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.”
In a 2007 article in the Energy Law Journal, Michael H. Dworkin and Rachel Aslin Goldwasser gave perhaps the definitive answer, describing RTOs as “larger than states but smaller than nations, [taking] a form that is between government and business, thus creating serious accountability problems.”
Dworkin
“Unlike governments, which must answer either directly to the electorate or to the people’s representatives, RTOs are not subject to elections or legislative confirmation processes,” they noted.
Their article suggests RTOs can be viewed through several lenses, “as agents of the FERC, as monopolists or private regulated entities, as ‘hybrid’ organizations, as similar to commodities trading markets, as agents of some of the market participants, and as planning processes.”
“Because confidence in the RTOs is vital to their success, stakeholders and members of the public needed to see them as independent actors dedicated to the public interest,” they write.
FERC gave much thought to the nature of RTOs in the rulemaking that led to Order 2000, which set minimum requirements for the organizations. FERC was concerned, they write, that “the potential for undue discrimination increases in a competitive environment unless the market can be made structurally efficient and transparent with respect to information and equitable in its treatment of competing participants.”
In the order, FERC noted that industrial consumers (the Electricity Consumers Resource Council, the American Iron & Steel Institute and the Chemical Manufacturers Association) had argued “that market participants must perform monitoring and, accordingly, an RTO’s operations should be fully transparent.”
The America Public Power Association told FERC in the rulemaking that the grid operators “still represent the interests of the transmission owners that formed” them. APPA said FERC should view RTOs as “regional monopolies that it must vigorously regulate, not regional extensions of the commission itself.”
Since the order, the authors noted, “there has been a chorus of questions regarding RTOs, their efficacy and their governance,” including reports by APPA and PJM stakeholders that argued that RTOs were not sufficiently accountable.
“The Energy Consumers Resource Council, a consortium of large industrial users, also produced a white paper questioning the ability of current RTO structures to provide real market solutions and claimed that ‘governing structures of the organized markets are skewed to benefit suppliers.’
“It is important to note,” the authors added, “that many of these ‘large consumer’ groups were originally supportive of restructuring and the RTOs.”
Dworkin, former chairman of the Vermont Public Service Board, is a professor and director of the Institute for Energy and the Environment at Vermont Law School.
Dworkin said yesterday that FERC “delegates great discretion to RTOs; and the RTOs’ exercise of that discretion is heavily influenced by the meetings of its stakeholders… The system would be far healthier if the people and businesses that will be affected can learn what was and wasn’t said about the issues that may well affect them.”
Goldwasser, a Vermont Law graduate, was a law clerk to a U.S. District Court judge in Maine when she co-authored the article. She is now executive director at the New England Conference of Public Utilities Commissioners (NECPUC). She declined to comment.
ERCOT released its final winter assessment Nov. 2, indicating it has more than sufficient generation to meet an anticipated peak demand of 57,400 MW. The Texas grid operator says it has more than 79,000 MW of generation resources available.
ERCOT’s final winter Seasonal Assessment of Resource Adequacy (SARA) focused on expected reliability scenarios for December through February. It reflects forecasted expectations based on customer demand experienced during recent cold-weather events and current expectations for average weather this winter.
Warren Lasher, ERCOT’s director of system planning, said the grid expects to meet winter demand “across a broad range of operating conditions and weather scenarios … even during high-load conditions with extreme generation outages.”
ERCOT’s senior meteorologist, Chris Coleman, told reporters during a conference call that he is forecasting wetter-than-normal conditions for December and January, based on an El Niño winter pattern that “has an opportunity to be the largest on record.” In Texas, he said, that will result in cloudy weather, leading to milder overnight temperatures and morning lows.
“If, as expected, El Niño backs off in intensity by February,” Coleman said, “we could see a late-season cold pattern that drives temperatures lower across the ERCOT region.”
In February 2011, severe cold weather and unexpected plant outages forced ERCOT to call for rolling blackouts. While the grid’s reserve margin has increased since then, ERCOT has also taken other steps to minimize a repeat occurrence.
“We’re more prepared for winter-weather issues than we have been in the past,” said ERCOT spokesperson Robbie Searcy. “We’ve been spending more time on site visits and working with generation owners on their winter plans.”
The grid has also added nearly 1,100 MW of resource capacity from mostly wind projects since its preliminary winter SARA, issued in September. (See ERCOT Expects Sufficient Generation for Fall, Winter.) It said several units previously in seasonal-mothball status have returned to service and several new resources have become operational.
ERCOT last week also released its preliminary SARA for next spring, based on average springtime weather conditions over the past 13 years. The study’s results indicate the grid will also have sufficient installed capacity to meet forecasted peak demands during March-May 2016.
The grid operator estimates 1 MW of demand is typically enough to power about 500 homes during mild weather conditions and about 200 homes during summer peak demand.
FERC last week told the North American Electric Reliability Corp. to provide additional detail on its new risk-based approach to reliability compliance monitoring and enforcement.
The commission had approved NERC’s Reliability Assurance Initiative in February, saying it would allow regulators to focus resources on the most serious issues. FERC told NERC to revise its rules of procedure to define the RAI concepts and programs and provide details on NERC’s planned oversight of the program. (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.)
In its Nov. 4 order (RR15-2), the commission told NERC to provide additional information on the program in its annual reports, including:
performance assessments of Regional Entities under the program;
an analysis of self-logging data provided by REs “to measure the quality and consistency of self-logging across regions”; and
the types of “data driven” metrics it will track.
FERC also ordered NERC to eliminate “regulator trust” as a “success factor” in its analyses. “The notion of ‘regulator trust’ is a subjective concept that is not conducive to quantitative measurement,” the commission said. The commission also ordered revisions to the rules of procedures to set data retention requirements for self-logging data.
Commissioner Cheryl LaFleur issued a concurring statement cautioning FERC against micromanaging NERC.
“The RAI program grew out of a well-documented concern … that NERC and the Regional Entities’ reliability work was unsustainably bogged down in paperwork on relatively minor issues, which detracted from our collective ability to focus on more significant reliability matters. Going forward, I believe we must be careful not to require, as part of our ongoing oversight, the type of overly prescriptive and time-consuming analysis that the RAI program was designed to avoid,” she said.
“FERC and NERC should focus our attention on significant issues before us like cybersecurity, geomagnetic disturbances and adapting the electric grid to changes in the resource mix. We should also stay focused on the risk-based prioritization that led us to approve RAI, and not require NERC to repeatedly justify that program.”
WEC Energy Group on Wednesday reported net income of $182.5 million ($0.58/share) for the third quarter, its first reporting period since Wisconsin Energy acquired Integrys to form WEC Energy on June 29. Wisconsin Energy’s stand-alone earnings, excluding acquisition costs, totaled $0.61/share for the period, up from $0.57/share a year ago.
Revenue for the third quarter totaled $1.7 billion, with Wisconsin Energy contributing $1.07 billion and Integrys delivering $630 million.
“I’m very pleased with our post-acquisition work, and we remain highly confident that the merger will deliver tangible benefits,” CEO Gale Klappa said in a release.
At the company’s We Energies utility, residential electricity use increased by 11.5% over last year’s third quarter, while electricity use by small commercial and industrial customers rose 1.6%. Large C&I customers’ electricity use — excluding the iron ore mines in Michigan’s Upper Peninsula — increased by 0.6%.
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.
