states for new nuclear plants. But states losing existing plants will have to do more to meet their emission targets without the retiring reactors.
According to the Nuclear Energy Institute, nuclear power generates 63% of the nation’s emission-free electricity.
“Alarmingly, over the past three years, four reactors vital to regional economies and clean air efforts have been shut down prematurely already or will be retired prematurely within the next few years,” NEI said in a statement before the summit, referring also to Entergy’s Vermont Yankee, shut in December, and Dominion Resources’ retirement of its Kewaunee plant in Wisconsin in 2013. (See related story, Entergy Closing FitzPatrick Nuclear Plant in New York.)
“If the United States is to substantially reduce carbon emissions, we cannot afford to prematurely close any more nuclear power plants because of flawed electricity markets,” NEI continued. “At the same time, new reactor construction — including development of small modular reactors and other advanced reactor technologies — should be pursued vigorously.”
The summit featured remarks by a number of federal officials, including NRC Chairman Stephen Burns and Janet McCabe, acting assistant administrator for EPA’s Office of Air and Radiation.
McCabe offered little encouragement, saying that while “nuclear power can be a very vigorous tool” in compliance with the CPP, the rule is “not all powerful.”
“We can’t alone change the trajectory” of nuclear power’s economic competitiveness, she said.
Merchant nuclear units have suffered in RTOs’ single-price clearing markets because of low-cost natural gas and wind.
In states that engage in regional emissions trading to comply with the CPP, nuclear units should see increased revenue reflecting their carbon-free generation. Reliable nuclear plants in PJM also should benefit from the RTO’s new Capacity Performance rules because of the security provided by their on-site fuel supplies.
Also speaking at the summit was David Christian, CEO of Dominion’s generation group, who said the company will ask NRC to approve a request for a second 20-year license extension for its 1,676-MW Surry generating plant. The two-unit plant’s current licenses expire in 2032 and 2033.
Burns said the agency is working with the Department of Energy to revise its regulatory framework, which is designed for light water reactors.
“We are confident we could license a non-light water reactor under the current framework. However, because the NRC’s reactor licensing regulations and guidance documents were developed based primarily on light water reactor technologies, we recognize the potential knowledge gaps for both the staff and prospective applicants,” he said.
NiSource on Tuesday reported third-quarter income from continuing operations of $14.8 million ($0.05/share), a reversal from the Merrillville, Ind., company’s 2014 third-quarter loss of $17.2 million (-$0.05/share).
NiSource CEO John Hamrock said results for the company’s first quarter as a “pure-play” utility were “solidly” in line with expectations and indicate that the company is primed for growth. On July 1, NiSource separated itself from Columbia Pipeline Group, distributing all of the NiSource-held common stock of CPG to NiSource shareholders.
The company said it continued to plan spending $1.3 billion on infrastructure improvements in 2015, part of its $30 billion long-term investment plan.
“During the quarter, we continued our disciplined execution of infrastructure and environmental investments complemented by regulatory initiatives, which are providing long-term safety and reliability and environmental benefits,” Hamrock said in a conference call.
Northern Indiana Public Service Co. filed its first electric rate case in five years on Oct. 1. A decision by the Indiana Utility Regulatory Commission is expected in the third quarter of 2016.
